SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION · PDF file · 2012-02-13• The fluid...

1 Final Draft Staff Report with Appendices for

Revised Proposed Amendments to Rule 4402

SAN JOAQUIN VALLEY UNIFIED AIR POLLUTION CONTROL DISTRICT

FINAL DRAFT STAFF REPORT


(Crude Oil Production Sumps)

December 15, 2011

Prepared by: Anna Myers, Senior Air Quality Specialist Kristopher Rickards, Air Quality Engineer Chelsea Gonzales, Air Quality Specialist Nichole Corless, Air Quality Specialist

Reviewed by: Tina Frederick, Compliance Inspector Ellyce Baldwin, Compliance Supervisor Jessi Fierro, Rule Development Supervisor

Mike Oldershaw, Compliance Manager Leonard Scandura, Permits Manager Errol Villegas, Strategies and Incentives Manager Samir Sheikh, Director of Strategies and Incentives

I. SUMMARY The San Joaquin Valley Unified Air Pollution Control District’s (District) Governing Board (Board) adopted amendments to Rule 4402 (Crude Oil Production Sumps) on December 17, 1992 as a part of an effort to renumber rules from a previous rule-numbering system to the current District rule-numbering system. The District submitted the 1992 rule revisions to the California Air Resources Board (ARB) for forwarding to the Environmental Protection Agency (EPA) as an amendment to the State Implementation Plan (SIP) in 2006. Upon evaluation of the submitted Rule 4402, EPA finalized a limited approval and limited disapproval of the rule as an amendment to the District portion of the SIP

(Revisions to the California State Implementation Plan, San Joaquin Valley Unified Air Pollution Control District 2011, 39777-39782), effective on August 8, 2011. In its limited disapproval, EPA cited concerns regarding the satisfaction of Reasonably Available Control Technology (RACT) requirements through Rule 4402. A copy of the Federal Register and the associated Technical Support Document is included as Appendix D of this final draft staff report.


Final Draft Staff Report: Rule 4402 December 15, 2011



Pursuant to Section (§)179 of the Clean Air Act (CAA), unless a rule has been updated and approved into the SIP within 18 months after disapproval, EPA shall impose one or more sanctions until they determine that the State has attained compliance. The purpose of this rule-amending project is to evaluate and address, as appropriate, the concerns identified by EPA regarding Rule 4402 and submit adopted revisions to EPA for inclusion into the SIP. This rule addresses VOC emissions from a source category that is relatively small. VOC emissions reductions are generally far less important to the Valley’s long-term attainment goals than are NOx emissions reductions. As such, the Valley’s attainment strategies generally emphasize NOx reductions. The District will continue to seek as much VOC reductions as expeditiously practical, technologically feasible, and as economically reasonable as determined by the Governing Board. II. RULE DEVELOPMENT PROCESS This rule development process is principally focused on ensuring that Rule 4402 meets requirements for Reasonably Available Control Technology (RACT). Based on the District’s evaluation of sources subject to Rule 4402, the District proposes to make a number of relatively minor and administrative amendments to the rule. District staff hosted a public workshop on October 18, 2011 and two technical workgroup meetings with industry representatives in September and October of 2011. District staff solicited comments from the public, stakeholders, trade organizations, ARB, and EPA. Upon review and evaluation, District staff incorporated the comments and data into the rule and final draft staff report as appropriate. As part of the District’s new socioeconomic policy adopted by the Board in October 2011, District staff identified three industry trade associations for this source category: the Western States Petroleum Association (WSPA), the Independent Oil Producers Associations (IOPA), and the California Independent Petroleum Association (CIPA). District staff solicited these groups for feedback on control costs and feasibility of the proposed rule amendments. At the October 18, 2011, public workshop, District staff asked for assistance in identifying other trade organizations that could provide additional cost and source-specific data. No additional industry groups have been identified at this time. District staff also solicited feedback from stakeholders to determine if any new Department of Transportation, Occupational Safety and Health Administration, safety or other requirements that would result from the proposed amendments. Thus far no additional requirements have been identified. The proposed rule and final draft staff report will be published and made available to affected sources and interested parties prior to a public hearing of the District Governing Board to consider adoption of the proposed rule amendments. Proposed amendments





to the rule are scheduled to be presented to the Governing Board during the public hearing on December 15, 2011. III. BACKGROUND

Crude Oil Production Operations with Sumps A. Oil production operations pump crude oil from the ground and separate the usable products from the sand, water, and other fluids that it is entrained in. In most cases, the separation process occurs in tanks or a combination of tanks and sumps. The following is a simplified overview of the initial separation procedure, which takes place prior to product being sent to a sump or tank for additional separation:

• Oil-water-gas mixtures produced from individual wells are sent to a fluid gathering system.

• The fluid then enters a free-water knockout (FWKO) vessel where initial separation of gas, oil, and water takes place. A free-water knockout is a vessel designed to reduce the velocity of the produced stream so that free water and solids settle out. The knockout may be a tank or pressure vessel.

• After leaving the FWKO vessel, the oil fraction, which usually contains significant amounts of residual water, is sent to a heater treater or tank where additional water is separated from the oil and any remaining gas. A heater treater is a pressure vessel used in an oil field to break oil-water emulsions. The process involves the application of heat and may be accompanied by the addition of chemicals upstream or at the treater.

• If significant gas is released, it may be directed to a vapor collection system; otherwise, gas is removed with the oil fraction. The separated oil is then directed to a storage tank and eventually sent offsite for sale/distribution.

The remaining oily water fraction is then directed to a tank or a sump for further separation. As identified in the ARB TSD for sumps used in oil production (Suggested Control Measure of the Control of Organic Compound Emissions from Sumps Used in Oil Production Operations), waste water, also called produced water, needs to be disposed of in one or more of the following ways: re-injection into the oil reservoir; injection into a favorable subsurface formation; re-direction into a permitted existing surface waterway after appropriate treatment to remove contaminants; percolation; or evaporation. In the Valley, processed water is commonly disposed of using a combination of percolation and evaporation; this is especially true for small and very small oil producers. The process of percolation can only be achieved through the use of unlined excavations in the ground, commonly referred to as sumps or ponds.





The Purpose and Use of Sumps B. In oil and gas production operations, sumps receive oil-water mixtures for the purpose of separating usable oil products from water, sand, and semi-sold hydrocarbons. Sumps operate under continuous use during normal operations of oil production. Sumps also serve as receptors or holding ponds to allow the disposal of water through evaporation and percolation. Sumps are separated into the following three classes, based upon where they function within the treatment process:

• First stage (primary) production sump. A sump that receives a stream of crude oil and produced water directly from one or more oil production wells or field gathering systems.

• Second stage (secondary) production sump. A sump that receives waste water

streams (water/oil) from one or more first stage separators (including first stage sumps and/or tanks).

• Third stage (tertiary) production sump. A sump that receives waste water streams

(water/oil) from one or more second stage separators (including second stage sumps and/or tanks). In most cases, there are only small amounts of oil present in the waste streams.

Sumps are further classified by the type of petroleum they receive:

• Light oil service sumps. Sumps that contain crude oil having an American Petroleum Institute (API) gravity of 30 o or greater.

• Heavy oil service sumps. Sumps that contain crude oil having API gravity less than 30o.

