24-Sour Gas Processing

UNIT 24

SOUR G AS PROCESSING

Introduction GAS PROCESSING OBJECTIVES 

Understanding the purpose of gas processing operations Dehydration  NGL recovery  Fractionation  LNG manufacture   

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Sweetening Sulfur recovery

Know the main types of processes for each operation

Gas processing is the treatment used to reduce impurities to an acceptable content or to enhance the total gas stream value. value. The process is generally implemented in the order listed, starting starting with dehydration to permit transport of the gas stream or to prepare it for natural natural gas liquid (NGL) recovery. Fractionation is used to separate the NGL components and Liquefied natural gas (LNG) consists primarily of liquefied methane from a cryogenic process. If H 2S or CO2 contaminate the gas, a gas sweetening process is used to remove these contaminants prior to dehydration and NGL recovery. H 2S and CO2 are called acid gases; they form acids in the presence of water. “Sour gas” is a produced gas stream (associated or non-associated) that contains acid gas components. Sour gas processing is more than the sweetening sweetening step. Acid gas disposal is the primary consideration since economic, environmental, and safety issues all impact and frame frame the possible alternatives. One option is sulfur recovery that is used to convert H 2S to sulfur. In addition sulfur disposal is a major component within the context of sour gas processing. Important points: Key Messages 

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Unit 24 Sour Gas Processing

This section has a variety of options available for sour gas treating. The variety can cause confusion. confusion. Increased supply of sulfur requires that we consider “sulfur disposal” instead of “sulfur recovery”. H2S is extremely toxic. Selection of treating/disposal options requires careful analysis of technical, safety, health, environmental, and business factors.

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UNIT 24


So u r G a s P r o c e s s i n g Sour Gas Processing Objectives    

Understand why we sweeten gas Know the components removed in a gas sweetening process Understand the types of processes available Understand the S.H.E. (Safety Health Environmental) Environmental) issues associated with w ith sour gas

The first step in sour gas processing usually occurs after the gas has been gathered and compressed to a pressure suitable for treating. The gas from several field areas gathered at a central site typically is the most cost efficient method for gas sweetening. H2S and CO2 removal is the common definition of “gas sweetening” where the hydrocarbon components are sent on for dehydration and NGL recovery while the non-hydrocarbon acid components are sent to “acid gas disposal”.

Steps in Gas Processing

The sour gas processing actually consists of two separate fundamental fundamental steps: 1.) Gas sweetening to remove H2S and CO2 and 2.) Sulfur recovery/tail gas cleanup to enable disposition of the H2S and CO2 in a safe and environmentally acceptable manner. The acid gas components in sour gas greatly add to OPEX and CAPEX of facilities. Most of the equipment shown in the photo would not be required if the gas were sweet.

Mary Ann and 823


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UNIT 24


In another plant layout, the gas sweetening processes and sulfur recovery processes are outlined at the left for each of three parallel trains. Note the tall incinerator stack at the far right of each plot area. Again this plant would be much smaller if processing only sweet gas.

Jay Gas Plant -- St. Regis

“Sour gas” consists of the hydrocarbon and nonhydrocarbon components that enter the gas sweetening process. This step gives the “sweet gas” of hydrocarbons and nitrogen (if any) in one stream and the “acid gas” of H2S and CO2 in the other stream. Most of the sulfur is recovered in a Claus plant and then any remaining H2S in the tail gas is removed in the tail gas cleanup unit (TGCU).

Traditional Sour Gas Processing

Sour Gas Processing Additional Considerations


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Other options to the traditional sour gas processing steps are shown in this schematic. The additional considerations to the basic process steps arise due to economic, regulatory, or plant construction time constraints. Other processing steps or acid gas/sour gas injection may yield improved economics and improved regulatory compliance.

UNIT 24


REMOVAL of H2S, CO2, etc. 

