AM inGr t

CO2 rmemproce

Utilize

NaturThermal swing adsorption (TSA)unit

Removes heavy hydrocarbons

Serves three functions

Membranepretreatment

Feed gas dehydration

Sales gas hydrocarbondew pointing.

Background

General Considerations

Plant built and commissioned in1998 without TSA membranepretreatment

Initial well tests indicated minimalamounts of heavy hydrocarbons

Subsequently, found not to bethe caseMembrane separation and

Amine adsorption

Simplified process flow diagram isshown in Figure A-2.DOI: 1emoval process uses abrane/adsorption hybridss

s bothProcess overviewCO2 concentrations

Inlet: 30%

Outlet: 3%Indonesia: Case

Introduction

ConocoPhillips operates Grissik GasPlant (Figure A-1) on behalf of itspartners:

Talisman Energy

Pertamina

BPMigas

Design basis

Gas feed: 310 MMscfdppendix Aembrane/Amissik Gas Plan0.1016/B978-1-85617-982-9.00008-9Fed to the amine absorptioncolumn where CO2 isremoved to about 3%.

Permeate rich in CO2 exits themembrane at near atmosphericpressure.CO2 rich permeate is sent toan atmospheric burner toproduce steam which is usedin the amine plant forregeneration.

al gas exiting the membrane

Contains about 15% CO2e Hybrid,1,2,3 Sumatra,Study

Benefits of membrane/amine hybridprocess

Have a single stagemembrane and utilize thethermal value in the permeatestream, thereby

Enjoying the simplicityof a membraneseparation processwithout the use of arecycle compressorwhile

Still avoidinghydrocarbon losses.

158 Gas Sweetening and Processing Field ManualFIGURE A-1 Grissik gas plant.First Commissioning

Membrane initially installed withpretreatment consisting of

Coalescing filter and

Nonregenerable absorptionguard bed.

At startup in 1998

Actual levels of heavyhydrocarbons (CO10,aromatics, and napthenes)were higher than anticipated.

Raw feed300 MMSCFD 1140 PSIG 83 F 30% CO2

Retentate 230 MMSCFD 1100 PSIG 99 F 15% CO2

Perm

Gas/liquid separator

TSA

Note: Approximate flows and compositions shown.

120F

FIGURE A-2 Grissik process flowResulted in sharp reductionin membrane capacity(declining to 2030% ofinitial capacity within in amonth)

To maintain productioncapacity, the membraneelements were beingfrequently replaced.

Installation of TSA

ConocoPhillips evaluatedheavy hydrocarbon removalprocesses including

Membrane

Steam generator

Sales gas

Amine absorption column

Dehydration

eate

200 MMSCFD1087 PSIG 2% CO2

diagram.

Gas chilling process and

Regenerableadsorption process.

Gas chilling process

Deemed ineffective atthe plant operatingpressure, which wasnear the cricondenbarof the feed gas phaseenvelope

Regenerable adsorptionprocess

Short cycle processfrom Engelhardwhich uses Sorbead

Designed toreduce C6components(includingaromatics andnapthenes) sothat membraneperformance canbe maintainedfor an extendedperiod of time

Designed withtwo separatetrains, each withfour adsorptionvessels (refer toFigure A-3)

hydrocarbons for properpretreatment so as to yieldlong membrane life.

FIGU l swing adso

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant 159RE A-3 Engelhard thermasilica gel at elevatedtemperatures.

TSA was built andinstalled by Kvaener in2000Aromatics

Napthenes

Adsorption cycle isfollowed byregeneration of the(Silica Gel) as theadsorbent

Uses multiple beds inparallel adsorption toremove

Heavyhydrocarbonsrption unit.TSA design andperformance

General Design

Considerations

Since feed gas was found to containhigh levels of heavy hydrocarbons(C10, aromatics, and napthenes)

TSA had two functions and solvedtwo problems:

TSA removes heavy

Removal of heavyhydrocarbons allows the salesgas to meet hydrocarbon dewpoint specs.

Since water is more strongly heldonto the Sorbead adsorbent thanany of the hydrocarbons, the TSAsystem also dehydrates the feedupstream of the membrane unit.

TSA Process Description

Each train was designed to treat225 MMscfd

Consiadsor

Refer(Figur

treated gas to thedownstreammembrane unit.

Balance of the feed gasbypasses the pressuredrop valve so as toprovide the necessaryflow through thetowers being cooledand heated.

Regeneration path containsthe

Tower being cooled

er ting Heliq

rem

diagram

160 Gas Sweetening and Processing Field Manualthrough the two-phaseseparator, is split into twoparallel paths.

Majority of the gasflows through thepressure drop valve andthen directly to twotowers on paralleladsorption.