The crude oil and water mixes as it flows through pipelines from upstream sources to the sump. Emulsions consisting of small globules of crude oil are dispersed throughout the mixture. The stability of the emulsion is an important factor affecting the separation of the oil and water phases. Stable emulsions are those in which the dispersed globules resist rapid coalescence. Because crude oil is usually less dense than water, when the mixture enters the sump, gravity causes the water to settle into a separate liquid layer below the oil; allowing the operator to skim the oil from the surface of the sump. The efficiency of the oil-water separation process in a sump is also dependent upon the amount of time the fluid spends in the sump, or its residence time. As the residence time increases, a more complete separation occurs The separation of oil and water in a sump happens as a result of density differences between the two primary components—oil being less dense than water. De-emulsifiers or the application of heat, which can be added to the oil-water mixture upstream of the





sump, can enhance the separation process. The oil-water mixture, or emulsion, is often held together with other agents such as silts, clays, or naturally occurring surfactants. A de-emulsifier is a chemical compound that forms electrochemical bonds with electrochemically similar compounds; they attach to certain parts of the mixture, forming denser globules that will separate from less-dense parts of the mixture. If mixing is adequate, the result is eventual removal of non-soluble globules from the liquid. Likewise, the application of heat to the oil-water mixture enhances separation. Heat raises the kinetic energy of the oil and water molecules to enhance separation; oil molecules, being less dense than water molecules possess a high velocity when heated, thus are more effectively separated from water with the application of heat.

Sump Activity in the Valley C. ARB1 made the determination that, in California, most of the sumps are used by a few producers, usually in areas where the production of heavy crude oil is predominant. The District’s emissions inventory, as presented in the 2007 Area Source Emission Inventory Methodology, supports this determination. In the past, some companies used primary sumps to accept crude oil directly from wells. However, these types of sumps have been eliminated and operators now direct crude oil from wells to tanks or vessels. District staff has confirmed that there are no primary sumps in the Valley. There are however, secondary and tertiary sumps still used in the Valley. Some producers still use these sumps to separate small amounts of crude that may be entrained in produced water discharged from upstream equipment (tanks and vessels). The sumps were identified, recorded, and verified through extensive efforts by District staff. The surface area of active sumps, by facility size and oil specific gravity as determined in the 2007 Area Source Emission Inventory Methodology, are presented in the following tables: Table 1. Facility Average Surface Area of Sumps in the Valley (2007)

Classification

First Stage Sumps

Second Stage Sumps

Third Stage Sumps

(ft2) (ft2) (ft2)

Large Operations

Light Oil 0 0 0

Heavy Oil 0 0 320.0

Small Operations

Light Oil 0 101.6 838.2

Heavy Oil 0 876.6 1,331.1

1 ARB TSD for the Suggested Control Measure of the Control of Organic Compound Emissions from

Sumps Used in Oil Production Operations





Table 2. Total Surface Area of Sumps in the Valley (2007)

Classification

First Stage Sumps

Second Stage Sumps

Third Stage Sumps

(ft2) (ft2) (ft2)

Large Operations

Light Oil 0 0 0

Heavy Oil 0 0 5,440

Small Operations

Light Oil 0 6,297 51,971

Heavy Oil 0 97,298 147,757

TOTAL

Light Oil 0 6,297 51,971

Heavy Oil 0 97,298 153,197

Staff calculated the number of active sumps in the Valley based on the information provided in the 2007 Area Source Emission Inventory Methodology, as presented in the table below. For purposes of this rule-amending project staff will assume that the quantity of active sumps in the Valley as presented in the table below is equivalent to the active sumps in 2011. Even though stakeholders have pointed out that the use of sumps has been and continues to be declining in the Valley. Table 3. Quantity of Active Sumps in the Valley (2007)

Classification

First Stage Sumps

Second Stage Sumps Third Stage Sumps

(ft2) (ft2) (ft2)

Large Operations Light Oil 0 0 0 Heavy Oil 0 0 17 Small Operations Light Oil 0 62 62 Heavy Oil 0 111 111 TOTAL

Light Oil 0 62 62 Heavy Oil 0 111 128

A. Emissions Emissions of volatile organic compounds (VOCs) from secondary and tertiary sumps depend on the type of crude oil they contain, which is broadly categorized as “light” or “heavy” based on its API gravity, and the surface area of the sumps.





The District reviewed and refined the emission inventory for this source category in 2007. The emission factors for crude oil production sumps presented in Table 4 reflect a correction made to the technical guidance document for the “Emission Inventory Criteria and Guidelines Regulation” for AB 2588 (Air Toxics “Hot Spots” Information and Assessment Act of 1987) by the Kern County Air Pollution Control District. District staff, ARB, and stakeholders vetted these emission factors throughout the emission inventory update process and through District permit streamlining efforts. These adopted and approved emission factors are summarized in the following table: Table 4. Emission Factors for Sumps

Classification Total Organic

Gas (lb/ft2 -day)

Fractional Reactive Organic

Gas

Reactive Organic Gas

(lb/ft2 -day)

Heavy Oil (API < 30°)

First Stage 0.10459 0.80 0.0837

Second Stage 0.05149 0.80 0.0412

Third Stage 0.00641 0.80 0.0051

Light Oil (API >30°)

First Stage 0.143 0.80 0.1144

Second Stage 0.02 0.80 0.016

Third Stage 0.01 0.80 0.008

Table 5 represents the 2007 emissions inventory for oil sumps, reported for each county in the District. For specific information regarding calculations and methodology used to determine the emission inventory please refer to the 2007 Area Source Emission Inventory methodology, available on the District website. Table 5. Total Emissions for Crude Oil Production Sumps (2007)

County Emissions (tpy)

NOx CO SOx VOC PM10 PM2.5

Fresno N/A N/A N/A 9.75 N/A N/A

Kern N/A N/A N/A 761.35 N/A N/A

Kings N/A N/A N/A 0.00 N/A N/A

Madera N/A N/A N/A 0.00 N/A N/A

Merced N/A N/A N/A 0.00 N/A N/A

San Joaquin N/A N/A N/A 0.00 N/A N/A

Stanislaus N/A N/A N/A 0.00 N/A N/A

Tulare N/A N/A N/A 197.34 N/A N/A

Total N/A N/A N/A 968.44 N/A N/A





IV. DISCUSSION Based on their analysis of the current version of District Rule 4402, EPA identified several areas of concern in the rule that preclude its full approval as an amendment into the SIP. EPA based its determination on the need for improved rule clarity, increased enforceability, and stronger requirements to implement RACT. A reasonably available control technology is a control technology that is considered reasonable for an operator to install or implement. By EPA definition, RACT must be technologically and economically feasible. Whether a control technology is considered RACT can vary between air basins and industries as well as over time. A RACT analysis integrates several factors, including technological advancements and costs for equipment, raw material, or labor. The following discussion summarizes the issues identified by EPA as published in the Federal Register and includes the District’s responses and proposed rule amendments to address the issues identified by EPA. Refer to Appendix B of this final draft staff report to review the RACT cost effectiveness analyses used to support the District responses to EPA. A. Section 1.0 – Purpose District staff proposes to remove some language from this section of the rule to simplify rule language. This change is administrative in nature and does not change the applicability or requirements contained in this rule. B. Section 3.0 – Definitions EPA Comments: Update the definition of Clean Produced Water (CPW) to replace EPA Test Methods 4.13.2, 418.2, and 8240, these are outdated test methods that used chlorofluorocarbon (CFC) 113 as the extraction solvent, with updated EPA Test Methods 1664A and 8260, both of which do not use CFCs. Also, for produced water to be considered clean produced water pursuant to Rule 4402 it must have a VOC content less than 35 mg/l VOC. In contrast, South Coast Air Quality Management District (SCAQMD) Rule 1176(i)(5)(J), Ventura County Air Pollution Control District (VCAPCD) Rule 71.4 C.1.c and San Luis Obispo County Air Pollution Control District (SLOCAPCD) Rule 419 C.4 define clean produced water as not exceeding 5 mg/l at the inlet.

