Main Menu P rocess Categories Contributor Index Gas Processes 2004 Index Gas Processes Articles Gas Processes Handbook - 2004 Main Menu Hydrocarbon Processing’s Gas Processes Handbooks have helped to provide the natural gas industry with the process technology necessary for drying, treating, NGL, LNG, liquid treating and sulfur removal. In a further expansion of the technology presented we also provide hydrogen generation, gas effluent cleanup and flue gas treatment. In the interest of maintaining as complete listings as possi- ble, the 2004 Gas Processes Handbook is available on CD-Rom only. Additional copies may be ordered from our website. • Process Categories • Gas Processes 2004 Index • Contributor Index • Gas Processes Articles • Gas Processing Company Equipment & Services Premier sponsor: Gulf Publishing Company PROGRAM LICENSE AGREEMENT YOU SHOULD READ THE TERMS AND CONDITIONS CAREFULLY BEFORE USING THIS APPLICATION. INSTALLING THE PROGRAM INDICATES YOUR ACCEPTANCE OF THESE TERMS AND CONDITIONS. CLICK HERE TO READ THE TERMS AND CONDITIONS
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Main Menu P rocess Categories Contributor IndexGas Processes 2004 Index Gas Processes Articles
Gas Processes Handbook - 2004Main MenuHydrocarbon Processing’s Gas Processes
Handbooks have helped to provide the
natural gas industry with the process
technology necessary for drying, treating,
NGL, LNG, liquid treating and sulfur
removal. In a further expansion of the
technology presented we also provide
hydrogen generation, gas effluent cleanup
and flue gas treatment. In the interest of
maintaining as complete listings as possi-
ble, the 2004 Gas Processes Handbook is
available on CD-Rom only. Additional
copies may be ordered from our website.
• Process Categories
• Gas Processes 2004 Index
• Contributor Index
• Gas Processes Articles
• Gas Processing Company Equipment & Services
Premier sponsor:
Gulf Publishing CompanyPROGRAM LICENSE AGREEMENTYOU SHOULD READ THE TERMS AND CONDITIONS CAREFULLY BEFOREUSING THIS APPLICATION. INSTALLING THE PROGRAM INDICATES YOURACCEPTANCE OF THESE TERMS AND CONDITIONS.
Main Menu P rocess Categories Contributor IndexGas Processes Index Gas Processes Articles
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Claus, high ratio (HCR)Claus, modifiedClaus, oxygen-enrichedClauspolCO2 recoveryCO2 recovery and purificationCO2 removal-Molecular GateCold Bed Adsorption (CBA)COPECRG processes—pre-reforming,
derichment, methanationCRYOMAX DCP (dual-column
propane recovery)CRYOMAX MRE (multiple reflux
ethane recovery)CrystaSulf
CYNARA membrane technologyDeNOx and DeDioxinD'GAASSDrigasDrizo gas dehydrationEcotegEUROCLAUS processFLEXSORB solventsFluor ammonia destructionprocess
Main Menu P rocess Categories Contributor IndexGas Processes 2004 Index Gas Processes Articles
Gas Processes Handbook - 2004
ARTICLES
• The Use of Aqueous Liquid Redox
Desulfurization Technology for the
Treatment of Sour Associated Gases
at Elevated Pressure
• Cleaning Up Gasification Syngas
• Liquid Redox Enhances Claus
Process
• The State of Iron-Redox Sulfur Plant
Technology: New Developments to
a Long-Established Process
Technology
• Suncor’s Optimization of a Sulfur
Recovery Facility
PROCESSES
Liquid treating
AMINEXMERICAT IITHIOLEX/REGEN
SulfurLO-CAT
Devising a comprehensive, flexible hydrogen sulfide(H2S) removal/recovery solution requires more than systems, media and equipment – it requires expertise.With more than twenty-five years of experience in H2Sremoval, Gas Technology Products LLC understands theneeds of every operator and every plant.
Gas Technology Products provides a full line of complementary hydrogen sulfide oxidation products: LO-CAT® and LO-CAT® II, Sulfur-Rite® and TheEliminator™ processes, along with its ARI®-100 mercaptan oxidation products and engineering services.
GTP offers both liquid and solid media desulfurizationtechnologies to sweeten gas streams and ventilation aircontaining virtually any levels of hydrogen sulfide ormercaptans – for systems of widely ranging capacities.For any size or type application, GTP offers completeturnkey systems and can take total system responsibility.
As a wholly owned subsidiary of Merichem Chemicals &Refinery Services LLC, Gas Technology Products LLC is apart of a fully integrated organization with unmatchedtechnical knowledge, applications expertise, and world-wide service coverage.
Uhde STAR process (dehydrogenation of lightparaffins to olefins)Application: The steam active reforming (STAR) pro-cess produces (a) propylene as feedstock for polypropy-lene, propylene oxide, cumene, acrylonitrile or otherpropylene derivatives, and (b) butylenes as feedstockfor methyl tertiary butyl ether (MTBE), alkylate, isooc-tane, polybutylenes or other butylene derivatives.
Feed: Liquefied petroleum gas (LPG) from gas fields,gas condensate fields and refineries.
Product: Propylene (polymer- or chemical-grade);isobutylene; n-butylenes; high-purity hydrogen (H2)may also be produced as a byproduct.
Description: The fresh paraffin feedstock is com-bined with paraffin recycle and internally generatedsteam. After preheating, the feed is sent to the reac-tion section. This section consists of an externallyfired tubular fixed-bed reactor (Uhde reformer) con-nected in series with an adiabatic fixed-bed oxyreac-tor (secondary reformer type). In the reformer, theendothermic dehydrogenation reaction takes placeover a proprietary, noble metal catalyst.
In the adiabatic oxyreactor, part of the hydrogenfrom the intermediate product leaving the reformeris selectively converted with added oxygen or air,thereby forming steam. This is followed by further
dehydrogenation over the same catalyst. Exothermicselective H2 conversion in the oxyreactor increasesolefin product space-time yield and supplies heat forfurther endothermic dehydrogenation. The reactiontakes place at temperature between 500°C–600°Cand at 4 bar–6 bar.
The Uhde reformer is top-fired and has a proprietary“cold” outlet manifold system to enhance reliability.Heat recovery utilizes process heat for high-pressuresteam generation, feed preheat and for heat requiredin the fractionation section.
After cooling and condensate separation, the prod-uct is subsequently compressed, light-ends are sepa-rated and the olefin product is separated from uncon-verted paraffins in the fractionation section.
Apart from light-ends, which are internally used as
fuel gas, the olefin is the only product. High-purity H2may optionally be recoverd from light-ends in thegas separation section.
Economics: Typical specific consumption figures (forpolymer-grade propylene production) are shown(perton of propylene product):Propane 1,200 kg/metric tonFuel gas 6.4 kJ/metric tonCooling water 220 m3/metric tonElectrical energy 180 kWh/metric ton
Installations: Two commercial plants using the STARprocess for dehydrogenation of isobutane to isobuty-lene have been commissioned (in the US andArgentina). More than 60 Uhde reformers and 25Uhde secondary reformers have been constructedworldwide.
References: Heinritz-Adrian, M., N. Thiagarajan, S.Wenzel and H. Gehrke, “STAR—Uhde’s dehydro-genation technology (an alternative route to C3-andC4-olefins),” ERTC Petrochemical 2003, Paris, France,March 2003.
Thiagarajan, N., U. Ranke and F. Ennenbach,“Propane/butane dehydrogenation by steam activereforming,” Achema 2000, Frankfurt, Germany, May2000.
ADAPT (Gas dehydrationand hydrocarbon dewpointing)Application: Dehydration, hydrocarbon dewpoint-ing, aromatics, methanol, mercaptan and carbon diox-ide removal from high-pressure gases. ADAPT can beused at natural gas reception terminals, undergroundgas storage facilities (i.e., salt cavities, aquifers anddepleted fields) and prior to LNG production. The pro-cess is suitable for prepurification and protection facil-ities for gas membrane systems.
Description: Undesirable components in high-pres-sure natural gasses are simultaneoudly removed withina solid adsorbent bed (1). Tailored adsorbents selec-tively remove gas-phase components and control theslippage rate to the export gas, thus meeting requiredproduction specification. Once saturated, the adsorb-ing bed is switched to regeneration mode and a freshbed (2) is brought online. Process flexibility enablesmultiple bed systems that allow very high through-puts. Using pre-heated (3) feed or product gas regen-
erates the saturated bed, which depends on the appli-cation requirements and economics. Regeneration tem-perature depends on the components being removed,but typically range from 200°C to 300°C. The rich-regen-eration gas is cooled, producing a saleable hydrocar-bon condensate (4). Cooler system flash gas is recycledback to the adsorbing bed for further processing. Someadvantages of ADAPT over competing processes are:
• Compact process plant
• Rapid startup and shutdown• No hot standby required• Turndown to 10% of design flow• High reliability and low maintenance• Long adsorbent life.
Operating conditions: Typical operating pressuresrange from 30 to 120 bar, and feed gas temperatures upto 45°C. Plants can be skid mounted or modularenabling phased asset development. Typical feed gasflows from 10 MMscfd to over 1,500 MMscfd.
Economics: Costs vary with scale and application buttypically range from £2 million for a 200 MMscfd plantto £9 million for a 1,500-MMscfd plant.
Installations: Plants in operation or construction acrossEurope, Africa and Asia. Total throughput for currentADAPT designs is approximately 9,000 MMscfd.
Reference: Metters, S. D., “An adaptable solution,”Hydrocarbon Engineering, March 2000.
DrigasApplication: Drigas is used to dehydrate natural gasto very low dew points by glycol absorption, withoutusing vacuum regeneration, no solvents and no con-sumption of stripping gas.
Description: Drigas process recycles the glycol regen-erator’s overhead vapors, cooled and dried, to thestripping tower.
The vent gas off of a conventional regeneratorwith a stripping tower is cooled in an overheadcondenser (1) and condensed water is separated inthe overhead knockout drum (2). The wet gas com-ing from (2) is reused as stripping gas, feeding it tothe bottom of the stripping tower by means of ablower (3).
Spent glycol is used to dry the recirculated gas to thestripping tower by means of a random packed atmo-spheric absorber (4) and a glycol pump (5) to move richglycol from the bottom of the atmospheric absorberto the still tower.
If higher concentrations are required, a second
stage of absorption (6) can be incorporated into thesame atmospheric column fed by a small fraction ofthe regenerated, lean TEG. This arrangement givesTEG purity up to 99.99 wt%.
Main advantages of the Drigas process are:
• Very low dew points• Stripping gas is not required• Low operating cost• Low pollution.
Operating conditions: Glycol flowrates up to 1,000m3/d, with TEG purity up to 99.99 wt%. Gas flowrateup to 15 million scmd for each train, wet gas tem-perature up to 60°C and pressure up to 150 bar.
Economics: A Drigas regenerator costs marginallymore than a traditional plant with stripping gas, butwithout any consumption of stripping gas.
Installations: One Drigas unit, with a capacity of200 m3/d DEG.
Reference: Franci, P. F., “New glycol regeneratoradaptable to offshore use,” World Oil, July 1993.
Drizo gas dehydrationApplication: Low water dew points, typical waterdew point depressions up to 180°F (depressionsgreater than 200°F achievable with Drizo HP), 95%+recovery of BTEX vapor components.
Description: Water is absorbed (1) from natural gasby glycol (DEG, TEG or tetraethylene glycol). The gly-col is then thermally regenerated in reboiler (2). Themain differences with conventional glycol processes are:glycol is flashed after preheating (3) to allow highrecovery of liquid hydrocarbons (4). After het-eroazeotropic distillation, these liquid hydrocarbons arerecovered from the still column condenser (5), vapor-ized (6) and used to strip the hot glycol (7). Water, stillpresent in the liquid hydrocarbons, can be removed bya coalescer (8) and by an optional solvent dehydrationpackage (9) (Drizo + and Drizo HP versions). Glycolpurities above 99.99 wt% and up to 99.998+ wt%(Drizo HP) are obtained, thus enabling residual watercontent in the treated gas down to below 0.1 ppm.
Economics: Combining very low dew points withlow CO2 and BTEX emissions, Drizo is an environ-
mentally friendly process compared with the other gly-col processes. Drizo is very competitive with all dehy-dration processes at water dew points below –30°C.A Drizo unit would be roughly 20% cheaper than anequivalent glycol stripping unit with recompression ofthe stripping gas (in addition to the fact that Drizo isable to reach much lower water dew points), and
can be 50% cheaper than a mol sieve unit.
Installations: More than 45 units.
References: Rigaill, C., “Solving Aromatic and CO2emissions with the Drizo gas/glycol dehydration pro-cess,” GPA Europe Meeting, February 23, 2001.
Smith, R. S., “Enhancement of Drizo gas dehydra-tion,” 47th Laurance Reid Gas Conditioning Confer-ence, March 2–5, 1997.
Smith, R. S. and S. E. Humphrey, “High Purity Gly-col Design Parameters and Operating Experience,”45th Laurance Reid Gas Conditioning Conference,1995.
Aarskog, A., T. Fontaine, C. Rigaill and C. Streicher,“Drizo revamping of TEG unit improves NGL recovery:The Ekofisk Challenge,” 82nd GPA Convention, SanAntonio, March 9–12, 2003.
Licensors: OPC Drizo, Inc., and Prosernat IFP GroupTechnologies
Contact: Christian Streicher, Marketing Manager,Prosernat, Tour Areva, 92084 Paris La Défense Cedex,France, Phone: (+33) 1 47 96 37 86, Fax: (+33) 1 47 9602 46, E-mail : [email protected]
Gas Processes 2004 Drying
Optional
Water
Fuel gas
Solventrecovery
Water reflux
Water
Dry glycolWet glycol
Wet gas
Dry gas
Equipment existing in conventional glycol processesEquipment specific to Drizo processDrizo loop
To flareCondensed
hydrocarbon(aromatics)
98
67
3
1
2
54
Return to Gas Processes INDEX
EcotegApplication: Ecoteg is a process that uses tri-ethyleneglycol (TEG) to dehydrate gases rich in aro-matic compounds (BTEX) where effluent control iscritical. Its aromatics emission into the environmentis negligible.
Description: When TEG is used to dehydrate natu-ral gas, it absorbs selectively not only water but alsopart of the BTEX that may be present. BTEX arereleased with all the outgoing streams of the regen-erator.
The vent gas off a still column is cooled in an over-head condenser (1) and condensed water and BTEXare separated in the overhead knockout drum (2). Thewet gas coming from (2) is reused as stripping gas andis fed to the bottom of the stripping tower by meansof a blower (3).
The spent glycol is used to dry the gas recirculatedto the stripping tower by means of a random-packedatmospheric absorber (4) and a glycol pump (5) tomove the rich glycol from the bottom of the atmo-spheric absorber to the still tower.
The liquid BTEX are recovered as oil if an oil prod-uct is already present in the plant; otherwise, they arereturned to dried gas by means of a pump (6) or recy-cled to presaturate the lean TEG.
Condensed water, before disposal, is strippedthrough a stripping tower (7) by means of combustionair.
Main advantages of the Ecoteg process are:
• Meet more stringent regulations for disposalwithout additional facilities
• Low operating cost• Low gas dew point.
Operating conditions: Gas flowrates up to 15 mil-ion scmd for each train, wet gas temperature up to60°C and pressure up to 150 bar.
Economics: Ecoteg is an ecological and cost-effectivedehydration process that does not require additionalexternal facilities to meet regulations for effluents.This simplifies the first installation and/or additions toan existing plant. Savings in stripping gas helps theeconomics and may be a determinant when low gasdew points are required.
Reference: Franci, P. F. and J. W. Clarke, “Emissionfree, high purity TEG regenerator,” 1994 GRI GlycolDehydrator/Gas Processing Air Toxic Conference, SanAntonio.
IfpexolApplication: Treat any gas for dehydration, hydrateprotection, dew-point control and acid-gas removal,using a single, low-freezing point solvent—methanol.Ifpexol is a two-step process; each step can be usedindependently or in combination:
• Ifpex-1—simultaneous water and hydrocarbondew pointing (down to –100°C)
• Ifpex-2—removal of acid gases and sulfur com-pounds (to sales gas specifications).
Description: Ifpex-1: A partial stream from the feedgas is loaded with methanol by stripping in a contactor(1). The methanol/water mixture is recycled from thecold process (2). Pure water is obtained from the bot-tom of the contactor (1). Overhead gas is mixed withthe main gas stream and contains enough methanolto prevent freezing during the cold process (2). Dur-ing this process, the gas is cooled to the requireddew-point temperature by any appropriate means(J-T expansion, turbo expander or external refriger-ation). The treated dry gas is recovered from the low-temperature separator along with condensed hydro-carbons and the methanol/water mixture. This
methanol/water mixture is recovered as a separate liq-uid phase and recycled to the contactor (1).
Ifpex-2: The gas from Ifpex-1 (or any other feed gas)is contacted with refrigerated methanol-based solventin the contactor (3). Acid gases (CO2, H2S) areabsorbed, along with other sulfur compounds (mer-captans, COS), and a dry sweet gas is obtained on topof the contactor (3). The solvent loaded with acidgases is regenerated by a simple flash and, in somecases, by thermal regeneration. Hydrocarbon co-absorption is controlled by the solvent composition
and a multi-flash regeneration recovers most of theco-absorbed hydrocarbons in a separate gas stream.Acid gases are recovered dry and under pressure (typ-ically around 10 bar); thus, this process is particularlysuitable for acid-gas reinjection applications.
Economics: For dew points below –30°C, Ifpex-1 cancompete with glycol processes and offers muchreduced (about 30% lower) CAPEX. Ifpex-2 offers sig-nificant savings compared to other processes for bulkacid-gas removal with acid-gas reinjection.
Installations: Fifteen Ifpex-1 units with capacities upto 350 MMscfd.
References: “Methanol treating schemes offers eco-nomics, versatility,” Oil & Gas Journal, June 1, 1992,p. 65.
Minkkinen, A., et al., “Technological developmentsin sour gas processing,” Gas Cycling, Les Entretiens IFP,May 14, 1998, Technip.
Licensors: Prosernat IFP Group Technologies andTitan SNC Lavalin
Contact: Christian Streicher, Marketing Manager,Prosernat, Tour Areva, 92084 Paris La Défense Cedex,France, Phone: (+33) 1 47 96 37 86, Fax: (+33) 1 47 9602 46, E-mail : [email protected]
Gas Processes 2004 Drying
4
2
Water +solvent
Condensedhydrocarbons
Cold, dry, sweet gasDry gas
Any raw,wet gas
IFPEX 2IFPEX 1
Recoveredwater
1 3
Dry acid gas
Return to Gas Processes INDEX
AMMOGENApplication: AMMOGEN provides gaseous ammoniato fossil-fuel-burning plants to operate pollution-control systems such as DeNOx/DeSOx SCR, SNCR andflue-gas treatment units. This process producesgaseous ammonia onsite and on demand with harm-less and easy-to-handle feedstocks—urea and water.It eliminates the hazard of transporting and storingtoxic compounds such as anhydrous or aqueous ammo-nia.
Products: The gaseous stream of ammonia(15–35%vol.), carbon dioxide and water vapor.
Description: Dry urea enters the dissolver/storagetank where it is dissolved using lean-recycle solutionand condensate. The stirrer reduces mixing time, andthe rich-urea solution (20–60%wt) is pumped to thehydrolyzer through the economizer where the leansolution sensible heat is recovered. A multistagehydrolysis, at 180–250°C and 15–30 bar, is done inthe baffled hydrolyzer, while the reaction products,i.e., ammonia and carbon dioxide, are removed by astripping fluid (typically steam). The heat of reactionis supplied by an internal heater and stripping fluid.After the urea decomposition, the lean solution is
flashed at atmospheric pressure in the flash separa-tor, from where almost pure water is recycled to thedissolver. The flashed vapor, rich in NH3, joins themain stream produced by the hydrolyzer and both aresent to the static mixer and diluted with air beforedelivery to the ammonia-injection grid of the flue-gastreatment system.
Main advantages include: • Gaseous ammonia produced onsite and on
demand• Utmost safety (no governmental reportable
amounts or contingency plans)• Urea feedstock is harmless, easy-to-handle and
widely available• Simple and safe noncatalytic process• No carryover of compounds that can damage SCR
systems• Very rapid response time and maximum turn-
down availability• Quick startup, shutdown and standby• Automatic operation and low maintenance• Limited plant footprint for easier installation; also
can be skid-mounted or module• Low capital and operating cost• Capacity from several to thousands kg/h of
ammonia.
Installations: Four plants in the US with designcapacity from 270 kg/h to 1,600 kg/h.
Beavon-othersApplication: Purify tail gas from sulfur recovery units(such as Claus units) and other gas streams contain-ing low concentrations of SO2. The type of process tobe combined with the Beavon treatment dependson the intended disposition of the treated product gas(e.g., additional sulfur recovery, other componentrecovery, incineration or exhaust, while meeting strin-gent air pollution standards).
Beavon-MDEA processing adds H2S separation.Beavon-Selectox processing converts H2S to ele-
mental sulfur.Beavon-Hi-Activity processing converts H2S to ele-
mental sulfur.
Description: In the Beavon step, essentially all sulfurcompounds in the feed gas (SO2, Sx, COS, CS2) areconverted to H2S. The feed gas is heated (1) to reac-tion temperature by mixing with the hot combus-tion products of fuel gas and air. This combustion iscarried out with a deficiency of air to provide sufficientH2 and CO to convert all of the sulfur and sulfur com-pounds to H2S. The heated gas mixture is then passedthrough a catalyst bed (2) where all sulfur compoundsare converted to H2S by hydrogenation and hydroly-
sis. The hydrogenated gas stream is cooled in a steamgenerator (3), and then by direct contact (4) with abuffer solution before entering the selected H2Sremoval process.
Beavon-MDEA. One of several processes used toremove H2S is by absorption (5) in a solution of MDEA(methyl diethanolamine) or one of the recently devel-oped highly selective amine type solvents. The cleantail gas contains less than 10 ppm H2S when using thenewer solvents. When this combination is operatingon a Claus tail gas, the separated H2S can be recycledto the Claus unit.
Beavon-Selectox. An alternative (6) for removing theH2S is to convert it to elemental sulfur by the Selec-tox process.
Beavon-Hi-Activity. Another alternate for removingthe H2S is to oxidize it directly to elemental sulfur bythe Hi-Activity process.
Operating conditions: All pressures are near atmo-spheric. The Beavon hydrogenation/hydrolysis reactoroperating temperature is in the range of 550°F to750°F. Equipment is essentially all carbon steel. Sulfurrecovery of Claus plus Beavon-Selectox or Beavon-MDEA is more than 99% or 99.9%, respectively.
Installations: There are more than 100 Beavon-typetail gas treating units worldwide. Among these aremore than 30 Beavon-MDEA plants operating world-wide. Two Beavon-Selectox plants are operating in theUS and Germany; one Beavon-Hi-Activity plant oper-ating in Germany. Two Beavon-Hi-Activity plants to beinstalled in China and Venezuela.
Licensors: Parsons Energy & Chemicals Group, Inc.,and UOP LLC.
Contact: Arif Habibullah, P.E. , Senior Technical Direc-tor & Manager, Process Technology, Parsons E&C, 125 W Huntington Drive, Arcadia, CA 9100, Phone:(626) 294-3582, Fax: (626) 294-3311, E-mail:[email protected]
Gas Processes 2004 Effluent cleanup
4
3
5
Steam
BFW
Air
Fuel gas
Claustail gas
Acid gas
Clean gas
Sulfur
Clean gas
2
1
6
Return to Gas Processes INDEX
ClauspolApplication: Claus tail-gas treatment with total sul-fur recoveries up to 99.9+%. Liquid-phase conver-sion of H2S and SO2 into liquid elemental sulfur (S).
Description: Claus tail gas is contacted counter-currently with an organic solvent in a low-pressuredrop packed column (1). Hydrogen sulfide (H2S) andSO2 are absorbed in the solvent and react to form liq-uid elemental S according to the Claus reaction,which is promoted by an inexpensive dissolved cat-alyst. The solvent is pumped around the contactor (1),and the heat of reaction is removed through a heatexchanger (3) to maintain a constant temperatureslightly above the sulfur melting point. Due to thelimited solubility of S in the solvent, pure liquid S sep-arates from the solvent and is recovered from a set-tling section (2) at the bottom of the contactor (1).This standard Clauspol II flow scheme allows S recov-ery up to 99.8% (Claus + Clauspol). The recoverylevel can be customized by adapting the size of thecontactor (1).
The latest development is the optional solventdesaturation section (4). By removing the dissolved sul-fur from the circulating solvent, the overall sulfurrecovery can be raised up to 99.9+%.
Economics: For a Clauspol unit treating a typicalClaus tail gas, in the 99.7–99.9% recovery, the CAPEXare typically 60–80% and OPEX 40–60% of those for
a conventional hydrogenation/amine plant. Contrar-ily to the hydrogenation/amine process, Clauspol doesnot recycle any H2S to the Claus unit, thus savingClaus plant capacity.
Installations: More than 40 units.
References: Barrère-Tricca, C., et al., “Thirty Years ofOperating Experience with a Wet Subdewpoint TGTProcess,” GPA Europe Annual Conference, Amster-dam, September 26–28, 2001.
Ballaguet, J. P., C. Barrère Tricca and C. Streicher,“Latest developments of the Clauspol TGT process,”AIChE Spring Meeting, New Orleans, March 30–April3, 2003.
Licensor: Prosernat IFP Group Technologies
Contact: Christian Streicher, Marketing Manager,Prosernat, Tour Areva, 92084 Paris La Défense Cedex,France, Phone: (+33) 1 47 96 37 86, Fax: (+33) 1 47 9602 46, E-mail : [email protected]
Gas Processes 2004 Effluent cleanup
Gas to incinerator
Claus tail gas
Liquid sulfur
Optional
1
2
4
3
Return to Gas Processes INDEX
LTGT (Lurgi tail-gas treatment process)Application: Wet-scrubbing process purifies Claustail gas for total sulfur recovery ranging from 99.8%to 99.9+%.
Description: The optimum Claus tail-gas treatmentconverts sulfur species to H2S and recovers it in a wet-scrubbing process. The Lurgi tail-gas treatment pro-cess (LTGT) is an amine treating system with genericMDEA solvent, structured packing and plate heatexchangers when possible. This process enables usingsmaller diameter columns, plot size, worldwide treat-ing solution availability, proven technology and highselectivity. Installing smaller equipment lowers totalinvestment costs.
Different sulfur species from the incoming Claus tailgas are converted (1) to H2S. Process water formed bythe Claus reaction is removed in a direct cooler (2), andH2S is expunged by MDEA solution in an absorber col-umn (3). The amine solution is regenerated in a steam-
heated stripper column (4) and produces a H2S gasstream that is recycled back to the Claus section. Dueto hydrogenation in the tail-gas treatment, both acidgases—H2S and CO2—are produced and routed tothe absorber column.
Tertiary amines like MDEA, which are used in theLTGT, have the ability to selectively absorb H2S due to
chemical structure and do not co-absorb CO2. Pri-mary (MEA) and secondary amines (DEA) will absorbH2S along with most of the CO2. In tertiary amine solu-tions, CO2 can only be absorbed by an indirectacid/base reaction forming bicarbonates; this is a veryslow reaction.
Economics: Investment amounts are approximately85–95% of the Claus unit cost. Using a common regen-eration along with the upstream amine unit, invest-ments are approximately 65–75% of the Claus unitcost.
Installations: Six LTGT units for processing Claus tailgases are in operation or under design.
ResulfApplication: Purification of sulfur recovery unit (SRU)tail gas for incineration. Resulf, Resulf-10 and Resulf-MM units are easily retrofitted to existing SRU com-plexes. They feature a low unit pressure drop and canuse the latest specialty solvents to lower energy con-sumption and maximize flexibility.
Products: Treated vent gas from a Resulf-MM unittypically contains 1,000 ppm H2S and must be incin-erated. Treated vent gas from a Resulf unit typicallycontains less than 150 ppmv H2S and is oxidized in anincinerator before venting to the atmosphere. Ventgas from a Resulf-10 unit has a maximum of 10 ppmvH2S and may not require incineration.
Description: SRU tail gas is heated in the feed heater,then mixed with a reducing gas containing H2. Theheated stream passes through the reactor (1), wherethe SO2, elemental sulfur and other sulfur-containingcompounds, such as COS and CS2, are converted to H2S.Hot gas leaving the reactor is cooled in a waste-heatsteam generator. The gas is further cooled in a directcontact water cooler (2). The overhead gas stream isfed to the absorber (3).
Lean solvent is also fed to the absorber. The down-
ward flowing solvent contacts the upward flowing gasand absorbs nearly all the H2S and only part of theCO2. Rich solvent is sent to the regenerator (4) wherethe H2S and CO2 are removed by steam stripping.Acid gas from the regenerator is recycled to the SRU.Lean solvent from the regenerator is cooled andreturned to the absorber.
Operating conditions: Resulf units use MDEA orformulated MDEA as a solvent. Resulf-10 units are
designed using specialty amines such as formulatedMDEA. Resulf units use generic MDEA solvents. Resulf-MM units use amine from the primary amine unit(MEA, DEA or MDEA).
Economics: Plate and frame heat exchangers havebeen used to reduce capital costs. Modular designs canalso be used to reduce capital costs while maintain-ing critical project schedules. The cost for Resulf-MMis significantly lower than for Resulf or Resulf-10 dueto the lower recovery. Key features of the Resulf-MMand Resulf technologies are that they can be inexpen-sively upgraded.
Installations: TPA has licensed and designed world-wide:
Contact: Mr. Jim E. Lewis, vice president and generalmanager, CB&I TPA Howe-Baker, 2703 Telecom Parkway, Ste. 150, Richardson, TX 75082, Phone: (972) 773-2257, Fax: (972) 669-3678, E-mail:[email protected]
Gas Processes 2004 Effluent cleanup
3 421
Acid gasto SRUSRU tail
gas
Steam
Hydrogen
Sourwater
Steam
Filtration
Toincinerator
Return to Gas Processes INDEX
SCOTApplication: A low-pressure drop, high-sulfur recov-ery efficiency process to recover sulfur componentsfrom tail gas of sulfur plants. The SCOT process isinsensitive to variations in the upstream SRU, such asin the H2S/SO2 ratio, hydrocarbon or ammonia break-through.
Products: Offgas from a SCOT unit contains a totalsulfur content less than 120 ppmv; offgas from aSuper SCOT unit contains maximum 50 ppmv total sul-fur content and the offgas from Low Sulfur SCOTcontains less than 10ppm.
Description: The Claus tail gas feed to the SCOTunit is heated to 220°C to 280°C using an inline burneror heat exchanger (1) with optionally added H2 or amixture of H2/CO. If reducing gas, H2 or CO is not avail-able, an inline burner (1) is operated in an air-deficientmode to produce reducing gas. The heated gas thenflows through a catalyst bed (2) where sulfur com-ponents, SO2, elemental sulfur (S), COS and CS2 arepractically completely converted to H2S. The gas iscooled to 40°C in an optional heat-recovery system (3)and a water-quench tower (4), followed by selective
H2S removal in an amine absorber (5) to typically 30to 100 ppmv H2S. The semi-loaded amine is oftenfurther loaded in another absorber. The H2S absorbedin the SCOT, Super SCOT or Low Sulfur SCOT processis recycled to the Claus unit via the amine regenera-tor. The absorber offgas is incinerated.
The process is continuous, has a pressure drop of 4psi or lower, provides excellent sulfur recovery and canbe operated at high reliability with less than 1%unscheduled downtime.
Economics: The total sulfur recovery efficiency of theSCOT process combined with the upstream Claus unittypically guarantees a sulfur recovery of at least99.8%. In case of a Super SCOT unit, an overall sulfurrecovery efficiency of 99.95% can be guaranteed. Anintegrated and cascaded SCOT unit has capital andoperational expenditures comparable to other tail-gastreating technologies, but has higher total sulfurrecovery efficiency.
References: Kees van den Brand, “Shell’s Low CostSCOT Process”, Sulphur Recovery Symposium, Vail,September 2002.
Hoksberg, et al., “Sulfur recovery for the new mil-lennium,” Hydrocarbon Engineering, November 1999.
Verhulst, “Recent developments in SCOT tail gastechnology,” Bovar/Western Research Sulfur Semi-nar, Istanbul, 1994.
Kuypers, Ten years SCOT experience, Erdol andKohle, January 1985.
Licensor: Shell Global Solutions International B.V.
SULFREENApplication: Catalytic purification of Claus tail gas orlean H2S waste gas for an overall sulfur recovery rang-ing from 99% to 99.9%. Different versions of theSULFREEN process are available.
Description: The SULFREEN process is based on thewell-known Claus reaction in which the components—H2S and SO2 in tail gas—are catalytically converted intoelemental sulfur. The process occurs in the gas phase;the operating conditions being those at which the tailgas leaves the upstream Claus plant. The catalyst,which is arranged in fixed beds, consists of impreg-nated activated alumina, the properties of which aresimilar to those of Claus catalysts.
Tail gas leaving the Claus plant at temperatures of120°C to 140°C passes through one of the two reac-tors (1) (2), where most of the H2S and SO2 are con-verted into elemental sulfur and adsorbed on thecatalyst.
The sulfur-laden catalyst is regenerated by using partof the Claus plant tail gas. The regeneration gas isheated in a gas/gas-heat exchanger (6), using theheat in the hot offgases from the incineration unit (3).A gas-fired heat exchanger, a direct-fired heater or anelectrical heater can also be used for heating purposes.
The desorbed sulfur contained in the hot regener-ation gas is recovered in the sulfur condenser (4) (5).The regeneration-gas blower (7) serves for overcom-ing the pressure drop of the closed regenerationloop. After subsequent cooling of the catalyst bed withpurified tailgas, the reactor (1) (2), is again ready tobe switched to adsorption.
If high COS and CS2 concentrations are expected tobe present in the tailgas, a modified version of the pro-cess, named HYDROSULFREEN, is available. The
HYDROSULFREEN process includes a pretreatment ofthe tail gas in an hydrolysis and oxidation reactor,located upstream of the SULFREEN reactors. For sul-fur recoveries up to 99.9%, the DOXOSULFREEN pro-cess can be applied. This process includes an additionaldirect oxidation step downstream of the SULFREENreactors.
Economics: SULFREEN investment amounts to30–45% of the Claus unit cost for the conventionalversion, and 50–85% for the improved versions. Oper-ating costs are much lower than for solvent-based pro-cesses.
Installations: More than 75 SULFREEN units—forprocessing tail gases of Claus plants, ranging from 5tpd to 2,200 tpd of sulfur—are in operation or underdesign.
Reference: Willing, W., and T. Lindner, “Lurgi’s TGTprocesses and new operational results from SULFREENplants,” presented at the SULPHUR ’94 Conference,Tampa, Florida, Nov. 6–9, 1994.
DeNOx and DeDioxin technologyApplication: Nitrogen Oxides (NOx) and Dioxinremoval contained in flue-gas leaving combustionprocesses, to meet the most stringent environmentregulations concerning atmospheric pollution.
Description: The De NOx and DeDioxin process tech-nologies consist of the selective catalytic reduction(SCR) of NO, NO2 and dioxin to elemental componentsair like nitrogen and water (H2O) vapor. The reducingagent is ammonia (NH3), which is available from anhy-drous NH3, H2O diluted or produced from urea viahydrolysis.
The reaction takes place over a regenerable catalystbased on titanium dioxide (TiO2) as a carrier withvanadium pentoxide (V2O5) and tungsten trioxide(WO3) as active elements. The catalyst can have eithera honeycomb structure with homogeneous pores sizedistribution and a very active surface or plate struc-ture with a low-pressure drop.
The gas entering the SCR system is heated up toreaction temperature by an inline fuel gas burner. Thereducing agent is injected upstream of the SCR reac-
tor by a multiple spray nozzle system or by an injec-tion grid. NH3 is uniformly distributed and led to inti-mate contact with the contaminants by a static mixer.Typically, downstream of the SCR reactor, a gas-gasheat exchanger is used to preheat gas entering theDeNOx system by cooling down the outlet gas fromthe reactor routed to the stack.
Operating conditions: The SCR system pressuredrop ranges from 0.20 bar to 0.30 bar and operatingpressure is slightly under atmospheric pressure. Oper-ating temperature can vary between 150°C and 450°C
depending on gas composition. Lower limit temper-ature is dictated by the need to avoid condensationleading to a catalyst deactivation, while the upper limitis to avoid TiO2 sintering . Catalyst regeneration is per-formed onsite with a proprietary technology (ReCat).The SCR system can reduce both NOx up to 90–95%and dioxin levels down to 0.1ng/Nm3. NH3 slip in theflue gas to the stack is generally kept below 5 ppm vol.
Economics: Technology is based on standard equip-ment and most are fabricated in carbon steel. Capi-tal cost can range from $1 million for 50,000 Nm3/h to$10 million for 800,000 Nm3/h.
Commercial plants: More than 40 units are alreadyin operation worldwide. Recently three plants in Italyand two in France have been built by SIIRTEC NIGIunder IUT license. Capacity of DeNOx and DeDioxinplants can range from thousands to millions Nm3/h offlue gas.
Licensor: SIIRTEC NIGI - Milan, Italy is the exclusivesub-licensor for Italy and other territories of IntegralUmwelt Unlagentechnik - Wien (Austria)
Fluor CO2LDSep processApplication: Modern hydrogen (H2) plants use apressure swing adsorption (PSA) technology to recoverH2 from shifted syngas. PSAs recover between 75% to90+% of the total H2 in syngas. The remaining H2 bal-ance is not recovered; thus is devalued as fuel gas.
In response to growing concerns regarding green-house gas emissions, carbon dioxide (CO2) recovery isgarnering greater attention. Fluor’s CO2LDSep is apatented process that consists of H2 and CO2 purifi-cation and recovery from a H2 plant’s PSA tailgas.
Description: The tailgas from the PSA unit, in theexisting H2 plant, enters the CO2LDSep plant and iscompressed in the feedgas compressor (1). It is thendried (2), further compressed (3), cooled and expanded(4). The compression/expansion services may be accom-plished in a single integrally geared package. A por-tion of the CO2 is removed through liquefaction. Sup-plemental refrigeration may be used, but is notrequired in most cases.
If food-grade CO2 production is desired, the liquidCO2 can be purified in a stripper (5) to a purity of 99.99wt%. The CO2 is available as a pumpable liquid, whichallows for low energy consumption when high prod-uct pressures are desired for enhanced oil recovery(EOR).
The H2-enriched gas leaving the CO2LDSep unit issent to the H2 recovery PSA (6), where H2 of 99.9vol% is separated from CO2, methane and other impu-rities. The tailgas stream from the new H2 recovery PSAalong with the overhead from the stripper, if appli-cable, is routed to the reformer furnace where it isblended with the natural gas fuel and combusted.
Operating conditions: Typical PSA tailgas concen-trations are 45% to 55% CO2 and 24% to 26% H2.
Economics: When applied to a 65 million scfd H2plant, the CO2LDSep process is able to recover 7 mil-lion scfd of H2 and 440 tpd of CO2 from the PSA tail-gas. This plant has an electrical load of 7 MW andrequires 4,200 gpm of cooling water in circulation.
References: US Patent 6,301,927.
Licensor: Fluor Enterprises, Inc.
Contact: Satish Reddy, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-2000, Fax: (949)349-2585, E-mail: [email protected]
Gas Processes 2004 Treating
LiquidCO2
543
2
6
11
Feed gas
H2 product
Fuel gas
M
Return to Gas Processes INDEX
Shell-Paques processApplication: Biological desulfurization of high-pres-sure natural gas, synthesis Gas and Claus tail gas.
Products: The Shell-Paques unit can be designedsuch that the treated gas stream contains less than 5ppmv H2S; the resulting sulfur recovery is conse-quently over 99.99%, based on gas streams. The bio-sulfur produced can be used directly as fertilizer, sinceit has a hydrophilic character. Thus, the sulfur is moreaccessible in soil for oxidation and subsequent uptakeby plants. Alternatively, the bio-sulfur can be washedand remelted to produce a final liquid sulfur productthat will meet industrial specifications. The hydrophiliccharacter of the bio-sulfur is lost after remelting.
Description: In the Shell-Paques process, H2S isdirectly oxidized to elemental sulfur (S) using color-less sulfur bacteria (Thiobacilli). These naturally occur-ring bacteria are not genetically modified. Feed gasis sent to a caustic scrubber (1) in which the H2Sreacts to sulfide. The sulfide is converted to ele-mental S and caustic by the bacteria when air is sup-plied in the bioreactor (2). Sulfur particles are coveredwith a (bio-) macropolymer layer, which keeps the sul-fur in a milk-like suspension that does not causefouling or plugging.
In this process, a sulfur slurry is produced, which canbe concentrated to a cake containing 60% dry mat-ter. This cake can be used directly for agriculturalpurposes, or as feedstock for sulfuric acid manufac-turing. Alternatively, the biological sulfur slurry canbe purified further by melting to high-quality sulfurto meet international Claus sulfur specifications.
Economics: The Shell Paques/Thiopaq processachieves a very low H2S content in the treated gas; avery high-sulfur recovery efficiency of 99.99% isachievable. This process can thus replace the combi-nation of an amine/Claus/TGTU or, for smaller appli-
cations, liquid redox processes.
Installations: There is one Shell-Paques unit inoperation with a second license sold. It comparesfavorably in terms of capital expenditure with prac-tically all liquid redox applications, and with thetraditional amine/Claus/TGTU for sulfur capacities, upto around 50 tpd. The capital and operating costs forthis biological process decrease with decreasingCO2/H2S ratios.
Reference: Cameron Cline et al. “Biological processfor H2S removal from gas streams. The Shell-Paques/THIOPAQ gas desulfurization process” Lau-rence Reid, Feb 2003
Janssen, A. J. H., et al, “Biological process for H2Sremoval from high pressure gas: The Shell-Paques/THIOPAQ gas desulfurization process,” Sul-phur, 2001.
Licensors: Shell Paques: Paques B.V. and Shell GlobalSolutions International B.V.
Thiopaq DeSOXApplication: The Thiopaq DeSOx biological processselectively removes and converts SOx in the flue gasesto elemental sulfur or H2S.
Product: The sulfur produced is hydrophilic; thus, itprevents equipment from fouling or blocking. More-over, this characteristic makes the product sulfur suit-able for agricultural use as fertilizer or as an insecti-cide. Alternatively, the sulfur can be melted to ahigh-purity product and meet international Claus sul-fur specifications. Alternatively, H2S can be producedand the gas can be sent to the sulfur treatment unit(amine/Claus).
Description: The Thiopaq DeSOx is a commercial,two-step biological process. It can convert sulfite andsulfate to elemental sulfur or H2S. A sodium biphos-phate solution quenches and removes particulatesand absorbs SOx from the flue gas. The scrubbing liq-uid is regenerated and recycled to the scrubber.
The heart of the Thiopaq process is the propri-etary anaerobic and aerobic bioreactors. In theseair-lift-loop reactors, the absorbed sulfite is reducedto sulfide (HS–) inside the anaerobic reactor in thepresence of microorganism with hydrogen and couldbe removed as H2S alternatively.
The sulfide is oxidized under controlled conditions
to elemental sulfur via the microorganisms. The pro-duced elemental sulfur has a hydrophilic nature andis separated from the aqueous effluent in a proprietarythree-phase separator.
Operating conditions: The scrubber operates closeto the atmospheric pressure and at saturation tem-perature of the scrubbing liquid. The anaerobic biore-actor can be operated at pressures of up to 6 barand 35°C. The aerobic bioreactor operates at atmo-spheric pressure and 35°C.
Installation: Twenty Thiopaq units operating world-wide to remove sulfur from gas and liquid streams fora variety of industries. Currently, a 13-mtpy unit is instartup phase for refinery service in Egypt.
Licensors: UOP LLC, Monsanto Environchem SystemInc., and Paques B.V.
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Flue gas treatment
Feed
H3PO4vessel
Sludgepumps
SulfurcakeNutrient
vessel
Solutioncooler
NaOHvessel
M/LtankAir
comp. Bleed
HAcvessel
H2 gasholder
H2 makeup
H2recyclecomp.Makup
water
SO2scrubber H2S
scrubber
Analyzer
Aero
bic
reac
tor
Anae
robi
cre
acto
r
Reactor offgass blower
To vent header To header
Centrifuge
Return to Gas Processes INDEX
Thiopaq—H2S RemovalApplication: The biological Thiopaq process selec-tively removes and converts H2S and light mercaptansfrom gas streams, aqueous streams and/or light hydro-carbons to elemental sulfur or sulfate.
Product: The sulfur produced is hydrophilic; thus, itprevents equipment from fouling and blocking. More-over, this characteristic makes the product suitable foragricultural use as fertilizer or as an insecticide. Alter-natively, the sulfur can be melted to a high-purityproduct meeting international Claus sulfur specifi-cations.
Description: The Thiopaq process consists of threeintegrated process sections: an absorption section toremove the H2S from the gas stream, bioreactor(s) anda sulfur-separation section.
The heart of this process is the proprietary biore-actor. In this air-lift-loop reactor, sulfide (HS–) is oxi-dized under controlled conditions to elemental sulfur
in the presence of microorganisms. These aerobic(oxygen consuming) organisms use the releasedenergy from the sulfide oxidation for metabolic pro-cesses. The elemental sulfur produced has a hydrophilicnature and is separated from the aqueous effluent ina proprietary three-phase separator.
The scrubbing step to remove H2S from the gas
streams is integrated into the Thiopaq process andregenerates the scrubbing solution, rather than its dis-posal. Regeneration is possible because the alkalinityconsumption due to the absorption of H2S is com-pensated by the oxidation of H2S to elemental sulfur.
