20120904 150120 proefschrift meerman
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Perspectivesongasificationsystemstoproduce
energycarriersandotherchemicalswithlowCO2
emissions
Technoeconomicsystemanalysisoncurrentand
advancedflexiblethermochemicalconversion
offossilfuelsandbiomass
HansMeerman
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Perspectivesongasificationsystemstoproduceenergycarriersandotherchemicalswith
lowCO2emissions:Technoeconomicsystemanalysisoncurrentandadvancedflexible
thermochemicalconversionoffossilfuelsandbiomass
HansMeerman,UtrechtUniversity,FacultyofGeosciences,DepartmentofInnovation,
EnvironmentalandEnergySciences,CopernicusInstitute,GroupEnergy&Resources.
ISBN: 9789039358375
Coverdesign: UitgeverBoxpress
Printing: UitgeverBoxpress
Copyright:
2012,
Hans
Meerman
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Perspectivesongasificationsystemstoproduceenergy
carriersandotherchemicalswithlowCO2emissions
Technoeconomicsystemanalysisoncurrentandadvancedflexiblethermochemicalconversionoffossilfuelsandbiomass
Perspectiefopvergassingssystemenvoorhetproducerenvan
energiedragersenanderechemicalinmetlageCO2emissies
Technoeconomischesysteemanalysevanhuidigeentoekomstigeflexibelethermochemischeomzettingvanfossielebrandstoffenenbiomassa
(meteensamenvattinginhetNederlands)
Proefschrift
terverkrijgingvandegraadvandoctoraandeUniversiteitUtrecht
opgezagvanderectormagnificus,prof.dr.G.J.vanderZwaan,
ingevolgehetbesluitvanhetcollegevoorpromoties
inhetopenbaarteverdedigenop
vrijdag7september2012desmiddagste12.45uur
door
JohannesCornelisMeerman
geborenop3augustus1981teHellevoetsluis
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Promotoren: Prof.dr.A.P.C.Faaij
Prof.dr.W.C.Turkenburg
Copromotor: Dr.C.A.Ramrez
Thisthesishasbeenmadepossiblewiththefinancialsupportof
NWOAgentschapNLandtheEOSresearchprogrammeCapTech.
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Voormijnouders
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WedonotinherittheEarthfromourancestors,weborrowitfromourchildrennativeAmericanproverb
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Contents
1 Introduction 11
1.1 Background........................................................................................................12
Energy........................................................................................................................12
Climatechange..........................................................................................................13
CO2emissions............................................................................................................13
1.2 Mitigationstrategies..........................................................................................14
Sectors.......................................................................................................................15
Biomassandbiofuels.................................................................................................16
Carbondioxidecapture,transportandstorage........................................................16
1.3 Integratedgasificationpolygenerationfacilities..............................................19
Processdescription....................................................................................................21
Performance..............................................................................................................21Flexibility....................................................................................................................22
1.4 Summarising......................................................................................................23
1.5 Thesisobjectiveandoutline..............................................................................24
2 Performanceofsimulatedflexibleintegratedgasification
polygenerationfacilities.PartA:Atechnicalenergeticassessment 272.1 Introduction.......................................................................................................29
2.1.1 General......................................................................................................30
2.1.2 Objectives..................................................................................................31
2.2 Commodities......................................................................................................322.2.1 Feedstocks.................................................................................................32
2.2.2 Endproducts.............................................................................................32
2.2.3 Byproducts...............................................................................................32
2.3 Processdescription............................................................................................33
2.3.1 Plantflexibility...........................................................................................33
2.3.2 Pretreatment...........................................................................................33
2.3.3 Pressurisingandfeeding...........................................................................35
2.3.4 Airseparationunit(ASU)..........................................................................36
2.3.5 Gasifier......................................................................................................36
2.3.6 Gascleanupandsyngascompositionoptimising......................................382.3.7 Syngasconversion.....................................................................................41
2.4 Methodology:AspenPlusflowsheetmodel.......................................................45
2.4.1 Modelledcomponents..............................................................................45
2.4.2 Parameters................................................................................................47
2.5 Casestudies.......................................................................................................49
2.6 Results................................................................................................................51
2.6.1 Referencecases........................................................................................53
2.7 Discussion..........................................................................................................66
2.7.1 Modelvalidation.......................................................................................66
2.7.2 Fuelflexibility............................................................................................66
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2.7.3 Modelassumptions...................................................................................67
2.8 Conclusion..........................................................................................................67
2.9 Acknowledgements...........................................................................................70
2.10 Supportinginformation.....................................................................................71
3 Performanceofsimulatedflexibleintegratedgasification
polygenerationfacilities.PartB:Economicevaluation. 833.1 Introduction.......................................................................................................84
3.2 Methodology.....................................................................................................85
3.2.1 TechnicaldataandAspenPlusprocessmodel..........................................86
3.2.2 Casestudies...............................................................................................88
3.2.3 Scenarios...................................................................................................90
3.2.4 TotalCapitalInvestment...........................................................................92
3.2.5 Economicmodel........................................................................................93
3.3
EconomicData
...................................................................................................
94
3.3.1 Commodityprices.....................................................................................94
3.3.2 Capitalcostsdata......................................................................................98
3.4 Results..............................................................................................................104
3.4.1 StaticIGPGfacilities...............................................................................104
3.4.2 Variationoffeedstock.............................................................................107
3.4.3 Variationofproduction...........................................................................114
3.4.4 Retrofit....................................................................................................115
3.4.5 Sensitivityanalysis...................................................................................116
3.5 Discussion&Conclusions.................................................................................118
3.6
Acknowledgement
...........................................................................................
