. *

SPEf==iLl~maKalcsESWI-CSSSf.WME

WE 6651

PiiOCESSlNGSOURdATURALGAST(IMET PIPELINECUALITY

by B. Ge!ieGear and Thomas O. Arrington.Goar,hrrington andAssociates, Inc.

1

Copyright 1977, Amemxr Insldute ot Mmmg. Metallurgical, and Petfoleum Ersgmeers, Inc

This paper was presenled al Ihe 1977 SoUr Gas Sympos!um ofmeSocfecyofPetroleum Engineers Of Al ME held m Tyler. Texas, November 14.15.1977 The malerlal Msubfecl 10correction by lhe authorPermission 10copy IS restricted to an abs[racl Of nol more than 300 words Write 6200 N Centra, Expy, Oak.. Texas 75206

4BSTRACTd) thea:tiountof sour components (H2S and C02)

The processing of sour natural gas is gaining to be removedinterest and popularity due to the search for addi- e) che amount of sulfur to be recoveredtional sources of available energy. The decision to f) the presence and amount of inerts and otherwild a sour natural gas processing plant involves contaminants such as N2, 02, COS, CS2 andnany considerations and represents a sizeable invest- mercaptansnent. Selection of the optimum prou%sing scheme 9) the sales 9as specifications to be metencompasses the areas of: (1) gas cleaning, (2j gas h) the air pollution regulationswhich will dic-treating, (3) LPG liquids recovery, (4) gas duhyd””a- tate if sulfur recovery and/or TGCU istion and (5) possibly sulfur recc!veryand tail gas required:lean-up. Major factors and various options affecting i) the availability of a close market for thethe selection of an rsptimumprocessing scheme are plant products~iscussed in this paper. j) the Price and total revenue obtained for the

[INTRODUCTIONplant products, i.e., sweet sales gas, liquidsand sulfur

k) the investment required to construct and“Theuse of fossil fuels in the United Stdtes operate the plant

doubles about every 20 years. With the ever increas-ing demand for more energy, the interest in processing DISCUSSIONand conditioning of sour natural gas for pipelinesales is growing. The large reserves of sour gas in Best Processing Approachthe Southwest are located in the Permian Basin of WestTexas and the Smackover trend runnincjthrough East and Once the drilling activity in a sour gas field isNortheast Texas, Louisiana, Mississippi, Alabama and nearing completion, the producer must decide upon theWestern F;orida. Huge amounts of sour gas will be best approach to processing the sour gas:produced *:,dprocessed from the Smackover trend in thefutur:. 1. Is it more economical to lay a sour gas line

to the riearestgas processing plant, whichWhen an evaluation to build a “grass-roots”sour handles similar gas and may have excess capac-

natural gas processing p!~nt is conducted, many pro- ity, and pay a processing cost (@/MCF) to htivecess considerationsand economic factors must be the gas conditioned?reviewed to decide upon the optimum overall scheme.A detailed evaluation must be performed to establish 2. Or, is it more economical to lease equipmentthe best combination of processing steps for: (1) gas (skid-mountedplant) for on-site processing?cleaning, (2) gas treating (sweetening),(3) LPGliquids recovery required for dewpoint control or 3. Or, is it most feasible to build a “grass-liquid sales, (4) gas dehydration, (5) sulfur recovery roots” plant to be owned and operated by theand (6) tail gas clean-up (TGCU)flif required. The producer? The plant can be owned by onemajor.factors affecting the outcome of the evaluation company or a group of companies/parties,con-are: tributing to the overall investment and

operating cost, and sharing in the overalla) the daily volume of sour gas to be processed revenue.b) the estimated life of the reservoir at this

flow The answers to these questions depend upon manyofC) the liquids content of the gas (GPM of C2+) the major factors discussed earlier, i.e., gas volume,

References at end of papergas composition, sulfur production, pollution

4 “

14 PROCESSING SOUR NATURAL GAS TO MEET PIPELINE QUALITY SPE 6651-. -----

regulations, plant revenues, plant costs, etc. If the 6. Will corrosion inhibitors be used for down-”decision is made to build a “grass-roots”plant, the hole corrosion control or collection-lineproducer should employ an engineering company to study protection? If so, what types and how muchthe project and prepare their recwmnendationsfor (a) of each?the optimum gas processing scheme, (b) the environ-mental impact, (c) the plant revenues to be realized 7. What quantity of free hydrocarbon liquids willand (d) the development of a definitive estimate for be produced with the sour gas (Bbls./MMSCFl?the construction and operation of the plant. Then aneconomic analysis and justificationmust be prepared The importanceof obtaining an accurate sour gaswhfch show an attractive pay-out and return-on- analysis and satisfactoryanswers to the above pGintsinvestment (ROI) for the project. If a 20-year ROI cannot be over-emphasized. The whole plant design(before taxes) of tess than 20-25% per year is real- and economics depend upon it. The presence of evenized, the project should be examined more closely small amounts of impurities such as COS, CS2 andbefore proceeding. The reader is referred to two mercaptans can have a large bearing on the selectionexcellent articles in the literature on plant costs of the type of treating process to be used. There-and “Economics ~f the Sour Gas Industry’’.26,27 fore, the gas must be diligently tested for the

presence of these and other impurit~es, (possiblySales Gas Specifications 02, Hg, cyanides and others).

Typical sweet and dry sales gas specifications set Gas Cleaning_by Intrastateand InterstateUtility Company contractsare: Many of the operational problems associated with

a sour gas plant arise from solids carried into the1.9 Minimum Gross Heating Value = 950 BTU/SCF plant a?’=q with the sour gas. Most sour gas gather-2. Maximum hydrogen sulfide content = ing lines are fabricated from carbon steel pipe.