Cycle time of thetowers is staggered by50% to allow for acontinuous flow of

Wellhead

Regen heater

TSA tower cooling

TSAtowhea

Liquid

Pressure drop valve

FIGURE A-4 TSA process flowsts of four internally insulatedber towers

Minimize the thermal massfor the short thermal cycle

Reduces heat load on thesystem

to TSA process flow diagrame A-4)

Feed gas, after passingTo membraneskids

TSA 2 towers adsorbing

avy uids

oved

.Wet feed gas is used as theregeneration medium, andbecause of the pressure dropvalve, there is no need for acompressor to boost thepressure of the spentregeneration gas.Cooling

AdsorbingEach tower is associated withsix valves that allow it tochange functional positions

Adsorbing

Heating/regeneratingRegeneration heater

Tower being heated

Heat recovery heatexchangers, and

Spent regeneration gasseparator

components aredesorbed

Reas

In ordflowbed,funct

MaximdeterGrissitoweadsor

in parallel on adsorption is anequalized composition of thetreate

In a s

Breakthrough

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant 161regeneration gasrequirement.ons for Four Towers

er to maintain an acceptablevelocity across the adsorberthe number of towers used is aion of

Flow rate and

Tower diameter.

um tower diameter wasmined by transport limits;k design resulted in fourrs with two towers in parallelption.

Internal insulation was usedto minimize the amount ofthe process where theheavy hydrocarbonsexit the system.Spent regeneration gasstream containing water andC6 is then cooled and

Condensed liquidsremoved in theregeneration gasseparator.

This is the only place inDuring adsorption

Water and C6components areadsorbed at 1100 psigand 90140 F.

Prior to C6breakthrough, thetower position isswitched to heatingmode and is completelyheated to 540 F.

Internal insulationallows heating of theadsorbent only and notthe steel shell.

During heating, thewater vapor and C6Cycle times

Driven by the breakthroughbehavior of the C6components in the towerdesign in order to meet thehydrocarbon specification ofthe treated gas

Result of analysis and fieldobservations

Typical cycle consisted of(Refer to Table A-1)

Two-hour adsorbing

One-hour heating, and

One-hour cooling.

Heat Recovery Between

Cooling and Heating

System uses one tower heating andone tower cooling at a time.composition betweenbeginning and end cycle,caused by the breakout of theindividual components.

In a four tower system with twotowers on adsorption

There is an offset time of halfan adsorption cycle.

Gas composition of thecombined outlet gas is moreconstant than from a singletower system.

Cycle Times andd gas.

ingle tower system

There is a difference in the gasHeating and cooling towers are in aseries arrangement which alsoconserves the amount ofregeneration gas required.

Additional benefit of having towers

Gas-t

adsorption bed and

ng

ating 1 h Coolingsorption 1 h Heatingoling 2 h Adsorptionating 1 h Cooling, 1 h adsorption

162 Gas Sweetening and Processing Field ManualHot gas is cross-exchangedwith the gas upstream of theregeneration gas heater(Refer to Figure A-4).

Exchanger is bypassed duringthe time when the gas exitingthe tower on cooling is at ahigher temperature than thegas leaving the tower in theheating step.Regento provide the requiredheating gastemperature.

o-gas heat exchanger

It is used to capture the heatexiting the tower which isbeing heated.temperature of the gasexiting the cooling tower

Drops so the heater hasDue to the entire towerbeing cooled the gas isat the hot regenerationtemperature of 540 F

During the cooling cycle, theHot gas leaving the towerbeing cooled flows throughthe heater in order to getadditional heat in.

At the beginning of the cycle,gas exiting the tower oncooling is almost at therequired heatingtemperature.

Results in nearly nomake-up heat beingrequired

Table A-1 Tower mode timi

Tower 1 2 h Adsorption 1 h HeTower 2 1 h Cooling 2 h AdTower 3 1 h Heating 1 h CoTower 4 1 h Adsorption 1 h Heeration heater

Direct-fired heaters

Size of the heater depends onthe regeneration gas flowrequired to heat theshown.

Note the strong cutoff thatoccurs between C6 and C8.

Heavier hydrocarbons areessentially completelyremoved.Tablhydr

TSA feTSA ouTable A-2.

Corresponding phaseenvelopes are shownin Figure A-5.

Figure A-6 shows the resultsof gas sampling done with amass spectrometer whereboth the feed and exitstreams of the TSA wereanalyzed dynamically.

Ratio of hydrocarbonconcentration in theoutlet versus inlet isexcellent membraneperformance.

