Shell Air Quality Plan Approval application for PA Ethane Cracker Plant

Air Quality Plan Approval Application

Petrochemicals Complex Shell Chemical Appalachia LLC

Beaver County, Pennsylvania

May 2014

Prepared for Submittal to:

Pennsylvania Department of Environmental Protection Bureau of Air Quality Southwest Regional Office

400 Waterfront Drive Pittsburgh, PA 15222-4745

Prepared by:

RTP Environmental Associates, Inc. 304-A West Millbrook Rd.

Raleigh, NC 27609

Shell Chemical Appalachia LLC Plan Approval Application

Beaver County, Pennsylvania Petrochemicals Complex

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Table of Contents

1.0 Introduction .................................................................................. 1-1

1.1 Project Description ........................................................................................................ 1-1 1.2 Overview of Process...................................................................................................... 1-5 1.3 Site Description ............................................................................................................. 1-7 1.4 Project Schedule .......................................................................................................... 1-10 1.5 Document Overview ................................................................................................... 1-10

2.0 Permit Application Requirements .............................................. 2-1

3.0 Process and Emission Source Descriptions ............................ 3-1

3.1 Ethylene Manufacturing Process .................................................................................. 3-2 3.1.1 Process Description ................................................................................................ 3-2 3.1.2 Ethylene Manufacturing Emissions Sources ........................................................ 3-6

3.2 Polyethylene Manufacturing – Gas Phase Technology ............................................... 3-8 3.2.1 Process Description ................................................................................................ 3-8 3.2.2 Gas Phase Technology Process Emissions ......................................................... 3-11

3.3 Polyethylene Manufacturing – Slurry Technology.................................................... 3-12 3.3.1 Process Description .............................................................................................. 3-12 3.3.2 Slurry Technology Process Emissions ................................................................ 3-16

3.4 Combustion Turbines and Duct Burners (Cogen Units) ........................................... 3-17 3.5 Utilities and General Facilities Process Descriptions ................................................ 3-18

3.5.1 Diesel Engines ...................................................................................................... 3-18 3.5.2 Storage Tanks ....................................................................................................... 3-18 3.5.3 Product Loading ................................................................................................... 3-21 3.5.4 Cooling Towers .................................................................................................... 3-22 3.5.5 VOC Control Systems (Flares and Incinerators) ................................................ 3-22 3.5.6 Wastewater Treating ............................................................................................ 3-24

4.0 AIR REGULATORY REQUIREMENTS ........................................ 4-1

4.1 Pennsylvania Air Pollution Control Regulations ......................................................... 4-1 4.1.1 25 Pa. Code Ch. 121. General Provisions ............................................................. 4-1 4.1.2 25 Pa. Code Ch. 122 National Standards of Performance for New Stationary

Sources .................................................................................................................... 4-7 4.1.3 25 Pa. Code Ch. 123. Standards for Contaminants .............................................. 4-7 4.1.4 25 Pa. Code Ch. 124. National Emissions Standards for Hazardous Air

Pollutants ................................................................................................................ 4-7 4.1.5 25 Pa. Code Ch. 127. Construction, Modification, Reactivation and

Operation of Sources ............................................................................................ 4-10 4.1.6 25 Pa. Code Ch.129. Standards for Sources ....................................................... 4-13



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4.1.7 25 Pa. Code Ch. 131. Ambient Air Quality Standards ....................................... 4-17 4.1.8 25 Pa. Code Ch. 135. Reporting of Sources ....................................................... 4-17 4.1.9 25 Pa. Code Ch. 137. Air Pollution Episodes ..................................................... 4-18 4.1.10 25 Pa. Code Ch. 139. Sampling and Testing ...................................................... 4-18 4.1.11 25 Pa. Code Ch. 145. Interstate Pollution Transport Reduction ........................ 4-19

4.2 Federal Regulations ..................................................................................................... 4-19 4.2.1 40 CFR Part: New Source Performance Standards ........................................... 4-19 4.2.2 40 CFR Part 61: National Emissions Standards for Hazardous Air

Pollutants (NESHAP) .......................................................................................... 4-37 4.2.3 40 CFR Part 63: National Emissions Standards for Hazardous Air

Pollutants for Source Categories (NESHAP) ..................................................... 4-40 4.2.4 40 CFR Part 64: Compliance Assurance Monitoring ........................................ 4-46 4.2.5 40 CFR Part 68: Chemical Accident Prevention Provisions ............................ 4-46 4.2.6 40 CFR Parts 72, 73, 74, 75, and 76: Acid Rain Programs ................................ 4-47 4.2.7 40 CFR Part 82: Protection of Stratospheric Ozone ........................................... 4-47 4.2.8 40 CFR Part 98: Mandatory Greenhouse Gas Reporting .................................. 4-48

5.0 Control Technology Analysis ..................................................... 5-1

5.1 Control Technology Background ................................................................................. 5-1 5.1.1 Control Technology Analyses Definitions ........................................................... 5-1 5.1.2 Methodology for LAER and BACT Analyses ..................................................... 5-2 5.1.3 Achieved in Practice and Technical Feasibility Criteria ...................................... 5-4 5.1.4 Control Technology Analysis Organization ......................................................... 5-7 5.1.5 Summary of Proposed BACT/LAER ................................................................... 5-8

5.2 Ethane Cracking Furnaces .......................................................................................... 5-21 5.2.1 Cracking Furnace NOx/NO2 LAER/BACT Analysis ........................................ 5-21 5.2.2 Cracking Furnace VOC LAER Analysis ............................................................ 5-50 5.2.3 Cracking Furnace PM/PM10/PM2.5 BACT/LAER Analyses ............................. 5-53 5.2.4 Cracking Furnace CO BACT Analysis............................................................... 5-57 5.2.5 Cracking Furnace Greenhouse Gas (GHG) Emissions BACT .......................... 5-61

5.3 Combustion Turbines & Duct Burners ...................................................................... 5-70 5.3.1 Combustion Turbine NOx/NO2 LAER/BACT Analyses .................................. 5-70 5.3.2 Combustion Turbine VOC LAER Analysis ....................................................... 5-78 5.3.3 Combustion Turbine PM/PM10/PM2.5 BACT/LAER Analyses ........................ 5-82 5.3.4 Combustion Turbine CO BACT Analysis .......................................................... 5-87 5.3.5 Combustion Turbine GHG BACT Analyses ...................................................... 5-93

5.4 Diesel Engines ........................................................................................................... 5-102 5.4.1 Diesel Engine NOx and VOC LAER Analyses ............................................... 5-102 5.4.2 Diesel Engine PM/PM10/PM2.5 BACT/LAER Analyses ................................. 5-110 5.4.3 Diesel Engine Carbon Monoxide BACT Analysis .......................................... 5-123 5.4.4 Diesel Engine GHG BACT Analysis................................................................ 5-132

5.5 Equipment Leaks ....................................................................................................... 5-134 5.5.1 Equipment Leaks of VOC LAER Analysis ...................................................... 5-134 5.5.2 Equipment Leaks of GHG BACT Analysis ..................................................... 5-139



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5.6 Evaluation of the Potential Use of Carbon Capture and Sequestration (CCS) as

BACT for CO2 .................................................................................................................... 5-143 5.6.1 Technical Feasibility of Potential CCS Process Alternatives .......................... 5-144 5.6.2 Step 3: CCS Control Technology Hierarchy ................................................... 5-160 5.6.3 Step 4: Evaluate the Most Effective Controls. ................................................. 5-161 5.6.4 Step 5: Proposed CO2 BACT ........................................................................... 5-165

5.7 Polyethylene Process, Storage, and Handling Vents ............................................... 5-167 5.7.1 Polyethylene Process, Storage and Handling Vent VOC LAER Analysis ..... 5-167 5.7.2 Polyethylene Process, Storage, and Handling Vent PM/PM10/PM2.5

LAER/BACT Analysis ...................................................................................... 5-176 5.8 VOC Emissions from Storage Tanks and Vessels................................................... 5-184

5.8.1 Tank Emissions Control Technology Baseline ................................................ 5-184 5.8.2 Step 1: Identify Tank VOC Control Options ................................................... 5-184 5.8.3 Step 2: Eliminate Technically Infeasible Tank VOC Controls ....................... 5-188 5.8.4 Step 3: Establish Tank VOC LAER ................................................................. 5-188

5.9 PM and VOC Emissions from Cooling Towers ...................................................... 5-192 5.9.1 Cooling Tower PM/PM10/PM2.5 BACT/LAER Analysis ................................ 5-192 5.9.2 Cooling Tower VOC LAER.............................................................................. 5-198

5.10 VOC Emissions from Wastewater Treatment Plant .............................................. 5-204 5.10.1 VOC LAER Analysis ........................................................................................ 5-204

5.11 Loading Operations ................................................................................................. 5-210 5.11.1 Polyethylene Loading PM/PM10/PM2.5 BACT/LAER Analysis ..................... 5-210 5.11.2 VOC LAER Analysis For Liquids Loading Operations .................................. 5-214

5.12 VOC Control Systems............................................................................................. 5-220 5.12.1 VOC Control Systems LAER Analyses ........................................................... 5-223 5.12.2 VOC Control System CO, NOx, PM, and GHG BACT/LAER Analyses ..... 5-243

5.13 Plant Roads .............................................................................................................. 5-247 5.13.1 Plant Road Fugitive PM LAER/BACT Analysis ............................................. 5-248

5.14 PaBAT Analyses for Pollutants Not Subject to BACT or LAER ........................ 5-250 5.14.1 SO2 ...................................................................................................................... 5-251 5.14.2 Ammonia (NH3) ................................................................................................. 5-256 5.14.3 Hazardous Air Pollutants (HAPs) ..................................................................... 5-258

6.0 Air Quality Modeling Analysis .................................................... 6-1

7.0 Additional Impacts Analysis ....................................................... 7-1

7.1 Analysis of Impacts Due to Growth ............................................................................. 7-1 7.1.1 Overview ................................................................................................................ 7-1 7.1.2 Growth in Population ............................................................................................. 7-2 7.1.3 Growth in Air Pollutant Emissions ....................................................................... 7-3 7.1.4 Air Quality Impacts ................................................................................................ 7-4

7.2 Analysis of Impacts to Visibility .................................................................................. 7-5 7.3 Analysis of Impacts to Soils and Vegetation ............................................................... 7-5

7.3.1 Overview ................................................................................................................ 7-5 7.3.2 Effects on Soil ........................................................................................................ 7-5



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List of Tables

Table 1-1. Summary of the Proposed Project’s Annual Potential to Emit Pollutants

(tons) 1 ........................................................................................................... 1-4 Table 3-1. Summary of Project Tanks and Vessels ...................................................... 3-19 Table 4-1. Summary of Regulatory Applicability .......................................................... 4-2 Table 4-2. Summary of Compliance with the Standards of Containment at 25

Pa.Code Ch. 123. .......................................................................................... 4-8 Table 4-3. Summary of Federal Regulatory Applicability ........................................... 4-20 Table 4-4. Tanks Not Subject to Control Under NSPS Subpart Kb ............................. 4-30 Table 5-1. Proposed Control Technology Evaluation Limits ......................................... 5-9 Table 5-2. Summary of RBLC Ethylene Cracking Furnace NOx Emissions Limits

(prior to the past two years) ........................................................................ 5-34 Table 5-3. Summary of Recent Ethylene Cracking Furnace NOx Emission Limits .... 5-35 Table 5-4. Summary of VOC BACT/LAER Limits for Ethylene Cracking

Furnaces ...................................................................................................... 5-52 Table 5-5. Summary of Proposed PM/PM10/PM2.5 BACT Limits for Ethylene

Cracking Furnaces ...................................................................................... 5-55 Table 5-6. Summary of CO BACT Limits for Ethylene Cracking Furnaces ................ 5-60 Table 5-7. CO2e Formed When Combusting Fossil Fuels ............................................ 5-62 Table 5-8. Summary of Texas Ethylene Cracking Furnace GHG BACT

Determinations ........................................................................................... 5-67 Table 5-9. Summary of NOx BACT Precedent Found in the RBLC Database For

40 to 50 MW Turbines ............................................................................... 5-72 Table 5-10. Summary of Recent NOx BACT Precedents ............................................. 5-73 Table 5-11. BAAQMD BACT Review for Authority to Construct Plant

Number 13289 ............................................................................................ 5-74 Table 5-12. Regulatory Agencies with NOx BACT Guidelines/Requirements for

Combustion Turbines ................................................................................. 5-77 Table 5-13. Summary of VOC BACT/LAER Precedents for Turbines with

Oxidation Catalyst ...................................................................................... 5-79 Table 5-14. Regulatory Agencies with VOC BACT Guidelines/Requirements for

Combustion Turbines ................................................................................. 5-82 Table 5-15. Summary of Particulate Matter BACT Precedents for Combustion

Turbines with Oxidation Catalyst ............................................................... 5-84 Table 5-16. Regulatory Agencies with PM BACT Requirements/Guidelines for

Combustion Turbines ................................................................................. 5-87 Table 5-17. Summary of CO BACT Precedent for Turbines with Oxidation

Catalyst ....................................................................................................... 5-89 Table 5-18. GHG Emissions for Combustion Turbine Fuels ....................................... 5-94 Table 5-19. Summary of Combustion Turbine Cogeneration GHG BACT

Determinations ........................................................................................... 5-98 Table 5-20. RBLC Summary of NOx and VOC Precedents for Emergency

Generator Diesel Engines ......................................................................... 5-104 Table 5-21. RBLC Summary of NOx and VOC Precedents for Emergency

Firewater Diesel Engines .......................................................................... 5-106



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Table 5-22. Regulatory Agencies with NOx and VOC Guidelines/Requirements

for Emergency Stationary Diesel Engines .............................................. 5-111 Table 5-23. RBLC Summary of PM BACT Precedents for Emergency Generator

Diesel Engines ........................................................................................ 5-113 Table 5-24. RBLC Summary of PM BACT Precedent for Emergency Firewater

Diesel Engines ........................................................................................ 5-115 Table 5-25. Regulatory Agencies with PM Guidelines/Requirements for

Emergency Stationary Diesel Engines .................................................... 5-119 Table 5-26. Basis for Removing PM Precedents from Consideration ........................ 5-121 Table 5-27. RBLC Summary of CO BACT Precedents for Emergency Diesel

Engines .................................................................................................... 5-125 Table 5-28. RBLC Summary of CO BACT Precedent for Firewater Emergency

Diesel Engines ........................................................................................ 5-127 Table 5-29. Regulatory Agencies with CO Guidelines/Requirements for

Emergency Stationary Diesel Engines .................................................... 5-130 Table 5-30. LAER Components and References ............................................................138 Table 5-31. SCAQMD Rule 1173 Equipment Leak Rates and Repair Periods 1 ....... 5-140 Table 5-32. TCEQ LAER Equipment Leak Rates and Repair Periods 1 .................... 5-140 Table 5-33. BAAQMD Best Available Control Technology Guideline ..................... 5-141 Table 5-34. Summary of Texas Ethylene/Polyethylene Manufacturing GHG

BACT Determinations ............................................................................ 5-142 Table 5-35. Amine Based CO2 Capture Plants ≥ 200 TPD 1 ...................................... 5-150 Table 5-36. CO2 BACT Hierarchy and Emissions ..................................................... 5-162 Table 5-37. Summary of CCS Impacts Analysis for the Cracking Furnaces and

Cogen Units ............................................................................................ 5-164 Table 5-38. Summary of VOC BACT Precedents for Polyethylene Unit Vents ........ 5-169 Table 5-39. Summary of Recent Determinations for Polyethylene Process Vents .... 5-178 Table 5-40. Summary of BACT Guidelines for Bay Area Air Quality Management

District and Texas Pertaining to Manufacturing Process Particulate

Emissions ................................................................................................ 5-183 Table 5-41. Summary of Storage Tanks and Vessels in VOC Service ....................... 5-185 Table 5-42. Summary of VOC BACT/LAER Precedents for Tanks .......................... 5-190 Table 5-43. RBLC Summary of Cooling Tower Emission Limits for PM ................. 5-194 Table 5-44. RBLC Summary of Cooling Tower Emission Limits for VOC .............. 5-200 Table 5-45. RBLC Summary of VOC RACT/BACT/LAER Precedent for

Wastewater Treatment ............................................................................ 5-205 Table 5-46. Summary of the State Implementation Plan Review for Loading

Operations PM Requirements ................................................................. 5-213 Table 5-47. Summary of the State Implementation Plan Review for Loading

Operations VOC Requirements for Loading of Low Organic Vapor

Pressure Liquid ....................................................................................... 5-218 Table 5-48. Summary of the State Implementation Plan Review for Loading

Operations VOC Requirements for Loading of C3+ or LPG ................... 5-220 Table 5-49. Summary of RBLC and Other Flare Related Permitting Precedents

and Regulatory Requirements .................................................................. 5-224 Table 5-50. Summary of RBLC Incinerator Related Permitting Precedents .............. 5-236



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Table 5-51. Summary of SIP Regulations for Plant Road Particulate ........................ 5-248 Table 5-52. Summary of RBLC Survey Results for Plant Road Particulate .............. 5-250 Table 5-53. Proposed Limitations to Meet SO2 BAT ................................................. 5-252 Table 5-54. Summary of Proposed PaBAT for HAP from the Proposed Project

Sources ..................................................................................................... 5-258 Table 7-1. Nine Counties Considered in Population Growth Impact Area .................... 7-3 Table 7-2. Other Area Source Emissions Increases Compared to Current Inventory .... 7-4 Table 7-3. Commercially Significant Vegetation in Ten-County Study Area

(Acres) ............................................................................................................12 Table 7-4. Pennsylvania-Listed Plant Species with Potential to Occur in Vicinity

of Beaver Valley Nuclear (BVN) Plant (7 miles from the Proposed

Project Site) ................................................................................................ 7-15

List of Figures

Figure 1-1. General Location of the Shell Facility ......................................................... 1-8 Figure 1-2. Proposed Facility Location .......................................................................... 1-9 Figure 3-1. Ethane Cracker Process Flow....................................................................... 3-3 Figure 3-2. Polyethylene Gas Phase Technology Process Flow Diagram ..................... 3-9 Figure 3-3. PE Unit 3 - Polyethylene Slurry Technology Simplified Process Flow

Diagram ...................................................................................................... 3-13 Figure 5-1. CO2 Capture and Concentration System .................................................. 5-147



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1.0 Introduction

1.1 Project Description

Shell Chemical Appalachia LLC (Shell) is proposing to construct a petrochemicals

complex (the Project) near Pittsburgh, Pennsylvania that will convert ethane (derived as a

byproduct from shale gas production in the region) into ethylene and subsequently

polyethylene, which is the key building block for many plastic products used every day.

The proposed complex will be the first major U.S. project of its type built outside the

Gulf Coast region in 20 years. The facility will leverage the plentiful new supplies of

ethane in the region to produce polyethylenes used extensively by the area’s

manufacturing base. This will reduce economic and environmental transportation costs

while providing regional manufacturers with more flexibility, shorter supply chains, and

enhanced supply dependability.

The proposed Project site is located within an industrial area adjoining the Ohio River in

Potter and Center Townships in Beaver County, Pennsylvania. The site offers strategic

advantages including access to marine, rail and road transportation, and pipelines;

proximity to both ethane supply and polyethylene markets; access to a skilled workforce;

a prior history of industrial use; appropriate zoning and compatible adjoining land uses;

and a positive business climate.

Shell Chemical Appalachia LLC is committed to keeping people safe, protecting the

environment and being a good neighbor. The proposed manufacturing facility would

deliver a number of benefits for the community including employment, economic growth,

and redevelopment of an existing industrial site. As the company continues with project

planning, it is working with the community and other interested parties to enhance the

proposed project’s potential benefits while identifying and addressing potential impacts.

With the increase in North American shale gas production, particularly in the “wet gas”

portions of the Marcellus and Utica shale in western Pennsylvania, West Virginia and

Ohio, there has been an accompanying increase in ethane production. The resultant



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availability of increased supplies of ethane at favorable prices has caused ethane to

become a highly competitive feedstock for use by the petrochemical industry.

The proposed Project, expected to employ 400 workers, will be comprised of an ethylene

manufacturing plant with an average capacity of 1,500,000 metric tons per year.1 The

ethylene that is produced will be used to supply feed to three polyethylene manufacturing

units with a combined annual production of approximately 1,600,000 metric tons of

polyethylene.2 Steam and electricity required for the process will be supplied by natural-

gas-fired combined cycle cogeneration units (Cogen Units). The Project includes all of

the ancillary units needed to support a new standalone complex including effluent

treatment, storage, logistics, cooling water facilities, emergency flares, buildings, and

warehouses. Excess electricity produced by the cogeneration units at the Project will be

sold for distribution within the PJM grid for regional use.

Shell is submitting an Air Quality Plan Approval pursuant to the Pennsylvania Air

Pollution Control Act and 25 Pa. Code Ch. 127, Subch. B, to obtain approval for

construction of an “air contamination source” and installation of associated air cleaning

devices, including review pursuant to the pre-construction permitting requirements under

the PSD and NSR programs.

The analysis provided in this application addresses the requirements governing air

emissions from the proposed facility including: 1) New Source Performance Standards

(“NSPS”), 2) National Emission Standards For Hazardous Air Pollutants (“NESHAPS”);

3) Prevention Of Significant Deterioration (PSD)/ Best Available Control Technology

(BACT) analysis for applicable pollutants for which the Project is classified as a major

source located within an attainment area for such pollutant; 4) Nonattainment New

Source Review (NNSR) / Lowest Achievable Emission Rate (LAER) analysis for those

applicable pollutants for which the Project is classified as a major source located within a

non-attainment area for such pollutant; 5) demonstration that the Project will not cause or

1 Assumes 7,500 hours per year of operation at the design capacity. 2 Assumes each of the polyethylene units will operate 8,000 hours per year at their design capcity.



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contribute to an exceedance of an applicable air quality standard or increment; 6)

quantification of the emissions reduction credits (i.e., offsets) required for certain

pollutants in accordance with the nonattainment NSR requirements; 7) demonstration that

emissions from the new sources will be the minimum attainable through use of best

available technology pursuant to 25 Pa. Code §127.12(a)(5) (“PaBAT”), 8) an additional

impacts analysis under 40 C.F.R. §52.21(o), and 9) an analysis as required by 25 Pa.

Code §127.205(5) of alternative sites, sizes, production processes and environmental

control techniques, showing that Project benefits outweigh the Project’s environmental

and social costs.

The Project site is located within an area that is designated as nonattainment for SO2 (1-

hr), PM2.5 (annual), ozone,3 and lead (Pb) and attainment or unclassified for all other

criteria pollutants under the Clean Air Act. A summary of the proposed facility’s

potential to emit regulated NSR pollutants is presented in Table 1-1. As shown,

emissions of NOx, PM2.5, and VOC, which are nonattainment pollutants, are above the

major facility thresholds of 100, 100, and 50 tons per year, respectively. As a result, the

proposed Project is subject to the nonattainment NSR requirements at 25 Pa. Code

§127.201 for NOx, PM2.5, and VOC. The Project is a major facility and emissions of

PM, PM10, NO2, and CO are above their respective significance thresholds of 25, 15, 40,

and 100 tons per year. As a result, the Project is subject to the prevention of significant

deterioration (PSD) requirements at 25 Pa. Code §127.81 for PM, PM10, NO2, and CO.

The proposed Project will have CO2e emissions above the major facility threshold of

100,000 tons per year and greenhouse gas (GHG) emissions greater than the significance

threshold; and as a result, the Project is subject to the PSD/BACT requirements for

GHGs. Increases in sulfur dioxide (SO2) and lead (Pb) emissions are less than the major

source threshold (100 tons/yr) and emissions of sulfuric acid mist are less than the PSD

significance threshold (7 tons/yr).

3 All of Pennsylvania is designated nonattainment for ozone because it is a part of the Northeast Ozone

Transports Region (NOTR), that was defined in the 1990 Clean Air Act Amendments.



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Table 1-1. Summary of the Proposed Project’s Annual Potential to Emit Pollutants (tons) 1

Pollutant Cracking

Furnaces

PE

Units

Cogen

Units

Flares &

Incinerators

Tanks &

Loading Fugitives

Support

Units Total

Significance

Threshold

Subject to

NSR/PSD

Carbon Monoxide 670 - 43.5 277 - - 0.6 991 100 Yes

Nitrogen Oxides 181 - 67.9 74.8 - - 2.8 327 100/40 Yes

PM 34.1 15.3 16.9 4.6 - - 8.3 79 25 Yes

PM10 86.8 4.9 59.8 8.2 - - 4.7 164 15 Yes

PM2.5 86.8 4.9 59.8 8.2 - - 0.1 160 100 Yes

Sulfur Dioxide 3.6 - 13.3 5.0 - - 0.0 22 100 No

VOC 32.4 96.6 31.9 219 14.1 47.5 42.7 484 50 Yes

CO2e 1,048,668 - 1,061,680 147,708 - 138 1,272 2,259,466 100,000 Yes

Sulfuric Acid Mist 0.1 - 0.5 0.2 - - 0.0 0.9 7.0 No

Total HAP 18.2 0.0 9.3 3.4 1.8 5.4 3.9 41.9 N/A N/A

Polyethylene (PE) Units: includes emissions from PE processing equipment but not fugitives, flare, and thermal incinerator emissions.

Support Units: includes emissions from firewater pump and emergency generator engines, cooling tower, wastewater treatment and plant roads

1. This Project may also increase emissions of other pollutants, but in minimal quantities. Appendix B includes the detailed

emissions increase calculations for the proposed Project.



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Under non-attainment NSR regulations, the proposed Project’s emissions of NOx, PM2.5,

and VOC will be subject to the emissions offset requirement at 25 Pa. Code §127.205(3).

As a result, in accordance with the offset ratios of 1.15, 1.1, and 1.15, respectively, at

25 Pa. Code §127.210(a), Shell will secure the following amounts of emissions reduction

credits (ERCs):

NOx: 376 tons = (1.15) x (327 tons)

PM2.5: 176 tons = (1.1) x (160 tons)

VOC: 557 tons = (1.15) x (484 tons)

In accordance with 25 Pa. Code §127.206(d)(1), Shell will not operate the sources until

the required ERCs are provided to and processed through the ERC registry, and the

Department certifies the required ERCs.

A summary of the potential to emit for hazardous air pollutant (HAP) emissions is

presented in Table 1-1. As shown, the total annual HAP emissions from the Project are

estimated to be approximately 42 tons. The largest individual source of HAP will be the

Cracking Furnaces, which will have the potential to emit 18.2 tons of total HAP.

1.2 Overview of Process

Ethane, the primary raw material for the proposed Project, is a natural gas liquid, or

NGL, that exists in certain natural gas deposits including the Marcellus and Utica Shales.

(Propane and butane are examples of other NGLs.) Natural gas companies remove NGLs

from natural gas, with the natural gas (mainly methane) to be shipped by pipeline for use

as a fuel by residences, power plants, and industry. The NGLs are used for a variety of

industrial, residential, and commercial uses. Ethane’s primary use is as a feedstock used

to create ethylene.

Ethylene is an important first step in creating many of the products in everyday use. This

facility will process the ethylene to make different types of polyethylene. Different

grades of polyethylene are used to make different types of products:



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low-density polyethylene (LDPE) and linear low density polyethylene (LLDPE)

are the raw materials for flexible items like food packaging, film, trash bags,

diapers, toys, and housewares;

high density polyethylene (HDPE) is used to create “stiffer” products such as

crates, drums, bottles, food containers, and other types of housewares.

The proposed Project will consist of an ethylene manufacturing process, three (3)

polyethylene manufacturing units, three Cogen Units, and a variety of ancillary

equipment required to support the overall plant operations.

The proposed Project’s cracking funaces units will “crack” ethane (C2H6) to create

ethylene (C2H4). This is accomplished by heating the ethane to very high temperatures,

greater than 1500°F (800°C). “Tail gas,” a byproduct from the cracker furnaces that

contains methane and a high percentage of hydrogen, will be recycled to fuel the process,

with natural gas used to supplement the process’s energy requirements.

The ethylene manufacturing process will consist of seven (7) cracking furnaces that will

be capable of converting ethane into ethylene at a maximum rate of 1,500,000 metric tons

per year.4 The ethylene that is produced will be used to feed two gas phase polyethylene

manufacturing units and one slurry technology unit. The two gas phase units will be

designed to produce 550,000 metric tons per year of polyethylene each, while the slurry

unit will be designed to produce 500,000 metric tons per year.5 Both technologies

employ catalyst, but use different equipment and operating parameters to produce each

specific grade of polyethylene. Each unit will have separate pellet handling systems prior

to blending. Common storage equipment, rail car, and truck loading operations will

follow the blending.

To support the overall plant operations, three on-site natural gas-fired combustion

turbines/duct burners and heat recovery steam generators (HRSGs) will be used to

generate electricity and steam. Other ancillary equipment will include four emergency

diesel generators and three diesel-driven firewater pumps, two cooling towers, numerous

4 Assumes 7,500 hours per year of operation at the design capacity. 5 Each polyethylene unit is assumed to operate 8,000 hours per year at its design capcity.



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storage tanks and pressure vessels for raw materials and by-products, and a wastewater

treatment facility. Additionally, the Project will include the necessary air pollution

control devices to meet all applicable federal and state requirements.

For a more detailed description of the processes and supporting equipment proposed for

this Project, please refer to Section 3.0.

1.3 Site Description

The Shell facility will occupy approximately 400 acres on the site of the zinc smelter

currently owned by the Horsehead Corporation. The site is located adjacent to the Ohio

River in Beaver County, Pennsylvania.. The approximate Universal Transverse Mercator

(UTM) coordinates of the facility are 556,129 meters east and 4,502,450 meters north

(UTM Zone 17, NAD 83). Figure 1-1 shows the general location of the facility. Figure

1-2 shows the specific facility location on a 7.5-minute U.S. Geological Survey (USGS)

topographic map.

Beaver County is located in western Pennsylvania, with its western boundary bordering

the Ohio State line. The Ohio River generally runs through the center of the county and

flows in a westerly direction. The Beaver River drains the northern portion of the county,

converging with the Ohio approximately 5km upstream of the proposed site location.

The cutting of these rivers has formed the hills and valleys of this region, whose local

difference in elevation constitutes the relief of the county. Thus, north of the Ohio the

highest land, or main divide, rises about 600 feet above the river. The relief of the area

lying between Beaver River and Crow Run is about 550 feet above the Ohio River. The

tributaries south of the Ohio form a main divide which rises at most 650 feet above the

river.

Winters are cold and snowy at high elevations in Beaver and Lawrence Counties. In the

valleys it is also frequently cold, but intermittent thaws preclude a long-lasting snow

cover. Summers are fairly warm on mountain slopes and very warm with occasional very

hot days in the valleys. Rainfall is evenly distributed throughout the year, but it is

appreciably heavier on the windward, west facing slopes than in the valleys. Normal



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Figure 1-1. General Location of the Shell Facility



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Figure 1-2. Proposed Facility Location



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annual precipitation is adequate for all crops, although summer temperature and growing

season length, particularly at higher elevations, may be inadequate. The lowest

temperature on record, which occurred at New Castle on January 29, 1963, is -23

degrees. In summer the average temperature is 70 degrees, and the average daily.

maximum temperature is 80 degrees. The highest recorded temperature, which occurred

at New Castle on September 2, 1953, is 100 degrees. The total annual precipitation is 38

inches. Of this, 22 inches, or 60 percent, usually falls in April through September, which

includes the growing season for most crops. In two (2) years out of 10, the rainfall in

April through September is less than 17 inches. The heaviest 1-day rainfall during the

period of record was 3.70 inches at New Castle on October 16, 1954. Thunderstorms

occur on about 36 days each year and most occur in summer. Heavy rains, which occur

at any time of the year, and severe thunderstorms in summer sometimes cause flash

flooding, particularly in narrow valleys. Average seasonal snowfall is 42 inches. The

greatest snow depth at any one time during the period of record was 19 inches. On

average, there are 24 days a year with at least 1 inch of snow on the ground. The number

of such days varies greatly from year to year. The average relative humidity in mid

afternoon is about 60 percent. Humidity is higher at night, and the average at dawn is

about 80 percent. The sun shines 60 percent of the time possible in summer and 35

percent in winter. The prevailing wind is from the southwest. Average wind speed is

highest, 12 miles per hour, in winter.

1.4 Project Schedule

Construction activities are planned to start in late 2015 and to continue for approximately

24 months. Operation is planned to commence in 2018.

1.5 Document Overview

The contents of this document are organized as follows:

Section 1.0 provides an overview of the Project, a description of the proposed

site’s location and surrounding terrain and local climate in Beaver County,

Pennsylvania, and a summary of the pollutant-by-pollutant emissions increases.

Section 2.0 contains a summary of the permit application requirements.



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Section 3.0 contains the process description. Each of the manufacturing

processes which comprise the proposed Project are described along with the

points and types of emissions from each point. Also included is a description of

the various outside the boundary limits (OSBL) elements of the Project.

Section 4.0 contains an overview of all of the air regulatory requirements to

which the proposed Project is subject. This includes a description of both state

and federal requirements.

Section 5.0 contains the Lowest Achievable Emissions Rate (LAER), Best

Available Control Technology (BACT) and Pennsylvania Best Available

Technology (PaBAT) analyses required in support of the plan approval process.

Section 6.0 contains a summary of the results from the air dispersion modeling

analysis performed in support of the plan approval process for the PSD criteria

pollutant for which the Project is subject to review (i.e., NO2, CO, and PM10).

Section 7.0 contains the additional impacts analysis required under 40 CFR

§52.21(o).

Appendices

A – Plan Approval Application Forms

B – Detailed Emissions Increase Calculations

C – Air Dispersion Modeling Report

D – Trade Secret and/or Confidential Proprietary Information (Not in

Public Version)

E – 25 Pa. Code §127.205(5) Analysis

F – Additional Support Material

G – Summary of Compliance Demonstration



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2.0 Permit Application Requirements

Pursuant to the requirements of Title 25 of the Pennsylvania Code Chapter 127,

Construction, Modification, Reactivation, and Operation of Sources, this application

contains the following:

Identification of the location of the source and the name, title, address, and

telephone number of the individual responsible for the operation of the

source. This general information is provided in Section 1.0, in the Plan

Approval forms located in Appendix A, and in the General Information Form

located in Appendix F.

Information that is requested by the Department and is necessary to perform a

thorough evaluation of the air contamination aspects of the source is provided

in the Plan Approval forms located in Appendix A or in this document as

referenced within the forms.

A demonstration that the source will be equipped with reasonable and

adequate facilities to monitor and record the emissions of air contaminants

and operating conditions which may affect the emissions of air contaminants

and that the records are being and will continue to be maintained and that the

records will be submitted to the Department at specified intervals or upon

request. Compliance information is provided in the Plan Approval forms, as

well as, Appendix G. Specific equipment in many cases is still to be

determined, however, the criteria for the design and/or purchase of equipment

is set forth by the compliance requirements of the applicable regulations noted

in Section 4.0.

A demonstration that the source will comply with applicable requirements of

this article and requirements promulgated by the Administrator of the EPA

under the Clean Air Act (42 U.S.C.A. §§ 7401-7706). The applicability of

Federal regulations under the Clean Air Act are presented in Section 4.0. A

detailed listing of the compliance requirements and demonstration cited by

each applicable regulation is provided in Appendix G on an affected source

basis. This listing also provides citations for recordkeeping and reporting

requirements.

A demonstration that the emissions from a new source will meet the control

technology and emission limitations of applicable federal and state regulations

is presented in Section 5.0. This section contains a full control technology

review for all pollutants and contaminants subject to PSD/NSR, BACT/LAER

and PaBAT, respectively.

A demonstration that the source will not prevent or adversely affect the

attainment or maintenance of ambient air quality standards. A summary of



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the results from an air quality analysis performed for the proposed Project is

presented in Section 6.0. A report detailing the analysis is included as

Appendix C;

A plan of action for the reduction of emissions during each level specified in

Chapter 137 (relating to air pollution episodes), when required by the

Department. As noted in Section 4.0, a plan will be developed and

implemented when requested by the Department.

Copies of letters of notification to local municipalities and proof that the

notices were received are contained in Appendix F.

A plan for dealing with air pollution emergencies, when requested by the

Department, or when required by the Clean Air Act. A plan will be developed

and implemented as required.

A demonstration that the source and the air cleaning devices are capable of

being and will be operated and maintained in accordance with good air

pollution control practices. As described in Section 5.0, Shell proposes to

satisfy the applicable BACT, LAER, and PaBAT requirements through the

design,installation, and operation of air cleaning devices capable of achieving

the proposed limits and/or the operation of process equipment to minimize air

contamination through accepted work practices.

A completed compliance review form is presented in Appendix F.

In addition to the requirements of 25 Pa. Code § 127, the DEP plan approval application

must also include a completed Cultural Resource Notice (CRN) and return receipt. The

Pennsylvania State History Code (Title 37, § 507) requires a completed Cultural

Resource Notice and return receipt as part of the DEP plan approval process where more

than 10 acres of earth will be disturbed. To meet this criteria, URS Coprporation on

behalf of Horsehead Corporation and Shell previously filed a CRN for a joint water

permit amendment. A copy of this CRN and return receipt are provided in Appendix F.



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3.0 Process and Emission Source Descriptions

This section presents the process description and emission source descriptions for the

proposed Project. The description is organized by processing areas as follows:

Ethylene Manufacturing

Polyethylene Manufacturing

Combustion Turbines and Duct Burners

Utilities & General Facilities

The objective of the Project is to convert ethane into ethylene and then to convert

ethylene into linear, low density polyethylene (LLDPE) and high-density polyethylene

(HDPE) pellets that can be shipped to plastic manufacturing facilities. Typical

manufacturing uses for LLDPE include:

Plastic bags and sheets,

Plastic wrap,

Stretch wrap,

Toys,

Covers and lids,

Pipes,

Buckets and containers,

Covering of cables,

Geo-membranes, and

Flexible tubing.

Typical manufacturing uses for HDPE include:

3-D printer filament,

Arena board (puck board),

Bottle caps,

Chemical resistant piping systems,

Coax cable inner insulator,

Food storage containers,

Fuel tanks for vehicles,

Electrical and plumbing boxes,

Folding chairs and tables,

Hard hats,

Plastic bags,



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Plastic bottles suitable both for recycling (such as milk jugs) or re-use,

Storage sheds, and

Water pipes for domestic water supply and agricultural processes

The manufacturing process for LLDPE and HDPE begins with pyrolysis of a

hydrocarbon to make ethylene. Ethylene is then converted into LLDPE and HDPE

pellets. The Project will take ethane, a product of shale gas production in Pennsylvania

and neighboring states, and convert it to ethylene by pyrolysis in large furnaces.

Ethylene in the pyrolysis gas exiting the furnaces will be separated from the pyrolysis gas

and purified for the manufacture of LLDPE and HDPE. A number of utilities are

required to support these processes including: steam, electricity, process water, cooling

water, wastewater treatment, tanks, flares, storage and loading operations. The following

subsections describe each process in more detail and characterize the air emissions

sources.

3.1 Ethylene Manufacturing Process

3.1.1 Process Description

Figure 3-1 presents the process flow diagram for the ethylene manufacturing process.

Ethane is thermally cracked into ethylene, propylene, methane, hydrogen, and other by-

products in the pyrolysis furnaces at temperatures up to ~1560°F in the presence of

steam. The furnaces act as pyrolysis reactors in which a wide range of mainly light

hydrocarbons are produced. The general chemical reaction scheme is:

C2H6 + heat → C2H4 + H2

Ethane conversion in the furnaces is typically 65-72% and is optimized depending on the

availability of ethane. Any methane that is contained in the feedstock is not pyrolyzed

and travels through the furnaces unchanged. Thus, it is not included in the equation.

Steam is used as a diluent to control the pyrolysis reactions and is also not shown in the

equation. Several byproducts are produced as part of the ethane cracking process

including carbon, which is deposited as coke in the furnace tubes, unreacted ethane and

polymerized carbon compounds (C3+, gasoline, tar/coke/pitch). The Project includes



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Figure 3-1. Ethane Cracker Process Flow



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seven cracking furnaces, which will be operated in parallel. One hundred percent of the

plant’s annual ethylene production rate (1,500,000 metric tons)6 will be achieved through

six furnaces in cracking operation while the seventh furnace is in either decoking, in hot-

standby or off-line for maintenance.

After leaving each furnace radiant section, the hot cracked gases are cooled while

generating super high pressure (SHP) steam. The SHP-steam is used to drive the

cracker’s main compressor. Next, the cooled cracked gases are quenched with water to

reduce the volume of gas that must be compressed prior to cryogenic separation and

purification of the ethylene product. The quench water is also used to partially absorb

acidic components formed in the furnaces from traces of additives used for equipment

protection and impurities present in the ethane feedstock. In the quench tower the

cracked gas is cooled to ambient temperature. Gasoline as well as process steam is

condensed. The purified and cold cracked gas exiting through the top of the quench

tower is directed to the compression section. Circulating quench water is withdrawn

from the bottom of the quench tower and pumped to the process sections for heat

recovery.

Excess water and gasoline are separated by gravity. The water is cleaned in the process

steam system and then reused as dilution steam. Solid components (coke/pitch/tar) are

removed from the process water by gravitational deposition and sent offsite for either use

or disposal. The pyrolysis tar and light gasoline7 are stored in separate tanks before being

shipped offsite for further processing into products. The possibility of combining the

pyrolysis tar with the coke/pitch/tar is being considered. The combined stream would be

stored in the pyrolysis tar tank prior to being shipped offsite.

6 Assumes 7,500 hours per year of operation at the design capacity. 7 Pyrolysis tar is primarily heavy oil (>85%) with less amounts of C9+ components (4-14 %), water, and

traces of benzene, toluene and styrene (all <0.1%). Light gasoline is primarily benzene, toluene xylene,

ethyl benzene, and styrene (40-45%) with the remainder being compounds in the C2-C5 range.



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After the quench tower, the cracked gases are directed to the compression section where

they are compressed in a five-stage centrifugal compressor; compressing the cracked gas

from a suction pressure of approximately 25 pounds per square inch (absolute) to a

discharge pressure of approximately 500 pounds per square inch (absolute). Between the

4th and 5th stages of the compressor, the cracked gas is scrubbed using caustic to remove

sour components (primarily CO2 and H2S) from the cracked gas. The spent caustic is

sent to a stripper tower where the hydrocarbons are stripped from the spent caustic before

the spent caustic is directed to the caustic oxidation system.

After compression, the cracked gases pass through a cooling and drying section and then

to the separation section where the cracked gases are separated at low temperatures into a

C2/CH4/H2 stream and a C3+ stream. The C2/CH4/H2 stream is selectively hydrotreated to

convert any acetylene to ethylene prior to separation into the main product ethylene,

unconverted ethane and tailgas (hydrogen and methane). The unconverted ethane is

recycled back to the furnaces as feed.

The product streams (from the de-ethanizer bottoms) are sent to storage prior to being

exported to other plants via rail car for further processing and recovery of valuable

components. Most of the hydrogen rich tailgas is sent directly to the fuel gas system for

the cracking furnaces and provides the vast majority of the fuel used for cracking. A

small amount of the tailgas is sent to a pressure swing absorption (PSA) unit where a high

purity hydrogen stream is generated for use at the polyethylene units. Tailgas from the

PSA unit is recycled back to the cracked gas compressor and eventually ends up in the

cracking furnace fuel gas system.

In addition to the main processing sections for ethylene manufacture, the following

support systems are located inside the ethylene manufacturing plant.

Ethylene Refrigerant Cycle: The ethylene refrigeration cycle represents an open

loop system. It generates the reflux for the C2H4/C2H6 separation, supplies the

ethylene coolant for the low temperature section and CH4/C2 separation and

compresses the ethylene product to the required pressure.

Propane Refrigerant Cycle: The propane refrigeration closed cycle provides the

cooling in the intermediate temperature range between cooling water and ethylene



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refrigerant. The propane vapors are compressed by a three-stage propane

compressor.

Gasoline Redistillation: The gasoline from the quench water system is separated

by distillation into a wash oil fraction overhead and a heavy bottom product. The

bottom product is mixed heavy gasoline from the quench water section and is

exported to storage. The overhead liquid product is a light gasoline stream that is

partially re-used in the process, but has a net export to storage.

Steam System: SHP steam is generated when cooling the cracked gases leaving

the cracking furnaces. The system is designed to supply steam to a number of

turbines driving compressors in the plant. Additionally, steam is directed to heat

consumers such as reboilers and process heat exchangers.

Condensate System: Condensates from the condensing turbines and reboilers are

collected in the condensate system. From there, they are returned to the facility

condensate treatment system.

Boiler Feed Water System: Demineralized water from the facility is delivered

to the cracking furnaces and other consumers at the required flow, pressure and

quality.

Fuel Gas System: Natural gas from offsite and tailgas from the separation

section are distributed by the fuel gas system to the cracking furnaces.

Regeneration Gas System: Part of the tailgas is used as regenerating gas for the

molecular sieve driers used in the ethylene manufacturing process to purify

nitrogen. Supply of the required regeneration gas, heating, cooling, and water

condensation is performed in the regeneration gas system.

Chemicals and Wash Oil System: This system provides performance chemicals

to several injection points. These chemicals include methanol, wash oil, ammonia

and dimethyl disulfide (DMDS).

Blow Down System: This system provides the facilities to safely remove process

gases and liquids to the facility flares during upset conditions and shutdowns.

Slop and Sewer System: This system collects all liquids that appear in the plant

in separate collection systems. This ensures that effluents are processed in a safe,

environmentally optimized manner before leaving the facility.

3.1.2 Ethylene Manufacturing Emissions Sources

3.1.2.1 Ethane Cracking Furnace Emissions

Each of the Project’s cracking furnaces will have a firing capability of approximately

620 MMBtu/hr (HHV) per furnace. Pyrolysis gas products, methane and hydrogen, will

be used to provide the heat input. Emissions from the cracking furnace stacks will result

from combustion of methane, hydrogen, and natural gas during normal operation,



3-7

startup/shutdown, decoking, and hot standby. The seven cracking furnaces will be

operated in parallel and have the following operating modes:

Ethane cracking: This is the normal operating mode of the unit during which

ethylene is being produced by cracking ethane.

Cold startup and shutdown: This mode covers both the operation of the unit when

it is initially started up following a turnaround and the period following feed

being taken out of the unit until it is off-line. In a cold start-up situation, where

no furnaces are in ethane cracking mode, natural gas serves as the fuel for the

furnaces until ethane cracking begins and tailgas is available.

Decoking: During the ethane cracking mode, coke is formed within the radiant

coils. Coke build-up eventually leads to high tube wall temperatures requiring

decoking of the furnace. Every 30 to 60 days a furnace will go through decoking,

which will last for approximately 33 hours. The coke buildup is removed during

this mode of operation. The heat input rate required during decoking is about

30% of the furnace’s maximum heat input. Once a furnace has been decoked, it is

placed into hot steam standby until another furnace shuts down or goes into

decoking mode. Additional information related to decoking is provided below.

Hot steam standby: Once a furnace has been decoked, it is placed into hot steam

standby until it is needed for cracking (i.e. one of the other furnaces requires

decoking).

Feed in/Feed out: As part of the process of bringing a furnace down for purposes

of decoking or maintenance, the furnace’s firing rate is reduced to a point where

the feed to the furnace can be stopped. Similarly, when a furnace is being brought

back online from hot steam standby, there is is a period during which the firing

rate is increased prior to when feed is placed into the furnace. These periods are

referred to as feed in and feed out.

Decoking: Furnace decoking is a normal and routine part of the ethylene manufacturing

process. High ethane conversion rates (i.e., 72 percent) require more frequent decoking

relative to lower ethane conversion rates (i.e., 65 percent). Decoking is accomplished by

injecting steam into the radiant coils while progressively raising the concentration of air

to achieve controlled combustion of the coke in the furnace tubes. The CO2 (carbon

dioxide) concentration exiting the tubes is used to monitor the decoking process. After

passing through a separator to remove large particulate, the decoking vent will be

redirected back into the furnace where the CO and remaining particulate in this stream

will be combusted.



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Furnace Emissions: The nitrogen oxide (NOx) emissions from the furnaces will be

controlled through the use of low NOx burner technology and selective catalytic

reduction (SCR), The carbon monoxode (CO), volatile organic compound (VOC) and

hazardous air pollutant emissions from the furnaces will be controlled through the use of

low carbon fuel and good combustion control.

3.1.2.2 Ethylene Manufacturing Equipment Leak Emissions

Methane and VOC emissions may result from equipment leaks in the ethylene

manufacturing process area. Processes within the ethylene manufacturing unit with

potential for fugitive methane and VOC emissions include:

Cracking furnace fuel system and process equipment;

Quench water system;

Cracked gas compression, acid gas removal and drying process area;

Cryogenic separation area;

C2 fractionation;

C2 hydrogenation unit, and

Spent caustic oxidation unit.

3.2 Polyethylene Manufacturing – Gas Phase Technology


Figure 3-2 presents a simplified process flow diagram of the gas phase polyethylene

manufacturing process. Two units (PE Units 1 and 2) are proposed; each designed to

produce 550,000 metric tons per year of polyethylene (PE).

The gas phase technology polyethylene plants consist of the following process sections:

ethylene purification, raw material supply and purification, catalyst system, reactor

system, resin degassing and vent recovery, granular resin seed bed storage system, and

additive handling and pelleting sections. The main feeds to the polyethylene process are

ethylene, co-monomer and hydrogen. Gas phase technology polyethylene plants are

designed to produce different grades of linear low density polyethylene (LLDPE) and

high density polyethylene (HDPE) polymers from polymer grade ethylene.



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Figure 3-2. Polyethylene Gas Phase Technology Process Flow Diagram 8

8 The stream definitions corresponding to the R-x references constitute trade secret and/or confidential

proprietary information as defined in the Pennsylvania Right to Know Law. These stream definitions are

provided in Table D-1 of Appendix D.



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The following is a brief description of the proposed gas phase technology polyethylene

plant. References such as R-1 are used to describe process streams within the process.

The stream definitions corresponding to these references are considered trade secret

and/or confidential proprietary information as defined in the Pennsylvania Right to Know

Law, and as a result are provided as Table D-1 in Appendix D.

3.2.1.1 Purification

Ethylene Purification: Fresh ethylene feed (R-1) flows through a series of purifiers

where trace quantities of impurities are removed. The purifiers are vented to a VOC

Control System before and during regeneration. The VOC Control System is described

in more detail in Section 3.5.5. The fresh ethylene is injected into the Reaction Systems.

Raw Material Purification: R-2 or R-3 as well as R-32 are passed through a degassing

column and then flow through purifiers to remove impurities and are injected into the

Reaction System. R-4 is injected directly into the Reaction System. R-8 is passed

through a series of purifiers where trace quantities of impurities are removed. The

purifiers are vented to the atmosphere or flare before and during regeneration. A portion

of R-8 is compressed and is then routed to the reactor. The remaining R-8 is used

throughout the plant. R-7 is routed directly to the reactor.

3.2.1.2 Reaction Systems

The Reaction System consists of two fluidized bed Reactors, Cycle Gas Compressors and

Coolers, and Product Discharge Tanks related to each Reactor. Ethylene (R-1), Raw

Materials (R-2, R-3, R-4, R-7, R-8 and R-32), and catalyst (R-9) are fed continuously to

the Reactors. Polyethylene resin is removed from the Reactors and is separated from

most of the small amount of gas accompanying it in the discharge tanks. The separated

gas is fed back to the reactors. A mixture of resin and residual gas (R-11) is then sent to

Resin Degassing and Vent Recovery.



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Slurry catalyst is prepared by mixing precursor (R-16) with additives (R-17 & R-18).

The prepared catalyst (R-19) is transferred to the Reaction System. To prevent catalyst

release to the atmosphere, the vessels vent to a disposal tank and seal pot.

3.2.1.3 Resin Degassing and Vent Recovery

Resin from the Reactors (R-11) is conveyed to two purge bins where the dissolved

hydrocarbons are stripped from the resin and returned to the process (R-15, R-20). Any

excess gas not used in the process is vented to the VOC Control System. Resin from both

purge bins (R-13) flows to Additive Handling and Pelleting.

3.2.1.4 Granular Resin Seed Bed Storage System

Granular Resin (R-37) flow can be routed to the Granular Resin Seed Bed Storage

System. From the seed bed storage system, resin can be conveyed to the Reaction System

(R-38) for seed bed use or conveyed back to the Additive Handling and Pelleting area

(R-40).

3.2.1.5 Additive Handling and Pelleting

Using feeders, the resin (R-13) and additives (R-31) are metered to the Pelleting Systems.

The additives and resin are thoroughly mixed, melted, and pelleted in the Pelleting

Systems. The pellets (R-27) are dried, cooled, and conveyed from the pelletizing section

to homogenization silos. Pellets are blended in the homogenization silos. From the

blender, the pellets are transferred to silos for loading trucks and railcars.

3.2.2 Gas Phase Technology Process Emissions

Two types of pollutant emissions result from the gas phase polyethylene process: VOC

and particulate. A detailed listing of the points of emissions and pollutant type emitted is

presented in Table D-2 in Appendix D. All of the vents with VOC containing gases

located upstream of and including the Product Purge Bin will be directed to the VOC

Control System. All of the vents with particulate containing gases located upstream of

and including the Product Purge Bin will be directed through filters prior to release to the

atmosphere. Control of VOC emissions resulting from vents located downstream of the



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Product Purge Bin will be accomplished by maintaining the residual VOC content in the

resin exiting the Product Purge Bin below a level of 50 ppmw. Except for the pellet

dryer, particulate filters (i.e., sintered metal, fabric, or HEPA) will be used to control the

non-fugitive particulate matter emissions from all vents located downstream of the

Product Purge Bin. In addition to VOC emissions associated with vents, fugitive VOC

emissions may also result from equipment leaks.

3.3 Polyethylene Manufacturing – Slurry Technology


One slurry based technology unit (PE Unit 3) designed to produce 500,000 metic tons per

year of polyethylene (PE) is proposed. Figure 3-3 presents a simplified process flow

diagram of the polyethylene slurry technology HDPE process. As shown, the plant will

consist of catalyst activation and feed systems, a reactor system followed by

separation/degassing, solvent recovery and a pelletizing section. The main feeds to the

polyethylene process are ethylene, co-monomer (Butene-1 and/or Hexene-1), hydrogen,

and light hydrocarbon diluent (isobutane). The reaction slurry is continuously withdrawn

from the reactor and the HDPE powder is separated from the hydrocarbon diluent and un-

reacted monomers.

The hydrocarbons are recycled to the reactors in a simple recovery system. The HDPE

powder that leaves the reactor enters a degassing system designed to remove traces of

diluent and residual monomer, then the powder is transferred to the finishing section. In

the finishing section, the powder is mixed with additives and is pelletized.

3.3.1.1 Catalyst Activation and Feed Systems

PE Unit 3 will use Ziegler and chromium based catalysts to manufacture polyethylene.

When Ziegler catalyst is needed, a drum is tumbled to mix the solution and then the



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Figure 3-3. PE Unit 3 - Polyethylene Slurry Technology Simplified Process Flow Diagram



3-14

slurry is pumped into a day tank with a mixer.9 From the mixing day tank the catalyst.

slurry flows into the catalyst slurry tank where further dilution is achieved by diluent

addition. The chromium catalyst delivered by trucks to the site will be activated in an

electic heater. The Project includes as part of its design two (2) activation heaters. Each

catalyst activation system has a vent to the atmosphere through which air, nitrogen,

moisture, and catalyst fines are exhausted after passing through a knockout pot and

HEPA type filter system. Once the catalyst has been activated, it is transferred into tote

bins that are unloaded to the catalyst day tank, similar to the Ziegler catalyst. All of the

vents in this system will be controlled using particulate filters.

Triethylaluminum (TEAL) and Triethylborane (TEB) will be used as cocatalysts with the

Ziegler catalyst. TEAL and TEB are volatile, colorless liquids and highly pyrophoric.10

Nitrogen is used to transfer cocatalyst from the on-site delivery containers to the

cocatalyst feedpot. When transfer from a new delivery container is first initiated the

nitrogen used for the transfer process, is exhausted through a mineral oil seal pot prior to

being directed to a remote sand pit for safe, managed destruction. During process upsets,

the cocatylst feedpot will be vented directly to the sand pit. The sand pit will be fenced,

weather-protected, and accessed by authorized personnel only.

Co-monomer Injection: Co-monomer (hexene or butane, alternatively) is fed to a dryer

to remove impurities and introduced with recovered hydrocarbon into the polymerization

process.

3.3.1.2 Reactor Section

The reactor is based on the slurry loop principle. The reaction takes place in an isobutane

diluent. Ethylene is dissolved in the diluent. Catalyst, comonomer and hydrogen are also

9 The Ziegler type catalyst is purchased in 55 gallon drums. 10 Pyrophoric means that the material is capable of igniting spontaneously in air.



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fed into the reactor. The ethylene comes into contact with the catalyst in the diluent and

polymer “grows” into a white powder.

Depending on the characteristics of the HDPE being manufactured, two reactors will be

used in series for both mono-modal and bi-modal operation. Intermediate treatment is in

service for the bi-modal process. The intermediate system is used to generate differences

in the reaction conditions in each reactor to enable different HDPE properties (i.e.,

polymer molecular weight).

The slurry from the second reactor is discharged to hydroclones where the concentration

of the polyethylene powder is increased prior to separation from the slurry liquid. After

the hydroclones, the thickened slurry is heated up to the solvent vaporization temperature

prior to discharge to the high pressure separator.

3.3.1.3 High Pressure/Low Pressure Solvent Recovery

In the PE Unit 3 process there are two hydrocarbon/diluent recycle systems: High

Pressure Solvent Recovery (HPSR) and Low Pressure Solvent Recovery (LPSR).

High Pressure Solvent Recovery (HPSR): Nearly all of hydrocarbon recovery/recycle

occurs in the HPSR system. The high pressure separator makes the main separation

between vaporized hydrocarbon and powder. The PE powder is transferred to the low

pressure system.

Low Pressure Solvent Recovery (LPSR): Powder enters the LPSR degasser from the

HPSR via the product discharge system. The powder is “dry” but still saturated with

monomer and hydrocarbon. As the powder enters the degasser, extra gas slip from the

discharge system goes to the low pressure recovery system. The powder in the degasser

is stripped by two counter flow gas streams; one is a mixture of nitrogen and light

hydrocarbons. The other, fed at a lower level in the vessel, is a fresh pure nitrogen

stream. Degassed powder is pneumatically transferred to finishing.



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3.3.1.4 Additives and Pelletizing

In the additives and pelletizing section, virgin powder (i.e., resin) from the

polymerization section is received and blended with additives for extrusion and

pelletizing. The extruder consists of a continuous mixer with gear pump and is fitted

with a screen pack changer, diverter valve, die plate and an underwater face cutting

system. Pellets are extruded from the pelletizer and cut under water. Then the pellets are

separated from the water and dried in the pellet dryer. Finally, pellets are collected in a

hopper before being pneumatically conveyed to pellet blending. Water recovered in the

pellet drier is recycled through the water tank to the pelletizer.

The pellets conveyed from the pelletizing section are blended in the static

homogenization silos. From the blender, the pellets are transferred to silos for loading

into trucks and railcars.

3.3.2 Slurry Technology Process Emissions

Three types of emissions result from the polyethylene slurry process:

VOC and particulate from process vents,

Emissions from the sand pit, and

Fugitive emissions from equipment leaks.

A detailed listing of the points of emissions and pollutant type emitted is presented in

Table D-3 in Appendix D. All of the vents with VOC containing gases located upstream

of the Degasser will be directed to the VOC Control System. All of the vents with

particulate containing gases located upstream of the Degasser will be directed through

particulate filters (i.e., sintered metal, fabric, or HEPA) prior to release to the atmosphere.

Control of VOC emissions resulting from vents located downstream of the Degasser will

be accomplished by maintaining the residual VOC content in the pellets below a level of

50 ppmw. Except for the pellet dryer, particulate filters (i.e., sintered metal, fabric, or

HEPA) will be used to control the non-fugitive particulate matter emissions from

Pelleting System and downstream vents. In addition to VOC emissions associated with

vents, fugitive VOC emission may also result from equipment leaks.



3-17

3.4 Combustion Turbines and Duct Burners (Cogen Units)

Three natural gas-fired combustion turbines (CTs), each coupled with a dedicated heat

recovery steam generator (HRSG), will supply the electricity and steam required to

support the site. Excess electricity produced by the Project will be available for sale to

the local electric utility grid. The combustion turbines will be either General Electric

Frame 6Bs or Siemens SGT-800s. The General Electric CTs have a baseload rating at

the average ambient site conditions of 40.6 MW. The heat input to each GE CT at

baseload at the average ambient site conditions is expected to be 475 MMBtu/hr (HHV).

The Siemens SGT-800 CTs have a baseload rating at the average ambient site conditions

of 48.7 MW. The heat input to each Siemens CT at baseload at the average ambient site

conditions is expected to be 492 MMBtu/hr (HHV). Each combined cycle CT will be

equipped with duct burners capable of firing natural gas up to rated capacity of

189 MMBtu/hr (HHV) if the GE turbine is selected, or 197 MMBtu/hr (HHV) if the

Siemens turbine is selected. Two steam turbines each rated at 64.3 MW will be used to

generate electricity using the steam produced by the HRSGs and excess steam from the

ethane cracking unit. For purposes of presentation the combustion turbines and duct

burners are refered to as Cogen Units.

Emissions from the Cogen Units will result from the combustion of natural gas. Methane

emissions may result from equipment leaks in the natural gas supply system used to

deliver fuel to the Cogen Units. When tailgas is in excess at the cracking furnaces, a

small quantity of the tailgas may be combusted in the duct burners in combination with

natural gas.

The nitrogen oxide (NOx) emissions from the Cogen Units will be controlled through the

use of dry low NOx combustion technology and SCR. The carbon monoxode (CO),

volatile organic compound (VOC) and hazardous air pollutant emissions from the

furnaces will be controlled through the use of a combination of good combustion control

and CO oxidation catalyst.



3-18

3.5 Utilities and General Facilities Process Descriptions

3.5.1 Diesel Engines

Seven diesel-fired reciprocating internal combustion engines are included as part of the

Project. Three of these engines, each rated at 700 BHP/0.52 MW, will be used to drive

the emergency firewater pumps. The remaining four, each rated at 5028 BHP/3 MW,

will be used to drive emergency electrical generators. Emissions from the diesel engines

will result from the combustion of diesel fuel. Additionally, fugitive VOC emissions

may result from equipment leaks in the diesel fuel supply system. Emissions of NOx,

VOC, CO, and particulate will be controlled through the use of engine design. In

addition, low sulfur Tier 2 diesel will be used to control SO2 and particulate emissions.

3.5.2 Storage Tanks

A summary of the tanks that will be constructed to support the Project is presented in

Table 3-1. The pressurized storage vessels (i.e., spheres or bullets) are not sources of

emissions. Emissions from storage/equalization tanks occur as a result of displacement

of headspace vapor during filling operations in the case of fixed roof and internal floating

roof tanks or from tank rim seals in the case of external floating roof tanks (i.e., “working

losses”). To a lesser degree, diurnal temperature variations and solar heating cycles also

result in emissions from storage tanks (i.e., “breathing losses”). The equipment

components (i.e., flanges, valves, and tank seals) associated with each tank are

considered to be sources of fugitive VOC emissions and will be controlled as part of the

facility’s leak detection and repair (LDAR) program. As shown in Error! Reference

source not found., breathing losses from the internal floating roof tanks will be directed

to the VOC control system which includes a thermal incinerator. The tanks used to store

the emergency diesel engine fuel will be vented to carbon canisters.

As shown, ethylene storage will comprise two ethylene storage vessels and an

atmospheric refrigerated storage tank. As part of the site’s waste gas minimization plan,



3-19

Table 3-1. Summary of Project Tanks and Vessels

Service Tank/Vessel Description No. Equipment ID Capacity

(m3) VOC

Ethylene Spherical Pressure Vessel 2 V-64201, V-64202 7,238

Ethylene Atmospheric Refrigerated 1 1 T-64201 30,000

C3+(propane and heavier hydrocarbons) Spherical Pressure Vessel 2 V-64205, V-64206 2,300

Butene Spherical Pressure Vessel 2 V-64301, V-64302 1,200

Isopentane Horizontal Pressure Vessel 2 V-64401, V-64402 600

Isobutane Horizontal Pressure Vessel 2 V-64501, V-64502 200

C3+ Refrigerant Horizontal Pressure Vessel 1 V-64203 300

Pyrolysis Tar Heated Cone Roof 2 1 T-64201 130

Light Gasoline Internal Floating Roof 3 2 T-64207, T-64208 650

Hexene Internal Floating Roof 4 2 T-64301, T-64302 2,300

Recovered Oil Storage 8 Internal Floating Roof 5 1 T-59708 90

Flow Equalization Wastewater 8 Internal Floating Roof 5 2 T-59707A, T-59707B 2,810

Biotreater Aeration 8 Tank 5 1 T-59709 5,210

Secondary Clarifier 8 Tank 2 T-59710A, T-59710B 1,466

Biosludge (WAS) Holding 6, 8 Tank 1 T-59711 43

Sand Filter Backwash Receiver 8 Tank 1 T-59713 143

Spent Caustic Internal Floating Roof 5 2 T-53501, T-53502 900/8,630 7

Aqueous Ammonia Pressure Vessel 2 V-59601, V18835 91/114

Fresh Caustic Cone Roof 1 T-64701 300

Generator Diesel Fixed Roof 2 4 T-58901A, T-58901B, T-

58901C, T-58901D 38

Fire Pump Diesel Fixed Roof 2 3 T-59101A, T-59101B, T-59101C 7

Locomotive Diesel Fixed Roof 2 1 T-4000 38

Sulfuric Acid Cone Roof 2 T-53503A, T-53503B 150

Dimethyl disulfide (DMDS)4 Pressure Vessel 1 V-18831 25

Demineralized Water Storage Cone Roof 2 T-59601A, T-59601B 4,100

SAC Resin Maintenance Open Top 1 T-59603 18

WBA and SBA Resin Maintenance Open Top 1 T-59604 15



3-20

Service Tank/Vessel Description No. Equipment ID Capacity

(m3) VOC

Suspect Condensate Storage Cone Roof 1 T-58201 3,120

Normally Clean Condensate Storage Cone Roof 1 T-58202 10,670

Primary Raw Water Clarifier Open Top 2 T-59301A, T-59301B 5,080

Clearwells for Clarifier Open Top 2 T-59302A, T-59302B 300

RW Sludge Holding Open Top 1 T-59304 150

Reclaim Water Cone Roof 1 T-59306 520

Filtered Water Storage Cone Roof 2 T-59303A, T-59303B 13,650

Potable Water Storage Cone Roof 1 T-59501 90

1. Emergency release to atmospheric refrigeration tank flare

2. Tank vapors vented to carbon canister

3. Tank vapors vented to LP Thermal Incinerator

4. Includes nitrogen blanketing. Tank vapors vented to LP Thermal Incinerator

5. Tank vapors vented to Spent Caustic Vent Incinerator

6. WAS = Waste Activated Sludge

7. Two spent caustic scenarios

8. Included as part of the WWTP (see Section 3.5.6)



3-21

these tanks will be managed such that there is available storage space to accommodate an

off-spec product incident and recycle this material back as feed to the furnaces for

reprocessing.

3.5.3 Product Loading

Rail Loading: PE pellet loading will be the primary operation followed by C3+ and

light gasoline loading operations. Hopper cars will be gravity loaded with PE pellets

from the loading silos using a loading arm. The C3+ will be loaded into pressurized

railcars. Three types of emissions may result from this operation: 1) fugitive component

related VOC emissions and 2) emissions resulting from connecting and disconnecting the

loading hoses and 3)particulate emissions resulting from loading of polyethylene pellets.

Some of the raw materials used to manufacture PE and caustic will be offloaded at the

railcar rack. There will be six (6) spots for hydrocarbon and one for caustic offloading

from railcars.11 Any emissions associated with offloading of hydrocarbon will be

controlled via the emission controls located on the receiving tanks. Fugitive emissions

components (i.e., valves and flanges) will be controlled through the facility’s LDAR

program.

Truck Loading: Pitch will be loaded into drums and trucked from the site. Spent

caustic will either be oxidized and sent to the waste water treatment plant (WWTP) or

shipped via truck from the site. PE pellets will be transported from the site via truck.

The pellets will be conveyed from the homogenization silos to the loading silos. PE

pellets will be either gravity loaded directly from the silos or conveyed loaded into

trucks. A separate truck loading rack will be built for pyrolysis tar loading. This rack

will be designed with a single loading arm.

11 Offloading means that materials are being brought into the facility



3-22

3.5.4 Cooling Towers

Two counter-flow mechanical draft recirculating cooling water towers (CWT) will be

constructed at the site to provide cooling water. A twenty-six (26) cell cooling tower will

be used to provide cooling water for the process units and another four (4) cell tower will

support the Cogen Units. Clarified, multimedia-filtered water will be used as makeup to

account for the cooling water that is lost due to evaporation and blowdown. The

blowdown will be directed to the wastewater treatment plant (WWTP). The process unit

cooling tower will be sized for a flow of 57,000 tonnes/hr (metric) and the Cogeneration

Plant tower will be sized for a flow of 10,000 tonnes/hr. The cooling towers will be a

source of particulate and VOC emissions. Particulate is formed when the water portion

of the cooling tower’s mist evaporates and the dissolved solids agglomerate to form

particulate. The VOC that may be emitted by a cooling tower are the result of

hydrocarbon leakage from heat exchangers.

Cooling tower particulate emissions will be controlled through the use of a high

efficiency demister and VOC emissions will be controlled by monitoring for VOC in the

cooling tower inlet water.

3.5.5 VOC Control Systems (Flares and Incinerators)

The proposed Project includes four header systems that will be used to gather and control

VOC emissions during normal operation, startup, shutdown, and unforeseeable events at

the facility as follows:

High Pressure (HP) Header System,

Low Pressure (LP) Header System,

Refrigerated Storage Relief System, and

Spent Caustic Vent Incinerator.

The HP Header system will be used to control VOC emissions resulting from startup,

shutdown, maintenance, and unforeseeable relief at the ethane cracking unit. Similar

vents will be routed to this system from the polyethylene units. This system will have a

total relieving capacity of 1500 tons/hr. The HP Header system comprises two ground



3-23

flares (HP ground flares), each rated at 150 tons/hr, one elevated flare (HP elevated

flare), rated at 1200 tons/hr, and ancillary equipment such as knockout pots. The HP

elevated flare will be a secondary system used only when the combined capacities of the

two HP ground flares is exceeded due to an emergency (e.g., power failure). The HP

elevated flare will be steam assisted. The two HP ground flares will be unassisted.

All of the continuous and intermittent vents prior to and including the Product Purge Bin

at the gas phase technology PE units and prior to the Degasser at the slurry technology

PE unit and the tank emission control systems will be routed to the Low Pressure (LP)

Header system, which will include a thermal incinerator (i.e., LP Thermal Incinerator)

and a ground flare (LP Ground Flare). This system will be designed to handle a total

relieving capacity of 57 tons/hr. During normal operation, the gases in this system will

be directed to the LP Thermal Incinerator where they will be combusted. The rated

capacity of the LP Thermal Incinerator will be 12 tons/hr. When the amount of gas in the

system exceeds the capacity of the LP Thermal Incinerator, the excess gas in the system

will be directed to the LP Ground Flare. The rated capacity of the LP ground flare will

be 45 tons/hr. The LP ground flare will be unassisted.

The Ethylene Refrigerated Atmospheric Storage Header system will be used as follows:

1) during the initial start-up of the facility while nitrogen is being removed from the

ethylene storage tanks, 2) following inspections of the ethylene storage tanks, and 3) for

emergency relief from the ethylene storage tanks. This system will be sized for

22 tons/hr of relieving capacity and will be comprised of an elevated flare.

There will be an additional thermal incinerator (Spent Caustic Vent Incinerator) installed

as part of the spent caustic system. The Spent Caustic Vent Incinerator will be used to

control VOC and reduced sulfur compound emissions in the Spent Caustic Oxidation unit

offgas and from the Wastewater Treatment Plant’s (WWTP’s) flow equalization and oil

removal tank vents. This incinerator will be rated for 8 tons/hr. The Spent Caustic Vent

Incinerator will have an approximate average annual heat release rate of 10 MMBtu/hr.



3-24

The flares and incinerators will emit combustion pollutants: SO2, NOx, PM/PM10/PM2.5,

CO, VOC and HAP. Control of these emissions will be accomplished by operating the

facility in accordance with a waste gas minimization plan. In addition, the flares will be

operated to ensure that the flares are operated in accordance with a net heating value in

the combustion zone limit.

3.5.6 Wastewater Treating

The Wastewater Treatment Plant (WWTP) will consist of primary flow equalization and

oil removal, followed by a secondary activated sludge bioreactor (including clarifiers),

and a tertiary sand filter to treat the wastewater streams from process units and potentially

contaminated storm water runoff from process paved areas. Several wastewater streams

from the facility, including those streams containing VOC, will flow into one of two

Flow Equalization and Oil Removal (FEOR) tanks. Each tank will be a fixed roof tank

equipped with an internal floating roof vented to the Spent Caustic Vent Incinerator. Oil

rising to the top of these tanks will be skimmed off and will flow to a recovered oil

holding tank for off-site disposal. The Recovered Oil Tank will be a fixed roof tank

equipped with an internal floating roof vented to the Spent Caustic Vent Incinerator.

Effluent from the FEOR tanks will then be routed to the Biotreater Aeration Tank.

Internal WWTP recycle streams will also flow into this tank, as well as small nutrient

additive and pH adjustment streams. Biotreater effluent will flow to two Secondary

Clarifier Tanks. The clarifiers’ overflow stream will be pumped through a Sand Filter.

Clarifier underflow will be pumped to a biosludge holding tank that will feed a centrifuge

used for concentrating clarifier solids into a cake. Cooling tower blowdown will be

pumped directly to the Sand Filter. Effluent from this filter will be discharged through an

outfall to the Ohio River. Sand filter backwash will be pumped into a tank and will be

recycled back to the Biotreater Aeration Tank.

Internal WWTP recycle streams that will be pumped to the Biotreater Aeration Tank

include:

Centrifuge centrate from the biosludge plant



3-25

Return activated sludge

Sand filter backwash

The WWTP will be a source of VOC emissions. Emissions will be controlled by venting

the Recovered Oil Storage and Equilization Wastewater tanks to the Spent Caustic

Incinerator.



4-1

4.0 Air Regulatory Requirements

This section addresses the applicability of Pennsylvania and Federal air quality

regulations to the proposed Project. A complete review was performed of the

Pennsylvania regulations and Federal regulations, including New Source Review

(NSR),12 New Source Performance Standards (NSPS), National Emissions Standards for

Hazardous Air Pollutants (NESHAP), and other federal rules. The results of this review

are documented herein identifying the State and Federal regulations applicable to the

Project. A full and complete listing of affected emission units and citations for the

requirements of compliance and recordkeeping and reporting is provided in

Appendix G.13

4.1 Pennsylvania Air Pollution Control Regulations

The Commonwealth of Pennsylvania has promulgated ambient air quality standards and

pollution control regulations under Title 25 of the Pennsylvania Code.14 The proposed

Project is subject to the Title 25 Code Pennsylvania Chapters 121 through 145. The

specific applicability of each of these regulations in Chapters 121 through 145, and how

Shell will address these requirements is presented below. The applicable requirements

that will be discussed in this section are summarized in Table 4-1.

4.1.1 25 Pa. Code Ch. 121. General Provisions

This chapter provides for the control and prevention of air pollution anywhere in the

Commonwealth of Pennsylvania. Included in this chapter are definitions, purpose,

applicability, organization of the Department of Environmental Quality (Department), the

12 New Source Review includes the Prevention of Significant Deterioration (PSD) review for attainment

pollutants, non-attainment (NA) review for non-attainment pollutants, and minor source review for

pollutants that are less than the applicable threshold values for PSD and NA review. 13 A number of the unit designations in this table constitute trade secret and/or confidential proprietary

information as defined under the Pennsylvania Right to Know Law, and hence the full table is being

provided in Appendix D. 14 The Pennsylvania Code is an official publication of the Commonwealth of Pennsylvania. Title 25.

Environmental Protection; Subpart C. Protection of Natural Resources; Article III. Air Resources;

Chapters 121 – 145.



4-2

Table 4-1. Summary of Regulatory Applicability

Applicable Regulation Regulatory Applicability Project Subject Unit &

Pollutants

Chapter 121. General provisions

25 Pa. Code §121.1-121.10

Provides for the control and prevention of air pollution anywhere in this Commonwealth,

except as expressly excluded in the act or otherwise noted in this article. Entire Facility

Chapter 122. National Standards

of Performance for New

Stationary Sources

25 Pa. Code §122.1-122.3

Adopts NSPS regulations at 40 CFR Part promulgated by the United States

Environmental Protection Agency under the Clean Air Act (42 U.S.C.A. § § 7401—

7642), regulating the construction or modification of stationary sources.

See Table 5-2 for discussion of

applicable 40 CFR 60 – New

Source Performance Standards

Chapter 123. Standards for

Contaminants

25 Pa. Code §§123.1, 123.2,

123.11-123.12, 123.21-123.22,

123.31, 123.41, 123.46, 123.51

This chapter contains standards for sources of particulate matter, sulfur compounds,

odors, visible emissions, and nitrogen compounds. Additionally, this chapter contains

NOx allowance requirements.

See Table 4.2 below for

detailed description of Ch. 123

requirements and applicable

sources.

Chapter 124. National Emissions

Standards for Hazardous Air

Pollutants

25 Pa. Code §§124.1-124.3

Adopts National Emission Standards for Hazardous Air Pollutants promulgated by the

United States Environmental Protection Agency under the Federal Clean Air Act (42

U.S.C.A. § 7412).

See Table 5-2 at 40 CFR 61 &

63 National Emissions

Standards for Hazardous Air

Pollutants

Chapter 127. Construction,

Modification, Reactivation and

Operation of Sources

Subchapter A. General

25 Pa. Code §127.1-127.3

General declaration of purposes.

Designed to insure that new sources conform to the applicable standards of this article

and that they do not result in producing ambient air contaminant concentrations in excess

of those specified in Chapter 131 (relating to ambient air quality standards).

New sources shall control the emission of air pollutants to the maximum extent,

consistent with the best available technology as determined by the Department as of the

date of issuance of the plan approval for the new source.

Entire Facility - applies to

Criteria and Hazardous Air

Pollutants



4-3


Pollutants

25 Pa. Code §127.3 Provides for operational flexibility, with cross-reference to other provisions Entire facility




Subchapter B. Plan Approval

Requirements

25 Pa. Code §127.11-127.52

Requires Department approval of the construction or modification of an air

contamination source, the reactivation of an air contamination source after the source has

been out of operation or production for 1 year or more, or the installation of an air

cleaning device on an air contamination source, unless the construction, modification,

reactivation or installation has been approved by the Department.

Entire Facility

25 Pa. Code §127.12(a)

Show that source to be equipped with reasonable and adequate facilities to monitor and

record emissions of air contaminants

Emissions from new source must be minimum attainable through use of the best

available technology (PaBAT)

Show source will comply with applicable EPA requirements

Show that source and air cleaning devises will be operated and maintained in accordance

with good air pollution control practices

All emission sources at facility




Subchapter B. Plan Approval

Requirements

25 Pa. Code §127.35

Incorporates by reference performance or emission standards promulgated under section

112 of the Clean Air Act (42 U.S.C.A. § 7412) at 40 CFR Part 63 (relating to National

Emission Standards for Hazardous Air Pollutants for Source Categories). If the

Administrator of the EPA has not promulgated a standard to control the emissions of

HAPs for a category or subcategory of major stationary sources Clean Air Act §112(c),

the Department will establish a performance or emission standard on a case-by-case

basis for individual sources or a category of sources for those major stationary sources.

The Department has the authority to require, in the plan approval, reasonable monitoring,

recordkeeping and reporting requirements for sources which emit hazardous air

pollutants.

Combustion Turbines - HAP,

Part 63, Subpart YYYY

(stayed)



4-4


Pollutants




Subchapter D. Prevention of

Significant Deterioration of Air

Quality

25 Pa. Code §§127.81-127.83

Adopts by cross-reference Prevention of Significant Deterioration (PSD) requirements

promulgated by the USEPA under the Clean Air Act.

Entire Facility - CO, PM,

PM10, and GHGs




Subchapter E. New Source

Review

25 Pa. Code §§127.201-218

Provides for regulation of construction or modification of an air contamination facility in

a nonattainment area or have an impact on a nonattainment area, imposing LAER and

offset requirements

Entire Facility - NOx, VOC,

PM2.5

25 Pa. Code §127.205(5)

Requires that a major new facility provide an analysis of alternative sites, sizes,

production processes and environmental control techniques, which demonstrates that the

benefits of the proposed facility significantly outweigh the environmental and social

costs imposed within this Commonwealth as a result of its location, construction or

modification.

Entire facility. See

Appendix E for the related

analysis.




Subchapter G. Title V Operating

Permits

25 Pa. Code §127.502(a)

Operating permit requirements for major sources (Title V facilities), requiring that

applicable requirements for stationary air contamination sources in the Title V facility be

included in the operating permit.

Entire Facility - All regulated

pollutants




Subchapter J. General Conformity

25 Pa. Code §§127.801-127.802

Adopts the general conformity rule promulgated by the United States Environmental

Protection Agency under section 176(c) of the Clean Air Act (42 U.S.C.A. § 7506(c))

and the regulations codified at 40 CFR Part 93, Subpart B (relating to determining

uniformity of general Federal actions to state or Federal implementation plans), with

respect to the conformity of general Federal actions to the Commonwealth’s State

Implementation Plan.

Entire Facility - All regulated

pollutants



4-5


Pollutants


Sources

25 Pa. Code §§129.51, 129.56,

129.57, 129.65, 129.71, 129.91-

129.95

This chapter contains emission standards for VOCs and NOx for numerous emission

sources including storage tanks, ethylene production, SOCMI manufacturing, and

combustion units.

VOCs and NOx from: Storage

tanks, ethylene production,

SOCMI manufacturing, and

combustion units


Sources

25 Pa. Code §129.56. Storage

tanks greater than 40,000 gallons

capacity containing VOCs.

No person may permit the placing, storing or holding in a stationary tank, reservoir or

other container with a capacity greater than 40,000 gallons of volatile organic

compounds with a vapor pressure greater than 1.5 psia (10.5 kilopascals) under actual

storage conditions unless the tank, reservoir or other container is a pressure tank capable

of maintaining working pressures sufficient at all times to prevent vapor or gas loss to

the atmosphere or is designed and equipped with an appropriate device.

Facility Storage Tanks storing

VOCs


Sources

25 Pa. Code §129.57. Storage

tanks less than or equal to 40,000

gallons capacity containing

VOCs.

Applies to above ground stationary storage tanks with a capacity equal to or greater than

2,000 gallons that contain volatile organic compounds with vapor pressure greater than

1.5 psia (10.5 kilopascals) under actual storage conditions. Petroleum liquid storage

vessels that are used to store produced crude oil and condensate prior to lease custody

transfer are exempt from the requirements.

Facility Storage Tanks storing

VOCs


Sources

25 Pa. Code §129.65. Ethylene

production plants.

Waste gas stream from an ethylene production plant or facility must be properly burned

at no less than 1,300°F for at least 0.3 seconds; except that no person may permit the

emission of volatile organic compounds in gaseous form into the outdoor atmosphere

from a vapor blowdown system unless these gases are burned by smokeless flares.

Ethane Cracker/Fractionation-

VOCs


Sources

25 Pa. Code §129.71. Synthetic

organic chemical an d polymer

manufacturing—fugitive sources

Requires certain design, equipment and leak detection program requirements, applicable

to surface active agent manufacturing facilities subject to § 129.72 and to a facility with

design capability to manufacture 1,000 tons per year or more of one or a combination of

the following: (1) Synthetic organic chemicals listed in 40 CFR 60.489 (relating to list of

chemicals provided by affected facilities). (2) Methyl tert-butyl ether. (3) Polyethylene.

(4) Polypropylene. (5) Polystyrene.

VOCs from

Ethane Cracking/Fractionation

Polyethylene manufacturing


Sources

25 Pa. Code §§129. 91-129.95.

Stationary Sources of NOx and

VOCs

Establishes reasonably available control technology (RACT) requirements for major

NOx emitting facilities or major VOC emitting facilities for which no RACT

requirement has been established.

NOx & VOC emissions from

combustion sources,

equipment leaks, wastewater

treating plant, transfer

operations, and process vents.



4-6


Pollutants

Chapter 131. Ambient Air Quality

Standards

25 Pa. Code §§ 131.1 - 131.3

Establishes the maximum ambient air concentrations of air contaminants. Adopts by

cross-reference National Ambient Air Quality Standards. Adopts additional ambient

standards for settled particulate, beryllium, fluorides, and hydrogen sulfide.

Entire Facility - CO, SO2,

NO2, PM, PM10, PM2.5, Ozone,

lead, beryllium, fluorides, and

hydrogen sulfide

Chapter 135. Reporting of

Sources

25 Pa. Code §§ 135.1-135.5

Provides for recordkeeping and submission of emission statements from most stationary

sources.

Entire Facility - all regulated

pollutants

Chapter 137. Air Pollution

Episodes

25 Pa. Code §137.1-137.14

Provides for Department determination of air pollution episodes and requires preparation

and submission of standby plans for certain industries including chemical and allied

products industries, located in counties designated by PaDEP.

Entire Facility - CO, SO2,

NO2, PM10 and Ozone

Chapter 139. Sampling and

Testing

25 Pa. Code §§139.1-139.101

Establishes the sampling and testing methods and procedures, monitoring duties for

certain sources, and requirements for source monitoring for stationary sources.

Entire Facility - all regulated

pollutants

Chapter 145. Interstate Pollution

Transport Reduction

25 Pa. Code §145.8

Establishes provisions for the NOx Budget Trading Program as a means of mitigating the

interstate transport of ozone and nitrogen oxides, an ozone precursor. § 145.8 transitions

the state program over to CAIR as of 2010.

NOx: Cogen Units

Chapter 145. CAIR NOx and

SO2 Trading Programs

25 Pa. Code § 145.201

Incorporates by reference the CAIR NOx Annual Trading Program and CAIR NOx

Ozone Season Trading Program. The subchapter also establishes general provisions and

the applicability, allowance and supplemental monitoring, recordkeeping and reporting

provisions.

SO2: Cogen Units

NOx: Cogen Units



4-7

prohibition of air pollution, responsibility to comply with other provisions of Title 25,

and prohibiting the circumvention of Article III rules through the use of a device (e.g.,

stack height) which would otherwise be in violation of Article III rules. The proposed

Project will comply with these provisions by obtaining all applicable permits, and

complying with the requirements of these permits.

4.1.2 25 Pa. Code Ch. 122 National Standards of Performance for New Stationary Sources

This chapter adopts NSPSs (40 CFR Part) promulgated by the United States

Environmental Protection Agency under the Clean Air Act (42 U.S.C.A. § § 7401-7642),

regulating the construction or modification of stationary sources. The standards are

adopted to make them independently enforceable by the Department implementing the

delegation of Federal authority under section 111(c) of the Federal Clean Air Act

(42 U.S.C.A. § 7411). The applicability of these standards is addressed in Section 4.2.

4.1.3 25 Pa. Code Ch. 123. Standards for Contaminants

This chapter contains standards for sources of particulate matter, sulfur compounds,

odors, visible emissions, nitrogen compounds, and NOx allowance requirements. As

presented in Table 4-2, sources that are specifically affected include: fugitive particulate

matter sources, combustion units, incinerators, and processes vents. The Project’s

emission sources that are affected by this chapter include the incinerators, flares,

furnaces, combustion turbines, process vents, and loading emissions. The proposed

Project will comply with the provisions in this chapter as presented in Table 4-2.

4.1.4 25 Pa. Code Ch. 124. National Emissions Standards for Hazardous Air Pollutants

This chapter adopts NESHAPs at 40 CFR Part 61 and 63 promulgated by the United

States Environmental Protection Agency under the Federal Clean Air Act (42 U.S.C.A. §

7412). The applicability of these standards is addressed in Section 4.2



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Table 4-2. Summary of Compliance with the Standards of Containment at 25 Pa.Code Ch. 123.

Standards for

Contaminants Affected Source(s) Regulatory Requirement Compliance

25 Pa Code § 123.1

Prohibition of certain

fugitive emissions

Fugitive sources of air

contaminants other than those

allowed in § 123.1 (i.e.,

construction activities, grading,

clearing of land, et. al).

Fugitive air emissions prohibited

except for certain listed sources and

emissions determined to be of minor

significance after appropriate

controls.

Emissions do not prevent or interfere

with attainment or maintenance of

ambient air quality standard.

Best management practices to be

followed for construction, demolition,

grading, paving and maintenance of

roads, and other activities.

Fugitive VOCs and particulate from

processes subject to controls, and are of

minor significance after controls.

Fugitives are included in the potential to

emit determination. Therefore the

impacts of fugitives with respect to air

pollution are considered in the New

Source Review. See Section 5.0

25 Pa Code § 123.2

Fugitive particulate

matter

All fugitive PM sources No fugitive particulate emissions

visible outside the property boundary

Fugitive PM emissions to be minimized

as presented in Section 5.0 to prevent

visibility outside the property boundary.

25 Pa Code § 123.11

PM - Combustion units Combustion Units

Emission limits on PM for various

sized units See Section 5.0

25 Pa Code § 123.12

PM – Incinerators Incinerators 0.1 grain/dscf @ 12% CO2

25 Pa Code § 123.13

PM – Processes

Processes except combustion

units and incinerators

Emission limit on PM by formula or

0.02 grains/dscf whichever is greater

25 Pa Code § 123.21

Sulfur Compound -

General

Combustion Units 500 ppmvd effluent gas limit

25 Pa Code § 123.22(d)

Sulfur Compound –

Combustion Units

Combustion Units Specific fuel dependent Lower Beaver

Valley limit on SO2

25 Pa Code § 123.31

Odor Emissions

Combustion Units, Process

Vents, Fugitives

No malodors detectable outside the

property boundary

Emissions will be minimized to avoid

detectable malodors outside the

property boundary

25 Pa Code § 123.41

Visible Emissions

Combustion Units, Fugitive

Sources of PM Visible emissions/opacity limitations

Visible emissions will be minimized as

presented in Section 5.0 to comply with



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Standards for

Contaminants Affected Source(s) Regulatory Requirement Compliance

opacity limits.

25 Pa Code § 123.46

Visible Emissions

Monitoring Requirements

Combustion Units Continuous opacity monitors Per 123.46(c), Shell will apply for an

exemption from this requirement

25 Pa Code § 123.51

Nitrogen Compound Combustion Units Continuous NOx monitoring See Section 5.0



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4.1.5 25 Pa. Code Ch. 127. Construction, Modification, Reactivation and Operation of Sources

This chapter contains the regulations applicable to construction, modification,

reactivation, and operation of applicable sources.

4.1.5.1 25 Pa. Code §§ 127.1 and 127.12 Best Available Technology

In stating the purpose of the Ch. 127 rules, Section 127.1 states the objective of

maintaining at existing levels in areas where the existing ambient air quality is better than

the applicable ambient air quality standards, and improving to achieve the applicable

ambient air quality standards in areas where the existing air quality is worse than the

applicable ambient air quality standards. The Ch. 127 rules require new sources conform

to the applicable standards and not result in producing ambient air contaminant

concentrations in excess of those specified in Chapter 131 (relating to ambient air quality

standards). These requirements are substantially addressed via PSD requirements.

Sections 127.1 and 127.12(a)(5) require that new sources control emission of air

pollutants to the maximum extent, consistent with the best available technology as

determined by the Department as of the date of issuance of the plan approval for the new

source. Shell will comply with the best available technology requirements where

applicable for all pollutants.

4.1.5.2 25 Pa. Code § 127.35 Maximum Achievable Control Technology Standards for Hazardous Air Pollutants (HAP)

Section 127.35 establishes the process that the Department will follow in establishing

maximum achievable control technology (MACT) standards in plan approvals.

Regulations promulgated under section 112 of the Clean Air Act (42 U.S.C.A. § 7412) at

40 CFR Part 63 are incorporated by reference into the plan approval program. These

standards regulate specific categories of stationary sources that emit or have the potential

to emit 10 tons per year of any HAP or 25 tons per year of any combination of HAP. As

presented in Table 1-1, HAP emissions from the proposed Project will exceed a



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combined 25 tons per year, rendering the Project a major source for HAP. NESHAP

standards applicable to the Project’s affected sources are presented in Section 4.2.2.

25 Pa. Code § 127.35(c) states that if the EPA has not promulgated a standard to control

emissions of hazardous air pollutants (HAP) from a category or subcategory of major

stationary sources under CAA Section 112 pursuant to the schedule established under

CAA Section 112(c), the Department will establish standards on a case-by-case basis as

required by section 112(g) of the CAA. These standards are to be incorporated into the

plan approval of each source within the category for which a MACT requirement has

been established. In essence, 25 Pa. Code §127.35(d) implements the Clean Air Act

Section 112(g) case-by-case MACT rule.

For the Project’s proposed natural gas-fired combustion turbines, EPA has promulgated a

MACT standard for stationary combustion turbines, (40 CFR 63 Subpart YYYY) which

would potentially regulate HAP emissions from these units. However, on April 7, 2004,

EPA published in the Federal Register a proposal to delist the gas-fired subcategory from

the source category list. On August 18, 2004, EPA published a final rule staying the

effectiveness of 40 CFR 63, Subpart YYYY for this subcategory of source. As a result, a

Case-by-Case MACT for this subcategory is not required because EPA did promulgate a

standard pursuant to the schedule established under section 112(c) of the Clean Air Act.

The now stayed provisions of Part 63 Subpart YYYY establish limits for

formaldehyde. Using the provisions of 25 Pa. Code § 127.12b, the formaldehyde limits

contained in Part 63 Subpart YYYY (91 ppmvd @ 15% O2) and the use of an oxidation

catalyst have been proposed for this Plan Approval application. As presented in Table 2

in Subpart YYYY of 40 CFR 63, for a stationary combustion turbine using an oxidation

catalyst, the owner/operator must maintain the 4-hour rolling average of the catalyst inlet

temperature within the range suggested by the catalyst manufacturer to demonstrate

continuous compliance with the emissions limit. These conditions also assure the proper

operation to meet the PaBAT provisions of 25 Pa. Code § 127.1 and § 127.12(a)(5).

Shell will comply with this requirement and other monitoring and recordkeeping

requirements associated with Part 63 Subpart YYYY as discussed in Section 4.2.3.



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4.1.5.3 25 Pa. Code § 127.83 Prevention of Significant Deterioration

Section 127.83 of the Pennsylvania air quality regulations adopts by reference the

Prevention of Significant Deterioration (PSD) requirements promulgated in 40 CFR 52

by the Administrator of the EPA under section 161 of the Clean Air Act (42 U.S.C.A. §

7471) in their entirety. In accordance with the PSD requirements, the proposed Project

belongs to a listed source category (chemical processing plant) and has potential

emissions of greater than 100 tons per year of a PSD regulated pollutant; thus, it is

subject to the PSD rules codified at 40 CFR 52.21. For a new source such as the

proposed Project, the source must estimate the potential to emit for the NSR pollutants

(CO, NO2/NOx, VOC, SO2, H2SO4, PM/PM10/PM2.5, and Pb) and CO2e. 15 If the

potential to emit for one or more NSR regulated pollutants is found to be significant

(greater than 100 tons per year) or the amount of CO2e emitted is greater than 100,000

tons per year and the amount of GHGs is greater than 100 tons per year, the source must

undergo PSD review, which includes applying Best Available Control Technology

(BACT), demonstrating compliance with air quality standards, assessing secondary

impacts, and undergoing public participation for each pollutant for which there is a

significant increase.

As documented in Section 1.0, the proposed Project constitutes a major new source under

PSD (emissions of at least one NSR regulated pollutant exceed the 100 tons per year

major source threshold), and the following pollutants have potential to emit greater than

their pollutant specific PSD significance thresholds: NO2, PM/PM10, CO, and GHG. As

such, project related emissions of these pollutants require PSD review. Shell will comply

with the requirements of this Part by documenting BACT analyses for each affected

emissions unit/pollutant combination, demonstrating compliance with air quality

standards, assessing secondary impacts, and undergoing public participation.

15 The Project will not emit quantities of the other NSR pollutants, which include hydrogen sulfide, total

reduced sulfur compounds, fluorides, and beryllium.



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4.1.5.4 25 Pa. Code § 127.201 New Source Review

Ch. 127, Subchapter E, (25 Pa. Code §§127.201-127.218) contains the nonattainment

NSR regulations incorporated into the Pennsylvania air quality regulations in accordance

with the federal requirements at 40 CFR §51.165. Nonattainment NSR applies to new

major sources or major modifications at existing major stationary sources for pollutants

where the area the source is located in is not in attainment with the National Ambient Air

Quality Standards (NAAQS). All nonattainment NSR programs must require (1) the

installation of the lowest achievable emission rate (LAER), (2) emission offsets, (3)

alternative sites evaluation, and (4) opportunity for public involvement.

Currently Beaver County, Pennsylvania is nonattainment for ozone, PM2.5, and SO2.

Ozone has defined precursors of VOC and NOx. PM2.5 has defined precursors of SO2

and NOx. As documented in Section 1.0, the proposed Project’s potential to emit is

greater than the major source threshold for NOx, VOC, and PM2.5. As a result, Shell will

comply with all the requirements listed above for obtaining a nonattainment NSR permit

for ozone (NOx and VOC) and PM2.5.

4.1.5.5 25 Pa. Code §127.205(5) Alternatives, Costs and Benefits Analysis

Pennsylvania air regulations, 25 Pa. Code §127.205(5), require that a major new or

modified facility provide an “analysis … of alternative sites, sizes, production processes

and environmental control techniques, which demonstrates that the benefits of the

proposed facility significantly outweigh the environmental and social costs imposed

within this Commonwealth as a result of its location, construction or modification.”

Appendix E of this application provides the required §127.205(5) analysis.

4.1.6 25 Pa. Code Ch.129. Standards for Sources

Chapter 129 contains regulations for specific sources and emissions units which emit

NOx and VOCs. The proposed Project will comply with the provisions in this chapter by

obtaining all applicable permits and complying with the requirements of these permits.



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4.1.6.1 25 Pa. Code § 129.14 Open burning operations

The proposed Project will be located in an area of Beaver County designated in § 121.1

as an air basin, which pursuant to 25 Pa. Code § 129.14, has a restriction on open

burning. Open burning is defined in 25 Pa. Code § 121.1 as a fire, the air contaminants

from which are emitted directly into the outdoor atmosphere and not directed thereto

through a flue. As part of the proposed Project, triethylaluminum (TEAL) and

triethylborane (TEB) will be used as cocatalysts in the polyethylene manufacturing

process. TEAL and TEB are highly pyrophoric, igniting immediately upon exposure to

air. During routine cocatalyst transfer and process upsets, the lines containing these

pyrophoric materials in nitrogen will be routed to a remote sand pit for safe, managed

destruction. These releases cannot be sent to the VOC Control System due to the oxygen

in the gases from other sources vented to the system.

Sending the TEAL and TEB vapors to the sand pit meets the exception to the open

burning ban in the air basin as it is a fire set to abate a fire hazard per § 129.14(c). Shell

requests the Department approve this exception. The sand pit will be fenced, weather-

protected, and accessed by authorized personnel only.

4.1.6.2 25 Pa. Code § 129.56. Storage tanks greater than 40,000 gallons capacity containing VOCs.

Section 129.56 requires that any stationary tank, reservoir or other container with a

capacity greater than 40,000 gallons used to store volatile organic compounds with a

vapor pressure greater than 1.5 psia (10.5 kilopascals) under actual storage conditions be

a pressure tank capable of maintaining working pressures sufficient at all times to prevent

vapor or gas loss to the atmosphere or be designed and equipped with an appropriate

device:

An external or an internal floating roof. This control equipment is not permitted if

the volatile organic compounds have a vapor pressure of 11 psia (76 kilopascals) or

greater under actual storage conditions.



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Vapor recovery system. A vapor recovery system, consisting of a vapor gathering

system capable of collecting the volatile organic compound vapors and gases

discharged and a vapor disposal system capable of processing such volatile organic

vapors and gases so as to prevent their emission to the atmosphere. Tank gauging

and sampling devices shall be gas-tight except when gauging or sampling is taking

place. The vapor recovery system shall be maintained in good working order and

recover at least 80% of the vapors emitted by such tank.

The Project will have a number of tanks containing volatile organic compounds with a

vapor pressure greater than 1.5 psia, such as 1-hexene, pentane, and gasoline. These

tanks will be equipped with controls that will, at a minimum, meet the requirements of

this section and meet lowest achievable emission rates (LAER) requirements.

4.1.6.3 25 Pa. Code § 129.57. Storage tanks less than or equal to 40,000 gallons capacity containing VOCs.

The provisions of this section apply to above ground stationary storage tanks with a

capacity equal to or greater than 2,000 gallons but less than 40,000 gallons, that contain

volatile organic compounds with vapor pressure greater than 1.5 psia (10.5 kilopascals)

under actual storage conditions. Storage tanks subject to this section must have pressure

relief valves which are maintained in good operating condition and which are set to

release at no less than 0.7 psig (4.8 kilopascals) of pressure or 0.3 psig (2.1 kilopascals)

of vacuum or the highest possible pressure and vacuum in accordance with state or local

fire codes or the National Fire Prevention Association guidelines or other national

consensus standards acceptable to the Department. Section 129.56(g) requirements also

apply to these smaller tanks. If the Project has any of these tanks, they will be equipped

with controls that at a minimum will meet the requirements of this section and will meet

LAER requirements.

4.1.6.4 25 Pa. Code § 129.65. Ethylene production plants.

Section 129.65 requires that waste gas streams from an ethylene production plant or

facility be properly burned at no less than 1,300°F for at least 0.3 seconds; except that



4-16

emission of volatile organic compounds in gaseous form into the outdoor atmosphere

from a vapor blowdown system may be burned by smokeless flares. The Project’s

Ethane Cracker and distillation section will be equipped with the above controls or

equivalent and will meet LAER requirements.

4.1.6.5 25 Pa. Code § 129.71. Synthetic organic chemical and polymer manufacturing—fugitive sources

This section applies to synthetic organic chemicals listed in 40 CFR 60.489, which

includes ethylene. As such, the Project will:

Install a second valve, blind flange, plug, cap or other equivalent sealing system

on open ended lines, except for safety pressure relief valves.

Develop and initiate a leak detection program including liquid leaks for pumps,

valves, compressors, vessels and safety pressure relief valves and a repair

program for these components that cause a hydrocarbon detection instrument

reading equal to or greater than 10,000 ppm.

The Project will comply with the above requirements and will have a more stringent leak

detection program as part of the LAER requirements.

4.1.6.6 25 Pa. Code § § 129.91-95. Stationary Sources of NOx and VOCs

This section requires the owner and operator of a major NOx or VOC emitting facility to

apply Reasonably Available Control Technology (RACT)16. This section applies to

facilities for which no RACT requirement has been established in § § 129.51, 129.52,

129.54 - 129.72, 129.81 and 129.82. The proposed Project will be a major source for

both NOx and VOC and the NOx and/or VOC-emitting sources with no existing RACT

requirement include: combustion sources, equipment leaks, the wastewater treating plant,

organic liquid transfer operations, and process vents and storage vessels. Given that

these sources are also subject to LAER for NOx and VOC, a case-by-case RACT analysis

is not required pursuant to the presumptive RACT emission limitations set forth in 25 Pa

16 RACT is lowest emission limit for VOCs or NOx that a particular source is capable of meeting by the

application of control technology that is reasonably available considering technological and economic

feasibility per 25 Pa. Code § 121.1



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Code § 129.93(c)(6). Sources that meet the LAER requirements and install, maintain,

and operate the source in accordance with manufacturing specifications satisfy the

presumptive RACT requirement. The proposed Project will comply with this provision

by complying with the proposed LAER limitations presented in Section 5.0.

4.1.7 25 Pa. Code Ch. 131. Ambient Air Quality Standards

This chapter establishes ambient air quality standards by incorporating by reference the

National Ambient Air Quality Standards (NAAQS), and by setting State Ambient Air

Quality Standards for settled particulate, beryllium, fluorides and hydrogen sulfide. The

NAAQS are applicable to the entire facility for the emissions of CO, SO2, NO2, PM,

PM10, PM2.5, ozone, and lead. For the PSD applicable pollutants, an air quality impacts

analysis demonstrating compliance with the NAAQS is included in Section 6.0.

Based on previous conversations with PaDEP, only significant sources of beryllium,

fluorides, and hydrogen sulfide, such as coal-fired emission sources, need to conduct an

analysis against the state standards. The Project is not expected to be a significant source

of beryllium, fluorides, or hydrogen sulfide based on the fuel to be combusted at the plant

(i.e., natural gas and low sulfur diesel). As a result, these pollutants are not included in

the ambient impacts analysis. Ambient impacts of settled particulate will be assessed as

part of the PM10/PM2.5 NAAQS modeling analysis.

4.1.8 25 Pa. Code Ch. 135. Reporting of Sources

Ch. 135 provides a means of obtaining data required to evaluate the effectiveness of

regulations, identify available or potential emission offsets, and maintain an accurate

inventory of air contaminant emissions for air quality assessment and planning activities.

It requires most stationary sources to submit annual emission inventories. Shell will

comply with the requirements of this chapter initially by providing emission factors and

emissions calculations as part of this application, and thereafter, Shell will submit by

March 1 of each year a source emissions inventory report for the preceding calendar year.

The report shall include information for all previously reported sources, new sources

which were first operated during the preceding calendar year, and sources modified



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during the same period which were not previously reported. Shell will provide to the

Department source reports that contain sufficient information to enable the Department to

complete its emission inventory. Shell will provide the report information in the format

specified by the Department. As part of this report, Shell will provide the Department

with a statement showing the actual emissions of NOx and VOCs from that source for

each reporting period, a description of the method used to calculate the emissions, and the

time period over which the calculation is based. The statement will contain a certification

by a company officer or the plant manager that the information contained in the statement

is accurate.

Shell will maintain and make available upon request by the Department records,

including computerized records that may be necessary to comply with reporting and

emission statements. These may include records of production, fuel usage, maintenance

of production or pollution control equipment, or other information determined by the

Department to be necessary for identification and quantification of potential and actual

air contaminant emissions. If direct recordkeeping is not possible or practical, sufficient

records will be kept to provide the needed information by indirect means.

4.1.9 25 Pa. Code Ch. 137. Air Pollution Episodes

Ch. 137 provides for the Department to declare air pollution episodes to prevent the

excessive buildup of air pollutants during an episode. The Ch. 137 rules require that

particular industries, including chemical industry facilities, in designated counties prepare

standby plans for implementation in such episodes. Shell will develop standby plans and

will implement plans when requested by the Department.

4.1.10 25 Pa. Code Ch. 139. Sampling and Testing

This chapter contains provisions for:

Subchapter A. Sampling and Testing Methods and Procedures,

Subchapter B. Monitoring Duties of Certain Sources, and

Subchapter C. Requirements for Source Monitoring For Stationary Sources.



4-19

Shell will follow the methods and procedures contained in this chapter as laid out in the

Project’s permit, and as directed by the Department.

4.1.11 25 Pa. Code Ch. 145. Interstate Pollution Transport Reduction

Ch. 145 establishes a NOx Budget Trading Program as a means of mitigating the

interstate transport of ozone and nitrogen oxides, an ozone precursor. Subchapter 145.8

transitions the NOx Budget Trading Program over to the CAIR NOx and SO2 Trading

Program (40 CFR Part 97) starting May 1, 2010, and for each control period thereafter.

Subchapter 145.201 incorporates by reference the CAIR NOx Annual Trading Program

and CAIR NOx Ozone Season Trading Program as a means of mitigating the interstate

transport of fine particulates and NOx, and the CAIR SO2 Trading Program as a means of

mitigating the interstate transport of fine particulates and SO2.

The proposed Cogen units will each serve a generator with nameplate capacity of more

than 25 MWe supplying in any calendar year more than one-third of the unit's potential

electric output capacity or 219,000 MWh, whichever is greater, to a utility power

distribution system for sale.

Shell will obtain NOx and SO2 budget allowances for the Cogen Units from the CAIR

NOx and SO2 Trading Program.

4.2 Federal Regulations

The applicability of Federal regulations to the Project is presented by federal rule citation

below. Table 4-3 presents a summary of the applicable Federal regulations, and the

following subsections provide additional detail.

4.2.1 40 CFR Part: New Source Performance Standards

The New Source Performance Standards (NSPS) are codified at 40 CFR 60, and adopted

by reference under Chapter 122 of the Commonwealth of Pennsylvania.



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Table 4-3. Summary of Federal Regulatory Applicability

Applicable Regulation Regulatory Applicability Project Subject Unit & Pollutants

40 CFR Part – New Source Performance Standards

Subpart A: General Provisions, except 60.18 Facilities subject to subsequent subparts of Part 60

Subpart Kb - Tanks

Subpart VV - Equipment Leaks

Subpart VVa - Equipment Leaks

Subpart DDD - Polymer Manufacturing

Subpart NNN - Distillation Process Vents

Subpart RRR - Reactor Process Vents

Subpart YYY - Wastewater (stayed)

Subpart IIII - Diesel Engines

Subpart KKKK - Combustion turbine/duct burners

Subpart TTTT – GHGs for New Electric Utilities

Subpart A: 60.18 - Control Device Requirements

Applies to flare(s) used to routinely combust VOC

from Subparts Kb, VV, VVa, DDD, NNN, and

RRR equipment

Flare(s) used as control devices for VOCs from

new or modified equipment as defined in the NSPS

subparts Kb, VV, VVa, DDD, NNN, and RRR

Subpart Kb – Standards of Performance for

Volatile Organic Liquid Storage Vessels for

Which Construction, Reconstruction, or

Modification Commenced after July 23, 1984.

Subject to certain exceptions, applies to storage

vessels with a capacity greater than or equal to 75

cubic meters (m3) that is used to store volatile

organic liquids (VOL). Does not apply to storage

vessels with a capacity greater than or equal to

151 m3 storing a liquid with a maximum true

vapor pressure less than 3.5 kilopascals (kPa) or

with a capacity greater than or equal to 75 m3 but

less than 151 m3 storing a liquid with a maximum

true vapor pressure less than 15.0 kPa. Does not

apply to pressure vessels designed to operate in

excess of 204.9 kPa and without emissions to the

Control of VOCs from:

VOL Storage Tanks (> 151 m3 & > 3.5 kPa) or

(>75m3 but < 151m3 & > 15kPa)



4-21


atmosphere.

Subpart VV- Standards of Performance for

Equipment Leaks of VOC in the Synthetic

Organic Chemicals Manufacturing Industry for

which Construction, Reconstruction, or

Modification Commenced after January 5, 1981,

and on or Before November 7, 2006

Applies to new, modified, or reconstructed

components assembled and connected by pipes or

ducts to process raw materials and to produce, as

intermediate or final products, one or more of the

chemicals listed in 40 CFR §60.489. Process unit

includes any feed, intermediate and final product

storage vessels (except as specified in §60.482–

1(g)), product transfer racks, and connected ducts

and piping. A process unit includes all equipment

as defined in this subpart: pumps, compressors,

connectors, valves, etc.


Equipment leaks from polyethylene manufacturing

- Note that Subpart VV applies because Subpart

DDD refers to Subpart VV, not VVa.

Subpart VVa- Standards of Performance for

Equipment Leaks of VOC in the Synthetic

Organic Chemicals Manufacturing Industry for

Which Construction, Reconstruction, or

Modification Commenced After November 7,

2006


components assembled and connected by pipes or

ducts to process raw materials and to produce, as

intermediate or final products, one or more of the

chemicals listed in 40 CFR §60.489a. Process unit

includes any feed, intermediate and final product

storage vessels (except as specified in §60.482–

1a(g)), product transfer racks, and connected ducts

and piping. A process unit includes all equipment

as defined in this subpart: pumps, compressors,

connectors, valves, etc.


Equipment leaks from ethylene manufacturing

Equipment leaks from polyethylene

manufacturing - Note that Subpart VV applies

because Subpart DDD refers to Subpart VV, not

VVa.

Subpart DDD- Standards of Performance for

Volatile Organic Compound (VOC) Emissions

from the Polymer Manufacturing Industry.

(manufacture of polypropylene, polyethylene,

polystyrene, or polyethylene terephthalate)


components inclusive of all equipment used in the

manufacture of these polymers.


Polyethylene manufacturing facilities beginning

with raw materials preparation and ending with

product storage, and covering all emissions

emanating from such equipment. Also, VOCs

from equipment leaks and process vents.

Subpart NNN- Standards of Performance for

Volatile Organic Compound (VOC) Emissions Applies to new, modified, or reconstructed Control of VOCs from:



4-22


from Synthetic Organic (SOCMI) Chemical

Manufacturing Industry Distillation Operations.

SOCMI distillation units. Ethylene manufacturing - Distillation columns

De-C1, DeC2, and C2 splitter.

Polyethylene manufacturing - Subpart NNN

does not apply to any distillation unit that is

subject to the NSPS provisions of subpart DDD.

Subpart RRR- Standards of Performance for

Volatile Organic Compound (VOC) Emissions

from Synthetic Organic Chemical Manufacturing

Industry Reactor Processes


SOCMI reactor not discharging its vent stream

into a recovery system.


Ethylene manufacturing - Reactors

Polyethylene manufacturing - Subpart RRR does

not apply to any reactor unit that is subject to

NSPS provisions of subpart DDD.

Subpart YYY (proposed)- Standards of

Performance for Volatile Organic Compound

(VOC) Emissions from Synthetic Organic

Chemical Manufacturing Industry (SOCMI)

Wastewater

An affected facility is a designated chemical

process unit (CPU) in the synthetic organic

chemical manufacturing industry which

commences or commenced construction,

reconstruction or modification after September 12,

1994. An affected facility that does not generate a

process wastewater stream, a maintenance

wastewater stream, or an aqueous in-process

stream, is not subject to the control requirements

of this subpart.

Never promulgated

Subpart IIII - Standards of Performance for

Stationary Compression Ignition Internal

Combustion Engines

Standards of Performance for emissions of NOx,

VOC, CO, and PM from Stationary Compression

Ignition Internal Combustion Engines

Control of NOx, NMHC, CO, and PM from:

Emergency diesel firewater pump engines,

emergency diesel electric generators, and any

miscellaneous diesel engine driven equipment.

Subpart KKKK- Standards of Performance for

Stationary Combustion Turbines

Standards of Performance for Stationary

Combustion Turbines with and without duct

burners for emissions of NOx and SO2

Control of NOx and SO2 from:

Combustion turbines and duct burners

(Cogeneration Units)



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Subpart TTTT- Standards of Performance for

Greenhouse Gas Emissions for New Stationary

Sources: Electric Utility Generating Units

(proposed)

Standards of Performance for GHG emissions

from Electric Utility Generating Units with a

design heat input to the turbine engine greater

than 73 MW (250 MMBtu/h), combusting natural

gas supplying one-third or more of its potential

electric output and more than 219,000 MWh net-

electrical output to a utility distribution system.

Control of GHG emissions from:

New electric utility generating units as defined in

NSPS subpart TTTT

40 CFR Part 61 – National Emission Standards for Hazardous Air Pollutants

Subpart A – General Provisions

The general provisions include list of pollutants,

definitions, construction and modification

approvals, notification, reporting, and monitoring

requirements.

Control of benzene emissions from:

Equipment leaks as defined in NESHAP

subparts J and V

Benzene waste operations as defined in

NESHAP subpart FF

Subpart J – National Emission Standard for

Equipment Leaks (Fugitive Emission Sources) of

Benzene

The provisions of this subpart apply to each of the

following sources that are intended to operate in

benzene service: pumps, compressors, pressure

relief devices, sampling connection systems,

open-ended valves or lines, valves, connectors,

surge control vessels, bottoms receivers, and

control devices or systems required by this

subpart.


Equipment leaks as defined in NESHAP Subpart J



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Subpart V – National Emission Standard for

Equipment Leaks (Fugitive Emission Sources)

Applies to each of the following sources that are

intended to operate in volatile hazardous air

pollutant (VHAP) service: pumps, compressors,

pressure relief devices, sampling connection

systems, open-ended valves or lines, valves,

connectors, surge control vessels, bottoms

receivers, and control devices or systems required

by this subpart.


Equipment leaks as referenced by NESHAP

subpart J

Subpart FF – National Emissions Standards for

Benzene Waste Operations

Applies to chemical manufacturing plants where

the total annual benzene quantity from facility waste is the sum of the annual benzene quantity for each waste stream at the facility that has a flow-weighted annual average water content greater than 10 percent or that is mixed with water, or other wastes, at any time and the mixture has an annual average water content greater than 10 percent.

The total annual benzene quantity from facility

waste is greater than 10 Mg/yr (11 tons per year)

for the facility to be subject to 40 CFR §61.342(c)

through (h). If not, then testing, recordkeeping

and reporting are required to demonstrate

exemption from the Subpart FF control

requirements.


Benzene waste operations

It is not anticipated that the facility will have a

total annual benzene quantity in the facility waste

equal or greater than 10 mega grams per year (11

tons per year).

40 CFR Part 63 - National Emission Standards for Hazardous Air Pollutants for Source Categories

Subpart A – General Provisions

Facilities subject to subsequent subparts of 40

CFR Part 63; Flares used to routinely combust

HAP from 40 CFR Part 63-affected equipment

Control of HAP emissions from:

Ethylene manufacturing - NESHAP subparts SS,

UU, WW, XX, YY

Miscellaneous Organic NESHAP manufacturing

– NESHAP subpart FFFF

Combustion Turbines – NESHAP subpart



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YYYY- (stayed for natural gas-fired turbines)

Engines – NESHAP subpart ZZZZ

Subpart SS - National Emission Standards for

Closed Vent Systems, Control Devices, Recovery

Devices and Routing to a Fuel Gas System or a

Process

Applies when another subpart references the use

of this subpart for such air emission control (e.g.,

Subpart YY).

Includes requirements for closed vent systems,

control devices and routing of air emissions to a

fuel gas system or process.


Ethylene manufacturing - Closed vent systems,

control devices and routing of air emissions to a

fuel gas system or a process

Subpart UU - National Emission Standards for

Equipment Leaks

Applies to the control of air emissions from equipment leaks for which another subpart references the use of this subpart for such air emission control (e.g., Subpart YY).

Applies to pumps, compressors, agitators, pressure relief devices, sampling connection systems, open-ended valves or lines, valves, connectors, instrumentation systems, and closed vent systems and control devices used to meet the requirements of this subpart.


Ethylene manufacturing - Equipment leaks

Subpart WW - National Emission Standards for

Storage Vessels

Applies to the control of air emissions from storage vessels for which another subpart references the use of this subpart for such air emission control (e.g., Subpart YY).


Ethylene manufacturing - Storage vessels

Subpart XX - National Emission Standards for

Ethylene Manufacturing Process Units: Heat

Exchange Systems and Waste Operations

Establishes requirements for controlling emissions of hazardous air pollutants (HAP) from heat exchange systems and waste streams at new and existing ethylene production units.


Ethylene manufacturing - Heat exchange systems

and waste operations



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Subpart YY – National Emission Standards for

Hazardous Air Pollutants for Source Categories:

Generic Maximum Achievable Control

Technology Standards

Provides for the control of HAP emissions from

the following emission points: storage vessels,

process vents, transfer racks, equipment leaks,

waste streams, and other (heat exchange systems

for ethylene production)


Ethylene manufacturing - Storage vessels, process

vents, transfer racks, equipment leaks, waste

streams, and heat exchange systems

Subpart FFFF – National Emission Standards for

Hazardous Air Pollutants: Miscellaneous Organic

Chemical Manufacturing

Provides for the control of HAP emissions from

the following emission points: continuous process

vents, batch process vents, storage tanks, transfer

racks, equipment leaks, waste streams, and heat

exchange systems in miscellaneous organic

chemical manufacturing


Polyethylene manufacturing - storage tanks,

process vents, transfer racks, equipment leaks,

waste streams, and heat exchange systems

Subpart YYYY - National Emission Standards for

Hazardous Air Pollutants for Stationary

Combustion Turbines

Establishes national emission limitations and

operating limitations for hazardous air pollutants

(HAP) emissions from stationary combustion

turbines located at major sources of HAP

emissions, and requirements to demonstrate initial

and continuous compliance with the emission and

operating limitations.

The HAP standard required by this subpart for

natural gas-fired combustion turbines is currently

stayed.

Subpart ZZZZ - National Emission Standards for

Hazardous Air Pollutants for Stationary

Reciprocating Internal Combustion Engines

Establishes national emission limitations and

operating limitations for hazardous air pollutants

(HAP) emitted from stationary reciprocating

internal combustion engines (RICE) located at

major and area sources of HAP emissions. This

subpart also establishes requirements to

demonstrate initial and continuous compliance

with the emission limitations and operating

limitations.


Emergency diesel firewater pump engines,

emergency diesel electric generators, and any

miscellaneous diesel engine driven equipment.



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OTHER 40 CFR REGLATIONS

40 CFR Part 64: Compliance Assurance

Monitoring

Applicable to any pollutant specific emissions unit

with an add-on control device, that has the

potential to emit, before controls, more than 100

tpy of indicated pollutant, with the exception of

control devices that meet certain exemptions

The proposed facility’s Compliance Assurance

Monitoring Plan for this project must be submitted

as part of an application for a Title V permit.

40 CFR Part 68: Chemical Accident Prevention

Provisions

Mandates that facilities with more than a

threshold quantity of a regulated substance in a

single process must develop a Risk Management

Program that includes a hazard assessment, an

accident prevention program and an emergency

response program

Ethylene manufacturing, polyethylene units, tanks,

and pressure vessels

40 CFR Part 72: Permits Regulation

40 CFR Part 73: Sulfur Dioxide Allowance

System

40 CFR Part 74: Sulfur Dioxide Opt-Ins

40 CFR Part 75: Continuous Emissions

Monitoring

40 CFR Part 76: Acid Rain Nitrogen Oxides

Emissions Reduction Program

These parts pertain to the Acid Rain Program.

Part 72 is the permitting requirements, Part 73 is

the SO2 allowance system, Part 74 is the SO2 Op-

Ins system, Part and Part 75 contains the

continuous monitoring requirements, and Part 76

is the NOx emissions reduction program.

Cogen- Parts 72, 73, and 75

Part 74 and 76 are not applicable.

40 CFR Part 82: Protection of Stratospheric

Ozone

Subpart F- Recycling and Emissions Reduction

The purpose of this subpart is to reduce emissions

of class I and class II refrigerants and their

substitutes to the lowest achievable level by

maximizing the recapture and recycling of such

refrigerants during the service, maintenance,

repair, and disposal of appliances and restricting

the sale of refrigerants consisting in whole or in

part of a class I and class II ozone depleting

substances (ODS) in accordance with Title VI of

the Clean Air Act

Refrigerant equipment leaks where ozone

depleting substances are employed



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40 CFR Part 98: Mandatory Greenhouse Gas

Reporting

Mandatory reporting of greenhouse gases (GHG)

from sources that in general emit 25,000 metric

tons or more of carbon dioxide equivalent per year

in the United States.

Combustion sources emitting CO2, CH4 and

N2O

Equipment leaks of CH4

Equipment leaks of SF6



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4.2.1.1 Part 60, Subpart A, General Provisions:

The NSPS general provisions in Subpart A are applicable to facilities subject to any

standard promulgated under Part 60. The Project’s new facilities will be subject to NSPS

Subparts Kb, VV, VVa, DDD, NNN, RRR, YYY (proposed), IIII, KKKK, and TTTT

(proposed). Therefore, some of the provisions of Subpart A are applicable to the Project.

In general, Subpart A provisions specify performance test, performance evaluation

(monitoring systems), notification, recordkeeping, reporting, and control device

requirements for affected facilities.

The NSPS emission control devices will comply with 40 CFR § 60.11(d), which requires

a facility to maintain and operate any affected facility including associated air pollution

equipment in a manner consistent with good air pollution control practice for minimizing

emissions. Additionally, any flares used as a VOC control devices under Subparts Kb,

VV, VVa, DDD, NNN, and RRR will comply with the applicable control device

requirements in 40 CFR §60.18.

4.2.1.2 Subpart Kb - Standards of Performance for Volatile Organic Liquid Storage Vessels for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

Subpart Kb applies is each storage vessel with a capacity greater than or equal to 75 cubic

meters (m3) that is used to store volatile organic liquids (VOL) for which construction,

reconstruction, or modification is commenced after July 23, 1984. This subpart does not

apply to storage vessels with a capacity greater than or equal to 151 m3 storing a liquid

with a maximum true vapor pressure less than 3.5 kilopascals (kPa) or with a capacity

greater than or equal to 75 m3 but less than 151 m3 storing a liquid with a maximum true

vapor pressure less than 15.0 kPa. This subpart also does not apply to pressure vessels

designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.

The two hexene storage tanks are affected tanks because their storage volume exceeds

151 m3 and the storage vapor pressure exceeds 3.5 kPa. As such, these tanks will be

equipped with a fixed roof in combination with an internal floating roof, or a closed vent

system and control device, or a system equivalent to those described in paragraphs (a)(1)

or (a)(3) as provided in § 60.114b. The tanks presented in Table 4-4 are not subject to the



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Table 4-4. Tanks Not Subject to Control Under NSPS Subpart Kb

Service Tank/Vessel Description Capacity

(m3)

Reason Not

Affected 2

Ethylene Spherical Pressure Vessel 7,238 PV

Ethylene Full Containment-

Refrigerated 30,000 VP

C3+(propane and heavier

hydrocarbons) Sphere 2,300 PV

Butene Spheres 1,200 PV

Isopentane Bullet 600 PV

Isobutane Bullet 200 PV

C3+ Refrigerant Bullet 300 PV

Pyrolysis Tar Cone Roof/Heat Coil 130 VP

Light Gasoline Storage Tank (IFR) 650 NESHAP YY

Recovered Oil Storage Tank (IFR) 90 VP

Equalization Wastewater Tank (IFR) 2,810 NVOLS

Biotreater Aeration Tank (Open Top) 5,650 NVOLS

Secondary Clarifier Tank (Open Top) 1,650 NVOLS

Biosludge Cone Roof Tank 50 NVOLS Sand Filter Clarifier

Backwash Cone Roof Tank 160 NVOLS

Spent Caustic Tank (IFR) 900/8,630 1 NESHAP YY

Aqueous Ammonia Pressure Vessel 91/114 PV

Caustic Cone Roof 300 VP

Generator Diesel Fixed Roof 38 S

Fire Pump Diesel Fixed Roof 7 S

Locomotive Diesel Fixed Roof 38 S

Sulfuric Acid Cone Roof Tank/N2 Blanket 150 NVOLS

DMDS Pressure Vessel 26 S

Demin Water Cone Roof Tank 4,100 NVOLS

SAC Resin Tank (Open Top) 18 S

WBA and SBA Resin Tank (Open Top) 15 S

Process Condensate Cone Roof Tank 3,120 NVOLS Surface Condensers

Condensate Cone Roof Tank 10,670 NVOLS

Primary Raw Water Clarifier Tank (Open Top) 5,080 NVOLS

Clearwells Tank (Open Top) 300 NVOLS

Raw Water (RW) Tank (Open Top) 150 NVOLS

Reclaimed Cone Roof Tank 520 NVOLS

Filtered Cone Roof Tank 13,650 NVOLS

Potable Cone Roof Tank 90 NVOLS 1. Two spent caustic scenarios are being considered.

2. S- size, VP- vapor pressure, PV- pressure vessel, NVOLS- not in VOL service



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control requirements of 40 CFR 60 Subpart Kb either due to size or vapor pressure, are

pressure vessels, are not in VOL service, or are subject to 40 CFR 63 Subpart YY.

4.2.1.3 Subpart VV - Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry (SOCMI) for which Construction, Reconstruction, or Modification Commenced After January 5, 1981, and on or Before November 7, 2006

Subpart VV is applicable to the polyethylene units as specifically referenced by 40 CFR

60 Subpart DDD, where the polyethylene units process raw materials to produce, as

intermediate or final products, one or more of the chemicals listed in §60.489. For the

purpose of this subpart, process unit includes any feed, intermediate and final product

storage vessels (except as specified in §60.482–1(g)), product transfer racks, and

connected ducts and piping. For the purpose of this subpart, a process unit includes all

equipment including each pump, compressor, pressure relief device, sampling connection

system, open-ended valve or line, valve, and flange or other connector in VOC service,

and any devices or systems required by this subpart.

Shell will demonstrate compliance with the requirements of §§60.482–1 through 60.482–

10 or §60.480(e) for all equipment within 180 days of initial startup. Compliance with

§§60.482–1 to 60.482–10 will be determined by review of records and reports, review of

performance test results, and inspection using the methods and procedures specified in

§60.485. Equipment that is in vacuum service is excluded from the requirements of

§§60.482–2 to 60.482–10 if it is identified as required in §60.486(e)(5). Equipment that

is in VOC service less than 300 hrs/yr is excluded from the requirements of §§60.482–2

through 60.482–10 if it is identified as required in §60.486(e)(6) and it meets any of the

conditions specified in paragraphs (e)(1) through (3) of §60.486. Shell may request a

determination of equivalent means of emission limitation to the requirements of

§§60.482–2, 60.482–3, 60.480-4, 60.482–5, 60.482–6, 60.482–7, 60.482–8, and 60.482–

10 as provided in §60.484 in order to put all of the facility equipment on the most

stringent equipment leak requirements to demonstrate LAER.



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4.2.1.4 Subpart VVa - Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry (SOCMI) for which Construction, Reconstruction, or Modification Commenced After November 7, 2006

This subpart applies to new, modified, or reconstructed components assembled and

connected by pipes or ducts to process raw materials and to produce, as intermediate or

final products, one or more of the chemicals listed in §60.489a. For the purpose of this

subpart, process unit includes any feed, intermediate and final product storage vessels

(except as specified in §60.482–1a(g)), product transfer racks, and connected ducts and

piping. A process unit includes all equipment as defined in this subpart: pumps,

compressors, connectors, valves, etc.

Shell will demonstrate compliance with the requirements of §§60.482–1a through

60.482–11a or §60.480a(e) for all equipment within 180 days of initial startup.

Compliance with §§60.482–1a to 60.482–11a will be determined by review of records

and reports, review of performance test results, and inspection using the methods and

procedures specified in §60.485a. Equipment that is in vacuum service is excluded from

the requirements of §§60.482–2a to 60.482–11a if it is identified as required in

§60.486a(e)(5). Equipment that is in VOC service less than 300 hrs/yr is excluded from

the requirements of §§60.482–2a through 60.482–11a if it is identified as required in

§60.486a(e)(6) and it meets any of the conditions specified in paragraphs (e)(1) through

(3) of §60.486a. Shell may request a determination of equivalent means of emission

limitation to the requirements of §§60.482–2a, 60.482–3a, 60/480-4a, 60.482–5a,

60.482–6a, 60.482–7a, 60.482–8a, 60.482-10a and 60.482–11a as provided in §60.484a

in order to put all of the facility equipment on the most stringent equipment leak

requirements, to demonstrate LAER.

4.2.1.5 Subpart DDD - Standards of Performance for Volatile Organic Compound (VOC) Emissions from the Polymer Manufacturing Industry.

This subpart applies to new, modified, or reconstructed components inclusive of all

equipment used in the Polymer Manufacturing Industry (manufacture of polypropylene,

polyethylene, polystyrene, or polyethylene terephthalate). For the proposed polyethylene



4-33

manufacturing plants, the components include raw materials preparation, polymerization

reaction, material recovery, product finishing, and end with product storage. This subpart

addresses control of VOCs from continuous and intermittent process vents, and from

equipment leaks. Shell will comply with the standards specified under §60.562–1 with

one or more of the following control devices: incinerator, boiler, process heater, flare,

absorber, condenser, or carbon adsorber or if by other means will provide to the

Administrator information describing the operation of the control device and the process

parameter(s) which would indicate proper operation and maintenance of the device. Shell

will also comply with the equipment leak provisions of under § 60.562-2, which

references Subpart VV, or a more stringent leak detection program resulting from the

LAER analysis.

4.2.1.6 Subpart NNN - Standards of Performance for Volatile Organic Compound (VOC) Emissions from SOCMI Distillation Operations.

This subpart applies to new, modified, or reconstructed SOCMI distillation units. This

subpart in not applicable to polyethylene manufacturing because any distillation unit that

is subject to the provisions of Subpart DDD is not an affected facility. Subpart NNN

applies to the following sources or units whose construction, modification, or

reconstruction is commenced after December 30, 1983: (1) each distillation unit not

discharging its vent stream into a recovery system; (2) each combination of a distillation

unit and the recovery system into which its vent stream is discharged; and (3) each

combination of two or more distillation units and the common recovery system into

which their vent streams are discharged. Distillation unit means a device or vessel in which

distillation operations occur, including all associated internals (such as trays or packing) and accessories

(such as reboiler, condenser, vacuum pump, steam jet, etc.), plus any associated recovery system. To

comply with this subpart, Shell will either:

Reduce emissions of TOC (total organic carbon less methane and ethane) by

98 weight-percent, or to a TOC (less methane and ethane) concentration of

20 ppmv, on a dry basis corrected to 3 percent oxygen, whichever is less

stringent. If a boiler or process heater is used to comply with this paragraph, then

the vent stream shall be introduced into the flame zone of the boiler or process

heater; or

Combusting the emissions in a flare that meets the requirements of §60.18; or



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Maintaining a TRE index value greater than 1.0 without use of VOC emission

control devices.