0.25 Grs./100 SCF Since the gas usually contains H2S, C02 and water3. Maximum mercaptan content = 0.20 Grs./100 SCF (and sometimes 02), the formation of iron SU1ffde,4. Maximiimtotal sulfur content = 1-5 Gr./100 SCF iron oxide and other corrosion by-products may be5. Maximum carbon dioxide content = 1-3% by volume quite high. Iron sulfide particles formed in gas6. Maximum water content = 4-7 lbs./MMSCF collection lines can exist in sizes as small as 0.17. Maximum hydrocarbon dewpoint at 800 psig = micron (typical particle size of tobacco smoke) tc

+15°F (often waived in U.S.; but not in Canada) as large as about 80-100 microns.8. Maximum delivery temperature = 120”F9. Minimum delivery pressure = 700 psig Provisions should be made for an adequate inlet10. Commercially free from sand, dust, gums and gas separator large enough and efficient enough to

free liquids remove essentially all solids and free liquids. In11. Shall be as free of oxygen as pos~ible, but not many plants, most of the iron sulfide found in the

to exceed 0.4% by volume (Contractmay permit amine system enters with the sour gas. Efficientno oxygen) removal of this iron sulfide from the gas can pre-—

vent many operational and maintenance problems. OfInlet Gas Stream Data course, removal of free liquids is essential to

satisfactory operation of the plant. If iron sul-One of the most important.aspects of the overall fide and/or liquids are known to be a problem, a

project is the collection of accurate and meaningful special highly-efficientseparator should be used,data on the inlet sour gas composition, the presence such as (a) a “filter-sep”type, (b) a centrifugalof contaminants,and the quantity of gas to be treated, type, or (c) a wash-liquid type.Questions should be asked, such as:

Gas Treating1. Row and when was the gas sampled for analysis?

Were the samples taken in sample bombs by Today, the field of gas treating is so broad andwater-displacement,evacuation or how? the available processes are so numerous, that selec-

tion of an optimum process is a complex problem.2. Were the wells flcwed fora while, prior to Gas composition, available gas pressure, quantity

the sampling, to insure that water was blown and type of sour components to be removed, productfrom ?ne well-bores and flow lines and a gas specifications,and subsequent processing ofrepr~sentativesample was obtained? the acid gas stream are all important factors to be

considered.l*2,3 Several different types and cata-3. Was the flow potential measured for only one or gories of processes are available, such PS:

two wells, or were several wells tested to getan average value? –Chemical Solvent processes - such as alkanol-

amines (MEA, DEA, DGA, MDEA,’Adip), and alkaline4. Was the acid gas (H2S and C02) content of the salt solutions (Hot Pot, Catacarb, Benfield).

gas determined at the wellhead or in the lab-oratory? It should be determined at the -Physical Solvent processes - such as Sulfinol,wellhead. Selexol and Fluor Solvent.

5. Are 02, COS, CS2, mercaptans or other trace -Direct Conversion processes - such as Stretford,impurities present in the gas? If so, to what Thylox, Takahax and Ferrox.extent? (Thesenonnally required a chromato-graphic analysis, preferably performed at the –Dry Bed processes - such as Iron Sponge andwellhead). Molecular Sieves.

..

SPE 6651 E. G. Gnar and T. n. Arvinrt+nn IF.- . -.---.-,. ~.. - . ... . . . ,.”, , ,“

All of the chemical processes involve actual desirable situation, MDEA can be used toreactionof the sour components with the treating good advantage. If the gas is conta~’.ed:hemicalsor dry bed. They are s mnarized and dis-

!!at a sufficiently high pressure (800-

:ussed in the literature.l.2$3S4~ 96,7 The highlights 1000 psig), pipelinequality gas (1/4>f the major processes considered to be of commercial Gr. ti2S/100SCF) can possibly beImportancein the U.S. and Canada will be reviewed ~btainedunder certain conditions. At]riefly. the same time, from 40% to 60% of the

C02 present may be allowed to flow1. Chemical Solvent Processes through the Contactor, unreacted. In

cases where a high C02/H S ratio isa. Alkaiiolarnines 6present, MDEA can be use to improve the

?ual~ty of the acid gas feed stream

1) MEA - the monoethanolamine process has higher H S content) to the Claus Sulfurbeen by far the most w,idelyused process ?Recovery lant. But of course, thefor gas treating. Advantages of theMEA higher C02-content of the treated resi-process are high reactivity, low solvent due gas must be toleraied.cost, good chemical stability, ease ofreclamatlcm, low hydrocarbon content of 5) Adip - the Shell Adip process uses DIPAthe acid gas produced, and lower plant (di-isopropanolamine)as the solvent.13investmentwhen compared tG many other It has been used most widely in Europe,processes. Disadvantages gfMEA are but appears to be gaining popularity inirreversibledegradation by COS, CS2, the U.S. and Canada. It can competeand 02 in the gas, higher vaporization with DEJ?and DGA for certain applica-losses than any other amine-type process, tiocs. It exhibits H2S selectivityineffectivenessfor removing mercaptans, ab”llitiesalso.non-selectivityfor H S in the presence

fof C02, and higher ut lity costs than b. Alkaline Salt Solutionssome other processes. Unless COS, CS2or 02 are present, MEA may be the best 1) Hot Potassium Carbonate - the “Hot Pot”choice for treating a sour gas stream process uses an aqueous solution of 25-containing low to medium acid gas con- 35wt.% i(2c03.192 It ismostappli-centrations, with low o medium acid

fcable to large gas streams containing

gas partial pressures. Some very an appreciable amount of C02. If H2Sgeneral guide lines might be a sour gas” is present, with little or no C02, Hotcontaining from 4 Grs. H2S/100 SCF to Pot will not effectively sweeten the15mol,% total acid gas, with acid gas gas. Hot Pot will remove some COS andpartial pressures up to 100 psia. CSi, by hydrolysis of these compounds.