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Acid Gases -- form acids in water H2S (hydrogen sulfide, SPEC < 4 ppmv)  CO2 (carbon dioxide, SPEC < 50 ppmv cryogenic)  CO2 Spec varies for other applications  Sulfur Species Spec between 10 -100 ppm COS (carbonyl sulfide)  CS2 (carbon disulfide)  RSH (mercaptans)  RSR (sulfides or thiophenes) 

Specification (spec) for gas going to a sales pipeline or into NGL recovery requires a very low level of H2S. The CO2 limit is about 50 ppm for cryogenic processing but can be much higher in certain situations. In addition other sulfur species have a maximum specification limit. Any undesirable component must be removed to the specification limit for acceptance for sale or NGL processing.

Why Remove Acid Gas Components?  

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H2S is very toxic, even in small concentrations H2S and water are corrosive.

CO2 will freeze in cryogenic processes. Some customers cannot accept CO2 in hydrocarbon feed streams. CO2 and water are corrosive.

Mercaptans, CS2, Sulfides, and COS are undesirable. These components can concentrate in NGL products

H2S SAFETY HEALTH and ENVIRONMENTAL sometimes called S.H.E. or H.S.E    

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H2S kills faster than Hydrogen Cyanide You never knew what hit you -- if you’re revived 1000 ppm or 0.1% is fatal Blocks respiration and causes chemical asphyxiation Vapor Density: 1.19 @ 59°F & 1 atm. (heavier than air) Flammable limits: 4.3% to 46% in air (wider range than methane) Combustion: burning H2S produces sulfur dioxide (SO2), which is also very toxic Odor threshold: 0.06 to 1 ppm Olfactory fatigue: 50 to 150 ppm OSHA 8-hour TWA: 10 ppm


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The extreme toxicity of H 2S requires special precautions at facilities and wells with this component. Common sense actions could save your life or that of your colleagues: Be aware which wells and facilities have H2S  Have H2S monitors on your person and know  where safety masks (SCBA – Self Contained Breathing Apparatus) are located Know wind direction and escape to upwind  locations Know that H2S is heavier than air and settles  in low points (well cellars) and stays in enclosed vessels Know that H2S tends to associate with the  vapor phase so be wary for vapor leaks at connections, mechanical seals on pumps, instrumentation, and safety relief valves If you ever become complacent you will most  likely die

UNIT 24


Gas Sweetening ‘Solvent’ Process

A few examples of the numerous solvents used are categorized by type of solvent and by the nature of its absorption process to remove the acid components. These examples and categories are shown at the top half of the list. In addition non-absorption processes are use to sweeten gas. These are listed in the bottom half. Most of the world’s sour gas is treated using solvent processes.

Gas Sweetening Processes

Sweetening PFD


The most common sweetening processes use “solvents” to absorb the acid gas components and remove them from the incoming sour natural gas stream. The sweet residue gas is ready for added processing and the “rich solvent” goes to the regenerator. In this step the acid gas components are removed from the solvent, which is then recycled as “lean solvent” to the absorber.

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The process flow diagram (PFD) for the typical sweetening process is shown in the schematic. In general concept it is much like the glycol dehydration PFD. Primary items are the absorber tower and the stripper tower. The absorber is the sweetening unit while the stripper is part of the solvent regenerating unit. The solvent essentially makes a continuous loop while the gas merely passes through the absorber.

UNIT 24


The key item is the absorber tower that contacts the down-flowing lean solvent on the trays (or packing) with the rising sour gas vapor. The mixing action causes the solvent to absorb the acid gas components, which leaves a sweet gas to exit the absorber overhead. The rich solvent with the acid gas components is sent to the stripper. The mixing also causes the solution to warm. Absorber bottom temperatures are generally 70 to 80 C (160 to 180 F).

Review of Absorber

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The stripper tower is the key item in the solvent regeneration procedure. The rich solvent enters the top tray (or packing) and is stripped of H2S and CO2 by the rising vapors. The lean solvent is returned to the absorber while the overhead stripper gas plus the H2S and CO2 go to sulfur recovery/disposal.