TRE index value means a measure of the supplemental total resource requirement per

unit reduction of TOC associated with an individual distillation vent stream, based on

vent stream flow rate, emission rate of TOC net heating value, and corrosion properties

(whether or not the vent stream is halogenated), as quantified by the equation given under

§60.664(e).

4.2.1.7 Subpart RRR - Standards of Performance for Volatile Organic Compound (VOC) Emissions from SOCMI Reactors

This subpart applies to a new, modified, or reconstructed SOCMI reactor not discharging

its vent stream into a recovery system. This subpart is not applicable to polyethylene

manufacturing because Subpart RRR excludes any reactor vent that is subject to the

provisions of Subpart DDD. Subpart RRR applies to any of the following units or

sources whose construction, modification, or reconstruction commenced after

June 29, 1990: 1) each reactor process not discharging its vent stream into a recovery

system; 2) each combination of a reactor process and the recovery system into which its

vent stream is discharged; and 3) each combination of two or more reactor processes and

the common recovery system into which their vent streams are discharged. Reactor

processes are unit operations in which one or more chemicals, or reactants other than air,

are combined or decomposed in such a way that their molecular structures are altered and

one or more new organic compounds are formed.

The Project has a number of reactor systems including the ethane cracking furnaces and a

C2 hydrogenation unit. These reactor systems do not vent to the atmosphere under

normal operation. During startup, shutdown, or malfunction these reactor systems will

vent to the HP flare system.

Shell will comply with this subpart by either:

Reducing emissions of TOC (carbon less methane and ethane) by 98 weight-

percent, or to a TOC (less methane and ethane) concentration of 20 ppmv, on a

dry basis corrected to 3 percent oxygen, whichever is less stringent. If a boiler or



4-35

process heater is used to comply with this paragraph, then the vent stream shall be

introduced into the flame zone of the boiler or process heater; or

Combusting the emissions in a flare that meets the requirements of §60.18; or

Maintaining a TRE index value greater than 1.0 without use of a VOC emission

control device.

The TRE index value is a measure of the supplemental total resource requirement per unit

reduction of TOC associated with an individual distillation vent stream, based on vent

stream flow rate, emission rate of TOC net heating value, and corrosion properties

(whether or not the vent stream is halogenated), as quantified by the equation given under

§60.664(e).

4.2.1.8 Subpart YYY (Proposed) - Standards of Performance for Volatile Organic Compound (VOC) Emissions from SOCMI Wastewater

The provisions of this proposed regulation would apply to a designated chemical process

unit (CPU) in the synthetic organic chemical manufacturing industry, which commences

or commenced construction, reconstruction, or modification after September 12, 1994.

An affected facility that does not generate a process wastewater stream, a maintenance

wastewater stream, or an aqueous in-process stream, is not subject to the control

requirements of this subpart.

Subpart YYY was proposed but never promulgated. When promulgated, if applicable,

Shell will comply with the final promulgated subpart.

4.2.1.9 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

The provisions of this subpart are applicable to manufacturers, owners, and operators of

stationary compression ignition (CI) internal combustion engines (ICE). For the purposes

of this subpart, the date that construction commences is the date the engine is ordered by

the owner or operator. There are different emission standards and requirements

depending on the use of the CI ICE (non-emergency, emergency, and fire pump engines),

model year, and size as follows:

Table 1 to Subpart IIII of Part 60—Emission Standards for Stationary Pre-2007

Model Year Engines With a Displacement of <10 Liters per Cylinder and 2007-



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2010 Model Year Engines >2,237 KW (3,000 HP) and With a Displacement of

<10 Liters per Cylinder

Table 3 to Subpart IIII of Part 60—Certification Requirements for Stationary Fire

Pump Engines

Table 4 to Subpart IIII of Part 60—Emission Standards for Stationary Fire Pump

Engines

Shell will comply with the emission standards, fuel, certification, testing, monitoring,

recordkeeping and reporting requirements of Subpart IIII.

4.2.1.10 Subpart KKKK- Standards of Performance for Stationary Combustion Turbines

This subpart establishes emission standards and compliance schedules for the control of

emissions from stationary combustion turbines that commenced construction,

modification, or reconstruction after February 18, 2005, where the turbine has a heat

input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based

on the higher heating value of the fuel. Only heat input to the combustion turbine should

be included when determining whether or not this subpart is applicable. Any additional

heat input to the associated heat recovery steam generators (HRSG) from the duct burners

should not be included when determining peak heat input. However, this subpart does

apply to emissions from any associated HRSG and duct burners. Heat recovery steam

generators and duct burners regulated under this subpart are exempted from the

requirements of subparts Da, Db, and Dc of this part.

There are different emission standards and requirements depending on the turbine type,

heat input at peak load, and fuel (natural gas and other than natural gas). Table 1 to

Subpart KKKK of Part 60—Nitrogen Oxide Emission Limits for New Stationary

Combustion Turbines presents these limits.

The SO2 -related limits are:

SO2 emission limit of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-

hour (lb/MWh)) gross output; or

Do not burn any fuel which contains total potential sulfur emissions in excess of

26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input. If a turbine simultaneously fires

multiple fuels, each fuel must meet this requirement.



4-37

Shell will comply with the emission standards, testing, monitoring, recordkeeping, and

reporting requirements of Subpart KKKK.

4.2.1.11 Subpart TTTT- Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units (Proposed)

On January 8, 2014, US EPA re-proposed new source performance standards for

emissions of carbon dioxide (CO2) for new affected fossil fuel-fired electric utility

generating units (EGUs). The proposed requirements, which are strictly limited to new

sources, would require new fossil fuel-fired EGUs greater than 25 megawatt equivalent

(MWe) to meet the following output-based standards:

New combustion turbines with a heat input rating greater than 850 MMBtu/hr

would be required to meet a standard of 1,000 lb CO2/MWh, or

New combustion turbines with a heat input rating less than or equal to 850 MMBtu/hr

would be required to meet a standard of 1,100 lb CO2/MWhr.

Shell will comply with the final emission standards, testing, monitoring, recordkeeping,

and reporting requirements of Subpart TTTT for new combustion turbines with a heat

input rating less than or equal to 850 MMBtu/hr.

4.2.2 40 CFR Part 61: National Emissions Standards for Hazardous Air Pollutants (NESHAP)

4.2.2.1 40 CFR Part 61 – Subpart A, General Provisions:

The NESHAP general provisions in 40 CFR 61 Subpart A are applicable to stationary

sources with facilities subject to any standard promulgated under Part 61. Although

benzene will be produced by the ethylene manufacturing process, it is not anticipated that

the Project will be subject to any control requirements under NESHAP Subpart FF.

However, some of the provisions of 40 CFR 61 Subpart A will be applicable to the

Project with respect to testing, recordkeeping, and reporting. In general, 40 CFR 61

Subpart A provisions specify performance testing, performance evaluation (monitoring

systems), notification, recordkeeping, reporting, and control device requirements for

affected facilities.



4-38

4.2.2.2 40 CFR Part 61 - Subpart J, Equipment Leaks (Fugitive Emission Sources) of Benzene

40 CFR 61 Subpart J applies to each of the following sources that are intended to operate

in benzene service: pumps, compressors, pressure relief devices, sampling connection

systems, open-ended valves or lines, valves, connectors, surge control vessels, bottoms

receivers, and control devices or systems required by this subpart. In benzene service

means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is

at least 10 percent benzene by weight as determined according to the provisions of

§61.245(d). The provisions of §61.245(d) also specify how to determine that a piece of

equipment is not in benzene service.

The ethane cracker wash water system and gasoline distillation systems contain benzene

as a byproduct of ethylene manufacturing. Shell will comply with the equipment leak

provisions of this subpart by complying with the requirements of 40 CFR 61 Subpart V

of this part.

4.2.2.3 40 CFR Part 61 - Subpart V, Equipment Leaks (Fugitive Emission Sources)

Subpart V applies to each of the following sources that are intended to operate in volatile

hazardous air pollutant (VHAP) service: pumps, compressors, pressure relief devices,

sampling connection systems, open-ended valves or lines, valves, connectors, surge

control vessels, bottoms receivers, and control devices or systems required by this

subpart. In VHAP service means that a piece of equipment either contains or contacts a

fluid (liquid or gas) that is at least 10 percent by weight a volatile hazardous air pollutant

(VHAP) as determined according to the provisions of §61.245(d). The provisions of

§61.245(d) also specify how to determine that a piece of equipment is not in VHAP

service. For fugitive emitting components, monitoring of all VHAP containing

components is proposed as part of the VOC LAER (see Section 5.5).



4-39

4.2.2.4 40 CFR Part 61 - Subpart FF, Benzene Waste Operations NESHAP:

The requirements of 40 CFR 61 Subpart FF apply to chemical manufacturing plants, coke

by-product recovery plants, and petroleum refineries as well as hazardous waste

Treatment Storage and Disposal Facilities (TSDF) treating wastes from such facilities.

40 CFR 61 Subpart FF applies to the testing, recordkeeping, and reporting requirements

for benzene waste operations. The total annual benzene quantity from benzene waste

must be greater than 10 Mg/yr (11 tons per year) for the facility to be subject to 40 CFR

61.342(c) through (h). The total annual benzene quantity from facility waste is the sum

of the annual benzene quantity for each waste stream at the facility that has a flow-

weighted annual average water content greater than 10 percent or that is mixed with

water, or other wastes, at any time and the mixture has an annual average water content

greater than 10 percent. The benzene quantity in a waste stream is to be counted only

once without multiple counting if other waste streams are mixed with or generated from

the original waste stream.

Shell will comply with the provisions of 40 CFR 61 Subpart FF by being exempt because

Shell will design and operate the facility such that the total annual benzene quantity from

the facility waste will be less than 11 tons per year (i.e., 10 mega grams) for the facility.

Shell will comply with the 40 CFR 61 Subpart FF exemption by following the testing,

recordkeeping, and reporting requirements as follows:

If the total annual benzene quantity from facility waste is less than 10 Mg/yr (11 ton/yr)

but is equal to or greater than 1 Mg/yr (1.1 ton/yr), then the Project will:

1) Comply with the recordkeeping requirements of §61.356 and reporting

requirements of §61.357 of this subpart; and

2) Repeat the determination of total annual benzene quantity from facility waste at

least once per year and whenever there is a change in the process generating the

waste that could cause the total annual benzene quantity from facility waste to

increase to 10 Mg/yr (11 ton/yr) or more.

If the total annual benzene quantity from facility waste is less than 1 Mg/yr (1.1 ton/yr),

then the Project will:



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1) Comply with the recordkeeping requirements of §61.356 and reporting

requirements of §61.357 of this subpart; and

2) Repeat the determination of total annual benzene quantity from facility waste

whenever there is a change in the process generating the waste that could cause

the total annual benzene quantity from facility waste to increase to 1 Mg/yr

(1.1 ton/yr) or more.

4.2.3 40 CFR Part 63: National Emissions Standards for Hazardous Air Pollutants for Source Categories (NESHAP)

40 CFR Part 63 contains National Emission Standards for Hazardous Air Pollutants

(NESHAP) established pursuant to section 112 of the Act as amended November 15,

1990. These standards regulate specific categories of stationary sources that emit (or have

the potential to emit) one or more hazardous air pollutants listed in this part pursuant to

section 112(b) of the Act. This part is independent of NESHAP requirements contained in

40 CFR Part 61, discussed above.

4.2.3.1 40 CFR Part 63, Subpart A - General Provisions:

The general provisions in 40 CFR 63 Subpart A are applicable to stationary and area

sources with facilities subject to any standard promulgated under 40 CFR Part 63. The

following Project facilities are subject to relevant subparts of 40 CFR Part 63:

Ethylene Manufacturing - Subparts SS, UU, WW, XX, YY,

Polyethylene Manufacturing – Subpart FFFF,

Combustion turbines - Subpart YYYY, and

Reciprocating Internal Combustion Engines - Subpart ZZZZ.

In general, Subpart A contains requirements related to notification, recordkeeping,

monitoring and performance testing. Subpart A also contains control device requirements

similar to the requirements in 40 CFR §60.18.

4.2.3.2 40 CFR Part 63, Subpart SS - National Emission Standards for Closed Vent Systems, Control Devices, Recovery Devices and Routing to a Fuel Gas System or a Process

40 CFR 63 Subpart SS applies when another subpart of 40 CFR Part 63 references the

use of this subpart for HAP emission control. 40 CFR 63 Subpart YY refers to this



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subpart for the control of closed vent systems, control devices, recovery devices, and

routing to a fuel gas system or a process as follows:

Closed vent system and flare. Owners or operators that vent emissions through a

closed vent system to a flare must meet the requirements in §63.983 for closed

vent systems; §63.987 for flares; §63.997(a), (b) and (c) for provisions regarding

flare compliance assessments; the monitoring, recordkeeping, and reporting

requirements referenced therein; and the applicable recordkeeping and reporting

requirements of §§63.998 and 63.999. No other provisions of this subpart apply to

emissions vented through a closed vent system to a flare.

Closed vent system and nonflare control device. Owners or operators who control

emissions through a closed vent system to a nonflare control device must meet the

requirements in §63.983 for closed vent systems, the applicable recordkeeping

and reporting requirements of §§63.998 and 63.999, and the applicable

requirements listed in paragraphs (c)(1) through (3) of §63.982.

Route to a fuel gas system or process. Owners or operators that route emissions to

a fuel gas system or to a process shall meet the requirements in §63.984, the

monitoring, recordkeeping, and reporting requirements referenced therein, and the

applicable recordkeeping and reporting requirements of §§63.998 and 63.999. No

other provisions of this subpart apply to emissions being routed to a fuel gas

system or process.

Shell will comply with the provisions of 40 CFR 63 Subpart SS where applicable by

designing and operating the closed vent systems, control devices, recovery devices and

routing to a fuel gas system or a process in compliance with this subpart, and by

complying with all of the subpart requirements for testing, recordkeeping, and reporting.

4.2.3.3 40 CFR Part 63, Subpart UU - National Emission Standards for Equipment Leaks

40 CFR 63 Subpart UU applies to the control of air emissions from equipment leaks for

which another subpart references the use of this subpart for such air emission control. 40

CFR 63 Subpart YY (discussed below) refers to this subpart for the control of equipment

leaks. 40 CFR 63 Subpart UU applies to equipment leaks from pumps, compressors,

agitators, pressure relief devices, sampling connection systems, open-ended valves or

lines, valves, connectors, instrumentation systems, and closed vent systems and control

devices used to meet the requirements of this subpart. The following equipment is

exempt from the requirements of 40 CFR 63 Subpart UU:



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Equipment in vacuum service,

Equipment intended to be in regulated material service less than 300 hours per

calendar year.

Lines and equipment not containing process fluids, such as utilities, other non-

process lines, and heating and cooling systems that do not combine their materials

with those in the processes they serve.

Shell will comply with the provisions of 40 CFR 63 Subpart UU where applicable by

designing and operating the pumps, compressors, agitators, pressure relief devices,

sampling connection systems, open-ended valves or lines, valves, connectors,

instrumentation systems, and closed vent systems and control devices in compliance with

this subpart, and by complying with all of the subpart requirements for testing,

monitoring, repair, recordkeeping, and reporting.

4.2.3.4 40 CFR Part 63, Subpart WW - National Emission Standards for Storage Vessels

40 CFR 63 Subpart WW applies to the control of air emissions from storage vessels for

which another subpart references the use of this subpart for such air emission control.

40 CFR 63 Subpart YY refers to this subpart for the control of storage vessels. For each

storage vessel to which this subpart applies, the owner or operator shall comply with one

of the requirements:

Operate and maintain an internal floating roof (IFR) tank.

Operate and maintain an external floating roof (EFR) tank.

Comply with an equivalent to the requirements as provided in §63.1064.

Shell will comply with the provisions of Subpart WW where applicable by designing and

operating the storage vessels with IFRs or EFRs or closed vent systems with control

devices and by complying with all of the subpart requirements for testing, repair

recordkeeping, and reporting.



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4.2.3.5 40 CFR Part 63, Subpart XX - National Emission Standards for Ethylene Manufacturing Process Units: Heat Exchange Systems and Waste Operations

40 CFR 63 Subpart XX establishes requirements for controlling emissions of HAPs from

heat exchange systems and waste streams at new and existing ethylene production units.

This subpart requires monitoring the cooling water for the presence of substances that

indicate a leak in the heat exchange system and repairing the leak. This subpart requires

compliance with 40 CFR Part 61, Subpart FF, National Emission Standards for Benzene

Waste Operations. There are some differences between the ethylene production waste

requirements and those of 40 CFR 61 Subpart FF. The waste stream provisions of 40

CFR 63 Subpart XX apply to the Project’s ethylene manufacturing process as this subpart

is expressly referenced from 40 CFR 63 Subpart YY.

40 CFR 63 Subpart XX subpart requires management and treatment of continuous

butadiene waste streams that contain greater than or equal to 10 ppmw 1,3-butadiene and

have a flow rate greater than or equal to 0.02 liters per minute. If the total annual

benzene quantity from waste at the facility is less than 10 Mg/yr, as determined according

to 40 CFR 61.342(a), additional requirements apply. For waste streams that contain

benzene, the source must comply with the requirements of 40 CFR Part 61 Subpart FF,

except as specified in Table 2 to 40 CFR 63 Subpart XX.

Shell will comply with the provisions of 40 CFR 63 Subpart XX relating to equipment

design/operation, testing, recordkeeping, and reporting.

4.2.3.6 40 CFR Part 63, Subpart YY – National Emission Standards for Hazardous Air Pollutants for Source Categories: Generic Maximum Achievable Control Technology Standards

40 CFR 63 Subpart YY controls HAP emissions from the following emission points:

storage vessels, process vents, transfer racks, equipment leaks, waste streams, and other

(heat exchange systems for ethylene production) from certain source categories. One of

the source categories covered by this subpart is ethylene production. The affected

sources include:



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All storage vessels (as defined in §63.1101) that store liquids containing organic

HAP.

All ethylene process vents from continuous unit operations.

All transfer racks that load HAP-containing material.

Equipment (as defined in §63.1101) that contains or contacts organic HAP.

All waste streams associated with an ethylene production unit.

All heat exchange systems associated with an ethylene production unit.

All ethylene cracking furnaces and associated decoking operations, while

considered affected sources, are exempt from any control requirements under this

subpart.

Shell will comply with the provisions of 40 CFR 63 Subpart YY where applicable by

designing and operating the storage vessels, process vents, transfer racks, equipment

leaks, waste streams, and heat exchange systems associated with the ethylene

production source category in compliance with all of the subpart requirements, and by

complying with all of the subpart requirements for testing, recordkeeping, and

reporting.

4.2.3.7 40 CFR Part 63, Subpart FFFF - National Emission Standards for Hazardous Air Pollutants: Miscellaneous Organic Chemical Manufacturing

40 CFR 63 Subpart FFFF establishes national emission standards for hazardous air

pollutants (NESHAP) for miscellaneous organic chemical manufacturing. This subpart

also establishes requirements to demonstrate initial and continuous compliance with the

emission limits, operating limits, and work practice standards. The three polyethylene

units are affected facilities. Processes covered by this subpart include:

continuous process vents,

batch process vents,

storage tanks,

transfer racks,

equipment leaks,

wastewater streams and liquid streams in open systems, and

heat exchange systems.



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Shell will comply with the provisions of 40 CFR 63 Subpart FFFF where applicable by

designing and operating the storage vessels, process vents, transfer racks, equipment

leaks, waste streams, and heat exchange systems associated with the affected source in

compliance with all of the subpart requirements, and by complying with all of the subpart

requirements for testing, recordkeeping, and reporting.

4.2.3.8 40 CFR Part 63, Subpart YYYY - National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines

40 CFR 63 Subpart YYYY establishes national emission limitations and operating

limitations for hazardous air pollutant (HAP) emissions from stationary combustion

turbines located at major sources of HAP emissions, and requirements to demonstrate

initial and continuous compliance with the emission and operating limitations. Duct

burners and waste heat recovery units are considered steam generating units and are not

covered under this subpart. In some cases, it may be difficult to separately monitor

emissions from the turbine and duct burner, so sources are allowed to meet the required

emission limitations with their duct burners in operation. This subpart applies to each

new or reconstructed stationary combustion turbine which is a lean premix gas-fired

stationary combustion turbine, a lean premix oil-fired stationary combustion turbine, a

diffusion flame gas-fired stationary combustion turbine, or a diffusion flame oil-fired

stationary combustion turbine. Stationary combustion turbines used for emergency

purposes are exempt from this subpart.

Currently, the standards for gas-fired subcategories have been stayed (69 Fed. Reg.

51184 (August 18, 2004), and EPA has proposed to delist from the MACT requirements

four categories of stationary combustion turbines, including the category that would

cover the Project’s proposed turbines. Projects that start up a new or reconstructed

stationary combustion turbine that is a lean premix gas-fired stationary combustion

turbine or diffusion flame gas-fired stationary combustion turbine as defined by this

subpart, must comply with the Initial Notification requirements set forth in § 63.6145 but

need not comply with any other requirement of this subpart until EPA takes final action

to require compliance and publishes a document in the Federal Register.



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4.2.3.9 40 C.F.R. Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines

40 CFR 63 Subpart ZZZZ establishes national emission limitations and operating

limitations for HAPs emitted from stationary reciprocating internal combustion engines

(RICE) located at major and area sources of HAP emissions. This subpart also establishes

requirements to demonstrate initial and continuous compliance with the emission

limitations and operating limitations.

An affected source must meet the requirements of 40 CFR Part 60 Subpart IIII, for

compression ignition engines. Shell will comply with the provisions of 40 CFR 63

Subpart ZZZZ by complying with the requirements for equipment design/operation,

testing, recordkeeping, and reporting.

4.2.4 40 CFR Part 64: Compliance Assurance Monitoring

40 CFR Part 64, Compliance Assurance Monitoring (CAM), applies to units subject to

federally enforceable emission standards at major Part 70 (Title V) sources with

uncontrolled emissions above major source thresholds. Where the basis of the emission

standard is a regulation proposed after November 15, 1990, additional monitoring

requirements under CAM are not applicable. The proposed Project will comply with the

CAM requirements.

4.2.5 40 CFR Part 68: Chemical Accident Prevention Provisions

This regulation mandates that facilities with more than a threshold quantity of a regulated

substance in a single process must develop a Risk Management Program that includes a

hazard assessment, an accident prevention program and an emergency response program.

It also requires that owners or operators of subject facilities submit a summary of their

program called a risk management plan (RMP), detailing these program elements to the

Environmental Protection Agency. The proposed Project will have a number of regulated

substances that may exceed the threshold quantity. If applicable, Shell will develop a

Risk Management Program that includes hazard assessment, an accident prevention

program and an emergency response program.



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4.2.6 40 CFR Parts 72, 73, 74, 75, and 76: Acid Rain Programs

These parts pertain to the Acid Rain Program. 40 CFR Part 72 is the permitting

requirements, 40 CFR Part 73 is the SO2 allowance system, and 40 CFR Part 75 contains

the continuous monitoring requirements. 40 CFR Part 74 is the SO2 Opt-In System for

units that are not affected units under 40 CFR Part 72. 40 CFR Part 76 is the NOx

emissions reduction program.

The proposed Cogen Units will sell more than one-third of their potential electric output

capacity and are greater than 25 MWe in capacity. Thus, these units will be subject to the

Acid Rain Program requirements found in 40 CFR Parts 72, 73, and 75. 40 CFR Part 74

does not apply because the Cogen Units are affected units under Part 72. 40 CFR Part 76

does not apply because the regulation only applies to coal-fired units. Shell will comply

with the Acid Rain Program requirements for the Cogen Units.

4.2.7 40 CFR Part 82: Protection of Stratospheric Ozone

4.2.7.1 40 CFR Part 82, Subpart F- Recycling and Emissions Reduction

40 CFR 82 Subpart F seeks to reduce emissions of Class I and Class II refrigerants and

their substitutes to the lowest achievable level by maximizing the recapture and recycling

of such refrigerants during the service, maintenance, repair, and disposal of appliances

and restricting the sale of refrigerants consisting in whole or in part of a Class I and

Class II ozone depleting substances (ODS) in accordance with Title VI of the Clean Air

Act. Appliance means any device which contains and uses a refrigerant and which is

used for household or commercial purposes, including any air conditioner, refrigerator,

chiller, or freezer. This subpart applies to any person servicing, maintaining, or repairing

appliances, or disposing of appliances, including small appliances and motor vehicle air

conditioners. In addition, this subpart applies to refrigerant reclaimers, technician

certifying programs, appliance owners and operators, manufacturers of appliances,

manufacturers of recycling and recovery equipment, approved recycling and recovery

equipment testing organizations, persons selling Class I or Class II refrigerants or

offering Class I or Class II refrigerants for sale, and persons purchasing Class I or

Class II refrigerants.



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This subpart prohibits, after June 13, 2005, any person maintaining, servicing, repairing,

or disposing of appliances knowingly venting or otherwise releasing into the environment

any prohibited refrigerant or substitute from such appliances. Releases associated with

good faith attempts to recycle or recover refrigerants or non-exempt substitutes that are

deminimis are not subject to this prohibition.

Other requirements of this subpart include repair of leaks for systems containing over

50 pounds of refrigerant. Shell will comply with the prohibition on venting non-exempt

refrigerants, and the leak monitoring, repair and reporting requirements for equipment

containing over 50 pounds of refrigerant.

4.2.8 40 CFR Part 98: Mandatory Greenhouse Gas Reporting

EPA promulgated this rule for the mandatory reporting of greenhouse gases (GHG) from

sources that in general emit 25,000 metric tons or more of carbon dioxide equivalent per

year in the United States. For the proposed Project, this rule applies to any combustion

source emitting CO2, CH4, and N2O, equipment leaks of CH4, and equipment leaks of

SF6. The Project’s combustion sources include the cracking furnaces, Cogen Units,

incinerators, flares, and emergency diesel engines. Equipment leaks of CH4 would occur

from the natural gas fuel system, the ethane cracker fuel system, and the ethylene

manufacturing cracked gas system including the quench towers, heat exchangers,

compressors, pumps, and distillation towers processing methane.



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5.0 Control Technology Analysis

5.1 Control Technology Background

Two primary types of control technology analyses are presented in this section.17 For

those pollutants for which the proposed project is a major source in an attainment area

requiring PSD review (CO2e/GHG, CO, NO2, and PM/PM10), best available control

technology (BACT) analyses are provided. For those pollutants for which the proposed

project is a major source in a non-attainment area (NOx, VOC, and PM2.5), lowest

achievable emission rate (LAER) technology analyses are provided. Where it is logical

to do so, analyses are combined on a pollutant/source basis (e.g., the NO2 BACT and

NOx LAER analyses). In addition, this section evaluates Pennsylvania best available

technology requirements under 25 Pa. Code §127.12(a)(5) (PaBAT). Where appropriate,

reference is provided to applicable New Source Performance Standards (NSPS), and

National Emission Standards for Hazardous Air Pollutants (NEHAPS), which provide a

baseline of technology requirements.

5.1.1 Control Technology Analyses Definitions

The federal PSD regulations, which are adopted by reference in the Pennsylvania air

quality regulations,18 define BACT at 40 CFR § 52.21(b)(12) as follows:

“[BACT] means an emissions limitation (including a visible emission standard)

based on the maximum degree of reduction for each pollutant subject to regulation

under Act which would be emitted from any proposed major stationary source or

major modification which the Administrator, on a case-by-case basis, taking into

account energy, environmental, and economic impacts and other costs, determines is

achievable for such source or modification through application of production

processes or available methods, systems, and techniques, including fuel cleaning or

treatment or innovative fuel combustion techniques for control of such pollutant. In

no event shall application of best available control technology result in emissions of

any pollutant, which would exceed the emissions allowed by any applicable standard

under 40 CFR parts 60 and 61. If the Administrator determines that technological or

economic limitations on the application of measurement methodology to a particular

17 For the purposes of the control technology analyses, the State Best Available Technology (BAT)

requirements are assumed to be met by either the BACT or LAER analyses contained herein. 18 25 Pa. Code §127.83.



5-2

emissions unit would make the imposition of an emissions standard infeasible, a

design, equipment, work practice, operational standard, or combination thereof, may

be prescribed instead to satisfy the requirement for the application of best available

control technology. Such standard shall, to the degree possible, set forth the

emissions reduction achievable by implementation of such design, equipment, work

practice or operation, and shall provide for compliance by means which achieve

equivalent results.”

LAER, as defined in 25 Pa Code § 121.1, means the following:

LAER—Lowest Achievable Emission Rate—

(i) The rate of emissions based on the following, whichever is more stringent:

(A) The most stringent emission limitation which is contained in the

implementation plan of a state for the class or category of source unless the

owner or operator of the proposed source demonstrates that the limitations

are not achievable.

(B) The most stringent emission limitation which is achieved in practice by the

class or category of source.

(ii) The application of the term may not allow a new or proposed modified source

to emit a pollutant in excess of the amount allowable under an applicable new

source standard of performance.

Per 25 Pa. Code 127.12(a)(5), applicants must show that emissions from a new source

will be the minimum attainable through use of the best available technology

(PaBAT). For sources also subject to BACT or LAER requirements, 25 Pa. Code

127.205(7) stipulates that the Pennsylvania Department of Environmental Protection

(PaDEP) may determine that PaBAT requirements are equivalent to BACT and LAER

determined under the new source review program. Thus, a separate PaBAT discussion is

provided below only for pollutants not subject to the BACT or LAER requirements.

5.1.2 Methodology for LAER and BACT Analyses

The LAER analyses conducted in this section will follow the following three steps:

Step 1: Identify existing permit limits and SIP limits;

Step 2: Identify existing permit limits and SIP limits that have been achieved in

practice; and

Step 3: Propose LAER based on the most stringent limit that has been achieved

in practice.



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The federal and state new source review (NSR) regulations do not prescribe a procedure

for conducting BACT analyses. U.S. EPA and Pennsylvania Department of

Environmental Protection (“PaDEP”) have interpreted the BACT requirement as

containing two core criteria. First, the BACT analysis must include consideration of the

most stringent available technologies (i.e., those that provide the “maximum degree of

emissions reduction”). Second, any decision to define BACT on the basis of a control

alternative that is less effective than the most stringent available must be justified by an

analysis of objective indicators showing that energy, environmental, and economic

impacts render the more stringent alternative(s) unreasonable or otherwise not

achievable.

U.S. EPA has developed and PaDEP has followed what is referred to as a “top-down”

approach for conducting BACT analyses and has indicated that this approach will

generally yield a BACT determination satisfying the two core criteria. Under the “top-

down” approach, analysis starts with the most stringent control technologies that are both

available and technically feasible for a particular source. Each control technology, in

order of stringency, is evaluated to determine whether its environmental, energy or

economic impacts render that alternative inappropriate as BACT. The energy impact

analysis considers direct energy consumption associated with the control technology.

Cost and economic analyses considers capital and annual costs of the control technology

in relation to the technology’s effectiveness in removing the pollutant(s) of concern,

considering both total and incremental cost-effectiveness. Economic impact analysis

considers the environmental impacts associated with a control technology, such as waste

generation, wastewater discharges, visibility impacts or emissions of unregulated

pollutants. Such “top-down” approach is utilized for the BACT analyses presented in this

application.

The five basic steps of a “top-down” BACT analysis are listed below:

Step 1: Identify all available control technologies with practical potential for

application to the specific emission unit for the regulated pollutant under

evaluation;

Step 2: Eliminate technically infeasible control technologies;



5-4

Step 3: Rank the remaining control technologies by effectiveness and tabulate a

control hierarchy;

Step 4: Evaluate the control technologies in order of effectiveness to determine

environmental, economic, and energy impacts, and document the results;

and

Step 5: Select BACT, which will be the most effective control option not rejected

as inappropriate based on the economic, environmental, and/or energy

impacts.

5.1.3 Achieved in Practice and Technical Feasibility Criteria

5.1.3.1 Achieved in Practice

One of the LAER criteria is to identify the most stringent emission limitation that has

been achieved in practice by the class or category of source. The "achieved-in-practice"

component of the LAER definition is not defined in the federal statutes and regulations,

and several interpretations have been formulated by various permitting agencies.

For example, EPA Region IX has taken a position that the successful operation of a new

control technology for six months constitutes “achieved-in-practice”.19 This

interpretation leaves open several key points, including the most important question as to

what demonstrates “successful operation.”

In a draft document, the San Joaquin Valley Air Pollution Control District defined

“achieved in practice” as an emission level or an emission control technology or

technique that is has been identified by the District, CARB, EPA, or any other air

pollution control District as having been “achieved in practice” for the same class and

category of source provided: 20

The rating and capacity for the unit where the control was achieved must be

approximately the same as that for the proposed unit.

The type of business (i.e. class of source) where the emissions units are utilized

must be the same.

19 Howekamp, David, U.S. EPA, Region IX, to Mohsen Nazemi, SCAQMD, August 25, 1997. 20 DRAFT San Joaquin Valley Air Pollution Control District Best Available Control Technology Policy,

March 1, 2010.



5-5

The availability of resources (i.e. fuel, water) necessary for the control technology

must be approximately the same.

The San Joaquin District’s draft guidance indicates that in addition to the criteria above,

an emission control technology or technique is considered “achieved in practice”

provided all of the following are satisfied:

At least one vendor must offer this equipment for regular or full-scale operation.

A performance guarantee should be (but is not required to be) available with the

purchase of the control technology.

The control technology must have been installed and operated reliably in at least

one commercial facility for at least 180 days.

The control technology must be verified to perform effectively over the range of

operation expected for that class and category of source. The verification shall be

based on a performance test or tests, when possible, or other performance data.

Just because a permit or SIP emission limit has been issued does not mean that the limit

is “achievable-in-practice” unless an emissions unit in the same class or category of

source has operated under normal operating mode and has demonstrated through testing

that the limit is achieved. This is why the definition of LAER includes the caveat “unless

the owner or operator of the proposed source demonstrates that the limitations are not

achievable.” For the purposes of this control technology analysis, a permit or SIP limit is

considered “achieved-in-practice” when testing has successfully demonstrated

compliance with the limit and averaging period. For example, if the permit limit is based

on a 12-month rolling average period excluding periods of startup, shutdown,

maintenance, and malfunction (SSMM), then at least 12-months of operation is required

to demonstrate that the limit is “achieved in practice.”

5.1.3.2 Technical Feasibility

Under Step 2 of a BACT analysis, each of the available control technologies identified

under Step 1 are evaluated to determine their technical feasibility. A control technology

is determined to be technically feasible if it has previously been installed and operated

successfully at a similar emission source, or if there is agreement that the technology can

be applied to the emission source that is under evaluation. Technical infeasibility is

shown through physical, chemical, or other engineering principles that demonstrate that



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technical difficulties preclude the successful use of the control option for the particular

source under consideration.

A technology must be commercially available for it to be considered as a candidate for

BACT. The EPA 1990 Draft Workshop Manual, at page B.12, states: “Technologies

which have not yet been applied to (or permitted for) full scale operations need not be

considered available; an applicant should be able to purchase or construct a process or

control device that has already been demonstrated in practice.”

In general, if a control technology has been "demonstrated" successfully for the type of

emission source under review, then it would be considered technically feasible. For an

undemonstrated technology, “availability” and “applicability” must be considered in

determining technical feasibility. Page B.17 of the 1990 Draft Workshop Manual states:

Two key concepts are important in determining whether an undemonstrated

technology is feasible: "availability" and "applicability." As explained in more detail

below, a technology is considered "available" if it can be obtained by the applicant

through commercial channels or is otherwise available within the common sense

meaning of the term. An available technology is "applicable" if it can reasonably be

installed and operated on the source type under consideration. A technology that is

available and applicable is technically feasible.

Availability in this context is further explained using the following process commonly

used for bringing a control technology concept to reality as a commercial product:

concept stage;

research and patenting;

bench scale or laboratory testing;

pilot scale testing;

licensing and commercial demonstration; and

commercial sales.

The 1990 Draft Workshop Manual, at page B.18, states, “A control technique is

considered available, within the context presented above, if it has reached the licensing

and commercial sales stage of development. A source would not be required to

experience extended time delays or resource penalties to allow research to be conducted

on a new application. Neither is it expected that an applicant would be required to



5-7

experience extended trials to learn how to apply a technology on a totally new and

dissimilar source type.”

It should be noted that some vendors will provide guarantees and commercial sale of

technology that has not been sufficiently demonstrated commercially. This can and has

led to significant compliance issues. Applicability involves not only commercial

availability (as evidenced by past or expected near-term deployment on the same or

similar type of emission source), but also involves consideration of the physical and

chemical characteristics of the gas stream to be controlled. A control method applicable

to one emission source may not be applicable to a similar source due to differences in

physical and chemical gas stream characteristics (such as the sulfur content of the flue

gas from a coal-fired boiler verses a natural gas-fired boiler, or the range and variability

of temperature characteristics of flue gas impacting the effectiveness of controls).

Vendor guarantees alone do not constitute technical availability. The 1990 Draft

Workshop Manual, at page B.20, notes:

Vendor guarantees may provide an indication of commercial availability and

the technical feasibility of a control technique and could contribute to a

determination of technical feasibility or technical infeasibility, depending on

circumstances. However, EPA does not consider a vendor guarantee alone to

be sufficient justification that a control option will work.

This is because there are many instances where vendor guarantees for emission control

equipment have not been met. Vendor guarantees rarely cover the cost of major

equipment modifications or the installation of new equipment required to attain

compliance, the cost of lost production and the legal cost of addressing enforcement

actions from regulatory agencies.

5.1.4 Control Technology Analysis Organization

The control technology analyses included in this section are organized by emissions unit

type and then by pollutant, except for the Greenhouse Gas (GHG) pollutants. The GHG

BACT analyses are addressed with a separate Section 5.6 addressing potential control of

CO2e by carbon capture and sequestration across the entire facility, with separate



5-8

discussion of other CO2e control methods addressed in the sections on particular

emissions unit types. This is because the top control technology option, carbon capture

and sequestration (CCS), is the “top” control option for all combustion sources and

process vents. Section 5.6 provides the control technology analyses for CCS.

5.1.5 Summary of Proposed BACT/LAER

Table 5-1 presents a summary of the proposed BACT and LAER limits for each of the

project’s emissions units and emissions points.



5-9

Table 5-1. Proposed Control Technology Evaluation Limits

Emissions Unit Pollutant Control Technology Limit/Averaging Time Compliance Method

Cracking Furnaces

NOx Low NOx Burners (LNB) &

Selective Catalytic Reduction

(SCR)

0.01 lb/MMBtu (12-mth roll)

0.015 lb/MMBtu (24-hr roll)

31.1 lb/hr during startup,

shutdown, decoking, hot

steam standby, feed in and

feed out modes

NOx Continuous

Emissions Monitoring

System (CEMS)

VOC Good Combustion Design &

Operation 1.07 lb/hr Performance test once

every 5 years using EPA

Reference Methods (RM)

18 & 25 and

PM/PM10/PM2.5 Good Combustion Design &

Operation 3.1 lb/hr

0.005 lb/MMBtu at rated heat

input

Performance test once


RM 5 & 202

CO Good Combustion Design &

Operation 035 lb/MMBtu (12-mth roll)

52.2 lb/hr during startup,

shutdown, and decoking

CO CEMS

CO2e/GHG Highly energy efficient

design & operation Only tailgas & pipeline

quality natural gas shall be

fired

Routine furnace tune up in

accordance with NESHAP

subpart DDDDD

Exhaust gas temperature shall

be limited to less than 350 oF

12-mth rolling per furnace

Fuel flow rate, heating

value (HHV), carbon

content, molecular

weight determined

hourly using online gas

chromatograph or

40 CFR 98.34(b)(3)

Exhaust gas temperature

HAP Good Combustion Design & Sections 5.2.2 & 5.2.5 VOC Sections 5.2.2 & 5.2.5



5-10


Operation & GHG LAER VOC & GHG LAER

Combustion Turbines/Duct Burners

NOx Dry low NOx Burners &

SCR 2 ppmvd @ 15% O2 (1-hr

roll)

22.6 tons/yr (12-mth roll)

including startup & shutdown

113 lb/hr during startup and

shutdown

LAER Limit

NOx CEMS

25 Pa Code § 25

Monitoring

§ 145.70 (Part 75

Subpart H)

§ 145.70 - Heat input

(Part 75 Subpart H)

§ 145.213 - Gross

electric output

VOC CO Oxidation Catalyst & use

of Good Combustion Design

& Operation

1 ppmvd @ 15% O2 (1-hr

roll)



RM 18 & 25 and

PM/PM10/PM2.5 Use of Natural Gas & Good

Combustion Design &

Operation

0.0066 lb/MMBtu

0.75 grains sulfur/100 dscf



RM 5 & 202

CO CO Oxidation Catalyst 2 ppmvd @ 15% O2 (1-hr

roll)

14.5 tons/yr 12-mth roll

including startup & shutdown

276 lb/hr during startup &

shutdown

CO CEMS

CO2e/GHG Use of Natural Gas & Energy

Efficient Design

GE G6581

1,030 lb CO2e/MWh (30-day

roll) total facility

340,558 tpy (365-day roll)

Siemens SGT-800

CO2 using Part 75

Appendix G

Calculate CO2e from

CO2 using a factor of

1.0010 as a multiplier



5-11


978 lb CO2e/MWh (30-day

roll)

353,893 tpy (365-day roll)

total facility

HAP CO oxidation catalyst Comply with requirements in

stayed 40 CFR 63

subpart YYYY

Installation of CO

oxidation catalyst

Operation above vendor

required design operating

temperature

Diesel Engines – Emergency Generators

NOx + VOC Combustion Control

Techniques 4.6 g/hp-hr Use of an engine

certified to achieve this

level

PM/PM10/PM2.5 Combustion Control

Techniques & the use of low

sulfur fuel

0.15 g/hp-hr

Fuel with less than 15 ppmw

sulfur content

Use of an engine


level

CO Combustion Control



level

CO2e/GHG Combustion Control

Techniques 1,151.6 tons/yr (all engines) Fuel usage & emissions

factor

HAP Combustion Control

Techniques 40 CFR 63 subpart ZZZZ 40 CFR 63 subpart ZZZZ

Diesel Engines – Firewater Pumps

NOx + VOC Combustion Control



level

PM/PM10/PM2.5 Combustion Control

Techniques & the use of low 0.15 g/hp-hr Use of an engine




5-12


sulfur fuel Fuel with less than 15 ppmw

sulfur content

level

CO Combustion Control



level

CO2e/GHG Combustion Control

Techniques 120.3 tons/yr (all engines) Fuel usage & emissions

factor

HAP Combustion Control

Techniques 40 CFR 63 subpart ZZZZ 40 CFR 63 subpart ZZZZ

Equipment Leaks – Fugitive Components

VOC Enhanced Leak Detection

and Repair

See Section 5.5.1

CO2e/GHG Enhanced Leak Detection

and Repair

See Section 5.5.2

HAP Enhanced Leak Detection

and Repair

See Section 5.5.1

PE Manufacturing Process Vents, Storage, and Handling

VOC VOC containing vents

directed to control system &

limit on residual VOC in

pellets

All VOC containing PE Units

1 & 2 vents located upstream

of and including Product

Purge Bin will be directed to

a VOC control system

All VOC containing PE Unit

3 vents located upstream of

the degasser will be directed

to a VOC control system

The VOC control system

shall achieve a 99.5% VOC

destruction removal

See VOC Control System

Requirements below

VOC content of the

pellets shall be

determined once weekly

using either the beverage

can method (Method 24)

or heated headspace

analysis (Method 3810)



5-13


efficiency

The residual VOC content in

the resin exiting the Product

Purge Bins at PE Units 1 & 2

shall be less than 50 ppmw

The residual VOC content in

the resin exiting the degasser

at PE Units 3 shall be less

than 50 ppmw

Applicable vents are listed in

Appendix D

PM/PM10/PM2.5 All of the particulate

containing vents in PE Units

1, 2 and 3 shall have

emissions of less than

0.005 g/dscf

Applicable vents are listed in

Appendix D

Baghouses



Reference Method 5 &

202

HEPA Filters

Manufacturer

specification

Visual inspection

Sintered Metal Filters

Manufacturer

specification

Visual inspection

HAP Section 5.7.1 VOC

LAER

Section 5.7.2 PM LAER

Tanks and Vessels

VOC Tank design and vent Light gasoline and hexene LP Thermal Incinerator



5-14


controls tanks will be equipped with

internal floating roofs & vent

to LP Thermal Incinerator

Flow equalization, recovered

oil storage, and spent caustic

tanks will vent to the Spent

Caustic Vent Thermal

Incinerator

Pyrolysis tar, diesel

locomotive, and small diesel

fuel tanks (each <20,000

gallons) will vented to carbon

canisters

Destruction Rate

Efficiency 99.5%

Spent Caustic Vent

Thermal Incinerator

Destruction Rate

Efficiency 99%

Carbon canisters shall be

monitored for

breakthrough at times

when there is actual flow

to the carbon canister.

For a single carbon

canister, "breakthrough"

is defined as any VOC

reading above

background. For all

canisters that are

operated as part of a

primary and secondary

system, "breakthrough"

is defined as any reading

of 50 ppm volatile

organic compound

("VOC").

HAP Spent Caustic Vent Thermal

Incinerator 99% Destruction Rate

Efficiency

Cooling Tower

PM/PM10/PM2.5 Mist/drift eliminators 0.0005% drift rate

TDS 2400 ppm (12-mth roll)

Demister specification

TDS measurement in



5-15


accordance with EPA

Method 160.1

VOC VOC content of circulating

water in process cooling

water tower heat exchange

system

0.5 lb/MMgal

Determine the

concentration of VOC in

the cooling water using

any method listed in 40

CFR Part 136.

HAP VOC content of circulating

water in process cooling

water tower heat exchange

system

40 CFR 63 Subparts XX and

FFFF

40 CFR 63 Subparts XX

and FFFF

Loading Operations

PE Loading PM/PM10/PM2.5 Fabric filter sock (i.e., filter

material designed to inhibit

emissions during loading)

0.01 g/dscf Manufacturer

specification

Visible emissions

Liquid Loading VOC Design and work practices Low Vapor Pressure Organic

Liquids

Vapor pressure of the low

vapor pressure organic liquids

loaded shall not exceed 0.5

psia

Submerged filling or bottom

loading shall be used for

loading of all low vapor

pressure organic liquids

All transport vehicles loaded

shall either be in dedicated

service or shall be cleaned

prior to loading



5-16


C3+ Liquids

Low leak couplings

Pressurized loading of C3+

liquids

HAP Section 5.11 VOC LAER

VOC Control System LP Thermal

Incinerator VOC/HAP Waste gas minimization &

operation to achieve good

destruction removal

efficiency

Operation in accordance with

approved waste gas

minimization plan

LP Thermal Incinerator

designed and operated to

achieve a 99.5% destruction

rate efficiency

Designed and operated to

achieve 99.5%

Destruction Rate

Efficiency

LP Ground Flare VOC/HAP Waste gas minimization &


destruction removal

efficiency


approved waste gas

minimization plan

Root cause analysis for

flaring events that exceed

baseload by 500,000 scf in 24

hour period

Corrective actions consistent

with good engineering

practice

Flare designed to meet

limitations on maximum exit

velocity, as set forth in the

general provisions at 40 CFR

Flaring Vent flowrate

measurement

Steam rate measurement

(if applicable)

Total hydrocarbon

analysis (optional)

40 CFR §60.18 and

§63.11



5-17


§60.18 & §63.11

Flare operated to meet

minimum net heating value

requirements for gas streams

combusted in the flares, as set

forth at 40 CFR § 60.18 & §

63.11 HP Ground Flares

(2) VOC/HAP Waste gas minimization &


destruction removal

efficiency


approved waste gas

minimization plan




hour period



practice





§60.18 & §63.11





forth at 40 CFR § § 60.18 &

63.11

Each flare shall be equipped


measurement


(if applicable)

GC analysis to determine

molecular weight and

heating value of the vent

gas

40 CFR §60.18 and

§63.11



5-18


with automated controls for

supplemental gas flow rate &

steam mass rate (is used for

assist) to the flare

The net heating value of the

combustion gases shall be

determined no less frequently

than once every 15 minutes

when the flare is in use

The net heating value in the

combustion zone shall be

equal to or greater than 500

Btu/scf

A net heating value of 1212

BTU/scf shall be used for

hydrogen HP Elevated Flare VOC/HAP Waste gas minimization &


destruction removal

efficiency


approved waste gas

minimization plan




hour period



practice





measurement


(if applicable)

Total hydrocarbon

analysis (optional)

40 CFR §60.18 and

§63.11



5-19



§60.18 & §63.11





forth at 40 CFR § 60.18 & §

63.11

LP Thermal

Incinerator/LP

Ground Flare/HP

Ground Flares

(2)/HP Elevated

Flare

NOx 0.068 lb/MMBtu

PM/PM10/PM2.5 0.0075 lb/MMBtu

CO 0.37 lb/MMBtu

CO2e/GHG 132 lb/MMBtu

HAP Section 5.12 VOC LAER

Spent Caustic Vent

Thermal Incinerator VOC 99% Destruction Rate

Efficiency



Reference Method 18 [40

CFR 61.355(e) as

referenced by

63.1095(b)(1)].

NOx 0.068 lb/MMBtu

PM/PM10/PM2.5 0.0075 lb/MMBtu

CO 0.37 lb/MMBtu

CO2e/GHG 132 lb/MMBtu

HAP 99% Destruction Rate

Efficiency



Reference Method 18 [40

CFR 61.355(e) as

referenced by



5-20


63.1095(b)(1)].

Plant Roads

PM Work Practices Pavement of all roads

Implementation of a road dust

control program

Other Contaminants

SO2 Fuel standard Natural gas containing less

than 0.5 gr/100 dscf sulfur

Use of pipeline natural

gas Appendix D of

40 CFR 75

Ammonia Furnaces

10 ppmvd @ 3% O2

Combustion Turbines

5 ppmvd @ 15% O2

Ammonia monitoring in

accordance with 30 TAC

§117.8130



5-21

5.2 Ethane Cracking Furnaces

As described in Section 3.1, ethane cracking furnaces are large process heaters specially

designed to produce high furnace box temperatures. The high furnace box temperatures

(2,100 to 2,200°F) heat the specially designed furnace tubes up to the temperatures

needed to thermally crack ethane in the presence of steam into ethylene (which occurs at

~1560°F) and byproducts (i.e., tailgas consisting of 85% by volume hydrogen with the

remainder being methane and other gaseous products). During normal operation, the

project’s ethane cracking furnaces will be fired with tailgas containing up to 85% by

volume hydrogen with the remainder being natural gas. As part of the cracking process,

coke is formed on the process side of the furnace tubes. As a result, the tubes in each

cracking furnace are decoked once every 30 to 60 days.21 The actual run length between

furnace tube decoking varies by licensor, design residence time used for the cracking

coils, and the operating severity (percent ethane conversion). During normal operation

and decoking, the furnaces are fired primarily on self-produced tailgas (hydrogen and

methane) with a small quantity of supplemental natural gas. When no ethane cracking is

taking place (e.g., start-up), the furnaces are fired on natural gas until ethane cracking is

started and self-produced tailgas becomes available. During normal operation and

decoking, NOx, CO, VOC, PM, PM10, PM2.5, and trace amounts of SO2 are emitted from

the furnaces. Accordingly, BACT/LAER analyses are included for NOx, VOC,

PM/PM10/PM2.5, and CO. (The project is not subject to BACT or LAER analysis for SO2

because it is not a major source of SO2).

5.2.1 Cracking Furnace NOx/NO2 LAER/BACT Analysis

Nitrogen oxides (NOX) are formed during combustion by two major mechanisms:

thermal NOX and fuel NOX. Thermal NOX results from the high temperature oxidation of

molecular nitrogen in combustion air. As its name implies, thermal NOX formation is

21 The furnace decoking process is described in Section 3.1.2.



5-22

primarily dependent on combustion temperature. Fuel NOX is formed from the direct

oxidation of organic nitrogen compounds in the fuel. Since tailgas (hydrogen and

methane from the cracking process), and natural gas will be combusted in the cracking

furnaces, fuel nitrogen levels will be negligible. As a result, thermal NOX is the primary

NOx formation mechanism.

This control technology analysis addresses emissions of NOx and NO2 from the ethane

cracking furnaces. The proposed project is located in an ozone nonattainment area so a

LAER analysis is provided for the precursor pollutant, NOx. The area is

attainment/unclassified with respect to NO2, so a BACT analysis is required for NO2 as a

PSD pollutant. From a control technology review perspective, emissions of NOx and

NO2 are the same. As a result, the more stringent three-step LAER methodology is used

to determine the proposed LAER limits for NOx and BACT limits for NO2. No

applicable NOx standards have been promulgated for cracking furnaces under 40 CFR

parts 60 and 61.

5.2.1.1 Step 1: Identify Cracking Furnace NOx/NO2 Controls/Limits

A review of the U.S. EPA’s RACT/BACT/LAER Clearinghouse (RBLC) database

identified fourteen process heaters with the following control technologies and techniques

for the control of NOx/NO2 emissions:22

Good combustion practices,

Latest generation low-NOX burners (LNB),23 and

Selective catalytic reduction (SCR).

22 U.S. EPA maintains a database documenting the permitted emissions limits for Reasonably Achievable

Control Technology (RACT) determinations, Best Available Control Technology (BACT)

determinations, and Lowest Achievable Emission Rate (LAER) determinations. This information is

input by the permitting authority and provides some information on the emissions unit and controls. 23 The terminologies for low NOx burner applications for use on boilers and process heaters have evolved

with time and performance, transitioning from low NOx burners (LNBs), to ultra low NOx burners

(ULNB), to current or next generation low NOx burners. For this application, LNBs means the lowest

emitting burner that can currently or in the near future be installed in the furnaces and heaters proposed

for the Project. These burners will include some or all of the combustion control methods including low

NOx burners, internal flue gas recirculation, stage air combustion, over-fire air, and steam injection. The

various burner options will depend on burner-furnace vendor design considerations.



5-23

Other potential NOx control technologies that have been applied at natural gas-fired

boilers and combustion turbines, and which may be considered for applicability through

technology transfer, include:

Flue gas recirculation (FGR) and over-fire air (OFA),

Selective non-catalytic reduction (“SNCR”), and

EMx™.

A brief description of the above listed NOx/NO2 controlled technologies follows. The

potential applicability and technical feasibility of each of these NOX/NO2 control options

are discussed in Step 2.

Good Combustion Practices: Good combustion practice addresses the three “Ts” of

combustion through the design and operation of the combustion device. The three “Ts”

are a summary of fluid flow and chemical reaction principles:

Temperature is the required energy for the initiation of a chemical reaction, in

this case combustion.

Turbulence is the interaction between two fluid streams required to achieve

intermixing of the two, fuel and air in the case of combustion.

Time is the period for the reaction to reach completion.

With respect to the cracking furnaces this means a burner temperature high enough to

ignite the fuel (tailgas), burner turbulence vigorous enough for the fuel constituents to be

exposed to the oxygen in the air and burner/firebox residence time long enough to assure

complete combustion (minimal CO, VOCs and products of incomplete combustion). In

addition to proper design and operation, advanced control systems are employed to

ensure good combustion practices.

Low NOx Burners (LNB): Low NOx burners reduce NOx emissions by managing and

controlling:

The oxygen level in the primary combustion zone to limit fuel NOx formation;

The flame temperature to limit thermal NOx formation; and/or

The residence time at peak temperature to limit thermal NOx formation.



5-24

The most common design approach is to control NOx formation by carrying out the

combustion in stages:24

Staged air burners, or delayed combustion LNBs, are two-stage combustion

burners that are fired fuel-rich in the first stage. They are designed to reduce

flame turbulence, delay fuel/air mixing, and establish fuel-rich zones for initial

combustion. The reduced availability of oxygen in the primary combustion zone

inhibits fuel NOx formation. Radiation of heat from the primary combustion zone

results in reduced temperature. The longer, less intense flames resulting from the

staged combustion lower flame temperatures and reduce thermal NOx formation.

Staged fuel burners also use two-stage combustion, but mix a portion of the fuel

and all of the air in the primary combustion zone. The high level of excess air

greatly lowers the peak flame temperature achieved in the primary combustion

zone, reducing thermal NOx formation. The secondary fuel is injected at high

pressure into the combustion zone through a series of nozzles, which are

positioned around the perimeter of the burner. Because of its high velocity, the

fuel gas entrains furnace gases and promotes rapid mixing with first stage

combustion products. The entrained gases simulate flue gas recirculation. This

approach is referred to as internal or burner flue gas recirculation. Heat is

transferred from the first stage combustion products prior to the second stage

combustion, and as a result, combustion in the second stage is achieved with

lower concentrations of oxygen and lower temperatures than would normally be

encountered. The reduced oxygen concentration and temperature results in

decreased thermal NOx formation.

The early low NOx burner design used the staged air approach to reduce NOx emissions,

while current generation or ultra low NOx burners rely upon staged fuel and burner flue

gas recirculation.

Selective Catalytic Reduction (SCR): SCR is the most widely applied post-

combustion/add-on control technique used to control NOx emissions. A selective

reducing agent (ammonia or urea), diluted with either steam or air is injected through a

grid system into the flue gas upstream of a catalyst bed. On the catalyst surface, the

reagent (reducing agent) reacts with the NOx to form molecular nitrogen and water. The

reaction rate is increased by the presence of excess oxygen. SCR is “selective” in that a

24 How to Incorporate Effects of Air Pollution Control Device Efficiencies and Malfunctions into Emission

Inventory Estimates. Volume II: Chapter 12. July 2000; Eastern Research Group, Inc. Page 12-4.7;



5-25

selective reagent (ammonia or urea) is used to reduce the NOx. The performance of an

SCR system is influenced by five factors:

Flue gas temperature;

Reagent-to-NOx ratio;

NOx concentration at the SCR inlet;

Space velocity (measure of the volumetric feed capacity of a continuous-flow

reactor per unit residence time); and

Condition (activity) of the catalyst.

Below the optimal temperature range, which is defined by the type of catalyst used (i.e.,

platinum versus vanadium based), the catalyst activity is greatly reduced, allowing

unreacted reagent to slip through. Operation at high temperatures can result in catalyst

deactivation.

Flue Gas Recirculation (FGR) and Over-Fire Air (OFA): In applications where

external FGR is installed, a portion of the flue gas is recycled back to the primary

combustion zone. FGR reduces NOx formation through two mechanisms:

Heating in the primary combustion zone of the inert combustion products

contained in the recycled flue gas lowers the peak flame temperature, thereby

reducing thermal NOx formation, and

FGR reduces thermal NOx formation by lowering the oxygen concentration in the

primary flame zone.

The recycled flue gas is either pre-mixed with the combustion air or injected directly into

the flame zone. Direct injection allows more precise control of the amount and location

of FGR. FGR is primarily applied to boilers.

Over-fire air (OFA) is a form of staged air combustion where only part of the required

amount of combustion air enters with the burners, and the remaining air needed to

complete the fuel’s combustion enters in the upper firebox. Lowering the concentration

of combustion air at the burners results in fuel rich combustion, which reduces the

availability of oxygen in the primary combustion zone, inhibiting NOx formation.

Injecting the air needed to complete the fuel combustion in the upper portion of the

firebox has the effect of extending the time of combustion and reducing the overall peak



5-26

combustion temperature. OFA systems are primarily used on coal-fired boilers due to the

large furnace volumes required to completely combust solid fuels.

Selective Non-Catalytic Reduction: SNCR is a post-combustion NOx control

technology in which a selective reagent, either ammonia or urea, is injected into the

exhaust gases to react with NOx/NO2, forming elemental nitrogen and water without the

use of a catalyst. This process is effective in reducing NOx/NO2 emissions within

specific constraints, requiring uniform mixing of the reagent into the flue gas within a

zone of the exhaust path where the flue gas temperature is within a narrow temperature

range of approximately 1600 to 2000°F. To achieve the necessary mixing and reaction,

the residence time of the flue gas within this temperature window must be at least one

half second. The consequences of operating outside the optimum temperature range are

severe. Above the upper end of the temperature range the reagent will convert to

NOx/NO2 and below the lower end of the temperature range the desired chemical

reactions will not proceed and the injected reagent will be emitted as ammonia slip.

EMx™: The EMx™ system (formerly referred to as SCONOX™) is an add-on control

device that simultaneously oxidizes CO to CO2, VOCs to CO2 and water, NO to NO2 and

then adsorbs the NO2 onto the surface of a potassium carbonate coated catalyst. The

EMx™ system does not require injection of a reactant, such as ammonia, as required by

SCR and SNCR and operates most effectively at temperatures ranging from 300°F to

700°F. The overall chemical reaction between NO2 and the potassium carbonate catalyst

is as follows:

2NO2 + K2CO3 → CO2 + KNO2 + KNO3

The catalyst has a finite capacity to react with NO2. As a result, to maintain the required

NOx/NO2 removal rate, the catalyst must be periodically regenerated. Regeneration is

accomplished by passing a reducing gas containing a dilute concentration of hydrogen

across the surface of the catalyst in the absence of oxygen. Hydrogen in the regeneration

gas reacts with the nitrites and nitrates adsorbed on the catalyst surface to form water and

molecular nitrogen. Carbon dioxide in the regeneration gas reacts with the potassium



5-27

nitrite and nitrates to form potassium carbonate, the original form of the chemical in the

catalyst coating. The overall chemical reaction during regeneration is as follows:

KNO2 + KNO3 + 4H2 + CO2 → K2CO3 + 4H2O + N2

The regeneration gas is produced in a gas generator using a two-stage process to produce

molecular hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted

across a partial oxidation catalyst to form carbon monoxide and hydrogen. Steam is

added to the mixture and then passed across a low temperature shift catalyst, forming

carbon dioxide and more hydrogen. The regeneration gas mixture is diluted to less than

four percent hydrogen using steam. To accomplish the periodic regeneration, the EMx™

system is constructed in numerous modules which operate in parallel so that one module

can be isolated and regenerated while the remaining modules are lined up for treatment of

the exhaust gas stream.

5.2.1.2 Step 2: Achieved/Demonstrated Cracking Furnace NOx/NO2 Limits

The application of good combustion practices, LNB, and SCR, separately or in

combination, are well established and demonstrated in process heaters and in cracking

furnaces used to manufacture ethylene. The primary issue related to the application of

these technologies to the ethane cracking furnaces is defining the achievable emission

rate for a specific cracking furnace; and Section 5.2.1 addresses this issue. The technical

feasibility of FGR/OFA, SNCR, and EMx™ are addressed in subsequent sections.

Good Combustion Practices and LNB Technology for Ethane Cracking Furnaces:

Good combustion practices and LNBs are considered to be technically feasible and as a

result applicable to cracking furnaces. Good combustion practices (design and operation)

are an integral part of the design and operation of all current cracking furnaces.

The following parameters affect the level of NOx/NO2 emissions that can be achieved by

a gaseous fuel-fired LNB in heater and furnace applications:

Fuel type,

Combustion air preheat,



5-28

Firebox temperatures, and

Furnace/heater design.

The impact of these parameters on the NOx/NO2 emissions from the proposed ethane

cracking furnaces is discussed below.

Fuel Type: Most gaseous fuel-fired process heaters are fired with natural gas, petroleum

refinery fuel gas, or a combination of the two. These fuels contain a high percentage of

methane (usually greater than 85 percent), which is the primary source of fuel heat

content (Btu per standard cubic feet).

In contrast, the tailgas that will be combusted in the proposed project’s cracking furnaces

will contain up to 85 percent by volume hydrogen with the remaining 15% being

methane. Because the proposed project is a standalone facility, and there are no nearby

facilities to which hydrogen can be exported, all of the byproduct tailgas (hydrogen and

methane) will be used as fuel in the ethane cracking furnaces.

The increased hydrogen concentration in the tailgas to the furnace burners will increase

the formation of NOx/NO2 from the proposed ethane cracking furnaces relative to other

ethylene manufacturing facilities that do not use ethane as a feedstock, or have customers

to which they export hydrogen. Hydrogen has a higher flame temperature, so hydrogen-

containing fuels generate more thermal NOx/NO2.25 For example, at a three percent

excess oxygen concentration, the adiabatic flame temperature for a mixture fuel

containing 80% hydrogen and 20% methane is approximately 3,450°F. In contrast, the

approximate adiabatic flame temperature for 100% methane is approximately 3260°F.

The net result is an increased level of thermal NOx formation because at temperatures

above 2800°F, thermal NOx formation increases exponentially with increases in

25 Figure C.3. Adiabatic Flame Temperatures for CH4 / H2 Mixtures, Ambient Combustion Air;

Appendix C. Burner NOx From Ethylene Cracking Furnaces, Robert G. Kunz, Environmental

Calculations: A Multimedia Approach, by Robert G. Kunz; Copyright 2009 John Wiley & Sons, Inc.

http://onlinelibrary.wiley.com/doi/10.1002/9780470925386.app3/pdf



5-29

temperature.26 The tailgas that will be fired in the proposed project’s cracking furnaces is

expected to generate NOx emission at the burners that are approximately 60 percent

higher than the emissions expected from firing low hydrogen content fuels.27 It should be

noted that the use of higher percentage hydrogen fuel has the advantage of lowering GHG

CO2 emissions.

Tailgas (methane and hydrogen) is a byproduct of the cracking process used to produce

ethylene. The relative amount of hydrogen produced as a byproduct from the process and

as a result burned in the furnace is a function of: 1) the hydrocarbon raw material that is

being cracked, and 2) whether the hydrogen that is generated by the cracking process is

recovered and sold or is used as a fuel. As noted in Section 3.0, ethane is the

hydrocarbon feedstock that will be used by the Project to produce ethylene. Feedstocks

used to produce ethylene at other locations include gas oil, naphtha (the predominate

feedstock), natural gas condensate, and liquefied petroleum gases. The relative amount

of hydrogen that is produced is a function of the hydrogen to carbon ratio of the

feedstock. Liquid feedstocks generate less hydrogen as a byproduct relative to ethane.28

However, a primary purpose of this project is to utilize ethane generated as a byproduct

from natural gas production in the Marcellus/Utica region, and use of alternative

feedstocks to reduce hydrogen are not consistent with the project’s purpose.

Combustion Air Preheat: Combustion air preheat is an effective method for reducing

fuel consumption for process heaters, but in some situations (as here) it may contribute to

increased production of NOx/NO2. Preheating the combustion air using the hot flue

gases from the heater reduces fuel consumption. This is typically accomplished by

installing an air to flue gas heat exchanger prior to the stack. Although the heat recovery

26 Page 4-1; USEPA Alternative Control Techniques Document—NOx Emissions from Process Heaters,

EPA-453/R-93-034. 27 Burner NOx From Ethylene Cracking Furnaces, Robert G. Kunz, Environmental Calculations: A

Multimedia Approach, by Robert G. Kunz; Copyright 2009 John Wiley & Sons, Inc.

http://onlinelibrary.wiley.com/doi/10.1002/9780470925386.app3/pdf 28 Ethane cracking generates four times more hydrogen and one-third less methane than naphtha cracking.

See Table 2 of “Olefins from conventional and heavy feedstocks: Energy use in steam cracking and

alternative processes”; Received June 1, 2004. http://igitur-archive.library.uu.nl/chem/2007-0621-

201429/NWS-E-2006-3.pdf



5-30

reduces fuel consumption, preheating the combustion air increases the formation of

NOx/NO2 emissions because the preheated air increases the temperature in the

combustion zone.

However, increasing the combustion air temperature in an ethane cracking furnace from

ambient to 350°F would increase the formation of NOx/NO2 from the furnace by

55 percent when burning high hydrogen containing fuel (which is the normal expected

tailgas fuel) and by 65 percent when burning natural gas or methane (the backup fuel).29

For the proposed ethane cracking furnaces, the heat recovered from the furnace’s hot flue

gases will be used to generate high pressure steam and preheat water for steam

generation. Thus, good overall process thermal efficiencies will be obtained without

preheating the combustion air and increasing the NOx/NO2 emissions rate from the

cracking furnaces.

Firebox Temperature: Firebox temperature is the average temperature within the

process heater or boiler where combustion takes place. As noted above, thermal NOx

formation increases exponentially with increasing flame temperature, and the flame

temperature is directly related to the firebox temperature. Therefore, applications

requiring high firebox temperatures, such as steam-methane-reformers and ethane

cracking furnaces, have higher inherent NOx emissions rates relative to applications with

medium to low firebox temperatures.30 Steam-methane-reformer (SMR) heaters operate

with firebox temperatures of 1800 to 1900 ºF. In contrast, ethane cracking furnaces

operate with firebox temperatures of 2100 to 2200 ºF.31 For comparable furnaces (i.e., a

comparison of SMR furnaces to ethane cracking furnaces), this increase in firebox

29 Id. Table C.3. 30 Maryland Industrial Boilers Emissions Report, September 2005. Maryland Department of Natural

Resources report DNR 12-10212005-70 (PPRP-134), at page 18. 31 Approximate Temperatures in Process Furnaces; Appendix C. Burner NOx From Ethylene Cracking

Furnaces, Robert G. Kunz, Environmental Calculations: A Multimedia Approach, by Robert G. Kunz;

Copyright 2009 John Wiley & Sons, Inc., at Table C.2.




5-31

temperature has been shown to result in a doubling of the NOx emissions (50 to 100 ppm

at 3% excess oxygen).32

As previously noted, to remove the coke deposited on the furnace tubes, ethane cracking

furnaces are decoked once every 30 to 60 days. Because coke inhibits the rate of heat

transfer, the cracking furnace firebox temperatures must be increased over the run length

as the amount of coke deposited increases. A typical start-of-run (SOR) temperature is

2160°F and a typical end-of-run (EOR) is 2185°F. Thus, NOx/NO2 formation increases

over the run period as the firebox temperatures are increased to overcome the deposition

of coke. To protect the tubes from thermal damage, furnace decoking is initiated when

the cracking tube skin temperature reaches a predetermined limit.

Furnace/Heater Design: Ethane cracking furnaces are very different from boilers and

other process heaters in both their design and operation. As one burner vendor states

“Cracking furnaces subject burners to the most abusive firing environment of all process

heaters.”33 The proposed cracking furnaces will have very high firebox temperatures for

two reasons: 1) the use of ethane as a feedstock requires higher cracking temperatures

relative to other feedstocks, and 2) the previously discussed high hydrogen content of the

fuel.

To obtain and operate at the high firebox temperatures required to crack hydrocarbons,

the burner/furnace designs for cracking furnaces differ significantly from boilers and

other process heaters. Typical boiler and process heater designs have an open firebox

with the radiant tubes located along the sidewalls of the firebox. The burners in these

applications fire into the center of the firebox. In contrast, ethane-cracking furnaces have

taller fireboxes with the radiant (cracking) tubes in the center of the firebox. In a

cracking furnace, floor and wall burners fire up along the refractory sidewalls to

minimize the possibility of flame impingement on the cracking tubes.

32 Id. Figures C.5 and C.6 for conventional burners and with no air preheat. 33 https://www.callidus.com/Documents/Burner_bro.pdf



5-32

Due to the differences in design, firebox temperatures and hydrogen content of the fuel,

the proposed cracking furnaces will have higher NOx emission rates than a typical boiler

or process heater. The current low NOx burner technology being used in a typical boiler

or process heater can achieve NOx emission rates of 0.03 pound per million Btu

(lb/MMBtu) or less. However, as discussed below, emission rates from well designed

and well operated ethane cracking furnaces are much higher.

The higher firebox operating temperatures required by ethane cracking furnaces and

higher flame temperatures due to the high hydrogen content of the fuel result in burner

operating issues not seen in boilers and other types of process heaters. As a result, the

staged burners that are used to achieve reduced NOx/NO2 in other types of boilers and

process heaters can plug and be thermally damaged at these higher temperatures. Staged

fuel burners have small diameter nozzles arranged around the perimeter of the burner that

accomplish the fuel staging required to reduce NOx/NO2 emissions by injecting fuel into

the primary combustion flame. This placement of small diameter nozzles close to the

primary combustion flame exposes the small diameter nozzles to high heat intensities,

making these nozzles much more prone to plugging and thermal damage. The resultant

damage to the small diameter nozzles impedes the burner’s ability to reduce NOx/NO2.

Industry experience with staged fuel burners in cracking furnace applications has

identified the following issues that impact the achievable NOx/NO2 emissions rates:

When the gas velocity in the primary combustion zone is lower than the flame

velocity, the flame front recedes into the burner tips (flashback) causing

mechanical/structural thermal damage. The potential flashback is increased when

the fuel contains hydrogen, which has a very high flame velocity.

At increased temperatures, hydrocarbons in the fuel are more likely to undergo

pyrolysis and form coke in the burner nozzle tips and plug the tips.

Too large of an exposed burner area inside the firebox with insufficient or

damaged insulation, in combination with insufficient cooling from the fuel gas

inside the burner riser, can result in high internal burner riser temperatures and

coke formation/carburization in the riser with subsequent plugging. High

hydrogen content in the fuel reduces the fuel’s specific heat capacity, which in

turn reduces the amount of cooling provided by the fuel.



5-33

Heat transfer through the nozzle tip is a function of velocity as well as mass flow.

During conditions of low mass flow (turndown or plugging), the external burner

tips can become severely fouled.

As a result, the LNBs installed in cracking furnaces are chosen with these operational and

maintenance issues in mind and do not achieve the deep reductions achieved by the LNBs

that can be installed in process heater and boiler applications.

Permit Limits: To exemplify the NOx/NO2 levels achievable by LNBs, the permitting

precedents were divided into two groups: 1) permits where only LNBs were used for

control, which were found in the precedents ten years prior to 2012 and 2) permits where

both LNB and SCR are used (recent permits). Table 5-2 presents a summary of the

results from a review of the RBLC database with respect to limits established for cracker

furnace installations during the ten year period prior to 2012. All three of the

determinations identified are based on the use of burner technology. The hourly NOx

limits range from 0.075 to 0.08 lb/MMBtu and annual limit is the same for all three,

0.06 lb/MMBtu. The BASF FINA cracking furnaces are fired with a combination of

natural gas and refinery gas.34,35 This facility is known to supply hydrogen to the pipeline

and to a nearby refinery for use in the refinery’s hydrotreaters. In addition, the feedstock

for two facilities identified in Table 5-2 is naphtha, where the amount of hydrogen

produced per unit of ethylene production is much less than for the proposed ethane

cracking project. As a result, the amount of hydrogen in the fuel used by these cracking

furnace precedents is much less than the proposed Shell project.

During the past two years, at least five companies have filed air permit applications for

olefin (ethylene) plant expansion or new plant projects located in the Houston-Galveston-

Brazoria ozone nonattainment area. Three of these companies recently received their

permits from the Texas Commission on Environmental Quality (TCEQ). The

information obtained from a review of the permit applications and permits issued for

34 The TOTAL petroleum refinery formerly the FINA petroleum refinery. 35 See Figure 3 of “Upgrade of a Tail-End Acetylene Converter BASF FINA Petrochemicals Limited

Partnership Naphtha Cracker”, April 25, 2006.

http://kolmetz.com/pdf/Upgrade%20NROC%20Converter_2006%20EPC%20Meeting.pdf



5-34

Table 5-2. Summary of RBLC Ethylene Cracking Furnace NOx Emissions Limits (prior to the past two years)

RBLC

ID Facility Name

Permit

Date Primary Fuel

Heat Input

(MMBtu/hr)

Control

Technology

Hourly Limit

(lb/MMBtu)

TX-

0511

BASF FINA

Ethylene/Propylene

Cracker

02/03/2006

Not indicated,

probably refinery or

natural gas – see

text

302

(1 furnace) Burner Technology 1 0.08

TX-

0511

BASF FINA

Ethylene/Propylene

Cracker

02/03/2006

Not indicated,

probably refinery

or natural gas – see

text

441.7

(8 furnaces) Burner Technology 1 0.08

TX-

0475

FORMOSA

Point Comfort, TX 5/9/2005 Fuel Gas

250

(3 pyrolysis

furnaces)

Internal Flue Gas

Recirculation and

Staged Fuel Gas

Ultra Low-NOx

Burners

0.075 2

1. From TCEQ permit number 36644, PSD-TX-903, and N-007; February 2010.

2. TCEQ permit 19169 MAERT verified RBLC lb/hr and tpy rates.



5-35

Table 5-3. Summary of Recent Ethylene Cracking Furnace NOx Emission Limits

Permit Date

Facility Name &

Location Permitted Fuel

Heat Input

(MMBtu/hr)

Hourly Limit

(lb/hr)

LNB+SCR Short

Term Limit

(lb/MMBtu)

LNB+SCR

Annual Limit

(lb/MMBtu)

5/2012 1

(2/2103

draft permit)

ExxonMobil

Baytown, TX

Natural gas or blend

of natural gas and

tailgas

575 2

(8 furnaces) 143.79

0.015

24-hour rolling

(8 furnace cap)

0.01

(8 furnace cap)

08/06/2013 3

(permit)

Chevron/Phillips

Cedar Bayou, TX

Plant fuel gas,

ethane, or natural

gas.

500

(8 furnaces)

32.50 (SCR not

operating &

decoking)

(~

0.065 lb/MMBtu)

0.015 (24-hr roll)

12.5 lb/hr (hourly)

(~0.025 lb/MMBtu)

0.010

(8 furnace cap)

11/14/2012 4

(permit)

Equistar

Channelview, TX

OP-2

Natural gas &

limited use of

hydrogen 5

640

(1 furnace) 38.4 None found

25.71 tpy

(~0.01 lb/MMBtu)

1/23/2013 6

(permit)

Equistar

Channelview, TX

OP-1

Natural gas &

limited use of

hydrogen 7

640 max

587 annual 7

(2 furnaces)

12 6 lb/hr 0.01

7/16/2012

(permit) 8

BASF FINA

Port Arthur, TX

Natural gas or

cracker off gas

(tailgas)

487.5

(1 furnace)

48.75 (startup &

short term spikes)

(~ 0.1 lb/MMBtu)

0.025 hourly 0.01

1. ExxonMobil Chemical Company; New Source Review Permit Application for Ethylene Expansion Project; Baytown Olefins Plant,

Baytown, TX; May 2012. TCEQ Draft Special Conditions & Maximum Allowable Emission Rates Permit Number 102982 (no dates).

2. Based on 5,037,000 MMBtu/yr / 8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit

Application for Ethylene Expansion Project, Baytown, TX.

3. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1504A, PSDTX748M1, and N148.

4. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (11/2012).

5. Permit Amendment Application Greenhouse Gas Emissions, Equistar Chemicals, Channelview, TX; Olefins Production Unit No. 2,

September 2011.

6. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 18978 PSDTX752M5, N162, 1/2013.

7. Permit Amendment Application Greenhouse Gas Emissions, Equistar Chemicals, Channelview, TX; Olefins Production Unit No. 1,

September 2011.

8. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M3, and N007M1, 7/2012.



5-36

these projects is summarized in Table 5-3. Not presented is the information for a project

at the Dow Chemical Freeport, Texas facility for which the application is currently

pending. Because of the relationship of fuel composition to the rate of NOx emissions

achievable through the use of low NOx burner technology, the fuels that will be fired by

the proposed new ethane cracking furnaces are also presented.

The permit application for the ExxonMobil Baytown Olefins Plant covers the

construction of eight new ethane cracking furnaces equipped with ultra low NOx burners

and SCR. A combined draft state and PSD permit has been issued by TCEQ. 36 This

permit was appealed and the results from the contested case hearing are now available. 37

During normal operation, the fuel for the ExxonMobil furnaces will be “imported natural

gas or a blend of process gas that consists of imported natural gas and tailgas.”38 The

draft permit for the ExxonMobil project includes the proposed NOx limits of

0.015 lb/MMBtu as a 24-rolling average of eight furnaces, and 0.01 lb/MMBtu as an

average of eight furnaces on a 12-month rolling basis. These lb/MMBtu limits are the

same as those included in the Chevron/Phillips permit and as proposed by Dow Chemical

in its permit application.

As noted, the lb/MMBtu limits for ExxonMobil and Chevron/Phillips precedents are not

applicable during the following activities:39

Hot Steam Standby Mode, defined as the period when the furnace is firing at 50%

or less of the maximum allowable firing rate and no hydrocarbon feed is being

charged to the furnace.

36 Draft special conditions and maximum allowable emission rate documents for permit 102982 are not

dated. The final permit was pending as of December 30, 2013. 37 State Office of Administrative Hearings, Cathleen Parsley. Chief Administrative Law Judge, SOAH

Docket No. 582-13-4611; TCEQ Docket No. 2013-0657-AIR; In Re: Application 0/ Air Quality Permit

No. 102892 for the Construction of a New Ethylene Production Unit at ExxonMobil's Baytown Olefins

Plant, located in Harris County, Texas, December 18, 2013. 38 ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for Ethylene

Expansion Project; May 2012, page 2-1. 39 Draft special conditions and maximum allowable emission rate documents for permit 102982 are not

dated. Special Condition No. 21, page 15.



5-37

Decoking Mode, defined as the period that starts when air is introduced to the

furnace for the purpose of decoking and ends when air is removed from the

furnace.

Start-up Mode, defined as the period beginning when fuel is introduced to the

furnace and ending when the SCR catalyst bed reaches its stable operating

temperature. A planned startup for each furnace is limited to 24 hours at 25% or

less of the maximum allowable firing rate, except during startups requiring

refractory dry out which is limited to 72 hours at 25% or less of the maximum

allowable firing rate.

Shutdown Mode, defined as the period beginning when the SCR catalyst bed first

drops below its stable operating temperature and ending when the fuel is removed

from the furnace.

Feed in Mode, defined as the period beginning when hydrocarbon feed is

introduced to the furnace and ending when the furnace reaches 70% of the

maximum allowable firing rate.

Feed out Mode, defined as the period beginning when a furnace drops below 70%

of the maximum allowable firing rate and ending when hydrocarbon feed is

isolated from the furnace.

During these periods of operation, the eight ExxonMobil furnaces are subject to a mass

emissions rate of 143.79 lb/hr. At full load, which is equal to 575 MMBtu/hr, this mass

rate is roughly equivalent to 0.25 lb/MMBtu if only one of the two furnaces are

experiencing one of the listed activities. For two furnaces experiencing one of the listed

activities (i.e., the more likely scenario), the rough equivalency would be

0.125 lb/MMBtu. The concentration of hydrogen in the fuel gas that will be fired by the

ExxonMobil furnaces will be much lower than will be fired by the proposed Shell project

furnaces.

In August 2013, Chevron/Phillips received state and PSD permits from TCEQ for the

addition of eight cracking furnaces at the Cedar Bayou, TX facility. The permit

application states that LNBs and SCR will be used to control NOx emissions. The fuel

used to fire the furnaces will be process off gases (i.e., tailgas) supplemented with natural

gas when necessary. “Typically, the ethane steam cracking furnaces will combust plant

tailgas (“fuel gas”); however, the furnaces may also operate on pipeline quality natural



5-38

gas.” 40 During decoking, there is a short-term mass emissions limit of 48.75 lb/hr when

the SCR is not operating. This rate appears to fulfill the same objective as the

ExxonMobil activities based condition.

Equistar submitted two separate applications covering the addition of new cracking

furnaces at each of its Olefins Plants located at the Channel View, TX facility (i.e., OP-1

and OP-2). State and PSD permits were issued by TCEQ for new cracking furnaces at

OP-1 and OP-2 in January 2013 and November 2012, respectively. The primary fuel for

these cracking furnaces is natural gas with limited use of hydrogen. The annual permit

limits for both the OP-1 and OP-2 furnaces is 0.01 lb/MMBtu. Based on the available

information, there appear to be two hourly limits for the new furnaces at OP-1: 6 lb/hr

and 12 lb/hr covering normal and startup operations, respectively. No information related

to the other activities defined by the ExxonMobil permit was identified in the Equistar

permit. Based on a review of the maximum emissions rate table for the Equistar permit,

it appears that there is also a short-term limit of 38.4 lb/hr intended to cover operation of

the furnaces when the SCR is not in service. No information related to the other

activities defined by the ExxonMobil permit was identified in permitting records for

either of the other two projects presented in Table 5-3.

In July 2012, BASF FINA received state and PSD permits for an additional cracking

furnace equipped with LNBs and SCR.41 The permit limits for the new furnace are:

0.01 lb/MMBtu as an annual average, 0.025 lb/MMBtu/hr for a maximum hourly during

normal operation, and 48.75 lb/hr during startup and short term spikes. The form of the

limits for the BASF FINA permit are similar to the ExxonMobil and Chevron/Phillips

precedents in that there are hourly and annual lb/MMBtu limits for normal operation and

an hourly mass emissions limit covering alternate operating scenarios. Of note is the fact

that the 0.01 lb/MMBtu annual limit is consistent with the other precedents and the

40 Chevron Phillips Chemical Company LP; Cedar Bayou Plant; New Ethylene Unit 1594; Greenhouse Gas

PSD Permit Application; December 2011, page 17, 41 BASF FINA Petrochemicals LP, Application for Air Permit Amendment for the 10th Furnace Project;

March 11, 2011.



5-39

0.025 lb/MMBtu hourly rate that is consistent with the Chevron/Phillips facility. The

BASF FINA furnace will use natural gas or cracker off gas as its fuel. The hydrogen

produced by the cracking process will be exported to Port Arthur Refinery (PAR) and to

a pipeline. Thus, the level of hydrogen in the fuel-fired in the new BASF FINA cracking

furnace will be much lower than is proposed by Shell.

In summary, the past and recent precedents for ethane cracking furnaces indicate the

following:

All of the prior (pre-2012) precedents (i.e., Table 5-2) covering 12 cracking

furnaces are fired with a fuel that is much lower in hydrogen content than the

proposed Project. The short-term, hourly NOx limit for these furnaces range from

0.075 to 0.08 lb/MMBtu. The annual NOx limit for all of the furnaces is

0.06 lb/MMBtu.

All of the six most recent precedents (i.e., Table 5-3) covering over 20 furnaces

have some form of an annual NOx limit (single furnace or group cap) of

0.01 LB/MMBtu.42

The most stringent short-term limit based on these recent precedents is

0.015 lb/MMBtu on rolling 24-hr average basis.

All of the precedents use mass rate hourly limits during alternate activities,

similar to those defined by the draft ExxonMobil and Chevron/Phillips permits.

None of the recently permitted projects have begun operation, so none of these

limits have been demonstrated in practice.

In considering the above precedents, it is notable that a number of factors result in the

high level of hydrogen in the process gas (~85% by volume) produced by the Project’s

cracking furnaces, resulting in a higher level of hydrogen in the tailgas that will serve as

the primary fuel for the cracking furnaces. The main factors are:

1) Hydrogen will be produced in large quantities as a co-product with ethylene.

Nearly all of the co-produced hydrogen and methane will be burned in the ethane

cracking furnaces. This will result in a large volume of hydrogen in the fuel gas

that is combusted in the cracking furnaces (~85 volume percent of hydrogen with

the balance being almost entirely methane). By contrast, natural gas usually

contains no hydrogen and is composed primarily of methane with other light

42 Based on a review of the technical support documents for these precedents, this level is considered to be

LAER for this class or category in Texas.



5-40

hydrocarbons. At sites where refinery fuel gas is available, the hydrogen content

in the refinery fuel gas is usually less than 15 volume percent.

2) The proposed facility will be a self-contained, ethane to chemicals manufacturing

site for producing finished chemicals such as polyethylene from ethane feedstock.

The facility will be located at an isolated site and will not be integrated with other

petrochemical or oil refining sites. Accordingly, nearly all intermediate chemicals

produced will be used at the site to manufacture finished chemicals.

It should be noted that hydrogen has many favorable combustion characteristics,

including zero CO2 emissions and extremely high flame speed, which results in

exceptional combustion stability. In many respects, it is an excellent fuel; however it also

has a high flame temperature that together with other combustion characteristics results in

an increased rate of NOx emissions. Robert G. Kunz describes this effect in detail in his

paper entitled “NOx From Ethylene Cracking Furnaces” (included in Appendix F).43

More specifically, in that paper, “Table C.3. Predicted Ethylene Furnace NOx Peak

Values, Burners and Air Preheat as Shown” can be used to predict NOx emissions as a

function of fuel gas hydrogen content.

When the hydrogen is recovered for sale or other use and not used as fuel for the

furnaces, the hydrogen content in the tailgas that is combusted in the cracking furnaces is

in a range between 10 and 30 volume percent. Table C.3 shows that a fuel gas with 10 to

30 volume percent hydrogen has a predicted NOx emission rate of 0.041 to 0.043 lb

NOx/MMBtu (HHV) from LNBs (without air preheat). This is a design number though,

not a permit limit. Because burners foul over time, NOx emissions increase over the run

length between turnarounds. As a result, permit limits must account for this impact.

The cracking furnace precedents presented and discussed above, which had short-term

NOx limits of 0.06 lb/MMBtu to 0.065 lb/MMBtu for burners fired with lower level

hydrogen fuel (i.e., 10 to 30 volume percent), illustrate this fact. Based on the

information presented in Table 5-3 (for the case of no air preheat), the Project’s cracking

43 Burner NOx From Ethylene Cracking Furnaces, Robert G. Kunz, Environmental Calculations: A

Multimedia Approach, by Robert G. Kunz; Copyright 2009 John Wiley & Sons, Inc.




5-41

furnaces, which will be fired with a fuel having ~85 volume percent hydrogen, will

produce NOx at a rate of ~0.06 lb/MMBtu where the same LNBs are used.

Selective Catalytic Reduction Technology for Ethane Cracking Furnaces: SCR

systems have been applied at several ethane cracking furnaces in the United States, and

are considered to be technically feasible for application on the proposed project’s

cracking furnaces. Although not in the RBLC database, Shell Chemical has extensive

experience using LNBs and SCR for NOx control on cracking furnaces. Shell received a

permit for the restart of the Deer Park, TX Olefins Plant Number 2 in August 2000.

These ten naphtha based cracking furnaces were retrofitted with low NOx burners to

meet permit limits of 0.08 lb NOx/MMBtu on an hourly basis, 0.06 lb/NOx/MMBtu on

an annual basis, and Selective Catalytic Reduction (SCR) to meet a limit of 0.03 lb

NOx/MMBtu on an annual basis averaged across all ten furnaces.44

As presented in Table 5-3, more recent precedents have been set with annual emission

limits of 0.01 lb NOx/MMBtu on a rolling 12-month basis, the TCEQ presumptive

BACT requirement for process furnaces and heaters.45,46 Three of the precedents establish

limits for individual cracking furnaces, and two have limits based on caps across eight

cracking furnaces.

Based on a comparison of the permitted limits for LNB only in Table 5-2 to recent

projects listed in Table 5-3 based on LNB and SCR, the expected average annual

performance of the SCR system ranges from 75 to 85 percent.47 There are two reasons for

the apparent somewhat low SCR performance. At end of run before shutdown for burner

maintenance, the burners are fouled with coke and the LNB emission rates are higher

44 Texas permit 3219 & PSD-TX-974; August 2000; Condition 14. 45 TCEQ Chemical Sources Current Best Available Technology (BACT) Requirements Process Furnaces

and Heaters, last revision Date 08/01/2011.

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_processfu

rn.pdf 46 In Texas if the proposed NOx limit for a process furnace or heater is greater than 0.01 lb NOx/MMBtu,

the applicant must undergo case-by-case review, and submit cost data to justify a higher NOx limit. 47 77% = [1 - 0.015 lb/MMBtu/0.06 lb/MMBtu]*100% and 85% = [1 - 0.010 lb/MMBtu/0.065 lb/MMBtu]

*100%.



5-42

than 0.06 and 0.065 lb/MMBtu. The other reason is as previously discussed, ethane

cracking furnaces operate at high temperatures to provide the heat necessary to thermally

crack hydrocarbons such as ethane. These high furnace temperatures translate into high

radiant tube skin temperatures in the furnace radiant section (lower part of the furnace).

As a result, the radiant tubes are made of special metal alloys and must be replaced every

two to three years. Ethane cracking furnaces typically employ radiant tube-metal alloys

containing upwards of 35 percent chromium.48

Ethane cracking furnaces controlled with SCR in Japan and the United States have

experienced a more rapid decline in SCR catalyst activity than would be expected for a

clean fuel/flue gas application (natural gas and refinery gas-fired process heaters, boilers,

and combustion turbines). At one Japanese ethylene plant, deactivation of 70% to 80%

from initial conditions was observed after one year of operation, versus an originally

anticipated deactivation rate of less than 10%. The premature loss of SCR catalyst

activity in that case was ascribed to chromium compounds condensing on the catalyst

surface. The exact mechanism is unknown at this time, but steam-methane reformers

equipped with SCR have a similar high rate of catalyst deactivation, as the process tube

metallurgy for steam-methane reformers is similar to that of ethane cracking furnaces.49

The chromium compounds that pass through the SCR are deposited on the downstream

convection section tubes in the form of black chromium oxide scale.

The more rapid SCR catalyst deactivation has two important impacts on ethane cracking

furnace applications. First, the expected catalyst life is reduced, and second the catalyst

performance (control efficiency) will drop over the three to four years of operation before

a furnace rebuild or a major maintenance shutdown of the plant. As a result, unlike

process heaters, boilers, or combustion turbines, special considerations must be given to

the NOx reductions achievable by an SCR in a cracking furnace application.

48 SCR Treatment of Ethylene Furnace Flue Gas, ICAC (Institute of Clean Air Companies) Forum ’02,

February 2002; Robert G. Kunz and T. Robert von Alten; Cormetech, Inc, page 5.

http://www.cormetech.com/brochures/ICAC2001%20Paper%20-

%20SCR%20Treatment%20of%20Ethylene%20Furnace%20Flue%20Gas.pdf 49 Ibid. page 8 & 9.



5-43

SCR system design considers many variables. The major variables include the amount of

catalyst, type of catalyst, operating temperature of catalyst, catalyst life, the allowable

ammonia slip, and the desired NOx reduction. For the proposed Project’s cracking

furnace SCR systems, there are two end-of-run (EOR) periods that must be

accommodated over the three to four years of operation for radiant coil life. As

previously noted, cracking furnaces go through a decoking process every 30 to 60 days.

As coke builds up on the inside of the radiant tubes over the 30 to 60 day cycle, firebox

and tube temperatures must be increased to overcome the insulating effect of the coke

deposits in the radiant tubes at constant yield. As a result, the NOx emissions at EOR,

just before decoking, are higher due to the increased firebox and tube temperatures. This

requires a higher percentage NOx removal by the SCR just before decoking to maintain

compliance with the NOx permit limits. There is a three to four year EOR cycle for the

SCR system catalyst replacement. As a result of the two EOR cycles for the cracking

furnace decoking and SCR catalyst replacement, actual NOx reduction levels for ethylene

cracking furnaces are less than 90 percent on a short term and annual basis.

The degradation of the SCR catalyst with time is recognized in the proposed permit limits

for one of the Texas ethylene expansion project applications. The draft permit for the

ExxonMobil Baytown facility contains a combined limit of 0.015 lb/MMBtu over the

eight (8) furnaces on a 24-hour rolling basis, and an annual combined limit of

0.010 lb/MMBtu over the eight (8) furnaces. The combined limits allow the SCR units,

which have recently undergone catalyst upgrades, to compensate for other units where

the SCR catalyst is approaching the end of its useful life.

Flue Gas Recirculation and Over-Fire-Air: Although external FGR and OFA have

been used extensively on natural gas-fired boilers, this technology has not been

demonstrated to function efficiently on cracking furnaces. This is because unlike natural

gas-fired boilers, which typically have a few burners (one to four), cracking furnaces

have hundreds of burners. In addition, the low NOx burners used in furnaces are

designed with internal flue gas recirculation and internal air/fuel staging. As a result, the

benefit of external FGR and OFA is negated. Additionally, boilers and typical process

heaters have open fireboxes; the tubes are on the firebox walls. Cracking furnaces have



5-44

tubes hanging down the center of the firebox, making the injection of flue gas or air

across the firebox without causing flame impingement on the tubes impractical. Due to

these significant technical differences between gas-fired boilers and the proposed ethane

cracking furnaces, external FGR and OFA have not been demonstrated to function

effectively on ethane cracking furnaces. Thus, external FGR and OFA are removed from

further consideration.

Selective Non-Catalytic Reduction: The SNCR reaction occurs in the temperature

window of 1,600°F to 2,000°F. For large utility boilers where most SNCR systems have

been installed, this temperature window is in the upper furnace section before the

convection tubes. This area of a typical utility boiler is clear of convective tube

obstructions, allowing for injection of the reagent across the upper furnace area. Even

under ideal conditions, the NOx removal capability of SNCR (30 to 70 percent) is much

less than that of SCR.

For the proposed Project’s cracking furnaces, the ideal temperature window for an SNCR

reaction is in the convective tube section of the furnace. This makes it difficult to inject

the SNCR reagent (ammonia or urea) across the furnace, significantly limiting good

mixing of the reagent with the flue gases. In turn, this limits the potential NOX/NO2

reduction, and increases the amount of unreacted ammonia in the flue gases going to the

atmosphere. Additionally, injection of the reagent into the tube sections of the furnace

can result in accelerated corrosion and erosion of the process tubes. Due to the very

limited NOX/NO2 reduction achievable and potentially high ammonia slip emissions, the

use of SNCR is considered to be technically infeasible for cracking furnaces. The RBLC

database review and the review of recent permit applications submitted in Texas for new

cracking furnaces did not identify the use of SNCR for NOx control on cracking

furnaces.



5-45

EMx™: There are currently six EMx™/SCONOX™ units in commercial installations

worldwide. All are on natural gas-fired combustion turbines of 45 MW or less.50 There

are no known installations on process heaters or cracking furnaces. There are a number

of differences between the operation and flue gas characteristics of combustion turbines

and the proposed cracking furnaces. Specifically, combustion turbines are essentially

constant flue gas flow combustion devices no matter what the load. Process

heater/furnace flue gas flow rates are directly proportional to load. The impact on the

load following ability of the EMx™/SCONOX™ is unknown with respect to cracking

furnaces. Additionally, the concentration of NOx/NO2 in the flue gases from the

cracking furnaces is much higher than that of the combustion turbine flue gases. This is

due to the high oxygen content of the combustion turbine flue gas (~15% O2) relative to

the cracking furnace flue gas (~3% O2). The impact of the flue gas oxygen content and

NOx/NO2 concentration on the EMx™/SCONOX™ is unknown with respect to cracking

furnaces. Additionally, the flue gas flow from the cracking furnaces and NOx/NO2

concentration during furnace tube decoking are significantly different from that during

normal operation. The impact on the load following ability of the EMx™/SCONOX™

during tube decoking is unknown.

Because the SCR technology demonstrated on cracking furnaces can achieve reductions

in NOx/NO2 comparable to EMx™ / SCONOX™, taking on the risk of an

undemonstrated technology is not warranted. In addition, the EMx™ / SCONOX™

regeneration process is mechanical in nature and the associated maintenance practices are

much different (higher cost) from that of the SCR technology, which relatively speaking

has very low maintenance requirements. For these reasons, the EMx™/SCONOX™

technology is not considered further by this analysis.

50 The heat input for a 45 MW combined cycle combustion turbine would be approximately 300

MMBtu/hr, assuming an efficiency of 50 percent.



5-46

5.2.1.3 Step 3: Establish Cracking Furnace NOx LAER Limits

Based on the permit precedents presented in Table 5-3, the following NOx/NO2 emission

limits are proposed as LAER/BACT for the proposed ethane cracking furnaces:

0.010 lbs/MMBtu per furnace on a 12-month rolling average basis for each furnace,

and

0.015 lbs/MMBtu per furnace on an hourly average basis.

The annual and hourly lb/MMBtu limits would not apply during the following

activities; instead, each furnace shall not exceed a mass hourly NOx emissions rate of

31.1 lbs/hr.51

Cold Start-up Mode, defined as the period beginning when fuel is introduced

to the furnace and ending when the SCR catalyst bed reaches its design

operating temperature.

Shutdown Mode, defined as the period beginning when the SCR catalyst bed

first drops below the catalyst bed design operating temperature and ending

when the fuel is removed from the furnace.

Decoking Mode, defined as the period beginning when air is introduced to the

furnace for the purpose of decoking and ends when air is removed from the

furnace.

Hot Steam Standby Mode, defined as the period when the furnace is firing at

50% or less of the maximum allowable firing rate and no hydrocarbon feed is

being charged to the furnace.

Feed in Mode, defined as the period beginning when hydrocarbon feed is

introduced to the furnace and ending when the furnace reaches 70% of the

maximum allowable firing rate.

Feed out Mode, defined as the period beginning when a furnace drops below

70% of the maximum allowable firing rate and ending when hydrocarbon feed

is isolated from the furnace.

The proposed emission limits for the ethane cracking furnaces must meet two criteria to

be considered LAER:

1) The limit must be at least as stringent as the most stringent emission limitation

which is contained in the implementation plan of a state for the class or category

of source unless the owner or operator of the proposed source demonstrates that

such limitations are not achievable, and

51 Basis: expected NOx emission rate prior to reaching the SCR operating temperature during a cold

startup. (0.18 lb/MMBtu)*(157 MMBtu/hr)*(1.1) = 31.1 lb/hr



5-47

2) The limit must reflect the most stringent emission limitation, which is achieved in

practice by the class or category of source.

To determine if the proposed limit is as stringent as the most stringent emission limitation

which is contained in an implementation plan, a review of the 2011 copy of the Oil &

Gas Journal International Survey of Ethylene from Steam Crackers was performed to

identify states where ethylene cracking furnaces are located. The results of that analysis

are presented in the table below.

State Number of Plants

Illinois 1

Iowa 1

Kentucky 1

Louisiana 9

Texas 25

As a result, the review of various state and local agency rules, regulations and permit

limits focused on the states of Louisiana and Texas. The proposed Project’s cracking

furnace emission limits meet the first criterion because a review of the Texas and

Louisiana SIP approved regulations found NOx regulations with emission rates higher

than those proposed here for the Project’s cracking furnaces. Thus, the proposed

emissions limits meet both of the LAER criteria.

More specifically, the TCEQ rule at Tex. Admin. Code tit. 30, Chapter 117 Subchapter B

contains specific emission limits for control of nitrogen compound emissions from

process heaters and boilers located in ozone nonattainment areas. There are three

nonattainment areas (Beaumont-Port Arthur, Dallas-Fort Worth, and Houston-Galveston-

Brazoria) with regulations that address NOx emissions from process heaters and boilers.

Only the Houston-Galveston-Brazoria nonattainment area regulations have a specific

category for ethane cracking furnaces; referred to in the regulation as a pyrolysis reactor



5-48

process heater.52 The NOx emission limit for a pyrolysis reactor process heater is

0.036 lb/MMBtu.

The Louisiana Department of Environmental Quality (LDEQ) rule at La. Admin. Code

tit. 33, Part III Chapter 22 has specific emission limits for control of nitrogen compounds

from process heaters/furnaces in the Baton Rouge ozone nonattainment area. The

regulation has a specific category for process heaters/furnaces that are not ammonia

reformers. The NOx emission limit for “All Others” is 0.08 lb/MMBtu.53 This regulation

also has an adjustment multiplier to apply to the emission factor for process

heaters/furnaces that fire gaseous fuel containing hydrogen and/or carbon monoxide. The

total hydrogen and/or carbon monoxide volume in the fuel is divided by the total fuel

flow volume to determine the volume percent of hydrogen and/or carbon monoxide in the

fuel. For fuels containing greater than 50 percent hydrogen + carbon monoxide, the fuel

multiplier is 1.25. The purpose of the fuel multiplier is to adjust the emission factor due

to the presence of hydrogen in the fuel, recognizing that high hydrogen fuels have higher

NOx emission rates relative to methane/natural gas. For the proposed Project’s ethane

cracking furnaces, the corresponding emission limit in the Baton Rouge ozone

nonattainment area would be 0.10 lb/MMBtu (0.08 x 1.25 = 0.10).

The emissions limit proposed matches the most stringent precedent identified by a review

of the permit limits for recently permitted ethane cracking furnaces, summarized in Table

5-3. It should be noted that none of these limits have yet been demonstrated in practice,

which is a key component of the second criteria. As previously noted, no applicable NOx

standards have been promulgated for cracking furnaces under 40 CFR Parts 60 and 61.

In accordance with 25 Pa. Code §127.205(7), the proposed NOx LAER limit is

equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

52 Pyrolysis reactor is one of several terms used to describe the manufacture of ethylene. Other terms

include cracker, cracking, thermal cracking, steam cracking, ethylene cracker, ethylene unit, ethylene

heater, ethylene furnace, and pyrolysis furnace. 53 See Table D-1A on page 224 of Title 33, Part III.



5-49

5.2.1.4 Cracking Furnace NO2 BACT Considerations

The criteria for determining a BACT limit are somewhat different than the criteria for

determining a LAER limit. LAER is based in part on the most stringent limit that has

been demonstrated in practice, while the BACT methodology requires consideration of

potential technology transfer from other classes and categories of sources, with

evaluation of applicability, technical feasibility, and whether environmental, energy or

economic factors render a particular technology inappropriate.

In this case, the proposed LAER limit discussed above is based on the application of

LNB and SCR technologies, which are the same control technologies that would be used

to control NOx emission from other combustion sources. The NOx emissions from the

proposed ethane cracking furnaces are a function of the feedstock, fuel fired, firebox

temperatures required to crack ethane into ethylene, burner/furnace design and

application of SCR. These factors significantly influence the achievable NOx emission

rates from the proposed ethane cracking furnaces as follows.

The proposed feedstock is ethane, recovered as a byproduct of natural gas

production. This feedstock requires very high firebox temperatures to crack the

ethane into ethylene.

Cracking ethane instead of an alternative feedstock makes a significantly greater

amount of hydrogen as a byproduct of the cracking process. Because there is not

a market for the hydrogen near the proposed site, the byproduct hydrogen and

methane will be fired in the cracking furnaces to provide the thermal energy

necessary to crack ethane into ethylene. Fuels with high hydrogen content

generate higher quantities of NOx relative to natural gas and typical refinery gas

because hydrogen has a higher adiabatic flame temperature than does methane,

the predominate gas found in natural gas and refinery gas. The proposed Project’s

cracking furnace fuel gas will contain approximately 85 volume percent

hydrogen. This high concentration of hydrogen in the fuel gas results in

approximately 60% higher NOx production at the burners compared to a furnace

firing typical fuel gas with hydrogen concentration at 15% volume or less.

Ethylene cracking furnaces have very high firebox temperatures relative to typical

gas-fired boilers, process heaters and steam/methane reformers. These high

temperatures are required to heat the ethane to its cracking temperature. As a

result, the burner/furnace NOx/NO2 emissions are higher than for typical gas-fired

boilers and process heaters.

Ethane cracking burners/furnaces are designed to generate the high firebox

temperatures necessary to heat the cracking (radiant) tubes to the ethane cracking



5-50

temperature. Operation is challenging due to the very high temperatures. In

particular, the burners are subject to plugging and thermal damage. The plugging

results from carbonization of hydrocarbons in the fuel. The thermal damage

occurs primarily to the secondary and tertiary injection nozzle tips used to create

staged fuel firing in the burners. Plugged or thermally damaged fuel nozzle tips

result in less burner NOx reduction and higher emission rates of NOx.

SCR is proposed to reduce the NOx emissions from the proposed ethane cracking

furnaces. As compared to typical gas-fired boilers and process heaters, the SCR

will have higher inlet NOx concentrations for the reasons described above than

would process heater/boiler applications where LNB and SCR are employed to

control NOx emissions.

Ethane cracking furnaces typically employ radiant tube-metal alloys containing

upwards of 35 percent chromium to withstand corrosion and high temperatures.

Chromium is an SCR catalyst poison. Over time, some of the cracking tube

chromium is released and deposits on the SCR catalyst. This results in decay in

the achievable NOx/NO2 reduction. As a result, very high SCR reductions

(greater than 90% reduction) are not achievable while maintaining acceptable

ammonia slip concentrations over the three to four year run lengths between

major furnace maintenances outages.

The proposed LAER limits are based on application of NLB technology coupled with

87.5 percent control with the SCR system on an annual basis for each furnace. This

proposal is based upon the same technologies as used to control NOx from other

combustion sources and the SCR performance level is as stringent as technically feasible.

As a result, the proposed cracking furnace LAER limits are considered to be equal to or

more stringent than BACT.

5.2.2 Cracking Furnace VOC LAER Analysis

Volatile organic compounds may be emitted from the ethane cracking furnaces due to

incomplete combustion of hydrocarbons in the fuel. This control technology analysis

will address the emissions of VOC from the ethane cracking furnaces. Because VOC is a

non-attainment pollutant (because all of Pennsylvania is considered to be in moderate

non-attainment for ozone), a LAER analysis is required for all of the project’s VOC

sources. No applicable VOC standards have been promulgated for cracking furnaces

under 40 CFR parts 60 and 61.



5-51

5.2.2.1 Step 1: Identify Cracking Furnace VOC Limit Precedents

Table 5-4 presents a summary of the results from a review of past cracking furnace

precedents identified in the RBLC database, recent permits, and one draft permit issued

in Texas. For purposes of comparison, for each of the VOC precedents identified, a

lb/MMBtu emission rate was determined by using the rated heat input of the furnace and

the mass hourly emission rate limit. As shown, the VOC emission limits range from

0.0009 lb/MMBtu to 0.0107 lb/MMBtu. These limits are based on good combustion

design and operation.

A review of the Texas and Louisiana SIP approved regulations found no VOC

regulations for cracking furnaces. The current TCEQ BACT guidance for process heaters

and furnaces only addresses NOx and CO.

5.2.2.2 Step 2: Achieved Cracking Furnace VOC Limits

As shown in Table 5-4, the VOC emission limits reflected in permits or draft permits

range from 0.0009 lb/MMBtu to 0.0107 lb/MMBtu. However, the more recent

determinations are for projects that have not begun construction or are under

construction. As a result, these limits do not meet the “achieved in practice” criteria for

LAER. As noted above, whether a limit has been achieved in practice is key to whether

that limit should be considered as LAER. The VOC emissions limits that are achieved in

practice range from 0.0019 lb/MMBtu to 0.0107 lb/MMBtu, with the 0.0019 lb/MMBtu

limit being derived from the hourly limit of 0.84 lb/hr. If the 0.0019 lb/MMBtu is

applied to the proposed furnace’s maximum heat input capacity of 620 MMBtu/hr the

resultant hourly rate is 1.18 lb/hr.

5.2.2.3 Step 3: Establish Cracking Furnace VOC LAER Limit

Taking into account the precedents that have been demonstrated in practice, the

application of good combustion design and operation is proposed to achieve the

following LAER limit:

VOC emission rate of 1.07 lb/hr, demonstrated through the use of EPA reference

method 18 and 25.



5-52

Table 5-4. Summary of VOC BACT/LAER Limits for Ethylene Cracking Furnaces

Permit

Date/

RBLC No. Facility Name Primary Fuel

Heat Input

(MMBtu/h

r) Control Technology

Calculated

lb/MMBtu Limit

5/2012 1 (draft

permit 2/2013)

ExxonMobil

Baytown, TX

Natural gas or blend of

natural gas and tailgas

575 2

(8 furnaces)

Good design, combustion

practices, and gaseous fuel firing

0.0049

(Basis: 22.66 lb/hr

8 furnace cap)

11/14/12 3

(permit)

Equistar

Channelview, TX OP-2

Natural gas & limited use

of hydrogen 4

640

(1 furnace)

Good combustion practice &

proper furnace design

0.001

(Basis: 0.64 lb/hr limit)

1/23/13 3

(permit)

Equistar


Natural gas & limited use

of hydrogen 4

640 max

(2 furnaces)


proper furnace design

0.0009

(Basis: 0.60 lb/hr limit)

7/16/12

(permit) 5

BASF FINA Ethylene/

Propylene Cracker

Natural gas or cracker off

gas

498 6

(1 furnace) Efficient Combustion No limit

08/06/13 7

(permit)

Chevron/Phillips

Cedar Bayou, TX

Plant fuel gas, ethane, or

natural gas.

500

(8 furnaces)

High hydrogen fuel & efficient

combustion technology

0.0054

(Basis: 2.7 lb/hr based on

natural gas at startup)

02/03/2006

TX-0511

BASF FINA

Ethylene/Propylene Cracker

Not indicated, probably

refinery or natural gas 302

(1 furnace) Pollutant not in RBLC

0.0019 7

(Basis: 0.57 lb/hr)

02/03/2006

TX-0511

BASF FINA



refinery or natural gas 441.7

(8 furnaces) Pollutant not in RBLC

0.0019 7

(Basis: 0.84 lb/hr)

TX-0475

(5/9/05)

Formosa Point Comfort

Plant Fuel Gas

250

(3 furnaces) None indicated

0.0107 (2 furnaces)

0.0092 (1 furnace) 8

1. ExxonMobil Chemical Company; NSR Permit Application for Ethylene Expansion Project; Baytown Olefins Plant, Baytown, TX; May 2012. TCEQ Draft

Maximum Allowable Emission Rates Permit Number 102982 (not dated). 0.0049 lb/MMBtu = 22.66 lb/hr / 8 furnaces / 575 MMBtu/hr. 0.0030 lb/MMBtu =

47.26 tpy VOC / 155.58 tpy NOx * 0.010 lb NOx/MMBtu.

2. Based on 5,037,000 MMBtu/yr / 8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for

Ethylene Expansion Project, Baytown, TX.

3. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (11/2012). & TCEQ Special Conditions &

Maximum Allowable Emission Rates Permit Numbers 18978 PSDTX752M5, N162, 1/2013.

4. NSR Permit Amendment Application - Revised; Equistar Chemicals, LP; Channelview, TX; Olefins Unit No.1&2; Permit Number 1768; February 2012.

5. TCEQ Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M5, and N007M1 7/2012.

6. Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the BASF FINA Petrochemicals LP (BFLP), NAFTA Region Olefins

Complex Permit Number: PSD-TX-903-GHG, April 2012.

7. TCEQ Special Conditions Permit Number 36644, PSDTX903M3, and N007M1, 7/2012: Fuel used in the cracking furnaces will be limited to plant fuel gas,

ethane, or to pipeline-quality, sweet natural gas.

8. TCEQ permit 19169 and PSDTX1226 Maximum Allowable Emission Rates (11/2012).



5-53

The proposed VOC emission limit for the cracking furnaces must meet two criteria to be

considered LAER. The proposed cracking furnace emission limits meet the first criterion

because a review of the Texas and Louisiana SIP approved regulations found no VOC

regulations for combustion sources. Current TCEQ BACT guidance for process heaters

and furnaces only addresses NOx and CO. The proposed LAER limit meets the second

criterion because it is as stringent as the lowest emissions limit that has been

demonstrated in practice. As previously noted, no applicable VOC standards have been

promulgated for cracking furnaces under 40 CFR parts 60 and 61. In accordance with 25

Pa. Code §127.205(7), the proposed VOC LAER limit is equivalent to and satisfies the

PaBAT requirements of 25 Pa. Code §127.12(a)(5).

5.2.3 Cracking Furnace PM/PM10/PM2.5 BACT/LAER Analyses

This section addresses the control of PM, PM10, and PM2.5 emissions from the proposed

cracking furnaces. The proposed project is located in an area that is classified as

nonattainment with regard to the annual PM2.5 standard. As a result, a LAER analysis is

required for all of the project’s sources of PM2.5. The area is designated as attainment for

PM10. As a result, a BACT analysis is required for those parameters. No applicable PM

standards have been promulgated for cracking furnaces under 40 CFR parts 60 and 61.

Emissions of particulate matter from gaseous fuel-fired sources result from inert solids

contained in the combustion air, unburned fuel hydrocarbons resulting from incomplete

combustion which agglomerate to form particles and condensable/secondary particulates.

Filterable PM emitted from the cracking furnaces is expected to be less than

10 micrometers in aerodynamic particle size diameter. In addition, for the very low

sulfur clean gas combustion that will occur in the proposed cracking furnaces, the rate of

PM, PM10 and PM2.5 are equivalent. The control technologies applicable to the control of

PM2.5 are the same as the technologies for PM and PM10. Thus, there is no need to

distinguish between the various PM species and throughout this LAER analysis all forms

of PM are referred to as “PM”. As a result, the PM2.5 LAER analysis will meet the

requirements of BACT for PM10 and PM.



5-54

5.2.3.1 Step 1: Identify Cracking Furnace PM Limits


precedents identified from the RBLC database, recent issued permits and one draft permit

proposed in Texas. All of the identified precedents have limits express in terms of

filterable PM, not PM10 or PM2.5. To allow for comparison of the identified PM

precedents, a lb/MMBtu emission rate was determined using the furnace’s rated heat

input and the mass hourly emission rate limit. As shown, the PM emission limits range

from 0.0036 lb/MMBtu to 0.016 lb/MMBtu. Based on a review of the BACT/LAER

precedents for PM emissions from cracking furnaces summarized in the RBLC, the only

controls applied are combustion controls and the use of low ash and low sulfur fuels (e.g.,

use of natural gas).

As previously noted, the Chevron/Phillips permit includes a short-term NOx emissions

rate that allows the SCR’s ammonia injection to be shut off during decoking of a furnace.

To allow for comparison of the identified precedents, the permitted hourly mass based

emission limits were converted to lb/MMBtu rates by using the rated heat input capacity

of the furnace. Because the proposed project’s cracking furnaces will also be decoked to

the furnace and a lb/MMBtu emission limit will be proposed as LAER, the impact of

decoking is considered as part of the LAER proposal.

A review of the Texas and Louisiana SIP approved regulations found no PM regulations

for cracking furnaces. The current TCEQ BACT guidance for process heaters and

furnaces only addresses NOx and CO.

5.2.3.2 Step 2: Achieved/Demonstrated Cracking Furnace PM Limits

As shown in Table 5-5, three of the identified precedents (i.e., TX-0511 for two projects

and TX-0475) are for projects that occurred in 2005 and 2006 and are consider to have

been achieved in practice. The PM limits included in these permits range from

0.005 lb/MMBtu to 0.016 lb/MMBtu. The 0.005 lb/MMBtu rate was derived based upon

the permitted hourly rate for those units. Applying that rate to the proposed furnaces

rated heat input of 564 MMBtu/hr results in an hourly rate of 2.82 lb/hr. The remaining

precedents are for recently permitted projects that have not been constructed or are only



5-55

Table 5-5. Summary of Proposed PM/PM10/PM2.5 BACT Limits for Ethylene Cracking Furnaces1

Permit

Date Facility Name Primary Fuel

Heat Input

(MMBtu/hr) Control Technology

Calculated

lb/MMBtu

Limit 5/12 2 (draft

permit 2/2013)

ExxonMobil Baytown TX

Olefins Plant



575 3

(8 furnaces)

Good design & combustion

practices

0.0036

(Basis: lb/hr)

11/14/12 4

(permit)

Equistar


Natural gas & limited

use of hydrogen 4

640

(1 furnace)


combustion of natural gas

and/or plant fuel gas

0.0066

(Basis: 4.23 lb/hr)

1/23/13 4

(permit)

Equistar



use of hydrogen 4

640 max

(2 furnaces)


combustion of natural gas

and/or plant fuel gas

0.0067

(Basis: 4.30 lb/hr)

7/16/12

(permit) 6

BASF FINA


Natural gas or cracker

off gas

487.5

(1 furnace)

Efficient Combustion & Clean

Fuels

0.005

(Basis: 2.49 lb/hr)

08/06/13 7

(permit)

Chevron/Phillips Cedar Bayou,

TX

Plant fuel gas, ethane,

or natural gas.

500

(8 furnaces)

High hydrogen fuel gas &

efficient combustion

technology

0.0075

(Basis: 3.73 lb/hr)

02/03/2006 TX-

0511

BASF FINA



refinery or natural gas 302

(1 furnace) Pollutant not in RBLC

0.005 8

(Basis: 1.51 lb/hr)

02/03/2006 TX-

0511

BASF FINA



refinery or natural gas 441.7

(8 furnaces) Pollutant not in RBLC

0.005 8

(Basis: 2.21 lb/hr)

5/09/2005

TX-0475

FORMOSA

Point Comfort, TX Fuel gas

250

(3 pyrolysis

furnaces)

Not indicated 0.016 9

(Basis: 3.96 lb/hr)

1. All of the identified precedents were for filterable PM, not PM10, or PM2.5

2. ExxonMobil Chemical Company; New Source Review Permit Application for Ethylene Expansion Project; Baytown Olefins Plant, Baytown, TX; May 2012.

TCEQ Draft Special Conditions & Maximum Allowable Emission Rates Permit Number 102982 (not dated). 0.0036 lb/MMBtu = 16.53 lb/hr / 8 furnaces /

575 MMBtu/hr.

3. Based on 5,037,000 MMBtu/yr / 8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for

Ethylene Expansion Project, Baytown, TX.

4. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (14/12) & 18978 /PSDTX752M5/N162

(1/2013).

5. NSR Permit Amendment Applications - Revised; Equistar Chemicals, LP; Channelview, TX; Olefins Production Unit No.1&2; February 2012.

6. TCEQ Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M5, and N007M1 7/2012. 0.005 lb/MMBtu = 2.49 lb/hr / 498 MMBtu/hr

7. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1504A, PSDTX748M1, and N148.

8. TCEQ Special Conditions Permit Numbers 36644, PSDTX903M3, and N007M1, 7/2012. 0.005 lb/MMBtu = 1.51 lb/hr / 302 MMBtu/hr

9. TCEQ Special Conditions & Maximum Emission Rates Permit Number 19168, PSDTX760M7 (2/15/2008).



5-56

under construction, and thus the permitted rates have not been achieved in practice such

as to qualify for LAER.

5.2.3.3 Step 3: Establish Cracking Furnace PM LAER/BACT Limits

Based on a review of the cracking furnace precedents that have been achieved in practice

(i.e., ranging from 0.005 lb/MMBtu to 0.016 lb/MMBtu) the application of good

combustion design and operation to achieve the following LAER/BACT PM limit is

proposed:

1) PM/PM10/PM2.5 emission rate of 3.10 lb/hr during normal furnace cracking

operation;

2) 1.86 lb/hr PM during decoking operation;

3) Compliance with these limits shall be demonstrated through the use of EPA

reference method 5/202.

For purposes of LAER determination with respect to PM2.5, the proposed emission limits

meet the two criteria to be considered LAER. With respect to the first criterion, a review

of the Texas and Louisiana SIP approved regulations found no PM regulations for

combustion sources. The current TCEQ BACT guidance for process heaters and

furnaces only addresses NOx and CO.

The second LAER criterion is met by proposing the most stringent emission limit

achieved in practice. The mass based emissions rate proposed during decoking is

consistent with this criteria because it is more stringent than the equivalent rate included

in the Chevron/Phillips permit. 54 As previously noted, no applicable PM standards have

been promulgated for cracking furnaces under 40 CFR parts 60 and 61.

As noted in Section 5.1.3, the criteria used to determine a proposed BACT limit are

somewhat different than the LAER criteria. However, in the case of PM emissions from

54 The Chevron/Phillips hourly limit is 3.73 lb/hr and their furnace size is 500 MMBtu/hr, which results in

a rate of 0.0075 lb/MMBtu. The proposed project’s furnaces will have a rated capacity of 564

MMBtu/hr. Using the most stringent level determined to have been achieved in practice,

0.005 lb/MMBtu, yields a mass rate of 2.82 lb/hr. The proposed LAER rate during decoking is

1.86 lb/hr.



5-57

the cracking furnaces, there is no difference in the limit. The proposed LAER limit of

0.005 lb/MMBtu for filterable PM is based on the use of the most-effective feasible PM

control option and the limit is the lowest that has been achieved in practice using that

approach on this type of source. In other words, the proposed LAER limit is consistent

with the top-performing control option in a top-down ranking of the feasible control

options, which is the appropriate basis for establishing a BACT limit. In accordance with

25 Pa. Code §127.205(7), the proposed PM BACT/LAER limit is equivalent to and

satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

5.2.4 Cracking Furnace CO BACT Analysis

This BACT analysis addresses carbon monoxide emissions from the ethane cracking

furnaces that result from incomplete combustion of hydrocarbons in the fuel gas.

Beaver County is an attainment area for CO, and the proposed Project is subject to major

source review for CO. As a result, the CO analysis included in this section will follow

the five step top-down BACT methodology to determine the proposed BACT limits. No

applicable CO standards have been promulgated for cracking furnaces under 40 CFR

parts 60 and 61.

5.2.4.1 Step 1: Identify Potentially Applicable Cracking Furnace CO Controls

The potentially available control technologies for CO emissions from cracking furnaces

fired with low-sulfur fuel gas are: good combustion practices and the use of oxidation

catalyst.

Good Combustion Practices: Good combustion practices for the proposed Project’s

cracking furnaces fired with tailgas and natural gas include the following:

Proper burner and furnace design; and

Good burner maintenance and operation.

As with other types of fossil fuel-fired systems, combustion control is the most effective

means for reducing CO emissions from ethane cracking furnaces. Good combustion is a

function of the three “T’s” of combustion: Temperature, Turbulence, and Time where:



5-58

Temperature is high enough to ignite the fuel,

Turbulence is vigorous enough for the fuel constituents to be exposed to the

oxygen, and

Time is long enough to assure complete combustion.

These components of combustion efficiency are designed into the furnaces to maximize

fuel efficiency and reduce operating costs. Therefore, combustion control is

accomplished primarily through furnace/burner design and operation.

Changes in excess air affect the availability of oxygen and combustion efficiency. Very

low or very high excess air levels will result in high CO formation and can also affect

NOx formation. Increased excess air levels will reduce CO emissions up to the point that

too much excess air is introduced and the overall combustion temperatures begin to drop.

When combustion temperatures drop enough, furnace efficiency and process

temperatures are negatively affected. Low excess air levels lower combustion

temperature and do not allow sufficient oxygen to minimize the formation of CO.

Cracking furnaces operate within a narrow range of excess air level due to the

interrelationship between oxygen levels, combustion efficiency and the formation of CO

and NOx.

Oxidation Catalyst: Oxidation catalyst is a well-known control technology for CO

emissions and has been widely applied on natural gas-fired combined cycle gas turbines

and to a limited extent on boilers. The oxidation of CO to CO2 utilizes excess air present

in the combustion exhaust. The catalyst lowers the temperature required for the oxidation

reaction to proceed. Products of combustion are passed through a catalytic bed with the

optimum temperature range for the system being 400°F to 1,200°F. No chemical reagent

addition is required.

5.2.4.2 Step 2: Eliminate Technically Infeasible Cracking Furnace CO Controls

Oxidation catalyst technology has been applied at several natural gas-fired boilers and

many combustion turbines, and is thus considered technically feasible for application on

combustion turbines and boilers firing low sulfur fuels.



5-59

However, in the case of cracking furnaces, use of oxidation catalyst technology is not

technically feasible due to leaks that may occur in cracking furnace tubes. Although tube

leaks are common in boilers and combustion turbine heat recovery steam generators, the

fluid leaked is steam or water. Water is not combustible and therefore it passes through

the oxidation catalyst without harming the catalyst. In contrast, when a tube leaks in a

cracking furnace, hydrocarbons leak into the furnace and end up in the combustion flue

gas. If the tube leak occurs in the upper part of the cracking furnace, the combustion

efficiency of the leaking hydrocarbons will be low because cracking furnaces are not

designed to efficiently combust hydrocarbons that do not come through the burner. The

leaked hydrocarbon gases will be oxidized by the catalyst and if present in sufficient

concentration, will release enough heat to damage the oxidation catalyst. Shell is not

aware of any cracking furnaces that have been equipped with oxidation catalyst

For these reasons, only good combustion design and operation is considered to be

technically feasible for the control of CO from ethane cracking furnaces.

5.2.4.3 Steps 3-5: Establish Hierarchy and Propose Cracking Furnace CO BACT Limit

The only technically feasible control option for CO emissions from ethylene cracking

furnaces is good combustion design and operating practices. Therefore, the remainder of

this analysis will focus on the achievable emission rates/limits for ethylene cracking

furnaces firing tailgas and natural gas.


precedents identified from the RBLC database, recent permits, and one draft Texas

permit. As shown, the lowest annual CO limit is 0.034 lb/MMBtu. The Texas BACT

guideline does not specify an averaging period.55

55 TCEQ Chemical Sources Current Best Available Technology (BACT) Requirements Process Furnaces

and Heaters, last revision date 08/01/2011.

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_processfu

rn.pdf



5-60

Table 5-6. Summary of CO BACT Limits for Ethylene Cracking Furnaces

RBLC

No./

Permit

Date Facility Name Primary Fuel

Heat Input

(MMBtu/hr)

Control

Technology

Hourly Limit

(lb/MMBtu)

Annual Limit

(lb/MMBtu)

5/12 1

(Draft Permit)

ExxonMobil

Baytown TX

Olefins Plant



575 2

(8 furnaces)

Good design &

combustion practices,

and gaseous fuel firing

0.567 1 0.035 (8 furnace cap)

(50 ppm at 3% oxygen)

08/06/13 7

(permit)

Chevron/Phillips

Cedar Bayou, TX

Plant fuel gas, ethane &

natural gas.

500

(8 furnaces)

High H2 fuel gas &

efficient comb. Tech.

0.29 7

(Basis: 145.57 lb/hr)

0.035

(8 furnace + boiler cap)7

11/14/12 3

(permit)

Equistar

Channelview, TX

OP-2


use of hydrogen 4

640

(1 furnace)

Good combustion

practice & proper

furnace design

0.053

(Basis: 33.88 lb/hr)

1/23/13 3

(permit)

Equistar

Channelview, TX

OP-1


use of hydrogen 4

640 max

(2 furnaces)

Good combustion

practice & proper

furnace design

0.035

(Basis: 20.36 lb/hr) 0.034

7/16/12

(permit) 5

BASF FINA

Ethylene/Propylene

Natural gas or cracker

off gas

498 6

(1 furnace)

Good combustion

practice & proper

furnace design

0.10

(876 hr/yr startups/spikes)

0.035 (50 ppm@3% O2)

0.035

(50 ppm at 3% oxygen)

TX-0427

(12/6/02)

Equistar Chemicals

La Porte Complex Natural gas

233 9

(1 furnace) None indicated 0.035 9

TX-0475

(5/9/05)

Formosa

Point Comfort Plant Fuel Gas

250

(3 furnaces) None indicated

0.035

(Basis: 8.75 lb/hr) 8

1. ExxonMobil Chemical Company; New Source Review Permit Application for Ethylene Expansion Project; Baytown Olefins Plant, Baytown, TX; May 2012. TCEQ Draft

Special Conditions & Maximum Allowable Emission Rates Permit Number 102982 (not dated). 0.567 lb/MMBtu = 2609.78 lb/hr/8 furnaces/575 MMBtu/hr.

2. Based on 5,037,000 MMBtu/yr/8760 hr/yr; Appendix A; ExxonMobil Greenhouse Gas Prevention of Significant Deterioration Permit Application for Ethylene Expansion

Project, Baytown, TX.

3. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140 (11/14/12)&18978 /PSDTX752M5/N162, 1/23/13

4. NSR Permit Amendment Applications - Revised; Equistar Chemicals, LP; Channelview, TX; Olefins Production Unit No.1&2; February 2012.

5. TCEQ Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M5, and N007M1 7/12.

6. TCEQ Special Conditions Permit Numbers 36644, PSDTX903M3, and N007M1, 7/12.

7. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Number 36644, PSDTX903M3, and N007M1, 7/2012: 0.29 calculated as ratio of NOx and CO

lb/hr limits times NOx limit of 0.025 lb/MMBtu; equivalent to 400 ppmv at 3% O2. 0.035 calculated as ratio of NOx and CO tpy limits times NOx limit of 0.010 lb/MMBtu;

equivalent to 50 ppmv at 3% O2.

8. TCEQ permit 19169 Special Conditions & Maximum Allowable Emission Rates (2/2008), 0.035 lb/MMBtu = 8.75 lb/hr (MAER hourly value)/250 MMBtu/hr

9. TX permit 18978 Special Conditions (2004) verifies RBLC 0.035 hourly limit.



5-61

To allow for comparison, lb/MMBtu rates were determined for each of the hourly limits

by using the furnace’s rated heat input and the permitted mass emissions rate. The

resultant rates for the recently permitted short-term limits for ExxonMobil

(0.567 lb/MMBtu), Chevron/Phillips (0.29 lb/MMBtu), and BASF FINA

(0.10 lb/MMBtu) are all greater than the BACT guideline rate of 0.035 lb/MMBtu, which

indicates that TCEQ considers alternative furnace operating conditions as part of the

permitting process. In addition, once these alternative operation conditions are

considered, a mass based emissions limits is used for purposes of the short-term

emissions limit.

Based on this review, Shell proposes the application of good combustion design,

operation and maintenance to achieve the following CO BACT limits:

Maximum CO emission rate of 0.035 lb/MMBtu, based on a 12-month rolling

average, excluding periods of startup, shutdown, decoking, and malfunction; and

During periods of startup, shutdown, decoking, or malfunction the CO emission

rate shall not exceed 52.2 lb/hr on an hourly average basis.

These values are consistent with permitted and draft limits for ethylene cracking furnaces

in Texas. As previously noted, no applicable CO standards have been promulgated for

cracking furnaces under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code

§127.205(7), the proposed CO BACT limit is equivalent to and satisfies the PaBAT

requirements of 25 Pa. Code §127.12(a)(5).

5.2.5 Cracking Furnace Greenhouse Gas (GHG) Emissions BACT

The proposed cracking furnaces will combust tailgas (hydrogen and methane), natural gas

and coke (during decoking), emitting three GHGs: CO2, CH4 and N2O. The end product

of combusting the carbon contained in these fuels is CO2. Methane is a product of

incomplete combustion and is emitted in much smaller quantities. Trace quantities of

N2O are generated by oxidation of nitrogen in the combustion air and fuel nitrogen.

Because the amount of CH4 and N2O emitted is very small (much less than one percent)

relative to the amount of CO2 emitted on a CO2e basis, the GHG BACT analyses will

primarily address control of CO2. No applicable GHG standards have been promulgated

for cracking furnaces under 40 CFR parts 60 and 61.