If H S is to be removed to meet normal2) DEA - the diethanolamine process is the fpipe ine specifications,a special

~~~~~s~stD!~~~l~d~~~~a~~~-$~t~~arddesign or a two stage system may haveto be used. Normally, a minimum contact

to MEA are its resistance to degradation p?essure of about 300 psig is requiredfrom COS and CS2, and lower vaporization. for Hot Pot.losses. Its disadvantages are lowerreactivity, higher solvent circulation- 2) Catacarb - this is a licensed versionrates (conventionalsystem) and higher of the Hot Pot process which containssolvent cost. DEA is often used to activator chemicals and corrosiontreat refinery sour gas streams because inhibitors to increase the reactivityof the presence of COS and CS2. In and loading of the solution. Therecent years, DEA has gained much wider Catacarb process has been applied mostacceptance in the United States for sour widely to C02 removal from hydrogennatural gas treating. This is due to plants and atnnoniaplants, both in thesuccessful experience gained with “Hi- U.S. and overseas.Loaded” DEA treating in Western Canada.In the “Hi-Loaded” version of the DEA 3) Beneffeld - the Benfield process isprocess, lower circulation rates and also a catalyzed and licensed versionmuch lower utilities are experienced of the Hot Pot process, containing ~than with MEA. activators to improve the treating

3) DGAg - the Diglycolamin~ process tom.capabilities of the solution. It hasbeen applied most widely to hydrogen, ,

petes with the MEA and DEA processes, ananoniaand SNG plants overseas.but has not gained as wide acceptanceas DEA for high-pressure sour gas treat- 4) Gianrnarco-Vetrocoke- the “G-V” processing. In some applications it presents is also a catalyzed version of the Hotcertain advantages over MEA and DEA. Pot process, using arsenic-ccutaining

4) MDEA - the methydiethanolamineprocess;;::~~~$,~ ~;o~~~c~;;;tyo~ the

‘s ‘iscussef ‘? ‘Fe ‘etail ‘n ‘hebuilt world wide; but, only one plant

literature; OJ 19 2 The major advantage has been built in the U.S. to treat sourwhich MDEA can offer over other amine natural gas. The poisonous nature ofprocesses is its selectivity for H2S in the arsenic-bearing solution has beenthe presence ofC02. Where this is a the process’ greatest draw-back.

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16 rxm-cccfhm cmm NfJTIIQhI cnc -m MCCT DTDrITNE nllaiTTV cDr cccl, ,,””&ti* *,,” .#W”,, ,,” ,V, vlb ““e ,“ ,-, kb, , , ● , &b L,. k <w”h* , , drk uud I

2. Physical Solvent Processes Most of the direct conversion processes.arebased on a scheme, using oxidation - reduction

The physical solvent processes all use reactions, involving absorption of H2S in anorganic solvents and accomplish acid gas alkaline solution containing oxygen carriers.removal mainly by physical absorption, rather The H2S is oxidized to elemental sulfur. Thethan chemical reaction, which is directly pro- oxygen is furnished by air which is normallyportional to the acid gas partial pressure in added to the bottom of the regenerator or oxi-the sour gas stream. dizer vessel. The air also acts as a flotation

agent for the sulfur, which is collected at theThese processes are most applicable to regenerated solution interface as a froth. The

high-pressuregas streams containing appreci- sulfur is recovered by filtration and melting.able quantities of sour components. The highacid gas loadings realized account for the low The leading processes in this class ofsolvent circulation rates, the reduction in treating systems are Stretford, Thylox,equipment size and cost, and the lower utili- Takahax, and Ferrox. these, only Stretfordties which are characteristic of these has been applied to nb;-;ralgas treating inprocesses. In general, the physical solvent the U.S. or Canada in recent years. Only aprocesses all have two major disadvantages: few Stretford plants have been built for this(1) the solvent’s affinity for absorbing heavy purpose. Considerable operational problemshydrocarbons (can cause dark sulfur production have been enco~nterec!.in the Claus Plant) and (2) the expensivenature of the solvents. All of these processes 4. Dry Bed Processesare licensed by the developer and require pay-ment of a royalty fee for their use. Two types of dry bed processes are consid-

ered to be of commercial importance: (1) Irona. Sulfinol - the Shell Sulfinol process is Sponge and (2) Molecular Sieves. Of these,

unique in this class of processes, in that the Iron Sponge is used most widely. Molecularit uses a mixture of solvents (Sulfolane Sieves have a special area of application.and DIPA) which allows it to behave as b ha chemical and physical solvent process.?!,14 The Iron’.Spongeor Iron Oxide process isSulfinol has good affinity for sour com- ,Ineof the oldest treating processes still inponents at low to medium partial pressures, u$e toady.l*2*3 It uses wood shavings impreg-and extremely high affinity for sour nated with ferric sulfide. Partial regenera-components at high partial pressures. It tion with air is possible, but eventually theshould normally be applied to gas streams bed becomes plugged with sulfur and must becontaining mostly light hydrocarbons. replaced. The process is usually limited toSulfinol appears to have its greatest treating gas streams of small to medium vol-advantage when the H2S/C02 ratio is 1:1 or umes, containing 1000 grains H2S/100 SCF orgreater, and when the acid ~as partial less, and co~taining up to 8-10 LTPD sulfur!~2pressure exceeds 110 psia.l These limitations are due to economics of bed

replacement. Advantages of this process areb. Selexol - the Allied Selexol process uses essentially complete H2S removal, ease of