District Response (Test Methods): District staff agrees with the EPA assessment that the test methods used to test for VOC content of the clean produced water should be updated. District staff proposes to amend the definition of Clean Produced Water to include updated test methods 1664A and Method 8260. Method 1664A uses hexane rather than a CFC to extract volatiles, and test Method 8260 has replaced Method 8240 in labs. District staff proposes to add these test methods to the rule instead of replacing the existing test methods because while EPA may discourage the existing test methods





they have not been prohibited, or discredited as ineffective. In fact, a mixture of test methods are currently in use (depending on the operator) and inclusion of all methods would be appropriate for this source category. District staff does not anticipate additional costs to be associated with this proposed amendment because the new test methods are currently in use, and operators still have the option to use the older test methods. District Response (VOC Content for CPW): District staff analyzed the feasibility and the cost effectiveness of reducing the VOC content limit for CPW from 35 mg/l to 5 mg/l VOC to determine whether this is a RACT option for operators in the Valley. The following analysis documents the District’s findings. District staff surveyed the existing CPW ponds and sumps and determined that operators do in fact store CPW greater than 5 mg/l. If the District were to change the CPW limit from 35 mg/l to 5 mg/l then Valley operators would be faced with either increasing the processing of the CPW to get the concentration to less than 5 mg/l and allow the continued use of sumps and ponds, or stop the use of sumps or ponds and send the CPW to either municipal wastewater systems or to reinjection wells. Disposal Alternatives As discussed above, EPA identified the SCAQMD Rule 1176 as an example of a rule that contains requirements to limit the VOC content of CPW to less than 5 mg/l. At the public workshop and technical workgroup meetings, stakeholders brought it to the attention of staff that in the SCAQMD, the operators do not have to comply with the 5 mg/l required limit because they are not sending their clean produced water to ponds; rather they send it to the Los Angeles and Orange County municipal sewer systems with oil content of up to 60 ppm to 100 ppm. Another disposal alternative for operators is to dispose of the wastewater using reinjection wells instead of treating it and putting it in ponds. These two options are not technologically feasible for Valley operators because they are not available options to crude oil production facilities in the Valley. Crude oil production facilities in the Valley differ greatly from those in other air district jurisdictions because they are located in rural areas and not in or near city limits, while in other parts of California the facilities are located within city limits. The location of these operations prevents them from having access to municipal wastewater systems. Also, operators in the Valley have not been able to get the necessary permits required to install reinjection wells from the Division of Oil, Gas & Geothermal Resources (DOGGR)2. Because industry has been unable to get the required permits District staff determined this is not a technologically feasible option to operators. Additionally, WSPA performed a cost effectiveness analysis independent of the District and determined that the cost effectiveness of injecting the water would be $679,978 per ton of VOC reduced; this is not a cost effective option. The WSPA analysis is presented in detail in Appendix B of this final draft staff report.

2 Cox, J. (2011, September 04). and Cook, R (2011, November 03).





Treatment of Water to Achieve 5 mg/l District staff calculated the difference in emissions from 35 to 5 mg of VOC per liter of water in three different scenarios using EPA Water9 software. District staff determined that the cost effectiveness would for treating water to 5 mg/l would be $54M per ton of VOC reduced. WSPA performed a cost effectiveness analysis independent of the District analysis for the treatment of clean produced water to achieve 5 mg/l and determined it would cost $8 million per ton of VOC reduced. Staff also performed a third cost effectiveness analysis as a worst case scenario cost effectiveness analysis using emission factors that we believe to be too high for clean produced water. The third analysis resulted in a cost effectiveness of greater than $70,000 per ton of VOC reduced. All three scenarios produced the same result; treatment of clean produced water from 35mg/l to 5 mg/l is not cost effective. For the detailed discussion of each of these three analyses please refer to Appendix B (RACT Cost Effectiveness Analysis) of this final draft staff report. Water9 Discussion EPA staff has expressed to District staff a concern that utilizing the EPA Water 9 software may not be the appropriate calculation methodology for estimating emissions from clean produced water ponds. District staff contends that EPA Water9 is appropriate for use in determining emissions from ponds used to dispose of produced water in oil production operations, as discussed below. Stakeholders agree with this assessment, as supported by the comment letter submitted to the District incorporated into this discussion. EPA has recommended staff perform a mass balance calculation to determine the VOC emissions from ponds of clean produced water. District staff has considered this option and determined that it would not be an appropriate method for determining the emissions from a pond because it would not account for the VOCs that would percolate into the soil nor does it compensate for biodegradation that naturally occurs in ponds. The user’s manual for EPA Water9 provides information on the applicability of this model for various process types. The preface at page ii states that Water9 is used for “for estimating air emissions of individual waste constituents in wastewater collection, storage, treatment, and disposal facilities …”. Produced water ponds (use for evaporation and percolation of wastewater) are disposal devices used in oil production wastewater handling operations. WSPA pointed out that EPA has used the Water9 model for many years and that these models serve as the basis for virtually all of the rulemaking pertaining to emissions of air contaminants from surface impounds; WSPA listed six other software programs (See Appendix A). According to the EPA Water9 instruction manual:

Water9 is used to estimate air emissions from site specific water treatment plants (including the prediction of biodegradation and sludge sorption of organics) for common wastewater treatment units including the following:





drains, sumps, weirs, open drains, j traps, manhole covers … and settling ponds. Water9 provides models for the evaluation of landfill, land treatment, and impoundment disposal facilities

In defining the constituents for the wastewater stream, Water9 includes crude oil (as decane) in the list of constituents available for use. The VOC constituents in produced water are generally heavier hydrocarbons, as the lighter hydrocarbons entrained in the produced fluids are released earlier in the production process. As such, using the default crude oil constituent is acceptable. Water9 also allows the concentration (ppmw) of a particular constituent to be used. In our calculations, we estimated emissions from ponds using a crude oil concentration of 35 mg/l (based on current rule exemption levels) and 5 mg/l (based on EPA suggested rule exemption levels).

Water9 includes lagoons as a component in the wastewater treatment process. Lagoons typically have a long retention time to allow for evaporation of the wastewater. Crude oil production ponds likewise have a long retention time for produced water. As such, crude oil production ponds serve a similar purpose as lagoons. It is important to note however, that Water 9 calculations do not account for percolation of water into the soil. Because a significant portion of the produced water (and associated VOCs) do percolate, and therefore are not the source of emissions, Water9 results potentially overstate the emissions from clean produced water ponds. The emissions modeled in Water9 are estimated based on biodegradation and evaporation of a portion of the VOCs in the wastewater. Therefore, the District still believes that the Water9 calculations are appropriate. Nevertheless, as discussed earlier, the District included a worst-case analysis that likely overestimates emissions by orders of magnitude.