5-62

5.2.5.1 Step 1: Identify Potentially Applicable Cracking Furnace GHG Controls

For the cracking furnaces, there are three broad strategies for reducing GHG emissions:

use of low carbon fuels, energy efficiency and carbon capture and sequestration (CCS).

The application of CCS is addressed for all of the project’s GHG emissions sources in

Section 5.6, which is incorporated by reference into this discussion. The use of low

carbon fuels and energy efficiency to reduce GHG emissions from the ethane cracker

furnaces is discussed below.

Minimize the Production of CO2

Lower-Emitting Fuel: Table 5-7 presents a summary of the expected GHG emissions

associated with the combustion of the fuels that will be combusted in the proposed

Project’s cracking furnaces (i.e., tailgas and natural gas). The GHG emissions from

combustion of coal, No. 6, and No. 2 oil are presented for comparison. As shown,

gaseous fuels such as the tailgas and natural gas proposed as the fuels for the cracking

Table 5-7. CO2e Formed When Combusting Fossil Fuels

Fuel Type Pounds CO2e per Million Btu

Coal 210 1

No. 6 Fuel Oil 167 1


Natural Gas 117 1

Ethane Cracking Process Tailgas 44

1. From Tables C-1 and C-2 to subpart C of 40 CFR part 98.

furnace produce the lowest amount of GHG emissions on a per million Btu basis.

Hydrogen is the primary combustible element in the Project’s cracking process tailgas,

which is the primary fuel gas for the Project’s cracker furnaces. When combusted,

hydrogen becomes water vapor, which is not a greenhouse gas. As a result, the energy

produced through the combustion of fuel gas, which is composed of a high percentage of

hydrogen, results in a much lower rate of CO2e generation on a heat input per million Btu

basis. Since the Project’s tailgas contains up to 85 percent volume of hydrogen, its CO2e

value when combusting tailgas is about one-third that produced by burning natural gas.



5-63

Energy Efficiency: The use of a highly efficient design and operation of the furnace to

minimize the fuel required to operate the process will directly impact the amount of CO2

produced. The strategies used for highly efficient design and operation are process and

emissions unit specific, as explained in the subsequent discussion of various elements of

the cracker furnace configuration.

5.2.5.2 Step 2: Eliminate Technically Infeasible Cracking Furnace GHG Controls

Low-Carbon Fuel Feedstocks: As previously discussed, natural gas and ethane

cracking process tailgas have the lowest CO2 emission rates. Accordingly, the

preferential burning of these low-carbon gaseous fuels to meet the ethane cracking

furnaces’ energy needs is considered a CO2 control technique. This control technique is

technically feasible for the ethane cracking furnaces. Any additional gaseous fuel

demand will be met using natural gas.

Energy Efficiency: For a large integrated chemical plant such as the proposed Shell

project, there are several ways to improve energy efficiency. All of the approaches

described below are considered to be technically feasible.

Combustion Air Preheat: Air preheat is a method of recovering heat from the hot

combustion exhaust gas by heat exchange with the combustion air before it enters the

combustion chamber or furnace. Preheating the combustion air reduces the amount of

fuel required in a boiler or furnace because the combustion air does not have to be heated

from ambient temperature to the fuel combustion temperature by combusting fuel. The

amount of CO2 reduction is typically 10 to 15 percent. This heat recovery approach is

commonly used on large process heaters and boilers. To equip a boiler or heater with air

preheat requires the addition of a draft fan and heat exchanger, incurring capital,

operating and maintenance costs. For heaters and boilers of sufficient size these costs

can be offset by the fuel savings. Although combustion air preheat reduces the amount of

CO2 emitted, NOx emissions increase because preheating the combustion air increases

combustion temperature.



5-64

Although technically feasible for application at the Project’s cracking furnaces,

combustion air preheat is not proposed because similar efficiencies will be obtained by

recovery of flue gas energy to generate steam. To make steam the stack temperature will

be reduced to the limits allowed by dew point considerations. In addition, the use of air

preheat has been shown to increase NOx emissions (i.e., in refinery process heater

applications NOx emission rates have increased by 20 percent).

Boiler Feed Water Preheat: Boiler feed water preheat is a method of recovering heat

from the hot combustion exhaust gas emitted by furnaces and boilers through heat

exchange with the boiler feed water or some other process fluid. These systems are

referred to as economizers when used to preheat water. Preheating the boiler feed water

reduces the amount of fuel required in the boiler because the feed water does not have to

be heated from ambient temperature to the required steam temperature by combusting

fuel. There are two principal types of economizers: noncondensing and condensing.

Economizers: Economizers are usually air-to-water heat exchangers. Because these

economizers are not designed to handle flue gas condensation, noncondensing

economizers must be operated at temperatures that are reasonably above the dew points

of the flue gas components. The dew point of the flue gases depends largely on the

amount of water in the gas, which, in turn, is related to the amount of hydrogen in the

fuel. For example, to avoid condensation in the exhaust gases produced by burning

natural gas, the exhaust gas temperature should typically be kept above 250°F.

Noncondensing economizers for heat recovery are commonly used on large boilers, are

technically feasible for the proposed cracking furnaces and will be applied to heat boiler

feed water used to generate steam.

Stack Temperature Reduction: Stack temperature reduction from process heaters and

furnaces results in less heat loss to the atmosphere from combustion exhaust gases.

Methods include options for recovering heat from the combustion exhaust gas such as

steam generation and designing/modifying process heaters to maximize heat recovery in

the heater convection section.



5-65

Steam generation is the primary method that the proposed cracking furnaces will utilize

to maximize heat recover, thereby reducing emissions of CO2. The ethane cracking

process utilizes a significant amount of steam. The majority of this steam will be

provided by recovering heat from the cracking furnace flue gas. The cracking furnace

design is expected to give an overall thermal efficiency of around 93% via maximum heat

integration and recovery of heat from the flue gas as limited by dew point considerations.

Recovering more heat in the heater convection section can be accomplished through

improved convection section tube design and the addition of more convection surface

area. The proposed cracking furnaces will use the most up to date technology design to

minimize the use of energy.

Process Integration and Heat Recovery: Process heat recovery opportunities include

maximizing feed-to-product heat exchange, heat recovery steam generation and advanced

heat exchange equipment design. As a new facility, these features will be utilized in the

design, construction, and operation of the Project.

Utilize Condensate Recovery: Steam is used throughout the site as feed to the cracking

furnaces, to heat process fluids, to drive compressors and for other processing needs.

Efficient recovery of steam condensate reduces energy demand in two ways. First,

recovering the steam condensate reduces the amount of water that needs to be treated for

steam generation. Water treatment is necessary to provide high quality water for use in

the boilers and furnaces. Secondly, recovered steam condensate is typically 100°F

warmer than water from the water treatment plant. As a result, recovering steam

condensate saves the amount of fuel required to heat treated water up by that 100°F. As a

new facility, these features will be utilized in the design, construction and operation of

the Project.

Continuous Excess Air Monitoring and Control: Excessive amounts of combustion

air used in boilers and process heaters results in heat inefficiencies because more fuel

combustion is required to heat the unnecessary air to combustion temperatures. This can

be alleviated by using state-of-the-art instrumentation for monitoring and controlling the

excess air levels in the combustion process. The result is a reduction in the heat input



5-66

because the amount of combustion air needed for safe and efficient combustion is

minimized. This requires the installation of oxygen monitors in the furnace stacks and

damper controls on the combustion air dampers. Lowering excess air levels while

maintaining good combustion reduces CO2 as well as NOx emissions.

The Project’s cracking furnaces will use oxygen analyzers and draft controls to minimize

energy use and emissions of NOx and CO.

5.2.5.3 Step 3: Hierarchy of Cracking Furnace GHG Controls

In order to address CO2 emissions, the Project considered three possible strategies.

1. Reduce the rate of CO2 emissions to the environment via carbon capture and

storage (CCS). The application of CCS is addressed for all of the project CO2

emission sources in Section 5.6.

2. Maximize the energy efficiency, which will minimize the production of CO2. A

highly efficient operation requires less fuel to operate, directly impacting the

amount of CO2 produced. Establishing an aggressive basis for energy recovery

and facility efficiency will reduce CO2 production. All of the options described in

the previous section are technically feasible and are part of the proposed Project.

3. Use of low carbon fuels such as ethane cracking tailgas and natural gas instead of

high carbon fuels and feedstock such as ethane instead of naphtha. This strategy

can be combined with the first strategy and is planned for the proposed Project.

The impacts of strategies 2 and 3 are addressed further in Steps 4 and 5.

5.2.5.4 Step 4: Evaluate Most Effective Cracking Furnace GHG Controls

The use of low-carbon fuels (cracking unit tailgas and natural gas) and various energy

efficiency measures (recovery of furnace flue gas heat down to approximately 284 °F in

new/clean condition) are included in the proposed project. Table 5-8 summarizes the

GHG BACT strategies identified and selected as BACT for a number of the recent

USEPA Region 6 GHG permits issued for cracking furnaces permitted in Texas (which

are the only GHG permits for similar cracking furnaces that have been identified). 56

56 The United States Environmental Protection Agency (USEPA) Region 6 is the review agency for GHG

Prevention of Deterioration permits issued in Texas.



5-67

Table 5-8. Summary of Texas Ethylene Cracking Furnace GHG BACT Determinations

Company/

Project Fuel Control Options Considered Selected Limits

BASF FINA

Petrochemicals

Port Arthur, TX

2012 PSD-TX-

903-GHG SOB

and permit

Pipeline quality

natural gas, low

pressure fuel gas,

high pressure fuel

gas, high hydrogen

fuel

CCS- not technically feasible

EED- steam generation from process waste

heat and periodic decoking of furnace coils

LCF- utilize hydrogen-rich product stream

that is not slated to fulfill contract

commitments

Energy Efficiency/Low-

Emitting Feedstocks/ Lower-

Carbon Fuels selected

CCS rejected: based on high

annual cost and 3-to-17 fold

increase in the total cost of the

project.

Any of the hydrogen-rich product

stream not slated to fulfill contract

commitments shall be utilized to

the maximum extent possible.

Furnace limit flue gas exhaust

temperature ≤ 309oF on a 365-day

average, rolling daily.

256,914 tpy CO2e on a12-month

rolling basis.

Chevron/Phillips,

Cedar Bayou, TX

PSD-TX-748-

GHG October

2012 SOB and

permit

Plant fuel gas

supplemented by

natural gas and

ethane

CCS- post combustion capture, transport,

and EOR considered technically feasible but

rejected for reasons stated in next column.

EED- energy efficient proprietary design

that: recovers refrigeration capacity from

incoming ethane feed, uses lower pressure

separation of ethylene and ethane, uses

optimized distillation tower design

LCF- high-hydrogen plant tailgas as the

primary fuel; the alternate fuel will be

natural gas.

GCP- supports the energy efficient design.

LCF/EED/GCP accepted.


annual cost, increased the total

capital project costs by more

than 25%. Would increase

emissions of NOx, CO, VOC,

PM10, SO2, and ammonia by as

much as 30%.

Combust plant tailgas (fuel gas) or

pipeline quality natural gas. Ethane

may be used as an emergency

backup fuel.

Furnace gas exhaust temperature

limit of less than or equal to 350oF

on a 12-month rolling average

basis.

Cap for the furnaces and boiler of

1,579,000 tpy CO2e on a 12-month

total, rolling monthly.


to less than or equal to 350oF on a

12-month rolling average basis.



5-68

Company/

Project Fuel Control Options Considered Selected Limits

Equistar

Channelview, TX

(OP-1 & OP-2)

PSD-TX-1272-

GHG May 2013

SOB and permit

Pipeline quality

natural gas and/ or

process gas (fuel

gas).

CCS- post-combustion capture is available

and applicable, but rejected for reasons

stated in next column

EED- selected a furnace design that will

maximize efficiency by incorporating the

latest improvements in heat transfer and

fluid flow to maximize energy efficiency

and energy recovery.

LCF- use hydrogen-rich gas stream as the

secondary fuel for the furnaces.

GCP- periodic tune-ups and oxygen trim

controls.

LNB – Low NOx burners limit the

formation of NOx (including N2O)

emissions.

LCF/EED/GCP/LNB accepted.


capital cost increase of 60 to

70% of project. Would increase

emissions of NOx, CO, VOC,

PM10, SO2, and ammonia by

as much as 30%.

Furnace gas exhaust temperature ≤

408 oF on a 365-day rolling

average basis.

Maintain a minimum thermal

efficiency of 89.5% on a 12-month

rolling average basis.

300,706 tpy CO2e on a 12-month

rolling basis.

The cracking furnaces shall

combust pipeline quality natural

gas and/ or process gas (fuel gas).

ExxonMobil,

Baytown, TX

(draft SOB and

permit)

Combust blended

fuel gas (fuel gas)

or pipeline quality

natural gas.

CCS- post-combustion capture, is applicable

to the cracking furnaces but rejected for

reasons stated in next column

EED- energy efficient design will be

equipped with heat recovery systems to

produce steam from waste heat for

use throughout the plant

LCF- use natural gas or a blended fuel gas

that consists of natural gas and tailgas

GCP- maintenance and operating within the

recommended combustion air and fuel

ranges as specified by design, with the

assistance of oxygen trim control

LCF/EED/GCP accepted.


annual cost of $205 million per

year. Would increase emissions

of NOx, CO, VOC, PM10, and

SO2 by as much as 11%.

Combust blended fuel gas (fuel

gas) or pipeline

quality natural gas.


less than or equal to 340 oF on a

365 day rolling average basis.

987,968 tpy CO2e on a 12-month

total, rolling monthly.

SOB- statement of basis; CCS- carbon capture and sequestration; EED- energy efficient design; LCF- low carbon fuel; GCP- good combustion practices; LNB-

low NOx burners



5-69

As shown, the USEPA Region 6 has issued permits for the identified ethylene

manufacturing projects that require the same GHG controls described as applicable and

available to ethane cracking furnaces in Steps 2 and 3. For all of the identified permit

precedents, the BACT limits include a statement of the permitted:

Low carbon fuels (LCF),

Flue gas exhaust temperatures (EED), and

Ton per year limits for CO2, CH4, N2O, and CO2e.57

5.2.5.5 Step 5: Propose Cracking Furnace GHG BACT

Employing highly energy efficient ethane cracking furnaces will minimize the emissions

of GHGs (CO2, N2O and methane). A highly efficient operation requires less fuel to

operate, which directly impacts the amount of GHGs emitted. Establishing an

aggressivebasis for energy recovery and facility efficiency will reduce GHG emissions

and the costs to mitigate it. Shell has also concluded that the use of low carbon fuels:

tailgas that is high in hydrogen, with natural gas as a backup fuel, is BACT. Shell

proposes the following efficiency based limits:

Only plant tailgas or pipeline quality natural gas shall be combusted in the

cracking furnaces.

Routine furnace tune-ups in accordance with 40 CFR 63 subpart DDDDD

(Process Heaters and Boiler MACT)

Cracking furnace gas exhaust temperature shall be limited to less than or equal to

350 oF on a monthly rolling 12-month average basis on each cracking furnace.

This stack temperature is for normal operations and does not include

commissioning, startup, shutdown, hot steam standby or decoking operations.

Total emissions from seven (7) ethane cracking furnaces shall be limited to, on a

12-month total average basis:

o 1,059,333 tpy CO2,

o 20 tpy CH4,

o 4 tpy N2O, and

o 1,060,946 tpy CO2e.

57 Although listed as limits in the USEPA region 6 GHG permits, the specific limits for CO2, CH4, N2O are

not shown in Table 5-8



5-70

As previously noted, no applicable GHG standards have been promulgated for cracking

furnaces under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code §127.205(7),

the proposed GHG BACT limit is equivalent to and satisfies the PaBAT requirements of

25 Pa. Code §127.12(a)(5).

5.3 Combustion Turbines & Duct Burners

Three natural gas-fired combined cycle units will supply the electricity and steam

required to support the Project. Each combined cycle unit will have a dedicated heat

recovery steam generator (HRSG). Excess electricity produced by the project will be

available for sale to the PJM electric grid.58 Each Cogen Unit will be equipped with duct

burners firing primarily natural gas and used to increase the steam produced by the

HSRGs. Two steam turbines will be used to generate electricity using the steam

produced by the HRSGs and any excess steam from the ethane cracking unit. When

tailgas is in excess at the cracking furnaces, a small quantity of the tailgas may be

combusted in the duct burners in combination with natural gas. As noted in Section 3.4,

the combustion turbines that comprise the three Cogen Units will be either General

Electric Frame 6Bs or Siemens SGT-800s.

5.3.1 Combustion Turbine NOx/NO2 LAER/BACT Analyses

The proposed project will be located in an area that is designated as nonattainment for

ozone. Nitrogen oxides (NOx) are a defined precursor to the formation of ozone. As a

result, a LAER analysis is required for NOx emissions from the proposed Cogen Units.

The area is also designated as attainment/unclassified for nitrogen dioxide (NO2). As a

result, a BACT analysis is required for NO2 emissions from the proposed Cogen UNits.

For purposes of these analyses, the more stringent LAER methodology is followed to

meet the criteria for both LAER and BACT. As noted in Section 4.0, newly constructed

combustion turbines are subject to NSPS subpart KKK NOx requirement of 25 ppm at

15 percent O2 or 150 ng/J of useful output (1.2 lb/MWh).

58 PJM = Pennsylvania, New Jersey, and Maryland electric utility distribution grid.



5-71

NOx formed as part of the combustion process is generally classified in accordance with

the formation mechanism as either thermal NOx or fuel NOx. Thermal NOx is formed

by the thermal dissociation and subsequent reaction of the nitrogen and oxygen in the

combustion air at high temperature. The amount of thermal NOx formation is a function

of the combustion turbine combustor design, flame temperature, residence time at flame

temperature and fuel/air ratio in the primary combustion zone. The rate of thermal NOx

formation is an exponential function of the flame temperature.

Fuel NOx is formed by the gas-phase oxidation of the nitrogen that is chemically bound

(i.e., CN compounds) in the fuel (i.e., char nitrogen). Fuel NOx formation is largely

independent of combustion temperature and the nature of the organic nitrogen compound.

Its formation is dependent on fuel nitrogen content and the amount of excess combustion

air (i.e., the excess oxygen beyond the fuel’s stoichiometric requirement). Natural gas

contains negligible amounts of fuel-bound nitrogen. As a result, the predominant type of

NOx that will be formed by the proposed combustion turbines is thermal NOx.

The control of air/fuel stoichiometry is critical in achieving reduction in thermal NOx.

Thermal NOx formation also decreases rapidly as the combustion temperature drops

below the adiabatic flame temperature for a given stoichiometry. Maximum reduction of

thermal NOx is achieved by simultaneous control of both combustion temperature and

stoichiometry.

5.3.1.1 Step 1: Identify Combustion Turbine NOx/NO2 Limits

Summary results from a review of the NOx BACT/LAER precedents for natural gas-fired

combustion turbines similar in size to the proposed Project’s turbines (i.e., 40 to 50 MW)

with duct burners (DB) are presented in Table 5-9. Table 5-10 presents a summary of

recent permits for projects not listed in RBLC. Each of these precedents is for a natural

gas-fired combustion turbine project where the turbine is greater in size than the proposed

Project’s turbines. The Table 5-10 precedents are presented to illustrate the NOx limits

currently being permitted. Step 2: Achieved/Demonstrated Combustion Turbine

NOx/NO2 Limits



5-72

Table 5-9. Summary of NOx BACT Precedent Found in the RBLC Database For 40 to 50 MW Turbines

RBLC ID

NO. FACILITY NAME

PERMIT

DATE

PROCESS

DESCRIPTION

CAPACITY

(MW) CONTROL

Emissions Limit

ppm@ 15% O2

AK-0071 International Station

Power Plant 3/31/2010

GE LM6000PF-25

Turbines with 140

MMBtu/hr DBs

40-45

(estimate)

SCR and Dry

Low NOx (DLN)

Combustion

5 (4-hr)

WY-0061

Black Hills

Corp./Neil Simpson

Two

4/4/2003

Turbine, Combined

Cycle and Duct Burner

(GE LM6000

Turbines)

40 Dry Low NOx

Burners and SCR 2.5 (24-hr)

IA-0064 Roquette America 1/31/2003 Turbine, Combined

Cycle (with DBs)

~53

(587 MMBtu/hr) SCR

3 (24-hr)

(calc – actual limit

0.012 lb/MMBtu)

OK-0056 Horseshoe Energy

Project 2/12/2002

Turbines and Duct

Burners (GE LM6000

with 185 MMBtu/hr

DB)

45 SCR 12.5

TX-0295 Sam Rayburn

Generation Station 1/17/2002

Combustion Turbines

7,8,9

(no DBs)

45 SCR and Good

Combustion 5



5-73

Table 5-10. Summary of Recent NOx BACT Precedents

State Facility Name

Permit

Date Process Description

Capacity

(MW) Control

Limit

(ppm @ 15% O2)

PA-

0291

Hickory Run Energy

Station 04/23/13

GE 7FA, Siemens SGT6-5000F5,

SGT6-8000H, or Mitsubishi

M501GAC.

900 DLN & SCR 2.0 (3-hr)

PA-

0268

Moxie Energy LLC/

Patriot Generation Plant 01/31/13

Two Mitsubishi M501GAC DLN &

387 MMBtu/hr Duct Burners or Two

Siemens SGT6-8000H DLN &

164 MMBtu/hr Duct Burners

944 DLN & SCR 2.0

CA 1 Pio Pico Energy Center 11/19/2012 GE LMS100

(simple cycle) 100

Water

Injection &

SCR

2.5 (1-hr)

PA-

0278

Moxie Liberty

LLC/Asylum Power 10/10/12

Two Combined Cycle Turbines with

HRSG and Duct Burners. 468 DLN & SCR 2.0

CA 3 Palmdale Hybrid Power

Project 10/18/2011 GE 7FA with 500 MMBtu/hr DB 154 DLN & SCR 2 (1-hr)

CA3 Oakley Generating

Station 5/18/2011 Fast start GE 207FA

624

(total MW

generated)

DLN & SCR 2 (1-hr)

GA 4 Live Oaks Power Plant 4/8/2010

Siemens SGT6-5000F Combustion

Turbines & 359 MMBtu/hr Duct

Burners

200

DLN

COMBUSTO

RS AND SCR

2.5 (3-hr)

1. Not in RBLC. Pio Pico Energy Center PSD Permit SD 11-01. 2. Not in RBLC. Palmdale Hybrid Power Project PSD Permit SE 09-01. 3. Not in RBLC. Oakley Generating Station Final Determination of Compliance, Application 20798, January 2011.

4. Not in RBLC. Live Oaks Power Plant Permit 4911-127-0075-P-02-0.



5-74

A summary of combustion turbine projects developed by the Bay Area Air Quality

Management District (BAAQMD) as part of the Authority to Construct review that

identifies operational projects with low emission limits is presented in Table 5-11.59

Although these precedents are for turbines much larger than those proposed for the

Project, the identified precedents indicate that the application of combustion controls and

SCR to combustion turbines can achieve NOx emission limits as low as 2 ppmv @ 15%

O2 in practice on an hourly basis.

Table 5-11. BAAQMD BACT Review for Authority to Construct Plant

Number 13289

Facility 1,2 NOx ppmvd @

15%O2

Initial

Operational

Palomar Energy Project 2 (1-hr) 2006

Sacramento Municipal Utilities District,

Consumnes 2 (1-hr) 2006

Sithe Mystic, MA-0029 2 (1-hr) 2003

Sithe Fore River, MA 2 (1-hr) 2003

Mountainview, San Bernadino County 2 (1-hr) 2005

Goldendale Energy, WA-0302 2 (3-hr) 2005

Magnolia, SCAQMD 2 (3-hr) 2005

Calpine Facility Sutter, Feather River AQMD 2.5 (1-hr) 2001

La Paloma, SJVAPCD 2.5 (1-hr) 2003

Elk Hills, SJVAPCD 2.5 (1-hr) 2003

Rocky Mountain Energy Center, CO-0056 3.0 (1-hr) 2004

ANP Blackstone, MA-0024 2 (1-hr) No Steam

3.5 (1-hr) Steam Inj. 2001

1. Information presented is from a database search of EPA’s BACT/RACT/LAER Clearinghouse

and CARB’s BACT Clearinghouse for recent permits issued for natural gas-fired combined-

cycle power plants.

2. Facilities from the EPA Clearinghouse are identified with an EPA clearinghouse number,

which is a two-letter state code followed by a four-digit number. All other facilities are from

the CARB Clearinghouse.

59 Authority to Construct for the Los Esteros Critical Energy Facility Combined-Cycle Conversion

(Phase 2) Plant Number 13289, November 2, 2010.



5-75

5.3.1.2 Step 3: Establish Combustion Turbine NOx/NO2 LAER/BACT Limits

The BAAQMD has also considered whether NOx emission limits below 2 ppmv @ 15%

O2 should be required. The BAAQMD concluded that the evidence did not support

imposing a NOx emission limit below 2 ppmv @15% O2 as BACT for the Los Esteros

Critical Energy Facility as follows: 60

“The District also considered whether it would be feasible to implement a NOx permit

limit below 2.0 ppm. Consistent compliance with a limit below 2.0 ppm has never

been demonstrated in practice, and the equipment vendors that the District contacted

regarding this issue stated that they would not be able to guarantee that a lower limit

could be achieved. The District nevertheless considered whether it would be

technologically feasible to do so. The District has concluded that imposing a NOx

emissions limit below 2.0 ppm cannot be justified as BACT at this time.

Additional NOx reductions could potentially be achieved by increasing the amount of

catalyst or size of the catalyst bed in the SCR system. It would be difficult to achieve

any substantial additional reductions, however, because at the very low NOx levels

that are currently being achieved by SCR additional efforts produce diminishing

returns. SCR performance for NOx control is highly dependent on the NOx-to-

ammonia reaction stoichiometry. At stoichiometric conditions, there would be just

enough ammonia to react with the NOx with no additional ammonia slip exhausted

out the stack. It becomes highly challenging to ensure a uniform distribution of

ammonia to NOx over the entire gas turbine operating range when NOx

concentrations are very low. Alternatively, some vendors have considered staging

two separate ammonia injection grids and catalyst beds in series in order to achieve

an optimal distribution of ammonia to NOx that might maintain emissions at less than

2.0 ppm NOx over the entire gas turbine operating range. But this approach has its

own drawbacks, such as increasing the backpressure on the turbine exhaust and

decreasing the efficiency of the turbine resulting in higher emissions per megawatt of

power generated. Moreover, no installation using a staged series of ammonia

injection grids has been demonstrated in practice. Additionally, temperature

variations across the catalyst bed also impact SCR performance. At progressively

lower NOx concentrations, these variations have an increasingly significant impact

on maintaining stoichiometric conditions. For all of these reasons, it becomes

increasingly difficult to gain additional NOx reductions as concentrations are driven

to extremely low levels simply by increasing the amount of catalyst or the size of the

catalyst bed. Increasing the amount of catalyst or size of catalyst bed theoretically

60 Ibid pages 12.



5-76

can provide for more NOx reduction, but for a number of reasons simply adding more

catalyst reaches a point of diminishing returns as NOx levels approach zero.”

Recent precedents in plan approvals issued by PaDEP similarly indicate that a LAER

limit of 2 ppmv @15% O2 is appropriate.

As a result, the use of dry low NOx (DLN) combustors and SCR to achieve the following

BACT/LAER limits is proposed:

2 ppmv @ 15% O2 on a 1 hour average basis,

Total annual emissions from the Cogen Units including startups and

shutdowns shall not exceed more than 22.6 tons of NOx in any 12 consecutive

month period,

Hourly emissions from a given Cogen Unit during startup or shutdown shall

not exceed 113 lb/hr

Startup and shutdown shall be defined as the period during which the SCR is

below the catalyst operating temperature.

The proposed LAER limits for the Project’s Cogen Units must meet two criteria to be

considered LAER. Table 5-12 summarizes the results of a review of states most likely to

have the most stringent emission limits contained in a state implementation plan. The

proposed emission limit of 2 ppmv @ 15% O2 on a 1-hour average basis is more stringent

or equal to the NOx BACT guidelines/requirements for the four agencies identified. As a

result, the proposed emission limit meets the first LAER criterion. The second LAER

criterion is addressed because the most stringent emission limit achieved in practice

identified for combustion turbines from the RBLC and BAAQMD databases and several

recently issued permits is proposed. The proposed NOx LAER limit is more stringent

than the applicable NSPS subpart KKKK limit of 25 ppmvd @ 15% O2. In accordance

with 25 Pa. Code §127.205(7), the proposed NOx LAER limit is equivalent to and

satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

It should be noted that the application of SCR involves some other considerations.

First, the combustion of sulfur in fuels produces SO2 and SO3 emissions during the

combustion process. Additional SO3 is formed as the SO2 in the flue gas passes through

oxidation catalyst (for CO and VOC control) and the SCR catalyst bed (for NOx control).



5-77

Table 5-12. Regulatory Agencies with NOx BACT Guidelines/Requirements for Combustion Turbines

Regulatory Agency Description Emission Limit Comment Reference Bay Area Air Quality

Management District

Gas Turbine; Combined

Cycle ≥ 40 MW

1. 2.0 ppmvd @ 15% O2

2. 2.5 ppmvd @ 15% O2

(2.0 ppm achieved in practice

for 50 MW LM6000

combined cycle)

1. Technologically

Feasible/ Cost Effective

2. Achieved in Practice

Best Available Control

Technology (BACT)

Guideline (7/18/03)

San Joaquin Valley Air

Pollution Control District

Gas Turbine - = or > 50

MW, Uniform Load,

without Heat Recovery

1. 2.5 ppmvd @ 15% O2,

based on a one-hour average,

excluding startup and

shutdown (SCR or equal).

2. 2.0 ppmvd @ 15% O2,

based on a one-hour average,

excluding startup and

shutdown (SCR or equal).

1. Achieved in Practice or

contained in the SIP

2. Technologically

Feasible/ Cost Effective

Best Available Control

Technology (BACT)

Guideline 3.4.7

Last Update: 10/1/2002 &

2008

New Jersey Department of

Environment Protection

Stationary Combustion

Turbines - Combined

Cycle

2.5 ppmvd @ 15% Oxygen 3-

hour rolling average State of the Art Manual for

Stationary Combustion

Turbines 12/21/2004 2nd

Revision

Texas Commission on

Environmental Quality

Gas-Fired Turbine

Combined Cycle with

Duct Burner

2.0 ppmvd at

15% O2, 24-hr average

TCEQ Combustion

Sources Current Best

Available Control

Technology (BACT)

Requirements Turbines

(7/2012)



5-78

The SO3 then reacts with unreacted ammonia (i.e., slip ammonia) passing through the

HRSG to form ammonium sulfate [(NH4)2 SO4] and ammonium bisulfate (NH4 HSO4)

salts, which are emitted as fine particulates. Because natural gas has very low sulfur

content, emissions of fine particulate (PM2.5) due to the SCR are expected to be minimal.

Second, in the injection of ammonia-based reagent to control NOx, the reaction is not

exact, and maximization of NOx reduction can result in left over ammonia in the exhaust

gas stream (known as ammonia slip). A PaBAT analysis for NH3 and SO2 is presented in

Section 5.14.

5.3.2 Combustion Turbine VOC LAER Analysis

Volatile organic compounds (VOCs) emissions from a natural gas-fired combustion

turbine are a product of incomplete combustion. The formation of VOC is limited by

ensuring complete and efficient combustion of the fuel in the combustion turbine. High

combustion temperatures, adequate excess air and good air/fuel mixing during

combustion minimize VOC emissions. Measures taken to minimize the formation of

NOx during combustion may inhibit complete combustion, which can increase VOC

emissions. Lowering combustion temperatures through staged-combustion can be

counterproductive with regard to VOC emissions. However, improved air/fuel mixing

inherent in newer DLN combustor designs and control systems overcome the impact of

fuel staging on VOC emissions. The Project is located in an ozone nonattainment area.

Because VOC is a defined precursor to the formation of ozone, the combustion turbines

emissions are subject to LAER for VOC. No applicable VOC standards have been

promulgated for combustion turbines and duct burners under 40 CFR Parts 60 and 61.

This section presents the VOC LAER analysis for the proposed combustion turbines.

5.3.2.1 Steps 1: Identify Combustion Turbine VOC Limit Precedents

Table 5-13 presents a summary of the results obtained from a review of the RBLC

database to identify the range of combustion turbine VOC emission limits. For purposes

of comparison, for each of the VOC precedents identified, the limit was converted to a

ppmv @ 15% O2 basis where needed. As shown, the VOC emission limits range from 1



5-79

Table 5-13. Summary of VOC BACT/LAER Precedents for Turbines with Oxidation Catalyst

RBLC ID

N0. Facility Name

Permit


Capacity

(MW)

Emission Limit

(ppmvd @ 15% O2) 8 Operational Status

PA-0291 Hickory Run

Energy Station 04/23/13

GE 7FA, Siemens SGT6-5000F5, SGT6-

8000H, or Mitsubishi M501GAC. 900 1.5 Pre-construction

PA-0268

Moxie Energy

LLC/ Patriot

Generation Plant

01/31/13





944 1.9 Pre-construction

PA-0278

Moxie Liberty

LLC/Asylum

Power

10/10/12 Two Combined Cycle Turbines with

HRSG and Duct Burners. 468

1 w/o Duct Burner

1.5 w/Duct Burner Pre-construction

CA 1 Oakley Generating

Station 5/18/11 GE 207FA

624

(total) 1 (as CH4) (1-hr) Under Construction

GA 2 Live Oaks Power

Plant 4/8/10

Siemens SGT6-5000F Combustion Turbines &

359 MMBtu/hr Duct Burners 200 2 (as CH4) (3-hr) Pre-construction

NV-0035 Tracy Substation

Expansion Project 9/12/05 2- Turbine & Duct Burner

306

(total) 4 (3-hr) In Operation 2009

WI-0227 Port Washington

Generating Station 10/13/04

GE 7FAs or Equivalent and Duct Burners

(371 MMBtu/hr) 180 1.2

In Operation

2005/2008

CA 3 Otay Mesa Energy

Center LLC 12/18/03 GE 7FA 172 2 (1-hr) Operating in 2009

MN-0054 Mankato Energy

Center 12/4/03 GE 7FA & Duct Burners (800 MMBtu/hr) 180 3.4 (3-hr) In Operation 2006

CA 3 Smud Consumers

Power Plant 9/9/03 GE 7FA ~172 1.4 (3-hr) In Operation 2006



5-80

RBLC ID

N0. Facility Name

Permit


Capacity

(MW)

Emission Limit

(ppmvd @ 15% O2) 8 Operational Status

CA 3 Magnolia Power

Project 5/27/03 PG7241FA 181 2 (1-hr) In Operation 2005

OR-0035 Port Westward Plant 1/16/22 Combustion Turbines & Duct Burners 650

(total) 4.9 In Operation 2007

CA 4 Metcalf Power Plant 9/24/01 Siemens Westinghouse 600

(total)

1 (as CH4)

(based on 2.7 lb/hr) In Operation 2005

CA 5 Blythe Energy LLC 3/21/01 Two F-class combustion turbine generators 520

(total)

1 (as CH4)


CA 6 High Desert –

Constellation 5/3/00 Siemens Westinghouse W501FD2 177

1 (as CH4)


1. Not in RBLC. Oakley Generating Station Final Determination of Compliance, Application 20798, January 2011.


3. California Air Resources Board (CARB) database.

4. California Energy Commission Metcalf Power Plant Project - Docket # 99-AFC-03 and Metcalf Energy Center, San Jose, California - Power Technology

at http://www.power-technology.com/projects/metcalf

5. California Energy Commission Blythe Energy Power Plant Project, docket 99-AFC-08 and Order Approving A Petition to Modify Air Quality Conditions,

March 30, 2005.

6. California Energy Commission High Desert Power Plant Project - Docket # 97-AFC-01 and Order Approving A Petition to Modify Air Quality Conditions,

October 20, 2004.

7. Projects that were never built are excluded and include: LA-0192, MI-0366, VA-0291, OR-0043, MI-0357, NJ-0043, OH-0248, OK-0070, and OH-0248.

8. Unless otherwise noted parentheses indicate the permitted averaging time.



5-81

to 4.9 ppmv @ 15% O2 based on the use of oxidation catalyst and good combustion

control.

5.3.2.2 Steps 2: Achieved Combustion Turbine VOC Limits

The VOC emissions limits that are achieved in practice range from 1 to 4.9 ppmv @ 15%

O2. Although these precedents are for turbines much larger than the proposed CTs, the

application of combustion controls and oxidation catalyst to CTs is concluded to have

achieved a VOC emission limit as low as 1 ppmv @ 15% O2. This finding is supported

by a recent BAAQMD permit action where a 1 ppmvd @ 15% O2 represented BACT for

two combustion turbine projects.61

5.3.2.3 Step 3: Establish Combustion Turbine VOC LAER

Taking into account the precedents that have been achieved in practice, the use of

oxidation catalyst and good combustion control is proposed to achieve the following

VOC LAER limit:

1 ppmvd @ 15% O2 on a one hour average basis.

Compliance with this limit shall be demonstrated through the use of EPA

reference method 18 and 25.

The proposed emissions limit for the Project’s Cogen Units must meet two criteria to be

considered LAER. To determine if the first criteria was met, a review of states most

likely to have the most stringent emission limits contained in a state implementation plan

was conducted. The results from this survey are presented in Table 5-14. As shown, the

proposed emission limit of 1 ppmvd @ 15% O2 on a one-hour average basis is as

stringent as the VOC BACT guidelines/ requirements for the three agencies identified.

Although the San Joaquin Valley Air Pollution Control District indicates that 0.6 ppmvd

may be technically feasible, this limit has not yet been “achieved in practice”. Thus, the

61 Authority to Construct for the Los Esteros Critical Energy Facility Combined-Cycle Conversion

(Phase 2) Plant Number 13289, November 2, 2010 and Final Determination of Compliance Oakley

Generating Station, January 2011.



5-82

Table 5-14. Regulatory Agencies with VOC BACT Guidelines/Requirements for

Combustion Turbines

Regulatory

Agency Description Emission Limit Comment Reference Bay Area Air

Quality

Management

District

Gas Turbine;

Combined

Cycle ≥ 40

MW

2.0 ppm, Dry @ 15%

O2 (oxidation catalyst

or efficient dry low

NOx combustors)

Achieved in

Practice

Best Available

Control Technology

(BACT) Guideline

(7/18/03)

San Joaquin

Valley Air

Pollution

Control

District

Gas Turbine - =

or > 50 MW ,

Uniform Load,

without Heat

Recovery

1) 2.0 ppmvd @ 15%

O2, based on a

(oxidation catalyst, or

equal).

2) 0.6 ppmvd @ 15%

O2, based on a three-

hour average

(oxidation catalyst).

1) Achieved in

Practice or

contained in the

SIP

2) Technically

Feasible

Best Available

Control Technology

(BACT) Guideline

3.4.7

Last Update:

10/1/2002 & 2008

New Jersey

Dept. of

Environmental

Protection

Stationary

Combustion

Turbines -

Combined

Cycle

4 ppmvd @ 15%

oxygen 3-hour rolling

average

State of the Art

Manual for Stationary

Combustion Turbines

12/21/2004 2nd

Revision

proposed emission limit of 1 ppmvd @ 15% O2 meets the first criterion for being LAER.

The second criterion is addressed by proposing the most stringent emission limit achieved

in practice identified for combustion turbines from the RBLC, CARB databases, and

several recently issued permits. As previously noted, no applicable VOC standards have

been promulgated for combustion turbines or duct burners under 40 CFR parts 60 and 61.

In accordance with 25 Pa. Code §127.205(7), the proposed VOC LAER limit is

equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

5.3.3 Combustion Turbine PM/PM10/PM2.5 BACT/LAER Analyses

Emissions of PM10 and PM2.5 from combustion turbines result from the inert solids

contained in the combustion air, unburned fuel hydrocarbons resulting from incomplete

combustion which agglomerate to form particles, condensable organic and inorganic

(e.g., sulfuric acid mist) compounds and secondary particulates formed as salts in the

exhaust stream (e.g., ammonium salts related to SCR). The proposed project is located in

an area that is designated as nonattainment for PM2.5. As a result, a LAER analysis is

required for all of the project’s PM2.5 sources. No applicable PM standards have been

promulgated for combustion turbines or duct burners under 40 CFR parts 60 and 61.



5-83

All of the filterable PM emitted from a combustion turbine/HRSG exhaust stack is

expected to have an aerodynamic particle size diameter of less than one micrometer. As

a result, from this point forward the LAER analysis will focus on filterable and

condensable particulate matter as measured by EPA Methods 5 or 201, and 202. In

addition, no differentiation will be made between PM, PM10, and PM2.5.

5.3.3.1 Step 1: Identify Combustion Turbine PM Limits

Table 5-15 presents a summary of previous combustion turbine RBLC precedents for PM

emissions.62 The summary includes only the results for projects where oxidation catalyst

and SCR are applied. The reason for including only precedents where oxidation catalyst

and SCR are applied relates to issues associated with potential sulfur reactions. Any

amount of sulfur in the natural gas that is combusted by the turbine and duct burners can

impact the achievable PM emissions rate in several ways. When combusted, the sulfur

present in the natural gas is converted to sulfur dioxide and sulfur trioxide. Although

only a small percentage of sulfur is converted to sulfur trioxide, sulfur trioxide combines

with water vapor in the flue gas to form sulfuric acid mist, which is then measured as

condensable particulate. Combustion turbines equipped with oxidation catalyst and SCR

oxidize sulfur dioxide to sulfur trioxide, increasing the amount of sulfuric acid mist that

is formed. Combustion turbines with SCR systems form fine particulates of ammonium

salts when unreacted ammonia reacts with sulfur trioxide.

The only controls applied to achieve these PM limits are combustion practices and the

use of low ash and low sulfur fuels (e.g., use of natural gas). No add-on controls, such as

electrostatic precipitators (ESP’s), baghouses, or scrubbers have ever been applied to

control PM emissions from a natural gas-fired combustion turbine. In fact, add-on

controls have never been applied in the broader context on natural gas-fired combustion

sources. This is because PM emissions from the subject sources are inherently low

because: 1) gaseous fuels have no ash content that would contribute to the formation of

62 Not included: projects never built, limits can’t be converted to standard units (lb/MMBtu or ppmv), no

oxidation catalyst.



5-84

Table 5-15. Summary of Particulate Matter BACT Precedents for Combustion Turbines with Oxidation Catalyst 1,2,3,4

RBLC

ID No. Facility Name

Permit

Date

Process

Description

Capacity

(MW) Control Description

PM10/PM2.5 Limit

(lb/MMBtu)

Operational

Status

PA-0291 Hickory Run

Energy Station 04/23/13

GE 7FA, Siemens

SGT6-5000F5,

SGT6-8000H, or

Mitsubishi

M501GAC.

900 Natural Gas

17.5 lb/hr (w/duct

burner)

10.0 lb/hr (w/0 duct

burner)

Pre-Construction

PA-0278

Moxie Liberty

LLC/Asylum

Power

10/10/12

Two Combined

Cycle Turbines with

HSRG and Duct

Burners

468

Low Sulfur Content &

Low Ash Content in

Natural Gas (0.4 grains

S/100scf)

0.004 total PM Pre-Construction

PA-0286

Moxie Energy

LLC/ Patriot

Generation Plant

01/31/13

Two Mitsubishi

M501GAC DLN

&387 MMBtu/hr

Duct Burners or

Two Siemens

SGT6-8000H DLN

& 164 MMBtu/hr

Duct Burners

944

High efficiency inlet air

filters; Good combustion

practices

0.0057 total PM Pre Construction

AK-0071

International

Station Power

Plant

3/31/10

GE LM6000PF-25

Turbines with 140

MMBtu/hr DBs

40-45

(estimate)

Good combustion

practices & maximum

total sulfur content of the

fuel is 20 parts per

million by volume

(ppmv) or less 1

0.0066 turbine

filterable &

condensable

0.0075 duct burner

filterable &

condensable

Under

Construction

NV-0035 Tracy Substation

Expansion Project 9/12/05

2- Turbine & Duct

Burner

306

(total)

Best combustion

practices 0.011 filterable In Operation 2009



GE 7FAs or

Equivalent and Duct

Burners (371

MMBtu/hr)

180 Natural Gas; Good

combustion practices

0.013 filterable &

condensable

(based on 33 lb/hr and

2597 MMBtu/hr)

In Operation

2005/2008

MN-

0054

Mankato Energy

Center 12/4/03

GE 7FA & Duct

Burners

306

(total)

Clean Fuels & Good

Combustion 0.009 filterable In Operation 2006



5-85

RBLC


Permit

Date

Process

Description

Capacity

(MW) Control Description

PM10/PM2.5 Limit

(lb/MMBtu)

Operational

Status

IA-0064 Roquette America 1/31/03 Turbine Combined

Cycle (with DBs)

~53

(587

MMBtu/hr)

Good combustion

practice, natural gas only 0.02 filterable

Unknown;

assumed

operational as in

2008 Title V

permit

OR-0035 Port Westward

Plant 1/16/02

Combustion

Turbines & Duct

Burners

650

(total)

Use of pipeline quality

natural gas

0.1 gr/dscf

(0.44 lb/MMBtu @

15% oxygen)

In Operation 2007

1. Projects without oxidation catalyst are excluded. This includes: IN-0092, IN-0114, OK-0096, and VA-0255.

2. Projects that were never built are excluded. This includes: LA-0192, MI-0357, MI-0366, MN-0071, MS-0059, NC-0101, NJ-0043, NM-0044, NY-0093, OH-

0248, OK-0055, OK-0056, OK-0070, OR-0039, OR- 0040, OR-0043, TX-0469, VA-0287, VA-0289 and VA-0291.

3. Projects where the lb/MMBtu could not be calculated directly and the limit is just for the duct burners are excluded. This includes: LA-0136, LA-0157, LA-

0164, MS-0055, NC-0095, OH-0252, OH-0254, OH-264, TX-0295, TX-0386, TX-0407, TX-0411, TX-0428, TX-0456, TX-0458, TX-0479, TX-0501, TX-

0502, TX-0504, and TX-0511.

4. Natural gas fuel specification requirement of permit (condition 14.5) Permit AQO164CPTO1 Final December 20, 2010. 20 ppmv fuel sulfur content equates

to 1.18 gr S/100 dscf and 0.0033 lb SO2/MMBtu, assuming fuel heating value of 1020 Btu/dscf.



5-86

PM and 2) the potential for PM formation (i.e., soot) is very low because of the high

pressure and excess air conditions under which the fuel is combusted.

5.3.3.2 Step 2: Achieved/Demonstrated Combustion Turbine PM Limits

As shown in Table 5-15, four of the identified precedents are operational and can be

consider to have been achieved in practice. The most stringent PM limits that have been

achieved in practice are as follows:

0.009 lb/MMBtu for a filterable (MN-0064)

0.013 lb/MMBtu for filterable plus condensable

Available data from an initial performance test of the combustion turbines at the Motiva

Port Arthur Refinery where the combustion turbines have oxidation catalyst and SCR

indicates that 0.0066 lb/MMBtu has been achieved in practice for total PM10.

5.3.3.3 Step 3: Establish Combustion Turbine PM BACT/LAER

Taking into account the precedents that have been achieved in practice, the most stringent

PM/PM10/PM/2.5 emission limit is 0.0066 lb/MMBtu for operation with and without duct

firing.

To determine if this emissions limit can be considered LAER two criteria must be

considered. To determine if the first LAER criterion is met, a review of the states

considered most likely to have the most stringent emission limits contained in an

implementation plan was conducted. The results from this effort, summarized in Table

5-16, indicate that a secondary limit on the natural gas sulfur content of less than 0.75

grains/100 dscf should be included as part of a proposed LAER limit. As a result the

following limits are proposed as LAER for PM/PM10/PM2.5 for the combustion turbines

and duct burners:

0.0066 lb/MMBtu with and without duct firing, demonstrated through the use of

EPA reference method 5/202.

The content of sulfur in the natural gas fired by the Cogen Units shall be less than

0.75 grains/100 dscf



5-87

Table 5-16. Regulatory Agencies with PM BACT Requirements/Guidelines for

Combustion Turbines

Regulatory

Agency

Description Emission

Limit

Comment Reference

Bay Area Air

Quality

Management

District

Gas Turbine;

Combined Cycle ≥

40 MW

Natural Gas Fuel

(sulfur content

not to exceed 1.0

grain/100 scf)

Achieved in

Practice

BACT Guideline

(7/18/03)

San Joaquin Valley

Air Pollution

Control District

Gas Turbine ≥ 50

MW Uniform

Load, without Heat

Recovery

PUC regulated

natural gas, LPG,

or non-PUC

regulated gas

with <0.75

grains S/100 dscf

Achieved in

Practice or

contained in the

SIP

BACT Guideline

3.4.7

Last Update:

10/1/2002 & 2008

New Jersey

Department of

Environment

Protection

Stationary

Combustion

Turbines -

Combined Cycle

No specification

or limit State of the Art

Manual for

Stationary

Combustion

Turbines

12/21/2004 2nd

Revision

This proposal meets the second criteria because it is the most stringent limit that has been

achieved in practice.

Given that there is no add-on control applicable to the control of PM/PM10 emissions

from a combustion turbine/duct burner, Shell concludes that the PM/PM10 BACT limit

would be the same as that proposed for LAER. As previously noted, no applicable PM

standards have been promulgated for combustion turbines or duct burners under 40 CFR

parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed

PM/PM10/PM2.5 BACT/LAER limit is equivalent to and satisfies the PaBAT


5.3.4 Combustion Turbine CO BACT Analysis

The proposed project will be located in an area that is in attainment with the CO

standards. No applicable CO standards have been promulgated for combustion turbines

or duct burners under 40 CFR parts 60 and 61.

Carbon monoxide (CO) is a product of incomplete combustion. The formation of this

pollutant is limited by ensuring complete and efficient combustion of the fuel in the



5-88

combustion turbine. High combustion temperatures, adequate excess air and good

air/fuel mixing during combustion minimize CO emissions. Measures taken to minimize

the formation of NOx during combustion may inhibit complete combustion, which can

increase CO emissions. Lowering combustion temperatures through staged combustion

can also increase the level of CO emissions. However, improved air/fuel mixing inherent

in newer DLN combustor designs and control systems has greatly reduced if not

eliminated the impact of fuel staging on CO emissions. This section presents the CO

BACT analysis for the proposed combustion turbines and duct burners.

5.3.4.1 Steps 1 & 2: Identify Potentially Applicable & Technically Feasible Combustion Turbine CO Controls

Table 5-17 presents a summary of the results from a review of the RBLC database and

other identified permitting actions. Based on this review, the following approached to

control CO emissions were identified:

Oxidation catalyst, and

Good combustion control.

The oxidation catalyst used in combustion turbine applications is typically a precious

metal catalyst (e.g., platinum), which has been applied over a metal or ceramic substrate.

The catalyst is located either before or in the heat recovery steam generator (HRSG),

depending on the turbine/duct burner exhaust temperature. The catalyst lowers the

activation energy for the oxidation of CO so that CO is oxidized at lower temperatures

(400°F to 1100°F) than in the combustors. This technology has been applied to turbines

of all sizes and as such is considered a demonstrated technology. The removal efficiency

for CO is typically greater than 90 percent.

Good combustion control is based upon maintaining good mixing, a proper fuel/air ratio

and adequate time at the required combustion temperature. Based on a review of the



5-89

Table 5-17. Summary of CO BACT Precedent for Turbines with Oxidation Catalyst 1

RBLC


Permit


Capacity

(MW)

Emission Limit 6

ppmv @ 15% O2

Operational

Status

PA-0291 Hickory Run Energy

Station 04/23/13

GE 7FA, Siemens SGT6-5000F5,

SGT6-8000H, or Mitsubishi

M501GAC.

900 2.0 (3-hr) Pre Construction

PA-0286

Moxie Energy LLC/

Patriot Generation

Plant

01/31/13





944 2.0 Pre-Construction

PA-0278 Moxie Liberty


Two Combined Cycle Turbines with

HRSG & Duct Burners 468 2.0 Pre-Construction

CA 2 Oakley Generating

Station 5/18/11 GE 207FA

624

(total)

2

(1-hr)

Under

Construction

VA 3 Warren County

Power Station 12/21/10

Mitsubishi Model M501 (2,996

MMBtu/hr) & Duct Burner (500

MMBtu/hr)

299

1.5 without DB

2.4 with DB

1-hr

Under

Construction

GA 4 Live Oaks Power

Plant 4/8/10

Siemens SGT6-5000F Combustion

Turbines & 359 MMBtu/hr Duct

Burners

200

2 without DB

3.2 with DB

(3-hr)

Pre-construction

CT-0151 Kleen Energy

Systems, LLC 2/25/08

Siemens SGT6-5000F (2136

MMBtu/hr)

& Duct Burners (445 MMBtu/hr)

580

(total)

0.9 without DB

1.45 with DB

(1-hr)

In Operation

2011

NV-

0035

Tracy Substation

Expansion Project 9/12/205 2- Turbines/Duct Burners

306

(total)

3.5 with DB

(3-hr)

In Operation

2009



GE 7FAs or Equivalent & Duct

Burners (371 MMBtu/hr) 180

3

(24-hr)

In Operation

2005/2008



5-90

RBLC


Permit


Capacity

(MW)

Emission Limit 6

ppmv @ 15% O2

Operational

Status

CA 5 Otay Mesa Energy

Center LLC 12/18/03 GE 7FA 172

6

(3-hr)

Operating in

2009

MN-

0054

Mankato Energy

Center 12/4/03

GE 7FA & Duct Burners (800

MMBTU/HR) 180

4 at full load

4.7 at reduced

load

(3-hr)

In Operation

2006

CA 5 Smud Consumnes

Power Plant 9/9/03 GE 7FA ~172 4

In Operation

2006

CA 5 Magnolia Power

Project 5/27/03 PG7241FA 181

2

(1-hr)

In Operation

2005

1. Projects that were never built are excluded. This includes: LA-0192, MI-0366, VA-0291, OR-0043, MI-0357, NJ-0043, OH-0248, OK-0070,

and OH-0248.

2. Not in RBLC. Oakley Generating Station Final Determination of Compliance, Application 20798, January 2011.

3. Not in RBLC correctly. Warren County Power Station, PSD permit to construct and operate, December 21, 2010.


5. California Air Resources Board (CARB) database.

6. Unless otherwise noted, the limits presented are for normal operation and are not applicable during start-up and shutdown.



5-91

permit precedents in the RBLC database, the expected CO emissions from a combustion

turbine without oxidation catalyst are between 2 and 15 ppmv @ 15% O2. The level

achieved is dependent on the combustion turbine and DLN combustor technology.

The use of oxidation catalyst combined with good combustion design/operation is

considered demonstrated in practice.

5.3.4.2 Step 3: Ranking of Technically Feasible CO Control Technologies

The CO precedents presented in Table 5-17 can be summarized as follows:

Combustion turbine with duct firing: 1.45 to 6 ppmv @ 15% O2

Combustion turbine without duct firing: 0.9 to 2.0 ppmv @ 15% O2

The most stringent permit precedent identified is the Kleen Energy System with hourly

limits of 1.45 ppmvd and 0.9 ppmvd for operations with and without duct firing,

respectively. This is the only precedent for an operational project that is less than

2.0 ppmvd @ 15% O2. In accordance with the BACT methodology, the cost,

environmental, and economic impacts associated with this precedent must be evaluated

before a less stringent BACT limit can be proposed.

5.3.4.3 Step 4: Evaluate Most Effective Combustion Turbine CO Controls

The current BACT limits for the BAAQMD and SJVAPCD63 are 4.0 ppmvd and

6.0 ppmvd (3-hour average), respectively. The BAAQMD evaluated the cost benefit of

reducing CO emissions from a 7FA combustion turbine from 2 ppmvd to 1 ppmvd with

the following conclusion:64

“The District evaluated the costs and emissions reduction benefits of installing a

larger oxidation catalyst capable of consistently maintaining emissions below

1.0 ppm. Based on these analyses, the cost of achieving a 1.0 ppm permit limit

would be an additional $77,882 per year (above what it would cost to achieve a

2.0 ppm limit), and the additional reduction in CO emissions would be

63 Bay Area Air Quality Management District (BAAQMD) and San Joaquin Valley AQMD (SJVAQMD) 64 Page 41 of Final Determination of Compliance Oakley Generating Station, Application 20798, January

2011.



5-92

approximately 20.11 tons per year, making an incremental cost-effectiveness

value of over $3,874 per ton of additional CO reduction. Moreover, the total cost

of achieving a 1.0 ppm CO limit (as opposed to the incremental costs of going

from 2.0 ppm to 1.0 ppm) would be over $524,959 per year, and the total

emission reductions from 9.0 ppm from the turbine to a 1.0 ppm limit would be

121.01 tons per year, resulting in a total (or “average”) cost effectiveness value

of $4,338. Based on these costs (on a per-ton basis) and the relatively little

additional CO emissions benefit to be achieved (on a per-dollar basis), requiring

a 1.0 ppm CO permit limit cannot reasonably be justified as a BACT limit.

Requiring controls to meet a 1.0 ppm limit would be more expensive, on a per-ton

basis, than what other similar facilities are required to achieve. The District has

not adopted its own cost-effectiveness guidelines for CO, but a review of

guidelines adopted by other districts in California and of BACT determinations

made by agencies around the country found that additional CO controls are not

normally required where the cost per ton exceeds a few hundred to a few

thousand dollars per ton. Additional CO reductions here would not be justified as

BACT given these costs.”

The above BAAQMD cost benefit evaluation associated with reducing combustion

turbine CO emissions from 2 ppmvd to 1 ppmvd was for a larger turbine (GE 7FA

turbines are 175 MW turbine) than the proposed project’s turbines (i.e., the GE 6FB is 41

MW and the Siemens SGT-800 is 49 MW). Due to economies of scale, the cost

effectiveness value (i.e., cost per amount of CO control to achieve a lower ppmvd value)

for the proposed project’s smaller combustion turbines would be higher than for the 175

MW GE 7FA turbine discussed in the above quote from BAAQMD, and the additional

CO reductions would likewise not be justified as BACT given such costs.

5.3.4.4 Step 5: Combustion Turbine and Duct Burner CO BACT Selection

Based on the cost infeasibility associated with achieving a CO level below 2.0 ppmvd @

15% O2, the use of good combustion practices in combination with a CO oxidation

catalyst to achieve the following BACT limits is proposed:

2 ppmv @ 15% O2 on a 1 hour average basis;

Total annual emissions from the Cogen Units including startups and

shutdowns shall not exceed more than 14.5 tons of CO in any 12 consecutive

month period;

Hourly emissions from a given Cogen Unit during startup and shutdown shall

not exceed 276 lb/hr of CO;



5-93

Startup is defined as the period between the commencement of ignition and

when the combustion turbine reaches 55 percent of it’s baseload operating

level;

Shutdown shall not occur for more than 30 minutes in duration;

Shutdown is defined as the period between the time that the combustion

turbine drops below 55 percent operating level and the fuel is cut to the unit.

As previously noted, no applicable CO standards have been promulgated for combustion

turbines or duct burners under 40 CFR Parts 60 or 61. In accordance with 25 Pa. Code

§127.205(7), the proposed CO BACT limit is equivalent to and satisfies the PaBAT


5.3.5 Combustion Turbine GHG BACT Analyses

The proposed Cogen Units will combust natural gas and will emit three GHGs: methane

(CH4), carbon dioxide (CO2), and nitrous oxide (N2O).65 All fossil fuels, including

natural gas, contain carbon and the majority of the heat released comes from the

oxidation of this carbon to form CO2. Methane from the combustion of fossil fuels is a

product of incomplete combustion and is emitted in much smaller quantities. Trace

quantities of N2O are generated by oxidation of nitrogen in the combustion air and fuel

nitrogen. On January 8, 2014, US EPA re-proposed new source performance standards

for emissions of carbon dioxide (CO2) for new affected fossil fuel-fired electric utility

generating units (EGUs). Under those proposed rules, natural-gas fired gas turbine

systems would be subject to CO2 emission limit of 500 kilograms (kg) of CO2 per

megawatt-hour (MWh) of gross output (1,100 lb/MWh) on a 12-operating month rolling

average.66

For fossil fuel combustion turbines and duct burners, there are three broad strategies for

reducing GHG emissions: use of low carbon fuels, energy efficiency and carbon capture

and sequestration (CCS). The use of low carbon fuels and energy efficiency are

65 At times, there may be small amounts of tailgas available as fuel that is in excess of what is consumed

by the ethane cracking furnaces. During these periods these small amounts of tailgas will be burned in

the duct burners. Due to the combustion characteristics of tailgas it is technically infeasible to combust

tailgas in the combustion turbines along with natural gas. 66 79 FR 1430.



5-94

discussed in the section. The application of CCS is addressed in Section 5.6 for all of the

project CO2 emissions sources.

5.3.5.1 Step 1: Identify Potentially Applicable Combustion Turbine GHG Controls

The use of low carbon fuels and energy efficiency to reduce GHG emissions from the

proposed Cogen Units is discussed below.

Lower-Emitting Fuel

Table 5-18 presents a summary of the expected GHG emissions associated with the

combustion of the various fossil fuels, including the natural gas that will be burned by the

proposed Project’s Cogen Units. The GHG emissions from combustion of coal, No. 6

and No. 2 oil are presented for comparison. As shown, the natural gas that will be burned

by the proposed Cogen Units is inherently lower GHG emitting than other fossil fuels.

This is true because natural gas has a low carbon-to-hydrogen ratio. The combustion of

hydrogen and hydrogen containing gaseous fuels such as tailgas reduces GHG emissions

because the combustion of hydrogen forms water vapor, which is not considered by

USEPA as a GHG.

Table 5-18. GHG Emissions for Combustion Turbine Fuels

Fuel Type Pounds CO2e per Million Btu

Coal 210 1



Natural Gas 117 1

1. From Tables C-1 and C-2 to subpart C of 40 CFR part 98.

Energy Efficiency

An energy efficient combustion turbine, DB, and HRSG design in conjunction with good

operating and maintenance practices allows the required amount of steam and electric

energy to be produced using less fuel, thereby reducing emissions of GHG collectively

and each greenhouse gas individually. In addition, some projects located where weather

conditions allow have installed solar arrays as part of the combustion turbine project.



5-95

Specific measures include the following:

Maximizing the HRSG surface area for heat recovery. This design element

increases the amount of heat recovered from combustion gases, thereby reducing

the amount of heat wasted to the atmosphere. Stack gas temperature is reduced to

the extent possible. Industry practice for HRSGs is to maintain the flue gas

temperature at least 45 °F above the flue gas moisture dew point (i.e., condensing

temperature). This is because condensate is acidic and will corrode the

convection tubes, flue gas ductwork, and stack. The amount of CO2 reduction is

typically one percent per 45 °F flue gas temperature decrease. 67

Flue gas oxygen monitoring. This design element and operational practice aids

in detecting air infiltration. Excess air in the HRSG increases GHG emissions

because less heat can be recovered in the HRSG; so minimizing excess air

reduces GHG emissions. Excess air in the combustion turbine has the same effect

as air infiltration and has the added effects of increasing NOx emissions and

requiring more fuel.

Insulation. Insulation of the combustion turbine combustion section and HRSG

will minimize heat losses, thereby reducing GHG emissions.

Combustor/DB maintenance and HRSG tube cleaning. Without good

maintenance practices, combustors and heat transfer surfaces can wear or become

fouled, lowering thermal efficiency significantly below design levels. Routine

maintenance practices reduce GHG emissions by minimizing these efficiency

losses.

Solar array. A solar array can be used to provide steam to the HRSG during

daylight; there by reducing the amount of duct firing. A solar array installed in

California required 250 acres to generate 50 MW of steam.68

Inlet air-cooling. Inlet air-cooling reduces the combustion air temperature,

allowing for more air mass to be processed through the combustion turbine,

raising the power generation and turbine efficiency. Inlet air cooler technology

includes the use of wetted media, fogging, mechanical chillers, absorption

chillers, etc.69

All of these measures are inherent in the proposed Project’s design except for the

installation of solar arrays.

67 “Energy Efficiency Improvement and Cost Saving Opportunities For Petroleum Refineries: An

ENERGY STAR® Guide for Energy and Plant Managers.” Ernest Orlando Lawrence Berkeley National

Laboratory, Berkeley, Calif. February 2005. 68 Palmdale Hybrid Power Project, Final Staff Report, California Energy Commission, December 2010,

CEC 700-2010-001-FSA, Page 5.3-6. 69 Turbine Inlet Cooling Association-Turbine Inlet Air Cooling Benefits and Technologies.

http://www.turbineinletcooling.org/benefits.html; http://www.turbineinletcooling.org/technologies.html



5-96

5.3.5.2 Step 2: Eliminate Technically Infeasible GHG Controls

The proposed Cogen Units will be fired with natural gas, the lowest CO2e emitting

conventional fuel for power and steam generation.70 This option is technically feasible

and available.

All of the energy efficiency options are considered technically feasible, although

requiring the use of a solar array is considered to be impractical due to weather in western

Pennsylvania (which is considerably different than Palmdale, California), and the use

both solar array and cooling inlet gas would constitute redefining the project. EPA has a

long standing policy of not redefining the source. For example, the USEPA’s response to

comments for the Palmdale Hybrid Power Project states:71

“The incorporation of the solar power generation into the BACT analysis for this

facility does not imply that other sources must necessarily consider alternative

scenarios involving renewable energy generation in their BACT analyses. In this

particular case, the solar component was a part of the applicant’s Project as

proposed in its PSD permit application. Therefore, requiring the applicant to

utilize, and thus construct, the solar component as a requirement of BACT did not

fundamentally redefine the source.”

Even if the addition of a solar array is not considered as redefining the source, there is

insufficient land available at the proposed site for a 250 acre solar array. Additionally, to

generate 50 MW of steam in Beaver County Pennsylvania, a much larger solar array

would be required than that proposed for the Palmdale Hybrid Power Project due to the

different latitude and weather in Beaver County, PA.

The use of inlet air cooling is also considered to be a redefinition of the source. This

technology is employed to keep peaking combustion turbine power generation from

deteriorating during high temperature days when electrical demand is high. These

70 For purposes of this analysis, because the amount of tailgas that is fired by the duct burners will be small

and is not quantifiable based on the current project design basis, it is not considered as a part of this

analysis 71 Comment/Response 40 of Responses to Public Comments on the Proposed Prevention of Significant

Deterioration Permit for the Palmdale Hybrid Power Project, U.S. Environmental Protection Agency,

October 2011.



5-97

applications are typically located in the southern and western states to maintain electric

utility grid stability during the hot summer months. This has little relevance to the

proposed Cogen Units, which will not operate as peaking units. However, when

employed, inlet air-cooling allows for more fuel to be combusted, resulting in increases

in GHG emissions.

5.3.5.3 Step 3-4: Rank Technically Feasible Combustion Turbine Controls

As noted above, the application of CCS is addressed in Section 5.6 for all of the project

CO2 emissions sources. With the elimination of a solar array and inlet air-cooling as

feasible options for the proposed Cogen Units, the top-ranked GHG control option

involves the use of natural gas in combination with energy-efficient HRSG design

including:

Maximizing the HRSG surface area for heat recovery,

Flue gas oxygen monitoring,

Insulation, and

Combustor/DB maintenance and HRSG tube cleaning.

Each of these controls will be included in the combustion turbine HRSG design for either

of the combustion turbines under consideration for the proposed Project.

The proposed CTs will be either General Electric Frame 6Bs or Siemens SGT-800s.

Each of these CTs options, which are natural gas-fired highly efficient designs in

combination with energy-efficient HRSG designs, have comparable performance based

efficiencies.

5.3.5.4 Step 5: Propose Combustion Turbine GHG BACT Limit

There are several recent GHG BACT determinations for combustion turbines used for

electric power generation where the steam produced by the HRSG is used to generate

electricity. A summary of these determinations is presented in Table 5-19. As shown,

the GHG BACT limits are expressed as a function of the electric power generated (i.e.,

Btu/kWh or lb CO2e/MWh). For the proposed project, a small amount of the heat

recovered by the HRSG will be used to generate steam that will be consumed by the



5-98

Table 5-19. Summary of Combustion Turbine Cogeneration GHG BACT Determinations

RBLC ID

/STATE ID

PROJECT NAME/DESCRIPTION MW BACT LIMITS

PA Plan

Approval

67-05009C 1

York Plant Holding

2x LM6000 Simple Cycle

39.788 11,389 Btu/kWh net 30-day rolling

(includes 3.3 % increase for design variations, 6% for

turbine degradation, 1.5% for auxiliary equipment

degradation)

1,330 lb CO2e/MWh net 30-day rolling

WA PSD-

11-05 2

Fredonia Generating Station Expansion

Project

GE &FA.05

209.4

net

1,299 lb CO2e/MW-hr net output, 365-day rolling average

311,382 tpy as CO2e, 12-month rolling total


Project

GE 7FA.04

182.3

net




Project

SGT6-5000F4

201.1

net




Project

2x GE LMS100

99.8 net

each

1,138 lb CO2e/MW-hr net output per unit, 365-day rolling


TX-0632 3 Deer Park Energy Center LLC

One SIEMENS CTG5/HRSG5 (FD3-

Series)

180 920 lb CO2/MW-h (30 day rolling)

7,730 Btu/KWh (30 day rolling)

1,044,629 tpy CO2 (365 day rolling)

Also has tpy limits for CH4, N2O, and CO2e.



5-99

RBLC ID

/STATE ID


TX-0633 4 Channel Energy Center, LLC

One SIEMENS CTG5/HRSG5 (FD3-

Series)

180 920 lb CO2/MW-h (30 day rolling)

7,730 Btu/KWh (30 day rolling)

984,393 tpy CO2 (365 day rolling)


PSD-TX-

1244-GHG 5

Lower Colorado River Authority

2x General Electric 7FA and one steam-

electric generator

195

each

920 lb/MWh net (365-day rolling) combined

7,720 Btu/KWh (365-day rolling) combined

908,957.6 tpy CO2 each (365-day rolling) each


GA 4911-

103-0012-

V-04-1 6

Effingham County Power, LLC

2x nominal 180-MW GE Model 7FA

2x heat recovery steam generators

(HRSGs) each equipped with a natural gas-

fired duct burner

One (1) 325-MW steam turbine generator

668

total

CTG each 863,953 tons CO2e per 12 months 9

DBs each 111,837 tons CO2e per 12 months 9

PSD-TX-

1290-GHG 7

(draft)

El Paso Electric- Montana Power Station

4x GE Model LMS100 Simple Cycle

100

each

1,194 lb CO2/MW-h (12 month rolling) per turbine

250,885.25 tpy each (365-day rolling)


CA 8

No. 15487 Calpine – Russell City Energy Center

2x Siemens/Westinghouse 501F, 2,038.6

MMBtu/hr each

2x Duct Burner Supplemental

Firing System, 200 MMBtu/hr each

612 242 metric tons of CO2E from the S-1 & S-3 Gas Turbines

and S-2 & S-4 HRSGs per hour.

5,802 metric tons of CO2E from the S-1 & S-3 Gas

Turbines and S-2 & S-4 HRSGs per day.

1,928,182 metric tons of CO2E from the S-1 & S-3 Gas

Turbines and S-2 & S-4 HRSGs per year.

S-1 & S-3 Gas Turbines such that the heat rate of each

turbine does not exceed 7,730 Btu/kW-hr



5-100

RBLC ID

/STATE ID


PA-0291 Hickory Run Energy Station – 2x GE 7FA,

Siemens SGT6-5000F5, SGT

6-8000H, or Mitsubishi M501GAC.

3.4MMMCF/H

900

total

3,665,974 tpy CO2e based on 12-month rolling total for

both units.

1000 lb/MW-hr CO2 on a 12-operating month annual

average basis

PA-0278 Moxie Liberty LLC/Asylum Power – Two

Combined Cycle Turbines with HRSG and

Duct Burners

468

total

1,480,086 tpy CO2e at 468 MW Powerblock; 1,388,540 tpy

CO2e at 454 MW Powerblock. Good Combustion

Practices.

Plan

Approval

41-

00084A10

Moxie Patriot, LLC - Two Mitsubishi

M501GAC DLN &387 MMBtu/hr Duct

Burners or Two Siemens SGT6-8000H

DLN & 164 MMBtu/hr Duct Burners

944

total

BAT limits: Mitsubishi 1,572,362 tpy CO2e or Siemens

1,401,333 tpy CO2e 12 consecutive month period

1. Page 84 of 110; Technical Support Document for Prevention of Significant Deterioration (PSD) Permit, Permit No: PSD-11-05, Department of Ecology

State of Washington, October 21, 2013

2. Page 36 of 110; Technical Support Document for Prevention of Significant Deterioration (PSD) Permit, Permit No: PSD-11-05, Department of Ecology

State of Washington, October 21, 2013.

3. PSD-TX-979-GHG; USEPA Region 6 PSD permit for Calpine Corporation Deer Park Energy Center; 11/29/2012.

4. PSD-TX-955-GHG; USEPA Region 6 PSD permit for Calpine Corporation Channel Energy Center; 11/29/2012.

5. LCRA, Thomas C. Ferguson Power Plant Prevention of Significant Deterioration Permit for GHG Emissions, permit number PSD-TX-1244-GHG; 11/10/11.

6. Part 70 Operating Permit Amendment, Permit Amendment No.: 4911-103-0012-V-04-1, Effective Date: May 30, 2012.

7. PSD-TX-1290-GHG; USEPA Region 6 PSD permit for El Paso Electric Company Montana Power Station; Draft 9/22/2013.

8. Bay Area Air Quality Management District Russell City Energy Center; 1/3/10.

9. As CO2e when firing natural gas. The CTG units have separate CO2e limits when firing fuel oil.

10. Pa.B. 6145 September 9, 2012.



5-101

ethylene and polyethylene manufacturing processes. Because the vast majority of the

steam generated will be used to generate power, the proposed GHG BACT limits are

expressed as a function of electric power generated (i.e., Btu/kWh or lb CO2e/MWh).

All of the determinations except York Plant Holding are for combustion turbines that are

much larger than proposed project’s Cogen Units and all of the determinations include

tons per year, day or hour CO2 or CO2e limits. Three of the determinations have Btu per

kilowatt-hour energy efficiency limits.

Based on the form of the limits associated with the recent precedents and the similarity of

the proposed project with regards to power generation, the following emission limits are

proposed:72

GE G6581 Proposed CO2e BACT Limits:

o 1,030 pounds CO2e/MW-h (30 day rolling) combined turbines/duct

burners/HRSGs/steam-electric generators.

o 340,558 tpy CO2e (365 day rolling) per turbine/duct burner.

Siemens SGT-800 Proposed CO2e BACT Limits:

o 978 pounds CO2e/MW-h (30 day rolling) combined turbines/duct

burners/HRSGs/steam-electric generators.

o 353,893 tpy CO2e (365 day rolling) per turbine/duct burner.

For purposes of demonstrating compliance, the CO2e will be calculated based on CO2

measurements multiplied by 1.0010. As previously noted, US EPA has re-proposed new

source performance standards for emissions of carbon dioxide (CO2) for new affected

fossil fuel-fired electric utility generating units (EGUs). The above values would meet

the proposed NSPS standard, which for these turbines would be 1,100 lb CO2/MWh on a

12-month rolling average basis. In accordance with 25 Pa. Code §127.205(7), the

proposed GHG BACT limit is equivalent to and satisfies the PaBAT requirements of 25

Pa. Code §127.12(a)(5).

72 EPA recently proposed NSPS subpart TTTT. This NSPS would regulate emissions of CO2e from

combustion turbines that are considered electric utility generating units. The final NSPS rule will define

the least stringent CO2e limit that can be proposed as BACT as of the date of initial proposal.



5-102

5.4 Diesel Engines

As part of the proposed Project, four diesel-fired emergency generator engines (same

model) will be installed in the vicinity of the proposed Cogen Units and three diesel-fired

firewater pump engines (same model) will be installed near the river. The rated output of

each of the proposed electric generator engines is 3000 kilowatts (4022 BHP). The rated

output of each of the proposed firewater pump engines is 700 BHP (522 kilowatts). All

of the diesel engines will be compression-ignition, internal combustion engines. The per

cylinder volume for the diesel engines will be less than ten 10 liters. As noted in

Section 4.0, emissions from this type of internal combustion engine are regulated under

NSPS standards set forth in 40 CFR subpart IIII with respect to NOx, non-methane

hydrocarbon (NMHC),73 CO, and PM emissions. By reference in NSPS subpart IIII, the

emission standards at 40 CFR §89.112 apply to the emergency generator diesel engines.

The emission standards for these engine categories are presented below.

Pollutant

Diesel Generators Diesel Firewater Pumps (700 hp)

(g/kw-hr) (g/hp-hr) (g/kw-hr) (g/hp-hr)

NOx+NMHC 6.4 4.8 4.0 3.0

CO 3.5 2.6 3.5 2.6

PM 0.20 0.15 0.20 0.15

The following subsections present the NOx+NMHC (VOC), CO, and PM emission

control technology analyses for the proposed emergency diesel engines.

5.4.1 Diesel Engine NOx and VOC LAER Analyses

BACT permit limits must be at least as stringent as applicable NSPS limits. Based on the

emission standards under Subpart IIII of 40 CFR part 60, the minimum standard that

would meet BACT requirements for NOx + VOC emissions from the proposed stationary

emergency diesel generator engines is 6.4 g/kw-hr (4.8 g/hp-hr) and the minimum that

would meet BACT for the firewater pump engines is 4.0 g/kw-hr (3.0 g/hp-hr).

73 NMHC is assumed to be equivalent to VOC for purposes of the control technology review and proposed

LAER.



5-103

5.4.1.1 Step 1: Identify Diesel Engine NOx & VOC Controls

Table 5-20 and Table 5-21 present summaries of the most recent permit determinations

listed in the RBLC database for stationary emergency generator engines and stationary

emergency firewater engines, respectively. As shown, for both engine categories,

combustion controls (good combustion practices, turbocharging/after cooling, and

compliance with the NSPS Part 60, subpart IIII standards) are used to meet BACT/LAER

requirements.

In addition to combustion controls, the USEPA Alternative Control Techniques (ACT)

document for stationary diesel engines identifies the following potential control

technologies and techniques for NOx and VOC emissions from compression-ignition

engines: 74

Injection Timing Retard, also called ignition timing retard, involves delaying the

fuel injection point in each engine cycle such that the heat release from fuel

combustion occurs during the cylinder expansion. Lower NOx emissions are

achieved by reducing the peak combustion temperature.

Exhaust Gas Recirculation involves retaining or re-introducing a fraction of the

exhaust gases. Lower NOx emissions are achieved by reducing the peak

combustion temperature and by reducing the amount of available molecular

oxygen.

NOx Adsorber Technology typically utilizes alkali or alkaline earth metal

catalysts to adsorb NOx on the catalyst surface under the fuel-lean and oxygen-

rich conditions typical of diesel engine exhaust. Periodically, the catalyst bed is

subjected to fuel-rich exhaust in order to desorb the NOx and regenerate the

catalyst. The desorbed NOx is catalytically reduced over a second catalyst,

typically platinum and/or rhodium active metal.

SCR for NOx reduction, and

Oxidation Catalyst for VOC reduction.

74 Alternative Control Techniques Document: Stationary Diesel Engines. EPA Contract No. EP-D-07-019;

March 2010 Final Report.



5-104

Table 5-20. RBLC Summary of NOx and VOC Precedents for Emergency Generator Diesel Engines

RBLC

ID NO. Facility Name

Permit

Date

Process

Description

Capacity

(hHiclory

Run p)

Control

Description

NOx Limit

(g/hp-hr)

VOC Limit

(g/hp-hr)

NOx+VOC

Limit

(g/hp-hr)

FL-0332 Highlands Biorefinery

and Cogeneration Plant 9/23/11

Emergency

Equipment

2666 (basis

2000 kW)

NSPS 40 CFR 60,

subpart IIII 4.8

4.8

(basis: 0.75 hp/kW)

FL-0322

Sweet Sorghum-to-

Ethanol Advanced

Biorefinery

12/23/10 Emergency

Generators 2682

NSPS 40 CFR 60,

subpart IIII 4.8

4.8

(basis: 0.75

Hp/kW)

NV-0050 MGM Mirage 11/30/09 Diesel Emergency

Generators 3622

Turbocharger & After-

Cooler 4.6 0.1 4.7

NV-0050 MGM Mirage 11/30/09 Emergency

Generators 2206

Turbocharging, After-

Cooling, & Lean-Burn

Technology

5.9 0.1 6.0

LA-0231 Lake Charles Gasification

Facility 6/22/09

Emergency Diesel

Power Generator

Engines

1341 Comply with 40 CFR

60 subpart IIII 5.8

5.8

(basis: lb/hr)

SDAQMD Pacific Bell 12/5/12 Emergency

Generator 3674 Tier 2 certified engine 3.5 4.6 3

SDAQMD San Diego International

Airport 10/3/11

Emergency

Generator 1881 Tier 2 certified engine 3.9 4.6 3

SDAQMD City of San Diego PUD

(Pump Station 1) 7/9/12

Emergency Diesel

(2) 2722 Tier 2 certified engine 4.0 4.6 3

SC-0115 GP Clarendon LP 2/10/09 Diesel Emergency

Generator 1400

Tune-Ups &

Inspections performed

as outlined in Good

Management Practice

Plan.

3.7 1 0.11 3.8

(basis: lb/hr)

SC-0114 GP Allendale LP 11/25/08 Diesel Emergency

Generator 1400 3.7 1 0.1 1 3.8

OK-0129 Chouteau Power Plant 1/23/09 Emergency Diesel

Generator 2200 4.8 2 0.3 2 4.8

OH-0317 Ohio River Clean Fuels,

LLC 11/20/08

Emergency

Generator 2922

Good Comb. Practices

& Engine Design,

Ignition Timing

Retard, Turbocharger,

& Low-Temp.

Aftercooler

4.8

(basis: 0.75

Hp/kW)

OK-0128 Mid American Steel

Rolling Mill 9/8/08

Emergency

Generator 1200 5.9 0.3

6.2

(basis: lb/hr)



5-105

RBLC


Permit

Date

Process

Description

Capacity

(hHiclory

Run p)

Control

Description

NOx Limit

(g/hp-hr)

VOC Limit

(g/hp-hr)

NOx+VOC

Limit

(g/hp-hr)

NV-0047 Nellis Air Force Base 2/26/08 Large Internal

Combustion Engines 1350

Turbocharger &

Aftercooler 7.6 0.2 7.8

MD-0037 Medimmune Frederick

Campus 1/28/08

3x Diesel-Fired,

Emergency

Generators Each

(2500 KW)

3604 6.1

(LAER)

LA-0219 Creole Trail LNG Import

Terminal 8/15/07

Diesel Emergency

Generator 2168

Good Comb. Practices

& Engine Design

Incorporating Fuel

Injection Timing

Retardation (ITR)

7.9 0.3 8.2

(basis: lb/hr)

IA-0088 ADM Corn Processing -

Cedar Rapids 6/29/07

Emergency

Generator

2000

(basis:1500

KW)

Engine required to

meet limits established

as BACT (Tier 2

Nonroad).

4.5 0.3 4.8

MN-0071 Fairbault Energy Park 6/5/07 Emergency

Generator

2333 (basis:

1750 KW) 10.9 0.3 12.2

PA-0271 Merck & Co. Westpoint 2/23/07 Mobile Emergency

Generator 2795 6.8 0.3 7.1



Emergency

Generator 4.93 0.01 4.94

PA-0286 Moxie Energy LLC/

Patriot Generation Plant 01/31/13

Emergency

Generator 4.93

0.01 (as

THC) 4.94


Station 04/23/13

Emergency

Generator 1135 bhp

3.96

(based on

9.89 lb/h

limit)

0.28

(based on 0.7

lb/h limit)

4.24

1. Stack testing not required by permit as part of initial compliance demonstration.

2. Based on Standards From § 89.112; NOX and is inclusive of NMHC. VOC emissions are estimated based on AP-42 (10/96), Section 3.4 TOC Factor.

3. The permit information identified for this engine lists a limit of 4.6 g/hp-hr with the compliance based on a Tier 2 Manufacturer certification. The

Tier 2 limit in Subpart IIII is 4.8 g/hp-hr.



5-106

Table 5-21. RBLC Summary of NOx and VOC Precedents for Emergency Firewater Diesel Engines

RBLC


Permit

Date

Process

Description

Capacity

(hp) Control Description

NOx

(g/hp-hr)

VOC

(g/hp-hr)

NOx + VOC

(g/hp-hr)

IA-0088

ADM Corn

Processing - Cedar

Rapids

06/29/07 Fire Pump 540

Engine is required to meet

limits established as BACT

(TIER 3 Nonroad).

2.80 0.2 3.00

IA-0095

Tate & Lyle

Ingredients Americas,

Inc.

09/19/08 Fire Pump Engine 575 2.93

calculated

0.75

calculated 3.68

LA-0231 Lake Charles

Gasification Facility 06/22/09 Firewater Pumps (3) 575

Comply with 40 CFR 60

subpart IIII 4.75

VOC not

permitted VOC not permitted

*MI-

0402 Sumpter Power Plant 11/17/11

Diesel Fuel-Fired

Combustion Engine

(RICE)

732 Good combustion practices 4.85 VOC not


SC-0114 GP Allendale LP 11/25/08 Firewater Diesel 525

Tune-Ups/Inspections will

be performed as outlined in

Good Management Practice

Plan.

5.10

calculated

0.41

calculated 5.51

LA-0194 Sabine Pass LNG

Terminal 11/24/04

Firewater Booster

Pump Diesel Engines

(2)

300 Good Engine Design &

Proper Operating Practices 5.20 0.15 5.35

LA-0219 Creole Trail LNG

Import Terminal 08/15/07

Firewater Pump

Diesel Engine 525

Good Combustion Practices

& Good Engine Design

Incorporating Fuel Injection

Timing Retardation (ITR)

5.83

calculated

0.048

calculated 5.88



Firewater Diesel

Engine 660


& Good Engine Design

Incorporating Fuel Injection

Timing Retardation (ITR)

6.93

calculated

0.028

calculated 6.96


Terminal 11/24/04

Firewater Diesel

Engines 1-3 660

Good Engine Design &

Proper Operating Practices

8.39 1

calculated

0.048

calculated 8.44

PA-0244 First Quality Tissue,

LLC 10/20/04 Fire Pump 575 14.1

No limit in

permit No limit in permit

OH-0254

Duke Energy

Washington County

LLC

08/14/03 Emergency Diesel

Fire Pump Engine 400

Low Sulfur Fuel,

Combustion Control 14.5

VOC not




Fire Pump

2.6 0.1 2.7



5-107

RBLC


Permit

Date

Process

Description

Capacity


NOx

(g/hp-hr)

VOC

(g/hp-hr)

NOx + VOC

(g/hp-hr)

PA-0286

Moxie Energy LLC/

Patriot Generation

Plant

01/31/13

Fire Pump Engine -

460 BHP

460 bhp 2.6 0.1 2.7


Station 04/23/13

Emergency Firewater

Pump (450 BHP)

450 bhp

1.88

(based on

1.86 lb/h

limit)

1.1

(based on

1.11 lb/h

limit)

3.0

1. RBLC had 0.0185 g/bhp. This should have been labeled as lb/bhp, which converts to 8.39 g/bhp.



5-108

5.4.1.2 Step 2: Eliminate Technically Infeasible NOx and VOC Control Options

Although SCR and oxidation catalyst have been applied and are considered to be

technically feasible for engines that operate under normal conditions, they are not

considered to be technically feasible for engines in emergency service. To ensure that

each engine is in good working order, the proposed engines will be operated infrequently

and for short periods of time (less than one hour/week). The short duration of the

proposed engine’s operation does not provide adequate time for the SCR and/or oxidation

catalyst to come to their required operating temperature where a practical level of

emissions reductions can be achieved. As a result, the use of SCR and oxidation catalyst

is not considered technically feasible and is not considered further by this analysis.

NOx adsorber technology is classified by the USEPA as an emerging control technology.

EPA has classified this technology as emerging because fuel sulfur is converted to stable

sulfates, which compete with NOx for storage sites and poison the catalyst.75 As a result,

NOx adsorber technology is considered to be an undemonstrated technology and is not

considered further by this analysis.

5.4.1.3 Step 3: Establish Diesel Engine NOx and VOC LAER

For any of the emergency diesel engines (i.e., electric generating or firewater pump), the

top-ranked control option for NOx and VOC emissions comprises use of combustion

control techniques. For the proposed emergency generator diesel engines, the most

stringent level of control achieved in practice is the Tier 2 emission standard for non-

road, compression-ignition engines, as codified at 40 CFR § 89.112. This level of control

will result in total NOx + VOC emissions of 10.2 tons per year from all four engines with

each engine operating 100 hours per year. For the proposed firewater pump diesel

engines, the most stringent level of control achieved in practice is the emission standard

for stationary fire pump engines required by 40 CFR Part 60, subpart IIII, Table 4. This

75 IBID. Pages 48 & 49.



5-109

level of control will result in less than 0.7 tons per year total NOx + VOC emissions from

all three engines with each engine operating 100 hours per year.

As LAER for the proposed emergency diesel engines, the following limits are proposed

for NOx + VOC:

Emergency Generators: 4.6 g/hp-hr

Emergency Firewater Pumps: 3.0 g/hp-hr

Compliance with these limits will be based on the purchase of certified engines and

following the manufacturer’s operation/maintenance procedures.

As shown in Table 5-20, there are three permit precedents for emergency generators with

NOx + VOC emissions limits more stringent than the proposed limits of 4.6 g/hp-hr.

These precedents are for two projects located in South Carolina (SC0114 & SC-0115),

with permitted NOx + VOC emissions limits of 3.8 g/hp-hr and the Hickory Run Energy

Station in Pennsylvania. The basis (e.g., BACT analysis) for the lower emission limits is

not presented in the preliminary determination documents for the South Carolina

projects.76 It is not known if the limits have been demonstrated because the permits do

not require compliance testing.77 As a result, these two precedents are eliminated from

consideration. The Hickory Run Energy Station is under construction so this limit has

not yet been achieved in practice. Based on a review of the RBLC precedents, the

proposed NOx + VOC emissions limit of 4.7 g/hp-hr represents the most stringent

emission limitation for an emergency generator engine that has been achieved in practice.

As shown in Table 5-20, the most stringent NOx + VOC emissions limit for an

emergency firewater pump that was identified was 2.7 g/hp-hr for the Moxie Liberty

76 South Carolina Department of Health and Environmental Control Preliminary Determination for Grant

Allendale Inc.; Permit Number 0160-0020-CB; August 14, 2008, and South Carolina Department of

Health and Environmental Control Preliminary Determination for Grant Clarendon, LP; Permit Number

0680-0046-CB; January 2, 2009. 77 South Carolina Department of Health and Environmental Control; Grant Allendale LP; Permit Number

0160-0020-CB; November 25, 2008 and South Carolina Department of Health and Environmental

Control Grant Clarendon, LP; Permit Number 0680-0046-CB ; February 10, 2009.



5-110

Project. This project is under construction so this limit has not yet been achieved in

practice. The next most stringent limit identified is 3.0 g/hp-hr. As a result, based on a

review of the RBLC precedents, the proposed NOx + VOC emissions limit of 3.0 g/hp-hr

represents the most stringent emission limitation for an emergency firewater pump engine

that has been achieved in practice.

The proposed emission limits for the emergency use diesel engines (i.e., generator and

firewater pump) must meet two criteria to be considered LAER. To determine if the first

criterion was met, a review of states most likely to have the most stringent emission

limits contained in the state implementation plan was conducted. The results from the

review are summarized in Table 5-22. As shown, the first criterion is met because the

proposed emission limit meets the requirement of LAER that the most stringent emission

limitation that is contained in the implementation plan of a state be met. The second

criterion is addressed by the proposing the most stringent emission limit achieved in

practice identified in the RBLC. As previously noted, the proposed emergency engines

are subject to the requirements of NSPS subpart IIII. The proposed limits are as stringent

as the standards in this NSPS subpart. In accordance with 25 Pa. Code §127.205(7), the

proposed NOx+VOC LAER limit is equivalent to and satisfies the PaBAT requirements

of 25 Pa. Code §127.12(a)(5).

5.4.2 Diesel Engine PM/PM10/PM2.5 BACT/LAER Analyses

Emissions of particulate from diesel engines result from the inert solids contained in the

combustion air and unburned fuel hydrocarbons resulting from incomplete combustion,

which agglomerate to form particles and condensable organic and inorganic compounds

(e.g., sulfuric acid mist). The proposed project is located in an area that is classified as

nonattainment with regards to the annual PM2.5 standard. As a result, a LAER analysis is

required for all of the project’s sources of PM2.5. For PM and PM10 the analysis is

presented in accordance with the five-step BACT methodology. Because the first two

steps in both the LAER and BACT methodologies are the same (i.e., 1) identify

potentially applicable controls and 2) eliminate technically infeasible controls), a

combined analysis is presented for those steps.



5-111

Table 5-22. Regulatory Agencies with NOx and VOC Guidelines/Requirements for Emergency Stationary Diesel Engines

Regulatory

Agency

Description Emission Limit Comment Reference

South Coast Air

Quality

Management

District

Stationary Diesel-Fueled Internal

Combustion and Other

Compression Ignition Engines;

also Direct Drive Fir Pump

Engines >750 HP

4.8 g/bhp-hr

Tables 2 and 3 Rule 1470. Requirements for


Combustion & Other Compression

Ignition Engines (Amended May 4,

2012)

Bay Area Air

Quality

Management

District

IC Engine, Compression Ignition:

Stationary Emergency, non-

Agricultural, non-direct drive fire

pump ≥ 50 BHP

KW> 560 (HP >

750) 4.8 g/bhp-hr

Any engine certified

or verified to

achieve the

applicable standard.

Best Available Control Technology

(BACT) Guideline (12/22/2010)

San Joaquin Valley

Air Pollution

Control District

Emergency Diesel I.C. Engine

Driving a Fire Pump

NOx – 6.9 g/bhp-hr

VOC- no limit

Achieved in Practice

or contained in the

SIP


(BACT) Guideline 3.1.4 Last Update:

6/30/2001

Emergency Diesel IC Engine NOx/VOC - latest

EPA Tier

Certification level


or contained in the

SIP


(BACT) Guideline 3.1.1 Last Update:

7/10/2009

New Jersey

Department of

Environment

Protection

Reciprocating Internal

Combustion Engines

SOTA for an emergency generator

application meeting the definition found at

N.J.A.C. 7:27-19.1, "emergency generator,"

is no auxiliary air pollution control.

State of the Art Manual for

Reciprocating Internal Combustion

Engines 2003



5-112

Approximately 77% of the filterable PM emitted from a diesel engine is expected to be

less than 2.5 micrometers in diameter and approximately 97% of the filterable PM10 is

PM2.5. 78 Most of the condensable particulate that is emitted is a result of the sulfur

contained in the fuel and its oxidation to form sulfur dioxide (SO2) and SO3. The SO3

that is formed combines with moisture in the exhaust gas to form sulfuric acid mist,

which is collected as condensable particulate. Because the emergency diesel engines will

use Tier 2 diesel fuel containing less than 15 ppmw sulfur, the amount of condensable

emissions resulting from the emergency diesel-fired engines is expected to be small (i.e.,

<0.00024 lb/MMBtu or <1.4% of the total PM).

BACT permit limits must be at least as stringent as an applicable NSPS limits. Based on

the 40 CFR Part 60, subpart IIII emission standards, the minimum standard that would

meet BACT requirements for PM emissions from the proposed emergency diesel engines

(i.e., generator and firewater pump) is a limit of 0.20 g/kw-hr (0.15 g/hp-hr).

5.4.2.1 Step 1: Identify Diesel Engine PM/PM10/PM2.5 Controls



emergency firewater engines, respectively. It should be noted that only one precedent

was identified for PM2.5. There are few PM2.5 precedents due in part to EPA’s surrogate

approach (which used PM10 as a surrogate for PM2.5), which was in place until April

2011. As shown, for both engine categories, combustion controls (good combustion

practices and good engineering design, tune-ups, turbocharging/after cooling, and

compliance with NSPS Part 60, subpart IIII) and utilization of low sulfur fuels are used to

meet BACT/LAER requirements. The USEPA ACT document for stationary diesel

engines identifies the following control technologies

78 EPA AP-42, Table 3.4-2.



5-113

Table 5-23. RBLC Summary of PM BACT Precedents for Emergency Generator Diesel Engines

RBLC

ID No.

Facility Name Permit

Date

Process

Description

Capacity

(hp)

Control

Description

Total

PM2.5

(g/hp-hr)

Filterable

PM10

(g/hp-hr)

Total

Filterable

PM

(g/hp-hr)


& Cogeneration Plant 9/23/11 Emergency

Equipment 2666 (Basis:

2000 KW) NSPS 40 CFR 60, subpart

IIII 0.15

(Basis: 0.2 g/kw-

hr)

LA-0254 Ninemile Point

Electric Generating

Plant 8/16/11 Emergency

Generator 1250 Ultra Low Sulfur Diesel &

Good Combustion

Practices 0.15 0.15

FL-0322 Sweet Sorghum-to-

Ethanol Advanced

Biorefinery 12/23/10 Emergency

Generators 2682 NSPS 40 CFR 60, subpart

IIII 0.15

(Basis: 0.2 g/kw-

hr)

MI-0389 Karn Weadock

Generating Complex 12/29/09 Emergency

Generators

2666

(Basis: 2000

KW)

Engine Design &

Operation 15 ppm sulfur

fuel

0.25

(Basis: 0.2 g/kw-

hr)

NV-0050 MGM Mirage

Units CC009 - CC015 11/30/09

Caterpillar

Diesel

Generator,

M/N: 3516C,

2,500 kW

3622

Turbocharger & Good

Combustion Practices 0.045

(Basis: 0.0001

lb/hr)

NV-0050 MGM Mirage

Units LX024 &

LX025 11/30/09

Caterpillar

Diesel

Generator,

M/N: 3512C,

1,500 kW

2206 Turbocharger & Good

Combustion Practices 0.08 3

(Basis: 0.38 lb/hr)


Gasification Facility 6/22/09 Emergency

Power

Generator 1341 Comply With 40 CFR 60

subpart IIII 0.02

(Basis: 0.06 lb/hr)

SC-0114 GP Allendale LP 11/25/08 Emergency

Generator 1400

0.065 2

(Basis:0.2 lb/hr)

SC-0115 GP Clarendon LP 2/10/09 Emergency

Generator 1400

Tune-Ups & Inspections

will be performed as

outlined in the Good

Management Practice

Plan.

0.065 1

(Basis: 0.2 lb/hr)

OK-0129 Chouteau Power Plant 1/23/09 Emergency

Generator 2200 0.15

(Basis: 0.2 g/kw-

hr) OH-0317 Ohio River Clean 11/20/08 Emergency 2922 Good Combustion 0.15



5-114

RBLC

ID No.

Facility Name Permit

Date

Process

Description

Capacity

(hp)

Control

Description

Total

PM2.5

(g/hp-hr)

Filterable

PM10

(g/hp-hr)

Total

Filterable

PM

(g/hp-hr) Fuels, LLC Generator Practice & Good Engine

Design (Basis: 0.2 g/kw-

hr)


Rolling Mill 9/8/08 Emergency

Generator 1200 0.32

(Basis: 0.84 lb/hr)

NY-0101 Cornell Combined

Heat & Power Project 3/12/08 Emergency

Generator

1333

(Basis: 1000

KW)

Ultra Low Sulfur Diesel

@ 15 Ppm Sulfur 0.06

(Basis: 0.19 lb/hr)


Combustion

Engines 1350 Turbocharger &

Aftercooler 0.08


Import Terminal 8/15/07 Emergency

Generator 2168

Good Combustion

Practices, Good Engine

Design, & Use of Low

Sulfur & Low Ash Diesel

0.14

(Basis: 0.69 lb/hr)

IA-0088 ADM Corn

Processing - Cedar

Rapids 6/29/07 Emergency

Generator 2000 (Basis:

1500 KW)

Engine is required to meet

limits established as

BACT (Tier 2 Nonroad). 0.15

MN-0071 Fairbault Energy Park 6/5/07 Emergency

Generator 2333 (Basis:

1750 KW) 0.18

PA-0278

Moxie Liberty


Emergency

Generator .02 .02

PA-0286

Moxie Energy LLC/

Patriot Generation

Plant

01/31/13 Emergency

Generator .02 .02


Station 04/23/13

Emergency

Generator 1135

0.13

1 - RBLC incorrectly shows as Total PM10 as 0.25 lbs/hr instead of 0.20 lb/hr (0.065 g/bhp-hr). See PSD Construction Permit 0680-0046-CB.

2 - RBLC incorrectly shows as Total PM10 as 0.25 lbs/hr instead of 0.20 lb/hr (0.065 g/bhp-hr). See PSD Construction Permit 0160-0020-CB.

3 - Clark County Department of Air Quality and Environmental Management, Part 70 Operating Permit, Source 825, December 30, 2010 page 59.



5-115

Table 5-24. RBLC Summary of PM BACT Precedent for Emergency Firewater Diesel Engines

RBLC


Permit

Date

Process

Description

Capacity

(Hp) Control Description

Total PM2.5

Limit

(g/hp-hr)

Filterable

PM10 Limit

(g/hp-hr)

Total

Filterable

PM Limit

(g/hp-hr)


Gasification Facility 06/22/09

Firewater Diesel

Pumps (3) 575

Comply with 40 CFR 60

subpart IIII

0.06

calculated


Terminal 11/24/04

Firewater Booster

Pump Diesel

Engines (2)

300 Good Engine Design & Proper

Operating Practices 0.09

IA-0088 ADM Corn Processing

- Cedar Rapids 06/29/07 Fire Pump 540

Engine must meet established

BACT limits (Tier 3 Nonroad). 0.15 0.15

IA-0095

Tate & Lyle

Ingredients Americas,

Inc.


calculated

0.15

calculated


Generating Complex 12/29/09 Fire Pump 525

Engine Design & Operation.

15 ppm Sulfur Fuel. 0.15



Firewater Pump

Diesel Engine 525

Good Combustion Practices,

Good Engine Design, & Use of

Low Sulfur & Low Ash Diesel)

0.24

calculated

SC-0114 GP Allendale LP 11/25/08 Firewater Diesel

Pump 525

Tune-Ups & Inspections will

be performed as outlined in the

Good Management Practice

Plan.

0.35

calculated

0.35

calculated



Firewater Pump

Diesel Engine 660

Good Combustion Practices,

Good Engine Design, & Use of

Low Sulfur & Low Ash Diesel)

0.44

calculated


Terminal 11/24/04

Firewater Pump

Diesel Engines 1-3 660

Good Engine Design, Proper

Operating Practices, & Use of

Low Sulfur Diesel

0.85

calculated



Fire Pump

0.09 0.09

PA-0286

Moxie Energy LLC/

Patriot Generation

Plant

01/31/13

Fire Pump Engine -

460 BHP

0.09 0.09



5-116

RBLC


Permit

Date

Process

Description

Capacity

(Hp) Control Description

Total PM2.5

Limit

(g/hp-hr)

Filterable

PM10 Limit

(g/hp-hr)

Total

Filterable

PM Limit

(g/hp-hr)


Station 04/23/13

Emergency

Firewater Pump

(450 BHP) 450 0.06



5-117

and techniques for PM emissions: combustion controls discussed for NOx and VOC

control and the use of catalytic diesel particulate filters (CDPF). It should be noted that

each of these controls focuses on the control of filterable PM. As discussed above, use of

low sulfur fuel is identified as the control method for the condensable PM fraction.

5.4.2.2 Step 2: Eliminate Technically Infeasible Controls

CDPF is generally designed around a substrate that captures PM from the diesel engine

exhaust in the catalyst-coated substrates cell walls. As the diesel exhaust gas passes

through the substrate, PM is collected and stored. The collected PM is then oxidized

through the use of a catalyst coating on the substrate. Although CDPF is technically

feasible for engines that operate under normal conditions, it is not considered to be

technically feasible for engines in emergency service. The proposed project’s engines

will be operated infrequently and for short periods of time (less than one hour/week) for

maintenance and testing. The short amount of time that the engine will be operating (i.e.,

less than an hour at a time) will not allow the CDPF oxidation catalyst to come to its

required operating temperature and successfully oxidize any particulate that is collected.

As a result, the use of CDPF is not considered feasible for the proposed engines and is

not considered further by this analysis.

5.4.2.3 Step 3: Establish Diesel Engine PM2.5 LAER

For any of the emergency diesel engines (i.e., electric generator or firewater pump), the

top-ranked control option for PM emissions comprises the use of combustion control

techniques. For the proposed emergency generator diesel engines, the most stringent

level of control achieved in practice is the Tier 2 emission standard for non-road,

compression-ignition engines, as codified at 40 CFR § 89.112.79 This level of control

will result in 0.04 tons per year of total filterable PM emissions from all four engines

with each engine operating no more than 100 hours per year in non-emergency mode,

79 The Hickory Run Energy Project is under construction. As a result, this limit is not yet considered

achieved in practice.



5-118

including the 50 hours per year allowed for maintenance and testing. For the proposed

firewater pump diesel engines, the most stringent level of control achieved in practice is

the emission standard for stationary fire pump engines, required by 40 CFR Part 60,

subpart IIII Table 4.80 This level of control will result in 0.035 tons per year a of total

filterable PM emissions from all three engines with each engine operating no more than

100 hours per year in non-emergency mode, including the 50 hours per year allowed for

maintenance and testing. The most stringent level of control identified for the control of

condensable PM is the use of diesel fuel containing less than 15 ppm sulfur.

As LAER for the proposed emergency diesel engines, the following limits are proposed

for PM2.5:



For all emergency engines diesel fuel with less than 15 ppmw sulfur shall be used

Compliance with these limits will be based on the purchase of certified engines, low

sulfur diesel fuel and following the manufacturer’s operation/maintenance procedures.

The proposed emission limits for the emergency use diesel engines must meet two

criteria to be considered LAER. To determine if the first criterion was met, a review of

states most likely to have the most stringent emission limits contained in the state

implementation plan was conducted. The results from this review are summarized in

Table 5-25. As shown, the proposed emission limit meets the first requirement of LAER

that the proposed limit be as stringent as any emission limitation that is contained in the

implementation plan of a state. The second criterion has been addressed by proposing the

most stringent emission limit achieved in practice identified in the RBLC. As previously

note, the proposed emergency engines are subject to the NSPS Part 60, subpart IIII PM

80 IBID.



5-119

Table 5-25. Regulatory Agencies with PM Guidelines/Requirements for Emergency Stationary Diesel Engines

Regulatory

Agency


South Coast Air

Quality

Management

District


Combustion and Other

Compression Ignition Engines

>750 HP

0.075 g/bhp-hr

0.02 g/bhp-hr

Table 1:

1/1/13 – 6/30/15

After 6/31/15

Rule 1470. Requirements for


Combustion & Other Compression

Ignition Engines 1

(Amended May 4, 2012)

New Stationary Emergency

Standby Diesel Fueled Direct-

Drive Fire Pump Engines > 750

HP

0.15 g/bhp-hr Table 3

Bay Area Air

Quality

Management

District

IC Engine- Compression Ignition:

Stationary Emergency, non-

Agricultural, non-direct drive fire

pump ≥ 50 BHP Output

0.15 g/bhp-hr Any engine certified or

verified to achieve the

applicable standard.



San Joaquin Valley

Air Pollution

Control District

Emergency Diesel I.C. Engine

Driving a Fire Pump

0.1 g/bhp-hr (if TBACT

triggered) (corrected 7/16/01)

0.4 g/bhp-hr (if TBACT not

triggered)

Achieved in Practice or



(BACT) Guideline 3.1.4

Last Update: 6/30/2001

Emergency Diesel IC Engine 0.15 g/hp-hr or Latest EPA

Tier Certification level for

applicable hp range,

whichever is more stringent.

Achieved in Practice or





New Jersey

Department of

Environment

Protection

Emergency Reciprocating

Internal Combustion Engines

SOTA for an emergency generator application meeting

the definition found at N.J.A.C. 7:27-19.1, "emergency

generator," is no auxiliary air pollution control.

State of the Art Manual for

Reciprocating Internal Combustion

Engines 2003

1. Also limits hours of operation: “New stationary emergency standby diesel-fueled engines (>50 bhp) shall not operate more than 50 hours per year for

maintenance and testing,” excluding new direct-drive emergency standby fire pump engines. Stationary emergency standby direct-drive fire pump

engines shall not operate more than the number of hours necessary to comply with the maintenance and testing requirements of the 2002 edition or the

most current edition of the National Fire Protection Association (NFPA) 25 – “Standard for the Inspection, Testing, and Maintenance of Water-Based

Fire Protection Systems.”



5-120

standard. No applicable PM2.5 standard has been promulgated for the emergency engines

under 40 CFR Parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the

proposed PM2.5LAER limit is equivalent to and satisfies the PaBAT requirements of 25

Pa. Code §127.12(a)(5).

5.4.2.4 Step 3: Ranking of Technically Feasible PM/PM10 BACT Control Technologies

For all of the identified emergency diesel engines (i.e., electric generator or firewater

pump), the top-ranked feasible and applicable control option for PM emissions was based

on the use of combustion control techniques. As previously noted, for the proposed

emergency generator and firewater pump diesel engines, the most stringent level of PM2.5

control achieved is 0.15 g/hp-hr.

Based on the RBLC reviews that are summarized in Table 5-23 and Table 5-24, there are

some permits that have more stringent emission limits for PM and PM10. There is a PM

limit of 0.02 g/hp-hr for the Lake Charles Gasification Project’s (LA-0231) emergency

generator. The permit for this project, issued on June 22, 2009, states the following in the

control description “Comply with 40 CFR 60 subpart IIII.” The BACT analysis basis is

stated as “good engineering design and combustion practices, and burning low sulfur

diesel fuel as BACT for all pollutants.”81 As a result, the stated basis for the Lake Charles

project’s limit is application of the same control technologies as proposed for the Shell

Project’s proposed generator engines. However, although permitted in 2009, the Lake

Charles Gasification Project has not yet begun operation.82 As a result, the PM limit in

the Lake Charles project permit is not demonstrated as achieved in practice and is not

considered further by this analysis.

81 Lake Charles Cogeneration LLC Title V Permit Application and Prevention of Significant Deterioration

Study, September 2008. Page 3-11. 82 http://finance.yahoo.com/news/investor-contracts-show-lake-charles-plant-moving-104347721--

finance.html



5-121

An additional evaluation was performed of the PM10 precedents presented in Table 5-23

with limits between 0.045 and 0.14 g/hp-hr. The results from this evaluation are

presented in Table 5-26. As shown below, the MGM and GP Allendale precedents were

removed from consideration because there is no add-on control that can be applied to the

selected engines that can achieve the emissions limits associated with these precedents.

Table 5-26. Basis for Removing PM Precedents from Consideration

Facility

Name

Filterable

PM10 Limit

(g/hp-hr)

Additional

Investigation

Conclusion

MGM Mirage

Units CC009 -

CC015

0.045

(Basis: 0.0001

lb/hr)

Engines included in

construction permit issued

in 2009 but not included in

2010 Title V operating

permit. Engines were never

installed

No demonstration that

the limit was achieve in

practice has occurred

MGM Mirage

Units LX024 &

LX025

0.08

(Basis: 0.38

lb/hr)

Permit does not require

compliance testing of the

engines




GP Allendale

LP

SC-0114

0.065

(Basis: 0.2 lb/hr)



engines




GP Clarendon

LP

SC-0115

0.065

(Basis: 0.2 lb/hr)



engines




In accordance with the top-down BACT methodology the following more stringent

precedents must be considered further before proposing a less stringent limit:

NY-0101: 0.06 g/hp-hr

NV-0047: 0.08 g/hp-hr

LA-0219: 0.14 g/hp-hr

As shown in Table 5-24, the two more stringent emergency firewater pump limits are

0.06 g/hp-hr and 0.09 g/hp-hr for the Lake Charles Gasification and Sabine Pass LNG

Terminal Projects, respectively. The Lake Charles Gasification Project has not finished



5-122

construction so these engines have not begun operation.83 As a result, demonstration that

this PM10 limit has been achieved in practice has not occurred and this precedent is not

considered further by this analysis. The Sabine Pass LNG Terminal precedent of

0.09 g/hp-hr has been achieved in practice, so in accordance with the BACT

methodology this precedent must be evaluated based on energy, environmental, or

economic impacts before proposing the less stringent limit.

5.4.2.5 Step 4: Evaluate PM/PM10 Control Options

As previously noted, the proposed emergency diesel generator engines will achieve the

most stringent level of control required by the Tier 2 emission standards for non-road,

compression-ignition engines, as codified at 40 CFR § 89.112 for this type of engine and

the proposed firewater pump engines will achieve the most stringent emission standards

for stationary fire pump engines, required by 40 CFR Part 60, subpart IIII Table 4 for this

type of engine. As a result, the only way to achieve the more stringent emissions rates

identified by RBLC review would be through the use of the previously eliminated (based

on technical feasibility when applied to emergency engines) CDPF technology.

However, if to be conservative the use of CDPF is considered further by this analysis, the

following would be the result. Economic analyses prepared by U.S. EPA indicate that,

for emergency use engines of the size proposed, the cost effectiveness of CDPF is

approximately $1 million per ton of PM reduction.84 The use of CDPF could achieve a

PM emission rate less than 0.01 and 0.001 tons per year from the proposed generator and

firewater engines, respectively. Based on this extremely high cost in relation to the very

small quantity of PM removed, the use of CDPF is rejected as BACT. It should also be

83 http://finance.yahoo.com/news/investor-contracts-show-lake-charles-plant-moving-104347721--

finance.html 84 Alternative Control Techniques Document: Stationary Diesel Engines. EPA Contract No. EP-D-07-019;

March 2010 Final Report. Table 5-3. Adjusted for 100 hours per year operation by multiplying by a

factor of 10 the cost effectiveness value for 1,000 hours per year operation ($99,724) for control of a

Tier 2 emission rate engine.



5-123

noted that the use of CDPF has an adverse energy impact. The pressure drop across the

catalyst bed results in a loss in the engine’s efficiency.

5.4.2.6 Step 5: Propose Diesel Engine PM/PM10 BACT Limit

The proposed diesel-fired, compression-ignition internal combustion engine will be

certified by the equipment manufacturer to meet the Tier 2 emission standards for

nonroad, compression-ignition engines, as codified at 40 CFR § 89.112 (generator

engines) and the 40 CFR § 60 subpart IIII Table 4 (firewater pump engines). Due to the

very low emissions from these engines, the fact that the engine will operate only

intermittently, the availability of engines that are certified to achieve this emission level

and considering the nature of the certification test procedure for the nonroad engine

emission standards, the following PM/PM10 BACT limits are proposed:



Compliance with these limits will be based on the purchase of certified engines and fuel,

and following the manufacturer’s operation/maintenance procedures.

The proposed PM BACT is as stringent as the applicable NSPS Part 60, subpatrt IIII and

no applicable PM10 standard has been promulgated for the emergency engines under 40

CFR parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed

PM/PM10 BACT limit is equivalent to and satisfies the PaBAT requirements of 25 Pa.

Code §127.12(a)(5).

5.4.3 Diesel Engine Carbon Monoxide BACT Analysis

Carbon monoxide (CO) is a product of incomplete combustion. The formation of this

pollutant is limited by ensuring complete and efficient combustion of the fuel in the

engine. High combustion temperatures, adequate excess air and good air/fuel mixing

during combustion minimize CO emissions. Measures taken to minimize the formation

of NOx during combustion may inhibit complete combustion, which could increase CO



5-124

emissions. For CO, the analysis is presented in accordance with the five-step BACT

methodology.

BACT permit limits must be at least as stringent as applicable NSPS limits. Based on

NSPS subpart IIII, the minimum standards that would meet BACT requirements for CO

emissions from the proposed emergency diesel engines (i.e., both for the generators and

firewater pumps) is a limit of 3.5 g/kw-hr (2.6 g/hp-hr).

5.4.3.1 Step 1: Identify Diesel Engine CO Controls



emergency firewater engines, respectively. As shown, combustion controls (good

combustion practices, tune-ups, turbocharging/after cooling, and compliance with

Subpart IIII) are used to meet BACT requirements. In summary, the identified control

technologies and techniques for CO emissions are the same as those identified for VOC

and the use of oxidation catalyst.

5.4.3.2 Step 2: Eliminate Technically Infeasible

Although oxidation catalyst has been applied and is considered to be technically feasible

for engines that operate continuously, it is not considered to be technically feasible for

engines in emergency service. To ensure that each engine is in good working order, the

proposed engines will be operated infrequently and for short periods of time (less than

one hour/week). The short duration of the proposed engine’s operation does not provide

adequate time for the oxidation catalyst to reach the required operating temperature

where a practical level of emissions reductions can be achieved. This conclusion is

consistent with the findings in the RBLC database review summarized in Table 5-27 and

Table 5-28. As a result, the use of oxidation catalyst is not considered feasible for the

Project’s emergency engines. However, for purposes of completeness, the impacts

associated with the potential use of oxidation catalyst are considered below. The decision



5-125

Table 5-27. RBLC Summary of CO BACT Precedents for Emergency Diesel Engines

RBLC


Permit


Capacity


CO Limit

(g/hp-hr)


& Cogeneration Plant 9/23/11 Emergency Equipment

2666

(Basis:

2000 KW)

NSPS 40 CFR 60, Subpart IIII 2.6

(Basis: 3.5 g/kw-hr)

LA-0254

Nine Mile Point

Electric Generating

Plant


Generators 1250

Ultra Low Sulfur Diesel and Good

Combustion Practices 2.6

FL-0322

Sweet Sorghum-to-

Ethanol Advanced

Biorefinery

12/23/10 Emergency Generators 2682 NSPS 40 CFR 60, Subpart IIII 2.6



Generating Complex 12/29/09 Emergency Generator

2666

(Basis:

2000 KW)

Engine Design & Operation 15 ppm

sulfur fuel

2.6


NV-0050 MGM Mirage

Units CC009 - CC015 11/30/09

Caterpillar Diesel

Generator, M/N:

3516C, 2,500 kW 3622

Turbocharger & Good Combustion

Practices

0.8

(Other Case-by-Case)

NV-0050 MGM Mirage

Units LX024 & LX025 11/30/09

Caterpillar Diesel

Generator, M/N:

3512C, 1,500 kW 2206

Turbocharger & Good Combustion

Practices

0.8

(Other Case-by-Case)



Emergency Diesel

Power Generator

Engines

1341 Comply with 40 CFR 60, Subpart

IIII

0.2

(Basis: 0.62 lb/hr)

SC-0114 GP Allendale LP 11/25/08 Diesel Emergency

Generator 1400

1.0

SC-0115 GP Clarendon LP 2/10/09 Diesel Emergency

Generator 1400

Tune-Ups & Inspections will be

performed as outlined in Good

Management Practice Plan.

1.0

OK-0129 Chouteau Power Plant 1/23/09 Emergency Diesel

Generator (2200 Hp) 2200

2.6


OH-0317 Ohio River Clean

Fuels, LLC 11/20/08 Emergency Generator 2922

Good Combustion Practices &

Good Engine Design 2.6




5-126

RBLC


Permit


Capacity


CO Limit

(g/hp-hr)


Rolling Mill 9/8/08 Emergency Generator 1200

0.32

(Basis: 0.84 lb/hr)


Combustion Engines 1350 Turbocharger & Aftercooler

0.2

(Other Case by Case)



Diesel Emergency

Generator 2168

Good Combustion Practices &

Good Engine Design and use of low

sulfur and low ash fuel

2.6

IA-0088 ADM Corn Processing

- Cedar Rapids 6/29/07 Emergency Generator

2000

(Basis:

1500 KW)

Engine is required to meet limits

established as BACT (Tier 2

Nonroad)

2.6

MN-

0071 Fairbault Energy Park 6/5/07 Emergency Generator

2333

(Basis:

1750 KW)

2.5


LLC/Asylum Power 10/10/12 Emergency Generator

1333

(Basis:

1000ekW

Operate and maintain to achieve the

emission standard over the entire

life of the engine. Limit 100

hours/yr operation.

0.13

PA-0286

Moxie Energy LLC/

Patriot Generation

Plant

01/31/13 Emergency Generator

1333

(Basis:

1000ekW)


emission standard over the entire

life of the engine. Limit 100

hours/yr operation.

0.13


Station 04/23/13 Emergency Generator 1135 bhp Good Combustion Practice

2.32

(based on 5.79 lb/hr)



5-127

Table 5-28. RBLC Summary of CO BACT Precedent for Firewater Emergency Diesel Engines

RBLC


Permit

Date

Process

Description

Capacity


CO Limit

(g/hp-hr)



Firewater Pump

Diesel Engine 660

Good Combustion Practices & Good

Engine Design Incorporating Fuel

Injection Timing Retardation (ITR)

0.21

calculated


Terminal 11/24/04

Firewater Booster

Pump Diesel

Engines (2)

300 Good Engine Design & Proper Operating

Practices 0.27



Firewater Diesel

Pumps (3) 575 Comply With 40 CFR 60 subpart IIII

0.29

calculated

MI-0402 Sumpter Power Plant 11/17/11

Diesel Fuel-Fired

Combustion Engine

(RICE)

732 Good Combustion Practices 0.31


Terminal 11/24/24

Firewater Pump

Diesel Engines 1-3 660

Good Engine Design & Proper Operating

Practices

0.38 1

calculated

SC-0114 GP Allendale LP 11/25/08 Firewater Diesel

Pump 525

Tune-Ups & Inspections will be

performed as outlined in the Good

Management Practice Plan.

1.1 calculated



Firewater Pump

Diesel Engine 525

Good Combustion Practices & Good

Engine Design Incorporating Fuel

Injection Timing Retardation (ITR)

1.38 calculated

IA-0088

ADM Corn

Processing - Cedar

Rapids

6/29/07 Fire Pump 540 Engine is required to meet limits

established as BACT (Tier 3 Nonroad). 2.6



5-128

RBLC


Permit

Date

Process

Description

Capacity


CO Limit

(g/hp-hr)

IA-0095

Tate & Lyle

Ingredients

Americas, Inc.


calculated


Generating Complex 12/29/09 Fire Pump 525

Engine Design & Operation. 15 ppm

Sulfur Fuel. 2.6

PA-0244 First Quality Tissue

LLC 10/20/04 Fire Pump 575 3.04 calculated

OH-

0254

Duke Energy

Washington County

LLC


Fire Pump Engine 400 Low Sulfur Fuel, Combustion Control

3.13 2

calculated



Fire Pump

460 bhp


emission standard over the entire life of

the engine. Limit 100 hours/yr

operation.

0.5

PA-0286

Moxie Energy LLC/

Patriot Generation

Plant

01/31/13

Fire Pump Engine -

460 BHP

460 bhp


emission standard over the entire life of

the engine. Limit 100 hours/yr

operation.

0.5


Station 04/23/13

Emergency

Firewater Pump

(450 BHP)

1135 bhp Good Combustion Practice

1.03

(based on 2.58 lb/hr

limit)

1. RBLC had 0.0008 g/bhp. This should have been labeled as lb/bhp, which converts to 0.38 g/bhp.

2. RBLC had 1 g/bhp. 2.76 pound per hour and 400 Hp converts to 3.13 g/bhp.



5-129

to include potential consideration of oxidation catalyst results from a review of SIP

provisions which indicate that, as shown in Table 5-29, oxidation catalyst is required

without the need for an emission limit in the San Joaquin AQMD rules.

5.4.3.3 Step 3: Ranking of Technically Feasible CO Control Technologies

Because oxidation catalyst is an add-on control, it can theoretically be coupled with

combustion controls to achieve a more stringent level of emission control. As a result,

the analysis below considers the use of combustion controls both with and without

oxidation catalyst.

As shown in Table 5-26, several of the CO precedents for emergency diesel generators

were removed from consideration because the limits in these permits have not been

demonstrated in practice. The most stringent remaining emergency generator precedents

are for the following projects:

OK-0128: 0.32 g/hp-hr

NV-0047: 0.2 g/hp-hr

MN-0071: 2.5 g/hp-hr

The most stringent emergency firewater pump limit presented in Table 5-28 is 0.21 g/hp-

hr (LA-0219) and the range of other more stringent limits is from 0.21 g/hp-hr 1.38 g/hp-

hr.

In accordance with the BACT methodology, the more stringent limits for both the

emergency generator and firewater engines must be evaluated further before proposing a

less stringent limit.

5.4.3.4 Step 4: Evaluate CO Control Options

Although the use of oxidation catalyst has been determined above to be technically

infeasible for the Project’s emergency engines, for the sake of argument, this technology

is considered further in this Step 4 analysis. The USEPA ACT document provides an



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Table 5-29. Regulatory Agencies with CO Guidelines/Requirements for Emergency Stationary Diesel Engines

Regulatory

Agency


South Coast Air

Quality Management

District


Combustion and Other Compression

Ignition Engines >750 HP


Rule 1470. Requirements for Stationary

Diesel-Fueled Internal Combustion &

Other Compression Ignition Engines 1

(Amended May 4, 2012)

New Stationary Emergency Standby

Diesel Fueled Direct-Drive Fire Pump

Engines > 750 HP


Bay Area Air

Quality Management

District

IC Engine- Compression Ignition:

Stationary Emergency, non-Agricultural,

non-direct drive fire pump ≥ 50 BHP

Output

2.6 g/bhp-hr Any engine certified

or verified to achieve

the applicable

standard.



San Joaquin Valley

Air Pollution Control

District

Emergency Diesel I.C. Engine Driving a

Fire Pump

Latest EPA Tier

Certification level

for applicable hp

range


or contained in the

SIP




Emergency Diesel IC Engine No limit (oxidation

catalyst considered

technically feasible)


or contained in the

SIP




New Jersey

Department of

Environment

Protection

Emergency Reciprocating Internal

Combustion Engines

SOTA for an emergency generator

application meeting the definition found at

N.J.A.C. 7:27-19.1, "emergency generator,"

is no auxiliary air pollution control.

State of the Art Manual for Reciprocating

Internal Combustion Engines 2003

1 - Also limits hours of operation: “New stationary emergency standby diesel-fueled engines (>50 bhp) shall not operate more than 50 hours per year for

maintenance and testing,” excluding new direct-drive emergency standby fire pump engines. Stationary emergency standby direct-drive fire pump engines

shall not operate more than the number of hours necessary to comply with the maintenance and testing requirements of the 2002 edition or the most current

edition of the National Fire Protection Association (NFPA) 25 – “Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection

Systems.”



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economic analysis for emergency engines of the size proposed by this Project. In the

ACT document, the cost effectiveness of oxidation catalyst designed to achieve a 90%

CO reduction is estimated at approximately $98,000 per ton of CO reduction. 85 A

similarly designed CO catalyst would result in a CO control level of 0.26 g/hp-hr, which

is very close to the limit for the most stringent of the identified precedents. Based on this

extremely high cost compared to the marginal (if any) reduction in CO, the use of

oxidation catalyst is rejected as BACT. It should also be noted that the use of oxidation

catalyst also has an adverse energy impact. The pressure drop across the catalyst bed

results in a loss in the engine’s efficiency. The more stringent precedents and their

associated limits identified above are therefore eliminated from consideration based on

the technical feasibility of applying oxidation catalyst to the Project’s emergency engines

and the high cost infeasibility of its application.

5.4.3.5 Step 5: Establish Diesel Engine CO BACT

The Project’s diesel-fired, compression ignition internal combustion engines (generator

and firewater pump) will be certified by the equipment manufacturer to meet the Tier 2

emission standards for nonroad, compression ignition engines (2.6 g/bhp-hr), as codified

at Subpart IIII of 40 CFR part 60 and 40 CFR § 89.112. Due to the very low annual

emissions from these sources, the fact that they will operate as non-emergency engines

only intermittently, the availability of engines that are certified to achieve this emission

level and considering the nature of the certification test procedure for the nonroad engine

emission standards, the following CO BACT limits are proposed:



Compliance with these limits will be based on the purchase of certified engines, and

following the manufacturer’s operation/maintenance procedures.

85 Ibid. Table 5-4. Adjusted for 100 hours per year operation by multiplying by 10 (1,000/100) the cost

effectiveness value for 1,000 hours per year operation ($9,837) for control of Tier 2 emission rate

engine.



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The proposed CO BACT limit is as stringent as the NSPS subpart CO standard. In

accordance with 25 Pa. Code §127.205(7), the proposed CO BACT limit is equivalent to

and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

5.4.4 Diesel Engine GHG BACT Analysis

GHGs emitted by the diesel engines are the same as emitted by other fossil fuel

combustion sources: CO2, CH4, and N2O, although the emission factors are different, due

to the combustion of a different fuel (diesel instead of natural gas) and a different type of

combustor (reciprocating engine versus a combustion turbine or furnace). As is the case

for all fossil fuel-fired sources, CO2 emissions are the dominant contributor to the CO2e

emission rate. No applicable GHG standards have been promulgated for emergency

engines under 40 CFR parts 60 and 61.

5.4.4.1 Steps 1-4: Identify Technically Feasible Controls

The available control techniques for control of GHGs from the diesel engines include:

Use of low GHG emitting fuels,

Energy efficiency,

Good combustion practices (meeting diesel engine NSPS requirements), and

Carbon capture and sequestration (CCS).

It is typical for emergency use diesel engines to be fired with diesel fuel rather than

natural gas, a lower GHG emitting fuel, as one of the emergencies that can happen at a

facility is the loss of natural gas supply. By storing diesel fuel at the site, the facility has

a backup fuel available for emergency use (electric power generation and firewater

pumping). As a result, requiring the use of natural gas would be considered redefining

the emissions unit, which is inconsistent with USEPA policy with respect to BACT

analyses.

Energy efficiency options for reducing GHG emissions outside of good combustion

practices are considered to be technically infeasible because emergency engines typically

only operate one hour a month for periodic maintenance and testing to ensure operability.



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As a result, the engines never reach steady state operation long enough for a heat

recovery system to warm up and operate.

Meeting the NSPS Part 60, Subpart IIII emission standards requires the use of good

combustion control, thereby minimizing the emissions of methane (CH4). As is the case

for CO and VOC emissions, oxidation catalyst is a potential control option for reducing

CH4 emissions. However, given the much lower emission rate for CH4 (0.026 g/hp-hr)

relative to CO (2.6 g/hp-hr), the use of oxidation catalyst would not be cost effective.86

The use of oxidation catalyst is rejected as BACT due to its adverse energy impacts, the

control system pressure drop, economic impacts and minimal environmental benefit.

While Section 5.6 discusses the potential applicability of CCS to the entire facility, it is

noted here that the application of CCS technology to emergency diesel engines would be

technically impractical. As is the case with a heat recovery system, the emergency diesel

engines do not operate long enough at steady state conditions to effectively capture CO2

emissions. As such, in addition to the analysis presented in Section 5.6, the use of CCS is

rejected as a BACT option for the control of CO2 for such engines.

5.4.4.2 Step 5: Propose Diesel Engine CO2e/GHG BACT Limits

The diesel-fired, compression ignition internal combustion engines will be certified by

the equipment manufacturer to meet the Tier 2 emission standards for nonroad,

compression ignition engines, as codified at Subpart IIII of 40 CFR part 60 and 40 CFR

§89.112. Due to the very low emissions from these sources, the fact that they will

operate only intermittently, the availability of engines that are certified to achieve this

emission level and considering the nature of the certification test procedure for the

nonroad engine emission standards, the following GHG BACT limits are proposed:

86 Application of oxidation catalyst to the control of CH4 in steady-state operations has demonstrated a

reduction of 50%. The level of reduction in an unsteady-state emergency engine application would

further reduce the level of control. In addition, as noted above, in EPA’s ACT document the cost

effectiveness of an oxidation catalyst designed to achieve a 90% CO reduction was estimated at

approximately $98,000 per ton of CO reduction.



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Emergency Generator Engines: Combined emissions of CO2e from the four

emergency generator engines shall not exceed 1,151.6 tons per year on a 12-

month rolling average basis.

Firewater Pump Engines: Combined emissions of CO2e from the three firewater

pump engines shall not exceed 120.3 tons per year on a 12-month rolling average

basis.

Compliance shall be demonstrated using the following factor: 1.15 lb CO2e/bhp-

hr.

As previously stated, no applicable GHG standards have been promulgated for

emergency engines under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code

§127.205(7), the proposed GHG BACT limit is equivalent to and satisfies the PaBAT


5.5 Equipment Leaks

The proposed project includes piping and a large number of connectors and valves, as

well as pumps, compressors and similar components for movement of gas and liquid raw

materials, intermediates and products. Each of these components are potential sources of

fugitive VOC and methane (CH4) emissions due to leakage from rotary shaft seals,

connection interfaces, valve stems and similar points.87

5.5.1 Equipment Leaks of VOC LAER Analysis

Control strategies for VOC emissions from component equipment leaks are based on

comprehensive work practices commonly known as leak detection and repair (LDAR)

programs. The baseline requirements for the LDAR program applicable to the proposed

ethylene cracking and polyethylene manufacturing facilities are set forth in 40 CFR

Part 60 subparts VV88 and VVa, 40 CFR Part 61 subparts J and V, and 40 CFR Part 63

subparts UU, YY, and FFFF. These programs include requirements for monitoring to

87 Control of hazardous air pollutants from equipment leaks is addressed by the appropriate 40 CFR

parts 61 and 63 subparts 88 Subpart VV is referenced by 40 CFR 60 subpart DDD; if desired VVa or 40 CFR 63 Subpart F

can be used as an alternate means of compliance with the LDAR requirements of the remainder of the

facility.