Operating conditions: The absorber operates atthe pressure of feed and at bioreactor temperature.The bioreactor operates at atmospheric pressure and30–35°C. If the feed is available at a higher temper-ature, then it requires cooling before entering theabsorber.
Installations: Thirty-one units are operating world-wide to remove sulfur from gas and liquid streams ina variety of industries. Currently, a 13-mtpd unit instartup phase for refinery service in Egypt.
Licensors: UOP LLC, Shell Global Solutions B.V. andPaques B.V.
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Flue gas treatment
Feed
Nutrientvessel
NaOHvessel
H2S scrubber
Aerobicreactor
Analyzer
To fuel header To stack
Reactoroffgass blower
Sludgepumps
Bleed
Sulfur cake60-65% wt
M/Ltank
Centrifuge
Air compressor
Return to Gas Processes INDEX
HydrogenApplication: To produce hydrogen from light hydro-carbons using steam-methane reforming.
Feedstock: Natural gas, refinery gas, liquefiedpetroleum gas (LPG) and naphtha.
Product: High-purity hydrogen and steam.
Description: Light hydrocarbon feed (1) is heatedprior to passing through two fixed-catalyst beds.Organic sulfur compounds present in feed gas (e.g.,mercaptans) are converted to hydrogen sulfide (H2S)and mono-olefins in the gas phase are hydrogenatedin the first bed of cobalt molybdenum oxide catalyst(2). The second bed contains zinc oxide to remove H2Sby adsorption. This sulfur-removal stage is necessaryto avoid poisoning of the reforming catalysts.
Treated feed gas is mixed with steam and heatedbefore passing to the reformer where the hydrocar-bons and steam react to form synthesis gas (syngas).
Foster Wheeler supplies proprietary side-fired Ter-race Wall reformers, with natural draft mode optionfor increased reliability, compact plot layout withconvection section mounted directly above the radi-ant section and modular fabrication option. FosterWheeler supplies top-fired reformer options for largecapacity plants.
Syngas containing hydrogen, methane, carbon diox-ide (CO2), carbon monoxide (CO) and water leaves thereformer and passes through the waste-heat boiler tothe shift reactor (3) where most of the CO is con-
verted to CO2 and hydrogen by reaction with steam.For heavier feedstocks, prereforming is used for con-version of feedstock upstream of the reformer.
The syngas is cooled through a series of heat-recov-ery exchangers before free water is recovered in aknockout drum. The resultant raw hydrogen streampasses to the pressure swing adsorption (PSA) unit forpurification (4) to typically 99.9% hydrogen productquality. Tail gas from the PSA unit provides a sub-stantial proportion of the firing duty for the reformer.The remaining fuel is supplied from the feed gas orother sources (e.g., refinery fuel gas).
Demineralized water makeup is de-aerated, mixedwith recovered condensate and preheated through aseries of heat-recovery exchangers before passing tothe steam drum. Saturated and superheated steam is
raised by heat exchange with the reformed gas andflue gas in the convection section of the reformer.Steam export quantities can be varied between 1,250and 5,750 lb/million scfd of hydrogen produced usingair pre-heat and auxiliary firing options.
Economics: Plant design configurations are opti-mized to suit the clients’ economic requirements,using discounted cash-flow modeling to establish thelowest lifecycle cost of hydrogen production.
Investment: 10–100 million scfd, 3rd Q 2002, USGC$9–55 million
Utilities, typical per million scfd of hydrogen produced (natural gas feedstock):
Feed + fuel, lb 960Water, demineralized, lb 4,420Steam, export, lb 3,320Water, cooling, US gal 1,180Electricity, kWh 12
Reference: Ward, R. D. and N. Sears, “Hydrogen Plantsfor the New Millennium,” Hydrocarbon Engineering,Vol. 7, Number 6, June 2002.Installation: Over 100 plants, ranging from 1 million scfdto 95 million scfd in a single-train configuration andnumerous multi-train configurations.Licensor: Foster WheelerContacts: US: 2020 Dairy Ashford, Houston, TX 77077,Phone: (281) 597-3066, Fax: (281) 597-3028UK: Shinfield Park, Reading, RG2 9FW, Phone: (+44) 118 913 1234, Fax: (+44) 118 913 2333, E-mail: [email protected]
Gas Processes 2004 Hydrogen
Producthydrogen
Steam
Fuel gas Purge gas
Steam
Steam
Hydrocarbonfeed 1
4
2 3
Return to Gas Processes INDEX
HydrogenApplication: Production of hydrogen (H2) from hydro-carbon (HC) feedstocks, by steam reforming.
Feedstocks: Ranging from natural gas to heavy naph-tha as well as potential refinery offgases. Many recentrefinery hydrogen plants have multiple feedstockflexibility, either in terms of back-up or alternative ormixed feed. Automatic feedstock change-over hasalso successfully been applied by TECHNIP in severalmodern plants with multiple feedstock flexibility.
Description: The generic flowsheet consists of feedpretreatment, pre-reforming (optional), steam-HCreforming, shift conversion and hydrogen purificationby pressure swing adsorption (PSA). However, it isoften tailored to satisfy specific requirements.
Feed pretreatment normally involves removal ofsulfur, chlorine and other catalyst poisons after pre-heating to 350°C to 400°C.
The treated feed gas mixed with process steam isreformed in a fired reformer (with adiadatic pre-reformer upstream, if used) after necessary super-heating. The net reforming reactions are stronglyendothermic. Heat is supplied by combusting PSA
purge gas, supplemented by makeup fuel in multipleburners in a top-fired furnace.
Reforming severity is optimized for each specificcase. Waste heat from reformed gas is recoveredthrough steam generation before the water-gas shiftconversion. Most of the carbon monoxide is furtherconverted to hydrogen. Process condensate result-ing from heat recovery and cooling is separated andgenerally reused in the steam system after necessary
treatment. The entire steam generation is usually onnatural circulation, which adds to higher reliability. Thegas flows to the PSA unit that provides high-purityhydrogen product (up to < 1ppm CO) at near inletpressures.
Typical specific energy consumption based on feed+ fuel – export steam ranges between 3.0 and 3.5Gcal/KNm3 (330–370 Btu/ scf) LHV, depending uponfeedstock, plant capacity, optimization criteria andsteam-export requirements. Recent advances includeintegration of hydrogen recovery and generation,recuperative (post-)reforming also for capacityretrofits.
Installations: TECHNIP has been involved in over240 hydrogen plants worldwide, covering a widerange of capacities. Most installations are for refineryapplication with basic features for high reliabilityand optimized cost.
HydrogenApplication: Produce hydrogen for refineryhydrotreating and hydrocracking or other refinery,petrochemical and industrial applications.
Feed: Natural gas, refinery offgas, LPG/butane, lightnaphtha and multiple feedstock.
Product: High-purity hydrogen (>99.9%). CO, CO2and/or electricity may also be produced separately forbyproduct credit.
Description: The feedstock (natural gas, for example)is desulfurized (1), mixed with steam and convertedto synthesis gas in the reformer (2) over nickel cata-lysts at 20 to 50 bar pressure and temperatures of800°C to 950°C.
The Uhde steam reformer is a top-fired reformer,which has tubes made of centrifugally cast alloy steeland a proprietary “cold” outlet manifold system toenhance reliability. Subsequent high-pressure steamgeneration (3) and superheating permit maximumprocess heat exploitation to achieve an optimizedenergy-efficient process.
The carbon monoxide (CO) shift occurs in a single-stage, adiabatic high-temperature reactor (4). Pressureswing adsorption (5) is a well-established purifica-tion step to obtain high-purity hydrogen (99.9 % andhigher).
The Uhde reformer design with the unique pro-prietary cold outlet manifold system enables con-struction and operation of world-scale reformers with
hydrogen capacities to 290,000 Nm3/h.
Economics: Typical consumption figures (feed andfuel) range between 150 and 175 GJ/metric ton ofhydrogen, depending on the individual plant con-cept.
Installations: Uhde has recently commissioned twoof the world’s largest hydrogen plants for SINCORC.A., Venezuela (2 x 98,000 Nm3/h) and Shell CanadaLtd., Canada (2 x 130,000 Nm3/h). More than 60 Uhdereformers have been constructed worldwide.
References: Larsen, J., Dr. M. Michel, J. Zschommler(Uhde), Dr. M. Whysall and Dr. S. Vanheertum (UOP),“Large-scale hydrogen plants, Uhde and UOP’s expe-rience,” AIChE 2003 Spring Meeting, New Orleans,March 30–April 3, 2003.
Fritsch, S., “Steam reformer based hydrogen plantoptimization,”The International Conference HYFO-RUM 2000, Munich, Germany, September 2000.
Hydrogen (Polybed PSA)Application: Production of any purity hydrogen,typically 90% to +99.9999 mole%. Impurities effi-ciently removed include: N2, CO, CH4, CO2, H2O, Ar, O2,C2–C8
+, CH3OH, NH3, H2S and organic sulfur com-pounds. The technology can also be used to: purifyCH4, CO2, He, N2 and Cl; remove CO2; adjust synthe-sis-gas stream composition ratios and separate nitro-gen from hydrocarbons.
Feed: Steam reformer (at any point after thereformer), catalytic reformer net gas, other refinerypurge streams, gasification offgases, ammonia plantpurge gases (before or after the NH3 waterwash),demethanizer or other ethylene plant offgases, par-tial oxidation gases, styrene plant offgases, methanolplant purge gases, coke-oven gas, cryogenic purifi-cation offgases or other H2 sources. Feed pressures upto 1,000 psig have been commercially demonstrated.
Product: Recovery of H2 varies between 60% and90%, depending on composition, pressure levels andproduct requirements. Typical temperatures are 60°Fto 120°F. Purity can be +99.9999 mole%.
Description: Purification is based on advanced pres-sure swing adsorption (PSA) technology. Purified H2is delivered at essentially feed pressure, and impuri-
ties are removed at a lower pressure. Polybed PSA units contain 4 to +16 adsorber vessels.
One or more vessels are on the adsorption step, whilethe others are in various stages of regeneration. Sin-gle-train Polybed PSA units can have product capac-ities over 200 million scfd.
All systems use advanced proprietary adsorbentsand patented void-gas recovery techniques to providemaximum product recovery. Other than entrainedliquid removal, no feed pretreatment is required. Inaddition, all impurities are removed in a single step,and purities exceeding 90% are obtained irrespective
of impurities. Many units presently produce streamswith less than one ppmv impurity from feed concen-trations of +40 mole%.
Operation is automatic with pushbutton startupand shutdown. After startup, the unit will produce H2in two to four hours. Onstream factors in excess of99.8% relative to unplanned shutdowns are typical.
Turndown capability is typically 50% but can beeven lower where required. The units are built com-pactly with plot plans ranging from 12 x 25 ft to 60 x120 ft. Units are skid-mounted and modular to min-imize installation costs. Material for piping and ves-sels is carbon steel. Control can be via a local orremote-mounted control panel or by integration intothe refinery’s computer control system. Units aredesigned for outdoor, unattended operation andrequire no utilities other than small quantities ofinstrument air and power for instrumentation.
Installations: More than 700 units are in operationor under construction, including the world’s first 16-bed system, and world’s largest single-train system.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Hydrogen
H2
Fuel
Feed
NN–121
Return to Gas Processes INDEX
Hydrogen (Polysep membrane)Application: Hydrogen recovery and purification orrejection from various refining, petrochemical andchemical process gas streams. Other examples are:synthesis gas ratio adjustment and carbon monoxide(CO) recovery.
Feed: Refinery streams include: catalytic reformeroffgas, hydrotreater and hydrocracker purge andfluid catalytic cracking offgas. Chemical and petro-chemical feed streams are: ethylene offgases, ammo-nia plant purges, methanol plant offgases, synthesisgas streams from steam reforming, partial oxidationor other gasification technologies.
Product: For typical hydrogen purification applica-tions, recovery varies between 70% and 95+% andpurity ranges from 70 to 99 mole%, depending onfeed composition, pressure levels and product require-ments.
Polysep membrane systems are also designed toproduce high-purity CO for petrochemical productssuch as polyurethanes and polycarbonates, and toratio adjust synthesis gas streams in methanol and oxo-alcohol plants. Also, a new application is hydrogenrecovery from IGCC power generation systems.
Description: The Polysep separation system is basedon state-of-the-art, composite, hollow-fiber polymermembrane technology. The hollow fibers are pack-aged in a proprietary countercurrent-flow bundleconfiguration that maximizes the separation drivingforce and minimizes required membrane area.
The Polysep separation is a pressure-driven process.It requires a minimum of moving parts, utilities andoperator attention. The systems are compact, shop-fab-ricated, modular units allowing reduced delivery sched-ules and simple inexpensive installation. Feed pre-treatment equipment typically includes: a knockoutdrum for bulk liquid removal, a coalescing filter for par-
ticulate and entrained liquid removal, and a preheaterto optimize the membranes’ performance.
Operation features include: automatic startup,capacity control, product-purity control, auto depres-surization and turnup/turndown. Turndown capabil-ity is typically 30% using a patented control strategy.Membrane system control is typically via integrationinto the refinery’s control system. Once installed, amembrane system can reach steadystate operationfrom cold startup in a few hours with onstream fac-tors over 99.8% relative to unplanned shutdowns.
Economics: Polysep membrane systems can be effi-ciently and economically scaled, from just a few mod-ules to over 100 modules, depending on the applica-tion. Membrane-separation systems have low capitalcosts and plot area, and offer a rapid return on invest-ment.
Installations: Over 50 units are in operation or underconstruction. Largest unit processes over 320 millionscfd of synthesis gas.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Hydrogen
1
2
N–1
N Nonpermeate
Hydrogen(permeate)
PretreatmentFeed
Return to Gas Processes INDEX
Hydrogen (steam reform)Application: Production of hydrogen for refineryhydrotreating and hydrocracking or other refinery,petrochemical, metallurgical, and food-processinguses.
Feedstock: Light hydrocarbons such as natural gas,refinery fuel gas, LPG/butane and light naphtha.
Product: High-purity hydrogen (99.9+%) at anyrequired pressure.
Description: The feed is heated in the feed preheaterand passed through the hydrotreater (1). Thehydrotreater converts sulfur compounds to H2S and sat-urates any unsaturated hydrocarbons in the feed. Thegas is then sent to the desulfurizers (2). These adsorbthe H2S from the gas. The desulfurizers are arrangedin series and designed so that the adsorbent can bechanged while the plant is running.
The desulfurized feed gas is mixed with steam andsuperheated in the feed preheat coil. The feed mix-ture then passes through catalyst-filled tubes in thereformer (3). In the presence of nickel catalyst, the feedreacts with steam to produce hydrogen and carbonoxides. Heat for the endothermic reforming reactionis provided by carefully controlled external firing inthe reformer.
Gas leaving the reformer is cooled by the process
steam generator (4). Gas is then fed to the shift con-verter (5), which contains a bed of copper promotediron-chromium catalyst. This converts CO and watervapor to additional H2 and CO2. Shift converter efflu-ent gas is cooled in a feed preheater, a BFW preheaterand a DA feed water preheater. Hot condensate isseparated out. Process gas is then cooled in a gas aircooler and a gas trim cooler. The cooled stream flowsto a cold condensate separator where the remainingcondensate is separated and the gas is sent to a PSAhydrogen purification system (6).
The PSA system is automatic, thus requiring minimaloperator attention. It operates on a repeated cycle
having two basic steps: adsorption and regeneration.PSA offgas is sent to the reformer, where it providesmost of the fuel requirement. Hydrogen from thePSA unit is sent off plot. A small hydrogen stream isthen split off and recycled to the front of the plant forhydrotreating.
The thermal efficiency of the plant is optimized byrecovery of heat from the reformer flue gas streamand from the reformer effluent process gas stream.This energy is utilized to preheat reformer feed gasand generate steam for reforming and export. Hot fluegas from the reformer is sent through the waste-heatrecovery convection section and is discharged by aninduced-draft fan to the stack.The boiler feed waterdeaerator and preheat circuits are integrated to maxi-mize heat recovery. A common steam drum serves thesteam generation coils and process steam generator forsteam production via natural circulation.
Installations: Over 170 plants worldwide-rangingin size from less than 1 million scfd to over 90 millionscfd capacities. Plant designs for capacities from 1million scfd to 280 million scfd.
Supplier: CB&I Howe Baker
Contact: Mr. Craig E. Wentworth, vice president ofsales, CB&I Howe-Baker, 3102 East Fifth St., Tyler, TX75701, Phone: (903) 595-7911, Fax: (903) 595-7751, E-mail: [email protected]
Gas Processes 2004 Hydrogen
5
2
3
4
6
Export gas
H2
Offgas toreformer fuel
Feed
Return to Gas Processes INDEX
Hydrogen (steam reform)Application: Hydrogen production from natural gas,refinery gas, associated gas, naphtha, LPG or any mix-ture of these. Appropriate purity product (up to99.999%) can be used in refinery upgrade processes,chemical production and metallurgy (direct reduc-tion). Possible byproducts are export steam or elec-tricity, depending on cost and/or efficiency opti-mization targets.
Description: The hydrocarbon feedstock is admixedwith some recycle hydrogen and preheated to350–380°C. Sulfur components are totally convertedto H2S at CoMo catalyst and then adsorbed on zincoxide by conversion to ZnS. The desulfurized feed ismixed with process steam at an optimized steam/car-bon ratio.
The desulfurized feed is mixed with process steamat an optimized steam/carbon ratio, superheated to500–650°C and fed to the Lurgi Reformer. Thefeed/steam mixture passing the reformer tubes isconverted at 800–900°C by presence of a nickel cata-lyst to a reformed gas containing H2, CO2, CO, CH4 andundecomposed steam. The reformed gas is cooled toapproximately 33°C in a reformed gas boiler.
The Lurgi Reformer is a top-fired reformer with alow number of burners and low heat losses, almostuniform wall temperature over the entire heated
tube length and low NOx formation by very accuratefuel and combustion air equipartition to the burners.
An adiabatic pre-reformer operating at an inlettemperature of 400–500°C (dependent on feedstock)may be inserted upstream of the feed superheater asa process option. Feedgas is partly converted to H2, COand CO2 with high-activity catalyst; all hydrocarbonsare totally converted to methane. The pre-reformerlimits steam export to maximize heat recovery fromthe process and increases feedstock flexibility.
The CO in the reformed gas is shift-converted withan iron-chromium catalyst, increasing hydrogen yield
and reducing CO content to below 3-vol.%. The shiftgas is cooled to 40°C and any process condensate isseparated and recycled to the process. The gas is thenrouted to the PSA unit, where pure hydrogen is sep-arated from the shift-gas stream. Offgas is used as fuelfor steam reforming.
Recovered waste heat from the reformed and fluegases generates steam, which is used as process steamwith the excess exported to battery limits.
Turndown rates of 30% or even less are achiev-able. The control concept allows fully automatic oper-ation with load changes typically 3% of full capac-ity/minute.
Economics: Consumption figures based on light nat-ural gas feedstock/1 millon scfd of H2:
Feed + fuel, million scfd 0.4Demineralized water, t 1.25 Cooling water, m3 3.0 Electricity, kWh 19 Export steam, t 0.7
Installations: More than 105 gas reforming plants,25 being hydrogen plants, with single-train capacitiesranging from 1 million scfd to 200 million scfd.
Hydrogen and liquid hydrocarbon recovery—cryogenicsApplication: Recover high purity hydrogen and C2
+
liquid products from refinery offgases.
Description: Cryogenic separation of refinery offgasesand purges containing from 10% to 80% hydrogen(H2) and 15% to 40% hydrocarbon liquids such asethylene, ethane, propylene, propane and butanes.Refinery offgases are optionally compressed and thenpretreated (1) to remove sulfur, carbon dioxide (CO2),H2O and other trace impurities. Treated feed is par-tially condensed in an integrated multi-passageexchanger system (2) against returning products andrefrigerant.
Separated liquids are sent to a demethanizer (3) forstabilization while hydrogen is concentrated (4) to90% to +95% purity by further cooling. Methane,other impurities, and unrecovered products are sentto fuel or optionally split into a synthetic natural gas(SNG) product and low-Btu fuel. Refrigeration is pro-vided by a closed-loop system (5). Mixed C2
+ liquidsfrom the demethanizer can be further fractionated (6)
into finished petrochemical feeds and products suchas ethane, ethylene, propane and propylene.
Operating conditions: Feed capacities from 10 to150+ million scfd. Feed pressures as low as 150 psig.Ethylene recoveries are greater than 95%, with higherrecoveries of ethane and heavier components. Hydro-gen recoveries are better than 95% recovery.
Economics: Hydrogen is economically co-producedwith liquid hydrocarbon products, especially ethy-lene and propylene, whose high value can subsidize
the capital investment. High hydrocarbon liquid prod-ucts recovery is achieved without the cost for feedcompression and subsequent feed expansion to fuelpressure. Power consumption is a function of hydro-carbon quantities in the feed and feed pressure. High-purity hydrogen is produced without the investmentfor a “back-end” PSA system. Project costs can haveless than a two-year simple payback.
Installations: Five operating refinery offgas cryo-genic systems processing FCC offgas, cat reformeroffgas, hydrotreater purge gas, coker offgas andrefinery fuel gas. Several process and refrigerationschemes employed since 1987 with the most recentplant startup in 2001.
Reference: US Patents 6,266,977 and 6,560,989.Trautmann, S. R. and R. A. Davis, “Refinery Off-
gases—Alternative Sources for Ethylene Recovery andIntegration,” AIChE Spring Meeting, New Orleans,LA, March 14, 2002, Paper 102d.
Hydrogen recovery (cryogenic)Application: Recovery of relatively pure hydrogenfrom refinery and petrochemical offgas streams suchas from thermal hydrodealkylation (THDA), catalyticreformers, hydrotreaters and fluid catalytic crackers.Cryogenic processing is the optimal route to producecarbon monoxide (CO) from syngas.
Products: 90% to 98% pure hydrogen. Valuableproduct streams, such as LPG, may also be recovered.
Description: A typical autorefrigerated cryogenicunit for recovery of hydrogen consists of two stagesof cooling and partial condensation. Suitably pre-treated feed gas is cooled and partially condensedagainst hydrogen product and fuel in the plate-finheat exchanger (1). The hydrocarbon rich conden-sate is separated in the two-phase separator (2) andthe vapor is further cooled and partially condensed inthe second plate-fin heat exchanger (3). The methane-rich condensate is separated in the second two-phaseseparator (4) giving relatively pure hydrogen product,which is reheated through both exchangers.
Autorefrigerated cryogenic units use refrigera-tion from Joule-Thomson expansion of the conden-sate streams and can generate hydrogen puritiesup to 96%.
Pretreatment ensures that the feed gas to the cryo-genic unit is dry and contains no components whichwould freeze in the cold section. Depending on thepretreatment scheme, additional products can be
obtained. Depending on feed gas conditions and hydrogen
product requirements, one, two or three stages of sep-aration may be optimal.
Operating conditions: Typical hydrogen recover-ies are 90% to 96%.
Economics: Cryogenic recovery of hydrogen is eco-nomically favored by the ability to recover other valu-able products, e.g., olefins and LPG. Compared withalternative technologies, cryogenic processing is themost efficient and has the lowest utilities cost. Cryo-genic recovery has been used to treat gases withhydrogen feed concentrations as high as 80% andpressures up to 80 barg.
Installations: Fourteen.
Reference: Allen, P., “Managing hydrogen recov-ery,” Hydrocarbon Engineering, April 1999, p. 71.
Licensor: Costain Oil, Gas & Process Ltd.
Contact: Adrian Finn, Technology Development Man-ager, Costain Oil, Gas & Process Ltd., Costain House,Styal Road, Manchester, UK, Phone: (44) 161 910 3227,Fax: (44) 161 910 3256, e-mail: [email protected]
Gas Processes 2004 Hydrogen
1
3
2
4
Hydrogen product
LP methane rich fuel gas
HP heavy fuel gas
Aromatics
Feedgas
Pretreatedfeed gasPre-
treatment
Return to Gas Processes INDEX
Hydrogen, HTCR based Application: Produce hydrogen (H2) from hydrocar-bon feedstocks such as: natural gas, LPG, naphtha,refinery offgases, etc., using the Haldor Topsøe Con-vective Reformer (HTCR). Plant capacities range from200 Nm3/h to 20,000 Nm3/h (200,000 scfd to 20MMscfd) and hydrogen purity ranges from 99.5% to99.999+% without steam export.
Description: The HTCR-based hydrogen plant canbe tailor-made to suit the customer’s needs withrespect to feedstock flexibility. In a typical plant, feed-stock is first desulfurized. Subsequently, process steamis added, and the mixture is fed to the HTCR. Processgases are reacted in a water-shift reactor and purifiedby pressure swing absorption (PSA) unit to obtainproduct-grade hydrogen. PSA offgases are used as fuelfor the HTCR. Excess heat is efficiently used for pro-cess heating and steam generation.
A unique technology feature is high thermal effi-
ciency. Product gas and flue gas are both cooled toabout 600°C (1,100°F) to recover heat for the reform-ing reaction. Energy-efficient hydrogen plants basedon the HTCR use high thermal efficiency and have nosteam export.
Economics: HTCR-based plants provide the customerwith a low-investment cost and low operatingexpenses. The plant can be supplied skid-mounted pro-viding a short erection time. The plants have high flex-ibility, reliability and safety. Fully automated opera-tion, startup and shutdown allow minimum operatorattendance. Net energy efficiency of about 3.4–3.6Gcal/1000 Nm3 is achieved depending on size andfeedstock (360–380 Btu/scf).
Installations: Twenty-one licensed units.
References: Dybkjær, I., et al., “Medium-size hydro-gen supply using the Topsøe convection reformer,”1997 NPRA Annual Meeting, March 16–18, 1997, SanAntonio.
Licensor: Haldor Topsøe A/S
Contact: Jørgen N. Gøl or Michael Agertoft,Nymollevej 55, DK-2800 Lyngby, Denmark, Phone:(45) 45 27 2000, Fax: (45) 45 27 29 99, E-mail: [email protected] or [email protected]
Gas Processes 2004 Hydrogen
Feed
Sulfur removal HTCR HT shift PSA
Combustionair
Fuel
BFW
Flue gasH2
Return to Gas Processes INDEX
Hydrogen, steam methanereform (SMR)Application: Produce hydrogen (H2) from hydrocar-bon feedstocks such as: natural gas, LPG, naphtha,refinery offgases, etc., using the Haldor Topsøe side-fired steam-methane reformer (SMR) process. Plantcapacities range from 5,000 Nm3/h to 200,000+ Nm3/h(4.5 MMscfd to 200+ MMscfd), and hydrogen purityranges from 99.5% to 99.999+%.
Description: The Haldor Topsøe SMR-based hydrogenplant can be tailor-made to suit the customer’s needswith respect to feedstock flexibility and steam export.In a typical low-steam export plant, the hydrocarbonfeedstock is desulfurized. Subsequently, process steamis added, and the mixture is fed to a pre-reformer. Fur-ther reforming is done in side-fired SMR. Processgases are reacted in a water-gas shift reactor andpurified by the pressure swing absorption (PSA) unitto obtain product-grade H2. PSA offgases are used as
fuel in the SMR. Excess heat in the plant is efficientlyused for process heating and steam generation.
The SMR operates at high outlet temperatures [toabout 950°C (1,740°F)] while the Topsøe reforming cat-alysts enable low steam-to-carbon ratios. Both con-
ditions (advanced steam reforming) are necessary forhigh-energy efficiency and low hydrogen productioncosts. This application of Topsøe’s reforming tech-nology is in operation in several industrial plantsworldwide.
Economics: The Advanced Steam Reforming condi-tions described can achieve a net energy efficiency aslow as about 2.96 Gcal/1,000 Nm3 hydrogen usingnatural gas feed (315 Btu/scf).
References: Gøl, J. N., et al., “Options for hydrogenproduction,” HTI Quarterly, Summer 1995.
Dybkjær, I. and S. W. Madsen, “Advanced reform-ing technologies for hydrogen production,” Hydro-carbon Engineering, December/January 1997/1998.
Rostrup-Nielsen, J. R. and T. Rostrup-Nielsen, “Largescale hydrogen production,” CatTech, Vol. 6, No. 4.
Hydrogen-methanol decompositionApplication: Produce hydrogen (H2) in the capacityrange of 100–1,000 Nm3/h of H2 for usage by thechemical industry and the manufacture of electronics.
Description: Feed methanol and water are mixed,evaporated and superheated before being sent tothe methanol decomposition reactor. In this reactor,the methanol is reacted to form H2, CO and CO2. Thereaction is endothermic and requires energy by heattransfer from externally heated oil or by steam.
The raw gas from the reactor is cooled, and the pro-cess condensate is separated. The separated gas isfurther purified by a pressure swing adsorption (PSA)unit; startup, operation and shutdown are automatic.
Features: Utility requirements per Nm3 of H2 are:
Methanol, kg 0.63Fuel, kcal 320Demineralized water, kg 0.37Electricity, kWh 0.06Additional utilities required Cooling water, instrument air and nitrogen
The hydrogen plant construction is compact and canbe skid-mounted.
Economics: Features include:• Low investment cost • Low operating costs • Low maintenance cost • Short delivery time• Fast installation of the skid-mounted unit.
Installations: Ten plants are in operation world-wide.
Hydrogen—PRISM membraneApplication: To recover and purify hydrogen or toreject hydrogen from refinery, petrochemical or gasprocessing streams. Refinery streams includehydrotreating or hydrocracking purge, catalyticreformer offgas, fluid catalytic cracker offgas or fuelgas. Petrochemical process streams include ammoniasynthesis purge, methanol synthesis purge or ethyleneoffgas. Synthesis gas includes those generated fromsteam reforming or partial oxidation.
Product: Typical hydrogen (H2) product purity is 90 to98% and, in some cases, 99.9%. Product purity isdependent upon feed purity, available differentialpartial pressure and desired H2 recovery level. TypicalH2 recovery is 80 to 95% or more.
The hydrocarbon-rich nonpermeate product isreturned at nearly the same pressure as the feed gasfor use as fuel gas, or in the case of synthesis gas appli-cations, as a carbon monoxide (CO) enriched feed tooxo-alcohol, organic acid, or Fisher-Tropsch synthesis.
Description: Typical PRISM membrane systems con-sist of a pretreatment (1) section to remove entrainedliquids and preheat feed before gas enters the mem-
brane separators (2). Various membrane separatorconfigurations are possible to optimize purity andrecovery, and operating and capital costs such asadding a second stage membrane separator (3). Pre-treatment options include water scrubbing to recoverammonia from ammonia synthesis purge stream.
Membrane separators are compact bundles of hol-low fibers contained in a coded pressure vessel. Thepressurized feed enters the vessel and flows on theoutside of the fibers (shell side). Hydrogen selectivelypermeates through the membrane to the inside of the
hollow fibers (tube side), which is at lower pressure.PRISM membrane separators’ key benefits includeresistance to water exposure, particulates and low feedto nonpermeate pressure drop.
Membrane systems consist of a pre-assembled skidunit with pressure vessels, interconnecting piping,and instrumentation and are factory tested for easeof installation and commissioning.
Economics: Economic benefits are derived fromhigh-product recoveries and purities, from high reli-ability and low capital cost. Additional benefits includerelative ease of operation with minimal maintenance.Also, systems are expandable and adaptable to chang-ing requirements.
Installations: Over 270 PRISM H2 membrane sys-tems have been commissioned or are in design. Thesesystems include over 54 systems in refinery applica-tions, 124 in ammonia synthesis purge and 30 in syn-thesis gas applications.
Hydrogen—PRISM PSAApplication: Purify hydrogen from dedicated H2-production equipment and a wide range of offgasstreams from refineries and hydrocarbon processingindustries (HPI) to produce 95–99.999+% H2 purity.
Feed: Wide range of H2-containing streams, typicallywith feed H2 greater than 50%, pressure from 70 psito 600 psi (5–40 bar), and temperature from 60°F to110°F. Examples of dedicated H2-production unitsinclude steam-methane reformers, naphtha-firedreformers and gasifiers. Hydrogen can be recoveredfrom ethylene, propylene, styrene, and coke ovenoffgases; and various refinery streams such as catreformer, hydrotreater/hydrocracker offgases.
Products: Hydrogen recovery is 83–90% for SMRapplications, with CO from 1 ppm to 50 ppm. Purityis typically 95–99.9% for offgas plants, with recov-ery dependent on operating conditions. Integratedprocesses producing multiple products are practiced.For example, gasifier or refinery offgas pressureswing absorption (PSA) can be integrated with cryo-genic processes for co-recovery of H2 with CO orhydrocarbons, respectively. PSAs are typically inte-grated with membranes in gasifier installations to co-produce high-purity H2 and a wide range of syngascompositions.
Description: PSA purifies H2 by sequentially adsorb-
ing impurities in multiple layers of adsorbents withina single PSA vessel. Adsorbent selection is critical,and is based on extensive R&D with verification fromfrequent plant performance tests. Hydrogen is pro-duced from vessel(s) in their feed step, while other ves-sels are regenerated.
The number of vessels depends on the system capac-ity and the desired H2 recovery. For example, 4-bed PSAtypically produces up to 15 million scfd H2. As capac-ity increases, it is generally economical to increase therecovery and number of beds. A 10-bed PSA unit canproduce over 120 million scfd H2 at up to 90% recov-ery. Single-train capacities exceed 200 million scfd.
The systems are skid-mounted, requiring minimalfieldwork. These PSAs include all control valves, switchvalves and instrumentation required. Feed, product,and tail gas monitoring, isolation, and venting systemscan be integrated into the skid design to further min-imize field piping associated with the PSA. The systemcan be controlled using any commercial PLC or DCSproducts. Average reliabilities exceed 99.9%.
Economics: PSA costs vary with capacity and recovery.When compared to the other hydrogen recovery tech-nologies (cryogenics and membranes), hydrogen PSAsfall in the medium-capital cost range and have mod-erate scaling economics. Using a PSA, H2 can typicallybe recovered for about 1.2-2X fuel value from offgasplants. When ultra-high-purity is required (e.g., ppm lev-els of CO, CO2 or other contaminants), PSA is typicallythe best technical and economic choice.
References: Sabram, T. M,. et al., “Integrate New andExisting Hydrogen Supplies,” World Refining, April2001, pp. 32–34.
Installations: Over 50 operating units, including theworld’s largest operating PSA installation.
MEDAL membrane (hydrogen)Application: Hydrogen recovery and purificationfrom refinery, petrochemical and ammonia plant gasstreams.
Feed: Refinery streams include hydroprocessing unitpurge streams, catalytic reformer offgas, fuel gasstreams and steam reformer (feed preparation/prod-uct purification). Petrochemical streams include: olefinplant process and recycle streams, polypropylene recy-cle streams, methanol plant purge, syngas streamsfrom steam reforming and gasification processes forhydrogen (H2 )/carbon monoxide (CO) ratio adjust-ment and/or process efficiency improvement.
Product: Hydrogen purity of 90–99% is typical ofmost applications. Hydrogen recovery range is from80% to 95+% depending on operating conditions andcustomer requirements. In refining applications, thehydrocarbon by-product, non-permeate streamleaves the unit at feed pressure with up to 99%recovery.
Description: Purification is based on polyaramideor polyimide hollow-fiber membrane modules withhigh resistance to typical hydrocarbon stream contam-inants. The hollow fibers are assembled in a patentedradial cross flow permeator module. Modules arecombined in pressure vessels to provide maximumsystem performance and to minimize space require-ments.
Hydrogen membrane systems typically include a
coalescing filter (1), a preheat exchanger (2) andmembrane separators (3). The membrane system’smodular nature allows for maximum flexibility in sys-tem capacity and permits future expansion.
Consistent H2 recovery and product purity can bemaintained through wide fluctuations in feed compo-sition, operating pressures and feed flow rates. Thesystems are skid-mounted for compactness, minimalinstallation costs and are designed for unattended out-door operation. A small amount of low-pressuresteam, instrument air and power for instrumenta-tion are the only utilities required.
Economics: MEDAL hydrogen membrane systemsare characterized by low capital and operating costs,and a high return on capital.
Installations: Over 100 installations are in opera-tion or under construction. MEDAL hydrogen mem-brane systems have been in operation since 1987.
Licensor: Air Liquide S.A. (MEDAL, L.P.)
Contact: David Marchese, Sales and MarketingManager, Phone: (302) 225-1100, E-mail: [email protected]
Gas Processes 2004 Hydrogen
Wastesteam
Feed
High-purityhydrogen
Hydrocarbon or inert reject(or desired H2 /CO ratio)
2
31
Return to Gas Processes INDEX
AMINEXApplication: Extract H2S, COS and CO2 from gases andlight liquid streams with amine solution using FIBER-FILM contactor technology.
Description: The amine phase flows along the FIBER-FILM contactor fibers, which are continuouslyrenewed, as the wet fibers are preferentially wettedby the amine phase in the AMINEX process. Hydro-carbons flow through the shroud parallel to theamine-wetted fibers where the H2S, COS, and/or CO2are extracted into the amine phase. The two phasesdisengage in the separator vessel where the richamine flows to the amine regeneration unit and thetreated gas or light liquids goes to storage.
Economics: FIBER-FILM contactor technology requiressmaller processing vessels allowing shorter separa-tion times and less waste generation. This saves plantspace and reduces capital expenditures.
Installations: Ten worldwide.
Reference: “Gas Processing Handbook,” HydrocarbonProcessing, April 1984, p. 87.
MERICAT IIApplication: Oxidize mercaptans to disulfides forgas condensates and natural gasoline with air, caus-tic and catalyst using FIBER-FILM contactor technology.This is followed by an upflow catalyst impregnated car-bon bed.
Description: The caustic phase flows along the FIBER-FILM contactor fibers, which is continuously renewed,as the fibers are preferentially wetted by the causticphase in the MERICAT II process. Hydrocarbon flowsthrough the shroud parallel to the caustic phasewhere mercaptans are extracted into the causticphase. It is converted to disulfides by air and catalystat the hydrocarbon-caustic interface. The two phasesdisengage and the hydrocarbon flows upwards
through a catalyst impregnated carbon bed where theremaining mercaptans are converted to disulfides.
Economics: FIBER-FILM contactor technology requiressmaller processing vessels allowing shorter separa-tion times and less waste generation. This saves plantspace and reduces capital expenditures.
THIOLEX/REGENApplication: Extract H2S, COS and mercaptans fromgases and light liquid streams, including gasoline,with caustic using FIBER-FILM contactor technology.It can also be used to hydrolize COS contained inLPG.
Description: The caustic phase flows along the FIBER-FILM contactor fibers, which is continuously renewed,as the wet fibers are preferentially wetted by thecaustic phase in the THIOLEX process. Hydrocarbonsflow through the shroud parallel to the caustic phasewhere the H2S and mercaptans are extracted intothe caustic phase. The two phases disengage and thecaustic flows to the REGEN system. The spent causticis regenerated using air and catalyst in the oxidizer for
reuse, which converts the extracted mercaptans todisulfides. The disulfides are removed from the caus-tic by a FIBER-FILM contactor solvent wash system.
Economics: FIBER-FILM contactor technology requiressmaller processing vessels, allowing shorter separationtimes and less waste generation. This saves plantspace and reduces capital expenditures.
Installations: Over 200 worldwide.
Reference: Oil & Gas Journal, Aug. 12, 1985, p. 78.
AET NGL recoveryApplication: The patented AET Process NGL Recov-ery Unit technology utilizes propane-refrigeration-based absorption to recover C2+ or C3+ NGLs fromnatural gas streams.
Description: The absorbed NGLs in the rich solventfrom the bottom of the NGL absorber column arefractionated in the solvent regenerator column,which separates NGLs overhead and lean solvent atthe bottom. After heat recuperation, the lean solventis presaturated with absorber overhead gases. Thechilled solvent flows into the top of the absorber col-umn. The separated gases from the presaturator sep-arator form the pipeline sales gas.
Operating conditions: Wide operating pressurerange: 200 to 1,200 psig feeds without inlet gas com-pression. Inexpensive metallurgy: Lowest tempera-ture, limited by C3 refrigeration, permits the use ofpredominantly carbon steel metallurgy. Feed pre-treatment: CO2 removal is not necessary, and glycolinjection for dehydration is adequate. The AET NGL
plant uses lighter (70 MW to 90 MW) lean oils. Formost applications, there are no solvent makeuprequirements.
Economics: Low capital and operating costs: The ini-tial and on-going costs are lower when flexibility forethane recovery or rejection is important. High ethanerecoveries: One pass ethane recovery typically exceeds
96+%. NGL component flexibility: Online switching,from 96+% C2 and 99+% C3 to <2% C2 and 98+% C3,with simple controls. Upgrading simple refrigerationplants: Add-on unit enhances propane recoveries,from typical 30–55% to 96+%, by processing coldseparator gases. Depending upon the economics ofethane recovery, the operation of the AET NGL plantcan be switched online from ethane plus recovery topropane plus recovery without affecting the propanerecovery levels.
Installations: Two units operating successfully.
References: Oil & Gas Journal, Vol. 95, No. 39,September 29, 1997, pp. 86–91.
“Upgrading Straight Refrigeration Plants for NGLEnhancement—A Follow-Up,” Gas Processors Associ-ation 77th Annual Convention, Dallas, Texas, March1998.
AET Process NRUApplication: The patented AET Process NitrogenRejection Unit utilizes noncryogenic absorption toseparate methane and heavier hydrocarbons fromnitrogen containing natural gases. If desired, propaneplus NGL product can also be produced.
Description: The absorbed methane and heavierhydrocarbons are flashed off from the solvent byreducing the pressure of the absorber bottoms streamin multiple steps to minimize gas compression. Theseparated gases leave as the sales gas product. The liq-uid from the proven, heatless flash regeneration stepis returned to the top of the methane absorber as leansolvent. If helium is present, the overhead streamfrom the methane absorber is further processed in amembrane/PSA unit to produce Grade A helium, andnitrogen product is available at high pressure. Formost applications, there are no solvent make-uprequirements.
Operating conditions: Wide operating pressurerange: 240 psig to 1,200 psig feeds without inlet gascompression. Low pressure drop for N2: 15–30 psi is
typical and suitable for noncryogenic helium produc-tion and N2 reinjection. Inexpensive metallurgy: Low-est temperature, limited by C3 refrigeration, permitsuse of predominantly carbon steel metallurgy. Feedpretreatment: CO2 removal is not necessary; glycolinjection for dehydration is adequate.
Economics: Low, capital operating costs: When highflexibility for inlet gas flow and composition is desired,
the initial and ongoing costs are lower. High methanerecoveries: One pass methane recovery typicallyexceeds 98+%. Low nitrogen content sales gas: Salesgas product at <2 mol% N2. Wide feedstock flexibil-ity: For constant inlet gas flow, inlet composition canvary between 15 mol% and 50 mol% N2 withoutimpacting sales gas. Short construction schedule:Excluding the compressor and membrane/PSA deliv-ery, expected to be 4–8 months based on unit capac-ity.
Installations: Two commercial.
References: “Noncryogenic N2-rejection processgets Hugoton field test,” Oil & Gas Journal, May24, 1993.
Gas Research Institute Topical Report GRI-93/0448,“Field Test Performance Evaluation of the Mehra pro-cess for Nitrogen Rejection from Natural Gas,” Febru-ary 1994. US Patent Nos. 4,623,371; 4,680,042;4,832,718; 4,883,514; 5,224,350; 5,462,583; 5,551,972.
CO2 recovery and purificationApplication: Purification and liquefaction of car-bon dioxide (CO2) from process gases to remove smalltraces of light hydrocarbons, e.g., amine stripper off-gases. Purification of natural gas containing high lev-els of CO2 and separation of ethane/CO2, via a hybridmembrane/cryogenic process.
Products: Carbon dioxide of purities up to 99.998%.Gaseous CO2 for use in applications such as enhancedoil recovery (EOR).
Description: Impure CO2-rich feed (typically 90% +CO2) is compressed and cooled to remove water (1).The gas is dried by molecular sieve driers (2) beforeentering the low-temperature section, where the gasis used to reboil the distillation column (3) beforeentering the column. The condenser is usually a refluxexchanger. Vapor rising through the exchanger pas-sages is cooled, and the resulting liquid flows backdown the same passages and has intimate contact withthe rising vapor. The cold reflux to the column is pro-vided by an external refrigeration cycle (4), typicallyammonia evaporating at –28°C. The bottoms product
from the column is pure liquid CO2.For recovery from lean-CO2 streams, a hybrid mem-
brane/cryogenic process can produce pure CO2. Typ-ically, the membrane concentrates the CO2 contentfrom 30% to 90%. The concentrated stream passes toa low-temperature unit for further purification. Thismethod enables ethane/CO2 mixtures to be separatedto pure products without multiple distillation columns.
For recovery from rich-CO2 streams, enhanced recov-ery can be achieved with a membrane to process the
distillation column overheads and recycling of theCO2-rich permeate into the cryogenic process.
Operating conditions: Plants from 5-tpd to 1,200-tpd pure CO2. Virtually any feed-gas pressure can behandled. Compression is required for feed-gas pres-sures below 14 barg.
Economics: Typical power requirements for a cryo-genic plant with a feed-gas at atmospheric pressureand producing liquid CO2 are 0.15 kWh/kg.
Installations: Seven.
References: Limb, D. I., “The purification and lique-faction of carbon dioxide-rich vent streams contain-ing light hydrocarbons,” AIChE 1985 Spring NationalMeeting.
Duckett, M., “Recovery of carbon dioxide from gasmixtures,” UK Patent No. 2151597.