Additional Amendments Staff proposes to add six definitions to Section 3.0 to improve clarity of rule requirements. These are amendments are administrative in nature and do not change the applicability or requirements of the rule. The following six definitions to be added are:

• APCO: the Air Pollution Control Officer of the San Joaquin Valley Unified Air Pollution Control District.

• API: American Petroleum Institute. • ARB: California Air Resources Board. • EPA: United States Environmental Protection Agency. • Operator: includes but is not limited to any person who owns, leases, supervises,

or operates a facility and/or equipment. • Volatile Organic Compound (VOC): as defined in Rule 1020 (Definitions).





C. Section 4.0 – Exemptions The Federal Register cites that Rule 4402 has exemptions that are broader than exemptions in other air districts in California and that the District should analyze whether these exemptions continue to be appropriate. EPA also calls for the District to use cost information that is more current than that used in the 2009 RACT Analysis, and to consider alternative disposal methods (e.g., underground injection, tanks, or additional pretreatment) in addition to sump and pond covers. The Federal Register specifies exemption Sections 4.1.1, 4.1.3, and 4.1.7 to be of particular concern. Section 4.1 District staff proposes to include the phrase “… Section 5.0 of …” to Section 4.1 to clarify that these operators are exempt from the requirements section of the rule; in order to demonstrate compliance with exemptions in Section 4.1 facilities are required, or will be required, to keep records pursuant to Section 6.0. The added phrase will improve rule clarity and is an administrative change to rule language. This change does not change the intent or requirements of existing rule language. Section 4.1.1 EPA Comment: Section 4.1.1 exempts operations less than 6000 barrels per day with sumps less than 1000 ft2. from substantive requirements. No other neighboring districts allow exemptions from small producers, except SBCAPCD Rule 344, which is more restrictive. The EPA TSD elaborates on the discussion in the Federal Register to clarify that SBCAPCD Rule 344 B.3.a.2. exempts small producers (less than 150 barrels/day average over one year) with no restriction on surface area of sump or type of crude oil in the sump; additionally, SBCAPCD Rule 344 B.4. exempts any 2nd or 3rd stage sump with less than 1000 ft2 of surface area, also with no restriction on type of crude oil in the sump. District Response (SBCAPCD): District staff have determined that the two exemptions in the SBCAPCD Rule 344 are less stringent then District Rule 4402 exemption 4.1.1. The SBCAPCD exemption for producers of less than 150 barrels per day have no restriction on the size of the sump or the type of crude in that sump; also, the second SBCAPCD Rule 344 exemption exempts any 2nd or 3rd stage sump with less than 1000 sq. ft with no restriction on the size of producer that can enjoy this exemption and no restriction as to the type of oil in the sump. District Rule 4402 exemption 4.1.1 restricts the size of the operator, the size of the sump, and the type of oil in the sump. This is more restrictive then the SBCAPCD exemptions, which have been found to meet RACT requirements by EPA3.

3 Approval and Promulgation of Implementation Plans; California State Implementation Plan Revision;

Kern County Air Pollution Control District; Santa Barbara County Air Pollution Control District, 1996, 5515 – 5517).





District Response (RACT): If the District were to remove the Section 4.1.1 exemption for small producers, operators would have two options available to them. Either comply with rule requirements pursuant to Section 5.0, or replace the sumps with tanks, which would also require additional processing in addition to the replacement. It is important to note that historically, when the rule was amended, and operators became subject to the requirements of Section 5.0, they have chosen to remove the sump and install a tank; as confirmed at the public workshop on October 18, 2011, and through conversations with stakeholders. Stakeholders also confirmed at the public workshop that this will continue to be industries response to any change to the requirements or the exemptions sections of this rule. Compliance with Section 5.0 District Rule 4402 Section 5.0 (Requirements) provides operators with three control device options to install for compliance; the three control devices must also comply with other requirements specified in the rule. The three control devices available to operators as a means of compliance are as follows:

1. A flexible floating cover 2. A rigid floating cover equipped with a closure device between the sump wall and

the cover edge which maintains the gap between the wall and cover at every point around the perimeter at no more than one inch

3. A fixed-roof cover Staff performed a cost effectiveness analysis for operators to install and maintain and to remain compliant with rule requirements for each of these three sump control devices. District staff evaluated the cost effectiveness for a small producer to comply with Section 5.0 and determined that it is not a cost effective option. It is important to note that in determining the cost effectiveness for operators to comply with Section 5.0 of Rule 4402, costs used for these analyses are for a 1,000 ft2 surface area sump (the exemption limit for small producers) and are annualized 1986 dollars from the ARB TSD document on sump control measures. Staff contacted stakeholders and requested additional cost information for sump covers but no facility in the Valley has ever installed a cover on a sump. As previously discussed, historically when an operator must install a cover on a sump they respond by replacing the sump with a tank. Therefore, stakeholders do not have any cost information to provide the District for costs of sump covers. Stakeholders informed District staff that they had asked vendors and were unsuccessful in getting cost data for sump covers from them. District staff did additional research to obtain this cost information, including requesting it from EPA, and because no facilities use sump covers, District staff were equally unsuccessful in obtaining said data; as such, District staff have determined that the cost information provided in the ARB TSD is the only cost data available, and therefore it is the appropriate cost information for these analyses. Refer to Appendix B for the complete discussion of these analyses.





Replace a sump with a Tank District staff then evaluated the cost effectiveness for a small producer to install a tank (with additional required processing) to replace a sump, and again determined that it is not a cost effective option. Refer to Appendix B for the complete discussion of this analysis. Because there is no cost effective method of compliance or an alternative, this exemption demonstrates RACT. District staff proposes to not amend Section 4.1.1. Section 4.1.2 This exemption is for clean produced water in sumps. The Federal Register does not cite a deficiency specific to Section 4.1.2; however, the TSD states that clean produced water has a limit of 5mg/l in SCAQMD, VCAPCD, and SLOCAPCD. The VOC content for clean produced water in the Valley is RACT as there is no additional available control technology or processing method reasonably available or feasible, as outlined in section 3.0 of the Discussion Section of this final draft staff report for that analysis and discussion. It is important to note that SBCAPCD Rule 344 B.2. has an exemption for post tertiary sumps and post tertiary pits, which can be interpreted as an exemption for clean produced water in sumps. Section 4.1.3 EPA Comment: Section 4.1.3 exempts operations less than 300 barrels per day with sumps less than 5000 sf from substantive requirements. No other neighboring districts allow exemptions for very small producers. The EPA TSD elaborates on the discussion in the Federal Register to clarify that SBCAPCD Rule 344 exempts small producers (less than 150 barrels/day average over one year) with no restriction on surface area of sump or type of crude oil in; additionally, SBCAPCD Rule 244 exempts any 2nd or 3rd stage sump with less than 1000 ft2 of surface area, also with no restriction on type of crude oil.