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detect leaks and attempting and completing repairs of leaking components in the

following categories:

Pumps in light liquid service;

Compressors;

Pressure relief devices in gas/vapor service;

Sampling connection systems;

Open-ended valves or lines;

Valves in gas/vapor service and in light liquid service;

Pumps, valves, connectors, and agitators in heavy liquid service;

Instrumentation systems;

Pressure relief devices in liquid service;

Closed-vent systems

5.5.1.1 Steps 1: Identify Equipment Leaks VOC Controls

Potential enhancements to the baseline LDAR program work practice requirements

include the following:

Lowering the monitoring exemption threshold from <10% VOC to <5% VOC.

Lower definition of a “leaking” component threshold concentration, as measured

at the potential leak interface. This has the effect of accelerating or broadening

the repair obligations for leaking components to include components that would

not require repair under the NESHAP/NSPS rules.

Increase leak monitoring frequencies, which has the effect of accelerating the

identification and repair of leaking components.

Disallowing reduced monitoring frequency for valves (skip periods)

As part of an effective LDAR program, equipment specifications and maintenance

practices are designed and implemented to reduce the occurrence of leaks. For certain

service applications, components with inherently leakless design features are available.

These components reduce VOC emissions, regardless of the quality or frequency of

LDAR activities. Some regulations and permits have specified the use of leakless

designs in applications where such use is practicable. These leakless designs include the

following:

Canned, magnetic drive or diaphragm pumps not having external seals;

Pumps with double mechanical seals and a barrier fluid;



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Magnetic-drive centrifugal pumps, with no direct coupling between the drive and

the pump casing, and consequently no rotating shaft seal (the pump is driven by

magnetic coupling of strong permanent magnets attached to the drive motor and

similar permanent magnets incorporated into the impeller of the pump);

Diaphragm valves;

Bellows valves with the bellows welded to both the bonnet and stem; and

Connectors welded around the complete circumference to prevent the joint from

being disassembled by unbolting or unscrewing the components.

Finally, in addition to enhanced work practice requirements, because leakless designs are

not available for all components and across all sizes, some facilities have been subjected

to enforceable limits on the number of leaking components.


All of the identified control options are technically feasible to some degree. However,

components with inherently leakless design features are not available for all services and

all sizes. The most effective of the identified control strategies is a combination of the

identified control options. Specifically, this includes an LDAR program with enhanced

work practices relative to the NESHAP prescribed minimum, combined with enforceable

limits on percent leaking components.

5.5.1.3 Step 3: Establish Equipment Leaks VOC LAER

The proposed LAER for VOC emissions from equipment leaks covers both the cracking

and polyethylene manufacturing facilities. In accordance with its definition, a proposed

LAER may not allow a source to emit a pollutant in excess of the amount allowable

under an applicable new source standard of performance. As a result, any proposal

covering both the cracking and polyethylene manufacturing facilities must include the

requirements of 40 CFR Part 60, subparts VVa, DDD (which refers to VV) and 40 CFR

Part 63 subparts UU, YY, and FFFF (which refers to UU). All of these can be

streamlined by requesting that the proposed equipment be controlled in accordance with

the requirements of NESHAP subpart UU (40 CFR §63.1019). As a result, site wide

compliance with NESHAP subpart UU is proposed except:

For purposes of compliance, all organic compounds (ethane, methane, VOC and

HAP) shall be considered as if they were organic HAP;



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Equipment containing or contacting fluids with < 5% total organic compounds

(including ethane and methane) is exempt from monitoring;

Monthly inspection of non-bellows seal valves shall be required unless

98.0 percent or greater of the non-bellows seal gas/vapor and/or light liquid

valves are found to leak at a rate less than 100 ppmv for two consecutive months,

then the operator may change to a quarterly inspection program. The annual

monitoring frequency for valves (skip periods) is not applicable;

Components with inherently leakless design features will be installed as

practicable;

Leak definitions of 100 ppmv for pump seals, compressor seals, flanges and

valves in gas/vapor and light liquid service, 200 ppmv for atmospheric pressure

relief devices without a rupture disk and 500 ppmv for all other components shall

be used;

Screwed connections; heat exchanger heads; sight glasses; meters; gauges;

sampling connections; bolted manways and hatches shall be included in the

definition of “equipment”;

All sampling systems in total organic compound (VOC, ethane, methane and

HAP) service > 5% shall be closed-purge, closed loop, or closed-vent systems.

In-situ sampling systems shall be exempt; and

A first attempt at repair shall be required for all leaking components within five

(5) days and repair shall be completed within 15 days for all components unless

the repair would require a unit shutdown that would create more emissions than

the repair would eliminate, and if so, the repair may be delayed until the next

scheduled shutdown, except first attempt at repair for:

o Any leak >10,000 ppm & <25,000 ppm - 2 days,

o Atmospheric pressure relief device leak without a rupture disk >200 &

<25,000ppm - 2 days,

o Any leak > 25,000 ppm - 1 day,

o Heavy liquid components > 500 ppm - 1 day, and

o Any leak in HRVOC89 service > 10,000 ppm - 1 day

These proposed work practice emission limits are substantially more stringent than NSPS

standards in 40 CFR 60 subpart VVa, 40 CFR 61 subparts J and V, and NESHAPS

requirements in 40 CFR 63 subparts FFFF, UU and YY. Table 5-30 presents the above

proposed LAER components and references the regulations/permits where these items

were found.

89 HRVOC = 1,3-butadiene, ethylene, propylene and butylene.



138

Table 5-30. LAER Components and References

LAER Component Reference

In organic hazardous air pollutant or in organic HAP service means that piece

of equipment either contains or contracts a fluid (liquid or gas) that is at least

five (5) percent by weight of total organic HAP's as determined according to

the provisions of §63.180(d) of subpart H.

40 CFR §63.1020 Definitions (Subpart UU)

If 98.0 percent or greater of the new (non-bellows seal) valves and the new

flange population inspected is found to leak gaseous or liquid volatile organic

compounds at a rate less than 500 ppmv for two consecutive months, then the

operator may change to a quarterly inspection program with the approval of

the District.

Chevron Products Co, El Segundo, CA. Permit to

Operate for Facility ID 800030, Revision #145, July

1, 2012.

Leak definition of 100 ppmv for pump seals, compressor seals, valves and

connectors in gas/vapor and light liquid service.

BAAQMD Best Available Control Technology

Guideline

Leak definition of 500 ppmv for all other components. SCAQMD Rule 1173 & TCEQ Tex. Admin. Code

tit. 30, Chapter 115 Subchapter H

Inclusion of connectors; heat exchanger heads; sight glasses; meters; gauges;

sampling connections; bolted manways; and hatches in the LDAR program;

TCEQ Tex. Admin. Code tit. 30, Chapter 115

Subchapter H

Underground process pipelines will contain no buried valves such that

fugitive emission monitoring is rendered impractical;

TCEQ Tex. Admin. Code tit. 30, Chapter 115

Subchapter D

Requirements for a first attempt at repair of all leaking components within 5

days a and repair in 14 days b for all components unless the repair would

require a unit shutdown, that would create more emissions than the repair

would eliminate, the repair may be delayed until the next scheduled

shutdown, except first attempt at repair for:

Any leak >10,000 ppm & <25,000 ppm - 2 days, c

Atmospheric pressure relief device leak >200 & <25,000 - 2 days, e

Any leak > 25,000 ppm - 1 day, e

Heavy liquid components > 500 ppm - 1 day, e

Light liquid leaks > 3 drops per minute - 1 day, e and

Any leak in HRVOC service > 10,000 - 1day.d

a - TCEQ Tex. Admin. Code tit. 30, Chapter 115

Subchapter D

b - Chevron Products Co, El Segundo, CA. Permit to

Operate for Facility ID 800030, Revision #145,

July 1, 2012

c - SCAQMD Rule 1173

d - TCEQ Tex. Admin. Code tit. 30, Chapter 115

Subchapter H



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The LDAR program that is proposed must meet two criteria to be considered LAER. To

fulfill the first criterion, the fugitive emissions regulations and BACT guidelines were

reviewed for the states most likely to have the most stringent emission limits contained in

the state implementation plan:

South Coast Air Quality Management District (SCAQMD) Rule 1173,

Texas Commission on Environmental Quality (TCEQ) 28LAER90 and Tex.

Admin. Code tit. 30, Chapter 115 Subchapter H (highly reactive VOCs)

programs, and

Bay Area Air Quality Management District (BAAQMD) BACT guidelines.

A summary of the equipment leak rates and repair periods in SCAQMD Rule 1173, the

TCEQ LAER requirements and the TCEQ Chapter 115 Subchapter H requirements are

presented in Table 5-31 and Table 5-32. Table 5-33 presents a summary of the

BAAQMD’s leak rate definitions. Based on a comparison of the program requirements

summarized in these tables, the first criterion is met by the equipment leak LDAR

proposal described above.

The second criterion is addressed above through the identification of the Chevron permit

precedent and the incorporation of its work practices (where more stringent) into the

proposed LDAR program. In accordance with 25 Pa. Code §127.205(7), the proposed

VOC LAER limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code

§127.12(a)(5).

5.5.2 Equipment Leaks of GHG BACT Analysis

Two sources of GHG emissions associated with equipment leaks must be considered: 1)

methane contained in the VOC leaks associated with process units (which are addressed

via the LAER analysis provided in the previous section, and 2) potential leaks from the

piping employed to deliver natural gas to the projects furnaces, Cogen Units, flares, and

other combustion sources. This piping includes connectors/flanges, block and control

90 28LAER refers to the Texas Commission on Environmental Quality’s (TCEQ’s) “boilerplate” special

conditions for nonattainment NSR. The most recent version of these conditions is found at

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bpc_rev28laer.pdf

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bpc_rev28laer.pdf



5-140

Table 5-31. SCAQMD Rule 1173 Equipment Leak Rates and Repair Periods 1

Equipment/Service 2 Leak Rate Trigger

(ppm)

First Repair

Period 3

Extended

Repair Period 3,4

Light liquid/gas/vapor

components >500 & <10,000 7 days 7 days

Heavy liquid components >100 & <500 7 days 7 days

Any leak >10,000 & <25,000 2 days 3 days

Atmospheric pressure relief

device >200 & <25,000 2 days 3 days

Any leak >25,000 1 day

Heavy liquid components >500 1 day

Light liquid leaks > 3 drops per minute 1 day

1. South Coast Air Quality Management District Rule 1173 Control of Volatile Organic Compound

Leaks and Releases from Components at Petroleum Facilities and Chemical Plants, as amended

February 6, 2009.

2. Components are valves, fittings, pumps, compressors, pressure relief devices, diaphragms, hatches,

sight-glasses, and meters

3. Calendar days

4. For each calendar quarter, the operator may extend the repair period for a total number of components

for a total number of leaking component, not to exceed 0.05 percent of components inspected during

the previous quarter, by type, rounded upward to the nearest integer where required.

Table 5-32. TCEQ LAER Equipment Leak Rates and Repair Periods 1

Equipment Leak

Rate

(ppm) 2

Repair Period Other

Valves

>500

15 days -

If the repair would

require a unit

shutdown, that would

create more emissions

than the repair would

eliminate, the repair

may be delayed until

the next scheduled

shutdown

Each open-ended valve or line shall be

equipped with a cap, blind flange, plug,

or a second valve.

Connectors

Connectors shall be inspected by

visual, audible, and/or olfactory means

at least weekly by operating personnel

walk-through

Agitator seals All new and replacement pumps,

compressors, and agitators shall be

equipped with a shaft sealing system

that prevents or detects emissions of

VOC from the seal. These seal systems

need not be monitored.

Compressor

seals

Pump seals

Any Leaks > 10,000 First attempt – 1 day

Repaired -7 days In HRVOC service

Pressure Relief

Valves with

Rupture Disc

For valves equipped with rupture disc, a pressure-sensing device shall be

installed between the relief valve and rupture disc to monitor disc integrity.

Replace at the earliest opportunity but no later than the next process shutdown

1. Texas Commission on Environmental Quality, Air Permits Division, New Source Review Boilerplate

Special Conditions for 28LAER, August 2011.

2. Quarterly monitoring using approved gas analyzer



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Table 5-33. BAAQMD Best Available Control Technology Guideline

Equipment/Service Leak Rate a (ppm)

Flanges >100

Valves >100

Pumps >100

Compressors >100

Pressure relief valves Not applicable

a - http://hank.baaqmd.gov/pmt/bactworkbook/default.htm

valves, pressure relief valves and miscellaneous devices (pressure and temperature

gauges, flow meters, sample connections, etc.).

No applicable GHG standards have been promulgated for equipment leaks under 40 CFR

parts 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed GHG BACT

limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

5.5.2.1 Steps 1-4: GHG Piping Equipment Leaks

The above discussion pertaining to equipment leaks of VOCs is directly applicable to

equipment leaks of the methane contained in the natural gas and as a result is not

reviewed again. Although LAER requirements are not applicable to methane emissions

(i.e., the definition of VOC’s excludes methane), the same LDAR program is proposed to

control equipment leaks of methane from natural gas lines containing methane.

The equipment leak provisions included in the Texas GHG permits for ethylene

manufacturing are summarized in Table 5-34. The Texas GHG permits for ethylene

manufacturing facilities utilize the following work practices:

LDAR for VOC containing streams but not gaseous fuel containing streams

(BASF FINA) for one furnace,

Auditory, Visual, and Olfactory (AVO) Monitoring (Chevron/Phillips and

ExxonMobil) for eight furnaces each, or

LDAR for methane containing streams for two furnaces.

5.5.2.2 Step 5: Establish Equipment Leaks GHG BACT

The same LDAR program that is proposed for VOCs in Section 5.5.1 is proposed for

GHGs except that methane will be the targeted pollutant. As previously noted, no



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Table 5-34. Summary of Texas Ethylene/Polyethylene Manufacturing GHG BACT Determinations

Company/

Project Control Options Considered Selected Limits

BASF FINA

Petrochemicals

Port Arthur, TX

2012 PSD-TX-

903-GHG SOB

and permit

Leak detection and repair (LDAR) for methane

Use of an LDAR program to control the

negligible amount of GHG emissions

that occur as process fugitives would be

cost prohibitive.

LDAR program to minimize process

fugitive VOC emissions.

No limit

Work practices: TCEQ’s 28LAER

LDAR for VOCs

Chevron/Phillips,

Cedar Bayou, TX

PSD-TX-748-

GHG October

2012 SOB and

permit

Leak detection and repair (LDAR) for methane

Audio and visual observations (AVO) monitoring

AVO for the piping components in the

new ethylene cracker plant in fuel gas

and natural gas service.

No limit

Work practices: AVO for the piping

components in fuel gas and natural

gas service.

Equistar

Channelview, TX

(OP-1 & OP-2)

PSD-TX-1272-

GHG May 2013

SOB and permit

Installation of leakless technology components to

eliminate fugitive emission sources. Instrumented

Leak Detection and Repair (LDAR) program

(Method 21).

Leak Detections and Repair with remote sensing

technology

Auditory, Visual, and Olfactory (AVO) monitoring

program.

Design and construct facilities with high quality

components, with materials of construction

compatible with the process.

Equistar proposes to use TCEQ method

28LAER for LDAR & to use AVO

methods as additional monitoring for

leaks.

Based on adverse environmental

impacts, leakless technologies are

eliminated as BACT.

No limit

Work practices: TCEQ’s 28LAER

LDAR for methane on two furnaces

ExxonMobil,

Baytown, TX

(draft SOB and

permit)

Leakless/Sealless Technology

Instrument LDAR Programs

Remote Sensing

Auditory, Visual, and Olfactory (AVO) Monitoring

AVO for the piping components in fuel

gas and natural gas service

Leakless valve technology for fuel lines

is considered technically impracticable

Instrument LDAR and/or remote sensing

of piping fugitive emissions in fuel gas

and natural gas service considered

economically impracticable

No limit

Work practices: AVO for the piping

components in fuel gas and natural

gas service.



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applicable GHG standards have been promulgated for equipment leaks under 40 CFR

parts 60 and 61.

5.6 Evaluation of the Potential Use of Carbon Capture and Sequestration (CCS) as BACT for CO2

The major GHG emitted by the Project is carbon dioxide (CO2). The significant sources

of CO2 emissions from the Project are the ethylene cracking furnaces and the Cogen

Units. Other minor combustion sources of GHG emissions include the emergency diesel

engines to generate electricity during power outages and diesel engine drivers for

emergency firewater pumps, thermal incinerators, and flares. These additional minor

sources of GHGs, which comprise approximately six percent of the combustion-related

CO2 emissions, are not considered by this analysis because the cost effectiveness

associated with application of CCS to these minor sources is less economic (i.e., less cost

effective) than its application to the significant sources for which CCS is determined

below to be cost infeasible.

CCS is an approach used to capture the CO2 emitted from large industrial facilities and

subsequently store the CO2 instead of releasing it to the atmosphere. The CCS process

involves three main stages:

Capturing and concentrating CO2 at its source by separating it from other

constituents in the exhaust gas stream;

Transporting the captured CO2 to a suitable storage location, typically in

compressed form; and

Storing the CO2 away from the atmosphere for a long period of time, for instance

in underground geological formations or in the deep ocean.

Steps 1 and 2 of the BACT analysis for CCS as presented below are organized by the

CCS process stage (i.e., capture, transport, and sequestration). For each of the process

stages, the results from the BACT Step 1 and 2 analyses are presented. Based on the Step

1 and 2 analyses, it is concluded that CCS is undemonstrated technology for exhaust

gases from natural gas-fired combustion turbines and tailgas-fired cracking furnaces due

to their inherently low CO2 concentration. However, in response to EPA’s request that

all CCS BACT analyses include a Step 4 cost based impact analysis, under Step 3 a best



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possible configuration for a CCS system is hypothesized and the cost impacts associated

with this hypothetical configuration is evaluated under Step 4.

5.6.1 Technical Feasibility of Potential CCS Process Alternatives

5.6.1.1 Step 1 - Identify Potential CO2 Capture Methods

The amount of CO2 produced by the Project’s ethane cracking furnaces and Cogen Units

is already designed to be reduced to a minimum through the use of improved efficiency

(see Sections 5.2.5 and 5.3.5). Thus, this analysis focuses on whether those already

reduced CO2 emissions can be feasibly captured.

In a conventional combustion source, the oxygen required for combustion of fuel is

provided by air. Because air contains 79 percent nitrogen, the CO2 concentration in the

exhaust gas from the source is diluted by the inert nitrogen as well as other products of

combustion. The average CO2 concentration in the exhaust gas from a natural gas-fired

source is on the order of 3 to 10 volume % depending upon the exhaust gas oxygen

concentration (i.e., combustion turbines have exhaust gas oxygen levels on the order of

15% by volume which greatly reduces the CO2 concentration in the exhaust to less than

3 % by volume when firing natural gas).

Capture and/or concentration of CO2 from a combustion source such as the proposed

furnaces and Cogen Units can theoretically be achieved either through pre-combustion

methods or through post-combustion methods.

Pre-Combustion: There are two potential pre-combustion CO2 capture approaches

using oxygen to combust the fuel: direct and indirect. Oxygen instead of air is used to

combust the fuel, eliminating the inert nitrogen from the exhaust, and thereby increasing

the exhaust gas CO2 concentration to approximately 90% (a concentration that can be

transported via pipeline). Notably, in both cases, there are significant capital and energy

costs associated with the construction and operation of an air separation plant required to

produce the oxygen that is needed for either direct or indirect oxygen use.

Direct Approach. The direct approach (i.e., oxy-firing) involves substituting oxygen for

air during the combustion process. This technique results in a more concentrated CO2



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exhaust gas stream, with the exhaust gas containing primarily CO2, H2O, and oxygen.

This stream would still need to be further processed to produce a relatively pure CO2

stream suitable for transportation and storage, but the size of downstream processing

equipment is reduced relative to that required if air is used in the combustion step.

Oxygen firing has not been demonstrated to be technically feasible on a commercial scale

for natural gas fired systems. Most of the oxygen firing research has focused on coal-

fired boilers. The use of oxygen firing for the Project’s ethane cracking furnaces and the

natural gas-fired Cogen unit has not been demonstrated and would require the

development of technology that is not currently commercially available. U.S. EPA has

explicitly acknowledged that, although various oxy-fueled combustion processes are

undergoing laboratory- and pilot-scale testing, this technology has not been

demonstrated.91 Because oxygen-fired cracking furnaces and Cogen Units are not offered

commercially, the use of oxygen firing for the proposed furnaces and Cogen Units is not

considered an “available technology” for purposes of this BACT analysis,92 As a result,

the precombustion direct approach is eliminated from further analysis.

Indirect Approach. The indirect approach, which is otherwise known as gasification,

involves partial combustion of a carbon-containing fuel (e.g., coal, coke or, residual oil)

with oxygen and steam to produce a synthesis gas (“syngas”) composed of CO and H2.

The CO is reacted with steam to yield CO2 and more H2. A physical or chemical

absorption based process is then used to separate the CO2, usually resulting in a

hydrogen-rich fuel that can be combusted. This indirect approach significantly increases

91 See, “Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from the

Petroleum Refining Industry,” U.S. EPA, Office of Air Quality Planning and Standards, October 2010,

at p. 13; see, also, “Available and Emerging Technologies from Coal-Fired Electric Generating Units,”

U.S. EPA, Office of Air Quality Planning and Standards, October 2010, at p. 35. 92 According to U.S. EPA’s top-down BACT guidance, “available control options are those air pollution

control technologies or techniques with a practical potential for application to the emissions unit and the

regulated pollutant under evaluation.” U.S. EPA’s assessment of oxy-combustion as it relates to

petroleum refining is that “this technology is still in the research stage” (see: Available and Emerging

Technologies for Reducing Greenhouse Gas Emissions from the Petroleum Refining Industry, p.25).

Therefore, the use of oxy-combustion does not have a practical potential for application to the planned

process heaters and it should not be considered in this BACT analysis.



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the fuel cost. It has currently only been used to produce hydrogen for use in the

manufacture of high valued chemicals and liquid fuels. In addition, firing a combustion

turbine with pure H2 has not been commercially demonstrated. To do so, the combustor

section of the turbine would need to be specifically designed for hydrogen’s unique

combustion characteristics (i.e., hydrogen has a much higher flame velocity and specific

heat release rate). A combustion turbine designed for hydrogen would not be capable of

combusting natural gas.

The ethane cracking process utilizes steam-ethane cracking to produce a valuable

chemical, ethylene, and byproduct tailgas, consisting of hydrogen and methane. Because

the proposed Project does not have an outlet for the hydrogen that is produced in the

cracking furnace process, the tailgas, containing hydrogen (~85% by volume) and

methane (~15% by volume), is designed to be combusted in the cracking furnaces,

replacing natural gas as a fuel. Thus, the fuel to the cracking furnaces already has a

significantly reduced carbon content, thereby resulting in a significant reduction in CO2

emissions. Approximately 50% of the heat required in the furnaces for ethane cracking is

obtained via the high hydrogen concentration of the tailgas, which means CO2 emissions

are approximately 50% lower for this Project’s cracking furnaces compared to a case

where natural gas is combusted in similar units.

Based on the above discussion, the pre-combustion indirect approach is eliminated from

further consideration.

Post-Combustion: Post-combustion methods are methods potentially applied to

conventional combustion sources (i.e., air is used to combust the carbon-containing fuels)

to capture and concentrate the CO2 in the combustion exhaust gases prior to transport.

The potentially available post-combustion CO2 capture technologies include: 1)

absorption with chemical solvents such as amines; 2) physical absorption using materials

such as Selexol®; 3) calcium cycle separation; 4) cryogenic separation; 5) membrane

separation; and 6) adsorption. These potential methods are addressed in order.

Absorption of the CO2 with chemical solvents such as amines. Use of amines for CO2

absorption is currently the most common method for CO2 capture where such capture is



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feasible. This process is illustrated in Figure 5-1. In such a process, monoethanolamine

(MEA) solvent is utilized, which has a fast reaction with CO2 at the relatively low partial

pressures found in most combustion exhaust gases. Some of the main concerns with

MEA and other amine solvents are: 1) corrosion due to the presence of O2 and other

impurities in the exhaust gas, 2) high solvent degradation rates because of the solvent’s

irreversible reaction with SO2 and NOx, and 3) the large amount of energy required for

solvent regeneration. This technology has not been commercially demonstrated with fuel

gas-fired combustion sources similar to the proposed project’s tailgas-fired furnaces and

natural gas-fired Cogen Units. However, this technology is assumed to be a potentially

Figure 5-1. CO2 Capture and Concentration System

“available technology” for the purposes of this BACT analysis because it can be applied

without materially negatively impacting the design or operation of the furnaces and

Cogen Units; and thus this technology is retained for further feasibility analysis in Step 2.



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One notable aspect of the capture and concentration process illustrated in Figure 5-1 is

that the solvent regeneration step in the process requires significant amounts of steam. If

the units currently included in the project cannot meet the increased steam demand,

construction of a new steam generator (e.g., a new natural gas-fired boiler) is required. In

any event, generation of additional steam will result in additional emissions, including a

considerable quantity of GHGs, as well as lesser amounts of NOx, CO, particulate matter,

and other pollutants.

Absorption with physical solvents such as Selexol®. Physical adsorbents, such as

Selexol, may be used for CO2 absorption at high pressure and low temperature. A form

of this method is commonly used for CO2 rejection from raw natural gas, which has a

composition this is much different than the exhaust gas composition from a combustion

source. This technology has not been commercially demonstrated in any application

related to combustion exhaust gases. As a result, this technology is removed from further

consideration.

Calcium cycle separation. In theory, quicklime (i.e., CaO) can be used to capture CO2

yielding limestone, which is then heated, releasing the captured CO2 in a concentrated

stream and regenerating the quicklime for reuse. Research and development work is still

required to obtain adequate sorbent stability after regeneration. As a result, this

technique is not considered an “available technology” for purposes of this BACT

analysis.

Cryogenic separation. This technique is based on solidifying CO2 by frosting (i.e.,

cooling CO2 to its condensation point) in order to separate the CO2 from other gaseous

components in the exhaust gas stream. The low concentration of CO2 in the exhaust gas

from conventional air-based combustion processes renders this technology impractical.

As a result, this technique is not considered an “available technology” for purposes of

this BACT analysis.

Membrane separation. Membrane separation is commonly used for CO2 removal from

natural gas at high pressure and high CO2 concentrations. Currently membranes are not

available that can effectively address gas streams with the low CO2 concentrations



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produced by the proposed cracking furnaces and Cogen Units. Additional research and

development work is required to develop membranes suitable for such an application,

including the need to optimize the technology for large-scale CO2 recovery and minimize

the energy required for separation. As a result, this technique is not considered an

“available technology” for purposes of this BACT analysis.

Adsorption. With this technique, exhaust gas is fed through a bed of solid material with

high surface area, such as a Zeolite or activated carbon. These materials can

preferentially adsorb CO2 while allowing other gases (e.g., nitrogen) to pass through.

The saturated adsorption bed is regenerated by either pressure swing (low pressure),

temperature swing (high temperature), or electric swing (low voltage) desorption.

Adsorption would require either a high degree of compression or multiple separation

steps to produce a high CO2 concentration from the furnace or Cogen Unit exhaust gas.

This technique has not been used in this type of application. As a result, adsorption is not

considered an “available technology” for purposes of this BACT analysis.

As noted above, amine-based chemical absorption is the only commercially demonstrated

technology that has been applied to the capture of CO2 from post-combustion exhaust gas

streams. The remaining technologies, are not commercially available. There are

additional potential CO2 reduction measures that are in the laboratory or conceptual

stages of development that are not discussed here because they have not been

demonstrated commercially. As a result, only amine-based chemical absorption and is

considered potentially available and considered further by this analysis.

5.6.1.2 Step 2- Technical Feasibility of Potential CO2 Capture Methods

Table 5-35 presents a summary of the commercial amine-based plants where CO2 is

captured from flue gas. As shown, these plants range in size from 200 to 600 metric tons

per day of CO2 captured with CO2 concentrations in the exhaust between 8 and 14%. In

comparison, the proposed Project’s cracking furnaces and Cogen Units will emit

5,270 metric tons per day of CO2 with the concentration of CO2 in the combined exhaust

being less than four (4) percent.



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Table 5-35. Amine Based CO2 Capture Plants ≥ 200 TPD 1

Capture Technology Location Fuel Gas CO2

Concentration

CO2 Capture

(Metric TPD) CO2 Use

Kerr-McGee/ABB Lumus Trona, CA Coal-fired 14% @ 3% O2 600 Soda Ash

Kerr-McGee/ABB Lumus Shady Point, OK Coal-fired 14% @ 3% O2 200 Food

Kerr-McGee/ABB Lumus Botswana, Africa Coal-fired 14% @ 3% O2 300 Soda Ash

Kerr-McGee/ABB Lumus Warrior Run, MD Coal-fired 14% @ 3% O2 200 Food

Fluor Econamine Bellingham, MA Gas-fired 8% @ 3% O2 320 Food

Mitsubishi Heavy Industries Kedah Darul Aman, Malaysia Gas Furnace 8% @ 3% O2 200 Urea

Mitsubishi Heavy Industries Fukoka, Japan Gas Furnace 8% @ 3% O2 330 General

Mitsubishi Heavy Industries Aonla, India Gas Furnace 8% @ 3% O2 450 Urea

Mitsubishi Heavy Industries Phulpur, India Gas Furnace 8% @ 3% O2 450 Urea

Mitsubishi Heavy Industries Kakinada, India Gas Furnace 8% @ 3% O2 450 Urea

Mitsubishi Heavy Industries Abu Dhabi, UAE Gas Furnace 8% @ 3% O2 400 Urea

Mitsubishi Heavy Industries Bahrain Gas Furnace 8% @ 3% O2 450 Urea

Mitsubishi Heavy Industries Ghotoki, Pakistan Gas Furnace 8% @ 3% O2 340 Urea

Mitsubishi Heavy Industries Phu My, Vietnam Gas Furnace 8% @ 3% O2 240 Urea

CERI Shanghai, China Coal-fired 14% @ 3% O2 360 General

1. http://www.globalccsinstitute.com/publications/process-modelling-amine-based-post-combustion-capture-

plant/online/113436.

http://www.globalccsinstitute.com/publications/process-modelling-amine-based-post-combustion-capture-plant/online/113436

http://www.globalccsinstitute.com/publications/process-modelling-amine-based-post-combustion-capture-plant/online/113436



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The information presented in Table 5-35, indicates that amine-based CO2 capture is

considered technically feasible for capturing CO2 in the combustion flue gases when the

CO2 concentration is eight (8) percent or greater than. However, no application has been

demonstrated in practice of amine-based CO2 capture for exhaust gas from a natural gas-

fired combustion turbine or tailgas-fired furnace where the concentration of CO2 in the

exhaust is less than 4%.

In conclusion, no amine-based or other CO2 capture techniques were identified as having

been demonstrated in practice in an application with a CO2 concentration in the exhaust

that is similar to that of the proposed natural gas-fired Cogen Units or tailgas-fired

cracking furnaces (i.e., less than 4 percent). In addition, if an amine-based technique

were applied, the energy requirements associated with the capture of CO2 from the

proposed project’s cracking furnaces and Cogen Units would result in a significant

energy impact.

5.6.1.3 Step 1 and 2 – Identification of Potential Technologies and Feasibility Analysis of CO2 Transportation

After capturing the CO2, regardless of the capture technique employed, the CO2 must be

transported to a suitable storage/sequestration site. Pipelines are the most common and

theoretically available method for transporting large quantities of CO2 over some

distance.

The oldest long-distance CO2 pipeline in the United States is the 140 mile Canyon Reef

Carriers Pipeline (in Texas), which began service in 1972 for Enhanced Oil Recovery

(EOR) in regional oil fields.93 Other CO2 pipelines, each of which is shorter, have been

constructed since then, mostly in the mid-continent United States, to transport CO2 for

EOR. These other pipelines carry CO2 from naturally-occurring underground reservoirs,

93 Congressional Research Service Report to Congress, Carbon Dioxide Pipelines for Carbon

Sequestration: Emerging Policy Issues; Order Code RL33971, updated January 2008.

http://www.marstonlaw.com/index_files/Emerging%20Policy%20issues%20for%20CO2%20pipelines%

202008%20CORRECTED%20(2008-01-17%20(No%20RL33971).pdf

http://www.marstonlaw.com/index_files/Emerging%20Policy%20issues%20for%20CO2%20pipelines%202008%20CORRECTED%20(2008-01-17%20(No%20RL33971).pdf

http://www.marstonlaw.com/index_files/Emerging%20Policy%20issues%20for%20CO2%20pipelines%202008%20CORRECTED%20(2008-01-17%20(No%20RL33971).pdf



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natural gas processing facilities, ammonia manufacturing plants, and a large coal

gasification project to oil fields located in the vicinity of the CO2 source. Altogether,

approximately 3,600 miles of CO2 pipeline are in operation in the United States.94

Pipeline transportation of CO2 requires very high pressures with correspondingly high

compressor energy requirements. CO2 is typically transported in its “supercritical” state.

It is very important that water be eliminated from CO2 pipeline systems, as the presence

of water results in formation of carbonic acid, which is extremely corrosive to the carbon

steel pipe. The primary compressor stations are located at the CO2 source. Booster

compressors are located as needed along the pipeline. CO2 pipelines are similar to

natural gas pipelines, requiring the same attention to design, monitoring for leaks and

protection against overpressure, especially in populated areas. All of these technical

issues can be addressed through modern pipeline construction and maintenance practices.

As a result, for the purposes of this BACT analysis, CO2 transportation by pipeline is

considered a technically feasible technology.

However, there are currently no CO2 pipelines at or near the proposed Project. The

closest existing CO2 pipeline, located in south central Mississippi, is over 900 miles

away. To install a pipeline as part of implementing CCS at the proposed Project is

considered impractical, especially in light the following: 1) technical/physical work

required to define and construct a pipeline in the mountainous western region of

Pennsylvania, 2) legal uncertainties associated with obtaining the rights of way required

to construct such a pipeline over a long distance (since the Project does not enjoy public

utility eminent domain powers), and 3) proposed Project’s timeline for construction.

5.6.1.4 Steps 1 and 2 Identification of Potential Technologies and Feasibility Analysis of CO2 Sequestration

There are several potential options for permanent storage of CO2 currently being

evaluated by regional carbon sequestration partnerships and other organizations. These

94 Ibid.



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options include storage in various geological formations (including saline formations,

exhausted oil and gas fields, and unmineable coal seams) and as well as storage in the

ocean. Each of these options is discussed in more detail below.

Geologic Formations:95 The geologic formations considered appropriate for CO2 storage

consist of layers of porous rock deep underground that are “capped” by a layer or

multiple layers of non-porous rock. In geologic storage, a well is drilled down into the

porous rock and pressurized CO2 is injected into it. Under high pressure, CO2 is turned

into a liquid and moves through the formation as a fluid. Once injected, the buoyant

liquid CO2 will flow upward until it encounters a non-porous rock barrier, trapping the

CO2 and preventing further upward migration.

There are other mechanisms for CO2 trapping. CO2 molecules can be dissolved in brine

or reacted with minerals to form solid carbonates or adsorbed in the pores of porous rock.

The degree to which a specific underground formation is amenable to CO2 storage is

difficult to determine. Ongoing research is aimed at developing the ability to characterize

a formation before CO2 injection in order to predict the structure’s CO2 storage capacity.

Research is also being conducted to develop CO2 injection techniques that achieve broad

dispersion of CO2 throughout the formation, to overcome low diffusion rates and to avoid

damaging the cap rock.

Some of the major unresolved issues with respect to CO2 sequestration pertain to the

legal framework for closing and remediating geologic sites, including liability for

accidental releases from these sites. In December 2010, U.S. EPA promulgated a final

rule establishing minimum Federal requirements under the Safe Drinking Water Act for

underground injection of CO2 for the purpose of geologic sequestration.96 This rule set

minimum technical criteria for the permitting, geologic site characterization, area of

review and corrective action, financial responsibility, well construction, operation,

95 2008 Carbon Sequestration Atlas of the United States and Canada, U.S. Department of Energy, National

Energy Technology Laboratory, Page 15. 96 75 Fed. Reg. 77230. December 10, 2010.



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mechanical integrity testing, monitoring, well plugging, post-injection site care, and site

closure of wells for the purposes of protecting underground sources of drinking water. In

September 2011, U.S. EPA promulgated a final rule making, U.S. EPA the permitting

authority for this program nationwide.97

Depending on geologic conditions in various regions, there are several types of geologic

formations in which CO2 can theoretically be stored and each has different opportunities

and challenges, as briefly described below.

Depleted Oil and Gas Reservoirs. Depleted oil and gas reservoirs are formations that

previously held crude oil and natural gas. In general, these formations have a layer of

porous rock with a layer of non-porous rock above, forming a dome. This dome offers

the potential to trap CO2 and makes these formations suitable for GHG sequestration. As

a side benefit of this type of sequestration, CO2 injected into a depleting oil reservoir can

enable recovery of additional oil and gas. When injected into a depleting oil-bearing

formation, the CO2 dissolves in the trapped oil and reduces its viscosity. This process

“frees” more of the oil by improving its ability to move through the pores in the rock and

flow with a pressure differential toward a recovery well. A CO2 flood typically enables

recovery of an additional 10 to 15 percent of the original oil in place.

Use of CO2 for enhanced oil recovery (EOR) and enhanced gas recovery (EGR) are

commercial processes used in some parts of the country, where CO2 can be injected to

increase pressures in partly depleted formations and thereby enhance recovery of oil and

gas from those formations. EOR injection of CO2 has occurred primarily in the Permian

Basin of west Texas.

There are known oil or gas reservoirs within the vicinity of the Project, including oil and

gas fields in western Pennsylvania and eastern Ohio. However, it is unknown whether

these depleted oil and gas fields provide a real sequestration opportunity or would be

97 76 Fed. Reg. 56982. September 15, 2011.



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available for such use. For example, a significant number of depleted gas reservoirs

(particularly those with proven geologic integrity) have been converted to natural gas

storage projects, and dedicated to seasonal injection and withdrawal of natural gas to

meet peak demands of the northeastern U.S., and thus unavailable for CO2 injection.

Regarding other active or depleted oil and gas reservoirs, only limited studies and tests

have been conducted by the Midwest Regional Carbon Sequestration Partnership

(MRCSP) or cooperating entities, including studies in the Michigan Basin-Otsego County

and a test well in Tuscarawas County, Ohio. Studies have noted that characteristics of

any particular formation in western Pennsylvania, eastern Ohio and West Virginia can

change significantly horizontally within the formation, where subtle shifts in lithology or

facies of each formation may be crucial to the capability of such formations to provide

for carbon sequestration. Further such studies would be needed to determine the field

injectability characteristics and migration/capture potential.98 The following steps would

be required to ensure that such a study was implemented safely and complied with all

regulations:

Initial planning and preliminary assessment,

Site characterization including seismic survey and implementation of a test well,

Conversion of the site to injection operations including additional wells if needed,

CO2 injection,

Monitoring prior to, during, and after injection, and

Closing or capping the well after the research is completed.

There are significant legal issues in terms of obtaining access to such oil and gas

reservoirs for CO2 injection. Injection of CO2 into underground horizons requires

acquisition of necessary property rights under relatively large amounts of acreage (with

typical oil and gas reservoirs spanning many square miles each). The mineral, oil and gas

rights associated with these areas are held by a large number of owners and mineral rights

lessees, and further it is unclear whether those interest holders have the right to, or would

98 Midwest Regional Carbon Sequestration Partnership (MRCSP) Geologic Projects,

http://www.mrcsp.org/GeologicProjects.aspx



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be inclined to, allow for injection of CO2.99 No entity currently has eminent domain

rights to acquire the subsurface interests needed to access such areas for purposes of

operating a CO2 injection and carbon sequestration project.

Due to the lack of studies and testing of EOR, EGR and depleted formation storage in the

western Pennsylvania and eastern Ohio fields and unknown legal issues associated with

such a sequestration effort, an assessment of the feasibility of injection CO2 from the

Project for EOR/EGR or storage in depleted oil and gas reservoirs is not currently

available. As a result, it is not possible to commit to the use of an undemonstrated

storage option until assessment, drilling, testing, analysis and injection and performance

monitoring has been conducted at potential EOR/EGR and/or depleted formation sites.

This type of effort would extend well beyond the PSD permitting and construction phases

of the proposed Project.

Unmineable Coal Seams. Unmineable coal seams are those that are too deep or too thin

to be mined economically. Theoretical use of unmineable coal seams involves injection

of CO2 into a coal bed, where it would both occupy pore spaces and would bond, or

adsorb, onto the carbon of the coal itself. Because the adsorption rate for CO2 in coals is

approximately twice that of methane, CO2 injection would displace coal bed methane

(CBM) that is adsorbed onto the pore surfaces of the coal. Thus, a potential has been

posited that wells could be drilled into unmineable coal beds to inject CO2 and recover

this coal bed methane (CBM).

Thus, like depleted oil reservoirs, unmineable coal beds represent a potential opportunity

for CO2 storage. One potential barrier to injecting CO2 into unmineable coal seams,

however, is swelling. When coal adsorbs CO2, it swells in volume. In an underground

formation, swelling can cause a sharp drop in permeability, not only restricting the flow

of CO2 into the formation, but also impeding the recovery of displaced CBM.

99 For example, Pennsylvania courts have held that the grant of oil and gas rights does not imply a right to

inject and store natural gas, but that such an injection/storage right must be explicitly stated in an oil and

gas lease.



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The only coal bed methane production identified in Pennsylvania by Pennsylvania’s

Department of Conservation and Natural Resources (DCNR) is in the anthracite region of

northeastern Pennsylvania.100 Moreover, injection of CO2 into underground coal seams

raises many of the same issues as to obtaining legal rights for injection, given the

complexity of mineral rights and multiplicity of involved mineral rights owners.

Accordingly, this CO2 sequestration technique is less advantageous for the Project than

other geologic sequestration options and is not considered further in this analysis.

Saline Formations. Saline formations are layers of porous rock that are saturated with

brine. They are much more common than coal seams or oil and gas bearing rock and

represent a significant potential for CO2 storage capacity. Much less is known about

saline formations than is known about crude oil reservoirs and coal seams and there is a

greater amount of uncertainty associated with the ability of saline formations to store

CO2. Saline formations contain minerals that could react with injected CO2 to form solid

carbonates. The carbonate reactions have the potential to be both a positive and a

negative. Such reactions can increase permanence but they also may plug up the

formation in the immediate vicinity of an injection well.

Additional research is required to better understand these potential obstacles and whether

and how those may be addressed. For example, a saline formation CO2 injection test was

conducted at the R.E Burger power plant near Shadyside, Ohio,101 approximately 60

miles southwest of the proposed Project site. CO2 injection testing was conducted on

three saline formations (Oriskany, Salina, and Clinton) at depths ranging from 5,900 to

8,300 feet. Even though the well was stimulated using acid and high injection pressures,

low flow rates were observed at each formation, indicating poor opportunities for CO2

sequestration.

100 Second Revisions to Final Draft Report by the Carbon Management Advisory Group (CMAG); April

2008. http://www.dcnr.state.pa.us/info/carbon/conferencecalls.aspx#secondfinal. 101 Appalachian Basin – R.E. Burger Plant Geologic CO2 Sequestration Field Test; DOE-NETL

Cooperative Agreement DE-FC26-05NT42589; Midwest Regional Carbon Sequestration Partnership;

January 2011.



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Use of saline formations for injection and storage involves many of the same legal /

property interest acquisition issues as those discussed above for injection into depleted oil

and gas formations or unminable coal seams.

Accordingly, this CO2 sequestration technique is considered to be technically infeasible

for the Project until assessment, drilling, testing, analysis and injection and performance

monitoring have been conducted at any potential injection site.

Basalt and Organic Rich Shale Formations.102 Two additional geological environments

being investigated for long-term CO2 storage are basalt formations and organic shale

formations. Basalt formations are geological formations of solidified lava. These

formations have a unique chemical makeup that could potentially convert injected CO2

into a solid mineral form, thus isolating it from the atmosphere permanently. Some key

factors affecting the capacity and ability to inject CO2 into basalt formations are effective

porosity and interconnectivity. Current efforts are focused on enhancing and utilizing the

mineralization reactions and increasing CO2 flow within basalt formations.

Organic-rich shales are another potential geological storage option. Shales are formed

from silicate minerals, which are degraded into clay particles that accumulate over

millions of years. The plate-like structure of these clay particles causes them to

accumulate in a flat manner, resulting in rock layers with extremely low permeability in a

vertical direction.

At this time, long-term CO2 storage in basalt formations and organic-rich shale basins has

not been demonstrated, as recently stated by the U.S. Department of Energy:

While the location of some basalt formations and organic-rich shale basins has

been identified, a number of questions relating to the basic geology, the CO2

trapping mechanisms and their kinetics, and monitoring and modeling tools need

to be addressed before they can be considered viable storage targets. As such, no

102 2008 Carbon Sequestration Atlas of the United States and Canada, U.S. Department of Energy, National

Energy Technology Laboratory, page 15.



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CO2 storage resource estimates for basalt formations or organic-rich shale basins

are currently available.103

As a result, this storage option is not considered an “available technology” for purposes

of this BACT analysis.

Terrestrial Ecosystems: 104 Terrestrial sequestration is the enhancement of CO2 uptake

by plants that grow on land and in freshwater and, importantly, the enhancement of

carbon storage in soils where it may remain more permanently stored. Terrestrial

sequestration provides an opportunity for low-cost CO2 emissions offsets. Early efforts

include tree-plantings, no-till farming and forest preservation. To date, there are no

applications of this method that would be large enough to handle the volumes of CO2

produced by this Project. Due to the undemonstrated cost and effectiveness of terrestrial

ecosystem sequestration options for storing 2 million tons per year of CO2 over the life of

the Project, this sequestration option is considered to be technically infeasible and is not

further evaluated as BACT.

5.6.2 Step 3: CCS Control Technology Hierarchy

As concluded above, 1) there are currently no CO2 pipelines at or near the proposed

Project and installation of such a pipeline is considered impractical; 2) permanent CO2

sequestration has not been commercially demonstrated as a GHG control technique; and

3) significant technical and legal uncertainties remain before this control option can be

considered commercially available in the context of a GHG BACT analysis. As a result,

the use of CCS is considered technically infeasible for application to the proposed

Project’s tailgas-fired cracking furnaces and natural gas-fired Cogen Units.

Although Shell does not consider CCS to be technically feasible for the proposed Project,

USEPA has requested that PSD permit applicants conduct a Step 4 BACT impacts

103 “The North American Carbon Storage Atlas,” 1st ed., U.S. Department of Energy et al., 2012, at page 19. 104 Ibid, Page 22.



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analysis, as reflected in the following recent permitting actions where USEPA reviewed

or issued the GHG PSD permits:

Illinois Environmental Protection Agency’s (IEPA) intent to issue a Prevention of

Significant Determination (PSD) construction permit for Universal Cement,

located in Chicago, Illinois.

Wisconsin Department of Natural Resources’ (WDNR) intent to issue a

Prevention of Significant Deterioration (PSD) construction permit for Wisconsin

DOA I UW Madison - Charter St.

USEPA Region 6 Application Completeness Determination for the Chevron

Phillips Chemical Company LP Prevention of Significant Deterioration Permit for

the Cedar Bayou Plant-New Ethylene Production Unit.

For this reason, Shell is proceeding in Step 4 to provide a cost, energy, and environmental

impact analysis of a conceptual CCS system.

5.6.3 Step 4: Evaluate the Most Effective Controls.

For purposes of the following evaluation of the impacts of applying CCS to the cracking

furnaces and Cogen Units, chemical absorption using MEA based solvents is assumed to

represent the most applicable CO2 capture option and the use of sequestration in a

subsurface saline formation is assumed to represent the most applicable option for long-

term storage.105 Under this conceptual CCS system, the combustion flue gases from the

furnaces and Cogen Units would be ducted to an absorption system where the gases

would be quenched and then CO2 would be captured in an MEA solution. The MEA

solution would be regenerated to release the CO2 as a concentrated stream, which would

then be dehydrated, compressed, transported and injected into a subsurface saline

formation.

The potential CO2 reductions that would result from the theoretical application of CCS

are presented in Table 5-36. It should be noted that due to the low CO2 concentrations in

the cracking furnace and combustion turbine exhaust gases, the capture efficiency of

105 Data in terms of potentially available metric tons of capacity, available through the National Carbon

Sequestration Viewer (http://www.natcarbviewer.com/), indicates that there is greater potential

capacities of subsurface saline than the other sequester options discussed above.

http://www.natcarbviewer.com/



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90 percent presented in Table 5-36 is considered to be conservatively high because is has

not been demonstrated in practice on an exhaust gas will CO2 levels of less than four (4)

percent.

As discussed previously, permanent CO2 sequestration has not been commercially

demonstrated as a GHG control technique and significant technical and legal

uncertainties remain. In addition, as shown by the following discussion, the adverse

economic, energy, and environmental impacts of CCS are significant and beyond those

that should be considered acceptable in establishing a BACT limit for GHG emissions

from the proposed Project.

Table 5-36. CO2 BACT Hierarchy and Emissions

Source

Uncontrolled CO2

(tons per year)

CCS %

Control

Controlled CO2

(tons per year)

Ethane Cracking Furnaces (7) 1,059,500 90 106,000

Cogen Units (3) 1,060,500 90 106,000

Emergency Generators (4) 1,150 0 1,150

Firewater Pumps (3) 120 0 120

Thermal Incinerators (2) 71,600 0 71,600

Flares (5) 75,600 0 75,600

Total 2,268,470 84 360,470

5.6.3.1 Economic Impacts Evaluation

To implement CCS, the exhaust streams from the process heaters would be collected and

routed to an MEA absorption unit to concentrate the CO2 in this combined stream from

around 5 percent to approximately 90 percent. This concentrated CO2 stream would then

need to be dehydrated and compressed from ambient pressure to about 2,200 pounds per

square inch before transportation and subsequent deep well injection. The costs of

purification, compression, transportation, well construction and operation are substantial,

as shown in Table 5-37 and as summarized below.

As shown in Table 5-37, the estimated capital cost for the equipment needed for

purification, compression and deepwell injection/storage of CO2 from the furnaces and



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Cogen Units is approximately $360 million. The annualized cost of implementing CCS,

including transportation, operating and maintenance costs, is estimated to be

approximately $132 million per year. The resulting control cost-effectiveness of CCS is

$117 per ton of CO2 sequestered.

5.6.3.2 Energy Impacts Evaluation

The electric power required to capture, compress, and inject the CO2 captured from the

furnaces and Cogen Units is about 30 megawatts, which is a significant, adverse energy

impact associated with the CCS option. This is enough electricity to power more than

22,500 average American homes.106 In addition, over six (6) billion cubic feet of natural

gas would be consumed annually in generating the steam needed to operate the CCS

Table 5-37. Summary of CCS Impacts Analysis for the Cracking Furnaces and

Cogen Units 1

Parameter Value

Economic Impacts

CCS Total Installed Cost 360,315,000 $

Annualized Costs 131,901,000 $/yr

Net GHG Reduced 1,730,800 T/yr

Control Cost-Effectiveness 117 $/T

Environmental Impacts (CCS Steam & Power Related Emissions)

NOx Emissions 392 T/yr

SO2 Emissions 860 T/yr

Energy Impacts

CCS Power Demand 264,500 MWh/yr

CCS Steam Demand (from Natural Gas) 6,033,500 MMscf/yr

1. The basis for the results presented in this table is presented in Table B-30

of Appendix B.

106 Source: http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3 (last accessed September 24, 2013).

http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3



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capture and concentration system. This is enough natural gas to heat more than 120,000

homes during the winter.107

5.6.3.3 Environmental Impacts

The adverse environmental impacts of implementing CCS on the CO2 emissions from the

furnaces and Cogen Units are those associated with construction of the subsurface CO2

injection well system along with the collateral increase in pollutants emitted from steam

and electrical generation required to meet the CCS system’s steam and power demands

described above. These emissions include 392 tons per year of NOx, 860 tons per year of

SO2, and 217,130 tons per year of CO2e. There will also be increases in emissions of

other pollutants such as PM10, PM2.5, CO and HAP.

5.6.4 Step 5: Proposed CO2 BACT

As discussed in Section 5.6, no carbon capture technologies are believed to be technically

feasible as applied to this Project’s low CO2 concentrations, no current infrastructure for

transport of CO2 in the region, and no carbon sequestration methods are available at this

time within a reasonable distance of the Project. Without this necessary transportation

and sequestration infrastructure, it is uncertain (and doubtful) that sufficient storage

capability will be available and/or accessible in the time frame being considered for

construction of the Project.

The estimated control cost for the application of CCS to the furnaces and Cogen Units is

$117 per ton. This cost is well above the range of cost effectiveness values considered to

be reasonable and acceptable in BACT determinations for control of GHG emissions.

For example:

107 Based on August 2013 EIA projections that a home heating with gas will consume 58 Mscf of natural

gas during the winter of 2013/14 (see: http://www.eia.gov/tools/faqs/faq.cfm?id=867&t=8 and

http://www.eia.gov/tools/faqs/faq.cfm?id=5&t=8 - last accessed September 24, 2013).





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In making the GHG BACT determination for Copano Processing, U.S. EPA

determined that control of GHG emissions at a cost of $54/ton is not BACT

because it is “economically prohibitive.”108

In making the GHG BACT determination for the City of Palmdale, U.S. EPA

determined that control of GHG emissions at a cost of $45/ton is not BACT

because it is “economically infeasible.”109

In making the GHG BACT determination for Valero’s McKee Refinery, U.S.

EPA determined that control of GHG emissions at a cost effectiveness of

$134/ton is not BACT.110

In making the GHG BACT determination for Freeport LNG Development,

L.P.’s Freeport LNG Liquefaction Project, U.S. EPA determined that control

of GHG emissions from the amine treatment units was cost prohibitive, were

the cost effectiveness of the control option under consideration was estimated

at approximately at $14/ton of CO2 sequestered.111

As another benchmark, California Carbon Allowances are currently trading on the spot

market for less than $12 per ton.112

As noted in Sections 5.2.5 and 5.3.5, incorporating the highly energy efficient cracking

furnaces and Cogen Units associated with the Project will minimize the emissions of

GHGs (CO2, N2O and methane). A highly efficient operation requires less fuel to

operate, directly impacting the amount of GHGs emitted. Establishing an aggressive

108 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction

Permit for the Copano Processing, L.P., Houston Central Gas Plant, Permit Number: PSD-TX-104949-

GHG. U.S. EPA Region 6, December 2012. (Cost effectiveness calculated based on listed cost of $10.9

million/yr for annual emission reduction of 202,000 tons per year.) 109 Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the

Palmdale Hybrid Power Project. U.S. EPA Region 9, October 2011. (Cost effectiveness calculated

based on listed cost of $78 million/yr for annual emission reduction of 1.7 million tons per year.) 110 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction

Permit for the Diamond Shamrock Refining Company, L.P., Valero McKee Refinery Permit Number:

PSD-TX-861-GHG, July 2013, p. 7; and Diamond Shamrock Refining Company, L.P., a Valero

Company Greenhouse Gas Prevention of Significant Deterioration Permit Application for Crude

Expansion Project Valero McKee Refinery Sunray, Texas, Updated December 2012, p. 4-15. 111 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction

Permit for the Freeport LNG Development, L.P., Freeport LNG Liquefaction Project, Permit Number:

PSD-TX-1302-GHG, December 2013, p. 31; and Greenhouse Gas PSD Application, Freeport LNG

Development, L.P., December 2011, p. 10-21. 112 See: BGC Carbon Market Daily, March 21, 2014.



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basis for energy recovery and facility efficiency will reduce GHG emissions and the costs

to mitigate it.

Further, as noted in Sections 5.2.5, use of low carbon fuels like hydrogen rich tailgas in

the cracking furnaces also reduces CO2 emissions by approximately 50% compared to

natural gas. Use of a low carbon feedstock such as ethane instead of naphtha will also

reduce the emissions of GHGs (CO2, N2O and methane).

Thus, the BACT analysis for GHG concludes that the combination use of hydrogen rich

tail gas in the cracking furnaces and energy efficient technologies discussed in

Sections 5.2.5 and 5.3.5 constitute BACT for this Project.

5.7 Polyethylene Process, Storage, and Handling Vents

The three PE manufacturing units and their associated pellet storage and handling

systems will have vents that exhaust to the VOC control system or to the atmosphere. A

summary of these vents along with the pollutant type emitted is included in Table D-2 of

Appendix D. The two pollutant types emitted from these vents are VOC and/or PM.

5.7.1 Polyethylene Process, Storage and Handling Vent VOC LAER Analysis

The proposed project is located in an area that is classified as nonattainment with regard

to the ozone standard, for which VOC is considered a precursor. As a result, a LAER

analysis is required for all of the project’s VOC sources. This LAER analysis addresses

VOC emissions from the PE manufacturing process, storage, and handling vents and

includes the emissions points identified in Table D-2 of Appendix D.

The VOC containing vents from the PE manufacturing process fall into two categories:

continuous/intermittent process vents that are part of the polyethylene manufacturing

process’ design and operation and emergency vents. Continuous/intermittent vents that

contain VOC and are inherent to the PE manufacturing process will either be directed to

the VOC Control System or restricted by the proposed LAER limit. Emergency vents

that contain VOC will be directed to the VOC Control System or the atmosphere.



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As noted in Section 4.0, VOC emissions from Polymer Manufacturing Facilities are

regulated under 40 CFR Part 60 subpart DDD. This NSPS covers all of the processes

used to manufacture high and low density polyethylene including the high and low

pressure processes used to manufacture low density PE and the gas phase, liquid phase

slurry, and liquid phase solution processes used to manufacture high density PE. The

number of VOC emitting vents that must be controlled in accordance with the NSPS’s

requirements is determined based on which process is used and the total uncontrolled

amount of VOC that is emitted from defined areas of that process.

5.7.1.1 Step 1: Identify PE Process, Storage, and Handling Vent VOC Controls

To identify VOC controls applicable to the class or category consisting of a PE

manufacturing facility’s process, storage, and handling vents, information contained in

the RBLC, recent and ongoing permitting actions and other permits for PE manufacturing

facilities were reviewed. A summary of the information obtained through this review is

presented in Table 5-38. Based on an evaluation of the information presented in Table

5-38, the following observations can be made:

There are three precedents in the form of recently issued permits or pending

applications (i.e., ExxonMobil MBPP, Chevron/Phillips, and Sasol Lake Charles)

that have not yet been constructed and as a result, the limits included/proposed in

those permits/applications have not yet been achieve in practice.

The same approach (i.e., form of the limits) is used for limiting emissions from

each of the identified facilities, regardless of the PE manufacturing process

employed.

The VOC emissions are limited from each of the identified facilities by using the

following combination of limits:

o There is a condition which requires the continuous/intermittent VOC

containing process vents located upstream of a defined point in the

process to be directed to a VOC control system, where either a flare or

incinerator is used to control the VOC emissions.



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Table 5-38. Summary of VOC BACT Precedents for Polyethylene Unit Vents 1

RBLC ID

No./State

Facility

Name

Permit

Date

Process

Description Vent Location Description

Control

Description VOC Limit

TX 103048 2

ExxonMobil

Chemical

Company -

MBPP

10/07/13

PE Unit

(2 Units Total

1,300 MT/yr) 3

Reactor and high capacity feed supply

depressurizations

Multipoint Ground

Flare

40 CFR 60.18 and

99.5% DRE

Unreacted gases removed from the gas/resin

in the purge system located upstream of the

granular resin feed hoppers

Flameless Thermal

Oxidizer (FTO) 99.99 % control

Elevated Flare 40 CFR 60.18 and

99% DRE

Residual emissions between the purger and

the extruder

Regenerative

Thermal Oxidizer

(RTO)

97% DRE or

<10 ppmv 12-mth

roll

Residual VOC after the extruder through

product loadout

Residual VOC

Limit

70 lb/MMlb of PE

pellets 12-mth roll

Dryer Vent Included in

Residual VOC limit

Emissions cap covering resin bins to loadout VOC Cap 13.83 TPY

TX 103832 4

final

Chevron/

Phillips

Chemical

Company LP

08/08/13

2 PE s\Units

(2 Units Total

1,200 MT/yr)

Carbon compound emissions from: process

vents, relief valves, analyzer vents, steam jet

exhausts, upset emissions, start-up &

shutdown-related emissions or purges,

blowdowns, or other system emissions of

waste gas

Flare

Compliance with 40

CFR 60.8, 60.18, and

subpart DDD, 40

CFR Part 63 subparts

A and FFFF

Dryer Vent No control Unit 41 – 6 lb/hr

Unit 40 – 12 lb/hr

Residual VOC after the dryer through

product loadout

Residual VOC

Limit

50 lb VOC/MMlb of

PE pellets 12-mth roll

Emissions cap covering uncontrolled vents

(i.e., extruder feed hopper vents, pellet

dryers, storage silos, & rail loadout)

VOC Cap 39.86 TPY

LA 5

SASOL

Lake Charles

Chemical

Complex

04/30/13

PSD

Permit

App.

Low Density PE

Low Product Purge Bin Vent filter

Centrifugal Dryer Vent Thermal Oxidizer

40 CFR 60 subpart

DDD

(99% control)

Extruder Pellet Hopper, Silo Vents, Bin

Vents, Pellet Elutriation Separator,

Emergency vent

Calc. threshold

emissions to

demonstrate need

for control

40 CFR 60 subpart

DDD



5-168

RBLC ID

No./State

Facility

Name

Permit

Date

Process


Control


LA 5

SASOL

Lake Charles

Chemical

Complex

04/30/13

PSD

Permit

App.

Linear Low

Density PE

CRV Catalyst Relief Vent, CV Catalyst

Vent, Pellet Dryers, Extruders, & Silos

Maintain TRE > 5.0

but <= to 8.0

40 CFR 60 subpart

DDD

40 CFR 63 subpart

FFFF

TX 8758

Exxon

Beaumont

Chemical

TX Permit

Linear low and

high density PE

800 MT/yr

1. Carbon compound emissions from process

vents, relief valves, analyzer vents, steam

jet exhausts, upset emissions, start-up and

shutdown-related emissions or purges,

blowdowns, or other system emissions of

waste gas

2. Excludes analyzer vents and vents

associated with the formation, handling,

and storage of solidified products.

Flare

Compliance with 40

CFR 60.18

Ground flare:

99% DRE C1-C4

98% >C4+

Air Assisted Flare

99.5% DRE C1-C4

98% DRE >C4+

Ethylene cap in PE granules at surge silos 6 Residual VOC

Limit

50 lb/MMlb PE

product

Emissions cap covering uncontrolled

emissions downstream of the product purge

vessels (dryers, product silos, Flo-Triators,

railcar loadouts, surge silo, loadout surge

vessels, prefill bins, seed silo, feed hoppers,

sample pot, product conveyers, and elutriator

VOC Cap 197.14

TX 40157

PSDTX1222

Formosa

Plastics

2/00 PSD

Permit

HDPE II

275 MT/yr

Vent control system Flare Compliance with 40

CFR 60.18

After the dryer through product loadout Residual VOC

Limit

40 lb VOC/MMlb of

PE pellets

Emissions cap covering pellet dryer,

blending and storage, & loadout VOC Cap 15 TPY

TC 18836

PSDTX1206 Equistar

PSD

Permit

High density PE

4 Lines

930 MT/yr

Vent control system Flare Compliance with 40

CFR 60.18

If hexane concentration of the vent stream

from the tank truck during PE loading

exceeds 2600 ppmv

Powder in silo shall

be purged to flare

until concentration

is below 2600

ppmv



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RBLC ID

No./State

Facility

Name

Permit

Date

Process


Control


1. VOC emitted to the atmosphere between

the classifier and hopper car loadout

2. As measured using headspace analysis

Residual VOC

Limit

90 lb/MMlb PE

product

Emissions cap covering uncontrolled

emissions from blending silos, product filter

receiver, product silos, railcar silos,

bagging/boxing

VOC Cap 83.7 TPY

1. MT = 1000 metric tons

2. ExxonMobil Chemical Company Permit 103048, Special Conditions.

3. http://www.businessweek.com/news/2012-06-01/exxon-applies-for-permits-to-expand-plastics-production-in-texas

4. Chevron/Phillips Chemical Permit 08/08/13 Condition 9

5. Sasol North America Permit Application for Lake Charles Chemical Complex, 4/30/13, pages 3-85 & 86.

6. Ethylene is in affect a surrogate for residual VOC. The same upstream actions that would be taken to control the ethylene content of the PE granules

would also control VOC.



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o There is a limit on the amount of residual VOC that the polymer can

contain at that same defined point in the process. This limit is used to

restrict the amount of VOC that can be emitted through the uncontrolled

vents located downstream of the defined point in the process.113

o A mass rate emissions cap is placed over all of the uncontrolled VOC

containing vents.

The point in the process where vents are directed to a VOC control system (i.e.,

flare or incinerator) vs. where vents are subject to a residual VOC content limit

varies between the various permit precedents reviewed.

o The Chevron/Phillips permit requires flaring of the VOC containing vents

prior to the extruder while the residual VOC limit begins following the

dryer. As a result, an additional mass rate limit is used to control

emissions from the dryer.

o The ExxonMobil Beaumont permit requires flaring of all process vents up

to the extruder (i.e., formation) and the residual VOC is measures in the

PE granules at surge silos. Thus, all VOC vents are covered under the

two limits.

The VOC control system must achieve a reduction between 98114 and

99.99 percent.

The VOC controls identified include the following

o Flameless Thermal Oxidizer (FTO) (see ExxonMobil MBPP)

o Regenerative Thermal Oxidizer (RTO) (see ExxonMobil MBPP)

o Thermal Oxidizer (see Sasol)

o Flares (see ExxonMobil MBPP, Chevron/Phillips, Exxon Beaumont,

Formosa, and Equistar)

In summary, the review of recent PE manufacturing facility permitting precedents

indicates that the continuous and intermittent VOC containing vents fall into two

categories of controls/limits: 1) vents that are directed to a VOC control device that must

achieve a certain required destruction efficiency and 2) vents that are permitted under one

of two forms of an emissions cap (i.e., residual VOC content or group emissions cap).

113 The residual VOC limit is, in effect, a performance specification on the upstream equipment that ensures

that equipment is operated in such a manner that the residual VOC remains below the limit. 114 Compliance with the flaring design and operational requirements at 40 CFR 60.18 is assumed to achieve

a minimum 98 % VOC destruction efficiency. In Texas, compliance with compliance with the design

and operational requirements at 40 CFR 60.18 is assumed achieve a 99% destruction efficiency on C1-

C3 compounds and a 98% destruction efficiency on C3+ compounds.



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5.7.1.2 Step 2: Eliminate Technically Infeasibility Controls

Three of the precedents presented are for facilities that have not yet been constructed. As

a result, the following precedents have not been achieved in practice at a polyethylene

manufacturing facility:

99.5% DRE using a flare to control the VOC from reactor and high capacity feed

supply depressurizations (ExxonMobil MBPP);

99.99% control using a flameless thermal oxidizer to control the VOC contained

in the unreacted gases removed from the gas/resin in the purge system located

upstream of the granular resin feed hoppers (ExxonMobil MBPP);

97% DRE or <10 ppmv VOC on a 12-month rolling average basis using a

regenerative thermal oxidizer to control the residual VOC emissions in the vents

located between the purge system and the extruder (ExxonMobil MBPP);; and

99% control using a thermal oxidizer to control the VOC in the vents located on

the low product purge bin and centrifugal dryer (Sasol).

In accordance with the LAER criterion that requires that limits be achieved in practice on

that class or category of source, these control levels (i.e., destruction efficiencies or

residual VOC concentrations) on the specified vents are eliminated from consideration in

determining the LAER limit for the proposed polyethylene manufacturing process vents.

5.7.1.3 Step 3: Establish PE Manufacturing Process, Storage, and Handling Vent VOC LAER

Based on the applicable LAER precedents for the operating PE facilities (i.e.,

ExxonMobil Beaumont, Formosa, and Equistar), the most comprehensive use of a VOC

control system from a process perspective is the ExxonMobil Beaumont precedent that

requires control of all carbon compound emissions from process vents, relief valves,

analyzer vents, steam jet exhausts, upset emissions, start-up and shutdown-related

emissions or purges, blowdowns, or other system emissions of waste gas. The

ExxonMobil control scheme excludes analyzer vents and process vents associated with

the formation, handling, and storage of solidified products. The vents that are not

directed to the flare for control are located in the part of the process where the solidified

products are formed, handled, and stored. VOC emissions from this section of the PE

manufacturing process are restricted by the residual VOC limit.



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Many of the identified precedents summarized in Table 5-38 reference to the flare design

and operational requirements at 40 CFR §60.18. In accordance with several of the NSPS

and NESHAP regulations (e.g., NSPS Part 60 subpart DDD or NESHAP Part 63 subpart

CC), it is assumed that greater than 98% destruction efficiency is achieved when a flare is

operated in compliance with the requirements of 40 CFR §60.18 or 40 CFR §63.11. The

ExxonMobil Beaumont permit requires that destruction efficiencies of 99.5% and 99% be

achieved on C1-C4 compounds when using the air assisted and ground flares,

respectively. However, the Beaumont permit does not include any testing requirement to

verify that these higher levels of destruction are achieved. As a result, because the flare

design and operating requirements at 40 CFR §60.18 are what is specified by the

Beaumont permit, it is concluded that only a 98% destruction of VOC from polyethylene

manufacturing vents has been achieved in practice at that facility.

The residual VOC limits (i.e., lb/MMlb limits) included in the identified permits vary

with respect to location(s) and sampling objective. The breakdown is as follows:

In some permits, the limit applies to residual VOC measured at one of three

possible sample locations with a presumption that all of the VOC in the sampled

material is emitted prior to the PE pellets being shipped from the facility:

o Granules or resin upstream of the extruder;

o Pellets exiting the extruder; or

o Pellets exiting the dryer.

In some permits, the limit applies to residual VOC based on measurements at two

sample locations with a presumption that only the change in measured VOC

content is emitted:

o Pellets exiting the dryer and pellets being loaded out.

The most stringent residual VOC limits are those where the sample is taken at the first

point in the process where the vents are not controlled

Mass emissions rate caps are also used to limit the emissions from uncontrolled vents.

The caps are set up in one of two ways. In the first, the cap quantifies the maximum

amount of VOC that can be emitted from that point forward in the process by limiting the

residual VOC content in the polymer at that point in the process. In the second, the cap is

used to limit emissions from uncontrolled vents that are not included in the residual VOC



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limit. An example of this would be the Chevron/Phillips permit, where the residual VOC

in the pellets is measured in the pellets exiting the dryer and then again prior to loadout.

The emissions cap covers all uncontrolled vents from the extruder feed hoppers and pellet

dryer to pellet loadout. If the residual VOC measurement is taken at the first point in the

process where the vent is uncontrolled, the need for a mass based emissions cap is

unnecessary as long as the mass production rate of polymer/pellets is measured.

Based on the above review of PE plant permits to determine the most stringent emissions

limits that have been achieved in practice, the following is proposed as VOC LAER for

the PE manufacturing process, storage, and handling vents:

At PE Units 1 & 2 all continuous and intermittent VOC containing gases vented

from the PE process vents (A listing of the controlled vents is presented in

Table D-4 of Appendix D) located upstream of the Product Purge Bin and

including the Product Purge Bin will be directed to a VOC control system

designed and operated to achieve a 99.5% DRE during normal operation;

At PE Unit 3 all continuous and intermittent VOC containing gases vented from

the PE process vents (A listing of the controlled vents is presented in Table D-4 of

Appendix D) located upstream of the degasser will be directed to a VOC control

system designed and operated to achieve a 99.5% DRE during normal operation;

At PE Units 1 & 2 the residual VOC content in the resin exiting the Product Purge

Bins shall be less than 50 ppmw.

At PE Unit 3 the residual VOC content in the resin exiting the Degasser shall be

less than 50 ppmw.

The proposed emission limits for the PE unit process vents meet the two criteria to be

considered LAER. Applying the first criterion, a review was performed of state

regulations and guidelines in states where PE manufacturing facilities are known to

operate. That review identified a BACT guideline for polyethylene manufacturing

facilities located in Texas as the most stringent guidance (not a SIP “limit”) provided by a

state. The Texas guideline requires the following:

Uncontrolled VOC < 80 lb/MMlb of polymer for low pressure HDPE and case-

by-case for high pressure LDPE

NSPS Part 60 subpart DDD, which is part of most if not all state SIPs, requires that the

controlled vents be directed to a control device capable of achieving 98% destruction



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efficiency. It does not include a residual VOC limit covering uncontrolled vents.

Because the proposed residual VOC limit of 50 lb/MMlb of polymer is more stringent

than the Texas BACT guideline and the NSPS, the first criterion is met. The second

criterion is addressed by proposing the most stringent emission limit achieved in practice,

identified from the survey discussed above of PE manufacturing facilities. The proposed

VOC LAER is more stringent than the applicable standard promulgated under 40 CFR

part 60 and 61. In accordance with 25 Pa. Code §127.205(7), the proposed VOC LAER


5.7.2 Polyethylene Process, Storage, and Handling Vent PM/PM10/PM2.5 LAER/BACT Analysis

The proposed project is located in an area that is classified as nonattainment with the

annual PM2.5 standard. As a result, a LAER analysis is required for all of the project’s

PM2.5 sources. Because the PM2.5 that will be emitted from the PE process, storage, and

handling system vents will be filterable PM, the control technologies applicable to the

control of PM2.5 are the same as the controls applicable to PM and PM10. As a result, for

purposes of this analysis all forms of PM (i.e., PM, PM10, PM2.5) are referred to as “PM”

unless otherwise noted. It should be noted that no applicable PM standards have been

promulgated for PE storage and handling vents under 40 CFR parts 60 and 61.

5.7.2.1 Step 1: Identify PE Process, Storage, and Handling Vent PM Controls

A summary of the results from a survey of the recent permit precedents related to

process, storage, and handling vents at PE manufacturing facilities is presented in Table

5-39. As shown, all of the permits that were reviewed relied upon the use particulate

filters (i.e., fabric, sintered metal, or HEPA) to control PM emissions from these points of

emissions. In addition, all of the permit limits are written in terms of PM (i.e., not PM10

and/or PM2.5). The most stringent limits identified required the fabric filters (FF) to

achieve a grain loading of 0.01 gr/dscf.

If technology transfer from other types of PM emitting sources (i.e., controls applied to

different classes or categories of sources) is considered, the following additional PM



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controls would be potentially applicable: mechanical separation (i.e., cyclonic

separators), wet scrubbing, and electrostatic precipitators (ESP).

5.7.2.2 Step 2 – Eliminate Technically Infeasibility Controls

Emissions of PM from the PE manufacturing process fall into two categories: emergency

vents and continuous/intermittent process vents used as part of the polyethylene

manufacturing process. Emergency vents cannot be routed to filter type controls and will

instead vent through knockout/seal pots. Emergency events are infrequent and

unplanned, so these emergency pressure relieving vents are expected to be used rarely.

Because these vents are designed to rapidly release pressure from within a process unit,

controls such as particulate filters, ESPs, and wet scrubbers are not technically feasible

due to the backpressure imposed on the vent. As a result, the use of particulate filters,

ESPs, and wet scrubbers to control PM emissions associated with the control of

emergency events is not considered further by this analysis. The remainder of this

section discusses the feasibility of applying the identified controls to the continuous/

intermittent process vents used as part of the polyethylene manufacturing process,

including storage and handling operations.

As shown by the review of recent permits, particulate filters are used to control PM

emissions from polyethylene manufacturing process vents. As a result, the use of

particulate filters is considered technically feasible for application to these process vents

associated with the project’s PE manufacturing processes. Particulate filters have several

advantages when used for PM control including:

High particulate matter control efficiencies.

Relatively constant outlet grain loading over the entire boiler operating range.

Simple operation and maintenance.

The remaining control technologies identified via technology transfer from other sources

of PM such as coal and oil-fired boilers are discussed below.



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Table 5-39. Summary of Recent Determinations for Polyethylene Process Vents

RBLC ID

NO /State Facility Name Permit Date

Process

Description

Emissions Unit

Description

Control

Description

PM Limit a

(gr/dscf)

TX

103048

ExxonMobil

Chemical Company -

MBPP

10/07/13 Polyethylene Unit Process Vents Filter 0.01 b

TX

0631 draft

103832

final

Chevron Phillips

Chemical Company

LP

08/06/13

08/08/13

Polyethylene

Manufacturing Unit

Process Vents & Pellet

Handling & Product

Loadout

High Efficiency

Filters 0.01

LA

SASOL North

America

Lake Charles

Chemical Complex

04/30/13

PSD Permit

Application c

Low Density

Polyethylene

B207 & B208 vents

Pellet Elutriation Separator

Vents (2)

Fabric Filter 0.02

LA

SASOL North

America

Lake Charles

Chemical Complex

04/30/13

PSD Permit

Application

Linear Low

Density

Polyethylene

Catalyst Relief Vent

Continuous Catalyst Vent

Powder/Pellets Drop Points

Feeder Vent

Extruder Feed Vent

Pellet Transfer System

Pellet Blending System

Polymer Relief Drum

Pellet Dryer

Fabric Filter 0.02

a – gr/dscf = grains per dry standard cubic feet as PM. Vent specific limits for PM10 and PM2.5 were not required by these precedents.

b – Exxon Mont Belvieu PE Plant Permit 103048 Special Conditions, page 8, condition 14 (D)

c – Latest amendment to permit application dated 10/09/2013



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Electrostatic Precipitators (ESPs)

Electrostatic precipitators (ESP) are a common PM control system for heavy oil and solid

fuel-fired boilers, and for systems where the exhaust gases are too hot for fabric filter

materials (kilns). An ESP uses a large enclosure to slow the exhaust gas stream, allowing

more time to electrostatically charge particulates and collect them in the ESP. An ESP is

arranged in a series of fields that consist of negatively charged discharge electrodes and

positively charged collection plates. The discharge electrodes impart a negative charge to

particles in the gas stream. The negatively charged particles then migrate to the larger

positively charged plates. PM collected on the plates is periodically removed by rapping

the plate. Most of the PM knocked off the plates falls into collection hoppers for

removal. A portion of the collected PM is re-entrained in the gas stream during rapping.

This re-entrained PM is normally collected in subsequent sections of the ESP. ESP’s

may be located either upstream of the air heater (hot-side ESP) or downstream of the air

heater (cold-side ESP). The location is selected to achieve the best PM resistivity

conditions. Gas composition and temperature and particle composition all influence

resistivity, which is a measure of the ability of a particle to retain an electrostatic charge.

The ability to collect particles using electrostatic attraction is directly related to particle

resistivity. If the particle resistivity is outside the design range, particle collection

efficiency is reduced. Unlike particulate emissions from coal and oil fired sources, PE

particulate has a very high resistivity. This very high resistivity would result in a poor

ESP collection efficiency. In addition, the control of particulate from the multiple PE

manufacturing related vents requires a control technology that can be implemented at

several different locations. As a result, as is seen from the review of recent precedents,

the use of FF technology is favored because of both its ease in implementation and the

higher collection efficiency achieved. As a result the use of an ESP is not considered

further by this analysis.

Wet Scrubbers

Wet scrubbers are used in many industrial processes to control PM emissions,

particularly when the PM is sticky or when the exhaust gas is saturated with moisture.



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Wet scrubbers reduce PM emissions through several mechanisms, including

condensation, inertial impaction of PM with water droplets, and reactions of PM and PM

precursors with the scrubber reagent.

There are many types of wet scrubbers, namely, spray towers, packed towers, and venturi

scrubbers. All of these scrubbers have one principal in common, to contact the particles

in the flue gas with a liquid droplet. Once wetted or trapped inside a liquid droplet, the

particle can be separated from the flue gas and washed away with the liquid stream.

Spray tower scrubbers contact the flue gas with a liquid spray. The liquid spray is

generated either using spray nozzles or high speed rotating disks. Spray tower scrubbers

typically have high removal efficiencies for large particles and are less effective as the

particle size decreases. Spray tower scrubbers have relatively low energy costs

associated with liquid pumping and flue gas compression (fan energy).

Packed tower scrubbers counter currently contact the flue gas with a liquid cascading

down through packing. The packing is wetted with the liquid and the particles in the flue

gas are impacted on the wet packing as the flue gas flows through the packing. Packed

tower scrubbers typically have higher removal efficiencies for small particles than do

spray towers. However, packed towers are more easily plugged if the particle loading is

high and the particles are sticky in nature. Packed tower scrubbers have relatively low

energy costs associated with liquid pumping and moderate energy costs for flue gas

compression (fan energy). Packed tower scrubbers can have high costs for labor and lost

production associated with cleaning of the packing.

Venturi scrubbers contact the flue gas with a liquid by forcing the liquid and gas through

a small diameter pipe called a venturi throat. The compressed flue gas and liquid rapidly

mix in the throat causing the production of fine liquid droplets. After passing through the

venturi throat, the flue gas and liquid droplets are well mixed as they are rapidly

expanded in the expansion section of the venturi. Venturi scrubbers have a range of

removal efficiencies depending on the particle size and the amount of energy used to

compress the liquid and flue gas through the venturi throat. To effectively remove fine

particles and to achieve low particulate outlet concentrations, a high-energy venturi is



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required. High-energy venturi scrubbers have high energy costs associated with liquid

pumping and flue gas compression.

Wet scrubbers are typically only used when the exhaust gas is at the water saturation

temperature, the particulate matter is sticky or the flue gas temperature is too hot for

fabric filters. In the proposed plant, the pellet dryer vent is the only PM-containing vent

that is high in moisture content, where the use of wet scrubbing should be considered.

Mechanical Collectors

Mechanical collectors (cyclones) are not as effective as FFs for particulate matter control.

Mechanical collectors are typically used upstream of more effective control devices such

as FFs and ESPs when the PM loading is very high. This is not the case with the

proposed PE manufacturing vents. As a result, while mechanical collectors are a

technically feasible alternative, the performance of mechanical collectors is inferior to

FFs for the proposed service. Thus, FFs are favored for control of the PE manufacturing

vents due to the higher control efficiencies that can be achieved using FF versus

mechanical collectors. The use of mechanical collectors is not considered further by this

analysis.

5.7.2.3 Step 3 – Establish PE Manufacturing Process, Storage, and Handling Vent PM BACT/LAER Limits

A summary of the project’s proposed controls for the PE manufacturing process, storage,

and handling vents is presented in Table D-5 of Appendix D. A review of the limits

associated with PE manufacturing facilities indicates that 0.01 gr/dscf has been achieved

in practice. However, based on recent permit precedents in the State of Pennsylvania for

fabric filters, a grain loading of 0.005 gr/dscf is proposed for all particulate containing

vents.115 Particulate filter technology will be used where feasible.

115 PA Bulletin, Doc. No. 07-643c, April 14, 2007; PA Bulletin, Doc. No. 08-353a, March 1, 2008; and PA

Bulletin, Doc. No. 12-1311a, July 14, 2012.

http://www.pabulletin.com/secure/data/vol37/37-15/643c.html

http://www.pabulletin.com/secure/data/vol38/38-9/353a.html





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The proposed emission limits for the PE unit process vents must meet two criteria to be

considered LAER. With respect to the first criterion, a review was conducted of the

BACT guidelines for California agencies (BAAQMD, SJVAPCD, SCAQMD, and

CARB) and the Texas guidelines. The results from this review identified the two BACT

guidelines presented in Table 5-40. The proposed emission limit of 0.005 gr/dscf is more

stringent than the identified guideline limit of 0.01 gr/dscf. As a result, the first LAER

criterion is met. The second criterion has already been addressed by proposing a limit

that is more stringent than the most stringent emission limit achieved in practice,

identified from the survey of recent permit actions for PE manufacturing facilities.

Table 5-40. Summary of BACT Guidelines for Bay Area Air Quality Management

District and Texas Pertaining to Manufacturing Process Particulate Emissions

Agency Description Emission

Limit

Technology Reference

Bay Area Air

Quality

Management

District

Solid Material

Handling

(Conveying, Size

Reduction,

Classification) - Dry

<0.01 grains

per dry

standard cubic

feet

Baghouse Best Available

Control Technology

Guideline

(10/18/91)

Texas

Commission on

Environmental

Quality

Polyethylene

Facilities

<0.01 grains

per dry

standard cubic

feet

Baghouse

BACT Guidelines

for Chemical

Sources

The criteria for determining a BACT limit are somewhat different than the criteria for

determining a LAER limit. However, in the case of PM emissions from the PE process

vents, there is no difference in the limit. The proposed LAER limit of 0.005 gr/dscf is

based on the use of the most-effective, feasible PM control technology option and the

limit is the lowest that has been achieved in practice using that technology on this type of

source. In other words, the proposed LAER limit is consistent with the top-performing

control option in a top-down ranking of the feasible control options, which is the

appropriate basis for establishing a BACT limit.

As previously noted, no applicable PM standards have been promulgated for PE storage

and handling vents under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code



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§127.205(7), the proposed PM LAER limit is equivalent to and satisfies the PaBAT


5.8 VOC Emissions from Storage Tanks and Vessels

As described in Section 3.5.2, the proposed Project will include the following VOC –

containing storage tanks and vessels, as shown in Table 5-41. The pressurized storage

vessels (i.e., spheres or bullets) are not sources of VOC emissions and do not require any

LAER analysis. The LAER analysis for emissions that may occur as a result of

component leaks, including leaks in piping and equipment associated with these tanks, is

presented in Section 5.5. This section presents the LAER analysis for the outside

boundary limit (OSBL) tanks for pyrolysis tar, light gasoline, hexene, recovered oil, spent

caustic, diesel, and wastewater flow equalization. The LAER analysis for VOC-

containing tanks included as part of the wastewater treatment system is presented in

Section 5.10.

Emissions from tanks occur as a result of displacement of headspace vapor during filling

operations in the case of fixed roof or internal floating roof (IFR) tanks, or from tank rim

seals in the case of external floating roof (EFR) tanks (i.e., “working losses”). To a lesser

degree, diurnal temperature variations and solar heating cycles also result in emissions

from storage tanks (i.e., “breathing losses”).

5.8.1 Tank Emissions Control Technology Baseline

5.8.2 Step 1: Identify Tank VOC Control Options

Available VOC control options for organic liquid storage tanks include inherently less-

polluting processes, control equipment designed to minimize vapor leakage from the



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Table 5-41. Summary of Storage Tanks and Vessels in VOC Service

Service Tank/Vessel Description No. Equipment ID Capacity(m3)

Ethylene Spherical Pressure Vessel 2 V-64201,V-

64202

7,238

Ethylene Atmospheric Refrigerated Tank 1 T-64201 30,000

C3+ (propane/heavier hydrocarbons) Spherical Pressure Vessel 2 V-64205,V-

64206

2,300

Butene Spherical Pressure Vessel 2 V-64301,V-

64302

1,288

Isopentane Horizontal Pressure Vessel 2 V-64401,V-

64402

600

Isobutane Horizontal Pressure Vessel 2 V-64501,V-

64502

200

C3+ Refrigerant Horizontal Pressure Vessel 1 V-64203 300

Pyrolysis Tar Heated Fixed Roof Tank 1 T-64201 130

Light Gasoline Internal Floating Roof 2 T-64207,T-

64208

325

Hexene Internal Floating Roof 1 2 T-64301,T-

64302

2,300

Recovered Oil Storage Internal Floating Roof 1 T-59708 90

Equalization (Wastewater) 4 Internal Floating Roof 2 T-59707A,T-

59707B

2,810

Biotreater Aeration Tank 1 T-59709 5,210

Secondary Clarifier 4 Tank 2 T-59710A,T-

59710B 1,466

Biosludge (WAS) Holding 4 Tank 1 T-59711 43

Sand Filter Backwash Receiver 4 Tank 1 T-59713 143

Spent Caustic Internal Floating Roof 1 T-53501,T-

53502

900/8,630 2

Generator Diesel 3 Fixed Roof 4 T-58901A,T-

58901B,T-

38



5-183

Service Tank/Vessel Description No. Equipment ID Capacity(m3)

58901C,T-

58901D

Fire Pump Diesel 3 Fixed Roof 3 T-59101A,T-

59101B,T-

59101C

7

Locomotive Diesel Fixed Roof 1 T-4000 38

Dimethyl disulfide (DMDS) Drum 1 V-18831 25

1. Includes nitrogen blanketing.

2. Two spent caustic scenarios.

3. Emergency use internal combustion engines.

4. VOC LAER analysis included in WWTP (see Section 5.10)



5-184

tanks, end-of-pipe air pollution control equipment and combinations thereof. Specific,

identified options are as follows:

Route tank vapors to a process via hard piping, such that the vessel (i.e., tank)

operates with no emissions;

Fixed roof in combination with an internal floating roof including vapor

collection in a closed vent system routed to a control device (e.g., thermal

incinerator);

Fixed roof with vapor collection by a closed vent system routed to a control

device (e.g., thermal incinerator or carbon adsorber).

Fixed roof in combination with an internal floating roof; and

External floating roof.

It should be noted that many of the Project’s tanks use a fixed roof in combination with

an internal floating roof and an inert gas blanket that is inherent to the process and would

be applied even in the absence of air pollution control requirements.

The above identified tank control options are typically used for tanks larger than 75 cubic

meters (20,000 gallons). For smaller tanks, such as the diesel fuel tanks, carbon

adsorption and other absorption media can be used to capture VOCs. These systems are

effective for remote, low flow and low VOC emitting vents.

As noted in Section 4.0, there are several regulations potentially applicable to the

Project’s tanks, including, for tanks in organic compound service:

NSPS 40 CFR Part 60, subpart Kb,

NESHAP 40 CFR Part 63 subpart FFFF,

NESHAP 40 CFR Part 63 subpart WW,

25 Pa. Code § 129.56, and

25 Pa. Code §129.57.

These regulations serve as a baseline for the proposed LAER and will be met or exceeded

via compliance with the proposed LAER controls.

5.8.3 Step 2: Eliminate Technically Infeasible Tank VOC Controls

The most effective control option is to operate the tank with the vent directed to a

process, a fuel gas system, or a VOC control system (i.e, incinerator or flare). Routing a



5-185

tank’s vent gases to a process is feasible only for tanks that store liquids compatible with

the process.

For the pyrolysis tar storage tank, the use of an internal or external floating roof design is

considered to be technically infeasible due to: 1) the asphalt-like nature of the material

being stored; and 2) the storage temperature of approximately 300 °F.

All other identified control options are technically feasible for the other storage tanks.

5.8.4 Step 3: Establish Tank VOC LAER

The most stringent storage tank control options, in order of decreasing overall control

effectiveness, are presented below:

Control strategies that achieve nearly 100 percent VOC control.

o Route vapors to a process via hard piping, such that the vessel operates

with no emissions.

o Fixed roof in combination with internal floating roof and vapor collection

in a closed vent system routed to a thermal incinerator.

Control strategies that achieve nearly 98 to 99 percent VOC control.

o Fixed roof tank with vapor collection by a closed vent system routed to a

control device

o Fixed roof tank with internal floating roof and nitrogen blanketing.

Neither the pressurized storage vessels nor the ethylene atmospheric refrigerated tank

presented in Table 3-1 will vent to the atmosphere. If over pressured, these vessels and

tank will vent to one of the facility’s VOC control systems. The only emissions of VOC

from these vessels/tank will be from equipment leaks. The remaining tanks listed in

Table 3-1 will be controlled as follows:

The Light Gasoline and two Hexene tanks will be internal floating roof tanks and

vent to a vapor recovery system with a thermal incinerator as their primary form

of control. During upset events when the loading on the LP Flare Header is

greater than the incinerator’s capacity, the excess load will be directed to a LP

Ground Flare.

The flow equalization and oil removal (FEOR) and recovered oil storage tanks,

and spent caustic/unoxidized spent caustic tanks will vent to the Spent Caustic

Vent Incinerator.



5-186

The pyrolysis tar, diesel locomotive, emergency generator and firewater pump

diesel engine fuel tanks (each <20,000 gallons) will vented to carbon canisters.

The proposed emission limits or operating standards for the above tanks meet the two

criteria to be considered LAER. A survey was conducted to determine the most stringent

emission limit contained in a permit and achieved in practice or included in approved

implementation plan. The results of the survey are presented in Table 5-42. As shown,

the proposed emission standards are consistent with the most stringent limitations

associated with the Arizona Clean Fuels Project (AZ-0046),116 St. Charles Refinery (LA-

0213), and the BAAQMD BACT Guidelines. The most stringent limitation found in the

implementation plan for a state/agency is the BAAQMD BACT Guidelines. As a result,

the proposed emissions controls/limitations meet both of the LAER criteria. The

proposed VOC LAER for the Project’s are as stringent as the applicable standards under

40 CFR parts 60 and 61.

In accordance with 25 Pa. Code §127.205(7), the proposed VOC LAER limit is

equivalent to and satisfies the PaBAT requirements of 25 Pa. Code §127.12(a)(5). The

proposed LAER is also more stringent than the applicable NSPS and NESHAP

requirements for these tanks.

116 The Arizona Clean Fuels project was never constructed/operated, and as such the limitations associated

with this permit are not demonstrated.



5-187

Table 5-42. Summary of VOC BACT/LAER Precedents for Tanks

RBLC ID

No. Facility Name

Permit

Date

Process

Description Capacity Control Description Emission Limitation

AZ-0046 Arizona Clean

Fuels Yuma 04/14/05

Petroleum Refinery

Group A Storage

Tanks

1.51 to 3.78

million

gallons

Emissions must be collected by

vapor compression system &

routed to the refinery fuel gas.

None specified


Fuels Yuma 04/14/05

Petroleum Refinery

Group D Storage

Tanks

850,000

gallons

The tanks are required to be

under pressure so that no

emissions are emitted to the

atmosphere

None specified


Fuels Yuma 04/14/05

Petroleum Refinery

Group B Storage

Tanks

378,000 to

7,560,000

gallons

Internal Floating Roofs with

headspace routed to the tank

farm thermal oxidizer

99.9% design destruction

efficiency & 20 ppmv limit when

inlet conc.to thermal oxidizer

<20,000 ppmv

IA-0096 Verasun Charles

City, LLC

11/18/08

Hexane Storage Tanks

30,000

gallons

Internal Floating Roof

NSPS Kb & NESHAP EEEE

LA-0213

Valero Refining

St. Charles

Refinery

11/17/09

Tanks - For Benzene,

Xylene, Sulfolane,

Parex, Intermediate

Not

specified

Equipped with internal floating

roofs followed by thermal

oxidizers

Not specified

TX -0631

ChevronPhillips

Chemical Cedar

Bayou Plant

08/06/13

Internal floating roof

tanks with VOC

partial pressure >0.5

psia 1

> 25,000

gallons 1

Tank VOC emissions will be

controlled by internal floating

roof tanks.

Internal floating roof: (1) a liquid-

mounted seal, (2) two continuous

seals mounted one above the other,

or (3) a mechanical shoe seal. 1

BAAQMD BACT

Guidelines 03/03/95

Storage Tank - Fixed

Roof, Organic Liquids

> 20,000

gallons

Vapor recovery system: Thermal

Incinerator; or Carbon Adsorber;

or Refrigerated Condenser

Overall system efficiency >98%

BAAQMD BACT

Guidelines 03/03/95

Storage Tank - Fixed

Roof, Organic Liquids

< 20,000

gallons

Vapor recovery system: Vapor

Balance; or Carbon Adsorber; or

Refrigerated Condenser; or

Incinerator

Overall system efficiency >95%

Special Conditions Permit Number 103832, N166; August 8, 2013. Note, this project subject to non-attainment review for VOC per Polyethylene Production

Units Initial Permit Application; June 21, 2012.



5-188

5.9 PM and VOC Emissions from Cooling Towers

Two counter-flow mechanical draft cooling water towers (CWT) will be constructed at

the site to provide cooling water. A twenty-six (26) cell recirculating water tower will be

used to provide cooling water for the process units and another four (4) cell recirculating

water tower will support the Cogeneration Plant.

Evaporative cooling towers are designed to cool water by contacting the water with air

and evaporating some of the water. Thus, these units use the latent heat of water

vaporization to exchange heat between the process and the air passing through the tower.

This type of cooling tower typically contains a wetted medium to promote evaporation,

by providing a large surface area and/or by creating many water drops with a large

cumulative surface area.

Measurement of the PM and VOC emissions from a cooling tower is impractical, because

of difficulties in obtaining a representative sample. There is currently no EPA Reference

Method for sampling the exhaust from forced draft cooling towers. As a result,

equipment specifications and operating practices are used to control PM and VOC

emissions. No applicable PM or VOC standards have been promulgated for cooling

towers under 40 CFR parts 60 and 61.

5.9.1 Cooling Tower PM/PM10/PM2.5 BACT/LAER Analysis

As part of a cooling tower’s operation, some of the liquid water is entrained in the air

stream and is carried out of the tower. PM, PM10, and PM2.5 (PM) emissions from a

cooling tower can be generated by the dissolved solids within the water droplets (drift)

that escape the tower. The PM is generated when escaped droplets evaporate and the

dissolved solids are left behind. The concentration of total dissolved solids (TDS) in

cooling water varies widely and is site dependent. For a given solids concentration

(defined by the cooling water source, tower design and operating specifications), PM

emissions from cooling towers depend on the amount of water that drifts from the tower.

Drift eliminators of various types are used to control the amount of total liquid drift.

Directional changes through a structured media result in the inertial separation of water

droplets (mist) from the air stream.



5-189

This section addresses the control of PM, PM10, and PM2.5 emissions from the project’s

two cooling towers. The proposed project is located in an area that is classified as

nonattainment with regard to the annual PM2.5 standard. As a result, a LAER analysis is

required for all of the project’s sources of PM2.5. The PM2.5 that will be emitted from

operation of the cooling towers will be filterable PM. As a result, the control

technologies applicable to the control of PM2.5 are the same as the technologies for PM

and PM10. Thus, there is no need to distinguish between the various PM species and

throughout this LAER analysis all forms of PM are referred to as “PM”. It is assumed

that the LAER analysis will meet the requirements of BACT for PM10 and PM.

5.9.1.1 Step 1: Identify Potential Cooling Tower PM Controls

A summary of the cooling tower PM permitting precedents in the USEPA’s RBLC

database for the last ten years is presented in Table 5-43. As shown, two PM control

options were identified for cooling towers: use of mist/drift eliminators and limits on the

level of total dissolved solids (TDS) in the circulating water. Another potential cooling

water approach not identified in the RBLC is the use of dry cooling.


Drift eliminators and the use of TDS limits are both controls that have been demonstrated

in the past and as a result are considered to be technically feasible for purposes of this

analysis.

Dry cooling uses an air cooled heat exchanger or a dry cooling tower that operates by

transferring the heat in the process cooling water through a surface such as in a tube to air

heat exchanger, utilizing convective heat transfer. Although air cooling and dry cooling

towers inherently generate less PM compared to a wet cooling tower, air coolers and dry

cooling towers are not technically feasible cooling options for the proposed Project. At

the ethylene manufacturing unit and PE units, there are process streams that must be

cooled to 130°F or less. At times during the summer, ambient air temperatures are high

enough that these streams cannot be cooled by using air alone.



5-190

Table 5-43. RBLC Summary of Cooling Tower Emission Limits for PM

RBLC ID

No. FACILITY NAME

Permit

Date

Capacity

(gpm) Control

Limit

(wt% of total

circulating rate)

Other Emission

Limit

FL-0299 Crystal River Power Plant 10/12/2007 342,306 Not specified 0.0005 None

IA-0088 ADM Corn Processing -

Cedar Rapids 06/29/2007 150,000 Drift Eliminators 0.0005 None

IA-0089 Homeland Energy Solutions,

LLC, PN 06-672 08/08/2007 50,000 Drift Eliminator / Demister 0.0005 None

IA-0095 Tate & Lyle Ingredients

Americas 09/19/2008

Not

specified Drift Eliminators 0.0005 None

ID-0017 Power County Advanced

Energy Center 02/10/2009 121,000 Drift/Mist Eliminators 0.0005 1.5 lb/hr

WI-0252 Specialty Minerals Inc. -

Superior 07/22/2011 200

High Efficiency Mist / Drift

Eliminators (W/ Additional

Layer); Dissolved Solids

Limit

0.0005 None

IA-0067 Walter Scott Jr. Energy

Center 06/17/2003 349,400 Mist Eliminators 0.001 None

ID-0017 Power County Advanced

Energy Center 02/10/2009 985 Drift/Mist Eliminators 0.001 0.3 lb/hr

MD-0032 Dickerson 11/05/2004 10 cells Mist Eliminators 0.001 None

IL-0102 Aventine Renewable Energy,

Inc. 11/01/2005

Not

specified Drift Eliminator 0.005 6.85 tpy

MN-0070 Minnesota Steel Industries,

LLC 09/07/2007

Not

specified Designed to Minimize Drift 0.005 None

NE-0029 Abengoa Bioenergy

Corporation - York 01/21/2004

Not

specified Not Specified 0.005

3600 ppm per

sample

2400 ppm per 12

consecutive months

AR-0100 Lion Oil Company 10/01/2007 19,977 Drift Eliminators 0.005 3000 mg/l

PA1 River Hill Power Company, 7/21/2005 140,000 Drift Eliminators 0.0005 5000 ppm



5-191

RBLC ID

No. FACILITY NAME

Permit

Date

Capacity

(gpm) Control

Limit

(wt% of total

circulating rate)

Other Emission

Limit

LLC

PA2 Robinson Power Co., LLC 6/30/2011 Not

specified Designed to Minimize Drift 0.0005 None

PA3 Hickory Run Energy, LLC 4/23/2013 175,000 Not Specified 0.0005 5000 ppm

1. PA Bulletin, Doc. No. 05-946b

2. PA Bulletin, Doc. No. 11-973

3. Plan Approval Number 37-337A issued April 23, 2013

http://www.pabulletin.com/secure/data/vol35/35-20/946b.html

http://www.google.com/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=7&cad=rja&uact=8&ved=0CEQQFjAG&url=http%3A%2F%2Fwww.pabulletin.com%2Fsecure%2Fdata%2Fvol41%2F41-24%2F973.html&ei=voExU7fUF-Ss0AHhg4DQCg&usg=AFQjCNGCNpiY9KXLIxsnOgKnLnmwp-SFRg



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At the Cogen Units, a water-cooled condensing steam turbine generator will be used.

The use of an air-cooled condensing steam turbine generator would result in significantly

lower power generation and increased air emissions. Air-cooled steam condensers are

installed in only 1% of U.S. steam electric generating plants. While they utilize less

water, the use of dry cooling systems can result in up to a 10% power production penalty

on hot days, and up to five times higher capital costs compared to a recirculating cooling

tower and water-cooled surface condenser systems. Large fans are used to circulate air

past the finned-condenser tubes. Besides the cost and the power production penalty,

other drawbacks of air-cooled condensers are the large footprint of the condenser and the

typical dimensions, including the fan size.117

The use of dry/air cooling for all process cooling and for power generation would result

in redefining the project.

5.9.1.3 Steps 3: Establish Cooling Tower PM BACT/LAER

As shown in Table 5-43, mist/drift eliminators combined with TDS limits are used to

control/limit PM emissions from cooling towers. The limits for drift losses range from

0.005 to 0.0005 weight percent of the total circulating water rate and the TDS limits

range from 2400 to 3600 ppm based on averaging time. Based on these prior precedents,

the following PM BACT/LAER limit for the cooling towers is proposed:

Use of mist/drift eliminators designed to achieve a drift rate of 0.0005%

TDS limits of 2400 ppm averaged over 12 consecutive months

The proposed emission limits or operating standards for the cooling towers must meet

two criteria to be considered LAER. To fulfill the first criterion, a survey of emissions

limits contained in state implementation plans for those states most likely to have the

most stringent emission limits was performed. The results of this survey found only two

117 NSF/EPRI Collaboration on "Water for Energy"- Advanced Dry Cooling for Power Plants.

http://www.nsf.gov/pubs/2013/nsf13564/nsf13564.htm



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agencies that included specific cooling tower PM control requirements in their

implementation plans:

The Texas Commission on Environmental Quality (TCEQ) has a BACT guideline

requiring:118

o drift eliminators, and

o drift < 0.001%.

The Maricopa County Arizona Air Quality Department Regulations require:119

o Drift eliminators not made out of wood,

o Concentration of Total Dissolved Solids multiplied by the percentage of drift not

to exceed 20.

The search included other agencies for which guidelines or rules could not be found:

South Coast Air Quality Management District (SCAQMD),

Bay Area Air Quality Management District (BAAQMD);

San Joaquin Valley Air Pollution Control District,

California Air Resource Board (CARB) permit determinations;

New Jersey State of the Art Manuals; and

Clark County Nevada Department of Air Quality.

The survey of emissions limits contained in state implementation plans for those states

most likely to have the most stringent emission limits demonstrated that the proposed

cooling tower PM limits are more stringent than Texas and Maricopa County

limits/regulation. Note that when the proposed drift rate of 0.0005% is multiplied by the

proposed TDS limit of 3600, the value obtained is 1.8, which is significantly below the

Maricopa County rule value of 20. As a result, the proposed cooling tower limits meet

the first criterion for LAER.

118 TCEQ Chemical Sources, Current Best Available Control Technology (BACT) Requirements, Cooling

Towers; last revision 08/01/2011.

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_cooltow.

pdf 119 Maricopa County Air Pollution Control Regulations, September 2013, Section 300-Standards, 301

Limitations-Particulate Matter, Rule 301.4 Cooling Towers.

http://www.maricopa.gov/aq/divisions/planning_analysis/rules/docs/MCAQD%20Rules.pdf



5-194

The second criterion is addressed by the proposal of the most stringent drift loss and TDS

concentration requirements identified via the survey of past precedents. As previously

noted, no PM standards have been promulgated for cooling towers under 40 CFR parts 60

and 61. In accordance with 25 Pa. Code §127.205(7), the proposed PM BACT/LAER


5.9.2 Cooling Tower VOC LAER

When water from a cooling tower is used to cool streams containing VOCs, leaks can

occur in the heat exchanger tubes allowing VOCs to leak into the cooling water stream if

the stream containing the VOC is at higher pressure than the cooling water. The VOCs

that leak into the cooling water get stripped out of the cooling water when it returns to the

cooling tower and is contacted with air. The cooling water at the Cogen Units will be

separate from the process cooling water, so there is no potential for VOC emissions from

the Cogen cooling tower.

5.9.2.1 Step 1: Identify Cooling Tower VOC Limits

A summary of the cooling tower PM permitting precedents in the USEPA’s RBLC

database for the last ten years is presented in Table 5-44. As shown, one control option

was identified for the control of VOC emissions from cooling towers: monitoring of

VOC content in the cooling water with repair of leaking heat exchangers. Another

cooling water approach not identified in the RBLC is the potential use of dry cooling.


As noted above, only one of the cooling water towers will be used to cool water that has

the potential to come in contact with hydrocarbon. The Cogen cooling tower will have

no source of hydrocarbon contamination. As result, only the Process Unit cooling tower

is considered further as part of this VOC analysis.

To minimize leaks of VOC containing process fluids into cooling water, a heat exchanger

leak detection and repair program is technically feasible and effective. This program

involves monitoring cooling water for the presence of hydrocarbons, finding and

repairing leaks. In some instances, suitable control may include installation of



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Table 5-44. RBLC Summary of Cooling Tower Emission Limits for VOC

RBLC

ID No. Facility Name Facility Type

Permit

Date

Capacity

(gpm) Control

Emission Limit

(lb/MMgal)

WI-

0204

United

Wisconsin

Grain

Producers

Fuel Grade Ethanol

Plant

(cooling tower P80)

08/14/2003 22,000

124 ppm VOCs

(synthetic minor permit for

VOCs)

0.076

Calculated from 0.1

lb/hr emission rate 1

WI-

0207

Ace Ethanol -

Stanley Ethanol Plant 01/21/2004 20,000 300 ppm VOCs

0.125

Calculated 2

OH-

0256

Lima

Chemicals

Complex

Manufacture of

butanediol &

tetrahydrofuran,

butyrolactone,

butanol, &

maleic anhydride

07/10/2003 20,000 LDAR Program 0.175

from permit

LA-

0211

Garyville

Refinery Petroleum Refinery 12/27/2006

30,000

96,250

2,500

"Monitoring Process Side of the

Heat Exchangers for Leaks

2008-35: VOC Monitoring

Program Meets 40 CFR 63

Subpart F"

0.5

Calculated from

4.14 lb/hr

OH-

0308

Sun Company

Toledo

Refinery

Petroleum Refinery 02/23/2009 2,000 Not Specified 0.7

from permit

TX-

0575

Sabina

Petrochemicals

LLC

C4 Olefins Complex

(Manufacture of 1,

3-butadiene &

mixed iso-octanes) 3

08/20/2010 73,000

Cooling Tower has non-contact

design, utilizes weekly

monitoring of VOC in water per

Appendix P or approved

equivalent & identified leaks

repaired as soon as possible, but

before next scheduled shutdown

0.7

Calculated 5



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RBLC

ID No. Facility Name Facility Type

Permit

Date

Capacity

(gpm) Control

Emission Limit

(lb/MMgal) 4

LA-

0246

St. Charles

Refinery Petroleum Refinery 12/31/2010

61,250

45,000

50,000

40,000

Monitoring VOC concentration

in cooling water

20.7

Calculated 6

1. This permit limit found in RBLC could not be confirmed. Construction permits only have the following permit condition for P80: (2) The cooling water

additives may not contain significant VOCs. As such, this listing is not considered further.

2. From permit 03-DCF-184 Source F06, 0.15 pounds per hour of VOC for 20,000 gpm cooling tower (0.125 = 0.15 lb/hr / 60 min/hr / 20,000 gpm* 10^6

gal/MMgal).

3. A leak is detected if the exit mean concentration is found to be greater than the entrance mean using a one-sided statistical procedure at the 0.05 level of

significance and the amount by which it is greater is at least 1 part per million or 10 percent of the entrance mean, whichever is greater. 40 CFR 63.104

(b)(6).

4. From Texas permits 41945, PSD-TX-950, and N-018; July 7, 2011. Weekly monitoring of the cooling water is required, not monthly as listed in RBLC.

5. Calculated by using 13.43 tpy VOC limit and 73,000 gpm flow rate as follows: 13.43 tpy * 2000 lb/ton / 8760 hrs/yr / 60 min/hr / 73,000 gpm * 10^6

gal/MMgal.

6. Calculated using gpm and the following cooling tower lb/hr limits: 76, 55.84, 62.04, and 49.63, respectively.



5-197

hydrocarbon detectors or sampling points in the exit water downstream of the exchanger

to identify leaks. This control measure also includes a systematic inspection, preventive

maintenance, and repair programs to avoid leakage. This latter function can include

routine replacement of seals, exchanger cleaning, and pressure testing of exchanger

vessels. This control technique is technically feasible for the Project’s Process Unit

cooling tower.

The use of dry cooling is eliminated based on the same technical logic stated in

Section 5.9.1 above for the PM BACT/LAER analysis.

5.9.2.3 Steps 3: Establish Cooling Tower VOC LAER

Some operations within the proposed project’s process units will need cooling water to

achieve the required process temperatures. Wherever possible, the proposed process

units will be designed/operated to maximize the recovery of heat for process use (e.g.,

steam generation) to maximize the project’s thermal efficiency, and minimize the

project’s demand for cooling water. In addition, based on the precedents listed in Table

5-44, a cooling water heat exchanger leak detection and repair program consistent with

40 CFR §63.104, except that weekly monitoring will be conducted instead of

monthly/quarterly as required by 40 CFR §63.104, consistent with Texas permit PSD-

TX-950 (RBLC ID TX-0575) is proposed. Based on the prior precedents, a VOC

emission limit of 0.5 pounds per million gallons of cooling water circulation is proposed

as VOC LAER for the cooling towers. The lower determinations found in RBLC (WI-

0207 and OH-0256) are rejected as LAER because these determinations are not for large

systems similar to that being proposed for the Project.

The proposed emission limits or operating standards for the cooling towers must meet

two criteria to be considered LAER. To fulfill the first criterion, a survey of emissions

limits contained in state implementation plans for those states most likely to have the

most stringent emission limits was performed. The results of this survey found only one

agency with a specific cooling tower VOC control requirement in its implementation plan

as follows.



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The Texas Commission on Environmental Quality (TCEQ) has a BACT guideline

requirement of:120

o Non-contact design, and

o Monthly monitoring of VOC in water per Appendix P or approved equivalent

– assume all VOC stripped out.

o Repair identified leaks as soon as possible, but before next scheduled

shutdown, or shutdown triggered by 0.08 ppmw cooling water VOC

concentration.

Conversion of TCEQ’s 0.08 ppmw cooling water VOC content limit gives a VOC pound

per million gallons of water of 0.7.121 This rate is higher than that proposed for the

Project.

Other agencies searched for which guidelines or rules could not be found include:

South Coast Air Quality Management District (SCAQMD),

Bay Area Air Quality Management District (BAAQMD);

San Joaquin Valley Air Pollution Control District,

California Air Resource Board (CARB) permit determinations;

New Jersey State of the Art Manuals;

Louisiana Department of Environmental Quality;

The Maricopa County Arizona Air Quality Department; and

Clark County Nevada Department of Air Quality.

The survey of emissions limits contained in state implementation plans for those states

most likely to have the most stringent emission limits demonstrate that the proposed

cooling tower VOC limits are more stringent than the Texas limits/regulations.

The second criterion is addressed above through the proposal of the most stringent limits

identified via the survey of past precedents. As previously noted, no VOC standards have

120 TCEQ Chemical Sources, Current Best Available Control Technology (BACT) Requirements, Cooling

Towers; last revision 08/01/2011.

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/bact/bact_cooltow.

pdf 121 0.08 ppmw /1,000,000 parts/million * 1,000,000 gallons *8.32 pounds/gallon of water = 0.665 lb

VOC/million gallons.



5-199

been promulgated for cooling towers under 40 CFR parts 60 and 61. In accordance with

25 Pa. Code §127.205(7), the proposed VOC LAER limit is equivalent to and satisfies

the PaBAT requirements of 25 Pa. Code §127.12(a)(5).

5.10 VOC Emissions from Wastewater Treatment Plant

5.10.1 VOC LAER Analysis

The Wastewater Treatment Plant (WWTP) will consist of primary flow equalization and

oil removal, followed by a secondary activated sludge bioreactor (including clarifiers)

and a tertiary sand filter to treat the wastewater streams from process units and potentially

contaminated storm water runoff from process paved areas. A more detailed description

of the WWTP is presented in Section 3.5.6. The NSPS Subpart Kb standards are

applicable to the WWTP’s recovered oil storage and flow equalization tanks.

5.10.1.1 Step 1: Identify WWTP VOC Controls

Table 5-45 presents a summary of the recent precedents/permit determinations for

wastewater treatment plants VOC emissions and controls. The review included an

examination of the following information sources:

EPA’s RACT/BACT/LAER Clearinghouse

SCAQMD BACT Guidelines

BAAQMD BACT/TBACT WORKBOOK

CA and TX RACT

Based on this review, WWTP tanks and equipment located upstream of activated sludge

biological treatment that are designed to store or treat influent wastewater containing



5-200

Table 5-45. RBLC Summary of VOC RACT/BACT/LAER Precedent for Wastewater Treatment

RBLC ID

No. Facility Name

Permit

Date

Process

Description Capacity Control Description VOC Limit

VOC Limit

Units

IA-0088 ADM

Cedar Rapids, IA 6/29/07

WWTP Aeration

Tank 1.5 MGD None 20

ppmvd avg. of 3

test runs

IA-0088 ADM

Cedar Rapids, IA 6/29/07

WWTP Anaerobic

Digester

1500 SCFM of

Biogas Enclosed Flare

98 % reduction avg. of

3 test runs

0.36 lb/hr avg. of 3 test

runs

TX-0354

ATOFINA

Chemicals

Jefferson County,

TX

12/19/02 WWTP Not specified

Emissions from any VOC Water Separation

Equipment Shall Be Vented to a Permitted

Control Device or Recycled to the Process.

0.12 lb/h

0.5 TPY

SCAQMD Sunoco Chemicals

Philadelphia, PA 7/27/99

WWT system at

chemical plant.

VOC-contaminated

water air stripped of

VOC.

Approx. 6000

scfm (510 gpm

water to

stripper)

Wastewater is required to be air-stripped with

stripper vented to thermal oxidizer with

minimum 95% destruction efficiency.

95 % destruction

efficiency

BAAQMD

Best Available

Control

Technology

(BACT) Guideline

6/2/95

Sewage Treatment

Plant - Headworks

and Primary

Treatment

N/A

Process modifications (e.g., turbulence

reduction), and covers with vapor phase

controls (process air recycle, odor control

equipment, activated carbon or alumina

systems, biofilters). None

[Technologically

Feasible/ Cost

Effective]

Industrial source control, packed scrubber for

odor control at headworks, and fixed covers

for primary clarifiers.

[Achieved in

Practice]

BAAQMD

Best Available

Control

Technology

(BACT) Guideline

6/2/95

Sewage Treatment

Plant - High Purity

Oxygen Activated

Sludge

N/A

Vapor phase controls (odor control equipment,

activated carbon or alumina systems, or

combustion abatement

device) None

[Technologically

Feasible/ Cost

Effective]

Industrial source control. [Achieved in

Practice]

BAAQMD

Best Available

Control

Technology

(BACT) Guideline

10/4/91 Water Treating -

Oil/Water Separator >250 Gal/min

Vapor-tight fixed cover and vented to vapor

recovery system

w/ combined collection and

destruction/recovery efficiency of >95%

None [Achieved in

Practice]



5-201

RBLC ID

No. Facility Name

Permit

Date

Process

Description Capacity Control Description VOC Limit

VOC Limit

Units

TN-0039 OSCO Treatment

Systems, INC. 6/12/90

Wastewater

Treatment Plant 0.325 MGD

Thermal Incinerator - 99% Efficient, Caustic.

Scrub.-95% Efficient 4.3 lb/hr

OH-0153 Hilton Davis Co. 7/22/87 Wastewater

Treatment System 4.5 MGD

Thermal Incinerator, Covers (Est. Efficiency

95%) 17.8 TPY



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significant concentrations of VOC are equipped with a closed vent system, where the

vapors are routed to one of the following types of control devices:

Combustion device with VOC destruction efficiency up to 99%

Activated carbon system

Alumina system

Biofilter

Packed scrubber

The VOC removal efficiencies of activated carbon and alumina systems, biofilters and

packed scrubbers vary considerably depending on the organic compound being removed.

According to Section 7.1 of EPA’s AP-42, activated carbon systems typically remove up

to 98% of the VOC from a petroleum tank vent.

5.10.1.2 Step 2: Eliminate Technically Infeasible WWTP VOC Control Options

Each of the precedents identified in Table 5-45 were reviewed to determine their

applicability to the proposed WWTP. This review is summarized below.

ADM. This precedent is for an Anaerobic Digester with vapors routed to an enclosed

flare. The proposed Shell WWTP will not be equipped with an anaerobic digester. As

such, this precedent is not applicable.

ATOFINA. This permit states: “Emissions from any VOC Water Separation Equipment

shall be vented to a permitted control device or recycled to the process.” The ATOFINA

emission controls are applicable only to the VOC/wastewater separation system. At the

proposed Shell WWTP, the flow equalization and oil removal (FEOR) tanks comprise the

VOC/wastewater separation system. As such, this precedent is partially applicable, and

applies only to those tanks.

SUNOCO. According to the SCAQMD summary, “Wastewater is required to be air-

stripped with stripper vented to thermal oxidizer with minimum 95% destruction

efficiency.” The proposed Shell WWTP will treat both stormwater and oily wastewater.

Oils and other hydrocarbons will be removed in FEOR tanks designed for flow

equalization and oil removal, and these tanks will be equipped with both IFRs and with a

system designed to collect VOCs and route them to a combustion device with a minimum

99% destruction removal efficiency. For the proposed project, it does not make process

sense to use an air stripper rather than the proposed system to remove VOCs from either

oily wastewater, or from stormwater, which has a widely varying flow rate. As such, this

precedent is not applicable.



5-203

BAAQMD. BACT for Sewage Treatment Plant: Headworks and Primary Treatment.

This precedent is partially applicable to the proposed WWTP, in which process

wastewater will be hard-piped from certain process units to the FEOR Tanks. These two

tanks can be classified as Primary Treatment (there will be no headworks at the proposed

facility).

BAAQMD. BACT for Sewage Treatment Plant: High Purity Oxygen Activated Sludge.

The Shell WWTP will not be equipped with High Purity Oxygen Activated Sludge. As

such, this precedent is not applicable.

BAAQMD. BACT for Water Treating: Oil/Water Separator. BAAQMD specifies as

BACT that the oil-water separator be covered with a vapor control system and vapors

routed to an emission control device. This precedent is partially applicable to the

proposed WWTP, in which process wastewater will be hard-piped from certain process

units to the FEOR Tanks which will be equipped with IFRs and a vapor control system

routed to emission control device. These tanks can be classified as Oil/Water Separators.

OSCO. The RBLC entry states: ”All incoming storage and treatment tanks are covered

and vented to a control system consisting of a thermal incinerator followed by a caustic

scrubber. The emission limit shown above does not include other fugitive emissions

from the facility.” At the proposed Shell WWTP, the flow equalization and oil removal

(FEOR) tanks comprise the incoming storage and treatment tanks. As such, this

precedent is partially applicable, and applies only to those tanks.

Hilton Davis. WWTP with thermal incinerator and covers with an estimated efficiency

of 95%. The RBLC data indicate that the process to which these controls apply are the

water system and wastewater tank. The proposed Shell project’s wastewater tanks are the

FEOR tanks, equipped with IFRs and a vapor control system routed to an emission

control device. As such, this precedent is partially applicable, and applies only to those

tanks.

Based on these precedents, add-on controls are considered to be technically feasible for

the proposed Flow Equalization and Oil Removal Tanks. No add-on controls were

identified as being feasible and applicable to the WWTP equipment located downstream

of the FEOR Tanks (i.e., Biotreater Aeration Tank, two Secondary Clarifiers, Biosludge

Holding Tank, Biosludge Dewatering Tank, Centrate Sump, Sand Filter, Sand Filter

Backwash Receiver and Outfall).



5-204

5.10.1.3 Step 3: Establish WWTP VOC LAER

For the Flow Equalization and Oil Removal (FEOR) Tanks,122 the most stringent level of

VOC control identified equipping the tanks with a closed vent system and routing the

collected vapors to a combustion device with a VOC destruction efficiency of 99% or

greater. This is the control identified for the proposed FEOR tanks.

As LAER for the proposed wastewater treatment plant units, the following limit is

proposed for VOC:

The two (2) Flow Equalization and Oil Removal Tanks (T-5307A/B) shall be

equipped with a closed vent system that routes collected vapors to a combustion

device with a design VOC destruction efficiency of 99% or greater.

Compliance with this limit shall be determined by testing the combustion device

during normal operation in accordance with a test protocol approved by PADEP.

It should be noted that the site will also operate in compliance with the applicable HAP

control requirements in the Miscellaneous Organic NESHAP or MON (40 CFR 63

Subpart FFFF) and Ethylene MACT (40 CFR 63 Subpart XX). The MON provides

multiple control options for various types of emission points, including process

wastewater and maintenance wastewater streams that contain listed HAPs, when those

streams exit the last recovery device or chemical manufacturing process unit equipment.

The proposed emission limits or operating standards for the above WWTP meet the two

criteria to be considered LAER.

The precedents presented in Table 5-45 represent a composite of the most stringent

emission limitation contained in the implementation plan and the most stringent emission

limitation achieved in practice, for the class or category of source. As a result, both

criteria have been met. The proposed controls are as stringent as the NSPS Part 60

subpart Kb standard. In accordance with 25 Pa. Code §127.205(7), the proposed VOC

122 Oil skimmed from these tanks is directed to the Recovered Oil Tank. VOC controls for this tank are

discussed in Section 5.8.



5-205

LAER limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code

§127.12(a)(5).

5.11 Loading Operations

The proposed project includes facilities that will be used to offload of materials used to

support the operation of the facility and loading of products generated by the facility.

Emissions associated with offloading will result from the displacement of gases in the

tanks used to store those materials and from leaks in fugitive components associated with

the offloading facilities. A VOC LAER analysis for each of these emissions points in

included in Sections 5.8 and 5.5, respectively. Particulate emissions will result from the

loading of PE pellets into railcars and truck. VOC emissions will result from the loading

of low vapor pressure organic liquids (i.e., pyrolysis tar, recovered oil, and spent caustic)

and C3+ materials. A PM BACT/LAER analysis for the PE pellet loading operation and

VOC LAER analysis for the low vapor pressure organic liquids and C3+ liquids is

presented below.

5.11.1 Polyethylene Loading PM/PM10/PM2.5 BACT/LAER Analysis

The primary end product of the proposed Project is polyethylene (PE) pellets. PE pellets

will be shipped from the facility via both truck and rail. Loading will be accomplished

by gravimetric feed through a chute that delivers the material into the truck or railcar.

Loading of PE pellets into transport vehicles could result in emissions of particulate

matter as the pellets flow by gravity from the storage loading silos into the trucks or rail

cars. Displaced air in the empty transport vehicles can entrain some of the dust present in

the pellets, creating the potential for particulate matter emissions from the loading

operations. The displaced air resulting from the loading operations will be vented

through a filter to prevent emissions of any particulate matter that may be entrained in the

air.

This section addresses the control of PM, PM10, and PM2.5 emissions from the PE loading

operations. The proposed project is located in an area that is classified as nonattainment

with regards to the annual PM2.5 standard. As a result, a LAER analysis is required for



5-206

all of the project’s sources of PM2.5. No applicable PM standards have been promulgated

for PE Loading operations under 40 CFR parts 60 and 61.

The PM2.5 that will be emitted from the PE loading operation will be filterable PM. As a

result, the control technologies applicable to the control of PM2.5 are the same as the

technologies available for controlling emissions of PM and PM10. For purposes of this

analysis, it is assumed that the PM2.5 LAER analysis will meet the requirements of BACT

for PM10 and PM. 123 Application of LAER is estimated to limit annual loadout

particulate emissions to less than 0.1 tons/yr.

5.11.1.1 Step 1: Identify PE Loading PM Controls

The only PM control option identified for application to the PE truck and rail car loading

operations is routing of the displaced air through a filter that would remove entrained

particulate matter from the air stream. The only similar emissions source identified

through a search of U.S. EPA’s RBLC database is the PE loading operation at the

Chevron Phillips polyethylene plant that will be located in Sweeny, Texas (RBLC ID

TX-0631). The BACT emissions limit applicable to the Chevron Phillips railcar loading

operation is 0.01 gr/scf.


Venting of the PE pellet loading operations through a filter is a feasible control option.

For PE loading, this control is typically accomplished by installing a filter on an open

hatch on the vehicle being loaded such that the displaced air vents through the filter. This

control method provides a high level of capture and control of any entrained particulate

matter generated by the loading operation and is technically feasible for application to the

PE loading operations at the proposed Project.

123 This assumption is appropriate given the low level of emissions that result from application of a LAER

limit to this source.



5-207

5.11.1.3 Step 3: Establish PE Loading PM BACT/LAER

The proposed emission limits or operating standards for the PE pellet loading operation

meet the two criteria to be considered LAER. To address the first criterion, a survey was

conducted of particulate matter emissions limits contained in state implementation plans

for those jurisdictions most likely to have the most stringent emission limits was

performed (i.e., air rules applicable to serious PM10 nonattainment areas).124 The results

of this review, summarized in Table 5-46, indicate that the applicable rules found at 25

Pa. Code §§ 123.13 and 123.41 are as restrictive as those in any of the other jurisdictions

reviewed. The applicable PA rules limit PM emissions from this process to 0.04 gr/dscf

and visible emissions to 20% opacity.

Table 5-46. Summary of the State Implementation Plan Review for Loading

Operations PM Requirements

Jurisdiction Rule Citation Pollutant Applicable Emissions

Limit

Clark County, NV

CCAQR Sec. 26 Visible

Emissions

20% opacity

CCAQR Sec. 27 PM Process Weight Rate

East Kern County,

CA

EKCAPCD Rule

401

Visible

Emissions

20% opacity

EKCAPCD Rule

404.1

PM 0.1 gr/scf

EKCAPCD Rule

405

PM Process Weight Rate

Maricopa County,

AZ

MCAQD Rule

310.303

Visible

Emissions

20% Opacity

MCAQD Rule

311.301

PM Process Weight Rate

Pennsylvania

25 Pa. Code

§123.13

PM 0.04 gr/scf

25 Pa. Code

§123.41

Visible

Emissions

20% Opacity

124 As of 12/5/2013 U.S. EPA’s Green Book listed the following serious PM10 nonattainment areas: Clark

County, Nevada; Coachella Valley, CA; East Kern Co, CA; Imperial Valley, CA; Owens Valley, CA;

Phoenix, AZ; and Washoe Co, NV. In general, PM2.5 regulations applicable to specific source

categories have not been developed. Thus, source-specific regulations limiting PM or PM10 were

surveyed as well.



5-208

To address the second criterion, BACT precedents were evaluated. A review of U.S.

EPA’s RBLC database identified a limit of 0.01 gr/dscf as the lowest limit achieved in

practice for this class or category of source. In addition, Texas’ BACT guidance for

polyethylene facilities identifies a particulate mass loading limit of 0.01 gr/scf as BACT

for particulate emitting sources in polyethylene plants. Similarly, potentially applicable

BACT guidance from the BAAQMD in California limits emissions to 0.01 gr/dscf.

Based on these reviews, a LAER limit equal to 0.01 gr/dscf fulfills the requirement to

address the second criterion used in determining LAER. Thus, LAER for the PE pellet

loading operations is appropriately based on the application of a loadout system that

vents the displaced air through a filter and the LAER PM2.5 emissions limit for this filter

is 0.01 gr/dscf.

Given the low rate of particulate emissions from the PE loadout operations (i.e., less than

0.1 tons per year), the PM/PM10 BACT limit would be 0.01 gr/dscf. In other words, there

are no more effective controls that could be considered that would not have adverse

economic impacts relative to the control provided by complying with the identified

LAER limit.

Because it is not feasible to test emissions from the PE loading operations, Shell proposes

that a design and work practice be established as BACT/LAER. Specifically, Shell

proposes a design standard requiring the use of filter material specified to limit

PM/PM10/PM2.5 emissions to no more than 0.01 gr/dscf for the PE loading application,

that PE pellets only be loaded into vehicles when the displaced air is vented through such

a filter, and that loading be terminated at any time visible emissions from the loading

operation are observed.

As previously noted no applicable PM standards have been promulgated for PE Loading

operations under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code §127.205(7),

the proposed PM BACT/LAER limits are equivalent to and satisfies the PaBAT




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5.11.2 VOC LAER Analysis For Liquids Loading Operations

A small amount of VOC may be emitted as liquid products/byproducts from the proposed

project are loaded into transport vehicles. This LAER analysis addresses emissions from

loading of the following liquids into transport vehicles:

Pyrolysis tar (i.e., pitch or ethylene cracker residue);

Recovered oil;

Spent caustic; and

C3+ byproduct (i.e., a mixture of propane, butane, etc.).

Note that any VOC emissions that may be emitted from PE pellet loading are addressed

in Section 5.8 of this control technology review. No applicable VOC standards have

been promulgated for liquid loading operations under 40 CFR parts 60 and 61.

5.11.2.1 Source Descriptions

Pyrolysis tar or pitch is a low vapor pressure organic liquid that is produced during the

manufacture of ethylene in a steam cracking process.125 An estimated 50 to 60 thousand

barrels per year of pyrolysis tar will be produced at the proposed plant. This organic

liquid will be stored in an insulated and heated fixed roof tank and from storage, loaded

into trucks and/or railcars for shipment offsite. Based on an annual production rate of

60,000 barrels and the proposed LAER limits in this analysis, potential VOC emissions

from this operation are estimated to be 1.4 tons per year.

Recovered oil is also a low vapor pressure organic liquid produced during the cracking

process. It is recovered from the process wastewater in the wastewater treatment plant.

An estimated 5,000 barrels per year of recovered oil will be produced by the proposed

Project. This organic liquid will be stored in an internal floating roof tank that vents to a

control device, and from the storage tank, loaded into trucks and/or railcars for shipment

offsite. Based on an annual production rate of 5,000 barrels and the proposed LAER

125 The term “low vapor pressure organic” is used in this LAER analysis to denote a liquid with a maximum

true vapor pressure of less than 0.5 psia. The term “high vapor pressure” is used to denote a liquid with

a maximum true vapor pressure in excess of 14.7 psia.



5-210

limits in this analysis, potential VOC emissions from this operation are estimated to be

0.1 tons per year.

An estimated 12,000 barrels per year of spent caustic solution will be produced by the

proposed Project. Spent caustic solution is a byproduct of the ethylene manufacturing

process. A caustic (i.e., sodium hydroxide) solution is used to scrub product gases to

remove H2S from those gases. Some organic compounds are also scrubbed in the process

giving the resulting aqueous spent caustic solution a vapor pressure, somewhat higher

than that of fresh caustic, due to entrained organic compounds.

The project is currently considering two options related to spent caustic: 1) on-site

regeneration where the stripped VOC will be directed to a Spent Caustic Vent Incinerator

(see Section 5.12) or 2) shipment off-site.

If the option to ship the spent caustic off-site is chosen, the aqueous spent caustic stream

containing entrained hydrocarbon will be loaded via hoses into trucks or railcars for

shipment offsite. The presence of organic compounds in the spent caustic makes the

loading of spent caustic a potential source of VOC emissions and this material will be

controlled as if it was a low vapor pressure organic liquid. Based on an annual spent

caustic production rate of 12,000 barrels and the proposed LAER limits in this analysis,

potential VOC emissions from this operation are estimated to be less than 0.3 tons per

year.