Duckett, M. and D. I. Limb, “Process for recoveringcarbon dioxide,” US Patent No. 4639257.
Licensor: Costain Oil, Gas & Process Ltd.
Contact: Adrian Finn, Technology Development Man-ager, Costain Oil, Gas & Process Ltd., Costain House,Styal Road, Manchester, UK, Phone: (44) 161 910 3227,Fax: (44) 161 910 3256, e-mail: [email protected]
Gas Processes 2004 NGL and LNG
3
H2O
Waste gas
2
4
1
CO2 product
Chiller
Feedgas
Return to Gas Processes INDEX
CRYOMAX DCP (dual-column propanerecovery)Application: A cryogenic process for gas fractiona-tion to recover C3
+ hydrocarbons from natural gas.With this process, more than 98% propane is extractedfrom natural gas. High efficiencies are achieved witha dual-column system associated with a turbo-expander. Multi-stream plate-fin exchangers increaseefficient heat integration.
Description: The high-pressure dry feed gas at 25°C,70 bars is cooled to –30°C in E1 and enters V1 whereliquid and gas are separated. The cold high-pressuregas is expanded to 30 bars in expander T1, and theresulting stream feeds the purifier C1.
Liquid from V1 is sent to the purifier bottom. Theliquid from the purifier is pumped to 33 bars and is
reheated to 20°C to feed the deethanizer. The deeth-anizer C2 produces a vapor distillate that is ethane-rich. This stream is liquefied in E1 and sent to C1 asreflux. The treated gas at 30 bars is reheated andcompressed to sales-gas pressure. Approximately99.5% propane recovery can be reached whenpropane value is high.
Economics: Propane production cost is approxi-mately 20% less than that for a conventional process.
Contact: La Defense 12, 9273 Paris La Defense Cedex,France; E-mail: [email protected]
Gas Processes 2004 NGL and LNG
R
Sales gas
Recycle
Feedgas
E1
NGL (C3+)
C2C1
P1
V1
T1 K1
Return to Gas Processes INDEX
CRYOMAX MRE (multiplereflux ethane recovery)Application: A cryogenic process for gas fractiona-tion to recover C2
+ hydrocarbons from natural gas.With this process, more than 95% of the ethane canbe extracted from natural gas. High efficiencies areobtained through a multiple reflux concept associatedwith a turbo-expander. Multi-stream plate-fin heatexchangers increase efficient heat integration of theprocess.
Description: The high-pressure, dry feed gas at 25°C,70 bars is cooled to –40°C in E1 and enters V1 wherethe liquid and gas are separated. The cold high-pres-sure gas is divided in two streams—the main cut(85%) is sent to the expander and to the demethanizerC1 that operates at 30 bars. The small segment (15%)is liquefied and sent as second reflux to C1.
The liquid pressure is reduced to 50 bars, and theliquid is partially vaporized in E1. Liquid and vapor areseparated in V2. The vapor is liquefied in E2, used as
third reflux and liquid is sent to C1.The demethanizer overhead is reheated and com-
pressed to sales gas pipeline specifications. A por-tion of the stream (10%) is recycled, cooled, liquefiedand sent as first reflux. Approximately 99% ethanerecovery can be reached when CO2 content of feed gasis low.
Economics: Ethane production cost is 20% less thanfor a conventional process.
Installations: Locations include: France, US,Venezuela, Mexico and Qatar.
Reference: US patents 4 689 063, 5 566 554 and 6 578379B2.
Licensor: Technip
Contact: La Defense 12, 9273 Paris La Defense Cedex,France; E-mail: [email protected]
Gas Processes 2004 NGL and LNG
E1
R
V1V2
E2
RecycleSales gas
NGL (C2+)
C1
K1 K2T1
Feed gas
Return to Gas Processes INDEX
Fluor Cryo-Gas processApplication: The Fluor Cryo-Gas process for naturalgas liquids (NGL) recovery is a complete portfolio ofpatented or patent pending turbo-expander-basedNGL recovery processes. It is tailored to meet a widevariety of feed gases and NGL recovery requirements.
Description: The Cryo-Gas process presented in thediagram is the vapor reflux absorption process (VRAP).VRAP is a two column process that can achieve 99.9%propane recovery without external refrigeration. Itfeatures low capital cost, weight and footprint and haslow energy and utility requirements.
Four additional Fluor Cryo-Gas process schemes are:Fluor’s patent pending two columns, high-pressure
absorber process (TCHAP) is the most energy effi-cient NGL recovery process for feed gas pressuresexceeding 1,000 psig. TCHAP achieves up to 85%ethane recovery with propane recovery in excess of99%. Alternately, the process can achieve propanerecoveries exceeding 99% while rejecting ethane. Itis resistant to carbon dioxide (CO2) freezing andrequires 30% less residue gas compression hp than
competing processes. TCHAP can produce productquality ethane with <500 ppmv CO2 without treating.
The stabilizer expander process (STEP) is specificallydesigned for rich feed gases that also vary in com-position over time. STEP is capable of 88% ethanerecovery with 97% propane recovery. It also has a highC2 and C3 recovery under a wide variation of feed gascompositions.
The twin-reflux absorption process (TRAP) achievesgreater than 90% ethane recovery with more than
99% propane recovery. It is ideal for revamping exist-ing NGL plants. The process can completely rejectethane without loss in propane recovery. TRAP can alsobe used for ethane recovery at feed pressures as lowas 300 psig. When used in an existing plant retrofit,TRAP usually does not require re-wheeling the exist-ing turbo-expander.
The subcooled absorption reflux process (SARP) isdesigned for rich feed gases with a high CO2 content.SARP can achieve ethane recoveries exceeding 90%with propane recoveries of more than 99%. SARPminimizes CO2 removal requirements and freezingproblems while maintaining ethane recovery exceed-ing 90%.
Installations: More than 50 turbo-expander plantsdesigns with single train capacities as high as 2,500 mil-lion scfd
References: US Patent 6,601,406 (VRAP).
Licensor: Fluor Enterprises, Inc.
Contact: Dick Nielsen, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349- 2000, Fax: (949) 349-2585, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
Feed gas
C3 + NGL
Deethanizer
Absorber
Dehydration
Coreexchanger
Expander/compressor Residue gas
compressor
Pipeline gas
Return to Gas Processes INDEX
Fluor LNG utilization technology 1 (FLUT 1)Application: Liquefied natural gas (LNG) often hasa higher heating value and is richer in heavier hydro-carbons than is permitted by typical natural gaspipeline specifications. The FLUT 1 regasification con-figuration, for which patents are pending, processesa wide range of LNG compositions to produce natu-ral gas meeting pipeline standards. Thus, allowingimporters to purchase LNG from the most economi-cal source. Electric power, LPG, and LNG and CNGvehicle fuels can be produced.
Description: LNG from storage is pressurized by LNGpump P1 to about 500 psig. Approximately 50% of thisLNG is sent to the demethanizer (V1) as reflux. LNGpower cycle pump P2, pressurizes the remaining LNG.This high-pressure LNG is used as a working fluid torecover low level heat from the power plant flue gas.
High-pressure LNG from P2 is heated in two heatexchangers, E1 and E2. The reflux condenser E1 in thedeethanizer (V2) overhead increases the LNG tem-perature to –190°F. Using LNG to satisfy the fraction-ation process refrigeration requirement eliminates a
costly propane refrigeration system. LNG leaving the reflux condenser is heated to 300°F
and vaporized in glycol-water exchanger E2, usingwaste heat from the power plant flue gas. A glycol-water heat medium is used to transfer heat betweenthe power block and the LNG regasification facility.This indirect heat exchange system isolates the LNGfrom direct heat exchange with the power block. Abackup heat source can use this heat transfer fluid to
vaporize the LNG if the power plant is not in opera-tion. Possible backup heat sources include a firedheater or duct firing of the waste heat recovery units.Hot LNG vapor is then expanded in EP1 to producepower. The low temperature of the LNG workingfluid results in a highly efficient power cycle.
The process can recover up to 99% of the propaneand over 90% of the ethane in LNG. For a 1.2 billionscfd integrated LNG regasification power plant facil-ity, the total power produced is 541 MW vs. 474 MWfor a non-integrated power plant. 37,700 bpd ofethane, 51,200 bpd of LPG, and 1,070 million scfd of999 Btu/scf HHV pipeline gas are also produced.
Fluor also has a process option, FLUT 2, that pro-duces low cost vehicle grade LNG and CNG alongwith additional power.
References: Mak, J., D. Nielsen, D. Schulte, and C. Gra-ham, “A new and flexible LNG regasification plant,”Hydrocarbon Engineering, October 2003.
Licensor: Fluor Enterprises, Inc.
Contact: Dick Nielsen, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-2000, Fax: (949)349-2585, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
LPG
V1 V2
E1
Ethaneexport
Ethanefor gasturbine
fuel
LNG fromstorage tank
Pipeline gas
EP1
P2
P1
E2
CWFluegas
Gas turbineinlet air
Combined cycle power plant
P3Glycol
Return to Gas Processes INDEX
Gas-to-liquids (GTLs)Application: To produce ultra-clean, synthetic fuelsfrom natural gas. The fuels, diesel, kerosene, naphthaand LPG contain no sulfur, aromatics or heavy metals.This process can be designed for onshore or offshoreapplications. Furthermore, it is self-sufficient in util-ities and can be configured to export electricity.
Description: The distinguishing characteristic of Syn-troleum’s Fischer-Tropsch (FT) process is using air toproduce synthesis gas. Air, natural gas and steam aremixed and react in a proprietary auto-thermalreformer (ATR) to produce synthesis gas with a H2:COratio of approximately 2:1. The synthesis gas is com-pressed and sent to the FT reactors. Using a proprietarycobalt catalyst, the carbon monoxide (CO) is hydro-genated into paraffinic, synthetic hydrocarbons. Thecatalysts yield an Anderson-Shultz-Fluory distributionwith an alpha between 0.88 and 0.94, depending onthe formulation.
Unreacted synthesis gas from the FT reactors is used
as process fuel for turbines, heaters and other equip-ment. Both the ATR and the FT reactions generatebyproduct heat and water, which are recovered andreused within the process.
The streams of synthetic crude are combined andrefined into ultra-clean diesel, kerosene, naphthaand LPG. Compared to conventional crude oil, refin-ing FT crude is less severe, i.e., lower H2 consumption,
lower temperature and pressure, and longer catalystlife, due to the absence of sulfur, aromatics and heavymetals.
Operating conditions: Approximately 10,000 scf ofgas produces one barrel of product. Plants can beeconomically designed for gas feedrates from 25 mil-lion scfd to 1,000 million scfd or more.
Economics: With the Syntroleum process, air is usedin place of pure oxygen from an air-separation unit.Using air combined with the high-activity catalysttechnology, this process can offer considerable capi-tal and operating cost savings as compared to othercompeting processes.
Reference: Patent 6,265,453
Licensor: Syntroleum Corp.
Contact: Ken Roberts, Senior Vice President, BusinessDevelopment, 4322 S 49th W. Ave., Tulsa, OK 74107,Phone: 918-592-7900, Fax: 918-592-7979, Email:[email protected]
Gas Processes 2004 Synthesis gas
LPG
Naphtha
Kerosene/jet
Diesel
Aircompression
Gastreating
Air
Naturalgas
Steam
Fischer-Tropschreactors
Syngasproduction
(ATR)
Productupgrading
Return to Gas Processes INDEX
High-Pressure Absorber—HPAApplication: Ethane, propane and heavier hydro-carbons recovery from natural gas feed streams usinga cryogenic turboexpander process. High propanerecovery (>99%) is achievable. Residue compression isminimized by using a high-pressure absorber (HPA).
Description: Raw feed gas is treated to removeimpurities such as water that would prevent cryo-genic processing. Clean, dry and treated feed gas (1)is cooled against cold process streams and sent tothe warm separator (2) for phase separation. Liquidfrom the separator is preheated against warmerstreams and sent to the deethanizer (3) as bottomfeed. Vapor leaving the warm separator is sent to aturboexpander (4) for isentropic expansion.
The two-phase stream exiting the expander is sentas bottom feed to a high-pressure absorber (5). Liq-uid exiting the absorber bottom is preheated againstwarm process streams and sent to the deethanizer as
top feed. The deethanizer produces C3+ liquid at the
bottom and a C2 top stream. The tower is generallyprovided with an external heat source for bottomreboiling.
Vapor from the tower top is partially condensed andsent to a reflux accumulator (6). Liquid is pumped asreflux, while vapor leaving the accumulator is com-
pressed (7), cooled, partially condensed and sent to theabsorber as top feed. The HPA process can also be usedto recover ethane and heavier components. Ninetypercent ethane recovery is achievable.
Operating conditions: This is very efficient whenfeed is available at high pressure. The absorber col-umn is run at a high-pressure to minimize residue com-pression, while the deethanizer is run at a lower pres-sure to keep the tower from critical conditions. Dueto this decoupling, the scheme is easily able to processa range of feed gas pressures while minimizing residuecompression and maintaining stable deethanizeroperation. Tower pressure decoupling in the ethanerecovery mode, and running the absorber at a higherpressure than the demethanizer, has similar savings inresidue compression as with propane recovery.
Licensor: Randall Gas Technologies, ABB LummusGlobal Inc., US Patent Pending
LiquefinApplication: Natural gas liquefaction (LNG) process.
Description: Liquefin process—Dry natural gas (A)enters the liquefaction train’s pre-cooling section (1)where it is cooled between –50°C and –80°C (–60°F and–110°F). The heat is exchanged with a mixed refrig-erant in a bank of brazed aluminum plate-fin heatexchangers (PFHEs). The cooled feed stream is thensent outside the liquefaction train to fractionator (2)for condensate removal. The gas returns to the cryo-genic exchanger and enters the cryogenic section (3)where it is liquefied by heat exchange in compact,energy-efficient PFHEs with a second mixed refriger-ant and leaves the cryogenic exchanger as LNG (B).
Pre-cooling refrigerant system (4)—Using mixedrefrigerant reduces the feed-gas temperature to amuch lower level than can be achieved with propanerefrigerant. This allows the pre-cooling power require-ment to be balanced with that of the cryogenic sec-tion so that two identical drivers (5) operating atoptimum efficiency can be used, thus lowering invest-ment, maintenance and operating costs.
Cryogenic refrigeration system (6)—The mixedrefrigerant gas entering the pre-cooling section is
completely condensed by the time it leaves the cryo-genic section without using separation equipment.After leaving the cryogenic section, the refrigerant isexpanded (7) and re-enters the cryogenic sectionwhere the process gas and cryogenic refrigerant arecondensed.
Using two mixed-refrigerant systems and modularPFHEs in a large single train has lower investment andoperating costs than systems involving single-com-ponent refrigerants or multiple cooling trains feedinga common liquefaction exchanger. Because the pre-
cooling and liquefaction sections comprise severalparallel modules, single trains of any size—e.g., 8million tpy—can be built. Proven extensively, thePFHEs are available from several vendors, which hasa very positive effect on price and delivery time.
Economics: Detailed studies by internationalpetroleum and E&C companies comparing conven-tional 4.5 to 8 MMtpy propane-plus-mixed refrigerantliquefaction trains with Liquefin LNG installationshave shown a 15–20% specific investment cost advan-tage for the LIQUEFIN train.
References: Fischer, B. and P. Boutelant, “A new LNGProcess is now available,” Gas Producers Association,London, February 2002.
Fischer, B. and M. Khakoo, “Platefin heat exchang-ers—an ideal platform for LNG process innovation,”Gastech 2002.
LNG Dual Expander CycleApplication: LNG production for either offshore oronshore
Description: Pretreated and dehydrated natural gas(1) is cooled in cold box (2) and then expanded to lowpressure via an expansion valve or liquid expander (3)and sent to storage as LNG. Refrigeration for lique-faction is obtained by continuous expansion of gasesthrough two independent cycles, one using methane(4) [mostly the same gas being liquefied] and the sec-ond with nitrogen (5). The methane cycle works in thewarmer end; while nitrogen provides refrigeration onthe cold end.
When superimposed, these two cycles act like abinary system. This process is a unique candidate foroffshore opportunities due to the refrigerants always
being in a gas phase. A propane pre-cooling step canbe added at the process’s front end (6), to achieve ahigh-efficiency process for onshore base load pro-duction.
Operating conditions: Feed gas should be above 800psig. For associated gases, LPG and condensate recov-ery is integrated with the same process. LNG is pro-duced at –260°F.
Efficiency: Depending on gas composition, energyconsumption varies between 11–16 kW/ton LNG/day.
Licensor: Randall Gas Technologies, ABB LummusGlobal Inc., US Patent 6,412,302
LNG end flash MLP (maxiLNG production)Application: A process to increase capacity of LNGplants and minimize fuel gas production.
Description: LNG from the main cryogenic heatexchanger at –140°C, 40 bar is expanded in T1 turbineto produce electric power. It is mixed with liquefiedfuel gas recycle before entering the LNG flash drumV1 at 1.2 bars. The LNG is pumped to storage tankthrough P1.
Cold flash gas is reheated to –30°C and compressedto 30 bar, thus producing fuel gas for gas turbines inK1. Part of the fuel gas is further compressed to 40 barsin K2. A portion of this stream is cooled to –80ºC in
E1, expanded to 8 bars at 130ºC in T2. It is thenreheated to 30ºC and sent to the fuel gas compressoras a side stream. The second stream portion is lique-fied and subcooled in E1 down to –155ºC.
Economics: Additional LNG production investmentof about $60/tpy for additional LNG.
Installations: None with turbo-expander T2/K2.
Reference: US patent application and LNG 13 con-ference, Seoul, paper PS2-1.
Licensor: Technip
Contact: La Defense 12, 9273 Paris La Defense Cedex,France; E-mail: [email protected]
Gas Processes 2004 NGL and LNG
K1
V1
E1
K2T2
T1
M
M
Fuelgas
Recycle
LNG fromMCHE
LNG to storage
Return to Gas Processes INDEX
LNG plantsApplication: Liquefaction of natural gas for plantcapacities ranging from small peak shaving applica-tions, up to mid-size plants (4,000 tpd, 1.4 milliontpa) using a mixed refrigerant cycle.
Products: Liquefied natural gas (LNG) at atmosphericpressure. Natural gas liquids (NGL) on larger facilities.
Description: Pretreated natural gas is cooled and con-densed by a multi-stage mixed-refrigerant cycle. Therefrigerant consists of a blend of nitrogen and hydro-carbons from methane through pentane.
The refrigerant is compressed by a two-stagemachine (1) (normally a gas turbine-driven centrifu-gal type depending upon plant capacity). The high-pressure mixed refrigerant is cooled (2) in the mainexchanger (3), which normally consists of multiple,brazed aluminum plate-fin heat exchangers, againstreturning low-pressure mixed refrigerant (4). Thesubcooled refrigerant is then let down in pressure andevaporated to provide cooling. Liquids from refrig-erant compression are cooled separately (5) in themain exchanger, let down in pressure and evapo-rated to provide increased process efficiency.
The natural gas is cooled (6) in the main exchangerprior to entering a hydrocarbon knockout pot (7) toremove components which would otherwise freeze in
the downstream process. On large plants, the knock-out pot may be replaced by a demethanizer column.NGLs recovered at this stage may be processed andused to provide refrigerant makeup. The natural gasleaving the knockout pot re-enters (8) the mainexchanger and is condensed and subcooled againstlow-pressure refrigerant.
The subcooled LNG then enters a two-stage flash sys-tem (9) where it is let down in pressure before beingpumped to storage at near atmospheric pressure.The LNG flash gas is fed to a flash gas compressor sys-tem to be used as fuel.
Economics: The mixed refrigerant cycle is often themost cost-effective process for LNG production, com-bining reasonable initial cost with low power require-ments. The use of plate-fin heat exchangers allowsthe plant to be designed with high efficiency. For a 1.4million tpy-facility, a total installed cost of $300 pertpy is feasible.
For small (peak-shaving) installations, expandercycles using nitrogen or methane may be cost-effec-tive. Expander cycles can also be the technology ofchoice for offshore applications. For high efficiency onbase-load installations, the cascade cycle, which usesmultiple levels of pure refrigerants, can be the opti-mum choice.
Installations: Fifteen total, in partnership (six mixedrefrigerant, nine expander plants).
Reference: Finn, A. J., G. L. Johnson and T. R. Tom-linson, “Developments in natural gas liquefaction,”Hydrocarbon Processing, April 1999, pp. 47–59.
European patent No. 0090108.
Licensor: Costain Oil, Gas & Process Ltd.
Contact: Adrian Finn, Technology Development Man-ager, Costain Oil, Gas & Process Ltd., Costain House,Styal Road, Manchester, UK, Phone: (44) 161 910 3227,Fax: (44) 161 910 3256, e-mail: [email protected]
Gas Processes 2004 NGL and LNG
1
NGLs
Pretreatednaturalgas feed
Flash gas tocompression
5
3
82
4
6
LNGproduct to
storage
9
Return to Gas Processes INDEX
LNG-ProApplication: To produce liquefied natural gas fortransportation or storage. The process is adequate forbase-load facilities, as well as for peak shaving units.The design is highly modularized, making it appropri-ate for remote sites or offshore applications. It is alsoa viable option to monetize stranded gas reserves.
Description: This process uses a hybrid technicalapproach for the liquefaction of natural gas. Specif-ically, it is a propane pre-cooled turbo-expander cycle.After being treated to remove contaminants andwater that will affect the cryogenic process conditions,the feed gas is liquefied in a cold box. A side streamof the inlet gas is expanded to low pressure to gen-erate refrigeration. The expanded gas is then sent tothe cold box to supply refrigeration, and is boostedto a medium-pressure level. It is then recycled to thefront end of the plant. The liquefied gas stream isexpanded in a flash vessel or series of flash vessels,depending on product specifications. The liquid prod-uct is LNG, which is sent to storage. The flashed gasis sent back to provide refrigeration, and is then recy-
cled to the front end of unit via recycle compression.This recycle stream becomes a supplementary refrig-eration stream.
This process scheme achieves energy consumptioncomparable with the world-class base load facilities.Energy usage is within 0.19 to 0.25 hp/lb of LNG prod-uct depending on gas sources and compositions.
Operating conditions: Ample range of pressures,temperatures and compositions. Depending on the
inlet gas pressure, an inlet gas compressor could berequired, but its influence is minor on energy con-sumption.
LPG recoveryApplication: Recovery of propane and heavier com-ponents from various refinery offgas streams andfrom low-pressure associated natural gas. Propanerecovery levels approaching 100% are typical.
Description: Low-pressure hydrocarbon gas is com-pressed and dried before being chilled by cross-exchange and propane refrigerant. The chilled feedstream is then contacted with a recycled liquid ethanestream in the propane absorber. The absorber bottomsis pumped to the deethanizer, which operates athigher pressure than the absorber. The tower over-head is condensed with propane refrigerant to forma reflux stream composed primarily of ethane. A slipstream of the reflux is withdrawn and recycled back
to the propane absorber. The deethanizer bottomsstream contains the valuable propane and heaviercomponents which may be further processed asrequired by conventional fractionation.
Economics: Compared to other popular LPG recov-ery processes, PRO-MAX typically requires 10–25%less refrigeration horsepower.
Installation: First unit under construction for Pertam-ina.
Reference: US Patent 6,405,561 issued June 18, 2002.
Licensor: Black & Veatch Pritchard, Inc.
Contact: Robert Mortko, 11401 Lamar, OverlandPark, KS 66211 USA, Phone: (913) 458-6058, Fax:(913) 458-6098, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
Feed gas fromdehydration Propane
absorber
DeethanizerC3+
Sales gas/fuel gas
Return to Gas Processes INDEX
Natural gas sweetening—MEDAL membrane (CO2removal)Application: Selectively removing carbon dioxide(CO2) and water (H2O) vapor from raw natural gas orassociated gas to meet pipeline specifications forboth onshore and off-shore locations. Upgrade lowBtu gas (e.g., landfill gas) for fuel. Debottleneck exist-ing solvent based CO2 removal systems. Recover valu-able hydrocarbons from enhanced oil recovery floodsfor CO2 reinjection.
Product: Purified natural gas, predominantlymethane, meeting pipeline specifications; high Btufuel gas; high-purity CO2 for reinjection.
Description: MEDAL natural gas membrane modulesare made up of millions of hollow-fiber membrane fil-aments. The hollow fibers are assembled in a patentedradial cross-flow permeator. Modules are combined inpressure vessels to provide maximum system perfor-mance and to minimize space requirements.
The feed stream (from which CO2 needs to beremoved) passes over the membrane module feedchamber at high pressure. Carbon dioxide, H2O vaporand hydrogen sulfide (H2S) pass through the mem-brane from the high-pressure chamber to the low-pressure chamber (the permeate). Methane, ethane,nitrogen and other hydrocarbons are enriched intohigh-pressure residual gas.
Typically, a two-stage design is used to limit thehydrocarbon losses to less than 1%. In a single stage,between 2% and 5% losses are typical. Typical feedrates vary from less than 1 million scfd to as high as1,000 million scfd with CO2 content varying between3% and 70%. Typical feed pressure varies between 100to 1,500 psig.
MEDAL natural gas membrane units are simple tooperate and have no moving parts, thereby requiringminimum maintenance. Additionally, the membraneunits are modular, enabling easy expansion—mak-ing them the ideal choice for remote locations.
Economics: Typical processing cost for CO2 removalusing MEDAL natural gas membranes varies between$0.05 and $0.15 per 1,000 scf of feed gas dependingon feed composition, temperature and pressure.
Installations: Several references processing up to300 million scfd of natural gas.
Licensor: Air Liquide S.A. (MEDAL, L.P.)
Contact: Charlie Anderson, Director of CO2 Activity,Phone: (302) 225-1100, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
Feedgas
Hydrocarboncondensate
Membranefeed
Sales gas
Permeate gas
Pret
reat
men
t
Membranestage 1
Membranestage 2
Return to Gas Processes INDEX
NGL from LNGApplication: Natural gas liquids (NGL) separationfrom liquefied natural gas (LNG) for Btu control of LNGand for enhanced product value. Primary applicationis for LNG import terminals.
Product: NGL stream containing ethane and heavierhydrocarbons. Can be used to produce light (ethaneplus), medium (propane plus) or heavy (butane plus)product stream as desired for a specific project.
Description: LNG is fed from storage to the processunit. Liquid feed pressure is increased with the feedpump (1) to proper pressure. Feed is then warmed inthe main exchanger (2) against cold gas. The warmedfeed stream is flashed (3) to separate the liquid andvapor. Liquid is pumped (4) to a demethanizer (5)where the NGL is separated. The vapor from thisdemethanizer joins the flash vapor which has beencompressed (6). This stream is recondensed (2) to
become LNG product which is pumped to sales pres-sure and sent to LNG vaporizers.
Internal operating parameter adjustments in theprocess unit allows the NGL stream recovery to fit agiven application. Varying these parameters allows
production of light or heavy NGL streams. A widerange of LNG feedstocks can be fed to a process unitand have the NGL successfully removed. Ethane recov-eries of 90% are possible as well as near completeethane rejection back into the LNG product.
Installations: No commercial installations have beencompleted. Several units have been designed andawait project approval.
References: US Patent 6,564,579, “Method for Vapor-izing and Recovery of Natural Gas Liquids from Liq-uefied Natural Gas.”
McCartney, “Gas Conditioning for Imported LNG,”Gas Processors Association Annual Convention, SanAntonio, 2003.
Licensor: Black & Veatch Pritchard Inc.
Contact: Brian Price, 11401 Lamar, Overland Park,KS 66211 USA, Phone: (913) 458-6151, Fax: (913)458-6098, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
6
3 5
7
21
4LNG
LNG
LNG
Return to Gas Processes INDEX
NGL recoveryApplication: Deep recovery of NGL from naturalgas.
Products: Sales gas and stable NGL, with a propanerecovery as high as 99%. For an ethane-extractionplant, ethane recovery can be over 95%, with apropane recovery of essentially 100%.
Description: With high feed-gas pressure and par-ticularly with dense-phase operation (above the cricon-denbar), two expanders used in series enables thedesign pressure of the gas/gas exchanger to bereduced significantly. It also enables a plate-fin heatexchanger to be used, thus improving process effi-ciency as compared to using a shell and tubeexchanger.
For very high-pressure ratios across the plant, twoexpanders in series avoid very high liquid flows in theexpander exhaust, thus improving the performanceand reliability of the turboexpander system.
Dehydrated feed gas is let down in pressure by thefirst expander (1), and the exhaust is passed to the firstseparator (2). Vapor from the first separator is cooled
and condensed in the gas/gas exchanger (3) and letdown in pressure by the second expander (4). Theexhaust is passed to the second separator (5). Unsta-ble liquids recovered from both separators are sent onto be stabilized. Cold vapor from the second separa-tor is rewarmed and recompressed in the brake endsof the expanders to sales gas pressure.
Operating conditions: A very high propane recov-ery of 99% can be achieved by using a pre-absorber
column and optimizing thermal integration with mul-tistream heat exchangers.
Improved energy integration enables NGL recoveryto be increased to very high levels with similar powerconsumption to conventional technology. Very highethane recovery, of over 95%, can be achieved byusing a portion of the sales gas for demethanizerrefluxing and by utilizing refrigeration efficientlywith good thermal integration.
Installations: Twelve, with capacities up to 11 mil-lion Sm3/d.
References: Finn, A. J., T. R. Tomlinson and G. L.Johnson, “Design equipment changes make possiblehigh C3 recovery,” Oil and Gas Journal, Jan. 3, 2000,p. 37.
US patent no. 6581410 (Propane-plus)US patent no. 6363744 (Ethane-plus).
Contributor: Costain Oil, Gas & Process Ltd.
Contact: Adrian Finn, Technology Development Man-ager, Costain Oil, Gas & Process Ltd., Costain House,Styal Road, Manchester, UK, Phone: (44) 161 910 3227,Fax: (44) 161 910 3256, e-mail: [email protected]
Gas Processes 2004 NGL and LNG
5
2
31
Sales gas
Feed
To stabilization
To stabilization
4
Return to Gas Processes INDEX
NGL-MAXApplication: Ethane/ethylene and heavier hydrocar-bons recovery, from natural gas or refinery off gas feedstreams, using a cryogenic turboexpander process.High ethane recovery (99%) is achievable with essen-tially complete C3
+ recovery. Lower ethane recoveriesare possible with the same process while maintainingC3
+ recovery in the 99% range.
Description: Raw feed gas that is to be processedcryogenically is treated to remove impurities such aswater that would prevent cryogenic processing. Acidgas removal may be needed, if concentration is largeenough to produce freezing in the plant’s cryogenicsection.
Clean, dry and treated feed gas (1) is cooled againstcold residue gas and against cold demethanizerstreams. Feed is then sent to the cold separator (2) forphase separation. Liquid (3) from the separator issent to the demethanizer tower (4) as bottom feed.Vapor leaving the separator is split into two. Thelarger stream is sent to the expander (5) for isen-tropic expansion and sent as feed to the demethanizer.
The smaller stream (6) from the cold separator iscooled, partially condensed and sent to a reflux sep-arator (7). Liquid (8) from the separator is sent tothe demethanizer as feed. Vapor stream (9) leaving thevessel is condensed and sent as second feed to thedemethanizer.
The demethanizer produces at the top, a methane
and lighter stream, and at the bottom a C2+ stream
containing the desired components to be recovered.Cold residue gas (10) is warmed up in exchangersand boosted in pressure by a compressor (11). Thewarm and intermediate pressure residue gas is boostedto pipeline pressure by residue compressors (12) andsent for further processing. A part of the high-pres-sure residue gas (13) is cooled, condensed and sent tothe demethanizer as top feed. This top feed is very lowin C2
+ thereby enabling very high C2+ recovery levels.
Operating conditions: Due to the presence of tworeflux streams, the scheme is able to process feedgases with a wide range of liquid content in the feedgas. The scheme requires the demethanizer tower torun at a somewhat higher pressure than a singletower system. This higher pressure will make the pro-cess more CO2 tolerant, and hence simplify or elimi-nate inlet gas treating.
Licensor: Randall Gas Technologies, ABB LummusGlobal Inc., US Patent Pending.
NGL-ProApplication: To recover ethane and higher compo-nents from natural gas streams. This process is espe-cially adequate with lean and semi-lean gas streams.
Description: The inlet gas is treated and condi-tioned to remove contaminants and water that can-not be processed cryogenically. The gas is partiallycondensed to knock out heavy hydrocarbons, and issent to a cold separator. Removed liquids are sent tothe demethanizer column, while the gas is sent to aturboexpander. The stream from the expander issent to the demethanizer column. To increase therecovery level, a recycle/reflux stream is taken fromthe residue gas and is precooled, extracting refrig-eration from the demethanizer column. The reflux is finally subcooled and sent to the top of the
demethanizer.This process is also adapted for the rejection of
ethane and production of LPG and heavier streams.Recoveries for ethane product are 95+%. Energy con-sumption is between 50 and 70 HP/million scfddepending on gas conditions.
Operating conditions: Ample range of pressuresand temperatures. Hydrocarbon liquid content lessthan 3.5 gal/thousand scf.
Reference: U.S. Patent 5,890,377.
Licensors: Randall Gas Technologies, ABB LummusGlobal Inc.
Nitrogen removal (reject)Application: Remove nitrogen from natural gas toincrease calorific value and/or to reduce gas volumefor compression.
Description: Natural gas is pretreated to removeconstituents that can freeze in the subsequent cryo-genic process or affect product quality. After cooling(1) against hydrocarbon product and waste nitrogen,the feed is expanded into the lower (high-pressure)distillation column (6) of the linked pair. Vapor ris-ing through the column is rectified to yield almostpure nitrogen. It condenses against boiling hydro-carbon in the condenser/reboiler (5) located in theupper (low-pressure) column (4). If helium is presentin the feed gas, a purge stream containing heliumcan be withdrawn from the condenser/reboiler forfurther enrichment.
Liquid nitrogen is taken off the top of the lower col-umn and subcooled (3) by low-pressure nitrogen.Part of the liquid nitrogen provides reflux to theupper column. Methane-rich liquid from the base ofthe lower column is drawn off, subcooled (2) and fedto the upper column. A waste-nitrogen stream, typ-ically containing less than 0.5% methane, is drawnfrom the top of the upper column. A hydrocarbonstream is withdrawn from the base and pumped to
product pressure by the hydrocarbon pump (7). Wastenitrogen and hydrocarbon product are heated toambient against the natural gas feed to providerefrigeration to the process.
For low-nitrogen content feeds, alternative pro-cess flowsheets using a heat-pumped single-columndesign, or a prefractionation column upstream ofone or two further columns, give improved perfor-mance.
Operating conditions: The double-column processis sufficiently flexible to handle natural gas with nitro-gen concentrations varying from 5 mol% to 80 mol%,
and can be a good choice for variable content streamsassociated with enhanced oil recovery (EOR). Feedgas above 27 bar can be processed without any com-pression. For feed gas containing heavy hydrocar-bons or a low-nitrogen content, a three-column pro-cess is more efficient. The third column also improvesplant tolerance to CO2, which may simplify gas pre-treatment requirements.
Economics: The double-column arrangement canoffer several benefits compared with conventional pro-cesses, especially for a feed gas nitrogen contentabove 20%. No power-consuming, heat-pump cyclesare required, and machinery needs are reduced. Inaddition, all hydrocarbon product can leave the plantat high pressure, which reduces recompression require-ments.
Installations: Five, with capacities from 80,000 Sm3/hto 350,000 Sm3/h.
Reference: Healy, M. J., A. J. Finn and L. Halford, “UKnitrogen removal plant starts up,” Oil and Gas Jour-nal, February 1, 1999, p. 36.
Licensor: Costain Oil, Gas & Process Ltd.
Contact: Adrian Finn, Technology Development Man-ager, Costain Oil, Gas & Process Ltd., Costain House,Styal Road, Manchester, UK, Phone: (44) 161 910 3227,Fax: (44) 161 910 3256, e-mail: [email protected]
Gas Processes 2004 NGL and LNG
Nitrogen
Feed gas
Hydrocarbon
1
2 3
4
6
5
7
Return to Gas Processes INDEX
PetroFluxApplication: Recovery of light olefins—typically ethy-lene, propylene or butylene—from offgases usingreflux exchanger technology as part of a low-tem-perature recovery system (LTRS). Reflux exchangertechnology can also be applied to ethylene chill trainsand to NGL recovery from refinery and petrochemi-cal offgases, as well as from natural gas.
Products: Olefins with a typical recovery of 99%. ForNGL recovery: 95+% recovery of propane and 100%recovery of heavier hydrocarbons.
Description: After removal of water and freezablecomponents in the molecular sieves (1), the gas ispartially liquefied in the plate-fin heat exchanger (2)and separated in the feed separator (3). The vaporformed passes upward through the passages of arefluxing plate-fin heat exchanger (4) where it iscooled and condensed. Condensed liquids flow coun-tercurrently to the gas down the heat exchanger pas-sages and are fractionated before collecting in thefeed separator. The resulting gas is then rewarmed and
sent to product/fuel gas while the liquids collected arestabilized. Refrigeration (5) may be provided by aseparate refrigeration cycle or by work expansion ofthe product/fuel gas. The choice of refrigerationscheme depends on both feed and product/fuel gaspressures.
Operating conditions: Typically, feed gas flows ofup to 100,000 Sm3/h can be processed. Feed gas pres-sure is typically between 10 barg and 70 barg.
Economics: The PetroFlux process offers high recov-eries and significant savings in refrigeration costs,giving attractive returns on investment. It has beenused widely for plant debottlenecking and to makemore effective use of existing refrigeration systems.
Installations: The basic refluxing heat exchange sys-tem has been used worldwide on 28 plants.
References: Finn, A. J., “Enhance gas processingwith reflux exchangers,” Chemical Engineering, May1994, p. 142.
Tomlinson, T. R. and D. R. Cummings, “Separationof hydrocarbon mixtures,” US patent no. 4622053.
Tomlinson, T. R. and B. A. Czarnecki, “Separation ofhydrocarbon mixtures,” US patent no. 4846863.
Licensor: Costain Oil, Gas & Process Ltd.
Contact: Adrian Finn, Technology Development Man-ager, Costain Oil, Gas & Process Ltd., Costain House,Styal Road, Manchester, UK, Phone: (44) 161 910 3227,Fax: (44) 161 910 3256, e-mail: [email protected]
Gas Processes 2004 NGL and LNG
Sales gas
Feedgas
1
2 45
3
Recovered hydrocarbon liquids
Crude NGL
Return to Gas Processes INDEX
Phillips optimized cascadeLNG processApplication: Large base-load natural gas liquefaction(LNG) facilities with optional capability for high ethane,propane or mixed LPG recovery. Feedstock: Naturally occurring hydrocarbon gas pre-treated to remove contaminants such as moisture, H2S,CO2, mercaptans and mercury.Description: The process uses three predominantly purecomponent refrigerants: propane, ethylene and methane.The first refrigerant is a multiple-stage closed-looppropane system (1). The second is a closed-loop ethylenesystem (2) consisting of two or more stages. Ethane maybe substituted for ethylene. A combination of brazed alu-minum and core-in-kettle exchangers are utilized forheat exchange. Feed is routed successively through eachstage of propane and ethylene. Air or cooling waterremoves process heat and condenses propane, whilepropane removes heat and condenses ethylene.
Heavier products are typically removed (3) after oneor more stages of ethylene refrigeration. Fractionationdesign is highly dependant on feed composition anddesired product recovery. Efficient designs with high
ethane and propane (>95%) recovery are available. Theresulting methane-rich feed is routed to methane refrig-eration.
Methane refrigeration (4) is a multiple-stage open- orclosed-loop system. A recycle methane stream is used tohelp balance refrigeration loads and improve efficiency.Propane and ethylene are used to remove process heat.With the open-loop configuration, fuel gas is drawn offto prevent inerts from building in the refrigerant. Forfeeds with high nitrogen or helium, an inerts rejectionsystem is integrated into the design.
Economics: The process offers a well-established, reli-able, efficient and low-cost LNG solution. Overall facil-ity EPC costs utilizing the technology have been at orunder $200 per mtpy. Thermal efficiency of the processis high with designs that exceed 93%, including utilities,feed pretreatment and the remaining facility. Largetrain sizes of over 7.5 mtpy are available in multiple tur-bine/driver configurations with even larger train sizes indevelopment.Installations: The first installation was the Kenai, Alaskafacility, brought online in June 1969. The facility hasdemonstrated over 34 years of reliable uninterrupted LNGsupply. Efforts to commercialize the technology beganin 1993. Since that time, three trains using the technol-ogy have been successfully brought online in Trinidadwith a fourth in construction. Additional licenses havebeen signed for two trains in Idku, Egypt, one train in Dar-win, Australia, and one train for a confidential LNG pro-ject. Other projects are in various stages of commercialdevelopment.Licensor: ConocoPhillipsContact: Rick Hernandez, LNG Technology licensingmanager, Phone: (281) 293-5698, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
Feed
Plant fuel
NGL (C2+)
LNG
421
3
Return to Gas Processes INDEX
PRICO (LNG)Application: Convert natural gas to liquefied natu-ral gas (LNG) form for transportation and/or storageusing the PRICO mixed refrigerant process. Applica-tions range from large base load LNG units to smallpeak-shaving units.
Product: LNG is produced at process pressure to bestored at –260°F and atmospheric pressure. Addi-tional products, such as ethane, liquefied petroleumgas (LPG) and gasoline may be recovered in liquidform, when present in the feed gas.
Description: The process is a very simple, efficient,reliable and cost-effective mixed-refrigerant cycle. Asingle mixed-refrigerant, composed of nitrogen andlight hydrocarbons from methane through pentane,is circulated in a closed refrigeration loop. Proportionsof individual refrigerant components are adjusted tomatch the processed gas. This loop contains a compres-sor (1), a partial condenser (2), an accumulator (3), arefrigerant heat exchanger (4), an expansion valve (5)and a refrigerant suction drum (6). Accumulator liq-uids are directed to the refrigerant heat exchanger
with a low head centrifugal pump (7). A single casecentrifugal or axial flow compressor can be used withor without intercooling.
The refrigerant heat exchanger (4) is composed ofmultiple plate-fin brazed aluminum cores arranged inparallel to provide desired production capacity andallow expansion easily.
Natural gas feed is pretreated for removal of car-
bon dioxide (CO2) to less than 50 ppmv and dried toless than 1 ppmv water by conventional methods.Natural gas liquids (NGL) from the natural gas feed areseparated in (8). The NGLs may then be separated bysubsequent fractionation into desired products. Nitro-gen in the natural gas feed is dealt with according tothe LNG product specification requirements by adjust-ing the liquefaction conditions. The process matcheswell with gas turbine, steam turbine or electric motor-driven compression systems.
Installations: Eight peak-shaving units up to 16 mil-lion scfd each are now being successfully operated.Three 180 million scfd base load plants with ethaneand heavier hydrocarbons extraction as separate prod-ucts also use the process.
References: Price, B. C., “Small Scale LNG FacilityDevelopment,” Hydrocarbon Processing, January 2003.
Price, B. C., “Bigger Baseloads,” Hydrocarbon Engi-neering, February 2003.
Licensor: Black & Veatch Pritchard Inc.
Contact: Brian Price, 11401 Lamar, Overland Park,KS 66211 USA, Phone: (913) 458-6151, Fax: (913)458-6098, E-mail: [email protected]
Gas Processes 2004 NGL and LNG
12
47
5
6
3
8
Feed gas
C2+LNG
Return to Gas Processes INDEX
Super Hy-ProApplication: The Super Hy-Pro process is a furtherdevelopment of its predecessor—the Hy-Pro process—and is designed for the high recovery of liquid hydro-carbons from natural gas, mainly LPG.
Description: The inlet gas is treated and conditionedfor processing at low temperatures. After this initialstep, the gas is cooled to a point to partially con-dense certain hydrocarbons. Gas and liquids are sep-arated in a cold separator. The gas is routed to the tur-boexpander where it is expanded into aproprietary-designed cold-absorption column of theliquids-recovery section. The liquids produced in theabsorption section are routed to a recovery column.The liquids-recovery column is the main process focus,where the natural gas liquids are recovered and sep-
arated. The overhead section of the column is ther-mally integrated with the rest of the process, follow-
ing a similar arrangement as is used in the Hy-Pro pro-cess.
Depending on the gas richness, a refrigeration sys-tem may be required to aid product recovery. Prod-uct recoveries for propane exceed 95%.
Typical energy consumption, depending on thecharacteristics of the feed gas, is about 45–65 Hp/mil-lion scfd, not considering utilities and treating.
Operating conditions: Ample range of pressures,temperatures and compositions.
Installations: More than 10 facilities overseas for Hy-Pro and Super Hy-Pro.
Licensors: Randall Gas Technologies, ABB LummusGlobal Inc.
CRG processes—pre-reforming, derichment,methanationApplication: Adiabatic steam reforming of hydro-carbon from natural gas through LPG to naphthafeeds. May be used for the derichment of naturalgas (LNG plants), as an adiabatic pre-reformer or in themethanation of H2/CO-rich streams in SNG manufac-ture.
Description: Fixed bed of nickel-based catalyst con-verts hydrocarbon feeds in the presence of steam toa product stream containing only methane togetherwith H2, CO, CO2 and unreacted steam. This streammay be exported as product, used as feed for furtherprocessing in a conventional fired reformer or as feedto additional CRG processing steps when the methanecontent of the product can be further enhanced.
Using a CRG pre-reformer enables capital cost savingsin primary reformer as a result of reduction in radiantbox heat load and allows high-activity gas reformingcatalyst to be used. The ability to increase preheat tem-peratures and transfer radiant duty to the convectionsection of the primary reformer can minimize invol-untary steam production.
