Reliable Precise Rapid

SpectraSensors TDLAS Analyzers for Refinery GasesAccurate and Reliable Measurement of H2S and H2O

TDLAS Analyzers for Refinery Gases2

SpectraSensors’ mission SpectraSensors specializes in the design and manufacture of tunable diode laser absorption spectroscopy (TDLAS) analyzers for on-line, real-time measurement of contaminants in process gas streams. Bringing together individuals from diverse scientific and engineering disciplines has enabled us to solve real-world problems and become the recognized leader in TDLAS technology with an unmatched portfolio of patents. Our commitment to providing accurate and reliable solutions for measuring contaminants in process gas streams is evidenced by an installed base of 7,500+ TDLAS analyzers around the world.      Industries served SpectraSensors’ TDLAS analyzers are used in the natural gas, gas processing, liquefied natural gas (LNG), petrochemical, refining, and atmospheric testing industries.  SpectraSensors’ organization SpectraSensors, Inc. was formed in 1999 as a technology spin-off of the NASA / Caltech Jet Propulsion Laboratory (JPL) in Pasadena, California. Technology development and analyzer manufacturing are based in Rancho Cucamonga, California, and the company headquarters is in Houston, Texas. A regional Center-of-Competence (CoC) is located in Compiegne, France to provide technical support to European customers. SpectraSensors was acquired by Endress+Hauser in 2012. Endress+Hauser is a global leader in instrumentation for process automation based in Switzerland which has built an unsurpassed reputation for producing high quality instruments for measurement and control of liquid phase processes. Acquisition of SpectraSensors extends Endress+Hauser’s presence into gas phase measurements and strengthens SpectraSensors’ ability to support customers globally. In late 2013, Kaiser Optical Systems, Inc, the company which developed the Raman-based Optograf spectrometer, was also acquired by Endress+Hauser, further solidifying the company’s position in gas analytics.        

SpectraSensors: A leading global provider of laser-based process instrumentation

Natural Gas Gas Processing

Liquefied Natural Gas (LNG) Petrochemical

Refining Atmospheric Testing

3

Refinery Unit Operations, Products and Gas Streams

LPG

H2 Recovery

Gas Processing

Refinery Fuel Gas

Isomerization

Reformate Splitter

Jet Fuel Hydrotreater

Diesel Hydrotreater

Diesel

Jet FuelKerosene

Crude

Evacuated Non-condensibles

Light Gas Fuel Hydrocracker

Light Gas Fuel Hydrotreater

Heavy Gas Oil

DAO

SolventDe-asphalter

FCC Feed Hydrotreater

Fluid CatalyticCracker

Gasoline Hydrotreater

Butamer Alkylation Alkylate

Naphtha HydrotreaterNaphtha

To H2Recycle

To H2 Recycle

To Gas Processing

To Gas Processing

To Gas Processing

To H2 Recycle

To H2 Recycle

To H2 Recycle

To H2

Recycle

To H2

Recycle

To H2 Recycle

RecoveredHydrogen and

Refinery Off Gas

AtmosphericBottoms

Atm

osph

eric

Dist

illat

ion

Olefins

Oil

Vacu

umDi

still

atio

n

H2

H2

H2

H2

H2

H2

H2

H2

H2

LPG

CatalyticReformers

Natural Gas

Sweet Dry GasH

2

Gasoline Blendstock

LPG

Gasoline Blendstockand Aromatics

Diesel

Jet Fuel

Gasoline Blendstock

Gasoline Blendstock

Aviation Gasoline

Industrial Fuel OilBlendstock

LPG

Gasoline Blendstock

Gasoline Blendstock

Hydrogen PlantPetrochemical

Plant

The design of a refinery gas distribution network and management of gas streams directly affect production capacity. Refineries must produce, recover, treat, and recycle hydrogen and other gases in order to produce low-sulfur clean fuels.

Refinery gas streams contain contaminants that can adversely affect operational efficiency, process yields, and refinery operating margins. SpectraSensors TDLAS analyzers perform on-line measurements of H2S and H2O

in process gas streams to help refineries control these contaminants and optimize unit operations.

On-line monitoring of H2S and H2O provides refineries the data needed to improve process control, meet product specifications, mitigate corrosion and catalyst poisoning, comply with environmental regulations, and treat hydrogen and off gas streams for use in downstream refinery and petrochemical processes.    