120
3.7 Supplementarydata........................................................................................121
3.7.1 Commoditypriceprojectionsinliterature..............................................121
3.7.2 DetailedtechnicalandeconomicdataofthestaticIGPGfacilities.......123
4 Technicalandeconomicprospectsofcoal andbiomassfiredIGPG
facilitiesequippedwithCCSovertime. 1274.1 Introduction.....................................................................................................128
4.2 Integratedpolygenerationgasificationfacilities............................................129
4.2.1 Processdescription.................................................................................129
4.3
Configurations..................................................................................................
130
4.4 Economicanalysis............................................................................................135
4.5 Results..............................................................................................................138
4.5.1 Sensitivity................................................................................................142
4.6 Discussion........................................................................................................142
4.7 Conclusions......................................................................................................143
4.8 Acknowledgement...........................................................................................144
4.9 Supportinginformation...................................................................................145
4.9.1 ProductionandCO2avoidancecostsformula.........................................145
4.9.2 Capitalcostbreakdown...........................................................................146
4.9.3 Detailedmass,energyandeconomicresults..........................................147
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5 FuturetechnologicalandeconomicperformanceofIGCCandFT
productionfacilitieswithandwithoutCO2capture:combining
componentbasedlearningcurveandbottomupanalysis. 1555.1 Introduction.....................................................................................................157
5.2 Methodology...................................................................................................164
5.2.1 Gasificationtechnology...........................................................................164
5.2.2 Costandperformanceprojectionswithexperiencecurves...................165
5.2.3 Costandperformanceprojectionsbymeansofabottomupanalysis..171
5.2.4 Comparisonofexperiencecurvebasedwiththebottomupanalysis....172
5.3 Dataforthecurrentsituationandfutureprojections.....................................174
5.3.1 Currentcostsandefficiencies.................................................................174
5.3.2 Progressratiosandinstalledcapacities..................................................175
5.4 Resultsoftheexperiencecurveanalysis.........................................................183
5.4.1 EfficiencydevelopmentofIGCC..............................................................183
5.4.2 CapitalcostsofIGCC...............................................................................1845.4.3 TrendsintheCOEandCO2mitigationcostsforIGCC.............................186
5.4.4 FTliquidsproduction..............................................................................189
5.5 Discussion........................................................................................................192
5.6 Conclusion........................................................................................................194
5.7 Supportinginformation...................................................................................197
6 TechnoeconomicassessmentofCO2captureatsteammethane
reformingfacilitiesusingcommerciallyavailabletechnology 2036.1 Introduction.....................................................................................................204
6.2 Background......................................................................................................2056.2.1 Steammethanereforming......................................................................206
6.2.2 Carbondioxidecaptureandstorage.......................................................206
6.3 Approach..........................................................................................................208
6.3.1 CO2capturelocation...............................................................................208
6.3.2 Solventselection.....................................................................................209
6.3.3 CO2captureunitconfiguration...............................................................211
6.3.4 OptimisationofCO2captureconfigurationconditions...........................212
6.3.5 Overviewoftechnicalparameters..........................................................215
6.3.6 TechnoeconomicperformanceofCO2captureatSMR.........................215
6.4 Technoeconomicresults.................................................................................2176.4.1 CO2captureunitperformancecasestudies............................................217
6.4.2 EffectloadfactoronCO2captureunitperformance..............................220
6.4.3 Sensitivityanalysis...................................................................................221
6.4.4 Utilityimport...........................................................................................222
6.4.5 Conclusion...............................................................................................223
6.4.6 Acknowledgements.................................................................................225
7 Summary,conclusionsandrecommendations 2277.1 Background......................................................................................................228
7.2 Objectiveandresearchquestions...................................................................229
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7.3 Methodology...................................................................................................230
7.4 Summaryoftheresults....................................................................................232
7.5 Mainfindingsandconclusions.........................................................................238
7.6 Finalremarksandrecommendationsforfurtherresearch.............................241
Samenvatting,conclusiesenaanbevelingen 245
Appendix:TechnicaldescriptionofIGPGfacilities 2679.1 Feedstock.........................................................................................................268
9.2 Feedstockpretreatment.................................................................................268
9.2.1 Feedstockprocessingandfeeding..........................................................269
9.3 Airseparation..................................................................................................270
9.3.1 Iontransportmembraneseparation......................................................271
9.3.2 Chemicallooping.....................................................................................272
9.3.3 (Vacuum)pressureswingabsorption.....................................................2729.4 Gasifier.............................................................................................................272
9.4.1 Supercriticalwatergasifier(SCWG)........................................................273
9.4.2 Highpressuregasification.......................................................................273
9.5 GasCleaning....................................................................................................274
9.5.1 Hotgascleaning......................................................................................275
9.6 Watergasshift.................................................................................................278
9.6.1 Sorptionenhancedwatergasshift.........................................................278
9.6.2 Advancedwatergasshift........................................................................279
9.7 CO2compressor...............................................................................................279
9.7.1 Shockwavecompression........................................................................2809.7.2 Electrolyticcompression.........................................................................281
9.8 Electricityproduction.......................................................................................281
9.8.1 Syngascombustion.................................................................................281
9.8.2 Steamturbinesandheatrecoverysteamgenerators.............................283
9.9 FTsynthesis.....................................................................................................284
9.10 Availability........................................................................................................284
References 287
Dankwoord 305
CurriculumVitae 307
Nomenclature 309
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11
1 Introduction
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Chapter1
12
1.1 BackgroundEnergyOurmodernsocietyrequiresaccesstoabundant,affordable,reliableandenvironmentally
sound sources of energy. As population and living standards are increasing, so is ourenergydemand(seeFigure1.1).In2009,globalprimaryenergydemandexceeded500EJ,
representingadoublinginabout35years.About80%ofthisdemandiscoveredbyfossil
fuels.[1,2,3]
In its Energy Technology Perspectives 2010 report, the International Energy
Agency (IEA) presented a business as usual scenario projecting an increase of the global
energy demand to over 750 EJ in 2035.[2]
Similar trends are forecasted by other
studies.[1,2,4,5,6,7,8]
Most of these studies indicate that fossil fuels will continue to play an
importantroleformanydecadestocome.