Operating conditions: CRG processes operate overa wide range of temperatures from 250°C to 650°C,and at pressures up to 75 bara.
Installations: CRG process technology covers 40years of experience with over 150 plants built andoperated. Ongoing development of the catalyst haslead to almost 50 such units since 1990.
References: Littlewood, S., et al., “Prereforming:Based on high activity catalyst to meet marketdemands,” Ammonia Plant Safety & Related Facilities,Vol. 40, p. 3, AIChE.
Licensor: The CRG Process and catalyst are licensedby Davy Process Technology. The CRG Process is avail-able through a number of process licensees worldwide,and the catalyst is manufactured and supplied underlicense by Johnson Matthey Catalysts.
Contact: 20 Eastborne Terrace, London W2 6LE, UK;e-mail: [email protected]
Gas Processes 2004 Pre-reforming
Hydrocarbon
CRGreactor
Steam
Methane-rich product
Return to Gas Processes INDEX
AQUISULFApplication: Decrease H2S content in liquid sulfurcondensed in SRUs and routed to sulfur degassingfacilities. Maximum H2S content is 10 ppm.
Description: A degassing unit is required to achieve10 ppm H2S in liquid sulfur. The degassing is done ina concrete pit or sulfur degassing vessel that is dividedinto two compartments. The first compartment (1) isequipped with a recirculation and cooling pump (3)and a spraying system. The second (2) is equipped witha recirculation and transfer pump (4) also with aspraying system. A partition wall separates the twoareas.
Sulfur arrives continuously into the first compart-ment where it is sprayed. It flows to the second com-partment through an opening located at the bot-tom of the partition wall. The sulfur is sprayed againin the second compartment where degassing is com-pleted. The degassed liquid sulfur is then transferredunder level control to sulfur storage. To quickly mix
the AQUISULF catalyst with sulfur, the catalyst isinjected at the suction side of each sulfur recirculationpump.
The optimal temperature for degassing is reachedby cooling the sulfur (5). The heat generates LP steam
that is condensed in the air cooler (6). The pit vaporphase is swept with atmospheric air sucked in by asteam ejector. Sweeping gas flows from the secondcompartment to the first through a hole located at thetop of the partition wall. The gas and H2S are sent tothe incinerator through a steam ejector.
Economics: AQUISULF, including the sulfur pit andsulfur degassing vessel, respectively, accounts forapproximately 20% of the Claus unit cost.
Installations: More than 80 AQUISULF units are inoperation or under design worldwide.
Reference: Nougayrede, J. and R. Voirin, “Liquid cat-alyst efficiently removes H2S from liquid sulfur,” Oiland Gas Journal, July 1989.
CAP-compact alkanolamineplantApplication: Selective hydrogen sulfide (H2S) removalin the presence of carbon dioxide (CO2), based on thenovel co-current ProPure gas-liquid contactor and aregenerative solvent.
Description: The key CAP technology is the ProPureco-current contactor, which is a gas flow driven “one-shot” contactor. The co-current contactor replacesthe counter-current tower in a conventional amineplant. The small liquid droplets generated promotehigh gas-liquid mass transfer rates at low to inter-mediate permanent pressure drops.
CAP’s H2S-selectivity is achieved by a short retentiontime combined with the high gas-solvent exposurearea throughout the contactor. Compared to counter-current contactors the gas residence time is consid-erably shorter, typically 30–60 times shorter. Therefore,CO2 co-absorption is significantly reduced, allowinghigher solvent H2S-loading capacity. Tertiary aminessuch as MDEA yield selective H2S-removal, as the sol-vent proton reaction with H2S is instantaneouswhereas the reaction with CO2 undergoes several(slow) intermediate reactions. The higher the ratio
between CO2 and H2S concentrations, the more com-petitive CAP becomes as compared to conventionalcounter-current contactor technology.
Due to the contactor operating at high gas veloci-ties, its size is much smaller compared to conven-tional equipment. The selective nature results in sig-nificantly lower circulation rates, which reduces theamine regeneration system’s overall size.
Economics: For a case with inlet concentrations of 5%CO2, 10–20 ppmv H2S and H2S-outlet specification of
2 ppmv, a reduction in installed weight of 60% isestimated compared to conventional technology. Thisis mainly due to the reduced amine circulation rate.The limited foot-print requirement makes CAP feasi-ble for retrofit installations on existing offshore fields.
Installations: Extensive tests have been carried outat the Statoil Mongstad refinery and at ProPure`s testfacility. During 2004, CAP will undergo a technologyqualification program with sour hydrocarbon gas at80–100 bar. The program is supported by a JIP (Total,Statoil, ConocoPhillips and Gaz de France) joint ven-ture, and the tests will be run at Gaz de France`s gasprocessing and distribution plant at Chemery, France.
Reference: Connock L., “Finding the best solution,”Sulphur, No. 283, Nov.–Dec. 2002.
Nilsen, F. P., H. Lidal and H. Linga, “Selective H2Sremoval in 50 ms,” GPA Annual Conference Amster-dam, Netherlands, September 2001.
Nilsen F. P., H. Lidal and I. Nilsen, “Novel contactingtechnology selectively removes H2S,” Oil & Gas Jour-nal, May 2002.
Claus, modifiedApplication: Recover sulfur from acid-gas streamsthat contain hydrogen sulfide (H2S) and ammonia(NH3).
Product: Bright yellow sulfur with 99.9 % purity andless than 10 ppmw of dissolved H2S after degassing.Front-end Claus tail gas is either processed in a tail gasclean-up (TGCU) unit for further sulfur recovery, orrouted to the Claus incinerator where residual H2S isoxidized to SO2.
Description: Acid gases from sweetening units andsour-water strippers are sub-stoichiometrically burntwith ambient air (or air plus oxygen) in a refractory-lined furnace to convert 1⁄3 of H2S to SO2. Subse-quently, elemental sulfur is produced in accordancewith the Claus reaction between 2⁄3 of the H2S and pro-duced SO2. Ammonia and hydrocarbons containedin the feed gas are also destroyed. High-pressuresteam is generated in a waste-heat boiler (WHB),which cools the acid gas from the high-flame tem-perature to the lower catalytic reactor (converter)
temperature. Further sulfur conversion is achievedin two or three stages of catalytic reaction in con-verters. Each converter is normally preceded by areheater and followed by a sulfur condenser. Severalmethods are available for reheating process gas.
Operating conditions: The temperature inside thecombustion chamber depends upon the type andquantities of species accompanying the H2S and O2.Generally, the operating temperature ranges between
925°C–1,200°C, but can be increased to 1,450°C ifNH3 is present in the feed gas. Total pressure drop ofthe process gas depends upon the numbers of con-verter stages. Typically, pressure drop can vary between0.3 bar and 0.5 bar.
Sulfur recovery efficiency depends on the feed-stream composition and the number of catalyticstages; typically, it ranges between 94.5% and 97.5 %.
Economics: Capital cost is approximately U.S.$10million/100-tpd sulfur recovery unit designed toachieve 95% recovery efficiency from typical amine offgas. Operating costs can be considered negligible ifcredit for steam generation is taken into account.
Installations: Since the 1970s, more than 60 modi-fied Claus units have been built worldwide by SIIRTECNIGI.
Claus, oxygen-enriched Application: Debottleneck existing sulfur recoveryunits (SRU) or reduce size, capital and operating costsfor new facilities by using oxygen, either to enrich orto replace combustion air.
Product: Bright yellow, high-purity sulfur. Claus tailgas is either processed in a tail gas clean-up unit(TGCU), or routed to the Claus incinerator whereresidual hydrogen sulfide (H2S) is oxidized to SO2.
Description: In an air-based Claus plant, nitrogenfrom the combustion air usually comprises more thanhalf of the molar flow through the plant. By replac-ing air with oxygen, plant capacity can be increasedsignificantly. The level of air enrichment with oxygenand, hence, the level of uprating depend upon thefeed-gas composition.
Process variations:• Up to about 30% oxygen , only minor modifi-
cations to the plant would be expected.• Above 30% oxygen concentration, a proprietary
oxygen-compatible burner would be required usingthe SURE burner. Some limited modifications could beexpected.
• For capacity increases in excess of about 100%,the SURE double combustion process could be used toachieve the desired expansion.
Operating conditions: The process uses a highercombustion temperature. The operating tempera-ture is kept below 1,650°C—the normal refractorylimit. Sulfur recovery efficiency for an oxygen-basedClaus process is slightly better than that of air-basedClaus and typically ranges between 95% and 98%,depending on process variables.
Economics: The cost of revamp is generally between10% and 30%—only includes the cost for additionalnew plant capacity. The cost of a new oxygen-basedClaus facility can save up to 35% of the installed costfor an air-based alternative.
Installations: Several units have been designed andrevamped by SIIRTEC NIGI in cooperation with Parsonsand BOC. Two new units were constructed for IGCCproject.
Licensor: SIIRTEC NIGI (up to 30% O2), SURE Par-sons/BOC through SIIRTEC NIGI
Cold Bed Adsorption (CBA)Application: Recover elemental sulfur from acid-gasstreams that contain hydrogen sulfide (H2S), or treatClaus tail gas for additional sulfur recovery. CBA bedscan be retrofitted in existing units to increase thesulfur recovery.
Product: Bright yellow, commercial grade sulfur. Tail-gas leaving the CBA reactor is normally routed tothe incinerator and thermally oxidized.
Description: The CBA is a dry-bed catalytic processwhich extends and enhances the characteristics ofthe Claus reaction in two ways:
• Operating the CBA reactors near the sulfur dewpoint extends the Claus reaction equilibrium and canachieve higher sulfur conversion
• Using the catalyst as an in-situ capture point forthe produced sulfur drives the reaction to completion.
A common flowsheet involves two CBA reactors,operating cyclically, downstream of a Claus converter.Gas leaving the sulfur condenser is fed directly to aCBA reactor on adsorption duty. The formed sulfur is
adsorbed on the catalyst bed. The bed on regenera-tion duty is heated by diverting some hot gas from theClaus reactor to drive off and recover the sulfur. Thisregeneration gas stream is re-combined with themain process gas for treatment in the adsorptionbed. Effluent gas from the plant may be sent to a ther-mal oxidizer. Other flowsheet configurations mayalso be used, where required, to meet specific sulfur
recovery or retrofit objectives.
Operating conditions: The temperature in the CBAreactor can vary from 120°C to 150°C during theadsorption cycle and 300°C to 350°C during regener-ation. The total pressure drop of the CBA section isaround 0.1–0.15 bar. Sulfur recovery can be over 99%.
Materials of construction: Mainly carbon steel.CBA reactors can be either aluminized or refractory-lined carbon steel. Cyclic valves should be constructedof SS 316.
Installations: Many CBA plants have been built withcapacities from 2 thousand tpd to 1,300 thousandtpd. The most recent CBA plant built by SIIRTEC NIGIis for Hindustan Petroleum Co. Ltd., at Visakhapatnam,India. This plant uses two units with 65-tpd capacityfor each unit.
COPEApplication: Increase capacity and recovery of exist-ing Claus sulfur recovery/tail gas cleanup units, pro-vide redundant sulfur processing capacity, and improvecombustion performance of units processing leanacid gas through oxygen (O2) enrichment.
Description: The sulfur processing capacity of typi-cal Claus sulfur recovery units can be increased tomore than 200% of the base capacity through partialto complete replacement of combustion air with pureO2. SRU capacity is typically limited by hydraulic pres-sure drop. As O2 replaces combustion air, the quantityof inert nitrogen is reduced allowing additional acidgas to be processed. The process can be implementedin two stages.
As the O2 enrichment level increases, the combustiontemperature (1) increases. COPE Phase I, which does notuse a recycle stream, can often achieve 50% capacityincrease through O2 enrichment to the maximum reac-tion furnace refractory temperature limit of about2,700–2,800°F. Higher O2 enrichment levels are possi-ble with COPE Phase II which uses an internal processrecycle stream to moderate the combustion tempera-ture allowing enrichment up to 100% O2.
Flow through the remainder of the SRU (2, 3, and
4) and the tail gas cleanup unit is greatly reduced.Ammonia and hydrocarbon acid gas impurity destruc-tion and thermal stage conversion are improved atthe higher O2 enriched combustion temperatures.Overall SRU sulfur recovery is increased by 0.5% to1%. A single proprietary COPE burner handles acidgas, recycle gas, air and oxygen.
Operating conditions: Combustion pressure from 6psig to 12 psig; combustion temperature up to 2,800°F.Oxygen concentration from 21% to 100%. SRU sulfurrecovery is 95% to 98%.
Economics: Expanded SRU and tail gas unit retrofitsulfur processing capacity at capital cost of 15–25%of new plant cost. New plant savings of up to 25%,and redundant capacity at 15% of base capital cost.Operating costs are a function of O2 cost, reducedincinerator fuel, and reduced operating and mainte-nance labor costs.
Installations: Nineteen COPE trains in operation at11 locations. Two additional trains are in engineeringand/or the construction phase of projects.
Reference: US Patents 4,552,747 and 6,508,998. Sala, L., W. P. Ferrell and P. Morris, "THE COPE PRO-
CESS—Increase Sulfur Recovery Capacity To MeetChanging Needs," European Fuels Week Conference,Giardini Naxos, Taormina, Italy, April 2000.
Nasato, E., and T. A. Allison, "COPE Ejector—ProvenTechnology," Sulphur 2002, Vienna, Austria, October2002.
Licensor: Goar, Allison & Associates, Inc., and AirProducts and Chemicals, Inc.
CrystaSulfApplication: Removes hydrogen sulfide (H2S) fromgas streams such as natural gas, refinery fuel gas,hydrogen recycle stream in refinery HDS, high-carbondioxide (CO2) streams in EOR plants and geothermalvent gas. Also removes H2S, sulfur dioxide (SO2) andelemental sulfur vapor from Claus tail gas in naturalgas processing plants and petroleum refineries. Cantreat any high- or low-pressure gas stream. CrystaSulfis the most economical choice for H2S removal fromgas streams containing between 0.2 and 25 long tonsper day (ltpd) of sulfur (S).
Description: Gas phase H2S is converted to elemen-tal sulfur in a single process step using a proprietarynonaqueous sorbent. The sulfur formed remains dis-solved in the solution; thus, no solids are present inthe circulating scrubbing liquor. Sulfur is removedfrom the system by cooling in a crystallizer/filter sys-tem. No surfactants, wetting agents or antifoams areneeded.
Scrubbing solution circulation rates are low (e.g.,20–50 gpm/ltpd) and product sulfur purity is high(98+% sulfur). It can be blended with Claus sulfur orused in agriculture. Chemical makeup costs are approx-
imately $250/lt of sulfur. Capital and operating costsare less than other options, and the process requiresno solution blowdown. For Claus tail gas treating, thetail gas is fed directly to the CrystaSulf absorber, thuseliminating the reducing gas generator, waste heatboiler, hydrogenation reactor and water quench.None of the gas needs to be recycled back to theClaus unit.
Operating conditions: Atmospheric to 2,000+ psi;120°F to 180°F. CO2, COS and CS2 in the inlet gas donot react and do not affect the system. Inlet gashydrocarbons do not cause foaming or sulfur settlingproblems for CrystaSulf.
Installations: Eighteen months of pilot plant testingwas conducted on a 300-psig CO2 stream. Two licensessold. First commercial unit startup is expected mid-2004.
References: Technical papers and publications areavailable at www.crystatech.com.
Licensor: CrystaTech is the Gas Technology Insti-tute’s (GTI) exclusive licensor of CrystaSulf. TheHanover Company and GTI are investors in CrystaTechand provide engineering and research support toCrystaTech. Hanover provides detailed design andfabrication of CrystaSulf units and can offer turnkeyprojects.
Contact: Bryan Petrinec, Director of Operations, Crys-taTech, Inc., 4616 W. Howard Lane, Suite #2500, Austin,TX 78759, Phone: (512) 248-6317, Fax: (509) 696-2939,E-mail: [email protected]
Gas Processes 2004 Sulfur
Sulfurfilter
systemCrystallizerFiltrate
Crystalline sulfur
Flashvessel
Cool
HeatSour gas
Vent toflare
header
Lean solution
Compressor
Sweet gas
Return to Gas Processes INDEX
D’GAASSApplication: Removal of dissolved H2S and H2Sx fromproduced liquid sulfur. Undegassed sulfur can createodor problems and poses toxic and explosive haz-ards during the storage and transport of liquid sulfur.
Description: Degasification is accomplished in a pres-surized vertical vessel where undegassed sulfur is effi-ciently contacted with pressurized process air (instru-ment or clean utility air). The contactor vessel may belocated at any convenient location. The undegassedsulfur is pumped to the vessel and intimately contactedwith air across special fixed vessel internals.
Operation at elevated pressure and a controlledtemperature accelerates the oxidation of H2S andpolysulfides (H2Sx) to sulfur.
The degassed sulfur can be sent to storage or directlyto loading. Operation at elevated pressure allowsthe overhead vapor stream to be routed to the tra-ditional incinerator location, or to the SRU main
burner or TGTU line burner—thus eliminating thedegassing unit as an SO2 emission source.
Economics: D’GAASS achieves 10 ppmw combinedH2S/H2Sx in product sulfur without use of catalyst.Elevated pressure results in the following benefits: lowcapital investment, very small footprint, low operat-
ing cost and low air requirement. Operation is simple,requiring minimal operator and maintenance time. Nochemicals, catalysts, etc., are required.
Installations: Sixteen units in operation. Fourteenadditional trains in engineering and constructionphase with total capacity over 17,000 ltpd.
Reference: US Patent 5,632,967. Nasato, E., and T. A. Allison, “Sulfur Degasifica-
EUROCLAUS processApplications: The EUROCLAUS process recovers ele-mental sulfur from hydrogen sulfide (H2S) containinggases, which originate from gas treating plants suchas alkanolamine units or physical solvent plants. Yieldsup to 99.7% overall sulfur recovery without any fur-ther tail gas clean up are possible.
Description: The EUROCLAUS process has a thermalstage followed by three catalytic reaction stages. Sul-fur is removed between stages by condensers. Tworeactors are filled with standard Claus catalyst whilethe last reactor is filled with selective oxidation cat-alyst.
In the thermal stage, acid gas is burned with a sub-stoichiometric amount of controlled combustion airsuch that, the tail gas leaving the second reactor con-tains typically 0.8 vol.% to 1.0 vol.% of H2S and100–200 ppmv sulfur dioxide (SO2). The low SO2 con-tent, produced with a hydrogenation catalyst, converts
SO2 to H2S in the reactor bottom. The last reactor oxidizes H2S to sulfur at more than
85% efficiency. However, because this catalyst neitheroxidizes H2S to SO2 nor reverses the reaction: total sul-fur recovery up to 99.3% efficiency can be obtained.If more than 99.3% sulfur recovery is required, oneadditional Claus reactor stage may be installed
upstream of the selective oxidation reactor.
Utilities: Basis: 100 tpd sulfur recovery unit; 93 vol%H2S feed gas and catalytic incineration.
Installations: Since the first commercial demon-stration of the EUROCLAUS process in 2000, morethan 12 plants are in operation or under constructionin the first quarter of 2003.
Licensor: Comprimo Sulfur Solutions, a member ofJacobs Engineering Group
Fluor hydrogenation/amineClaus tail gas treating processApplication: The Claus sulfur conversion processrecovers up to 97% of the sulfur from acid gas streams.The Fluor hydrogenation/amine process converts sul-fur dioxide (SO2), COS, carbon disulfide (CS2), ele-mental sulfur and other sulfur species in the Claus tailgas to hydrogen sulfide (H2S). The H2S is then removedvia selective amine treating to achieve a total sulfurrecovery efficiency of up to 99.99%.
Description: Air and natural gas are combustedunder substoichiometric conditions in a reducing gasgenerator (1). The hot combustion product reducinggases, carbon monoxide (CO) and hydrogen (H2), aremixed with the Claus tail gases in a mixing chamber(2) integral with the reducing gas generator. Thecobalt molybdenum (CoMo) catalyst in the reactor (3)hydrogenates/hydrolyzes all the sulfur species in thegas mixture to H2S.
The hydrogenated tail gas is then cooled in the
effluent cooler (4), generating steam in the process.The effluent gas is further cooled in a direct contactquench tower (5) to condense and remove water.The condensed water, which contains a small amountof H2S, is treated in a sour-water stripper where theH2S is removed and returned to the Claus unit.
The Fluor design optionally uses a desuperheatingsection with an alkaline circulation to remove anypotential SO2 breakthrough from the hydrogenationreactor. This design feature is especially useful whenthe downstream amine unit operates with an expen-sive proprietary amine.
After quench cooling, the hydrogenated tail gas isthen treated by a highly efficient selective amine toremove H2S. In the absorber (6), the H2S is selectivelyabsorbed in the amine while rejecting as much CO2 aspossible. The rich amine solution is then regeneratedin the stripper (7) and circulated back to the absorber.Acid gas from the stripper is recycled back to theupstream Claus unit. The process can achieve a totalsulfur recovery efficiency of up to 99.99%
Installations: Three plants engineered or constructed.
References: Chow, T. K., J. K. Chen and V. W. Wong,“Desulfurizing fuels: Know the basics,” Chemical Engi-neer, September 2002, pp. 66–71.
Licensor: Fluor Enterprises, Inc., Contact: ThomasChow, One Fluor Daniel Dr., Aliso Viejo, CA 92698,Phone: (949) 349-4247, Fax: (949) 349-2898, e-mail:[email protected]
Gas Processes 2004 Sulfur
5
6
7
Lean aminepump
Filter
Vent to atmosphere
Amine section of TGTUHydrogenation section of TGTU
Sourwater
Acid gasrecycle to SRU
Hydrogenatedtail gas
Rich amine pump
Condensedwater
Steam
Fluegas
Air Tailgas
4
1 2
Return to Gas Processes INDEX
HCR—High Claus RatioApplication: Remove sulfur compounds present in tailgases from Claus plants and meet air pollution stan-dards.
Description: The high Claus ratio (HCR) process con-sists of two sections :
• Hydrogenation and hydrolysis of sulfur com-pounds present in tail gases (COS, CS2, Sx and SO2).Tail gas is heated to about 300°C and, without hydro-gen addition, is treated with Co/Mo catalyst. Gaspasses through a waste-heat boiler (WHB) and iscooled to approximately 40°C in a direct contacttower.
• H2S removal and recycle of acid gas to a Clausplant.The gas is washed in a carefully designed amineabsorber, and the treated gas is incinerated. Richamine is processed and recycled.
The process requires adjusting the operating crite-ria for the Claus unit by increasing the H2S/SO2 tail gasratio. The operation is very steady and has high ser-
vice factors that are achieved during upset condi-tions from upstream units. Hydrogen or reducing gasfrom external sources are not required in the hydro-genation reactor.
Operating conditions: The pressure drop of theunit is 0.20–0.30 bar and the operating pressure is
almost atmospheric. Treated gas contains less than 250ppmv of H2S.
Economics: Process uses standard equipment andcarbon steel almost everywhere. No consumption ofreducing gas or caustic chemicals is required. Processanalyzers are not mandatory.
Reduction in utilities and chemical costs are approx-imately $1.50/t of sulfur produced. Lower operatingand maintenance labor is about one-eighth man pershift.
Installations: The first commercial HCR plant wasstarted up in November 1988 at Agip Plas’s facility (anaffiliate of Agip Petroli S.p.A.) in Robassomero, Italy.Since then, more than 10 HCR plants are under con-struction with capacities ranging from 1.5 tpd up to270 tpd.
LO-CATApplication: Removal of H2S and the production ofhigh-purity sulfur from both anaerobic and aerobic gasstreams including wellhead gas, fuel gas, acid gas, nat-ural gas, carbon dioxide, Claus tail gas, synthesis gasand ventilating-air streams. Infinite turndown withrespect to H2S concentration, sulfur loading and gasrate with sulfur capacities ranging from a few poundsper day to greater than 25 ltpd. Recovery of the sul-fur product as a slurry, a filter cake or as high-purity,molten sulfur. In most cases, sulfur cake can bedeposited in a non-hazardous landfill. Autocirculationconfiguration when treating amine acid gas allows forremote or unattended operation typical for gas fieldoperation.
Description: Three processing configurations areavailable depending on the type of gas and final useof the sweet gas. The conventional scheme, shownabove, is used to process both combustible gas streamsand product gas streams. The sour gas contacts adilute, proprietary, iron chelate catalyst solution in anabsorber (1), where the H2S is absorbed and oxidizedto solid sulfur. The sweet gas leaves the absorber foruse by the client. The reduced catalyst solution returnsto the oxidizer (2), where sparged air reoxidizes the
catalyst solution. The catalyst solution is then returnedto the absorber. The continuous regeneration of thecatalyst solution allows for very low chemical oper-ating costs.
In the patented autocirculation scheme, theabsorber (1) and the oxidizer (2) are combined inone vessel, but separated internally by baffles. Sparg-ing of the sour gas and regeneration air into the spe-cially designed baffle system creates a series of “gaslift” pumps eliminating the external circulation pumps.This configuration is ideally suited for treating amineacid gas streams.
The third processing scheme sweetens air streamscontaminated with H2S. The absorption and oxidationof H2S to sulfur, as well as the regeneration of the cat-alyst solution, occur in one vessel. The air in the gasstream is used to regenerate the catalyst, eliminatingthe oxidizer air blowers.
Operating conditions: Operating pressures fromvacuum conditions to several hundred psi. Operatingtemperatures range from 40°F to 140°F. Hydrogensulfide concentrations from a few ppm to 100%. Sul-fur loadings from a few lb/d to 25+ ltpd. No restrictionson type of gas to be treated; however, some con-taminants such as SO2 may increase operating costs.
Installations: 119 operating, 3 under constructionand 151 under license.
Reference: Hardison, L. C. and D. E. Ramshaw, “H2Sto S: Process improvement,” Hydrocarbon Process-ing, Vol. 71, Jan. 1992, pp. 89–90.
Licensor: Gas Technology Products LLC, a MerichemCo.
Contact: William Rouleau, applications engineeringmanager, Gas Technology Products LLC, 846 E. Algo-nquin Rd. Ste. A100, Schaumburg, IL 60173, Phone:(847) 285-3865, Fax: (847) 285-3888, E-mail:[email protected]
Gas Processes 2004 Sulfur
1 2Line presssour gas inlet
Solution pump
Sweet gas out
Air
Spent air ventto atmosphere
Sulfur slurryto melter,centrifuge
or disposal
Return to Gas Processes INDEX
MeroxApplication: Extraction of mercaptans from gases,LPG, lower boiling fractions and gasolines, or sweet-ening of gasoline and heavier stocks by in situ con-version of mercaptans into disulfides.
Products: Essentially mercaptan sulfur-free, i.e., lessthan 5 ppmw, and concomitant reduced total sulfurcontent when treated by Merox extraction technique.
Description: Merox units are designed in severalflow configurations, depending on feedstock typeand processing objectives. All are characterized by lowcapital and operating costs, ease of operation and min-imal operator attention.
Extraction: Gases, LPG and light naphtha are coun-tercurrently extracted (1) with caustic containingMerox catalyst. Mercaptans in the rich caustic areoxidized (2) with air to disulfides that are decanted(3) before the regenerated caustic is recycled.
Sweetening: Minalk is now the most prevalentMerox gasoline and condensate sweetening scheme.Conversion of mercaptans into disulfides is accom-plished with a fixed bed of Merox catalyst that usesair and a continuous injection of only minute amounts
of alkali. Sweetened gasoline from the reactor typi-cally contains less than one ppm sodium. A new addi-tive, Merox Plus reagent, can be used to greatlyextend catalyst life.
Heavy gasoline and condensate may be sweetenedin a fixed-bed unit that closely resembles Minalk, exceptthat a larger amount of more concentrated caustic isrecirculated intermittently over the catalyst bed.
Installations: Capacity installed and under con-struction exceeds 13 million bpsd. More than 1,600units have been commissioned to date, with capaci-ties between 40 and 140,000 bpsd. UOP has licensedgas Merox extraction units with capacities as high as2.9-billion-scfd for mercaptan control.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Sulfur
Extracted product
H2S free feed
RichMeroxcaustic
Catalystinjection
Merox-causticsolution
Excess air
Disulfide
Air1 2
3
Return to Gas Processes INDEX
OxyClausApplication: Increase capacity up to 200% in exist-ing Claus sulfur recovery units, or for a more eco-nomical design of grassroots Claus sulfur recoveryunits.
Description: The modified Claus reaction is carriedout with direct oxygen combustion. By using a pro-prietary thermal reactor burner (1), levels of 80–90%net oxygen can be utilized. Combustion temperaturemoderation is achieved without the need for anytype of gas recycle. Oxygen is combusted with the acidgas in the center of an extremely hot flame core,while air is introduced around the outside of thisflame, combusting the balance of the acid gas. Con-siderable cracking of H2S to hydrogen and sulfuroccurs in the hot flame core as thermodynamic equi-librium is approached. Carbon dioxide is also reducedto carbon monoxide. These endothermic reactionsprovide proven temperature moderation consistentwith conventional refractory/insulating brick materi-als. The level of produced hydrogen then decreases inthe waste-heat boiler as the hot gas is cooled, sinceequilibrium of the H2S-cracking reaction is favored byhigh temperatures. Heat generated by the exother-mic reverse reaction is removed in the waste-heat
boiler (2). Downstream recovery of elemental sulfuris accomplished by the conventional modified Clausprocess using a series of catalytic reactors (3) and sul-fur condensers (4). No specialized equipment orchanges to conventional design practices are required.
Ammonia-containing sour water stripper offgascan also be processed. The ammonia is combusted withair in a separate central burner muffle at near-oxi-dizing conditions.
Units may be operated in a base-load mode with air
only. Peak shaving, as well as operation at full designcapacity, is accomplished with air and oxygen.
Economics: For a reference 200-tpd sulfur recoveryunit (Claus and tail gas unit) requiring 99.9% overallsulfur recovery, capital cost savings of $1.6 million to$2.5 million are achievable with oxygen enrichmentas compared to an air-only design.
Based on typical pipeline oxygen costs of $35 perton, even if oxygen enrichment were used 100% ofthe time, it would take over eight years for oxygencosts to equal the incremental capital savings.
Installations: More than 30 Claus sulfur recoveryunits with OxyClaus are in operation or under designworldwide.
Reference: Stevens, D. K., L. H. Stern and W. Nehb,“OxyClaus technology for sulfur recovery,” LauranceReid Gas Conditioning Conference, Norman, Okla-homa, 1996.
Licensors: Lurgi Oel-Gas-Chemie GmbH and ThePritchard Corporation (US only)
SRUApplication: To recover liquid sulfur from hydrogensulfide (H2S)-containing gases such as acid gas fromgas-sweetening units, acid gas from sour-water strip-pers or offgas from sulfur degassing facilities.
Description: The main reactions are well-knownClaus reactions. Ammonia (NH3), present in the sour-water stripper offgas, is processed in the main burner(1) directly with other feed gas streams. Practicalcomplete NH3 destruction is ensured by choosing theproper high-intensity burner and preheating feedgas. The Claus unit is designed to suppress SO3 for-mation at the reaction furnace and subsequent lineburners. The sulfur complexes, even with ammonia inthe feed, can typically run for 3 to 4 years without amaintenance shutdown.
The Claus tail gas is routed to a SCOT unit, wherethe sulfur components are recovered (see SCOT).Upsets, such as those based on partial oxidation, usu-ally pass almost unnoticed in the SCOT unit. For exam-ple, a hydrocarbon upset in the feed to the Clauswill not have any other effect on the SCOT, otherthan a slight increase in H2S content from the SCOT
absorber. A temporary NH3 breakthrough from theSRU has no other effect than a slight pH increase inthe quench water.
Liquid sulfur produced in the Claus unit is degassedin the Shell sulfur degassing facilities (see “sulfurdegassing” for more details). In this process, the H2Slevel in liquid sulfur is reduced to below 10 ppmw,without using catalyst, which improves safety duringliquid sulfur handling. Offgas of the sulfur stripper canbe routed to the Claus unit or to an incinerator.
The incinerator downstream the Claus/SCOT unit isdesigned such that a maximum of 10 ppmv H2S can slipthrough, the remainder of the H2S and any other sul-fur component are oxidized to SO2. A thermal incin-erator can be designed with a heat-recovery sectionfor superheating steam produced in the Claus unit orgas preheating. A catalytic incinerator, using propri-ety catalyst, more selectively oxidizers sulfur com-pounds, thus significantly reducing the risk from tem-perature runaways.
Installations: Units with sulfur capacities up to 4,000tsd for refineries and gas plants.
References: Hoksberg, et al., “Sulfur recovery forthe New Millennium,” Hydrocarbon Engineering,November 1999.
Verhulst, “Safeguarding of the sulfur recovery pro-cess,” Bovar/Western Research Sulfur Seminar,Budapest, 1993.
Licensor: Shell Global Solutions International B.V.
SulFeroxApplication: Removal of hydrogen sulfide (H2S) froma large range of gas streams giving a sulfur produc-tion of 0.1–20 tpd. Gas applications include: naturalgas, amine tail gas, enhanced oil recovery CO2 recy-cle, refinery gases, geothermal, syngas, offshore pro-duction gas, digester offgas and offgas from wastew-ater treatment plants. The full range of H2Sconcentrations (from a few ppmv to almost 100%v ofH2S) can be treated to 1 ppmv H2S. Turndown prop-erties—both on H2S concentration and total gasflow—are very good, and the process shows excellentflexibility. If gas flows become too large (in excess of10 million Nm3/d) the combination of an amine unitcoupled to a SulFerox unit becomes more economical.The sulfur product can be obtained as a filter cake oralternatively as molten sulfur of high quality. Thesulfur cake can be land filled as a nonhazardous wasteor-depending on local regulations-directly used as afertilizer.
Description: SulFerox is a redox-based process thatconverts H2S in sour gas to elemental sulfur (S) in thecontactor through reaction with a proprietary aque-ous ferric iron chelate solution. Various contactortypes are available, such as sparged towers, spraytowers and pipeline contactors. The sparged tower isthe most versatile contactor and will be selectedwhenever pressure drop allows. After contacting the
sour gas and SulFerox solution in the (sparged tower)contactor, the gas/liquid mixture is separated. In theseparator, the solution and treated gas is separatedyielding the treated sweet gas—leaving the unit viaan optional knockout vessel—and the depletedSulFerox solution.
After optional degassing, the reduced iron chelatesolution is regenerated via reaction of Fe2
+ back to Fe3+
with oxygen from an air source in the regenerator ves-sel. Via a thickener vessel, part of the solution is sentfor filtration and sulfur recovery; the major portionof the stream is returned to the contactor.
In addition, the resulting filtrate is returned to theprocess for maximum solution recovery, thus, optimallyusing the chelate solution. Depending on the feed gas
conditions, the contactor and separator can be com-bined in one vessel as can be done with the regen-erator and surge vessel. This gives a two-vessel con-figuration suited for amine regenerator offgas.
Operating conditions: Operating pressures varyfrom just over atmospheric to 500 psig. The SulFeroxprocess itself operates at temperatures of 110°F–140°F.However, the feed gas temperature can be between75°F–130°F. The feed gas must be free of hydrocarbonliquids. Gas at other conditions may need pretreat-ment first (cooling, dew pointing). Although theapplicability of the SulFerox process is very wide,some feed gas contaminants such as high levels of NH3,HCN and SO2 might affect the economics of the pro-cess.
Installations: Thirty units in operation.
References: Smit, C. J. and E. C. Heyman, “Present sta-tus SulFerox process,” Proccess GRI Sulfur RecoveryConference, 9th meeting, 1999.
Oostwouder, S. P., “SulFerox process update,” Proc-cess GRI Sulfur Recovery Conference, 8th meeting,1997.
Licensor: Shell Global Solutions International B.V.
Sulfint HPApplication: Selective hydrogen sulfide (H2S) removalfrom high-pressure gases with direct conversion of H2Sinto elemental sulfur (S). Residual H2S levels in thetreated gas can be lower than 1 ppm vol.
Description: The Sulfint HP uses the well-knownconcept of redox desulfurization. However, this pro-cess has been specifically designed to treat high-pres-sure gases. The feed gas is contacted with the redoxcatalytic solution (aqueous iron chelate based solution)in a co-current absorber (1). The H2S is absorbed by thecatalytic solution, reacts with the catalyst and is con-verted into elemental S. Desulfurized gas is recov-ered from the top of the separator vessel (2). Thesulfur-loaded solution is then pumped through amulti-cartridge, high-pressure filter (3). The filteredsolution can be partly recycled to the absorber (1) andpartially expanded for regeneration.
The expanded solution, after separation of the dis-
solved gases (4) is regenerated with air in the oxi-dizer vessel (5). The whole process operates at near-ambient temperature, and no thermal regenerationnor chilling is needed. High-pressure filtration mitigatesfoaming/plugging problems, especially after the expan-sion of the solution. Due to direct recycle of the filtered
solution to the absorber, pumping costs are mini-mized. This process is highly selective; only H2S isremoved (no CO2 co-absorption and very little hydro-carbons co-absorption).
Economics: For units treating 100–300 MMscfd of gaswith a sulfur production 0.1–10 tpd, the CAPEX willbe 20–50% lower than for conventional processes.
Installations: An industrial pilot plant is treatingup to 1.7 MMscfd of gas under 1,160 psia and has beenoperated successfully for more than 6,000 hours.
Reference: Le Strat, P. Y., et al., “New redox processsuccessful in high pressure gas streams,” Oil & Gas Jour-nal, November 26, 2001, pp. 46–54.
Licensors: Prosernat IFP Group Technologies and LeGaz Integral
Contact: Christian Streicher, Marketing Manager,Prosernat, Tour Areva, 92084 Paris La Défense Cedex,France, Phone: (+33) 1 47 96 37 86, Fax: (+33) 1 47 9602 46, E-mail : [email protected]
Description: Sulfur, as produced by the Claus process,typically contains from about 200–500 ppmw H2S.The H2S may be contained in the molten sulfur as H2Sor as hydrogen polysulfides (H2Sx). The dissolved H2Sseparates from the molten sulfur readily, but the H2Sxdoes not.
The sulfur degassing process accelerates the decom-position of hydrogen polysulfides to H2S and elemen-tal sulfur (S). The dissolved H2S gas is released in acontrolled manner. Sulfur temperature, residencetime, and the degree of agitation all influence thedegassing process. Chemical catalysts, including oxy-gen (air) that accelerate the rate of H2Sx decompo-sition, are known to improve the degassing charac-teristics.
In fact, the majority of successful commercialdegassing processes use compressed air, in some fash-ion, as the degassing medium. Research performed byAlberta Sulphur Research Ltd. has demonstrated thatair is a superior degassing agent when compared tonitrogen, steam or other inert gases. Oxygen presentin air promotes a level of direct oxidation of H2S to ele-mental S, which reduces the gaseous H2S partial pres-sure and increases the driving force for H2Sx decom-
position to the more easily removed gaseous phaseH2S.
The MAG degassing system concept was developedto use the benefits of degassing in the presence of airwithout relying on a costly compressed air source.With the MAG system, motive pressure from a recir-culated degassed sulfur stream is converted to energyin a mixing assembly within the undegassed sulfur. Theenergy of the recirculated sulfur creates a high air-to-sulfur interfacial area by generating intense turbu-lence within the jet plume turning over the contentsmany times, thus exposing the molten sulfur to thesweep air. Intimate mixing is achieved along withturbulence to promote degassing. This sulfur
degassing system can readily meet a 10 ppmw totalH2S (H2S + H2Sx ) specification.
Tests show degassing rate constants nearly identi-cal to traditional air sparging for well-mixed, air-swept degassing systems. Thus, comparable degassingto air sparging can be achieved without using a com-pressed air source. The assemblies are designed to beself-draining of molten sulfur and to be easily slippedin and out for maintenance through the pit nozzlesprovided. The mixing assemblies require no movingparts or ancillary equipment other than the typical sul-fur-product-transfer pump that maximizes unit relia-bility and simplifies operations.
The process is straightforward; it is inherently saferthan systems using spray nozzles and/or impinge-ment plates because no free fall of sulfur is allowed.
Economics: Typically does not require changes toexisting sulfur processing infrastructure.
Installation: Several units are in design.
Reference: US Patent 5935548, issued August 10,1999.
Licensor: Black & Veatch Pritchard, Inc.
Contact: David K. Stevens, Vice President, SulfurTechnology, 11401 Lamar, Overland Park, KS 66211USA, Phone: (913) 458-6068, Fax: (913) 458-6098,Email: [email protected]
Safety: Hydrogen sulfide is a highly toxic and poten-tially explosive gas. A concentration of 600 ppmv islethal and is explosive at approximately 3.5% vol.Dissolved H2Sx is decomposed, and H2S is released instorage, during loading and unloading and also dur-ing transportation, thus leading to potentially dan-gerous conditions.
Product: Liquid sulfur containing 10 ppmw of H2S orless.
Description: Liquid sulfur flowing from the Clausplant to the sulfur pit contains typically 250–350ppmw of H2S + H2Sx. Sulfur is degassed using an activegas-liquid contacting system to release dissolved gas.
Adding chemicals is not required. Sulfur from the pitis pumped into the degassing tower where it is con-tacted counter-currently with hot compressed air overa fixed catalyst bed. Degassed sulfur is returned to the
product section of the sulfur pit.
Operating conditions: The operating temperaturein the sulfur degassing tower can vary from 125°C to150°C depending on the temperature in the sulfur pit.The operating pressure drop is around 0.3–0.5 bar.Treated sulfur has a residual H2S level in the range of5–10 ppmw.
Materials of construction: Mainly carbon steel.Aluminized steel may be used for the degassing tower.
Installations: Several units are in operation, designor under construction with unit capacities up to 300tpd.
SUPERCLAUS processApplication: The SUPERCLAUS process recovers ele-mental sulfur from hydrogen sulfide (H2S) containinggases originating from gas treating plants such asalkanolamine units or physical solvent plants. ModernSUPERCLAUS plants should be able to processH2S/ammonia (NH3) containing gases as well, origi-nating from sour water strippers, to yield up to 99.4%overall sulfur recovery without any further tail gasclean-up.
Description: The SUPERCLAUS process has a thermalstage followed by three catalytic reaction stages withsulfur removed between stages by condensers. Tworeactors are filled with standard Claus catalyst whilethe last reactor is filled with a new selective oxidationcatalyst.
In the thermal stage, the acid gas is burned with asubstoichiometric amount of controlled combustionair such that the tail gas leaving the second reactorcontains typically 0.8 vol.% to 1.0 vol.% of H2S. The
catalyst in the third reactor oxidizes H2S to sulfur atmore than 85% efficiency.
However, because the new catalyst neither oxidizesH2S to SO2 and water nor reverses the reaction; totalsulfur recovery up to 99% can be obtained. If sulfurrecovery more than 99% is required, one additionalClaus reactor stage will be installed upstream of theselective oxidation reactor.
Utilities: Basis: 100 tpd sulfur recovery unit; 93 vol.%H2S feed gas and catalytic incineration.
Installations: Since the first commercial demon-stration of the SUPERCLAUS process in 1988, morethan 110 plants with a capacity up to 1,165 tpd are inoperation or under construction in the first quarter of2003.
Licensor: Comprimo Sulfur Solutions, a member ofJacobs Engineering Group
SureApplication: Oxygen-enhanced recovery of sulfurfrom H2S-containing gas streams. Products are brightyellow sulfur (99.9% pure) and clean tail gas for fur-ther recovery or incineration.
Description: The capacity of a Claus-type sulfurrecovery unit can be increased by thermal combustionof H2S in two or more stages with an oxidant whichis an oxygen-rich gas stream comprised of pure oxy-gen or a mixture of air and oxygen. A portion of theoxidant is fed to a first combustion zone (1) with allor a portion of the acid gas or ammonia-containingacid gas. The reacted mixture is cooled (2) and theremaining gas streams are fed to a second combustionzone (3). After condensing sulfur, the remaining gasstream is then fed to one or more Claus converters (4).
Operating conditions: Pressures are near atmo-
spheric. Oxygen concentration in oxidant is 21% to100%. Sulfur recovery is 90% to 98%.
Economics: Replacing air with oxygen will morethan double the capacity of a Claus-type sulfur plant
and subsequent tail gas treating unit. Use of the Sureprocess is particularly attractive for revamping exist-ing Claus and tail gas units to substantially increasethe acid gas removal and for intermittent operationof such units at higher throughputs. Using the Sureprocess in new installations significantly reduces cap-ital investment.
Installations: One in Japan, one in the UK, eight inItaly and six in the US Twelve more plants in variousengineering and design phases.
Licensors: BOC Gases and Parsons Energy & Chemi-cals Group, Inc.
Contact: Arif Habibullah, P.E. , Senior Technical Direc-tor & Manager, Process Technology, Parsons E&C, 125 W Huntington Drive, Arcadia, CA 9100, Phone:(626) 294-3582, Fax: (626) 294-3311, E-mail:[email protected]
Gas Processes 2004 Sulfur recovery
321
Acid gas
Air
Oxygen
4
Liquidsulfur
To nextClausstage
Return to Gas Processes INDEX
ACORN methane washApplication: To produce a high-purity carbon monox-ide (CO) stream, and a high-purity hydrogen stream,plus a ratio adjusted synthesis gas stream, if required,for use as a chemical feedstock. The synthesis gasstream is typically the product of steam methanereforming (SMR).