C3+ is a high vapor pressure organic liquid produced during the ethylene cracking

process. An estimated 1.3 million barrels per year of C3+ liquids will be produced at the

proposed plant. This organic liquid will be stored in pressure spheres with no vents to

atmosphere. From storage, C3+ will be loaded into pressurized transport vehicles (i.e.,

trucks and/or railcars) for shipment offsite. All VOC emissions from the vehicle loading

operations are fugitive. These VOC emissions are estimated to total 13 tons per year.

The low vapor pressure organic liquids produced at the proposed plant are distinctly

different from the C3+ (i.e., high vapor pressure) liquids in physical and chemical

characteristics and in the equipment and techniques used to store, transfer, and transport



5-211

these materials. These materials are also subject to distinctly different regulatory

requirements. Thus, the LAER analysis for these loading operations evaluates the

loading activities for low vapor pressure organic liquids and the C3+ liquid as two

distinct categories.

5.11.2.2 VOC LAER Analysis for Low Vapor Pressure Organic Liquids

This LAER analysis applies to the pyrolysis tar, recovered oil, and spent caustic loading

operations. The proposed emission limits or operating standards for the low vapor

pressure organic liquid loading operations meet the two criteria to be considered LAER.

To address the first criterion, a survey was made of relevant VOC emissions limits and

work practices applied to loading of low vapor pressure organic liquids contained in state

implementation plans and recent PSD permits. The results of this survey are summarized

in Table 5-47 below. In general, loading of low vapor pressure organic liquids is not

specifically regulated under any SIP provisions.

Low vapor pressure organic liquid loadout operations have not been required to be

controlled using add-on control devices in recently issued PSD permits (second LAER

criterion).

Exceptions to this general conclusion include petroleum refineries where the truck

loading operations also include the loading of liquids such as gasoline and/or in cases

where the limit has not been achieved in practice because the permitted facilities have not

yet been constructed. These facilities do not belong to the same class or category as the

low vapor pressure organic liquids loading operations planned for the Project. Based on

this review, the control option that has been applied to the same class or category of

source and that has been achieved in practice is the use of submerged filling coupled with

dedicated service transport vehicles.

Consistent with the appropriate LAER precedents, Shell proposes the following LAER

limits for the low vapor pressure organic liquid loading operations (including spent

caustic, if the option to ship spent caustic off-site is chosen) at the Franklin plant:



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Operations VOC Requirements for Loading of Low Organic Vapor Pressure Liquid

Jurisdiction Rule Citation /

RBLC ID Pollutant Applicable Limit

South Coast, CA SCAQMD Rule 462 VOC None for liquids with Vp <1.5 psia.

Bay Area, CA BAAQMD Reg. 8,

Rule 6 VOC None for liquids with Vp < 0.5 psia.

Texas (TCEQ) Subchapter C,

§115.211 VOC None for liquids with Vp < 0.5 psia.

Arizona (ADEQ) AZ-0046 VOC

Thermal oxidizer w/ no specific

limit.

Limit not achieved in practice

because this facility has not been

constructed.

Louisiana (LDEQ) LA-0212 VOC None for liquids with Vp < 1.5 psia.

Louisiana (LDEQ) LA-0213 VOC None for liquids with Vp < 1.5 psia.

Louisiana (LDEQ) LA-0232 VOC Submerged loading and dedicated

service.

New Mexico

(NDEQ) NM-0050 VOC

10 mg VOC/L of liquid loaded.

Unclear if this applies to low-Vp

liquids.

Ohio (OEPA) OH-0317 VOC

0.06 lb VOC/Mgal naptha loaded.

0.01 lb VOC/Mgal diesel loaded.

Limit not achieved in practice

because this facility has not been

constructed.

Virginia (VDEQ) VA-0313 VOC

10 mg VOC/L of gasoline loaded.

No limit on distillate, residual or

lube oil (i.e., low-vapor pressure

liquids) loading.



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The maximum true vapor pressure of the low vapor pressure organic liquids

loaded shall not exceed 0.5 psia;

Submerged filling or bottom loading shall be used for loading of all low vapor

pressure organic liquids into transport vehicles; and

All transport vehicles loaded shall either be in dedicated service or shall be

cleaned prior to loading.

As previously note, no applicable VOC standards have been promulgated for liquid

loading operations under 40 CFR parts 60 and 61. In accordance with 25 Pa. Code

§127.205(7), the proposed VOC LAER limit is equivalent to and satisfies the PaBAT


5.11.2.3 VOC LAER Analysis for C3+ Liquids

For purposes of the C3+ liquid LAER analysis, Shell conducted a review of SIP rules and

permits applicable to loading of LPG, since the C3+ liquid and LPG loading operations

have similar characteristics. The results of this review are summarized in Table 5-48.

Shell did not identify any recent PSD permits that establish emissions limits for C3+ or

LPG loading operations.

Based on the above review, it appears that the most restrictive “limits” applicable to the

same class or category of source are the use of pressurized loading (Texas) and the use of

low-leak fittings with no visible leaks (Louisiana). The use of vapor balance/recovery is

less effective than pressurized loading due to the potential for additional leakage from the

vapor balance system. In addition, it is unclear whether vapor balanced loading is even

feasible with pressurized liquids. Because any emissions from the C3+ loading are

considered fugitive, it is appropriate to establish design/work practices in lieu of a

specific emissions limit. Thus, based on the most stringent achievable limits, this

analysis concludes that LAER for the C3+ liquid loading is a design standard requiring

low-leak couplings and pressurized loading of the C3+ liquids. In terms of the low-leak

couplings, this analysis proposes to use OPW’s Drylok™ Dry Disconnect Coupling or

equivalent. These couplings minimize leakage associated with disconnecting pressurized

hoses after loading of transport vehicles. In accordance with 25 Pa. Code §127.205(7),

the proposed VOC LAER limit is equivalent to and satisfies the PaBAT requirements of

25 Pa. Code §127.12(a)(5).



5-214


Operations VOC Requirements for Loading of C3+ or LPG

Jurisdiction Rule Citation /

RBLC ID Pollutant Applicable Limit

South Coast, CA

SCAQMD Rule 462 VOC Not applicable to LPG loading.

SCAQMD Rule 1177 VOC Not applicable to facilities that produce

LPG.

SCAQMD Rule 1173 VOC

Applicable to leaks and releases. No

specific requirement applicable to

loading operations.

Bay Area, CA BAAQMD Reg. 8,

Rule 6 VOC Not applicable to LPG loading.

Texas (TCEQ) Subchapter C,

§115.212 VOC

Requires vapor control, vapor balance

or pressurized loading.

Louisiana

(LDEQ) LAC 33:III.2107 VOC

Requires vapor recovery to storage

tank or control device plus low-leak

fittings and no visible leaks.

5.12 VOC Control Systems

The proposed project includes four systems that will be used to gather and control VOC

emissions during normal operation, startup, shutdown, and unforeseeable events at the

facility as follows:

High Pressure (HP) Header System (HP System),

Low Pressure (LP) Header System (LP System,

Ethylene Refrigerated Storage Relief System, and

Spent Caustic Vent Incinerator.

The HP System will be used to control VOC emissions resulting from startup, shutdown,

maintenance, and unforeseeable (i.e., upsets and malfunctions) events at the ethane

cracking unit and the polyethylene units. The HP System comprises two enclosed ground

flares, one elevated flare and ancillary equipment such as knockout pots. The elevated

flare (HP Elevated Flare) will be a secondary system used only when the combined

capacity of the two ground flares (HP Ground Flares) is exceeded due to a major facility

upset or malfunction (e.g., power failure).

The following VOC containing streams will be directed to the LP System, which includes

the LP Thermal Incinerator and LP Ground Flare:



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Continuous and intermittent VOC containing gases vented from the PE process

vents in accordance with the VOC LAER proposal in Section 5.7.1.3 and

specifically defined in Table D-4 of Appendix D;

Tank emission control systems as defined by the VOC LAER proposal in

Section 5.8.4;

VOC containing streams generated during product grade changes;

VOC containing streams generated during startup and shutdown of the three PE

manufacturing units;

VOC containing streams resulting from maintenance activities at the three PE

manufacturing unit; and

VOC containing streams generated during an upset or malfunction.

The gases in the LP System will be directed to the LP Thermal Incinerator whenever

there is capacity available in the incinerator. When the incinerator’s capacity is exceeded

due to an upset or malfunction, the excess gases will be directed to the LP Ground Flare.

The Ethylene Refrigerated Atmospheric Storage Relief system will be dedicated to

controlling emissions from ethylene refrigerated atmospheric storage tank startup,

shutdown, and emergency release. The Spent Caustic Vent Incinerator will be used to

control VOC and reduced sulfur compound emissions in the spent caustic oxidation unit

offgas and from the WWTP flow equalization and oil removal (FEOR) tank vents. The

Spent Caustic Vent Incinerator will be in a very different service than the LP Thermal

Incinerator. While the LP Thermal Incinerator will see high concentration VOC

containing streams that are easily combusted without the need of significant quantities of

supplemental fuel, the VOC containing offgas from the Spent Caustic oxidation unit and

the WWTP FEOR tank vents will have a much lower VOC concentration and require

significant amounts of supplemental fuel on a relative basis.126 In addition, there is the

chance for caustic carryover from the spent caustic oxidation unit, which restricts the

incinerator type to a flame-based system. As a result, the LP Thermal Incinerator is a

different category of emissions source than the Spent Caustic Vent Incinerator.

126 The vent stream composition is predominately moisture and air (i.e., 99.7 percent) with trace quantities

of VOC and H2S.



5-216

The HP and LP systems will be designed such that the foreseeable events are combusted

in the most efficient control device. In the HP System the ground flares, which are the

more efficient control device, will be used to control VOC containing streams associated

with foreseeable events. In the LP system, the LP Thermal Incinerator, which is the more

efficient control device, will be used to control foreseeable VOC containing streams

associated with operation of the PE units. In general, the two elevated flares in the HP

and LP systems will be used during unforeseeable events.

The primary purpose of each of the VOC control systems reviewed in this section of the

LAER analysis will be efficient combustion of VOC-containing gases generated at the

facility due to routine operation as well as planned and unplanned infrequent events. As

a result, the control technology analysis focuses on: (1) minimizing the production of

those gases; and (2) ensuring efficient combustion of the gases that are generated. As

discussed in Section 5.12.2, control of the secondary pollutants (i.e., NOx/ NO2,

PM/PM10/PM2.5, CO, and GHGs that are formed as byproducts of thermal

incinerator/flare operation) will be achieved by minimizing the amount of gas that is

combusted.

5.12.1 VOC Control Systems LAER Analyses

Incomplete combustion of the gases directed to the VOC control systems results in VOC

emissions. The proposed project is located in an area that is classified as nonattainment

for ozone, for which VOC is a defined precursor. As a result, the VOC control systems

are subject to LAER.

For VOC emissions, there are several potentially applicable NSPS and NESHAP rules

that would require any continuously or periodically generated vent gas streams to be

controlled, including subparts VV, VVa, DDD, NNN and RRR of 40 CFR 60 and

subparts YY, SS, UU, and FFFF of 40 CFR 63. Each of the NSPS and NESHAP rules

require a defined control efficiency of 95 to 98% or compliance with design/work

practice requirements at 40 CFR §60.18 (NSPS) or 40 CFR §63.11 (NESHAP) if a flare

is used. The specifications at 40 CFR §60.18 and 40 CFR §63.11 establish a floor with

respect to the LAER analysis.



5-217

5.12.1.1 Step 1: Identify VOC Control System Precedents

Summary results from a review of precedents and requirements identified for flares in the

RBLC database, permits, EPA/DOJ consent decrees, and State Implementation Plan

(SIP) requirements and regulations are presented in Table 5-49. As shown, the identified

flaring related control options used to minimizing VOC emissions are work practices and

equipment design elements that will: (1) minimize the quantity (i.e., mass) of the gases

directed to the combustion devices within these systems and (2) maximize the VOC

destruction efficiency of the flare. The following specific measures are included:

Compliance with the design and operating requirements of 40 CFR §60.18

maximum exit velocity and net heat content of the vent gas;

Using flare gas recovery systems;

Instrumentation and control required for automated control of the net heating

value of the gases in the combustion zone



5-218

Table 5-49. Summary of RBLC and Other Flare Related Permitting Precedents and Regulatory Requirements

Facility

Instrumentation &

Monitoring Waste Gas Minimization Combustion Efficiency

Flaring

Limits

NHVcz 2

(Btu/scf)

Ethylene Manufacturing

ExxonMobil Baytown

Olefins Plant

Elevated flare (EF) &

Multi-point ground

flare (MPGF)

pilot thermocouple

or an infrared

monitor

continuous flow

monitor and

composition

analyzer

gas net heating value

and actual exit

velocity determined

Not specified 40 CFR §60.18

No visible emissions

The flare shall be

operated with a flame

present at all times

and/or have a constant

pilot flame

lb/hr &

tpy for:

NOx, SO2,

CO,

&VOC

Chevron/Phillips Cedar

Bayou Plant Flares

pilot thermocouple

or an infrared

monitor

continuous flow

monitor and

composition

analyzer


and actual exit

velocity determined



The flare shall be




pilot flame

lb/hr &

tpy for:

NOx, SO2,

CO, VOC



5-219

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)

Equistar Channelview

Plant OP-1 furnace

addition

Flares

pilot thermocouple

or an infrared

monitor



The flare shall be



and/or have a

constant pilot flame

99.5% control

lb/hr &

tpy for:

NOx, SO2,

CO, VOC

Equistar Channelview

Plant OP-2 furnace

addition

Flares

pilot thermocouple

or an infrared

monitor


and actual exit

velocity determined

None specified 40 CFR §60.18


The flare shall be




pilot flame

lb/hr &

tpy for:

NOx, SO2,

CO, VOC

PE Manufacturing

ExxonMobil Beaumont

Polyethylene Plant

Air Assisted (AA) and

Ground (G) Flares

pilot thermocouple

or an infrared

monitor

continuous flow

monitor and British

thermal unit (Btu)

analyzer

Maintenance venting from

each Low Pressure Reactor

are limited to 20 ventings

per year.

40 CFR §60.18


The flare shall be


present and have a

constant pilot flame.

The Air-Assisted Flare

destruction efficiency

AA & G

Flares:

lb/hr &

tpy for:

NOx, SO2,

CO, VOC



5-220

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)


and actual exit

velocity determined

of 99.5 percent for

carbon compounds with

a carbon number of one

through four and 98

percent for carbon

compounds with a

carbon number of five

or greater.

The Ground Flare

destruction efficiency

of 99 percent for carbon

compounds with a

carbon number of one

through three and 98

percent for carbon

compounds with a

carbon number of four

or greater.

ExxonMobil Mont

Belvieu Plastics Plant

Elevated flare (EF) &

Multi-point ground

flare (MPGF)

pilot thermocouple

or an infrared

monitor

continuous flow

monitor and

composition

analyzer

None specified EF & MPGF:

40 CFR §60.18


The flare shall be




pilot flame

MPGF:

>99.5% DRE

EF &

MPGF:

lb/hr &

tpy for:

NOx, SO2,

CO, VOC

MPGF:

lb/hr &

tpy for:

PM/PM10



5-221

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)


and actual exit

velocity determined

>800 Btu/scf /PM2.5

Chevron/Phillips Sweeny

Complex pilot thermocouple

or an infrared

monitor

continuous flow

monitor and

composition

analyzer


and actual exit

velocity determined

None specified 40 CFR §60.18


The flare shall be




pilot flame

lb/hr &

tpy for:

NOx, SO2,

CO, VOC

Consent Decrees

Shell Deer Park Refining

Consent Decree

Vent gas flow

monitoring

Vent gas MW 1

Steam flow rate

Steam control

equipment

Gas chromatograph

(regular use flares)

Net heating value

(temporary-use

flares)

Video camera

Pilot gas rate

Initial WGMP submittal

Characterize waste gas

Baseload waste gas rate

Identify constituents

Waste gas mapping

Planned reductions

Prevention measures

First Update WGMP

Updated mapping

Reductions based on root

cause

Subsequent Updates -

Root cause anal. & corrective


Pilot monitoring

40 CFR §60.18

monitoring

Automated control of

steam and supplemental

gas

Operate in accordance

with design

Net heating value of

vent gas (NHVvg)

Momentum Flux Ratio

(MFR)

Yes

refinery

wide

w/FGR 4

355



5-222

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)

(optional) action implementation

Shell Deer Park Olefins

Consent Decree

Vent gas flow

monitoring

Vent gas MW 1

Steam flow rate

Steam control

equipment

Gas chromatograph


Net heating value

(temporary-use

flares)

Video camera

Pilot gas rate

(optional)





Waste gas mapping

Planned reductions

Prevention measures

First Update WGMP

Updated mapping


cause



action implementation


Pilot monitoring

40 CFR §60.18

monitoring



gas


with design


vent gas (NHVvg)

Momentum Flux Ratio

(MFR)

No 500 3



5-223

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)

Marathon Petroleum

Consent Decree

Vent gas flow

monitoring

Vent gas MW 1

Steam control

equipment

Steam flow rate

Gas chromatograph

Video camera

Pilot gas rate

(optional)





Waste gas mapping

Planned reductions

Prevention measures

First Update WGMP

Updated mapping


cause





Pilot monitoring

40 CFR §60.18

monitoring



gas


with design


vent gas (NHVvg)

Momentum Flux Ratio

(MFR)

Yes by

flare

w/FGR 4

Based on

vent gas

VOC

content 3

BP Whiting Refinery

Consent Decree

Vent gas flow

monitoring

Vent gas MW 1

Steam flow rate

Gas chromatograph


Video camera

Pilot gas rate

(optional)





Waste gas mapping

Planned reductions

Prevention measures

First Update WGMP

Updated mapping


cause




Pilot monitoring

40 CFR §60.18

monitoring



gas


with design


vent gas (NHVvg)

Momentum Flux Ratio

(MFR)

Yes

refinery

wide

w/FGR 4

Based on

vent gas

VOC

content 3



5-224

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)


Country Mark Refining

Consent Decree

Vent gas flow

monitoring

Vent gas MW 1

Steam flow rate

Gas chromatograph


Video camera

Pilot gas rate

(optional)





Waste gas mapping

Planned reductions

Prevention measures

First Update WGMP

Updated mapping


cause





Pilot monitoring

40 CFR §60.18

monitoring



gas


with design


vent gas (NHVvg)

Yes

refinery

wide

Based on

vent gas

VOC

content 3



5-225

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)

State SIP Requirements and Regulations

BAAQMD Rule 12 Flares

at Petroleum Refineries The owner or

operator of a flare

subject to this rule

with a water seal

shall continuously

monitor and record

the water level and

pressure of the water

seal that services

each flare.

Continuously

monitor volumetric

flow

Flare gas

composition

monitoring

Pilot monitoring

Video monitoring

Flaring is prohibited unless it

is consistent with an approved

FMP and all commitments

due under that plan have been

met.

Evaluate flaring that has

occurred during planned

major maintenance

activities, including startup

and shutdown, and the

feasibility of performing

these activities without

flaring.

Evaluate flaring caused by

the recurrent failure of air

pollution control equipment,

process equipment, or a

process to operate in a

normal or usual manner,

and consider the adequacy

of existing maintenance

schedules and protocols.

SCAQMD Rule 1118

Control of Emissions

from Refinery Flares

Gas flow

Gas higher heating

value

Conduct a Specific Cause

Analysis for any flare event,

Operate all flares in such a

manner that minimizes all

Maintain a pilot flame

present at all times a

flare is operational.

Operate all flares in a



5-226

Facility

Instrumentation &


Flaring

Limits

NHVcz 2

(Btu/scf)

flaring and that no vent gas

is combusted except during

emergencies, shutdowns,

startups, turnarounds or

essential operational needs.

Develop Flare Minimization

Plan if cannot meet specific

SO2 emission requirements.

smokeless manner with

no visible emissions

TCEQ Title 30, Part 1,

Chapter 115, Subchapter

B, Division2 Vent Gas

Controls, rule 115.121

Flares 40 CFR

60.18

None specified Control efficiency of at

least 98% or to a

volatile organic

compound (VOC)

concentration of no

more than 20 ppmv

TCEQ Chemical Sources

Current Best Available

Control Technology

(BACT) Requirements

Flares and Vapor

Combustors

Flares:

flow

Btu

None specified Flares

40 CFR 60.18

99% for certain

compounds up to three

carbons, 98% otherwise

1. MW = molecular weight

2. NHVcz = Net heating value of the combustion zone

3. Net Heating Value for hydrogen shall be equal to 1212 BTU/scf when determining the NHVcz.

4. FGR = Flare gas recovery



5-227

The use of waste gas minimization plans (WGMPs) to minimize emissions during

startup and shutdown;

Operate the flare system in accordance with a required net heating value in the

combustion zone.

Summary results from a review of the precedents identified for thermal incinerators in the

RBLC database, a recent Texas permit, and State Implementation Plan (SIP)

requirements and regulations are presented in Table 5-50. As shown, the incinerator

requirements are directed at defining a design that will achieve the required destruction

efficiency and operating conditions (e.g., operating temperatures) that ensure the desired

destruction efficiency.

5.12.1.2 Step 2: Achieved VOC Control System Work Practices and Limits

Each of the identified control options, except use of a flare gas recovery system, is

technically feasible and is inherent in the design of the proposed Project’s VOC control

systems. Flare gas recovery systems are only feasible at large integrated petrochemical

facilities where the recovered gas can be combined with other gases and used as fuel. As

discussed below, this is not technically feasible for the proposed Project.

Ethylene Manufacturing: As part of the ethylene manufacturing process, tailgas will be

recovered and used as fuel in the cracking furnaces. During normal operation of the

cracking unit, no routine vent gases other than analyzer vents and pressure relief valve

leakage will be directed to the HP System. As a result, during normal operations there

will be little or no VOC gas to recover using a flare gas recovery system. The start-up

and shutdown release of VOC gases to the HP System will be infrequent and primarily

composed of ethylene. The use of a flare gas recovery system to recover routine vent

gases beyond what is recovered as tailgas and routing of these gases to a process or to a

fuel gas system is not technically feasible for the proposed facility.



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Table 5-50. Summary of RBLC Incinerator Related Permitting Precedents

Facility Instrumentation &

Monitoring Waste Gas

Minimization Combustion Efficiency Incinerator Limits 1

ExxonMobil Mont Belvieu

Plastics Plant RTO & Flameless

Thermal Oxidizer (FTO)

RTO:

exit temperature shall

be continuously

monitored

FTO:

exit temperature shall

be continuously

monitored

None specified RTO:

99% VOC control or

outlet VOC

concentration of less

than 10 ppmv

FTO:

99.99%

RTO:

Maintain a minimum of 1400°F

lb/hr & tpy limits for: VOC,

NOx, CO, SO2,

PM/PM10/PM2.5

FTO:

Maintain a minimum of 1400°F


NOx, CO, SO2,

PM/PM10/PM2.5

Owens Corning Medina

Asphalt Roofing Plant

(OH-0288)

Thermal Incinerator

continuous temperature

monitor

None specified 95% For any 3-hour block of time

when the emissions unit is in

operation, shall not be less than

1450 oF


NOx, CO, SO2, PM Formosa Specialty PVC

Plant

(TX-0508)

Incinerators/Scrubbers

continuous temperature

monitor

O2 monitor

None specified 99.95% Minimum firebox temperature

set by testing

Minimum standby firebox

temperature of 800 oF


NOx, CO, SO2



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Facility Instrumentation &

Monitoring Waste Gas

Minimization Combustion Efficiency Incinerator Limits 1

State SIP Requirements and Regulations

TCEQ Title 30, Part 1,

Chapter 115, Subchapter

B, Division2 Vent Gas

Controls, rule 115.121

Incinerator exhaust gas

temperature

None specified Control efficiency of

at least 98% or to a

volatile organic

compound (VOC)

concentration of no

more than 20 ppmv

TCEQ Chemical Sources

Current Best Available

Control Technology

(BACT) Requirements

Flares & Vapor

Combustors

Temperature None specified 99%

1. Sufficient information was not found in RBLC and the permits to put the lb/hr and tpy emission limits on a standard unit basis (e.g.,

lb/MMBtu).



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Capture and recovery of ethylene for use as a fuel gas at the Cogen Units is not

technically feasible because ethylene has very different combustion characteristics (e.g.,

adiabatic flame temperature, flame velocity and heat release rate) 127 than tailgas

(primarily hydrogen and methane), and natural gas (primarily methane with lesser

amounts of ethane and propane). The cracking furnaces will be designed to efficiently

and cleanly combust tailgas and natural gas. The Cogen Units will be designed to burn

natural gas. As a result, use of either the furnaces or Cogen Units to combust ethylene

would result in 1) damage to the burners due to ethylene’s high heat release and 2) burner

fouling due to the formation of polymerization residue.128 Furthermore, the combustion

turbines will use dry low NOx combustors, which must be designed for a particular fuel

type. It is not possible to design a dry low NOx combustor to burn both natural gas and

ethylene due to the dissimilarity in the combustion characteristics.

During startup and shutdown, the capture and recovery of cracking furnace product gas

for use as a feedstock is not technically feasible because the low purity of the captured

gases. The recovered furnace product gases would contain ethane, ethylene, propylene

and acetylene. The furnaces require high purity ethane to produce desirable product (i.e.,

ethylene). Using these startup/shutdown gases as a cracking furnace feedstock would

result in rapid coking of the cracking furnace process tubes.

PE Manufacturing: The PE units will have continuous and intermittent process vents

that will be directed to the LP system. These vents contain significant amounts of

diluents (i.e., air and nitrogen) that make their capture and recovery for use as fuel

infeasible. If a vent gas containing a significant amount of nitrogen is mixed with

another fuel, the heat content of that stream is reduced. This in turn results in a fuel that

has different combustion characteristics. Unlike the cracking furnaces and Cogen Units,

127 The heat content of ethylene is 1,631 Btu/scf and the adiabatic flame temperature is ~2010 oC. The heat

content of methane is 1,011 Btu/scf and the adiabatic flame temperature is 1950 oC. 128 Polymerization residues form when ethylene is combusted in a combustion device not designed to

combust ethylene. The products of incomplete combustion are sticky and polymerize at or near the point

of combustion (i.e., the burner).



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the LP System’s incinerator will be designed to combust vent gases with significant

amounts of diluents with highly variable combustion characteristics.

Releases of hydrocarbons to the LP System during startup, shutdown, maintenance, and

unforeseeable events will be intermittent and infrequent. Additionally, as noted above,

the captured gases, mostly ethylene, are not suitable for use as fuel at the proposed

facility, where the combustion units (i.e., cracking furnaces and Cogen Units) will be

designed to combust clean burning tailgas and natural gas. As such, a flare gas recovery

system is not technically feasible for the LP System.

Recovered ethylene from the PE units during startup, shutdown, or malfunction would

contain catalyst, other reaction chemicals and polyethylene. Introducing these

contaminants into the PE unit feed would result in off specification polyethylene.

As noted above, the gases in the LP System will be routed to the LP Thermal Incinerator

whenever there is capacity available in tis incinerator. When the incinerator’s capacity is

exceeded due to an upset or malfunction, the excess gases will be directed to the LP

ground flare. The LP Thermal Incinerator will be sized and designed to ensure a

residence time in the incinerator and operating temperature that results in a high

destruction efficiency (i.e., >99.5%) when combusting the routinely generated vent gases

from the PE unit. To accept additional upset and malfunction gases would require an

incinerator with a larger firebox. This larger firebox would result in a loss of efficiency

during the treatment of the routinely generated gases, due to mixing constraints. As a

result, it is not technically feasible to design an incinerator that can both reliably ensure a

high VOC destruction efficiency of the routinely generated gases while having an

adequate size to achieve similar combustion efficiency for the possible gas rates

associated with upsets and malfunctions.

Refrigerated Atmospheric Storage System: This flare will be dedicated to controlling

emissions from ethylene refrigerated atmospheric storage tank startup, shutdown, and

emergency. These events will occur infrequently. As such, a vapor recovery system

would not have anything to recover on a routine basis. Additionally, any recovered



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ethylene could not be put in the fuel gas system or as feed to the cracking furnaces for

reasons discussed previously in this subsection.

Spent Caustic Incinerator: This incinerator will be used to control VOC and reduced

sulfur compounds in the spent caustic oxidation unit offgas and from the WWTP FEOR

tank vents. This incinerator will operate continuously. The vent stream composition is

predominately moisture and air (i.e., 99.7 percent) with trace quantities of VOC and H2S.

5.12.1.3 Step 3: Establish VOC Control System Work Practices and Limits

The proposed LAER for VOC emissions from the VOC control systems includes a

combination of emissions limitations, work practice requirements, and equipment design

standards as follows:

The LP Thermal Incinerator and Spent Caustic Vent Incinerator shall be designed

and operated to achieve VOC control efficiencies of 99.5 and 99%, respectively.

The facility will minimize flaring resulting from startups, shutdowns, and

unforeseeable events by operating at all times in accordance with an approved

flare minimization plan. The plan shall include the following elements:

o Procedures for operating and maintaining the HP and LP Systems during

periods of process unit startup, shutdown and unforeseeable events.

o A program of corrective action for malfunctioning process equipment.

o Procedures to minimize discharges either directly to the atmosphere or to

the HP and LP Systems during the planned and unplanned startup or

shutdown of process unit and air pollution control equipment.

o Procedures for conducting root cause analyses.

o Procedures for taking identified corrective actions.

The facility shall conduct a root cause analysis within 45 days after any startup,

shutdown and unforeseeable flaring event. Flaring event shall be defined as an

event that exceeds the baseline by 500,000 scf within a 24 hour period.129 The

analysis shall address the following elements:

o The date and time that the flaring event started and ended.

o The total quantity of gas flared during each event.

o An estimate of the quantity of VOC that was emitted and the calculations

used to determine the quantities.

129 See Shell Deer Park Consent Decree, July 10, 2013, No. 4:13-cv-2009, page 18.



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o The steps taken to limit the duration of the flaring event or the quantity of

emissions associated with the event.

o A detailed analysis that sets forth the root cause and all significant

contributing causes of the flaring event to the extent determinable.

o An analyses of the measures that are available to reduce the likelihood of a

recurrence of a flaring event resulting from the same root cause or

significant contributing causes in the future.

o A demonstration that the actions taken during the flaring event are

consistent with the procedures specified in the flare minimization plan.

o In response to a flaring event, the facility shall implement, as

expeditiously as practicable, such interim and/or long-term corrective

actions as are consistent with good engineering practice to minimize the

likelihood of a recurrence of the root cause and all significant contributing

causes of that flaring event.

The flares shall be designed to meet limitations on maximum exit velocity, as set

forth in the general provisions at 40 CFR § 60.18 and § 63.11.

The flares shall be operated to meet minimum net heating value requirements for

gas streams combusted in the flares, as set forth at 40 CFR § 60.18 and § 60.18.

o HP and LP Ground Flares shall be equipped with the following automated

controls:Control of the supplemental gas flow rate to the flare

o Control of the total steam mass flow rate (if applicable) to the flare.

Net Heating Value of Combustion Zone Gas (NHVcz)130

o The HP Flare Header shall be operated such that the NHVcz, on a

three-hour rolling average basis, rolled every fifteen minutes, is equal to or

greater than 500 Btu/scf, using a Net Heating Value for hydrogen of 1212

BTU/scf.

Establishment of equipment design and work practice requirements as LAER is

appropriate in this instance because it is infeasible to apply a measurement methodology

for demonstration of compliance with numeric limits on emissions rates. The

configuration of flare systems renders both manual stack testing and continuous

emissions monitoring systems technically infeasible.

130 Net Heating Value of Combustion Zone Gas” or “NHVcz” shall mean the Lower Heating Value, in

Btu/scf, of the combustion zone gas in a flare and shall be determined in accordance with Appendix 1.3

of the Shell Deer Park Consent Decree, July 10, 2013, No. 4:13-cv-2009.



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The proposed emission limits for the VOC control systems must meet two criteria to be

considered LAER. The first criterion is met because the proposed LAER limits and work

practices identified in Table 5-49 and Table 5-50 are equivalent to or go beyond what is

currently required for flares and incinerators in any State implementation plans and

regulations. The second criterion is met because the proposal represents a compilation of

the most stringent limits and work practices in permits and recent consent decrees. Note

the consent decrees were relied on primarily because they provided more detailed

requirements than the permits and State implementation plans and regulations. The

proposed VOC LAER for the VOC Control System is more stringent than the standards

promulgated under 40 CFR Parts 60 and 61. In accordance with 25 Pa. Code

§127.205(7), the proposed VOC LAER limit is equivalent to and satisfies the PaBAT


5.12.2 VOC Control System CO, NOx, PM, and GHG BACT/LAER Analyses

The proposed VOC control systems will be used to safely control routine and non-routine

hydrocarbon venting. The combustion of the hydrocarbons will produce emissions of

CO, NOx, PM, PM10, PM2.5, and GHGs. There are no applicable NSPS or NESHAP

rules that would establish a baseline emission rate for CO, NOx, PM, PM10, PM2.5, or

GHG emissions from the flares and incinerators, although the regulations at 40 CFR parts

60.18 and 63.11 do require smokeless operation of flares, which would affect the amount

of CO and PM emitted.

5.12.2.1 Step 1 – Identify All Control Options

A review of the RBLC database identified the following types of design and work

practices for flares and incinerators:

Work practice/good combustion practices,

Proper equipment design,

Maintain the net heating value of the gas being combusted (e.g., 300 Btu/scf or

greater if the flare is steam-assisted or 200 Btu/scf or greater if the flare is not

assisted),



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Burner design, premix and combustion temperature control,

Proper plant operations,

Comply with 40 CFR parts 60.18 and 63.11, and

Proper maintenance practices.

5.12.2.2 Step 2 – Eliminate Technically Infeasible Control Options

For flares, there are no technically feasible add-on control technologies demonstrated for

the control of CO, NOx, PM, PM10, PM2.5, and GHG emissions. This is because gas flow

rates to flares are highly variable, and the high temperatures required to obtain high

efficiency destruction of the hydrocarbons would damage add-on control technologies

such as oxidation catalyst for CO control, selective catalytic reduction for NOx control or

filters for PM control.

Another control option for condensable PM is through the combustion of low sulfur flare

gases and pilot fuel. The proposed facility will used natural gas for the pilot fuel, and the

vent streams from the cracking facility and PE units will have no sulfur compounds, as

this is a requirement of the manufacturing processes. Trace amounts of sulfur

compounds coming in with the ethane feed stock will be scrubbed out of the ethylene

stream using a caustic wash.

For incinerators, there are no identified add-on control technologies demonstrated for the

control of CO, NOx, PM, PM10, PM2.5, and GHG emissions. One entry in the RBLC

database identified the use of low NOx burners and good combustion practices for

control of NOx.131 Using the available information, NOx emissions were estimated to be

0.2 lb/MMBtu when firing natural gas and 0.3 lb/MMBtu when firing waste gas. As is

the case for flares, the high temperatures required to obtain high efficiency destruction of

the hydrocarbons would damage add-on control technologies.

131 RBLC ID LA-0235 Westlake Vinyls Company Geismar site VCM-E plant.



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5.12.2.3 Steps 3-5: Establish VOC Control System BACT/LAER for CO, NOx, PM/PM10/PM2.5, and GHG

The most effective control options for CO, NOx, PM, PM10, PM2.5, and GHG emissions

from the VOC control systems are the work practices and equipment design elements

identified in Section 5.12.1.3. Each of these control options is technically feasible and is

inherent in the design of the proposed facility. The proposed work practices and

equipment design standards for these pollutants are those proposed for VOC LAER.

For flares, establishment of equipment design and work practice requirements as

BACT/LAER is appropriate in this instance because it is infeasible to apply a

measurement methodology for demonstration of compliance with numeric limits or

emissions rates. The configuration of elevated flare systems renders both manual stack

testing and continuous emissions monitoring systems technically infeasible. Although

stack testing of ground flares is potentially more feasible than testing of an elevated flare,

“infield” testing is generally difficult or impossible for several reasons. Operating

conditions are not easily modified or controlled and taking the plant off-line to test the

flare is impractical. In addition, flares are nearly impossible to test under critical design

conditions once installed and operating.”132 Testing of an operating ground flare is

unsafe to the stack testers because an unforeseeable event creates safety concerns and

would destroy the test equipment.

For incinerators, manual testing and continuous emission monitoring are feasible

although manual testing at or near maximum design loads may not be feasible without

disrupting the process. LAER and BACT emission rates (e.g., lb/MMBtu) for CO, NOx,

PM, PM10, PM2.5, and GHG emissions based on the RBLC database review and other

permits could not be determined for the thee permits found in Table 5-50 because the

design heat input to the incinerators was not found in the permits. Only pound per hour

and ton per year limits were identified in these permits.

132 Industrial-Scale Flare Testing, Jianhui Hong, et. al. John Zink Company. www.johnzink.com/wp-

content/uploads/industrial-flare-testing.pdf



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With the exception of the ExxonMobil Mont Belvieu PE plant RTO and FTO, the other

incinerators precedents presented in Table 5-50 are not of the same class or category as

the proposed Project’s incinerators. For LAER, the control technology must be verified

to perform effectively over the range of operation expected for that class or category of

source. The verification must be based on a performance test or tests, when possible, or

other performance data. The Mont Belvieu plant has not yet begun operation, so the

limits in these permits have not been achieved in practice.

Due to the lack of achieved in practice emission rates from the same class or category of

emissions units, Shell proposes the following emission rates for the LP Thermal

Incinerator and the Spent Caustic Vent Incinerator:

0.068 lb/MMBtu for NO2/NOx,

0.0075 lb/MMBtu for PM/PM10/PM2.5,

0.37 lb/MMBtu for CO, and

132.0 lb/MMBtu for CO2e.

The proposed emission limits for NOx and PM2.5 must meet two criteria to be considered

LAER. To evaluate the first criterion as noted above, a review of the requirements

included in State implementation plans, regulations and BACT guidelines for Texas, and

California agencies (CARB, BAAQMD, SJVAPCD and SCAQMD) was performed. No

State implementation plans, regulations, and BACT guidelines specific to incinerators for

CO, NOx, PM, PM10, PM2.5, and GHG emissions were identified. The second criterion is

met because no CO, NOx, PM, PM10, PM2.5, and GHG emissions rate limits achieved in

practice were identified, except for NOx at the Owens Corning Medina Asphalt Roofing

Plant (OH-0288). This NOx limit was “estimated” to be 0.2 lb/MMBtu when firing

natural gas and 0.3 lb/MMBtu when firing waste gas. Shell has proposed a much lower

limit as being reasonable for the class and category of incinerators proposed.

In accordance with 25 Pa. Code §127.205(7), the proposed CO, NOx, PM/PM10/PM2.5,

and GHG BACT/LAER limits are equivalent to and satisfies the PaBAT requirements of

25 Pa. Code §127.12(a)(5).



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5.13 Plant Roads

Although much of the material that moves in and out of the the proposed project will be

transported by rail, certain materials will also transported by truck. Truck traffic on plant

roadways is a potential source of fugitive particulate matter emissions. Most of these

emissions are estimated to be PM with only a small fraction of the total emissions being

PM10 (about 20%) and even smaller fraction being PM2.5 (about 5%).

Particulate emissions occur as vehicles travel over a paved surface such as a road.

Particulate emissions from paved roads are primarily associated with re-suspension of

loose material on the road surface. According to U.S. EPA’s model of road-related

fugitive emissions, in the absence of continuous addition of fresh material (through

localized trackout or application of antiskid material), paved road surface silt loading

reaches an equilibrium value in which the amount of material re-suspended matches the

amount replenished.133

Dust emissions from paved roads have been correlated with what is termed the “silt

loading” present on the road surface as well as the average weight of vehicles traveling

the road. The term “silt loading” refers to the mass of silt-size material (i.e., loose

surface dust equal to or less than 75 µm in physical diameter) per unit area of the travel

surface. The total road surface dust loading consists of loose material that can be

collected by vacuuming of the traveled portion of the paved road. The silt fraction is

determined by measuring the proportion of the loose dry surface dust that passes through

a 200-mesh screen, using the ASTM-C-136 method. Silt loading is the product of the silt

fraction and the total loading.

Based on the expected level of truck traffic, the characteristics of the production

processes and the length of the plant roads, estimated fugitive PM emissions from the

133 See AP-42, Chapter 13, Section 2.1 (paved roads)



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plant roads total approximately 0.3 tons per year. PM2.5 emissions are estimated to be

less than 0.1 tons per year.

5.13.1 Plant Road Fugitive PM LAER/BACT Analysis

Two criteria must be evaluated to determine LAER for a particular class or category of

source. The first criterion considered is the most stringent achievable limit in a SIP that

is applicable to the class or category of source being evaluated – in this case an industrial

paved road. A review of SIP limits applicable to fugitive particulate emissions from

industrial plant roads shows that there are no specific emissions limits applicable to this

class or category of source. Instead, SIP regulations contain design and/or work practices

applicable to this source category. A sampling of applicable SIP “limits” is shown in

Table 5-51.

Table 5-51. Summary of SIP Regulations for Plant Road Particulate

Jurisdiction Rule

Citation Summary of Requirements

Louisiana LAC §1301 Paving roadways and maintaining the roadways in a

clean condition.

Clark County,

NV §93.2.1.1

Paved roads shall be constructed with a paved travel

section, and four (4) feet of paved or stabilized

shoulder on each side of the paved travel section.

Texas §111.147

Requires industrial roads to be paved unless the

owner of the roadway demonstrates that the cost of

paving is economically unreasonable compared to

other specified methods of dust control.

The second criterion in determining a LAER limit is that it must be at least as stringent as

the most stringent limit achieved in practice by the class or category of source. U.S.

EPA’s RBLC database was queried to determine limits established for industrial paved

roads in recent permit actions. Selected results of this review are summarized in Table

5-52. As shown, in most of the recent BACT determinations, fugitive particulate

emissions are limited by work practices that include paving and dust removal/suppression

as deemed necessary.



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Based on the information provided in Table 5-51 and Table 5-52, it is concluded that

PM2.5 LAER for plant roads is not an emissions limit, but rather a design/work practice.

This conclusion is consistent with U.S. EPA’s guidance in the 1990 DRAFT NSR

Workshop Manual that states:

In some cases where enforcement of a numerical limitation is judged to be

technically infeasible, the permit may specify a design, operational, or equipment

standard; however, such standards must be clearly enforceable, and the

reviewing agency must still make an estimate of the resulting emissions for offset

purposes.134

Based on available BACT precedents, a LAER design/work practice which requires that

all plant roads be paved and that Shell develop and implement a road dust control plan to

minimize fugitive emissions from the roadways is proposed. Given the low level of

estimated emissions from the proposed Project’s roads, the proposed design/work

practice also represents BACT for PM and PM10 emissions. In other words, there are no

more effective controls that could be considered that would not have adverse economic

impacts relative to the control provided by implementing the identified LAER

design/work practices. In accordance with 25 Pa. Code §127.205(7), the proposed PM

BACT/LAER limit is equivalent to and satisfies the PaBAT requirements of 25 Pa. Code

§127.12(a)(5).

134 See “1990 New Source Review Workshop Manual, DRAFT”, 1990, page G.4.



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Table 5-52. Summary of RBLC Survey Results for Plant Road Particulate

Facility RBLC

ID

Emission

Limit Discussion

Indiana Gasification,

LLC IN-0166 90% control

There is no practical way to measure control

efficiency of a road dust control plan so this “limit” is

not achievable. Further, this facility has not been

constructed and therefore, this “limit” has not been

achieved in practice and is appropriately not

considered in establishing a LAER limit.

Aventine Renewable

Energy Aurora West NE-0046

Silt Loading

< 3 g/m2

Note that this is not an emissions limit, but rather a

limit on a variable that is correlated with fugitive

road dust emissions. This facility is not operational

and Shell has been unable to determine if compliance

with this limit has been demonstrated or achieved in

practice. However, Shell believes this “limit” is

achievable.

Flopam, Inc. LA-0240 PM10 < 0.2 T/yr

This is the lowest paved road BACT limit identified.

Compliance with this limit is not monitored in any

way, nor is it even possible to monitor compliance

with such a limit. In this case, BACT is implemented

via a design/work practice that requires the facility’s

main roadways to be paved “where practical” and

that precautions be taken to prevent dust from

becoming airborne.

5.14 PaBAT Analyses for Pollutants Not Subject to BACT or LAER

This section presents Pennsylvania best available technology (PaBAT) analysis for those

pollutants which are not subject to BACT and LAER.

Sulfur dioxide (SO2) will be emitted from the proposed Project’s combustion sources

including the ethane cracking furnaces, catalyst activation process heaters, Cogen Units,

emergency generators, firewater pumps, and the VOC control system. The Project’s

potential to emit for SO2 was determined by assuming that all of the sulfur in the fuel will

be released as SO2 when combusted. Based on this approach the combined SO2

emissions for the Project were determined to be below the major source threshold.135

135 The location of the proposed Project in Beaver County is in an area that is classified as nonattainment

with the 1-hr SO2 standard. As a result, NSR applicability was determined in accordance with the major

source threshold for listed sources.



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Selective catalytic reduction (SCR) technologies will be used to control NOx emissions

from the cracking furnaces and the Cogen Units using ammonia (NH3) as the selective

reducing agent. Ammonia emissions, known as NH3 slip, will result from the NH3 that is

not adsorbed on the SCR catalyst. The NH3 injection rate is controlled to ensure

compliance with the required NOx emissions limits while minimizing NH3 slip.

Finally, certain sources will potentially emit some quantity of hazardous air pollutants

(HAP) which are not subject to BACT or LAER.

For projects and modifications not subject to the major source or major modification

requirements of 25 Pa. Code §127.12(a)(5) requires that a new or modified source “show

that the emissions from a new source will be the minimum attainable using best available

technology.” The following sections address the BAT requirement associated with

emissions of SO2 and NH3.

5.14.1 SO2

In accordance with the §127.12(a)(5) requirement, the SO2 PaBAT limits presented in

Table 5-53 are proposed. Accepted approaches for controlling SO2 emissions include

add-on control technologies such as sorbent injection and flue gas desulfurization and use

of lower sulfur fuels. All of the proposed projects combustion sources will be fired with

either fuels that have very low concentrations of sulfur or no sulfur. The fuels that are

not a byproduct of the processes will be either pipeline quality natural gas or Tier II ultra

low sulfur diesel (i.e., <15 ppmw sulfur).

Control of SO2 via add-on control technology is widely applied to coal-fired and high

sulfur oil-fired combustion sources. Emissions of sulfur dioxide from the proposed

Project’s sources,136 which will fire either natural gas (i.e., ~2 ppmv S) or low-sulfur

136 There will be no sulfur in the tailgas that is fired in the cracking furnaces and the process vent gases that

result from manufacturing PE. The only process gas that will be combusted by the Project that will



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Table 5-53. Proposed Limitations to Meet SO2 BAT

Emission Unit Fuel Proposed Limit 1 Compliance

Demonstration

Cracking Furnaces Tailgas & NG 2 0.5 gr/100 dscf Pipeline NG 2

Cogen Units NG 2 0.5 gr/100 dscf Pipeline NG 2

Emergency Generators Diesel 15 ppmw S in fuel Fuel purchase

records

Firewater Pumps Diesel 15 ppmw S in fuel Fuel purchase

records

VOC Control System

& Spent Caustic Vent

Incinerator

NG 2 0.5 gr/100 dscf

Pipeline NG 2

1. The definition of pipeline natural gas at 40 CFR Part 72 includes the following: “Pipeline

natural gas contains 0.5 grains or less of total sulfur per 100 standard cubic feet.”

2. NG = natural gas

diesel (i.e., 15 ppmw), are significantly less than in coal-fired add-on control applications

where the coal sulfur content is measured in percentages of greater than one percent (i.e.,

1% = 10,000 ppmw). As a result, SO2 emissions from natural gas and low sulfur diesel

fuel are too low to make the use of either sorbent injection or flue gas desulfurization cost

effective on the basis of $/ton of SO2 removed.

Further removal of sulfur contained in the pipeline natural gas or Tier II ultra low sulfur

diesel is also cost prohibitive. To avoid corrosion in the pipeline, any appreciable amount

of sulfur present in natural gas produced at the wellhead is removed prior to placing the

gas into the pipeline. Ultra low sulfur diesel is produced at refineries via desulfurization

processes that operate under high pressure and use catalytic reactions to react hydrogen

with the fuel bound sulfur and remove it from the oil as H2S. In accordance with the fuel

sulfur requirements at 40 CFR §80.510(1), the proposed diesel engines will burn Tier II

mobile source diesel containing less than 15 ppmw sulfur. Treatment to remove

additional sulfur would require more severe hydrotreating by a refinery or at the proposed

contain sulfur is the spent caustic stripper off gas, which will contain less than 50 ppmv H2S and be

combusted in the Spent Caustic Vent Thermal Incinerator.



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new source. The cost to install and operate this additional treatment equipment and its

operation would not be justified by the level of SO2 emissions reductions.

Further, the RBLC database does not identify any add-on control technology

requirements for the projects with combustion sources fired by natural gas or low sulfur

diesel. Due to these findings, coupled with the economic infeasibility of add-on controls,

the PaBAT for SO2 emissions is considered the use of natural gas, as proposed.

5.14.1.1 Cracking Furnaces SO2 PaBAT

As described in Section 3.1, ethane cracking furnaces are large combustion sources used

to thermally crack ethane into ethylene. During normal operation, over 95% of the

furnaces’ heat input will come from firing tailgas (consisting of up to 85% hydrogen and

15% methane by volume) with the remainder of the fuel being natural gas. There will be

no sulfur present in the tailgas. During start up, pipeline quality natural gas will be used

until the tailgas production has begun. During operations, pipeline natural gas will be

used as a supplement.

The permit precedents summarized in the RBLC 137 for sources similar to the ethane

cracking furnaces (i.e., refinery fuel gas combustion devices, pyrolysis furnaces,

reformers, and recent cracking furnace precedents) indicate that the most stringent sulfur

content requirement on a lb/MMBtu basis is 0.0015 lb/MMBtu.138 The proposed

0.5 gr/100 limit is equivalent to 0.0007 lb/MMBtu. Compliance with this proposed limit

would be based on the use of pipeline natural gas.

5.14.1.2 Cogen Unit SO2 PaBAT

The proposed Project includes three natural gas-fired Cogen Units. A review of

combustion turbine based cogen precedents in the RBLC database (see Table F.1-3 in

Appendix F) indicated that the use of pipeline natural gas is consistent with the proposed

137 A complete summary of the identified precedents is included in Appendix F. 138 For purposes of comparison the permitted hourly mass rate limits were converted to a lb/MMBtu value

based on the rated heat input capacity provided in the RBLC.



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BAT. For purposes of the proposed Project’s Cogen Units, a sulfur content of 0.5

grains/100 scf (0.0007 lb/MMBtu) in the natural gas is proposed. Compliance with this

proposed limit would be based on the use of pipeline natural gas.

5.14.1.3 Emergency Generators and Firewater Pumps SO2 PaBAT

The project includes four diesel-fired emergency generator engines and three firewater

pump engines. Each of the engines will combust low sulfur diesel fuel containing

15 ppmw sulfur; the total annual SO2 emissions are estimated at 2.8 tons/yr. The SO2

emissions from these engines are low enough to exempt these engines from the PaDEP

Plan Approval Process. Nonetheless, the use of 15 ppmw sulfur diesel is proposed as

PaBAT. This sulfur level meets the lowest levels identified in the RBLC database for

similar sources (see Appendix E.1-4 and E.1-5). Though not required, this will meet

Condition 7 of the General Plan Approval for Diesel or No. 2 Fuel-fired Internal

Combustion Engines (BAQ-GPA/GP-9). This will also comply with 40 CFR §80.510(1)

requirement referenced in 40 CFR Part 60 subpart IIII, NSPS for Stationary Compression

Ignition Internal Combustion Engines, which requires the fuel sulfur content be no

greater than 15 ppmw.

5.14.1.4 VOC Control System SO2 PaBAT

As discussed in Section 3.5.5, the proposed Project will include three header systems and

a Spent Caustic Vent Thermal Incinerator that will be used to gather and control VOC

emissions during normal operation, startup, shutdown, and unforeseeable events at the

facility. No sulfur will be present in the vent streams controlled by the header systems.

Sulfur dioxide emissions from these systems may result from pipeline natural gas

combustion in the flare pilots and to support operation of the proposed thermal

incinerator at its operating temperature. For the proposed flares and incinerators, a sulfur

content of 0.5 grains/100 scf (0.0007 lb/MMBtu) in the natural gas is proposed.

Compliance with this proposed limit would be based on the use of pipeline natural gas.

Emissions of SO2 from the Spent Caustic Vent Thermal incinerator will result from the

combustion of any H2S that is stripped from the spent caustic and the supplemental



5-246

natural gas fuel that is used to ensure that the incinerator operates above a specified

operating temperature. The level of H2S in the stripped gas is expected to be less than

40 ppmv, which is well below the level where removal would be considered cost

effective. As a result, only a PaBAT sulfur content for the natural gas which is used to

ensure the specified operating temperature is proposed. For purposes of the proposed

Spent Caustic Vent Incinerator, a sulfur content of 0.5 grains/100 scf (0.0007 lb/MMBtu)

in the natural gas is proposed. Compliance with this proposed limit would be based on

the use of pipeline natural gas.

5.14.2 Ammonia (NH3)

The following limits are proposed as BAT for the ammonia emissions:

Cracking Furnaces: 10 ppmv at 3% O2, and

Cogen Units: 5 ppmv at 15% O2.

5.14.2.1 Cracking Furnace NH3 PaBAT

As discussed in Section 5.2, ethane cracking furnaces are different from boilers and

process heaters in both their design and operation. Due to fuel differences (i.e., high

hydrogen content) and the firebox temperatures required by cracking furnaces and

resulting burner issues, LNBs do not achieve the same NOx levels as when implemented

in boilers and process heaters. Though a review of the RBLC database of boilers and

process heaters was performed for completeness (and is presented in Table 1), the sources

are dissimilar enough to warrant an examination that focuses on recent permits for similar

cracking furnaces. Five (5) recently permitted ethylene plant expansions or new plants

located in Texas include:

BASF Fina Port Arthur, TX Cracking Furnace (10 ppmvd at 15% O2),139

Equistar Channelview, TX Op-2 Furnace (10 ppmvd at 3% O2 hourly),

Equistar Channelview, TX Op -1Furnace (10 ppmv at 3% O2),

139 Equivalent to 30.3 ppmvd @ 3% O2.



5-247

ExxonMobil Baytown, TX Furnace (15 ppmvd at 3% O2), and

Chevron Phillips Cedar Bayou, TX Furnace (10 ppmvd at 3% O2).

These facilities are also presented in Table E.2-1 of Appendix E.2. The range of NH2 slip

limits is from 10 ppmvd at 3% O2 hourly to 15ppmvd at 3% O2 hourly. These findings

support the proposed NH3 PaBAT limit of 10 ppmvd at 3% O2 (dry) for the cracking

furnaces.

5.14.2.2 Combustion Turbine NH3 PaBAT

The RBLC findings for NH3 slip limits for combined cycle turbines are presented in

Table E.2-2 of Appendix E.2. As shown, the NH3 limits range from 2 ppm at 15%

(steady state operations) to 10 ppmv at 15% O2 3 hr rolling average. The 2 ppm limit is

for the Kleen Energy Systems power plant in Middletown, CT for times of steady-state

operation firing natural gas. This site has experienced operating issues since its original

start-up. As a result, the facility has not yet demonstrated that the 2 ppmvd @ 15% O2

NH3 slip has been achieved at the catalyst end of run condition. It is therefore eliminated

from consideration. Three PaBAT determinations for NH3 in Pennsylvania at SCR-

controlled combined-cycle combustion turbines were identified. For these precedents

PaDEP determined a BAT level of 5 ppmvd at 15% O2. The facilities permitted at this

level include:

Moxie Liberty LLC – 10/10/2012,

Sunbury Generation – 04/01/2013, and

Hickory Run Energy Station – 04/23/2013.

Pursuant to BAT, these facilities must monitor the pre-control and post-control NOx

emissions by the feed-forward process control loop to ensure maximum control

efficiency and minimize NH3 slip. To be consistent with the recently approved BAT

determinations by the Pennsylvania DEP, the project proposes the same 5 ppmvd at 15%

O2 limit as BAT for the Cogen Units.



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5.14.3 Hazardous Air Pollutants (HAPs)

Each of the following sources that comprise the Project will potentially emit some

quantity of HAP: cracking furnaces, Cogen Units, emergency engines, incinerators and

flares, cooling towers, WWTP, fugitive emitting components. As a result, per 25 Pa.

Code 127.12(a)(5), each of these sources must have their emissions limited to the

minimum attainable through use of the best available technology (PaBAT). Organic

HAP is emitted from the Project’s combustion sources and has the potential to be emitted

from the Project’s process fugitive emitting components, water cooling tower, and

WWTP. The potential for metal HAP emissions is from the Project’s combustion

sources. The level of organic HAP that is emitted will be directly related to the amount

of VOC emitted while the amount of metal HAP emitted will be related to the amount of

fuel combusted. As a result, the VOC LAER limits will minimize the amount of organic

HAP emitted and the GHG BACT fuel efficiency limits will minimize the amount of

metal HAP emitted. A summary of the proposed HAP PaBAT is presented in Table

5-54. As shown, the proposed VOC LAER and GHG BACT efficiency requirements are

used as the basis for the proposal.

Table 5-54. Summary of Proposed PaBAT for HAP from the Proposed Project

Sources

Source PaBAT Proposal

Cracking Furnaces Sections 5.2.2 & 5.2.5 VOC & GHG LAER

Cogen Units Sections 5.3.2 & 5.3.5 VOC & GHG LAER

Emergency Engines Sections 5.4.1 and 5.4.4 VOC & GHG LAER

PE Process Vents Section 5.7.1 VOC LAER and Section 5.7.2

PM LAER

Equipment Leaks Section 5.5.1 VOC LAER

Spent Caustic Tanks Section 5.8 VOC LAER

Cooling Towers Section 5.9 VOC LAER

WWTP Section 5.10 VOC LAER

VOC Control System

Incinerators & Flares

Section 5.12 VOC LAER



6-1

6.0 Air Quality Modeling Analysis

An air quality dispersion modeling analysis was conducted for the proposed Project to be

located in Beaver County Pennsylvania. Details of the air dispersion modeling analysis

performed in support of the Project are presented in Appendix C. The analysis evaluated

emissions of the criteria pollutants regulated under the Prevention of Significant

Deterioration ("PSD") regulations of 40 CFR 52.21 as implemented under 25 Pa. Code

Chapter 127, Subchapter D. The criteria pollutant analysis was conducted to insure that

the proposed project will not cause or contribute to air pollution in violation of a National

Ambient Air Quality Standard ("NAAQS") or PSD increments.

The analyses quantify only the impacts of the pollutants that are emitted in amounts in

excess of the significant emission rates ("SERs"). For the proposed project, emissions of

nitrogen dioxides ("NO2"), carbon monoxide ("CO"), and particulate matter with an

aerodynamic diameter of less than 10 µm ("PM10") will be emitted in significant

quantities.

To determine if the Project would significantly impact local air quality, only the

emissions from the proposed Project were initially evaluated. The resultant modeled

concentrations from this effort were compared to the ambient Significant Impact Levels

("SILs") for Class I and Class II areas. The results of this significant impacts analysis

demonstrate that the proposed Project will result in ambient impacts in excess of the

Class II SIL only for the 1-hour NO2 standard. Impacts for all other pollutants were

determined to be less than the Class I and Class II SILs. Therefore, a refined air quality

analysis to determine concentrations for comparison to the NAAQS was required for the

1-hr NO2 standard.

The results from the NAAQS analysis for the 1-hour NO2 standard indicate modeled NO2

violations in the vicinity of the proposed Shell site. These modeled violations are

attributable to existing sources in the vicinity of the proposed Project’s site. However,

the proposed Project is shown not to cause or contribute to any of the existing modeled

exceedances of the 1-hour NO2 NAAQS.



6-2

Class II visibility impacts were also evaluated at the Raccoon Creek State Park and

determined to be acceptable.

The analysis conforms to the modeling procedures outlined in the Environmental

Protection Agency’s Guideline on Air Quality Models 140 ("Guideline") and associated

EPA modeling policy and guidance as well as the modeling protocol submitted to and

approved by the PaDEP on February 18, 2014.

For purposes of the modeling demonstration the following additional mass based

emission limits covering foreseeable operation are required:

Cracking Furnaces PM10:

o 2.480 lbs/hr on a 24-hr rolling average basis

o 2.264 lbs/hr on an annual basis

Cogen Units PM10:

o 11.385 lbs/hr on a 24-hr rolling average basis (all units combined)

HP Ground Flares PM10:

o 7.507 lbs/hr on a 24-hr rolling average basis

o 0.230 lbs/hr on an annual basis

HP Elevated Flare PM10:

o 0.289 lb/hr on a 24-hr rolling and annual average basis

Refrigerated Storage Flare PM10:

o 0.404 lb/hr on a 24-hr rolling average basis

Cooling Towers PM10:

o 0.125 lb/hr on a 24-hr rolling and annual basis

140 Guidelines on Air Quality Models, (Revised). EPA-450/2-78-027R, Appendix W of 40 CFR Part 51,

U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research

Triangle Park, North Carolina. November 2005.



7-1

7.0 Additional Impacts Analysis

In accordance with 40 CFR §52.21(o)(1) and (2), this section provides: 1) an analysis of

the potential for impairment to visibility, soils, and vegetation that could occur as a result

of the proposed Project, and 2) an analysis of air quality impacts projected for the area as

a result of general commercial, residential, industrial and other growth associated with

the proposed source. For purposes of presentation, the potential for impacts due to

growth are discussed first, followed by a discussion of the potential impacts to visibility,

soils and vegetation.

7.1 Analysis of Impacts Due to Growth

7.1.1 Overview

The proposed Project is a major stationary source (major source) subject to PSD program

requirements, including the requirement to analyze air quality impacts projected for the

area resulting from general commercial, residential, industrial, and other growth

associated with the Project. The growth analysis is used in conjunction with the air

quality impacts analysis to assess the impacts of activities that are not a part of the Project

but can reasonably be expected to occur as a result of the Project.

The growth analysis focuses on the permanent impacts during the operational phase of a

project. Aggregate air quality impacts during the construction phase of the project are

small in relation to the impacts during the operational phase, and permit applicants are

not required to consider these emissions in the growth analysis.141

For the proposed Project, quantifiable growth includes commercial and residential growth

related to the project workforce. Shell expects no industrial growth in the immediate

area, because existing markets for the Project’s product (i.e., polyethylene) already exist

141 U.S. EPA interpretive policy expressly calls for consideration of only “permanent residential,

commercial, and industrial growth,” excluding “temporary sources,” in the growth analysis under 40

CFR § 52.21(o). See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-

081), Oct. 1980, at page I-D-5.



7-2

within the area and region. No further chemical processing of the proposed Project’s

major product (i.e., PE) is required. Moreover, the Project will not produce the primary

raw material (ethane), but instead will receive ethane by pipeline.

7.1.2 Growth in Population

The proposed Project is located in Beaver County, Pennsylvania, approximately 35 miles

northwest of Pittsburgh. Beaver County is bordered on five sides by Allegheny, Butler,

Lawrence, and Washington Counties in Pennsylvania; Hancock county in West Virginia;

and, Columbiana County in Ohio. A 45-mile radius from the site also includes Brooke

County in West Virginia, and Mahoning County in Ohio.

Upon completion of construction, the Project will employ approximately 400 workers.

Shell expects to fill most of these permanent jobs from the local population. As the plant

converts from zinc smelting to cracker operations, Shell anticipates no significant change

in the permanent workforce, because Horsehead Corporation formerly employed

approximately 600 workers at the site. Thus, no residential growth is expected due to

direct job growth. However, when considering indirect and induced job growth arising

from increased economic activity, the Project may increase local employment by as much

as 2000-8000 permanent jobs.142 For purposes of this growth analysis, this higher growth

rate is assumed to result from the Project. As shown in the following analysis, the

emissions associated with this growth will not be substantial when compared to the

existing emissions inventory.

The U.S. Census Bureau tracks commuter flow patterns from one county to another.

According to data from 2006-2010, of the people who reside in the 10 county area but

work in Beaver County, 77 percent of the commuters also live in Beaver County.

Residents working in Beaver County and residing in one of the other nine counties

represent the remaining 13%. Less than one (1) percent of commuters reside in Jefferson

142 “Economic Impact Analysis of Proposed Petrochemical facility in Beaver County,” Pennsylvania

Economy League of Greater Pittsburgh, Sept. 18, 2012.



7-3

County, WV. As a result, this county was removed from further consideration in this

growth analysis.143

As shown in Table 7-1, the nine-county region encompasses over 4,282 square miles and

has a current population of individuals over the age of 18 of approximately 1.8 million

persons.

Table 7-1. Nine Counties Considered in Population Growth Impact Area144

County Land Area

(square

miles)

Population

Over 18

(2012)

Population

Density

(persons/mi2)

Project

Induced

Growth (# of

individuals)

Percent of

Beaver County

Workers living

in County

Allegheny, PA 730 995,764 1,676 574 7

Beaver, PA 435 135,661 392 6176 77

Butler, PA 788 142,596 233 218 3

Lawrence, PA 358 71,756 254 362 5

Washington, PA 857 165,136 243 87 1

Columbiana, OH 531 83,075 203 361 5

Mahoning, OH 411 185,765 580 62 1

Brooke, WV 89 19,559 269 62 1

Hancock, WV 83 24,244 371 96 1

Total 4282 1,823,556 8000

7.1.3 Growth in Air Pollutant Emissions

Based on population growth of 8000 individuals, the Project’s operations are expected to

cause indirect pollution growth in the nine county region of 0.44 percent, with the largest

growth likely occurring in Beaver County. The associated residential and commercial

growth will result in increased air pollutant emissions throughout this region.

7.1.3.1 Stationary Source Emissions

For the reasons described above, Shell expects no quantifiable industrial growth in the

area to occur as a direct result of the proposed Project.

143 See Table 2 Residence County to Workplace County Flows for the United States and Puerto Rico Sorted

by Workplace Geography: 2006-2010. Available at:

https://www.census.gov/newsroom/releases/archives/news_conferences/commuting.html#ccc_flows . 144 Population data from http://quickfacts.census.gov/qfd/states/16000.html. (Last accessed Feb. 26, 2013.)

https://www.census.gov/newsroom/releases/archives/news_conferences/commuting.html#ccc_flows

http://quickfacts.census.gov/qfd/states/16000.html



7-4

7.1.3.2 Other Area Source Emissions

It is anticipated that residential and commercial growth in the affected area will lead to

increased emissions from various categories of area source emissions. These categories

include residential and commercial fuel combustion, solvent usage, and waste disposal,

commercial cooking, commercial marine vessels, and gas stations. The emissions

increases associated with these categories were estimated by applying the highest

population growth rate (0.44%), to the existing inventory for the nine counties in

proportion to each county’s expected contribution to growth (as represented by the

commuter patterns). The area source emissions within the affected area are summarized

in Table 7-2. Also shown is a summary of the anticipated increases in emissions within

the affected area due to residential and commercial growth associated with the Project,

and provides a comparison with the existing emissions inventory in the nine county area.

Table 7-2. Other Area Source Emissions Increases Compared to Current Inventory

Pollutant

2011 Emissions

Other Area

Sources

(tons/yr)

Emissions

Increases

Other Area

Sources

(tons/yr)

2011 Total

Emissions

Inventory

(tons/yr)

Relative

Increase in

Affected

Area

(%)

CO 30,046 133 406,974 0.033

NOX 8,535 46 98,532 0.047

PM10 5,802 28 42,259 0.007

PM2.5 4365 23 17,063 0.001 VOC 19000 80 106,462 0.008

7.1.4 Air Quality Impacts

As shown in Table 7-2, residential and commercial growth associated with the proposed

Project will result in slight increases in air pollutant emissions in the surrounding area.

Because the anticipated emissions increases are very small in relation to the existing

emissions inventory, the impact on ambient air pollutant concentrations will not be

significant. Thus, no adverse impacts are anticipated.



7-5

7.2 Analysis of Impacts to Visibility

The CAA Amendments of 1977 require evaluation of new and modified emission sources

to determine potential impacts on visibility. The maximum increase in hourly particulate

matter and NOX emissions from the proposed Shell facility were used as input parameters

in the visibility analysis. Emissions were evaluated as described in the EPA Workbook

for Plume Visual Impact Screening and Analysis 145 to determine potential contribution to

atmospheric discoloration and visual range reduction. The results from this analysis are

presented in Section 7.0 of the Modeling Report included as Appendix C to this

document. Class II visibility impacts were evaluated at the Pittsburgh International

Airport and Raccoon Creek State Park and determined to be acceptable.

7.3 Analysis of Impacts to Soils and Vegetation

7.3.1 Overview

The pollutants included in this analysis of the potential for impairment to soils and

vegetation are PM, PM10, PM2.5, NOX, CO, and VOC. Consistent with EPA policy, we

did not include GHG in this analysis. The results of the soils and vegetation impact

analyses show that no significant impairment will occur as a result of the construction or

operation of the facility. Specific findings are documented in the following subsections.

7.3.2 Effects on Soil

For purposes of the soil analysis, information related to soils in the Beaver County area

was reviewed. The Natural Resources Conservation Service (“NRCS”) has published

soil survey data collectively covering Beaver and Lawrence counties. 146 The total land

area in Beaver County covered by this analysis is approximately 447 square miles. This

145 Workbook for Plume Visual Impact Screening and Analysis. US EPA, EPA Pub. No. 450/4-88-015.

RTP, NC. September 1988. 146 “Soil Survey of Beaver and Lawrence Counties, Pennsylvania,” U.S. Dept. of Agric. Soil Conservation

Service in cooperation with Penn. State Univ., Issued April 192. NRCS Soil Data Mart at

http://www.nrcs.usda.gov/Internet/FSE_MANUSCRIPTS/pennsylvania/PA603/0/gsm.pdf (last accessed

March 14, 2013).



7-6

exceeds the scope suggested by U.S. EPA guidance, which is limited to the area within

approximately 10 kilometers (i.e., ~120 square miles) of the proposed facility.147

The assessment of potential impacts on soils shows no likelihood of impairment from the

proposed project. The basis for this conclusion is summarized below. This conclusion is

likely representative of the lack of impairment throughout the larger 10-county area. This

is because greater levels of deposition to soil and a higher potential for impairment occur

closer to the project. Having found no likelihood of impairment within the Beaver

County, there is no likelihood of impairment further from the project.

7.3.2.1 Pollutant Impacts on Soils

At least 10 different soil types exist in the Beaver county area.148 Some of these soils are

moderate to well-drained, while others exhibit poor drainage characteristics. Most of the

soils in the NRCS maps units are classified as various varieties of silt loam, with the

surface soil pH ranging from 4.6 to 7.0. A readily accessible table of Beaver county soils

with key soil properties is available through the Pennystone Project.149

Current literature contains little information on impairment or other direct effects on soils

due to air pollution, and as part of this analysis no studies were identified in which

potential pollutant effects on the soils specific to the project area were evaluated. This is

consistent with U.S. EPA’s findings on this topic:

In contrast to the amount of published information on the effects of atmospheric

pollutants on plants and animals, very little has been reported on their effects on

soils. Research on trace elements in soils, often the same elements as

atmospheric pollutants, has been directed to notable deficiencies or excesses that

limit agricultural crop production. When the amount of an atmospheric pollutant

entering a soil system is sufficiently small, the natural ecosystem can adapt to

these small changes in much the same way as the ecosystem adapts to the natural

147 See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-081), Oct. 1980, at

page I-D-6, expressly limiting the soils and vegetation impairment analysis to the “impact area.” See,

also, the same document at page I-C-12, defining the impact area as “a circular area whose radius is

equal to the greatest distance from the source to which approved dispersion modeling shows the

proposed emissions will have a significant impact.” 148 Beaver River Conservation and Management Plan, Penn. Environmental Council, August 2008. 149 See http://www.pennystone.com/soils/beaver.php.



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weathering processes that occur in all soils. Cultural practices (e.g., liming,

fertilization, use of insecticides and herbicides) add elements and modify a soil

system more than a small amount of deposited atmospheric pollutant can The

secondary effects of the pollutant appear to impact the soil system more

adversely than the addition of the pollutant itself to the soil. For instance,

damaging or killing vegetative cover could lead to increased solar radiation,

increased soil temperatures, and moisture stress. Increased runoff and erosion

add to the problem. The indirect action of the pollutant, through changes to the

stability of the system, thus may be more significant than the direct effects on

soil invertebrates and soil microorganisms. However the lack of long-term

historical data on both the type and amount of atmospheric pollutants as well as

the lack of baseline data on soils has made difficult the task of determining the

effect of pollutants on soils by monitoring changes associated with exposure to

pollutants. A limited number of studies have been carried out on trace element

contamination in soils. Plant and animal communities appear to be affected

before noticeable accumulations occur in the soils. Thus, the approach used here

in which the soil acts as an intermediary in the transfer of deposited trace

elements to plants appears reasonable as a first attempt at identifying the air

quality related values associated with soils.150

Because deposition of NOX and other nitrogen compounds into soils in the survey area

could occur as a result of emissions from the facility, it is reasonable to consider whether

some marginal acidification of the soils might occur as a result of this project. Changes in

soil acidity caused by nitrogen deposition can affect tree growth, and affect lake and

stream acidification through nitrate (NO3-) leaching.

In 2007, the USDA Forest service undertook an assessment to estimate critical acid loads

(CAL) and exceedances for forest soils in the United States.151 A critical load is an

estimate of ecosystem exposure to a pollutant below which harmful ecosystem effects do

not occur, and above which there is an increased risk of adverse effects. A soil’s acid

neutralizing capacity (ANC) will affect an area’s critical load. The ANC is the ability of

the soil to buffer acids. Critical loads are typically expressed in terms of kilograms per

hectare per year (kg/ha/yr) of wet or total (wet + dry) deposition, and consider the soil’s

acid neutralizing capacity (ANC). For acidification, CAL is a function of both nitrogen

150 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on

Plants, Soils, and Animals (EPA-450/2-81-078). U.S. EPA, Office of Air Quality Planning and

Standards. Research Triangle Park, NC. December 1980. Pp. 17-19. 151 “Estimates of critical acid loads and exceedances for forest soils across the conterminous United States,”

Steven G. McNulty, et. al., Environmental Pollution 149 (2007) 281-292.



7-8

and sulfur deposition. Based on 1994-2000 data, the 2007 assessment reported areas in

Western Pennsylvania as having a CAL between 1000-2000 eq/ha/yr, with exceedances

of the CAL in this area of between 0 and 250 eq/ha/yr.

Importantly, however, the study concluded that these findings were preliminary, and that

additional research was needed before a CAL exceedance should be used as a tool for

identifying areas of potential concern. Moreover, the CAL estimates are based on 1994-

2000 data which occurred before a significant amount of the NOx and SO2 emissions

reductions occurred due to the Acid Rain Program, the Clean Air Interstate Rule (CAIR),

the NOx SIP call and other 1990 Clean Air Act Amendment emissions reductions

programs. In fact, the U.S. EPA reports a 31% decline in NO2 ambient air concentrations

(based on annual 98th percentile of daily max 1-hour average values) and a 67% decline

in SO2 ambient air concentrations (based on the annual 99th percentile of daily max 1-

hour averages) in the Northeast between the years 2000-2012.152 Thus, to the extent that

the estimated CAL levels have planning value, the reported exceedances may no longer

exist in the Northeast area due to the rapid decline in acidic deposition in the area.

The critical loads (CLs) for nitrogen deposition were considered. The National

Atmospheric Deposition Program (NADP) collects pollutant deposition data from a

number of national monitoring networks. There are four monitoring sites located in the

Western Pennsylvania area that are in relatively close proximity to the proposed Project’s

location. These include Goddard State Park (62 miles north), Laurel Hill State Park

(87 miles, southeast), Crooked Creek Lake (55 miles east), and Allegheny Portage

Railroad (115 miles east). The 2012 monitoring data from these sites indicted annual

NO3 deposition rates of 12.49 kg/ha, 15.57 kg/ha, 10.67 kg/ha, and 15.67, respectively.

Published CL values for NO3 deposition specific to the Beaver county area were not

identified. In general, however, it is recognized that broad areas of the entire eastern US

are likely exceeding empirical (CL) estimates for nitrogen. Studies for the broad

Northeastern US region have shown that nitrogen leaching begins to increase in some

152 See U.S. EPA emissions trends reports available at http://www.epa.gov/airtrends/.



7-9

forests soils at atmospheric nitrogen deposition greater than 8-12 kg N/ha/yr,153

Leaching, however, does not directly equate to an adverse effect, as the effect is related to

the CAL/ANC, and can be both positive or negative, depending on the species effected

(e.g. stunted growth of an invasive species would be a positive effect.)

As critical load information is unavailable for the Beaver county area, empirical values

developed for an application in the United Kingdom for habitats, which may be at least

remotely comparable to the Beaver County area, were considered.154 In 1982, NRCS

found that roughly 44% of the county was covered by woodlands, with 28% oak-hickory

cover, 23% elm-ash-red maple cover; 23% aspen-birch cover; 19% maple-beech-birch

cover; chestnut-oak 2 and white pine cover 4%. Roughly 5% of the area is used as

outdoor recreation land including state game lands, camps and golf courses, and large

parts of land support agricultural crops such as hay.155 This is largely consistent with a

study of the Beaver Creek Watershed that reported 43% of the study area comprised of

deciduous and coniferous forest, and 28% hay pastures.156 The U.K. recommended

critical load level for broadleaved, deciduous woodlands is 10-20 kg N/ha/yr; for

coniferous woodland is 5-15 kg N/ha/yr; and for mountain hay, and low and medium hay

meadows are 10-20 kg N/ha/yr and 20-30 kg N/ha/yr, respectively.

Notably, the monitored values from the 2012 NADP monitoring data represent a single

year of data. Data from earlier years are generally unavailable, and no useful annual

trends for the monitored sites are available. In a recent presentation, Penn State

Associate Professor Dr. Elizabeth Boyner indicated that there was a significant

downward trend in nitrate concentration in stream and lakes in near the Western

Pennsylvania area.157 This is indicative of an overall decrease in the nitrogen deposition

153 “Setting Limits: Using Air Pollution Thresholds to Protect and Restore U.S. Ecosystems,” Issues in

Ecology, Report No. 14, Fall 2011. Available at: http://www.esa.org/esa/wp-

content/uploads/2013/03/issuesinecology14.pdf. 154 See data available through the Air Pollution Information System, http://www.apis.ac.uk/. 155 See NRCS Soil Data Mart and Section 2.3 of this Report - Effects on Vegetation. 156 PA. Envir. Council at 64. 157 “Atmospheric Deposition in Pennsylvania & Impacts on Watersheds,” Penn State Water Resources

Extension Webinar Series, Sept. 4, 2013.



7-10

rate. Given this, it is reasonable to assume that monitored values from the NADP

similarly represent one point on a declining curve.

After reviewing all of this information, and recognizing that “[t]here is no single

‘definitive’ critical load for a natural resource,” it is concluded that the Project will not

cause additional impairment of soils in this area.158 This finding is based on the

decreasing levels of acid deposition and nitrogen deposition in the area. In addition, to

the extent that any of the identified acid and nitrogen CL values have meaning for the

Beaver county area, it should be noted that the NADP values are near values at which

leaching (but not necessary adverse effects) only begins to occur, and they are close to or

well below levels recommended CLs for potentially comparable ecosystems in the U.K.

Finally, this project will result in a net decrease of approximately 500 tpy of NOx in the

area from offsets, further contributing to the likelihood that the proposed Project will not

cause further impairment to soils.

7.3.2.2 Effects on Vegetation

Pursuant to 40 CFR § 52.21(o), our initial analysis is limited to vegetation having

significant commercial or recreational value. The assessment of potential impacts on

vegetation shows no likelihood of impairment from the proposed project. The basis for

this conclusion is presented below.

7.3.2.3 Identification of Vegetation with Significant Commercial Value

This analysis of impacts to commercial vegetation covers both the entire ten-county area.

This exceeds the scope suggested by U.S. EPA guidance, which is limited to the area

within the impact area of the proposed facility (10 km).159

158 “Integrated Science Assessment” at p 250. 159 See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-081), Oct.

1980, at page I-D-6, expressly limiting the soils and vegetation impairment analysis to the “impact area.”

See, also, the same document at page I-C-12, defining the impact area as “a circular area whose radius is

equal to the greatest distance from the source to which approved dispersion modeling shows the

proposed emissions will have a significant impact.”



7-11

Table 7-3 lists the commercially significant vegetation in the ten-county study area. As

shown, approximately 14 percent of the land area in the ten-county study area is used for

harvested crops; of this total, approximately 92 percent is used for corn as grain, corn as

silage, other forage (e.g. hay), and soybeans. Based on the results of the vegetation

survey, the following were identified as the principal crops for study in this analysis:

Corn for grain (Zea mays)

Corn for silage or greencrop

Oats for grain ((Avena sativa)

Vegetables for harvest

Other forage (other hay, etc.)

Soybean for beans

7.3.2.4 Identification of Vegetation with Potential Recreational Value

To identify vegetation with potential recreational value, the Beaver County Natural

Heritage Inventory (NHI) was reviewed. The NHI, identifies areas within the county that

are of importance for biological diversity and ecological integrity of the County. Within

Beaver County, the NHI identified two areas as Dedicated Areas (DA). A DA is an area

that is specifically dedicated for protection for ecological and biological diversity. DAs

within Beaver County include the Raccoon Creek State Park and Wildflower Reserve,

(located approximately 17 miles northwest of the proposed Project site); and the Ohio

River Islands National Wildlife Refuge, Georgetown Island (approximately 11 miles west

of the proposed Project site), and Phillis Island (approximately 9 miles west of the

proposed Project site). Of these two, only Raccoon Creek State Park is listed as habitat

for several plant species of concern.

Beaver County also includes five Biological Diversity Areas (BDAs) within Potter

Township. A BDA identifies areas supporting a special species or a large number and

kinds of species. The BDA’s within Potter Township include the Lower Raccoon Creek

[which includes a northern hardwood forest community; a Mesic central forest

community; dry-mesic acidic central forest community; a robust emergent Marsh

community; and habitat for a plant species of special concern (SP001)]; Monaca Bluffs

[which includes habitat for two plant species of concern (SP002 and SP003); and two



12

Table 7-3. Commercially Significant Vegetation in Ten-County Study Area (Acres)

Beaver Allegheny Butler Lawrence Washington Total

Total Land Area 278,214 467,251 504,704 229,235 548,473 2,027,877

Harvested Cropland 24,426 8,689 63,341 52,580 75,163 224,199

Corn for Grain 3,508 538 14,920 18,328 4,205 41,499

Corn for Silage/Greenchop 848 141 3,320 3,876 -- 8,185

Wheat for Grain (all) 849 -- -- -- -- 849

Oats for Grain 206 895 3,163 2,549 1,080 7,893

Barley for Grain 155 44 435 148 782

Vegetables Harvested for Sale 787 803 1,225 211 664 3,690

Sweet Corn -- 398 -- -- 398

Cut Christmas Trees 392 281 562 88 332 1,655

Other Forage (hay, haylage, grass,

silage, & greenchop)

15,568 6,188 31,597 18,011 63,795 135,159

Soybeans for Beans 1,386 6,112 8,428 1,319 17,245

Blueberries, Raspberries, Strawberries 20 41 51 200 15 327

Land in Orchards 174 126 183 90 239 812



13

Table 1-3. Commercially Significant Vegetation in Ten-County Study Area (Acres) – cont’d

Columbiana Mahoning Brook Jefferson Hancock Total

Total Land Area 339,840 263,040 56,960 53,120 134,400 847,360

Harvested Cropland 79,340 41,656 4,594 38,351 2,190 166,131

Corn for Grain 20,932 12,839 9,164 7,198 212 50,345

Corn for Silage/Greenchop 5,216 3,558 84 4,186 13,044

Wheat for Grain (all) 5,963 2,835 3,985 130 12,913

Oats for Grain 2,560 1,255 69 50 100 4,034

Barley for Grain 29 175 1 391 596

Vegetables Harvested for Sale 274 908 -- 118 30 1,330

Sweet Corn -- -- -- -- -- 0

Cut Christmas Trees 256 258 -- 227 v 741

Other Forage (hay, haylage, grass,

silage, & greenchop)

28,328 10,477 4,199 15,696 1,789 60,489

Soybeans for Beans 17,036 10,051 -- 7,930 -- 35.017

Blueberries, Raspberries, Strawberries 49 31 -- -- -- 80

Land in Orchards 395 189 -- 828 -- 1,412



7-14

natural communities (NC005 and NC006)]; Ohio River [habitat for several fish species of

concern]; Ohioview [which includes a rivertine forest community (NC008) and habitat

for species of concern (SA004, SA005, SA007, SA008 and SA010).]

A search of the Pennsylvania Natural Diversity Inventory Index to identify potential

impacts to threatened and endangered, and/or special concern plant species within the

project area was as conducted. The PNDI is a database run by the Pennsylvania Natural

Heritage Program that provides information on the location and status of important

ecological resources. A search of the PNDI Database (Search #20140318443038)

indicated that further development of the proposed Project site should have no known

impacts on plant species federally protected under the Endangered Species Act, and no

known impact on Pennsylvania plant species of special concern if conservation measures

are implemented within the riparian buffer.

To evaluate whether any vegetation outside of the Beaver County area, but within the ten

county region might contain vegetation of special concern, the 2009 Environmental

Report, produced by the Nuclear Regulatory Commission (NRC) to support approval of

the license renewal for the Beaver Valley Nuclear Plant (BVNP) was reviewed. BVNP is

located 7 miles west of the proposed Project site. As shown in Table 7-4, the NRC

identified 11 Pennsylvania-listed plant species that have the potential to occur within the

vicinity (50 mile radius) of BVNP.160,161,162 The NRC noted that none of these plants

were identified in a 2002 survey of the area, and the NRC concluded that tall larkspur

(Delphinium exaltatum) was the only species of plant that had the potential to occur in

the impact area in the future. No records exist that document its historical occurrence in

160 The Beaver Valley Nuclear Plant is located approximately 7 miles west of the Franklin Ethane Cracker

facility. The application for permit renewal and final environmental report considered impacts within a

50 miles radius of the facility. 161 No federally-listed, vegetation species were identified with the potential to occur in the vicinity. 162 “Generic Environmental Impact Statement for License Renewal of Nuclear Plants,” NUREG-1437,

Supplement 36, Nuclear Regulatory Commission, p 81, May 2009.



7-15

Table 7-4. Pennsylvania-Listed Plant Species with Potential to Occur in Vicinity of

Beaver Valley Nuclear (BVN) Plant (7 miles from the Proposed Project Site)

Species Common Name State Listing Status

Carex typhina Cattail sedge Endangered Clematis viorna Vasevine Endangered

Delphinium exaltatum tall larkspur Endangered*

Helianthemum bicknellii Hoary frostweed Endangered

Juncus torreyi Torrey’s rush Threatened

Lithospermum latifolium American stoneseed Endangered

Matelea obliqua Climbing milkvine Endangered

Myriophyllum sibiricum Northern water-milfoil Endangered

Potamogeton tennesseensis Tennessee pondweed Endangered

Cypripedium calceolus var.

parviflorum

Lesser yellow lady’s slipper Endangered

*Only species determined by NRC for potential to occur within vicinity of BVN plant.

the Beaver County area, however, there is a record of occurrence before 1980 in

Allegheny and Butler Counties, and after 1980 in Washington County.163 164

7.3.2.5 Identification of Pollutants of Concern

There are substantial scientific data characterizing the effects of air pollutant emissions

on certain crops (e.g., common wheat), whereas there are limited data available for other

crops. This subsection discusses the methodology utilized to identify air pollutants, and

constituents thereof, to which the identified crops and recreational vegetation may be

sensitive. Air pollutants can affect crops through two principal means:

Direct phytotoxic effects from air concentrations of pollutants; and

Indirect phytotoxic effects due to deposition of pollutants in soils in which the

crops are growing.

Direct Phytotoxic Effects of Air Pollutants: Of the gaseous air pollutants covered by

this analysis, only NOX (i.e., NO and NO2) is known to be toxic to some plants at

moderate to high concentrations in the ambient air. Carbon monoxide and volatile

163 Id. 164 Tall Larkspur (Delphinium exaltatum) Fact Sheet, Pennsylvania Natural Heritage Program.



7-16

organic compounds are generally not phytotoxic.165,166,167,168 Thus, these pollutants were

not considered further by this analysis. Studies linking gaseous species of nitrogen (N) to

plant foliar damage have been conducted well above concentration levels occurring in the

United States. Thus, there is little evidence to show that current U.S. concentrations of

gaseous phase N cause phytotoxic effects.169 In the 2008 review of the secondary NO2

NAAQS, EPA concluded that agricultural ecosystems are not sensitive to N

concentrations found in the U.S.170

7.3.2.6 Determination of Effects Concentrations

This section discusses the methodology used to determine the air pollutant concentrations

that may be expected to result in adverse effects to the vegetation species.

Direct Phytotoxic Effects: As is customary for this type of analysis, the assessment

relied heavily on the screening criteria in the U.S. EPA report, A Screening Procedure for

the Impacts of Air Pollution Sources on Plants, Soils, and Animals.171 This document

establishes the air pollutant concentrations that are generally viewed by U.S. EPA to be

protective of soils and vegetation having significant commercial or recreational value,

including agricultural crops, based on a broad review of pertinent scientific literature.



Standards. Research Triangle Park, NC. December 1980. p. 11. 166 Air Quality Criteria for Carbon Monoxide. U.S. Department of Health, Education, and Welfare, Public

Health Service, National Air Pollution Control Administration. Washington, DC. March 1970. pp. 7-1

through 7-3. 167 Air Quality Criteria for Hydrocarbons. U.S. Department of Health, Education, and Welfare, Public

Health Service, National Air Pollution Control Administration. Washington, DC. March 1970. pp. 6-1

through 6-9. 168 E.M. Hulzebos et al. “Phytotoxicity Studies with Lactuca Sativa in Soil and Nutrient Solutions.”

Environmental Toxicology and Chemistry. Volume 12. 1993. pp. 1079-1094. 169 “Executive Summary Integrated Science Assessment Oxides of Nitrogen and Sulfur Ecological

Criteria.” EPA/600/R-08/082F, Dec. 2008. 170 ISA at 713. 171 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on


Standards. Research Triangle Park, NC. December 1980.



7-17

The secondary National Ambient Air Quality Standards (NAAQS),172 which are

established by U.S. EPA at levels that are protective of the public welfare, including

agriculture, are also relied on.

Indirect Deposition Effects: Two general approaches have been used in establishing

deposition rate limits and soil concentration limits: a) preventing accumulation of

pollutants in soils; and b) maximizing the capacity of soils to assimilate, attenuate, and

detoxify pollutants. The first approach is based on the premise that soil can be used

without any undue restriction if it is maintained free of contamination; if pollutants are

artificially introduced and are allowed to accumulate in the soil, then, over the long term,

the potential uses of the soil may become limited. The second approach is based on the

premise that soils have a capacity to detoxify pollutants. This approach has been applied

by the U.S. EPA and by the World Health Organization.173

7.3.2.7 Results

This section presents the results of dispersion modeling for each air pollutant, and

assesses these results with respect to effects levels.

NOX Effects: NOX includes both nitric oxide (NO) and nitrogen dioxide (NO2), and

much of the scientific literature treats these two gases separately.

Based on the results of the air quality impacts analysis, the maximum predicted ambient

NOX concentrations due to emissions from the facility are 44.2 μg/m3 (1-hour average)

and 0.79 μg/m3 (annual average). These values represent total NOX, including both NO

and NO2. These impacts are one to two orders of magnitude below the secondary

NAAQS of 100 μg/ m3 (annual average)174 and the minimum U.S. EPA screening values

172 See, 40 CFR part 50. 173 A.C. Chang, et al. Developing Human Health-related Chemical Guidelines for Reclaimed Water and

Sewage Sludge Applications in Agriculture. World Health Organization. Copenhagen, Denmark. May

2002. pp. 19-41. 174 40 CFR § 50.11(c).



7-18

of 3,760 μg/ m3 (4-hr average) and 94 μg/ m3 (annual average).175 Both the secondary

NAAQS and the screening value are expressed in terms of NO2; there are no NAAQS or

screening values for NO.176

The agricultural crops for which the minimum U.S. EPA screening value is listed as

being protective include barley, corn, oats, vegetables (carrot, lettuce, leek, broccoli,

radish, peas). The principal crops identified in the 10-county area (Table 7-4 above) that

are not specifically listed in the Screening Procedures report are soybean and forage (e.g.

hay).177

The literature was reviewed to ascertain whether there exists, in the scientific literature,

any basis for concluding that: a) the secondary NAAQS and the minimum U.S. EPA

screening value are not protective of any of the crops identified herein; or b) the facility’s

NOX emissions will have an unacceptable, adverse impact on agricultural crops in the

five-county study area. A summary of the findings follows.

In April 2012, U.S. EPA issued a final rule retaining and affirming the secondary NO2

NAAQS of 100 μg/ m3 (annual average).178 This action reflected both the U.S. EPA

Administrator’s finding that this standard is “adequate to protect against direct phytotoxic

effects on vegetation”179 and the judgment that an alternative standard to protect against

deposition-related effects is not supported by currently available data.180 The data relied

upon by U.S. EPA with respect to direct phytotoxic effects are summarized in the

Integrated Science Assessment,181 including the following observations:



Standards. Research Triangle Park, NC. December 1980. p. 11. 176 Ibid. 177 Ibid at p. 68. 178 See, generally, 77 Fed. Reg. 20218. April 3, 2012. 179 Ibid at p. 20241. 180 Ibid at pp. 20262-63. 181 Integrated Science Assessment for Oxides of Nitrogen and Sulfur – Ecological Criteria (EPA-600/R-08-

082F). U.S. EPA, Office of Research and Development. Research Triangle Park, NC. December 2008.



7-19

An analysis of over 50 peer-reviewed reports on the effects of NO2 on foliar

injury indicated that plants are relatively resistant to NO2. With few exceptions,

visible injury was not reported at concentrations below 377 μg/ m3, and these

occurred when the cumulative duration of exposures extended to 100 hours or

longer.

Soybean, peas (Pisum sativum L.) radish (Raphanus sativus L.) are among

numerous plant species for which no phytotoxic effects were documented based

on exposure to NO2 at 189 μg/ m3.182

In 2000, the WHO instituted a NOX guideline concentration value of 30 μg/m3 on an

annual average (including both NO and NO2, expressed as NO2). The WHO declined to

institute a short-term value, saying “[t]here are insufficient data to provide these levels

with confidence at present,” but indicated that current evidence would suggest a guideline

NOX concentration value of about 75 μg/m3 on a daily average. The guideline

concentration value is intended to be protective of all classes of vegetation under all

environmental conditions.183

In summary, the scientific literature affirms that the secondary NAAQS and the minimum

annual U.S. EPA screening value are protective of the crops identified herein. The

maximum predicted NOX concentration resulting from the Project and other emission

sources in the area is well below the secondary NAAQS, the minimum U.S. EPA

screening value, guideline concentration values established by foreign governmental

agencies, and concentrations that are identified in the literature as being harmful to

commercially significant vegetation in the ten-county study area.

A search was conducted to determine whether any information identifies a unique

sensitivity of tall larkspur, the only endangered plant species NRC identified with

potential to occur within the vicinity of the Beaver Valley Nuclear plant (and hence the

vicinity of the Project). Tall larkspur grows in meadows at high elevations and is

poisonous to cattle. Efforts to develop an effective herbicide program have led to

182 Ibid at pp. 3-200 through 3-201. 183 Air Quality Guidelines for Europe, 2nd Ed. World Health Organization, Regional Office for Europe.

Copenhagen, Denmark. 2000. pp. 230-233.



7-20

experiments with a high rate of N application on the plant. A variety of these studies

demonstrate that tall larkspur is generally resistant to high concentration N application,

and that herbicide mortality is linked to salt concentrations, not N concentrations.184

7.3.2.8 Conclusion

Based on the effects analysis described herein, the facility’s emissions are not expected to

result in adverse effects to soils, crops, or plant species of concern, within the vicinity of

the Project site. For each pollutant of concern, the predicted ambient concentration or the

predicted deposition rate is well below the secondary NAAQS and the minimum

screening values established by U.S. EPA. Nothing in the scientific literature identified

during this review indicates that the secondary NAAQS and the minimum U.S. EPA

screening values are not protective of any identified crops and, the predicted ambient

concentration or the predicted deposition rate is less than the screening values established

by other governmental authorities. Moreover, the only identified plant species of

concern, tall larkspur, is resistant to N application in experimental studies.

184 “Mechanism by which ammonium fertilizer kill tall larkspur,” Woolsey, et.al., Journal of Range

Management, 56, 524-528, Sept 2003. (citing results of various historical studies).

Appendix A Plan Approval Application Forms

Section B - Processes Information (Ethylene Manufacturing) 1. Source Information

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Ethylene manufacturing process is described in detail in Section 3.1 of the Plan Approval Application.

Manufacturer To be determined

Model No. Number of Sources

Source Designation Maximum Capacity Rated Capacity Ethylene: 1,500,000 metric tons/yr

Type of Material Processed

Maximum Operating Schedule Hours/Day 24

Days/Week 7

Days/Year 7

Hours/Year 365

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE)

Capacity (specify units) Per Hour Per Day Per Week Per Year

1,500,000 metric tons/yr Operating Schedule Hours/Day 24

Days/Week 7

Days/Year 7

Hours/Year 365

Seasonal variations (Months) From to If variations exist, describe them

N/A

2. Fuel

Type Quantity Hourly Annually Sulfur

% Ash (Weight) BTU Content

Oil Number GPH @ 60°F X 103

Gal % by wt

Btu/Gal. & Lbs./Gal. @ 60 °F

Oil Number GPH @ 60°F X 103

Gal % by wt


Natural Gas SCFH X 106

SCF grain/100

SCF Btu/SCF

Gas (other) SCFH X 106

SCF grain/100

SCF Btu/SCF

Coal TPH Tons % by wt Btu/lb

Other *

*Note: Describe and furnish information separately for other fuels in Addendum B.

Section B - Processes Information (Ethylene Manufacturing) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. See the Plan Approval Application as follows: A detailed project description containing flow diagrams is included as Section 3.1. Raw materials and capacity information are provided in Appendices B and D. No restrictions on the production capacity are requested.

Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. N/A

Describe each proposed modification to an existing source. N/A

Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of the fugitive emissions points is presented in Section 5.0 of the Plan Approval Application Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate startup and shutdown BACT/LAER limits are proposed. A VOC control system will be used to minimize emissions during startup, shutdown, and upsets. The VOC Control System LAER proposal (see Section 5.12) includes submittal of a waste gas minimization plan (WGMP) along with the performance of a root cause and corrective action analysis in response to events greater than a defined trigger level. The proposed WGMP will include procedures to minimize emissions during startup, shutdown, and upset. Anticipated Milestones:

i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018

Section B – Combustion Unit Information (Ethane Cracking Furnaces (7x)) 1. Combustion Units: Coal Oil Natural Gas Other:

Tailgas (85% hydrogen & 15% methane by volume) Description: ETHANE CRACKING FURNACES: Furnaces will be fired with a fuel comprised of

tail gas and a makeup portion of natural gas defined by the systems fuel balance. In the presence of steam, ethane will be thermally cracked to form ethylene. As part of the cracking

process, other cracking side products will be formed. Tail gas is a side product of the cracking process.

Manufacturer TBD

Model No.

Number of units Seven (7)

Maximum heat input (Btu/hr) 620 MM (each)

Rated heat input (Btu/hr)

Typical heat input (Btu/hr)

Furnace Volume

Grate Area (if applicable) N/A

Method of firing

Indicate how combustion air is supplied to boiler N/A Indicate the Steam Usage:

Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed

iv. Other v. Frequency of Cleaning

As part of the cracking process, coke is formed on the process side of the furnace tubes. As a result, the tubes in each cracking furnace are decoked once every 30 to 60 days. To ensure complete combustion the exhaust gases generated by the decoking process are directed back into the cracking furnace.

Maximum Operating schedule (per Furnace) Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)

Capacity (specify units) Per hour

Per day

Per week

Per year

Typical Operating schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: From to Operating using secondary fuel: Form to Non-operating: From to 2. Specify the primary, secondary and startup fuel. Furnish the details in item 3.

During start-up, furnaces are fired on natural gas until ethane cracking begins and self-produced tail-gas becomes available. At that point the furnace is primarily tailgas-fired with some natural gas being used to meet the process’ heat balance requirements.

Section B - Combustion Unit Information (Ethane Cracking Furnaces (7x)) (Continued) 3. Fuel



Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas

77,200 SCFH

X 106

Gal

0.5 gr/100 SCF

1020 Btu/SCF

Gas (other)

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF

Coal Other* Tailgas 1,174,000 0% 461 Btu/SCF * Note: Describe and furnish information separately for other fuels in Addendum B. 4. Burner Manufacturer TBD

Model Number

Type of Atomization (Steam, air, press, mech., rotary cup)

Number of Burners TBD

Maximum fuel firing rate (all burners)

Normal fuel firing rate

If oil, temperature and viscosity. Maximum theoretical air requirement Percent excess air 100% rating Turndown ratio Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe. Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. 5. Nitrogen Oxides (NOx) control Options

Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) x Low-NOx burner Low NOx burners with over fire

air

Flue gas recirculation Burner out of service Reburning x Flue gas treatment (SCR /

SNCR)

Other:.

Section B - Combustion Unit Information (Ethane Cracking Furnaces (7x)) (Continued)

6. Miscellaneous Information

Describe fly ash reinjection operation N/A

Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.

NOx monitoring will meet 40 CFR Part 75 requirements as referenced by 25 Pa. Code Ch. 145.

Describe each proposed modification to an existing source.

N/A

Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.

Emissions will be minimized through operation in accordance with the proposed BACT/LAER limits cracking furnace limits and the waste gas minimization plan. Emissions estimates associated with startup and shutdown of the cracking furnaces are provided in Appendix B of the Plan Approval Application.

Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable). N/A

Anticipated milestones:

Expected commencement date of construction/reconstruction: Late 2015 Expected completion date of construction/reconstruction: 2018 Anticipated date(s) of start-up: 2018

Section C - Air Cleaning Device (Ethane Cracking Furnaces (7x))

1. Precontrol Emissions* Please refer to Appendix B in the Plan Approval Application for this emissionsdataEmission Rate

Pollutant

Maximum Emission Rate Calculation/ Estimation

Method Specify Units Pounds/Hour Hours/Year Tons/Year PM

PM10

SOx

CO

NOx

VOC

Others: (e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operatingschedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emissionvalues were determined. Attach calculations.

2. Gas Conditioning – N/A

Water quenching YES NO Water injection rate GPM

Radiation and convection cooling YES NO Air dilution YES NO

If YES, CFM

Forced draft YES NO Water cooled duct work YES NO

Other

Inlet volume

ACFM@ °F

Outlet volume

ACFM@ °F % Moisture

Describe the system in detail.

* Please refer to the Plan Approval Application for a detailed process description.

Section C - Air Cleaning Device (Ethane Cracking Furnaces (7x)) (Continued)

8. SELECTIVE CATALYTIC REDUCTION (SCR)

SELECTIVE NON-CATALYTIC REDUCTION (SNCR)

NON-SELECTIVE CATALYTIC REDUCTION (NSCR)

Equipment specifications Manufacturer

To be determined

Type Model No

Design inlet volume (SCFM) Design operating temperature (°F)

Is the system equipped with process controls for proper mixing/control of the reducing agent in gas stream? If yes, give details.

Attach efficiency and other pertinent information (e.g., Ammonia, urea slip). SCR will be designed to meet the proposed NOx LAER/BACT limits (See Section 5.2.1 of the Plan Approval Application). Operating parameters

Volume of gases handled (ACFM) @ (°F) Operating temperature range for the SCR/SNCR/NSCR system (°F) From To

Reducing agent used, if any. Ammonia

Oxidation catalyst used, if any.

State expected range of usage rate and concentration.

Service life of catalyst Ammonia slip (ppm) 10 ppmvd @ 3% O2

Describe fully with a sketch giving locations of equipment, controls system, important parameters and method of operation.

Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.

Emissions data: Please refer to Section 5.2 and Appendix B of the Plan Approval Application for this emissions data.

Pollutant Inlet Outlet Removal Efficiency (%) NOx 0.01 lb/MMBtu Annual

Avg. 85 – 90%

NOx 0.015 lb/MMBtu 24-hr rolling avg.

85 – 90%

Section C - Air Cleaning Device (VOC Control System- HP System Ground Flares (2x)) (Ethylene Manufacturing)

1. Precontrol Emissions* See Appendix B of the Plan Approval Application

Pollutant


Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operatingschedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emissionvalues were determined. Attach calculations.

2. Gas Cooling

Water quenching Yes No Water injection rate GPM

Radiation and convection cooling Yes No

Air dilution Yes No If yes, CFM

Forced Draft Yes No Water cooled duct work Yes No

Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. NOTE: This is the same HP Flare System presented in the forms for PE Plants.

Section C - Air Cleaning Device (VOC Control System -HP System Ground Flares (2x)) (Ethylene Manufacturing) (Continued)

12. Flares Equipment Specifications


Type Elevated flare Ground flare Other Describe

Model No.

Design Volume (SCFM)

Dimensions of stack (ft.) Diameter 55 Height 110

Residence time (sec.) and outlet temperature (°F) 1832

Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring

Describe the operation of the flare’s ignition system.

Describe the provisions to introduce auxiliary fuel to the flare.

Operation Parameters

Detailed composition of the waste gas

Heat content

Exit velocity

Maximum and average gas flow burned (ACFM)

Operating temperature (°F)


Emissions Data See Appendix B of the Plan Approval Application

Pollutant Inlet Outlet Removal Efficiency (%)

Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare)

(Ethylene Manufacturing)


Pollutant


Method Specify Units Pounds/Hour Hours/Year Tons/Year PM PM10 SOx CO NOx VOC Others: (e.g., HAPs) ----- ----- ----- ----- ----- * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating

schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.

2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. NOTE: This is the same HP Flare System presented in the forms for the PE Plants..

Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare) (Ethylene Manufacturing) (Continued)

12. FLARES Equipment Specifications

Manufacturer


Model No.


Dimensions of stack (ft.) Diameter Height


Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or non-assisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted. Refer to Section 3.5.5 and Section 5.12 of the Plan Approval Application for full flare description. Pilot flame monitoring. Describe the operation of the flare’s ignition system.


Operation Parameters See Appendix B of the Plan Approval Application Detailed composition of the waste gas

Heat content

Exit velocity






Section C - Air Cleaning Device (Ethylene Manufacturing) (Continued)

10. Costs – Refer to Section 5.0 of the Plan Approval Application

Indicate cost associated with air cleaning device and its operating cost (attach documentation if necessary)

Device Direct Cost Indirect Cost Total Cost Operating Cost

11 MISCELLANEOUS Describe in detail the removal, handling and disposal of dust, effluent, etc. from the air cleaning device including proposed methods of controlling fugitive emissions.

N/A

Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).

Expected guarantees of control system performance consistent with levels determined as BACT/LAER/BAT.

ch the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.

Maintenance will be performed per manufacturer’s recommendations, as needed during operations, and during planned or forced outages as necessary.

Section E - Compliance Demonstration (Ethylene Manufacturing)

Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Method of Compliance Type: Check all that apply and complete all appropriate sections below.

Monitoring Testing Reporting

Recordkeeping Work Practice Standard

Monitoring: Refer to Table 5-1 of the Plan Approval Application for more information a. Monitoring device type (stack test, CEM etc.): NOx and CO: CEMs;

VOC and PM/PM10/PM2.5:Stack test; CO2e/GHG; In-line gas chromatograph or 40 CFR 98.34(b)(3)

b. Monitoring device location: NOx (upstream of SCR and stack); CO (stack); Fuel Supply

c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter: Continuous measurement of NOx and CO concentration, and volumetric flow rate, 5 year performance test for PM and VOC, and hourly monitoring of total fuel flow, HHV, carbon content and MW.

Testing: a. Reference Test Method Citation: PM: EPA Method 5, and 202.

VOC: EPA Method 18, 25,

CO2e/GHG: 40 CFR 98.34(b)(3)

b. Reference Test Method Description: Method 18-Measurement of Gaseous Organic Compound Emissions by Gas Chromatography; Method 25-Determination of Total Gaseous Nonmethane Organic Emissions as Carbon; Method 5 – Determination of Particulate Matter Emissions from Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources. 40CFR 98.34(b)(3) – Contains procedure for determining carbon content and molecular weight of fuels.

Recordkeeping: Describe the parameters that will be recorded and the recording frequency:

Records kept for continuous measurement of NOx and CO concentration and volumetric flow rate (15-minute value), 5 year performance test for PM and VOC, and hourly monitoring of total fuel flow, HHV, carbon content and MW (daily).

Reporting: a. Describe the type of information to be reported and the reporting frequency:

Reporting of required monitoring in compliance with regulations listed in Appendix G of the Plan Approval Application. Submittal of reports of required monitoring semi-annually per 25 Pa. Code § 127.511(c)

b. Reporting start date: To be determined

Work Practice Standard: Describe each: Good combustion design of the furnaces and operation for control of VOC, PM/PM10/PM2.5, and CO. Highly energy efficient design and operation for control of CO2e (GHG). VOC Control System – Waste gas minimization and operation to achieve good destruction removal efficiency. Flares will be designed to meet limitations on maximum exit velocity, as set forth in the general provisions at 40 CFR 60.18 and 63.11. Flares will be operated to meet minimum net heating value requirements for gas streams combusted in flares as set forth in 40 CFR 60.18/63.11 Further details on the VOC Control System compliance methods are presented in Section 5.0 of the Plan Approval Application

Refer to the Plan Approval Application for further details.

Section F - Flue and Air Contaminant Emission

1. Estimated Maximum Emissions* Refer to Appendix B for emissions calculations

Pollutant

Maximum emission rate Calculation/

Estimation Method specify units lbs/hr tons/yr. PM

PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emissions calculations.

2. Stack and Exhauster Refer to Appendix C of the Plan Approval Application

Stack Designation/Number: Seven (7) Identical Stacks –

List Source(s) or source ID exhausted to this stack: F-11101, F12101, F-13101, F-14101, F-15101, F-16101, F-17101

% of flow exhausted to stack: 100

Stack height above grade (ft.) Grade elevation (ft.)

Stack diameter (ft) or Outlet duct area (sq. ft.)

Weather Cap YES NO

Distance of discharge to nearest property line (ft.). Locate on topographic map.

If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application

Location of Stack** Latitude/Longitude Point of Origin

Latitude Longitude

Degrees Minutes Seconds Degrees Minutes Seconds

Stack Exhaust

Volume ACFM Temperature °F Moisture %

Exhauster (attach fan curves) in. of water HP @ RPM.

** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.

Section B - Processes Information (Polyethylene Plants 1 & 2) 1. Source Information:

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Polyethylene (PE) Plants 1 and 2 are described in detail in Section 3.2 of the Plan Approval Application.

Manufacturer(s) To be determined

Model No.

Number of Sources See Appendix D of the Plan Approval Application

Source Designation See Table D-2 of the Plan Approval Application

Maximum Capacity:

Rated Capacity (Design capacities) Polyethylene: 1200 metric tons/yr

Type of Material Processed: Ethylene polymerized with comonomer to produce various grades of polyethylene (PE). Maximum Operating Schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour

Per Day

Per Week

Per Year 1200 metric tons/yr PE, total

Operating Schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Seasonal variations (Months) From to If variations exist, describe them N/A

2. Fuel:



Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal

TPH Tons % by wt Btu/lb

Other *


Section B – Processes Information (Polyethylene Plants 1 & 2) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. See the Plan Approval Application as follows: A detailed project description containing flow diagrams is included as Section 3.2. Raw materials and capacity information are provided in Appendices B and D. No restrictions on the production capacity are requested. Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. N/A


Identify and describe all fugitive emission points, all relief and emergency valves, and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of the fugitive emissions points is presented in Section 5.0 of the attached Plan Approval Application.

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate, startup and shutdown BACT/LAER limits are proposed. A VOC control system will be used to minimize emissions during startup, shutdown, and upsets. The VOC Control System LAER proposal (see Section 5.12) includes submittal of a waste gas minimization plan (WGMP) along with the performance of a root cause and corrective action analysis in response to events greater than a defined trigger level. The proposed WGMP will include procedures to minimize emissions during startup, shutdown, and upset. Anticipated Milestones:


Section C - Air Cleaning Device (Particulate Control - PE 1 & 2 Manufacturing and Pellet Handling)

1. Precontrol Emissions* (Refer to Appendix B for emissions calculations)

Pollutant





Appendix D of the Plan Approval Application provides a full listing of the PE manufacturing PM sources and proposed particulate filter control. A grain loading of 0.005 gr/dscf is proposed for all particulate containing vents, except truck and rail loading. A grain loading of 0.01 gr/dscf is proposed for truck and rail loading. Particulate filter technology will be used where feasible.

Section C - Air Cleaning Device (PE 1& 2 Manufacturing and Pellet Handling) (Continued) 5. Fabric Collector: Particulate filters be designed to achieve PM limits as presented in Section 5.0 of the Plan

Approval Application. Equipment Specifications Refer to Appendix D for PM Sources. Specifications TBD Manufacturer To be determined

Model No.

Pressurized Design Suction Design

Number of Compartments

Number of Filters Per Compartment

Is Baghouse Insulated? Yes No

Can each compartment be isolated for repairs and/or filter replacement?

Yes No

Are temperature controls provided? (Describe in detail)

Yes No

Dew point at maximum moisture °F Design inlet volume SCFM Type of Fabric

Material Felted Membrane Weight oz/sq.yd Woven Others: List: Thickness in Felted-Woven

Fabric permeability (clean) @ ½” water-∆ P CFM/sq.ft.

Filter dimensions Length Diameter/Width

Effective area per filter Maximum operating temperature (°F)

Effective air to cloth ratio Minimum Maximum

Drawing of Fabric Filter A sketch of the fabric filter showing all access doors, catwalks, ladders and exhaust ductwork, location of each pressure and temperature indicator should be attached.

Operation and Cleaning Volume of gases handled

ACFM @ °F

Pressure drop across collector (in. of water). Describe the equipment to be used to monitor the pressure drop.

Type of filter cleaning Manual Cleaning Bag Collapse Reverse Air Jets Mechanical Shakers Sonic Cleaning Other: Pneumatic Shakers Reverse Air Flow

Describe the equipment provided if dry oil free air is required for collector operation

Cleaning Initiated By Timer Frequency if timer actuated Expected pressure drop range in. of water Other Specify

Does air cleaning device employ hopper heaters, hopper vibrators or hopper level detectors? If yes, describe.

Describe the warning/alarm system that protects against operation when the unit is not meeting design requirements.

Emissions Data: Refer to Appendix B of the Plan Approval Application for Emissions Estimates Pollutant Inlet Outlet Removal Efficiency (%)

Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Polyethylene Plants 1 & 2)

1. Precontrol Emissions See Appendix B of the Plan Approval Application

Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC containing vents upstream of the Product Purge Bins will be routed to the VOC Control System’s LP header (LP System). The LP System consists of an LP Thermal Incinerator and an LP Ground Flare. The rated capacity of the Thermal Incinerator will be 12 tons/hr. The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. Section 3 of the Plan Approval Application provides additional information on LP System. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plant 3).

Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Polyethylene Plants 1 & 2)

11. Oxidizer/Afterburners Equipment Specifications


Type Thermal Catalytic Model No.

Design Inlet Volume (SCFM)

Combustion chamber dimensions (length, cross-sectional area, effective chamber volume, etc.)

Describe design features, which will ensure mixing in combustion chamber.

Describe method of preheating incoming gases (if applicable).

Describe heat exchanger system used for heat recovery (if applicable).

Catalyst used

Life of catalyst

Expected temperature rise across catalyst (°F)

Dimensions of bed (in inches). Height: Diameter or Width: Depth:

Are temperature sensing devices being provided to measure the temperature rise across the catalyst? Yes No If yes, describe.

Describe any temperature sensing and/or recording devices (including specific location of temperature probe in a drawing or sketch.

Burner Information

Burner Manufacturer

Model No.

Fuel Used

Number and capacity of burners

Rated capacity (each)

Maximum capacity (each)

Describe the operation of the burner

Attach dimensioned diagram of afterburner

Operating Parameters

Inlet flow rate (ACFM) @ °F Outlet flow rate (ACFM) @ °F

State pressure drop range across catalytic bed (in. of water).

Describe the method adopted for regeneration or disposal of the used catalyst.




Section C - Air Cleaning Device (VOC Control System – LP System Ground Flare) (Polyethylene Plants 1 & 2)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


Continuous and intermittent VOC containing vents prior to the upstream of the Product Purge Bins will be routed to the VOC Control System’s LP header (LP System). The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. The capacity of the totally enclosed LP Ground Flare will be 45 ton/hr. Section 3 of the Plan Approval Application provides additional information on LP system. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plant 3).

Section C - Air Cleaning Device (VOC Control System – LP System Ground Flare) (Polyethylene Plants 1 & 2) (Continued)




Model No.




Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring.





Heat content

1 MMBtu/hr (Pilot) Exit velocity






Section C - Air Cleaning Device (VOC Control System- HP System Ground Flares (2x)) (Polyethylene Plants 1 & 2)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plant 3).

Section C - Air Cleaning Device (VOC Control System -HP System Ground Flares (2x))

(Polyethylene Plants 1 & 2) (Continued)




Model No.




Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring





Heat content

Exit velocity







(Polyethylene Plants 1 & 2)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plant 3).


(Polyethylene Plants 1 & 2) (Continued)


Manufacturer


Model No.


Dimensions of stack (ft.) Diameter 5 Height


Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted, pilot flame monitoring. Refer to Section 3.5.5 and 5.12 of the Plan Approval Application for full flare description. Describe the operation of the flare’s ignition system.


Operation Parameters See Appendix B of the Plan Approval Application Detailed composition of the waste gas

Heat content

Exit velocity






Section C - Air Cleaning Device (PE 1& 2 Residual VOC Content in Pellets)

13. Other Control Equipment Equipment Specifications

Manufacturer

Type

Model No.


Capacity

Describe pH monitoring and pH adjustment, if any.

Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any.

Attach efficiency curve and/or other efficiency information.

Attach any additional date including auxiliary equipment and operation details to thoroughly evaluate the control equipment.


Volume of gas handled

ACFM @ °F % Moisture

Describe fully giving important parameters and method of operation.

The residual VOC content in the resin exiting the Product Purge Bins shall be less than 50 ppmw.


Emissions Data


Section E - Compliance Demonstration (Polyethylene Plants 1 & 2) Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.

Method of Compliance Type: Check all that apply and complete all appropriate sections below



Monitoring: a. Monitoring device type (Parameter, CEM, etc): PM: Once every five years EPA reference method stack

tests Residual VOC: weekly measurement

b. Monitoring device location: Particulate containing vents as denoted in Appendix D

VOC content in resin exiting the product purge bin c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

Testing:

a. Reference Test Method: Citation PM: EPA Method 5, 202 VOC: EPA Method 3810

b. Reference Test Method: Description Method 5 – Determination of Particulate Matter Emissions from

Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources; Method 3810-Headspace

Recordkeeping:

Describe what parameters will be recorded and the recording frequency:

VOC content of the resin exiting the Product Purge Bins will be recorded weekly.

Reporting:

a. Describe what is to be reported and frequency of reporting:


b. Reporting start date:

Work Practice Standard:

Describe each:

VOC Control System – Waste gas minimization and operation to achieve good destruction removal

efficiency. Flare will be designed to meet limitations on maximum exit velocity, as set forth in the general

provisions at 40 CFR 60.18 and 63.11. Flare will be operated to meet minimum net heating value

requirements for gas streams combusted in flares as set forth in 40 CFR 60.18. Further details on the

VOC Control System compliance methods are presented in Section 5.0 of the Plan Approval Application.

Section F - Flue and Air Contaminant Emission (Polyethylene Plants 1 & 2)

1. Estimated Atmospheric Emissions* See Appendix B of the Plan Approval Application for the detailed emissions calculations

Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.

2. Stack and Exhauster See Appendix D for specific stack identification and Appendix C for stack parameter information

Stack Designation/Number: Refer to Section 6.0 of the Plan Approval Application

List Source(s) or source ID exhausted to this stack: % of flow exhausted to stack:



f. Weather Cap YES NO

Distance of discharge to nearest property line (ft.). Locate on topographic map. Does stack height meet Good Engineering Practice (GEP)? If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. Refer to Appendix C of the Plan Approval Application

Location of stack** Latitude/Longitude

Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds LP Ground Flare HP Ground Flare HP Elevated Flare PE vents –

See Appendix C for Detailed Information on location and exhaust characteristics.

Stack exhaust Volume ACFM Temperature °F Moisture %

Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions. Exhauster (attach fan curves) in. of water HP @ RPM.

** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.

Section B - Processes Information (Polyethylene Plant 3) 1. Source Information

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary.

Polyethylene Plant 3 is described in detail in Section 3.3 of the Plan Approval Application. Manufacturer(s) Various

Model No.

Number of Sources

Source Designation

Maximum Capacity

Rated Capacity Polyethylene: 500 metric tons/yr

Type of Material Processed Ethylene polymerized with comonomer to produce various grades of polyethylene (PE) Maximum Operating Schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760


Per Day

Per Week

Per Year 500 metric tons/yr


Days/Week 7

Days/Year 365

Hours/Year 8760


2. Fuel



Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal


Other *


Section B - Processes Information (Polyethylene Plant 3) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. See the Plan Approval Application as follows: A detailed project description containing flow diagrams is included as Section 3.3. Raw materials and capacity information are provided in Appendices B and D. No restrictions on the production capacity are requested.

Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. N/A


Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of the fugitive emissions points is presented in Section 5.0 of the attached Plan Approval Application

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate startup and shutdown BACT/LAER limits are proposed. A VOC control system will be used to minimize emissions during startup, shutdown, and upsets. The VOC Control System LAER proposal (see Section 5.12) includes submittal of a waste gas minimization plan (WGMP) along with the performance of a root cause and corrective action analysis in response to events greater than a defined trigger level. The proposed WGMP will include procedures to minimize emissions during startup, shutdown, and upset. Anticipated Milestones:


Section C - Air Cleaning Device (Particulate Control - PE 3 Manufacturing and Pellet Handling)

1. Precontrol Emissions* (Refer to Appendix B for emissions calculations)

Pollutant





Appendix D of the Plan Approval Application provides a full listing of the PE manufacturing PM sources and proposed particulate filter control. A grain loading of 0.005 gr/dscf is proposed for all particulate containing vents, except truck and rail loading. A grain loading of 0.01 gr/dscf is proposed for truck and rail loading. Particulate filter technology will be used where feasible.

Section C - Air Cleaning Device (PE 3 Manufacturing and Pellet Handling) (Continued) 5. Fabric Collector: Particulate filters be designed to achieve total PM of less than 0.005 gr/DSCF outlet Equipment Specifications Refer to Appendix D for Filter Specifications Manufacturer

Model No.

Pressurized Design Suction Design

Number of Compartments

Number of Filters Per Compartment

Is Baghouse Insulated? Yes No

Can each compartment be isolated for repairs and/or filter replacement?

Yes No

Are temperature controls provided? (Describe in detail)

Yes No

Dew point at maximum moisture °F Design inlet volume SCFM Type of Fabric

Material Felted Membrane Weight oz/sq.yd Woven Others: List: Thickness in Felted-Woven

Fabric permeability (clean) @ ½” water-∆ P CFM/sq.ft.

Filter dimensions Length Diameter/Width

Effective area per filter Maximum operating temperature (°F)

Effective air to cloth ratio Minimum Maximum

Drawing of Fabric Filter A sketch of the fabric filter showing all access doors, catwalks, ladders and exhaust ductwork, location of each pressure and temperature indicator should be attached.

Operation and Cleaning Volume of gases handled

ACFM @ °F

Pressure drop across collector (in. of water). Describe the equipment to be used to monitor the pressure drop.

Type of filter cleaning Manual Cleaning Bag Collapse Reverse Air Jets Mechanical Shakers Sonic Cleaning Other: Pneumatic Shakers Reverse Air Flow

Describe the equipment provided if dry oil free air is required for collector operation

Cleaning Initiated By Timer Frequency if timer actuated Expected pressure drop range in. of water Other Specify

Does air cleaning device employ hopper heaters, hopper vibrators or hopper level detectors? If yes, describe.

Describe the warning/alarm system that protects against operation when the unit is not meeting design requirements.

Emissions Data: Refer to Appendix B of the Plan Approval Application for Emissions Estimates Pollutant Inlet Outlet Removal Efficiency (%)

Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator)

(Polyethylene Plant 3)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


Continuous and intermittent VOC containing vents prior to the upstream of the Degasser will be routed to the VOC Control System’s LP header (LP System). The LP System consists of a Thermal Incinerator and a LP Ground Flare. The rated capacity of the Thermal Incinerator will be 12 tons/hr. The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. Section 3 of the Plan Approval Application provides additional information on LP system. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plants 1&2).

Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Polyethylene Plant 3) (Continued)









Catalyst used

Life of catalyst





Burner Information

Burner Manufacturer

Model No.

Fuel Used













Section C - Air Cleaning Device (VOC Control System - LP System Ground Flare) (Polyethylene Plant 3)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


Continuous and intermittent VOC containing vents prior to the upstream of the Degasser will be routed to the VOC Control System’s LP header (LP System). The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. The capacity of the totally enclosed LP Ground Flare will be 45 ton/hr. Section 3 of the Plan Approval Application provides additional information on LP system. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plants 1&2).

Section C - Air Cleaning Device (VOC Control System - LP System Ground Flare) (Polyethylene Plant 3) (Continued)




Model No.




Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Refer to Section 3.5.5 and Section 5.0 for a full flare system description





Heat content

1 MMBtu/hr (Pilot)

Exit velocity






Section C - Air Cleaning Device (VOC Control System - HP System Ground Flares (2x))



Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plants 1 & 2)..

Section C - Air Cleaning Device (VOC Control System -HP System Ground Flares (2x)) (Polyethylene Plant 3) (Continued)




Model No.



Residence time (sec.) and outlet temperature (°F)

Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Non-assisted, pilot flame monitoring. Refer to Section 3.5.5 and Section 5.12 for a full flare system description.





Heat content

.

Exit velocity









Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


VOC emissions resulting from startup, shutdown, maintenance and upset at the ethane cracking unit and PE manufacturing units will be routed to the HP Flare System. The HP system consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP elevated flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application. (NOTE: This is the same HP Flare System presented in the forms for PE Plants 1 & 2).

Section C - Air Cleaning Device (VOC CONTROL SYSTEM -HP System Elevated Flare) (Polyethylene Plant 3) (Continued)


Manufacturer


Model No.




Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted, pilot flame monitoring. Refer to Section 3.5.5 and Section 5.12 for a full flare system description.





Heat content

1 MMBtu/hr (Pilot)

Exit velocity






Section C - Air Cleaning Device (PE 3 Residual VOC Content in Pellets)

13. Other Control Equipment Equipment Specifications Manufacturer

Type

Model No.


Capacity

Describe pH monitoring and pH adjustment, if any.

Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any.

Attach efficiency curve and/or other efficiency information.

Attach any additional date including auxiliary equipment and operation details to thoroughly evaluate the control equipment.


Volume of gas handled

ACFM @ °F % Moisture

Describe fully giving important parameters and method of operation.

Based on the LAER determination presented in Section 5.8 of the Plan Approval Application, VOC from the PE units will be controlled as follows: The residual VOC content in the resin exiting the Degasser shall be less than 50 ppmw.


Emissions Data


[Section E - Compliance Demonstration (Polyethylene Plant 3)

Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.




Monitoring: a. Monitoring device type (Parameter, CEM, etc): PM: Stack test once every 5 years for PM/PM10/PM2.5

Residual VOC: weekly measurement b. Monitoring device location: Particulate containing vents as denoted in Appendix D

VOC content in resin exiting the Degasser c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

Testing:

a. Reference Test Method: Citation PM: EPA Method 5, 202 VOC: EPA Method 3810

b. Reference Test Method: Description Method 5 – Determination of Particulate Matter Emissions from

Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources; Method 3810-Headspace

Recordkeeping:


VOC content of the resin exiting the Degasser will be recorded weekly.

Reporting:





Describe each:

VOC Control System – Waste gas minimization and operation to achieve good destruction removal

efficiency. Flare will be designed to meet limitations on maximum exit velocity, as set forth in the general

provisions at 40 CFR 60.18 and 63.11. Flare will be operated to meet minimum net heating value

requirements for gas streams combusted in flares as set forth in 40 CFR 60.18. Further details on the VOC

Control System compliance methods are presented in Section 5.0 of the Plan Approval Application.

Section F - Flue and Air Contaminant Emission (PE3)

1. Estimated Atmospheric Emissions* See Appendix B of the Plan Approval Application for the detailed emissions calculations

Pollutant Maximum emission rate Calculation/


PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----


2. Stack and Exhauster

Stack Designation/Number See Appendix D for specific stack identification and Appendix C for stack parameter information. List Source(s) or source ID exhausted to this stack:

% of flow exhausted to stack:





Does stack height meet Good Engineering Practice (GEP)? If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions. . . Refer to Appendix C of the Plan Approval Application


Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds LP Ground Flare HP Ground Flare HP Elevated Flare PE vents

See Appendix C for Detailed Information on location and exhaust characteristics.

Stack exhaust Volume ACFM Temperature °F Moisture %

Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.



Section B - Combustion Unit Information (Combustion Turbines/Duct Burners (3x)) 2. Combustion Units: Coal Oil Natural Gas Other:

Description: Combustion turbines with duct burners (3 Combined Cycle Units)

Manufacturer Siemens or GE

Model No. SGT-800 or GE Frame 6B

Number of units 3

Maximum heat input (Btu/hr)

Rated heat input (Btu/hr) GE – 475 MMBtu/hr Siemens – 490 MMBtu/hr


Furnace Volume

Grate Area (if applicable)

Method of firing Direct

Indicate how combustion air is supplied to boiler Indicate the Steam Usage:



Maximum Operating schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760



Per day

Per week

Per year

Typical Operating schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760


Single fuel, 40 CFR Part 72 pipeline natural gas.

Section B - Combustion Unit Information (Combustion Turbines/Duct Burners (3x)) (Continued)

5. Fuel



Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas

GE 465 MSCFH Siemen 482.4 MSCF

X 106

Gal

0.5 gr/100 SCF

1020 Btu/SCF

Gas (other)

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF

Coal Other* * Note: Describe and furnish information separately for other fuels in Addendum B. 6. Burner Manufacturer

Model Number


Number of Burners




Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) x Low-NOx burner Low NOx burners with over fire

air

Flue gas recirculation Burner out of service Reburning x Flue gas treatment (SCR)

Other. : Lean Premix Dry Low NOx Combustor

Section B - Combustion Unit Information (Combustion Turbines/Duct Burners (3x)) (Continued)


Describe fly ash reinjection operation




Limits covering startup and shutdown are proposed in Section 5.3 of the Plan Approval Application. Estimates of emissions are provided in Appendix B.

Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable).



Section C - Air Cleaning Device (Combustion Turbines/Duct Burners (3x))

1. Precontrol Emissions* Please refer to Appendix B of the Plan Approval Application for this emissions data

Emission Rate

Pollutant



PM10

SOx

CO

NOx

VOC

Others: (e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.

2. Gas Conditioning NA



If YES, CFM


Other

Inlet volume

ACFM@ °F

Outlet volume



Three gas turbines with direct-fired duct burners and heat recovery steam generation capable of producing steam. The baseload ratings are 40.6 MW for the GE unit and 48.7 MW for the Siemens. Both gas turbine models will be equipped with lean premix combustors to minimize NOx. NOx LAER/BACT limits and BACT CO limits will be achieved by using selective catalytic reduction and CO oxidation catalyst, respectively. Two steam turbines each rated at 64.3 MW will be used to generate electricity using the steam produced by the HRSGs and any excess steam from the ethane cracking unit. When tailgas is in excess at the cracking furnaces, a small quantity of the tailgas may be combusted in the duct burners in combination with natural gas.

Section C - Air Cleaning Device (Combustion Turbines/Duct Burners (3x)) (Continued)

8. SELECTIVE CATALYTIC REDUCTION (SCR)

SELECTIVE NON-CATALYTIC REDUCTION (SNCR)

NON-SELECTIVE CATALYTIC REDUCTION (NSCR)


To be determined (TBD)

Type

Model No

Design inlet volume (SCFM)

Design operating temperature (°F)

Is the system equipped with process controls for proper mixing/control of the reducing agent in gas stream? If yes, give details. Attach efficiency and other pertinent information (e.g., Ammonia, urea slip). Operating parameters

Volume of gases handled (ACFM) @ (°F) Operating temperature range for the SCR/SNCR/NSCR system (°F)

From

To

Reducing agent used, if any. Ammonia

Oxidation catalyst used, if any.

State expected range of usage rate and concentration. Service life of catalyst

Ammonia slip (ppm) 5 ppmvd @ 15% O2

Describe fully with a sketch giving locations of equipment, controls system, important parameters and method of operation. SCR and CO oxidation will be designed to reduce NOx and CO emissions to the proposed BACT/LAER limits of 2 ppmvd @15% O2. (See Sections 5.3.1 and 5.3.4 of the Plan Approval Application for technology reviews). Emissions calculations for each of the proposed turbine units are included in Appendix B of the Plan Approval Application. Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.

Emissions data Refer to Appendix B of the Plan Approval Application for emissions data Pollutant Inlet Outlet Removal Efficiency (%)


9. Other Control Equipment: CO Oxidation


To be Determined (TBD)

Type

Model No

Design inlet volume (SCFM)

Capacity

Describe pH monitoring and pH adjustment, if any. Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any. Attach efficiency curve and/ or other efficiency information. Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment. Operating parameters Volume of gas handled

@ °F % Moisture

Describe, in detail, important parameters and method of operation.