Review of the Stripper

A wide variety of solvents can be used to remove H2S and CO2 or primarily H2S. A solvent that removes primarily the H 2S is deemed selective, that is the H 2S is removed (to the specification limit) but a significant portion of the CO 2 is not (slips through). More “selective” processes allow more CO2 to slip into the sweet gas. Selective processes generally require less CAPEX for downstream sulfur disposal options. However, the sweet gas customer(s) must be willing to take the additional CO2.

Selectivity


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UNIT 24


Solvent loading is the quantity of acid gas components contained per unit quantity of solvent. The lean solvent loading is termed lean loading and the example shows this to be 0.001 mole H2S per mole of MEA (monoethanolamine). Exiting the absorber tower, the solvent is rich with acid gas and the term rich loading is applied. The example has this as 0.350 mole H2S per mole of MEA. The pickup of acid gas is the difference or 0.349 mole H2S per mole of MEA. High loading values are desirable because they relate to lower solvent circulation rates and lower investment.

Solvent Loading

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Amine Solvents

MEA - Monoethanolamine DEA - Diethanolamine DGA - Diglycolamine DIPA - Di Isopropanolamine MDEA - Methyl Diethanolamine TEA - Tri Ethanolamine DEMEA -Diethyl Monoethanolamine

An amine solution is the most commonly used sour gas processing solvent. They are categorized as primary, secondary, or tertiary by the number of alcohol groups attached to the nitrogen. The common amines in each category are shown. The amine solutions are weak organic bases that have a chemical reaction with the weak acid solutions containing H2S or CO2. This acid – base reaction forms weak salts that decompose when heated.

Gas Treating Amines


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UNIT 24


The size of the sweetening plant can be very large, such as the left photo of the Saudi Aramco DGA Plant at Shedgum circulating 10,000 gpm to treat 500 million scf per day of sour gas. Skid-mounted rental unit at right circulates 3 gpm for fuel gas treating.

Sizes of Amine Plants

FLEXSORB is a class of ExxonMobil solvents that are generally selective for H2S. They allow the CO 2 to slip through for further processing. The combination of high selectivity and high solution loading permit circulation rates to be reduced, which significantly reduce the initial capital and operating costs.

Technology Review Capacity Increase with FLEXSORB ®

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FLEXSORB ® SE Highly selective for H2S  High capacity for H 2S  Not tertiary amine, but sterically hindered  FLEXSORB ® SE Hybrid Addition of Sulfolane to FLEXSORB ® SE enhances  mercaptan and carbonyl sulfide removal. FLEXSORB ® PS Hybrid A Hybrid of FLEXSORB ® PS and Sulfolane gives good  bulk removal and an improvement over Sulfinol. Also removes mercaptans and carbonyl sulfides

Potassium Carbonate Solvents

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Potassium carbonate solvents (K2CO3) are used for removal of large quantities of CO2. This chemical absorption process has the absorber tower and stripper tower schematic shown that is similar to the amine processes. Potassium carbonate cannot achieve the high purity achieved with amine solvent. Potassium carbonate is usually limited to bulk removal operations.


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FLEXSORB-HP Catacarb Benfield Lurgi Vetricoke

Potassium Carbonate Solvents

UNIT 24


Physical Solvents

The physical absorption solvents listed below do not react chemically but use physical attraction similar to lean oil or glycol absorption processes. The absorber tower and stripper tower components are the same and since no chemical reaction occurs, the solvent does not degrade as quickly. Physical solvents normally have lower heat requirements. The disadvantages are high-pressure requirements (6000 – 10000 kPa, 800-1500 psi) and high heavy hydrocarbon co-absorption. Selexol  Purisol  Recitisol  Propylene Carbonate 

The PFD for a physical solvent system is very similar to a chemical solvent system. However there is a succession of recycle flash tanks downstream of the absorber. Also in some applications stripping gas can be used in lieu of a reboiler. There is generally a trade off with the physical solvent systems using more recycle horsepower and less heat and fuel gas.