Description: Feed gas for CO recovery is pretreatedto remove carbon dioxide and water, which will freezeat the cryogenic temperatures encountered in theprocess. The pretreated feed gas is cooled in the mainexchanger and fed to the bottom of the wash column(1). The column is refluxed with liquid methane to pro-duce a hydrogen wash-product free of CO, but satu-rated with methane (2–3%). The hydrogen is thenrewarmed and recovered as a product. The liquidfrom the wash column is preheated, reduced in pres-sure and separated in the flash column (2) wherehydrogen dissolved in the methane (CH4) is rejected
to fuel gas. To minimize CO losses, this column is alsorefluxed with liquid CH4.
The hydrogen-free liquid from the flash column isheated and flashed to the CO/CH4 splitter column(3). The CO from the overhead is rewarmed and com-
pressed. Part of this stream is delivered as product; theremainder is cooled and recycled within the process.It is first used to reboil the splitter column and preheatthe column feed streams. It is then flashed for refrig-eration and the liquid is used as reflux for the split-ter column. The CH4 liquid from the bottom of thesplitter is pumped to the wash column for use asreflux. The net CH4 is vaporized in the main exchangerand leaves as the byproduct fuel gas.
Variations of this cycle have been developed tomeet special requirements. In all cases, however, thehydrogen stream is produced at high pressure and theCO is available at low pressure. If CO is desired, aproduct compressor is usually required.
ACORN partial condensationApplication: To produce a high-purity carbon monox-ide (CO) stream, and a moderate-purity hydrogen(H2) stream, plus a ratio adjusted synthesis gas streamfor use as a chemical feedstock. The synthesis gasstream is typically the product of partial oxidation reac-tion (POX).
Description: Feed gas for CO recovery is pretreated toremove carbon dioxide and water, which will freeze atthe cryogenic temperatures encountered in the process.The feed gas is cooled against products in the warmexchanger, and is then further cooled providing heatfor reboiling the CO/CH4 splitter. Condensed CO andmethane (CH4) are removed from uncondensed vaporin the warm separator. Vapor from the warm separa-tor is cooled in the cold exchanger where most of theremaining CO is condensed and separated in the coldseparator. The liquid from this vessel is a high-purity COstream used as reflux for the CO/CH4 splitter.
Liquid from the warm separator is reduced in pres-sure and flashed in the flash separator to removedissolved H2. The vapor from this separator isrewarmed, compressed and recycled to the feed torecover CO. The liquid from the flash separator issent to the CO/CH4 splitter. The CO overhead from this
tower is warmed and recovered as product. The bot-toms, containing CO and CH4, is also warmed and isavailable as byproduct fuel gas. The H2 from the coldseparator is warmed in the cold exchanger, expandedto provide refrigeration for the cycle, warmed in thecold and warm exchangers and leaves the process at97–98% purity.
Variations on this basic cycle are possible depend-ing on feed gas pressure and gas composition, anddesired product purity. The H2 product is delivered athigh pressure, but the CO exits the process at lowpressure. Therefore, a CO-product compressor is usu-ally required to deliver the product to a downstreamprocess.
Gas-to-liquids (GTL)Application: To produce transportable middle dis-tillate products from natural gas. The process has ahigh carbon efficiency built around ConocoPhillips’proprietary COPox catalytic partial oxidation syngasprocess and ConocoPhillips’ proprietary Fischer-Trop-sch (FT) gas conversion process. ConocoPhillips GTL isa viable option to monetize stranded gas reserves.
Description: The front-end process (1) is based onConocoPhillips’ unique and highly proprietary COPoxcatalytic partial oxidation syngas technology. Thehydrocarbon feed conversion and selectivity to carbonmonoxide (CO) and hydrogen (H2) is higher than con-ventional equilibrium syngas production methods.The ConocoPhillips reactors have a high throughputand operate at relatively mild conditions.
The middle process (2) is based on ConocoPhillips’proprietary FT Gas Conversion Technology. The FTprocess features a highly active catalyst that generatesa paraffinic product spectrum with a high ASF alphadistribution and low methane selectivity. A higher
alpha implies the production of a greater propor-tion of heavy hydrocarbons at the expense of lessproduction of lighter hydrocarbons. Different reactorconfigurations can be used to minimize overall reac-tor volume and tailor the desired product slate.
The FT product is finished in a back-end ProductUpgrading Unit (3) that includes Hydro Processingusing both conventional and ConocoPhillips propri-etary technology.
The efficient ConocoPhillips COPox syngas and FTconversion technologies are configured with an over-all process design that delivers a high carbon effi-ciency while minimizing the required CAPEX. Theintegrated process maximizes the use of the exother-mic reaction heat and minimizes recycles.
Operating conditions: The ConocoPhillips COPoxsyngas process operates within a range of conditionsdepending on inlet gas composition. Typical operat-ing temperature range is 600–1,000°C. The Conoco-Phillips FT process operates within a typical temper-ature range of 200–250°C.
Installations: ConocoPhillips is currently starting upa 400 barrel per day (bpd) demonstration plant inPonca City, Oklahoma. Plans are to have the firstcommercial plant operating in 2010.
Licensor: ConocoPhillips will be the licensor to itsequity affiliates.
Contact: Jim Rockwell, Manager Gas to Liquids, E-mail: [email protected]
Gas Processes 2004 Synthesis Gas
LPGsNaphthaDiesel
CoPOXSG1
Productupgrade
3
FT2
Natural gas
Airseparation
unit
Tail gashandling
Air
Boilerfeed
water
SteamBoilerfeed
water
Steam
Return to Gas Processes INDEX
Gas-to-liquids (GTL)Applications: To produce a zero-sulfur, pumpable syn-crude from remote gas fields or from associated gas.The process can operate on a range of natural gasfeedstocks including fields containing high carbondioxide levels. The process is suited for remote oroffshore locations where space and weight are ofparticular concern.
Description: Natural gas is pre-treated to remove sul-fur using conventional desulfurization technology(1). Steam and recycle gases are added and the feedis further heated before passing to the CRG pre-reformer (2). Using a nickel catalyst, the CRG pre-reformer converts heavier hydrocarbons to methaneand partially reforms the feedstock. Addition of steamand further preheating is completed before the mixedgas passes to the compact reformer (3).
The Davy/BP compact reformer is a multi-tubular,counter-current reactor, which, in the presence of anickel catalyst, produces a mixture of carbon oxidesand hydrogen. Heat for this endothermic reaction isprovided by external firing of excess hydrogen pro-
duced by the process with supplementary natural gasas required. Gas leaving the reformer is cooled (4) andgenerates sufficient steam to satisfy process heatingrequirements. Excess condensate then is removed.
Dry syngas is compressed in a single-stage cen-trifugal compressor (5) and passes to a membrane-sep-aration package (6) where the surplus hydrogen is
recovered and reused as fuel. The non-permeateproduct from the membrane separation is fed to theconversion section (7) where the syngas is convertedinto a mixed paraffin and wax product using a cobaltcatalyst. The reaction system can either be a fixed bedor slurry type depending on unit size and projectneeds. Unconverted syngas is recycled to the compactreformer feed.
The wax products from the conversion section canbe hydrocracked to produce a pumpable syncrudeusing conventional hydrocracking technology (8).
Operating conditions: A wide range of reformeroperating conditions are possible to optimize theprocess efficiency.
Installations: The compact reformer and fixed-bedFT processes have been successfully demonstrated inBP’s Test Facility in Nikiski, Alaska. This facility hasbeen in operation since the second-quarter 2003.
Licensor: Davy Process Technology
Contact: 20 Eastborne Terrace, London W2 6LE, UK;e-mail: [email protected]
Gas Processes 2004 Synthesis gas
Naturalgas feed
Steam Recycle gas
Fuel
Air
Flue gas
Syncrude product
Condensate
7
1
2
6
5
4
3
8
Return to Gas Processes INDEX
MegaSynApplication: Large-scale syngas production, essen-tially hydrogen (H2) and carbon monoxide (CO), fromnatural gas or other gaseous hydrocarbons formethanol, ammonia, Fischer-Tropsch and other syn-thesis plants in one train.
Description: The hydrocarbon feedstock is preheatedand desulfurized. The gas is then saturated withwater by a circulation loop fed by process condensate.Before routing the feedgas to the autothermalreformer (prereforming is optional), this gas is pre-heated by a fired heater. Superheated gas is thensent to the autothermal reformer. If required carbondioxide (CO2) can be fed to the prereformed gas.
In the autothermal reformer (ATR), the hydrocarbonfeed is converted with oxygen to mainly CO and H2over a nickel-containing catalyst bed. The heart of theATR is the mixer-device, which facilitates the highlyexothermic reaction between oxygen and hydrocar-bon. Due to high temperatures in the ATR flamezone, reforming reactions take place here. The gas
equilibrium composition is established within the cat-alyst bed. The temperature at the ATR outlet is 900°Cto 1,050°C. Thus, high methane conversions areachieved. The reformed gas is cooled down to gen-
erate high-pressure steam, preheat feedgas, boilerfeed water and circulation water loop.
Economics: Typical figures are presented for a syn-gas generation plant delivering syngas to Fischer-Tropsch synthesis. Consumption per 1 million scfdsyngas:Natural gas (feed + fuel): 441 million Btu; oxygen: 0.22million scfd (over the fence); CO2: 0.09 million scfd; dem-ineralized water: 0.98 tons; cooling water: 11.5 tons;electricity: 22.4 kWh; export steam: 18.5 tons; specificinvestment: €224,000/million scfd syngas.
Installations: World largest natural gas-based syngasgeneration plant, world largest (single-train) autother-mal reforming unit. A total of 30 autothermal units
Licensor: Lurgi Oel-Gas-Chemie GmbH
Contact: Dr. Thomas Wurzel, Lurgi Oel-Gas-ChemieGmbH, Lurgiallee 5, D-60295 Frankfurt am Main, Ger-many, Phone: (49) 69 5808 2490, Fax: (49) 69 5808 3032,E-mail: [email protected]
Gas Processes 2004 Synthesis gas
Natural gas NG fuel
Compression(optional)
Pretreatment(Hydrodesulfurization)
Prereforming(optional)
Gas conditioning(optional)
Saturation
Process steam(optional)
Steamexport
CO2(optional)
O2
DMW
Syngas tobattery limit
Proc
ess
cond
ensa
te
Autothermal reforming
Gas cooling
Return to Gas Processes INDEX
Multipurpose gasification Application: Production of synthesis gas, essentiallyH2 and CO, from a wide range of gaseous to extraheavy liquid hydrocarbons, as well as emulsions andslurries. Recent new applications are in (chemical)waste gasification. The main advantage over com-parable processes is its extreme feedstock flexibility inthe quench mode. A boiler mode for highest effi-ciency is also available.
Description: Continuous noncatalytic partial oxida-tion process. The quench mode is shown above: hydro-carbon feedstock, moderator (H2O, CO2 or N2) and oxi-dant (pure or diluted O2, air) are fed through a specialburner into the reactor (1), a refractory-lined pressurevessel. Operating conditions are automatically con-trolled. Hot gas leaves the reactor at the bottom,passing the quench where water is injected to lowerthe temperature near the saturation value. Quenchwater washes out most particulates as unconvertedcarbon (soot) and ash.
Further cleaning occurs in a venturi scrubber (2)from where the gas passes to a medium-pressuresteam boiler (3) for heat recovery and to the finalcooler (4) before further processing. In hydrogen pro-duction, the hot, wet gas from the venturi is passeddirectly to a raw gas shift conversion. The soot/ashslurry from the process contains virtually all metals andashes from the feedstock. It is withdrawn via a slurrycollector (5) and processed in the metals ash recovery
system (MARS) (6). There, soot/ash is filtered fromthe slurry and incinerated under controlled condi-tions yielding a saleable metal/ash product. Filteredwater is returned for quenching. Excess water isstripped and sent to conventional wastewater treat-ment.
Operating conditions: Actual gasification temper-atures of 1,200°C to 1,600°C, pressures from atmo-spheric to 70 bar (or higher, if economically justified).Feedstock and oxidant preheat possible in a widerange from 100°C to 600°C, depending on type offeed. Product yields and composition vary with mod-erator rate and type of feed. Water quench is selected
for highest feedstock flexibility. At low-salt contents,the boiler mode can recover heat as high-pressuresteam, raising overall efficiency.
Economics: Characteristic consumption and pro-duction rates per ton of heavy residue feedstock: 1 to1.1 t O2 (100%), export 0.5 t MP steam to 2.2 t HPsteam, 2.2 t raw syngas (dry) equiv. to 2,600 Nm3 H2+ CO. Cold gas efficiency is 82% to 85%. In boilermode, thermal efficiencies including HP steam gen-erated are about 95% based on feedstock HHV. Thismakes the process attractive for syngas production andfor an IGCC power plant. A highly integrated andefficient power complex will be in the range of$800/kW total invested cost.
Installations: A large-scale industrial plant operatesin Germany, demonstrating full feedstock and prod-uct flexibility by feeding to a methanol and IGCCcomplex. Another plant gasifies residue asphalt pro-ducing syngas for an ammonia plant.
Reference: Liebner, W., and C. Erdmann, “MPG—Lurgi Multipurpose Gasification—Recent Applicationsand Experiences,” World Petroleum Congress 2000,Calgary, Canada, June 2000.
Metals ashrecovery system MARS(soot slurry treatment)
6
Quench
Return to Gas Processes INDEX
Syngas (ATR)Application: Produce CO-rich synthesis gas.
Products: Pure carbon monoxide (CO) and hydrogen(H2) or synthesis gas for methanol, synthetic fuels, oxo-synthesis or ammonia. Very large-scale productionof synthesis gas for GTL plants.
Description: The process combines partial oxidationand adiabatic steam reforming using a fixed catalystbed (nickel catalyst). Soot-free operation is secured byproprietary burner design and application.
The unit consists of a feed preheater (1), feed desul-furization (2), pre-reforming (optional) (3), autother-mal reformer reactor with burner, combustion cham-ber and catalyst bed (4), heat-recovery section (5)and, when required, gas purification section, e.g.,CO2 removal (not shown).
The autothermal reformer burner features lowmetal temperatures and high resistance to mechani-cal wear, thus ensuring long burner lifetime. Theburner is manufactured in commercially availablehigh-temperature alloys without cooling circuits.
The hydrocarbon feedstock can be natural gas, LPGor naphtha. The oxygen feed can be pure oxygen, airor enriched air. CO2 recycle or CO2 import can be
applied to adjust synthesis gas composition.
Operating conditions: Typically, CO-rich synthesis gasis obtained at feed ratios of H2O/CH4 = 0.2 to 1.5 andCO2/CH4 = 0.0 to 2.0, resulting in synthesis gas ratiosH2/CO—0.8 to 2.5 at reactor exit temperatures of950°C to 1,050°C. Reactor pressure ranges between 20bar and 70 bar.
Installations: Since 1958, 26 complete installationshave been licensed. New burner technology with
improved lifetime was introduced in 1992 and is inoperation in 20 autothermal reforming plants and 8secondary reforming plants. Six burners are on orderfor GTL plants with up to 17,000-bpd capacity per line.Recently, LOIs have been obtained for ATR installationsfor GTL projects in South Africa and Qatar.
References: Christensen, T. S. and I. I. Primdahl,“Improve Syngas Production Using AutothermalReforming,” Hydrocarbon Processing, March 1994, p.39.
Christensen, T. S., et al., “Burners for Secondaryand Autothermal Reforming—Design and IndustrialPerformance,” Ammonia Plant Safety, Vol. 35, 1994,p. 205.
Christensen, T. S., et al., “Syngas Preparation byAutothermal Reforming for Conversion of NaturalGas to Liquid Products (GTL),” Monetizing StrandedGas Reserves Conference, San Francisco, 1998.
Ernst, W. S., et al., “Push Syngas Production Limits,”Hydrocarbon Processing, March 2000, p. 100-C.
Licensor: Haldor Topsøe A/S
Contact: Jørgen N. Gøl or Peter Søegaard-Andersen,Nymollevej 55, DK-2800 Lyngby, Denmark, Phone:(45) 45 27 2000, Fax: (45) 45 27 29 99, E-mail: [email protected] or [email protected]
Gas Processes 2004 Synthesis gas
Sulfurremoval
Pre-reforming
Firedheater
Autothermalreformer
Steamproduction
Synthesisgas
Steam exportProcess steamCO2 rich gasNatural gas
Hydrogen
Oxygen
Boiler feedwater
2
1 45
3
Return to Gas Processes INDEX
Syngas (autothermal)Application: Production of carbon monoxide andhydrogen for petrochemical use. Typical consumers areoxo-alcohol synthesis units and methanol synthesisunits.
Products: Synthesis gas containing carbon monoxideand hydrogen. The synthesis gas can be used directlyfor chemical production or alternatively can be furtherprocessed to yield high-purity carbon monoxide andhigh-purity hydrogen.
Description: The feed is preheated (1) and thendesulfurized in a conventional hydrotreating-zincoxide system (2). Steam is added to the desulfurizedfeed. Carbon dioxide recycle (optional) is also added.The feed mixture is sent to the autothermal reformer(3) a refractory-lined vessel containing catalyst and aburner. The feed mixture is burned with oxygen in theburner located near the top of the reformer vessel.Partial oxidation reactions occur in a combustionzone just below the burner. The mixture then passesthrough a catalyst bed where reforming reactionsoccur. The gas exits at about 1,700°F to 1,900°F,
depending on the final product specifications.The exit gas is cooled and passed through a carbon
dioxide removal unit (4). The resulting process gas con-sists primarily of carbon monoxide and hydrogen andis available as product synthesis gas. This synthesis gascan be used to make a variety of chemicals, includingmethanol and oxo alcohols. Alternatively, the gascan be further processed (typically by cryogenic sep-
aration) to yield high-purity carbon monoxide andhigh-purity hydrogen.
Carbon dioxide can be recycled to adjust the H2/COproduct ratio. For natural gas feedstocks, the H2/COproduct ratio ranges from about 2.7 (for no CO2 recy-cle) to 1.6 (for full CO2 recycle).
Autothermal reforming technology is similar to sec-ondary reforming for ammonia production, exceptthat oxygen is used as feedstock instead of air. Oxy-gen is required since nitrogen would dilute the H2/COproduct gas purity.
Economics: The economics can be favorable forautothermal reforming when oxygen is available atrelatively low cost. For natural gas feedstocks, theoptimum H2/CO product ratio is about 1.6 to 2.7.
Reference: Tindall, B. M., and M. A. Crews, “Alterna-tive technologies to steam-methane reforming,”Hydrocarbon Processing, November 1995.
Supplier: CB&I Howe Baker
Contact: Mr. Craig E. Wentworth, vice president ofsales, CB&I Howe-Baker, 3102 East Fifth St., Tyler, TX75701, Phone: (903) 595-7911, Fax: (903) 595-7751, E-mail: [email protected]
Gas Processes 2004 Synthesis gas
4
1
2
3
Heatrecovery Synthesis
gas product
CO2 recycle(optional)
Natural gas O2Export steam
H2product
CO product
Purification(optional)
Return to Gas Processes INDEX
Syngas-advanced SMRApplication: Produce a CO-rich synthesis gas.
Products: Pure CO and H2, or mixtures of CO and H2(synthesis gas), are used to manufacture many chem-icals, e.g., acetic acid, oxo-alcohols and isocyanates.
Description: Advanced steam reforming in a fired-tubular reformer is the predominant process route formedium-sized synthesis gas plants. The Topsøe side-fired reformer and reforming catalysts enable oper-ating at low steam-to-carbon ratios, high reformeroutlet temperature and high heat flux.
The hydrocarbon feedstock can be natural gas, LPGor naphtha. For heavy feedstocks, an adiabatic pre-reformer is needed upstream of the tubular reformer.Carbon dioxide (CO2) import and/or CO2 recycle isapplied to produce CO-rich synthesis gas.
The unit typically consists of a feed desulfurization,pre-reforming, tubular reforming, CO2 recovery andrecycle, and final purification. Purification of the syn-thesis gas by membrane, cold box and PSA is depen-
dent on the required end-product specifications.
Operating conditions: Typically, CO-rich synthesis gasis obtained at feed ratios of H2O/CH4 = 1.5 to 2.0with CO2 recycle and/or CO2 import. This results inH2/CO ratios down to 1.8 at reformer exit tempera-tures of 950°C (1,740° F). Even lower H2/CO ratios can
be obtained by CO2 reforming using the SPARG pro-cess or by applying a high-activity, noble-metal reform-ing catalyst.
Economics: Production CO-rich synthesis gases atadvanced steam reforming conditions offers signifi-cant savings in operating and investment costs.
References: Vannby, R. and C. Stub Nielsen, “Oper-ating experience in advanced steam reforming,” Sym-posium on Large Chemical Plants, Antwerp, October1992.
Winter Madsen, S. and J-H. Bak Hansen, “Indus-trial aspects of CO2 reforming,” AIChE spring meeting,Houston, March 1997.
Winter Madsen, S., et al., “Advanced reformingtechnologies for synthesis gas production,” Symposiumon Large Chemical Plants, Antwerp, September 1998.
Feedstock: Natural gas, multiple feedstock and naph-tha.
Product: Synthesis gas for the production of carbonmonoxide, hydrogen (H2), ammonia, methanol, Fis-cher-Tropsch synthetic fuel and oxo-chemicals.
Description: Autothermal reforming can be used asan alternative to conventional steam reforming. Feed-stock is preheated and subsequently desulfurizedbefore entering the adiabatic reactor (ATR) combus-tion chamber. At the ATR top, the feed mixture isburned with oxygen in a partial oxidation chamber.The main feature of the ATR design is the uniquearrangement of water cooled oxygen nozzles in the
ATR dome. This method allows for complete mixingwithout any metal internals in the combustion zone,thus ensuring a long burner life.
After entering a nickel-based catalyst bed where thesteam reforming reactions occurs, the reformed gas
leaves the ATR at about 1,050°C. The gas passes thecooling train before entering the required purificationsection, e.g. carbon dioxide (CO2) removal, cryogenicseparation, etc.
Installation: Uhde’s autothermal reforming tech-nology is derived from the secondary reformer usedin the ammonia technology, except that oxygeninstead of air is applied. The water cooled burnernozzles arrangement has been tested successfullyover ten years in a 12,000 Nm3/h H2/CO demonstra-tion unit based on Uhde’s proprietary combinedautothermal reforming (CAR) technology.
Reference: Babik A. and J. Kurt (Uhde), “Slovakianrefiner operating new hybrid hydrogen-productionprocess,” Oil & Gas Journal, March 21, 1994 OGJ SPE-CIAL
Product: Synthesis gas for hydrogen, ammonia,methanol, Fischer-Tropsch-synfuel, oxo-synthesis prod-ucts, etc.
Description: The steam-reforming process comprisesthe high-temperature reaction of methane or lighthydrocarbons over a nickel catalyst that produceshydrogen and carbon monoxide (CO). The reformingoccurs in tubes packed with catalyst and arranged ver-tically in gas-fired steam reformers. A nickel catalystis used and applied to a supporting structure. Theoperating conditions of the steam reformer vary anddepend on the application, with discharge tempera-tures ranging from 740°C to 950°C and pressures upto 50 bar. This wide range of operating conditionsnecessitates a versatile reformer design.
The Uhde steam reformer is a top-fired reformer
which has tubes made of centrifugally cast alloy steeland a proprietary “cold” outlet manifold system. Thereformer and outlet system design have proved its suit-ability over the past decades. It satisfies the demandsof various applications and permits constructing andoperating world-scale reformers with unrestricted reli-ability. The largest reformer, based on Uhde tech-nology, consisted of 960 tubes.
Installations: More than 60 Uhde reformers existworld-wide. The first Uhde reformer with a cold out-let manifold went onstream in 1966. In 1977 and1984, two large Uhde steam reformers with 540reformer tubes each were commissioned, and theseunits are still in operation today. The company hasrecently commissioned two large ammonia/urea com-plexes based on natural gas in Qatar and Egypt withammonia syngas capacities of 96,000 Nm3/h of CO +H2 and 81,000 Nm3/h of CO + H2, respectively. A plantfor oxo-chemicals supplied by Uhde to South Korea hasan oxo-syngas production capacity of 9,700 Nm3/h ofCO + H2. Uhde has recently commissioned two world-scale hydrogen plants for SINCOR C.A., Venezuela (23 98,000 Nm3/h) and Shell Canada Ltd., Canada (2 3130,000 Nm3/h).
Reference: Fritsch, S., “Steam reformer based hydro-gen plant optimization,” The International ConferenceHYFORUM 2000, Munich, September 2000.
ADIPApplication: The regenerative-amine process removeshydrogen sulfide (H2S) and carbon dioxide (CO2) fromnatural gas, refinery gases and synthesis gas. Hydro-gen sulfide can be reduced to low sulfur levels. Theprocess can also be applied to remove H2S, CO2 andcarbonyl sulfide from liquefied petroleum gas or nat-ural gas liquids (NGL) to low levels. Bulk CO2 removalfrom synthesis gas with flash regeneration is anotherapplication.
The process sequence-ADIP/Claus/SCOT-can be usedadvantageously with an integrated ADIP system thathandles selective H2S removal upstream and the SCOTprocess treating the Claus offgas.
Description: The ADIP process uses aqueous solutionsof the secondary amine, di-isopropanolamine or thetertiary amine, methyl di-ethananolamine. Amineconcentrations up to 50%wt can be applied.
The process has low observed corrosion rates and acontrollable foaming tendency of the solvent due toan optimized design. Its line-up can be very diverse,depending on the application. High integration of sep-arate process units is possible.
The simplest system resembles those of other amineprocesses. The ADIP liquid treating consists of an
extractor followed by mixer/settlers for COS removal.Common regeneration for separate amine absorbersis often applied. Solvent composition will be opti-mized for customer requirements.
For a typical design, the co-absorbed hydrocarbonsfrom the absorber (1) are flashed (2) from the solventand used as fuel gas after treatment (3). The solventis flashed again (4) to release CO2 from the enrichmentabsorber (5), thereby improving the acid-gas compo-sition from the regenerator (6) to the Claus unit.
Operating conditions: A very wide range of treat-ing pressures and contaminant concentrations canbe accommodated. Sulfur specifications of 100 mbaraH2S in gas and 10 ppmw in liquid hydrocarbon streamscan be met. In liquid hydrocarbon, COS can beremoved down to 5 ppmw. Improved Claus feed gasquality can be met by improving the H2S/CO2 ratio inthe acid gas. Bulk CO2 removal from a high percent-age to several percentage points is easily attained.
Installations: More than 400 ADIP units are in oper-ation or under construction.
ADIP-XApplication: This regenerative-amine process ishighly suitable for bulk and deep carbon dioxide(CO2)-removal from gas streams. It also removeshydrogen sulfide (H2S), some COS and mercaptansfrom natural gas, refinery gas and synthesis gas.Hydrogen sulfide can be reduced to low-sulfur levels.This process achieves a higher loading capacity andreduced equipment size compared to general aque-ous amine solvents.
Description: The ADIP-X process uses aqueous solutionsof the tertiary amine, methyl diethananolamine and anadditive. Amine concentrations up to 50%wt can beapplied. The process has low observed corrosion ratesand a controllable foaming tendency of the solvent dueto an optimized design. Its lineup can be very diverse,depending on the application. High integration ofseparate process units is possible. The simplest systemresembles those of other amine processes. Common
regeneration for separate amine absorbers is oftenapplied and may consist of one or more flash/steam stripregeneration steps. Solvent composition will be opti-mized for customer requirements.
Operating conditions: A very wide range of treat-ing pressures and contaminant concentrations can
be accommodated. Carbon dioxide specificationsbelow 50 ppmv in gas streams can be met. Hydrogensulfide specifications down to 100 mbar are alsoachievable. Bulk CO2 removal from a high percentageto several percentage points is easily attained.
Installations: ADIP-X is applied in one natural gasapplication.
References: “Faithful solvent learns new tricks: Prac-tical experience with Shell accelerated Sulfinol andMDEA,” Laurance Reid, February 2003.
“Deep removal of CO2 and H2S from natural gas inLNG applications,” Gas Processors Association, Rome,March 2002.
Licensor: Shell Global Solutions International B.V.
Advanced aminesApplications: Advanced Amines is a complete port-folio of amine (DEA, MDEA and activated MDEA)based processes to sweeten natural gases. TheAdvanced Amines processes cover all types of acid gasremoval applications, for any feed gas compositionand product specifications as low as hydrogen sulfide(H2S) <1 ppm and carbon dioxide (CO2) <50 ppm.
Description: The Advanced Amines portfolio is basedon TOTAL’s extensive industrial and operational expe-rience which developed these technologies (initiallySNEA-(P), ELF Group). It includes the following pro-cesses:
• High load DEA: based on using high concentra-tion (4 mol DEA/l) and high loading (mol acid gas/molDEA) DEA, for high performance complete deacidifi-cation.
• Selective MDEA: based on using pure MDEAaqueous solution for selective H2S removal or H2Senrichment applications.
• Activated MDEA: for all complete deacidifica-
tion and bulk CO2 removal applications, with a rangeof patented activators. Activated MDEA offers specificadvantages like partial/total flash regeneration ofthe solvent for CO2 removal applications.
For all these processes various flow schemes areavailable, from the conventional absorber/thermalregenerator process up to more sophisticated flowschemes. For instance, the Double Split Flow scheme,
shown in the figure, maximizes acid gas removal andminimizes energy requirements. It uses a flow ofsemi-lean amine, withdrawn from the thermal regen-erator’s (3) intermediate level and sent back at theabsorber’s (1) intermediate level. Energy require-ments can also be minimized by using activated MDEA,with flash regeneration of the solvent. With highload DEA, a proprietary absorber design is also avail-able which allows high COS hydrolysis levels (up to95% COS removal).
Installations: More than 120 units, among whichabout one fifth operated by TOTAL, with unit capac-ities between 0.3 and 25.2 Nm3/d.
References: “MDEA based solvents used at the Lacqprocessing plant,” Elgue J. and F. Lallemand, GPAEurope meeting, January 18, 1996.
Licensor: Prosernat–IFP Group Technologies
Contact: Christian Streicher, Marketing Manager,Prosernat, Tour Areva, 92084 Paris La Défense Cedex,France, Phone: (+33) 1 47 96 37 86, Fax: (+33) 1 47 9602 46, E-mail : [email protected]
Gas Processes 2004 Treating
Acid gas
Water makeup
3
2
1
Flash gasFeedgas
Treated gas
Return to Gas Processes INDEX
aMDEA processApplication: Removal of carbon dioxide (CO2), hydro-gen sulfide (H2S), COS and RSH from synthesis gas, nat-ural gas or other gases.
Products: Treated gas to meet pipeline, liquefiednatural gas (LNG) plant, ammonia plant or petro-chemical plant specifications. Acid offgas with verylow inert gas content. Production of food-gradeCO2 is possible.
Description: Acid components, found in the feedgas, are removed by absorption with an aqueoussolution of MDEA and an activator system. The richsolution leaving the absorber is regenerated by flash-ing and/or stripping through one or more regenerat-ing steps. Different process configurations can becombined with various solvent types and concentra-tions to meet requirements for individual applica-tions. It is possible to customize gas treatment to thecustomers’ economic priorities.
Operating conditions: Reference plants cover arange from 3,000 to 810,000 Nm3/hr feed gas capac-
ity, absorber temperatures from 30°C to 90°C, absorberpressures from atmospheric range up to 120 bar andfeed gas compositions from 0.5 to 25 vol.% CO2 and0 to 15 vol.% H2S. Treatment at higher pressures withmore CO2 /H2S in the feed gas is achievable.
Economics: The process is highly energy efficientdue to the elevated acid-gas loadings achievable with
the solvent; this enables using low circulation rates andreduced energy consumption, as well as reducingrequired equipment size. Energy consumption forCO2 removal from ammonia synthesis gas: 1 kWh/kmolCO2 electrical power and 32 MJ/kmol CO2 thermalenergy. Thermal energy consumption for natural gastreatments: 15–20 MJ/kmol CO2 and H2S removed(flash regeneration).
Additional advantages: very low hydrocarbon co-absorption, no degradation products, no corrosion(mainly carbon steel equipment can be used), lowfoaming tendency, no reclaimer operation is necessary,and the solvent is nontoxic and biodegradable.
Installations: More than 200 plants in operationand over 30 units are under design or construction,mostly treating synthesis gas, natural gas and hydro-gen streams.
Amine Guard FSApplication: Remove CO2 and H2S from natural gas;CO2 from ammonia syngas, etc., with a solution con-taining one of the UCARSOL family of formulatedsolvents offered by Dow. When desired, H2S can beremoved selectively to provide a superior Claus plantfeed and reduce regeneration requirements.
Product: Purified gas to meet pipeline, LNG plant,ammonia plant or petrochemical plant specificationsas appropriate.
Description: The treating solution scrubs acid gasesfrom the feed in an absorber column (1). The rich solu-tion is regenerated by reducing its pressure and strip-ping with steam in the stripper tower (2). Waste heatis commonly used to provide the steam.
Regeneration energy is minimized by choosing the
optimum UCARSOL solvent for the situation, usinghigh solvent concentrations and proper selection ofprocess parameters.
Operating conditions: Absorption pressure is atmo-
sphere to 1,800 psi, as available. Feed temperature is85°F to 150°F. Acid gas content may be 5–35%.
Economics: For a 500-million scfd natural gas unithaving a feed gas containing 6% CO2 and 1% H2S, typ-ical costs are as follows:
Installations: Approximately 500 units worldwide,mostly treating natural gas, ammonia syngas andhydrogen streams.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Treating
Feed gas
OffgasPurified gas
Leansolution
Richsolution
3
21
Return to Gas Processes INDEX
Ammonia Claus technology—ACTApplication: Sulfur recovery from hydrogen sulfide(H2S) contained in ammonia (NH3) bearing feeds, typ-ically acid gases from sour water strippers (SWS).
Product: Bright yellow high-purity sulfur and NH3decomposition in elemental species like nitrogen andwater (H2O).
Description: Conventional straight-through Clausplant configuration applying a single zone reactor fur-nace that can operate when NH3 volume concentra-tion in the feed gas is lower than a few tenths of a per-cent. At higher NH3 concentrations, especially from aSWS gas stream, which is mainly NH3, H2S and H2O, itbecomes necessary to destroy NH3 in order to avoidsevere operational problems that may occur in the sul-fur recovery units (SRU).
In fact, NH3 in the presence of H2S forms ammonium(poly) sulfide, which solidifies at temperatures below150°C and tends to plug sulfur condensers, sulfurrun-down lines and seal pots. In addition to plug-
ging problems, NH3 in sulfur recovery gas feedsincreases plant size, related cost and decreases sulfurrecovery.
To fully destroy NH3, the straight-through typeplant can still be applied but with different burn con-figurations conceived to attain the operating condi-tions needed for NH3 decomposition. In ACT, a dual-stage burn strategy is used by applying a “two zonefurnace” design in which NH3 bearing stream is burnedwith part of the amine acid gas (NH3 “free” stream)
in zone 1 at high temperature, followed by reinject-ing the remaining amine acid gas into zone 2 of thereaction furnace. In addition a high intensity properlydesigned burner, having excellent mixing character-istics, is used to easily reach the required high tem-perature levels.
Operating conditions: The operating temperaturein the ACT “two zone furnace” configuration canvary between 1,350°C and 1,650°C and the ACT pres-sure drop is around 0.3 bar. By adopting ACT, an NH3bearing feed can be treated up to a level of NH3 con-centration in the furnace effluent gas that is notharmful for regular SRU operation.
Economics: ACT uses standard equipment and car-bon steel almost everywhere.
Commercial plants: Several ACT plants have beenbuilt with NH3 concentration in the feed stream rang-ing from 0.5% to 30%. The most recent plant, underconstruction, is at Gorlice, Poland for Lurgi Bipronaft( Lurgi Group Co.) with 14% vol. of NH3 in the feed gas.
BenfieldApplication: Removal of CO2 and H2S from naturalgas, syngas, etc. Removal of CO2 from ammonia syn-gas, ethylene oxide recycle gas, etc.
Product: Purified gas to meet pipeline or LNG plant,ammonia plant or petrochemical plant specificationsas appropriate.
Description: Acid gases are scrubbed from the feedin an absorber column (1) using potassium carbonatesolution with Benfield additives to improve perfor-mance and avoid corrosion. The rich scrubbing solu-tion is regenerated by reducing its pressure and strip-ping with steam in the stripper tower (2). Waste heatis commonly used to provide the steam. In the LoHeatversion, the hot, lean solution is flashed by sendingthe steam through ejectors to reduce the energyrequirements. In the HiPure version, acid gases arereduced to very low levels by polishing using an inte-grated DEA absorption loop.
Operating conditions: Absorption pressure is 150 to1,800 psi, as available. Feed temperature is about150°F to 250°F. If the feed is available at a highertemperature, that heat will be used to supply regen-eration heat. Acid gas content may be 5–35%. Heavyhydrocarbons are easily handled. If no H2S is present,oxygen contents of several percent are handled with-
out difficulty or solvent degradation.
Economics: The extensive use of carbon steel, theelimination of a rich/lean solution heat exchanger, theheat recovered by LoHeat and the low cost of the solu-tion chemical make the process attractive for a widerange of applications. For a 500-million scfd naturalgas unit having a feed gas containing 6% CO2 and 1%H2S, typical costs are as follows:
Installations: Of the more than 700 units world-wide, more than 65 treat natural gas, over 200 treatammonia syngas and about 110 are in hydrogenplants. The remainder are in SNG, partial oxidation,coal gasification and petrochemical applications.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Treating
1 32
Purified gas out
Rawgas in
Leansolution
Richsolution
Acidgas
Steam
Return to Gas Processes INDEX
CO2 recoveryApplication: Recover high-purity, including food-grade, CO2 from oxygen-containing gases such asboiler flue gases, gas turbine exhausts and wastegases using Kerr-McGee/ABB Lummus Global absorp-tion/stripping technology.
Description: CO2-containing feed gases are firstcooled and scrubbed (1), if necessary, to reduce SO2levels. The gases are boosted slightly in pressurebefore entering the recovery system.
The system is based on absorption/stripping usinga monoethanolamine (MEA) solution. Feed gases aresent to an amine absorber (2) where they are scrubbedwith MEA to recover CO2. The scrubbed gases arevented to the atmosphere after water washing inthe absorber’s top to minimize MEA losses. Rich solu-tion from the MEA absorber is preheated in anexchanger (3), flashed and sent to a stripper (5) whereCO2 is recovered overhead. Condensate from thestripper overhead is returned to the system.
Lean MEA from the stripper (5) is cooled (3, 7), fil-tered (6) and returned to the absorber. Periodically,a batch reclaiming operation (8) is conducted to purgeMEA degradation products and to recover MEA by
decomposing heat-stable salts. CO2 recovered from the stripper overhead may be
compressed and used as a vapor product, or dried andliquefied using a standard ammonia refrigerationsystem to produce a liquid product.
Operating conditions: Operating units have exhib-ited availability factors in excess of 98%. Absorptionand stripping operations take place at slightly aboveatmospheric pressure. Moderate levels of SO2 and
NOx in the feed are acceptable. SO2 prescrubbing isrequired only with SO2 levels higher than 25 ppmv.
Economics: Typical capital investment for a 200-tpdCO2 plant is $9 million. Liquefaction facilities wouldadd roughly $4 million to the capital investment. Util-ity consumptions used in a design are determinedfrom utility costs and availability. Typical utility andchemical requirements per ton of CO2 recovered areas follows (for the recovery section only):
Steam, LP, t 1.9 to 2.7 Water, cooling, gal: 23,000 Power, kWh: 100 Chemicals, $ 1.00
Installations: Four units are operating on coal-firedboiler flue gases. Two plants produce gaseous chem-ical-grade CO2 and two produce food-grade liquid.Capacities range from 150 tpd to 800 tpd. Maximumtrain capacity for high CO2 content feeds is approxi-mately 2,700 tpd.
Licensors: Randall Gas Technologies, ABB LummusGlobal Inc.
CO2 removal—MolecularGateApplication: Simultaneously removes carbon dioxide(CO2) and water from contaminated natural gas.Feedstocks include coalbed methane and natural gas.Water-saturated feeds and CO2 levels of 3% to 40%can be treated. Product is pipeline-quality naturalgas with characteristic CO2 levels of less than 2%.The process uses a specialty adsorbent for CO2 removalin a patent-pending, proprietary, pressure swingadsorption (PSA) system.
Description: Water-saturated feed, at pressure lev-els between 100 psig and 800 psig, is routed througha series of adsorber vessels. One or more vessels areremoving the water and CO2 while pipeline-qualitynatural gas flows through the adsorbent bed at essen-tially feed pressure. Typically, between three andeight adsorber vessels are used. When the adsorbentis saturated with water and CO2, the spent vessel isremoved and replaced with a regenerated one. It is
depressurized and produces a low-pressure, methane-rich stream for compression/recycle to the feed and alow-pressure fuel stream containing CO2 to berejected. To maximize adsorbent capacity, impuritiesare removed through a single-stage vacuum blower.If the feed contains C3
+ components in large quanti-ties an NGL recovery section can be added to producea mixed NGL product containing these components at
high recovery rates. The system is flexible for a widerange of CO2 concentrations and has turndown capa-bility to 30%. Modular construction facilitates instal-lation.
Economics: The technology can be cost-effectivelyapplied to a wide range of flowrates. A small, 2-MMscfd unit’s typical total installed cost is $0.30/Mft3
of feed processed. This cost decreases to less than$0.15/Mft3 for a 10-MMscfd design. Modular con-struction allows low-cost installation and equipmentrelocation flexibility.
Installations: Two units are in operation.
Reference: Mitariten, M. J., “Eliminating carbondioxide from coalbed methane using the MolecularGate adsorption process,” Third Annual Coalbed andCoal Mine Methane Conference, Denver, March 2002.
Licensor: Engelhard Corp.
Contact: Michael Mitariten, Business Manager, Molec-ular Gate, Phone: (732) 205-6979, Fax: (732) 205-5915,E-mail: [email protected]
Gas Processes 2004 Treating
Moleculargate
adsorbers
Methane recycle
Fuel
Productnatural gas
CO2 < 2%
Feed gasCO2 3% to 40%
Return to Gas Processes INDEX
CYNARA membrane technologyApplication: Carbon dioxide (CO2) removal fromhydrocarbon gas streams such as produced natural gas,associated gas and associated natural gas liquidsrecovery. The systems are used for high CO2 gas bulkremoval as in offshore applications and onshore EOR,and to remove CO2 to meet pipeline gas specificationsin low CO2 gas streams onshore.
CYNARA membranes can also be applied to createa high quality CO2 product (+95% CO2) for reinjection.The unique hollow fiber design allows condensationof liquid hydrocarbons from rich gas streams (i.e.,EOR) during separation.
Description: Systems use CYNARA asymmetric, hol-low membrane fibers to selectively separate CO2 fromhydrocarbon streams. The membrane is a polymericmaterial that, unlike filters, molecularly interacts withthe gas components to transport them through themembrane wall.
Membrane modules are housed in vertical cases andskid packaged to reduce installation and site workcosts. System configurations (i.e., staged units, pri-mary/secondary units, and parallel units) are quiteflexible to meet various process objectives.
Economics: CYNARA membrane systems range from5 to 750 million scfd and process various feed com-positions. Generally, economics favor feed streamscontaining 15% to 85% CO2, but CYNARA mem-branes have been successfully applied in lower CO2streams to polish gas to pipeline specifications.
Liquids recovery and environmental factors also
favor CYNARA membrane systems over solvents andother membranes. Secondary membrane systems canbe designed to further recover hydrocarbons from theprimary permeate stream.
Operating conditions: CYNARA membranes canprocess a variety of gas compositions from 5% to90% CO2 in the inlet to outlets of 1.5% to 23% CO2.Systems are designed with an application specificpretreatment process that removes harmful contam-inants while optimizing feed temperature and pres-sure for membrane selectivity and efficiency. CYNARAmembranes typically operate with CO2 partial pressureless than 500psi.
Installations: Over 30 installations including thefirst large scale commercial CO2 membrane facility(SACROC, 367 million scfd with >98.6% availability for20 years), and the world’s largest offshore membraneplant (750 million scfd).
Licensor: NATCO Group Inc.
Contact: Gary Blizzard, NATCO Group, 2950 N. LoopWest, Suite 700, Houston, TX 77092, Phone: (713)975-6121, E-mail: [email protected]
Gas Processes 2004 Treating
Membrane
Pretreat
Inlet gasMembrane
CO2 permeate gas
Product gas
Liquid hydrocarbons
Secondaryoptional
Return to Gas Processes INDEX
FLEXSORB solventsApplication: Remove H2S selectively, or remove agroup of acidic impurities (H2S, CO2, COS, CS2 andmercaptans) from a variety of streams, dependingon the solvent used. Flexsorb SE technology has beenused in refineries, natural gas production facilitiesand petrochemical operations.
Flexsorb SE or SE Plus solvent is used on: hydro-genated Claus plant tail gas to give H2S, rangingdown to H2S < 10 ppmv; pipeline natural gas to giveH2S < 0.25 gr/100 scf; or Flexicoking low Btu fuelgas. The resulting acid gas byproduct stream is richin H2S.
Hybrid Flexsorb SE solvent is used to selectivelyremove H2S, as well as organic sulfur impurities com-monly found in natural gas.
Flexsorb PS solvent yields a treated gas with: H2S < 0.25 gr/100 scf, CO2 < 50 ppmv, COS and CS2 <1 ppmv, mercaptans removal >95%. This solvent is pri-marily aimed at natural gas or syngas cleanup. Thebyproduct stream is concentrated acid gases.