as a solvent dimethyl ether of polyethylene operation, and simplicity and lost cost ofglycOl (DMpEG). Typically,,no water is installation.used with the solvent. This process isapplicable for bulk removal of C02 and H2S, LPG Liquids Recoveryprimarily C02. Most past applications havebeen on streams containing large amounts of Some sales gas contracts require that the hydro-C02 (18-43 mol.%) and less than 1 mol.% H2S. carbon dewpoint not exceed 15°F at 800 psig pressure.Selexol is not particularly attractive for However, now-a-days this specification is usually nota condition of low acid gas partial pres- errforced very widely. The producer usually is moresure.3 Selexol has not been widely used or concerned about liquids recovery for revenue purposesaccepted for treating natural gas contain- than to meet dewpoint controls. Four basic schemesing appreciable H2S. may be used to recover liquids from natural gas: (1)

conventional refrigeration (normally using propane),c. Fluor Solvent, Lurgi Purisol,lLur i Recti- (2 cryogenic refrigeration (using a turbo-expander)

sol, GAF M-Pyrol, Est&scllan UB3.Y- none of 1(3 lean oil absorption (ambient and refrigerated)these physical solvent processes have gained and (4) dry bed adsorption. The type process selectedvery wititiacceptance in natural gas treating depends upon the quantity of gas and its liquid con-in the U.S. or Canada. tent (GPM ofC2+).

3. Direct Conversion Processes 1. Conventional Refrigeration

The direct conversion processes have been If the gas stream is small to medium inused most widely in Europe for removal of H2S size (say 10-50 MMSCFD) and contains appreci-and.recovery of sulfur from manufactured gas, able liquids (say 3-16 GPM of C2+), propanecoal gas and coke-oven gases. The processes refrigerationmight be selected as the opti-are usually best suited for sour gases contain- mum scheme. If the market situation ising 1 to 1000 grains H#/100SCF, andwi ha

i,favorablefor “moderately-deep”ethane

maximum sulfur production of 10-15 LTPO. *5$18 recovery (say 70-75% of C2 and 93% of C3+),These processes do not remove any C02 from the the refrigeration system would probably befeed gas. operated at -45°F to chill the gas stream to

9

SPE 6651 B. G. Gear and T. O. Arrington 17

-40°F. Ifethane recovery is not desired, andonly 80%+ recovery of propane and heavier com-ponents is desired, the refrigerant systemmight be operated at 5-10”F to chill the gasstream to 15-20°F.

If ethane recovery is desired, the normalscheme for small to medium size plants is to“demethanize”the liquids and sell them as“ethane & heavier” mix via a liquids pipeline.In some larger plants, the liquids are first~emethanized and “deethanized”and later frac-tionated into specification propane, butaneand natural gasoline products, and sold assuch. In plants designed for only propane andheavier recovery, the liquids may be “deethan-ized” and sold as a mix or fractionated intospecification products. The quantity ofliquids produced and the market situationwill dictate the optimum scnei,wfor processingof the liquids recovered from ‘ihegas.

Often times, trace amounts of H2S areremoved from the gas with the li ulds, even

?though the gas has been treated sweetened)upstream. If so, Molecular Sieves, solidCaustic Potash(KOH), or possibly Iron Spongetreatment will remove the H2S to permit theliquids to pass the sp i “cation “copper-stript[corrosion test>~~~~

2. Cryogenic Refrigeration

The use of “turbo-expanders”to achievecryogenic processing of natural gas is offairly recent vintage, and is gaining po~u-.larity due t t

? !7 ‘~:~:d;r::;::d;:u:;srecoverY.15S 6*significantly higher pressure than requiredfor the gas pipel’ine,“free” pressure drop isavailable and can be used to good advantagein a turbo-expander. Even if’high pressureis not available, use of this cryogenic schemefollowed by recompression is advantageous inmany applications.

If the gas stream is of medium to largesize (say 30-250 MMSCFD) and contains amedium amount of_liquids (say 3-10 GPM of C2+),cryogenic processing of the gas might beselected. If deep ethane recovery is desired”(say 90-95% of the C2+), the turbo-expanderprocess will probably be operated at -150”Fto -225”F, depending upon the gas composition.The normal scheme is todemethanize the liquidsand sell the “ethane plus” mix via a liquidspipeline.

For both conventional and cryogenic refrig-eration processes, the degree of liquidsrecovery may be limited by the minimum gas“gross heating value” specification definedin the sales gas contract.

If the natural gas stream contains appre-ciable nitrogen, which would lower the salesgas heating value below the minimum contractrequirement, cryogenic processing of the gasfor upgrading of the “BTUcontent” should beevaluated. In this method, essentially allhydrocarbons (Cl+) are liquified and

3.

4.

.,

separated from the nitrogen. The turbo-expander outlet typically operates at -300°For colder. The separated hydrocarbon liquidsare heat-exchangedwith the incoming gasstream. The methane is re-vaporized andessentially all of the ethane and heavier,fractions are available for liquid sales.

The deep-cryogenic N rejection scheme fort“BTU upgrading” should e considered if the

gas stream volume is 10-15 MMSCFD or larger,depending upon the N content and composition

?of the gas. Typical y, smaller gas flows willnot justify the expensive cost of such plants.Special circumstances can alter the aboveguidelines.

Lean Oil Absorption

The Lean Oil Absorption (LOA) process maybe applied to medium to large gas streams(say 50-500 MMSCFD) of low to medium 1iquidscontent (say 0.5-5.0 GPM of C +) for moder-

?ate to high liquids recovery say 70-99% ofc~+). The ambient LOI!scheme would typicallyrecover the lower percentage of liquidsindicated above. The refrigerated LOA processwould chill the incoming gas and lean oil to20°F to -50°F, depending upon the gas compo-sition and degree of liquids recovery desired.Typically, the refrigerated LOA process wouldrecover 50-75% of the C2 and 99% or more ofthe C~+ fractions.

The LOA process is much more complicated(and normally more expensive) thar,a turbo-expander process for a typical application inthe medium plant size range. Many producerswere reluctant to accept the mechanicalstability of a turbo-expanderwhen thesedevices first came on the market (say 10-12years ago). With the advancement of thistechnology and demonstration of turbo-expandermachines in many gas plants built, industryis accepting the process more readily. Oueto the popularity, simplicity of constructionand operation, and lower capital investment,the turbo-expandercryogen<c process is pre-ferred over the refrigerated LOA process inmany applications. Cer2ain other applicationsmay still fit the refrigerated LOA processbest.