District Response: Removing the exemption in Sections 4.1.3 would result in very small producers either having to comply with rule requirements pursuant to Section 5.0, or having to replace the sumps with tanks (and additional required processing). It is important to note that historically, when faced with complying with rule requirements, operators have chosen to remove the sump and install a tank, as confirmed at the public workshop on October 18, 2011. District staff evaluated the cost effectiveness for a small producer to comply with Section 5.0 and determined that it is not a cost effective option. District staff then evaluated the cost effectiveness for a small producer to install a tank to replace a sump, and again determined that it is not a cost effective option. A summary of these analyses is presented earlier in this final draft staff report; for the detailed analyses for these refer to Appendix B of this final draft staff report. Because there is no cost effective method of compliance or an alternative, this exemption demonstrates RACT. District staff proposes to not make this rule amendment. Very small producers have smaller facilities and similar, if not more expensive and difficult to implement, cost and feasibility factors as small producers; therefore the determination that there is no cost effective option for





small producers is also applicable to very small producers. See section 4.1.1 of the Discussion section of this final draft staff report for the analysis. Section 4.1.4 The Federal Register does not cite a deficiency for Section 4.1.4. However, the TSD does cite that no other districts were found to have a similar exemption. This exemption is for sumps with estimated emissions of 0.007 lb/sq ft per day or less established by the ARB flux-box test method. District staff researched this exemption and determined that this exemption originated from the ARB Suggested Control Measure (SCM) for the Control of Organic Compound Emissions from Sumps Used in Oil Production Operations. ARB has not since published a revised SCM recommending that air districts no longer offer this exemption for crude oil production operations. Therefore, District staff has determined that this exemption is still relevant and it continues to be appropriate. District staff proposes to keep this exemption in rule language. Section 4.1.5 The Federal Register does not cite a deficiency for Section 4.1.5. However, the TSD does cite that no other districts were found to have a similar exemption. This exemption, as currently enforced, is for any first, second or third stage sump used not more than seven days in any one calendar month and not more than 21 days per calendar year. District staff has evaluated the relevance of this exemption and have determined that it is still relevant and does continue to be an appropriate exemption; therefore, District staff propose to keep this exemption in rule language. District staff does however; propose to amend this section to remove references to first stage sumps. First stage sumps would be prohibited in the Valley on and after January 1, 2013, therefore it would be irrelevant to include them in this exemption. Refer to Section 5.0 of the Discussion section of this final draft staff report for further discussion on this proposed prohibition of first stage sumps. Section 4.1.6 The Federal Register does not cite a deficiency for Section 4.1.6. The TSD does cite that Rule 4402 is intended to control emissions from crude oil production sumps and is not meant to address sumps at petroleum refineries.





Section 4.1.7 EPA Comment: Section 4.1.7 exempts ponds of “clean produced water” with less than 35 mg/l VOC from Rule 4402 requirements. In contrast, SCAQMD Rule 1176(i)(5)(J), VCAPCD Rule 71.4 C.1.c and SLOCAPCD Rule 419 C.4 exempt wastewater sumps only where the VOC content does not exceed 5 mg/l at the inlet. District Response: District staff has determined that 35 mg/l VOC for clean produced water is RACT. See Section 3.0 of the Discussion section of this final draft staff report for the discussion of that determination. Staff proposes to make no amendments to this section of the rule. Section 4.1.8 EPA Comment: Rule 4402 does not limit the time that oil or oily water can be kept in an emergency pit. In contrast, SLOCAPCD Rule 419 C.2 requires clean-up to begin within 24 hours and to finish within 15 days. The TSD further states that the SBCAPCD exempts pits for emergencies that are used less than 30 days per year and VCAPCD also exempts emergency pits. The TSD elaborates, “We understand that many ponds in the San Joaquin Valley have been closed under Regional Water Quality Control Board (RWQCB) order, but other ponds continue to operate in the district.” Emissions from these ponds are not included in the Districts current VOC emission inventory for crude oil production sumps because they are exempt. It is not known if the VOC emissions from the ponds are significant or not. The ponds that initially receive wastewater from oil production would have the highest VOC concentrations and are of particular concern. District Response: District staff has reviewed this comment and has determined that it would be appropriate to require a time limit for use of emergency pits. District staff has determined that the use of an emergency pit, as currently enforced, is not an unlimited time. If it is determined that a sump is in continuous use it is inspected and regulated as a sump; however, staff agree that this amendment could improve enforceability of rule requirements. Staff proposes to amend Section 4.1.7 to remove “Pits” from the section and to add it to a new section by itself. As such, Section 4.1.8 would be created to provide the exemption for pits, and effective on and after January 1, 2013 the use of emergency pits would be required to begin within 24 hours after the end of each emergency occurrence and for clean-up to be completed within 15 days after the beginning of clean-up efforts. This requirement would also contain associated recordkeeping requirements pursuant to Section 6.0 of the rule; please see Section 6.0 of Rule 4402 for recordkeeping requirement language. It should be noted that District staff disagree with EPA concerns that VOC emissions from ponds may be significant. Ponds are defined to only contain clean produced water, which has a VOC content of 35 mg/l of water. This is significantly less than what would be found in a sump with oily water in it. Clean produced water has already been through a process to remove the majority of the oil.





D. Section 5.0 – Requirements EPA Comment: Rule 4402 allows 1st stage sumps. In contrast, SBCAPCD Rule 344 and VCAPCD Rule 71.4 do not allow the operation of 1st stage sumps.

District Response: Research of the District permit database, the District emission inventory, and field research by District staff indicate that no first stage sumps are in use in the Valley. Tanks were installed to replace the first stage sumps over twenty years ago, in response to regulatory requirements for air and water quality. District staff proposes to add a new section that prohibits first stage sumps as of January 1, 2013; this new section would be Section 5.1. All sections under Section 5.0 would be renumbered to reflect the addition of the new requirement in Section 5.1. Section 5.1.2 EPA Comment: Section 5.1.2 allows a 1-inch gap and does not require seals for rigid floating covers. In contrast, SCAQMD Rule 1176(e)(2)(B)(vi) and SLOCAPCD Rule 419 D.2.e. require rigid floating covers to have seals, the gap cannot exceed 1/8” for a cumulative length of 95% of the perimeter, and no single gap may exceed ½ inch. District Response: Based on staff research and conversations with stakeholders and staff from other air districts staff have determined that there are no sumps in the SLOCAPCD and there are no sumps in SCAQMD. This is further supported by the 1988 ARB TSD which determined that 95% of the total surface area of sumps in California were located in the Valley, and the majority of these sumps were used by small producers of heavy crude oil. Only 0.44 percent of the total surface area of sumps were located in SLOCAPCD and only two percent of the total surface area of sumps were located in the SCAQMD during the years of 1984 – 1986. District staff believes that there are no sumps in California complying with the proposed requirements in the EPA comment. The requested requirements in the EPA comment are beyond RACT. It is important to note that sumps in the Valley are excavations in the ground with unfinished, and unlined, sides. Covers with a 1/8-inch gap are not a feasible option for existing sumps in the Valley because the sides of the sumps erode. No facilities in the Valley use covers on their sumps, rigid or otherwise. If the rule requirements are amended or exemptions removed resulting in previously exempt sumps becoming subject to rule requirements then, based on historical activities and observations, and statements from operators, operators will opt to put in a tank to replace the sumps rather than invest significant funds to meet new sump requirements. Because sumps in the Valley are unlined excavations in the ground and no facility has a sump cover, if an operator were to become subject to new rule requirements they would be required to install new sumps and new sump covers. As discussed earlier in this final draft staff report, compliance with requirements pursuant to Section 5.0 is not cost effective for small and very small producers. Amending Section 5.0 would be beyond RACT for small and very small producers.