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Physical Solvents

FLEXSORB - PS FLEXSORB-SE Hybrid Sulfinol – D Sulfinol – M


Hybrid Solvents

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UNIT 24


Hybrid Solvents

Hybrid solvents combine chemical and physical absorption solvents to potentially achieve the best characteristics of each. This combination can reduce capital, energy required for regeneration, and operating cost. The PFD has the same absorber tower and stripper tower arrangement as the amine processes.

Gas Sweetening Processes

Alternatives to solvent sweetening processes are the non-regenerable, direct conversion, dry bed, and separation processes listed.

For very small quantities of sour gas, such as fuel gas, the non-regenerable scavenger processes can be used. Small quantities of  H2S No CO2 removal  Dispose of spent  material Operation of scavenger systems can become very expensive with time due to the reoccurring fresh solvent purchase costs and the spent solvent disposal costs. Unit 24 Sour Gas Processing

Non-Regenerable / Scavengers

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UNIT 24


Non-Regenerable / Iron Oxide

Iron sponge is another non-regenerable process. It consists of wood shavings or wood chips impregnated with hydrated iron oxide for removal of H 2S. Exposure to H2S and mercaptans produces iron sulfides and iron mercaptides. The removal of H2S results in iron sulfides as follows: 2Fe2O3 ·H2O + 6H2S --> 2Fe2S3 + 8H2O

Sometimes it may be re-oxidized or reverted, with exposure to air, to iron oxide and elemental sulfur. The spent iron sponge is pyrophoric or self-heating and care should be taken when handling the spent material.

The LO-CAT process is one of several processes that removes H2S and converts it to elemental sulfur in one unit operation. The LO-CAT process is a liquid redox system that uses a chelated iron solution to convert H2S to elemental sulfur. The Stretford process is an older process that has similar performance, but the Stretford solution is toxic. LO-CAT does not use toxic chemicals and produces no hazardous waste byproducts. Generally the sulfur from a LO-CAT unit cannot be sold; it does not have the bright yellow color of Claus sulfur because it contains impurities. However, sometimes it can be given to farmers. Some operators have reported solids plugging.

Direct Conversion LO-CAT Unit

Dry Bed Removal of Acid Gas

Dry bed methods use the molecular sieves similar to dry bed desiccant dehydration. In fact the mole sieves can be used to sweeten and dehydrate simultaneously, but considerably more molecular sieve is needed to do both. The beds are usually regenerated with a heated side-stream of treated gas. The tower undergoing regeneration also has its pressure reduced to accelerate the regeneration procedure. Regeneration temperatures are 250 to 300 C (450600 F) The gas used to regenerate the beds must also be treated and can require a separate treating system. °

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UNIT 24


Cryogenic separation processes could be used for a sour gas stream containing 20% to 80% acid gases. The cold temperature cryogenic facility could integrate NGL recovery, nitrogen rejection, and liquefaction. Most cryogenic sweetening systems must make allowances for CO2 freezing in the system.

Cryogenic Separation

Ryan-Holmes is a cryogenic process that uses a solvent to prevent CO2 freezing. The CO2 can be removed from the NGL via traditional fractionation, however more solvent may be necessary to break the azeotrope and allow complete separation.

Acid Gas Separation - Ryan Holmes

Acid Gas Separation - Membranes

Feed Gas

C2 CH4

Residue Permeate

Gas

N2

SPIRAL WRAP Feed Gas

CO2

Residue Gas

Permeate

H2S C2 CH4 N2

HOLLOW FIBER


SLOW

O2

CO2 H2S

H2

PERMEATION RATES

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H20

FAST

H2O

Membranes provide direct separation of gas components with no moving parts. Issues: Gas purity  Membrane integrity  Plugging  Much work is being done to improve membrane run times. Membranes are ideal for offshore and fuel gas treating, however premature plugging and performance degradation have kept acceptance limited to special cases.