Dry Bed Adsorption

The Dry Bed Adsorption (DBA) process isused mostly for dewpoint control on small tomedium gas streams (say 1-10 MMSCFD) whichcontain a low liquids content (say 0.5 to1.0 GPMof C3+or less). An added advantageof this scheme is that gas dehydration isnormally accomplished simultaneously. Liquidrecoveries of 10-15% of the C4’S and 50-90%of C5+ fractions are typical. If the gas isvery sour, it must be sweetened before pro-cessing in a OBA unit, since H2S tends topoison the desiccant. The DBA processfunctions best at an optimum contact pressureof about 600 psig or higher. The process isa semi-continuous (cyclic batch) scheme,normally employing three or more DBA vessels

1

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18 PROCESSING SOUR NATURAL GAS TO MEET PIPELINE OUALITY sPr mv-il

[with beds) cycling between (1) processing,2) regeneration and (3) cooling. A stabil-ized condensate product (say 12 #RVPor26 #RVP liquid) is typically produced. Thedesiccant normally used in DBA units is someformof silica gel (Mobil Sorbead or Davisonsilica gels are conrnon).

Gas Dehydration

Basically three types of gas dehydration processesre used in natural gas plants: (1) ethylene glycolEG) injection for conventional refrigeration schemes,2) triethylene glycol (TEG) contacting for residueas drying and (3) dry bed adsorption dryfng (DBAD)br residue (sales) gas streams or cryogenic pro-essing pretreatment. Normally, sour gas is treatedsweetened), processed for liquids recovery and thenehydrated, if necessary. Sometimes only gas treat-ng is used and then followed by dehydration.

The presence of H2S and C02 in a natural gas streamends to increase the temperature at which hydratesIii]form. If long collection lines in cold climatesr~ encountered, glycol (TEG) dehydration at the wellites or methanol injection may be required to pre-‘enthydrate formation in the sour gas gatheringystem. If hydrates form, eventual line pluggingrillresult.

1. Glycol (EG) Injection

If a conventional refrigeration process isused for liquids recovery in the plant, EG isnormally injected Into the inlet gas stream atseveral points in the process to preventhydrate formation in the plant. Of course,dehydration to some degree is obtained alsowith use of the EG. The wet EG is collected,regenerated and recycled back to the process.Water dewpoints of the gas obtained wslthEGinjection depend upon the refrigeration temper-ature used, but usually will meet sales gasspecificationsfor water content, if thecontact pressure is sufficiently high.

2. GIYCO1 (TEG) Contactin~

If no liquids recovery is planned, then TEGis normally used in a gas contactor tower toaccomplish dehydration after gas sweetening.Circulation rates may vary from2.5 to4.Ogals. TEG/lb. H20 removed, typically. Dewpointdepressions of 7O-11O”F may be achieved,depending upon the number of contact trays(normally 6-8) and th’”degree of TEG regenera-tion (normally 99-99.~, lean TEG). Sales gaswater contents of 4-7 lbs./MMSCF can normallybe achieved readily with TEG dehydration.

3. Dry Bed Adsorption Dryinq (DBAD)

If cryogenic (turbo-expander)processingis planned, then methanol injection or a drybed pretreatment unit is required. Thepreferred method is to use a Molecular Sievedry bed adsorption unit ahead of a cryogenicplant, which normally yields a water dewpointof -150°F or lower. Also, the MolecularSieve unit will remove trace amounts ofC02from the gas. Neither H200r C02 can betolerated to any significant amount in a

cryogenic plant (formationof solids andeventual plugging).

A dry bed unit, containing alumina orsilica gel as a desiccant, may be used to dryresidue (sales) gas. If appreciable LPGliquids are present in the gas, they may beadsorbed and carbonized (fouls bed) during ,the high-temperatureregenerationcycle.Normally, dry bed dehydration units should beapplied to lean residue gas streams whichhave been sweetened and processed for liquidsremoval. Such a dehydrator will yield waterdewpoints of -1OO*F or lower. The typicalsales gas specificationof 4-7 lbs. H O/MMSCF

?can be achieved easily with such a un t.

Sulfur Recovery

If the acid gas stream removed from the sour gasfeed contains an equivalent of more than 3-5 LTPD ofsulfur, and if the plant is to be located in Texas,normally the Texas Air Control Board (TACB) wouldrequire installationof a Sulfur Recovery Unit.Several key points should be considered in the .selection of a Claus Sulfur Recovery Unit (SRU)process scheme.

1. General SRU Process Selection

A choice must be made between the “once-through” or the “split-stream”Claus process.18If the acid gas feed contains 30-40 mol.Z H S

ior greater, the once-through scheme should eselected, since it gives the highest overallsulfur recovery and permits maximum heatrecovery at a high temperature. In thisscheme, all of the acid gas is fed to theReaction Furnace, along with enough air toburn 1/3 of the H2S to S02 and all hydrocarbonscompletely.

Normally, 150-300 psig steam is generatedin the Waste Heat Boiler. Inmost cases, thehigh-pressure steam is utilized in a steamtf~rbine(with 40 psig exhaust) to drive thecombustion air blower for the unit. Oftentimes, the amount of steam generated isadequate to drive the air blower. The lowpressure steam from the turbine exhaust isflowed to the amine stripper reboilers,whereit usually supplies 40-50% of the reboilersteam requirement. This steam generation/utilization system makes for a very thermallyefficient overall plant operation.

2. SRU Design Considerations

The major desi n~ $E~${~@ations for aClaus SRU are:18* 9S

a. Composition of acid gas feed.b. Combustion of acid gas.c. For a once-through scheme, retention time

of combustion gases at elevated tempera-tures.