Description: A typical amine system flow scheme isused. The feed gas contacts the treating solvent in theabsorber (1). The resulting rich solvent bottom streamis heated and sent to the regenerator (2). Regenera-
tor heat is supplied by any suitable heat source. Leansolvent from the regenerator is sent through rich/leansolvent exchangers and coolers before returning to theabsorber.
Flexsorb SE solvent is an aqueous solution of a hin-dered amine. Flexsorb SE Plus solvent is an enhancedaqueous solution, which has improved H2S regenera-bility yielding <10 vppm H2S in the treated gas. HybridFlexsorb SE solvent is a hybrid solution containingFlexsorb SE amine, a physical solvent and water. Flex-sorb PS solvent is a hybrid consisting of a different hin-dered amine, a physical solvent and water.
Economics: Lower investment and energy require-ments based primarily on requiring 30% to 50% lowersolution circulation rates.
Installations: Total gases treated by Flexsorb sol-vents are about 2 billion scfd and the total sulfurrecovery is about 900 long tpd.
Flexsorb SE—28 plants operating, one in designFlexsorb SE Plus—15 plants operating, two in designHybrid Flexsorb SE—two plants operating, two in
designFlexsorb PS—four plants operating.
Reference: Garrison, J., et al, “Keyspan Energy CanadaRimbey acid gas enrichment with FLEXSORB SE Plustechnology,” 2002 Laurance Reid Gas ConditioningConference, Norman, Oklahoma.
Adams-Smith, J., et al, “Chevron USA ProductionCompany Carter Creek Gas Plant FLEXSORB tail gastreating unit,” 2002 GPA Annual Meeting, Dallas.
Licensor: ExxonMobil Research and Engineering Co.
Contact: Dr. Girish Chitnis, ExxonMobil Researchand Engineering Company, 3225 Gallows Road, Fair-fax, Virginia 22037-0001 USA, Phone: (703) 846-2724,Fax: (703) 846-2725, E-mail: [email protected]
Gas Processes 2004 Sulfur
Treated gas
Acid gasto Claus
Rich amine
Lean amine
Feed gas 1
2
Return to Gas Processes INDEX
Fluor ammonia destructionprocessApplication: Ammonia (NH3) and hydrogen sulfide(H2S) are usually encountered in refinery sour waterstripper offgas. This gas is often processed in a Claussulfur plant prior to venting to atmosphere. Ammo-nia must be completely destroyed in the Claus plantreaction furnace to prevent deposition of ammoniasalts in the downstream equipment.
Description: The process utilizes a split-flow reactionfurnace to destroy NH3. All the NH3 containing sourwater acid gases from the sour water stripper (SWS),and all the combustion air is mixed with a controlledportion of the amine acid gas stream from the aminetreating units.
The furnace is divided into two zones. The NH3-richstream combustion occurs in the first zone at 2,650°Fto 2,800°F. This temperature is sufficiently high toensure complete NH3 destruction. Zone 1 temperature
is controlled by the amine acid gas amount divertedto that zone. The balance is sent to the reaction fur-nace’s Zone 2 and mixed with the combustion prod-ucts from Zone 1.
Installations: Five plants engineered or constructed.
References: Chow, T. K., J. A. Gebur and V. W. Wong,“Trends, issues and technology advances in sulfurrecovery for a greener environment,” WorldPetroleum Congress 2nd Regional Meeting, December2003.
Licensor: Fluor Enterprises, Inc.
Contact: Thomas Chow, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-4247, Fax: (949)349-2898, E-mail: [email protected]
Gas Processes 2004 Treating
Claus reactionfurnace
Zone1
Burner
NH3 containingSWS offgas
Combustion air
Zone2
Wasteheat
boiler
Processgasses to
catalytic stages
Return to Gas Processes INDEX
Fluor Econamine FG Plus processApplication: Econamine FG Plus is an energy efficient,patents pending process used to recover carbon diox-ide (CO2) from low-pressure, oxygen (O2) containingstreams, such as burner flue gas, combined cycle gasturbine flue gas and coal-fired power plant flue gasstreams.
Description: Flue gas is cooled in a direct contactcooler (1) and is sent to a blower to overcome pres-sure losses though the system. It then enters theabsorber (2) bottom and flows upward through ran-dom dumped packing where the CO2 reacts chemicallywith the lean and semi-lean monoethanolamine(MEA) solvent to remove most of the CO2. MEA con-centration is at least 30%.
Treated gas is passed through a water wash andvented through the top of the absorber. Solvent inter-cooling in the absorber may be utilized to reduceabsorber size and solvent circulation rates.
The CO2-rich solution is split into two streams,heated and regenerated, utilizing two schemes: flashregeneration and steam stripping. Steam strippingtakes place in the stripper (3) where energy is providedthrough the reboiler (5), producing a lean solution.Flash regeneration is conducted in the semi-lean flashdrum (4) where a semi-lean solution is produced with-
out additional external energy. The overhead gasproduced is sent to the stripper top. The gas is cooledand condensate is routed back to the column to gen-erate CO2 product. This may be compressed for seques-tration or liquefied to produce a saleable product. Thelean and semi-lean solutions are pumped, cooled andfiltered before being sent back to the absorber. Thereclaimer (6) is operated intermittently to recoveramine from heat stable salts and to remove degra-dation products.
Operating conditions: The feed gas may contain 3to 25+ mol% CO2 and up to 15 mol% O2. The feed gas
pressure may be near atmospheric. Due to the addi-tion of an inhibitor that retards decomposition andcorrosion, the majority of the plant may be con-structed using carbon steel.
Economics: Typical US Gulf Coast investment (ISBL)for a 300 tpd plant is approximately $10.4 million. Fora typical flue gas from a steam methane reformer, theenergy consumption is approximately 1395 Btu/lbCO2. Solvent replacement costs approximately equal$2.09/ton CO2.
Installations: Twenty-four Econamine FG plants havebeen built worldwide.
Reference: Reddy, S., et al., “Fluor’s Econamine FGPlusSM technology,” Second National Conference onCarbon Sequestration, Alexandria, Virginia, May 5–8,2003.
Khambaty, S. and S. Reddy, “Application of theEconamine FG PlusSM process to Canadian coal-basedpower plant,” Clean Coal Session of CombustionCanada Conference, Vancouver, British Columbia,Canada, September 22–24, 2003.
Licensor: Fluor Enterprises, Inc.
Contact: Satish Reddy, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-2000, Fax: (949)349-2585, E-mail: [email protected]
Gas Processes 2004 Flue gas treatment
CO2 product
Processgas feed
Makeupwater
Treatedgas
4
3
5
2
16
Return to Gas Processes INDEX
Fluor ECONAMINE/Fluorimproved ECONAMINEApplication: Amine plants where stringent gas spec-ifications must be met and cooling water is not avail-able. Carbon dioxide (CO2) removal down to 50 ppmv(liquefied natural gas {LNG}specification) and hydro-gen sulfide (H2S) removal down to 4 ppmv at treatingpressures as low as 50 psig.
Description: Feed gas is contacted with a diglyco-lamine (DGA) solution in the contactor (1) whereacidic impurities react with the amine. The rich solu-tion is flashed to recover hydrocarbons (2), heated byexchange with the hot lean solution (3), and thenflows to the solvent regenerator (4). Acid gases andwater vapor pass overhead to the condenser (5).
Condensed water is returned to the regeneratorwhile the acid gases go to flare, sulfur recovery or fur-ther processing. Regenerator heat can be furnished bysuitable heat media or direct firing. Lean solution ispumped from the regenerator through the exchang-ers and coolers to the contactor. Amine degradationby COS and carbon disulfide (CS2) is completelyreversible by reclaiming (5) at elevated temperatures.The reclaimer provides part of the regenerator heat.
The Fluor improved ECONAMINE process is designedfor plants using all air cooling in a hot environment.The process adds a side cooler (6) to the absorber toremove a significant portion of the reaction heat.Amine circulation is reduced, which results in lowercapital costs in the plant’s regeneration section.
The Fluor ECONAMINE process uses an aqueousDGA solution. Solution concentrations up to 65 wt%DGA result in appreciably lower circulation rates and
steam consumption, which in turn, results in sub-stantial savings in both capital and operating costswhen compared to other amines. Aqueous DGA hasa very low freezing point, below –40°F, making itsuitable for Arctic climates where winterization is anissue.
Installations: More than 55 ECONAMINE plants,ranging in size from 3 to 400 million scfd. There are7 Improved Econamine plants, each sized for 547 mil-lion scfd.
References: Huval, M., and H. Van De Venne, “DGAproves out as a low pressure gas sweetener in SaudiArabia,” Oil & Gas Journal, August 17, 1981, pp.91–99.
Bucklin, R. W., “Removal of hydrogen sulfide fromnatural gas by DGA,” Oil & Gas Journal, July 17, 1978,pp. 71–73.
Licensor: Fluor Enterprises, Inc.
Contact: Dick Nielsen, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-2000, Fax: (949)349-2585, E-mail: [email protected]
Gas Processes 2004 Treating
6
5
5
41
3
2
Treated gas
Sour gas
To fuel gas
Rich
Lean
Acid gas
Return to Gas Processes INDEX
Fluor oxygen enrichmentprocessApplication: Oxygen (O2) enrichment technology isone of the most economical routes for achievingincremental sulfur recovery unit/tail gas treating unit(SRU/TGTU) capacity.
Description: Fluor offers two levels of O2 enrich-ment technologies—low and medium. The processcan increase a sulfur plant’s capacity up to 175% of theoriginal design capacity depending on the enrich-ment level and acid gas composition.
Pure O2 is injected into combustion air or fed directlyinto the reaction furnace burner. Installing a new O2
line, supply system, compatible burner and manage-
ment system is required depending on the enrich-ment level and the chosen technology.
The Fluor oxygen enrichment process provides aunique control and burner management schemeensuring safe and smooth operation.
Installations: Five plants engineered or constructed.
References: Chow, T. K., J. A. Gebur and J. K. Chen,“A logical approach for SRU operating challenges,”Sulphur, British Sulfur, October 2002, pp. 53–62.
Licensor: Fluor Enterprises, Inc.
Contact: Thomas Chow, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-4247, Fax: (949)349-2898, E-mail: [email protected]
Gas Processes 2004 Treating
O2
Acid gas
O2
Burner
Air
Furnace
Wasteheat
boiler
Processgasses to
catalytic stages
Return to Gas Processes INDEX
Fluor Solvent processApplication: The Fluor Solvent process is a physicalsolvent process to remove bulk carbon dioxide (CO2)and trace hydrogen sulfide (H2S) amounts from vari-ous gas streams. The process can remove CO2 to lessthan 1.0 mol% and H2S to 4 ppmv for natural gas. CO2removal down to 1,000 ppmv is possible for synthe-sis gas. The process is particularly suited for feedgases with a CO2 partial pressure above 70 psia, H2Slevels below 50 ppmv and <0.5 mol% C5
+.
Description: Feed gas is dried with TEG (1) andchilled (2, 3) to remove heavy hydrocarbons. Liquidsformed are removed in a knock-out (KO) drum (4) andthe gas enters the absorber (5). The gas is contactedwith Fluor Solvent and propylene carbonate to removeacid gases. Acid gas desorption is accomplished with-out heat.
The rich liquid passes through three pressure flashes(6), an atmospheric flash (7) and a vacuum flash (8).The gas from the first three flash stages (6) contain-ing significant volumes of hydrocarbons, is com-
pressed (9) and recycled to the absorber. Hydraulic tur-bines between the absorber and the first stage flashand the first and second stage flashes recover energyand reduce refrigeration requirements. Patents arepending.
Since the solvent loading increases with decreasing
temperature, the absorber is operated below 0°F toreduce the circulation rate. The solvent is non-haz-ardous, biodegradable and freezes at –57°F, makingthe process suitable for Arctic environments. It is usu-ally the most economic choice for CO2 bulk removalwhen CO2 partial pressure is high and H2S concen-tration is low.
Process configurations for feed gas H2S concentra-tions up to 200 ppmv or for producing a liquid CO2stream are also available.
Installations: 13 plants (8 natural gas, 2 ammonia,1 synthesis gas, 2 hydrogen) with feed gas rates up to220 million scfd and pressures up to 2,000 psig.
References: Mak, J., D. Wierenga, D. Nielsen, and C.Graham, “Consider physical solvents to treat naturalgas,” Hydrocarbon Processing, June 2002, pp. 87–92.
Licensor: Fluor Enterprises, Inc.
Contact: Dick Nielsen, One Fluor Daniel Dr., AlisoViejo, CA 92698, Phone: (949) 349-2000, Fax: (949)349-2585, E-mail: [email protected]
Gas Processes 2004 Treating
Treatedgas Flash
drums
Sourgas
Condensate
Recyclecompressor Vacuum
pump
Acid gas
Hydraulic turbines Circulation pump
Water
Refrig.
CW
5
432
1
6
9
8
7
Return to Gas Processes INDEX
Gas contaminantsremoval—MultibedApplication: Remove mercury (Hg), arsenic, water,CO2, other oxygenates, tertiary butyl catechol (TBC),NH3 and sulfur species from natural gas, industrialgases and petrochemical streams using Axens Multibedtechnology.
Description: This technology uses combinations ofspecial aluminas and zeolite molecular sieve adsor-bents that are installed as beds in the same or sepa-rate vessels. (The configuration will depend on thespecific application.) The aluminas function as cata-lysts or adsorbents for chemical or physical removal ofcontaminants such as HCl, Hg, AsH3, TBC and water.The molecular sieves remove contaminants by physi-cal adsorption.
In multibed processing, Hg can be removed eitherupstream or downstream of the gas dehydrationstep. The treated gas can contain less than
0.01µg/Nm3 Hg and less than 1 ppmv of other con-taminants. Most adsorbents are thermally regener-ated with nitrogen or light-hydrocarbon streams.
Operating parameters: Operating conditions are:Inlet temperature, °F 40–140Inlet pressure, psig 40–1,400 Regeneration gas temperature, °F 350–600Phase liquid or vapor
Installations: Currently, over 60 installations world-wide are treating natural and industrial gases andother hydrocarbon streams from refining, gas andpetrochemical sectors.
References: Jochem, G., “Optimization of naturalgas drying and purification,” Petroleum TechnologyQuarterly, Spring 1997.
Nedez, C., et al., “Optimization of the textural char-acteristics of an alumina to capture contaminants innatural gas,” American Chemical Society, 1996.
IRON SPONGEApplication: To remove hydrogen sulfide (H2S) andmercaptans from natural gas streams at low- or high-pressure conditions at or near the well head.
Process description: Iron sponge (iron oxidizedonto wood shavings) uses a simple packed tower (3)on a flow-through support (4). After liquid separation(1), the deflected (2) sour gas flows down to contactwith the reactive iron oxide, simply and effectively con-verting H2S into a solid. The iron sulfide stays in thepacked tower, effectively removing it from the gasstream. Iron sponge also removes mercaptans, themalodorous sulfur compounds found in some gas,producing a deodorized, sweet gas.
For iron sponge to effectively perform, it must bemaintained within a range of water levels. Thisrequirement is usually satisfied if the gas is saturatedwith water vapor, as is frequently the case. If it is notthe case, a simple water spray will correct it. An excessof water is tolerated very well by iron sponge as longas the excess is drained off (5), so as not to flood the
bed. Because the reaction of iron oxide with H2S pro-duces a small quantity of water, monitoring the dripwater volume is an effective method of confirming thepresence of sufficient moisture. Since the iron oxideis impregnated onto the wood, it will not wash off ormigrate with the gas.
Operating conditions: The process should be locatedas close to the source of gas as possible, to eliminateas many corrosion problems as possible caused bythe H2S. The process should be used after a gas/liquidseparator and before the dehydration process. Themaximum temperature should not exceed 120°F, andthe minimum of 50°F, or whatever is necessary toavoid hydrate formation for the system pressure andcomposition of the gas.
The gas purification is not pressure sensitive, and isnot affected by other gas constituents. Carbon diox-ide levels are not a problem for treatment, but liquidhydrocarbons should be removed before the IRONSPONGE process.
Since the process is so simple, minimum operatortime is required. It runs unattended for days at atime.
Manufactured and supplied by: Connelly-GPM,Inc.
Contact: Galen Dixon, 3154 S. California Ave.,Chicago, IL 60608-5176, Phone: (773) 247-7231, Fax:(773) 247-7239, E-mail: [email protected]
Gas Processes 2004 Treating
1 3
2
4
5
Sweet gas
Sour gas
Return to Gas Processes INDEX
LRS 10—CO2 removalApplication. Remove CO2 from natural gas, SNG orammonia syngas. The purification process is applica-ble in facilities for LNG plants and petrochemical appli-cations.
Description. Rich-CO2 feed gas is passed to theabsorber column containing potassium carbonate solu-tions and LRS10 additives. The used solution goesthrough the regeneration system and purified gas exitsthe top of the absorber. The rich solution is regener-ated either in a re-boiler facility or directly with steam.The recovered potassium carbonate/LRS10 solution ispumped back to the absorber for further reaction. Feedgas containing about 20% CO2 has been treated suc-cessfully, typically to CO2 levels of 1% in the processedgas, depending on process arrangement. Process con-figuration changes can lower CO2 slippage levels from
500 ppm to 1,000 ppm in some designs.
Economics. A plant utilizing typically 3% LRS10 in a
potassium carbonate system has been shown to offerimproved performance over CO2-removal systems suchas Benfield (DEA promoted potassium carbonate) byup to 10%. OPEX savings are realized through:
• Increasing gas throughput of typically 10% • Lower regeneration energy by about 10% • Reduce CO2 slippage in the outlet gas by up to
50% • Improve column operations by moving away from
column constraints.
Installations. Thirty plants worldwide, mainly retrofits,in the ammonia, hydrogen, natural gas and chemicalsindustries.
Morphysorb (acid gasremoval from natural gas)Application: Hydrogen sulfide (H2S), carbon dioxide(CO2), COS and RSH removal from natural gas or syn-gas by physical absorption. Bulk-acid gas removalwith simple flash regeneration. Removes impurities topipeline specification with additional thermal regen-eration step. Highly selective H2S removal, even at highCO2 partial-pressures. Simultaneous dehydration andBTEX removal.
Description: For bulk acid gas removal the Mor-physorb process simply requires solvent flash regen-eration as the acid gas compounds are physically dis-solved. Applications vary from product gasspecifications of several percent for the acidic com-ponents down to about 2% for CO2 alone. Additionalthermal regeneration is required for H2S removaldown to pipeline specification (4 ppmv H2S, 2% CO2)or removal of CO2 to liquefied natural gas (LNG) spec-ification (50 ppmv CO2, 4 ppmv H2S).
The process flow diagram shows a bulk-acid gasremoval unit as an example. The feed gas enters theabsorber bottom, flows upward through a packedbed, where it is treated with the regenerated sol-vent, and leaves the absorber at the top.
The enriched solvent exits the absorber bottomand is flashed consecutively into the recycle flashdrums. The offgas from these drums is recycled to theabsorber feed by a two-stage compressor minimizingmethane losses. The solvent is further flashed into theacid gas flash drums for regeneration. The acid gas isproduced at two pressure levels for high-pressuredownhole reinjection or for further processing in a sul-fur recovery unit. The regenerated Morphysorb solventis pumped back to the absorber.
Due to the solvent’s specific nature (low co-absorp-tion of C1 to C3 hydrocarbons, high acid gas capacity,non-corrosive, low-vapor pressure and non-toxic) the
process exhibits the following features: low recycle gasflow and higher hydrocarbon product yield, low sol-vent circulation rate, extensive carbon steel usage asconstruction material and low solvent losses in theproduct and acid gas.
Operating conditions: Typical feed conditions rangefrom 400 psi to 1,300 psi with a 5% to 70% acid gascontent (CO2 and H2S). Depending on the processapplication, product specifications vary from a fewppmv to several percent for bulk removal.
Installations: Two plants: A 300 million-scfd feedgas capacity commercial plant, removing 1,000 tpd ofacid gas for downhole reinjection. A pilot plant instal-lation with a 1 million-scfd feed gas capacity.
References: “Performance of Morphysorb solventin a commercial acid gas treating plant,” 53rd AnnualLaurance Reid Gas Conditioning Conference, Febru-ary 23–26 2003, Norman, OK, USA.
“Morphysorb, A new solvent for acid gas removaland its impact on BTEX emissions,” The 49th AnnualLaurance Reid Gas Conditioning Conference, Febru-ary 21–24 1999, Norman, OK, USA.
N2 rejection—MolecularGateApplication: Remove nitrogen (N2) from contami-nated natural gas. Feedstocks include N2 contamina-tion from 5% to 30%. Product is pipeline quality nat-ural gas with typical N2 levels of 3% to 4% using theMolecular Gate process and a patented proprietaryadsorbent in a pressure swing adsorption (PSA) system.
Description: Natural gas at pressure levels between100 psig and 800 psig is routed through a series ofadsorber vessels. One or more vessels remove N2,while pipeline-quality natural gas flows through theadsorbent bed at essentially feed pressure. Typically,between three and eight adsorber vessels are used.When the adsorbent is saturated with N2, the spentvessel is removed and replaced with a regeneratedone. It is depressurized and produces a low-pressure,methane-rich stream for compression/recycle to thefeed and a low-pressure fuel stream containing N2 to
be rejected. To maximize adsorbent capacity, N2 istypically removed through a single-stage vacuumblower. The process is based on an adsorbent that issize selective and allows smaller N2 molecules to fit inadsorbent pores, while the larger methane moleculeis unaffected. Carbon dioxide is also completelyremoved with the N2 and oxygen is removed at N2 lev-
els. The system is flexible for a wide range of N2 con-centrations and has turndown capability to 30%.Modular construction facilitates installation.
Economics: The technology can be cost-effectivelyapplied to a wide range of flowrates. A small, 2-MMscfd unit’s total installed cost is $0.50/thousand ft3
of feed processed. This is decreased to less than$0.30/thousand ft3 for a 10-million scfd design. Mod-ular construction allows low-cost installation andequipment relocation flexibility.
Installations: Five units are in operation or fabrica-tion.
Reference: Mitariten, M. J., “New technologyimproves nitrogen removal economics,” Oil and GasJournal, April 23, 2001.
Licensor: Engelhard Corp.
Contact: Michael Mitariten, Business Manager, Molec-ular Gate, Phone: (732) 205-6979, Fax: (732) 205-5915,E-mail: [email protected]
Gas Processes 2004 Treating
Productnatural gas
N2 3% to 4%
Moleculargate
adsorbers
Methane recycle
Fuel
Feed gasN2 5% to 30%
Return to Gas Processes INDEX
Nitrogen rejectionApplication: Reject nitrogen from natural gas toincrease heating value.
Description: Natural gas feed to the nitrogen rejec-tion unit (NRU) is partially condensed and fed to thetop of the high-pressure (HP) column. A reboilerdriven by condensing the feed provides strippingvapors in the column. The bottoms from the firststripping column are enriched in hydrocarbons anddepleted in nitrogen. This HP residue is boiled in thewarm NRU exchanger and sent to residue gas compres-sion. Enriched in nitrogen, the overhead vapor fromthe column is sent to the cold end of the NRU.
Vapor from the HP column is partially condensedagainst returning residue streams. The vapor and liq-uid are separated in a vertical separator drum. Thevapor stream, enriched in nitrogen, from the drum isfurther condensed and is fed as reflux to the low-pres-sure (LP) column.
Liquid from the drum is the feed to the LP column.Vapor generated in the reboiler strips the descendingliquid of nitrogen creating the remainder of theresidue product. The liquid flowing down the col-umn scrubs the methane from the vapor, creating ahigh-purity nitrogen vent stream from the top of the
column.Liquid product from the LP column is pumped to LP
residue pressure. This stream is boiled against thecondensing HP vapor from the overhead of the firststripping column. The nitrogen vent stream and LPresidue stream are warmed in both exchangers inthe NRU along with the HP residue gas stream. Theresidue streams are sent to recompression for exportto pipeline systems. Nitrogen is vented to the atmo-sphere or recompressed for reinjection.
Operating conditions: The dual-column NRU processhas good CO2 tolerance and feed flexibility, handlingfeeds from 5 to 80 mol% nitrogen and pressures as lowas 250 psig (17 barg).
Economics: The dual-column NRU has high hydrocar-bon recovery (>99.9%). This process is particularlywell-suited for streams with less than 20% nitrogenin the feed, and is easily adapted to recover helium(HeRU) as well. The hydrocarbons are recovered at twopressure levels, reducing recompression requirements.The amount of hydrocarbons recovered from the sec-ond column is greatly reduced requiring a smallercryogenic pump.
Installations: Eight NRU and HERU installations,with three using the dual-column process with capac-ities from 30 million scfd to 70 million scfd.
Reference: Janzen, K. H. and S. R. Trautmann, “Inno-vative NRU design at Pioneer Natural Resources’ Faingas plant,” 2000 GPA Convention.
OmniSulfApplication: Natural gas from reservoirs now beingexplored is of increasingly poorer quality. By con-trast, demands on gas quality are rising. This is par-ticularly true when the gas is used as feedstock for liq-uefied natural gas (LNG) production. Polishing the gasfrom trace contaminants such as COS, mercury andspecifically, mercaptans is becoming evermore impor-tant; aside from classic hydrogen sulfide (H2S), carbondioxide (CO2) and water removal task.
Description: The OmniSulf concept encompasses thefollowing proprietary key processes: Acidic compo-nents are eliminated using BASF’s aMDEA process(AGR). The cleaned gas is routed to a DMR unit thatremoves moisture and mercaptans with Zeochem’sspecial 13X zeolite technology. Where necessary, thesweet gas can be routed further to a mercury removalunit operated with impregnated activated carbon.The DMR is thermally regenerated at regular intervals.Mercaptans are recovered from the regeneration gas
using Purisol technology. The gas can then be fed tothe fuel gas system.
All gas streams containing sulfur are routed to a sul-fur recovery unit (SRU). Elemental sulfur is produced
in the Claus process (equipped with Lurgi Multi-Pur-pose Burner). A Lurgi tail gas treating and acid gasenrichment (LTGT) system is combined with the Clausunit to boost sulfur recovery. The sulfur product is thentreated further applying an AQUISULF degassing pro-cess (AQU) which removes H2S concentrations below10 ppm. Vent gases are incinerated (INC) before beingreleased to the atmosphere.
As the sulfur market is saturated, acid gas re-injec-tion is increasingly selected as a viable alternative. TheOmniSulf concept can be tailored to gas re-injection.
Installations: A contract for the OmniSulf process wassigned in 2003 for a plant in the Middle East.
Reference: Tork, T. and M. M. Weiss, “Natural GasSweetening,” Hydrocarbon Engineering, May 2003
PURASPECApplication: PURASPEC processes remove low levelsof sulfur and mercury compounds from hydrocarbongases and liquids to meet pipeline, chemical grade orenvironmental specifications.
Description: PURASPEC uses absorbent fixed beds toirreversibly react with impurities to be removed. Thereare no feedstock losses; only the impurity binds withinthe absorbent. The process is flexible to accommodatechanges in throughput. There is no operator inter-vention required to run the process and change-outcan be done by contract labor.
During operation, there are no vents, flares or noisesources. Used absorbent can be reprocessed and dis-posed in an environmentally friendly manner. A typ-ical lead-lag configuration is shown. However, singlevessels are operated and have been used to phaseexpenditure. Axial and radial flow reactor designsare available. Radial flow reactors have been used induties where a very low-pressure drop is required.
Hydrogen sulfide (H2S) removal from natural and
associated gas can achieve impurity levels a low asppbv at the bed exit. In liquid duties (propane and liq-uefied petroleum gas), H2S is removed to meet cop-per strip 1A quality.
Mercury can be removed from natural gas to levelsbelow 10 ng/Nm3 (liquefied natural gas quality). In liq-uid duties (propane, butane, naphthas) mercury canbe reduced to <1 ppbw.
Operating conditions: PURASPEC operates effec-tively over wide temperature and pressure rangesfrom 20°F to 400°F and atmospheric to 2,000 psi. Noheat input is required.
Installations: There are over 100 operating unitsworldwide treating natural gas rates up to 2 billionscfd and NGLs up to 5,000 tpd for major oil and gascompanies.
References: Spicer, G. W. and C. Woodward, “H2S con-trol keeps gas from big offshore field on spec,” Oil &Gas Journal, May 27, 1991, p.76.
Carnell, P. J., H. K. W. Joslin and P. R. Woodham,“Fixed bed processes provide flexibility for COS, H2Sremoval,” Oil & Gas Journal, June 5, 1995, p.52.
Rhodes, E. F., P. J. Openshaw and P. J. H. Carnell,“Fixed-bed technology purifies rich gas with H2S,Hg,” Oil & Gas Journal, May 31, 1999, p.58.
PurisolApplication: Removal of acid gases from naturalgas, fuel gas and syngas by physical absorption inNMP (N-methyl-pyrrolidone). Typical cases: 1. HighCO2 contents to low residual level, 2. Bulk acid gasremoval to moderate purity by simple flash regener-ation, 3. Selective H2S removal. Ideally suited for (3)in an IGCC based on POX of coal or oil, as NMP, is themost selective solvent on the market. 4. Selectiveremoval of mercaptans from gas streams, e.g., fromspent regeneration gas coming from a molecularsieve mercaptan removal unit from natural gas. It isa cheap, stable, noncorrosive and easily available sol-vent with a broad range of further industrial appli-cations.
Description: Raw gas from a POX of heavy residueis cooled; HCN and organic sulfur compounds areremoved in prewash (1). H2S is removed in mainabsorber (1) by hot-regenerated, lean solvent cooledslightly below ambient temperature. NMP traces arebackwashed on top of (1) with H2O. Laden solventfrom (1) is flashed at medium pressure in a reab-
sorber (2). H2S traces in the flash gas are reabsorbedby a small quantity of lean NMP. The sulfur-free gasfrom (2) is compressed back to the produced fuel gas(1). Flashed solvent from (2) is heated by hot lean sol-vent and flashed again (3). Hot-flashed gas is cooledand sent back to reabsorber (2). Solvent from (3) isfinally hot-regenerated in (4). The resulting, cooledacid gas, very rich in H2S, is processed in an OxyClausunit, the tail-gas is hydrogenated, formation water is
removed by quenching, recompressed to reabsorber(2) for desulfurization and finally ending up in fuel gas.
This closed cycle is offgas free and leads to increas-ing overall efficiency of the IGCC plant.
Material balance for a 500-MW IGCC power plant in mol%Raw gas Fuel gas
H2 43.12 43.36N2 + Ar 1.49 2.31CO + CH4 45.9 45.95CO2 8.27 8.38H2S + COS 1.20 < 50 ppmFlow, kmol/h 18,666.3 18,610.0Pressure, bar 52.0 49.5
Utilities:Power (shaft) (without power recovery) 4,300 kWSteam, medium-pressure 20.6 tphWater, cooling (∆t = 10°C) 1,650 m3/hNMP vapor loss 2 kg/hDemineralized water 2.2 tph
Installations: Seven units in operation or under con-struction.
RectisolApplication: Acid gas removal using an organic sol-vent at low temperatures. In general, methanol isused for H2S, COS and bulk CO2 removal, wherebyorganic and inorganic impurities are also removed. Itis possible to produce a clean gas with less than 0.1ppm sulfur and a CO2 content down to the ppmrange. The main advantage over other processes is theuse of a cheap, stable and easily available solvent, avery flexible process and low utilities.
Description: Rectisol unit for the selective desulfu-rization and CO2 removal in the production ofmethanol synthesis gas. Raw gas (from SGP-POX) iscooled and trace components are removed in theprewash (1) with cold methanol. Prewashed gas isdesulfurized (1) by using CO2-laden solvent down to0.1 ppm. H2S-laden solvent is regenerated first byflashing to medium pressure (4) to recover H2 and CO,and second, by heating to boiling temperature andstripping with methanol vapors (3). The stripped H2S-enriched gases are sent to a Claus unit. The portionof the desulfurized gas which has been shifted in theCO-shift conversion unit (6) has a typical CO2 con-
tent of 33%. Shifted gas re-enters the Rectisol unit,is cooled and the CO2 is removed in a two-stageabsorber (2). In the lower section, the gas CO2 contentis reduced to about 5% using flash-regeneratedmethanol (5). Remaining CO2 is removed using hotregenerated (3), cold methanol in the upper section;thus, about 3% CO2 is contained in the synthesis gas.The flashed CO2 is free of sulfur and can be dischargedto atmosphere or used further. The refrigeration bal-
ance of the system is maintained by a conventionalrefrigeration unit. Methanol is injected in the raw gascooling to prevent icing. The condensedmethanol/water mixture is separated in amethanol/water column (not shown).
Material balance for a 2,000-tpd methanol plant in mol%Raw gas Syngas CO2 Claus gas
• Selectively remove H2S and COS in integratedgasification combined cycle (IGCC), with high CO2rejection to product gas (+85%) and high sulfur (25%to 80%) feed to the Claus unit
• Selectively remove H2S/COS plus bulk removal ofCO2 in gasification for high-purity H2 generation forrefinery or fertilizer applications, and
• Treat natural gas to achieve either LNG or pipelinespecification with dew-point reduction
Description: This process uses Dow’s SELEXOL sol-vent—a physical solvent made of a dimethyl ether ofpolyethylene glycol, which is chemically inert and notsubject to degradation. The process also removesCOS, mercaptans, ammonia, HCN and metal carbonyls.
A variety of flow schemes permits process optimiza-tion and energy reduction. Carbon steel can be usedfor the construction materials of equipment and pip-ing due to the process’s non-aqueous nature and
inert chemical characteristics. Acid gas partial pressure is the key driving force. Typ-
ical feed conditions range between 300 and 2000psia, with acid gas composition (CO2 + H2S) from 5%to more than 60% by volume. The product specifica-tions achievable depend on the application and canrange from ppmv up to percent levels of acid gas.
Installations: More than 55 SELEXOL units havebeen put into commercial service. The SELEXOL pro-cess is used in many applications, ranging from nat-ural gas to synthetic gas, and has been the dominantacid-gas removal system for gasification projectawards.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Treating
Absorber
Stripper
MakeupwaterReflux
pump
Acid gasAcid gascooler
Acid gasknock-out
drum
Acid gas
Feedgas
Leansolutioncooler
Leansolutionpump
Rich flashdrum
Lean/richexchanger
Solution pump
Reboiler
Reboiler
Leansolution
filter
Return to Gas Processes INDEX
SelexsorbApplication: Purify ethylene feed stream to polyethy-lene production processes. Treated ethylene gas con-tains less than 0.2 ppmv CO2 and H2O and less than1.0 ppmv oxygenates.
Description: Upstream of Selexsorb towers, the feedethylene stream is prepurified via acetylene converter(1), tower (2) of reduced copper catalyst and bed (3)of CuO. Water and oxygenates are removed by com-bination bed (4) of 3A molecular sieve (H2O adsorp-tion) and Selexsorb CD selective adsorbent (oxygenateadsorption). Final treating step involves adsorption ofCO2 with bed (5) of Selexsorb COS selective adsorbent.Selexsorbs are thermally regenerated with nitrogenor light hydrocarbon streams. The selective adsor-bents will purify: comonomer, fresh diluent, recyclediluent and reaction controlling gas (hydrogen, nitro-
gen) to polyethylene processes. In ethylene treatingservice (CO2 adsorption), Selexsorb COS has proven itsvalue in protecting Ziegler-Natta type catalysts inpolyethylene plants worldwide.
Operating conditions: (typical)Inlet ethylene temperature, °F 40 to 120Inlet pressure, psig 50 to 1,500Inlet contaminant, ppmv
CO2 0.5 to 50H2O 0.5 to saturatedOxygenates 2.0 to 50
Regeneration gas temperature, °F 450 to 600Regeneration gas pressure, psig 10 to 200
Installations: More than 200 installations world-wide for the treatment of ethylene and propylenefeed streams to polymer plants.
Reference: Smith, D. L., “Applications for selectiveadsorbents in polymer production processes,” TheInternational Journal of Hydrocarbon Engineering,July/August 1997.
Separex membrane systemsApplications: CO2 and water vapor removal from nat-ural gas or associated gas to meet pipeline specifica-tions for onshore or offshore locations. Hydrogenand helium purification and upgrading low GHV gasfor fuel. Debottlenecking existing solvent scrubbingsystems or providing bulk CO2 removal upstream ofnew installations. Hydrocarbon recovery fromenhanced oil recovery floods for CO2 reinjection andlandfill gas purification.
Products: Purified gas meeting pipeline specifica-tions, high-quality fuel gas for turbine, reformer, orpower generation or high-purity CO2 gas for reinjec-tion.
Description: Separex membrane systems are simple,dry systems requiring minimal moving parts. Feedgas, after liquids separation, is conditioned at thepretreatment before being processed in a one- ortwo-stage membrane system. As the CO2-rich feed gasmixture passes over the polymeric membrane at highpressure, it separates into two streams. Carbon diox-ide, hydrogen sulfide and water vapor permeatereadily through the membrane collecting on the low-pressure permeate side. The high-pressure residualretains most of the methane, ethane, other hydro-carbons and nitrogen. In a two-stage system, the first
stage low-pressure permeate is compressed for furthertreatment at the second-stage membranes to recoverhydrocarbons.
Hydrocarbon recovery can be as high as 99% for atwo-stage design, and 95% for a single stage withoutcompression, depending upon feed composition, pres-sure levels, system configuration and product require-ments. Feedrates vary from 1 million scfd to 1,000 mil-lion scfd, with CO2 levels from 3% to 70% and feedpressures from 400 to 1,400 psig.
Designed for operational simplicity, Separex mem-brane systems are an excellent choice for offshore andremote locations. They require minimal rotatingequipment, no chemical reagent replacement and
minimal maintenance. The prefabricated units areskid mounted to minimize installation costs and plotspace.
Separex membrane systems offer two membranemodule configurations, spiral wound and hollowfiber, to satisfy the varied CO2 removal requirements.
Economics: For natural gas upgrading to pipelinespecification, the processing costs are lower than, orcomparable to, an amine unit. However, the Separexmembrane system eliminates the need for the glycoldehydration unit found in typical treating plants. Theeconomics of smaller installations or remote opera-tions favor membrane systems over traditional treat-ment options. CO2-removal costs range between $0.05to $0.15 per 1,000 scf of feed gas, depending onremoval requirements, feed pressure, system config-uration and product specifications.
Installations: Separex membrane systems have beensuccessfully used in gas field operations since 1981.Over 50 units have been built or are in construction.The largest operating unit processes over 260 mil-lion scfd of natural gas.
Licensor: UOP LLC
Contact: Anita Black, UOP, 25 E. Algonquin Ave., DesPlaines, IL 60016 USA, Phone: (847) 375-7801, Fax:(847) 391-2253, E-mail: [email protected]
Gas Processes 2004 Treating
Pret
reat
men
t
Pret
reat
men
t
Recyclecompressor
Membranestage 1
Membranestage 2
Sales gas
Permeategas
Membranefeed
Hydrocarboncondensate
Feedgas
Return to Gas Processes INDEX
Shell HCN/COS hydrolysistechnologyApplication: The catalytic conversion of HCN andCOS is a cost effective technology to abate the harm-ful effects these components have in gas streams.
This hydrolysis technology has three main fields ofapplication:
1. Syngas treatment upstream of an amine unit forcoal or oil gasification processes.
2. Other syngas treatments where HCN and/or COSpresence is not acceptable to downstream processingunits such as gas -to-liquid processes, e.g., the Shellmiddle distillate synthesis process.
3. FCC dry gas treatment to avoid problems indownstream treating units.
Description: In the gasification process, for example,syngas is produced, which is mainly comprised ofhydrogen and carbon monoxide. However, contami-
nants such COS and HCN are also formed. A deepremoval of both these contaminants is not possibleusing “conventional” amine treating solvents. How-ever, catalytic HCN/COS hydrolysis technology is a costeffective alternative to avoid the harmful effects ofthese compounds downstream of the process.
Syngas is water scrubbed for soot removal. Conse-quently, the water saturated gas is heated to a desiredtemperature before the syngas enters a HCN/COShydrolysis reactor. In this reactor, catalytic hydrolysisof HCN and COS takes place to produce CO, H2S, CO2and ammonia.
After the HCN/COS reactor, the syngas is first cooledand then fed into an ammonia scrubber to remove thewater-soluble components. The condensed water issent to water treatment and the syngas is routed todownstream processing units.
Installations: At present one unit is in operationand license agreements have been signed to supplythe technology to two other companies.
Licensor: Shell Global Solutions International B.V.
Shell sulfur degassing processApplication: To remove dissolved hydrogen sulfide(H2S) and H2Sx from liquid sulfur coming from Clausunits. Liquid sulfur from Claus units contains approx-imately 300 ppmw dissolved H2S and H2Sx; to meetenvironmental and safety restrictions the liquid sul-fur should be degassed such that less than 10ppmwH2S remains.
Description: Sulfur from the Claus unit is rundowninto either a concrete sulfur pit or a steel vessel. It isthen circulated over a stripping (bubble) column bybubbling air through the sulfur. By agitating the sul-fur in this way, H2S is released. Sweep air is passed overthe top of the sulfur to remove released H2S. The
vent gasses are usually sent to an incinerator via anejector. The degassed sulfur is then pumped into stor-age. The advantage to this process is that there are no
moving parts and no catalyst is required, consequently,the process is easy to operate.
Economics: The Shell sulfur degassing process hasbeen developed to decrease residence time and con-sequently capital expenditure. Operational costs arekept low as no catalyst is required.
Installations: There are currently more than 150Shell sulfur degassing units in operation with capac-ities varying from 3 to 4,000 tpd of sulfur.
Licensor: Shell Global Solutions International B.V.and Jacobs Nederland B.V.
SORDECO Application: The SORDECO process applies Sorbeadadsorbent beads packed into an adsorber column. Itselectively removes water (H2O) and hydrocarbonsfrom natural gas. When the adsorbent is saturated,stripping with hot regeneration gas regenerates it.Condensing the stream when leaving the regenerat-ing adsorber separates H2O and heavy hydrocarbons.
Description: In a typical natural gas plant two, threeor four adsorbers are applied to allow for onlineregeneration. As the process relies on selective adsorp-tion of heavy hydrocarbons and H2O, the attainabledew point specification is virtually independent of thenatural gas pressure. This is a major advantage overlow temperature separation technology when natu-ral gas is available at a relatively low-pressure (<100Bar, <1,500 psi) or when only limited pressure dropsover the treating unit is allowed.
The process is very flexible with respect to feed gas
and turndown ratio; this only influences the cycletime, which is an operational variable. The excellentturndown capabilities and short startup time makethe process ideal for peak shaving and undergroundstorage facilities. The process can be designed toselectively remove aromatics for membrane protec-tion applications.
Installations: Shell Global Solutions has providedits operating companies with design support andoperational advice since the early 1990s. Engelhardwas involved with over 200 Sorbead based dew point-ing units.
References: Schulz, T., J. Rajani and D. Brands, “Solv-ing storage problems,” Hydrocarbon Engineering,June 2001, p. 55.
Brands, D.S. and J.B. Rajani, “Comparison betweenlow temperature separation (LTS) and SORDECO pro-cess for hydrocarbon dew pointing”, GPA EuropeMeeting, Amsterdam, September 2001.
Licensor(s): Shell Global Solutions International B.V.and Engelhard Process Chemicals GmbH
Sour water stripper (SWS)Application: Remove dissolved hydrogen sulfide(H2S) and ammonia (NH3) from sour water (H2O)before conveying it to waste H2O treatment. SourH2O comes from many sources such as catalytic crack-ing units, hydrocrackers, flare seal drums, etc. Nor-mally, refinery SWS are designed for feed concentra-tion ranging from 500 to 15,000 ppmw each of NH3and H2S. The molar ratio of NH3 to H2S generallyranges between 0.75 to 2, and averages about 1.2. pHis commonly from 7 to 9.3. The process can also bedesigned to take account of mercaptans, phenolsand some aromatics. There are several SWSs types, allof them operate by passing sour H2O through a multi-stage stripping tower.
Description: SWS contains a fractionating tower,which removes H2S and NH3 from sour H2O alongwith some mercaptans, aromatics and phenols. Thetower is normally refluxed to reduce H2O in the over-head offgas and reduce downstream processing units(i.e. sulfur plants) size and cost. Steam is the most com-monly used stripping medium, but flue gas, fuel gas
and natural gas can also be used. Typically, the sour H2O feed stream is preheated by
heat exchange with hot stripped H2O prior to towerentry. Stripping steam is introduced into the towerbottom. H2S and NH3 are stripped out by counter-cur-rent contact with the steam. Typically, H2S and NH3 arestripped to ppm level.
Operating conditions: Operating pressure is gen-
erally set at a level to provide enough pressure todeliver offgas to its destination. A tower top pressureof 1.3–1.7 barg is typically enough when the offgasis sent to a sulfur recovery plant.
Overhead separator operating temperature shouldbe set in the range of 82°C–90°C. A lower tempera-ture can lead to plugging problems due to the for-mation of ammonium hydrosulfide, while a highertemperature results in more H2O vapor in the offgasaffecting downstream equipment size. Fluids han-dled in SWS facilities are corrosive. Proper construc-tion materials selectionis an important aspect in SWSdesign.
Commercial plants: More than 25 SWS plants havebeen built globally with capacities ranging from 1.5m3/h up to 120 m3/h.Recently a SWS plant was designedfor AGIP GAS BV LIBYAN BRANCH consisting of twounits whose capacity is 25 m3/h sour H2O each.
SulfaClean–HCApplication: SulfaClean–HC is a granular materialthat is used to remove aggressive sulfur compounds,primarily hydrogen sulfide (H2S), in a variety of clearliquid streams. Propane/propylene, butane, LNG, NGL,gasoline and other light liquid hydrocarbon streamstreatment reduces corrosion to pass copper strip test-ing and meet H2S limits. Dry or water-saturated liquidhydrocarbon can be treated, as well as water or brinesfor removal of dissolved H2S prior to disposal.