Monitoring contaminants in refinery gas streams for operational efficiencySelective and specific measurement of critical process contaminants

The SpectraSensors advantage Tunable diode laser absorption spectroscopy (TDLAS) analyzers from SpectraSensors perform on-line, real-time measurements of impurities in process gas streams from sub-ppm levels to low percentage levels. The unique design of SpectraSensors’ TDLAS Analyzers provide significant advantages over other technologies for monitoring H2O and H2S in refinery gas streams.

Non-contact measurement The laser and solid state detector components of TDLAS analyzers are isolated and protected from the process gas and entrained contaminants flowing through the sample cell. This design avoids the fouling and corrosion problems associated with Al2O3 and Quartz Crystal Microbalance moisture analyzers, ensuring reliable long-term operation.

Fast response and analysis time TDLAS analyzers detect changes in analyte concentration much faster than other techniques. The wet-up and dry-down times associated with Quartz Crystal Microbalance moisture analyzers result in a delayed response to concentration changes. Gas chromatography (GC) results can be delayed several minutes awaiting completion of a chromatographic run.

Low cost of ownership Unlike GCs and lead acetate tape analyzers, TDLAS analyzers have virtually no consumable components resulting in a lower cost of ownership and a lower service and maintenance burden on technicians.

TDLAS Analyzers for Refinery Gases4

Laser-based analyzers for refinery gasesLaser spectroscopy – a better solution for challenging process conditions

TDLAS Analyzers for Refinery Area Safety Classifications

5

Fluid Catalytic Cracker Unit (FCCU) C3 Gas Recovery

Fluid catalytic cracking units (FCCU) are a major source of the propylene feedstock used in petrochemical plants. The yield of propylene from an FCCU varies with feedstock and operating conditions. Refineries operate FCCUs to achieve a balance of gasoline and propylene production.

The gas plant associated with an FCCU separates fuel gas from C3 and C4 gases and gasoline, and contains treatment equipment to remove H2S, H2O and other contaminants from these products.

Many downstream petrochemical processes employ catalysts that are highly sensitive to H2S and H2O.

These contaminants must be removed from C3 propane/propylene mixtures to avoid carryover into the separated propane and propylene product streams.

On-line monitoring of H2S and H2O in C3 mix, and the separated propane and propylene product streams ensures purity specifications are met for downstream refinery and petrochemical production processes.

SpectraSensors’ patented* differential spectroscopy technique enables detection and quantitation of low ppm levels of H2O and H2S in propane/propylene mixtures.

Fluid catalytic cracker unit (FCCU) C3 gasesH2S and H2O measurement in propylene and propane

*www.spectrasensors.com/patents

Products

Feed

Propane

C3 Splitter

PropyleneC3 MixC3 / C4

Fuel GasC2 and lighter

C4

Debutanizer

Gasoline

Absorber

Slurry Oil

Fractionator

Heavy Cycle Oil

Light Cycle Oil

Heavy Naptha

L/L Separator

G/L Separator

Flue Gas

Air Blower

Regenerated

Spent

Regenerator

Reactor

AX

AX

Catalyst

CatalystDepropanizer

AX

TDLAS Analyzers for Refinery Gases6

Semi-Regenerative Catalytic Reformer (SRR)

Catalytic reformers convert naphtha into high-octane aromatic compounds used in gasoline blending, and yield large quantities of hydrogen which is recycled and used in other refinery processes. A semi-regenerative catalytic reformer (SRR) unit has three fixed bed catalytic reactors employing a platinum/rhenium catalyst on a chloride alumina support. Water and an organic chloride compound are continuously injected to maintain acid sites needed to perform the conversion reactions. Excess H2O strips chloride from catalyst surfaces and forms corrosive HCl which is transported throughout the process piping of the SRR unit. On-line monitoring of the H2O concentration enables refineries to control the chloride level for catalyst activity and minimize HCl formation.

Catalyst activity in an SRR gradually decreases as coke is deposited on the catalyst. The SRR must be shut down periodically to burn off coke deposits and regenerate the catalyst. Tracking the H2O level in hydrogen gas recirculating through an SRR to dry down catalyst following regeneration helps determine when end point H2O conditions have been reached to restart the SRR unit and resume production. Delays in restarting a SRR can cost a refinery hundreds of thousands of dollars per day in lost production.

Inside an SRR sulfur compounds are converted into H2S which is entrained in the recycle and net hydrogen streams. On-line monitoring of H2S in the hydrogen recycle gas helps prevent poisoning of the platinum/rhenium catalyst.