Figure1.1GlobalhistoricenergydemandandfutureprojectionoftheIEAbusinessasusual
scenario.[2,3]
Unfortunately,theuseoffossilfuelshasseveral importantdrawbacks.First,mostofthe
conventionaloilandgasreservesarelocatedinafewworldregions.Consequently,many
countriesaredependentonfewothercountriesfortheir energysupplies.
[2,4,9,10]
Second,keeping up extraction from easily recoverable fossil fuel sources to the everincreasing
demandforfossilfuelsprovesdifficult,causingimpactsonthepriceoffossilfuels.[2]
Third,
the combustion of fossil fuels is responsible for the largest share of anthropogenic
greenhousegas(GHG)emissionsintotheatmosphere.[11]
Andlastbutnotleast,duetothe
depletionofeasilyrecoverablefossilfuelsources,extractionofunconventionalfossilfuel
sources,suchastarsandsandshalegas,andextractioninenvironmentallysensitiveareas
areexpectedtoincrease,resultinginhigherGHGemissionsandincreasedrisksofsevere
environmentaldamage.[5,12]
0
100
200
300
400
500
600
700
800
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035
G
lobalenergydemand(EJ/yr)
Year
Otherrenewables Hydro Nuclear NG Oil Coal
Historicdemand Projecteddemand
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Introduction
13
ClimatechangeEmissionsofGHGarelinkedtoglobalwarming
1,withCO2beingresponsibleformorethan
50% of the direct radiative forcing ofGHG.[11]
In 1992, theUnitedNations Framework
Convention on Climate Change (UNFCCC) was established with the goal of achieving
stabilisationof
atmospheric
greenhouse
gas
concentrations
at
alevel
that
would
prevent
dangerousanthropogenicinterferencewiththeclimatesystem.[13]
By2005,averageglobal
temperatures were already about 0.8C higher than preindustrial levels (see Figure
1.2).[11]
The4th
AssessmentReportof the InternationalPanelonClimateChange (IPCC)
projects thatascenario focussingoneconomicdevelopmentand relianceon fossil fuels
(A1fossilintensive:A1FI)couldresultinanincreaseintheaveragetemperatureonEarth
of 2.96.9C above preindustrial values (with a best estimate of 4.5C) by 2100.[2]
A
temperature change of thismagnitudewould be unprecedented in human history and
probablyresult indetrimental impactsonclimate,biodiversity, foodproductionandsea
levelrise.Thesamereportalsoprojectsthat inascenariowhichassumesstrongpolicies
to mitigate GHG emissions, the increase in average temperatures could be limited to
1.63.4C, with a best estimate of 2.3C.[11]
In 2009 and 2010, the Conference of the
Parties(COP)totheUNFCCCagreedthattheincreaseinglobalmeantemperatureshould
bekeptbelow2C,comparedtopreindustriallevels.[14,15]
Figure1.2Historicclimatechangeandprojectedclimatechangeunder
differentGHGmitigationpolicies.[11]
CO2emissionsKeeping the increase in global mean temperature to less than 2C means that the
atmosphericCO2concentrationneeds tostabilisemostprobablyat350400ppm(v)CO2
(445490
ppm(v)
CO2
equivalent).
11]
The
current
proven
reserves
of
fossil
fuels
contain
around800Gtcarbon,[1]
whichcouldresultinalmost3000GtofCO2emissions.Thisvalue
isroughlythesameamountofCO2currentlypresentintheatmosphere.Maintainingthe
increaseinglobalmeantemperaturebelow2Cimpliesthatonly10001625GtCO2canbe
emittedbetween20002100,thesocalledcarbonbudget.[16,17]
Between2000and2010,
already330GtCO2wereemitted,leavingroomforonly6701295GtofanthropogenicCO2
emissionsinthecomingdecades.WithoutadditionalCO2abatementpolicies,thisvalueis
expectedtobereachedwithinafewdecades.[2,4,6,16]
Keepingwithintheindicatedcarbon
1Formore informationonclimatechangeand itseffectswerefertothe4
thassessment
reportof
the
IPCC.[11]
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Chapter1
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budgetwillrequirereductionsinCO2emissionsofmostlikely5080%in2050comparedto
the2000level.[11,15,18]
1.2 MitigationstrategiesThere
are
several
routes
to
reduce
global
CO2
emissions.
The
most
obvious
one
is
to
consume less primary energy. This, however, has proved to be difficult in the past.