TSA performanceregarding hydrocarbondew point wasimpressive, seeplant in October 2000

Good TSA performanceremoving the heavyhydrocarbons led todesorb the water andhydrocarbons within thedesign cycle time.

TSA performance

After recommissioning thee A-2 TSAocarbon dew point

ed gas 86 F at 1150 psigtlet gas 22 F at 1115 psig

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant 163200

400

600

800

1000

1200

1400

1600Pr

essu

re [p

sig]

Bubble pointAir liquidemedalmembrane

General Considerations

Polyimide hollow fiber membraneelements (shown in Figure A-7)provide for a high efficiencyseparation of CO2 fromhydrocarbon streams.

Membrane system was fabricatedasmultiple skids (refer to Figure A-8)operating in parallel.

0250 200 150 100

Temp

FIGURE A-5 TSA inlet and outlet

0

1

C4 C5 C6 C7

TS

A o

utl

et/in

let

FIGURE A-6 TSA hydrocarbon taiActual TSAinlet gasdew pt

Actual TSAoutlet gasdew pt

Dew ptpossibleby chillingEach skid contains multiplehorizontal tubes.

Each tube contains multiplemembrane elements (refer toFigure A-9).

Multiple elements areinstalled in a single tube.

Membrane elements areactually functioning in parallel.

More than 100membrane elementsare used in this plant.

50 0 50 100 150erature [F]

phase envelopes.

C8 C9 C10 C11

l.

164 Gas Sweetening and Processing Field ManualC1+CO2H2SH2OFeed gas enters the tube near oneend and flows axially to all themembrane elements by way of anannular clearance.

Each element is composedof several hundred thousand

CO2H2SH2O

FIGURE A-7 Air LiquideMEDAL

FIGURE A-8 Skid containing Air L

Feed

Permeate

FIGURE A-9 Multiple membraneC1+parallel hollow polyimidefibers.

Feed gas enters the membraneelements on the fiber shell insideand flows over the fibers, whereCO2 is removed, to a coaxial tube in

Air liquide

natural gas membrane.

iquide membrane elements.

Residue

element flow arrangement.

the center of each element(retentate).

Retentate streams for each elementflow axially to exit at one end of thetube.

CO2 selectively permeates intothe bore of the fibers and thenflows axially to a collection pointat the end of each element(permeate).

Permeate of each element is thencollected in the coaxial center tubeand flows axially to exit the tube atthe opposite end from theretentate.

Membrane Performance

Typical operating conditions

Permeate pressure is about10 psig which flows to thesteam generator burners.

Hydrocarbon losses versus time

One of the major advantagesof the polyimide membrane isits ability to maintain integrityindefinitely, even aging in thepresence of heavyhydrocarbons.

As shown in Figure A-10,membrane integrity is solidand the hydrocarbon losseshave decreased somewhatsince startup.

This trend of decreasinghydrocarbon losses indicatesno loss of membraneintegrity and actually showsa slight increase in apparent

Se

ca

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant 1650.0

0.2

0.4

0.6

0.8

1.0

Aug-00 Mar-01

Hyd

roca

rbon

loss

es (

norm

aliz

ed)

FIGURE A-10 Membrane hydroMembrane skids are feddirectly from the output ofthe TSA.

Feed temperatures varybetween 90 and 120 F.

Feed pressure is 1100 psig.

Feed gas contained 30%CO2.

1.2intrinsic membraneselectivity.

Such a selectivity increasewould be consistent with thechange in permeability (seebelow).

Membrane capacity versus time

After TSA was commissionedin October 2000

p-01 Apr-02 Nov-02

Design losses

rbon losses versus time.

One membrane skidwas retrofitted withnew membraneelements and itsperformance tracked.

Results shown in Figure A-11

Vertical axis is labeledRelative Capacity toRemove Moles ofCO2 which is thenormalized intrinsicmembranepermeability.

Initial capacity waswell above design,and after 10 years ofoperation, the capacitystill remains abovedesign.

Membrane skids wereshut down andrestarted many timesfor maintenanceof surroundingequipment or capacityturndown.

Start and stop, orpressurization anddepressurizationcycles have no effecton membraneperformance, althoughcaution must be usedto avoid reversepressurization.

Permeate/Acid GasUtilization

0.0

0.5

1.0

1.5

2.0

00 20,0 from start

tive

capa

city

to re

move

m

ole

s of C

O2

Design ca

FIGU city vers

166 Gas Sweetening and Processing Field Manual0 5000 10,000 15,0Hours

RE A-11 Membrane capaRel

aExact membrane lifecan be extrapolatedto be over 12 yearswithout replacement

Excellent operation ofthe TSA and membranehave resulted in yearsof trouble freeoperation with zeromaintenance, that is,no membranereplacements.00 25,000 30,000 35,000-up

pacity

us time.Two waste heat boiler units areinstalled.