d. Catalytic-converterfeed-gas tempel’ature.e. Optimum reheat scheme(s).f. Space velocity in converters.g. Sulfur condensing temperatures.h. Coalescing and separation of entrained sul-

fur from condenser effluent gases.

. m

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;PE 6651 B. G. Gear and T. fi. Arv+ntltnn IQ------ . -. - . ---- ---- . . -. . .. . . ..=.”.. .-

i. Turn-down of plant throughput. The SNPA Sulfreen and Amoco CBA processes aresimilar in nature. Both employ the concept of an

3. SRU Operatina Variables extended Claus reaction on a cool catalyst bed. The

Ihe major o crating control variables foroverall sulfur recovery obtained may be only 98-99%,

5which is lower than that for the SCOT, Beavon or

an SRU arei18) 0,23 Wellman-Lord processes (which is normally 99,5-99.9%).Typically, the Sulfreen and CBA processes have been

a. Control of the H2S/S02 ratio at the optimum applied to huge SRU plants (500-1000LTPD size) invalue of 2/1. Canada and France.

b. Catalytic converter feed-gas temperatures.The inlet temperaturemust be kept high The IFP process is based on the extended Clausenough to prevent sulfur condensation in reaction in a liquid, catalyzed solvent system, Itsthe catalyst bed. overall recovery is not equivalent to that of the

c. Catalyst maintenance.23 SCOT, Beavon or Wellman-Lord processes. IFP’s pro-d. Sulfur condenser outlet temperatures. cess is !msing popularity in the U.S. and Canada,e. Elimination of hydrocarbons and other because of its inability to meet expected future

impurities in the feed gas. State and EPA regulations.f. Proper operation of instrumentationat

severe turn-down conditions. Environmental Impact

4. Lean Acid Gas Processing in a SRU Since the processing of sour natural gas neces-

Lean acid gas streams (with high impuritiessarily produces hydrogen sulfide and/or sulfurdioxide as waste emissions, these air pollutants must

1such as C02, H20 and N2 present many designand operating problems. 9 consideration should

be dealt with in light of cuqrent and possible futureFederal and State regulations. In the State of Texas,

be given to enriching the H2S content of such regulations of three governmental bodies must bea tream, instead of constructing an SRU that considered, those being (1) The Railroad Commissionwill be an operational nightmare. Technologyis available to industry for enriching a lean

of Texas, (2) The Texas Air Control Board, and (3)The U.S. Environmental Protection Agency. The appli-

acid gas stream containing 10-20% H2S to an cable regulations of e~ch f these governmentalupgraded acid gas stream containing 50-70% 8bodies will bediscussed.3 ’39tizs.lg

1. Railroad Commission of TexasTail Gas Clean-Up

Due to the extreme toxicity of hydrogenIf a Sulfur Recovery Unit is to be installed in sulfide, the Railroad Commission of Texas

Texas,and if its size is greater than 50-100 LTPD, amended, effective September 1, 19/6, Ruie 36I Tail Gas Clean-Up (TGCU) Unit may be required by the“ACB.

so as to provide additional protection to thegeneral public. Hydrogen sulfide is anextremely toxic gas. An exposure of only 250

Several viable TGCU processes are available toThe leading processes are:24~25

ppmv/hr is considered to be a hazardous limitindustry. (concentrationthat may cause death), and

600 ppmv is considered to be a lethal concen-1. Shell’s SCOT process tration (concentrationthat will cause death2. Parson’s Beavon process3. Wellman-Lord’s process

with short-term exposure). The threshold limit(concentrationat which it is believed that

4. SNPA’S Sulfreen process5. Amoco’s CBA process

all workers may be repeatedly exposed day afterday without adverse effects) has been set at

6. IFP’s process only 10 ppmv by the American Conference ofGovernmental Industrial Hygienists. Hydrogen

If the tail gas from the SRU contains less than cyanide is only slightly more toxic than hydro-!0-40%CO , the SCOT process might be selected on the

tgen sulfide, and hydrogen sulfide is much more

lasisof 1) low investment (2) low utilities and (3) toxic than carbon monoxide. Basically, Rule~idecommercialization. The SCOT process is based on 36 applies to gas processing facilities in}igh-temperaturecatalytic hydrogenationof th~>sulfur which the H S concentration is greater than:ompoundsin the SRU tail gas stream, followed by i100 ppmv an the “1OO ppmv radius of exposure”:oolingand absorption of the H2S in a selective amine is greater than 50 feet Depending uponiolvent. whether or not the “1OO ppmv radius of expos-

If an extremely high C02 content is present in theure” penetrates a public area or the “500 ppmvradius of exposure” penetrates a’public road,

;RU tail gas, probably the Beavon or Wellman-Lord various degrees of compliance are required.mocess would be selected. The Beavon is more suit- The ultimate compliance requirements are to:ible for smaller, as well as larger plants. It is>asedon high-temperaturecatalytic hydrogenation of a. Provide adequate markers and signs.the SRU tail gas, followed by cooling and removal of b. Provide adequate facility security (pro-Lhe H2S by the Stretford process. tection from public access).

c: Provide (for new construction or modifica-The Wellman-Lord (Davy Powergas) process is better tions) facilities that satisfy the

suited for larger SRU plants requiring more stringent requirementsof NACE Standard MR-01-75 and502 removal. It is based on incinerationof the SRU ~P; RP-14E, Sections 1.7 (c), 2.1 (c), andtail gas, followed by cooling and absorption of the502 in a solution of sodium sulfite. d..&~!de adequate safety and control equip-

rnvkwailma auum l!RIUrufL UH3 IU PEE I t’l FCLINE UUAL 1 I Y SPE 665~

e. Provide a comprehensive contingency d. For greater than 50 LTPD; process to useplan.

f. Provide adequate personnel training.gas treating plus 3 stage SRU plus probablyTGCU, incinerationofTGCU tail gas; 99.5+%

NACE Standard MR-01-75, entitled “Materials forexpected sulfur recovery.