Keepingtheglobalenergydemandconstantwithanincreasingpopulationandincreasing
average standard of living is already a daunting challenge, as indicated by several
studies.[2,4,5,6,7]
Nevertheless,thereisalargepotentialtoincreasetheefficiencyofenergy
conversionprocessesthatneedstobetargeted.Thesecondoptionistousefossilenergy
sourceswhichare less carbonintensiveor to switch to renewableenergy sources.This
includes switching from fossil fuels to renewable and nuclear energy sources, but also
fromcoaltonaturalgas.Inthescenariosfrome.g.,theIEA,IPCC,BP,Greenpeace,WWF,
and in the Global Energy Assessment (GEA), an increased utilisation of renewables is
projected
but
at
various
degrees
depending
on,
among
others,
assumptions
related
to
technologicalimprovementsintheenergysystemandclimatepolicies.Athirdoptionisto
reduce the CO2 emitted by the use of fossil fuels (and biomass) using carbon dioxide
capture,transportandstorage(CCS)technologies.Allstudiesjustmentionedprojectthat
noneofthethreeoptionsbythemselvescanreachthe2Ctarget,andthataportfolioof
mitigationoptionshastobe implemented inordertomeettheGHGemissionmitigation
targets(seee.g.,Figure1.3).[2,4,5,6,7,8,19]
Figure1.3ContributionofdifferentCO2mitigationstrategiesintheIEABluemapscenario,aiming
atstabilisingatmosphericGHGemissionsat450ppm(v)CO2eq.[4]
CCS(19%)
Renewables(17%)
Nuclear(6%)
Powergenerationefficiency
andfuelswitching(5%)
Endusefuelswitching
(15%)
Endusefuelandelectricity
efficiency(38%)0
10
20
30
40
50
60
2010 2015 2020 2025 2030 2035 2040 2045 2050
GlobalCO2emissions(GtCO2/yr)
Year
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Introduction
15
SectorsAlmost 85% of the 29 Gt CO2 emitted by the combustion of fossil fuels in 2009, were
producedbythepower,transportandindustrysectorscombined(seeFigure1.4).[20]
Each
sector has its own unique characteristics and challenges and, therefore, needs specific
strategiestomitigateGHGemissions.
Figure1.4GlobaldirectannualCO2emissionsbysectorin2009.[20]
Thepowersectorconsumed190EJofprimaryenergyin2009ofwhichalmost50%came
from coal and another 25% from natural gas and oil.[2]
Most CO2 emissions from this
sector stem from large, stationary sources, making this sector suitable for endofpipe
solutions, such as CCS. Literature studies indicate that the most costeffective CO2
mitigation options for the short to mid term are fuel switching (cofiring biomass in
coalfired power plants or replacing coalfired power plants by natural gasfired power
plants)andapplyingCCS.[2,4,5,6,7]
Thetransportsector consumed almost100 EJ of primary energy in 2009, of which more
than 90% came from oil.[2]
The CO2 emissions from this sector originate from numerous
small, mobile sources, making endofpipe solutions unattractive.[34]
Therefore,
decarbonisingthissectorisonlyrealisticviadecarbonisingthefuel.Amainobstacleinany
transition towards a new transportation fuel is the large interdependence between car,
fuel and infrastructure, making any transition difficult and expensive if the currentinfrastructure and car park cannot be used.
[21] The current infrastructure is designed for
liquidswithahighenergydensity,likeliquefiedpetroleumgas(LPG),gasoline,dieseland
FischerTropsch liquids (FTliquids are a mixture of linear hydrocarbons of different
length).LiteratureindicatesthatapromisingCO2mitigationoptionfortheshortertomid
term is replacing conventional diesel and gasoline with liquid 2nd
generation biofuels.
When producing these fuels, CCS can be applied to reduce GHG emissions even
further.[21,22,23,24,25]
Theindustrysectorconsumedalmost90EJofprimaryenergyin2009ofwhich40%came
fromcoal,28%fromnaturalgasand20%fromoil.Almost75%ofthedirectCO2emissions
Other
2.9GtCO210%
Industry
5.9GtCO220%
Electiricty
andheat
11.8GtCO241%
Transport
6.5GtCO222%
Residential
1.9GtCO27%
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Chapter1
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from this sector originate mainly from the production of iron and steel, cement and
chemicals.[4]
These emissions come from large, stationary sources, making the industry
sectorsuitableforCCS.FormoreinformationonCO2mitigationstrategiesintheindustry
sector,werefertoKuramochi.[26]
BiomassandbiofuelsSustainable biomass is an attractive CO2 mitigation strategy as it can be converted into
carbonneutralbuildingblocksforthechemicalindustryorintohighenergydensityliquids
forthetransportsector.[7]
Biomass istheonlyrenewablecarbonsourceforthechemical
industryandisconsideredakeyalternativeforthetransportsectorintheshortterm.[2,4,7]
In2009,10%oftheglobalprimaryenergydemand(about50EJ)wassuppliedbybiomass,
ofwhich1112EJwasbeingused inmodernapplications, likepowerplantsandbiofuels
facilities.[7,27,28]
For comparison, in the same year the total energy demand of the power
and transport sectors combined was almost 300 EJ.[2]
The deployment potential for
sustainablebiomass isuncertain,butconsiderable.Scenarioandmodelanalyses indicatethatthetechnicalpotentialofbiomassenergyresourcesmayrangebetween50500EJ/yr
in 2050[7,28,29,30]
and the deployment potential could be in the order of 100300 EJ/yr in
2050, depending on policies and market conditions.[7]
These high deployment levels of
biomass require the implementation of sustainability criteria to prevent, among others,
competitionwithfoodorfeedsupplies,depletionofwatersources,lossofbiodiversityor
excessiveGHGemissionsdueto(indirect)landusechange.[7,28]
In general, a distinction is made between 1st
and 2nd
generation biofuels. Examples of
1st
generation biofuels are vegetable oils, ethanol from corn and sugarcane and biogas
fromorganicwaste,while2nd
generationbiofuelsincludeFTliquidsorethanolfromwood,
grassesorresiduesfromtheforestandagriculturalsectors.[7]FTdieselhastheadvantage
that it is almost similar to conventional diesel, allowing the use of the existing
infrastructure and car park. Advantages of 2nd
generation biofuels over 1st
generation
biofuelsaretheuseofnonfood/feedsourcesasfeedstockandhigherenergyyieldsand
(potential) savings in GHG emissions on a hectare basis.[28,31]
Finally, biomass crops
(including trees) for 2nd
generation biofuels can be cultivated on marginal or degraded
land, not only further reducing the competition with food supplies, but also offering an
opportunitytorestoredegradedland.[32,33]
Carbondioxidecapture,transportandstorageCarbondioxidecapture,transportandstorage(CCS)isthegeneraltermforprocessesthat
preventtheemissionofCO2bylongtermisolationoftheCO2fromtheatmosphere.[34,35]
It
allowstheuseoffossilfuelsbutwithsignificantlylowerCO2emissions.ForthisreasonCCS
canbeseenasatransitionalmitigationoption.Itincreasestheavailabletimetotransform
thecurrentfossilfuelbasedenergy infrastructure intoan infrastructurebasedmainlyon
renewable sources. Moreover, when CCS is applied in combination with conversion of
sustainably produced biomass, it can result in negative emissions, i.e., extracting and
isolating CO2fromtheatmosphere andthusextending thecarbon budget.Thepotential
deploymentofCCSdependsheavilyontechnological improvementsandclimatepolicies.