Emissions data Pollutant Inlet Outlet Removal Efficiency (%)


10. Costs Refer to the BACT/LAER Analysis contained in Section 5.0 of the Plan Approval Application






Section E - Compliance Demonstration (Combustion Turbines/Duct Burners (3x)) Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Method of Compliance Type: Check all that apply and complete all appropriate sections below.



Monitoring: a. Monitoring device type (stack test, CEM etc.): NOx & CO CEMs; Stack test VOC and PM/PM10/PM2.5 b. Monitoring device location: Stack c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

Continuous measurement of NOx and CO concentration and volumetric flow rate, 5 year performance test for PM and VOC.

Testing:

a. Reference Test Method Citation: : EPA Method 18, 25, 5, and 202

b. Reference Test Method Description: Method 18-Measurement of Gaseous Organic Compound Emissions by Gas Chromatography; Method 25-Determination of Total Gaseous Nonmethane Organic Emissions as Carbon; Method 5 – Determination of Particulate Matter Emissions from Stationary Sources; Method 202 – Dry Impinger Method for Determining Condensable Particulate Matter from Stationary Sources.

Recordkeeping:

Describe the parameters that will be recorded and the recording frequency:

Records kept for continuous measurement of NOx and CO concentration and volumetric flow rate, 5 year performance test for PM and VOC. Calculations kept for SO2 and CO2.

Reporting:

a. Describe the type of information to be reported and the reporting frequency:



Work Practice Standard: Describe each

Good combustion design and operation for PM/PM10/PM2.5 control. Use of natural gas and energy efficient design for CO2e/GHG control.

Section F - Flue and Air Contaminant Emission (Combustion Turbines/Duct Burners (3x)) 1. Estimated Maximum Emissions*Presented here for one of three identical SCR/CO Ox units

Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emissions calculations


Stack Designation/Number Three (3) Identical SCR/CO Ox List Source(s) or source ID exhausted to this stack: CT1/2/3




Weather Cap YES NO


Does stack height meet Good Engineering Practice (GEP)? Yes



Latitude Longitude

Degrees Minutes Seconds Degrees Minutes Seconds Stack Exhaust




Section B - Combustion Unit Information (Emergency Generators (4x)) 3. Combustion Units: Coal Oil Natural Gas Other: Diesel fuel Description: Four diesel-fired reciprocating internal combustion engines, each rated at ~5028 BHP/3MWe, will be used to drive emergency electrical generators.

Manufacturer

Model No.

Number of units 4




Furnace Volume






Maximum Operating schedule Hours/Day

Days/Week

Days/Year

Hours/Year 100 (each)



Per day

Per week

Per year

Typical Operating schedule Hours/Day

Days/Week

Days/Year

Hours/Year


Low sulfur diesel fuel

Section B - Combustion Unit Information (Emergency Generators (4x)) (Continued) 7. Fuel



Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF


Model Number


Number of Burners




Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) Low-NOx burner Low NOx burners with over fire

air

Flue gas recirculation Burner out of service Reburning Flue gas treatment (SCR /

SNCR)

Other.

Section B - Combustion Unit Information (Emergency Generators (4x)) (Continued)









Section C - Air Cleaning Device(Emergency Generators (4x))

1. Precontrol Emissions*Work Practice (Engine Design)

Emission Rate

Pollutant



PM10

SOx

CO

NOx

VOC

Others: (e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emission calculations.

2. Gas Conditioning N/A



If YES, CFM


Other

Inlet volume

ACFM@ °F

Outlet volume



Combustion control techniques and use of low sulfur fuel.

Attach efficiency curve and/ or other efficiency information. Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.

Section C - Air Cleaning Device (Emergency Generators (4x)) (Continued)

10. Costs Refer to Section 5.0 of the Plan Approval Application






Section E - Compliance Demonstration(Emergency Generators (4x)) Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Refer to Table 5-1 of the Plan Approval Application for more details. Method of Compliance Type: Check all that apply and complete all appropriate sections below.



Monitoring: a. Monitoring device type (stack test, CEM etc.): Fuel usage b. Monitoring device location: Fuel Supply c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter: Fuel

usage and operating hours when emergency generator is in use Testing:

a. Reference Test Method Citation:

b. Reference Test Method Description:

Recordkeeping:


Record fuel usage and operating hours when emergency generator is in use

Reporting:





Compliance with proposed limits for NOx, VOC, PM/PM10/PM2.5 and CO met with purchase of certified engine.

Section F - Flue and Air Contaminant Emission (Emergency Generators (4x)) 1. Estimated Maximum Emissions*

Pollutant Maximum emission rate Calculation/


PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations Refer to Appendix B of the Plan Approval Application for emissions calculations.


Stack Designation/Number

List Source(s) or source ID exhausted to this stack: EGEN1/2/3/4




Weather Cap YES NO





Latitude Longitude

Degrees Minutes Seconds Degrees Minutes Seconds Generator 1 Generator 2 Generator 3 Generator 4

Stack Exhaust




Section B - Combustion Unit Information (Firewater Pump Engines (3x)) 4. Combustion Units: Coal Oil Natural Gas Other: Diesel fuel Description: Three diesel-fired reciprocating internal combustion engines, each rated at ~700BHP/0.52 MW, will be used to drive emergency firewater pumps. Manufacturer

Model No.

Number of units 3




Furnace Volume






Maximum Operating schedule Hours/Day

Days/Week

Days/Year

Hours/Year 100 (each)



Per day

Per week

Per year

Typical Operating schedule Hours/Day

Days/Week

Days/Year

Hours/Year


Low sulfur diesel fuel

Section B - Combustion Unit Information (Firewater Pump Engines (3x)) 9. Fuel



Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF


Model Number


Number of Burners




Mark and describe the NOx control options adopted Low excess air (LEA) Over fire air (OFA) Low-NOx burner Low NOx burners with over fire

air

Flue gas recirculation Burner out of service Reburning Flue gas treatment (SCR /

SNCR)

Other.

Section B - Combustion Unit Information (Firewater Pump Engines (3x))









Section C - Air Cleaning Device(Firewater Pump Engines (3x))

1. Precontrol Emissions*Work Practice

Emission Rate

Pollutant



PM10

SOx

CO

NOx

VOC

Others: (e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emission calculations.

2. Gas Conditioning N/A



If YES, CFM


Other

Inlet volume

ACFM@ °F

Outlet volume



Combustion control techniques and use of low sulfur fuel.

Attach efficiency curve and/ or other efficiency information. Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.

Section C - Air Cleaning Device (Firewater Pump Engines (3x)) (Continued)

10. Costs Refer to Section 5.0 of the Plan Approval Application






Section E - Compliance Demonstration (Firewater Pump Engines (3x)) Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Refer to Table 5-1 of the Plan Approval Application for more details. Method of Compliance Type: Check all that apply and complete all appropriate sections below.



Monitoring: a. Monitoring device type (stack test, CEM etc.): Fuel usage b. Monitoring device location: Fuel Supply c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter: Fuel

usage and operating hours when firewater pump is in use. Testing:

a. Reference Test Method Citation:

b. Reference Test Method Description:

Recordkeeping:


Record fuel usage and operating hours when firewater pump is in use.

Reporting:





Compliance with proposed limits for NOx, VOC, PM/PM10/PM2.5 and CO met with purchase of certified engine.

Section F - Flue and Air Contaminant Emission (Firewater Pump Engines (3x)) 1. Estimated Maximum Emissions*

Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----

* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations. Refer to Appendix B of the Plan Approval Application for emissions calculations.



List Source(s) or source ID exhausted to this stack: FWP1/2/3




Weather Cap YES NO





Latitude Longitude

Degrees Minutes Seconds Degrees Minutes Seconds Firewater Pump 1 Firewater Pump 2 Firewater Pump 3

Stack Exhaust




Section B - Processes Information (Process Cooling Tower) 1. Source Information

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Process Cooling Tower- 26 cell counter-flow mechanical draft cooling tower to supply cooling water to process units. Manufacturer To be Determined

Model No.

Number of Sources 1

Source Designation

Maximum Capacity 57,000 metric tons/hr

Rated Capacity

Type of Material Processed Maximum Operating Schedule Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour 66,992 tons

Per Day

Per Week

Per Year


Days/Week 7

Days/Year 365

Hours/Year 8760


2. Fuel



Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal


Other *


Section B - Processes Information (Process Cooling Tower) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored.

Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. TDS, Total VOC in circulating water.


Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. N/A

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. N/A

Anticipated Milestones: i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018

Section E Compliance Demonstration (Process Cooling Tower)





Monitoring: a. Monitoring device type (Parameter, CEM, etc): b. Monitoring device location: c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

TDS, Total VOC in circulating water

Testing:

a. Reference Test Method: Citation b. Reference Test Method: Description

Recordkeeping:


Reporting:





Describe each: High efficiency drift eliminators with a manufacturer’s specification of no more than 0.0005%

drift loss will be installed.

Section F - Flue and Air Contaminant Emission(Process Cooling Tower)

1. Estimated Atmospheric Emissions*

Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----




List Source(s) or source ID exhausted to this stack: PCT









Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack exhaust





Section B - Processes Information (Cogen Cooling Tower) 1. Source Information

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Cogen Cooling Tower- 4 cell counter-flow mechanical draft cooling tower to supply cooling water to cogeneration units Manufacturer To be Determined

Model No.

Number of Sources 1

Source Designation

Maximum Capacity 10,000 metric tons/hr

Rated Capacity


Days/Week 7

Days/Year 365

Hours/Year 8760

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE) Capacity (specify units) Per Hour 10,455 cubic meters

Per Day

Per Week

Per Year


Days/Week 7

Days/Year 365

Hours/Year 8760


2. Fuel



Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal


Other *


Section B - Processes Information (Cogen Cooling Tower) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored.

Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate.


Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. N/A

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. N/A

Anticipated Milestones: i. Expected commencement date of construction/reconstruction/installation: Late 2015 ii. Expected completion date of construction/reconstruction/installation: 2018 iii. Anticipated date of start-up: 2018

Section E Compliance Demonstration (Cogen Cooling Tower)






TDS

Testing:


Recordkeeping:


Reporting:





Describe each: High efficiency drift eliminators with a manufacturer’s specification of no more than 0.0005%

drift loss will be installed.

Section F - Flue and Air Contaminant Emission(Cogen Cooling Tower)

1. Estimated Atmospheric Emissions*

Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----



Stack Designation/Number CogenCWT

List Source(s) or source ID exhausted to this stack: CogenCWT






Does stack height meet Good Engineering Practice (GEP)?



Latitude Longitude






Section B - Processes Information (Utilities and General Facility) 1. Source Information

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. This section covers units outside the battery limits (OSBL) of the ethylene and polyethylene manufacturing lines. Included are tanks, cogeneration units, auxiliary engines, cooling tower, and wastewater treatment. . Manufacturer(s) Various

Model No.

Number of Sources

Source Designation

Maximum Capacity

Rated Capacity


Days/Week 7

Days/Year 365

Hours/Year 8760


Per Day

Per Week

Per Year


Days/Week 7

Days/Year 365

Hours/Year 8760


2. Fuel



Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal


Other *


Section B - Processes Information (Utilities and General Facility) (Continued) 3. Burner Manufacturer

Type and Model No.

Number of Burners

Description:

Rated Capacity

Maximum Capacity

4. Process Storage Vessels A. For Liquids: Refer to Table D-6 of Appendix D of the Plan Approval Application Name of material stored

Tank I.D. No.

Manufacturer

Date Installed

Maximum Pressure

Capacity (gallons/Meter3)

Type of relief device (pressure set vent/conservation vent/emergency vent/open vent) Relief valve/vent set pressure (psig)

Vapor press. of liquid at storage temp. (psia/kPa)

Type of Roof: Describe:

Total Throughput Per Year

Number of fills per day (fill/day): Filling Rate (gal./min.): Duration of fill hr./fill):

B. For Solids Refer to Table D-7 of Appendix D of the Plan Approval Application Type: Silo Storage Bin Other, Describe

Name of Material Stored

Silo/Storage Bin I.D. No.

Manufacturer

Date Installed

State whether the material will be stored in loose or bags in silos

Capacity (Tons)

Turn over per year in tons

Turn over per day in tons

Describe fugitive dust control system for loading and handling operations

Describe material handling system

5. Request for Confidentiality Do you request any information on this application to be treated as “Confidential”? Yes No If yes, include justification for confidentiality. Place such information on separate pages marked “confidential”.

Section B - Processes Information (Utilities and General Facility) (Continued) 6. Miscellaneous Information Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored. Please refer to the Plan Approval Application. The detailed process descriptions and flow diagrams are included in Section 3.0. The Project’s emissions estimates are included as Appendix B to the Plan Approval Application. Proposed limits for each of the proposed projects emissions points are included in Section 5 of the Plan Approval Application. .

Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate. Compliance monitoring equipment and recordkeeping procedures will be implemented to ensure that all of the proposed projects sources are operated in compliance with the proposed permit limits. Compliance monitoring and testing requirements are included as part of each of the proposed limits in Section 5.0. Continuous NOx and CO emissions monitors will be used to monitor compliance at the cracking furnaces and combustion turbines. Flares and incinerators will have enhanced monitoring to ensure combustion efficiency. Describe each proposed modification to an existing source. N/A

Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. Fugitive emissions will result from equipment leaks, tanks, paved roads and parking areas, cooling towers, and pressure safety valves (psvs). Additional information related to the control and monitoring of emissions from each of these sources is presented in Section 5.0 of the attached Plan Approval Application

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. The facility will install BACT and LAER controls as proposed in Section 5.0 of the Plan Approval Application. Where appropriate startup and shutdown limits are proposed as part of these analyses. As part of the VOC Control System LAER proposal covering the operation of the incinerators and flares submittal of a waste gas minimization plan (WGMP) is proposed along with the performance of a root cause and corrective action analysis in response to events greater than a defined size. This WGMP will include procedures to minimize emissions due to flaring and incineration during startup and shutdown of the proposed project’s emissions sources. Anticipated Milestones:


Section C - Air Cleaning Device (Carbon Canisters) (Utilities and General Facility)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


Carbon canisters will be used to control tank emissions associated with the pyrolysis tar, emergency diesel generator (4x), emergency firewater pump diesel (3x), and locomotive diesel tanks. Emissions associated with these carbon canister controlled tanks are included in Appendix B of the Plan Approval Application.

Section C - Air Cleaning Device (Carbon Canisters) (Utilities and General Facility)

8. Adsorption Equipment Equipment Specifications

Manufacturer

Type

Model No.


Adsorbent charge per adsorber vessel and number of adsorber vessels

Length of Mass Transfer Zone (MTZ), supplied by the manufacturer based upon laboratory data.

Adsorber diameter (ft.) and area ft2.)

Adsorption bed depth (ft.)

Adsorbent information

Adsorbent type and physical properties.

Working capacity of adsorbent (%)

Heel percent or unrecoverable solvent weight % in the adsorbent after regeneration.


Inlet volume of gases handled (ACFM) @ °F

Adsorption time per adsorption bed

Breakthrough capacity: Lbs. of solvent / 100 lbs. of adsorbent =

Vapor pressure of solvents at the inlet temperature

Available steam in pounds to regenerate carbon adsorber (if applicable)

Percent relative saturation of each solvent at the inlet temperature

Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.


Emissions Data: See Appendix B of the Plan Approval Application


Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator)

(Utilities and General Facility)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


Continuous and intermittent VOC containing vents from the light gasoline and hexene tanks will be routed to the VOC Control System’s LP header (LP System). The LP System consists of an LP Thermal Incinerator and an LP Ground Flare. The rated capacity of the Thermal Incinerator will be 12 tons/hr. The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. Section 3 of the Plan Approval Application provides additional information on LP System. (NOTE: This is the same VOC Control System presented in the forms for Ethylene Manufacturing and PE Plants).

Section C - Air Cleaning Device (VOC Control System – LP System Thermal Incinerator) (Utilities and General Facility)









Catalyst used

Life of catalyst





Burner Information

Burner Manufacturer

Model No.

Fuel Used













Section C - Air Cleaning Device (LP Flare System – LP Ground Flare) (Utilities and General Facility)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


Continuous and intermittent VOC containing vents from the light gasoline and hexene tanks will be routed to the VOC Control System’s LP header (LP System). The LP Ground Flare will only be used during process upsets. Emissions associated with the VOC Control System are included in Appendix B of the Plan Approval Application. The capacity of the totally enclosed LP Ground Flare will be 45 ton/hr. Section 3 of the Plan Approval Application provides additional information on LP system.

Section C - Air Cleaning Device (LP Flare System – LP Ground Flare) (Utilities and General Facility) (Continued)




Model No.




Turn down ratio

Burner details






Heat content

1 MMBtu/hr (Pilot)

Exit velocity






Section C - Air Cleaning Device (HP Flare System – Ground Flares (2x)) (Utilities and General Facility)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


The HP Header System consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP Elevated Flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application

Section C - Air Cleaning Device (HP Flare System – Ground Flares (2x)) (Utilities and General Facility) (Continued)




Model No.




Turn down ratio

Burner details




Operation Parameters Refer to Appendix B of the Plan Approval Application


Heat content

Exit velocity






Section C - Air Cleaning Device (HP Flare System – Elevated Flare



Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


The HP Header System consists of one elevated flare with a relieving capacity of 1,200 tons/hr and two totally enclosed ground flares, each rated for 150 tons/hr. The HP Elevated Flare will only be used to control emissions during upsets. The two HP Ground Flares will be used to control VOC emission associated with startup, shutdown, and maintenance of the ethylene manufacturing plant and PE Units. Emissions associated with the two HP Ground and Elevated Flares are included in Appendix B of the Plan Approval Application.

Section C - Air Cleaning Device (HP Flare System – Elevated Flare) (Utilities and General Facility) (Continued)


Manufacturer


Model No.



Residence time (sec.) and outlet temperature (°F)

Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or non-assisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch. Steam assisted, pilot flame monitoring. Refer to Section 3.5.5 and Section 5.12 of the Plan Approval Application for full flare description.



Operation Parameters Refer to Appendix B of the Plan Approval Application Detailed composition of the waste gas

Heat content Exit velocity






Section C - Air Cleaning Device (Refrigerated Atmospheric Storage Flare) (Utilities and General Facility)


Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


The refrigerated atmospheric storage flare will be a ground flare sized for 22 tons/hr of relieving capacity. This flare will be used during the initial startup, following inspections, and for emergency relief of the refrigerated atmospheric storage tank. Inspections will occur once every five to ten years. Emissions associated with refrigerated atmospheric storage flare are included in Appendix B of the Plan Approval Application.

Section C - Air Cleaning Device (Refrigerated Atmospheric Storage Flare) (Utilities and General Facility) (Continued)

12. Flares Equipment Specifications Manufacturer To be determined


Model No.




Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch.



Operation Parameters Refer to Appendix B of the Plan Approval Application


Heat content

Exit velocity






Section C - Air Cleaning Device (Spent Caustic Vent Thermal Incinerator) (Utilities and General Facility)

1. Precontrol Emissions* See Appendix B or the Plan Approval Application

Pollutant




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


The Spent Caustic Vent Thermal Incinerator will have a design heat input of 10 MMBtu/hr. It will be designed to control VOC emissions from the spent caustic oxidizer stripper, and tank emissions from the spent caustic, flow equalization, and recovered oil tanks.

Section C - Air Cleaning Device (Spent Caustic Vent Thermal Incinerator) (Utilities and General Facility) (Continued)

11. Oxidizer/Afterburners Equipment Specifications Manufacturer To be determined







Catalyst used

Life of catalyst





Burner Information

Burner Manufacturer

Model No.

Fuel Used











Emissions Data: See Appendix B of the Plan Approval Application


Section C - Air Cleaning Device (Wastewater Treatment Plant (WWTP)) 1. Precontrol Emissions*

Pollutant





The wastewater treatment plant (WWTP) will consist of primary flow equalization and oil removal, followed by a secondary activated sludge bioreactor (including clarifiers), and a tertiary sand filter to treat the wastewater streams from process units and potentially contaminated storm water runoff from process paved areas. A more detailed description of the WWTP follows.

Several wastewater streams from the facility, including those streams containing volatile organic compounds, will flow into one of two flow equalization oil removal (FEOR) tanks (T-59707A/B). Each tank will be a fixed roof tank equipped with an internal floating roof. Oil rising to the top of these tanks will be skimmed off and will flow to a recovered oil storage tank (T-59708) for off-site disposal.

Effluent from the FEOR tanks will then be routed to the biotreater aeration tank. Internal WWTP recycle streams will also flow into this tank, as well as small nutrient additive and ph adjustment streams. Biotreater effluent will flow to two secondary clarifier tanks, and the clarifiers’ overflow stream will be pumped through a sand filter. Clarifier underflow will be pumped to a biosludge holding tank that will feed a centrifuge used for concentrating clarifier solids into a cake. Cooling tower blowdown will be pumped directly to the sand filter, and effluent from this filter will be discharged through an outfall to the Ohio river. Sand filter backwash will be pumped into a tank, and will be recycled back to the biotreater aeration tank.

Emissions from the two flow equalization (T-59707A/B) and recovered oil storage ((T-59708) tanks will be equipped with a closed vent system, and collected vapors will be routed to the spent caustic incinerator with a VOC destruction efficiency of 99% or greater. All other WWTP sources are designated as other WWTP equipment (W-1001).

Maximum EmissionRate Factor

Pollutantmillion gal/day

lb/million gal lb/hr hrs/year TPY lb/hr hrs/year TPY

VOC N/A N/A 0.381 8,760 0.755 0.004 8,760 0.008 Emissions model EPA TANKS 4.0.1daPrecontrol emissions were calculated based on tanks equipped with internal floating roofs.BasisPrecontrol emissions, both lb/hr VOC and TPY VOC, were calculated using EPA's TANKS 4.0.1d. software.Combustion source control efficiency: 99% for VOCExample Calculation0.004 lb/hr VOC [post-control] = (0.381 lb VOC/hr) x (100% - 99%) / 100%

Wastewater Treatment Plant

2 Flow Equalization and Oil Removal Tanks (T-5307A/B) - Emissions Summary

Precontrol Emissionsa Controlled EmissionsCalculation/Estimation

MethodEmission Factor

Reference


Pollutantmillion gal/day

lb/million gal lb/hr hrs/year TPY lb/hr hrs/year TPY

VOC N/A N/A 0.289 8,760 1.26 0.003 8,760 0.013 Emissions model EPA WATER9

Others: (e.g., HAPs) - - - - - - - - -

Benzene N/A N/A 0.051 8,760 0.22 0.0005 8,760 0.0022 Emissions model EPA WATER9

Ethylbenzene N/A N/A 0.039 8,760 0.17 0.0004 8,760 0.0017 Emissions model EPA WATER9

Toluene N/A N/A 0.199 8,760 0.87 0.002 8,760 0.0087 Emissions model EPA WATER9

Phenol N/A N/A 9.05E-07 8,760 3.96E-06 9.05E-09 8,760 3.96E-08 Emissions model EPA WATER9

BasisPrecontrol emissions were calculated using EPA's WATER9 modeling software.Emissions were calculated for worst-case conditions of dry weather flow.Combustion source control efficiency: 99% for VOC and HAPsExample Calculations0.003 lb VOC/hr [post-control] = (0.289 lb VOC/hr) x (100% - 99%) / 100%1.26 ton VOC/yr [pre-control] = (0.298 lb/hr) x (8,760 hrs/year) / (2,000 lb/ton)

Biotreater Aeration Tank (T-5309) - Emissions Summary

Precontrol Emissions Controlled EmissionsCalculation/Estimation

MethodEmission Factor

Reference

Section E - Compliance Demonstration (Utilities and General Facility)






Testing:


Recordkeeping:


Reporting:





Describe each: VOC Control System and Refrigerated Flare– Waste gas minimization and operation to achieve good destruction removal efficiency. Flare will be designed to meet limitations on maximum exit velocity, as set forth in the general provisions at 40 CFR 60.18 and 63.11. Flare will be operated to meet minimum net heating value requirements for gas streams combusted in flares as set forth in 40 CFR 60.18. Further details on the VOC Control System compliance methods is presented in Section 5.0 of the Plan Approval Application. Spent Caustic Vent Thermal Incinerator will be designed and operated to ensure 99% DRE. The LP Thermal Incinerator will be designed and operated to ensure 99.5% DRE.

Section F - Flue and Air Contaminant Emission (Carbon Canisters) (Utilities and General Facility)

1. Estimated Atmospheric Emissions* Refer to Appendix B for emissions calculations

Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----




List Source(s) or source ID exhausted to this stack: EGEN1/2/3/4









Latitude Longitude





Section F - Flue and Air Contaminant Emission (LP Ground Flare)



Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----



Stack Designation/Number LPGFLARE

List Source(s) or source ID exhausted to this stack: See Appendix D









Latitude Longitude





Section F - Flue and Air Contaminant Emission (HP Ground Flares (2x))



Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----



Stack Designation/Number HPGFLARE

List Source(s) or source ID exhausted to this stack: See Appendix D









Latitude Longitude





Section F - Flue and Air Contaminant Emission (HP Flare System – Elevated Flare)



Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----



Stack Designation/Number HPEFLARE

List Source(s) or source ID exhausted to this stack:









Latitude Longitude






Section F - Flue and Air Contaminant Emission (Spent Caustic Vent Thermal Incinerator)



Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----













Latitude Longitude






Section F - Flue and Air Contaminant Emission (Refrigerated Atmospheric Storage Flare)



Pollutant



PM10

SOx

CO

NOx

VOC

Others: ( e.g., HAPs) ----- ----- ----- -----













Latitude Longitude






Section D - Additional Information

Will the construction, modification, etc. of the sources covered by this application increase emissions from other sources at the facility? If so, describe and quantify.

No.

If this project is subject to any one of the following, attach a demonstration to show compliance with applicable standards. In accordance with the PSD and NSR requirements, the Plan Approval Application contains all of the materials required for a complete PSD/NSR application including BACT/LAER analyses, air quality impacts analysis/offsets requirements, additional impacts/alternative site evaluation and a complete regulatory analysis and detailed emissions increase calculations. The Plan Approval Application also contains proposed methods of compliance for the applicable standards denoted below. a. Prevention of Significant Deterioration permit (PSD), 40 CFR 52? (NO2, CO, PM, & PM10) YES NO b. New Source Review (NSR), 25 Pa. Code Chapter 127, Subchapter E? (NOx, VOC, & PM2.5) YES NO c. New Source Performance Standards (NSPS), 40 CFR Part 60? YES NO (If Yes, which subpart) Kb, VV, VVa, DDD, NNN, RRR, YYY (stayed), IIII, KKKK, & TTTT (proposed) d. National Emissions Standards for Hazardous Air Pollutants (NESHAP), YES NO 40 CFR Part 61? (If Yes, which subpart) J, V, & FF e. Maximum Achievable Control Technology (MACT) 40 CFR Part 63? YES NO (If Yes, which part) SS, UU, WW, XX, YY, FFFF, YYYY (stayed for natural gas-fired CTs), & ZZZZ Attach a demonstration showing that the emissions from any new sources will be the minimum attainable through the use of best available technology (BAT). See the control technology reviews included in Section 5.0 of the Plan Approval Application.

Provide emission increases and decreases in allowable (or potential) and actual emissions within the last five (5) years for applicable PSD pollutant(s) if the facility is an existing major facility (PSD purposes).

Section D - Additional Information (Continued)

Indicate emission increases and decreases in tons per year (tpy), for volatile organic compounds (VOCs) and nitrogen oxides (NOx) for NSR applicability since January 1, 1991 or other applicable dates (see other applicable dates in instructions). The emissions increases include all emissions including stack, fugitive, material transfer, other emission generating activities, quantifiable emissions from exempted source(s), etc.

Permit number

(if applicable) Date

issued

Indicate Yes or No if

emission increases and

decreases were used

previously for netting Source I. D. or Name

VOCs NOx Emission increases

in potential to emit

(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases

in potential to emit

(tpy)

Creditable emission

decreases in actual

emissions (tpy)

If the source is subject to 25 Pa. Code Chapter 127, Subchapter E, New Source Review requirements, a. Identify Emission Reduction Credits (ERCs) for emission offsets or demonstrate ability to obtain suitable ERCs for

emission offsets. b. Provide a demonstration that the lowest achievable emission rate (LAER) control techniques will be employed (if

applicable). See the LAER subsections in Section 5.0 of the Plan Approval Application. c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques demonstrating

that the benefits of the proposed source outweigh the environmental and social costs (if applicable). See Section 1.0 and Appendix E.2 of the Plan Approval Application.

Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of Article III and applicable requirements of the Clean Air Act adopted there under The Department may request additional information to evaluate the application such as a standby plan, a plan for air pollution emergencies, air quality modeling, etc. See the Plan Approval Application for this information.

Section G - Attachments Number and list all attachments submitted with this application below:

The contents of this Plan Approval Application are organized as follows:

Section 1.0 provides an overview of the Project, a description of the proposed site’s location and surrounding terrain and local climate in Beaver County, Pennsylvania, and a summary of the pollutant-by-pollutant emissions increases.

Section 2.0 contains a summary of the permit application requirements.

Section 3.0 contains the process description. Each of the manufacturing processes which comprise the proposed Project are described along with the points and types of emissions from each point. Also included is a description of the various outside the boundary limits (OSBL) elements of the Project.

Section 4.0 contains an overview of all of the air regulatory requirements to which the proposed Project is subject. This includes a description of both state and federal requirements.

Section 5.0 contains the Lowest Achievable Emissions Rate (LAER), Best Available Control Technology (BACT) and Pennsylvania Best Available Technology (PaBAT) analyses required in support of the plan approval process.

Section 6.0 contains a summary of the results from the air dispersion modeling analysis performed in support of the plan approval process for the PSD criteria pollutant for which the Project is subject to review (i.e., NO2, CO, and PM10).

Section 7.0 contains the additional impacts analysis required under 40 CFR §52.21(o).

Appendices A – Plan Approval Application Forms B – Detailed Emissions Increase Calculations C – Air Dispersion Modeling Report D – Trade Secret and/or Confidential Proprietary Information (Not in Public Version) E – 25 Pa. Code §127.205(5) Analysis F – Additional Support Material G – Summary of Compliance Demonstration

Appendix B

Emissions Estimates

1.0 GENERAL DISCUSSION For purposes of evaluating applicability of PSD and NSR nonattainment and determining the potential to emit of the proposed facility, the methodology used for evaluating emissions increases is the actual-to-potential test described at 40 CFR § 52.21(a)(2)(d) and incorporated by reference at 25 Pa. Code §127.83. Since this project is a greenfield facility, emissions increases under the actual-to-potential test are equal to the potential to emit of all of the equipment that will be constructed as part of the project. Baseline actual emissions from all units are zero.

The following discussion provides a summary of the methodology used determine the potential to emit from all units to be constructed project.

1.1 Emissions Units Table 1-1 lists the categories of emissions units to be constructed as part of the project and identifies the general methodology used to estimate the potential to emit for each unit type. A specific discussion of each of the calculation methodologies is provided in the following subsections.

Table 1-1. List of Emissions Units and Emissions Estimation Methods

EU Description Methodology

Ethane Cracking Furnaces (Emission Factor/Proposed Limit) x (Firing Rate) Combustion Turbines (Emission Factor/Proposed Limit) x (Firing Rate) Emergency Generator Engine (Emission Factor/Proposed Limit) x (Capacity) x (Op. Hours) Fire Water Pump Engine (Emission Factor/Proposed Limit) x (Capacity) x (Op. Hours)

Fugitive Equipment Leaks (SOCMI Leak Factors) x (Component Counts) x (1 – Ctrl. Efficiency) x (Component Pollutant Concentration)

PEU Particulate Emissions Vendor Estimates of Potential Emissions PE Handling, Storage & Loading PM (Emission Factor) x (Throughput-Based Air Flows) PE Handling, Storage & Loading VOC (Emission Factor/Proposed Limit) x (Throughput) Tanks VOC (not vented to flare) (TANKS 4.09d) x (1 – Ctrl. Efficiency) WWTP Units (not vented to TI) EPA WATER9 Model Cooling Tower PM AP-42 Methodology; PSD from Reisman & Frisbie Cooling Tower VOC (Proposed Limit) x (Circulation Rate) Organic Liquid Loading AP-42 Methodology (Chapter 5, Section 2) C3+ Loading (Emission Factor) x (Throughput) Caustic and LP TI (Emission Factor) x (Capacity) Flares (Emission Factor) x (Maximum Expected Flaring Rate) Plant Haul Roads AP-42 Methodology (Chapter 13, Section 2)

B-1

1.2 Ethane Cracking Furnaces Seven ethane cracking furnaces will be constructed. During normal operation, six of the furnaces will be operating at max capacity while the seventh will be in some other mode of operation related to decoking, etc. For some pollutants, the alternative modes of operation have different emission characteristics than normal operations. To address this situation, a model was developed that estimates the amount of time each year that a furnace will be in the various operating modes. Emissions are estimated based on the expected average annual time in each operating mode multiplied by the average firing rate in that mode multiplied by a mode-specific emissions factor. The emissions estimates are dominated by normal operations at the maximum firing rates. See Tables B-4 through B-6 for the complete documentation of the emissions factors used as well as the calculation methodology.

1.3 Combustion Turbine/Cogen Units Three Cogen Units will be constructed. These units are expected to operate at or near maximum capacity for most of the year. With the exception of NOx and CO, potential emissions from these units are estimated based on proposed BACT/LAER limits applied to the maximum firing rate assuming full-time (i.e., 8,760 hours per year) operation at that rate. In the case of NOx and CO, emissions during startup are expected to be significantly higher (on a pound per hour basis) than emissions during normal full-load operation. Thus, for purposes of estimating potential emissions of these pollutants, the maximum startup emissions rates were assumed to occur for 7 hours per year, with the remaining hours per year (i.e., 8,753) assumed to be at full-load. See Tables B-7 and B-8 for the complete documentation of the emissions factors used as well as the calculation methodology.

1.4 Emergency Use Engines A total of seven (7) emergency diesel-fueled internal combustion engines will be constructed. Normal (i.e., non-emergency) operation of these units is limited to 100 hours per year or less. Potential emissions from these units are estimated based on proposed BACT/LAER limits applied to the maximum firing rate assuming 100 hours per year of operation. See Tabled B-9 through B-12 for complete documentation of the emissions factors used as well as the calculation methodology.

1.5 Fugitive Equipment Leaks (SOCMI Leak Factors) U.S. EPA developed methodologies for estimating fugitive emissions of VOC from various components (e.g., valves, flanges, pump seals, etc.) organic chemical manufacturing plants, petroleum refineries, and petroleum marketing operations. Some of these methodologies provide estimates of fugitive emissions based on the service-type of (e.g., vapor) each component and the number and types of components in a facility. U.S. EPA’s analysis and the various methodologies developed are documented in a report titled Protocol for Equipment Leak Emission Estimates.1

1 See: Protocol for Equipment Leak Emission Estimates, U.S. EPA, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina 27711, EPA-453/R-95-017, 1995.

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The default factors for the synthetic organic chemical manufacturing industry (SOCMI) are used to estimate fugitive emissions from equipment leaks. To account for the effect emissions control resulting from implementing an LDAR program on these emissions sources, control efficiencies developed by the Texas Commission on Environmental Quality (TCEQ) have been applied to the uncontrolled SOCMI emissions factors for various components.2

Estimates are made of fugitive emissions of VOC, CH4, and HAP. These estimates are based on the controlled leak rate from a component and the concentration of the relevant species in the gas or liquid serviced by the component. See Tables B-13 through B-15 for complete documentation of the emissions factors used as well as the component counts, control efficiencies, and species concentrations used in estimating these emissions.

1.6 PE Unit Particulate Emissions A small quantity of particulate will be emitted from operations within the three PE production units. Estimates of these emissions have been provided by prospective process licensers and these estimates are summarized in Tables B-16 and B-17. Where appropriate, the vendor estimates have been scaled-up to 8,760 hours per year of operation. Certain assumptions regarding operating schedules were made to estimate short-term emissions from these operations for purposes of air quality modeling.

1.7 PE Pellet Handling, Storage, and Loadout A small quantity of particulate will be emitted from operations involving handling, storage, blending, and loadout of the product PE pellets. In general, these operations are relatively dust-free. However, some particulate is created in the processing and handling of the PE pellets. Particulate emissions from these operations are estimated based on an assumed particulate mass loading multiplied by an estimate of the ratio of exhaust air flows required or created by these operations to the potential PE pellet production capacity of the proposed plant. See Table B-18 for complete documentation of the emissions factors used as well as the calculation methodology.

In the case VOC emissions from these operations, potential emissions are estimated based on a maximum residual VOC concentration in the pellets multiplied by the potential pellet production rate. This estimation approach conservatively assumes that 100% of the residual VOC is emitted in the handling, storage, or loadout operations.

1.8 Storage Tank Emissions Uncontrolled emissions from certain fixed-roof atmospheric storage tanks (Table B-20) are estimated using U.S. EPA’s TANKS 4.09d software. This software implements the emissions estimation methodology outlined in AP-42, Chapter 7, Section 1. Controlled emissions from

2 See: TCEQ – Control Efficiencies for TCEQ Leak Detection and Repair Programs, Revised 07/11 (APDG 6129v2) available at: http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf

B-3

these tanks are estimated by assigning a 95% control efficiency based on the use of carbon canisters that will be installed on the vents from these tanks. No routine emissions, other than fugitive emissions from equipment components, are estimated from pressurized storage tanks (i.e., the C3+ storage spheres). These tanks are sealed and pressurized so that working and breathing losses do not occur. Emissions from storage tanks with vents routed to the flare headers are accounted for in the estimated emissions from the LP Thermal and Spent Caustic Vent Thermal Incinerators.

1.9 Wastewater Treatment Plant Emissions Uncontrolled emissions from the wastewater treatment unit operations are estimated using EPA’s WATER9 air emissions model. Emissions from certain controlled WWTP tanks were estimated using EPA’s TANKS software. These emissions are accounted for in the controlled emissions estimates from Spent Caustic Vent Thermal Incinerator.

1.10 Process and Cogen Cooling Towers Particulate emissions for the Process and Cogen Cooling Towers are estimated based on the design drift rate, the cooling water recirculation rate, the TDS of the cooling water, an estimated dry particle size distribution, and assumed full-time operation (i.e., 8,760 hours per year) of the tower. The “Reisman and Frisbie” methodology for determining the PM10 and PM2.5 size distribution of the PM emissions is used to estimate fine particulate emissions.3 For the TDS level in the plant cooling water systems, the PM10 fraction predicted by this methodology is 57.2 wt. % and the PM2.5 fraction is 0.21 wt. %. VOC emissions from the process cooling towers are estimated based on the proposed VOC LAER limit and the design cooling water circulation rate. See Tables B-22 and B-23 for documentation of the calculation methodology used to estimate PM and VOC emissions.

1.11 Organic Liquid Loading VOC emissions from loading of organic liquids (other than C3+ liquids) into transport trucks and railcars are estimated using the methodology found in AP-42, Chapter 5, Section 2. The VOC emissions estimates from these operations are based on an assumed VOC vapor pressure of 0.5 psia, a surrogate VOC vapor molecular weight, and the use of submerged loading. See Table B-24 for documentation of the calculation methodology used to estimate emissions.

1.12 C3+ Liquid Loading C3+ liquids will be store in pressure spheres and loaded into pressurized transport vehicles. VOC emissions from these operations have been estimated based on a study of LPG loading

3 See “Calculating Realistic PM10 Emissions from Cooling Towers,” Joel Reisman and Gordon Frisbie, Environmental Progress (Vol. 21, No. 2), July 2002, p. 127 – 129.

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conducted by the South Coast Air Quality Management District (SCAQMD) in California.4 An emissions factor of 13.3 lb VOC per railcar loaded was derived from the SCAQMD study and applied to the maximum expected volume of C3+ that will be shipped from the proposed plant.

1.13 Thermal Incinerators Two thermal incinerators will be used to control certain VOC emissions sources within the proposed plant. Emissions from these incinerators are estimated based on the expected maximum vent rates to the control devices, the design VOC destruction efficiency of the controls, and emissions factors for various pollutants produced during the combustion process. Emissions consist of products of combustion (e.g., NOx) along with unoxidized VOC and non-VOC organic compounds (e.g., CH4). See Tables B-26 and B-28 for documentation of the emissions factors as well as the calculation methodology used to estimate emissions from these control devices.

1.14 Flares Five flares will be constructed to control VOC emissions from the proposed plant. Emissions from the flares are estimated based on the expected maximum vent rates to the flares, the VOC destruction efficiency of the flares, and emissions factors for various pollutants produced during the combustion process. Emissions consist of products of combustion (e.g., NOx) along with unoxidized VOC and non-VOC organic compounds (e.g., CH4). For the most part, these flares are only used for short-periods during startup, shutdown, or emergency events. Potential emissions from these control devices are estimated based on a number of worst-case assumptions about the flaring rates expected to occur during routine, foreseeable operations. See Table B-27 for documentation of the emissions factors as well as the calculation methodology used to estimate emissions from the flares.

1.15 Plant Roads Particulate emissions from plant roads are estimated using the methodology described in AP-42, Chapter 13, Section 2.1 – Paved Roads. Specifically, Equation 2 in this section is used to determine a paved road emissions factor and then that factor is applied to the estimated truck travel distance based on the estimated maximum number of trucks that will enter and leave the facility. The derivation of the pollutant-specific emissions factors are documented in the spreadsheet printouts provided in Table B-29.

1.16 Cocatalyst Feed Pots Table B-34 contains an estimate of emissions of hexane that occur during the transfer of cocatalyst from delivery containers to the feed pots. The estimate assumes compliance with 40 CFR Part 63 Subpart FFFF. The vent stream cannot be controlled by the VOC Control System due to the highly pyrophoric nature of the cocatalyst. As a result, the stream vents to a remote

4 See Final Staff Report Proposed Rule 1177 – Liquefied Petroleum Gas Transfer and Dispensing, South Coast Air Quality Management District, June 2012; available at: http://www.aqmd.gov/hb/attachments/2011-2015/2012Jun/2012-Jun1-031.pdf; (see Attachment F)

B-5

http://www.aqmd.gov/hb/attachments/2011-2015/2012Jun/2012-Jun1-031.pdf

sand pit for safe destruction. Since the % destruction cannot be measured, a 20ppm hexane exhaust concentration is used for the calculation. Documentation of the calculation methodology used to estimate the emissions is also presented in the table.

B-6

Attachment B1 - Tables

B-7

PollutantCracking Furnaces

Polyethylene Units

Combined Cycle Units

Flares & Incinerators

Tanks & Loadout

FugitivesSupport

UnitsTotal

Carbon Monoxide 670 - 43.5 277 - - 0.6 991Nitrogen Oxides 181 - 67.9 74.8 - - 2.8 327PM 34.1 15.3 16.9 4.6 - - 8.3 79PM10 86.8 4.9 59.8 8.2 - - 4.7 164PM2.5 86.8 4.9 59.8 8.2 - - 0.1 160Sulfur Dioxide 3.6 - 13.3 5.0 - - 0.0 22VOC 32.4 96.6 31.9 219 14.1 47.5 42.7 484CO2e 1,048,668 - 1,061,680 147,708 - 138 1,272 2,259,466Sulfuric Acid Mist 0.1 - 0.5 0.2 - - 0.0 0.9§112 HAP 18.2 <0.1 9.3 3.4 1.77 5.40 3.9 41.9Support Units include: fire pump and emergency generator engines, cooling towers, wastewater treatment and plant roads.Polyethylene Units include: PE processing equipment exluding fugitive, flare, and incinerator emissions.

Potential Annual Emissions (tons per year)

Table B-1. Summary of Potential Annual Emissions

B-9

PollutantCracking Furnaces

Polyethylene Units

Combined Cycle Units

Flares & Incinerators

Tanks & Loadout

FugitivesEmergency

EnginesWWTP

Cooling Tower

Total

1,3-Butadiene 3.90E-032-Methylnaphthalene 2.31E-043-Methylchloranthrene 1.73E-057,12-Dimethylbenz(a)anthrac 1.54E-04Acenaphthene 1.73E-05 3.64E-05Acenaphthylene 7.17E-05Acetaldehyde 3.63E-01 1.96E-04Acrolein 5.80E-02 6.13E-05Anthracene 2.31E-05 9.56E-06Arsenic 1.93E-03Benzene 2.02E-02 1.09E-01 6.03E-03 4.24E-01Benzo(a)anthracene 1.73E-05 4.84E-06Benzo(a)pyrene 1.16E-05 2.00E-06Benzo(b)fluoranthene 1.73E-05 8.63E-06Benzo(g,h,i)perylene 1.16E-05Benzo(g,h,l)perylene 4.32E-06Benzo(k)fluoranthene 1.73E-05 1.69E-06Beryllium 1.16E-04Cadmium 1.06E-02Chromium 1.35E-02Chrysene 1.73E-05 1.19E-05Cobalt 8.09E-04Dibenzo(a,h)anthracene 1.16E-05 2.69E-06Dichlorobenzene 1.16E-02Ethylbenzene 2.90E-01Fluoranthene 2.89E-05 3.13E-05Fluorene 2.70E-05 9.95E-05Formaldehyde 7.22E-01 6.44E+00 6.13E-04Hexane 1.73E+01Indeno(1,2,3-cd)pyrene 1.73E-05 3.22E-06Manganese 3.66E-03Mercury 2.50E-03Naphthalene 5.87E-03 1.18E-02 1.01E-03Nickel 2.02E-02PAH 1.99E-02Phenanthrene 1.64E-04 3.17E-04Phenol 4.10E-05Propylene Oxide 2.63E-01Pyrene 4.81E-05 2.88E-05Selenium 2.31E-04Toluene 3.27E-02 1.18E+00 2.18E-03Xylenes 5.80E-01 1.50E-03TOTAL HAP 1.82E+01 9.31E+00 3.4 1.8 5.4 1.22E-02 4.24E-01 3.42 4.19E+01Support Units include: fire pump and emergency generator engines, cooling towers, wastewater treatment and plant roads.Polyethylene Units include: PE processing equipment exluding fugitive, flare, and incinerator emissions.

Potential Annual Emissions (tons per year)

Table B-2. Summary of Potential Hazardous Air Emissions

<0.1

<0.1

B-10

Source/Basis

grams per pound = 453.6 g/lb standard conversion factorpounds per kilo = 2.205 lb/kg standard conversion factorHydrogen HHV = 61,000 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionEthylene HHV = 21,884 Btu/lb http://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html

Butane HHV = 20,900 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionPentane HHV = 20,908 Btu/lb http://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html

Ethane HHV = 22,400 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionMethane HHV = 23,900 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustion

Natural Gas HHV = 23,000 Btu/lb http://en.wikipedia.org/wiki/Heat_of_combustionNatural Gas HHV = 1,020 Btu/SCF AP-42, Table 1.4-1 (footnote "a").

kW per bhp = 0.7457 kW/bhp standard conversion factorMolecular Weight of Air = 28.84 lb/lb-mole Based on 21% O2 & 79% N2.

Gas Law Constant R = 10.732 ft3∙psi/°R∙lb-mol standard conversion factorStandard Pressure = 14.696 psia standard for environmental calcuations

Standard Temperature = 68 °F standard for environmental calcuationsMolar Volume = 385.6 scf/lb-mole Molar voume at 14.696 psia and 68 °F.

VOC Molecular Weight = 44 lb/lb-mole VOC assumed to be propane for purposes of calculating mass emissions from ppmv values.Tons per Metric Tonne = 1.102 T/MT standard conversion factor

Gallons per Cubic Meter = 264.2 gal/m3 standard conversion factorHorsepower per Megawatt (mechanical) = 1,341 hp/MWm standard conversion factorICE Avg Brake-specific Fuel Consumption = 7,000 Btu/hp-hr AP-42, Table 3.3-1, footnote 'a'.

CH4 Global Warming Potential = 25 lb/lb CO2 40 CFR 98, Table A-1.N2O Global Warming Potential = 298 lb/lb CO2 40 CFR 98, Table A-1.

Natural Gas CO2 Emissions Factor = 117.0 lb/MMBtu 40 CFR 98, Table C-1 (HHV basis).Natural Gas CH4 Emissions Factor = 2.2E-03 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).Natural Gas N2O Emissions Factor = 2.2E-04 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).

Natural Gas CO2e Emissions Factor = 117.1 lb/MMBtu Sum of CO2, CH4, and N2O factors adjusted for global warming potentials.Natural Gas CO2e-toCO2 Ratio = 1.001 lb CO2e/lb CO2 = (Natural Gas CO2e Emissions Factor) / (Natural Gas CO2 Emissions Factor)

Ethane CO2 Emissions Factor = 131.4 lb/MMBtu 40 CFR 98, Table C-1 (HHV basis).Fuel Gas N2O Emissions Factor = 1.3E-03 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).Fuel Gas CH4 Emissions Factor = 6.6E-03 lb/MMBtu 40 CFR 98, Table C-2 (HHV basis).

Methane CO2 Emissions Factor = 114.8 lb/MMBtu Based on a methane HHV of 23,900 Btu/lb.Fuel Gas CO2 Emissions Factor = 130.1 lb/MMBtu 40 CFR 98, Table C-1 (HHV basis).

Natural Gas Condensable PM10/PM2.5 EF = 0.0056 lb/MMBtu AP-42, Table 1.4-2 (condensable only); Smokless flare assumed to produce no filterable PM.Natural Gas Filterable PM/PM10/PM2.5 EF 0.0019 lb/MMBtu AP-42, Table 1.4-2 (filterable only); Smokless flare assumed to produce no filterable PM.

Natural Gas VOC EF = 0.0054 lb/MMBtu AP-42, Table 1.4-2.Natural Gas CO EF = 0.0824 lb/MMBtu AP-42, Table 1.4-1.

Natural Gas Lead EF = 4.9E-07 lb/MMBtu AP-42, Table 1.4-2.Natural Gas F-Factor Conversion = 2.3E-05 lb-mol/MMBtu-ppmvd 40 CFR 60, Table 19-2; dry basis, 0% O2, 68°F.

Parameter ValueStandard Conversion Factors and Constants:

Standard Emissions Factors:

Table B-3. Constants

B-11

http://en.wikipedia.org/wiki/Heat_of_combustion

http://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html


http://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html




Source/BasisParameter Value

Specific Gravity of LDPE = 57.28 lb/ft3 Industry standard value.natural gas sulfur content = 5,000 gr/MMSCF Preliminary design specification.

Natural Gas SO2 EF = 0.0015 lb/MMBtu Based on sulfur content and AP-42, Table 1.4-2, Footnotes "a" and "d".Natural Gas H2SO4 EF = 0.0001 lb/MMBtu AP-42, Table 1.3-1; estimated based on SO3-to-SO2 emissions ratio for distillate oil.

Avg. % H2 used to fire Cracking Furnaces = wt. % Preliminary design basis.Flare Pilot Burner Size = 1 MMBtu/hr Preliminary design specification.

HP Flare Header Sweep Gas Rate = 1 MT/hr Based on use of natural gas as sweep gas in flare header.Annual PE Pellet Production Capacity = 1,600,000 MT/yr Facility design basis (metric tonnes).Annual PE Pellet Production Capacity = 1,763,696 T/yr Facility design basis (short tons).

Max PE Out by Rail = 95% wt. % A max-case estiamte of the mass of pellets that will be loaded out by rail.Max PE Out by Truck = 20% wt. % A max-case estiamte of the mass of pellets that will be loaded out by truck.

ECU Maximum Firing Rate = 620 MMBtu/hr Preliminary design basis @ 110% of nominal rate.NG to TG Header = 9.4 T/hr NG added to TG header at ECU design firing rate of 620 MMBtu/hr & 6 furnaces operating.

CO2 Emissions from Decoking = 1,461 lb/hr Preliminary design basis; excludes CO2 from NG combustion.Tail Gas HHV = 461 Btu/scf Excludes NG that is added to tail gas; based on TG composition below.

Tail Gas H2 Content = 48.3% % of HHV Based on 79 mol% H2 in tail gas and 9.4 tons per hour NG to TG header @ design firing rate.Tail Gas CH4 Content = 40.1% % of HHV Based on 21 mol% CH4 in tail gas and 9.4 tons per hour NG to TG header @ design firing rate.Tail Gas NG Content = 11.6% % of HHV Based on 9.4 T/hr NG added to TG header at design firing rate.

VOC Content of Gases to HP Ground Flare = 60% wt. % Preliminary design specification (average ethylene content)

Project-Specific Constants & Factors:

Table B-3. Constants (cont'd)

B-12

HeatInput

Fuel Source

Event Frequency

Duration per Event

Annual EventDuration

NOx Emissions

PM10 Emissions

COEmissions

Furnace Operating Modes MMBtu/hr # per yr hrs hrs/yr lb/hr lb/hr lb/hrNormal Operation (ST) 620 TG 9.30 3.10 21.7Normal Operation (LT) 620 TG 7,509 6.20 3.10 21.7Decoking 180 TG 12 36 432 2.70 1.86 52.2Feed In 277 NG 12 2 24 4.16 1.39 9.70Feed Out 277 NG 12 2 24 4.16 1.39 9.70Hot Steam Standby 173 NG 12 60 723 4.33 0.87 6.06Startup 86.5 NG 1 24 24 15.57 0.43 25.1Shutdown 86.5 NG 1 24 24 15.57 0.43 25.1

Annual Emissions =Decoking Cycle ST Rates = 4.33 1.86 52.2

Normal Ops ST Rates = 9.30 3.10 21.7Normal Ops LT Rates = 6.20 3.10 21.7

Average Annual Rates = 5.91 2.83 21.9

Table B-4. Cracking Furnace Emission Estimates

B-13

Furnace Operating ModesNormal Operation (ST)Normal Operation (LT)DecokingFeed InFeed OutHot Steam StandbyStartup Shutdown

Annual Emissions =Decoking Cycle ST Rates =

Normal Ops ST Rates =Normal Ops LT Rates =

Average Annual Rates =

NOx EF PM EFPM10/2.5

EF CO EF SO2 EF VOC EF CO2 EF CH4 EF N2O EF CO2e EF H2SO4 EF Pb EFlb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu lb/MMBtu

0.015 0.002 0.0050 0.035 0.0002 0.0019 59.5 0.0011 0.00022 59.6 6.8E-06 5.7E-080.010 0.002 0.0050 0.035 0.0002 0.0019 59.5 0.0011 0.00022 59.6 6.8E-06 5.7E-080.015 0.010 0.0103 0.290 0.0002 0.0019 67.7 0.0011 0.00022 67.8 6.8E-06 5.7E-080.015 0.002 0.0050 0.035 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.015 0.002 0.0050 0.035 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.025 0.002 0.0050 0.035 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.180 0.002 0.0050 0.290 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-080.180 0.002 0.0050 0.290 0.0015 0.0019 117.0 0.0011 0.00022 117.1 6.8E-06 5.7E-08

Table B-4. Cracking Furnace Emission Estimates (cont'd)

B-14

Furnace Operating ModesNormal Operation (ST)Normal Operation (LT)DecokingFeed InFeed OutHot Steam StandbyStartup Shutdown

Annual Emissions =Decoking Cycle ST Rates =

Normal Ops ST Rates =Normal Ops LT Rates =

Average Annual Rates =

NOx Emissions

PM Emissions

PM10/2.5 Emissions

CO Emissions

SO2 Emissions

VOC Emissions

CO2 Emissions

CH4 Emissions

N2O Emissions

CO2e Emissions

H2SO4 Emissions

PbEmissions

T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr T/yr

23.28 4.34 11.64 81.47 0.40 4.42 138,613 2.65 0.51 138,832 1.6E-02 1.3E-040.58 0.40 0.40 11.28 0.01 0.07 2,631 0.04 0.01 2,634 2.7E-04 2.2E-060.05 0.01 0.02 0.12 0.00 0.01 389 0.00 0.00 389 2.3E-05 1.9E-070.05 0.01 0.02 0.12 0.00 0.01 389 0.00 0.00 389 2.3E-05 1.9E-071.56 0.12 0.31 2.19 0.09 0.12 7,316 0.07 0.01 7,322 4.3E-04 3.6E-060.19 0.00 0.01 0.30 0.00 0.00 121 0.00 0.00 122 7.1E-06 5.9E-080.19 0.00 0.01 0.30 0.00 0.00 121 0.00 0.00 122 7.1E-06 5.9E-0825.9 4.87 12.4 95.8 0.51 4.63 149,580 2.78 0.54 149,810 1.7E-02 1.4E-04

Table B-4. Cracking Furnace Emission Estimates (cont'd)

B-15

ETHYLENE CRACKING FURNACE CALCULATION NOTES/BASISGeneral:

• Cracking Furnace Emission Unit IDs = F-11101, F-12101, F-13101 ,F-14101, F-15101, F-16101, F-17101.• Calculation is for 1 furnace.• ST = short-term; this mode represents the possibility of reduced SCR performance due to short-term process fluctiations. No more than 2 furnaces expected to be in this mode at any one time.• LT = long-term; this mode represents the average NOx limit achievable by the SCR system including short-term fluctuations.• Furnace operating mode parameters are estimated based on 7 furnaces with 6 in normal operation at all times.• Each furnace is assumed to require decoking a maximum of 12 times per year.• Each furnace is assumed to undergo one startup/shutdown cycle per year.• Heat input estimates for decoking-related operating modes are the average for an acitivity over the period (e.g., "Feed In" value is average of 160MMBtu/hr at start and 395 MMBtu/hr at end of "Feed In").• Annual Emissions (T/yr) = (Mode Heat Input - MMBtu/hr) x (Hours/Year in Mode) x (EF - lb/MMBtu) / (2,000 lb/T)• Hourly Emissions (lb/hr) = (Mode Heat Input - MMBtu/hr) x (EF - lb/MMBtu)

BASIS OF EMISSION FACTORS:NOx:

• Normal Operation: ST and LT rates based on proposed LAER limits.• Decoking, Feed In, Feed Out, Hot Standby and Shutdown: based on preliminary vendor data / expected SCR performance.• Startup = SCR Offline.

CO:• Normal Operation, Feed In, Feed Out and Hot Steam Standby = Proposed BACT limit.• Decoking, Startup, Shtudown: factors equivalent to proposed lb/hr BACT limit for decoking.

SO2/H2SO4:• All Modes: SO2 EF based on a natural gas sulfur content of 5,000 gr/MMSCF and an average NG firing rate of 11.6% of heat input to furance (remainder is Tail Gas).• All Modes: Tail Gas fired in furnace does not contain any sulfur.• All Modes: H2SO4-to-SO2 ratio is assumed equal to ratio for firing distillate oil (see AP-42, Table 1.3-1).

VOC • All modes: VOC EF is equivalent to proposed LAER limit at max firing rate.PM/PM10/PM2.5:

• PM emissions do not include condensable particulate.• Normal Operation, Feed In, Feed Out, Hot Standby, Startup and Shutdown: EF based on preliminary vendor data.• Decoking: based on preliminary vendor data; hourly emissions during decoking are estimated at 1.86 lb/hr; value shown is normalized to lb/MMBtu for consistency with calculation methodology.

GHGs• All modes except decocking: emissions factors for CO2, CH4, and N2O are from 40 CFR 98, Tables C-1 and C-2.• Firing H2 does not produce any CO2 or CH4 emissions so CO2 and CH4 emissions factors are adjusted to account for Tail Gas H2 concentrationof 48.3% where applicable.• N2O emissions factor for NG used for both Tail Gas and Natural Gas firing.• CO2e emissions during decoking include emissions from fuel combustion as well as emissions from coke burn-off. See 'Constants' sheet forcoke burn-off emissions rate.

• CO2e emissions equal total of CO2, CH4, and N2O emissions adjusted for global warming potentials of 1, 25, and 298 respectively.Lead

• All Modes = Pb EF based on a AP-42 natural gas emissions factor (see Table 1.4-2) and an average NG firing rate of 12% of gas fired in furance (remainder is Tail Gas).• All Modes = Tail Gas fired in furnace does not contain any lead.

Table B-5. Ethylene Cracking Furnace Calculation Notes

B-16

Emission Unit IDs = Ethylene Cracking Furnace HAP PTEMax CH4+NG Input = 320 (MMBtu/hr) Based on 620 MMBtu/hr and 51.7% of heat in from CH4+NG.*

Annual Hours @ 100% Load = 8,760 hr/yr Conservatively assumes full-time at 100% load.Hourly Emissions = (Max Heat Input - MMBtu/hr) x (1 SCF/1,020 Btu) x (EF - lb/MMSCF)Annual Emissions = (Max Heat Input - MMBtu/hr) x (1 SCF/1,020 Btu) x (EF - lb/MMSCF) x (Annual Operating Hours) / (2,000 lb/T)

PollutantEF

(lb/MMSCF) EF SourceEF

(lb/MMBtu) §112 HAP?

PTE1 Cracking Furnace

(lb/hr)

PTE1 Cracking Furnace

(T/yr)2-Methylnaphthalene 2.40E-05 AP42; Table 1.4-3; 7/98. 2.35E-08 YES 7.54E-06 3.30E-053-Methylchloranthrene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-067,12-Dimethylbenz(a)anthracene <1.6E-05 AP42; Table 1.4-3; 7/98. <1.57E-08 YES <5.02E-06 <2.20E-05Acenaphthene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Anthracene <2.4E-06 AP42; Table 1.4-3; 7/98. <2.35E-09 YES <7.54E-07 <3.30E-06Benzo(a)anthracene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Benzene 2.10E-03 AP42; Table 1.4-3; 7/98. 2.06E-06 YES 6.59E-04 2.89E-03Benzo(a)pyrene <1.2E-06 AP42; Table 1.4-3; 7/98. <1.18E-09 YES <3.77E-07 <1.65E-06Benzo(b)fluoranthene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Benzo(g,h,i)perylene <1.2E-06 AP42; Table 1.4-3; 7/98. <1.18E-09 YES <3.77E-07 <1.65E-06Benzo(k)fluoranthene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Butane 2.10E+00 AP42; Table 1.4-3; 7/98. 2.06E-03 NO 6.59E-01 2.89E+00Chrysene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Dibenzo(a,h)anthracene <1.2E-06 AP42; Table 1.4-3; 7/98. <1.18E-09 YES <3.77E-07 <1.65E-06Dichlorobenzene 1.20E-03 AP42; Table 1.4-3; 7/98. 1.18E-06 YES 3.77E-04 1.65E-03Ethane 3.10E+00 AP42; Table 1.4-3; 7/98. 3.04E-03 NO 9.73E-01 4.26E+00Fluoranthene 3.00E-06 AP42; Table 1.4-3; 7/98. 2.94E-09 YES 9.42E-07 4.13E-06Fluorene 2.80E-06 AP42; Table 1.4-3; 7/98. 2.75E-09 YES 8.79E-07 3.85E-06Formaldehyde 7.50E-02 AP42; Table 1.4-3; 7/98. 7.35E-05 YES 2.35E-02 1.03E-01Hexane 1.80E+00 AP42; Table 1.4-3; 7/98. 1.76E-03 YES 5.65E-01 2.48E+00Indeno(1,2,3-cd)pyrene <1.8E-06 AP42; Table 1.4-3; 7/98. <1.76E-09 YES <5.65E-07 <2.48E-06Naphthalene 6.10E-04 AP42; Table 1.4-3; 7/98. 5.98E-07 YES 1.92E-04 8.39E-04Pentane 2.60E+00 AP42; Table 1.4-3; 7/98. 2.55E-03 NO 8.16E-01 3.58E+00Phenanthrene 1.70E-05 AP42; Table 1.4-3; 7/98. 1.67E-08 YES 5.34E-06 2.34E-05Propane 1.60E+00 AP42; Table 1.4-3; 7/98. 1.57E-03 NO 5.02E-01 2.20E+00Pyrene 5.00E-06 AP42; Table 1.4-3; 7/98. 4.90E-09 YES 1.57E-06 6.88E-06Toluene 3.40E-03 AP42; Table 1.4-3; 7/98. 3.33E-06 YES 1.07E-03 4.68E-03Arsenic 2.00E-04 AP42; Table 1.4-4; 7/98. 1.96E-07 YES 6.28E-05 2.75E-04Barium 4.40E-03 AP42; Table 1.4-4; 7/98. 4.31E-06 NO 1.38E-03 6.05E-03Beryllium <1.2E-05 AP42; Table 1.4-4; 7/98. <1.18E-08 YES <3.77E-06 <1.65E-05Cadmium 1.10E-03 AP42; Table 1.4-4; 7/98. 1.08E-06 YES 3.45E-04 1.51E-03Chromium 1.40E-03 AP42; Table 1.4-4; 7/98. 1.37E-06 YES 4.40E-04 1.93E-03Cobalt 8.40E-05 AP42; Table 1.4-4; 7/98. 8.24E-08 YES 2.64E-05 1.16E-04Copper 8.50E-04 AP42; Table 1.4-4; 7/98. 8.33E-07 NO 2.67E-04 1.17E-03Manganese 3.80E-04 AP42; Table 1.4-4; 7/98. 3.73E-07 YES 1.19E-04 5.23E-04Mercury 2.60E-04 AP42; Table 1.4-4; 7/98. 2.55E-07 YES 8.16E-05 3.58E-04Molybdenum 1.10E-03 AP42; Table 1.4-4; 7/98. 1.08E-06 NO 3.45E-04 1.51E-03Nickel 2.10E-03 AP42; Table 1.4-4; 7/98. 2.06E-06 YES 6.59E-04 2.89E-03Selenium <2.4E-05 AP42; Table 1.4-4; 7/98. <2.35E-08 YES <7.54E-06 <3.30E-05Vanadium 2.30E-03 AP42; Table 1.4-4; 7/98. 2.25E-06 NO 7.22E-04 3.16E-03Zinc 2.90E-02 AP42; Table 1.4-4; 7/98. 2.84E-05 NO 9.11E-03 3.99E-02Total § 112 HAPs from 1 Cracking Furnace = <5.93E-01 <2.60E+00Total § 112 HAPs from 7 Cracking Furnaces = <4.15E+00 <1.82E+01* No HAP emissions have been attributed to combustion of H2 in the cracking furnaces.

F-11101 - F17010

Table B-6. Cracking Furnace Hazardous Air Pollutant Emission Estimates

B-17

Emission Unit(s) ID = Combustion Turbine & Duct Burner RNSRP PTEParameter

Calcuation Inputs:Max Heat Input [HHV] = 690 MMBtu/hr

Turbine/Duct Burner PM EF = 0.0019 lb/MMBtuTurbine/Duct Burner PM10 EF = 0.0066 lb/MMBtu

Turbine/Duct Burner PM2.5 EF = 0.0066 lb/MMBtuTurbine/Duct Burner VOC EF = 0.00352 lb/MMBtuTurbine/Duct Burner NOx EF = 0.00736 lb/MMBtuTurbine/Duct Burner SO2 EF = 0.0015 lb/MMBtuTurbine/Duct Burner CO EF = 0.00448 lb/MMBtu

Turbine/Duct Burner CO2 EF = 117.0 lb/MMBtuTurbine/Duct Burner N2O EF = 2.2E-04 lb/MMBtuTurbine/Duct Burner CH4 EF = 2.2E-03 lb/MMBtu

Turbine/Duct Burner H2SO4 EF = 5.9E-05 lb/MMBtuTurbine/Duct Burner Pb EF = 4.9E-07 lb/MMBtu

Turbine/Duct Burner Fluoride EF = 0 lb/MMBtuStartup NOx EF = 113 lb/hr

Startup CO EF = 276 lb/hrStartup Hours = 7 hr/yrAnnual Hours = 8,760 hr/yr

Annual Emissions Calculations (for 1 unit):PM Emissions = 5.63 T/yr

PM10 Emissions = 19.95 T/yrPM2.5 Emissions = 19.95 T/yr

VOC Emissions = 10.64 T/yr

NOx Emissions = 22.6 T/yrSO2 Emissions = 4.44 T/yr

CO Emissions = 14.5 T/yrCO2 Emissions = 353,528 T/yrN2O Emissions = 0.67 T/yrCH4 Emissions = 6.66 T/yr

H2SO4 Emissions = 0.18 T/yrPb Emissions = 0.00 T/yr

Fluoride Emissions = 0.00 T/yrCO2e Emissions = 353,893 T/yr

Short-Term Emissions (for 1 unit):PM Emissions = 1.29 lb/hr

PM10 Emissions = 4.55 lb/hrPM2.5 Emissions = 4.55 lb/hr

VOC Emissions = 2.43 lb/hrNOx Emissions = 5.17 lb/hrSO2 Emissions = 1.01 lb/hrCO Emissions = 276 lb/hr

CO2 Emissions = 80,714 lb/hrN2O Emissions = 0.15 lb/hrCH4 Emissions = 1.52 lb/hr

H2SO4 Emissions = 0.04 lb/hrPb Emissions = 0.00 lb/hr

Fluoride Emissions = 0.00 lb/hrCO2e Emissions = 80,798 lb/hr

Summary of Results

PM PM10 PM2.5 VOC NOx SO2 CO GHGm CO2e H2SO4One Unit = 5.6 19.9 19.9 10.64 22.6 4.44 14.5 353,536 353,893 0.18

Three Units = 16.9 59.8 59.8 31.92 67.9 13.33 43.5 1,060,607 1,061,680 0.54

Potential Emissions (tons per year)

= (Max Heat Input [HHV]) x (Turbine/Duct Burner VOC EF)= Annual Average Value for Modeling Purposes.= (Max Heat Input [HHV]) x (Turbine/Duct Burner SO2 EF)= Startup Max Rate for Modeling Purposes= (Max Heat Input [HHV]) x (Turbine/Duct Burner CO2 EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner N2O EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner CH4 EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner H2SO4 EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Pb EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Fluoride EF)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.

= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM2.5 EF)

= (Max Heat Input [HHV]) x (Turbine/Duct Burner SO2 EF) x (Annual Hours) / (2000 lb/T)= [(Max Heat Input [HHV]) x (Turbine/Duct Burner CO EF) x (Annual Hours - Startup Hours ) + (Startup CO EF) x (Startup Hours )] / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner CO2 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner N2O EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner CH4 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner H2SO4 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Pb EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner Fluoride EF) x (Annual Hours) / (2000 lb/T)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.

= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM EF)= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM10 EF)

= [(Max Heat Input [HHV]) x (Turbine/Duct Burner NOx EF) x (Annual Hours - Startup Hours ) + (Startup NOx EF) x (Startup Hours )] / (2000 lb/T)

40 CFR 98, Table C-1; EF for natural gas.40 CFR 98, Table C-2; EF for natural gas.40 CFR 98, Table C-2; EF for natural gas.AP-42, Table 1.3-1; estimated based on SO3-to-SO2 emissions ratio for distillate oil.AP-42, Table 1.4-2.Not emitted.

= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM10 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner PM2.5 EF) x (Annual Hours) / (2000 lb/T)= (Max Heat Input [HHV]) x (Turbine/Duct Burner VOC EF) x (Annual Hours) / (2000 lb/T)

Worst-case estimate.

Design estimate.Design estimate.

Equivalent to proposed LAER limit at max load (based on 2 ppmvd @ 15% O2).

CT1/2/3Value Source / Basis

Total maximum heat input to each turbine/duct burner unit.AP-42, 3.1-2a (filterable only).Proposed BACT limit.Proposed LAER limit.Equivalent to proposed LAER limit at max load (based on 1 ppmvd @ 15% O2 as C3H8).Equivalent to proposed LAER limit at max load (based on 2 ppmvd @ 15% O2 as NO2).Based on max NG sulfur content; see "Constants" sheet for details.

Table B-7. Combustion Turbine & Duct Burner Emission Estimates

B-18

Emission Unit(s) ID = Combustion Turbine & Duct Burner HAP PTEMax CH4+NG Input : 690 (MMBtu/hr) Total heat input to turbines plus duct burners.*

Annual Hours @ 100% Load : 8,760 hr/yr Conservatively assumes full-time at 100% load.Hourly Emissions : (Max Heat Input - MMBtu/hr) x (EF - lb/MMBtu)Annual Emissions : (Max Heat Input - MMBtu/hr) x (EF - lb/MMBtu) x (Annual Operating Hours) / (2,000 lb/T)

EF SourceEF

(lb/MMBtu) §112 HAP?

PTE1 CT/DB(lb/hr)

PTE1 CT/DB

(T/yr)1,3-Butadiene : AP42; Table 3.1-3; 4/00. <4.30E-07 YES <2.97E-04 <1.30E-03Acetaldehyde : AP42; Table 3.1-3; 4/00. 4.00E-05 YES 2.76E-02 1.21E-01

Acrolein : AP42; Table 3.1-3; 4/00. 6.40E-06 YES 4.42E-03 1.93E-02Benzene : AP42; Table 3.1-3; 4/00. 1.20E-05 YES 8.28E-03 3.63E-02

Ethylbenzene : AP42; Table 3.1-3; 4/00. 3.20E-05 YES 2.21E-02 9.67E-02Formaldehyde : AP42; Table 3.1-3; 4/00. 7.10E-04 YES 4.90E-01 2.15E+00

Naphthalene : AP42; Table 3.1-3; 4/00. 1.30E-06 YES 8.97E-04 3.93E-03PAH : AP42; Table 3.1-3; 4/00. 2.20E-06 YES 1.52E-03 6.65E-03

Propylene Oxide : AP42; Table 3.1-3; 4/00. <2.90E-05 YES <2.00E-02 <8.76E-02Toluene : AP42; Table 3.1-3; 4/00. 1.30E-04 YES 8.97E-02 3.93E-01Xylenes : AP42; Table 3.1-3; 4/00. 6.40E-05 YES 4.42E-02 1.93E-01

Total § 112 HAPs from 1 Cogen Unit = <7.09E-01 <3.10E+00Total § 112 HAPs from 3 Cogen Units = <2.13E+00 <9.31E+00* HAP emissions from duct burners assumed to have the same profile as HAP emissions from the turbines.

CT1/2/3

Pollutant

Table B-8. Combustion Turbine & Duct Burner HAP Emission Estimates

B-19

Emission Unit(s) ID = Emergency Generator IC EnginesParameter Value Units

Calculation InputsGen-Set Output = 3.0 MWe

Gen-Set Efficiency = 80% kWe/kWmRated Horsepower, each engine = 5,028 bhp

No. of Engines = 4Rated Horespower, Total = 20,110 bhp

PM EF = 4.41E-05 lb/bhp-hrPM10 EF = 4.23E-05 lb/bhp-hr

PM2.5 EF 3.97E-05 lb/bhp-hr VOC EF = 7.80E-03 lb/bhp-hrNOx EF = 2.34E-03 lb/bhp-hr SO2 EF = 1.09E-05 lb/bhp-hr

CO EF = 4.41E-05 lb/bhp-hrCO2 EF = 1.14E+00 lb/bhp-hrCH4 EF = 4.63E-05 lb/bhp-hrN2O EF = 9.26E-06 lb/bhp-hr

CO2e EF = 1.15E+00 lb/bhp-hrH2SO4 EF = 4.37E-07 lb/bhp-hr

Annual Operating Hours = 100 hrs/yr/engineHourly Emissions Calculations (each engine)

PM Hourly Max = 0.22 lb/hrPM10 Hourly Max = 0.21 lb/hr

PM2.5 Hourly Max = 0.20 lb/hrVOC Hourly Max = 39.24 lb/hrNOx Hourly Max = 11.75 lb/hrSO2 Hourly Max = 0.05 lb/hrCO Hourly Max = 0.22 lb/hr

CO2 Hourly Max = 5,738 lb/hrCH4 Hourly Max = 0.233 lb/hrN2O Hourly Max = 0.047 lb/hr

CO2e Hourly Max = 5,758 lb/hrH2SO4 Hourly Max = 0.002 lb/hr

Annual Emissions Calculations (all engines)PM PTE = 0.04 tpy

PM10 PTE = 0.04 tpyPM2.5 PTE = 0.04 tpy

VOC PTE = 7.85 tpyNOx PTE = 2.35 tpySO2 PTE = 0.01 tpyCO PTE = 0.04 tpy

CO2 PTE = 1,148 tpyCH4 PTE = 0.047 tpyN2O PTE = 0.009 tpy

CO2e PTE = 1,152 tpyH2SO4 PTE = 0.0004 tpy

EGEN1/2/3/4

PM10 = 96% of PM from AP-42, Table B.2-2, Category 1.

Source / Basis

= (Gen-Set Output MWe) x (1,341 bhp/MWm) / (Gen-Set Efficiency)Design basis of project= (Rated Horsepower, each engine) x (No. of Engines)= 2X Vendor's "Nominal Emissions" value.

= (Rated Horsepower, each engine) x (PM10 EF)

PM2.5 = 90% of PM from AP-42, Table B.2-2, Category 1.= (Proposed NOx+VOC LAER limit) - (NOx EF)= 2X Vendor's "Nominal Emissions" value.Based on: fuel sulfur = 15 ppmw; 7,000 Btu/hp-hr; oil HHV = 19,300 Btu/lb. = 2X Vendor's "Nominal Emissions" value.40 CFR 98, Table C-1 (Fuel Oil No. 2) @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.Sum of CO2, N2O, & CH4 adjusted for GWP.

Proposed permit limit.

= (Rated Horsepower, each engine) x (PM EF)

AP-42, Table 1.3-1; estimated at based on SO3-to-SO2 emissions ratio for distillate oil.

= (PM10 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (PM2.5 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

= (Rated Horsepower, each engine) x (PM2.5 EF)= (Rated Horsepower, each engine) x ( VOC EF)= (Rated Horsepower, each engine) x (NOx EF)= (Rated Horsepower, each engine) x ( SO2 EF)= (Rated Horsepower, each engine) x (CO EF)= (Rated Horsepower, each engine) x (CO2 EF)

= (Rated Horsepower, each engine) x (H2SO4 EF)

= (H2SO4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

= (N2O Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO2e Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

Design basis of projectStandard gen-set efficiency.

= (VOC Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (NOx Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (SO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CH4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

= (Rated Horsepower, each engine) x (CH4 EF)= (Rated Horsepower, each engine) x (N2O EF)= (Rated Horsepower, each engine) x (CO2e EF)

= (PM Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

Table B-9. Emergency Generator Emission Estimates

B-20

PollutantEF

(lb/MMBtu) Source §112 HAP?Emissions Rate (lb/hr)

Emissions Rate (T/yr)

Acetaldehyde 2.52E-05 AP42; Table 3.4-3; 10/96. YES 3.55E-03 1.77E-04Acrolein 7.88E-06 AP42; Table 3.4-3; 10/96. YES 1.11E-03 5.55E-05Benzene 7.76E-04 AP42; Table 3.4-3; 10/96. YES 1.09E-01 5.46E-03Formaldehyde 7.89E-05 AP42; Table 3.4-3; 10/96. YES 1.11E-02 5.55E-04Propylene 2.79E-03 AP42; Table 3.4-3; 10/96. NO 3.93E-01 1.96E-02Toluene 2.81E-04 AP42; Table 3.4-3; 10/96. YES 3.96E-02 1.98E-03Xylenes 1.93E-04 AP42; Table 3.4-3; 10/96. YES 2.72E-02 1.36E-03Naphthalene 1.30E-04 AP42; Table 3.4-4; 10/96. YES 1.83E-02 9.15E-04Acenaphthylene 9.23E-06 AP42; Table 3.4-4; 10/96. YES 1.30E-03 6.50E-05Acenaphthene 4.68E-06 AP42; Table 3.4-4; 10/96. YES 6.59E-04 3.29E-05Fluorene 1.28E-05 AP42; Table 3.4-4; 10/96. YES 1.80E-03 9.01E-05Phenanthrene 4.08E-05 AP42; Table 3.4-4; 10/96. YES 5.74E-03 2.87E-04Anthracene 1.23E-06 AP42; Table 3.4-4; 10/96. YES 1.73E-04 8.66E-06Fluoranthene 4.03E-06 AP42; Table 3.4-4; 10/96. YES 5.67E-04 2.84E-05Pyrene 3.71E-06 AP42; Table 3.4-4; 10/96. YES 5.22E-04 2.61E-05Benzo(a)anthracene 6.22E-07 AP42; Table 3.4-4; 10/96. YES 8.76E-05 4.38E-06Chrysene 1.53E-06 AP42; Table 3.4-4; 10/96. YES 2.15E-04 1.08E-05Benzo(b)fluoranthene 1.11E-06 AP42; Table 3.4-4; 10/96. YES 1.56E-04 7.81E-06Benzo(k)fluoranthene <2.18E-07 AP42; Table 3.4-4; 10/96. YES <3.07E-05 <1.53E-06Benzo(a)pyrene <2.57E-07 AP42; Table 3.4-4; 10/96. YES <3.62E-05 <1.81E-06Indeno(1,2,3-cd)pyrene <4.14E-07 AP42; Table 3.4-4; 10/96. YES <5.83E-05 <2.91E-06Dibenzo(a,h)anthracene <3.46E-07 AP42; Table 3.4-4; 10/96. YES <4.87E-05 <2.44E-06Benzo(g,h,l)perylene <5.56E-07 AP42; Table 3.4-4; 10/96. YES <7.83E-05 <3.91E-06Total PAH <1.68E-04 AP42; Table 3.4-4; 10/96. NO <2.36E-02 <1.18E-03

<2.22E-01 <1.11E-02Calcualtion Basis: Hourly Emissions = EF x Max Heat In x No. of Engines

Annual Emissions = Hourly x Hrs/yr / 2000.

Emergency Generator Diesel ICE HAP PTE - EGEN1/2/3/4(total for all engines)

Total § 112 HAP =

Table B-10. Emergency Generator HAP Emission Estimates

B-21

Emission Unit(s) ID = Fire Pump IC EnginesParameter Value Units

Calculation InputsRated Horsepower, each engine = 700 bhp

No. of Engines = 3Rated Horespower, Total = 2,100 bhp

PM EF = 3.31E-04 lb/bhp-hrPM10 EF = 3.17E-04 lb/bhp-hr

PM2.5 EF 2.98E-04 lb/bhp-hr VOC EF = 2.51E-03 lb/bhp-hrNOx EF = 4.10E-03 lb/bhp-hr SO2 EF = 1.09E-05 lb/bhp-hr

CO EF = 5.73E-03 lb/bhp-hrCO2 EF = 1.14E+00 lb/bhp-hrCH4 EF = 4.63E-05 lb/bhp-hrN2O EF = 9.26E-06 lb/bhp-hr

CO2e EF = 1.15E+00 lb/bhp-hrH2SO4 EF = 4.37E-07 lb/bhp-hr

Annual Operating Hours = 100 hrs/yr/engineHourly Emissions Calculations (each engine)

PM Hourly Max = 0.231 lb/hrPM10 Hourly Max = 0.222 lb/hr

PM2.5 Hourly Max = 0.208 lb/hrVOC Hourly Max = 1.760 lb/hrNOx Hourly Max = 2.870 lb/hrSO2 Hourly Max = 0.008 lb/hrCO Hourly Max = 4.012 lb/hr

CO2 Hourly Max = 799.0 lb/hrCH4 Hourly Max = 0.032 lb/hrN2O Hourly Max = 0.006 lb/hr

CO2e Hourly Max = 801.7 lb/hrH2SO4 Hourly Max = 0.001 lb/hr

Annual Emissions Calculations (all engines)PM PTE = 0.035 tpy

PM10 PTE = 0.033 tpyPM2.5 PTE = 0.031 tpy

VOC PTE = 0.264 tpyNOx PTE = 0.430 tpySO2 PTE = 0.001 tpyCO PTE = 0.602 tpy

CO2 PTE = 119.8 tpyCH4 PTE = 0.005 tpyN2O PTE = 0.001 tpy

CO2e PTE = 120.3 tpyH2SO4 PTE = 0.0001 tpy

Summary of Results

PM PM10 PM2.5 VOC NOx SO2 CO GHGm CO2e H2SO4Fire Pump ICE Emissions (3 units) = 0.03 0.03 0.03 0.264 0.430 0.001 0.602 120 120 0.000

= (CO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CH4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (N2O Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (CO2e Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)


= (H2SO4 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

= (CO Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

= (Rated Horsepower, each engine) x (CO EF)= (Rated Horsepower, each engine) x (CO2 EF)= (Rated Horsepower, each engine) x (CH4 EF)= (Rated Horsepower, each engine) x (N2O EF)= (Rated Horsepower, each engine) x (CO2e EF)

= (PM Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (PM10 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (PM2.5 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (VOC Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (NOx Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)= (SO2 Hourly Max) x (No. of Engines) x (Annual Operating Hours) / (2000 lb/ton)

= (Rated Horespower, Total) x (H2SO4 EF)

= (Rated Horsepower, each engine) x ( SO2 EF)

NSPS Subpart IIII; Table 4; 600 - 750 HP; 2009+.40 CFR 98, Table C-1 (Fuel Oil No. 2) @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.40 CFR 98, Table C-2 @ 7,000 Btu/bhp-hr.Sum of CO2, N2O, & CH4 adjusted for GWP.

Proposed permit limit.

= (Rated Horsepower, each engine) x (PM EF)= (Rated Horsepower, each engine) x (PM10 EF)= (Rated Horsepower, each engine) x (PM2.5 EF)= (Rated Horsepower, each engine) x ( VOC EF)= (Rated Horsepower, each engine) x (NOx EF)

AP-42, Table 1.3-1; estimated at based on SO3-to-SO2 emissions ratio for distillate oil.

FWP1/2/3

Based on: fuel sulfur = 15 ppmw; 7,000 Btu/hp-hr; oil HHV = 19,300 Btu/lb.

Source / Basis

C18 ACERT™ Fire PumpDesign basis of project= (Rated Horsepower, each engine) x (No. of Engines)NSPS Subpart IIII limit.PM10 = 96% of PM from AP-42, Table B.2-2, Category 1.PM2.5 = 90% of PM from AP-42, Table B.2-2, Category 1.AP-42; 10/96; Table 3.3-1NSPS Subpart IIII; Table 4; 600 - 750 HP; 2009+; assumes NOx = NMHC + NOx - VOC EF.

Table B-11. Fire Pump Emission Estimates

B-22

PollutantEF

(lb/MMBtu) Source §112 HAP?Emissions Rate (lb/hr)

Emissions Rate (T/yr)

Acetaldehyde 2.52E-05 AP42; Table 3.4-3; 10/96. YES 3.70E-04 1.85E-05Acrolein 7.88E-06 AP42; Table 3.4-3; 10/96. YES 1.16E-04 5.79E-06Benzene 7.76E-04 AP42; Table 3.4-3; 10/96. YES 1.14E-02 5.70E-04Formaldehyde 7.89E-05 AP42; Table 3.4-3; 10/96. YES 1.16E-03 5.80E-05Propylene 2.79E-03 AP42; Table 3.4-3; 10/96. NO 4.10E-02 2.05E-03Toluene 2.81E-04 AP42; Table 3.4-3; 10/96. YES 4.13E-03 2.07E-04Xylenes 1.93E-04 AP42; Table 3.4-3; 10/96. YES 2.84E-03 1.42E-04Naphthalene 1.30E-04 AP42; Table 3.4-4; 10/96. YES 1.91E-03 9.56E-05Acenaphthylene 9.23E-06 AP42; Table 3.4-4; 10/96. YES 1.36E-04 6.78E-06Acenaphthene 4.68E-06 AP42; Table 3.4-4; 10/96. YES 6.88E-05 3.44E-06Fluorene 1.28E-05 AP42; Table 3.4-4; 10/96. YES 1.88E-04 9.41E-06Phenanthrene 4.08E-05 AP42; Table 3.4-4; 10/96. YES 6.00E-04 3.00E-05Anthracene 1.23E-06 AP42; Table 3.4-4; 10/96. YES 1.81E-05 9.04E-07Fluoranthene 4.03E-06 AP42; Table 3.4-4; 10/96. YES 5.92E-05 2.96E-06Pyrene 3.71E-06 AP42; Table 3.4-4; 10/96. YES 5.45E-05 2.73E-06Benzo(a)anthracene 6.22E-07 AP42; Table 3.4-4; 10/96. YES 9.14E-06 4.57E-07Chrysene 1.53E-06 AP42; Table 3.4-4; 10/96. YES 2.25E-05 1.12E-06Benzo(b)fluoranthene 1.11E-06 AP42; Table 3.4-4; 10/96. YES 1.63E-05 8.16E-07Benzo(k)fluoranthene <2.18E-07 AP42; Table 3.4-4; 10/96. YES 3.20E-06 <1.60E-07Benzo(g,h,l)perylene <5.56E-07 AP42; Table 3.4-4; 10/96. YES 8.17E-06 <4.09E-07Total PAH <1.68E-04 AP42; Table 3.4-4; 10/96. NO 2.47E-03 <1.23E-04

<2.31E-02 <1.16E-03Calculation Basis: Hourly Emissions = EF x Max Heat In x No. of Engines

Annual Emissions = Hourly x Hrs/yr / 2000.

Fire Pump ICE HAP PTE - FWP1/2/3(total for all engines)

Total § 112 HAP =

Table B-12. Fire Pump HAP Emission Estimates

B-23

SOCMI Average Emissions Factor

VOC CH4 HAPLAER Control

EfficiencyComponent

Count

(lb/hr/src) (wt. %) (wt. %) (wt. %) % # VOC CH4 HAPGas/Vapor 0.0132 100.0 0.0 100.0 97 67 0.12 0.00 0.12Gas/Vapor 0.0132 100.0 0.0 50.0 97 34 0.06 0.00 0.03Gas/Vapor 0.0132 100.0 0.0 0.0 97 846 1.47 0.00 0.00Gas/Vapor 0.0132 98.2 1.8 0.0 97 179 0.30 0.01 0.00Gas/Vapor 0.0132 95.0 5.0 10.0 97 890 1.47 0.08 0.15Gas/Vapor 0.0132 92.4 7.6 0.0 97 315 0.50 0.04 0.00Gas/Vapor 0.0132 33.2 66.8 0.0 97 1111 0.64 1.29 0.00Light Liquid 0.0089 100.0 0.0 100.0 97 946 1.11 0.00 1.11Light Liquid 0.0089 100.0 0.0 50.0 97 226 0.26 0.00 0.13Light Liquid 0.0089 100.0 0.0 0.0 97 901 1.05 0.00 0.00Light Liquid 0.0089 98.7 1.3 0.0 97 94 0.11 0.00 0.00Light Liquid 0.0089 92.4 7.6 0.0 97 92 0.10 0.01 0.00Heavy liquid 0.0005 100.0 0.0 0.0 0 234 0.51 0.00 0.00Gas/Vapor 0.0039 100.0 0.0 100.0 97 180 0.09 0.00 0.09Gas/Vapor 0.0039 100.0 0.0 50.0 97 96 0.05 0.00 0.02Gas/Vapor 0.0039 100.0 0.0 0.0 97 2265 1.16 0.00 0.00Gas/Vapor 0.0039 98.2 1.8 0.0 97 480 0.24 0.00 0.00Gas/Vapor 0.0039 95.0 5.0 10.0 97 3288 1.60 0.08 0.17Gas/Vapor 0.0039 92.4 7.6 0.0 97 887 0.42 0.03 0.00Gas/Vapor 0.0039 33.2 66.8 0.0 97 3431 0.58 1.17 0.00Light Liquid 0.0005 100.0 0.0 100.0 97 2720 0.18 0.00 0.18Light Liquid 0.0005 100.0 0.0 50.0 97 715 0.05 0.00 0.02Light Liquid 0.0005 100.0 0.0 0.0 97 2596 0.17 0.00 0.00Light Liquid 0.0005 98.7 1.3 0.0 97 211 0.01 0.00 0.00Light Liquid 0.0005 92.4 7.6 0.0 97 252 0.02 0.00 0.00Heavy liquid 0.00007 100.0 0.0 0.0 30 710 0.15 0.00 0.00Gas/Vapor 0.2293 100.0 0.0 50.0 97 35 1.05 0.00 0.53Gas/Vapor 0.2293 33.2 66.8 0.0 97 35 0.35 0.70 0.00Light liquid 0.0439 100.0 0.0 50.0 93 26 0.35 0.00 0.17Light liquid 0.0439 92.4 7.6 0.0 93 4 0.05 0.00 0.00

Heavy liquid 0.0190 100.0 0.0 0.0 0 4 0.33 0.00 0.00Gas/Vapor 0.5027 100.0 0.0 50.0 95 14 1.54 0.00 0.77Gas/Vapor 0.5027 95.0 5.0 10.0 95 10 1.05 0.06 0.11Gas/Vapor 0.5027 33.2 66.8 0.0 95 8 0.29 0.59 0.00

Total Cracker Fugitive Emissions = 17.4 4.1 3.6Calculation Basis:

• Average Emission Factors from: Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), Table 2-1.• Component counts derived from preliminary design estimates for ethylene cracker unit equipment.• Emissions = (Component Count) x (EF - lb/hr/scr) x (1 - Control Efficiency) x (wt. % compound in stream)• LAER control efficiency based on TCEQ 28 LAER LDAR program control effectiveness.

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf• Pump and compressor counts doubled to account for 2 seals per unit.• 10 relief valves per furnace assumed.

EMISSIONS (tpy)

CRACKER FUGITIVE EMISSION COUNTS & VOC/CH4/HAP EMISSIONS

Pumps

Compressor Seals

Equipment Service

Valves

Connectors/Flanges

Relief Valves

Table B-13. Fugitive Emissions Estimate - Cracking Furnaces

B-24

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf

Equipment ServiceSOCMI Average

Emissions Factorlb/hr/src

LAER Control Efficiency %

Component CountVOC Emissions

(tpy)

Gas/Vapor 0.0132 97 1,414 2.45Light Liquid 0.0089 97 332 0.39

Relief Valves Gas/Vapor 0.2293 97 50 1.51Pumps Light Liquid 0.0439 93 32 0.43

Compressor Seals Gas/Vapor 0.5027 95 4 0.44Gas/Vapor 0.0089 97 2,348 2.75Light Liquid 0.0005 97 803 0.05

Subtotal of PE 1 & 2 VOC Emissions (total for 2 units) = 16.0

Gas/Vapor 0.0132 97 1,116 1.94Light Liquid 0.0089 97 957 1.12

Relief Valves Gas/Vapor 0.2293 97 50 1.51Pumps Light Liquid 0.0439 93 32 0.43

Compressor Seals Gas/Vapor 0.5027 95 4 0.44Agitators Light Liquid 0.0439 93 3 0.04

Gas/Vapor 0.0039 97 5,197 2.66Light Liquid 0.0005 97 2,090 0.14Heavy Liquid 0.00007 30 0 0.00

Subtotal of PE 3 VOC Emissions = 8.27Total VOC Emissions from PE Units 1 - 3 = 24.3Total HAP Emissions from PE Units 1 - 3 = 1.2

• Average Emission Factors from: Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), Table 2-1.• Component counts derived from preliminary design estimates for PE ISBL equipment.• PE 1 and 2 relief valve and pump counts assumed equal to PE3.• Emissions = (Component Count) x (EF - lb/hr/scr) x (1 - Control Efficiency)• LAER control efficiency based on TCEQ 28 LAER LDAR program control effectiveness.

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf• Agitator seal control efficiency assumed equal to pump seal LAER efficiency.

Valves

Connectors/Flanges

POLYETHYLENE UNITS 1 & 2(emissions and counts shown are for each unit)

POLYETHYLENE UNIT 3

Valves

Connectors/Flanges

Table B-14. Fugitive Emissions Estimate - Polyethylene Units

B-25


Equipment Service SOCMI Average Emissions Factor (lb/hr/src) Pollutant

LAER ControlEfficiency

(%)

Component Count

EMISSIONS(tpy)

Fuel/NG 0.0132 CH4 97 284 0.49Gas/Vapor 0.0132 VOC 97 355 0.62Light liquid 0.0089 VOC 97 618 0.72

Heavy liquid 0.0005 VOC 0 68 0.15Fuel/NG 0.2293 CH4 97 4 0.12

Gas/Vapor 0.2293 VOC 97 37 1.11Light liquid 0.0089 VOC 97 37 0.04

Heavy liquid 0.0089 VOC 97 5 0.01Fuel/NG 0.0037 CH4 97 185 0.09

Gas/Vapor 0.0037 VOC 97 147 0.07Light liquid 0.0037 VOC 97 90 0.04

Heavy liquid 0.0037 VOC 97 5 0.00Light liquid 0.0439 VOC 93 56 0.75

Heavy liquid 0.0190 VOC 0 6 0.50Compressor Seals Gas/Vapor 0.5027 VOC 95 6 0.66

Fuel/NG 0.0039 CH4 97 1419 0.73Gas/Vapor 0.0039 VOC 97 1617 0.83Light liquid 0.0005 VOC 97 2235 0.15

Heavy liquid 0.00007 VOC 30 234 0.05VOC Emissions = 5.7

CH4 Emissions 1.4HAP Emissions 0.6

Calculation Basis:• Average Emission Factors from: Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), Table 2-1.• Component counts derived from preliminary design estimates for OSBL equipment.• Emissions = (Component Count) x (EF - lb/hr/scr) x (1 - Control Efficiency)• LAER control efficiency based on TCEQ 28 LAER LDAR program control effectiveness:

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf• HAP content of streams assumed equal to 10% as conservative estimate.

Connectors/Flanges

OSBL FUGITIVE EMISSION COUNTS & VOC/CH4 EMISSIONS

Valves

Relief Valves

Open-ended Lines

Pumps

Table B-15. Fugitive Emissions Estimate - OSBL

B-26


Table B-‐16. Polyethylene Units 1 & 2 Process Vent Particulate Matter Emissions Estimates

Line 1/2 Vent Descriptions Emission Point IDs Vent TypePM/PM10/PM2.5

Emissions (T/yr/line)24-‐hr Avg PM/PM10 Rate (lb/hr/line) Basis / Discussion

Continuous 0.9439 0.2155Annual rate based on preliminary vendor data scaled to 8,760 hr/yr; 24-‐hour rates estimated based on 8,760 hr/yr of operation.

Intermittent 0.1397 0.0350Annual rate based on preliminary vendor data; 24-‐hour rates estimated based on 333 days per year of operation.

1.0836 0.2505 Total of above rates.2.1671 0.5009 2X above totals.

NOTES:• Assumed operating days for intermittant vents = 333 days/yr• 24-‐hr Rate for Intermittant Vents = (Annual Emissions -‐ T/yr) x (2,000 lb/T) / (333 days/yr * 24 hr/day)• 24-‐hr Rate for Continuous Vents = (Annual Emissions -‐ T/yr) x (2,000 lb/T) / (8,760 hr/yr)• Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.

PEU 1 & 2 Process Vent Particulate Emissions Estimates

Totals per Line =Totals Line 1 + Line 2 =

B-27

Line 3 Vent Descriptions EU IDsPM/PM10/PM2.5 Emissions (T/yr)

24-hr Avg PM/PM10 Rate

(lb/hr) Basis / Discussion

S2003A, S2003B 0.037 0.008Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.

S4005A/B, E4001 0.000 0.000 Vented to LP Flare. Emissions accounted for at flare.

C6005 0.062 0.014Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.

Q6002A, Q6002B, Q6002C, Q6002D 0.005 0.001

Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.

C60040.126 0.029

Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.

C6003 0.664 0.152Annual rate based on preliminary vendor data scaled to 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.

V6007 0.039 0.009Annual rate based on preliminary vendor data @ 8,760 hr/yr; 24-hour rates estimated based on 8,760 hr/yr of operation.

0.932 0.213 Total of above rates.NOTES:

• All vents are assumed to be continuous although many are intermittent.• 24-hr Rate = (Annual Emissions - T/yr) x (2,000 lb/T) / (8,760 hr/yr)• Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.

PE Unit 3 Process Vent Particulate Emissions Estimates

Totals =

Table B-17. Polyethylene Unit 3 Process Vent Particulate Matter Emissions Estimates

B-28

Parameter Units Blending Silo

Railcar Handling &

Storage

Truck Handling &

StorageDeDuster

VentsRailcar Loading

Truck Loading Source / Basis

Calculation Inputs: (rates for all three lines)

Annual Rate MT/yr 3,000,000 1,520,000 320,000 1,600,000 1,520,000 320,000 Based on 1.6 MM MT/yr production w/ 95% max via rail and 20% max by truck.

Max PE Pellet Rate MT/hr 410 240 160 400 200 130 Prelimiary design: 24-hr average max rates.

Normal PE Pellet Rate MT/hr 375 190 60 250 190 60 Prelimiary design: annual average rates.

Pellet-to-Air Ratio lb/lb 10 10 10 22 766 766 10:1 ratio for conveying; 22:1 for DeDuster; Loading air displacement based on 1 scf air per ft3 PE loaded.

PM Exit Grain Loading gr/dscf 0.010 0.010 0.010 0.010 0.010 0.010 LAER Limit.

PM10/2.5 Exit Grain Loading gr/dscf 0.0017 0.0017 0.0017 0.0001 0.010 0.010 Equivalent to proposed hourly emission limit at max rates.Annual Operating Hours hr/yr 8,000 8,000 5,333 8,000 8,000 5,333 Annual operating hours at normal rates. Hours may be higher if rates are lower.

Calculated Values:

Max Exhaust Rate scfh 1,208,429 707,373 471,582 535,889 7,697 5,003 = (Max PE Pellet Rate) x (2,204.6 lb/MT) / (Pellet-to-Air Ratio) / (28.84 lb/lb-mol) x (385.57 scf/lb-mol)

Normal Exhaust Rate scfh 1,105,271 560,004 176,843 334,930 7,312 2,309 = (Normal PE Pellet Rate) x (2,204.6 lb/MT) / (Pellet-to-Air Ratio) / (28.84 lb/lb-mol) x (385.57 scf/lb-mol)

24-hr PM10 Rate lb/hr 0.293 0.17 0.11 0.01 0.01 0.01 = (PM10/2.5 Exit Grain Loading) x (Max Exhaust Rate) / (7,000 gr/lb)

Annual Average PM10 Rate lb/hr 0.25 0.12 0.03 0.00 0.01 0.00 = (PM10/2.5 Exit Grain Loading) x (Normal Exhaust Rate) / (7,000 gr/lb) x (Annual Operating Hours ) / (8760 hr/yr)

Annual PM PTE T/yr 6.32 3.20 0.67 1.91 0.04 0.01 = (Normal Exhaust Rate) x (Annual Operating Hours ) x (PM Exit Grain Loading) / (7,000 gr/lb) / (2000 lb/T)Annual PM10/2.5 PTE T/yr 1.07 0.54 0.11 0.02 0.04 0.01 = (Normal Exhaust Rate) x (Annual Operating Hours ) x (PM10/2.5 Exit Grain Loading) / (7,000 gr/lb) / (2000 lb/T)

EU List:Blending Silos: PE1BLEND A/B/C/D/E; PE2BLEND A/B/C/D/E; V7001A; V7001B; V7001C; V7001D

Railcar Handling & Storage: PE1RAILSILO - A/B/C/D, PE2RAILSILO - A/B/C/D; PE3RAILSILO - A/B/C/DTruck Handling & Storage: PE1TRUCKSILO- A/B/C/D/E/F/G/H/I/J; PE2TRUCKSILO- A/B/C/D/E/F/G/H/I/J; PE3TRUCKSILO- A/B/C/D/E/F/G/H/I/J/K/L/M/N/O/P/Q/R

DeDuster Vents: PE1RAILDEDUSTA/B; PE2RAILDEDUSTA/B; PE1TRUCKDEDUST A/B/C/D/E; PE2TRUCKDEDUST A/B/C/D/E; PE3RAILDEDUSTA/B; PE3TRUCKDEDUST A/B/C/D/E/F/G/H/I

PE Pellet Transport, Storage, Blending and Loading Operations

Table B-18. PE Handling & Loadout PM PTE

B-29

Emission Unit(s) ID = VOC Emissions from Pellet Handling OperationsParameter Value Units Source / Basis

Calculation InputsPellets Produced = 1,931,247 T/yr Design basis of Franklin plant ratioed to 8,760 hrs/yr.

Residual VOC = 50 ppmw Proposed LAER limit.Fraction of VOC Emitted = 100% Worst-case assumption.

Annual Emissions CalculationsVOC PTE = 96.6 T/yr = (Pellets Produced - T/yr) x (Residual VOC - ppmw) x (Fraction of VOC Emitted) / (1,000,000 ppmw)

NOTES:• Refer to Tables D-2 and D-3 of Appendix D for Listing pf EUs covered by this estimate.• Residual VOC in PE pellets contain no OHAP.

See Note

Table B-19. Residual VOC Estimate

B-30

Tank Name EU ID Tank TypeVolume

[m3]Dianeter

[m]

Height / Length

[m]

Operating Temperature

[°C]

Surrogate Liquid

Annual Throughput

(gal/yr)Emission Control

Uncontrolled VOC/HAP

Emissions*(T/yr)

Control Efficiency

(%)

Controlled VOC /HAP Emissions*

(T/yr)Diesel Locomotive Fuel NA Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 412,000 Carbon Canister 2.7E-03 95% 1.3E-04Pyrolysis Tar Tank T-64201 Vertical Fixed Roof 130 4.6 8.0 150.0 No. 2 Oil 2,520,000 Carbon Canister 9.4E-03 95% 4.7E-04Emergency Generator Diesel Fuel T-58901A Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Emergency Generator Diesel Fuel T-58901B Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Emergency Generator Diesel Fuel T-58901C Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Emergency Generator Diesel Fuel T-58901D Horizonal Fixed Roof 38 2.4 8.2 38.0 No. 2 Oil 55,000 Carbon Canister 1.0E-03 95% 5.2E-05Spent Caustic Storage Tank T-53501 Internal Floating Roof 900 10.7 10.0 20.0 Jet Kerosene 26,151,000 See Note 1.0E-01 95% 5.0E-03Unoxidized Spent Caustic Storage Tank T-53502 Internal Floating Roof 8,630 26.2 16.0 20.0 Jet Kerosene 26,151,000 See Note 2.7E-01 95% 1.3E-02Fire Water Pump Diesel Fuel T-59101A Horizonal Fixed Roof 7 1.6 3.7 38.0 No. 2 Oil 7,200 Carbon Canister 1.8E-04 95% 8.8E-06Fire Water Pump Diesel Fuel T-59101B Horizonal Fixed Roof 7 1.6 3.7 38.0 No. 2 Oil 7,200 Carbon Canister 1.8E-04 95% 8.8E-06Fire Water Pump Diesel Fuel T-59101C Horizonal Fixed Roof 7 1.6 3.7 38.0 No. 2 Oil 7,200 Carbon Canister 1.8E-04 95% 8.8E-06* NOTES: Totals = 0.39 0.02

• This sheet summarizes emissions from those tanks not vented to a common control device.• The tanks listed in this sheet are vented to individual carbon canisters installed on each tank.• As a conservative assumption, 100% of VOC emissions from these tanks are assumed to be HAP.

Table B-20. Storage Tank Emissions

Tank vapors vented to Spent Caustic Vent Incinerator•

B-31


Pollutantmillion gal/day lb/million gal lb/hr hrs/year TPY lb/hr hrs/year TPY

VOC N/A N/A 0.097 8,760 0.42 0.097 8,760 0.42 Emissions model EPA WATER9

Benzene N/A N/A 0.097 8,760 0.42 0.097 8,760 0.42 Emissions model EPA WATER9

Phenol N/A N/A 9.4E-06 8,760 4.1E-05 9.4E-06 8,760 4.1E-05 Emissions model EPA WATER9

Basis:Emissions were modeled under worst-case conditions of dry weather flow.Example Calculations:0.42 ton VOC/yr = (0.097 lb/hr) x (8,760 hrs/year) / (2,000 lb/ton)

WWTP Equipment (W-1001) include:Biotreater Aeration Tank, two Secondary Clarifiers, Biosludge Holding Tank, Biosludge Dewatering Tank, Centrate Sump, Sand Filter, Sand Filter Backwash Receiver and Outfall. The Flow Equalization and Oil Removal Tanks (T-5307A/B) are vented to the Spent Caustic Vent Incinerator (A5401).

WWTP Equipment (W-1001) - Emissions SummaryPrecontrol Emissions Controlled Emissions

Calculation/Estimation

Method Emission Factor Reference

Table B-21. Wastewater Treatment Emissions Summary

B-32

Emission Unit(s) ID = Cogen Cooling TowerParameter Source / Basis

Calculation InputsNumber of Cells = 4 Design Specification (GM1-001-U5000-AA-7704-00001, Rev. 00)

Cell Circulation Rate = 11,000 gal/min/cell Design Specification (GM1-001-U5000-AA-7704-00001, Rev. 00)Annual Operating Hours = 8,760 hrs/yr Maximum potential use.

Drift Loss Factor = 0.00050% wt. % Design specification. Basis for proposed BACT limit.Cooling Water Rate = 44,000 gal/min = Cell Circulation Rate * Number of CellsCooling Water TDS = 2,400 ppmw Annual average BACT/LAER proposal.

Calculation ResultsPM10 Fraction of PM = 57.2% wt. % See particle size distribution calculation -->

PM2.5 Fraction of PM = 0.21% wt. % See particle size distribution calculation -->Hourly PM PTE [per cell] = 0.1 lb/hr = (Cell Circulation Rate) x (60 min/yr) x (8.34 lb/gal) x (Drift Loss Factor) x (Cooling Water TDS) / (1,000,000)

Annual PM PTE [total] = 1.2 tpy = (Hourly PM PTE [per cell]) x (Annual Operating Hours) / (2,000 lb/T) x (Number of Cells)Hourly PM10 PTE [per cell] = 0.0378 lb/hr = (PM10 Fraction of PM) x (Hourly PM PTE [per cell])

Annual PM10 PTE [total] = 0.7 tpy = (PM10 Fraction of PM) x (Annual PM PTE [total])Hourly PM2.5 PTE [per cell] = 0.00 lb/hr = (PM2.5 Fraction of PM) x (Hourly PM PTE [per cell])

Annual PM2.5 PTE [total] = 0.0 tpy = (PM2.5 Fraction of PM) x (Annual PM PTE [total])

CogenCWTValue

Table B-22. Cogen Cooling Tower Emission Estimates

B-33

=

10 524 5.24E-04 1.26E-06 1 1.03 0.00020 4189 4.19E-03 1.01E-05 5 2.06 0.19630 14137 1.41E-02 3.39E-05 15 3.09 0.226 0.240 33510 3.35E-02 8.04E-05 37 4.12 0.51450 65450 6.54E-02 1.57E-04 71 5.15 1.80660 113097 1.13E-01 2.71E-04 123 6.18 5.70270 179594 1.80E-01 4.31E-04 196 7.21 21.34890 381704 3.82E-01 9.16E-04 416 9.26 49.812

110 696910 6.97E-01 1.67E-03 760 11.32 70.509 57.2130 1150347 1.15E+00 2.76E-03 1255 13.38 82.023150 1767146 1.77E+00 4.24E-03 1928 15.44 88.012180 3053628 3.05E+00 7.33E-03 3331 18.53 91.032210 4849048 4.85E+00 1.16E-02 5290 21.62 92.468240 7238229 7.24E+00 1.74E-02 7896 24.71 94.091270 10305995 1.03E+01 2.47E-02 11243 27.79 94.689300 14137167 1.41E+01 3.39E-02 15422 30.88 96.288350 22449298 2.24E+01 5.39E-02 24490 36.03 97.011400 33510322 3.35E+01 8.04E-02 36557 41.18 98.340450 47712938 4.77E+01 1.15E-01 52050 46.32 99.071500 65449847 6.54E+01 1.57E-01 71400 51.47 99.071600 113097336 1.13E+02 2.71E-01 123379 61.77 100.000

1.00 g/cc2.20 g/cc

2,400 ppmw57.20 wt. %

PM2.5 fraction of PM = 0.21 wt. %From "Calculating Realistic PM10 Emissions from Cooling Towers"; Reisman & Frisbie (uses EPRI wet droplet size distribution).

Cooling Tower Design TDS =PM10 fraction of PM =

Specific Gravity of Dried Solids =Specific Gravity of Water =

Wet Droplet Diameter(μm)

Wet Droplet Volume(μm3)

Wet Droplet Mass(μg)

Dry Particle Mass(μg)

Cogen Cooling TowerCogenCWTEmission Unit(s) IDDry Particle

Volume(μm3)

Dry Particle Diameter

(um)

wt. % Mass Smaller Than

DropletWt% PM10 in

PM EmissionsWt% PM2.5 in

PM Emissions

Table B-22. Cogen Cooling Tower Emission Estimates (cont'd)

B-34

Emission Unit(s) ID = Process Cooling TowerParameter Source / Basis

Calculation InputsNumber of Cells = 26 Design Specification

Cell Circulation Rate = 10,000 gal/min/cell Design Specification (GM1-001-U5000-AA-7704-00001, Rev. 00)Annual Operating Hours = 8,760 hrs/yr Maximum potential use.

Drift Loss Factor = 0.00050% wt. % Design specification. Basis for proposed BACT limit.Cooling Water Rate = 260,000 gal/min = Cell Circulation Rate * Number of CellsCooling Water TDS = 2,400 ppmw Annual average BACT/LAER proposal.

VOC Emissions Limit = 0.50 lb/MMgal Proposed LAER limit.OHAP Fraction of VOC = 10% wt. % ROM estimate; few HAP-containing streams in process.

Calcualtion Results Hourly VOC PTE [per cell] = 0.30 lb/hr = (Cell Circulation Rate - gpm) x (60 min/hr) x (VOC Emissions Limit - lb/MMGal) / (1,000,000)

Annual VOC PTE [total] = 34.2 T/yr = ( Hourly VOC PTE [per cell]) x (Annual Operating Hours) / (2,000 lb/T) x (Number of Cells) Annual HAP PTE [total] = 3.4 T/yr = (OHAP Fraction of VOC) x ( Annual VOC PTE [total])

PM10 Fraction of PM = 57.2% wt. % See particle size distribution calculation -->PM2.5 Fraction of PM = 0.21% wt. % See particle size distribution calculation -->

Hourly PM PTE [per cell] = 0.1 lb/hr = (Cell Circulation Rate) x (60 min/yr) x (8.34 lb/gal) x (Drift Loss Factor) x (Cooling Water TDS) / (1,000,000)Annual PM PTE [total] = 6.8 tpy = (Hourly PM PTE [per cell]) x (Annual Operating Hours) / (2,000 lb/T) x (Number of Cells)

Hourly PM10 PTE [per cell] = 0.034 lb/hr = (PM10 Fraction of PM) x (Hourly PM PTE [per cell])Annual PM10 PTE [total] = 3.9 tpy = (PM10 Fraction of PM) x (Annual PM PTE [total])

Hourly PM2.5 PTE [per cell] = 0.00 lb/hr = (PM2.5 Fraction of PM) x (Hourly PM PTE [per cell])Annual PM2.5 PTE [total] = 0.0143 tpy = (PM2.5 Fraction of PM) x (Annual PM PTE [total])

PCTValue

Table B-23. Process Cooling Tower Emission Estimates

B-35

=

10 524 5.24E-04 1.26E-06 1 1.03 0.00020 4189 4.19E-03 1.01E-05 5 2.06 0.19630 14137 1.41E-02 3.39E-05 15 3.09 0.226 0.240 33510 3.35E-02 8.04E-05 37 4.12 0.51450 65450 6.54E-02 1.57E-04 71 5.15 1.80660 113097 1.13E-01 2.71E-04 123 6.18 5.70270 179594 1.80E-01 4.31E-04 196 7.21 21.34890 381704 3.82E-01 9.16E-04 416 9.26 49.812

110 696910 6.97E-01 1.67E-03 760 11.32 70.509 57.2130 1150347 1.15E+00 2.76E-03 1255 13.38 82.023150 1767146 1.77E+00 4.24E-03 1928 15.44 88.012180 3053628 3.05E+00 7.33E-03 3331 18.53 91.032210 4849048 4.85E+00 1.16E-02 5290 21.62 92.468240 7238229 7.24E+00 1.74E-02 7896 24.71 94.091270 10305995 1.03E+01 2.47E-02 11243 27.79 94.689300 14137167 1.41E+01 3.39E-02 15422 30.88 96.288350 22449298 2.24E+01 5.39E-02 24490 36.03 97.011400 33510322 3.35E+01 8.04E-02 36557 41.18 98.340450 47712938 4.77E+01 1.15E-01 52050 46.32 99.071500 65449847 6.54E+01 1.57E-01 71400 51.47 99.071600 113097336 1.13E+02 2.71E-01 123379 61.77 100.000

1.00 g/cc2.20 g/cc

2,400 ppmw57.20 wt. %

PM2.5 fraction of PM = 0.21 wt. %From "Calculating Realistic PM10 Emissions from Cooling Towers"; Reisman & Frisbie (uses EPRI wet droplet size distribution).

Specific Gravity of Water =Specific Gravity of Dried Solids =

Cooling Tower Design TDS =PM10 fraction of PM =

Wet Droplet Diameter(μm)

Wet Droplet Volume(μm3)

Wet Droplet Mass(μg)

Dry Particle Mass(μg)

Emission Unit(s) ID PCT Process Cooling TowerDry Particle

Volume(μm3)

Dry Particle Diameter

(um)

wt. % Mass Smaller Than

DropletWt% PM10 in

PM EmissionsWt% PM2.5 in

PM Emissions

Table B-23. Process Cooling Tower Emission Estimates (cont'd)

B-36

ParameterPyrolysis Tar

Loading Slop Oil LoadingSpend Caustic

Loading Units Source / BasisT-64201 T-59708 T-53501,T-53502

Material Loaded Pyrolysis Tar Slop Oil Spent Caustic

Surrogate Material No. 6 Residual Oil Jet Kerosene Jet Kerosene Selected as conservatively volatile species representing actual materials.

Material Temperature 180 30 30 °C Pyrolysis tar is heated; Slop Oil is ≈ maximum daily avg temperature in July

Material Temperature 816 546 546 °R = (Material Temperature - °C) x (1.8) + (32) + (460)

VOC Vapor Pressure 0.5000 0.5000 0.5000 psia Proposed LAER/BACT Vapor Pressure Limit.

VOC Vapor MW 190 130 130 lb/lb-mole TANKS 4.09D value for surrogate material.

Type of Loadout Operation RAIL & TRUCK RAIL & TRUCK RAIL & TRUCK

Type of Loading System SUBMERGED SUBMERGED SUBMERGED Proposed design/work practice.

Annual Loading Rate 2,520 210 504 103gal/yr Loading rates are from preliminary facility design basis.

Saturation Factor 0.60 0.60 0.60 S from AP-42 equation (see below)VOC Loading Loss Factor 1.110 0.992 0.992 lbs/103gal LL from AP-42 equation (see below) using LAER limit Vp.

Control Efficiency 0% 0% 0% wt. % No controls applied due to low Vp

Annual VOC Emissions 1.40 0.10 0.25 T/yr = (Annual Loading Rate) x (VOC Loading Loss Factor) x (1 - Control Efficiency) / (2000 lb/T)

VOC Vapor Pressure 3.45 3.45 3.45 kPa = (6.895 kPa/psi ) x (VOC Vapor Pressure)

Estimated HAP Fraction 100% 100% 100% wt. % Worst-case estimate.

Annual HAP Emissions 1.40 0.10 0.25 T/yr = (Annual VOC Emissions) x (Estimated HAP Fraction)

Emissions Estimates based on Equation 1 in AP-42, Chapter 5, Section 2 (Jan-1995 version):

Table B-24. Low Organic Vapor Pressure Liquid Loadout Operations Emission Estimates

B-37

Emission Unit(s) ID = C3+ Loading EmissionsParameter Value Units Source / Basis

Calculation InputsC3+ Produced = 212,000 m3/yr Design basis of plant.

Volume of 1 Railcar = 115 m3 Standard railcar volumeAnnual Railcars Filled = 1,843 #/yr = (C3+ Produced) / (Volume of 1 Railcar)

VOC EF -g/fill = 6,044 g/fill SCAQMD Controlled Emission Factor for LPG vehicle loading.VOC EF - lb/fill = 13.3 lb/fill = (VOC EF -g/fill) / (453.6 g/lb)

Annual Emissions CalculationsVOC PTE = 12.3 tpy = (VOC EF - lb/fill) x (Annual Railcars Filled - #/yr) / (2,000 lb/ton)

NOTES:• EF source: Final Staff Report Proposed Rule 1177 – Liquefied Petroleum Gas Transfer and Dispensing (June 2012).

C3LOAD

Table B-25. C3+ Loading Emission Estimates

B-38

Emission Unit(s) ID = Spent Caustic Vent IncineratorParameter

Calcuation InputsDesign Heat Input [HHV] = 10.7 MMBtu/hr

Heat Input from VOC [HHV] = 0.7 MMBtu/hrDesign DRE = 99% wt. %

PM EF = 0.0019 lb/MMBtuPM10 EF = 0.0075 lb/MMBtu

PM2.5 EF = 0.0075 lb/MMBtuVOC EF = 0.0302 lb/MMBtuNOx EF = 0.0680 lb/MMBtuSO2 EF = 0.0879 lb/MMBtuCO EF = 0.3700 lb/MMBtu

CO2 EF = 124.8 lb/MMBtuN2O EF = 2.2E-04 lb/MMBtuCH4 EF = 2.2E-03 lb/MMBtu

H2SO4 EF = 3.5E-03 lb/MMBtuHAP EF = 0.0302 lb/MMBtu

Annual Hours = 8,760 hr/yrAnnual Emissions Calculations

PM Emissions = 0.09 T/yrPM10 Emissions = 0.35 T/yr

PM2.5 Emissions = 0.35 T/yrVOC Emissions = 1.42 T/yrNOx Emissions = 3.2 T/yrSO2 Emissions = 4.13 T/yrCO Emissions = 17.4 T/yr

CO2 Emissions = 5,864 T/yrN2O Emissions = 0.01 T/yrCH4 Emissions = 0.10 T/yr

H2SO4 Emissions = 0.17 T/yrHAP Emissions = 1.42 T/yr

CO2e Emissions = 5,870 T/yrShort-Term Emissions Calculations

PM Emissions = 0.02 lb/hrPM10 Emissions = 0.08 lb/hr

PM2.5 Emissions = 0.08 lb/hrVOC Emissions = 0.32 lb/hrNOx Emissions = 0.73 lb/hrSO2 Emissions = 0.94 lb/hrCO Emissions = 3.97 lb/hr

CO2e Emissions = 1,339 lb/hrN2O Emissions = 0.00 lb/hrCH4 Emissions = 0.02 lb/hr

H2SO4 Emissions = 0.04 lb/hrHAP Emissions = 0.32 lb/hr

CO2e Emissions = 1,340 lb/hrSummary of Results

PM PM10 PM2.5 VOC/HAP NOx SO2 CO GHGm CO2e H2SO4Caustic TO PTE = 0.09 0.35 0.35 1.42 3.19 4.13 17.38 5,864 5,870 0.17

= (Design Heat Input [HHV]) x (CO EF) x (Annual Hours) / (2000 lb/T)

= (Design Heat Input [HHV]) x (N2O EF) x (Annual Hours) / (2000 lb/T)

Assumed full-time operation.

= (Design Heat Input [HHV]) x (PM EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (PM10 EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (PM2.5 EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (VOC EF) x (Annual Hours) / (2000 lb/T)

= (Design Heat Input [HHV]) x (SO2 EF) x (Annual Hours) / (2000 lb/T)

Value

= (Design Heat Input [HHV]) x (PM10 EF)

= (Design Heat Input [HHV]) x (VOC EF)

A5401

= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs.

= (Design Heat Input [HHV]) x (PM2.5 EF)

= (Design Heat Input [HHV]) x (CH4 EF) x (Annual Hours) / (2000 lb/T)

= (Design Heat Input [HHV]) x (CO2 EF) x (Annual Hours) / (2000 lb/T)

Based on 0.05 g/Nm3 H2S in offgas to oxidizer. AP-42, Table 13.5-1, 9/91.

= (Design Heat Input [HHV]) x (NOx EF) x (Annual Hours) / (2000 lb/T)

40 CFR 98, Table C-2 (as of July-2013); EF for natural gas.40 CFR 98, Table C-2 (as of July-2013); EF for natural gas.AP-42, Table 1.3-1; estimated at based on SO3-to-SO2 emissions ratio for distillate oil.Controlled EF; conservatively assumes HAP is 100% of VOC.

40 CFR 98, Table C-1 (as of July-2013); EF for natural gas + 8.4 g/Nm3 CO2 in influent gas.


= (Design Heat Input [HHV]) x (N2O EF)= (Design Heat Input [HHV]) x (CH4 EF)

= sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 .

= (Design Heat Input [HHV]) x (H2SO4 EF)= (Design Heat Input [HHV]) x (HAP EF)

= (Design Heat Input [HHV]) x (CO2 EF)

= (Design Heat Input [HHV]) x (H2SO4 EF) x (Annual Hours) / (2000 lb/T)= (Design Heat Input [HHV]) x (HAP EF) x (Annual Hours) / (2000 lb/T)

= (Design Heat Input [HHV]) x (PM EF)

= (Design Heat Input [HHV]) x (CO EF)

= (Design Heat Input [HHV]) x (NOx EF)= (Design Heat Input [HHV]) x (SO2 EF)

Controlled EF: based on 3.2 g/Nm3 VOC in offgas to oxidizer and 99% DRE. AP-42, Table 13.5-1, 9/91.

Source / Basis

Preliminary design basis based on treated gas flow and composition (VOC + NG)

AP-42, Table 1.4-2, 7/98.AP-42, Table 1.4-2, 7/98.AP-42, Table 1.4-2, 7/98.

Preliminary design basis based on treated gas flow and composition (VOC only)Preliminary design basis based on treated gas flow and composition.

Table B-26. Spent Caustic Vent Thermal Incinerator Emissions Estimates

B-39

MMBtu/hr VOC to Flare VOC DRE NOx SO2 PM2.5 VOC CO2 CH4 N2O CO2e CO PM PM10 H2SO4 HAP PbHP Ground Flares / Short-Term Max 2,687 31 MT/hr 0.068 0.37 0.0075HP Ground Flares / Annual Average 82 0.98 MT/hr 98.0% DRE 0.068 0.0015 0.0075 0.3146 131.4 0.0066 0.0013 132.0 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07HP Elevated Flare / Normal Ops 51.7 NG only 0.068 0.0015 0.0075 0.0054 117.0 0.0022 0.0002 117.1 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07LP Ground Flare / Normal Ops 1.0 NG only 0.068 0.0015 0.0075 0.0054 117.0 0.0022 0.0002 117.1 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07Refrigerated Tank Flare / Short-Term Max 72 0 MT/hr 0.068 0.37 0.0075Refrigerated Tank Flare / Annual Avg. 2.3 0 MT/hr 98.0% DRE 0.068 0.0015 0.0075 0.0000 131.4 0.0066 0.0013 132.0 0.37 0.0019 0.0075 0.00006 0.00185 4.9E-07

MMBtu/hr NOTES NOx CO PM10HP Ground Flares / Short-Term Max 2,687 [A] 36.5 994 20.0HP Ground Flares / Annual Average 82 [B] 5.6 0.61HP Elevated Flare / Normal Ops 51.7 [C] 3.5 19.1 0.39LP Ground Flare / Normal Ops 1.0 [D] 0.1 0.4 0.01Refrigerated Tank Flare / Short-Term Max 72 [E] 1.0 26.7 0.54Refrigerated Tank Flare / Annual Avg. 2.3 [F] 0.2 0.02

Hours/yr MMBtu/yr NOx SO2 PM2.5 VOC CO2 CH4 N2O CO2e CO PM PM10 H2SO4 HAP PbHP Ground Flares / Annual Average 8,760 720,146 24.5 0.53 2.68 113.3 47,312 2.38 0.48 47,513 133.2 0.67 2.68 0.02 0.67 1.8E-04HP Elevated Flare / Normal Ops 8,760 452,947 15.40 0.33 1.69 1.22 26,492 0.50 0.05 26,520 83.80 0.42 1.69 0.01 0.42 1.1E-04LP Ground Flare / Normal Ops 8,760 8,760 0.30 0.01 0.03 0.02 512 0.01 0.00 513 1.62 0.01 0.03 0.00 0.01 2.1E-06Refrigerated Tank Flare / Annual Avg. 8,760 19,871 0.68 0.01 0.07 0.00 1,305 0.07 0.01 1,311 3.68 0.02 0.07 0.00 0.02 4.9E-06

BasisFLARE EMISSIONS CALCULATIONS

VOC to Flare

FLARE / FLARING MODE

FLARE / FLARING MODE

NSR POLLUTANT EMISSION FACTORS (lb/MMBtu)

NSR POLLUTANT RATES USED IN AMBIENT IMPACT MODELING (lb/hr)

NSR POLLUTANT PTE (T/yr)

Basis

Basis

Table B-27. VOC Control System Flares Emissions Estimates

B-40

FLARE EMISSIONS CALCULATIONS NOTES:General:

• VOC mass flaring rates are based on preliminary vendor data associated with various potential scenarios (e.g., a cold-startup).• Short-term VOC mass flaring rates represent maximum expected short-term rates excluding emergency flaring.• Annual average VOC mass flaring rates represent annual average anticipated flaring rates excluding emergency flaring.• Where applicable, flare destruction efficiencies represent LAER or beyond-LAER control levels.

Calculation Methodology:• Hourly Emissions = (Heat Input - MMBtu/hr) x (Emissions Factor - lb/MMBtu)• Annual Emissions = (Heat Input - MMBtu/hr) x (Annual Hours) x (Emissions Factor - lb/MMBtu) x (1 ton/2,000 lb)

Basis for Emissions Factors:• NOx/NO2 and CO = AP-42, Table 13.5-1.• SO2 = Natural gas SO2 emissions factor (see "Constants" sheet); Factor applied to pilot flame only; Flared process gases do not contain sulfur.• PM10/2.5 = Natural gas external combustion emissions factor (see "Constants" sheet); Somkeless flares have zero filterable PM (see AP-43, Table 13.5-1).• VOC from HP Ground Flares: based on 98.00% DRE of incoming VOC; VOC content of flared gases = 60.1 wt.%.• VOC from Refrigerated Tank Flares: flared gases contain no VOC.• VOC emissions factor for emergency-only flares pilot fuel = AP-42, Table 1.4-2.• CO2 from pilot fuel is based on natural gas firing = weighted U.S. average NG CO2 emissions factor from 40 CFR 98, Table C-1.• CO2 from VOC flaring is assumed to result from ethane flaring = ethane CO2 emissions factor from 40 CFR 98, Table C-1.• CH4 and N2O from pilot fuel is based on natural gas firing = NG emissions factors from 40 CFR 98, Table C-1.• CH4 and N2O from VOC flaring is assumed to result from fuel gas flaring = fuel gas emissions factors from 40 CFR 98, Table C-2.• CO2e = sum of CO2, CH4 and N2O emissions adjusted for global warming potentials; see "Constants" table for details.• PM = AP-42, Table 1.4-2; Natural gas filterable emissions factor used as conservative estimate since flares are smokeless.• H2SO4 = AP-42, Table 1.3-1; estimated based on SO3-to-SO2 emissions ratio for distillate oil.• Little HAP-containing gas will be flared; HAP emissions estimated based on the total of all AP-42 HAP emissions factors for external combustion of natural gas.

[A] - HP Ground Flares Short-Term Maximum Emissions Rates: • Short-term max heat input based on flaring 52 MT/hr which is maximum anticipated rate from various SU/SD modes.• Heat input also includes 1.0 MMBtu/hr of pilot gas at all times.• The 1-hr maximum NOx rate used for short-term NO2 modeling is divided by 5 because SU/SD events expected to occur less than once every five years.

[B] - HP Ground Flares Annual Average Emissions Rates: • Annual average heat input based on assuming 1 startup and 1 shutdown occur in a year.• Annual average heat input also includes flaring events associated with reasonably anticipated maintenance events at a rate of 1 of each event/year/furnace.• Annual average heat input also includes 1.0 MMBtu/hr of pilot gas at all times.

[C] - HP Elevated Flare Annual Average Emissions Rates:• Heat input based on 1.0 MMBtu/hr of pilot gas plus 1.0 MT/hr of natural gas as sweep gas.

[D] - LP Ground Flare Annual Average Emissions Rates:• Heat input based on 1.0 MMBtu/hr of pilot gas.• All other flaring is emergency-use only.

[E] - Refrigerated Tank Flare Short-Term Maximum Emissions Rates:• Short-term max heat input based on flaring 1.4 MT/hr of ethane which is maximum anticipated rate from various SU/SD modes.• Heat input also includes 1.0 MMBtu/hr of pilot gas at all times.• The 1-hr maximum NOx rate is divided by 5 because SU/SD events expected to occur at most once every five years.

[F] - Refrigerated Tank Flare Annual Average Emissions Rates:• Annual average heat input based on assuming 1 startup and 1 shutdown occur in a year with anticipated flaring of 225 MT of ethane/event in this flare.• Annual average heat input also includes 1.0 MMBtu/hr of pilot gas at all times.