UNIT 24


The sour gas treating options are listed and each process identifies the ExxonMobil plants. The most common is MDEA (methyldiethanolamine) and the second is Sulfinol, which is a hybrid of sulfolane (tetrahydrothiophene dioxide) and DIPA (di-isopropanolamine) or MEA (monoethanolamine).

Gas Sweetening Facilities - Operational Issues -

ExxonMobil Sour Gas Processing

Issues relating to sour gas processing operations are:  

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Off specification gas, solvent carryover Varying composition or unknown feed impurities: paraffins, BTX’s, sulfur, oxygen, FeS, mercury Inadequate regeneration, impurities, off-spec solvent concentration Hydrocarbon (HC) contamination, low H 2S/CO2 ratio Exchanger leaks Vessels foaming, flooding, or plugging plus corrosion or mechanical damage

UNIT 24


Sour Gas Processing Processes Used at ExxonMobil Locations Chemical Solvents (Reaction)      

Process Selection

Traditional Amines MEA, DEA, DGA, MDEA High Performance Amines FLEXSORB SE Promoted MDEA Potassium Carbonates

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Physical Solvents (Absorption) 

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Selexol, Purisol

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Hybrid Solvents 

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H2S concentration CO2 concentration Inlet gas composition Heavy hydrocarbons (especially aromatics)  Mercaptans, COS, sulfur, etc  Mercury, Diamondoids  Operating pressure and temperature Treated gas specifications Disposal mechanism

Sulfinol, FLEXSORB PS

Other    

Ryan Holmes Molecular Sieves Iron Sponge, Scavengers Membranes

Process selection is largely dependent on the quantity of H 2S and of CO 2 in the feed stream. H2S must be removed for sale or NGL processing of the gas, however CO2 might be retained to control the BTU content of the gas or for subsequent processing and use in enhanced recovery projects. Acid gas pickup should be high in order to reduce circulation rate, which can reduce absorber tower size and reduce the heat duty needed to regenerate the solvent.

Sweetening Process Selection

Summary -- H2S CO2 Removal    

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H2S and CO2 are the main acid gas components removed in a sweetening process. There are a wide variety of options available for sour gas treating. Sour gas treating is a costly complex operation. H2S is extremely toxic. Selection of treating/disposal options requires careful analysis of technical, SHE, and business factors. The cost and design of gas sweetening units depend on gas composition, pressure, product specs, markets, and local regulations.


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UNIT 24


Su l f u r Re c o v e r y /D i s p o s a l Sulfur Recovery/Disposal Objectives    

Understand why we recover or dispose of sulfur compounds Understand the effect of CO2 on the processes Understand the types of processes available for sulfur recovery and tail gas cleanup Understand there are significant S.H.E. (Safety Health Environmental) issues associated with sour gas.

Disposition of H2S is the step after sour gas sweetening. The acid gas components must be processed to remove H2S or they must be injected. Typically the H2S is converted to sulfur in the Claus sulfur recovery plant with a small remaining quantity converted in the tail gas cleanup unit.

Disposition of H2S

The numerous ExxonMobil sulfur recovery units (SRU) are listed. The variations of the Claus process are represented at the plants depend on the nature of the acid gas and local regulations.

ExxonMobil Upstream Sulfur Recovery Units


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UNIT 24


ExxonMobil Sulfur Production

Need sulfur? We can make you a special deal. Along with being the largest oil company, ExxonMobil has the “dubious” distinction of producing the most sulfur. Sulfur production occurs worldwide since oil and gas operations containing H2S are common.

H2S and Sulfur Species Disposal Options Traditional SRU/TGCU 

Convert to elemental sulfur and hopefully sell it.

Seawater Scrubbing 

Oxidize to SO2, absorb with seawater, and discharge in the ocean.