Semi-regenerative catalytic reformer (SRR)H2O and H2S measurement in hydrogen recycle gas

Net Hydrogen

HydrogenRecycle Gas

Off Gas

Liquid

Reformate

Recy

cle G

as

Fired Heater Fired Heater Fired Heater

Fixed Bed Reactor

Naphtha and Hydrogen

Recycle Gas

Feed (Naphtha)

Cooler

Gas Separator

Fixed Bed Reactor

Fixed Bed Reactor

AX

7

Continuous Catalytic Reformer (CCR)

A continuous catalytic reactor (CCR) has a 3-stage stacked reactor employing platinum/rhenium catalyst on a spherical chloride alumina support. Gravity causes the catalyst to flow down through the reactor stack. The catalyst is continuously extracted from the bottom of the reactor stack and transferred to a separate, external catalyst regenerator.

Inside the regenerator, coke deposits are burned off and the catalyst oxy-chlorinated and dried sequentially in separate zones. Following reactivation with hydrogen the catalyst is returned to the top of the reactor stack.

On-line monitoring of the H2O concentration enables refineries to control the chloride level required for catalyst activity and helps minimize HCl formation. Carryover of small amounts of HCl in the net hydrogen gas can cause serious operating problems in downstream processes using the hydrogen.

Sulfur compounds in the naphtha feed are converted to H2S inside a CCR reactor. On-line monitoring of H2S in the hydrogen recycle gas helps prevent poisoning of the platinum/rhenium catalyst.

Continuous catalytic reformer (CCR)H2O and H2S measurement in hydrogen recycle gas

AX

Heater

Fuel GasLight endsto recovery

LowPressure

Separator

Recycle HydrogenReformate

Net Liquid

Net H2 Gas

Stabilizertower

Regeneratedcatalyst

Stacked Reactor

Spent Catalyst

CCR Regenerator

Feed

TDLAS Analyzers for Refinery Gases8

AX

AX

Feedstock(olefins, isobutane)

Acid Purifier

Reactor

Acid Oils

Fresh Acid

Settler

Caustic Washer

Recycle Isobutane

Deisobutanizer Propane

Depropanizer

Alkylate

AcidRecycle

Refinery Fuel and Flare Gas Systems

Refinery fuel gas is composed of a mixture of hydrogen and C1 to C5 hydrocarbons recovered from different unit operations within a refinery for use as fuel in fired heaters and boilers. In the U.S. sulfur emissions from combustion of fuel gas and refinery flare systems are regulated under the Clean Air Act & Amendments (CAAA).

The U.S. EPA is responsible for issuing regulations and test methods for compliance enforcement. Regulations covering sulfur (SO2) emissions from combustion of fuel gas and flare systems are defined in 40 CFR 60 Subpart Ja. Similar regulations aimed at reducing SO2 emissions have been promulgated in Europe, the Middle East, and Asia.

The U.S. EPA recognizes that measurement of H2S gives a good approximation of the total SO2 that is generated from combustion of refinery fuel and flare gases. The required measurement range for H2S in fuel gas is 0 – 320 ppmv. The regulatory limit is 162 ppmv. One measurement every 15 minutes (96 times / day) is required to meet U.S. EPA requirements for continuous emissions monitoring. For flare gas H2S levels must not exceed 162 ppmv over a three-hour rolling average time period (approximately 500 lbs. of SO2 in any 24-hour period).

Refinery fuel and flare gasH2S measurement for environmental compliance

AX

AX

AX

FCC Off GasCrude Off Gas

Fractionator Off Gas Naphtha Flash Gas

Catalytic Reformer Off GasHydrotreater Off Gas

Isomerization Off Gas

To Refinery Heaters / Boilers

Gas Treatment

RefineryFuel Gas

Refinery Off Gas (ROG)

Flare Headers

Knock OutDrum

Flare Gas

9

Refinery off gas (ROG)Measuring contaminants in refinery off gas for olefins recovery

Refinery Off Gas System for Olefins Recovery

Refinery off gases recovered from unit operations are typically collected and sent to the refinery’s fuel gas system. Large quantities of off gas from FCCU, coker, and catalytic reforming units can overload a refinery’s fuel gas system with excess gas sent to flare.

The off gas streams from FCCU and coker units contain significant amounts of olefins that can be recovered, treated, and upgraded from low value fuel components into higher value ethylene and propylene. Refineries with high crude oil processing capacities (> 250,000 bpd) may have integrated petrochemical complexes to take advantage of feedstocks recovered from

refinery off gases. In these cases the ROG must undergo more extensive gas treatment to remove contaminants (H2S, CO2, H2O, NH3, C2H2, Hg, and COS) than occurs in a fuel gas system prior to fractionation and olefins recovery. ROG exiting an amine treatment unit is saturated with water. Water must be removed before the gas undergoes cryogenic fractionation. Molecular sieve dehydration is used to dry ROG streams down to < 1 ppmv H2O to avoid formation of hydrates and ice during cryogenic fractionation. On-line monitoring of H2O at the outlet of molecular sieve dryer vessels helps detect H2O breakthrough and prevent gas with elevated levels of H2O from entering cryogenic separation equipment.