If a large producer were to become subject to rule requirements costs would include the installation of new sumps and new sump covers and additional gas capture systems and control or destruction technology, in addition to additional labor and maintenance costs. According to the 2007 Area Source Emission Inventory Methodology, there are seventeen third stage sumps used by large operations producing heavy crude oil. There are no second stage sumps used by large operations and no third stage sumps used at light oil production facilities. These seventeen active sumps have an average surface area of 3,200 ft2. The smallest sized sump that the ARB TSD accounted for was a 500 ft2 sump with annualized capital costs of $5,580 for a flexible floating cover and $9,480 for a rigid floating cover. For purposes of this cost effectiveness analysis, District staff used the cost information provided by ARB in the TSD, converted those costs to 2011 costs then added the additional costs associated with the necessary capture and control devices. See below for the full analysis. District staff used the cost information from the ARB TSD because it is the only information available because, as previously discussed, no operators have ever installed a sump cover and distributers do not know of any facility in California that has a sump cover, therefore they also do not have cost information. Staff used the following equation to adjust from the annualized cost at 1986 dollars to 2011 dollars (multiplying by 2.75% inflation/yr):

$/��1 + 0.0275�2011 − 1986�� = $�� Table 6. ARB TSD Data for Floating Sump Covers for 500 ft2 Sumps (Adjusted to

2011 dollars)

Type of Floating Cover

1986 Annualized

Capital Costs

2011 Annualized Capital costs

Control Efficiency

Life Span of Cover

Flexible $5,580 $9,416 98% 5 years

Rigid $9,480 $15,998 90% 5 years

ARB makes the statement in the TSD that floating covers pose a safety hazard because sumps where methane is produced or dissolved gases can enter the sump with the feed stream. The floating cover would not allow the escape of these gases and could create a situation that would result in explosions. The ARB TSD further explains that the combustible gases that might otherwise accumulate beneath the cover would need to be removed and disposed of. The method of disposal of collected gas would be to install a combustion device such as a flare. This cost effectiveness analysis accounts for these additional costs. Additional costs for the capture and control devices used for this analysis, as discussed in detail in Appendix B of the final draft staff report, include the following:

• Cost for capture device ($45,068) • Cost for control/destruction device ($85,729)





The adjusted annual cost accounts for the cost of the sump cover, the capture device, and the control/destruction device as discussed above are presented in the table below: Table 7. Total Adjusted Annualized Costs

Type of Cover

Cost for Sump Cover

Cost for Capture Device

Cost for Control Device Total Costs

Flexible $9,415 $45,068 $85,729 $140,213

Rigid $15,998 $45,068 $85,729 $146,795 The ARB TSD costs were combined with the above mentioned costs to perform the cost effectiveness analysis as presented in Table X below. Table 8. Cost Effectiveness for 3rd Stage 500 ft2 Heavy Oil Sump Equipped with a

Floating Sump Cover

Sump VOC Emissions

(tpy)

Control Efficiency

VOC Controlled

(tpy)

Adjusted Annualized

Cost

Cost per ton of VOC

controlled Flexible 0.47 98% 0.46 $140,213 $304,810 Rigid 0.47 90% 0.42 $146,795 $349,511

Section 5.2.5 EPA Comment: Section 5.2.5 requires fixed covers to be equipped with a pressure/vacuum (PV) valve set to within ten percent of maximum safe working pressure. In contrast, SCAQMD Rule 1176(2)(A)(ii) and (6)(A) and SBCAPCD Rule 344 D.2.b.2 require that fixed covers be equipped with a 95% efficient air pollution control (APC) device.

District Response: As discussed earlier in this final draft staff report, compliance with requirements pursuant to Section 5.0 is not cost effective for small and very small producers. Amending Section 5.0 would continue to be not cost effective, and therefore go beyond RACT for small and very small producers. If a large producer were to become subject to rule requirements costs would include the installation of new sumps and new sump covers and additional gas capture systems and control or destruction technology, in addition to additional labor and maintenance costs. According to the 2007 Area Source Emission Inventory Methodology, there are seventeen third stage sumps used by large operations producing heavy crude oil with an average surface area of 320 ft2 The smallest sized sump that the ARB TSD accounted for was a 500 ft2 sump with annualized capital costs of $3,920 for a fixed roof cover. For purposes of this cost effectiveness analysis, District staff used the cost information provided by ARB in the TSD because it is the only information available because, as previously discussed, no operators have ever installed a sump cover and distributers do not know of any facility in California that has a sump cover, therefore





they also do not have cost information. 1. The ARB TSD lists $3,920 per year, 90% control efficiency, and a 5 year life. Adjusting from the annualized cost at 1986 dollars to 2011 dollars (multiplying by 2.75% inflation/yr):

$3,920��

�1 + 0.0275�2011 − 1986�� = $6,615��

2. Again, this cost data would be combined with the additional capital costs for installing a vapor recovery and destruction device to each sump for safety purposes. The adjusted annual cost accounts for the costs discussed are summarized above and discussed in detail in Appendix B of the final draft staff report. Those costs include the following:

• Cost for capture device ($45,068) • Cost for control/destruction device ($85,729)

3. Staff combined the annual capital cost with the cost for the capture device and the cost for the control device as follows:

$6,615 + $45,068 + $85,729 = $137,412 4. Using the same capital cost data discussed previously in combination with the added cost of emptying the sump and storing or disposing of the liquid within it during the construction of the new sump would result in the cost effectiveness analysis as presented in the table below.

Table 9. Cost Effectiveness for a Large Producer Heavy Oil 500 ft2 Sump Equipped

with a Fixed Roof Sump Cover Sump VOC

Emissions (tpy)

Control Efficiency

VOC Controlled

(tpy)

Adjusted Annualized

Cost Cost per ton of VOC controlled

3rd Stage: 0.93 90% 0.84 $137,412 $115,426

It is important to note that if the rule requirements and exemptions are amended resulting in the requirement of facilities to install a 95% control on a sump, then operators will install a tank to replace the sumps. Replacing a sump with a tank is not a cost effective option, as discussed in the earlier in this final draft staff report. Section 5.3 EPA Comment: Section 5.3 states: “If replacement tank exclusively serves identical function of sump replaced, permitting of such tank shall not be considered an emission change for the purposes of Rule 2201 (New and Modified Source Review Rule)”. Any exemptions to NSR requirements should be incorporated within the NSR program. This





language should be removed.