Description: Liquids flow upward through the Sul-faClean–HC media. Flow rates and system designsdepend on fluid type and contaminants quantity. Sys-tems range from single vessels or multiple parallel flowto lead/lag style applications. A properly designed
system can adapt to variable flow rates without lossin treating efficiencies.
Economics: The SulfaClean–HC media removes up to7.5 wt% H2S. Its costs are often one-fourth the cost ofzinc oxide products. It is competitive with caustic sys-tems when accounting for regulatory, personal safetyand disposal issues. The vessels are simple and inex-pensive. Converted mole sieve, zinc oxide or ironsponge units can usually be used without modification.
Installations: This system has numerous placementsworldwide. This process is currently being qualified fortreatment of diverse streams such as MTBE and iso-octane.
Licensor: SulfaTreat, a Business Unit of M-I L.L.C.
Contact: June Weible, SulfaTreat, a Business Unit ofM-I LLC, 17998 Chesterfield Airport Rd., Suite 215,St. Louis, Missouri 63005 USA, Phone: (800) 726-7687,Fax: (636) 532-2764, E-mail: [email protected]
Gas Processes 2004 Treating
Platformwith ladder
Liquid outlet
Liquid outlet
Flow deflector
Flow deflector
Washed gravel orceramic balls bed
Foam filter
SulfaClean product
Disengaging space
Relief valve
Loading manway
LiquidflowCleanout manway
SkirtDrain Perforated plate/
gravel containment
Return to Gas Processes INDEX
SulfaTreat—Gas or air H2SremovalApplication: Various SulfaTreat processes treat con-taminated gas and air with a granular media thatselectively removes hydrogen sulfide (H2S) and somelight mercaptans.
Description: Gas or vapor flows through the media,reacting with H2S forming a stable and environmen-tally compliant byproduct at any point in its life cycle.Product consumption is not adversely affected byother gas components. The media prefers high humid-ity levels to fully water-saturate gas. Computer-assisteddesign matches operating conditions with desiredresults, such as maximum outlet allowed pressuredrops (needs only a few inches W.C.) and long bed life.It works in any gas pressure or vacuum, inlet H2S con-centration and at temperatures up to 300°F. Systemsizes range from removing a few pounds up to overa ton H2S daily, and to as low as 0.1-ppm maximumoutlet, depending on system design.
Products:SulfaTreat: media removes H2S in fully water-satu-
rated gas.SulfaTreat–HP: media removes H2S and light mer-
captans in under-saturated gas and is faster than Sul-faTreat in fully water-saturated gas.
SulfaTreat–410HP: media performs like SulfaTreat-HP
but with a low pressure drop required. It is fasterreacting and has twice the H2S loading capacity in gasor air streams containing oxygen.
SulfaTreat–XLP: is a concentrated high-capacity prod-uct that lasts 2 to 4 times longer in the same vessel.It extends the operating period and reduces operat-ing costs.
Economics: Operating costs are less than liquid reac-tants and have greater reliability. Operator attentionis minimal. Vessels are simple and non-proprietary indesign, thus lowering installation cost. Products canbe used alone or may be combined with other pro-cesses that remove contaminants other than H2S.
Installations: Over 2,000 applications globally.
Licensor: SulfaTreat, a Business Unit of M-I L.L.C.
Contact: June Weible, SulfaTreat, a Business Unit ofM-I LLC, 17998 Chesterfield Airport Rd., Suite 215,St. Louis, Missouri 63005 USA, Phone: (800) 726-7687,Fax: (636) 532-2764, E-mail: [email protected]
Gas Processes 2004 Treating
Sweet gastreated airSour gas/contaminated air
Inlet separator
Return to Gas Processes INDEX
SulfinolApplication: Removal of hydrogen sulfide (H2S),COS, RSH, other organic sulfur compounds and bulkor deep removal of carbon dioxide (CO2) from natu-ral, synthetic and refinery gases. Total sulfur com-pounds in the treated gas can be reduced to ultra-lowppm levels, as required for refinery-fuel and pipeline-quality gases.
An improved application is to selectively remove H2S,COS, RSH and other organic sulfur compounds forpipeline specification, while co-absorbing only part ofthe CO2. Deep CO2 removal for LNG plants is anotherapplication, as well as bulk CO2 removal with flashregeneration of the solvent. The process sequence—Sulfinol/Claus/SCOT—can be used advantageouslywith an integrated Sulfinol system that handles selec-tive H2S removal upstream and the SCOT process thattreats the Claus offgas.
Description: The mixed solvent consists of a chemi-cal-reacting alkanolamine, water and physical sol-vent Sulfolane (tetra-hydrothiophene dioxide). Theactual chemical formulation is customized for eachapplication. Unlike aqueous amine processes, Sulfinolremoves COS, RSH and other organic sulfur com-
pounds to stringent total sulfur specifications. The pro-cess achieves 4 ppm H2S pipeline specification at lowstream consumption. Observed corrosion rates arelow and very little foaming is experienced, both arecontrolled through the application of optimizeddesign.
The system line-up resembles that of other amineprocesses. In most applications, co-absorbed hydro-carbons from the absorber (1) are flashed (2) from thesolvent and used as fuel gas after treatment in a fuel-gas absorber (3). Loaded solvent is regenerated (4).
Operating conditions: Very wide ranges of treatingpressures and contaminant concentrations can beaccommodated. Refinery-fuel gas and gas pipelinespecifications, such as 40 ppmv total sulfur and 100ppmv H2S, are readily met. Removal of organic sulfurcompounds is usually done for the circulation set byH2S and CO2 removal. In LNG plants, a 50 ppmv CO2specification is easily attained.
Installations: Over 200 units have been licensedworldwide, covering natural gas treating, synthesis gasand refinery gases.
References: “Gas pretreatment and their impact onliquefaction processes,” GPAl, March 1999, Nashville,Tennesse.
“Process application of the ADIP and Sulfinol Pro-cess,” Gas Processing Symposium, Dubai, United ArabEmirates, April 1999.
“A mixed solvent for low total sulfur specification,”AIChE national meeting, San Diego, California, August21, 1990.
Licensor: Shell Global Solutions International B.V.
ThioSolv SWAATS process(sour water ammonia toammonium thiosulfate)Application: Converts ammonia (NH3) and sulfur insour water stripper gas (SWSG) to low-toxicity ammo-nium thiosulfate (ATS) solution. The process can alsooxidize all sulfur species in Claus tail gas and scrub sul-fur dioxide (SO2) from that or other dilute streams toachieve low sulfur oxide (SOx) emissions.
Description: Ammonia and a stoichiometric amountof hydrogen sulfide (H2S) are selectively absorbedfrom the SWSG. Unabsorbed H2S is burned to SO2.Claus tail gas is combined with the burner outlet andall sulfur species therein are oxidized to SO2, which isscrubbed by reaction to thiosulfate with negligiblepressure drop.
6 NH3 + 4 SO2 + 2 H2S + H2O › 3 (NH4)2S2O3 (ATS)
SWAATS converts the NH3 in the SWSG; no pur-chased NH3 is required. The process prevents andreverses equipment plugging by converting any ele-
mental sulfur in Claus tail gas to soluble thiosulfate.The process is highly selective for H2S and SO2 vs. CO2.
Economics: For each ton of sulfur in SWSG divertedto SWAATS, about 2.5 tons of capacity for amine acidgas (AAG) sulfur is freed up in Claus. The value of theeffect will increase as deeper desulfurization increasesNH3 production. Avoids CAPEX to expand SRU capac-
ity or OPEX for oxygen enrichment. Claus operabilityand catalyst life are greatly improved by removing NH3from its feed. OPEX <$100/ton of sulfur capturedfrom SWSG and tail gas. CAPEX to convert SWSG andscrub tail gas is less than for SCOT alone. Consumes noexternal chemicals, reducing gas or steam. Opera-tional simplicit reduces overall cost of operation andmaintenance for the combined SRU. Licensor removesATS produced.
Installations: SWAATS process was developed fromthe Coastal ATS process that has been successfullydesulfurizing acid gas and Claus tail gas in a Coastalplant since 1980. No units incorporating the improve-ments have been built.
References: US Patent No. 6,534,030Berry, R., “Treating hydrogen sulfide: When Claus
is not enough,” Chemical Engineering, October 6,1980, p. 92.
Licensor: ThioSolv, LLC
Contact: Mark C. Anderson, Principal, ThioSolv, LLC,8911 Kennet Valley Road, Spring, TX 77379, Phone:(281) 320-7570 , E-mail: [email protected]
Gas Processes 2004 Treating
Claus reactorsand condensers
Sulfur
Incinerator
Tailgas
Clausthermal reactor
AAG
SWSG
ATSSWAATSreactor
SWAATSabsorber
Rx
Burner
Return to Gas Processes INDEX
Twister supersonic gas conditioningApplication: Twister is a gas conditioning technology.Applications include natural gas dehydration, hydro-carbon dewpointing, natural gas liquids (NGL)/lique-fied petroleum gas (LPG) extraction, heating valuereduction and bulk hydrogen sulfide (H2S) removal.
Condensation and separation at supersonic veloc-ity is the key to unique benefits. An extremely shortresidence time prevents hydrate problems, eliminat-ing chemicals and associated regeneration systems.The simplicity and reliability of a static device, with norotating parts and operating without chemicals,ensures a simple facility with a high availability, suit-able for unmanned operation.
Description: Feed gas is cooled using a combina-tion of air/seawater coolers (1) and gas/gas cross-exchange (3). In case of deep NGL extraction, upstreamdehydration will be required (2). Inlet cooling is oper-ating just outside the hydrate regime. Condensedliquids are removed in an inlet separator (4). The gasis directed through Twister tubes (5). The tubes (5)
expand the gas isentropically to supersonic velocity,cooling the gas to cryogenic temperatures and con-densing water and NGLs, which are then separatedusing an in-line cyclone separator.
The separate product streams are recompressedusing a diffuser, reducing the velocity. The gaseous liq-uid stream contains slip gas, which is removed ineither a two- or three-phase liquid degassing vessel
(6) and recombined with the dry gas stream. Dryexport gas is directed through the exchanger (3) tocool the feed stream. In case the operating conditionsof the degassing vessel (6) are within the hydrateregime, Twister BV proprietary LTX technology is usedto melt the hydrates. Depending on the application,water and condensate from the separators (4,6) istreated, processed, re-injected and/or disposed (7,8).
Economics: Typical capital investment for a 100 mil-lion scfd package is $2 million.
Footprint 4m x 3.5m x 4.5m (LxWxH) Weight 25 metric tons Power 2 kW, excluding power for tracing
and LTX heating (75 kW)Pressure drop 25%–35%
Installations: Two 300-million scfd trains including12 Twister tubes on Sarawak Shell Berhad/Petronas B11platform offshore Malaysia. One 35-million scfd trainfor Shell SPDC Utorogu field onshore Nigeria.
The Use of Aqueous Liquid Redox DesulfurizationTechnology for the Treatment of Sour Associated Gases atElevated PressureMyron ReicherGas Technology Products846 E. Algonquin Road, Suite A100 • Schaumburg, IL 60173 • Tel: (847) 285-3850 • Fax: (847)285-3888
Bill NiemiecGas Technology Products846 E. Algonquin Road, Suite A100 • Schaumburg, IL 60173 • Tel: (847) 285-3850 • Fax: (847)285-3888
Dr. Tamas KatonaMol Hungarian Oil and Gas CompanyMol Rt. SzegedP.O. Box 37Szeged, Hungary
Abstract
The use of aqueous, liquid redox desulfurization technology for thedirect treatment of sour associated and process gas streams atelevated operating pressure and relatively high CO2 partial pressurepresents unique design and operational challenges. The LO-CAT II®process, an aqueous liquid redox process that utilizes a ferric(Fe +3 )/ferrous (Fe +2 ) amino-carboxylate redox couple, installed atthe MOL Gas Plant in Szeged, Hungary has performed to specification.However, to achieve this goal, resolution of technological challengesrelated to the solution circulation pump; absorber pluggage withassociated high system pressure drop; liquid hydrocarbon influx;foaming with associated liquid entrainment; and corrosion wererequired.
The design and operational history of the facility is presented, and theaforementioned technological challenges and their resolution arediscussed.
Background
ARI Technologies, the developer of the LO-CAT® and LO-CAT IIprocesses; and the predecessor of USF/Gas Technology Products,supplied a LO-CAT II desulfurization system to MOL Hungarian Oil andGas Company for operation at the Szeged Production Unit. Szeged islocated in southern Hungary, approximately 100 miles southeast ofBudapest. This unit was placed in service in late 1992, was only the
third of the LO-CAT II units produced, and was the first to treat gas atelevated pressure. Furnished at the same time by others wereauxiliary operations such as the water removal system downstream ofLO-CAT.
Figure 1. Process Flow Diagram of LO-CAT II® Unit at MOL, Hungary
1 Reicher, Myron, [email protected] , Manager of ProcessTechnology, Gas Technology Products, 846 E. Algonguin Road, SuiteA100, Schaumburg, IL 60173, USA.
2 Niemiec, Bill, [email protected] , Technical Service Manager,Gas Technology Products, 846 E. Algonguin Road, Suite A100,Schaumburg, IL 60173, USA.
3 Katona, Dr. Tamas, [email protected] , Manager of Gas ProcessingPlant, Mol Hungarian Oil and Gas Company, Mol Rt. Szeged, P.O. Box37, Szeged, Hungary.
LO-CAT and LO-CAT II are registered trademarks of Gas TechnologyProducts.
The LO-CAT II unit was designed to treat natural gas, however theactual gas is a blend of recycled process gas and associated gascollected from the oilfields around the plant. Both oil and gas from theoilfields are simultaneously transported to the plant via a mixed-phasetransport pipeline, followed by separation in a bank of gas-liquidseparators. After the separators, the associated gas is combined with
the recycled process gas stream, compressed to approximately 250psig, and then sent to the LO-CAT II unit.
Figure 1 is the flow diagram of the LO-CAT II unit. As the design teamanticipated some liquid entrainment in the sour gas, the first two unitoperations are a knockout pot and a coalescing filter. The knockout pothad a liquid surge volume of approximately 35 ft 3. After thecoalescing filter, the sour gas is routed to the LO-CAT II static mixerabsorbers where it is contacted with oxidized LO-CAT catalyst solution.(Two static mixers had been provided with the forethought that theywould probably plug with sulfur and would therefore require periodiccleaning). Exiting the static mixer absorber is a two-phase streamconsisting of sweet gas and reduced LO-CAT solution, which thenenters the absorber separator. In the separator, the gas and liquid areallowed to separate. The treated gas exits the LO-CAT II unit afterpassing through a mist eliminator. Downstream of the unit, the gas isthen cooled to remove water, and then compressed to 925 psig in thethird stage compressor.
The reduced solution from the separator passes through a pressurereducing valve and flash drum, then gravity drains to the oxidizer,where the iron is regenerated for re-use in the absorber. A slipstreamof this oxidized solution is then sent to the settler where sulfur isallowed to settle and subsequently transferred as slurry to the beltfilter. Filtrate from the filter is returned to the oxidizer while sulfurcake is discharged after washing. A small quantity of flash gas isvented to the flare header.
LO-CAT ®II Chemistry
The LO-CAT II process utilizes a ferric (Fe +3 )/ferrous (Fe +2 )amino-carboxylate redox couple as a catalyst to absorb H 2S from sourgas and to oxidize it to elemental sulfur in the absorber according toreactions (1) through (3):
The ferrous ion that is produced is then recycled to the oxidizer whereit is regenerated by oxygen according to reactions (4) and (5):
The overall reaction (6) is therefore:
Equation (6) is recognized as the overall Claus reaction, and it can beseen that the role of iron is catalytic since it is not consumed.Chelating agents, represented by "L" in the above equations, while notpartaking in any role in the above reactions, serve to maintain theferric and ferrous ions in solution.
Design Parameters
The LO-CAT II unit was designed as outlined in Table 1.
Start-Up Challenges
During the initial start-up and subsequent restarts of the unit,problems arose in several areas including:
Liquid entrainment in sweet gas, thus limiting gas flowFoaming and floating sulfurChronic failure of the catalyst recirculation pumpHigh system pressure dropPoor H2S removal efficiency
To answer these challenges, modifications to equipment, proceduresand chemistry were required. A discussion of the challenges and thecountermeasures are discussed below.
Discussion
Liquid Entrainment
During the initial start-up, liquid entrainment was seen to be excessivewhenever the sour gas flow exceeded 35,000 SCFM. This wasattributed, at that time, to the absorber separator vessel beingundersized. As a result, not only was it difficult for the gas and liquidto separate, but sulfur particles were also entrained, thus causing themist eliminator to foul, resulting in further aggravation of theentrainment issue.
To remedy the situation, the separator was resized and a newseparator, complete with modified mist eliminator, was retrofitted intothe plant. As a result, gas flow up to 58,000 SCFM was achievedwithout excessive liquid entrainment.
Foaming and Floating Sulfur
Foaming and floating sulfur are typical start-up problems thatoftentimes are remedied in short order. However, such was not thecase with this unit.
Foaming and sulfur settling problems usually go hand-in-hand and area result of condensed hydrocarbons and/or an imbalance in the use ofsurfactant and anti-foam additives. When condensed hydrocarbons arepresent, sulfur particles become coated. These hydrocarbon-coatedparticles cannot be wetted and can trap air or gas bubbles, so theyfloat on free liquid surfaces such as in the absorber separator,oxidizer, and settler and therefore cannot be removed from the systemvia settling. When surfactant is added in an attempt to wet the sulfur,foam can be created. Further, if anti-foam is added to control theresultant foam, this could actually aggravate the foaming situation.
Eventually, it was determined that there were excessive liquidhydrocarbons entering the LO-CAT II unit. At one point, a sample ofsolution was found to contain solid wax-like material. Additionally,stable emulsions were forming among the aqueous LO-CAT solution,sulfur particles, and hydrocarbon condensate. In retrospect,hydrocarbon induced foaming may have aggravated the entrainmentsituation in the absorber separator as well.
If the condensate could have been prevented from entering thesystem, this entire problem would not have existed. However, it wasdetermined that considerable condensate was frequently beingintroduced from both the process gas and also as a result of operationof the two-phase oil/gas pipeline. Consequently, it was deemed notpossible to easily keep the condensate out. Therefore, a multi-faceted
approach to the problem was undertaken. To reduce the quantity ofcondensate and to provide immediate, short-term relief, modificationswere made to the sour gas transfer line to allow condensate to betrapped out. Fortunately, the main line was high on the pipe rack anda simple drainage boot could be retrofitted to catch the condensate. Inaddition, the knockout pot that was furnished with the unit wasreplaced with a larger one.
At the same time, MOL’s R&D group went about to develop a newadditive, which would allow the stable emulsions to be broken and thesulfur to be wetted. Their goal was met by the formulation of what istermed "B-3". B-3 has replaced ARI-600 and anti-foam in this unit,and has allowed the plant to operate in spite of continued hydrocarboninflux.
Catalyst Recirculation Pump
The catalyst recirculation pump in this plant was a six stageprogressive cavity pump. This type of pump was selected as it best fitthe hydraulic specifications and had operated successfully in manyprevious units, albeit at lower pressure. However, during the severalattempts to start the plant, it became apparent that this pump wouldnot be dependable in the long-term, even though a larger, slowerrunning pump was installed as recommended by the manufacturer. Asa result of the failure of the larger pump on Christmas Eve, 1997 andthe need to keep the plant running, plant maintenance personnelretrofitted a scavenged multi-stage centrifugal pump. This style pumphad never been used in LO-CAT units before due to fear of erosion andinter-stage pluggage. However, there were no options available onChristmas Eve. A year later, this pump was still operational but thecapacity of the unit had been compromised, as the volumetric capacityof this pump was less than that required. As a result, in December of1998, a new pump with the required capacity was installed.Emboldened by the lack of erosion and inter-stage plugging in themulti-stage pump, but not wanting to chance inter-stage plugging inthe long-term, MOL selected a Durco, Mark III pump. This pump is acentrifugal pump with an open impeller, and operates at 3160 rpm. Sofar, the new pump has performed satisfactorily, having operatedsuccessfully for 9 months.
High System Pressure Drop
High system pressure drop was caused by absorber fouling and back-pressure in the water removal train downstream of the LO-CAT unit.
Absorber pluggage had been expected; therefore the two static mixerswere furnished with flushing connections. Unfortunately, the plannedcleaning procedure was not effective, possibly due to the stickiness ofhydrocarbon-coated sulfur. An alternate cleaning procedure, usingsteam, was implemented by the operators, but the pressure drop wasnever reduced to the as-clean condition. In September of 1998, arevised steaming procedure was implemented that allowed recovery tothe as-clean condition. However, to implement this procedure, theabsorber required isolation by blinds, as the original isolation valveswere not rated for steam service. Replacement of these valves isscheduled shortly. When replaced, more frequent steam outs will bepossible, thus allowing low absorber pressure drop and increased gasthroughput to be maintained.
Modifications to the water separation train downstream of LO-CAT arealso planned for the future and will permit a further increase in gasflow.
H2S Removal Efficiency
From the onset, H2S removal efficiency had been less than designedfor. This was largely due to the CO2 concentration of the sour gasbeing higher than the design, thus greatly reducing the solution pH atthe discharge of the static mixer (where liquid and gas emerge as atwo-phase stream). To remedy this, it was recognized that additionalsolution buffering (i.e. more bicarbonate ion) was required beyond thatdesigned for. Unfortunately, increasing the buffer when NaOH is usedas alkali supply can cause precipitation of NaHCO3. Usually, KOH isused for higher buffering capacity but it is more expensive. Operatorsat MOL decided to supplement the NaOH feed with NH4OH. Thisworked insofar as the solution buffer capacity was increased, but therewas a continuous NH3 loss from the oxidizer vent. A packed columnscrubber was added to the vent, using oxidizer make-up water as theabsorbent. This had some beneficial effect, however ammonia lossescontinued. Further, a review of solution chemistry in September of1998 revealed that the solubility product of NaHCO3 was beingapproached. This prompted a switch to KOH and the discontinuance ofNH4OH in December of 1998.
Present Situation
At present, the plant has been operating with a gas flow of 35,000 to58,000 SCFM, averaging about 38,000 SCFM, with a sulfur load ofabout 0.05 LTPD (due to low H2S concentration in the gas). The
improvements that were made in the hydrocarbon collection system,coupled with improvements in operating procedures have greatlyreduced the ingress of hydrocarbon condensates into the unit. In turn,this has reduced the difficulties associated with floating sulfur,foaming, and absorber fouling. The development of B-3 has furtherimproved hydrocarbon-induced problems.
The recently replaced recirculation pump, the switch to KOH, andimproved absorber cleaning procedures have combined to permithigher gas flow (58,000 SCFM when clean) and greater H2S removalefficiency (averaging 90%).
Table 2 summarizes the present operating conditions of the unit.
Table 2 -- Present Operating Conditions
Corrosion is not considered to be a problem at this time, but aninspection of the oxidizer and settler is planned during the next turn-around. Replacement of the EPDM sleeves by polyurethane is apossibility at that time as well.
ANTICIPATED FUTURE CONDITIONS
It is anticipated that when final modifications to the absorber isolationvalves and water separation train are made, a sustained gas flow of58,000 SCFM, meeting pipeline H2S specification of less than 4 ppmvwill be achieved (static mixer efficiency improves with increased gasflow). Table 3 summarizes the anticipated future conditions.
After a difficult, extended start-up period, modifications to equipment,procedures, and chemistry has permitted the LO-CAT II unit to operateclose to expectations in spite of the continuing ingress of hydrocarboncondensate and higher than designed for CO2 partial pressure. It isanticipated that design gas load and efficiency will be achieved shortly.
The experiences gained in this first LO-CAT II elevated-pressureapplication, a subsequent 4 LTPD unit operating at 500 psig, and ahigh pressure pilot plant operating at nearly 1000 psig have beeninvaluable and will serve as a guide to the design and operation offuture units of this nature.
As demonstrated at the MOL site, the impediments to the use ofaqueous liquid redox technology for direct treat applications have beenresolved. This achievement, when combined with over 20 years ofexperience in other LO-CAT/LO-CAT II applications, makes LO-CAT IIthe technology-of-choice for the direct treatment of sour gases atelevated pressure.
Cleaning Up Gasification Syngas
Introduction
By definition, gasification is the art of changing a non-gaseoussubstance, such as a liquid or a solid, into a gas. By this definition,processes such as combustion, anaerobic digestion and pyrolysis wouldbe classified as gasification. However, in today’s world, gasification isdefined as any process, which produces a "synthesis gas" or a"syngas", which is a gas consisting mainly of CO and H2. With thisdefinition, the substance to be gasified may be a gas. The syngas canbe used for producing power and/or hydrogen, methanol, Fischer-Tropsch liquids, etc. Gasification is extremely environmentally friendlyin that if properly designed, gasification systems produce very minimalpollution even when processing dirty feedstocks, such as high sulfurcoals. In addition, gasification can effect large volume reductions insolid wastes while producing an environmentally friendly slag-typebyproduct. Also as the prices of natural gas and crude oil continue toincrease, gasification can be economically attractive even withoutgovernmental subsidies.
In a gasification process, a feedstock is heated to very hightemperatures (1000°C to 1500°C) under pressure (20 bar to 85 bar)in the presence of controlled amounts of steam and pure oxygen. Asindicated below, two sets of reactions occur in the gasifier. First,partial oxidation (Equation 1) occurs, which is exothermic and providesthe heat required for the second set of pyrolysis reactions (Equations 2through 4), which are endothermic.
In addition to CO, H2 and CO 2, small amounts of CH 4, HCl, HF, COS,NH3 and HCN are also formed. H2S is also formed with the amountdependent on the sulfur content of the feedstock.
Gasification feedstocks can consist of anything organic-based such ascoal, petroleum coke, biomass, wood-based materials, agriculturalwastes, tars, coke oven gas and asphalt. Gasification provides ameans of upgrading the value of very low or even negative value
materials. In refineries, cokers use to provide the same function;however, the fuel market for petroleum coke is disappearing, andpetroleum coke is becoming a waste product in and of itself.
Gasifiers are classified into three different types - fixed bed units,fluidized bed units and entrained flow units. The best known fixed bedunit is the British Gas / Lurgi process as shown in Figure 1. In thisunit, the feedstock is fed into the gasifier from the top and is depositedon the top of a fixed bed of material, which is maintained in the vessel.Steam and oxygen is fed into the bottom of the unit. As the feedstockis consumed, all inorganic materials melt and are removed from thebottom of the vessel where the molten material is fused into a non-leachable, non-hazardous slag. Syngas is removed from the top of thevessel. The best known entrained flow gasifier is the Texaco downflowgasifier as shown in Figure 2. In this process, the material to begasified is slurried with water and fed into the top of the gasifier alongwith oxygen. Slag and syngas are removed from the bottom of thegasifier. A fluidized bed gasifier is shown in Figure 3. In this type ofunit, the material to be gasified along with steam and oxygen are fedinto the bottom of the gasifier and the velocities are such that apercolating bed of material is maintained in the vessel. Syngas isremoved form the top of the vessel and slag is removed from thebottom.
In all of these processes, essentially all of the organic material isgasified, and the only solid material remaining is the inorganic slag,which can be used as road base and other building material. Thistremendous volume reduction in solid wastes is extremely attractive,especially in Europe where it is becoming very difficult and veryexpensive to dispose of solid wastes.
Combining a gasification process with power generation is called"Integrated Gasification Combined Cycle" or IGCC. As shown in Figure4, a typical IGCC facility combines the gasification process with aBrayton cycle (gas turbine/generator) and a Rankine cycle (steamturbine/generator). In petroleum refinery applications, a pressureswing adsorption unit (PSA) can be added to produce hydrogen for usein the refinery.
IGCC's generally consists of four processing blocks or "islands" - an airseparation unit (ASU), the gasifier, the syngas purification island andfinally the power generation island. These islands are generallydesigned and furnished by totally different vendors. The air separationunit is provided by a merchant gas company, which sometimes ownsand operates the ASU. The ASU may be sized to provide othercustomers in the area with oxygen and nitrogen. As previouslymentioned, there are many suppliers of gasifiers and the number ofsuppliers and types of gasifiers are increasing as the global gasificationmarket expands. The power generation equipment is supplied by thesame vendors as conventional power plant equipment. And finally,there are many approaches and consequently, many suppliers ofpurification equipment, which is the main focus of this article.
SynGas Purification
In an IGCC plant (Figure 4), the feedstock generally needs to beprocessed to make it suitable to feed to the gasifier. Generally, feedpreparation consists of milling and screening, and in the case of theTexaco gasifier, the feed needs to be slurried with water.
The feed is then fed to the gasifier where it is combined with oxygenand steam. Two streams exit the gasifier, a molten slag stream whichis composed of all the inorganic material in the feed and a syngasstream consisting mainly of CO and H2 but also containing entrainedsoot and ash, various amounts of H2S depending on the sulfur content
of the feed, and trace quantities of CO2, NH3, COS, HCl and HCN.Various treatment processes are required to remove the H2S and othertrace contaminants. A description of these processes follows. The cleansyngas from the purification island is then saturated with water priorto be combusted in a gas turbine. The moisture reduces NOx formationin the gas turbine. The chemical energy contained in the syngas isrecovered as both power and steam generation via a gasturbine/generator set followed by a waste heat boiler/steamturbine/generator set.
The gas exiting the gasifier is hot and contains fine soot and ashparticulate. The particulate is removed by either hot, dry candle filterslocated upstream of the high temperature heat recovery devices or bywater scrubbers located downstream of the cooling devices. Hot candlefilters are advantageous since the particulate is removed as a drysolid; however, these filters are subject to blinding and breakage. Inwater scrubbers, the particulate is removed as a slurry which must bedewatered; however, the water scrubber also removes the tracequantities of chlorides which may be present in the syngas and whichif not removed will poison the hydrolysis catalyst and cause metallurgyproblems in downstream equipment. In both cases, the recoveredparticulate is recycled back to the gasifier.
The high temperature heat recovery is generally accomplished by afiretube or radiant boiler followed by water tube boiler. Both boilersproduce high pressure steam while reducing the syngas temperatureto approximately 425°C.
The next step in the purification process is to remove the carbonylsulfide (COS) from the gas stream; otherwise, SO2 emission limits maybe exceeded after combustion in the gas turbine. There are two meansof accomplishing this removal. The more conventional means is topass the syngas through a fixed bed, catalytic hydrolysis reactor,which will hydrolyze the COS to CO2 and H2S and the HCN to NH3 andCO. Activated alumina type catalysts are generally employed for theseapplications, and COS concentrations approaching equilibrium levels (1- 10 ppm) can be achieved.
When hydrolysis reactors are employed, the reactor effluent gas iscooled and then processed through an acid gas removal system toseparate the H2S from the syngas. In syngas applications, physicalsolvent systems are generally more economical than chemical solventsystems, and the processes of choice are either Rectisol or Selexol.Rectisol tends to remove all of the acid gas components while Selexol
is more selective for sulfur compounds. However, chemical solventssuch as MDEA are also in use in gasification facilities.
A different approach to removing the COS and the other acid gascompounds from the syngas, is to process cooled (<50°C) digestergas, free of particulate, through a diglycolamine® (DGA) unit. In theprocess, the DGA reacts with COS as follows,
In the above equation R is HO-CH 2-CH 2-O-CH 2-CH 2- and R-NH 2isDGA.
The degradation product, R-N-C-N-R, is converted back to DGA in areclaimer which operates at of temperature of approximately 190°C.The reclaimer reaction is as follows,
In addition to removing COS, DGA also removes H 2S and CO 2to verylow levels.
An economic comparison should be done for each application todetermine which acid gas removal scheme should be employed -Hydrolysis/Rectisol, Hydrolysis/Selexol or DGA.
For straight IGCC applications, the effluent syngas from the acid gasremoval step is ready to be processed in the power generation islandof the facility. The gas is first combusted in a gas turbine/generatorset. Usually steam is injected into the combustion zone of the gasturbine to decrease NOx formation. The effluent gas from the gasturbine is then directed through a high pressure, waste heat recoveryboiler. The high pressure steam is directed through a steamturbine/generator set. Low pressure steam from the turbine is directedto export, and the effluent gas from the waste heat boiler is exhaustedto atmosphere.
For some refinery applications, it may be advantageous to separatesome or all of the hydrogen from the syngas for use in the refinery.This is accomplished by passing the syngas through a pressure swingadsorption unit. In this type of unit, the syngas is passed through abed of adsorbent in which all components other than hydrogen areadsorbed onto a molecular sieve at relatively high pressure. Thusproducing a very pure hydrogen stream. The adsorbent bed is thenisolated and depressured which releases the CO and other impurities.A water gas shift reactor may also be installed to increase the yield ofH2.
Sulfur Recovery
As previously stated, in a gasification process an acid gas streamconsisting primarily of CO2 and H2S is produced from whichever acidgas removal process (DGA, hydrolysis/Rectisol, hydrolysis/Selexol,etc.) is employed. It is imperative that the H2S contained in the acidgas stream be recovered in a safe and efficient manner to ensure thatthe entire process remains "Clean." Consequently, the selection of thesulfur recovery technology or technologies is an extremely importantstep in the design process of a gasification facility.
Since essentially all of the sulfur in the gasifier feedstock is convertedto H2S, the amount of H2S produced is totally dependent on the sulfurcontent of the feedstock. As a point of reference, coal has a relativelyhigh sulfur content while biomass has a relatively low sulfur content.Generally, the acid gas removal processes will lower the H2S content ofthe syngas to less than 4 ppm, which means that, in essence, all of theH2S produced in the gasifier must be processed in the sulfur recoverysystem.
The type of sulfur recovery system required is dependent on therequired sulfur recovery efficiency, the quantity of sulfur to beremoved and the concentration of the H2S in the acid gas. Therequired sulfur removal/recovery efficiency will vary depending onlocation; however, the gasification industry claims that the technologyhas "near zero" pollution, so it behooves the industry to install thebest available control technology. Currently, H2S removal efficienciesof 99.9+% can be economically achieved.
The Claus process has been the sulfur recovery workhorse forapplications with large amounts of sulfur (>20 LTPD), relatively high H2S concentrations (>15%) and consistent inlet conditions. However,the Claus process is limited by chemical equilibrium to removalefficiencies of approximately 98% if three catalytic reactor stages areemployed. To achieve higher removal efficiencies, a tail gas treatingunit is required.
For over 30 years, the tail gas treating process of choice has been theSCOT process. A simple schematic flow diagram of the SCOT process isshown in Figure 5. In the process, the tail gas from the Claus unit isheated to approximately 300°C in an in-line burner, which serves thedual purpose of heating the gas stream and producing a reducing gas,which is needed in the downstream reactor. The effluent from the
burner is then passed over a cobalt-molybdenum catalyst. In thereactor, all of the SO2, COS, and CS2 are converted to H2S by acombination of hydrogenation and hydrolysis reactions. The reactoreffluent gas is then cooled and processed through a typical amine unit,which is selective to the absorption of H2S. The recovered H2S is thenrecycled back to the Claus unit, and the remaining gas is sent to anincinerator prior to exhausting to atmosphere.
It is important to select the proper amine and to design the absorberin such a manner to minimize the absorption of CO2. Otherwise, alarge CO2 recycle stream will develop in through the Claus unit. Sincethe rate of absorption of H2S in alkanolamines is much quicker thanCO2, absorbers should be designed to minimize gas-liquid contact.Regarding amine selection, MDEA is a good selection for syngas. If theabsorber is designed properly and the correct amine is chosen, CO2
absorption can be limited to between 10% and 40% of the CO2 in thefeed gas to the absorber(1).
In some cases, the SCOT unit can be integrated with the upstreamamine unit, which is treating the syngas and producing the acid gas forthe Claus unit. For instance, if the syngas is being treated with anMDEA amine unit, the system can be designed with two absorbers, onefor the syngas and one for the Claus tailgas; however, only oneregenerator would be required.
When using MDEA, the sulfur content of the treated effluent gas will beless than 250 ppm, and the overall sulfur recovery of a Claus/SCOTsystem is typically 99.8%(2). The treated effluent gas is alwaysprocessed through an incinerator prior to exhausting to atmosphere.
Another method of increasing the overall sulfur recovery of a Clausunit is to replace the amine portion of the SCOT process with a liquidredox process such as LO-CAT® as illustrated in Figure 6. Thisapproach differs from that of SCOT because 99.9+% of the H2S in theeffluent gas from the hydrolysis/hydrogenation unit is converteddirectly to sulfur in the redox process(3) without having to recycle gasback to the inlet of the Claus unit. Because the liquid redox system isso efficient in removing H2S, overall (Claus + tail gas cleanup) sulfurrecoveries of 99.9+% can be easily realized. Thus, incineration of theliquid redox effluent gas is not required prior to exhausting toatmosphere; consequently, the capital and operating cost of theincineration system are removed from the project economics. Inaddition, by operating the Claus unit at high H2S:SO 2ratios (sub-stoichiometric oxygen), it is possible to eliminate the
hydrolysis/hydrogenation unit and still maintain overall sulfurrecoveries of 99.9+%. This approach is shown in Figure 7.
Another unique feature of employing a liquid redox system as a tailgas treating unit is that the turndown capability of the Claus/tail gassystem can approach 100% if the system is design properly. The liquidredox system differs from SCOT in that the liquid redox process is asulfur recovery process in and of itself, which has 100% turndowncapability. Consequently, by correctly sizing the liquid redox unit, theacid gas feed to the Claus unit can be routed directly to the liquidredox unit when the turndown capability of the Claus unit is reached.
For syngas applications in which the sulfur capacity is less than 20LTPD and/or the H2S in the acid gas is less than 15% and/or a greatdeal of turndown is required, Claus units may not be a good choicedue to difficulties in keeping the unit running. However, these are idealconditions for a liquid redox process.
Conclusions
Cleaning up syngas from gasification units is not a straightforwardproposition. Each application must be investigated in regards to boththe technical and economic aspects of the specific requirements of theapplication. Feedstock variability is also an important characteristic,which must be evaluated since many of the cleanup requirements willbe dependent upon the nature of the feedstock. In addition, great careshould be taken in the selection of the sulfur recovery portion of thesystem, since the sulfur recovery unit will determine how really"Clean" the system is.
ReferencesKohl, A.L. and Riesenfeld, F.C., "Gas Purification, Third Edition" p-686.Holub, P.E. and Sheilan, M., "LRGCC 200 Conference Fundamentals Manual",p-106.Nagl, G.J., "Employing Liquid Redox as a Tail Gas Cleanup Unit", ChemicalEngineering , March, 2001.Holub, P.E. and Sheilan, M., "LRGCC 200 Conference Fundamentals Manual",p-105
By Gary J. NaglGas Technology Products846 E. Algonquin Road, Suite A100 • Schaumburg, IL 60173 • Tel: (847) 285-3850 • Fax:(847) 285-3888 •Emai: [email protected]
Throughout the years, the Clausprocess has undergone a contin-uous evolution in attempts to
increase the sulphur recovery effi-ciency of the process. In the 1930s, athermal stage was added to the twocatalytic stages, which increased therecovery efficiency from 95% toapproximately 97%. In the 1970s, theSCOT process was introduced whichadded hydrogenation/hydrolysis plusamine separation to treat the tail gasfrom the Claus process. In 1988,SuperClaus was introduced, whichadded a selective oxidation reactor tothe end of the Claus process, increas-ing the efficiency to approximately99%. And just recently, EuroClaus1
was introduced, which replaced thesecond Claus reactor in the Super-Claus process with a selective hydro-genation catalyst increasing the effi-ciency to 99.5%.
It is obvious that the trend is toachieve higher and higher sulphurrecovery efficiencies. It is anticipatedthat in the near future Claus unitsinstalled in developed nations willrequired sulphur recovery efficienciesof 99.5% or better. Coupling a Clausunit and a liquid redox process, such asthe LO-CAT® either directly or indi-rectly in combination with a hydro-genation/hydrolysis reactor, however,can reliably achieve 99.9+% sulphurrecovery.
Direct tail gas treatmentWhen considering liquid redox to treatClaus tail gas without the inclusion ofa hydrogenation/hydrolysis reactor, theamount of SO2 in the tail gas is animportant operating parameter. Sinceliquid redox units operate at alkalinepHs in the range of 8 to 9, any SO2 inthe tail gas will be easily absorbed, andform sulphates in accordance withreaction 1:
SO2+2NaOH+½O2Na2SO4+H2O (1)
It is important to note that SO2 doesnot interfere with the liquid redoxchemistry and consequently does not
affect the H2S removal efficiency ofthe process. However, reaction 1 doesaffect the operating cost of the processin two ways. First, two moles of caus-tic are consumed for each mole ofSO2 absorbed, which increases theoperating cost of the unit. Secondly,the resultant sulphate product accu-mulates in the liquid redox solution,and eventually a blowdown is requiredresulting in loss of valuable catalystsolution. Replacing lost solution addsfurther to operating costs. Conse-quently, if this process configurationis to be employed, it is advantageousto minimise the formation of SO2 inthe Claus unit.
CLAUS AND LIQUID REDOX
Sulphur No 274May . June 2001 11
Liquid redox enhancesClaus process
Claus units can easily achieve sulphur recovery efficiencies exceeding 99.9+% by employing a liquid redox system such as LO-CAT as a tail gas treating unit. The significantlylower capital cost of this combination compared to conventional amine-based tail gas units offsets its higher operating costs. Further benefits include reduced sensitivity of the Claus unit to changes in feed gas composition and flow rate and excellent turndown capability.
Gary J. Nagl of USFilter Gas Technology Products discusses the merits of this process combination.
The first LO-CAT unit to treat Claus tail gas was recently installed at the WesternGas/Anadorko Bethel plant in Texas, USA.
The SO2 formation rate can beminimised by operating the Clausunit with sub-stoichiometric quanti-ties of oxygen, thus increasing theH2S:SO2 ratio in the unit.The effectof this mode of operation can be seenby analysing the Claus reactions.
H2S+1½O2 SO2+H2O (2)2H2S+SO2 3S+2H2O (3)
The conventional mode of operationfor a Claus unit is to convert one thirdof the H2S to SO2, which then reactswith the remaining H2S to form ele-mental sulphur.This is accomplishedby carefully controlling the quantityof oxygen entering the system. Due toequilibrium limitations, some of theSO2 leaves the system with the tailgas.
If the unit is operated in a mannersuch that there is insufficient oxygento complete reaction 2, then there willbe insufficient SO2 produced to com-plete reaction 3, and the H2S removalefficiency will be reduced. However,the amount of unreacted SO2 in thetail gas will also decrease.The effects2
of H2S:SO2 ratio on the H2S andSO2 contents in the tail gas and theoverall removal efficiency are illus-trated in Figs 1-3.
A flow diagram of a typical LO-CAT liquid redox unit for treatingClaus tail gas directly is shown in Fig.4. Since the liquid redox system isaqueous-based, elevated tempera-tures will cause water balance prob-lems; consequently, the tail gas is firstpassed through a cooler where the gastemperature is reduced from approxi-mately 135°C to 50°C.The cooled gasthen enters a knockout pot where anycondensate is separated. Dependingon the amount of condensate and sul-phur tonnage, this sour condensatemay be employed as make-up waterto the liquid redox process. If it can-not all be used as make-up water, theremaining sour water will need to beprocessed through a sour water strip-per with the sour gas being directedback to the liquid redox unit.
For direct treatment of Claus tailgas, the LO-CAT process would em-ploy a proprietary Mobile Bed Absor-ber (MBA) because of its low, inher-ent pressure drop (approximately 500mm of WC). For contacting media,the MBA uses hollow, ping-pong-likespheres which, when fluidised, are
CLAUS AND LIQUID REDOX
Sulphur No 274 May . June 20012
10,000
1,000
100
10
SO2
in ta
il ga
s (p
pm)
H2S:SO2 in Claus Unit
2 2.1 2.2 2.3 2.4 2.5 2.6 2.7
3-stage Claus 2-stage ClausSource: US Filter
Fig. 2: Effect of H2S:SO2 ratio on SO2 in tail gas
99
98
97
96
95
94
93
92
sulp
hur r
ecov
ery
effic
ienc
y, %
H2S:SO2 in Claus unit
2 2.1 2.2 2.3 2.4 2.5 2.6 2.7
3-stage Claus 2-stage ClausSource: US Filter
Fig. 3: Effect of H2S:SO2 ratio on sulphur recovery efficiency
10,000
1,000
100
10
1
H 2S:
SO2
in ta
il ga
s
H2S:SO2 in Claus Unit
2 2.1 2.2 2.3 2.4 2.5 2.6 2.7
3-stage Claus 2-stage ClausSource: US Filter
Fig. 1: Effect of H2S:SO2 ratio on tail gas
self-cleaning. Within the MBA, theH2S and the SO2 are absorbed intothe circulating solution, and the sul-phide ions are converted to elementalsulphur in accordance with theReaction 4 while the SO2 is convertedto sulphate as indicated by reaction 1.
H2S + ½O2 H2O + S (4)Fe
As indicated in Reaction 4, the reac-tion is catalysed by a proprietarychelated-iron catalyst.
MBA’s are normally designed toreduce the H2S concentration in agas to approximately 10 ppm. For tailgas applications with H2S:SO2 ratiosof greater than 2.0, this would resultin overall removal efficiencies of99.99+%. Even if the ratio weremaintained at 2.0, the removal effi-ciency would be 99.7%; however, thecaustic consumption would be muchhigher as indicated in Figure 3.