AX AXAX

FCC Off GasCrude Off Gas

Fractionator Off Gas Naphtha Flash Gas

Catalytic Reformer Off GasHydrotreater Off Gas

Isomerization Off Gas

To Refinery Heaters / Boilers

Gas Treatment

RefineryFuel Gas

Refinery Off Gas (ROG)

Flare Headers

Knock OutDrum

Flare Gas

DehydrationOlefins

Fractionation & Recovery

Petrochemical/Polymer Plant

TDLAS Analyzers for Refinery Gases10

AX

AX

Feedstock(olefins, isobutane)

Acid Purifier

Reactor

Acid Oils

Fresh Acid

Settler

Caustic Washer

Recycle Isobutane

Deisobutanizer Propane

Depropanizer

Alkylate

AcidRecycle

HF Alkylation Process

In HF alkylation C3 – C5 olefins from a fluid catalytic cracker unit (FCCU) are reacted with isobutane to produce high octane fuel alkylate. Water must be removed from the olefin feedstock to minimize corrosion and formation of acid soluble oil (ASO) and fluorinated by-products. Process efficiency and properties of the alkylate end product (octane number, vapor pressure) are affected by HF acid purity and water content. The water content of olefin feedstock is typically in the range of 1 – 5 ppmv. On-line monitoring of H2O helps prevent build-up of ASO which consumes HF and reduces acid strength. HF consumption can cause an acid runaway condition requiring process shutdown for costly, specialized maintenance.

The exceptionally fast response of TDLAS analyzers to changes in H2O concentration helps control the H2O content of feedstock entering an HF alkylation unit. The non-contact, laser based measurement technique of TDLAS analyzers avoids fouling and corrosion that leads to frequent replacement of devices using direct contact sensors.

The superior on-stream factor (analyzer availability) of TDLAS analyzers reduces the need for personnel to enter the HF alkylation unit area to undertake repair or replacement of H2O analyzers.

HF alkylationH2O measurement in alkylation feedstock

AX

Feedstock(olefins, isobutane)

Acid Purifier

Reactor

Acid Oils

Fresh Acid

Settler

Caustic Washer

Recycle Isobutane

Deisobutanizer

Propane

Depropanizer

Alkylate

AcidRecycle

11

Instrument air systemsH2O measurement in instrument air

Instrument Air System

The air supplied to instruments, transmitters, solenoid valves, and pneumatic controllers must be clean and dry for efficient operation of control system components. Corrosion damage from moisture in an instrument air system can cause false readings and/or instrumentation malfunctions potentially leading to process upsets or shutdowns.

Refineries and petrochemical plants monitor moisture in instrument air to protect pneumatically controlled devices and ensure those devices are functioning properly and safely.

Moisture, particulate matter, lubricants and hazardous or corrosive chemicals are the four major types of contaminants defined in ISA-S7.3: Quality Standard for Instrument Air.

TDLAS analyzers have proven to be an effective means of monitoring moisture in refinery instrument air systems. The laser and detector components are isolated and protected from contaminants entrained in instrument air. This design avoids the fouling and corrosion problems experienced with analyzers using direct contact sensors (aluminum oxide capacitance sensors and quartz crystal microbalances).

AX

Compressor

After-Cooler

Air Tank Air Dryer Dry Receiver

To Plant

Pre Filter After Filter

Docu

men

tatio

n co

deBR

REF

INER

Y EN

01

(6/1

7)Contact

SpectraSensors, Inc.4333 W. Sam Houston Pkwy N. Suite 100Houston, TX 77043

Tel +1 713 300 2700 +1 800 619 2861Fax +1 713 856 6623

sales@spectrasensors.comservice@spectrasensors.comwww.spectrasensors.com

© 2017 SpectraSensors, Inc.Products or references stated may be trademarks or registered trademarks of their respective owners. All Rights reserved.

Endress+Hauser is a global leader in measurement instrumentation, services and solutions for industrial process engineering. The company acquired SpectraSensors in 2012. Soon thereafter Kaiser Optical Systems was also acquired bringing the Raman-based Optograf analyzer into the product portfolio further solidifying Endress+Hauser’s position in process gas analytics.