AG Injection 

Compress and inject acid gas in an appropriate subsurface location.

Claus Sulfur Recovery Unit


The Claus sulfur recovery unit pictured is typical of the various installations. A portion of the H 2S is burned to form SO2, which is then reacted with the remaining H 2S feed to yield elemental sulfur. The facility has thermal (furnace) and catalyst (reaction or converter) sections to obtain the necessary high conversion of H2S to elemental sulfur (96 – 98%).

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UNIT 24


THERMAL SECTION 60 - 65%

Technology Description - Sulfur Recovery Units 

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Burner: Burn 1/3 of H 2S to SO2 Reaction Furnace: Time for thermal reaction Most of sulfur is formed Waste Heat Boiler: Recover heat Sulfur Condenser: Remove sulfur CATALYTIC SECTION 93 - 98 %

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The conversion of H2S to sulfur is shown on the chart as Sulfur Recovery %. It is a function of the % H2S in the acid gas feed stream. The recovery is highest and the investment capital is lowest for cases with high H2S content acid gas. This occurs because less inert CO2 must be processed in the system

Sulfur Recovery Units Effects of H2S Enrichment

Sometimes acid gas enrichment (AGE) can be added to increase the H2S content in the Claus feed, which reduces the cost of the facility.

SRU Feed Conditioning Acid Gas Enrichment (AGE)


Reheat: Vaporized entrained sulfur Avoid sulfur condensation Reactor (Converter): Promotes Claus reaction Alumina catalyst Sulfur condenser: Remove sulfur Reduce sulfur loses

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UNIT 24


Some SRU components in the LaBarge sulfur recovery unit are pictured. The catalytic converter is shown at upper left, the run down pits are shown at upper right, and the sulfur storage tanks are at bottom.

LaBarge SRU

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Catalyst deactivation sulfation  coking  sulfur condensation  thermal degradation  Excessive emissions due to off-design performance H2S and/or solids buildup in rundown pit Significant amounts of CO2 increase OPEX and CAPEX Poor reaction furnace performance due to burner or internals failure Hydrocarbon (HC) contamination Aromatics in acid gas Low H2S/CO2 ratio Exchanger leaks in condensers, reheaters, and waste heat units. SULFUR SALES OR DISPOSAL??

The Claus plant does not convert 100% of the H2S to sulfur, so a small quantity remains for disposal. The tail gas cleanup unit (TGCU) is used convert the small remaining amount to sulfur or to recycle any remaining H2S back to the Claus unit.

Disposition of H2S


Claus Sulfur Recovery Units -Operational Issues-

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UNIT 24


Approaches to Tail Gas Cleanup

The tail gas cleanup units of ExxonMobil are listed. The plant name, followed by country location and process option, shows a widespread geographic and process range.

ExxonMobil Tail Gas Cleanup Units

Amoco CBA (Sub Dew Point TGCU)


The sulfur compounds remaining in the tail gas from the Claus unit must be converted and the basic approaches are listed. The tail gas cleanup unit (TGCU) is generally an extension of the Claus process that increases H2S conversion. Some of the processes recycle H2S back to the front of the SRU.

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The Amoco Cold Bed Adsorption (CBA) method is an example of the extended Claus process. It operates at a sub-dew point temperature and the sulfur vapor is adsorbed on the catalyst. When the bed is saturated with sulfur, the catalyst is regenerated with hot vapor directly from the first converter. The elemental sulfur desorbs and is removed in the condenser. The higher conversion of H2S to sulfur at the lower temperatures causes the improved recovery.

UNIT 24


The Shell Claus Offgas Treating (SCOT) process has a reduction section and an H2S selective absorption section. The tail gas is mixed with hydrogen and undergoes a reduction reaction over the cobalt molybdenum catalyst. Most sulfur compounds are converted to H2S that can be recovered in a selective amine process to be recycled to the Claus plant.