The IPCC special report on CCS indicates that the economic potential of CCS could be
2202200 Gt CO2 avoided cumulative by 2100, while the IEA Energy Technology
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Introduction
17
Perspectivesprojectsashareofabout19% in2050,equivalentto18GtCO2emissionsa
year.[4,34]
TheEuropeanCommissionsEnergyRoadmap2050estimatesthat,dependingon
the scenario, CCS could account for 1932% of the total mitigated CO2 emissions in the
powersector.[36]
Althoughtotalmitigationcostsareuncertain, ithasbeenprojectedthat
largescaledeploymentofCCScouldreduceglobalmitigationcostsbyupto40%asmoreexpensive CO2 mitigation options can be postponed or even avoided.[34,37,38,39,40]
FurthermoreapplyingCCSatbiomassfeedstockscouldresultinanadditionalreductionin
globalmitigationcostsofabout40%relativetotheoptionofusingCCSatfossilfeedstocks
only.[38,39]
However,tofullyrealisethispotentialrequiresthatdeploymentofCCStakesoff
this decade. In 2011, there were only 8 operational integrated commercial scale CCS
demonstrationprojectsintheworld[41]
and,accordingtotheIEATechnologyroadmapon
CCS, the number of projects needs to increase to around 100 projects by 2020 and to
almost3500by2050ifthefullcontributionofCCStoprojectedmitigationeffortsistobe
realised(seeFigure1.5).[37]
Figure1.5RoadmapforglobaldeploymentofCCSuptill2050accordingtotheIEATechnology
roadmaponcarboncaptureandstorage.[37]
TheCCSchainiscomposedofthreesteps:capture,transportandstorage.DuringtheCO2
capturestep,CO2isextractedfromindustrialandenergyrelatedsourcese.g.,naturalgas,
fluegasandsyngas.ThisCO2issubsequentlypurified,driedandcompressed.Thisstepis
generally the most expensive part of the CCS chain due to the high capital costs of the
equipmentandtheenergyuseinvolved.Exceptionsaresomespecificindustrialprocesses,likeammoniaorethyleneoxideproduction,whichalreadyproduceahighlyconcentrated
CO2gasstream.ThisreducestheCO2capturesteptodryingandcompressionoftheCO2.
Inthetransportstep,theCO2ismovedfromtheemissionsourcetothestoragelocation.
CO2 transport by pipeline is already applied in various settings, including enhanced oil
recovery (EOR) and enhanced natural gas recovery (EGR). CO2 is transported in
supercritical phase to improve economics. In this phase CO2 behaves like a liquid with a
liquidlikedensity,whiletheviscosityandcompressibilityshowagasphasebehaviour.The
storage phase consists of the longterm isolation of CO2 from the atmosphere via
0
2
4
6
8
10
12
0
1000
2000
3000
4000
2010 2015 2020 2025 2030 2035 2040 2045 2050
CO2captured(GtCO2
/yr)
Numberofprojects
Year
OECDNorthAmerica
OECDEurope
OECDPacific
China&India
Other
CO2captured (world)
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Chapter1
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mineralisation or by injection of the CO2 into underground geological locations, such as
depletedgasoroilfieldsorsalineaquifers.[5]
CO2 capture is often divided into four categories: postcombustion capture,
precombustioncapture,oxyfuelcombustioncaptureandcaptureatindustrialprocesses.
PostcombustioncaptureinvolvestheextractionofCO2fromfluegaseswhichareproduced by combusting fossil fuels or biomass with air. The flue gas is at
atmospheric pressure and has a low CO2 concentration, resulting in a low CO2
partialpressure.Duetothislowpartialpressure,captureiscurrentlyachievedby
chemicalabsorptionusingsolvents.Theregenerationofthesesolventsinvolvesa
temperatureswing,whichrequireslargeamountsofenergy.Anadvantageisthat
it can be applied at existing power plants (retrofit). Moreover, the CO2 capture
processdoesnot interferewithnormaloperations,meaningthattheavailability
ofthefacilityisnotaffected.
Precombustioncapture isthe extraction of CO2 from anenergyrichgas streamprior to combustion. This prevents N2 dilution and, if the facility operates at
elevated pressure, allows the removal of the CO2 at this elevated pressure.