Ialvesfor Resistance to Sulfide Stress Corrosion The above guidelines are the authors’;rackingin Production and Pipeline Service”, specifies interpretat~onsand do not reflect any official;hematerials of construction for valves and valve com- rules of the TACB.]onentsthat are acceptabl~ in hydrogen sulfideiervice. The principle of sulfide stress corrosion 3. Federal Environmental Protection Agency:rackingis a widely known, extremely complex phe-]omena. It is generally felt that wet environments Up until the present time there have been)elow 150”F in which the H2S partial pressure is essentially no comprehensive standards govern-]?’eaterthan 0.001 atmospheres may cause certain ing the emissions from field sour gas treating:arbonsteels to be susceptible to stress corrosion and sulfur recovery facilities. At the present:racking. Generally, carbon steels with Rockwell C time any new gas treating facility moving into]ardnessesof 22 or less are not nearly as susceptible an area could decrease the ambient air quality:0 stress cracking as those with Rockwell C harnesses no greater than that allowed by the Signifi-]f greater than 22. NACE Standard MR-01-75 addresses cant Air Quality Deterioration StandardsItselfto valves and valve components only. It published in the Federal Register of December;pecifieshandling, manufacturing, and heat treating 5, 1974. In the pastair pollution regulationswocedures, as well as types of carbon steels, etc., for these field facilities have basically been)cceptablefor valve components in sour service. In established by state regulatory bodies such asIddition,the standard sr)ecifiesother materials of the Texas Air Control Board, as provided forconstructionthat are satisfactory for use in valves by the Federal Clean Air Act. However, itIn sour gas service. At the present times NACE now appears that the issuance of stringent:ormnitteeis in the process of preparing a broader Federal standards for field units is justitandard for materials suitable for use in sour gas around the corner. Emission standards foriervice. This standard is to be much more general sulfur recovery facilities located in refin-inowi’11not be limited to valves and valve components cries have been “proposed” (and are thereforerely., it is expected that the new standard will be law) in the Federal Register “40 CFR Part 60”,issued in the very near future. issued 0ctober4, 1976.

2. Texas Air Control Board In January of this year the EPA issued the“Standards Support and Environmental Impact

In addition to having to meet the require- Statement” for emission regulations governingments of the Railroad Commission of Texas, gas fieid gas processing plants. It is expectedprocessing facilities must meet the emission that the proposed regulationswill be veryrequirements of the Texas Air Control Board(TACB).

similar to the regulations now proposed forrefinery located sulfur recovery facilities.

The Texas Clean Air Act, as administered It is now believed that the “New Sourceby the Texas Air Control Board, currently Performance Standards” for natural gas fieldprovides for emission standards for new gas processing plants, soon to be proposed by theprocessing facilities on a case by case basis, EPA, will basically set down the followingconsistent with ambient air quality standards approximate requirements:and best available control technology con-sidering economics. Emission limits aredependent upon location and proximity to highly

a. Plant fuel gas H2S concelitrationwill belimited to 10grains/100 SCF {160 ppmv).

industrializedor populated areas. Each newfacility,will require a “Permit to Construct” b. The concentration of sulfur dioxide (SOZ)and a “Permit to Operate” from the Texas Air in tail gases discharged to the atmosphereControl Board. In general, approximate guide-lines for emission limits for sour gas

will be limited to 250 ppmv on a zeropercent oxygen and dry basis.

processing facilities by the State of Texasare shown below: To correct to zero percent oxygen, multi-

ply the actual S02 concentration by thea. For less than 3-5 LTPD ; process to use factor:

gas treating only, probably no SRU, flaringor incinerationof tail gas; 0% expected F02

,= 20.9sulfur recovery. 20.9- % O*

b. For greater than 3-5 LTPD, but less than To correct to a dry basis, multiply the30 LTPD; process to use gas treating plus actual S02 concentration by $he factor:probably 2 stage SRU, incinerationofSRUtail gas; 94-95% expected sulfur recovery. 100

‘H20 = 100 .H26

c. For greater than 30 LTPD, but less than 50LTPD; process to use gas treating plus The%02 and % H20 values used in theprobably 3 stage SRU, incinerationofSRUtail gas; 95-96.5% expected sulfur recovery.

above equations are actual volumetricpercentages as measured in the tail gas.

.

SPE 6651 B. G. Gear and

c.

d.

e.

For sulfur recovery processes (such asStretford) that do not include incineration,the total concentration of H2S, COS, and CS2(calculatedas S02) in the tail gas dis-charged to the atmosphere will be limitedto 300 ppmv. In addition, the H2Sconcen-tration will be limited to 10 ppmv. Thesevalues are on a zero percent oxygen and adry basis.

Current thinking is to exempt sulfur recoveryfac~lities of less than 2 LTPD capacity fromthe propo’jedstandard.i.

Also clirrent”thinkingis to exclude smallsulfur recovery units added to gas sweeten-ing plants that existed prior to thepromulgation of these standards.

Typically SO concentrations in tail gas from sul-?‘urrecovery un ts without tail gas clean-up are on

;heorder of l0,000-15,000 ppmv. Therefore, applica-tionof the above emission limits would dictate thatIewfield sour gas treating facilities include gasireatingplus a 2 or 3 stage Claus sulfur recoveryInitplus a tail gas clean-up unit. Of course SRU’SIfless than 2 LTPD would be exempted from this‘requirement.However on the bright side, some currentthinkingwithin EPA is to relax the proposed SRU‘emulationsfor units located within t’efineries. Thisould apply to some particularly difficult and/orUneconomicalapplications - such as SRU’S having a‘eedH2S/C02 ratio of less than 1:1, and SRLI’Sbelow‘QLTPD capacity. If this is done for refinery SRU’S,hen field located SRU’S should follow.