District Response: If the NSR exemption were removed from Rule 4402, operators who replace sumps with tanks that serve an identical function would be subject to BACT when they apply for permits to install those tanks. Although existing Rule 2201 Sections 4.2.3 and 4.6.8 allow exemptions from BACT and Offset requirements, the exemptions apply only to the installation or modification of an emission control technique performed solely for the purpose of compliance with the requirements of District, State or Federal air pollution control laws, regulations or orders. Such exemptions do not apply to replacement units needed to comply with the prohibitory rules. Therefore, District propose to retain the existing language in Rule 4402 with the replacement of the word “shall” with the word “may” as agreed upon as appropriate for District Rule 4702 by EPA and ARB. E. Section 6.0 – Administrative Requirements EPA Comment: Rule 4402 does not require periodic inspection of covers and APC equipment to ensure proper operation. In contrast, SCAQMD Rule 1176(f)(1)(C) requires periodic leak inspection and APC testing. District Response: It is not technologically feasible for sumps in the Valley to have covers; therefore no sumps in the Valley have covers or associated APC equipment. Additionally, if this amendment were made, and exemptions were removed to make currently exempt sumps subject to rule requirements facilities would respond by replacing the sumps with tanks which is not a cost effective option. However, if facilities were to install a tank to replace a sum then the tank would become subject to Rule 4623. As it would be duplicative to put tank requirements in this rule staff propose to not amend this section of the rule. Section 6.1 EPA Comment: Add requirement to keep all records for at least two, and preferably five years. District Response: District staff proposes adding requirements to keep records for a minimum of five years to Section 6.1. Staff has determined through review of permit conditions that crude oil production facilities are already keeping records for a five-year period. For any facilities not keeping records for five years, this would be an administrative change and would not be associated with significant operational changes or increased costs. Staff revised the proposed language to remove the term “on site” from the language. Many oil sites are at remote locations with no buildings around them, and many operators have several remote locations and a an office at a different location, removing the “on site” language will allow operators to have flexibility in where they store these records.





District staff proposes to require operators to keep records pursuant to Section 6.1 and make them available to the District, ARB, and EPA upon request instead of requiring annual submission of this data. This is not a relaxation because the records will still be maintained and made available, but it will streamline the process for both the stakeholders and the District. EPA Comment: Add requirements to verify the sump surface area and the annual production rates for both the small producers and very small producers in section 6.1.1. District Response: District staff proposes to amend Section 6.1.1 to clarify and simplify rule language and to require that on and after January 1, 2013, operators shall be required to keep records that will verify sump surface area and annual production rates. District staff assume these facilities are already keeping these records, therefore this is an administrative change and will result in no emissions reduce and no additional costs to the facility. District staff also proposes to create a new Section 6.1.2 and require that after January 1, 2013, any operator claiming exemption pursuant to Section 4.1.3 keep records that document the sump surface area and annual production rates. District staff assumes these facilities are already keeping these records; therefore this is an administrative change and will result in no emission reductions and no additional costs to the facility. EPA Comment: Require documentation justifying any exemptions claimed under section 4, including 4.1.7, which exempts pits and ponds. District Response: District staff proposes to add Section 6.1.5 to rule language to require an operator claiming an exemption pursuant to Section 4.1.6 to keep records to justify the exemption. EPA Comment: Add requirement to document use of emergency pits, including when use started, clean-up started and clean-up finished. District Response: District staff proposes to add Section 6.1.6 to rule language to require recordkeeping to document the use of emergency pits including when the use of the emergency pit began, when clean-up of the pit began, and when clean-up of the pit is finished. This is an administrative change and is not expected to result in emissions reduced or additional costs to the facility. Staff revised the proposed language to clarify that this new recordkeeping requirement pertains only to pits used for emergencies. Staff also want to further clarify that the emergency pits that are unmanned and at remote locations staff does not expect them to know when the emergency began, to fulfill that requirement staff will request that operators document when the emergency was discovered. For example, if a facility has an emergency on Saturday morning, but the operator doesn’t check on that facility until Tuesday, then the documented time of the start of the emergency would be Tuesday.





With regards to the clean-up beginning within 24 hours after the end of the emergency, this would still apply. If the emergency is discovered Tuesday morning, and has already ended, then efforts should begin within 24 hours after the discovery. Section 6.2 EPA Comment: Revise Section 6.2 Test Methods to remove and/or replace inappropriate or outdated test methods such as ARB Method 432, which is designed for paints and coatings and not oily wastewater. EPA also recommends adding EPA Test Method 21 in Section 6.2 for determining leaks. District Response: District staff reviewed test methods presented in Section 6.2 and determined that the test method ARB Method 432 is not applicable to sumps, therefore propose to remove it from the rule. Staff proposes to delete the test method from Section 6.2.1 and move test method 422 from Section 6.2.2 to Section 6.2.1. Additionally, staff proposes to add a sentence to the beginning of Section 6.2 verifying that the test methods pertain to rule requirements in Section 5.0 of the rule. This added sentence will improve clarity of rule requirements and does not change the intent or requirements of the rule. District staff does not propose the addition of EPA Method 21 for detection of leaks because there are no leak standards, no seals, and no proposed standards or seals in rule language to justify the requirement of a leak test method. F. Section 7.0 Compliance Schedule

EPA Recommendation: EPA recommends deleting Section 7.0 from the rule since it is no longer applicable. It is important to note that this is a recommendation and not a deficiency. District Response: District staff has reviewed this recommendation and rule language, and proposes to delete Section 7.0 from rule requirements; this amendment will improve rule clarity and simplify rule language, but does not change the intent or requirements of the rule. G. Additional EPA Comments and Recommendations EPA Comment: Provisions should be added in Rule 4402 or Rule 4623 (Storage of Organic Liquids) that ensure that tanks used to replace the 1st stage crude oil sumps have adequate VOC controls.

District Response: If a sump is replaced with a tank it becomes subject to Rule 4623; which includes the appropriate requirements for tank controls, and has already been approved by EPA as at least satisfying RACT. The purpose of this rule-amending project is to address EPA cited deficiencies in Rule 4402 only. Adding tank requirements to the sump rule would be duplicative. As such, District staff proposes to not make any amendments to Rule 4402 to include requirements for tanks.





EPA Recommendations: EPA recommends the following improvements for the District to consider during rule-amending process:

1. Increase the requirements for testing wastewater at each inlet to the clean produced water ponds from annually to at least quarterly to ensure ongoing compliance with wastewater VOC limits.

2. Rule 4402 does not include controls for crude oil well cellars, evaluate whether to include requirements for controlling emissions from crude oil well cellars in Rule 4402 or as a separate rule.

District Response: District staff does not feel that increasing the testing from annual to quarterly is warranted. Additionally, crude oil well cellars are a very small source of emissions in the Valley, with estimated emissions of just 0.05 tons of VOC per day. The District will consider these recommendations during future reviews of this rule. V. GLOBAL CLIMATE CHANGE AND GREENHOUSE GASES The California Global Warming Solutions Act of 2006 (AB 32) created a comprehensive, multi-year program to reduce greenhouse gas (GHG) emissions in California, with the overall goal of restoring emissions to 1990 levels by the year 2020. In the coming years, the Air Resources Board (ARB) and the Legislature will be developing policies and programs to implement AB 32. The District believes that the evidence and the rationale that climate change is occurring is compelling and convincing. In addition to the long-term consequences of climate change, the District is concerned with the potential ramifications of more moderate but imminent changes in weather patterns. The Valley depends heavily on agriculture for its economy and has developed agricultural practices based on the last several decades of weather patterns. Unanticipated and large fluctuations in these patterns could have a devastating effect on the Valley’s economy. While there are many win-win strategies that can reduce both GHG and criteria/toxic pollutant emissions, when faced with situations that involve tradeoffs between the two, District staff believes that the more immediate public health concerns that may arise from an increase in criteria or toxic pollutant emissions should take precedence. The San Joaquin Valley Air Pollution Control District’s Governing Board adopted the Climate Change Action Plan (CCAP) in August 2008. For California Environmental Quality Act (CEQA) requirements, one of the goals of the CCAP is to establish District processes for assessing the significance of greenhouse gas impacts. The District has developed a policy and guidance for addressing greenhouse gases under CEQA.