BecauseofthehighpartialpressureofCO2,physicalsolventscanbeusedinstead
ofchemicalsolventstocapturetheCO2.Asregenerationofphysicalsolventscan
be achieved by pressure swing instead of temperature swing, this results in a
lower energy consumption in the capture process and thus (in principle) lower
CO2capturecosts.
OxyfuelcombustioncaptureentailstheextractionofCO2fromfluegasconsistingmainlyofCO2andsteamasthefossilfuelorbiomassiscombustedwith(almost)
pure O2. Removal of the steam by condensation results in a CO2 purity of
8098%.[34]
In this process high temperatures in the combustion process can be
reached resulting, in principle, in more efficient Brayton (for gas turbines) or
Carnot (for boilers) cycles. Currently, metallurgical constrains prevent the
utilisation of these high temperatures. Therefore, CO2 or steam needs to be
recycledtoreducetheoperatingtemperature.Amaindrawbackofthisoptionis
theneedfor(currentlyexpensive)pureO2.
For capture from industrial processes generally one of the above describedoptions is applied, depending on the process conditions. In some industrial
processes (e.g., ammonia production and natural gas processing) CO2 is already
extracted as part of the industrial process. Applying CCS at these sources,therefore,significantlyreducestheadditionalcostsforCO2separation.Formore
information on the possibilities and potential of CO2 capture at industrial
processes,werefertoKuramochi.[26]
There are three main approaches to separate CO2 from other gases, namely using
sorbents,membranesorcryogenics.[34,35]
SeparationbysorptionmeansbringingthegasstreamcontainingCO2inclosecontactwith
asorbent(orsolventwheninliquidphase).TheCO2isabsorbedintooradsorbedontothe
sorbent. To release the CO2, the sorbent is regenerated. This is commonly done by
increasingthetemperatureforchemicalsorbentsordecreasingthepressureforphysical
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19
sorbents. The main disadvantage of this process is the high energy consumption in the
regenerationstep,especiallywhenchemicalsolventsareused.[34,35]
Cryogenic separation involves cooling the gas stream containing the CO2 to below the
boilingtemperatureofCO2.ImpuritiescaneasilyberemovedfromtheliquidCO2.Priortocooling, the gas stream is dried to prevent ice formation in the heat exchangers. After
compression,theCO2isreadyfortransport.Anadvantageofthistechniqueisthataliquid
CO2streamisproduced,whichisbeneficialforcertaintransportoptions,suchastransport
by ship. The main disadvantage is that the entire gas stream needs to be cooled down,
resulting in bulky equipment and a high energy consumption when separating CO2 from
dilutedstreams.[34,35]
MembraneseparationinvolvespassingthegasstreamcontainingCO2alonga(polymeric,
metallicorceramic)materialwhichisselectivelypermeableforonlyCO2orpermeablefor
all other relevant gases except CO2. As only the permeable gases pass through the
membrane,thisresultsinapureCO2stream.Thedrivingforceisthedifferenceinpartial
pressure across the membrane, making high pressure streams more suitable than low
pressure streams for membrane separation. The advantage of this technique is the low
energyconsumptionwhenapressurisedgasstreamisavailable.Althoughthisprocesscan
also be applied at low pressure streams, it requires creating a vacuum,which drastically
increases energy consumption. Furthermore, reliable and affordable CO2 selective
membranes are currently not commercially available and CO2 removal by membrane
separationhasnotyetbeentestedinlargescaleindustrialfacilities.[34,35]
1.3 Integratedgasificationpoly-generationfacilitiesA key technology which can play a role in the development of a sustainable energy
infrastructure is the production of fuels and other chemicals via gasification. Interest in
gasification has increased significantly in the last few decades, resulting in an installed
syngascapacityofaround70GWthin2010.Projectionsfromtheindustryindicatethatthis
capacity could almost double by 2016 (Figure 1.6).[42]
Gasification technology (partly
combinedwithCCS)isseenasaninterestingoptionforCO2mitigation.IntheBlueenergy
scenariooftheIEA,forinstance,installedgasificationcapacityisprojectedtoexceed1500
GWth syngas in 2050[27]
and the World Energy Technology Outlook 2050 H2case scenario
projectsthatmorethan900GWthsyngasisneededforhydrogenproductionalone.[43]
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Figure1.6Worldwideinstalledsyngascapacity(GWth)accordingtoChildress.
[42,44,45,46]
The main reason behind the increasing interest in gasification is its ability to convert
carbonaceous feedstocks, like coal, stranded natural gas and biomass, into high value
products, e.g., electricity, transportation fuels and other chemicals.[42]
Gasification offers
additional benefits over the conventional production of energy carriers and chemicals,
namely:
Theabilitytouseavarietyofcarbonaceousfeedstockswithoutbeingdependentonaspecificfeedstock;
[47]
Theabilitytoproduceavarietyofproducts(electricity,fuels,fertilizersandotherchemicals)fromthesyngas,allowingflexibleproductionandoutput;[47]
Lowerspecificemissionsof,amongothers,NOx,sulphurcompounds,particulatematter and heavy metals compared to conventional PC power plants and
refineries;[47]
Facilitating the more energy efficient precombustion CO2 capture instead ofpostcombustion CO2 capture, as the syngas has a high pressure and a high
concentrationofCO2;
The conversion of sustainable biomass feedstocks into carbon neutraltransportationfuelswhichcanbeusedinthecurrenttransportinfrastructure;
[2]
The conversion of sustainable biomass feedstocks into carbon neutral rawmaterialsforthechemicalindustry.[48]
Gasificationfacilitiesalsohavesomedisadvantages.Forelectricityproduction,integrated
gasification combined cycle (IGCC) facilities are more complex and expensive than
conventional natural gas combined cycle (NGCC) and pulverised coal (PC) power plants.