Waste heat boilers recoverwaste heat available in lowBTU permeate gas stream(150250 Btu/scf) from themembrane units.

Utilizing waste heat in thepermeate stream meanssingle stage membrane can

Appendix A: Membrane/Amine Hybrid Grissik Gas Plant 167be used without thelimitations of a secondmembrane stage with theaccompanying recycle gascompressor and still avoidhydrocarbon losses.

Boilers are designed toincinerate the acidgases removed by theamine unit.

Auxiliary fuel is utilized tomake up any inadequacy ofheating value input and tostabilize the flame.

Furnace temperature ismaintained above 1600 Fprior to introducing permeatefuel or acid gases.

Lower temperature leads toincomplete destruction of thecomponent and results in theemission hazards.

Waste heat boilers arecontrolled by steam headerthat actuates pressurecontrol valves on eachsteam drum.

Output of the steam headerpressure controller goesthrough flow ratiocontrollers of permeategas, fuel gas, andcombustion air.

Fuel gas flow rate is setaround 10% of permeate gasflow rate while combustionair is controlled to ensurestoichiometry and completecombustion with 25%excess air.

Waste heat boiler producessteam up to 210,000 lbs/h at150 psig and 348 F.

Biggest consumer of steamproduced is the aminesystem.

Condensing heat released bythe steam is used to removeacid gas from amine solventat amine reboilers.Amine System

Amine system further reduces CO2and H2S to meet sales gasspecification.

Residue gas from the membraneunit, containing 15% CO2,

Flows into the aminecontactors and

Contacted with lean amine(50%wt-activated MDEA).

CO2 absorption by activated MDEAis limited to a maximum loading of0.5 mol acid gas/mol MDEA.

CO2 content in the treated gasvaries between 2% and 5% byvolume (3%-vol average).

Rich amine is then flashed at75 psig, heated through a lean/richamine exchanger, and regeneratedby the steam heated reboiler.

The 150 psig steam used forregenerating amine is produced inthe waste heat boiler that burnspermeate gas.

Several common problems of anamine system include

Reduced strength and abilityto absorb acid gas

Degradation

Foaming and

CO2 corrosion attack duringacid gas breakout inside thereboiler.

Most problems found in an aminesystem are due to the presence ofcontaminant in the amine solvent,including

Heat stable salts

Degradation products

Injected chemicals

Hydrocarbons and

Particulates.

Heat stable salts and degradationproducts are formed by amine

solvents that decompose and/orreact with other contaminants.

TSA/membrane installed upstreamof the amine system has mitigatedthe above problems to anacceptable level.

TSA unit removes heavyhydrocarbons from the feedgas and nearly eliminatedthe foaming risk of aminesolvent.

An antifoam injection systemis provided to anticipate worstcase conditions.

CO2 content reduction by themembrane unit

Breakout in the regenerationprocess

Lessons CO2 breakout in theregeneration process

Treated gas condition at the outletof the amine unit is normally 3%-volCO2 and 24 ppmv H2S, while salesgas contract specifies 5%-vol CO2and 8 ppmv H2S.

One advantage from the highperformance of absorption is anallowance to increase systemdeliverability by bypassing someuntreated gas and blending withtreated gas while maintaining thesales gas specification.

References

1. Anderson, C.L. and Siahaan, A.

Case study: Membrane CO2 re-

moval from natural gas, Grissik

gas plant, Sumatra, Indonesia,

Regional Symposium onMembrane

168 Gas Sweetening and Processing Field ManualReduces contaminants thatmay trigger salt formation oramine degradation

Though contaminants couldalso be introduced bymakeup water or evenmakeup amineScience and Technology, 2004,

Johor Bahru, Malaysia.

2. Malcolm, J. The Grissik gas plant,Hydrocarbon Asia, 2001.

3. Anderson, C.L. Case study: Mem-

brane CO2 removal from natural

gas, Regional Symposium on

Membrane Science and Technol-

ogy, 2004, Johor Bahru, Malaysia.

Membrane/Amine HybridGrissik Gas Plant,1,2,3 Sumatra,Indonesia: Case StudyIntroductionProcess overviewBackgroundGeneral ConsiderationsFirst Commissioning

TSA design and performanceGeneral Design ConsiderationsTSA Process DescriptionReasons for Four TowersCycle Times and BreakthroughHeat Recovery Between Cooling and Heating

Air liquide-medal membraneGeneral ConsiderationsMembrane Performance

Permeate/Acid Gas UtilizationAmine System