VI. HEALTH BENEFITS This rule contributes to the Valley’s progress towards federal health-based air quality standards (National Ambient Air Quality Standards, or NAAQS). Progressing the Valley towards attainment of the NAAQS helps reduce the Valley’s air pollution-related health impacts and health-related costs. The District periodically compiles attainment plans to quantify the amount of emission reductions needed and identify the individual control measures that will achieve these reductions. The control strategy as a whole has important public health benefits and health costs savings. However, for a number of reasons, it can be difficult or even misleading to attempt to subdivide this total plan benefit on a rule-by-rule basis. For example, photochemical reactions in the Valley’s atmosphere combine precursor emissions to generate ozone and particulate matter in the atmosphere, so it is not always appropriate to attribute the health and cost benefits to just one precursor. Also, considering the extensive emission reductions that have already been achieved in the Valley over the past several years, some emissions sources may appear relatively small and inconsequential from a health perspective. In reality, all attainment plan rule commitments are important to the District’s overall strategy for reducing ambient air pollutant concentrations and the associated health impacts and costs. VII. ANALYSES A. Emission Reduction The proposed rule amendments are intended to address the limited approval from EPA concerning RACT. District staff reviewed all subjected facility’s permit data and determined units are already in compliance with the proposed. Therefore, no emission reductions are expected from this rule making project. B. Cost Effectiveness Pursuant to California Health & Safety Code Section 40920.6(a), the District is required to analyze the cost effectiveness of new rules or rule amendments that implement Best Available Retrofit Control Technology (BARCT) or planning requirements to incorporate all feasible measures. The proposed amendments to this rule would only add federal RACT requirements but not BARCT or all feasible measures, and are therefore not subject to the cost effectiveness analysis mandate. Given that operators are generally complying with the new limits currently and there are no significant emission reductions or compliance costs expected from these rule changes, a cost effectiveness analysis has not been performed.





C. Socioeconomic Pursuant to CH&SC 40728.5, “whenever a district intends to propose the adoption, amendment, or repeal of a rule or regulation that will significantly affect air quality or emissions limitations, that agency shall, to the extent data is available, perform an assessment of the socioeconomic impacts of the adoption, amendment, or repeal of the rule or regulation.” The source category covers crude oil production sumps pits and ponds in the Valley. This rule-amending project is not expected to have significant costs associated with it. As there would be no costs associated with this rule-amending project, there would be no additional socio-economic impacts.

Environmental Impact D. Pursuant to §15061 of the Guidelines for Implementation of the California Environmental Quality Act (CEQA), District staff investigated the possible environmental impacts of the proposed amendments to Rule 4402. Based on the lack of evidence to the contrary, District staff has concluded that the proposed amendments to this rule will not have any significant adverse effects on the environment. Staff recommends filing a Notice of Exemption under the provisions of Public Resource Code 15061(b)(3).

Rule Consistency E. Pursuant to CH&SC §40727.2, District staff prepared a rule consistency analysis that compared the elements of amendments with the corresponding elements of other District rules and federal regulations. District staff found that none of the proposed amendments would conflict with other District rules, or federal rules, regulations, or policies covering similar stationary sources. That analysis is presented in Appendix C of this final draft staff report.

Reasonably Available Control Technology F. CAA §182(b)(2) states that ozone attainment plans shall assure that RACT for VOC is applied at certain sources. A RACT analysis requires an examination of a rule against Federal rules, regulations, and technology guidelines as well as comparing it against rules from other air districts in California. On Thursday, July 7, 2011, EPA published in the Federal Register a RACT analysis of District Rule 4402. As documented in the Federal Register, EPA determined that Rule 4402 satisfies RACT and the rule is largely consistent with the relevant CAA requirements, with a few exceptions. The purpose of this rule-amending project is to address the RACT deficiencies as identified by EPA and as discussed in this final draft staff report. As such, this rule satisfies RACT requirements.





VIII. REFERENCES Bay Area Air Quality Management District [BAAQMD]. (Amended September

15, 2004). Regulation 8 Organic Compounds Rule 8 Wastewater Collections and Separation Systems. Retrieved from http://www.baaqmd.gov/~/media/Files/Planning%20and%20Research/Rules%20and%20Regs/reg%2008/rg0808.ashx?la=en

California Air Resources Board [ARB]. (Updated December 1993). Emissions Factors

for Oil and Gas Production Sumps and Pits California Air Resources Board [ARB]. (August 1988). Technical Support Document.

ARB’s Suggested Control Measure for the Control of Organic Compound Emissions from Sumps Used in Oil Production Operations

Cook, R (2011, November 03). Governor removes DOGGR supervisor from her post.

Bakersfield.com Retrieved from http://www.bakersfield.com/news/business/economy/x1454911264/Governor-removes-DOGGR-supervisor

Cox, J. (2011, September 04). Local oil industry wary of EPA’s push for tighter rules

protecting underwater aquifers. Bakersfield.com . Retrieved from http://www.bakersfield.com/news/business/economy/x130698618/Local-oil-industry-wary-of-EPAs-push-for-tighter-rules-protecting-underground-aquifers?utm_campaign=flyout&utm_medium=flyout&utm_source=news_business_economy

Environmental Protection Agency [EPA]. (October 2010). Technical Support Document.

EPA’s Analysis of San Joaquin Valley Air Pollution Control District’s Rule 4402, Crude Oil Production Sumps

Federal Register. Approval and Promulgation of Implementation Plans; California State

Implementation Plan Revision; Kern County Air Pollution Control District; Santa Barbara County Air Pollution Control District, 1996, 5515 – 5517).

Revisions to the California State Implementation Plan, San Joaquin Valley Unified Air

Pollution Control District [CFR], 76, Fed. Reg. 130, pp 39777-39782. (2011, July 7). (to be codified at 44 CFR Part 64)

San Joaquin Valley Unified Air Pollution Control District [District]. (2009, January 23).

2007 Area Source Emissions Inventory Methodology 310 – Oil Production Fugitive Losses

San Luis Obispo County Air Pollution Control District [SLOCAPCD]. (Adopted July 12,





1994). Rule 419 Petroleum Pits, Ponds, Sumps, Well Cellars, and Wastewater Separators. Retrieved from http://www.arb.ca.gov/DRDB/SLO/CURHTML/R419.htm

Santa Barbara County Air Pollution Control District [SBCAPCD]. (Adopted

November 10, 1994). Rule 344 Petroleum Sumps, Pits, and Well Cellars. Retrieved from http://www.arb.ca.gov/DRDB/SB/CURHTML/r344.pdf

South Coast Air Quality Management District [SCAQMD]. (Amended September 13,

1996). Rule 1176 VOC Emissions from Wastewater Systems. Retrieved from http://www.aqmd.gov/rules/reg/reg11/r1176.pdf

Ventura County Air Pollution Control District [VCAPCD]. (Amended June 8, 1993). Rule 71.4 Petroleum Sumps, Pits, Ponds and Well Cellars. Retrieved from http://www.arb.ca.gov/DRDB/VEN/CURHTML/R71-4.PDF

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