Whenconsideringproductionoftransportationfuelsandotherchemicals,theuseofcoal
as feedstock in the absence of CCS can double specific CO2 emissions compared to
producing the chemical in conventional refineries using natural gas or crude oil.[22,23,24]
Lastly,thecommercialexperiencewithgasificationfacilitiesisstilllimited.This,combined
withthecomplexoperationofthefacilities,hindersitsdeployment.
0
20
40
60
80
100
120
140
1970 1980 1990 2000 2010
Installedsyngascapcity(GWth)
Year
1999forecast 2004forecast
2007forecast 2010forecastOperationalcapacity
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21
ProcessdescriptionAn integrated gasification polygeneration (IGPG) facility consists of various key
processes. A schematic overview is given in Figure 1.7. First, a solid carbonaceous
feedstock is fed into an entrained flow (EF) gasifier. The high operating temperature
(>1500C)ofthistypeofgasifierbreaksthefeedstockdownintosyngas,consistingmainlyofCO,CO2,H2andH2O.Therequiredtemperatureisobtainedbycombustingpartofthe
feedstock insidethegasifier.Asubstoichiometricamountof(almost)pureO2,produced
inanairseparationunit(ASU)functionsasoxidant.PureO2isusedtopreventN2dilution
of the syngas, increasing the overall conversion efficiency and reducing the size of
downstream equipment.[47,49,50]
Prior to the gas cleaning, the syngas is quenched to
prevent fouling of the cooling equipment. In the gas cleaning sector, impurities like
halogen gases and solid particles are removed using filters and wet scrubbers. Acidic
compoundsareremovedintheacidgasremovalsection(AGR).
Dependingonthedesiredproduction,theH2:COrationeedstobeadjusted.Thisisdoneina watergas shift (WGS)reactorwhich canbe locatedupstream or downstream theAGR
unit. After cleaning, the syngas can be converted into the final product. To improve
economics and the overall conversion efficiency, steam is generated at various locations
throughoutthefacilityandusedforelectricityproduction.
KeycharacteristicofanIGPGfacilityisthatCO2needstobeextractedfromthesyngasto
improve the conversion efficiency of the downstream chemical or transportation fuel
conversion reactors. Using that concentrated CO2 for CCS purposes results in low CO2
removalcosts,makingIGPGfacilitiesinterestingearlyoptionsforCCSimplementation.
Figure1.7SimplifiedprocesslayoutofaflexibleIGPGfacilitywithCO2captureusing
stateofthearttechnology.Waste,heatandrecyclestreamsarenotdisplayed.
PerformanceDespite the many advantages of gasification facilities, the current globally installed
gasificationcapacityisrelativelylow.Amainreasonisthehighcapitalcostsofgasification
facilities, resulting in high production costs.[51]
Literature studies indicate that an IGCC
without CO2 capture can produce electricity for 5094 /MWh with an efficiency of
4045%HHV.[52,53]
If CCS is applied, the production costs are projected to increase to
64132 /MWh and efficiency could drop by as much as 11%pt, depending on the
technologyusedforgasification,CO2extractionandturbine;theseresultsaresimilarfora
Feedstock
ASU
Pre treatment GasifierGas
Cleanup
Power
production
FTliquids
production
H2production
AGR
MeOH
production
Urea
production
CO2compression
Claus/
SCOT
FTfuel
MeOH
Urea
LiquidS
H2
O2
O2
N2
CO2
H2S
Scompounds
Syngas
CO2
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conventional PC plant, both with and without CCS.[52,53]
A recent study by the European
Technology Platform for Zero Emission Fossil Fuel Power Plants (ZEP) reported the
production costs of electricity of different types of Nth
of a kind power plants, namely
pulverised coal (PC), integrated gasification combined cycle (IGCC) and natural gas
combined cycle (NGCC), both with and without CCS. Production costs of electricityproductionwithoutapplyingCCSare48/MWhforPCand72/MWhforNGCC.IfCCSis
applied,theproductioncostsofIGCC2andPCaresimilar(6675/MWhvs.6773/MWh
respectively), while NGCCCCS results in significant higher electricity production costs
(104/MWh).AstudybytheNationalEnergyTechnologyLaboratory(NETL)foundsimilar
results for coal, but much lower production costs of electricity for NGCC mainly due to
lowernaturalgasprices.[53,54]
Furthermore, model studies indicate that FTliquids can be produced from coal in
commercialscaleplantsfor617/GJ.[22,23,24,25,55,56]
Thelowerrangesaremainlyaresultof
low coal prices (in the range of 1 /GJ). For comparison,oilderived transportation fuels
canbeproducedfor13/GJifcrudeoilpriceare72/bbl(whichwastheaveragecrude
oilpricein2011).[65]
Asmentionedbefore,CO2needstobeextractedfromthesyngasto
enablehighefficiencies intheconversionreactors.Thisresults inCO2avoidancecostsas
low as 17 /t CO2.[57]
IGPG facilities can also use biomass. However, literature studies
suggest that production costs of electricity and FTliquids could double due to higher
feedstockcosts,lowerefficienciesandsmallerscaleinstallations.[22,23,24]
Thecombineduse
of coal and biomass in gasificationfacilities equipped with CCS hasbeen investigated by
the Princeton Environmental Institute, but only for dedicated gasifiers for each type of
feedstock.[23,24,25,57]
They conclude that CCS can be applied at integrated gasification
facilities producing FTliquids (IGFT) at relative low costs. The cofeeding of biomass
results in higher production costs compared to a coalfired IGFT, mainly due to higher
capital and feedstock costs. Their studies also indicate that applying CCS at a coalfired
IGFT facility has the same effect to mitigating CO2 emissions as replacing about 40% of
thecoalbybiomassatanIGFTfacilitywithoutCCS.[57]
Inthemidtolongterm,significantcostsreductionsareexpectedforgasificationfacilities
due to technological learning. Studies by the NETL estimate that novel technologies and
improved operating experience could decrease production costs of electricity in an IGCC
by 33% and reduce the CO2 avoidance costs to 13 /t CO2.[58,59]
Production costs of
FTliquids without CCS could potentially drop to 9 /GJ, equivalent to an oil price of
50/bbl.