Therefore, it is obvious that future gas processing‘acilitieswill necess~ily become more complex and~re expensive due to existing and forthcoming Federalnd State air pollution regulations, and the increasedProtectionof the general public.

IUMMARY

The processing of sour natural gas to meet pipelineIualitycan be a complex problem, involving technical,nvironmental afideconomic considerations. The sourIasplant must meet the sales gas specifications,Irovidefor a safe operation, and comply with allIertinentair pollution regulations.

INFERENCES

. Maddox, Dr. R.N.: Gas and Liquid Sweetening, SecondEdition, Campb~inan,Oklahoma, 1974.

‘, Kohl, A.L., and Riesenfeld, F.C.: Ga$ Purification,Second Editions Gulf Publishing Company,Houston, Texas, 1974.

L Gear, B.G.: “Today’s Gas-Treating Processes - l“,~~ Oil and Gas Journal, July 12, 1971, pp. 75-

.

. Blake, R.J.: “HowAcid-Gas Treating ProcessesCompare”, The Oil and Gas Journal, January 9,1967, pp. 105-108.

~.Riesenfeld, F.C., and Blohm, C.L.: “Acid GasRemoval Processes Compared”, HydrocarbonProcessing & Petroleum Refiner, April 1962,pp. 123-127.

T. O. Arri.~gton ?116.

7.

8.

9

10.

11.

12.

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20.

a .

Fitzgerald, K.J., and Richardson, J.A.: “How GasComposition Affects Treating Process Selec-tion”, Hydrocarbon Processing, July 1966,pp. 125-129.

Swaim, Jr., C.D.: “Gas Sweetening Processes ofthe 1960’s”, Hydrocarbon Processing, March19?0, pp. 127-130.

Smith, R.F., and Younger, A.H.: “Tips on DEATreating”, Hydrocarbon Processing, July 1972,pp. 98-100.

Dingman, J.C., and Moore, T.F.: “Gas Sweeteningwith Diglycolmine”, Proceedings of the 196SGas Conditioning Conference, University ofOklahoma, Norman, Oklahoma, 1968.

Miller, F,E., and Kohl, A.L.: “SelectiveAbsorp-tion of Hydrogen Sulfide”, The Oil and Gas:l;rf~~, Vol. 51, No. 51, April 1953, pp.

-.

Pearce, R.L., and Brownlie, T.J,: “SelectiveHydrogen Sulfide Removal”, Proceedings of the1976 Gas Condit~oning Conference, Universityof Oklahoma, Norman, Oklahoma, 1976.

Vidaurri, F.C., and Ferguson, R.C.: “MDEAUsedin Ethane Purification”,Proceedings of the1977Gas Conditioning Conference, Universityof Oklahoma, Norman, Oklahoma, 1977.

Klein, J.P.: “Developments in Sulfinol andAdipProcesses Increase Uses”, Oil and GasInternational,September 1970, pp. 109-111.

Gear, B.G.: “Sulfinol Process Has Several KeyAdvantages”, The Oil and Gas Journal, June 30,1969, pp. 117-120.

Randall, B.: “Cryogenic Processing of NaturalGas:, Proceedings of the 1973 Gas Condition-ing Conference, University of Oklahoma,Norman, Oklahoma, 1973.

Ewan, D.N., etal: “Why Cryogenic Processing(investigatingthe Feasibility of a Cryo-genic Turbo-Expander Plant)”, Paper presentedat the 54th GPA Annual Convention, March 10-121975, Houston, Texas.

Maddox, R.N., and Bretz, K.E.: “Turbo-ExpanderApplications in Natural Gas Processing”,Journal of Petroleum Technology, May 1976,pp. 611-613.

Gear, B.G.: “Today’s Sulfur Recovery Processesi’,Hydrocarbon Processing, September 196B, pp.248-251.

Gear, B.G.: “Impure Feeds Cause Claus PlantProblems”, Hydrocarbon Processing, July 1974,pp. 129-132.

Gear, B.G.: “Sulfur Recovery From Natural Gas ,Involves Big Investment”,The Oil and GasJournal, July 14, 1975, pp. 78-85.

Palm. J.Ii.:“Watch These Trends in Sulfur PlantDesign”, Hydrocarbon Processing, March 197~,pP. 105-108.

. .

22 PROCESSING SOUR NATIJR4LGAS TO MEET PIPELINE OUALITY SPE ;651●

22. Gear, B.G.: “TighterControl of Claus PlantsNeeded by TGCU System”, The Oil and GasJournal, August 22, 1977, pp. 134-137.

23. Norman, W.S.: “ThereAre Ways to Smoother Opera-tion of Sulfur Plants”, The Oil and GasJournal, November 15, 1976, pp. 55-60.

24. Goa~ir;~G.: “Claus Tail-Gas Cleanup, Part 1 of 2- Cost, Alr Regulations Affect Process

Choice”, The Oil and Gas Journal, August 18,1975, pp. 109-112.

25. Gear, B.G.: “Claus Tail-Gas Cleanup, Par’t2 of2 Parts - Dry Bed Processes Can Cover A WideApplication Range”, The Oil and Gas Joiw’nal,August 25, 1975, pp. 96-103.

26. Berlie, E.M.: “’EstimatingCapital and OperatingCosts”, Gas Processing/Canada,September-October 1972, pp. 28-34.

27. Estep, J.W., and Plum, E.W.: “Economics of SourGas Industry”, Paper presented at the 19th.anadian Chemical Engineering Conference and3rd Symposiumon Catalysis, Edmonton, Alberta,October 19-22, 1969.

28. Per:~{a~~R.: “Several Treating Options Open For- Recovery Plants”, The Oil and Gas

Journal, May 23, 1976, pp. 76-79.

29. Cunrnings,W.P.: “Special Considerations ForProduct Treating”, Paper presented at theRocky Mountain Regional GPA Meeting, September25, 1975, Denver, Colorado.

30. Railroad Commission of Texas, Order No. 20-65,354,“Special Order Amending Rule 36 of the GeneralConservation Rules of Statewide Application,State of Texas, Having Reference to Oil and Gas;~~~tion in Hydrogen Sulfide Areas”, March 15,

.

31. National Association of Corrosion Engineers, NACEStandard MR-01-75, “Material for Valves forResistance to Sulfide Stress Cracking inProduction and Pipeline Service”, ApprovedMarch 1975.

32. Private Communicationswith Rearick-HansonAssociates, April 1975.

33. Private Conmnications with the Railroad Com-mission of Texas, Spetember 1976.

34. Private Communicationswith the Texas Air ControlBoard, 1976.

35. Saulmon, W.D.:’’TougherAir-Quality Standards Face.Sulfur-RecoveryPlants”, The Oil and GasJournal, May 9, 1977, pp. 53-57.

36. U.S. Environmental Protection Agency, “AirQuality ImplementationPlans, Prevention ofSignificant Air Quality Deterioration”,Federal Register, Vol. 39, No. 235, December 5,1974, pp. 42510-42517.

37. U.S. Environmental Protection Agency, “Standardsof Performance for New Stationary Sources,Petroleum Refinery Sulfur Recovery Plants”,Federal Register, 40CFR Part60, Vol. 41,No. 193, 0ctober4, 1976, pp. 43866-43874.

38. Private Conmmnicationswith the EnvironmentalProtection Agency, May 1977.

39. U.S. EnvironmentalProtection Agency, “StandardsSupport and Environmental Impact Statement,An Investigationof the Best Systems ofEmission Reduction for Sulfur Compoundsfrom Crude Oil and Natural Gas FieldProcessing Plants”, Research Triangle Park,NC, January 1977.