Table B-27a. VOC Control System Flares Emissions Estimates Notes

B-41

Emission Unit(s) ID = LP Thermal IncineratorParameter

Calcuation InputsPotential Heat Input [HHV] = 103 MMBtu/hr

Design DRE = 99.5% wt. %PM EF = 0.0075 lb/MMBtu

PM10 EF = 0.0075 lb/MMBtuPM2.5 EF = 0.0075 lb/MMBtu

VOC EF = 0.2280 lb/MMBtuNOx EF = 0.0680 lb/MMBtuSO2 EF = 0 lb/MMBtuCO EF = 0.0824 lb/MMBtu

CO2 EF = 145.4 lb/MMBtuN2O EF = 1.3E-03 lb/MMBtuCH4 EF = 6.6E-03 lb/MMBtu

H2SO4 EF = 0 lb/MMBtuHAP EF = 1.9E-03 lb/MMBtu

Annual Hours = 8,760 hr/yrAnnual Emissions Calculations

PM Emissions = 3.37 T/yrPM10 Emissions = 3.37 T/yr

PM2.5 Emissions = 3.37 T/yrVOC Emissions = 103.08 T/yrNOx Emissions = 30.7 T/yrSO2 Emissions = 0.00 T/yrCO Emissions = 37.2 T/yr

CO2 Emissions = 65,728 T/yrN2O Emissions = 0.60 T/yrCH4 Emissions = 2.99 T/yr

H2SO4 Emissions = 0.00 T/yrHAP Emissions = 0.84 T/yr

CO2e Emissions = 65,981 T/yrShort-Term Emissions Calculations

PM Emissions = 0.77 lb/hrPM10 Emissions = 0.77 lb/hr

PM2.5 Emissions = 0.77 lb/hrVOC Emissions = 23.53 lb/hrNOx Emissions = 7.02 lb/hrSO2 Emissions = 0.00 lb/hrCO Emissions = 8.50 lb/hr

CO2e Emissions = 15,006 lb/hrN2O Emissions = 0.14 lb/hrCH4 Emissions = 0.68 lb/hr

H2SO4 Emissions = 0.00 lb/hrHAP Emissions = 0.19 lb/hr

CO2e Emissions = 15,064 lb/hrSummary of Results

PM PM10 PM2.5 VOC NOx SO2 CO GHGm CO2e H2SO4 HAPLP TI PTE = 3.37 3.37 3.37 103.08 30.74 0.00 37.22 65,732 65,981 0.00 0.84


= (Potential Heat Input [HHV]) x (VOC EF)= (Potential Heat Input [HHV]) x (NOx EF)= (Potential Heat Input [HHV]) x (SO2 EF)= (Potential Heat Input [HHV]) x (CO EF)= (Potential Heat Input [HHV]) x (CO2 EF)= (Potential Heat Input [HHV]) x (N2O EF)= (Potential Heat Input [HHV]) x (CH4 EF)= (Potential Heat Input [HHV]) x (H2SO4 EF)= (Potential Heat Input [HHV]) x (HAP EF)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.

= (Potential Heat Input [HHV]) x (PM2.5 EF)

= (Potential Heat Input [HHV]) x (SO2 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (CO EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (CO2 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (N2O EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (CH4 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (H2SO4 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (HAP EF) x (Annual Hours) / (2000 lb/T)= Sum of CO2, N2O and CH4 emissions adjusted for NO2 and CH4 GWPs of 298 and 25.

= (Potential Heat Input [HHV]) x (PM EF)= (Potential Heat Input [HHV]) x (PM10 EF)

= (Potential Heat Input [HHV]) x (NOx EF) x (Annual Hours) / (2000 lb/T)

40 CFR 98, Table C-1 (as of July-2013); EF for ethylene.40 CFR 98, Table C-2 (as of July-2013); EF for fuel gas.40 CFR 98, Table C-2 (as of July-2013); EF for fuel gas.No sulfur in PE vents.Based on the total of all AP-42 HAP emissions factors for external combustion of natural gas.Assumed full-time operation at max rate as worst-case.

= (Potential Heat Input [HHV]) x (PM EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (PM10 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (PM2.5 EF) x (Annual Hours) / (2000 lb/T)= (Potential Heat Input [HHV]) x (VOC EF) x (Annual Hours) / (2000 lb/T)

AP-42, Table 1.4-1, 7/98.

LPINCINERATORValue Source / Basis

Preliminary design basis.Preliminary design basis.AP-42, Table 1.4-2, 7/98 & proposed BACT limit.AP-42, Table 1.4-2, 7/98 & proposed BACT limit.AP-42, Table 1.4-2, 7/98 & proposed LAER limit.Preliminary design basis of 2.4 T/hr VOC to TI and a DRE of 99.50%.Preliminary design basis.No sulfur in PE vents.

Table B-28. VOC Control System Low Pressure Thermal Incinerator Emissions Estimates

B-42

Parameter Reference & Calculation Basis

k for PM 0.011 lb/VMT AP-42, Table 13.2.1-1k for PM10 0.0022 lb/VMT AP-42, Table 13.2.1-1

k for PM2.5 0.00054 lb/VMT AP-42, Table 13.2.1-1sL 0.20 g/m2 Estimated value based on application of LAER controls.W 25 tons average weight (tons) of the vehicles traveling the road.P 150 days Number of days with rain fall greater than 0.01 inchN 365 days Number of days in the averaging period.

EF for PM 0.059 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))EF for PM10 0.0119 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))

EF for PM2.5 0.00292 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))Vehicles per day 22 vehicles/day Design estimate.

Hours per day of vehicle traffic 24 hr/day Annual average value.Road Length 0.97 miles Round trip distance from current plot plan.

VMT hourly = 0.9 VMT/hr = (Vehicles per day) / (Hours per day of vehicle traffic) x (Road Length)PM Emissions [hourly] 0.053 lb/hr = (VMT hourly =) x (EF for PM)

PM10 Emissions [hourly] 0.011 lb/hr = (VMT hourly =) x (EF for PM10)PM2.5 Emissions [hourly] 0.003 lb/hr = (VMT hourly =) x (EF for PM2.5)

PM Emissions [annual] 0.231 tpy = (PM Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)PM10 Emissions [annual] 0.046 tpy = (PM10 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)

PM2.5 Emissions [annual] 0.011 tpy = (PM2.5 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)

TRANSPORT TRUCK ROAD PARTICULATE MATTER EMISSIONS(Annual Rate)

ValueCalculation based based on paved Road Equation from AP-42 section 13.2.1 for hourly emissions

Table B-29. Transport Truck Road PM Emissions Estimates

B-43

Parameter Reference & Calculation Basis

k for PM 0.011 lb/VMT AP-42, Table 13.2.1-1k for PM10 0.0022 lb/VMT AP-42, Table 13.2.1-1

k for PM2.5 0.00054 lb/VMT AP-42, Table 13.2.1-1sL 0.20 g/m2 Estimated value based on application of LAER controls.W 25 tons average weight (tons) of the vehicles traveling the road.P 0 hours Number of hours with rain fall greater than 0.01 inch.N 24 hours Number of hours in the averaging period.

EF for PM 0.068 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))EF for PM10 0.0136 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))

EF for PM2.5 0.00333 lb/VMT EF = k (sL)0.91 (W)1.02 (1 –1.2 P/(4*N))Vehicles per day 22 vehicles/day Design estimate.

Hours per day of vehicle traffic 8 hrs/day Assumes 8 hours per day of traffic as worst-case for short-term rate.Road Length 0.97 miles Round trip distance from current plot plan.

VMT hourly = 2.7 VMT/hr = (Vehicles per day) / (Hours per day of vehicle traffic) x (Road Length)PM Emissions [hourly] 0.180 lb/hr = (VMT hourly =) x (EF for PM)

PM10 Emissions [hourly] 0.036 lb/hr = (VMT hourly =) x (EF for PM10)PM2.5 Emissions [hourly] 0.009 lb/hr = (VMT hourly =) x (EF for PM2.5)

PM Emissions [annual] 0.789 tpy = (PM Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)PM10 Emissions [annual] 0.158 tpy = (PM10 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)

PM2.5 Emissions [annual] 0.039 tpy = (PM2.5 Emissions [hourly]) x (8,760 hr/yr) / (2,000 lb/T)

TRANSPORT TRUCK ROAD PARTICULATE MATTER EMISSIONS(Hourly Rate)

ValueCalculation based based on paved Road Equation from AP-42 section 13.2.1 for hourly emissions

Table B-29. Transport Truck Road PM Emissions Estimates (cont'd)

B-44

Parameter Discussion / BasisCO2 Capture & Concentration - Capital Costs

CO2 flow from Furnaces and Cogen Units = 5,774 T/d Based on 365 d/yr operation (assumes no APHT installed on heaters)Assumed CO2 Capture Efficiency = 90% wt. % Assumed overall efficiency of capture and concentration system.

Base Cost CO2 flow to CCS = 5,353 T/d Case 14 NETL Report , p. 478.Base CO2 Concentration = 4.04% Case 14 NETL Report , p. 478.

Influent Gas CO2 Concentration = 3.54% Estimate.June 2011 CPI = 676.162 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0Feb 2014 CPI = 703.300 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0

Base Cost CO2 Removal System TCI = 259,459,000 $2011 Case 14 NETL Report Update , p. 44 (June 2011 costs).Base Cost CO2 Removal System TCI = 269,872,478 $2014 Adjusted using CPI ratios.

Size Adjustment Exponent (SAE) = 0.60 Peters & Timmerhaus , p 166.CO2 Scrubber & Regen TCI = 305,503,045 $2014 Based on NETL Report Update costs, Case 14 using ratio of CO2 flow/concentration and SAE.

Capital to Duct 7 Furnaces and 3 Cogen Units to 1 CCS System = 10,000,000 $2014 ROM estimate @ $1.0 MM/unit.CO2 Capture System TCI 315,503,045 $2014 Scrubber/regen system cost.

CO2 Compression - Capital CostsBase Cost CO2 Compression & Drying TCI = 35,960,000 $2011 Case 14 NETL Report Update , p. 44 (June 2011 costs).Base Cost CO2 Compression & Drying TCI = 37,403,267 $2014 Adjusted using CPI ratios.

Size Adjustment Exponent = 0.60 Peters & Timmerhaus , p 166.Estimated Compression System TCI = 39,142,327 $2014 Estimate based on NETL Case 14 using ratio of CO2 flows and Size Adjustment Exponent.

CO2 Injection Well - Capital CostsCost for Saline Formation Injection Well System = 46,049,328 $2008 Final CO2 GS Rule Cost Analysis (Large-scale project well costs).

Jan-2008 CPI = 632.300 $2008 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0Feb-2014 CPI = 703.300 $2014 From: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0

Estimated CO2 GS Well System TCI = 51,220,137 $2014 TCI adjusted to $2014 using CPI ratios.CO2 Capture & Concentration - Annualized Costs

CO2 Capture Unit Steam Use = 3.2 103lb/T Case 14 NETL Report , p. 478 (stream 8).CO2 Capture Unit Power Use = 43 kWh/T Case 14 NETL Report , p. 479 (amine system auxiliaries).

Unit Power Cost = $/kW Site power cost basis.Unit Steam Cost = $/103lb See Steam Cost and EFs Basis sheet.

CO2 Capture Annual Power Cost = $/yr = (Unit Steam Use - Mlb/T) x (CO2 flow to CCS - T/d) x (365 d/yr) x (Steam Cost - $/Mlb)CO2 Capture Annual Steam Cost = $/yr = (Unit Power Use - kWh/T) x (CO2 flow to CCS - T/d) x (365 d/yr) x (Power Cost - $/kWh)

Annual O&M Labor & Materials @ 4% of TCI = $/yr Peters & Timmerhaus , average for simple processes, p. 201.Administrative, Taxes, Insurance @ 4% of TCI = 12,620,122 $/yr OAQPS Control Cost Manual.

Total Annual O&M Costs = 8 $/yrCapital Recovery Rate = 7% %/yr

Capital Recovery Period = 15 yrsCapital Recovery Factor = 11.0% % of TCI OAQPS CCM.

Annualized Capital Costs = $/yrSubtotal CO2 Capture Annualized Costs = 120,612,072 $/yr

CO2 Compression and Injection Well - Annualized CostsCO2 Compression Power Use = 105 kWh/T See CCS Power Calc sheet; value is per ton of CO2 captured by the system.

CO2 Compression Annual Power Cost = $/yr

CCS Impacts AnalysisValue

Table B-30. CCS Impacts Analysis

B-45

$2008 Well O&M Costs = 4,396,289 $/yr Final CO2 GS Rule Cost Analysis (Pilot project well costs).$2014 Well O&M Costs = 4,889,942 $/yr Adjusted using CPI ratios.

Allocated Annual O&M, Taxes, Ins., Admin. & Capital Costs = 17,150,310 $/yr Scaled from TCI: Capital Recovery Factor =10.98%, O&M = 4%, and Taxes, Ins. & Admin = 4%.Subtotal CO2 Compression & Well System Annualized Costs = 29,000,508 $/yr

Total CCS Process - Annualized CostsAnnualized CO2 Capture Costs = 120,612,072 $/yr

Annualized CO2 Compression and Well System Costs = 29,000,508 $/yrTotal CCS Annualized Costs = 149,612,580 $/yr

Process Heaters CCS - Cost Effectiveness Determination

CCS Steam Use = 6,712,998 103lb/yr = (CO2 Capture Unit Steam Use) x (CO2 flow from Furnaces and Cogen Units) x (365 d/yr)

CCS Power Use = 289,577,652 kWh/yr= ((CO2 Capture Unit Power Use) + (CO2 Compression Power Use) x (90% capture)) x (CO2 flow from Furnaces and Cogen Units) x (365 d/yr)

Gross CO2 Recovered = 1,896,881 T/yr Based on 90% capture of all combustion unit CO2.GHGs to produce steam for CO2 capture = 483,597 T/yr Based on a GHG EF of 144.1 lb/Mlb steam produced. See 'Steam Cost and EFs Basis' sheet.

GHGs Emitted by off-site power production = 180,122 T/yr Based on an incremental GHG EF of 2.23 lb CO2e/kWh (EPA 2010 eGRID database for LA).Net CO2 Recovered = 1,233,162 T/yr = Gross CO2 Recovered - GHGs emitted by Steam Generator - GHGs emitted by LA power plants.

Net Control Cost-Effectivness = 121 $/T = (Total CCS Annualized Costs) ÷ (Net CO2 Recovered)Process Heaters CCS Environmental Impacts

State ID = PA Two-letter state ID; location of CCS system & assumed source of electric power for that system.Off-site Power SO2 EF = 0.0065 lb/kWh EPA 2010 eGrid database; incremental power production factor for PA.Off-site Power NOx EF = 0.0018 lb/kWh EPA 2010 eGrid database; incremental power production factor for PA.

Off-site Power CO2e EF = 1.64 lb/kWh EPA 2010 eGrid database; incremental power production factor for PA.Steam Boiler NOx EF = 0.062 lb/103lb steam See Steam Cost and EFs Basis sheet.

Off-site Power SO2 = 942 T/yr = (CCS Power Use) x (Off-site Power SO2 EF) / (2000 lb/T)Off-site Power NOx = 266 T/yr = (CCS Power Use) x (Off-site Power NOx EF) / (2000 lb/T)

Steam Boiler NOx = 207 T/yr = (CCS Power Use) x (Steam Boiler NOx EF) / (2000 lb/T)NETL Report = Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2 ; November 2010; DOE/NETL-2010/1397.NETL Report Update = Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases ; August 2012; DOE/NETL-341/082312.Peters & Timmerhaus = Plant Design and Economics for Chemical Engineers (3rd ed.) , Peters, M.S., and Timmerhaus, K.D. (1980),McGraw‐Hill.Final CO2 GS Rule Cost Analysis = Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule), U.S. EPA, EPA 816-R10- Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.

Table B-30. CCS Impacts Analysis (cont'd)

B-46

Discussion/BasisTIC [$2008] = 46,049,328 $2008 Ref. 1; Cost for large-scale saline formation injection project under RA3; Large-scale project costs used

as injection volume most closely approximates project CO2 rates.Annual O&M [$2008] = 4,396,289 $2008 Ref. 1; Cost for large-scale saline formation injection project under RA3; Large-scale project costs used

as injection volume most closely approximates project CO2 rates.Jan-2008 CPI = 632.3 $2008 See: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0Jan-2014 CPI = 700.71 $2014 See: http://www.economagic.com/em-cgi/data.exe/blscu/CUUR0000AA0

TIC = 51,031,512 $2014 = ($Jan-2014 CPI) / ($Jan-2008 CPI) x (TIC [$2008])Annual O&M = 4,871,934 $2014 = ($Jan-2014 CPI) / ($Jan-2008 CPI) x (Annual O&M [$2008])

CO2 Geologic Sequestration Saline Well CostsParameter Value

Ref. 1: Cost Analysis for the Federal Requirements Under the Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells (Final GS Rule), U.S. EPA, EPA 816-R10-013, Nov-2010.

Table B-31. Geologic Sequestration Saline Well Costs

B-47

Pump Power CalculationCO2mass Captured= 5,197 MT/day

Pinitial = 0.10 MPaPfinal = 15.0 MPa

Pcut-off = 7.38 MPaρ = 630 kg/m3

ηp = 0.75Wp = 970 kW

Compressor Power CalcalationGeneral Parameters

R = 8.314 kJ/kmol-oKM = 44.01 lb/lb-mol

Tin = 313.15 oKηis = 0.75CR= 2.36 per stage

Stage 1 ParametersZs1 = 0.995ks1 = 1.277

Ws1 = 4,465 kWStage 2 Parameters

Zs2 = 0.985ks2 = 1.286


Zs3 = 0.97ks3 = 1.309


Zs4 = 0.935ks4 = 1.379


Zs5 = 0.845ks5 = 1.704

Ws5 = 4,141 kWTotal Compressor Power

Stage 1 - 5 = 21,731 kWTotal Transport PowerPump + Compressor = 22,701 kW

Source: Techno-Economic Models for Carbon Dioxide Compression, Transport, and Storage; Institute of Transportation Studies University of California, Davis 2006; pubs.its.ucdavis.edu/download_pdf.php?id=1047

Table B-32. CCS Compression and Pumping Energy Calculation

B-48

Estimated Gas Cost =Steam Cost (fuel only) = 5.72 $/Mlb

Steam Cost (fuel + O&M + CR) = 8.57 $/MlbSteam GHG EF = 144.1 lb/MlbSteam NOx EF = 0.01 lb/Mlb

Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.

Based on above equation and energy content values and 40 CFR Part 98 NG GHG EFs.Based on an assumed NOx emissions rate of 0.01 lb/MMBtu.

Steam Cost and EFs Basis

From: http://www.energystar.gov/buildings/sites/default/uploads/tools/bnch_cost.pdfShell's estimate of fuel costs.See above equation and energy content values; assumes 88% efficiency.Assumes O&M + Capital Recovery ≈ 50% of Fuel Cost.

Table B-33. Steam Cost and Emission Factor Basis

B-49

Input Data Unit SourceMass Flowrate of Transfer Line = lb/hr Licensor providedConcentration Hexane = 20 ppm MON ComplianceMole Weight Hexane = 86.17 lb/lb-mole ConstantMole Weight Nitrogen = 28.02 lb/lb-mole ConstantNumber of Venting Episodes times/yr Licensor/Shell ProvidedDuration of Venting Episode hours/episodeLicensor/Shell Provided

Hourly Emission Rate = 0.03 lb/hrAnnual PTE = 9.11E-04 tpy

Calculation Basis:Hourly Emissions = Annual Emissions =

Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law.

(Hourly) x (Hrs/episode) x (episodes/yr) / 2000

Hexane Emissions Estimates from Cocatalyst Transfer Line EU=COCATFD1/2

Emissions Estimate

Calculation Basis

(Mass Flowrate)x(Concentration of hexane)*(Mole Wt Hexane/Mole Weight N2)

Table B-34. Cocatalyst Feed Pot Emissions Estimate

B-50

APPENDIX C

AIR DISPERSION MODELING AND CLASS II VISIBILITY ANALYSIS FOR THE PROPOSED SHELL CHEMICAL

APPALACHIA LLC PETROCHEMICALS COMPLEX PROJECT IN BEAVER COUNTY PENNSYLVANIA

Prepared for: Shell Chemical Appalachia LLC

910 Louisiana Houston TX 77002

Prepared by: RTP Environmental Associates

304A West Millbrook Road Raleigh, North Carolina 27609

April 2014

i

Table of Contents

1.0 INTRODUCTION AND SUMMARY OF RESULTS .............................................. 1-1 2.0 PROJECT DESCRIPTION .................................................................................. 2-1 3.0 SITE DESCRIPTION ........................................................................................... 3-1 4.0 MODEL SELECTION AND MODEL INPUT ........................................................ 4-1

4.1 Model Selection ................................................................................................ 4-1 4.2 Model Control Options and Land Use .............................................................. 4-1 4.3 Source Data ..................................................................................................... 4-2 4.4 Ambient Monitoring and Monitored Background Data ...................................... 4-8 4.5 Receptor Data ................................................................................................ 4-16 4.6 Meteorological Data ....................................................................................... 4-17

5.0 MODELING METHODOLOGY ............................................................................ 5-1 5.1 Pollutants Subject to Review ............................................................................ 5-1 5.2 Turbine Load/Operating Conditions .................................................................. 5-1 5.3 Furnace Operating Conditions.......................................................................... 5-1 5.4 Significant Impact Analysis ............................................................................... 5-2 5.5 NAAQS Analysis .............................................................................................. 5-2 5.6 NO2 Analyses ................................................................................................... 5-4

6.0 RESULTS ............................................................................................................ 6-1 6.1 Turbine Load Analysis Results ........................................................................ 6-1 6.2 Furnaces Operating Condition Results ............................................................. 6-1 6.3 Significant Impact Analysis Results .................................................................. 6-1 6.4 NAAQS Analysis Results ................................................................................. 6-4 6.5 Summary and Conclusions .............................................................................. 6-7

7.0 CLASS II VISIBILITY ANALYSIS ........................................................................ 7-1 8.0 CLASS I AREA IMPACTS ................................................................................... 8-1

8.1 Class I AQRV Analysis ..................................................................................... 8-1 8.2 Class I Significant Impacts Analysis ................................................................. 8-1

List of Tables

Table 1. Proposed Background Concentrations 2010-2012 ...................................... 4-11 Table 2. Beaver Falls 98% Hourly NO2 (ppb) By Season and Hour of Day ............... 4-11 Table 3. Receptor Grid Spacing ................................................................................ 4-17 Table 4. PSD Class II Significant Impact Levels ......................................................... 5-3 Table 5. Load Analysis Results ................................................................................... 6-2 Table 6. Worst Case Furnace Analysis Results .......................................................... 6-3 Table 7. Class II Significant Impact Analysis Results .................................................. 6-3 Table 8. Class I Significant Impact Analysis Results ................................................... 6-4 Table 9. NAAQS Analysis Results .............................................................................. 6-5 Table 10. Shell Contribution to the Modeled 1-hr NO2 NAAQS Exceedences ............ 6-6 Table 11. Class II Visibility Analysis Results for Raccoon Creek State Park ............... 7-3 Table 12. Class I Significant Impact Analysis Results ................................................. 8-1

ii

List of Figures

Figure 1. General Location of the Shell Facility ........................................................... 3-2 Figure 2. Specific Location of the Shell Facility ........................................................... 3-3 Figure 3. Land Use within Three Kilometers ............................................................... 4-3 Figure 4. Shell Facility Plot Plan .................................................................................. 4-6 Figure 5. Shell Three Dimensional Plot Plan (View from SW) ..................................... 4-7 Figure 6. Ambient Air Quality Monitors in the Vicinity of the Shell Site ........................ 4-9 Figure 7. Shell Near-field Receptor Grid ................................................................... 4-18 Figure 8. First Energy Meteorological Tower Location Relative to Shell ................... 4-20 Figure 9. Beaver Valley Windrose 2006-2010 ........................................................... 4-21 Figure 10. Pittsburgh International Airport Location Relative to Shell ....................... 4-22 Figure 11. Meteorological Data Representativeness Analysis Results ..................... 4-23 Figure 13. Class I Areas Located within Three Hundred Kilometers of Shell and

Modeled Receptors ................................................................................................ 8-2

Shell Chemical Appalachia LLC Plan Approval Application Beaver County, Pennsylvania Petrochemicals Complex

1-1

1.0 INTRODUCTION AND SUMMARY OF RESULTS

This document presents the results of the air quality dispersion modeling analysis

conducted for the proposed Shell Chemical Appalachia, LLC Ethane

Cracker/Polyethylene Plants Project ("Shell") to be constructed in Beaver County

Pennsylvania.

The analysis evaluated emissions of the criteria pollutants regulated under the

Prevention of Significant Deterioration ("PSD") regulations of 40 CFR 52.21 as

implemented under 25 Pa. Code Chapter 127, Subchapter D. The criteria pollutant

analysis was conducted to insure that the proposed project will not cause or contribute

to air pollution in violation of a National Ambient Air Quality Standard ("NAAQS") or PSD

increments.

The analyses quantify only the impacts of the pollutants that are emitted in amounts in

excess of the significant emission rates ("SERs"). For the proposed project, emissions

of nitrogen oxides ("NOX"), carbon monoxide ("CO"), and particulate matter with an

aerodynamic diameter of less than 10 µm ("PM10") will be emitted in significant

quantities.

Only the emissions from the proposed Shell facility were initially evaluated for

determining if the project would significantly impact local air quality. The resultant

modeled concentrations were compared to the ambient Significant Impact Levels

("SILs") for Class I and Class II areas. The results of this significant impacts analysis

demonstrate that the proposed project will result in ambient impacts in excess of the

Class II SIL only for the 1-hour NO2 standard. Impacts for all other pollutants were

determined to be less than the Class I and Class II SILs. Therefore, a refined air quality

analysis to calculate concentrations for comparison to the NAAQS was required for the

1-hr NO2 standard.


1-2

The results of the NAAQS analysis for the 1-hour NO2 standard indicate modeled NO2

violations in the vicinity of the proposed Shell site. These modeled violations are

attributable to existing sources in the vicinity of the proposed Shell site. The proposed

project is shown not to cause or contribute to an existing modeled violation.

Class II visibility impacts were also evaluated at the Pittsburgh International Airport and

determined to be acceptable.

The analysis conforms to the modeling procedures outlined in the Environmental

Protection Agency’s Guideline on Air Quality Models1 ("Guideline") and associated EPA

modeling policy and guidance as well as with the modeling protocol submitted to and

approved by the Pennsylvania Department of Environmental Protection ("PADEP") on

February 19, 2014.2

.


2-1

2.0 PROJECT DESCRIPTION The proposed Shell facility will produce approximately 1,600,000 metric tons per year of

ethylene and 1,600,000 metric tons per year of polyethylene. From an air emissions

modeling perspective, the facility will consist of seven ethane cracking furnaces, a

number of diesel engines to provide emergency power and power fire water pumps,

incinerators, flares, a cooling tower, three catalyst activation heaters, and three

combustion turbines with heat recovery systems to provide steam and electric power to

the facility and electric power for sale.

The project will result in increases in emissions of nitrogen oxides ("NOx"), particulate

matter with an aerodynamic diameter of less than 10 microns (PM10"), and carbon

monoxide ("CO") that are in excess of PSD SERs. Please note that the portion of

Beaver County where the Shell facility is to be located is classified as non-attainment for

ozone, sulfur dioxide ("SO2"), PM2.5, and lead ("Pb"). These pollutants are therefore

subject to non-attainment review and were not required to be evaluated under PSD.


3-1

3.0 SITE DESCRIPTION

The Shell facility will occupy approximately 400 acres on the site of the zinc smelter

currently owned by the Horsehead Corporation. The site is located adjacent to the Ohio

River in the Borough of Monaca, Pennsylvania in Beaver County. The approximate

Universal Transverse Mercator ("UTM") coordinates of the facility are 556,129 meters

east and 4,502,450 meters north (UTM Zone 17, NAD 83). Figure 1 shows the general

location of the facility. Figure 2 shows the specific facility location on a 7.5-minute U.S.

Geological Survey ("USGS") topographic map.

The facility will be classified under the regulations governing PSD (40 CFR 52.21) and

Title V (40 CFR 70.2) as a major source of air pollution. The portion of Beaver County

where the Shell facility is to be located is classified as attainment or unclassifiable for all

regulated pollutants except ozone, SO2, PM2.5, and Pb.a

a A portion of Beaver Co is non-attainment for the 1997 and 2008 8-hour ozone standards, the 2010 1-hr SO2 standard, the 1997 annual PM2.5 standard, the 2006 24-hr PM2.5 standard, and the 2008 lead (Pb) standard.


3-2

Figure 1. General Location of the Shell Facility


3-3

Figure 2. Specific Location of the Shell Facility


4-1

4.0 MODEL SELECTION AND MODEL INPUT 4.1 Model Selection The latest version of the AMS/EPA Regulatory Model (AERMOD, Version 13350) was

used to conduct the dispersion modeling analysis. AERMOD is a Gaussian plume

dispersion model that is based on planetary boundary layer principals for characterizing

atmospheric stability. The model evaluates the non-Gaussian vertical behavior of

plumes during convective conditions with the probability density function and the

superposition of several Gaussian plumes. AERMOD is a modeling system with three

components: AERMAP is the terrain preprocessor program, AERMET is the

meteorological data preprocessor and AERMOD includes the dispersion modeling

algorithms.

AERMOD is the most appropriate model for calculating ambient concentrations near the

Shell facility based on the model's ability to incorporate multiple sources and source

types. The model can also account for convective updrafts and downdrafts and

meteorological data throughout the plume depth. The model also provides parameters

required for use with up to date planetary boundary layer parameterization. The model

also has the ability to incorporate building wake effects and to calculate concentrations

within the cavity recirculation zone. All model options were selected as recommended

in the EPA Guideline on Air Quality Models.

Oris Solution's BEEST Graphical User Interface ("GUI") was used to run AERMOD.

The GUI uses an altered version of the AERMOD code to allow for flexibility in the file

naming convention. The dispersion algorithms of AERMOD were not altered. A model

equivalency evaluation has been submitted to PADEP pursuant to Section 3.2 of 40

CFR 51, Appendix W.

4.2 Model Control Options and Land Use AERMOD was run in the regulatory default mode for all pollutants except NO2. The

NO2 modeling included the non-regulatory default Plume Volume Molar Ratio Method


4-2

("PVMRM") in the NAAQS analysis. This non-default option is discussed in more detail

in Section 5.5.

The default rural dispersion coefficients in the model were used. This rural classification

is supported by the Land Use Procedure consistent with subsection 7.2.3(c) of the

Guideline and Section 5.1 of the AERMOD Implementation Guide.

The USGS 2006 National Land Cover Data (NLCD) within 3km of the site were

converted to Auer 1978 land use types, using recommendations from the PADEP, and

evaluated.3 It was determined that the land use in the vicinity of Shell is predominantly

rural (less than 15% of the area is classified as urban - Figure 3). Based upon this rural

determination, the potential for urban heat island affects, which are regional in

character, should not be of concern.

4.3 Source Data Modeled source input data and emissions are included in Attachment A of this report. Source Characterization Point Sources Most emission sources at the Shell site will vent to stacks with a well defined opening.

These sources were modeled as point sources in AERMOD. Several other types of

sources such as fugitive emissions, flares, horizontal releases and merged flues also

required evaluation.

Fugitive Emissions Fugitive emissions were modeled as volume sources. The initial dispersion coefficients

(sigma y and sigma z) were calculated based upon the dimensions of the area of

release and the equations contained in Table 3-1 of the AERMOD User’s Guide.

Haul roads were modeled pursuant to procedures adopted by the EPA Haul Road


4-3

Figure 3. Land Use within Three Kilometers


4-4

Workgroup4 as developed by the Texas Commission on Environmental Quality and

outlined in the six steps below:

Step 1: The adjusted width of the “road” was calculated as the actual road width plus 6 meters. The additional width represents turbulence caused by the vehicle as it moves along the road. Step 2: The number of volume sources was calculated by dividing the length of the road by the adjusted width. This was the maximum numer of volume sources modeled. Step 3: The height of the volume was set to 1.7 times the height of the vehicle generating the emissions. Step 4: The initial horizontal sigma for each volume was calculated by dividing the adjusted width by 2.15. Step 5: The initial vertical sigma was calculated by dividing the height of the volume determined in Step 2 by 2.15. Step 6: The release point height was calculated as the height of the volume divided by two. This point is in the center of the volume.

Flares There will also be flares at the facility: ground flares and elevated, candlestick flares.

Several of the flares will only be operated during periods of malfunction. Malfunction

emissions are not required to be modeled per 40 CFR Part 51 Appendix W. Therefore,

only the emissions associated with the pilot lights were modeled for the flares that are

used for malfunction. However, flares used for startup or shutdown (i.e., non-

emergency flaring) were model using the SCREEN3 proceedures developed by the

EPA as described by the Ohio EPA5. The effective stack height (H, in meters) was

computed as a function of heat release rate according to the following equation, where

Q is the heat release rate of the flare in MMBty/hr:

Hequivalent = Hactual + 0.944(Q)0.478

The effective flare diameter (d, in meters) was computed as a function of heat release

rate according to the following equation, where Q is the heat release rate of the flare in

MMBty/hr:


4-5

dequivalent = 0.1755(Q)0.5

An exit temperature of 1273°K and velocity of 20 m/sec was assumed.

All source locations were based upon a NAD83, UTM Zone 17 projection. The source

elevations for all Shell sources were determined from facility survey data, not from

AERMAP.

Good Engineering Practice Stack Height Analysis A Good Engineering Practice (GEP) stack height evaluation was conducted to

determine appropriate building dimensions to include in the model and to calculate the

GEP formula stack height used to justify stack height credit for stacks to be constructed

in excess of 65m. Procedures used were in accordance with those described in the

EPA Guidelines for Determination of Good Engineering Practice Stack Height

(Technical Support Document for the Stack Height Regulations-Revised).6 GEP

formula stack height, as defined in 40 CFR 51, is expressed as GEP = Hb + 1.5L, where

Hb is the building height and L is the lesser of the building height or maximum projected

width. Building/structure locations were determined from a facility plot plan. The

structure locations and heights were input to the EPA’s Building Profile Input Program

(BPIP-PRIME) computer program to calculate the direction-specific building dimensions

needed for AERMOD. The Shell facility plot plan is shown in Figure 4. A three

dimensional rendering of the facility is shown in Figure 5.

Merged Exhaust Streams The three combustion turbines will each vent to an individual flue contained within a

common stack. For the modeling analysis, the exhaust streams from the turbines were

“merged,” such that the exhaust streams from the three units are emitted through a

single flue in a combined stack. Such merging is permissible under the GEP

regulations and is not considered a “dispersion technique” prohibited under 40 CFR §

52.21(h)(1)(ii) and § 51.100(hh).


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Figure 4. Shell Facility Plot Plan


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Figure 5. Shell Three Dimensional Plot Plan (View from SW)

A dispersion technique is “any technique which attempts to affect the concentration of a

pollutant in the ambient air by … [i]ncreasing final exhaust gas plume rise by

manipulating source process parameters, exhaust gas parameters, stack parameters,

or combining exhaust gases from several existing stacks into one stack; or other

selective handling of exhaust gas streams so as to increase the exhaust gas plume

rise.” 40 CFR § 51.100(hh)(1)(iii).

Specifically excluded from the prohibition is “[t]he merging of exhaust gas streams

where … [t]he source owner or operator demonstrates that the facility was originally

designed and constructed with such merged gas streams.” 40 CFR § 51.100(hh)(2)(ii).

Because the original design and construction of the facility will include merged gas

streams, the exclusion applies; merging in these circumstances is not a dispersion

technique and the modeling must take into account the merged flue.


4-8

The merged flues were modeled by calculating an equivalent diameter of the merged

flues. The equivalent diameter was based the following formula:

Square root of (the total area of the combined flues divided by 3.14) x 2.

The stack velocity was calculated based upon the combined flow and the total area of

the combined flues.

4.4 Ambient Monitoring and Monitored Background Data Pursuant to 40 CFR 52.21(i)(5), as adopted at 25 Pa. Code Chapter 127, Subchapter D,

requirements for ambient monitoring data may be waived by the permitting authority if

projected increases in ambient concentrations due to the project are less than the

Significant Monitoring Concentrations. As shown in Section 6.2 herein, the Shell project

would qualify for such a waiver with respect to all listed pollutants because the

maximum modeled impacts are less than the Class II SILs and, therefore, also less than

the Significant Monitoring Concentrations ("SMC") (please note there is no SMC for NO2

for the 1-hour average). In light of the decision of the D.C. Circuit Court of Appeals

Sierra Club v. EPA last year,7 Shell has elected not to request such a waiver. However,

it should be noted that the PSD regulations in effect for this project would not require

ambient monitoring data.

The Monitoring Guidelines, other EPA interpretive guidance, and EPA administrative

decisions clarify that representative, existing air quality monitoring data may be used to

fulfill the PSD pre-construction monitoring requirements and establish the background

concentrations needed for assessing NAAQS compliance, in lieu of monitoring data

from the area in the vicinity of the proposed source or modification. EPA’s Monitoring

Guidelines suggest specific criteria to determine representativeness of off-site data:

quality of the data, currentness of the data, and monitor location.

There are two ambient monitors in close vicinity (within 10km) of the proposed Shell site

(Figure 6). The Brighton Township monitor, on Sebring Road (AQS #42-007-0005), is


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Figure 6. Ambient Air Quality Monitors in the Vicinity of the Shell Site


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located just across the river from the site to the north. However, only SO2 and O3 are

monitored at this location. The second monitor is located in Beaver Falls (AQS #42-

007-0014). PM10, PM2.5, NO2, O3, and SO2 are monitored at this location. There are

no CO monitors in Beaver Co (Please note that CO was monitored at the Beaver Falls

site. However, the CO monitor was inactivated in 2008). The nearest CO monitor is the

Pittsburgh monitor in Allegheny County (AQS# 42-003-0010).

RTP proposes to use the most recent available, quality assured PM10 and NO2 data

(2010-2012) from the Beaver Falls monitor to establish representative background

concentrations. This monitor best represents background concentrations as it is the

closest monitor with data for the pollutants of concern and is in the vicinity of the site. It

is also not likely significantly influenced by the localized source impacts of the AES and

First Energy facilities. CO from the Pittsburgh monitor will also be used. The proposed

background data are presented in Tables 1 and 2. The proposed existing monitoring

data satisfy the criteria provided in EPA’s Ambient Monitoring Guidelines8 as being

representative of the Shell site and should therefore be allowed for use.

A range of monitored background NO2 values that consider seasonal and diurnal

variation was used to assess compliance with the 1-hr NAAQS. These seasonal values

reflect the three year average (2010-2012) of the 98th percentile value by hour of day

and by season. These seasonal NO2 values were added to the modeled value within

AERMOD.

Monitor Location The Beaver Falls monitor is located less than 9 kilometers from the proposed Shell

facility. It is also located in an adjacent river valley, absent the influence of any major,

localized industry. While the CO monitor is more distant at 40km, measurements from

this site should provide a conservative representation of the air quality in the vicinity of

the Shell site.


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Table 1. Proposed Background Concentrations 2010-2012

Pollutant Averaging Time

Maximum Monitored Value

(µg/m3) Monitor Site

Location PM10 24-hour 78.0 Beaver Falls NO2 Annual 21.5 CO 1-hour 4571 Pittsburgh 8-hour 3086

Table 2. Beaver Falls 98% Hourly NO2 (ppb) By Season and Hour of Day

Model Ending Hour Winter Spring Summer Fall

01 32.0 31.0 23.0 25.3 02 34.7 32.3 23.3 25.7 03 33.7 31.7 22.7 25.0 04 32.7 33.3 22.3 24.7 05 33.3 32.0 21.7 24.0 06 33.3 32.7 22.3 25.0 07 34.0 34.7 23.7 25.0 08 35.0 34.0 23.0 26.0 09 37.3 33.3 23.7 29.0 10 36.3 33.0 25.0 31.7 11 35.0 31.7 18.7 30.0 12 33.3 24.3 13.7 25.3 13 30.7 21.7 10.3 20.7 14 28.3 16.3 10.3 16.3 15 27.7 15.7 10.0 15.3 16 29.0 15.3 9.0 16.0 17 28.0 16.0 7.7 21.7 18 29.3 16.7 10.7 27.3 19 31.3 21.3 13.3 26.0 20 31.0 27.7 15.7 26.3 21 30.3 28.3 18.3 26.0 22 32.7 29.7 22.7 28.0 23 32.7 31.0 22.0 27.3 24 32.7 31.3 20.7 25.3

Note: Maximum 1-hr NO2 value is 37.3 ppb or 70.4 µg/m3.


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Data Quality The existing ambient monitors were established and air quality data were collected as

part of EPA's ambient air quality monitoring network. Federal regulations at 40 CFR

Part 58, Appendix A, require that these data meet quality assurance ("QA")

requirements. The existing ambient air quality data also meet the data quality

requirements of Section 2.4.2 of the Monitoring Guidelines. The QA requirements for

monitoring criteria pollutants at PSD sites are very similar to the QA requirements for

monitoring sites for NAAQS compliance. The data presented in Section 5.3 meet the

data quality criterion.

Currentness of Data The Monitoring Guidelines suggest that air quality monitoring data used to meet PSD

data requirements should be “collected in the 3-year period preceding the permit

application.”9 The data presented herein are current and meet this criterion.

Relevant EPA Decisions Recent actions by U.S. EPA, including permit approvals by Regional Offices and

decisions by the Environmental Appeals Board, support reliance on regional monitors to

fulfill the one year PSD ambient air quality monitoring requirements for NO2, PM10, and

CO in the Shell application. Several relevant actions are summarized below, beginning

with the final PSD permit decision recently issued by U.S. EPA for Energy Answers

Arecibo, LLC (“EA”). In that matter, the agency stated:

EA provided EPA with monitoring data for all criteria pollutants subject to PSD even though those pollutants were less than the Significant Monitoring Concentrations in 40 C.F.R. 52.21(i)(5)(i)…. Energy Answers requested approval to use existing data for all of the criteria pollutants instead of obtaining new, site-specific monitoring data in May and September 2011. EPA approved this request based on the fact that representative existing ambient monitoring data was provided. The existing data that is available was collected at sites that have higher concentrations than Arecibo since they are located in more industrial areas, such as Catano, Barceloneta, and San Juan (see Response to Comment 3 in this section for further details). *


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* [The Monitoring Guidelines document] allows the use of monitors in other geographical areas provided they are representative. In this case, the monitors are located in more industrialized area so they represent a conservative estimate. EPA allowed the use of these monitors for background in this case since these monitors measure more than the “natural, minor or major distant sources” in Arecibo (Guideline on Air Quality Models section 8.) They also measure concentrations from other large sources.10

The decision by U.S. EPA to approve the use of existing, representative monitoring data

from regional monitors in the EA permit review was made notwithstanding the fact that

complex terrain exists within 5 km of the EA project site.11 These regional monitors are

located in industrialized areas and are outside the project’s maximum impact area –

more than 70 km from the EA project site in the case of the San Juan monitoring data

used for PM10 and CO. Moreover, none of the data from the regional monitors were

gathered in the year preceding the submittal of the permit application; the NO2 and SO2

data were collected by EA outside the three-year time window suggested by the

Monitoring Guidelines. U.S. EPA’s decision with respect to EA supports Shell’s reliance

upon data from the selected off-site monitoring locations; the data relied upon by Shell

are arguably more representative and more current than the data accepted by the

agency in that matter.

The EA permit decision is consistent with long-standing EPA policy that, with respect to

approval of representative, existing ambient monitoring data from regional monitors,

“the guidelines are very broad and leave much to the discretion of the permitting

authority.”12 Notably, EA was the first PSD permit approval from U.S. EPA since the

decision in Sierra Club v. EPA, vacating the SMCs, making the approach in the EA

permit review especially informative. The agency’s determination in the EA matter

confirms that the court’s decision in Sierra Club v. EPA cannot be read to narrow the

agency’s broad discretion on this PSD requirement. Over the 25 years since U.S. EPA

issued the Monitoring Guidelines, the agency has consistently used its discretion to

accept existing, representative ambient air quality data in permit decisions and formal

administrative decisions. More examples follow:


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• In Hibbing Taconite, the U.S. EPA Administrator determined that the permitting

authority acted within its discretion in determining that the project site was not in

an area of multisource emissions, as that term is used in the Monitoring

Guidelines, although “there are eleven SO2 sources within 65 kilometers of [the

project site].”13 On the basis of this determination, the agency approved the use

of existing, representative ambient monitoring data.

• In Encogen Cogeneration, the U.S. EPA Environmental Appeals Board

determined that the permitting authority acted within its discretion in approving

the use of existing, representative ambient monitoring data from a regional

monitor located approximately 70 km from the project site because “the choice of

appropriate data sets for the air quality analysis is an issue largely left to the

discretion of the permitting authority” and “[t]he use of background data with

higher pollution concentrations, in essence, provides an additional margin of

safety for future air quality at the site.”14

• In support of its decision to issue a PSD permit for Shell’s Chukchi Sea

Exploration Drilling Program, U.S. EPA Region 10 approved the use of ambient

monitoring data from a regional monitor located more than 100 km from the

project site. The agency justified this decision on the basis that it would be

inconvenient to install, operate, and maintain ambient air quality monitoring

equipment near the project site and because “[m]onitoring data from an onshore

location near a village or other onshore sources is expected to be conservative

when compared to monitoring data that would be collected miles offshore

because onshore data will be more influenced by the local emission sources.”15

• In support of its decision to issue a PSD permit for the Diamond Wanapa project,

U.S. EPA Region 10 waived the preconstruction ambient monitoring

requirements for all pollutants other than PM10. For PM10, the agency approved

the use of ten-year-old data from a regional monitor located approximately 24 km

from the project site. The agency did not document any analysis of whether the


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area includes complex terrain or is an area of multisource emissions. With

respect to spatial representativeness, the agency’s description of its analysis, in

its entirety, is as follows:

With regard to monitoring location, the existing data should be representative of three types of areas: (1) the location(s) of maximum concentration increase from the proposed source or modification; (2) the location(s) of the maximum air pollutant concentrations from existing sources; and (2) the location(s) of the maximum impact area. See Ambient Monitoring Guidelines at p.6. EPA has determined that this factor is satisfied because both areas are rural, have similar topography, have similar land use and climate, and are located in the same airshed.16

• In support of its final PSD permit decision for the Bonanza Power Plant in 2007,

U.S. EPA Region 8 approved as representative the use of ambient monitoring

data from the period 1991-1993, more than ten years prior to permit application

submittal.17

• In support of its final PSD permit decision for the Pio Pico Energy Center in 2012,

U.S. EPA Region 9 waived the preconstruction ambient monitoring requirements

for all pollutants other than NO2 and PM2.5.18 For both NO2 and PM2.5, the

agency approved as representative the use of existing ambient monitoring data

from a regional monitoring site located 15 km from the project site; in granting

this approval, the agency dismissed as not representative of background

concentrations the monitoring data from the Otay Mesa monitor located only

2 km from the project site, due to localized impacts from mobile sources at that

monitor.19 In responding to public comments, the agency also made clear that

the considerations set forth in the Modeling Guidelines afford discretion to the

permitting authority:

[W]e note that guidance documents on representativeness of data identify important factors to consider in evaluating the need for site-specific data collection, but do not dictate exactly when site-specific data must be used rather than data from nearby locations. * *


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As a result, the analyses conducted in this case using the Chula Vista data are consistent with the principles from the 1987 Guidelines cited by the commenter and achieve the objectives reflected in these Guidelines in an alternative manner. Furthermore, the use of modeled emissions from nearby sources such as the Otay Mesa Power Plant, rather than background data in the immediate vicinity of those sources, is a more conservative approach to determining NAAQS compliance, because such modeling takes into account potential emissions, which could be higher than the actual emissions from the sources at issue that would be reflected in the background data.20

The U.S. EPA’s Environmental Appeals Board recently upheld this waiver, more

than six months after the court’s decision in Sierra Club v. EPA, which manifests

a determination by the agency that the Significant Monitoring Concentrations and

associated exemption remain in effect. 21

PADEP has broad discretion to accept the monitoring data provided for NO2, PM10, and

CO in Shell’s permit application. The off-site data relied upon by Shell to fulfill the

ambient air quality monitoring requirement for this PSD application satisfies the criteria

outlined in EPA’s Monitoring Guidelines: data quality, currentness of the data, and

location of the monitors, and represents the ambient air quality in the area of Shell’s

proposed project. Representative, existing data provided for NO2, PM10, and CO fulfill

the one year pre-construction data requirement.

4.5 Receptor Data Modeled receptors were placed in all areas considered as "ambient air" pursuant to 40

CFR 50.1(e). Ambient air is defined as that portion of the atmosphere, external to

buildings, to which the general public has access. Approximately 22,700 receptors

were used in the AERMOD 1-hr NO2 significant impacts analysis. The receptor grid

consists of four cartesian grids and receptors spaced at 25m intervals along the facility

fenceline and the railroad that transects the facility.. The first cartesian grid extended to

approximately 1km from the fence in all directions. Receptors in this region were

spaced at 50m intervals. The second grid extended to 3km. Receptor spacing in this

region was 100m. The third grid extended to 10km with a spacing of 500m.


4-17

The fourth grid extended to 50km with a receptor spacing of 1,000m. Receptors with

flagpole elevations were also placed along the Highway 376 bridge east of the facility.

The receptor grid was designed such that maximum facility impacts fall within the 50m

spacing of receptors. Such an expansive grid will be used as significant 1-hr NO2

concentrations extended to a distance of 43km from the proposed facility.

The receptor grid spacing is presented in Table 3.

Table 3. Receptor Grid Spacing

Receptor Spacing (m) Distance from Facility

Fence (m) 50 1,000

100 3,000 500 10,000

1,000 50,000 The Shell facility will be located in western Pennsylvania. Terrain within 10km of the

site is gently rolling; however, there is terrain in excess of stack top elevation. Receptor

elevations and hill height scale factors were calculated with AERMAP (11103). The

elevation data was obtained from the USGS 1 arc second National Elevation Data

(NED) obtained from the USGS. Locations were based upon a NAD83, UTM Zone 17

projection. The near-field receptor grid is presented in Figure 7.

4.6 Meteorological Data

Data Selection and Representativeness

The 2006-2010, 5-year sequential hourly surface meteorological data collected at the

First Energy Beaver Valley Nuclear Generating Station (Beaver Valley) and upper air

data from the Pittsburgh International Airport (KPIT, WBAN 94823) were used in the


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Figure 7. Shell Near-field Receptor Grid


4-19

analysis. The First Energy surface data were collected as part of a continuous data

collection program required by the U.S. Nuclear Regulatory Commission (NRC). The

meteorological data adequately represent atmospheric boundary layer conditions within

the Shell analysis domain for AERMOD to properly characterize the transport and

dispersion of the Shell emissions plumes. A profile base elevation of 228.6m was

employed which corresponds to the base elevation of the Beaver Valley tower.

The First Energy station is located approximately 8km downstream of the proposed

Shell site, also on the Ohio River. The Beaver Valley meteorological station and

proposed Shell site also share a similar orientation in relation to the Ohio River. As can

be seen in Figure 8, the river flows from the northeast to southwest relative to both the

proposed Shell site and the Beaver Valley meteorological station. The topography is

also similar at each location. The wind patterns are therefore likely similar at each

location (see the wind rose Figure 9). Wind speed, direction and standard deviation of

the horizontal wind direction are measured at three levels at the Beaver Valley station

(10.7m, 45.7m, and 152.4m). Temperature is also measured at the 10.7m level. These

three levels provide adequate representation of plume behavior at the various release

heights to be seen at the Shell site.

The Pittsburgh International Airport is located approximately 21km southeast of the

facility (Figure 10). Station pressure, cloud cover, and twice daily sounding data from

Pittsburgh were used. These meteorological parameters are of synoptic scale and are

adequately representative of the Beaver Valley area.

According to the EPA’s AERMOD Implementation Guide22, the surface characteristics

should be similar for the meteorological station and the study site. RTP compared the

surface characteristics at the First Energy station and the proposed site. The

AERSURFACE program was run to determine the characteristics for comparison. The

results of the surface roughness comparison, by season, are shown in Figure 11. As

can be seen, the surface characterisitics values for the two sites, when compared on a

seasonal and sector basis, are similar.


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Figure 8. First Energy Meteorological Tower Location Relative to Shell


4-21

Figure 9. Beaver Valley Windrose 2006-2010


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Figure 10. Pittsburgh International Airport Location Relative to Shell


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Figure 11. Meteorological Data Representativeness Analysis Results


4-24

Data Processing The meteorological data were provided to RTP Environmental by the PADEP. The

PADEP processed the Beaver Valley surface data, Pittsburgh International Airport

(KPIT) surface data and KPIT upper air data using the meteorological preprocessor

AERMET (Ver. 12345). Since these data were provided to RTP Environmental, the

EPA issued a newer version of AERMET (Ver. 13350). In response RTP Environmental

re-ran the PADEP's AERMET Stage 3 inputs using the more recent version of

AERMET. In AERMET Stage 1, KPIT surface meteorological data in the Integrated

Surface Data (ISD) format were extracted. KPIT upper air meteorological data in the

Forecast Systems Laboratory (FSL) format were also extracted.

Also, the MODIFY keyword was entered to fill missing temperatures in the upper air

data with interpolated values. In AERMET Stage 3, values of the surface characteristics

(noon-time albedo, Bowen ratio, and surface roughness length) representative of the

Beaver Valley surface meteorological site, were entered.

These surface characteristics values were calculated by AERSURFACE 13016 using

USGS National Land Cover Data ("NLCD") for 1992. The following options were

selected in AERSURFACE: default 1-km radius and default twelve 30-degree sectors

for surface roughness length, seasonal temporal resolution, non-airport site and non-

arid region. AERSURFACE was executed for each surface moisture condition

(average, dry, and wet), assuming both no continuous snow cover and continuous snow

cover during the winter (i.e., AERSURFACE was executed six times). AERMET

Stage 3 was then executed for each set of surface characteristics to produce six (6)

surface (.sfc) files. The final AERMET surface file was assembled by season based on

actual estimates of surface moisture condition and snow cover during the

meteorological data period. Estimates of surface moisture condition were based on

precipitation data for Pennsylvania Climate Division 9. Snow cover was based on

National Climatic Data Center (NCDC) Local Climatological Data from KPIT.


5-1

5.0 MODELING METHODOLOGY

5.1 Pollutants Subject to Review Only the regulated NSR pollutants whose emissions increases exceed the PSD SERs

and are therefore subject to PSD review were evaluated in the modeling analysis.

5.2 Turbine Load/Operating Conditions The combustion turbines will occasionally operate at a reduced load. Therefore, a

range of load conditions and operating modes representing potential unit operation were

evaluated to identify the condition which results in the worst-case impact for each

averaging period of concern. Three load conditions were evaluated for each turbine:

100%, 75%, and 45%. In addition, three turbine operating modes were evaluted: three

turbine mode, two turbine mode, and single turbine mode. A unit (i.e., 1 lb/hr) emission

rate was assumed to represent the 100% load condition for each turbine and the

emissions and flows for the other loads and operating modes scaled from the 100%

load condition. The condition resulting in the worst-case impacts was carried forward

for the remainder of the analysis.

5.3 Furnace Operating Conditions The furnaces will also have different modes of operation for short durations. Only the

pollutant emission rate will be affected by the operational model. When in decoking

mode, the CO emission rate will be elevated. Since only one furnace will be in decoking

mode at any point in time, the elevated, short-term CO emission rate was only assigned

to a single furnace. The NOx control on the furnaces may also have a reduction in short

term performance due to process fluctuations. Only two furnaces will operate in this

mode at any one time. It was therefore necessary to identify the furnaces with the worst

case short-term impacts. Each furnace was modeled with a unit emission rate. The two

furnaces that generated the worst case impacts were assigned these two operating

modes.


5-2

5.4 Significant Impact Analysis The criteria pollutant air quality analysis was conducted in two phases: an initial or

significant impact analysis, and a refined phase including an increment analysis and a

NAAQS analysis. In the significant impacts analysis, the calculated maximum impacts

were determined for each pollutant with a net emissions increase that exceeds the PSD

significant emission level. These impacts determine the net change in air quality

resulting from the proposed project. Maximum modeled concentrations were compared

to the pollutant-specific significance levels for all pollutants and averaging times except

for the 1-hr NO2 impact. The five year average of the maximum impact at each receptor

was used to assess significance for the 1-hr NO2 average.

Pollutants with impacts that exceed the ambient air significance levels, as defined in

40 CFR 51.165, were included in both the NAAQS and increment analyses. In these

latter analyses, impacts from the Shell facility were added to concentrations calculated

from other nearby sources, plus a regional background concentration. The resultant

total concentration was compared to the NAAQS and increments to determine

compliance. The PSD Class II Significant Impact Levels are listed in Table 4.

Five years of meteorological data were used in the significant impact analysis. The

maximum distance to significant impact was determined for each pollutant and

averaging period. The maximum concentration was used to determine significance. 5.5 NAAQS Analysis Following the determination of significant impacts, a refined air quality analysis to

determine compliance with the NAAQS was conducted. A refined analysis was

conducted to determine compliance with the NAAQS only for the 1-hr NO2 standard as

this is the only pollutant and averaging time modeled as having significant impacts in

the initial analysis. Please note that no PSD increment evaluation was required as

there is no PSD increment for NO2 for the 1-hr average and the maximum annual NO2

impact was determined to be less than the SIL.


5-3

Table 4. PSD Class II Significant Impact Levels

Pollutant Averaging Time PSD Class II Significant Impact Levels (µg/m3) 1

PM10 24-hour 5.0Annual 1.0

NO2 1-hour 7.5 2

Annual 1.0CO 1-hour 2000

8-hour 5001. Please note that on January 22, 2013, the US Court of Appeals for the District of Columbia Circuit Court granted a

request from the EPA to vacate and remand the PM2.5 SILs. EPA has stated that as long as the differencebetween the background monitored PM2.5 value and the NAAQS is greater than the SIL, the SIL can still be used inevaluating significance (see the March 3, 2013, "Draft Guidance for PM2.5 Permit Modeling"). The PADEP isfollowing this guidance for PM2.5 as well as other pollutants. The difference between Beaver Falls backgroundvalues and the NAAQS were evaluated and determined to be greater than the SILs (Please see Tables 1 & 2).

2. Please also note that there is no 1-hr NO2 SIL promulgated at 40 CFR 51.165. Consistent with to the June 28,2010 EPA Policy Memorandum from Anna Marie Wood to the Regional Air Directors, an interim 1-hr NO2 SIL of 4ppb (7.5µg/m3) has been adopted by the PADEP (see the December 1, 2010 Memorandum from Andrew Fleck tothe Regional Air Program Managers).

The receptors modeled in the 1-hr NO2 NAAQS analyses were limited to those showing

a significant impact in the initial analysis. Each source's potential emission rate will be

used. Five years of meteorological data were again used in the 1-hr NO2 NAAQS

analysis.

Nearby Source Inventory

Off-site sources were included in the 1-hr NO2 NAAQS analysis. Pursuant to the

March 1, 2011 Clarification Memorandum (see page 16 of reference no. 8), only

sources within 10km of the proposed Shell facility were considered for inclusion in the 1-

hr NAAQS analysis. The PADEP provided RTP Environmental with an inventory of

sources located within 10km of the proposed Shell site.23 The inventory included the

potential hourly emission rates that were calculated pursuant to Table 8-2 in the

“Guideline on Air Quality Models” (40 CFR 51, Appendix W).

NAAQS Compliance Assessment

Appropriate ambient background concentrations (as discussed in more detail in Section

4.3) were then added to the modeled concentrations to assess NAAQS compliance.

The five year average of the 98th percentile maximum daily 1-hr NO2 modeled value


5-4

was added to the three year average of the 98th percentile NO2 monitor value by

season and hour of day within AERMOD. The resultant concentration was compared to

the 1-hr NO2 NAAQS. The methodology for combining NO2 background concentrations

in the 1-hour cumulative analysis is based upon the methodology outlined in the March

1, 2011 Additional Clarification memorandum.24

As discussed below, modeled exceedances of the 1-hr NO2 NAAQS were identified.

These modeled exceedences are due to existing sources in the vicinity of the proposed

Shell site. Shell employed the EPA's post-processor "MAXDCONT" to demonstrate that

the proposed project does not significantly contribute to an existing modeled

exceedance. This demonstration is receptor and averaging time specific. 5.6 NO2 Analyses Following recent USEPA guidance, the NO2 modeling analyses used the recommended

three tier screening approach. Initially, Tier 1 was employed with the conservative

assumption that 100% of the available NOx converts to NO2. The annual NO2 impact

under this assumption exceeded the SIL. The Tier 2 (Ambient Ratio Method, or ARM)

was therefore employed with the EPA recommended NOx to NO2 conversion factor of

0.75 for the annual average and 0.80 for the hourly average. Tier 3 was employed to

assess the 1-hr NO2 NAAQS. Tier 3 accounts for the chemical reactions that convert

NOx to NO2 in the presence of ozone.

Tier 3 Option There are two Tier 3 methods currently available in AERMOD for simulating the

conversion of NOx to NO2: the Ozone Limiting Method (OLM) and the Plume Volume

Molar Ratio Method (PVMRM). Each method is considered to be an alternative model,

use of which must be formally approved prior to use. Shell has employed PVMRM. A

formal request has been submitted to PADEP that addresses the five criteria of

Section 3.2.2(e) of 40 CFR 51 Appendix W. PADEP also requested formal approval

from EPA Region 3. Approval was received on April 21, 2014.


5-5

The EPA's default NO2/NOx in stack ratio of 0.50 has been employed for all sources

except for the First Energy Bruce Mansfield and the AES Beaver Valley sites. A

NO2/NOx in stack ratio of 0.05 was employed for the uncontrolled emissions from the

First Energy coal boilers. This value was used based upon footnote "c" of Table 1.1-3

in AP-42, which states that 95% or more of NOx present in combustion exhaust will be

in the form of NO, the rest is NO2. An in stack ratio of 0.17 was employed for the AES

Beaver Valley coal boilers due to the preferential removal of NO2 due to the selective

non-catalytic reduction ("SNCR") employed on these units. In addition, a NO2/NOx

equilibrium ratio of 0.90 was employed.

Hourly ozone concentrations from the Sebring monitor, concurrent with the 2006-2010

meteorological data period, were employed. Missing data were filled with data from the

Tomlinson Road O3 monitor in southwestern Beaver County. The month of March is

missing for several years for both the Sebring and Tomlinson Road monitors. These

data were filled with data from the Harrison and Lawrenceville O3 monitors in Pittsburgh.

Intermittent Emissions Emissions from sources that emit intermittently (i.e., emergency generators, firewater

pumps, flares, and certain furnace operating scenarios, and startups and shutdowns)

were modeled in the 1-hr NO2 analysis pursuant to the March 1, 2011 EPA guidance.

Pursuant to this guidance, any source with emissions that do not have the potential to

contribute significantly to the annual distribution of the daily maximum concentrations

will either be excluded from the analysis or the emissions will be based on an average

hourly rate, rather than the maximum hourly rate. Sources that are not likely to

contribute include those with emission duration of less than 24-hours and with

operational frequency of less than seven occurrences per year.


6-1

6.0 RESULTS

Attachment B to this report provides the model summary output as well as contour plots

of the results. AERMOD input and output files, including the BPIP-PRIME files, are

included on the enclosed CD.

6.1 Turbine Load Analysis Results The results of the load analysis are presented in Table 5. As shown, the 100% load

scenario with three turbines operational was found to generate the highest impacts for

the turbines. The 100% load case was therefore used in the remainder of the modeling

analysis.

6.2 Furnaces Operating Condition Results The results of the worst-case furnace analysis are presented in Table 6. As shown, the

Furnace Nos. 1&2 were found to generate the highest short-term impacts. These two

furnaces were therefore assigned the elevated CO and NOx emissions associated with

the short-term furnace operating modes.

6.3 Significant Impact Analysis Results The Class II and Class I significant impact analysis results are presented in Table 7 and

Table 8, respectively. As shown in Table 7, the project is expected to result in

significant impacts for NO2 for the 1-hr average. A more refined NAAQS analysis was

therefore conducted for NO2 for the 1-hour averaging period. Please note that there is

no PSD increment for NO2 for the 1-hour average. Therefore, no increment analysis

was required. Please also note that the significant monitoring concentration levels were

not predicted to be exceeded for any pollutant. As shown in Table 8, the project will not

result in a significant impact at the closest Class I area, the Otter Creek Wilderness

Area. Therefore, no additional Class I increment modeling was conducted.


6-2

Table 5. Load Analysis Results

Averaging Period Source Name

Modeled Concentration

(μg/m3) Source Description

1-hr

3CT100 3.13 Three turbines, 100% load 2CT100 2.83 Two turbines, 100% load 1CT100 2.19 One turbine, 100% load 1CT75 2.02 One turbine, 75% load 1CT45 1.78 One turbine, 45% load

24-hr


8-hr


Annual



6-3

Table 6. Worst Case Furnace Analysis Results

Averaging Period Source Name


(μg/m3) Source Description

1-hr

EC#1 1.81 Ethane Cracking Furnace #1 EC#2 1.80 Ethane Cracking Furnace #2 EC#3 1.69 Ethane Cracking Furnace #3 EC#4 1.48 Ethane Cracking Furnace #4 EC#5 1.52 Ethane Cracking Furnace #5 EC#6 1.45 Ethane Cracking Furnace #6 EC#7 1.45 Ethane Cracking Furnace #7

24-hr


8-hr


Table 7. Class II Significant Impact Analysis Results

Pollutant Averaging

Period

Maximum Modeled Impact (μg/m3)

PSD Significant

Class II Impact Level

(μg/m3)

Significant Monitoring

Concentration (μg/m3)

Maximum Distance to a Significant Impact (km)

PM10 24-hr 4.14 5.0 10 NA

Annual 0.80 1.0 N/A NA

NO2a 1-hr 44.2 7.5 N/A 43.0

Annual 0.79 1.0 14 N/A

CO 1-hr 434 2000 N/A N/A

8-hr 169 500 575 N/A aNO2 impacts include ARM of 0.75 for the annual average and 0.80 for the 1-hr average. N/A – not applicable


6-4

Table 8. Class I Significant Impact Analysis Results

Pollutant Averaging

Period


PSD Significant

Class I Impact Level

(μg/m3)

PM10 24-hr 0.21 0.30

Annual 0.01 0.20

NO2a Annual 0.02 0.10

aNO2 impact includes ARM of 0.75 for the annual average.

6.4 NAAQS Analysis Results Following the determination of significant impacts, an analysis was conducted to assess

compliance with the 1-hr NO2 NAAQS. All major and minor sources located within

10km of the proposed facility were modeled in conjunction with the proposed Shell

facility. Background NO2 concentrations were added to the model results to assess

compliance. Evaluation of compliance with the 1-hour NO2 NAAQS was based on the

five-year average of the 98th percentile of the annual distribution of daily maximum 1-

hour concentrations.

The results of the NAAQS analysis are presented in Table 9. As shown, the model

indicates that 1-hour NO2 concentrations are in excess of the NAAQS. However, the

modeled violations are attributable to existing sources that were modeled as part of the

off-site inventory and not the proposed Shell facility. The Shell contribution to each

modeled concentration in excess of the NAAQS was determined using the

"MAXDCONT" option in AERMOD. This option allows for the calculation of the impact

due to Shell consistent in both time and space with each modeled concentration in

excess of the standard. Table 10 presents the ten highest concentrations from Shell at each modeled value in

excess of 188 µg/m3 for the 5 year modeled period. This table also presents the 10

highest overall modeled concentrations. Since the concentrations from the proposed

Shell project are insignificant (i.e., less than 7.5 µg/m3), the proposed project will not

contribute to any existing modeled 1-hr NO2 NAAQS violation.


6-5

Table 9. NAAQS Analysis Results

Pollutant Averaging

Period


(µg/m3)1 Standard (µg/m3) Comment

NO2 1-hour 3644 188 Maximum concentration due to off-site sources. Project impact is insignificant as paired in time and space.

1 Based on the 98th percentile of the annual distribution of maximum daily 1-hour concentrations, averaged across the 5 years of meteorological data modeled. PVMRM was employed for the 1-hr calculations. ARM of 0.75 used to calculate the annual impact.


6-6

Table 10. Shell Contribution to the Modeled 1-hr NO2 NAAQS Exceedences

Receptor Location (UTM X, m)

Receptor Location (UTM Y, m)

Total Modeled Concentration

(µg/m3)a Shell Project

Contribution (µg/m3)Top Ten Concentrations Sorted by Shell Contribution to Existing Violation

557,100 4,503,000 287.90 5.92 557,200 4,503,000 304.85 5.87 556,950 4,502,800 321.35 5.81 557,550 4,503,250 288.38 5.73 557,100 4,502,900 304.45 5.72 557,300 4,502,950 324.83 5.54 558,200 4,503,700 270.31 5.46 557,100 4,502,950 286.72 5.39 557,600 4,503,150 311.87 5.32 557,150 4,503,050 289.25 5.26 Top Ten Concentrations Sorted by Overall Maximum Modeled Concentration554050 4500600 3644.031 0.0006 554050 4500600 3509.551 0.03751 554050 4500600 3275.415 0.00545 554050 4500600 3120.157 0.00035 554050 4500600 3043.719 0.00052 554050 4500600 2852.118 0.0116 554050 4500600 2724.927 0.12449 554050 4500600 2672.093 0.03037 554050 4500600 2589.843 0.19152 554050 4500600 2553.22 0.00065

a Based on the 98th percentile of the annual distribution of maximum daily 1-hour concentrations, averaged over the 5 years of meteorological data modeled. PVMRM was employed for the 1-hr calculations. Only the top 10 receptors, sorted by the project contribution to maximum, are shown in this table. Please refer to the MAXDCONT output on the enclosed CD for a complete listing of all receptors with an impact in excess of 188 µg/m3.


6-7

6.5 Summary and Conclusions

Emissions of regulated pollutants were evaluated in a dispersion modeling analysis.

The modeling demonstrates that the proposed Shell facility will not cause or contribute

to ground level concentrations of any pollutant in excess of the levels designed to

protect human health and welfare. The modeling input and output files are provided on

the attached CD. Model summary results are presented in Attachment B to this report.

The summary results list the model file names associated with each phase of the

analysis.b

b As a general rule, the AERMOD input files have a “dta” extension. The AERMOD output files have a “lst” extension.


7-1

7.0 CLASS II VISIBILITY ANALYSIS The CAA Amendments of 1977 require evaluation of new and modified emission

sources to determine potential impacts on visibility. The maximum increase in hourly

particulate matter and NOX emissions from the proposed Shell facility were used as

input parameters in the visibility analysis. Emissions were evaluated as described in the

EPA Workbook for Plume Visual Impact Screening and Analysis25 to determine potential

contribution to atmospheric discoloration and visual range reduction.

Generally, atmospheric discoloration occurs when NO emissions from combustion

sources react in the presence of atmospheric oxygen to form NO2, a reddish-brown gas.

Another form of atmospheric discoloration may be caused by particulate emissions and

secondary aerosols formed by gaseous precursor emissions. The visual range

reduction (increased haze) is caused primarily by particulate emissions and secondary

aerosols such as sulfates and nitrates.26 Both secondary sulfate and primary particulate

emissions are accounted for in the analysis. Emission of other pollutants do not

materially affect visibility.

U.S. EPA visibility impairment analysis guidelines were followed in conducting the

analysis. The analysis was performed for the Raccoon Creek State Park, located 16km

southwest of the proposed Shell site.

This analysis requires inputs of emission rates (PM and NOX), regional visual range,

distance between the source and the object of study, and worst-case dispersion

parameters (i.e., wind speed and stability). Outputs from the model include:

• Plume contrast against the sky and terrain; and,

• Perceptibility of the plume (Delta E criteria).

Emission rates for PM and NO2 for the analyses were set to 47.9 and 74.6 lb/hr,

respectively. These emissions represent the total facility proposed emissions. The

background visual range was set to 20km, which was determined from Figure 9 of the

VISCREEN manual. The VISCREEN default screening values for Delta E (2.0) and

contrast (0.05) were assumed.


7-2

The results visibility analysis are shown in Table 11. As shown, there should be no

plumes from the Shell facility visible at the Raccoon Creek park. The VISCREEN model

files are provided on the enclosed CD.


7-3

Table 11. Class II Visibility Analysis Results for Raccoon Creek State Park

Viewing Background

Theta (degrees)

Azimuth (degrees)

Distance (km)

Alpha (degrees)

Delta E Green Contrast Criterion Plume Criterion Plume

SKY 10 146 23 23 2 1.565 0.05 0.012 SKY 140 146 23 23 2 0.306 0.05 -0.01 TERRAIN 10 146 23 23 2 0.043 0.05 0.0 TERRAIN 140 146 23 23 2 0.01 0.05 0.0


8-1

8.0 CLASS I AREA IMPACTS 8.1 Class I AQRV Analysis There are three Class I areas located within 300km of the Shell facility.c Each Class I

area is located in excess of 50km from the proposed Shell facility. The FLM’s Q/D

(maximum daily emissions in tons per year over distance in kilometers) method was

used to determine the potential for adverse Air Quality Related Values ("AQRV")

impacts for each Class I area. AQRVs include impacts to Class I area soils, vegetation,

and visibility. The maximum Q/D value was calculated to be 3.9 (Q= 733.7 tpy, D = 189

km for Otter Creek). The Q/D evaluation has been presented to the FLMs. The FLMs

reviewed the Q/D evaluation and have stated that no Class I Air Quality Related Values

(AQRV) evaluation will be required for the proposed Shell facility.27

8.2 Class I Significant Impacts Analysis The air quality impacts at each Class I area within 300km was determined using

AERMOD. An arc of receptors spaced at 1 degree, located in the direction of the

Class I areas, was placed at 50km from the proposed Shell site (Figure 12). The model

results were compared to the proposed Class I significant impact levels (Table 12). As

shown, the impacts are less that the Class I SILs. The proposed facility will not

therefore threaten a Class I increment.

Table 12. Class I Significant Impact Analysis Results

Pollutant Averaging

Period


Proposed Class I

Significant Impact Level

(μg/m3) % Class I

SIL

PM10 24-hr 0.21 0.30 70%

Annual 0.01 0.20 6%

NO2 Annual 0.02 0.10 21%

c Class I areas are pristine areas (e.g., National Parks and Wilderness Areas) that have been designated by Congress and are afforded a greater degree of air quality protection. All other areas are designated as Class II areas.


8-2

Figure 12. Class I Areas Located within Three Hundred Kilometers of Shell and Modeled Receptors

Shenandoah

Shell Facility

Dolly Sods

Otter Creek

Arc or Receptors Spaced at 1 Degree, 50km from Shell

Virginia

Ohio

Pennsylvania

New YorkOntario

West VirginiaMaryland

Delaware

Michigan

Kentucky

New Jersey

®0 68,000 136,000 204,000 272,00034,000Meters

REFERENCES 1. Guidelines on Air Quality Models, (Revised). EPA-450/2-78-027R, Appendix W of 40 CFR Part 51, U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. November 2005. 2. February 19, 2014 letter from Andrew Fleck, PADEP, to David Keen, RTP Environmental. 3. Auer, Jr., A.H. "Correlation of Land Use and Cover with Meteorological Anomalies." Journal of Applied Meteorology, 17:636-643, 1978. 4. Haul Road Workgroup Final Report, EPA Region 5, December 6, 2011. 5. Engineering Guide #69, Air Dispersion Modeling Guidance. Ohio EPA, Division of Air Pollution Control, 2003. 6. Guideline for Determination of Good Engineering Practice Stack Height (Technical Support Document for Stack Height Regulations (Revised). EPA-450/4-80-023R, U.S. Environmental Protection Agency, June 1985. 7. Sierra Club v. EPA, No. 10-1413, 2013 WL 216018 (Jan. 22, 2013). 8. Ambient Monitor Guidelines for Prevention of Significant Deterioration, EPA-450/4-87-007, USEPA, May 1987. 9. Monitoring Guidelines at p. 9. 10. Responses to Public Comments on the Clean Air Act Prevention of Significant Deterioration of Air Quality Draft Permit for Energy Answers Arecibo, LLC. U.S. EPA Region 2. June 2013. Pages 92-94. 11. PSD Air Quality Modeling Analysis (Revised PM10/PM2.5 Analysis). Energy Answers Arecibo, LLC. Revised October 2011. 12. In the Matter of Hibbing Taconite Co., PSD Appeal No. 87-3, 2 E.A.D. 838 (Adm’r 1989). 13. In the Matter of Hibbing Taconite Co., PSD Appeal No. 87-3, 2 E.A.D. 838 (Adm’r 1989). 14. In re: Encogen Cogeneration Facility, PSD Appeal Nos. 98-22 through 98-24, 8 E.A.D. 244 (EAB 1999). 15. Supplemental Response to Public Comments for Outer Continental Shelf Prevention of Significant Deterioration Permits: Noble Discoverer Drillship. U.S. EPA Region 10. September 2011. Page 63.

16. Response to Public Comments: Diamond Wanapa I, L.P., Wanapa Energy Center. U.S. EPA Region 10. August 2005. Page 12. 17. Final Statement of Basis for Permit No. PSD-OU-0002-04.00: Deseret Power Electric Cooperative, Bonanza Power Plant, Waste Coal Fired Unit. U.S. EPA Region 8. August 2007. Page 155. 18. Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio Pico Energy Center. U.S. EPA Region 9. November 2012. Pages 37-44. 19. Fact Sheet and Ambient Air Quality Impact Report for a Clean Air Act Prevention of Significant Deterioration Permit: Pio Pico Energy Center. U.S. EPA Region 9. June 2012. Pages 28-29. 20. Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio Pico Energy Center. U.S. EPA Region 9. November 2012. Page 43. 21. In re: Pio Pico Energy Center. PSD Appeal Nos. 12-04 through 12-06. August 2, 2013. 22. AERMOD Implementation Guide, EPA, September 27, 2005. 23 . February 6, 2014 email from Alan Binder, PADEP, to Irene Kuo, RTP Environmental. 24. Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard, Memo from Tyler Fox, US EPA, to Regional Air Division Directors, March 1, 2011. 25. Workbook for Plume Visual Impact Screening and Analysis. US EPA, EPA Pub. No. 450/4-88-015. RTP, NC. September 1988. 26. Workbook for Estimating Visibility Impairment. US EPA, EPA Pub. No. 450/4-80-031. RTP, NC. November 1980. 27. February 11, 2014 email from Melanie Pitrolo, US Forest Service, to David Keen, RTP Environmental. February 12, 2014 email from Don Sheperd, National Parks Service, to David Keen, RTP Environmental. February 13, 2014 email from Claire O'Dea, US Forest Service, to David Keen, RTP Environmental.

ATTACHMENT A MODELED SOURCE INPUT DATA

Shell Franklin Model Input Data (NAD83, Zone 17)Point Source (updated 4/11/14)

Source ID Source Description Easting (X) (m)Northing (Y)

(m)

Base Elevation

(ft)Stack

Height (ft)Temperature

(°F)Exit Velocity

(ft/sec)

Stack Diameter

(ft)NO2 (lb/hr) NOx (lb/hr) CO (lb/hr)

PM‐ST (lb/hr)

PM‐LT (lb/hr)

EC#1 Ethane Cracking Furnace #1 555501.14 4502188.87 795.0 280.0 284.0 49.4 8.50 9.300 5.913 52.200 2.480 2.264EC#2 Ethane Cracking Furnace #2 555511.76 4502175.45 795.0 280.0 284.0 49.4 8.50 9.300 5.913 25.085 2.480 2.264EC#3 Ethane Cracking Furnace #3 555527.98 4502157.00 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#4 Ethane Cracking Furnace #4 555538.60 4502143.59 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#5 Ethane Cracking Furnace #5 555550.90 4502128.49 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#6 Ethane Cracking Furnace #6 555563.76 4502115.07 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264EC#7 Ethane Cracking Furnace #7 555579.42 4502098.86 795.0 280.0 284.0 49.4 8.50 6.200 5.913 25.085 2.480 2.264CTS Combustion Turbines 1‐3 555997.63 4502118.90 795.0 213.2 230.0 85.5 17.32 15.500 15.500 282.186 11.385 11.385GFLARE1 Ground Flare 1 555470.39 4502011.07 788.0 244.9 1832.0 65.62 29.83 18.270 2.795 497.043 7.507 0.230GFLARE2 Ground Flare 2 555420.07 4502085.43 788.0 244.9 1832.0 65.62 29.83 18.270 2.795 497.043 7.507 0.230HPFLARE HP Elevated Flare 555387.08 4502007.16 786.0 337.0 1832.0 65.62 4.14 3.516 3.516 19.131 0.289 0.289LPFLARE LP Ground Flare ‐ pilot 556466.10 4502507.88 795.0 75.0 1832.0 0.03 30.00 0.068 0.068 0.370 0.007 0.007REFFLARE Refrigerated Tank Flare 556042.79 4502603.60 795.0 256.1 1832.0 65.62 4.88 0.982 0.154 26.724 0.404 0.017INCIN LP Incinerator 556444.09 4502531.19 795.0 250.0 1600.0 82.6 4.50 7.017 7.017 8.499 0.769 0.769COI Caustic Oxidizer 555233.89 4502080.96 713.0 200.0 1600.0 45.0 2.00 0.729 0.729 3.966 0.080 0.080COOLTWR1 C li T 1 555836 14 4502495 23 795 0 70 0 71 0 20 0 45 00 0 000 0 000 0 000 0 106 0 106COOLTWR1 Cooling Tower 1 555836.14 4502495.23 795.0 70.0 71.0 20.0 45.00 0.000 0.000 0.000 0.106 0.106COOLTWR2 Cooling Tower 2 555858.65 4502515.06 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR3 Cooling Tower 3 555881.16 4502534.89 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR4 Cooling Tower 4 555903.67 4502554.73 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR5 Cooling Tower 5 555926.18 4502574.56 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125COOLTWR6 Cooling Tower 6 555948.69 4502594.40 795.0 70.0 71.0 20.0 52.00 0.000 0.000 0.000 0.125 0.125FWP1 Fire Water Pump 1 555233.89 4502089.91 713.0 30.0 885.0 113.0 1.00 0.033 0.033 4.012 0.074 0.003FWP2 Fire Water Pump 2 555226 06 4502080 96 713 0 30 0 885 0 113 0 1 00 0 033 0 033 4 012 0 074 0 003FWP2 Fire Water Pump 2 555226.06 4502080.96 713.0 30.0 885.0 113.0 1.00 0.033 0.033 4.012 0.074 0.003FWP3 Fire Water Pump 3 555252.33 4502079.29 713.0 30.0 885.0 113.0 1.00 0.033 0.033 4.012 0.074 0.003GEN1 Generator 1 556100.05 4502113.84 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002GEN2 Generator 2 556079.18 4502093.93 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002GEN3 Generator 3 556055.00 4502074.01 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002GEN4 Generator 4 556028.00 4502047.00 795.0 30.0 882.5 125.0 2.00 0.134 0.134 0.222 0.071 0.002

Volume Sources

Source ID Source Description Easting (X) Northing (Y)

Base Elevation

(ft)Release

Height (ft)

Horizontal Dimension

(ft)

Vertical Dimension

(ft) NO2 (lb/hr)NOx (lb/hr) CO (lb/hr)

PM‐ST (lb/hr)

PM‐LT (lb/hr)

PEBLD PE Blending Silos 556322.06 4502332.48 795.0 131.2 29.0 61.0 0.00 0.00 0.00 2.93E‐01 2.45E‐01PERC PE Rail Loading Silos 556359.33 4502324.12 795.0 151.0 66.7 70.2 0.00 0.00 0.00 1.90E‐01 1.38E‐01PETK PE Truck Loading Silos 556544.99 4502174.37 854.0 151.0 54.7 70.2 0.00 0.00 0.00 1.29E‐01 3.25E‐02PEU1 LDPE Vents 556263.39 4502415.83 795.0 131.2 30.4 61.0 0.00 0.00 0.00 2.50E‐01 2.47E‐01PEU2 LDPE Vents 556363.24 4502496.66 795.0 131.2 30.4 61.0 0.00 0.00 0.00 2.50E‐01 2.47E‐01PEU3 HDPE Vents 556183.45 4502346.54 795.0 131.2 30.4 61.0 0.00 0.00 0.00 2.13E‐01 2.13E‐01RD_1 PE Haul Road 556401.89 4501780.43 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_2 PE Haul Road 556379.96 4501801.60 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 3 PE Haul Road 556358 03 4501822 76 854 0 12 8 20 9 11 9 0 00 0 00 0 00 7 35E 04 2 15E 04RD_3 PE Haul Road 556358.03 4501822.76 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_4 PE Haul Road 556336.10 4501843.93 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_5 PE Haul Road 556314.16 4501865.10 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_6 PE Haul Road 556311.47 4501894.44 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_7 PE Haul Road 556329.12 4501918.33 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_8 PE Haul Road 556351.41 4501939.13 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 9 PE Haul Road 556373.70 4501959.92 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_9 PE Haul Road 556373.70 4501959.92 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E 04 2.15E 04RD_10 PE Haul Road 556395.98 4501980.71 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_11 PE Haul Road 556418.27 4502001.50 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_12 PE Haul Road 556440.56 4502022.29 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_13 PE Haul Road 556462.85 4502043.09 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_14 PE Haul Road 556485.13 4502063.88 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_15 PE Haul Road 556507.42 4502084.67 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_16 PE Haul Road 556529.71 4502105.46 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_17 PE Haul Road 556552.00 4502126.25 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_18 PE Haul Road 556574.28 4502147.04 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_19 PE Haul Road 556596.57 4502167.84 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_20 PE Haul Road 556618.86 4502188.63 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_21 PE Haul Road 556641.15 4502209.42 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_22 PE Haul Road 556662.22 4502230.89 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_23 PE Haul Road 556668.19 4502260.78 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_24 PE Haul Road 556652.46 4502284.45 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_25 PE Haul Road 556625.52 4502294.81 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_26 PE Haul Road 556599.22 4502286.50 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_27 PE Haul Road 556576.93 4502265.72 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 28 PE Haul Road 556554 63 4502244 94 854 0 12 8 20 9 11 9 0 00 0 00 0 00 7 35E 04 2 15E 04RD_28 PE Haul Road 556554.63 4502244.94 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_29 PE Haul Road 556532.33 4502224.15 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_30 PE Haul Road 556510.04 4502203.37 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_31 PE Haul Road 556487.74 4502182.59 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_32 PE Haul Road 556465.44 4502161.81 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_33 PE Haul Road 556448.37 4502137.37 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 34 PE Haul Road 556436.52 4502109.29 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04_3 au oad 556 36 5 50 09 9 85 0 8 0 9 9 0 00 0 00 0 00 35 0 5 0

Volume Sources

Source ID Source Description Easting (X) Northing (Y)

Base Elevation

(ft)Release

Height (ft)

Horizontal Dimension

(ft)

Vertical Dimension

(ft) NO2 (lb/hr)NOx (lb/hr) CO (lb/hr)

PM‐ST (lb/hr)

PM‐LT (lb/hr)

RD_35 PE Haul Road 556424.66 4502081.21 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_36 PE Haul Road 556412.80 4502053.14 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_37 PE Haul Road 556400.94 4502025.06 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_38 PE Haul Road 556382.32 4502001.71 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_39 PE Haul Road 556360.02 4501980.94 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_40 PE Haul Road 556337.71 4501960.17 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_41 PE Haul Road 556315.40 4501939.40 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_42 PE Haul Road 556297.28 4501915.14 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 43 PE Haul Road 556292 21 4501886 74 854 0 12 8 20 9 11 9 0 00 0 00 0 00 7 35E 04 2 15E 04RD_43 PE Haul Road 556292.21 4501886.74 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_44 PE Haul Road 556304.90 4501861.06 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_45 PE Haul Road 556326.72 4501839.79 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_46 PE Haul Road 556349.08 4501819.08 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_47 PE Haul Road 556371.55 4501798.48 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_48 PE Haul Road 556394.01 4501777.88 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD 49 PE Haul Road 556407.18 4501765.80 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E‐04 2.15E‐04RD_49 PE Haul Road 556407.18 4501765.80 854.0 12.8 20.9 11.9 0.00 0.00 0.00 7.35E 04 2.15E 04

Combustion Turbine Load Analysis Model Input

Source ID Source Description Easting (X) (m)Northing (Y)

(m)

Base Elevation

(ft)Stack


(°F)Exit Velocity

(ft/sec)

Equivalent Stack

Diameter (ft)

Unit Emission (lb/hr)

Combined Flue Area

(ft2)

Combined Flue Flow (acfm)

Individual Actual Flue Diameter (ft)

Single Turbine Flow (acfm)

3CT100 3 Turbines 100% Load 555997.63 4502118.90 795.0 213.2 230 85.5 17.32 3.00 235.6 1,208,259 10.0 402,7532CT100 2 Turbines 100% Load 555997.63 4502118.90 795.0 213.2 230 85.5 14.14 2.00 157.1 805,506,1CT100 1 Turbine 100% Load 555997.63 4502118.90 795.0 213.2 230 85.5 10.00 1.00 78.5 402,7531CT75 1 Turbine 75% Load 555997.63 4502118.90 795.0 213.2 230 68.4 10.00 0.82 78.5 322,2021CT45 1 Turbine 45% Load 555997.63 4502118.90 795.0 213.2 230 51.3 10.00 0.64 78.5 241,652Note: Turbine emissions and flow are decrease at lower loads though the relationship is not linear.

Shell Franklin Off‐Site Source Model Input Data (Only Sources within 10km of Shell Site) (NAD83, Zone 17)

Source ID

Stack Release Type (Beta)

FLAT (Non‐Default) Source Description

Easting (X) (m)

Northing (Y) (m)

Base Elevation

(ft)Stack


(°F)

Exit Velocity (ft/sec)

Stack Diameter

(ft)NO2 (lb/hr)

BASF_S02 BASF Thermal Oxidation Unit 555298 4501272 743.2 40.0 70 4.72 0.3 7.50AES_S02 AES Beaver Valley (No. 2 Boiler) 554599.9 4500896.1 754.8 200.0 135 53.20 7.8 385.0AES_S03 AES Beaver Valley (No. 3 Boiler) 554610.0 4500895.4 754.8 200.0 135 52.30 7.8 385.0AES_S04 AES Beaver Valley (No. 4 Boiler) 554619.5 4500892.5 755.0 200.0 135 58.60 7.8 385.0AES_S05 AES Beaver Valley (No. 5 Boiler) 554628.2 4500889.2 755.1 200.0 135 79.60 4.8 219.5NOVA_S01 Nova Chem Beaver Valley D3 D4 EPS 554033.5 4500593.4 755.0 40.0 460 71.90 4.8 4.40NOVA_Z07 Nova Chem Beaver Valley Gen Plant 554033.5 4500593.4 755.0 1.0 70 0.03 1.0 0.38EATON_S01 Eaton Boilers 557399 4504911 765.9 49.0 550 28.00 4.7 1.96ANCH_S01 Anchor Hocking Misc NG 560718 4504581 739.1 1.0 200 0.03 1.0 1.61ANCH_S02 Anchor Hocking Melt Tank 560718 4504581 739.1 100.0 800 4.33 5.0 17.20ANCH_S115 Anchor Hocking Dec LEHR 560718 4504581 739.1 1.0 70 0.03 1.0 0.23ANCH_Z01 Anchor Hocking Quench LEHR 560718 4504581 739.1 40.0 68 0.03 1.0 0.37ANCH_Z02 Anchor Hocking Anneal LEHR 560718 4504581 739.1 40.0 68 0.03 1.0 2.33ANCH_Z107 Anchor Hocking Glass Form Lub 560718 4504581 739.1 1.0 600 0.03 1.0 0.08FEBV_S01 First Energy Nuclear Beaver Valley Aux Boil A 548011.9 4497013.1 734.3 122.0 601 17.10 7.0 6.74FEBV_S02 First Energy Nuclear Beaver Valley Aux Boil B 548011.9 4497013.1 734.3 122.0 601 17.10 7.0 6.74FEBV_S101 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 635 0.03 1.0 156.0FEBV_S102 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 635 0.03 1.0 156.0FEBV_S103 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 900 0.03 1.0 173.3FEBV_S104 First Energy Nuclear Beaver Valley Dies Eng 548011.9 4497013.1 734.3 20.0 900 0.03 1.0 173.3FEBV_S105 First Energy Nuclear Beaver Valley Emg Res Gen 548011.9 4497013.1 734.3 1.0 1000 0.03 1.0 156.0FEBV_Z109 First Energy Nuclear Beaver Valley Misc 548011.9 4497013.1 734.3 1.0 70 0.03 1.0 375.9FEBM_S02 First Energy Bruce Mansfield (Unit #1) 549490.5 4498345.9 729.4 950.0 126 75.11 19.2 3959.0FEBM_S03 First Energy Bruce Mansfield (Unit #2) 549490.5 4498345.9 729.4 950.0 126 75.11 19.2 3959.0FEBM_S06 First Energy Bruce Mansfield (Unit #3) 549490.5 4498345.9 729.4 600.0 126 75.11 19.2 3959.0FEBM_S07 First Energy Bruce Mansfield (Aux Boils) 549490.5 4498345.9 729.4 136.0 585 6.89 12.0 129.02NGC_S09 NGC Ind Shippingport Board Dryer 548962 4497373 771.9 1.0 250 0.03 1.0 20.96NGC_S100 NGC Ind Shippingport IMP Mill 548962 4497373 771.9 30.0 350 53.10 2.0 15.72NGC_S11 NGC Ind Shippingport Cage Mill 548962 4497373 771.9 20.0 200 61.40 5.7 12.10USGYP_S1 US Gypsum S1 564369 4497719 740.5 54.0 203 50.20 8.5 7.46USGYP_S2 US Gypsum #1 Kettle 564369 4497719 740.5 97.0 600 139.00 1.4 4.21USGYP_S3 US Gypsum #2 Kettle 564369 4497719 740.5 98.0 600 139.00 1.4 4.21USGYP_S4 US Gypsum #1 Dryer Mill 564369 4497719 740.5 100.0 220 51.60 5.1 2.50USGYP_S5 US Gypsum #2 Dryer Mill 564369 4497719 740.5 100.0 220 51.60 5.1 2.50USGYP_S6 US Gypsum Gauging Water Heater 564369 4497719 740.5 25.0 600 52.40 0.9 0.49Offsite source data from PADEP. See workbook called "NOx Sources PA DEP Update 2‐6‐14".

Step 1: Adjusted Width of RoadRoad Width (ft) of 25 + 20 ft (6 m) = 45 ft

Step 2: Maximum No. of SourcesRoad Length (ft) of 4752 / Adj. Width = 106

Step 3: Height of VolumeVehicle height (ft) of 15 X 1.7 = 25.5 ft

Step 4: Initial Sigma Y (Horizontal Dimension)Adjusted road width (ft) of 45 / 2.15 = 20.93 ft

Step 5: Initial Sigma Z (Vertical Dimension)Height of volume (ft) of 25.5 / 2.15 = 11.86 ft

Step 6: Height of ReleaseHeight of volume (ft) of 25.5 / 2 = 13 ft

Step 7: Emission rateTotal PM10 short termemission rate (lb/hr) of 0.036 /# sources = 0.000735 lb/hr

Total PM10 annual emission rate (lb/hr) of 0.011 /# sources = 0.000215 lb/hr

Truck Roadway Volume Source Parameter Calculation

Model ID Source Description Length (ft) Width (ft)

Square Root of Area (ft)

Structure Height/Vertical Dimension (ft)

Release Height (ft)

Initial Horizontal

Dimension sY (ft)

Initial Vertical Dimension sZ (ft) Reference

PEBLD PE Blending Silos 190.0 82.0 124.8 131.2 131.2 29.03 61.0 Note 1, 2, and 3PERC PE Rail Loading Silos 235 0 350 0 286 8 151 0 151 0 66 70 70 2 Note 1 2 and 3

Shell Franklin Non-Road Volume Source Parameter CalculationSource Dimensions Initial Dispersion Coefficients

PERC PE Rail Loading Silos 235.0 350.0 286.8 151.0 151.0 66.70 70.2 Note 1, 2, and 3PETK PE Truck Loading Silos 235.0 235.0 235.0 151.0 151.0 54.65 70.2 Note 1, 2, and 3PEU1&2 LDPE Vents 190.0 90.0 130.8 131.2 131.2 30.41 61.0 Note 1, 2, and 3PEU3 HDPE Vents 190.0 90.0 130.8 131.2 131.2 30.41 61.0 Note 1, 2, and 3

Note 1: Release height equal to top of structure as process is aspirated and emissions will occur at the top of the structure.

Note 2: Sigma Y value calculated as the square root of the area, or average length of side, divided by 4.3 (Table 3-1 of AERMOD Manual for single volume source).

N 3 Si Z l f l d dj b ildi l l d h b ildi h i h di id d b 2 1 (T bl 3 1 f AERMOD M l f El d S Adj B ildi )

Note 2: Sigma Y value calculated as the square root of the area, or average length of side, divided by 4.3 (Table 3-1 of AERMOD Manual for single volume source).

Note 3: Sigma Z values for elevated sources on or adjacent to a building calculated as the building height divided by 2.15 (Table 3-1 of AERMOD Manual for Elevated Source on or Adjacent to Building).

ATTACHMENT B MODEL SUMMARY RESULTS

Turbine Load Analysis Results (4/14/14)Model File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 1CT100 1ST 2.19036 556514.8 4502316.1 246.73 342.68 0 8071201 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 1CT100 1ST 2.13971 556950 4501600 312.31 336.53 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 1CT100 1ST 1.95197 556100 4501150 336.46 340.15 0 7062704 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 1CT100 1ST 1.72661 557250 4502450 319.18 341.93 0 6031103 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 1CT100 1ST 1.71558 556514.8 4502316.1 246.73 342.68 0 10051005 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.77824 556467.42 4502258.8 249.95 337.02 0 6100901 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.75547 556377.51 4502171.9 244.21 337.02 0 10052704 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.685 556514.8 4502316.1 246.73 342.68 0 8071201 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.68326 556000 4501150 324.2 340.28 0 7062704 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 1CT45 1ST 1.51032 556950 4501800 323.1 334.23 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 1CT75 1ST 2.01595 556514.8 4502316.1 246.73 342.68 0 8071201 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.8708 556050 4501100 338.92 338.92 0 7062704 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.85049 556950 4501700 333.51 333.51 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.76011 556431.02 4502224.5 248.96 337.02 0 6100901 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 1CT75 1ST 1.68973 556377.51 4502171.9 244.21 337.02 0 10052704 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.83105 557150 4500900 293.37 358.2 0 9020901 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.63299 557550 4502350 341.79 341.79 0 6031103 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.52732 554700 4502500 330.67 347.29 0 7090623 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.41952 557550 4502700 336.01 341.15 0 10061722 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 2CT100 1ST 2.32568 554950 4502700 322.91 344 0 8042522 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 1‐HR 3CT100 1ST 3.13463 556427.79 4503499.6 208.13 355.56 43 10102524 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.98092 557250 4502300 333.8 333.8 0 9121623 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.9547 554450 4502850 337.79 352.07 0 7090623 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.86316 554600 4502550 343.41 343.41 0 6050124 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 1‐HR 3CT100 1ST 2.70158 555000 4502900 343.75 343.75 0 8042522 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.37783 556527.97 4502337.3 244.53 343.02 0 10030724 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.35014 556514.8 4502316.1 246.73 342.68 0 6071624 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.31997 557150 4502350 319.7 337.02 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.28571 557100 4502750 308.85 338.9 0 8081824 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 1CT100 1ST 0.2537 556613.73 4502595.8 239.26 343.02 0 9042524 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.37448 556514.8 4502316.1 246.73 342.68 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.34631 556501.63 4502294.8 248.75 340.98 0 8110624 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.30837 556514.8 4502316.1 246.73 342.68 0 10030824 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.29934 556527.97 4502337.3 244.53 343.02 0 6071624 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 1CT45 1ST 0.22955 556514.8 4502316.1 246.73 342.68 0 9071324 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.35835 556514.8 4502316.1 246.73 342.68 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.34906 556514.8 4502316.1 246.73 342.68 0 10030824 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.34168 556514.8 4502316.1 246.73 342.68 0 6071624 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.33155 556485.61 4502275.9 250.09 337.02 0 8110624 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 1CT75 1ST 0.24805 556514.8 4502316.1 246.73 342.68 0 9071324 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.45935 556716.34 4502861.8 241.65 343.02 43 10011424 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.40525 556767.7 4502692.1 244.96 345.63 0 9042524 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.37981 556716.34 4502861.8 241.65 343.02 43 8060924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load 2006 UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.35088 556675.12 4502952.9 237.04 343.02 43 6121424 Beaver Valley 2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24 HR 2CT100 1ST 0.35088 556675.12 4502952.9 237.04 343.02 43 6121424 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 2CT100 1ST 0.34414 557400 4502250 327.4 343.02 0 7090324 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.52878 556716.34 4502861.8 241.65 343.02 43 10011424 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.5165 556716.34 4502861.8 241.65 343.02 43 8060924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.48703 556767.7 4502692.1 244.96 345.63 0 9042524 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.43403 556675.12 4502952.9 237.04 343.02 43 6121424 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 24‐HR 3CT100 1ST 0.40037 555350 4503200 286.28 354.3 0 7101824 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.74701 556514.8 4502316.1 246.73 342.68 0 10072208 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.74338 556501.63 4502294.8 248.75 340.98 0 9071308 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.73303 556501.63 4502294.8 248.75 340.98 0 6070708 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.72687 556527.97 4502337.3 244.53 343.02 0 7092908 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 1CT100 1ST 0.65924 556527.97 4502337.3 244.53 343.02 0 8081208 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.76737 556514.8 4502316.1 246.73 342.68 0 6070708 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.68269 556514.8 4502316.1 246.73 342.68 0 9071308 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.67047 556527.97 4502337.3 244.53 343.02 0 7092908 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.6624 556467.42 4502258.8 249.95 337.02 0 8110608 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 1CT45 1ST 0.60142 556074.06 4501874.4 230.65 340.28 0 10020624 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.81153 556514.8 4502316.1 246.73 342.68 0 6070708 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.77022 556527.97 4502337.3 244.53 343.02 0 7092908 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.74029 556514.8 4502316.1 246.73 342.68 0 9071308 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.70358 556527.97 4502337.3 244.53 343.02 0 10072208 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 1CT75 1ST 0.61544 556449.22 4502241.6 249.36 337.02 0 8110608 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.97598 556158.1 4501507.2 289.58 340.28 0 10020624 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.92486 557100 4502750 308.85 338.9 0 9121208 Beaver_Valley_2009.SFC 5 5 22746

AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.88641 556150 4501400 311.92 338.71 0 7081808 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.8544 557050 4502450 308.54 337.02 0 8010924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 2CT100 1ST 0.84672 556675.12 4502952.9 237.04 343.02 43 6121408 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.14705 556200 4501350 324.98 324.98 0 10020624 Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.10107 556675.12 4502952.9 237.04 343.02 43 6121408 Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.05795 556150 4501300 325.05 337.73 0 7081808 Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.01181 557250 4502400 331.76 336.42 0 8010924 Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT 8‐HR 3CT100 1ST 1.00734 557350 4502800 334.15 338.9 0 9121208 Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03869 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03435 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03272 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.03024 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 1CT100 1ST 0.02856 556779.2 4502644.4 255.07 343.02 0 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.03879 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.03579 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.03212 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.02946 556604.22 4502546.7 239.74 343.02 0 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 1CT45 1ST 0.02853 556604.22 4502546.7 239.74 343.02 0 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.03981 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.03605 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.0328 556613.73 4502595.8 239.26 343.02 0 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.0303 556527.97 4502337.3 244.53 343.02 0 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 1CT75 1ST 0.02887 556604.22 4502546.7 239.74 343.02 0 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.0399 557250 4502300 333.8 333.8 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03658 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03555 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03217 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 2CT100 1ST 0.03028 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2007.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2010_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.04 557700 4501900 352.7 353.04 0 1 YEARS Beaver_Valley_2010.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2006_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03681 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2006.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2009_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03473 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2009.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2008_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03152 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2008.SFC 5 5 22746AerMod 13350 Shell Franklin CT Load_2007_UNIT.SUM UNIT ANNUAL 3CT100 1ST 0.03038 556757.56 4502770.7 238.99 345.63 43 1 YEARS Beaver_Valley_2007.SFC 5 5 22746

Turbine Load Analysis Results (4/14/14)Pollutant Average Group Rank Conc.UNIT 1‐HR 3CT100 1ST 3.13UNIT 1‐HR 2CT100 1ST 2.83UNIT 1‐HR 1CT100 1ST 2.19UNIT 1‐HR 1CT75 1ST 2.02UNIT 1‐HR 1CT45 1ST 1.78UNIT 24‐HR 3CT100 1ST 0.53UNIT 24‐HR 2CT100 1ST 0.46UNIT 24‐HR 1CT100 1ST 0.38UNIT 24‐HR 1CT75 1ST 0.36UNIT 24‐HR 1CT45 1ST 0.37UNIT 24‐HR 1CT45 1ST 0.37UNIT 8‐HR 3CT100 1ST 1.15UNIT 8‐HR 2CT100 1ST 0.98UNIT 8‐HR 1CT100 1ST 0.75UNIT 8‐HR 1CT75 1ST 0.81UNIT 8‐HR 1CT45 1ST 0.77UNIT ANNUAL 3CT100 1ST 0.040UNIT ANNUAL 2CT100 1ST 0.040UNIT ANNUAL 1CT100 1ST 0.039UNIT ANNUAL 1CT75 1ST 0.040UNIT ANNUAL 1CT45 1ST 0.039

Worst Case Furnace Analysis Results (4/14/14)Model File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#1 1ST 1.80809 554350 4502650 352.99 352.99 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#1 1ST 1.54581 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#1 1ST 1.49846 554150 4503950 371.21 371.21 0 10040122 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#1 1ST 1.26121 553300 4502200 360.14 360.14 0 8102303 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#1 1ST 1.2507 554350 4502650 352.99 352.99 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#2 1ST 1.79526 554350 4502650 352.99 352.99 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#2 1ST 1.52881 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#2 1ST 1.4812 554150 4503950 371.21 371.21 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#2 1ST 1.22966 554350 4502650 352.99 352.99 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#2 1ST 1.19096 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#3 1ST 1.69294 554350 4502600 352.26 352.26 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#3 1ST 1.5251 554050 4503400 361.55 361.55 0 10043024 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#3 1ST 1.50136 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#3 1ST 1.27648 553300 4502200 360.14 360.14 0 8032922 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#3 1ST 1.19496 554400 4502600 351.12 351.12 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#4 1ST 1.47894 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#4 1ST 1.45098 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#4 1ST 1.28151 554150 4503500 364.13 364.13 0 7092523 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#4 1ST 1.18378 554350 4502600 352.26 352.26 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#4 1ST 1.1539 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#5 1ST 1.52046 554350 4502600 352.26 352.26 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#5 1ST 1.45159 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#5 1ST 1.44593 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#5 1ST 1.1764 554350 4502600 352.26 352.26 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#5 1ST 1.13989 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#6 1ST 1.44662 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#6 1ST 1.42328 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#6 1ST 1.34588 554350 4502600 352.26 352.26 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#6 1ST 1.15432 554350 4502600 352.26 352.26 0 6100619 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#6 1ST 1.12933 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 1‐HR EC#7 1ST 1.44529 554200 4503950 369.64 369.64 0 10120920 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 1‐HR EC#7 1ST 1.37452 555000 4502900 343.75 343.75 0 9120121 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 1‐HR EC#7 1ST 1.35683 554400 4502550 350.78 350.78 0 7090623 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 1‐HR EC#7 1ST 1.13309 554350 4502700 353.36 353.36 0 6041101 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 1‐HR EC#7 1ST 1.12227 554150 4503500 364.13 364.13 0 8110418 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#1 1ST 0.17884 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#1 1ST 0.13557 557650 4501450 357.99 371.48 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#1 1ST 0.13174 557700 4502550 342.06 343.16 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#1 1ST 0.12124 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#1 1ST 0.12074 557700 4501550 362.03 371.48 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#2 1ST 0.17908 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#2 1ST 0.13777 554600 4502550 343.41 343.41 0 10032824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#2 1ST 0.13609 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace 2009 UNIT.SU UNIT 24‐HR EC#2 1ST 0.13172 554150 4503550 364.24 364.24 0 9020624 Beaver Valley 2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24 HR EC#2 1ST 0.13172 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#2 1ST 0.12317 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#3 1ST 0.17805 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#3 1ST 0.13794 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#3 1ST 0.13753 557700 4502500 341.93 341.93 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#3 1ST 0.13021 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#3 1ST 0.12558 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#4 1ST 0.17827 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#4 1ST 0.16002 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#4 1ST 0.14192 554400 4502550 350.78 350.78 0 10032824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#4 1ST 0.13909 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#4 1ST 0.12729 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#5 1ST 0.1762 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#5 1ST 0.15857 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#5 1ST 0.14247 557250 4502350 336.13 336.13 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#5 1ST 0.13998 557650 4501400 358.01 359.95 0 7031824 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#5 1ST 0.12924 557800 4501500 371.88 371.88 0 6110224 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#6 1ST 0.17495 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#6 1ST 0.17482 554400 4502550 350.78 350.78 0 8051124 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#6 1ST 0.15939 554400 4502600 351.12 351.12 0 7090624 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#6 1ST 0.14763 557250 4502350 336.13 336.13 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#6 1ST 0.14575 554400 4502550 350.78 350.78 0 6050924 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 24‐HR EC#7 1ST 0.17115 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 24‐HR EC#7 1ST 0.1702 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 24‐HR EC#7 1ST 0.16155 554400 4502600 351.12 351.12 0 7090624 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 24‐HR EC#7 1ST 0.15238 557250 4502350 336.13 336.13 0 10030824 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 24‐HR EC#7 1ST 0.14847 554400 4502550 350.78 350.78 0 6050924 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#1 1ST 0.39608 554350 4502950 347.56 347.56 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#1 1ST 0.3562 557700 4501250 353.35 353.35 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#1 1ST 0.35119 557650 4501450 357.99 371.48 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#1 1ST 0.3411 557700 4501550 362.03 371.48 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#1 1ST 0.28288 557800 4501500 371.88 371.88 0 6110208 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#2 1ST 0.39539 554350 4502950 347.56 347.56 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#2 1ST 0.363 554400 4502600 351.12 351.12 0 10032808 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#2 1ST 0.35165 557650 4501450 357.99 371.48 0 7031808 Beaver_Valley_2007.SFC 7 7 22746

AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#2 1ST 0.3381 557700 4501550 362.03 371.48 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#2 1ST 0.28393 557800 4501500 371.88 371.88 0 6110208 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#3 1ST 0.39267 554400 4502900 346.63 346.63 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#3 1ST 0.36172 557700 4501250 353.35 353.35 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#3 1ST 0.35618 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#3 1ST 0.33828 557750 4501500 364.08 372.11 0 9120524 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#3 1ST 0.31206 554050 4503350 361.71 361.71 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#4 1ST 0.39028 554400 4502900 346.63 346.63 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#4 1ST 0.36476 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#4 1ST 0.35949 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#4 1ST 0.35452 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#4 1ST 0.34182 554050 4503350 361.71 361.71 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#5 1ST 0.38863 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#5 1ST 0.36869 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#5 1ST 0.36221 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#5 1ST 0.35339 554150 4503200 357.68 357.68 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#5 1ST 0.35073 554150 4503550 364.24 364.24 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#6 1ST 0.39261 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#6 1ST 0.38689 554550 4502600 347.25 347.25 0 8082308 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#6 1ST 0.37192 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#6 1ST 0.3648 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#6 1ST 0.35391 554150 4503200 357.68 357.68 0 6012824 Beaver_Valley_2006.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2009_UNIT.SU UNIT 8‐HR EC#7 1ST 0.38399 554150 4503500 364.13 364.13 0 9020624 Beaver_Valley_2009.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2008_UNIT.SU UNIT 8‐HR EC#7 1ST 0.379 554350 4502900 349.57 349.57 0 8082224 Beaver_Valley_2008.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2010_UNIT.SU UNIT 8‐HR EC#7 1ST 0.3755 557750 4501150 356.79 356.79 0 10030508 Beaver_Valley_2010.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2007_UNIT.SU UNIT 8‐HR EC#7 1ST 0.36703 557650 4501400 358.01 359.95 0 7031808 Beaver_Valley_2007.SFC 7 7 22746AerMod 13350 Shell Franklin Worst Case Furnace_2006_UNIT.SU UNIT 8‐HR EC#7 1ST 0.34565 554150 4503200 357.68 357.68 0 6012824 Beaver_Valley_2006.SFC 7 7 22746

Worst Case Furnace Analysis Results (4/14/14)Pollutant Average Group Rank Conc.UNIT 1‐HR EC#1 1ST 1.81UNIT 1‐HR EC#2 1ST 1.80UNIT 1‐HR EC#3 1ST 1.69UNIT 1‐HR EC#4 1ST 1.48UNIT 1‐HR EC#5 1ST 1.52UNIT 1‐HR EC#6 1ST 1.45UNIT 1‐HR EC#7 1ST 1.45UNIT 24‐HR EC#1 1ST 0.18UNIT 24‐HR EC#2 1ST 0.18UNIT 24‐HR EC#3 1ST 0.18UNIT 24‐HR EC#4 1ST 0.18UNIT 24‐HR EC#5 1ST 0.18UNIT 24‐HR EC#6 1ST 0.17UNIT 24‐HR EC#7 1ST 0.17UNIT 8‐HR EC#1 1ST 0.40UNIT 8‐HR EC#2 1ST 0.40UNIT 8‐HR EC#2 1ST 0.40UNIT 8‐HR EC#3 1ST 0.39UNIT 8‐HR EC#4 1ST 0.39UNIT 8‐HR EC#5 1ST 0.39UNIT 8‐HR EC#6 1ST 0.39UNIT 8‐HR EC#7 1ST 0.38

4/14/14 ‐ Shell Franklin Class II SIL Model ResultsModel File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin Significance_2006_CO.SUM CO 1‐HR ALL 1ST 357.82418 554800 4502350 267.42 353.88 0 6100901 Beaver_Valley_2006.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2007_CO.SUM CO 1‐HR ALL 1ST 339.61616 557850 4501500 370.83 371.72 0 7010622 Beaver_Valley_2007.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2008_CO.SUM CO 1‐HR ALL 1ST 315.97833 557800 4501500 371.88 371.88 0 8032102 Beaver_Valley_2008.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2009_CO.SUM CO 1‐HR ALL 1ST 433.87082 554850 4502500 249.13 359.4 0 9062302 Beaver_Valley_2009.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2010_CO.SUM CO 1‐HR ALL 1ST 335.32911 557750 4501650 360.42 363.17 0 10121101 Beaver_Valley_2010.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2006_CO.SUM CO 8‐HR ALL 1ST 114.82163 554400 4501950 266.67 353.88 0 6112508 Beaver_Valley_2006.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2007_CO.SUM CO 8‐HR ALL 1ST 150.27682 557800 4501500 371.88 371.88 0 7031808 Beaver_Valley_2007.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2008_CO.SUM CO 8‐HR ALL 1ST 105.22263 554400 4501950 266.67 353.88 0 8092408 Beaver_Valley_2008.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2009_CO.SUM CO 8‐HR ALL 1ST 168.74595 557800 4501500 371.88 371.88 0 9120524 Beaver_Valley_2009.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2010_CO.SUM CO 8‐HR ALL 1ST 133.21505 557800 4501500 371.88 371.88 0 10012908 Beaver_Valley_2010.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_5yrs_NO2.SUM NO2 1ST‐HIGHEST MAX DAILY 1 ALL 1ST 55.27977 554200 4503950 369.64 369.64 0 5 YEARS Beaver_Valley_6_10.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2006_NOX.SUM NOX ANNUAL ALL 1ST 0.7882 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2006.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2007_NOX.SUM NOX ANNUAL ALL 1ST 0.79555 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2007.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2008_NOX.SUM NOX ANNUAL ALL 1ST 0.80139 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2008.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2009_NOX.SUM NOX ANNUAL ALL 1ST 0.7874 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2009.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2010_NOX.SUM NOX ANNUAL ALL 1ST 1.05445 557250 4502350 336.13 336.13 0 1 YEARS Beaver_Valley_2010.SFC 22 1 22746AerMod 13350 Shell Franklin Significance_2006_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.79273 556485.61 4502275.9 250.09 337.02 0 1 YEARS Beaver_Valley_2006.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2007_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.72996 556501.63 4502294.8 248.75 340.98 0 1 YEARS Beaver_Valley_2007.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2008_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.72323 556485.61 4502275.9 250.09 337.02 0 1 YEARS Beaver_Valley_2008.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2009_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.70918 556485.61 4502275.9 250.09 337.02 0 1 YEARS Beaver_Valley_2009.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2010_PM‐LT.SUM PM‐LT ANNUAL ALL 1ST 0.79985 556501.63 4502294.8 248.75 340.98 0 1 YEARS Beaver_Valley_2010.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2006_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.03771 556716.34 4502861.8 241.65 343.02 43 6101524 Beaver_Valley_2006.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2007_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.70084 556633.89 4503044 234.29 341.93 43 7090324 Beaver_Valley_2007.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2008_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 4.143 556716.34 4502861.8 241.65 343.02 43 8110624 Beaver_Valley_2008.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2009_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.326 557800 4501500 371.88 371.88 0 9120524 Beaver_Valley_2009.SFC 83 1 22746AerMod 13350 Shell Franklin Significance_2010_PM‐ST.SUM PM‐ST 24‐HR ALL 1ST 3.98477 556716.34 4502861.8 241.65 343.02 43 10100824 Beaver_Valley_2010.SFC 83 1 22746

4/14/14 ‐ Shell Franklin Class II SIL Model ResultsPollutant Average Group Rank Conc. Background Total Standard % Standard Analysis CommentPM‐ST 24‐HR ALL 1ST 4.14 NA 4.1 5 83% Class II SignificancePM‐LT ANNUAL ALL 1ST 0.80 NA 0.80 1 80% Class II Significance

NOx ANNUAL ALL 1ST 0.79 NA 0.8 1 79% Class II SignificanceNO2 1ST‐HIGHEST MAX DAILY 1 ALL 1ST 44.2 NA 44.2 7.5 590% Class II Significance

CO 1‐HR ALL 1ST 433.9 NA 433.9 2000 22% Class II SignificanceCO 8‐HR ALL 1ST 168.7 NA 168.7 500 34% Class II SignificanceNotes:1) 1‐hr NO2 impacts include ARM of 0.8 for 1‐hr and 0.75 for annual.

4/14/14 ‐ Shell Franklin Class I SIL Model ResultsModel File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups Receptorsg p / p ( ) ( ) g p pAerMod 13350 Shell Franklin Class I Significance_2006_NOX.SUMNOX ANNUAL ALL 1ST 0.02677 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2006.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2007_NOX.SUMNOX ANNUAL ALL 1ST 0.0283 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2007.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2008_NOX.SUMNOX ANNUAL ALL 1ST 0.02242 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2008.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2009_NOX.SUMNOX ANNUAL ALL 1ST 0.02278 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2009.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2010_NOX.SUMNOX ANNUAL ALL 1ST 0.0272 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2010.SFC 22 1 40AerMod 13350 Shell Franklin Class I Significance_2006_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.01052 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2006.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2007_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.01113 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2007.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2008_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.00868 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2008.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2009_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.00867 568938.58 4453822.6 378.7 436.9 0 1 YEARS Beaver_Valley_2009.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2010_PM‐LT.SU PM‐LT ANNUAL ALL 1ST 0.01059 588800.58 4464383.4 375.2 375.2 0 1 YEARS Beaver_Valley_2010.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2006_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.1617 580997.63 4458817.6 368.6 368.6 0 6012124 Beaver_Valley_2006.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2007_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.20107 568938.58 4453822.6 378.7 436.9 0 7081324 Beaver_Valley_2007.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2008_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.21069 588800.58 4464383.4 375.2 375.2 0 8092824 Beaver_Valley_2008.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2009_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.14874 588800.58 4464383.4 375.2 375.2 0 9022424 Beaver_Valley_2009.SFC 83 1 40AerMod 13350 Shell Franklin Class I Significance_2010_PM‐ST.SU PM‐ST 24‐HR ALL 1ST 0.18756 588800.58 4464383.4 375.2 375.2 0 10030424 Beaver_Valley_2010.SFC 83 1 40

4/14/14 ‐ Shell Franklin Class I SIL Model ResultsPollutant Average Group Rank Conc. Background Total Standard % Standard Analysis CommentNOx ANNUAL ALL 1ST 0.02 NA 0.02 0.1 21% Class I Significance

PM‐LT ANNUAL ALL 1ST 0.01 NA 0.01 0.2 6% Class I SignificancePM‐ST 24‐HR ALL 1ST 0.21 NA 0.21 0.3 70% Class I SignificanceNotes:1) NO2 impact includes ARM adjustment of 0.75.

2/8/14 ‐ Shell NAAQS Analysis ResultsModel File Pollutant Average Group Rank Conc/Dep East (X) North (Y) Elev Hill Flag Time Met File Sources Groups ReceptorsAerMod 13350 Shell Franklin NAAQS_5yrs_NO2.SUM NO2 8TH‐HIGHEST MAX DAILY 1ALL 1ST 3644.0311 554050 4500600 230.12 352.23 0 5 YEARS Beaver_Valley_6_10.SFC 57 3 9384

2/8/14 ‐ Shell NAAQS Analysis ResultsPollutant Average Group Rank Conc. Background Total Standard % Standard Analysis CommentNO2 8TH‐HIGHEST MAX DAILY 1ALL 1ST 3644.0 NA 3644.0 188 1938% NAAQS Shell not significant at exceedenceNotes: 1) NO2 background from Beaver Falls added to AERMOD results within the model. 2) Shell does not cause or contribute to exceedence. Maximum Shell impact as paired in time and space with an existing exceedence is 5.96 ug/m3. See MAXDCONT output.

Visual Effects Screening Analysis forSource: Shell

Class I Area: Raccoon Creek

*** Level-1 Screening *** Input Emissions for

Particulates 47.90 LB /HR NOx (as NO2) 74.60 LB /HR Primary NO2 0.00 LB /HR Soot 0.00 LB /HR Primary SO4 0.00 LB /HR

**** Default Particle Characteristics Assumed

Transport Scenario Specifications:

Background Ozone: 0.04 ppm Background Visual Range: 20.00 km Source-Observer Distance: 16.00 km Min. Source-Class I Distance: 23.00 km Max. Source-Class I Distance: 23.00 km Plume-Source-Observer Angle: 11.25 degrees Stability: 6 Wind Speed: 1.00 m/s

R E S U L T S

Asterisks (*) indicate plume impacts that exceed screening criteria

Maximum Visual Impacts INSIDE Class I AreaScreening Criteria ARE NOT Exceeded

Delta E Contrast =========== ============ Backgrnd Theta Azi Distance Alpha Crit Plume Crit Plume ======== ===== === ======== ===== ==== ===== ==== ===== SKY 10. 146. 23.0 23. 2.00 1.565 0.05 0.012 SKY 140. 146. 23.0 23. 2.00 0.306 0.05 -0.010 TERRAIN 10. 146. 23.0 23. 2.00 0.043 0.05 0.000 TERRAIN 140. 146. 23.0 23. 2.00 0.010 0.05 0.000

Maximum Visual Impacts OUTSIDE Class I AreaScreening Criteria ARE Exceeded

Delta E Contrast =========== ============ Backgrnd Theta Azi Distance Alpha Crit Plume Crit Plume ======== ===== === ======== ===== ==== ===== ==== ===== SKY 10. 20. 10.5 149. 2.00 2.308* 0.05 0.018 SKY 140. 20. 10.5 149. 2.00 0.531 0.05 -0.015 TERRAIN 10. 1. 1.0 168. 2.00 2.686* 0.05 0.029 TERRAIN 140. 1. 1.0 168. 2.00 0.736 0.05 0.029

Appendix D Information contained in this appendix constitutes Trade Secret and/or Confidential

Proprietary Information as defined in the Pennsylvania Right to Know Law

THIS APPENDIX HAS BEEN REDACTED

FROM THIS COPY OF THE PLAN APPROVAL APPLICATION

CONFIDENTIAL

APPENDIX E

25 PA. CODE §127.205(5) ANALYIS

1. Introduction

Pennsylvania air regulations, 25 Pa. Code §127.205(5), require that a major new or modified

facility provide an “analysis … of alternative sites, sizes, production processes and

environmental control techniques, which demonstrates that the benefits of the proposed facility

significantly outweigh the environmental and social costs imposed within this Commonwealth as

a result of its location, construction or modification.” This appendix provides the required

§127.205(5) analysis based on information available as of the date of this Plan Approval

application. Certain additional environmental and economic evaluations are anticipated to be

completed during the period when this Plan Approval application is under review, and Shell will

supplement the information contained in this appendix as appropriate to reflect the results of

those evaluations.

2. Analysis of Alternative Sites, Sizes, Production Processes and Environmental

Control Techniques

The fundamental Project purpose is to develop a petrochemical facility in the northeastern

United States that is capable of utilizing locally available ethane, a component of the liquids-rich

natural gas being produced in the western half of the Marcellus Shale and in the Utica Shale, to

make various grades of polyethylene, providing a critical material to the wide range of

polyethylene users in the region. Project alternatives (sites, processes, sizes, and environmental

control techniques) have been evaluated to minimize and mitigate environmental impacts.

2.1 Alternative Sites

Currently, most ethane cracking/ethylene and polyethylene manufacturing capacity is located in

the U.S. Gulf Coast region, a considerable distance from both the ethane producing areas of the

Marcellus/Utica Shales and many of the polyethylene using industries of the Northeastern and

Midwest regions. A fundamental objective of the Project was to site the facility in that portion of

the northeastern U.S. with relative proximity to both ethane sources associated with the “wet

gas” sections of the Marcellus and Utica formations, and to polyethylene customers. Potential

sites outside the region (such as another site along the Gulf Coast) would necessitate

development of new pipeline capacity transport ethane derived from the Marcellus and Utica

shales more than 1,000 miles, and in turn require transportation of the polyethylene back via rail,

truck or barge to the region’s polyethylene users.

Accordingly, the Project’s siting process focused on the Appalachia region in Ohio,

Pennsylvania and West Virginia. With respect to potential sites in the Appalachia region, Shell

employed a detailed site selection process utilizing multiple criteria in identifying a number of

potential sites before ultimately choosing the proposed site. As discussed below, key factors

included site size and constructability (a minimum of 250 acres); safety; relative environmental

impacts; land use compatibility; access to transportation infrastructure, including pipelines,

marine, rail and road; the availability of skilled local labor, both for construction and operation;

and access to the power grid. The governors of the target states also expressed a preference for

building the facility on a “brownfield” (former or existing industrial) site, redeveloping it for the

new use.

Starting with 44 potential sites in three states, each location was reviewed based on its ability to

satisfy key criteria. A short list of four potentially acceptable sites was derived.

Further assessments were conducted of the four sites. The selected site in Potter and Center

Townships, near Monaca, Pennsylvania scored highest on virtually all criteria, including safety

and environmental, land acquisition, workforce, community, constructability and operating costs.

The advantages of the selected site include:

• Logistical access – For safety and logistics, the Project’s construction and operations

depend on suitable transport options via ship, barge, road, rail and pipeline. The

preferred site satisfies these requirements. The site is located less than one mile from

a four-lane interstate, minimizing impacts on local traffic and road safety concerns.

The Ohio River will provide transport for construction supplies, removing traffic

from roads, and rail will be a key conduit for supplies and products.

• Lowest risk to public safety from traffic – Due to the volume of worker traffic and

movement of materials by truck during construction and truck traffic during

operations, the Project requires proximity to highway transport for access and to

ensure public safety. Of the final sites evaluated, the preferred site was located

closest to an interstate. Certain road upgrades and expansions will be warranted,

particularly for the construction phase, and the Project is proactively working with

local and state authorities to implement those upgrades.

• Fewest residential communities in/near site – Of all the top-ranked sites, the

preferred site is surrounded by the fewest number of residential and commercial

neighbors on its fenceline. The Project has obtained options to purchase property

from the few nearby residences and businesses to ensure an appropriate safety buffer.

This location, in an existing industrial area, will limit possible disturbances to the

surrounding community (such as noise, light, and traffic). The Project also considered

broad environmental justice factors to determine whether any of the final sites

presented considerable differences in sensitivity to industrial development. The

preferred site’s characteristics had the least potential environmental justice impacts.

• Minimal environmentally sensitive areas –

o The selected site is a brownfield location that will be redeveloped and addressed

under Pennsylvania Act 2 requirements for the new use. Project development also

will provide a long-term caretaker to manage the environmental impacts that have

accrued over a century of industrial use.

o Because of the site’s long history of industrial use in an industrial corridor, no

critical habitats for any threatened or endangered species as listed by the US Fish

& Wildlife Service or the state were identified on or adjacent to the site during

site selection evaluation.

o A Pennsylvania Natural Diversity Inventory (PNDI) search identified two types of

freshwater mussels listed as Special Concern Species by the Pennsylvania Fish

and Boat Commission as potentially present in the Ohio River. During an

evaluation of areas to be used for docks or other purposes, and working in

accordance with regulatory guidelines, trained crews found and relocated

specimens of these mussel species to undisturbed locations.

o The site includes approximately five acres of wetlands, which will be replaced in

accordance with regulatory guidelines. Site construction may impact several

streams which traverse the site, and the Project is working with regulatory

authorities on appropriate mitigation measures, including creating, recreating,

enhancing and preserving in-kind habitats. Planned mitigations also will help

better control run-off from the site into the river and groundwater.

• Water supply – The site’s proximity to the Ohio River provides access to the water

supply needed for facility operations. Through use of recirculating cooling water

systems, the Project water demand is estimated to be approximately 10 million

gallons per day (MGD), down from historic highs of more than 75 MGD withdrawn

at this location. Project withdrawals are minimal in comparison with Ohio River

flows and will not impact local supplies. The Project will also be able to use the

existing water intake structures, minimizing additional disturbance to the river.

• Industrial-skilled labor pool – Because of the size and composition of the Project’s

anticipated work force, the site’s location in the “labor pool nexus” provides the

requisite access to a large pool of potential employees within a one-hour commute.

The Project will employ 400 workers once operational and anticipates needing up to

10,000 workers at peak construction.

2.2 Alternative Sizes

The proposed ethylene/polyethylene manufacturing facility would include an ethane cracker with

an approximate annual average capacity of 1.5 million metric tons of ethylene; three

polyethylene units, including two gas-phase and one slurry unit, with a combined annual

production of approximately 1.6 million metric tons; and ancillary units including a cogeneration

unit, storage, logistics, cooling water facilities, industrial waste water treatment plant, emergency

flares, buildings and warehouses.

The facility size was determined by Shell’s goal to develop an integrated and cost-competitive

Project that uses as much local ethane as possible to produce polyethylene for use by regional

manufacturers. The size of available suitable sites in the region dictated use of a single-train

cracker. In turn, technology constraints determine the maximum output available with a single-

train ethylene cracker design.

One integrated facility of the proposed size will result in less air emissions and a smaller

environmental footprint in terms of land use, water, waste, biodiversity, community and other

impacts, than multiple smaller facilities producing an equivalent amount of product using a

similar volume of ethane. From an investment perspective, a single large facility also provides

economies of scale and a better return on investment.

2.3 Alternative Production Processes

The Project utilizes a series of processes, including (1) a cracker process to convert ethane to

ethylene, (2) a gas-phase polyethylene process, and (3) a slurry polyethylene process. The gas-

phase and slurry polyethylene technologies produce polyethylene with different grades and

characteristics. The Project has sought to use proven technology with high efficiency. Shell

evaluated global licensing suppliers of proven technology, evaluating the vendors for health,

safety and environmental performance, appropriateness of processes for the Project, and

demonstrated ease and reliability of operations. The technologies selected provide the most

energy efficient technology, producing the least emissions.

There is only one commercially viable technology to make ethylene from ethane, which is the

cracker process proposed for this Project. The cracker process uses very high temperatures, in

the presence of steam, to break up the ethane molecules and rearranging the atoms to form

ethylene. While research is being conducted with regard to processes to make ethylene from

other feedstocks such as methane or ethanol, none of these technologies are yet ready for

commercial development. While it is possible to produce ethylene from naphtha, extracted from

crude oil or from heavy oil, an alternative feedstock would change the basic definition of this

Project, which is intended to provide a beneficial use of ethane produced in conjunction with

shale gas extraction in the region. The Project is employing several measures to reduce

emissions from the cracker operations, including reuse of tail gas, supplemented by natural gas

as needed, to fuel the furnaces. Tail gas is a combination of methane and high percentages of

hydrogen, and is created as a byproduct of the ethylene production process. The use of hydrogen-

rich tail gas as fuel serves to reduce carbon dioxide emissions.

The Project is proposing use of a combination of gas-phase and slurry processes for conversion

of ethylene to polyethylene. Shell evaluated a number of alternatives before selecting industry-

leading technology providers based on efficiency, cost, flexibility and environmental impacts.

Again, the selected vendors provide the most energy efficient technology with the least

emissions. Shell has licensed a gas phase technology (to make LDPE and LLDPE) which is

currently used to produce nearly 25 percent of the world’s polyethylene including nearly 100

reactor lines in 25 countries. The licensed process can produce a wide range of commercial

products using just three pieces of major rotating equipment: a cycle gas compressor, a vent

recovery compressor and a pelleting system, in a process that eliminates the need for

intermediate storage, reducing costs and the facility’s footprint. Shell is similarly licensing a

proprietary slurry phase process from a technology provider who has more than 50 years of

experience in the market. Its slurry phase technology can produce a wide range of products for

low capital and operating costs.

The Project requires substantial quantities of steam and electricity for the ethane cracker,

polyethylene production and ancillary processes. Alternatives to provide such steam and

electricity include (1) installation of gas fired boilers to produce steam alone, coupled with

purchase of electricity from the grid; (2) purchase of electricity from the grid to heat boilers to

produce steam, as well as provide necessary Project power; and (3) installation of on-site natural

gas-fired combined cycle generation units capable of producing both electricity and steam in

proximity to the manufacturing process.

Given that the Project requires significant quantities of steam, on-site natural gas-fired combined

cycle (NGCC) units are the most energy efficient approach. NGCC units utilize gas fired

turbines driving electric generators, with the exhaust gas from the turbines routed to a heat

recovery steam generator (HRSG) that produces steam for the Project along with driving a steam

turbine linked to an additional electric generator. In terms of thermal efficiency (that is, the

efficiency of converting fuel energy to power), NGCC and NGCC cogeneration units are

significantly more efficient than conventional steam electric generation technology.