SCOT Process BSR with Amine Absorption

Any remaining sulfur compounds incinerated to form sulfur dioxide (SO 2). 

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are

Incineration (Thermal Oxidizer)

The tail gas is fired with auxiliary fuel gas to achieve a stack temperature of approximately 1000 ºC. The stack is approximately 100 m high to allow sufficient dispersion of unrecovered sulfur dioxide. With new technology sulfur emissions can be kept below 100 ppm during normal operations.

Sulfur Disposal


Sulfur disposal is currently a problem since the worldwide production from sulfur recovery plants exceeds the demand.

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UNIT 24


Tengiz

One large accumulation of sulfur is at Tengiz. The people walking on this block are potentially at hazard for their lives. Bubbles of molten sulfur can migrate within the sulfur block, and a person could fall into molten sulfur if the surface gives away.

Some forecasts predict there will over one billion metric tonnes of sulfur stored in Alberta alone by 2099. This view of the Quirk Creek plant and sulfur storage shows the size of a 200,000 tonne block and indicates the magnitude of the potential problem.

Prilled Sulfur


174,000 Tons of Sulfur

Sulfur can be made into pellets for shipment to manufacturing plants for sulfuric acid or similar uses. The liquid sulfur is piped the top of the prilling towers at left. The sulfur falls, similar to rain drops, and cools in descent to arrive at bottom as pellets. The right photo shows the pellets being removed for bulk shipment by rail or barge or for bagging to be shipped in smaller quantities.

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UNIT 24


Offshore Sulfur Disposal

When sulfur recovery is required in fuel systems offshore, the sulfur must be returned to land. An ASME vessel is filled with sulfur production and is carried to shore on a workboat for disposal.

Acid gas disposal is an option to sulfur recovery and tail gas cleanup. Two options are listed. The first requires processing to convert H2S to SO 2 and the second uses injection into approved salt water aquifers.

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ABB SO2 Seawater Scrubbing Acid Gas Injection

The seawater scrubbing steps are:

Seawater Scrubbing of SO 2

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Technology Review - Acid gas disposal

Page 22

H2S is converted to SO 2 in an incinerator. Hot effluent from an acid gas incinerator is quenched with seawater. Additional seawater is used to absorb approximately 98-99% of the SO2 from the gas. A countercurrent packed bed absorber is used. The spent quench water and absorber wash water are returned to the sea. The treated gas is vented via fuel gas fired incinerator.

UNIT 24


Operational issues regarding seawater scrubbing are:

SO2 Seawater Scrubbing -Operational Issues-

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Seawater must be available, fresh water will not work. Large quantities of seawater are required. Reliable quenching is essential. Only applicable to reasonably small quantities of sulfur Significant quantities of CO2 in the acid gas adversely affect the economics. Picture shows unit delivered to Statoil's Åsgard B platform

Injection into approved subsurface locations is an option. The facility will typically have multistage compression. Sour gas injection will have the hydrocarbon components whereas acid gas injection would be primarily the H2S and CO2. For sour gas injection dehydration is required at an intermediate pressure to minimize the corrosion problem.

Acid Gas / Sour Gas Injection -Operational Issues-

Sour Gas / Acid Gas Injection

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Page 23

Number of wells Completions: Materials for tubing string, wellhead and packers. Reservoir: Volume, injectivity, impurities, communication with other zones Facilities: Horsepower, injection pressure containment , materials, seals, toxicity, maintenance, sparing, and rotor dynamics

UNIT 24


Summary H2S Recovery and Disposal 

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H2S has no value and cannot be vented. It must be disposed of safely. 99.0 to 99.9% of the H2S must be recovered. CO2 mixed with the H2S adds to the disposal cost and complexity. Sometimes acid gas enrichment is required. H2S is extremely toxic. Selection of disposal options requires careful analysis of technical, SHE, and business factors. The cost and design of sulfur recovery units depend on acid gas composition, markets, and local regulations.


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24-Sour Gas Processing

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