The solution exiting the MBA isdirected to an Oxidiser where air isinjected to regenerate the iron catalyst.If there is insufficient pressure avail-able for moving the tail gas throughthe MBA, a blower can be supplied oran eductor may be installed as shownin Fig.4.
LO-CAT systems are designedwith very ample liquid inventories.Although this increases the capital
cost slightly, there is sufficient capaci-tance in these systems to render themvery insensitive to sudden changes infeed conditions.Thus, fluctuations inthe H2S:SO2 ratio in the Claus unitwill essentially have no effect on theoverall removal efficiencies of the sys-tem as long as the Claus unit contin-ues to run. In the event that the Clausunit is unable to operate due to turn-down requirements beyond its capa-bilities, the system can be designedto bypass the Claus unit entirelyand route the acid gas directly intothe LO-CAT unit. This mode ofoperation (Fig.5) will still yield H2S
removal efficiencies of 99.99+%.Theversatility of the liquid redox systemwill ensure that the overall system willachieve 99.9+% removal efficienciesat all times. This inherent feature ofthe system is well accepted by regula-tors. In addition, the effluent from theliquid redox unit will not requireincineration since it will only containa very small amount of H2S andessentially no SO2.
Indirect tail gas treatingIn this processing scheme (Fig. 6) allsulphur compounds in a Claus tail gas
CLAUS AND LIQUID REDOX
Sulphur No 274May . June 2001 3
quench tower
makeup waterto oxidiser
steam
water to WWTP
vacuum belt filter
coolingwater
coolingwater
sour water stripper(optional)
eductor (optional)
mobile bed absorber
oxidiser air blower
wash water
exhaust to atmosphere
Claustail gas
sulphur cake
Source: US Filter
Fig. 4: Direct treat LO-CAT system
Claus unit
sulphur
exhaust toatmospherenormal operation
sulphur
closed closed
acid gas
acid gas
coolercooler LO-CAT unit
Claus unit
sulphur
exhaust toatmosphereturndown operation
coolercooler LO-CAT unit
Source: US Filter
Fig. 5: Claus bypass for 100% turndown
are converted to H2S by passing thetail gas through a hydrogenation/hydrolysis, catalytic reactor at elevatedtemperatures. Reactions 5 and 6(hydrogenation) and reactions 7 and8 (hydrolysis) represent the majorreactions, which occur in the reactor.
In this processing scheme, a fuel gasis subjected to partial oxidation,which not only generates sufficient
heat to raise the tail gas to reactiontemperatures but also generates suffi-cient hydrogen (reaction 9 shownbelow) to satisfy the requirement ofreactions 5 and 6.
CH4+O2 2H2+CO2 (9)
After passing through the reactor, theeffluent gas must be cooled to approx-imately 50°C. This can be accom-plished by emploing a direct contactcondenser as shown in Figure 6.Alternatively, an indirect condensercan be employed.
In either case, sour cooling wateror sour condensate will be generated.Again a portion of the sour condensateor water may be used as makeup waterfor the liquid redox unit; however,some of it will need to be sent to a sourwater stripper with the vapor beingrouted back to the liquid redox unit.
This processing scheme will beeven more forgiving to changes in theoperations of the upstream Clausunit, since the hydrogenation/hydrol-ysis unit will act to muffle any com-positional changes from the Clausunit. Consequently, the amount ofSO2 entering the liquid redox unitwill remain fairly constant, and theoperating cost of the system willremain constant.
CLAUS AND LIQUID REDOX
Sulphur No 274 May . June 20014
sour water stripperoptional
hydrolysisreactor
fuel gasair
Claus tail gas
quenchtower
firebox
coolingwater
coolingwater
eductoroptional
mobile bedabsorber
oxidiser
wash water
vacuum belt filter
sulphur cake
steam
water to WWTP
air blower
exhaust toatmosphere
Source: US Filter
Fig. 6: Indirect treat LO-CAT unit
vacuumpump
filtratepump
melter feedpump sulphur
pit
filtrate tosystem
slurry fromoxidiser
filtratereceiver
wash water
vacuum belt filter flash drum
sulphur separator
water vent
to drain
reslurrytank
hot oilor steam
Source: US Filter
Fig. 7: Sulphur melter system
Sulphur disposalBecause of its poor quality, sulphurproduced from liquid redox processeshas a bad reputation, which in somecases is well earned. However, due tothe relatively small quantities of sul-phur produced in liquid redox instal-lations, most liquid redox sulphur hasbeen either landfilled or disposed ofas solid, agricultural sulphur; hence,not a lot of effort has been exerted toimprove its quality. However, greatprogress has been made in improvingthe quality of sulphur produced inLO-CAT units.3
Sulphur is produced as a solid ina liquid redox unit. Since the reac-tions are not gas phase, there is nodissolved H2S in liquid redox sul-phur; thus sulphur degassing is neverrequired.The sulphur is normally fil-tered and washed to produce a filtercake, which is 65% to 85% sulphurdepending on the type of filter used,with the remainder being water anddissolved salts. It is not possible tosimply dump this cake into the Claussulphur pit, since there is insufficientheat in the pit to evaporate the waterand to melt the sulphur. And even ifthe moisture is removed prior todumping the sulphur in the pit, thesolid particles have a tendency tofloat on top of the molten sulphurthus making heat transfer and conse-quently melting very difficult. Due tothese problems, the sulphur from theliquid redox system must be disposedof as a solid3 or melted prior to beingintroduced into the sulphur pit.
Melting of liquid redox sulphurcan be accomplished in either batchtype melters or continuous melters. Asa rule of thumb, sulphur productionrates of greater than 5 tons per day(TPD) warrant continuous meltingwhile rates less than 5 TPD generallyrequire batch melting due to econom-ics. However, continuous melters canbe installed on any LO-CAT systemregardless of size. A typical melter sys-tem for a LO-CAT system is shown inFig. 7.
The change in quality of the Claussulphur due to the addition of molten,liquid redox sulphur will be as indi-cated in Figure 8. As a matter of com-parison, specifications for sulphuricacid plant grade sulphur are less than1000 ppm carbon and less than 250
ppm ash. This suggest that addingmolten, liquid redox sulphur to aClaus sulphur pit can be done withoutdegrading the Claus sulphur to anygreat degree. However, the overallquality of the sulphur mix can be fur-ther improved by processing the liquidredox sulphur through a diatomaceousearth filter prior to directing it to thesulphur pit.
CostsBudgetary capital costs of direct-treat,liquid redox, tail gas units completewith coolers and sour water strippers
are contained in Fig. 9. For compari-son purposes, the capital costs4 ofamine-based, tail gas cleanup units(TGCU) are also contained Fig. 9. Itis obvious that considerable capitalcost savings can be realized by utilis-ing liquid redox systems as tail gastreating units.With regard to operat-ing costs, the liquid redox system willincrease the operating cost of theClaus unit by approximately $14 perlong ton of sulphur entering the Clausunit. For an amine-based TGCU thisfigure will be approximately $8 perlong ton. Consequently, each applica-tion needs to be analysed to see if the
CLAUS AND LIQUID REDOX
Sulphur No 274May . June 2001 5
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carbon ashSource: US Filter
Fig. 8: Increase in contaminants from molten liquid redox sulphur
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Claus and liquid redox (with melter)
Claus and liquid redox (no melter)
note: based on 2-stage Claus unit operating at 96% efficiencySource: US Filter
Fig. 9: Capital cost of Claus plus direct treat liquid redox TGCUs
savings in operating cost of the amine-based system justi-fies the higher capital cost.
Field experienceThe direct contact, tail gas treating scheme described abovehas never been demonstrated commercially; however, thetwo processes comprising the scheme are commerciallyproven.The HCR2 process, which is a Claus unit operatingwith sub-stoichiometric oxygen, is well proven while theLO-CAT liquid redox process has been in commercialoperation for over 20 years with 150 licensed units. In addi-tion, approximately 50 of these units are treating acid gasstreams (CO2 and H2S). Consequently, there is no reasonto believe that the proposed arrangement would not oper-ate satisfactorily.
Variations of the indirect, tail gas treating schemeemploying an intermediate hydrogenation/hydrolysis stephave been in commercial operation since the early 1970swhen the Beavon Sulphur Removal Process was intro-duced.This process consisted of a hydrogenation/hydroly-sis reactor followed by a Stretford unit. Approximately 30of these units were installed.The process fell out of favourdue the potential toxicity problem with the vanadium cata-lyst employed in the Stretford process. Due to this prob-lem, iron-based, liquid redox processes such as the LO-CAT process has since replaced the Stretford process.
Recently,Western Gas installed the first LO-CAT unitin a Claus tail gas application at their natural gas produc-tion field in Palestine,Texas, USA. Initially, the LO-CATunit was treating amine acid gas; however, as the process-ing and the sulphur capacities of the facility increased, a2-stage Claus unit and a hydrogenation/hydrolysis reac-tor were installed, and the LO-CAT unit treated the reac-tor effluent.This system is yielding over 99.9+% sulphurremoval.
ConclusionsClaus units can easily achieve hydrogen sulfide removal effi-ciencies exceeding 99.9+% by employing a liquid redox sys-tem such as LO-CAT as a tail gas treating unit.The combi-nation of Claus and liquid redox has a significantly lowercapital cost than conventional amine-based tail gas unitswhich offsets its higher operating costs. In addition, the liq-uid redox unit will significantly reduce the inherent sensi-tivity of the Claus unit to changes in feed gas compositionand flow rate. And if designed properly, the turndown capa-bility of a system employing a Claus unit with a LO-CATtail gas unit can be approximately 100%.
p.65 (Sep/Oct 2000).2. Villa, Sergio and Ramshaw, D.E., “The HCR Modified Claus
Process Combined with LO-CAT II,” Sulphur ’91 Con-ference, New Orleans, LA (Nov 1991).
3. Nagl, G, “Emerging Markets for Liquid Redox Sulphur,”Sulphur ’97 Conference, Vienna, Austria (Nov 1997).
4. Tannerhill,C., “Budget Estimate Capital Cost Curves for GasConditioning and Processing,” GPA Annual Convention,Atlanta Georgia (Mar 2000).
S
CLAUS AND LIQUID REDOX
The State of Iron-Redox Sulfur Plant TechnologyNew Developments to a Long-Establishesd ProcessTechnologyBy Douglas L. Heguy and Gary J. NaglGas Technology Products LLC846 Algonquin Road Suite A100Schaumburg, IL 60173
The iron-redox process has enjoyed commercial success for over 25years, generally in applications requiring sulfur removal capacity below20 tons per day. Key process benefits include high H2S conversionefficiency, significant turndown flexibility, and ability to treat a widerange of gas compositions, and environmentally innocuous processand products. The process has also been know to consume expensivechemicals, produce “low-value” sulfur, and plug. This paper reviewsthe status of the technology, explains how the operating issues arebeing addressed in commercial practice, and provides a glimpse ofimprovements that are in the final stages of development.
Introduction
The family of liquid redox processes that has been developed since the1920’s is best represented, currently, by the “iron-redox process” or“chelated-iron” process. This technology has served its clients well formore than 25 years. Units typically achieve 99.9+% H2S removalefficiency, treat a wide variety of gas types over a wide variety ofoperating conditions, have substantial turndown capability on H2Sconcentration and gas flow and produce innocuous products and by-products. No wonder more than 200 such units have been licensedaround the world – a technical and commercial success by almost anydefinition!
The iron-redox technology is typically applied to gas streams requiringless than 20 tons per day sulfur removal capacity, unless operatingconditions limit use of other sulfur plant technologies, such as Claus.In such cases, Iron-redox may still be the best sulfur removaltechnology. Highly variable gas and low H2S concentration areexamples. Iron-redox plants as large as 80 tons per day are in
commercial use.
Also well known are the operating issues that have been associatedwith this process, such as high chemical cost, chemical degradation,plugging, foaming, production of “low-value” sulfur, inability to treathigh-pressure applications.
How are the leading developers of this technology addressing theseoperating issues? What improvements are on the horizon? With 25years of commercial application, is iron-redox technology stillcompetitive in today’s commercial environment?
The answers are clear. The iron-redox process technology has beenimproved continuously over the last 25+ plus years. Numeroustestimonials confirm that the technologies/solutions described in thispaper are being successfully applied in commercial applications. Asfurther evidence, there continues to be significant commercial activityfor this well-developed, well-proven technology in applications fornatural gas and associated gas processing, geothermal plants, refineryfuel gas, municipal odor control, landfill gas, and recently, municipalwaste gasification, as well as a host of others. Furthermore,improvements in the final stages of development will benefit the usersof this process technology in the near-term future, and ensure itslong-term commercial viability.
This paper will discuss the benefits of H2S removal, provide a basicdescription of iron-redox technology, a description of the solutionsbeing commercially employed to successfully address past and currentoperating issues, and, finally, explore the innovations that are on thehorizon.
Background
Removal of hydrogen sulfide (H2S) from gas streams has been an issuefor the energy industry since its inception. Hydrogen sulfide is anextremely toxic, corrosive and odorous gas, causing safety andmaterials issues in its unaltered form. After burning, the H2S isoxidized to sulfur dioxide (SO2), a major player in acid rain andgreenhouse gas emissions for the downwind neighbors. So, whilesulfur removal from gas streams has been an issue since the inceptionof the hydrocarbon-based energy industry, it also continues to getever-increasing attention as an environmental issue.Iron is an excellent oxidizing agent for the conversion of H2S toelemental sulfur. However, due to the very low solubility of iron in
aqueous solutions, the iron had to be present in the dry state (ironsponge) or in suspensions (the Ferrox process) or compounded withtoxic materials such as cyanides. In the 1960’s development work wasbegun in England to increase the solubility of elemental iron inaqueous solutions. This work led to the introduction of CIP (ChelatedIron Process). However, it wasn’t until the late 1970s that a system ofchelates was developed that had sufficient oxidative resistance to besufficiently stable and be commercially successful. This developmentwork led to the successful commercialization of the iron redox process.
Iron-redox process
In this process, iron, in its ferric state (+3), is held in solution bychelating agents. The intent of the process is to oxidize hydrosulfide(HS-) ions to elemental sulfur by the reduction of the ferric (Fe+3)iron to ferrous (Fe+2) iron, and the subsequent reoxidation of theferrous ions to ferric ions by contact with air. The chemistry of allchelated iron processes is summarized as follows with (l) and (v)representing the liquid and vapor states, respectively;
Equations 1 and 2 represent the absorption of H2S into the aqueous,chelated iron solution and its subsequent ionization, while equation 3represents the oxidation of hydrosulfide ions to elemental sulfur andthe accompanying reduction of the ferric iron to the ferrous state.Equations 4 and 5 represent the absorption of oxygen into theaqueous solution followed by oxidation of the ferrous iron back to theferric state.
Equations 3 and 5 are very rapid. Consequently, iron-based systemsgenerally produce relatively small amounts of by-product thiosulfateions, and, in properly designed units, air streams can actually beprocessed. However, equations 1 and 4 are relatively slow and are therate controlling steps in all chelated iron processes.
It is interesting to note that the chelating agents do not appear in theprocess chemistry, and in the overall chemical reaction, the ironcancels out. So why is chelated iron required at all, if it doesn’t takepart in the overall reaction? The iron serves two purposes in theprocess chemistry. First, it serves as an electron donor and acceptor,or in other words, a reagent. Secondly, it serves as a catalyst inaccelerating the overall reaction. Because of this dual purpose, theiron is often called a “catalytic reagent”. The chelating agent(s) do nottake part at all in the process chemistry. The sole purpose of thechelating agents is to solubilize iron in water, thus making it possibleto have a solution of iron.
Iron-based, liquid oxidation has developed into a very versatileprocessing scheme for treating gas streams containing moderateamounts of H2S. Advantages of these systems include the ability totreat both aerobic and non-aerobic gas streams, removal efficiencies inexcess of 99.9%, essentially 100% turndown on H2S concentration andquantity, and the production of innocuous products and by-products.
The two most common processing schemes encountered in iron-based,liquid oxidation systems are illustrated in Fig. 1 and 2. Fig. 1 shows a“conventional” unit, which is employed for processing gas streams,which are either combustible or cannot be contaminated with air suchas carbon dioxide, which is being treated for beverage purposes. Inthis scheme, equations 1 through 3 are performed in the Absorberwhile equations 4 and 5 are performed in the oxidizer. Fig. 2 illustratesan “autocirculation” unit, which is used for processing acid gas (CO2
and H2S) streams or for other non-combustible streams, which can becontaminated with air. In this scheme, equations 1 through 3 areperformed in the “centerwell” which is nothing more than a piece ofpipe open on each end. The purpose of the centerwell is to separatethe sulfide ions from the air to minimize by-product formation. Thevolume within the centerwell is essentially the same as the absorber ina conventional unit. The other unique feature of the autocirculationscheme is that no pumps are required to circulate solution betweenthe centerwell (absorber) and the oxidizer. In these units there is alarger volume of air than acid gas; consequently, the aerated density
on the outside of the centerwell is less than on the inside resulting in anatural circulation from the oxidizer into the centerwell.
The sulfur product is typically a sulfur “cake”, with entrained water andcatalyst solution. The entrained catalyst solution is effectively a“blowdown” stream for the aqueous process. (The catalyst solution isitself non-toxic and non-hazardous.) Depending on the type of sulfurfilter used, the sulfur cake can have a sulfur concentration between30% (bag filter) to 90% (filter press). The vacuum belt filter is quitecommon, and produces a sulfur cake that is 60-65% sulfur.
Developments in Iron-Redox Technology
Practitioners of iron-redox technology have as many as 25 years ofexperience designing process solutions for a wide variety ofapplications. That can be a very good thing, but it also means that alot that is “known” about iron-redox characteristics is 25 years old.However, this technology has, indeed, continued to evolve to addressthe issues of high chemical costs, chemical degradation, plugging,
foaming, production of “low-value” sulfur, and an “inability” to treathigh-pressure gas.
High Chemical Cost
It is not a simple matter of expensive catalysts used in the process.Rather, chemical costs in the iron-redox process are a function ofseveral variables: catalyst concentration, chemical degradation andchemical recycle.
Catalyst Concentration
Chemical concentration is an issue because the sulfur produced fromthe process is in the form of a sulfur “cake,” which has significantamount of entrained liquid. The filtered sulfur product exiting theprocess typically runs between 60% and 80% sulfur, but can run aslow as 30% sulfur. The remaining amount is a combination of washwater and catalyst solution. Clearly, the more concentrated thecatalyst solution, the more chemical is likely to leave the process withthe sulfur.
The main licensees of the iron-redox technology practice two verydifferent philosophies regarding catalyst concentration. The differencein catalyst concentration between the two philosophies is on the orderof 20-40x, depending on actual configurations and applications. Thisdifference in chemical concentration has aspects of a capital/operatingtrade-off, as the more concentrated solution clearly has benefits invessel and pump size (capital cost), at the expense of operating cost(chemicals). However, that analysis very much understates the impactof the catalyst concentration issue.
The scale factor on capital cost is moderated by several factors. 1)Vessel size is moderated by circulation rates, and 2) there aresignificant elements of the capital cost that are not affectedsignificantly by this relative equipment size, such as license fee,engineering design, project management, start-up, commissioning,and to a lesser degree, installation. So, while there is likely to be adifference in capital cost between the two philosophies, it will besignificantly moderated.
Chemical cost difference will be moderated by the effectiveness of thesulfur wash and chemical recycle. The catalyst cost difference won’t be20-40x, but it is likely to be at least several multiples. Current practicesuggests that a chemical cost difference of 2 to 3 times exists between
the two approaches.
Looking at catalyst concentration as solely a cost issue overlooks theoperating benefits with the more dilute system, namely:Higher capacity to solubilize products and by-products, andModerated response to process changes.
Depending on the feed gas composition, the iron-redox catalystsolution will have varying amounts of thiosulfates, carbonates andbicarbonates and oxalates, in addition to the iron and chelates. It isreasonable that the more dilute catalyst solution will have highercapacities to keep these other chemical species in solution, with lesslikelihood of creating precipitates, and less likelihood of operatingproblems resulting from precipitation. In fact, it is these solubilitylimits and the resulting operating problems that often limit the amountof chemical recycle that can be achieved in efforts to reduce chemicalloss. (This issue will be covered in more detail in the following twosections on chemical degradation and chemical recycle.)
The larger catalyst volumes and lower chemical concentrationscombine to create a “fly wheel” effect, so that changes to the inlet gasconditions result in greatly moderated changes to the sulfur plantoperating conditions, and a commensurate reduction in operatorattention.
There are iron-redox clients that operate the two different systemsside-by-side that can and have testified to the difference in operatingcost and operability between the two systems.
Chemical Degradation
The catalyst regeneration process requires oxidation of the ironcatalyst. Unfortunately, chelates are oxidized at the same time. Thiscreates two issues: the need to replace the degraded chelates and theexistence of the products of the degradation reaction, which tend to beoxalates. The build-up of the oxalates in the system will limit theamount of chemical recycle that can be achieved before precipitationof the oxalates occurs.
However, there has been significant development work to control therate of chemical degradation.
Although the iron-redox process is about 25 years old, research tounderstand and reduce chelate degradation has been ongoing for morethan 40 years and continues today. The catalyst systems employed by
the leading licensors tend to be proprietary, some are patented. Forexample, one technology supplier has used a patented blend ofchelates to improve stability over a broader range of operatingconditions, offering better oxidative resistance than can beaccomplished by a catalyst system that is based on only one type ofchelate.
In addition, there is significant work done on identifying oxygenscavengers. One elegant solution is the controlled production ofthiosulfate ions, which act as an oxygen scavenger in the system andeffectively reduces chelate degradation rates.
The chemical equation for the production of thiosulfate (potassiumthiosulfate, assuming potassium hydroxide is used to maintain pH) isshown in equation 7.
The trick is to produce thiosulfate in the right amount. Over productionof thiosulfate will over consume the caustic used to maintain pH.Underproduction will result in excessive chelate degradation.Controlled thiosulfate production can make a significant contribution tolowering chemical cost and improving process performance.
In summary, prospective buyers of iron-redox processes should asktheir supplier about their chelate degradation control mechanism. Bestpractice includes both oxidation resistant chelates and controlledproduction or introduction of an effective oxygen scavenger.
Chemical Recycle
The ability to recycle chemicals reduces chemical cost. The moreconcentrated catalyst system requires more chemical recycle to beeconomic. However, too much recycle leads to a build-up of unwantedoxalates and other chemicals, which can lead to precipitation andoperating problems. Thus, there is a limit to how much chemicalrecycle can close the chemical cost disparity associated with a largedifference in catalyst concentration.
Summary of Catalyst Concentration-Related Issues:
The dilute catalyst system offers significant operating cost benefits, asthere are fewer chemicals leaving the system and fewer barriers torecycling chemicals. In addition, there are significant operatingbenefits, as there is a significantly lower amount of oxalates and other
salts being recycled back into a catalyst solution that has a highercapacity for the recycled salts. This means that they dilute system isfar less likely to incur operating and maintenance problems associatedwith precipitates. Also, the relatively large volume attributed to thedilute catalyst system creates a “fly wheel” effect that moderates theimpact of variations in the inlet gas on the operation of the sulfur unit.
So, while chemical costs can vary significantly, depending on gas to betreated and sulfur wash and recycle designs, chemical costs for manysystems employing the dilute catalyst concentration are in the range of$175-$250/ton. Comparable costs for the more concentrated system,in similar applications, tend to be a factor of 2-3 times that cost.
In conclusion, prospective buyers of modern iron-redox systemsshould insist in good chemical cost guarantees with his unit. Thereputable and experienced firms in this area offer good experience,can estimate chemical usage based on feed gas and equipmentconfiguration with reasonable accuracy, and will back their analysiswith good guarantees.
Plugging
Plugging problems have been solved by eliminating packed towers,and by incorporating standard piping designs that limit dead spots andareas of restricted flow—not rocket science, just good basic designdiscipline.
Some iron-redox suppliers insist sulfur is formed in the oxidizer, andthe return catalyst stream can run through a filter to prevent sulfurfrom going into the absorber to prevent plugging. This design will plug.The sulfur reaction is fast: sulfur will form in the absorber, and thepacked tower will plug, regardless of the effectiveness of any filter inthe catalyst return line. Prospective customers of this technology needto insist that their design be void of any fixed surfaces that can offersites for sulfur build-up, or alternatively, insist on good sulfur clean-out provisions as part of the design.
Additional steps to prevent plugging include proprietary heatexchanger designs that minimize plugging. Newly designed absorberspargers and improved oxidizer spargers have significantly improvedmaintenance requirements and decreased plugging in the oxidizer.Oxidizer vessels and/or separator vessels now have cone-shapedbottoms with additional air injection systems to maintain fluidity in thecone.
For absorber designs that include counter-current gas/liquid flow inwhich the catalyst solution is sprayed into the column, plugging due tosulfur carryover is being controlled with properly designed andpositioned spray nozzles and knockout pots.
Foaming
Chelated-iron systems can foam when two conditions are present:during the initial plant start-up and when a large amount of heavyhydrocarbons enter the system.
In the first case, the surface tension properties of the fresh catalystsolution can lead to foaming issues in the first few days of operation.This is an issue only with the initial start-up with fresh solution, andcan easily be handled by following the start-up procedures. This willnot be an issue with subsequent start-ups with aged solution.
Continuous incursions of small amounts of liquid hydrocarbons arefrequently experienced with no adverse effect on the operation of aunit; however, the introduction of large amounts of liquidhydrocarbons can present foaming problems. The good news is thatthe unit will continue to operate and treat the gas, but the operationwill be “messy”. It is unlikely the plant will need to shut down. (This isin contrast to most Claus-type reactor systems with fixed catalyst bedsthat would likely experience catalyst fouling, and be forced to shutdown and replace catalyst following a similar process upset.) Wherethis is seen to be a possibility, suitably designed knockouts andseparators should be incorporated into the gas inlet piping design.However, should foaming occur, “designer” surfactants1 have beendeveloped, which alleviate the foaming symptoms caused by theintroduction of large amounts of liquid hydrocarbons.
Production of “low-value” sulfur
In this world of excess sulfur production due to the large amount ofby-product sulfur being produced, when was the last time anyoneproduced “high-value” sulfur?
It is true that typical iron-redox sulfur has entrained water andresidual catalyst in sulfur cake form. The sulfur content of the cake canrange from 30% sulfur to 90% sulfur depending on the type of sulfurfilter incorporated. Though sulfur in this unmelted “cake” form istypically undesirable as a chemical feedstock; it actually has superior
properties as a sulfur fertilizer when compared to typical “pure” sulfurproduced by more traditional processes.
One California chemical manufacturer typically handles 20,000 tons ofiron-redox sulfur per year, and would like more. The fact that iron-redox sulfur was formed in the liquid phase at low temperature meansthat the sulfur particle is amorphous (softer) than solidified moltensulfur, and has a smaller particle size, for faster reaction in the soil. Inaddition, the other catalyst elements in the iron-redox solution, andpresent in the sulfur “cake” (iron, chelates), are micronutrients in theirown right and sold as such by several suppliers of agriculturalproducts.
In order to ensure a market for iron-redox-produced sulfur,commercial proposals have been made that include concurrentfertilizer market development activity.
Commercial sulfur purification systems can convert iron-redox sulfur tomolten sulfur of 99.9% purity. However, the appearance (color) willstill be slightly degraded due to the presence of iron polysulfides.Where development of a fertilizer market is an option, it is preferableto develop that opportunity rather than install equipment to purify thesulfur, as the cost incurred is generally not matched by acorresponding increase in sulfur value in this market of excess sulfur.
Inability to treat high-pressure gas
Operation of aqueous-based liquid redox systems at high pressure hasbeen a problem due to difficulties with keeping the liquid circulationpumps running. Circulation pumps were always specified as ANSI,open-impeller centrifugal pumps. The logic being that closed-impellerpumps would plug with sulfur particles or possibly erode.Consequently, for high head applications in which open impeller pumpswould not apply, plunger type pumps were chosen. The plunger pumpshad no difficulty supplying the required head, however, seal rings hadextremely short lives. To solve this problem, a multi-staged, closed-impeller, centrifugal pump was installed in one high-pressureapplication with excellent results. The pump has been in continuousoperation for approximately 4 years without any signs of plugging orerosion. Since that installation, similar installations at even higherpressure (as high as 1,000 PSI) have had similar success. For allfuture high-pressure applications, closed-impeller single or multi-stagecentrifugal pumps will be specified. Obviously, the original concernabout plugging had no basis.
While iron-redox systems can now be designed to direct treat highpressure gas streams, there will still be occasions where it will makesense to direct treat the high pressure gas with a conventional amineunit and treat the resulting acid gas with an iron-redox autocirculationunit (Figure 2). In applications that benefit from the additionalabsorption capabilities of a conventional amine unit, such as removalof CO2, along with the required infrastructure, utilities, and experienceto run a conventional amine unit, the simplicity of the iron-redoxautocirculation can be an advantageous process solution. About 30%of the installed iron-redox plants are this configuration.
The Future of Iron-Redox Systems
While many of the operating issues associated with iron-redox systemshave been successfully addressed in current designs, significantadvances are being made in the state of the technology which willensure a bright future well into the next century. Developmentactivities are focusing on improved capital cost and design flexibility,focused on development of improved mass transfer devices in theoxidizer, and improved iron-redox sulfur market development.
An improved mass transfer device in the oxidizer is scheduled forcommercial demonstration in early 2003. Successful demonstration ofthis technology will result in reducing the size of the oxidizer by asmuch as a factor of ten, creating significant cost, space and weightdifferences relative to current systems and provide significant designflexibility. Also, the ability to modularize portions of the plant shouldalso create economies in the design and installation of the new units.
Finally, expansion of the successful marketing of iron-redox sulfur canpay large dividends to the operator of the iron-redox plant. In additionto the significant agricultural benefits available to the surroundingagriculture industry, the successful market development of this sulfurshould reduce sulfur transport and disposal costs, reduce futureliability from disposal issues, and improve plant-permitting prospectsfor new and/or expanded facilities.
Summary
In summary, the iron-redox technology has been continuouslyimproved over 25 years of successful commercial application. Solutionsto most of the “operating issues” associated with the technology havebeen developed and are being successfully practiced in commercial
applications. The most robust iron-redox plant operations willincorporate, as part of the design:low concentration iron catalyst (around 1,000 PPM)catalyst solutions that incorporate “chelate blends” for enhanced stability andoxidative resistanceavoidance of “packed” columns for gas-liquid contacting“slurry-friendly” piping designs.
New developments on the horizon promise improvements in designflexibility and reduced capital cost.
The implication for operators that must remove sulfur from gasstreams is that the iron-redox technology offers a unique combinationof proven experience and continuous improvement. It is a technologythat is commercially and technically attractive, and in which theoperator can have a high degree of confidence.
Suncor’s Optimization of a Sulfur Recovery FacilityBy Dean Freeman, Suncor,Jackie Barnette, GTP LLC, Gary Nagl, GTP LLC
Introduction
Suncor Incorporated Resources Group acquired the 7-22 Progress GasPlant, located in Spirit River, Alberta, Canada, in 1996. Due to theextremely competitive nature of the natural gas business, all gasprocessors, including Suncor, are obsessed with reducing operatingcosts. As part of Suncor’s cost reduction program, a close examinationof their sulfur recovery unit by Suncor and Gas Technology ProductsLLC resulted in significant cost savings by optimizing the method ofoperation.
The Facility
The 7-22 Progress Gas Plant processes 20 MMSCFD of natural gas atapproximately 950 psig. As shown in Figure 1, the processing trainconsists of an MDEA amine unit for removing CO2 and H2S, a glycoldehydrator and an Autocirculation LO-CAT® unit for removing the H2Sin the amine acid gas prior to exhausting to the atmosphere.
The LO-CAT® process is a proprietary process, which converts H2S toelemental sulfur by employing a patented, environmentally safe,multichelate, iron catalyst. The overall reaction (Rx 1) of the process is
the modified Claus reaction; however, the mechanism for achievingthis reaction is much different than that which occurs in the Clausprocess.
The LO-CAT® process is a liquid phase, ambient temperature process,which is in contrast to a Claus unit, which is a gas phase, elevatedtemperature process. The LO-CAT® reactions can be separated intothe Absorption Section and the Regeneration Section. In theAbsorption Section, the H2S is absorbed (Rx 2) from the gas streaminto the circulating aqueous (aq.) LO-CAT® solution. Once absorbed,the H2S ionizes (Rx 3) into hydrogen and hydrosulfide ions, and thehydrosulfide ions then react (Rx 4) with ferric ions to form elemental,solid sulfur and ferrous ions.
The ferrous ions are not capable of being reduced any further;consequently, to have a continuous process they must be oxidizedback to the ferric state. This is accomplished by sparging air throughthe effluent solution from the Absorption Section of the process.Oxygen is absorbed (Rx 5) into the solution, which then oxidizes theferrous ions (Rx 6) back to the ferric state.
Adding reactions 2 through 6 yields reaction 1 with all components inthe gaseous phase with exception of the sulfur, which is in the solidphase.
The LO-CAT® unit employed at the Suncor plant was installed in 1990and is of the patented Autocirculation design, which is shown in Figure2. In this configuration, the Absorption and Regeneration Sections ofthe process are located within the same vessel. The acid gas from the
amine unit is sparged into a centerwell (Absorber), which is nothingmore than an open-ended pipe located within a cone-bottom tank. TheAbsorption reactions (Rx 2 – 4) occur within the centerwell. Theregeneration air is sparged into the solution outside of the centerwellwhere the regeneration reactions (Rx 5 & 6) occur. Since there isconsiderably more regeneration air than acid gas, the solution outsideof the centerwell is more aerated (less dense) than the solution insideof the centerwell. Consequently, this density difference creates anatural liquid circulation from the Regeneration Section of the vessel tothe Absorption Section. Thus liquid circulation is established withoutthe need of pumps.
Sulfur settles out of solution into the cone section of theAutocirculation Vessel where it is removed as a 10 wt% to 15 wt%slurry. The sulfur slurry is heated to approximately 120o C by heatexchange with hot oil, and the solid sulfur is melted. The molten sulfurand LO-CAT® solution are then separated, with the solution beingreturned to the process. The melter system operates underapproximately 3.5 barg pressure to prevent the aqueous solution fromboiling. The molten sulfur is allowed to solidify, and is then hauled to alandfill. Due to the remoteness of the plant and the relatively smallamount of sulfur being produced (2.2 MTPD), it is more economical todispose of the sulfur at the local landfill than to sell it to a remote user.Trucking the sulfur to a remote user will cost more than what thesulfur is worth.
Even though water is produced in the process, a small amount ofmakeup water is still required for the LO-CAT® unit to compensate forthe moisture consumed in saturating the regeneration air. The plantoriginally used well water for this purpose; however, the plantpersonnel discovered that some of the problems they wereexperiencing in the unit, such as occasional foaming, disappearedwhen they switched to deionized water. Obviously, the well watercontained surface active components which were conducive tofoaming. In general, LO-CAT® units only require water of potablequality.
An Autocirculation LO-CAT® unit is an extremely simple system tooperate. In essence, the unit consists of a cone-bottom tank throughwhich air and acid gas are sparged through an aqueous solution ofchelated iron. A small slip stream of concentrated sulfur slurry ispumped through a hot oil heat exchanger with molten sulfur beingwithdrawn from the system, and solution being returned to the cone-bottom tank. Operators’ attention is only required to test the solution
for pH and Redox potential once or twice a day.
Operating Costs Associated with the LO-CAT® Unit.
There are two major sources of operating costs associated with a liquidredox process such as LO-CAT®. They being the costs related tochemical makeup and those related to power consumption. The majorcomponents of the power costs for the Suncor unit involved two,rotary lobe blowers (65 KW/each) used for blowing air into theprocess, and the major components of the chemical makeup costs areassociated with iron and chelate makeup’s and caustic addition to theunit.
Chelates are water soluble, organic compounds which hold the iron insolution. By employing the proper chelate, the solubility of iron inwater can be increased from a few parts per million to the 5 wt%range. The chelates will, over time, oxidize by a free radicalmechanism and require replacement. The rate at which they oxidizecan be controlled by utilizing a stabilizing agent, which acts as a freeradical scavenger.
The LO-CAT® process utilizes a proprietary means of reducing chelatedegradation. Within the process, a small portion of the H2S isdeliberately converted to thiosulfate ions (S 2O3=), which are excellentfree radical scavengers. In fact, many years of research by GasTechnology Products have failed to result in a better free radicalscavenger. By being able to generate thiosulfate within the process,chelate replacement costs can be held to a minimum with minimaleffort.
Iron is lost from the system by physically removing solution from theunit. For LO-CAT® systems with sulfur melters, the major means ofiron lost is by the blowdown of solution from the unit to controlsolution specific gravity.
The specific gravity of a LO-CAT® solution is dependent upon theamount of salts, which are dissolved in the solution. Since LO-CAT®operates at relatively low iron concentrations, the chelated iron is nota major contributor to the density of the solution. This is in sharpcontrast to other redox processes. In a LO-CAT® unit, the majorcontributors to solution density are carbonate/bicarbonate salts andthiosulfate/sulfate salts. Carbonate/bicarbonate salts are formed whengas streams containing CO2 are being processed. Depending on theCO2 partial pressure and the desired pH of the solution, CO2 willdevelop equilibrium concentrations of carbonate and bicarbonate asfollows:
The equilibrium constants for each reaction are pH dependent,increasing with increasing pH. Although the Suncor LO-CAT® unit is
processing an acid gas stream containing a high concentration of CO2 ,the system is operating at atmospheric pressure, which yields arelatively low CO2 partial pressure. Consequently, thecarbonate/bicarbonate concentrations in the solutions are also low.
As previously discussed, thiosulfate formation is desirable as a meansof controlling chelate degradation. However, if solutions become toooxidizing (high oxidation/reduction potential), thiosulfate can beoxidized to sulfate, which has no beneficial value in the process. Theformation of thiosulfate and sulfate occur as follows:
It is important to note that the above reactions (Rx 7 – 11) all produceacidic products (H+). Consequently, to maintain the solution in theslightly alkaline range, which is required to promote good absorptionof H2S, caustic in some form (KOH, NaOH or NH3) must be added tothe solution. The thiosulfate/sulfate salts also contribute to increasingthe specific gravity of the solution.
If the concentrations of dissolved salts are allowed to increaseunabated, a point will eventually be reached when one or both of twothings will occur. First, the solution will become less capable ofabsorbing oxygen and H2S, which will affect the ability of the processto remove H2S from a gas stream, and second, the solution willeventually become saturated and salts will actually start precipitatingfrom the solution resulting in plugging problems. To prevent this fromhappening, a small blowdown stream is taken. For systems, whichhave a filter for removing sulfur from the unit, a sulfur cake isproduced, which usually contains sufficient solution to compensate forsalt formation; however, in a system, which produces molten sulfursuch as Suncor’s, a liquid blowdown stream is usually required. Theseblowdown streams represent a lost of iron from the process, whichrequire makeup iron to be added.
Unless there is a hazardous or toxic component in the gas streambeing treated, which is soluble in aqueous solutions, the blowdownliquid will be merely water containing dissolved salts; however, it willhave a chemical and biological oxygen demand due to the chelates.Consequently, there is a cost associated with treating the blowdownstream. In Suncor’s case the blowdown is hauled away for remotetreatment since there are no onsite wastewater treatment facilities.
Suncor’s Optimization
Prior to Suncor’s purchase of the Spirit River facility, little attentionwas given to the LO-CAT® unit. In general, over injecting chemicalsinto a LO-CAT® unit will not result in operating problems, just higherthan required operating costs. Consequently, in remote gas plantssuch as Spirit River, it is sometimes difficult to convince operators tochange operating conditions if the unit is not presenting any operatingproblems. However, this is not Suncor’s operating philosophy.
Upon taking ownership of the facility, Suncor contacted GasTechnology Products and stated that the operating costs associatedwith the LO-CAT® unit were not cost effective and something had tobe done about chemical consumption, power consumption and thedisposal cost of blowdown liquid or the unit would be shutdown. At thispoint, Suncor and Gas Technology Products started working closelytogether to optimize the system.
The Suncor LO-CAT® unit is operating at close to the designconditions of 123.4 Nm3/Hr of acid gas containing 57.5% H2S (2.19MT/day of sulfur). As suspected, an initial examination of the unit anda review of historical operating data show that the chemical additionrates were much higher than the original design rates, and that theoperators were maintaining a lower solution specific gravity thanrequired by maintaining a higher than normal blowdown rate. Forexample, the iron concentration was being maintained at more thantwice the design level while the chelate concentration was more thanthree times the design level. In addition, the system was designed tooperate with one air blower in operation; however, the unit was beingoperated with both air blowers in operation. These conditions resultedin a very positive, solution oxidation-reduction potential (redoxpotential), which promoted the formation of sulfate rather thanthiosulfate resulting in a relatively high chelate oxidation rate.Consequently, this highly oxidized solution state resulted in high saltformation and thus a high blowdown rate to maintain the less thandesign solution specific gravity. Consequently, the high blowdown rateresulted in a high iron replacement rate and higher than requiredsolution disposal costs. The unit was also experiencing symptoms suchas occasional sparger plugging, which indicated that the solution wasclose to saturation.
The obvious remedy to Suncor’s problems was to get the solutionchemistry back to a normal state. This was accomplished bydiscontinuing the chemical addition of the makeup chelate and the
makeup iron. In addition, one air blower was shutoff, thus immediatelyreducing power consumption by 50%. During this period, GTPmonitored the solution chemistry on a biweekly basis. Over a relativelyshort period of time, the iron, chelate, and stabilizer concentrationsand the solution specific gravity were bought into line. At this time, thechemical addition and blowdown rates were re-established, but atrates corresponding to actual processing conditions of the unit. Whenthe unit was operating at design conditions, power consumption,chemical costs and disposal costs were reduced by approximately50%, thus achieving operating costs, which were in line with Suncor’srequirements. In addition, problems with sparger plugging weregreatly reduced. All of these reductions were achieved whilemaintaining an H2S removal efficiency of greater than 99.99+%. Table1 summarizes the before and after operating costs.
It is important to note that these cost savings were obtained by simplyturning pumps and blowers off. No daily detailed chemical analyzeswere required, just simple redox potential, pH and specific gravityreadings. And although it took years to get the LO-CAT® solution in astate of near saturation, the situation was remedied in a matter ofweeks.
Although dramatic reductions in chemical costs were achieved at theSuncor facility, even more chemical savings can be realized in moremodern LO-CAT® units due to the ability to more accurately controlthiosulfate concentrations.
Conclusions
A determined commitment to teamwork by Suncor and GasTechnology Products has resulted in a significant reduction in plantoperating costs in the LO-CAT® unit while maintaining high H2Sremoval efficiency and ease of operation. As summarized by the plant
operation staff– “Chemical consumption and cost savings areimportant to Suncor. The ultimate is to remain emission free whilerunning as economical as possible. This process can run emission freewhich will in turn guarantee the safety of the plant operators and ourenvironment.”
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AxensEngelhard CorporationDow Chemical CompanyGas Technology Products LLC
Description: Axens is a refining, petrochemical and natural gas market focusedsupplier of process technology, catalysts, adsorbents and services, backed bynearly fifty years of commercial success. Axens is a world leader in severalareas, such as: Petroleum hydrotreating & hydroconversion, FCC gasolinedesulfurization, Catalytic Reforming, BTX (benzene, toluene, xylenes) production& purification, Selective Hydrogenation of olefin cuts, Sulfur recovery catalysts.Axens is a fully-owned subsidiary of IFP.
Executives: Jean Sentenac, Chairman & CEOJean-Pierre Franck, Chief Operating OfficerMichel Dugert, Managing Director & Process LicensingFrancis Nativel, Managing Director & Performance ProgramsChristian Vaute, Managing Director & Procatalyse Catalysts and Adsorbents
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Dow Chemical CompanyDow Gas Treating Products & ServicesP.O. Box 1206Midland, MI 48642USATel: 800-447-4369Tel: 989-832-1560Fax: 989-832-1465http://www.dowgastreating.com
Description: Dow Gas Treating Products & Services is the worldwide leader inproviding gas treating processors with technology and specialized services. Ourpeople have been at the forefront of gas treating technology for over 60 years.Our amine chemicals, UCARSOLTM Solvents, specialty amines and specializedtechnologies are the most advanced solutions available for gas treatment.
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Gas Technology Products LLC,A Member of the Merichem Family of Companies846 E. Algonquin Rd., Suite A100Schaumburg, IL 60173USATel: 847-285-3850Fax: 847-285-3888http://www.gtp-merichem.com
Description: Devising a comprehensive, flexible hydrogen sulfide (H2S)removal/recovery solution requires more than a systems, media and equipment –it requires expertise. With more than twenty-five years of experience in H2Sremoval, Gas Technology Products LLC understands the needs of everyoperator and every plant.
Products: Gas Technology Products provides a full line of complementaryhydrogen sulfide oxidation products: LO-CAT® and LO-CAT® II, Sulfur-Rite®and The EliminatorTM processes, along with its ARI®-100 mercaptan oxidationproducts and engineering services.GTP offers both liquid and solid media desulfurization technologies to sweetengas streams and ventilation air containing virtually any levels of hydrogen sulfideor mercaptans – for systems of widely ranging capacities. For any size or typeapplication, GTP offers complete turnkey systems and can take total systemresponsibility.As a wholly owned subsidiary of Merichem Chemicals & Refinery Services LLC,Gas Technology Products LLC is a part of a fully integrated organization withunmatched technical knowledge, applications expertise, and worldwide servicecoverage.