The alternative of using separate on-site gas-fired boilers to produce steam, while technically

feasible, would be less efficient, while necessitating acquisition of electric energy from a

regional grid which has a higher percentage of coal-fired and less-efficient oil or gas-fired

electric generating facilities with higher emission rates per unit of heat input. The “all electric”

option, purchasing electricity to heat boilers for steam generation plus the Project’s electric

power needs, is even less efficient, and again would rely on power generation from a mix of

generation facilities with higher NOx, SO2, PM and CO2 emission rates.

2.4 Alternative Environmental Control Techniques

Air emissions from the facility will be reduced and controlled through a combination of process

design and post-emission control technologies as described in Section 5 of this plan approval

application, which is incorporated in this analysis by reference. As noted in Sections 4 and 5,

facility processes are subject to a series of new source performance standards (NSPS) and

national emission standards for hazardous air pollutants (NESHAP) established under the

Federal Clean Air Act for particular industrial categories. Facility emissions of certain air

pollutants (such as nitrous oxides or NOx and PM2.5) are subject to non-attainment area new

source review, which includes a requirement for achieving the lowest achievable emissions rate

(LAER). For other pollutants, such as carbon monoxide (CO), nitrogen dioxide (NO2),

particulates (PM) and greenhouse gases, the facility is subject to prevention of significant

deterioration (PSD) best available control technology (BACT) requirements. Both LAER and

BACT are determined on the basis of a “top-down” analysis of potentially available control

technologies. Emissions of certain contaminants classified as hazardous air pollutants under

federal rules are subject to maximum available control technology (MACT), and the facility

overall is subject to Pennsylvania best available technology (PaBAT) requirements. Section 5 of

the plan approval application contains a detailed description of the alternative emission control

technologies considered, demonstrating how the selected technologies meet applicable NSPS,

LAER, BACT, MACT and PaBAT requirements.

3. Project Benefits

3.1 Economic Benefits

The Project is expected to provide significant benefits to Pennsylvania and the surrounding

region. As a starting point, the Project will take ethane, a byproduct from ongoing natural gas

production in the Marcellus/Utica region, and convert that resource into ethylene and

subsequently various grades of polyethylene, the key building block for a variety of plastic

products produced by industries across the region. The proposed complex would be the first

major U.S. project of its type built outside the U.S. Gulf Coast region in 20 years, and would

bring ethane to polyethylene manufacturing capabilities much closer to both the source of ethane

and to polyethylene customers in the region.

The multi-billion-dollar Project will deliver large and tangible benefits for the local and state

economies:

• 400 operational jobs, up to 10,000 at peak construction and thousands of indirect jobs;

• increased household earnings;

• additional tax revenues; and

• redevelopment of existing industrial “brownfield” sites.

If the Project is built, Shell will work to enhance local economic opportunities, including hiring

and buying locally. The Project is establishing a plan to provide full and fair opportunity to

qualified local and local minority workers to obtain employment with Shell and its contractors,

and full and fair opportunity to local businesses to compete for the provision of services for

which they are technically qualified.

The Pennsylvania Economy League of Greater Pittsburgh has evaluated the Project’s expected

economic impacts during the year of peak construction and during one year of plant operation. It

estimated the following impacts would likely flow from the Project to the 10-county region:

• Up to 10,000 direct jobs during peak construction and up to 18,000 total

• $2.8 billion in economic output that year

• 400 direct operational jobs and 2,000-8,000 total

• $4.8 billion total annual economic output from operations

Additional economic impact evaluations will e conducted, the results of which will be submitted

when available to supplement the analysis provided this Appendix.

3.2 Environmental Benefits

The Project will provide substantial environmental benefits through the redevelopment of an

existing brownfield site, including several properties that have been used for many decades for a

variety of industrial purposes. The site includes (1) approximately 200 acres used for zinc

smelting for almost a century, and (2) two adjacent abandoned sites, referred to as the “brick

yard” and “mall lot”. Project development will involve demolition and remediation, to the extent

required, of the former smelter site, together with capping and stabilization of other areas, and

long term stewardship of the site. Such brownfield redevelopment not only addresses concerns

as to future stabilization and productive use of the site, but also is anticipated to reduce future

public costs that would otherwise have been incurred to address previously abandoned

contaminated sites.

Providing excess electricity from the energy efficient natural gas-fired Cogen Units will help

improve air quality by reducing the grid’s carbon dioxide equivalent intensity.

Finally, by building a Project close to both supply and markets will minimize the environmental

impacts associated with transporting ethane via pipeline to the U.S. Gulf Coast for processing

and shipping the polyethylene back to the northeastern region via truck, rail, or barge. This

includes avoiding the significant capital required to build new pipeline capacity and the

environmental effects of such construction on water, wetlands, cultural heritage, air and other

impacts.

3.3 Community Benefits

In addition to the economic and environmental benefits discussed above, the Project will provide

significant community benefits. As part of its company values, Shell contributes to the

communities in which it operates with social investments that are sustainable, deliver lasting

benefits, are self-supporting after start-up, involve local support and have a measurable positive

impact, meeting community needs. Such Projects focus on education, civic/community,

environment, health and human services, and provide benefits to communities in close proximity

to Shell Projects. Shell also fosters and supports a culture of strong volunteerism by its

employees. Annually, Shell employees donate numerous hours to community Projects.

Significant community benefits are anticipated from training and education programs conducted

during both the construction and operation phases of the Project. Shell will require a significant

workforce during both construction and operations. The Project’s major and general contractors

are expected to employ up to 10,000 workers at peak construction. Training required for these

positions, including on-the-job training, training in certificate and apprentice programs and

accreditations from skilled craft certifying bodies, are expected to add to the skill sets of the

community workforce. Once operational, the facility will employ 400 workers in jobs ranging

from craft / maintenance to process technology and operations as well as other technical,

administrative and management jobs. Many of these jobs will require two-year associates

degrees and others undergraduate diplomas. Shell and its major contractor(s) will be working

with local schools, community and technical colleges, and local and regional leaders in the

construction industry, to support education and training programs that prepare students for

careers in construction, engineering and plant operations.

4. Minimization of Air Quality, Other Environmental Impacts and Social Costs

As detailed in the applications filed for other environmental permits required for the Project,

Shell is engaged in ongoing efforts to identify, evaluate, and avoid and/or mitigate environmental

impacts. To briefly summarize:

• Air emissions will be controlled and minimized through use of technologies described in

Section 5 of this Plan Approval application, meeting all applicable BACT, LAER and

PaBAT standards. Air quality modeling, applying conservative assumptions, indicates

that the resulting emissions will not cause or contribute to exceedance of any national

ambient air quality standard or any allowable incremental increase in ambient

concentrations of regulated pollutants. Flares, used to safely mange gases during non-

standard operating conditions or emergencies, are designed in accordance with accepted

best industry standards. The emergency flare tower system, although visible to the

community for some distance from the facility, is expected to be used only during rare

events, such as complete loss of power to the facility.

• The facility will withdraw approximately 10 million gallons per day from the Ohio River,

or approximately 15 percent of the total water demand from past-on-site operations. To

reduce water use, the Project will be utilizing a recirculating cooling water system. The

Project anticipates use of the existing site intake system, with withdrawal rates and

screens that meet the requirements of §316(b) of the Federal Clean Water Act to reduce

entrainment and impingement of aquatic organisms. The intake design and operation is

subject to review as part of the NPDES Permit for the facility.

• Storm water discharges during construction activities will be managed in accordance with

an erosion and sedimentation control plan and NPDES stormwater construction permit

approved by PaDEP under 25 Pa. Code Ch. 102.

• Process and stormwater discharges from the Project site will be managed under an

NPDES permit issued by PaDEP, and will be managed to meet all applicable technology-

based and water-quality based effluent limits to protect instream and downstream water

uses.

• Emergency and contingency plans will be developed and implemented in accordance

with the federal Spill Prevention Control and Countermeasure (SPCC) and PaDEP

guidelines for Environmental Emergency Response Plans, to include measures to avoid,

contain and respond to potential spills or accidental releases.

• Site development will involve filling of approximately 4.59 acres of wetlands and

placement of certain smaller streams traversing the site into stream enclosures or culverts

under permits issued by PaDEP pursuant to 25 Pa. Code Ch. 105 and by the U.S. Army

Corps of Engineers under Federal Clean Water Act §404. Mitigation (in the form of

wetland replacement or enhancement) will be provided as required by state and federal

regulations.

• Wastes generated will be managed (stored, treated, recycled and/or disposed) in

accordance with strict federal and state regulations. The Project has been designed to

recycle and reuse materials where practicable to minimize waste generation.

• Safety is addressed at all aspects of Project development and operation, following Shell’s

rigorous, systematic approach to process and operational safety. A comprehensive,

integrated safety system will be implemented to prevent accidents and incidents, and to

provide for appropriate response to events.

• Shell will maintain its own highly-trained team of emergency responders at the facility

for quick response, as well as a fire house with fire-fighting equipment, spill response

capabilities, and an on-site medical clinic. Shell will continue to confer and work with

local police, fire and other emergency response agencies on future cooperative endeavors,

including Shell’s active participation in the area’s mutual aid arrangements.

• Noise, lighting and vibration issues have been and will be addressed by a series of

studies, and are substantially mitigated by the fact that the site is located within an

already well-established industrial area with significant surrounding buffers to the nearest

non-industrial neighbors.

• Historic and cultural resource issues are being addressed through assessments submitted

to, and ongoing consultations with, the Pennsylvania Historic and Museum Commission

(the State Historic Preservation Officer).

• A traffic study has been conducted to evaluate the impact of Project construction and

operation on local traffic and road safety, with improvements recommended to address

and mitigate those impacts.

• Wildlife impacts are anticipated to be minimal, because the Project is utilizing an existing

industrial site that has been occupied for nearly a century. Two types of freshwater

mussels, listed as special concern species by the Pennsylvania Fish and Boat

Commission, were identified in the area to be used by docks, and trained crews found and

relocated specimens of those mussel species to undisturbed locations in accordance with

regulatory guidelines. Ospreys, which are not considered protected or endangered

species, have built nests in some electric transmission towers within the site vicinity.

Those power lines will be moved as a result of site development, but such work will be

conducted when the nests are not in use.

• The Project is located within areas designated as industrial zones by applicable township

zoning ordinances. The Project is consistent with local zoning and land development

plans.

• The Project will engender some level of impact to community services demands,

including police, fire and other emergency services. Because Shell is intending to

implement an on-site security force, on-site fire department, and on-site health clinic, the

impacts to local emergency response agencies will be mitigated. Throughout the process

of developing emergency response plans, Shell will be consulting with applicable

response agencies to assess current resources and capabilities and measures appropriate

to supplement those capabilities. Through that process, potential community service

impacts are expected to be mitigated.

• PaDEP’s Environmental Justice Public Participation Policy establishes requirements for

expanded public participation activities for certain permits authorizing Projects within or

within an “area of concern” around “Environmental Justice Areas,” defined as any census

tract with 30 percent or greater minority population or 20 percent or greater at or below

the poverty level. Three such Environmental Justice Areas are located in Beaver

County. However, none of the three areas are within a half-mile radius of the site, which

is one of the criteria defining an “area of concern.” The Project is consulting with the

community and PADEP to determine if any such area is likely to experience significant

impacts from the Project. Irrespective of that determination, however, Shell’s plans for

public participation in neighboring communities are believed to meet the guidelines for

enhanced public participation both within and beyond potential Environmental Justice

Areas.

Shell places a high value on community consultations and collaboration. The company will

continue to engage with the surrounding communities and other interested parties during Project

development, construction and operation. The purpose of such efforts is to share information

about the Project, understand community interests and work together to enhance potential Project

benefits and identify and address potential concerns. Information from this on-going

consultation process will be utilized to identify, evaluate and if necessary mitigate potential

community and environmental impacts.

5. Comparison of Project Benefits to Environmental and Social Costs

The proposed Shell ethylene/polyethylene manufacturing facility in Potter and Center

Townships, near Monaca, in Beaver County, Pennsylvania, would deliver real and quantifiable

benefits for the community, state and regional, including (1) 400 operational jobs, up to 10,000

at peak construction and thousands of indirect jobs; (2) increased household earnings; (3)

additional tax revenues; and (4) redevelopment of existing industrial “brownfield” sites. Shell

has conducted extensive work to date to identify and assess potential environmental and social

effects from this proposed Project, with substantial efforts throughout the planning process to

avoid, minimize and mitigate impacts to the extent possible and to enhance positive benefits.

Based on all currently available information, while there are environmental and social costs

associated with this Project – as there are with any major Project – on balance, the combination

of the Project’s benefits with Shell’s commitment to manage and mitigate those impacts results

in net benefits that significantly outweigh the environmental impacts and social costs resulting

from the Project’s location, construction and operation.

Appendix FAdditional Support Material

This appendix contains the following items:

1. General Information Forms2. Compliance Review Forms3. Municipality Notices and Receipt of Deliveries4. Cultural Resource Notification Submittal Information5. Burner NOx From Ethylene Cracking Furnaces6. RBLC Tables for PaBAT Analyses7. Copy of Permit Fee Check

From: Bellew, Serena [mailto:[email protected]] Sent: Wednesday, April 23, 2014 1:53 PMTo: Lingle, DavidSubject: PA SHPO review for Air Permit Beaver Co. project Dear Mr. Lingle, PHMC-BHP received an August 22, 2013 request to initiate consultation under Section 106 of the National Historic Preservation Act for the Proposed Petrochemicals Project, Beaver County, Pennsylvania. This project was submitted by URS on behalf of Horsehead Corporation and Shell Chemical. A second project submittal was sent to our office for the same undertaking as a result of the need for a Section 402 US Corps of Engineers permit. PHMC-BHP subsequently assigned Environmental Review (ER) No. 2013-2037-007 G & H for the overall project/undertaking. The US Corps of Engineers is considered the lead Federal agency by PHMC-BHP for the purposes of the Section 106 review process on the above referenced Beaver county project, so no additional information including updating or amending the original application and notice, is required for the project's Air Permit Application, as potential impacts to historic properties are being addressed via the US Corps Permit project review by PHMC-BHP. Thank you, Serena Georgia Bellew | Director & Deputy State Historic Preservation OfficerBureau for Historic Preservation | Pennsylvania Historical and Museum Commission400 North Street, 2nd Floor | Harrisburg, PA 17120-0093Phone: 717.705.4035 | Fax: 717.772.0920

Cultural Resource Notification Submittal Information

BURNER NOx FROM ETHYLENE CRACKING FURNACES Robert G. Kunz

RGK Environmental Consulting, L.L.C. Hillsborough, North Carolina

Abstract: Allowable emission limits for nitrogen oxides (NOx) remain under scrutiny as regulatory agencies continue to assess the impact of NOx emissions on ambient air quality for ground-level ozone. The ozone is formed in the atmosphere by the sunlight-induced reaction of NOx with certain hydrocarbons. It is understandable that operators of affected combustion sources would prefer to achieve compliance with any such NOx reductions by means of burner modifications, rather than through more costly and complex post-combustion controls, such as selective catalytic reduction (SCR). For smooth project execution, accurate prediction of the extent of burner-NOx reduction is critical. However, computational fluid dynamics (CFD), used to model flame patterns, furnace temperatures, and the like, has done a poor job in predicting burner NOx. Likewise, burner testing in a manufacturer’s pilot facility often produces low estimates for NOx when compared to a full-scale furnace. A viable alternative is an empirical approach based on kinetic theory and validated by numerous field data. This paper shows the results from a new correlation of NOx emissions for ethylene cracking furnaces. It is derived from an established NOx correlation for commercial steam-methane reformer (SMR) furnaces, while recognizing the differences in fuels and furnace conditions between the two processes. It uses adiabatic flame temperature (AFT), excess furnace oxygen (O2), and furnace temperatures. Calculations can be accomplished rapidly and allow one to compute absolute values of NOx, explore changes in NOx from a base case, and explain experimental observations. Calculated values compare favorably with available NOx data reported for commercial ethylene furnaces spanning a wide range of conditions. The correlation can also be tailored to fit individual furnace data for even better agreement.

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Introduction

Accurate prediction of NOx emissions before implementation of burner modifications to comply with changing regulatory mandates will avoid unpleasant surprises in the field after start-up. To that end, this presentation provides a tool to estimate NOx and/or changes in NOx from properly operating furnace burners over a wide variety of conditions. Step-by-step details of its development have been discussed previously.1 As before, the following caveat applies…

Disclaimer (“Some restrictions apply; batteries not included; your mileage may vary”)

The information contained herein is offered in good faith but without guarantee, warranty, or representation of any kind (expressed or implied) as to its usefulness, correctness, completeness, or fitness for any particular purpose. The user assumes all risk for its implementation and should seek independent professional verification of its accuracy. The author assumes no responsibility and shall not be liable for any loss of profit nor any special, incidental, consequential, or other damages which may result from the use of any of the information contained in this presentation, be it oral or written. Any statements concerning design, construction, operation, what constitutes regulatory compliance, and/or how to achieve such compliance should not be construed as recommendations on the part of the author and/or his organization.

Regulatory Considerations The majority of ethylene production in the United States is concentrated along a system of interconnected pipelines2 on the Texas-Louisiana Gulf Coast.3 Canadian production is contained in the provinces of Alberta, Ontario, and Quebec.3 A number of the U.S. ethylene plants are located in ozone nonattainment areas. In the Houston-Galveston-Brazoria (HGB) Nonattainment Area of Texas, especially, plants are faced with having to comply with increasingly more stringent emission-control limits for NOx. Along with certain hydrocarbons, NOx is a critical ingredient in the formation of ground-level ozone. Hydrocarbons specifically identified as “bad actors” in ozone formation include ethylene, propylene, butanes, and butadiene,4 emissions of which are also being closely regulated. As explained later in the text, ethylene pyrolysis furnaces typically fire what are essentially mixtures of hydrogen (H2) in methane (CH4),5 the primary constituent of natural gas. Historical NOx emissions from conventional burners in ethylene-plant furnaces are stated as 100-120 parts per million (ppm)6 and 220-250 ppm for a “hydrogen-rich” fuel gas.7 Test results for low-NOx burners range from 55-60 ppm for natural gas and from 70-100 ppm for 20-70% H2 in the fuel gas, presumably using ambient air for combustion; a typical range for ultra low-NOx burners was quoted in 1993 as 25-40 ppm.7 A more recent emission inventory for the HGB area indicates a range of 0.06-0.25 lb/MMBtu, based on the higher heating value (HHV) of the fuel.8 With certain exceptions, the current standard for pyrolysis reactors in the HGB area is 0.036 lb/MMBtu (HHV).9

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The relationship between ppm NOx (dry), corrected to 3% O2 on a dry basis in the flue gas (ppmd @ 3% O2, dry), varies slightly with the composition of the fuel being burned. The NOx standard of 0.036 lb/MMBtu (HHV) corresponds to a NOx concentration of 30 ppmd @ 3% O2 (dry) for natural gas/methane and roughly 44 ppmd @ 3% O2 (dry) for pure hydrogen. Values for the standard are shown in Figure 1 for the full range of methane-hydrogen mixtures. Other sets of corresponding values between ppmd @ 3% O2 (dry) and lb/MMBtu (HHV) for a given gas composition can be obtained by proration. The general relationship between ppm, pounds per hour (lb/hr), and lb/MMBtu has been discussed previously.10

28

30

32

34

36

38

40

42

44

46

0 10 20 30 40 50 60 70 80 90 100

Percent Hydrogen in Methane Fuel

ppm

d @

3%

O2

(dry

)

Figure 1. NOx Concentration Equivalent to 0.036 lb/MMBtu (HHV)

Additional NOx emission standards and the ground-level ozone standards in effect at the time of the previous presentation are discussed there in greater detail.1 It is still fair to say that the situation will continue to evolve.

Technical Considerations Driven by the plant operator’s desire to achieve NOx compliance in the most cost effective manner, burner developments have focused on making the latest regulatory NOx targets within reach using burners. However, lower NOx is often accompanied by flame instability – rollover and impingement on the furnace tubes11-13 – unless and until corrected by redesign. Part of the (re)design effort for ethylene-furnace burners has involved computational fluid dynamics (CFD) to study burner flame patterns and temperature profiles.11-14 CFD has been employed for steam-methane reformer (SMR) furnaces as well.15 Although CFD has proven to be a useful tool in the cited studies, it is unable to predict burner and furnace NOx emissions.11-14 That has prompted our investigation to develop a NOx-prediction technique for ethylene furnaces as a complement to CFD. The resulting model is an extension of a successful correlation for SMR-furnace burner NOx, whose functional form is derived from theory, with empirical constants based on experimental data. This approach is

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a proven technique for estimation of physical property data.16 The new correlation also turns out to be effective in its own right, independent of CFD, for a variety of situations.

NOx Correlation for SMR Furnace Burners The original correlation was first presented at the 1992 NPRA Annual Meeting17 and has been elaborated upon in a series of subsequent presentations and articles as more data have become available.10,18-23 Its generalized form [ln(NOx/O2) = A – B.10,000/AFT(°R)] is shown in Figure 2, with constants specified in the figure for conventional and low-NOx burners. NOx at the furnace is in parts per million by volume; furnace O2 is in vol. %. Concentration units for NOx and O2 at furnace flue-gas conditions must be consistent, either both wet or both dry. The existing generalized correlation contains lines only for conventional burners and low-NOx burners. A patient and careful count shows that these relationships are derived from regression of seventy data points. The two lines have come out virtually parallel, as one would hope, to avoid the anomaly of their crossing at some point along the x-axis.

0.0

1.0

2.0

3.0

4.0

5.0

2.3 2.5 2.7 2.9 3.1

10,000/AFT(oR)

ln [

NO

x (p

pm) /

O2

(%) ]

Conventional BurnersEquation of line: y = 12.6-3.58x

R2 = 83%s = 0.2757

Low-NOx BurnersEquation of line: y =12.2-3.60x

R2 = 77%s = 0.2474

Figure 2. SMR NOx Correlation Its functional form is derived from Zeldovich kinetics24 for the formation of nitric oxide (NO) from oxygen (O2) and nitrogen (N2) in the combustion air (thermal NOx). NO is the primary constituent (95%) of NOx along with nitrogen dioxide (NO2) (5%) in furnace combustion. It does not apply to prompt NOx, formed by a more rapid free-radical mechanism, nor to fuel NOx, arising from chemically-bound nitrogen compounds in the fuel. The variables identified were the temperature in the flame, where the thermal NOx reaction takes place, and the excess O2 concentration. The predicted dependence on the N2 concentration turns out not to be statistically significant for combustion with atmospheric air. The correlation employs the adiabatic flame temperature (AFT) for combustion of the given fuel under the specified conditions plus the furnace firebox excess O2, normally measured on a

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wet basis, as the independent variables. Firebox O2 and dry-basis O2 measured at the stack during source testing are not the same if significant infiltration of tramp air occurs in between. The theoretical AFT assuming complete combustion is the temperature attained when a fuel is burned, without mechanical work or gain or loss of heat, to the theoretical end products such as carbon dioxide (CO2) and water vapor (H2O), regardless of any equilibrium condition which might apply;25 it is a function of the heating value of the fuel, the combustion products generated, and the inlet conditions.17 Other research has shown the AFT to agree reasonably well with the actual peak temperature in a combustion flame.26-30 AFT is a useful surrogate for that temperature and therefore serves as a good correlating variable. Similarly, O2 concentration at the furnace exit is a surrogate for oxygen in the flame. Use of an additional parameter, the so-called elusive third variable, such as the furnace firebox temperature at the bridgewall, to reduce the scatter has been discussed.17 The rationale is that the calculated AFT more closely approaches the actual flame temperature the higher the overall temperature being maintained in the surrounding furnace into which the flame radiates. For an individual furnace, one can also improve on the prediction from the generalized correlation.21

Extension of the Correlation to Ethylene Cracking Furnaces The correlation of Figure 2 can be modified to apply to ethylene furnace burners by considering the similarities and differences between those burners and their fuels compared to the burners and fuels in a steam-methane reformer. The development of the new correlating equations, already discussed in great detail elsewhere,1 will only be summarized here. Processes Are Different – A Review SMR Process and Fuels. Steam-methane reforming (SMR) is a commercial process for the simultaneous production of hydrogen and carbon monoxide (CO). In this continuous process, steam and a desulfurized hydrocarbon feed react at elevated temperatures over a solid nickel-based catalyst,31-34 which is contained inside tubes suspended in a furnace.35,36 To maximize the H2 yield for a hydrogen plant, additional steam is provided in one or more shift-converter vessels downstream outside the furnace. Feed is usually natural gas but can also be refinery gas, propane, liquefied petroleum gas (LPG), butane, or straight-run naphtha.31,37,38 The H2 product is separated from the resulting synthesis gas (syngas), a generic term for mixtures of H2, CO, and CO2. In a hydrogen-carbon monoxide plant, where CO is a desired product (along with a hydrogen co-product), the CO is recovered by low-pressure distillation at cryogenic temperatures following CO2 removal by regenerative amine absorption and a drying step.10 In either case, the hydrogen is separated from the syngas in a pressure-swing-adsorption (PSA) unit. Other components in the syngas end up in the PSA purge gas resulting from the periodic regeneration of the PSA unit.22,23 Hydrogen-plant PSA purge gas contains unrecovered H2 plus the non-hydrogen constituents in the syngas – unreacted methane (CH4) excess steam (H2O), CO, CO2, and impurities such as nitrogen (N2) from the feed.17,22,23 Combustible components include H2, CO, and unreacted CH4, the so-called methane slip.35,36 A typical purge gas/natural gas composition can be found in previous publications.10,17,19

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The internally generated PSA purge gas is recycled as fuel to the reformer furnace burners. This purge gas can provide 50 %17 up to 90%17,31 of the fuel requirement for the furnace. The low-Btu hydrogen-plant PSA purge gas containing some 40% CO is supplemented by an auxiliary, or trim, fuel to make up the firing requirement, typically natural gas or refinery fuel gas.22,23 In contrast, the PSA purge gas from a hydrogen-carbon monoxide plant contains about 90% H2 and 10% CO without the high CO2 concentration usually found in hydrogen-plant PSA purge gas.10 Older hydrogen plants, built before the mid-1970s, typically used amine absorption, carbon dioxide removal, and methanation to make a final product of lower hydrogen purity.22-23 This design also produces high purity CO2, which can be liquefied for sale or used in further processing.17,39,40 These older SMR plants without a PSA are fired solely on external fuels. Ethylene Cracking Process and Fuels. In the continuous thermal cracking process for ethylene production, hydrocarbon feed is mixed with steam and reacted inside tubes known as radiant coils suspended in a furnace. The ethylene cracking unit is also referred to as a steam cracker, ethylene cracker, thermal cracker, or pyrolysis furnace.2,6,41,42 Hydrocarbons ranging from ethane, propane, butane, and liquefied petroleum gas (LPG) through naphtha, kerosene, and gas oil can be used as feed.5 Following thermal cracking to the desired conversion, the cracked gas exiting the furnace coils is rapidly quenched and separated downstream into its constituents. Many by-products or co-products are generated in addition to ethylene, with greater amounts formed from the heavier feeds, and the distribution of products is strongly influenced by operating conditions. Components in the cracked gas include ethylene, propylene, butadienes, butanes, butenes, higher olefins, and aromatics as useful products; hydrogen recovered as a product or used as fuel; methane used as fuel; and coke, which lays down on the inside surface of the radiant coils and interferes with the operation. To remove the unwanted by-product coke from inside the radiant coils, elements of the process train must be taken out of service periodically and “decoked” using a mixture of steam and air. The decoking offgas, containing CO, CO2, and carbon particles,6 is either diverted to quench water and a knockout pot2,6,43 and thence to atmosphere, or it is combusted in a firebox.6 This might be the ethylene furnace itself11,43 or some external heater with its own separate stack. The steam-cracking process generates an impure hydrogen-rich gas, which may be purified or upgraded for chemical uses or used as fuel,5 plus an impure methane stream known as methane-rich gas5 or the pyrolysis methane fraction2 that is used as fuel.2 The hydrogen-rich fuel is only 85% to a maximum of 95% pure.5,6 The methane fuel-gas stream consists of 95% methane with some minor impurities of hydrogen, carbon monoxide, and traces of ethylene.6 By-product ethane and propane may also be contained in the fuel.2 In addition, a so-called pyrolysis fuel oil product is obtained from cracking heavier feedstocks.5,41 A lighter cut known as pyrolysis gasoline,5,41 or pygas,41 a gasoline-like liquid high in unsaturated compounds and rich in aromatics (benzene, toluene, xylenes (BTX)),44 is used as a chemical feedstock. An ethylene cracking furnace can also be supplied or supplemented with other fuels available in a petroleum refinery or petrochemical complex.

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But Combustion Is Similar Although the processes are different, the combustion sides are quite similar. Both processes:

• Employ a furnace to supply the heat of reaction. • Use many small burners to deliver the required heat as uniformly as possible.45 • Must be capable of burning significant concentrations of hydrogen in the fuel mixture • Must be designed to prevent flame rollover and impingement on the tubes/coils.

Firebox Temperatures Are Different It is no secret that ethylene furnaces tend to run hotter than SMR furnaces, and this difference must be accounted for in predicting NOx. In Table 1,46 firebox temperature in an ethylene furnace is typically 1000-1200 °C (~1830-2200 °F).2 In a reformer furnace, flue-gas temperature exiting the radiant firebox, referred to as the bridgewall temperature,33 is 1800-1900 °F (~980-1040 °C).31,37 These figures average about 2000 °F (~1100 °C) and 1850 °F (~1010°C), respectively. Tube-metal temperatures, drawn from multiple sources and shown for information only, may not be completely consistent with the furnace temperatures.

Table 1. Approximate Temperatures in Process Furnaces

Process

Furnace

Tube-Metal

Ethylene

1830-2200 °F

1750-2100 °F

SMR

1800-1900 °F

1600-1925 °F

Adiabatic Flame Temperatures Are Both Different And Similar Adiabatic flame temperatures for typical fuel gases used in SMR and ethylene cracking furnaces are examined below. Adiabatic Flame Temperatures for Typical SMR Furnace Fuels. Adiabatic flame temperatures for fuels containing both hydrogen-plant PSA purge gas and for fuels containing hydrogen-carbon plant PSA purge gas can be found in the cited references.10,17,19 The AFT for a natural gas at various combustion air temperatures is also addressed.17 In summary, with hydrogen plant PSA purge gas (containing about 40% CO2 in the mixture) supplemented by natural gas, the AFT is some 400 °F (222 °C) ± below that for firing natural gas or pure methane alone. Because of this lower AFT, hydrogen plant furnaces have a natural tendency to produce lower NOx. However, hydrogen-carbon monoxide plant purge gas (H2 and CO without the high concentration of CO2) mixed with a natural gas trim fuel produces AFTs 100-200°F (56-111°C) above that of the natural gas/methane reference. Adiabatic Flame Temperatures for Typical Ethylene Furnace Fuels. Typical fuel gases combusted in an ethylene furnace are impure waste gases recovered in the process. These consist mainly of methane and hydrogen with some minor constituents. However, to keep things simple in the calculations that follow, the fuels are assumed to be various

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combinations of pure methane and pure hydrogen. Furthermore, “natural gas,” also a common fuel brought in to fire the furnace, is assumed to be 100% methane. AFTs for combustion of methane, hydrogen, and various mixtures thereof are shown in Figure 3. Its basis is fuel and air temperatures of 60 °F (15.6 °C) and 60% relative humidity for the ambient air. (Unless otherwise stated, that same basis is assumed here throughout.)

2700

2900

3100

3300

3500

3700

3900

4100

0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )

Adi

abat

ic F

lam

eTem

p. (o F)

Lines from Top to Bottom:

100% Hydrogen (H2)80% H2 / 20% Methane60% H2 / 40% Methane40% H2 / 60% Methane20% H2 / 80% Methane 100% Methane (CH4)

Figure 3. Adiabatic Flame Temperatures for CH4 / H2 Mixtures, Ambient Combustion Air As depicted in Figure 3, AFTs are higher as more hydrogen is present in the fuel. The curves are linear in excess O2 up to about 5-6%, although a slightly better fit can be obtained through the addition of a quadratic term. Slope of the line is on the order of 150 °F per %O2 (83 °C per %O2) but increases slightly with increasing hydrogen. The line for methane is essentially the same as that calculated for a typical natural gas in a previous presentation.17 The AFTs calculated for the methane-hydrogen blends fired in an ethylene cracker (Figure 3) are higher than for methane alone. Their AFTs are comparable to those for SMR hydrogen-carbon monoxide plant PSA purge gas (mixtures of H2 and CO) supplemented by natural gas10 and fall within the range of applicability of the SMR NOx correlation (Figure 2). AFT increases as fuel and air temperatures are raised. The effect is more dramatic for combustion air temperature (air preheat) because of the relative amounts of air and fuel taking part in the combustion process. AFTs for combustion of the fuel gases of Figure 3 recalculated for the same starting ambient air and a combustion air temperature of 350 °F (177 °C) are shown elsewhere.1 In round numbers, corresponding values between the cases depicted in Figure 3 and the air-preheat cases are about 200 °F (a delta of 111 °C) higher for preheated air, but the slopes of AFT vs. O2 remain nearly the same.

NOx Correlating Equations For Ethylene Furnaces The proposed correlating equations for NOx from ethylene cracking furnaces derived from the SMR correlation of Figure 2 are shown in Figure 4, with an additional line estimated for ultra

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low-NOx burners.1 The relationship to AFT is assumed to be the same. (The coefficient B, slope of NOx vs. 10,000/AFT(°R), equals 3.6 to two significant figures.) The constant A is taken as 13.0, 12.6, and 11.9, respectively, for conventional, low-NOx, and ultra low-NOx burners to account for a difference in furnace temperatures between the two processes (Table 1). It turns out that about 1½ times as much NOx would be generated from the “average,” or “typical” ethylene furnace compared to the “average,” or “typical” SMR furnace, caused by a difference in furnace temperature alone, everything else being equal. It is interesting to note that the low-NOx burner equation for ethylene furnaces (Figure 4) is nearly the same as the conventional-burner equation for SMRs (Figure 2). The decoking step in the ethylene process is not modeled in this correlation.

0.0

1.0

2.0

3.0

4.0

5.0

2.3 2.5 2.7 2.9 3.1

10,000/AFT(oR)

ln [

NOx (p

pm) /

O2 (%

) ]

Top Line - Conventional Burners Equation of line: y = 13.0-3.6x

Middle Line - Low-NOx BurnersEquation of line: y = 12.6-3.6x

Bottom Line - Ultra Low-NOx BurnersEquation of line: y = 11.9-3.6x

Figure 4. Proposed NOx Correlation for Ethylene Furnaces

Influence of the Variables Oxygen Dependence Oxygen dependence in the NOx correlation is both direct through the ln[NOx/O2] term and indirect through the AFT (Figure 3). The ln[NOx/O2] relationships from Figures 2 or 4 [ln(NOx/O2) = A – B.10,000/AFT(°R)] (1) can be plotted on linear coordinates as NOx vs. O2 for combustion of a given fuel at a specified set of fuel, air, and furnace conditions. There then results a curve passing through a maximum point, where the competing influences of excess O2 and AFT are in balance.17 Some previously published NOx data points17,19,20,21 and customized correlating curves for three commercial SMR furnaces firing natural gas are plotted against furnace excess O2 in Figure 5. NOx concentrations in the figure are expressed as ppm wet at conditions, as reported in the original publications. Concentrations in ppm at conditions on a dry basis would be about 20-25% higher,10,19 and adjustment of ppm (dry) to a flue-gas concentration of 3% O2 (dry) (a common regulatory standard) would shift the curves somewhat.10 As discussed

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previously,17,21 NOx values below about 1.5% O2 (wet) may not be reliable since the actual intercept is expected to be positive, rather than zero,47 and NOx in this region may be somewhat higher than predicted from the curve as drawn.

0

20

40

60

80

100

120

140

0.0 1.0 2.0 3.0 4.0 5.0Excess O2 ( % wet )

NO

x pp

m (w

et),

at c

ondi

tions

Conventional: 400oF Combustion Air

Low-NOx: 530oF Combustion Air

Conventional: Ambient Air

Figure 5. NOx from Natural-Gas Fired SMR Furnaces, Burners and Air Preheat as Noted Through the magic of differential calculus, it is possible to calculate the value of furnace oxygen corresponding to the peak of the ppm NOx wet at conditions vs. %O2 (wet) curve, such as those depicted in Figure 5. For the more general case of ln[NOx] = A – B.10,000/AFT(°R)] + C. ln[O2] (2) with an additional coefficient of the ln[O2] term, the O2 at the maximum point is given as O2 at the peak = {[(B.10,000/C) + 2.b] – SQRT[[(B.10,000/C) + 2.b]2 – 4. b2]}/(2.a) (3) where a = the absolute value of the linear slope of AFT vs. O2 (°F or °R per % O2) b = AFT(°R) at 0% O2 (linear intercept) (Note temperature in °R.) C = an additional constant that reduces to 1.0 for the standard NOx equation SQRT = the square-root operator Both the slope a and intercept b are obtained by regression of AFT against %O2 (wet), as plotted in Figure 3, but in °R. Flue-gas moisture (not shown) is also linear in %O2 (wet). NOx in ppmd @ 3% O2 (dry) vs. O2 curves predicted for ethylene cracking furnaces from the equations of Figure 4 are shown in Figures 6-9 for several representative cases, with ambient (60 °F) combustion air and with 350 °F air preheat.

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Peak values of NOx for these and other fuel compositions are listed in Table 2. The peak occurs at 3.0-3.2 %O2 (wet) for ambient air and at 3.3-3.6 %O2 (wet) for air preheat. Oxygen at the peak increases with higher AFT as H2 in the fuel increases (Figure3). The curves become steeper and the maximum point moves to the right with added air preheat.19

0

40

80

120

160

200

0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )

NO

x [ p

pmd

@ 3

% O

2 (dr

y) ]

Conventional Burners

Low-NOx Burners

Ultra Low-NOx Burners

Figure 6. Predicted Ethylene Furnace NOx: 100% Methane Fuel and 60 °F Air

0

40

80

120

160

200

0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )

NO

x [ p

pmd

@ 3

% O

2 (dr

y) ]


Low-NOx Burners


Figure 7. Predicted Ethylene Furnace NOx: 40% H2 / 60% Methane and 60 °F Air

440

452

0

40

80

120

160

200

0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )

NO

x [ p

pmd

@ 3

% O

2 (dr

y) ]


Low-NOx Burners


Figure 8. Predicted Ethylene Furnace NOx: 100% Methane and 350 °F Air Preheat

0

40

80

120

160

200

0.0 1.0 2.0 3.0 4.0 5.0 6.0Excess O2 ( % wet )

NO

x [ p

pmd

@ 3

% O

2 (dr

y) ]


Low-NOx Burners


Figure 9. Predicted Ethylene Furnace NOx: 40% H2 / 60% Methane and 350 °F Air Preheat

Finding the peak value of the ppmd @ 3% O2 curve by calculus requires differentiating a more complicated function than Equation (2) followed by a trial-and-error solution for O2. It is more straightforward then to locate the maximum point from the function itself by iteration.

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Table 2. Predicted Ethylene Furnace NOx Peak Values, Burners and Air Preheat as Shown

ppmd @ 3% O2 (dry)

lb/MMBtu (HHV)

% H2 in Fuel

Ambient Conven-

tional Low-NOx Ultra Low-NOx

Conven-tional Low-NOx Ultra

Low-NOx 0 10 20 30 40 50 60 70 80 90 100

101 104 108 112 118 126 136 149 170 205 270

68 70 72 75 79 84 91 100 114 137 181

34 35 36 37 39 42 45 50 57 68 90

0.121 0.123 0.126 0.129 0.134 0.139 0.146 0.155 0.168 0.188 0.222

0.081 0.083 0.084 0.087 0.090 0.093 0.098 0.104 0.113 0.126 0.149

0.040 0.041 0.042 0.043 0.044 0.046 0.049 0.052 0.056 0.063 0.074

350°F Air 0 10 20 30 40 50 60 70 80 90 100

165 169 174 181 189 200 214 234 263 310 397

110 113 117 121 127 134 144 157 176 208 267

55 56 58 60 63 67 71 78 88 103 133

0.197 0.200 0.204 0.209 0.214 0.221 0.230 0.243 0.260 0.286 0.328

0.132 0.134 0.137 0.140 0.144 0.148 0.154 0.163 0.174 0.191 0.220

0.066 0.067 0.068 0.069 0.071 0.074 0.077 0.081 0.086 0.095 0.109

Combustion-Air Temperature Another way to depict the effect of combustion air temperature on AFT and NOx (Figures 6-9, Table 2) is to plot the relative concentration of NOx formed for a given combustion air temperature to NOx at some reference ambient air temperature, say 60 °F (15.6 °C). At otherwise constant conditions, the relative NOx can be derived from the functional form of the NOx correlation (Figures 2 and 4) to yield: NOx with air preheat/NOx ambient = exp[B.(10,000/AFT(°R)ambient – 10,000/AFT(°R)air preheat)] (4) This relationship comes from writing the NOx equation twice, once for each combustion air temperature chosen and subtracting. The explicit excess O2 concentrations, being the same, drop out as does the constant term A, indicative of burner type. The only things left

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are the coefficient B and the AFTs for combustion of the fuel with the preheated air and with the reference air. The AFT for the reference condition is actually a constant in the equation. According to the model, it follows that the relative NOx from combustion of a particular fuel gas at a given temperature and ambient-air conditions is a function of the combustion-air temperature and the excess O2. Relative NOx depends on the combustion-air temperature because the AFT is a function of that temperature. The AFT also provides an excess O2 functionality (Figure 3) even though the explicit excess O2 term drops out in the derivation of Equation (3). A graph of the above equation for combustion of three methane-hydrogen fuel compositions at 2% excess O2 (wet) is shown in Figure 10 for a coefficient B of 3.6, its value from Figure 2 to two significant places. The curves are distinct from one another, but the differences are minor. When plotted on linear coordinates, the curves clearly display an exponential character. Use of Equation (3) with experimental relative NOx data for preheated combustion air may be another way to determine the coefficient B.

0.0

1.0

2.0

3.0

0 100 200 300 400 500 600 700 800Combustion Air Temperature (oF)

NO

x Rel

ativ

e to

60

o F A

ir

Top Curve: 100% Methane

Middle Curve: 75% Hydrogen /

25% Methane

Bottom Curve: 100% Hydrogen

Figure 10. Relative NOx at 2% Excess O2 for Preheated Combustion Air, Fuels as Noted Curves of this type, plotted without numerical values on the axes, may be familiar from burner manufacturers’ literature, for example,47 and a rule of thumb quoted from industrial experience is that NOx can be expected to double as combustion air is preheated from ambient to the range of 500 °F (260 °C) 47 to 600 °F (316 °C). 47,48 Curves for methane containing up to about 75% hydrogen cross the Relative NOx = 2.0 line in Figure 10 within this temperature range. In addition, a similar set of curves (not shown) for an unspecified fuel and excess O2 but with numerical values48 is available showing relative NOx ranging from 1.85 (min.) to 2.3 (max.) at 750 °F (399 °C) with respect to a base temperature of 100 °F (37.8 °C). Correction between the two temperature bases is about 6%. Relative NOx from the published curves at

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350 °F (177 °C) is close to 1.2 and between 1.3 (min.) and 1.7 (max.) at 500 °F (260 °C) and 600 °F (316 °C), respectively. Although agreement between those curves and Figure 10 is not quite exact even on the same basis, Figure 10 is certainly in the same ball park while providing more conservative values of NOx. If desired, the coefficient B can be adjusted to make the relative NOx curves of the model coincide with one’s own experimental data. Fuel Temperature Relative NOx as a function of fuel temperature is plotted in Figure 11 using 60 °F (15.6 °C) as the basis. A range of 40 °F (4.4 °C) to 150 °F (65.6 °C)F is covered. Combustion air at 60 °F (15.6 °C) and 60% relative humidity (RH) is held constant. Excess O2 in the furnace is 2% (wet). Four curves are shown, each nearly linear, for 100% hydrogen fuel and 100% methane fuel at the extremes, 75% H2 in methane midway between them, and 50% H2 midway between 75% H2 and 100% methane. The difference over the temperature range investigated is only 6% for hydrogen fuel [4% between 60 °F (15.6 °C) and 150 °F (65.6 °C)] and 2 % for methane [1½% from 60 °F (15.6 °C) to 150 °F (65.6 °C)]. Since fuel volume is only about 10% of the combustion air or flue gas at typical excess air conditions for methane / natural gas (about ⅓ for a pure hydrogen fuel), it is not surprising that the impact of fuel temperature on AFT, and therefore NOx, is such a small fraction of the effect of combustion-air temperature, certainly for fuels containing high concentrations of methane.

0.99

1.00

1.01

1.02

1.03

1.04

1.05

40 50 60 70 80 90 100 110 120 130 140 150Fuel Temperature (oF)

NO

x Rel

ativ

e to

NO

x Fo

rmed

Usi

ng

60 o F

Fuel

Fuel Composition from Top to Bottom: 100 % H2, 75 % H2, 50 % H2, 0% H2 in Methane

Lines Calculated Using 60 oF, 60 % RH Ambient Air at 2 % Furnace Excess O2 (wet)

Figure 11. Relative NOx from Heated Fuel at 2% Excess O2 (wet) Ambient-Air Humidity Figure 12 shows the effect of humidity in the combustion air drawn in at ambient-air temperatures from 40-100 °F (4.4-37.8 °C). The relationship is depicted as a single, nearly

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linear curve with a negative slope since the miniscule differences in relative NOx with ambient-air temperature are imperceptible at the scale of the figure. For each temperature, the curve should be used only up to the saturation humidity at that temperature (Table 3, below).

0.60

0.65

0.70

0.75

0.80

0.85

0.90

0.95

1.00

0.00 0.01 0.02 0.03 0.04 0.05 0.06 0.07Absolute Humidity ( moles of water per mole of dry air)

Rel

ativ

e N

Ox

at S

ame

Am

bien

t-Air

Tem

pera

ture

Curve Calculated for 100 % Methane FuelFired at 2 % Excess O2 (wet)

for Ambient-Air Temperatures 40-100 oF

Figure 12. NOx Relative to NOx Formed Using Zero-Humidity Ambient Air Even though the predicted increase in NOx on days with lower humidity may be minimal compared to some other effects, it is still real. According to the figure, halving the humidity from 0.028 to 0.014 moles of water per mole of dry air (e.g., from 80% RH to 40% RH at 80 °F (26.7 °C)) results in a relative NOx increase of 9%, or an absolute increase of about 8 ppm NOx at 90 ppm, 5½ ppm at 60 ppm, and 3 ppm at 30 ppm. Such an increase, in general, has been alluded to in testing of burner emissions.12 This is especially important when ambient conditions cause the operation to approach NOx permit limits more closely.

Table 3. Saturation Humidity at Indicated Ambient Temperature and Atmospheric Pressure

Temperature (°F / °C)

Absolute Humidity (moles of water per mole of dry

air)

40 / 4.4 50 / 10.0 60 / 15.6 70 / 21.1 80 / 26.7 90 / 32.2 100 / 37.8

0.008330 0.012248 0.017735 0.025328 0.035735 0.049894 0.069074

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Hydrogen Content of Methane / Hydrogen Fuel Mixtures NOx relative to firing 100% methane for methane / hydrogen fuel blends is plotted in

Figure 13. Fuel-hydrogen content from 0-100% is investigated at 2% excess O2 (wet) in the furnace flue gas. A fuel temperature of 60 °F (15.6 °C) and combustion-air temperatures of 60, 350, and 750 °F (15.6, 177, and 399 °C) starting with ambient air at 60 °F (15.6 °C) and 60% RH were employed in the calculations. Basis for comparison is NOx concentration expressed as ppmd @ 3% O2 (dry) for 100% methane.

Three distinct curves result, progressing in order from top to bottom with the 60 °F (15.6 °C) combustion-air curve on top. Like Figure 10, these curves also are exponential in character. Relative NOx increases with increasing hydrogen, gradually at first, but then the curves begin to take off in the range of 50-60% H2.

Different curves with a lower relative NOx and a more gradual rise but with a similar take-off point are obtained when comparing NOx emissions in lb/MMBtu (HHV) rather than in ppmd @ 3% O2 (dry). This occurs because the ratio of ppm to lb/MMBtu changes with fuel hydrogen, as shown in Figure 1. The lb/MMBtu (HHV) relative-NOx curve for 60 °F (15.6 °C) combustion air is shown as the lowest curve in Figure 14, along with several others. The shape of this curve has been discussed previously,1 including the experimental observation of no measurable impact of H2 on NOx (as reported, tested up to about 50-60 vol% H2).14

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

2.6

0 10 20 30 40 50 60 70 80 90 100Hydrogen in Methane Fuel (vol %)

NO

x R

elat

ive

to

100

% M

etha

ne F

uel

Top Curve: 60 oF Combustion Air

Middle Curve: 350 oF Combustion Air

Bottom Curve: 750 oF Combustion Air

Curves Calculated Starting with 60 oF Fuel and 60 oF, 60 % RH Ambient Air

Figure 13. NOx with H2 in Fuel Relative to Firing 100% Methane, 2% Excess O2 (wet)

A published graph, termed “the classical and accepted curve for hydrogen influence on NOx emissions,” was found in the literature.48 However, its origin, basis, and non-hydrogen fuel composition are not clearly stated; the background fuel is assumed here to be natural gas fired with ambient combustion air. This curve, redrawn, appears in Figure 14 as well. Although it is noted as the flattest curve in the figure, it has been fitted for the plot using a third-order polynomial to capture the rise and inflection point exhibited by the original curve.

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The 60 °F (15.6 °C) combustion-air relative NOx curve at 2% excess O2 from Figure 13 and a slightly lower relative-NOx curve based on 10% excess air at the same combustion-air temperature are also shown in Figure 14. Both of these curves deviate from the literature curve by at most 5% up to a concentration of 70% H2. Beyond that point, the published curve increases slightly from a relative NOx of 1.4 at 70% H2 to just less than 1.6 at 100% H2, compared to a more conservative 2.4-2.6 ± estimated from the correlation for 100% H2.

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

2.6

0 10 20 30 40 50 60 70 80 90 100Hydrogen Content in Fuel ( vol %)

NO

x R

elat

ive

to 1

00%

M

etha

ne /

Nat

ural

Gas

Fue

l Top Curve (from Previous Figure) Based on 2 % O2 (wet) and ppmd @ 3% O2 (dry)

Second Curve Based on 10 % Excess Air and ppmd @ 3% O2 (dry)

Lowest Curve Based on lb/MMBtu (HHV)

Flattest Curve Redrawn from Cited Literature Reference; Origin,Basis, and Non-Hydrogen Composition of Fuel Not Stated Therein

Figure 14. Relative NOx from Hydrogen Content in Ethylene Furnace Fuel – A Comparison Acetylene Content of Methane and Hydrogen Fuels Now that hydrogen has been explored, let us now look at the implications of acetylene in ethylene-furnace flue gas. By-product acetylene in the cracked gas would end up in the fuel in the event that it is not being recovered or hydrogenated to ethane and ethylene in the normal processing sequence.49 Under comparable conditions, acetylene as a pure component is calculated to generate an AFT over 600 °F (333 °C delta) higher than hydrogen and about 950 °F (528 °C delta) higher than methane. Firing a significant concentration of acetylene, therefore, has the potential to increase ethylene-furnace NOx emissions substantially. Relative NOx from combustion of fuel gas containing percentage concentrations up to as high as 10% acetylene is shown in Figure 15. This range has been exaggerated to magnify differences. Two lines are indicated, one for 100% hydrogen (upper) and the other 100% methane (lower), both using 60°F (15.6 °C), 60% RH air for combustion at 2% excess O2 (wet). The relationships are nearly linear, with a relative NOx at 10% acetylene of approximately 1.30 compared to pure hydrogen for the hydrogen line, and 1.28 compared to pure methane for the methane line. With both lines anchored at 1.0 relative NOx for 0% acetylene, each of the ordinates at 100% acetylene swing down about 0.03 when this same combustion air is heated to 350 °F (177 °C), and an additional 0.03 for 750 °F (399 °C) combustion air.

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459

1.00

1.05

1.10

1.15

1.20

1.25

1.30

0.0 2.0 4.0 6.0 8.0 10.0Acetylene Content in Fuel ( vol %)

NO

x Rel

ativ

e to

100

% H

ydro

gen

or

Met

hane

Fue

lTop Line: Hydrogen with

60 oF, 60 % RH Combustion Air

Bottom Line: Methane with60 oF, 60 % RH Combustion Air

Figure 15. Relative NOx from Acetylene in Ethylene Furnace Fuel at 2% Excess O2 (wet)

Experimental Verification of NOx Predictions NOx data for ethylene cracking furnaces in the open literature are few and far between, especially when accompanied by simultaneous operating conditions. Still, it is possible with a little detective work to squeeze out some data for comparison with NOx predictions by making reasonable assumptions to augment whatever meager information that has been reported. Often, the burner-NOx reported is incidental to the main subject under discussion. A number of usable cases were identified in the cited paper,1 with a synopsis of the data and circumstances for each case, an interpretation of experimental observations, and values predicted by the correlation. These were then summarized in an overall parity plot of predicted vs. observed NOx. In addition, two newly discovered commercial ethylene-furnace NOx data points48 are tabulated here in Appendix A, accompanied by corresponding predictions. The same source document48 also contains NOx data obtained in the burner manufacturer’s pilot test facility. Those data are not representative of full-scale operation, for reasons discussed by the manufacturer, and are not shown here. In other work, tests of multiple burners have produced significantly higher NOx levels than single-burner tests in a smaller furnace.50 The previously developed graph of predicted vs. observed NOx is reproduced in Figure 16, augmented by the additional data points of Appendix A. Reported measurements for all cases considered have been converted, where necessary, to a common unit of ppmd @ 3% O2 (dry). The typical NOx values mentioned in a previous section on Regulatory Considerations would also plot well in Figure 16. However, these are not included in the parity plot because they cannot be guaranteed to be from full-scale ethylene cracking furnaces, or even if so, conditions are not specified well enough to validate the model unequivocally. For example,

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the historical figure of 100-120 ppm NOx from conventional burners could arise at the maximum point of NOx-O2 curve, according to the correlation, for methane with up to 40% hydrogen in the blend fired with ambient air (Figures 6 and 7, Table 2), with 100% methane and air preheat up to about 160 °F (71 °C) (not shown), or from any number of other combinations.

0

20

40

60

80

100

0 20 40 60 80 100Observed NOx (ppmd @ 3% O2)

Pred

icte

d N

Ox

(ppm

d @

3%

O2)

Figure 16. Parity Plot – Predicted vs. Observed NOx Agreement between the correlated and measured values in Figure 16 is indeed satisfactory, especially considering that these data were not used in the derivation of the correlation. Regardless of the origin of the proposed equations, their use, as it turns out, appears promising in estimating NOx for a wide variety of situations encountered in ethylene plants.

Opportunities For Improvement The proposed correlating functions appear to check out well enough against spot data. However, the author has not yet come across a complete set of NOx data in the open literature showing a systematic variation in furnace excess O2 similar to the SMR data of Figure 5 to test it further. It is hoped that more complete data sets will become available to provide a definitive check of the NOx prediction equations for an ethylene cracking furnace. Data sufficient to correlate and predict NOx from a plant furnace can often be generated at minimal incremental expense during mandatory stack testing for regulatory

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purposes. Multiple regression of such data enables one to tailor the constants of the generalized function for a specific furnace, and constants are easily adjusted as more data become available. This can be especially useful when the furnace / burners can be considered the prototype for others of the same model already in service or yet to be built. Suggested data are listed in Appendix B; concomitant process conditions during emission testing can also be noted and recorded. Target operating conditions are outlined in Figure 4 of the cited reference,10 being careful to remain within one’s permit limits at all times.

Summary And Conclusions

• NOx Correlation Extended to Ethylene Cracking Furnace Burners • Correlation Provides Reasonable NOx Estimates. • Correlation Can Be Used to:

+ Estimate NOx Quickly + Evaluate Changing Conditions + Play “What-if” Games + Complement Other Techniques Such as CFD + Interpret Experimental Data

• Correlation Works for: + A Variety of Fuels and Fuel Temperatures + Ambient Air for Combustion + Preheated Combustion Air + Combustion Air with Varied Humidity

• Correct Inputs Are Required. • Additional Data Needed to:

+ Increase Confidence + Make Modifications, if Necessary

About The Author

Robert G. Kunz was an environmental engineering manager at Air Products and Chemicals, Inc., Allentown, PA before retiring after 26+ years of service. He joined Cormetech, Inc., Durham, NC in April 2001 as Technical Project Manager in support of sales and marketing efforts in the petroleum refining and petrochemical industries, advising on business development strategy, development of training materials, technical report writing, and evaluation of laboratory and field data. He held engineering positions previously at Esso Research and Engineering Company, Florham Park, NJ and The M.W. Kellogg Company, New York, NY and is currently an independent environmental consultant. “Dr. Bob” has earned a BChE degree in Chemical Engineering from Manhattan College, a PhD in Chemical Engineering from Rensselaer Polytechnic Institute, an MS in Environmental Engineering from Newark College of Engineering, and an MBA from Temple University. He has contributed numerous publications to the technical literature, including many on NOx measurement, prediction, correlation, and control. He is a member of the American Institute of Chemical Engineers (AIChE), the American Chemical Society (ACS), and the Air & Waste Management Association (A&WMA) and is a licensed professional engineer in several states.

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References

1. Kunz, R.G., “Extension of NOx Correlation to Ethylene Cracking Furnaces,” ENV-05-197, 2005 NPRA Environmental Conference, Dallas, TX (Sept. 19-20, 2005).

2. Gerhartz, W., et al., editors, “Ullmann’s Encyclopedia of Industrial Chemistry,” 5 ed., Vol. A 10, pp.45-93, VCH Publishers, New York (1987).

3. Anon., “International Survey of Ethylene from Steam Crackers – 2006,” Oil & Gas J., 104.12, 51-56 (Mar. 27, 2006).

4. Texas Commission on Environmental Quality (TCEQ), “Revisions to the State Implementation Plan (SIP) for the Control of Ozone Air Pollution: Houston/Galveston/Brazoria Ozone Nonattainment Area,” Chapter 1: Executive Summary, pp.1-1 to 1-2 (adopted Dec. 1, 2004).

5. McKetta, J.J. and W.A. Cunningham, editors, “Encyclopedia of Chemical Processing and Design,” Vol. 20, pp.88-159, Marcel Dekker, Inc., New York (1984).

6. Kroschwitz, J.I. and M. Howe-Grant, editors, “Kirk-Othmer Encyclopedia of Chemical Technology,” 4 ed., Vol. 9, pp.877-915, Wiley, New York (1994).

7. Patel, R., B.P. Evans, and W.K. Lam, “NOx Reduction Technologies for Pyrolysis Furnaces,” Proc. 5th Ethylene Producers’ Conf., 2, pp.416-431, AIChE, New York (1993).

8. Texas Commission on Environmental Quality (TCEQ), Emission Inventory Spreadsheet for HGB Ozone Nonattainment Area (circa 2001-2002).

9. 30 TAC Part I, Chap.17, Subchap. B, Div. 3, Sect. 117.206(c)(8)(B) (eff. May 19, 2005). 10. Kunz, R.G., D.D. Smith, and E.M. Adamo, “Predict NOx from Gas-Fired Furnaces,”

Hydrocarbon Processing, 75(11), 65-79 (Nov. 1996). 11. Just, R., “Flame Rollover and Other Flame Shape Problems,” Proc. 16th Ethylene

Producers’ Conf., 13, pp.594-601, AIChE, New York (2004). 12. Gartside, R.J., P.R. Ponzi, F.D. McCarthy, S.G. Chellappan, P.J. Chapman, and

R.T. Waibel, “Commercialization of Ultra-low NOx Burners for Ethylene Heaters,” Proc. 16th Ethylene Producers’ Conf., 13, pp.618-626, AIChE, New York (2004).

13. Tang, Q., B. Adams, M. Bockelie, M. Cremer, M. Denison, C. Montgomery, A. Sarofim, and D.J. Brown, “Towards Comprehensive CFD Modeling of Lean Premixed Ultra-Low NOx Burners in Process Heaters,” Proc.17th Ethylene Producers’ Conf., 14, pp.594-619, AIChE, New York (2005).

14. Stephens, G. and D. Spicer, “A Low NOx Burner Developed for ExxonMobil Ethylene Furnaces,” Proc. 17th Ethylene Producers’ Conf., 14, pp.487-499, AIChE, New York (2005).

15. Barnett, D. and D. Wu, “Flue-Gas Circulation and Heat Distribution in Reformer Furnaces,” Ammonia Plant Safety & Related Facilities: a Technical Manual, 41, pp.9-16, AIChE, New York (2001).

16. Reed, R.C. and T.K. Sherwood, “The Properties of Gases and Liquids – Their Estimation and Correlation,” p. 2, McGraw-Hill, New York (1958).

17. Kunz, R. G., D. D. Smith, N. M. Patel, G. P. Thompson, and G. S. Patrick, “Control NOx from Gas-Fired Hydrogen Reformer Furnaces,” AM-92-56, 1992 NPRA Annual Meeting, New Orleans, LA (March 22-24, 1992).

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18. Kunz, R.G., D.D. Smith, N.M. Patel, G.P. Thompson, and G.S. Patrick, “Control NOx fromGas-Fired Hydrogen Reformer Furnaces,” pp. 381-392 in Emission Inventory Issues –Proceedings of an International Specialty Conference, Durham, NC, Oct. 19-22, 1992,VIP-27, Air & Waste Management Association: Pittsburgh, PA (1993).

19. Kunz, R.G., D.D. Smith, N.M. Patel, G.P. Thompson, and G.S. Patrick, “Control NOx fromFurnaces,” Hydrocarbon Processing, 71(8), 57-62 (Aug. 1992).

20. Kunz, R.G.; Keck, B.R.; Repasky, J.M. “Mitigate NOx by Steam Injection,” ENV-97-15,1997 NPRA Environmental Conference, New Orleans, LA (Sept. 28-30, 1997).

21. Kunz, R.G.; Keck, B.R.; Repasky, J.M. “Mitigate NOx by Steam Injection” Hydrocarbon Processing, 77(2), 79-84 (Feb. 1998).

22. Kunz, R.G., D.C. Hefele, R.L. Jordan, and F.W. Lash, “Use of SCR in a Hydrogen PlantIntegrated with a Stationary Gas Turbine – Case Study: The Port Arthur Steam-MethaneReformer,” Paper No. 70093, Air and Waste Management Association (A&WMA) 96th

Annual Conference & Exhibition, San Diego, CA (June 22-26, 2003).23. Kunz, R.G., D.C. Hefele, R.L. Jordan, and F.W. Lash, “Consider SCR to Mitigate NOx

Emissions,” Hydrocarbon Processing, 82(11), 43-50 (Nov. 2003).24. Zeldovich, Ya. B., P. Ya. Sadovnikov, and D.A. Frank-Kamenetskii, “Oxidation of

Nitrogen in Combustion,” Academy of Sciences of the USSR, Institute of ChemicalPhysics, Moscow-Leningrad, translated by M. Shelef of the Scientific Research Staff ofthe Ford Motor Company (1947).

25. Hougen, O.A., K.M. Watson, and R.A. Ragatz, “Chemical Process Principles Part I:Material and Energy Balances,” 2 ed., pp.354-357, 408-411, Wiley, New York (1954).

26. Jones, G.W., B. Lewis, J.B. Friauf, and G. St. J. Perrot, “Flame Temperatures ofHydrocarbon Gases,” J. Am. Chem. Soc., 53(3), 869-883 (Mar. 1931).

27. Loomis, A.G. and G. St. J. Perrot, “Measurements of the Temperatures of StationaryFlames,” Ind. Eng. Chem., 20(10), 1004-1008 (Oct. 1928).

28. Singer, J.M., E.B. Cook, M.E. Harris, V.R. Rowe, and J. Grumer, “Flame CharacteristicsCausing Air Pollution: Production of Oxides of Nitrogen and Carbon Monoxide,” 33 pp.,U.S. Bureau of Mines R.I. 6958 (1967).

29. Grumer, J., M.E. Harris, V.R. Rowe, and E.B. Cook, “Effect of Recycling CombustionProducts on Production of Oxides of Nitrogen, Carbon Monoxide and Hydrocarbons byGas Burner Flames,” Preprint 37A, 60th Annual Meeting AIChE, NY (Nov. 26-30, 1967).

30. Lange, H.B., Jr., “NOx Formation in Premixed Combustion,” AIChE Symposium SeriesNo. 126, 17-27 (1972).

31. Kroschwitz, J.I. and M. Howe-Grant, editors, “Kirk-Othmer Encyclopedia of ChemicalTechnology,” 4 ed., Vol. 13, pp.838-894, Wiley, New York (1995).

32. McKetta, J.J., editor, “Encyclopedia of Chemical Processing and Design,” Vol. 47,pp.165-203, Marcel Dekker, Inc., New York (1994).

33. Elvers, B., S. Hawkins, M. Ravenscroft, and G. Schulz, editors, “Ullmann’s Encyclopediaof Industrial Chemistry,” 5 ed., Vol. A 13, pp.317-328, 435-438, VCH, New York (1989).

34. Gary, J.H. and G.E. Handwerk, “Petroleum Refining: Technology and Economics,” 4 ed.,pp. 261-285, 313-317, Marcel Dekker, New York (2001).

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35. O’Leary, J.R., R.G. Kunz, and T.R. von Alten, “Selective Catalytic Reduction (SCR) Performance in Steam-Methane Reformer Service: The Chromium Problem,” ENV-02-178, 2002 NPRA Environmental Conference, New Orleans, LA (Sept. 9-10, 2002).

36. O’Leary, J.R., R.G. Kunz, and T.R. von Alten, “Selective Catalytic Reduction (SCR) Performance in Steam-Methane Reformer Service: The Chromium Problem,” Environmental Progress, 23(3), 194-205 (Oct. 2004).

37. Tindall, B.M. and D.L. King, “Designing Steam Reformers for Hydrogen Production,” Hydrocarbon Processing, 73(7), 69-74 (July 1994).

38. Johansen, T., K.S. Ragharaman, and L.A. Hackett, “Trends in Hydrogen Plant Design,” Hydrocarbon Processing, 71(8), 119-127 (Aug. 1992).

39. Kunz, R.G. and W.F. Baade, “Predict Methanol and Ammonia in Hydrogen-Plant Process Condensate and Deaerator-Vent Emissions,” ENV-00-171, 2000 NPRA Environmental Conference, San Antonio, TX (Sept. 10-12, 2000).

40. Kunz, R.G. and W.F. Baade, “Predict Contaminant Concentrations in Deaerator-Vent Emissions,” Hydrocarbon Processing (Intl. Ed.), 80(6), 100-A to 100-O (June 2001).

41. Royal Dutch/Shell, “The Petroleum Handbook,” 6 ed., p.284, 309, 586, 689, Elsevier, Amsterdam (1983).

42. Bland, W.F. and R.L. Davidson, editors, “Petroleum Processing Handbook,” Section 14, pp. 14-1 to 14-46, McGraw-Hill, New York (1967).

43. Funahashi, K., T. Kobayakawa, K. Ishii, and H. Hata, “SCR DeNOx in New Maruzen Ethylene Plant,” Proc. 13th Ethylene Producers’ Conf., 10, pp.741-755, AIChE, New York (2001).

44. Wines, W.T., “Improve Contaminant Control in Ethylene Production,” Hydrocarbon Processing, 84(4), 41-46 (April 2005).

45. Baukal, C.E., Jr., and R.E. Schwartz, editors, “The John Zink Combustion Handbook,” p.111, CRC Press, Boca Raton, FL (2001).

46. Kunz, R.G. and T.R. von Alten, “SCR Treatment of Ethylene Furnace Flue Gas (A Steam-Methane Reformer in Disguise),” Paper presented at Institute of Clean Air Companies (ICAC) Forum ’02, Houston, TX (Feb. 2002).

47. Waibel, R.T., “Ultra Low NOx Burners for Industrial Process Heaters,” Paper presented at the Second International Conference on Combustion Technologies for a Clean Environment, Lisbon, Portugal (July 19-22, 1993).

48. Krotzer, K., D. Bishop, and D. Giles, “Retrofit Application of an Ultra Low NOx Burner in an Ethylene Furnaces,” (sic) Proc. 9th Ethylene Producers’ Conf., 6, pp.416-431, AIChE, New York (1997).

49. “Ullmann’s Encyclopedia of Industrial Chemistry,” Sixth, Completely Revised Edition, Vol. 12, pp.531-583, WILEY-VCH, Weinheim, Germany (2003).

50. Bussman, W., R. Poe, B. Hayes, J. McAdams, and J. Karan, “Low NOx Burner Technology for Ethylene Cracking Furnaces,” Proc. 13th Ethylene Producers’ Conf., 10, pp.774-796, AIChE, New York (2001).

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APPENDIX A

ADDITIONAL ETHYLENE-FURNACE NOx DATA

I. BURNER NOx DATA FROM HOUSTON OLEFINS PLANT

Synopsis of Reported Information and NOx Predictions. Some ultra low-NOx burner pilot data and furnace field data are contained in a presentation from the 1997 Ethylene Producers’ Conference.48 The Design Case and a field test on a plant fuel are summarized in Table A1; where not clearly specified, the basis for lb/MMBtu was taken as the LHV in accordance with the custom in the burner industry and usage elsewhere in the cited paper. The burners were also designed to achieve 0.08 lb/MMBtu (LHV) (~60 ppmd @ 3% O2 (dry)) on natural gas at 10% excess air (1.72% O2 (wet) and 2.10% O2 (dry)). NOx values were predicted using atmospheric air at 60 °F (15.6 °C) and 60% RH, heated to temperature. For prediction of NOx, the rather high field-test excess O2 (dry) was assumed to reflect furnace O2 without appreciable infiltration of tramp air between the furnace and the stack. Regardless, the predicted NOx curve between the reported O2 and a more typical operating level is fairly insensitive to O2. The ethane vs. ethylene composition of the field-test plant fuel, unclear in the paper, makes little difference in the NOx prediction as well. The pilot data obtained in the burner manufacturer’s test facility are not representative of full-scale operation, for reasons discussed by the manufacturer, and are not reproduced here.

Table A1. Summary of Design Basis, Field Data, and NOx Predictions

Plant Fuel (vol %) Design Case Field Test

Hydrogen (H2) Methane (CH4) Ethane (C2H6)

Ethylene (C2H4) Propane (C3H8)

Propylene (C3H6) Carbon Monoxide (CO)

Nitrogen (N2)

56.24 40.48 0.06 0.42 0.01 0.07 0.40 2.32

56.46 41.26 0.03 0.53

– –

0.14 1.54

Total 100.00 99.96 LHV (Btu/SCF) 533 539 (calc)

Combustion Air Temp. (°F / °C) 750 / 399 (max) 510 / 266

Flue Gas: Low Test

Point High Test

Point Excess Air (%) Excess O2 (% dry) Excess O2 (% wet) Measured NOx (lb/MMBtu (LHV)) Measured NOx (ppmd @ 3% O2) Predicted NOx (lb/MMBtu (LHV) Predicted NOx (ppmd @ 3% O2)

10 2.15 (calc) 1.68 (calc)

0.12 (design) 97.4 (calc)

0.111 90.1

31.1 (calc) 5.50

4.46 (calc) 0.102

82.9 (calc) 0.106 85.8

31.6 (calc) 5.57

4.52 (calc) 0.117

95.0 (calc) 0.105 85.4

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APPENDIX B

SUGGESTIONS FOR ETHYLENE-FURNACE NOx DATA

Table B1. Wish List for Data Sets for NOx Correlation

At Furnace: Fuel (Gaseous) Composition

Temperature Measured Heating Values (HHV and LHV), if available Flow Rate (units? wet or dry, actual or standard – basis for std cubic ft, etc., 60°F, 70°F, 68°F) (enables one to calculate mass flow rates of atmospheric contaminants)

Combustion Air Temperature of Ambient Air Humidity (or enough info, e.g., date and time of testing to get data on ambient air from Weather Bureau) Temperature of Preheated Air (if employed) Flow Rate (if available) (units? wet or dry, actual or standard – basis for std cubic ft, etc., 60°F, 70°F, 68°F)

Flue Gas Excess O2 (probably wet) at Furnace Furnace Bridgewall or Crossover Temperature

Type of Burners Manufacturer and Nomenclature Standard/Conventional Low-NOx (type of low-NOx) Ultra Low-NOx (type) Firing Orientation

At Stack: Flue Gas Contaminant Concentrations (NOx and possibly CO) Specify wet or dry.

Composition of Major Constituents (N2, CO2, O2, and H2O (moisture), or at least O2 and H2O) Temperature Flow Rate (units? wet or dry, actual or standard – basis for std cubic ft, etc., 60°F, 70°F, 68°F)

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Table F.1-1. Summary of Ethylene Cracking Furnace Precedents for SO2 in the RBLC

RBLC ID No. Facility Name Permit

Date Emission Unit

Description

Size in MMBtu/h

r Control Description SO2Limit 1

LA-0206 Baton Rouge Refinery 02/18/04 Feed Preparation

Furnaces F-30 & F-31 352 Limit concentration of H2S in fuel gas to 160 ppmv (0.01 gr/dscf)

0.18 lb/MMBtu

AZ-0046

Arizona Clean Fuels Yuma 04/14/05 Hydrogen Reformer

Heater 1435 S limited to 35 ppm (as H2S) 35 ppmw

AZ-0046

Arizona Clean Fuels Yuma 04/14/05 Atmospheric Crude

Charge Heater 346 35 ppm S limit in fuel. (as H2S) 35 ppmw

AZ-0046

Arizona Clean Fuels Yuma 04/14/05

Butane Conversion Unit Dehydrogenation

Reactor Interheater 328 Sulfur limit of 35 ppm in

fuel burned. (as H2S) 35 ppmw

AZ-0046


Butane Conversion Unit Dehydrogenation

Reactor Charge Heater

311 35 ppm S limit on fuel burned. (as H2s) 35 ppmw

AZ-0046


Butane Conversion Unit Isostripper

Reboiler 222 S limited to 35 ppm in

fuel burned. (as H2S) 35 ppmw

AZ-0046


Hydrocracker Unit Main Fractionator

Heater 211 S limited to 35 ppm. (as

H2S) 35 ppmw

TX-0475

Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnaces

(1001-1008, 1009B) 250 0.38 lb/hr (0.0015 lb/MMBtu

TX-0475

Formosa Point Comfort Plant 05/09/05 Pyrolysis Furnace

(1010b) 250 0.41 lb/hr (0.0016 lb/MMBtu)

TX-0475


(1054-1056) 250 0.38 lb/hr (0.0015 lb/MMBtu)

TX-0475


(1057-1062, 1091) 250 0.38 lb/hr (0.0015 lb/MMBtu)

TX-0475


(N1011-1012) 250 0.41 lb/hr (0.0016 lb/MMBtu)

TX-0511

BASF Ethylene/ Propylene Cracker 02/03/06 Boiler (2) 425.4 12.1 lb/hr

(0.0284 lb/MMBtu) NM-0050 Artesia Refinery 12/14/07 Steam Methane

Reformer Heater 337 Pipeline quality natural gas

0.494 lb/hr (0.0015 lb/MMBtu)


Date Emission Unit

Description

Size in MMBtu/h

r Control Description SO2Limit 1

OH-0308

Sun Company, Inc., Toledo Refinery 02/23/09 Boiler (2) 374 Boilers are the control 9.15 lb/hr

(0.0245 lb/MMBtu) *WY-0071 Sinclair Refinery 10/15/201

2 581 Crude Heater 233 Follow Subpart Ja Fuel gas H2S limits

Permit Equistar Channelview, TX Op-2 11/14/12 Furnace 640 No more than 5 grains

S/100dscf 5 gr/100 dscf

(0.0071 lb/MMBtu) Draft

Permit ExxonMobil Baytown,

TX 2/13 8 Furnaces 575 No more than 5 gr S/100 dscf

5 gr/100 dscf (0.0071 lb/MMBtu)

Permit Chevron /Phillips Cedar Bayou, Tx 08/06/13 8 Furnaces 500

Fuel limited to plant fuel gas, ethane, or pipeline-

quality, sweet natural gas 1. Precedents based on H2S content are eliminated from consideration because they do not take into account other reduced sulfur

compounds that are known to exist in these refinery fuel gases

Table F.1-2. Summary of Catalyst Activation Heater Precedent for SO2 in the RBLC RBLC ID No. Facility Name Permit

Date Unit Description Capacity MMBtu/hr Control Description SO2 Limit

OH-0276 Charter Steel 06/10/04 (3) Tundish Preheaters 12 0.007 lb/hr (0.0006 lb/MMBtu)

OH-0276 Charter Steel 06/10/04 Ladle Preheater & Dryer, 4 Units 10 0.006 lb/hr

(0.0006 lb/MMBtu)

AR-0077 Bluewater Project 07/22/04 Furnaces, Heaters, &, Dryers 11 Natural gas combustion

only 0.0006 lb/MMBtu

WI-0227 Port Washington Generating Station 10/13/04 Gas Heater

(P06, S06) 10 Natural gas fuel 0.02 lb/hr (0.002 l lb/MMBtu)

*PA-0284

AK Steel Corp/Butler Works 03/11/05 Boiler 21 (Htp) 16.6668 0.5 lb/MMBtu

MD-0031 Chalk Point 04/01/05 (2) Natural Gas Fuel Heaters 10 Use of low sulfur fuels 0.056 lb/hr

(0.0056 lb/MMBtu)

AK-0062 Badami Development Facility 08/19/05 Natco Miscible

Injection Heater 14.87 Limit sulfur content of fuel combusted 250 ppmv

OH-0302 Republic Engineered Products, Inc. 08/30/05 (2) Ladle

Dryers/Preheaters 14.5

Good engineering practices; Natural gas w/ S content less than 0.6

wt%

0.01 lb/hr (0.0007 lb/MMBtu)

AR-0090 Nucor Steel, Arkansas 04/03/06 Pickle Line Boilers, Sn-52 12.6

0.1 lb/hr (0.0079 lb/MMBtu)

FL-0286 FPL West County Energy Center 01/10/07 (2) Gas-Fueled Process

Heaters 10 2gr/100 scf

OH-0315 New Steel International, Inc., Haverhill 05/06/08 Vacuum Oxygen

Degasser (4) 16 0.11 lb/hr (0.0069 lb/MMBtu)

FL-0303 FPL West County Energy Center Unit 3 07/30/08 Two Natural Gas-Fired

Process Heaters 10 2 gr/100 scf

AL-0251 Hillabee Energy Center 09/24/08 Fuel Heater 11.64 Pipeline quality natural gas

OK-0135 Pryor Plant Chemical 02/23/09 Nitric Acid Preheaters #1, #3, & #4 20 0.03 lb/hr

(0.0015 lb/MMBtu)

OK-0134 Pryor Plant Chemical 02/23/09 Nitric Acid Preheaters No. 1 (EU 401, EUG

4) 20 Natural gas combustion 0.03 lb/hr

(0.0015 lb/MMBtu)


Date Unit Description Capacity MMBtu/hr Control Description SO2 Limit

*IN-0167 Magnetation LLC 04/16/13 Ground Limestone /Dolomite Additive System Air Heater

19 Use of natural Gas &

good combustion practices

0.0005 lb/MMBtu

Table F.1-3. Summary of Natural Gas-fired Combustion Turbine Precedents for SO2 in the RBLC RBLC ID No. Facility Name Permit

Date Emission Unit

Description MW Control Description SO2 Limit

OK-0056 Horseshoe Energy Project 2/12/02

Turbines & Duct Burners (45 MW GE LM6000 With 185

MMBtu/hr Db)

45 Low Sulfur Fuel (Natural

Gas) 0.0056 lb/MMBtu

TX-0295 Sam Rayburn Generation Station 1/17/02

Combustion Turbines 7,8,9 (No DBs) (45MW

Each) 45 Firing Nat Gas 2.2 lb/hr

MD-0036 Dominion 03/10/06 Solar Titan 130s; 12.2 MW; 137 MMBtu/hr

(@77 F) 12.2 0.9 lb/MW-hr

MD-0035 Dominion 08/12/05 Combustion Turbine 21.7 0.58 lb/MW-hr

NE-0022 C. W. Burdick Generating Station 06/22/04 Gas-Fired Combustion

Turbine 40

Fuel Limited to Pipeline Quality NG, Low Ash &

Sulfur Content Under 0.05%.

5.4 lb/hr

TX-0482 Cobisa Greenville 06/03/05 Turbines & Ducts Firing Natural Gas - Scenario

1, Case 1 80

Firing Low Sulfur Pipeline-Quality Natural Gas And Fuel Oil Will Control SO2 & H2SO4

211.2 lb/hr


2, Case 1 80

Firing Low Sulfur Pipeline-Quality Natural Gas And Fuel Oil Will Control SO2 & H2SO4

211.4 lb/hr


3, Case 1 80

Firing Low Sulfur Pipeline-Quality Natural

Gas & Fuel Oil Will Control SO2 & H2SO4.

231.5 lb/hr

TX-0525 Texas Genco Units 1 & 2 09/13/05 80 MW Gas Turbine 80 Case 3: Turbines Firing Natural Gas With Duct

Burners Fired 0.7 lb/hr

Table F.1-4. Summary of Emergency Generator Precedents for SO2 in the RBLC


Date Emission Unit

Description Size Size in

BHP Control Description SO2 Limit

TX-0440 Corpus Christi LNG 01/20/04 Emergency Diesel Generator 1500 KW 1983 4.44 lb/hr

WV-0023 Maidsville 03/02/04 Emergency Generator 1801 hp 1776 Sulfur content in the fuel

limited to 0.05 wt% 500 hr/yr Op

6.5 lb/hr

LA-0211 Garyville Refinery 12/27/06 Emergency Generators 1341 hp 1322 0.02 lb/hr

IA-0088 ADM Corn Processing - Cedar Rapids 06/29/07 Emergency Generator 1500 KW 1983

Burn low-sulfur diesel fuel 0.05 wt% or less not to exceed

the NSPS requirement. 0.17 g/bhp-hr

SC-0114 GP Allendale LP 11/25/08 Diesel Emergency Generator 1400 hp 1381 5.4 lb/hr

OK-0129 Chouteau Power Plant 01/23/09 Emergency Diesel Generator (2200 hp) 2200 hp 2170 Low sulfur diesel 0.05%S 0.89 lb/hr

SC-0115 GP Clarendon LP 02/10/09 Diesel Emergency Generator 1400 hp 1381

Tune-ups & inspections will be performed as outlined in

the good management practice plan.

5.4 lb/hr

LA-0231 Lake Charles Gasification Facility 06/22/09

Emergency Diesel Power Generator

Engines (2) 1341 hp 1322 Comply with 40 CFR 60

Subpart IIII 0.01 lb/hr

FL-0332 Highlands Biorefinery & Cogeneration Plant 09/23/11 600 hp Emergency

Equipment 600 hp 592 . 0.0015 wt%

IN-0166 Indiana Gasification, LLC 06/27/12 Two (2) Emergency

Generators 1341 hp 1322 Use of low-S diesel & limited

hours of non-emergency operation

15 ppmw

PA-0278 Moxie Liberty LLC/Asylum Power 10/10/12 Emergency Generator 0.005 g/bhp-hr

PA-0268 Moxie Energy LLC/ Patriot Generation Plant 01/31/13 Emergency Generator 0.005 g/bhp-hr

PA-0291 Hickory Run Energy Station 04/23/13 Emergency Generator 1135 bhp 1135 Ultra low sulfur distillate 0.01 lb/hr

OH-0352 Oregon Clean Energy Center 06/18/13 Emergency Generator 2250 KW 2975 0.03 lb/hr

Table F.1-5. Summary of Firewater Pump Engine Precedents for SO2 in the RBLC


Date Emission Unit



TX-0440 Corpus Christi LNG 01/20/04 Diesel Firewater Pump 660 HP 651 1.08 lb/hr

TX-0440 Corpus Christi LNG 01/20/04 Diesel Firewater

Booster Pump 525 HP 518 1.35 lb/hr

TX-0446 Jasper Oriented Strandboard Mill 02/09/04 Fire Water Pump 1.18 lb/hr

WV-0023 Maidsville 03/02/04 IC Engine, Fire Water Pump 85 HP 84 Sulfur content limited to

0.05 wt% 3.3 lb/hr

TX-0447 Carhage Oriented Strandboard Mill 3/16/04 Fire Water Pump 1.23 lb/hr

OH-0275 PSI Energy-Madison Station 08/24/04 Emergency Diesel Fire

Pump

1.6 MMBTU

/H 222

Sulfur limited to 0.05 wt%

Operations limited to 499 hr/yr

0.8 lb/hr

WI-0228 WPS - Weston Plant 10/19/04 Main Fire Pump

(Diesel Engine) 460 HP 454 Good combustion

practices, ULSD (0.003 Wt. % S)

0.94 lb/hr

NC-0112 Nucor Steel 11/23/04

Diesel Fired Emergency Generators

And Diesel Fired Emergency Water

Pumps

Operation limited to 100 hours for each emergency generator & water pump

per 12 month period

OH-0252 Duke Energy Hanging Rock Energy Facility

12/28/04 Fire Water Pump (1) 265 HP 261 Low sulfur fuel 0.1 lb/hr

LA-0192 Crescent City Power 06/06/05 Diesel Fired Water

Pump 425 HP 419 Good engine design &

Proper operating practices

0.61 lb/hr

NC-0101 Forsyth Energy Plant 09/29/05 IC Engine, Emergency

Firewater Pump

11.4 MMBTU

/H 1581 0.58 lb/hr


Date Emission Unit



TX-0511 BASF


02/03/06 (2) Fire Water Pump Engine 1.05 lb/hr

IA-0088 ADM Corn Processing - Cedar Rapids

6/29/07 Fire Pump 540 HP 533

Burn low-Sulfur diesel Fuel. 0.05 wt% or less not to exceed the NSPS

requirement.

0.17 g/bhp-hr

IA-0089 Homeland Energy Solutions, LLC,

PN 06-672 08/08/07

Emergency Diesel Fire Water Pump, S110,

(07-A-982p) 300 BHP 300 None 0.203 g/kwh

MN-0070 Minnesota Steel Industries, LLC 09/07/07

Diesel Fire Water Pumps

(500 HP)

Limited sulfur In fuel; limited hours 0.05 wt%

LA-0224 Arsenal Hill Power Plant 03/20/08 DFP Diesel Fire Pump 310 HP 306

Use of low-sulfur fuels, limiting operating hours

& proper engine maintenance

0.64 lb/hr

FL-0304 Cane Island Power Park 09/08/08

Emergency Fired Pump 7 ULSD Oil Storage

Tank

IA-0095 Tate & Lyle Ingredients

Americas, Inc. 9/19/08 Fire Pump Engine 575 HP 567 Limit on sulfur in fuel 0.23 g/kwh

MD-0040 CPV St Charles 11/12/08 Internal Combustion Engine - Emergency

Fire Water Pump 300 HP 296

SC-0114 GP Allendale LP 11/25/08 Fire Water Diesel Pump 525 HP 518

Tune-ups & inspections will be performed as

outlined in good management practice

plan

0.39 lb/hr

OK-0129 Chouteau Power Plant 01/23/09 Emergency Fire Pump

(267-Hp Diesel) 267 HP 263 Low sulfur diesel 0.11 lb/hr


Date Emission Unit



SC-0115 GP Clarendon LP 02/10/09 Fire Water Diesel Pump 525 HP 518

Tune-ups & inspections will be performed as

outlined in good management practice

plan

0.39 lb/hr

LA-0231 Lake Charles Gasification

Facility 06/22/09 Fire Water Diesel

Pumps (3) 575 HP 567 Comply with 40 CFR 60 subpart IIII 0.01 lb/hr

FL-0318 Highlands Ethanol Facility 12/10/09 Emergency Fired Pump 360 HP 355 Ultra low sulfur fuel oil

(ULSFO) 15 ppmw

FL-0324 Palm Beach Renewable

Energy Park 12/23/10 Two emergency diesel

firewater pump engines 250 HP 246 15 ppmw

FL-0323 Gainesville Renewable

Energy Center 12/28/10 Emergency Diesel Fire

Pump - 275 HP 275 HP 271

The permittee shall adhere to the compliance

testing & certification requirements listed in 40

CFR 60.4211 and maintain records

demonstrating fuel usage and quality.

15 ppmw

SC-0113 Pyramax Ceramics, LLC 02/08/12 Fire Pump 500 HP 493

Use Of Low Sulfur Fuel Diesel, Sulfur Content

Less Than 0.0015 Percent. Operating Hours Less Than 100 Hours Per Year For Maintenace And

Testing.

IN-0166 Indiana Gasification, LLC 06/27/12 Three (3) Firewater

Pump Engines 575 HP 567 Use Of Low-S Diesel & Limited Hours Of Non-Emergency Operation

15 ppmw


Date Emission Unit



WY-0070 Cheyenne Prairie

Generating Station

08/28/12 Diesel Fire Pump Engine (EP16) 327 HP 322 Ultra Low Sulfur Diesel

PA-0278 Moxie Liberty LLC/ Asylum

Power Pl T 10/10/12 Fire Pump 0.005 g/bhp-hr

IN-0158 St. Joseph Energy Center, LLC 12/03/12 Two (2) Firewater

Pump Diesel Engines 371 BHP 371 Ultra Low Sulfur Distillate & Usage Limits 15 ppmw

PA-0286 Moxie Energy LLC/Patriot

Generation PLT 1/31/13 Fire Pump Engine - 460

BHP 460 BHP 460

0.005 g/hp-hr

IN-0167 Magnetation LLC 04/16/13 Fire Water Pump 300 HP 296 Use of Natural Gas &


0.0015 g/kwh

PA-0291 Hickory Run Energy Station 4/23/13

Emergency Firewater Pump (450 BHP)

3.25 MMBTU

/H 450

0.0055 lb/hr

OH-0352 Oregon Clean Energy Center 06/18/13 Emergency fire pump

engine 300 HP 296 0.003 lb/hr

NH3 BAT Analysis - RBLC Database Summaries

Table F.2-1 Summary of NH3 RBLC and Recent Permits for Furnaces RBLC ID

No. Facility Name Permit Date Emission Unit Description

Capacity (MMBtu/hr) NH3 Limit

TX-0505 Certainteed Insulation Fiber Glass & Ductliner Manufacturing 04/19/06 Bi Stack 73.85 lb/hr

TX-0526 Air Products Hydrogen, Steam, & Electricity Production 08/18/06

Reformer Furnace Stack 1373 24.9 lb/hr

TX-0496 Ineos Chocolate Bayou Facility 08/29/06 Furnace Emission Caps 27.47 lb/hr

NM-0050 Artesia Refinery 12/14/207 Steam Methane Reformer Heater 337 7 ppmv (WET)

TX-0580 Mckee Refinery Hydrogen Production Unit 12/30/210

Hydrogen Production Unit Furnace 355.65

10 ppmv

Not in RBLC BASF Fina Port Arthur, TX1 7/16/12 Cracking Furnace 487.5 10 ppmvd at 15% O2

Not in RBLC Equistar Channelview, TX Op-2 2 11/14/12 Furnace 640 10 ppmvd at 3% O2 hourly

Not in RBLC Equistar Channelview, TX Op-1 3 1/12/13 Furnace 640 10 ppmv at 3% O2

Not in RBLC ExxonMobil Baytown, TX 4

2/13 (DRAFT) Furnace 575 15 ppmvd at 3% O2 hourly

Not in RBLC Chevron/Phillips Cedar Bayou, TX 5 08/06/13 Furnace 500

10 ppmvd at 3% O2 hourly and annually

1. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 36644, PSDTX903M3, and N007M1, 7/2012

2. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 2933/PSDTX1270/N140, 11/20123. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 18978 PSDTX752M5, N162, 1/20134. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1029825. TCEQ Special Conditions & Maximum Allowable Emission Rates Permit Numbers 1504A,PSDTX748M1/N148

Table F.2-2 Summary of NH3 RBLC Results for Combustion Turbines RBLC ID No. Facility Name Permit

Date Emission Unit Description Capacity NH3 Limit

OR-0043 Umatilla Generating Company, L.P. 05/11/04

Turbine, Combined Cycle &Amp; Duct Burner, Nat Gas (2) 2,007 MMBtu/hr 5 ppmvd @ 15% O2

NV-0037 Copper Mountain Power 05/14/04 Large Combustion Turbines, Combined Cycle &Amp; Cogeneration 600 MW 10 ppmvd

NV-0033 El Dorado Energy, LLC 08/19/04 Combustion Turbine, Combined Cycle &Amp; Cogen(2) 475 MW 10 ppmvd @ 15% O2

TX-0479 Dow Texas Operations Freeport 12/02/04 Piping Fugitives For Turbines (5) 0.26 lb/hr

TX-0479 Dow Texas Operations Freeport 12/02/04

Combustion Via Four Gas-Fired Steam Boilers 410 MMBtu/hr 1.7 lb/hr


2 WESTINGHOUSE 501F TURBINES WITH 2 735mmbtu/Hr DUCT BURNER (START UP) 735 MMBtu/hr

27.58 lb/hr


2 WESTINGHOUSE 501F TURBINES WITH 2 735mmbtu/Hr DUCT BURNER (START-UP, SHUTDOWN, MAINTENANCE) 735 MMBtu/hr

27.58 lb/hr

OH-0252 Duke Energy Hanging Rock Energy Facility 12/28/04

Turbines (4) (Model Ge 7fa), Duct Burners Off 172 MW 28 lb/hr

OH-0252 Duke Energy Hanging Rock Energy Facility 12/28/04

Turbines (4) (Model Ge 7fa), Duct Burners On 172MW 37.8 lb/hr

WA-0328 BP Cherry Point Cogeneration Project 01/11/05

Ge 7fa Combustion Turbine &Amp; Heat Recovery Steam Generator 174 MW 5 ppmvd

FL-0263 FPL Turkey Point Power Plant 02/08/05 170 Mw Combustion Turbine, 4 Units 170 MW 5 ppmvd @ 15% O2

TX-0482 Cobisa Greenville 06/03/05 Turbines And Ducts Firing Natural Gas - Scenario 4, Case 1 825 MMBtu/hr 127.4 lb/hr




OR-0041 Wanapa Energy Center 08/08/05 Combustion Turbine &Amp; Heat Recovery Steam Generator 2,384.1 MMBtu/hr 5 ppmvd @ 15% O2



NJ-0066 AES Red Oak LLC 02/16/06 Combined Cycle Natural Gas Fired Combustion Turbines( 3) 63,122 MMscf/yr 29.1 lb/hr

TX-0509 Ponderosa Pine Energy Partners Cogeneration 03/15/06

Turbine And 375 MMBtu/hr Heat Recovery Steam System 250 MW 32.5 lb/hr

TX-0506 NRG Texas Electric Power Generation 04/19/06 Annual Limits 89.7 T/YR

TX-0504 Navasota Power Generation Facility 04/20/06

Turbines Without 165 MMBtu/hr Duct Burners 75 MW 9.6 lb/hr

TX-0504 Navasota Power Generation Facility 04/20/06 Startup, Shutdown, Maintenance 75 MW 10.8 lb/hr

TX-0504 Navasota Power Generation Facility 04/20/06

Turbines With 165 MMBtu/hr Duct Burners 75 MW 11.1 lb/hr

TX-0502 Nacogdoches Power Sterne Generating Facility 06/05/06

Westinghouse/Siemens Model SW501F Gas Turbine w/ 416.5 MMBtu Duct Burners 190 MW

16.8 lb/hr

TX-0497 Ineos Chocolate Bayou Facility 08/29/06

Cogeneration Train 2 & 3 (Turbine & Duct Burner Emissions) 35 MW 8.45 lb/hr

FL-0285 Progress Bartow Power Plant 01/26/07

Combined Cycle Combustion Turbine System (4-On-1) 1,972 MMBtu/hr 5 ppmvd

FL-0286 FPL West County Energy Center

01/10/07 Combined Cycle Combustion Gas Turbines - 6 Units

2,333 MMBtu/hr 5 ppmvd @ 15 % O2

PA-0260 Delta Power Plant 01/03/08 Gas Fired Turbines (6) (Simple Cycle) 11,240 5 ppmvd @ 15% O2 PA-0260 Delta Power Plant 01/03/08 Gas Fired Turbines (60 (Combined Cycle) 11,240 5 ppmvd @ 15% O2 CT-0151 Kleen Energy Systems,

LLC 02/25/08 Siemens SGT 6-5000F Combustion

Turbine #1 & #2 (Natural Gas Fired) w/ 445 MMBtu/hr Natural Gas Duct Burner

2.1 MMcf/hr 2 ppm @ 15 % O2 at steady state

5 ppm @ 15% O2 all other times

FL-0305 OUC Curtis H. Stanton Energy Center 05/12/08

300 MW Combined Cycle Combustion Turbine 1,765 MMBtu/hr 5 ppmvd

FL-0304 Cane Island Power Park 09/0808 300 MW Combined Cycle Combustion Turbine 1,860 MMBtu/hr 5 ppmvd

TX-0600 Thomas C. Ferguson Power Plant 09/01/11 Natural Gas-Fired Turbines 390 MW 7 ppmvd

PA-0276 York Generation Facility 03/01/12 Combustion Turbine, Dual Fuel, T01 & T02 (2 Units) 634 MMBtu/hr 5 ppm

PA-0278 Moxie Liberty LLC/Asylum Power PLT 10/10/12

Combined-Cycle Turbines (2) - Natural Gas Fired 3,277 MMBtu/hr 5 ppmvd at 15% O2



OH-0356 Duke Energy Hanging Rock Energy 12/18/12

Turbines (4) (Model GE 7FA) Duct Burners Off 172 MW 28 lb/hr

OH-0356 Duke Energy Hanging Rock Energy 12/18/12

Turbines (4) (Model GE 7FA) Duct Burners On 172 MW 31.7 lb/hr

PA-0288 Sunbury Generation LP/Sunbury SES 04/01/13

Combined Cycle Combustion Turbine & Duct Burner (3) 2,538,000 MMBtu/hr 5 ppmvd at 15% O2

PA-0291 Hickory Run Energy Station 04/23/13

Combined Cycle Units #1 & #2 Natural Gas 3.4 MMcf/hr 110.2 tpy

1. 42 Pa.B. 4724 confirms 15% O2

2. 43 Pa.B. 1425 confirms 15% O2

Appendix G

Compliance Demonstration Certain information in this appendix has been redacted. Redacted information constitutes trade secret and/or

confidential proprietary information as defined in the Pennsylvania Right to Know Law

Table G-1. Summary of Compliance Demonstration

Process Area Equip. ID Emissions Unit Pollutant Affected Source Regulation Compliance Requirement

Compliance Demonstration

Recordkeeping & Reporting

Ethylene Production

§63.1103(e)(2) -Ethylene production or production unit means a chemical manufacturing process unit in which ethylene and/or propylene are produced by separation from petroleum refining process streams or by subjecting hydrocarbons to high temperatures in the presence of steam. The ethylene production unit includes the separation of ethylene and/or propylene from associated streams such as a C4 product, pyrolysis gasoline, and pyrolysis fuel oil. Ethylene production does not include the manufacture of SOCMI chemicals such as the production of butadiene from the C4 stream and aromatics from pyrolysis gasoline.

§63.1103(e)(1)(i) -The affected source shall comprise all emission points listed in paragraphs (e)(1)(i) (A) through (G) of this section that are associated with an ethylene production unit that is located at a major source, as defined in section 112(a) of the Act.

Equipment Leaks HAP §63.1103(e)(1)(i)(D), §63.1019 Part 63 Subpart YY

§63.1103(e)(3) - Table 7(f)(1); §63.1107

§§63.1022 - 63.1035 §63.1038, §63.1039

non-HAP Part 63 Subpart YY

§63.1103(e) (1)(ii)(A) -Exception: Not subject to control requirements of 63.1103(e)(3).

NA NA

Ethylene Production Unit HAP §63.11 Part 63 Subpart A, Part 63 Subpart YY

§63.1, §63.1108(a)(1),(2), (5), (6), (7)

§§63.5 - 63.9, §63.11, §63.1108(b)

§63.10, §63.1109,§63.1110

All waste streams associated with an ethylene production unit.

§63.1103(e)(1)(i)(E) Part 63 Subpart YY

§63.1103(e)(3) - Table 7(g)(1)(i)

§§63.1091 - 1094 as applicable, §63.1095(b)(1),§61.342(c)(1), (2),(3)(i); §61.348(a)

§61.356 as applicableexcept §61.356(b)(2)(ii), (b)(3) through (b)(5); §61.357 as applicableexcept submit the information required in §61.357(a) as part ofthe Initial Notification required in §63.1110(c), submit the information in §61.357(d)(1) and (d)(2) for spent caustic, dilution steam blowdown, and continuous butadiene waste streams, submit the information required in §61.357(d)(1) as part ofthe Notification of Compliance Status required in §63.1110(d) and do not comply with §61.357(d)(3) through(d)(5).

T59708 Recovered Oil Storage - Wastewater Tank

HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX

§63.1095(b)(1) §61.348(b)(1), (c)(2),(e)-(g); §61.343(a), (c), (d); §61.349 as applicable; §61.354 as applicable; §61.355 asapplicable but specifically (h)

T59709 Biotreater Aeration Tank - Wastewater Treatment


§63.1095(b)(1) §61.342(c)(1)(i);§61.348(b)(2), (c)(1),(f)(g); §61.354(b)(2); §61.355(c)(3), (g)

A5401 Spent Caustic Vent Incinerator - Closed Vent System and Control Device


§63.1095(b)(1) §61.342(c)(1)(i);§61.348(a)(1)(iii);§61.348(c)(2);§61.349(a)(1),(a)(2)(i), (b), (c)(2), (e) - (h); §61.354(a)(2), (c)(1),(f), (g); §61.355(f), (h), (i)

1

Redacted information constitutes trade secret and/or confidential proprietary information as defined in the Pennsylvania Right to Know Law





Wastewater - Individual Drain System


§63.1095(b)(1) §61.346; §61.349 asapplicable; §61.354 as applicable; §61.355 asapplicable but specifically (h)

T59707A/B FEOR Tank - Wastewater OWS HAP §63.1103(e)(1)(i)(E) Part 63 Subpart XX

§63.1095(b)(1) §61.348(b)(1), (c),(e)-(g); §61.347 as applicable; §61.349 as applicable; §61.354 asapplicable; §61.355 as applicable but specifically (h)

T53501 Spent Caustic Storage - Wastewater Tank


§63.1095(b)(1) §61.348(b)(1), (c)(2),(e)-(g); §61.343(a), (c), (d); §61.349 as applicable; §61.354 as applicable; §61.355 asapplicable but specifically (h)

T53502 Unoxidized Spent Caustic Storage - Tank

HAP §63.1103(e)(1)(i)(A), §63.1060 Part 63 Subpart YY

§63.1103(e)(3) - Table 7(b)(1)(i)

§63.1062, §63.1063 §63.1065, §63.1066

2






Ethylene process vents - 63.1103(e)(2) Definitions. Ethylene process vent means a gas stream with a flow rate greater than 0.005 standard cubic meters per minute containing greater than 20 parts per million by volume HAP that is continuously discharged during operation of an ethylene production unit, as defined in this section. Ethylene process vents are gas streams that are discharged to the atmosphere (or the point of entry into a control device, if any) either directly or after passing through one or more recovery devices. Ethylene process vents do not include relief valve discharges; gaseous streams routed to a fuel gas system; leaks from equipment regulated under this subpart; episodic or nonroutine releases such as those associated with startup, shutdown, and malfunction; and in situ sampling systems (online analyzers).

HAP §63.1103(e)(1)(i)(B) Part 63 Subpart YY

§63.1103(e)(3) - Table 7(d)(1)(i); §63.1104 except for paragraphs (d), (g), (h), (i), (j), (l)(1), and (n).

§63.982(b), §63.983 §63.998, §63.999

V64205/ V64206

C3+ Storage - Sphere HAP §63.1103(e)(1)(i)(A) Part 63 Subpart YY

§63.1103(e)(1)(ii)(K) -Exception: Not subject to control requirements of §63.1103(e)(3).

NA

T64207/ T64208

Light Gasoline Storage - Tank HAP §63.1103(e)(1)(i)(A) Part 63 Subpart YY

§63.1103(e)(3) - Table 7(b)(1)(ii)

§63.982(b), §63.983 §63.998, §63.999

T64201 Pyrolysis Tar Storage - Tank HAP §63.1103(e)(1)(i)(A) Part 63 Subpart YY

§63.1103(e)(1)(ii)(G) -Exception: Not subject to control requirements of §63.1103(e)(3).

NA

C3+ Loading - Transfer Rack HAP §63.1103(e)(1)(i)(C) Part 63 Subpart YY

§63.1103(e)(1)(ii)(I) -Exception: Not subject to control requirements of §63.1103(e)(3).

NA

Pyrolysis Tar Loading - Transfer Rack

HAP §63.1103(e)(1)(i)(C) Part 63 Subpart YY

§63.1103(e)(1)(ii)(H) -Exception: Not subject to control requirements of §63.1103(e)(3).

NA

3






Ethylene cracking furnaces and associated decoking operations

HAP §63.1103(e)(1)(i)(G) Part 63 Subpart YY

§63.1103(e)(1)(ii)(J) -Exception: Not subject to control requirements of §63.1103(e)(3).

NA

HPGFLARE1/2, HPEFLARE, REFTANKFLARE

High Pressure Ground Flares, High Pressure Elevated Flare, Refrigerated Tank Flare

HAP §63.11(a)(1), (2) Part 63 Subpart A

§63.11(b) §63.11(b)(4), (5);§63.987; §63.997(a)- (c)

§63.998, §63.999

Stormwater from segregated sewers, water from fire-fighting and deluge systems in segregated sewers, Spills, Water from safety showers, Water from testing of fire-fighting and deluge systems, Vessels storing organic liquids that contain organic HAP as impurities, Vessels permanently attached to motor vehicles such as trucks, railcars, barges, or ships.

Non-HAP Part 63 Subpart YY

§63.1103(e)(1)(ii)(B) -(G), (L) Exception: Not subject to control requirements of §63.1103(e)(3).

NA

Heat Exchange System HAP §63.1103(e)(1)(i)(F), §63.1083, §63.1084 Part 63 Subpart YY

§63.1085 §§63.1086 - 63.1088 §63.1089, §63.1090

V64201/ V64202

Ethylene Storage - Sphere VOC §60.110b(a) Part 60 Subpart Kb

§60.112b(d)(2) - Thissubpart does not apply to the following: Pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.

NA

§60.116b

V64205/ V64206

C3+ Storage - Sphere

V18831 DMDS Storage - Tank T-64201 Ethylene Refrigerated

Atmospheric Storage V-64203 Refrigerant Storage

T53501 Spent Caustic Storage - Wastewater Tank

§60.112b(a) §63.1100(g)(1)(ii) -After the compliance date, a storage vessel that must be controlled according to the requirements of Part 63 Subpart YY and subpart Kb or 40 CFR Part 60 is required to comply only with the storage vessel

NA

T53502 Unoxidized Spent Caustic Storage - Tank

T64207/ T64208

Light Gasoline Storage - Tank

4






requirements of Part 63 Subpart YY.

T64202 Pyrolysis Tar Storage - Tank §60.112b(a)(3) §60.113b(c) §60.115b(c), §60.116b

T59708 Recovered Oil Storage - Wastewater Tank

VOC Storage Tank 25 Pa. Code Ch. 129

25 Pa. Code §129.57

T59707A/B FEOR Tank - Wastewater OWS 25 Pa. Code §129.56(a)(2) T53501 Spent Caustic Storage -

Wastewater Tank T53502 Unoxidized Spent Caustic Storage -

Tank V64205/V64206

C3+ Storage - Sphere

T64207/T64208

Light Gasoline Storage - Tank

V64201/V64202

Ethylene Storage - Sphere

V18831 DMDS Storage - Tank 25 Pa. Code §129.57 T-64201 Ethylene Refrigerated

Atmospheric Storage 25 Pa. Code §129.56(a)(2)

V-64203 Refrigerant Storage T64202 Pyrolysis Tar Storage - Tank 25 Pa. Code §129.57

Ethylene Production Unit VOC Waste gas streams 25 Pa. Code §129.65

25 Pa. Code §129.65 - No person may permit the emission into the outdoor atmosphere of a waste gas stream from an ethylene production plant or facility unless the gas stream is properly burned at no less than 1,300°F for at least .3 seconds; except that no person may permit the emission of volatile organic compounds in gaseous form into the outdoor atmosphere from a vapor blowdown system unless these

5






gases are burned by smokeless flares.

GHG §98.240 Part 98 Subpart X

§§98.241-243, 245 §98.244 §§98.246, 247

Equipment Leaks VOC 25 Pa. Code §129.71(a) - This section applies to a facility with design capability to manufacture 1,000 tons per year or more of the following: (1) Synthetic organic chemicals listed in 40 CFR 60.489 (relating to list of chemicals provided by affected facilities).

25 Pa. Code §129.71

25 Pa. Code §129.71(d) 25 Pa. Code §129.71(d)

25 Pa. Code §129.71(d), (e)

§60.480a Part 60 Subpart VVa

§§60.482-1a - 60.482-11a §60.485a §60.486a, §60.487a

A5401 Spent Caustic Vent Incinerator - Closed Vent System and Control Device

NOx 25 Pa. Code §121.1 - Incinerator - A device designed to burn or oxidize solid, semisolid, liquid or gaseous wastes for the primary purpose, as determined by the Department, of volume reduction or of disposal. The term includes heat recovery systems.

25 Pa. Code Ch. 129

25 Pa. Code §129.93(c)(4), (6)

PM 25 Pa. Code Ch. 123

25 Pa. Code §123.12




25 Pa. Code Ch. 129

25 Pa. Code §129.93(c)(4), (6)


25 Pa. Code §123.12



VOC Part 60 Subpart A

§60.18

Process Vents VOC

§60.660, §60.667 Part 60 Subpart NNN §60.662 §60.663, §60.664 §60.665

6






PM 25 Pa. Code §121.1 Process - A method, reaction or operating in which materials are handled or whereby materials undergo physical change-that is, the size shape, appearance, temperature, state or other physical property of the material is altered-or chemical change-that is, as substance with different chemical composition or properties is formed or created. The term includes all of the equipment, operations and facilities necessary for the completion of the transformation of the materials to produce a physical or chemical change. There may be several processes in series or parallel necessary to the manufacture of a product.

25 Pa. Code Ch. 123

25 Pa. Code §123.13(a), (c)(1)

Ethylene cracking furnaces and

associated decoking operations NOx 25 Pa. Code §123.51(a) - Combustion units with

a rated heat input of 250MMBtu/hr or greater and with an annual average capacity factor of greater than 30%.

25 Pa. Code Ch. 129

25 Pa. Code §129.93(c)(6)

25 Pa. Code §129.91(i), (j)

SO2 25 Pa. Code §121.1 - Combustion unit - A stationary equipment used to burn fuel primarily for the purpose of producing power or heat by indirect heat transfer.

25 Pa. Code Ch. 123

25 Pa. Code §123.22(d)(2)

NA

PM 25 Pa. Code

§123.11(a)(2) Polyethylene 1/2/3

§63.2440(a) - This subpart applies to each miscellaneous organic chemical manufacturing affected source.

§63.2440(b) - The miscellaneous organic chemical manufacturing affected source is the facilitywide collection of MCPU and heat exchange systems, wastewater, and waste management units that are associated with manufacturing materials described in §63.2435(b)(1).

Polyethylene Production Unit HAP §63.2435(a), (b)(1)(i), (b)(2); §63.2440(a), (b), (c)(1)

Part 63 Subpart A, Part 63 Subpart FFFF

§63.1, §63.2450, §63.2550

§§63.5 - 63.9, §63.11, §63.2450

§63.10, §63.2515, §63.2520, §63.2525

Equipment Leaks HAP §63.2435(b), §63.1019 Part 63 Subpart FFFF

§63.2480(a) - Table 6 - 2ai

§§63.1022 - 63.1035 §63.1038, §63.1039

Process Wastewater

HAP

§63.2440(b); §63.2485(b), (c); §63.2550(i); §63.132(b) - (e)

Part 63 Subpart FFFF

§63.2485(a) - Table 7; §63.132

§63.2485(d) - (f), (i) - (k), (m), (n); §§63.132 through 63.148 and the requirements referenced therein, except as specified in §63.2485.

§63.2485(o) if applicable.

Maintenance wastewater §63.2440(b); §63.2550(i) §63.2485(a) - Table 7 §63.105 and the requirements referenced therein, except as specified in §63.2485.

§63.105(e)

7






Liquid streams in an open system within an MCPU

§63.2435(b) §63.2485(l) §63.149 and therequirements referenced therein, except as specified in §63.2485.

Stormwater from segregated sewers; Water from fire-fighting and deluge systems, including testing of such systems; Spills; Water from safety showers; Samples of a size not greater than reasonably necessary for the method of analysis that is used; Equipment leaks; Wastewater drips from procedures such as disconnecting hoses after cleaning lines; and Noncontact cooling water.

Non-HAP 63.2550(i) - The following are not considered wastewater for the purposes of this subpart: Stormwater from segregated sewers; Water from fire-fighting and deluge systems, including testing of such systems; Spills; Water from safety showers; Samples of a size not greater than reasonably necessary for the method of analysis that is used; Equipment leaks; Wastewater drips from procedures such as disconnecting hoses after cleaning lines; and Noncontact cooling water.

NA

8






Process Vents HAP §63.2450(c); §63.2550(i) - Continuous processvent means the point of discharge to the atmosphere (or the point of entry into a control device, if any) of a gas stream if the gas stream has the characteristics specified in §63.107(b) through (h), or meets the criteriaspecified in §63.107(i), except: (1) The reference in §63.107(e) to a chemical manufacturing process unit that meets the criteria of §63.100(b) means an MCPU that meets the criteria of §63.2435(b); (2) The reference in §63.107(h)(4) to §63.113 means Table 1 to this subpart; (3) The references in §63.107(h)(7) to §§63.119 and 63.126 meantables 4 and 5 to this subpart; and (4) For the purposes of §63.2455, all references to the characteristics of a process vent (e.g., flowrate, total HAP concentration, or TRE index value) mean the characteristics of the gas stream. (5) The reference to “total organic HAP” in §63.107(d) means “total HAP” for the purposesof this subpart FFFF. (6) The references to an “air oxidation reactor, distillation unit, or reactor” in §63.107 mean any continuous operation for the purposes of this subpart. (7) A separate determination is required for the emissions from each MCPU, even if emission streams from two or more MCPU are combined prior to discharge to the atmosphere or to a control device.


§63.2455, §63.2455 -Table1 - 1ai, §63.2455 - Table1 - 4

§63.982(b);§63.982(c)(2);§63.983; §63.993

§63.998, §63.999

S2003A/B HAP Metal Process Vent Metal HAP §63.2550(i) - HAP metals means the metal portion of antimony compounds, arsenic compounds, beryllium compounds, cadmium compounds, chromium compounds, cobalt compounds, lead compounds, manganese compounds, mercury compounds, nickel compounds, and selenium compounds.


§63.2465(a) - Table 3 - 2 §63.2465(d)

HPGFLARE1/2

High Pressure Header Ground Flares

HAP §63.2455 Part 63 Subpart FFFF

§63.2450(e)(2) §63.11;§63.2450(f)(1)

§63.2450(f)(2); §63.998,§63.999

LPGFLARE Low Pressure Header Ground Flare

9






LPINCINERATOR

Low Pressure Header Incinerator §63.2450(e)(1) §63.2450(g), (i), (k);§63.988; §§63.996,997 as applicable.

§63.998, §63.999

T64301 Hexene Storage - Tank Non-HAP §63.2250(i) - Storage tank means a tank or other vessel that is used to store liquids that contain organic HAP and/or hydrogen halide and halogen HAP and that has been assigned to an MCPU according to the procedures in §63.2435(d).


NA NA

§63.2525(a)

T64302 Hexene Storage - Tank

V64301 Butene Storage - Sphere

V64302 Butene Storage - Sphere

V64401 Isopentane Storage - Bullet

V64402 Isopentane Storage - Bullet

V64501 Isobutane Storage - Bullet

V64502 Isobutane Storage - Bullet

PEHEATEXCH Heat Exchange System HAP §63.2440(b); §63.2490 - Table 10; §63.104(a)Unless one or more of the conditions specified in paragraphs (a)(1) through (a)(6) of this section are met, owners and operators of sources subject to this subpart shall monitor each heat exchange system used to cool process equipment in a chemical manufacturing process unit .

§63.104(a) (5) The recirculating heat exchangesystem is used to cool process fluids that contain less than 5 percent by weight of total hazardous air pollutants listed in table 4 of this subpart.


NA NA

§63.2525(a)

LPGFLARE Low Pressure Header Ground Flare VOC Part 60 Subpart A

§60.18

PE1/2/3 Polyethylene Production Unit VOC §60.560(a) Part 60 Subpart DDD

§60.560(c) §60.564 §60.565

10






Emergency vent streams VOC §60.561 - Emergency vent stream means anintermittent emission that results from a decomposition, attempts to prevent decompositions, power failure, equipment failure or other unexpected cause that requires immediate venting of gases from process equipment in order to avoid safety hazards or equipment damage. This includes intermittent vents that occur from process equipment where normal operating parameters (e.g., pressure or temperature) are exceeded such that the process equipment cannot be returned to normal operating conditions using the design features of the system and venting must occur to avoid equipment failure or adverse safety personnel consequences and to minimize adverse effects of the runaway reaction. This does not include intermittent vents that are designed into the process to maintain normal operating conditions of process vessels including those vents that regulate normal process vessel pressure.

Part 60 Subpart DDD

§60.560(h) - Emergencyvent streams from a new, modified or reconstructed polyethylene affected facility are exempt from the requirements of §60.562-1(a)(2).§60.562-1(a)(2) - Thisparagraph does not apply to emergency vent streams exempted by §60.560(h) and as defined in §60.561.

NA NA

Equipment Leaks VOC §60.560(a)(4) - For VOC emissions fromequipment leaks from polypropylene, polyethylene, and polystyrene (including expandable polystyrene) manufacturing processes, the affected facilities are each group of fugitive emissions equipment (as defined in §60.561) within any process unit (as defined in§60.561). This subpart does not apply to VOCemissions from equipment leaks from poly(ethylene terephthalate) manufacturing processes.

Part 60 Subpart DDD

§60.562-2 §60.485 §60.486, §60.487

PE1BLENDA/B/C/D/E, PE2BLENDA/B/C/D/E

PE Process Vents VOC

§60.561 - Vent stream means any gas streamreleased to the atmosphere directly from an emission source or indirectly either through another piece of process equipment or a material recovery device that constitutes part of the normal recovery operations in a polymer process line where potential emissions are recovered for recycle or resale, and any gas stream directed to an air pollution control device. The emissions released from an air pollution control device are not considered a vent stream unless, as noted above, the control

Part 60 Subpart DDD

§60.562-1(a)(2) §60.560(g) toexempt this intermittent vent; §60.563(e) torequest compliance "by any other means", specifically residual VOC content in the granular resin below a level of 50 ppmw of resin.

§60.565(a)(10),§60.565(h)

11






device is part of the normal material recovery operations in a polymer process line where potential emissions are recovered for recycle or resale. Continuous emissions means any gas stream containing VOC that is generated essentially continuously when the process line or any piece of equipment in the process line is operating. Intermittent emissions means those gas streams containing VOC that are generated at intervals during process line operation and includes both planned and emergency releases.

§60.562-1(a)(1)(i),§60.560(g) - Individualvent streams that emit continuous emissions with uncontrolled annual emissions of less than 1.6 Mg/yr (1.76 ton/yr) or with a weight percent TOC of less than 0.10 percent from a new, modified, or reconstructed polypropylene or polyethylene affected facility are exempt from the requirements of §60.562-1(a)(1).

§60.564(d), ResidualVOC content in the granular resin below a level of 50 ppmw of resin.

PE1RAILSILOA/B/C/D, PE2RAILSILOA/B/C/D

Process Vent - Railcar Storage Silos

PE1RAILDEDUSTA/B, PE2RAILDEDUSTA/B

Process Vent - Rail Car DeDuster Vents

PE1RAILLOAD A/B, PE2RAILLOAD A/B

Process Vent – Rail Car Loading

PE1TRUCKSILOA/B/C/D/E/F/G/H/I/J, PE2TRUCKSILOA/B/C/D/E/F/G/H/I/J

Process Vent - Truck Storage Silos

PE1TRUCKDEDUSTA/B/C/D/E, PE2TRUCKDEDUSTA/B/C/D/E

Process Vent - Truck DeDuster Vents

12






PE1TRUCKLOAD A-E, PE2TRUCKLOAD A-E

Process Vent – Truck Loading

SANDPIT

PE Process Vents

§60.564(d)S2003A/B C6004

§60.564(d), ResidualVOC content in the granular resin below a level of 50 ppmw of resin.

C6003 V6007 V7001A/B/C/D PE3RAILSILOA/B/C/D

Process Vent - Railcar Storage Silos

PE3RAILDEDUSTA/B


PE3RAILLOAD A/B

Process Vent – Railcar Loading

PE3TRUCKSILO A/B/C/D/E/F/G/H/I/J/K/L /M/N/O/P/Q/R

Process Vent - Truck Storage Silos

PE3TRUCKDEDUST A/B/C/D/E/F/G/H/I


PE3TRUCKLOAD A-I

Process Vent – Truck Loading

T64301 Hexene Storage - Tank VOC §60.110b(a) Part 60 Subpart Kb

§60.112b(a)(3) §60.113b(c) or (d) asapplicable

§60.115b(c) or (d) asapplicable, §60.116b

T64302 Hexene Storage - Tank

V64301 Butene Storage - Sphere §60.112b(d)(2) - Thissubpart does not apply to the following: Pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.

NA

§60.116bV64302 Butene Storage - Sphere V64401 Isopentane Storage - Bullet V64402 Isopentane Storage - Bullet V64501 Isobutane Storage - Bullet V64502 Isobutane Storage - Bullet

13






HPGFLARE High Pressure Header Ground Flare: Process Vent -

S3004

VOC

§60.561 - Control device means an enclosedcombustion device, vapor recovery system, or flare.

Part 60 Subpart DDD

§60.562-1(a)(1)(i)(C),§60.562-1(d), §60.562-1(e)

§60.18, §60.562-1(a)(2)(i), §60.563(a)(2),§60.563(a)(3),§60.563(c),§60.563(d),§60.564(e), (f)

§60.565(a)(3), (5);§60.565(e),§60.565(b)(1),§60.565(a)(3)(i),§60.565(a)(5)(i)LPGFLARE Low Pressure Header Ground

Flare: Process Vent -

V5005, T5004, R5002, R5003A/B, R5004, E5011, S4005A/B, E4001

LPINCIN Low Pressure Header Incinerator: Process Vent -

V5005, T5004, R5002, R5003A/B, R5004, E5011, S4005A/B, E4001

§60.562-1(a)(1)(i)(A),§60.562-1(d), §60.562-1(e), §60.562-1(a)(2)(ii)

§60.562-1(a)(2)(ii),§60.563(a)(1),§60.563(a)(3),§60.563(b)(1)(i),§60.563(b)(2),§60.563(c),§60.563(d),§60.564(b),§60.564(c)

§60.565(a)(4),§60.565(c),§60.565(b)(1),§60.565(a)(1),§60.565(a)(4)

PE Process Vents

PM

25 Pa. Code §121.1 Process - A method, reaction or operating in which materials are handled or whereby materials undergo physical change-that is, the size shape, appearance, temperature, state or other physical property of the material is altered-or chemical change-that is, as substance with different chemical composition or properties is formed or created. The term includes all of the equipment, operations and facilities necessary for the completion of the transformation of the materials to produce a physical or chemical change. There may be several processes in series or parallel necessary to the manufacture of a product.

25 Pa. Code §123.13

25 Pa. Code §123.13(a), (c)(1)

PE1BLENDA/B/C/D/E, PE2BLENDA/B/C/D/E

14






PE1RAILSILOA/B/C/D, PE2RAILSILOA/B/C/D

Process Vent - Railcar Loading Silos

PE1RAILDEDUSTA/B, PE2RAILDEDUSTA/B


PE1TRUCKSILOA/B/C/D/E/F/G/H/I/J, PE2TRUCKSILOA/B/C/D/E/F/G/H/I/J

Process Vent - Truck Loading Silos

PE1TRUCKDEDUSTA/B/C/D/E, PE2TRUCKDEDUSTA/B/C/D/E


C6005

PE Process Vents

Q6002A/B/C/D C6004 C6003 V6007 V7001A/B/C/D PE3RAILSILO A/B/C/D

Process Vent - Railcar Loading Silos

PE3RAILDEDUSTA/B


PE3TRUCKSILO A/B/C/D/E/F/G/H/I /J/K/L/M/N/O/P/Q/R

Process Vent - Truck Loading Silos

PE3TRUCKDEDUST A/B/C/D/E/F/G/H/I


S2003A/B Process Vent - R2001A, R2001B

15






T64301 Hexene Storage - Tank VOC Storage Tank 25 Pa. Code §129.56

25 Pa. Code §129.56(a)(2)T64302 Hexene Storage - Tank

V64301 Butene Storage - Sphere V64302 Butene Storage - Sphere V64401 Isopentane Storage - Bullet V64402 Isopentane Storage - Bullet V64501 Isobutane Storage - Bullet V64502 Isobutane Storage - Bullet LPGFLARE Low Pressure Header Ground Flare NOx 25 Pa. Code §121.1 - Incinerator - A device

designed to burn or oxidize solid, semisolid, liquid or gaseous wastes for the primary purpose, as determined by the Department, of volume reduction or of disposal. The term includes heat recovery systems.

25 Pa. Code Ch. 129

25 Pa. Code §129.93(c)(4), (6)


25 Pa. Code §123.12

LPINCIN Low Pressure Header Incinerator: Process Vent -

R5003A/B, R5004, E5011, S4005A/B, E4001


25 Pa. Code Ch. 129

25 Pa. Code §129.93(c)(4), (6)


25 Pa. Code §123.12

Equipment Leaks VOC 25 Pa. Code §129.71(a) - This section applies to a facility with design capability to manufacture 1,000 tons per year or more of the following: (3) Polyethylene

25 Pa. Code Ch. 129.71

25 Pa. Code §129.71(b), (d)

25 Pa. Code §129.71(d)

25 Pa. Code §129.71(d), (e)

Cogen Equipment Leaks VOC §60.480a Part 60 Subpart

VVa §§60.482-1a - 60.482-11a §60.485a §60.486a, §60.487a

CT1/2/3 Combustion Turbines NOx and SO2

§60.4305(a) Part 60 Subpart KKKK

§60.4320(a) - Table 1,§60.4330(a), §60.4333,§60.4360, §60.4405

§60.4340(b)(1),§60.4345, §60.4350,§60.4365(a),§60.4400,§60.4415(a)(2)

§60.4375, §60.4380,§60.4395

HAP §63.6090(a)(2), §63.6092 Part 63 Subpart YYYY

§63.6095(d) §63.6145(c)

16


V5005, T5004, R5002,





NOx 25 Pa. Code §§145.4(a)(1)(iii), 145.203 25 Pa. Code Ch. 145

25 Pa. Code §145.8(c); 25 Pa. Code §145.10-14; 25 Pa. Code §145.213(a); 25 Pa.Code §145.223(a)

25 Pa. Code §§145.54, 145.71(b), 145.72

25 Pa. Code §§145.30; 145.52; 145.60; 145.70; 145.71(d); 145.73; 145.74; 145.76; §145.213(a), (c)-(e);§145.223(a), (c)-(e)

PM 25 Pa. Code §121.1 - Combustion unit - A stationary equipment used to burn fuel primarily for the purpose of producing power or heat by indirect heat transfer.

25 Pa. Code Ch. 123

25 Pa. Code §123.11(a)(2)

SO2 25 Pa. Code §123.22(d)(2)

SO2 and CO2

§72.6(a)(3)(i) Part 72 Parts 72, 73 §75.10(a)(3)(ii),§75.11(d)(2),§75.13(b), §75.14(c),§75.20(g);§75.59(b), (e)

§75.53(a); (e); (f)(1), (6);(g); (h); §75.57; §75.58(c)(4), (8);§75.60-64;

GHG §98.40 Part 98 Subpart D

§§98.41-43, 45 §98.44 §§98.46, 47

§60.5509(a) Part 60 Subpart TTTT - Proposal expected 6/2014

§§60.5515, 5520, 5525, 5530

§§60.5535, 5540 §§60.5550, 5555, 5560, 5565

COGENCWT Cooling Water Tower PM 25 Pa. Code Ch. 123

25 Pa. Code §123.13(c)(1)

Shared Units T59708 Recovered Oil Storage -

Wastewater Tank VOC §60.110b(a) Part 60 Subpart

Kb §60.112b(a) §63.1100(g)(1)(ii) -

After the compliance date, a storage vessel that must be controlled according to the requirements of Part 63 Subpart YY and subpart Kb or 40 CFR Part 60 is required to comply only with the storage vessel requirements of Part 63 Subpart YY.

NA T59707A/B FEOR Tank - Wastewater OWS

Synthetic Organic Chemical Manufacturing Industry Wastewater

VOC §60.770 Part 60 Subpart YYY - Proposed but never published in FR

§§60.773-780, 786 §60.781-783 §§60.785, 786

17






T4000 Locomotive Diesel Storage - Tank SO2 25 Pa. Code Ch. 123

25 Pa. Code §123.22(d)(2)(i)

25 Pa. Code §123.22(g)(1)

25 Pa. Code §123.22(g)(4), (5)T58901

A/B/C/D Generator Diesel Storage - Tank T59101 A/B/C Fire Pump Diesel Storage - Tank T4000 Locomotive Diesel Storage - Tank VOC Storage Tank <40,000 25 Pa. Code

Ch. 129 25 Pa. Code §129.57

T58901 A/B/C/D Generator Diesel Storage - Tank T59101 A/B/C Fire Pump Diesel Storage - Tank PROCESSCWT Process Cooling Water Tower


25 Pa. Code §123.13(c)(1)

EGEN1/2/3/4 Emergency Generators

NOx Internal Combustion Engine 25 Pa. Code Ch. 129

25 Pa. Code §129.93(c)(5), (6)

25 Pa. Code §129.95(a)-(d)

FWP1/2/3 Fire Pump Engines

EGEN1/2/3/4

Emergency Generators HAP, VOC §60.4200(a), §63.6585, §63.6590(a)(2)(i), §63.6590(b)(1)(i)

Part 63 Subpart ZZZZ, Part 60 Subpart IIII

§60.4205(b), §60.4206,§60.4211(a)(1),§60.4211(a)(2),§60.4211(a)(3),§60.4209(a),§60.4211(f),§60.4207(b),

§60.4211(c) §60.4214, §63.6645(f)

FWP1/2/3

Fire Pump Engines §60.4200(a), §63.6585, §63.6590(a)(2)(i),§63.6590(b)(1)(i)]

§60.4205(c) – Table 4,§60.4206,§60.4211(a)(1),§60.4211(a)(2),§60.4211(a)(3),§60.4209(a),§60.4211(f),§60.4207(b),

§60.4211(c) §60.4214, §63.6645(f)

Sitewide Part 68

GHG §98.2(a)(1) - Table A-3, §98.2(a)(2) Part 98 Subpart A

§98.3 §98.7, §98.8 §98.4, §98.5

§98.30 Part 98 Subpart C

§§98.31-33, 35 §98.34 §98.36, §98.37

§60.1(a) Part 60 Subpart A

§60.11, §60.13, §60.18 §60.7, §60.8 §60.19

HAP 25 Pa. Code §124.3 NESHAP promulgated in 40 CFR Part 61 by the EPA under section 112(d) of the CAA are hereby adopted in their entirety by the Department and incorporated herein by reference.

25 Pa. Code Ch. 124

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VOC Sources Subject to NSPS 25 Pa. Code §129.51

25 Pa. Code §129.51(b) - New source performance standards. Sources covered by new source performance standards which are more stringent than those contained in this chapter shall comply with those standards in lieu of the standards found in this chapter. 25 Pa. Code §129.51(a) as applicable

25 Pa. Code §129.51(c) -Demonstration of compliance. Test methods and procedures used to monitor compliance with the emission requirements of this section are those specified in Chapter 139 (relating to sampling and testing).

25 Pa. Code §129.51(d) - Records. The owner or operator of a facility or source subject to the VOC emission limitations and control requirements in this chapter shall keep records to demonstrate compliance with the applicable limitation or control requirement.

NOx and VOC

25 Pa. Code §129.91(a) - Major NOx or major VOC emitting facility for which no RACT requirement has been established in §§129.51, 129.52, 129.54-129.72, 129.81 and 129.82

25 Pa. Code Ch. 129

25 Pa. Code §129.91(g); §129.92(a)(1)-(4), (7),(8), (10); §129.92(c)

25 Pa. Code §129.93(a)

25 Pa. Code §129.95(a)-(d)

SO2 25 Pa. Code Ch. 123

25 Pa. Code §123.21(b)

25 Pa. Code §§123.31, 127, 128, 131, 135, 137, 139 as applicable

25 Pa. Code §§123.31, 127, 128, 131, 137 as applicable

25 Pa. Code Ch. 139 as applicable

25 Pa. Code Ch. 135

Visible Emissions

25 Pa. Code Ch. 123

25 Pa. Code §§123.41, 123.42

25 Pa. Code §123.43

Fugitive air contaminants

Use of roads and streets 25 Pa. Code Ch. 123

25 Pa. Code §123.1(a)(3)

25 Pa. Code §§123.1(c)(3), 123.2

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