FlexibilityThementionedstudiesassumenoflexibilityinfeedstockorproduction.However,market
conditions can change considerably in the operational lifetime of a largescale IGPG
facility.Examplesaretheemergingmarketofbiomasspelletsforenergy,thedevelopment
oftheCO2creditspriceandthemarketofnonoilbasedtransportationfuelsaswellasthe
mature markets of coal and crude oil which has experienced strong price fluctuations in
2 In this study the reference plants is always a PC power plant, therefore data for IGCC
withoutCCSarenotreported.
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Introduction
23
thelastyears(seeFigure1.8).[60,61,62,63,64,65]
Besideslongtermuncertainties,therearealso
shortterm variations, such as the daily variation in the electricity price,[66]
which can
impacttheeconomicsof IGPG facilities,especiallyas largescalestorageofelectricity is
currentlyeconomicallynotfeasible.
Figure1.8Historicpricesofprimaryenergycarriers(left)anddistributionofhistoricelectricityprices(right).[60,61,64,65,66]
AsIGPGfacilitiescanhandleavarietyoffeedstocksandcanproducemultipleproducts,
thesefacilitiesallowreactiontoandexploitationoffluctuations inmarketconditions.An
example is exploiting the daily electricity variation existing in North WestEurope by
producing electricity during peak hours and transportation fuels or chemicals during
offpeak hours. Flexibility of the facility does, however, come with thedisadvantage of
highercapitalinvestmentandO&Mcostsand,dependingonthetypeofflexibility,lower
efficiencies compared to nonflexible IGPG facilities. Currently, a detailed analysis of
whether the advantages of flexibility offset the disadvantages has not been performed
yet, despite the fact that flexibility is mentioned to be a strong argument in favour of
IGPG
facilities.[44,67]
1.4 SummarisingThere are significant potentials for both biomass and CCS to reduce GHG emissions.
However,thecurrentcapacityofbothCO2mitigationoptionsislow.Asstatedpreviously,
biomass for modern applications only comprises 2% of our global primary energy
demand[7,27,28]
and CCS is only being applied in eight commercialscale projects.[41]
Important reasons for the lowpenetration forbiomassare thecurrentlyhigh feedstock
prices,theuncertaintyregardingavailabilityduetotheimmaturityofthebiomassforthe
energymarket,[7]
resulting in relatively smallscalebiomassfed conversion facilities.For
CCS,important
reasons
are
the
high
costs
to
avoid
CO2
emissions
relative
to
the
current
CO2creditpriceorCO2taxandtheuncertaintyinfutureclimatepolicy.
Gasification can play an important role to increase the deployment of both mitigation
options.Theinstalledgasificationcapacityis,however,onlyaround70GWth.Animportant
cause is the high production costs. Although technological innovation resulting in large
reductionsincapitalcostsandimprovementinoverallefficiencyareforeseeninthenear
future, achieving this improved performance requires that the installed gasification
capacityincreasessignificantly.
0
5
10
15
2000 2002 2004 2006 2008 2010
2008
/GJ
Year
EUBrentCrudeOilBiomasspelletsNorthernAppalachia
0%
5%
10%
15%
20%
0 50 100 150 200
Occurence(%)
Electricityprice(2008/MWh)
Nominalprice
Dayprice
Nightprice
Priceat50%occurence
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Chapter1
24
Flexibility might facilitate the deployment of gasification facilities for two main reasons.
First, the ability of IGPG facilities to be feedstock flexible allows the construction of
biomassfed facilities at coalfed scale, and thereby takes advantage of economies of
scale,butwithouttheriskimposedbyaninadequatesupplyofbiomass.Second,flexibility
lowers the investment risk as both feedstock and production can be altered during theoperationallifetimeofthefacility.Anadditionaladvantageofgasificationfacilitiesisthat
CO2 is often removed when chemicals are produced. This should allow the
implementation of CCS at relatively low costs. Currently, there is a need for better
understanding what the possibilities and limitations of flexibility at gasification facilities
areandunderwhich(economic)conditionsflexiblefacilitiesaremoreadvantageousthan
theirstaticcounterparts.Theseaspectsareatthecoreofthisthesis.
A promising (natural gasfired) gasification application for the deployment of CCS in the
shorttermissteammethanereforming(SMR)atindustrialfacilities.CO2avoidancecosts
at SMR facilities are projected to be lower compared to the avoidance costs at power
plants due to the presence of a pressurised CO2 rich gas stream and the possible
availability of waste heat streams, as SMR facilities are generally located inside large
industrial complexes, like refineries. Although literature studies on applying CCS at SMR
facilities have been performed, the impact of applying CCS at existing facilities (retrofit)
andtheeffectofusingwasteheatontheCO2avoidancecostsatSMRfacilitieshavenot
yetbeenstudied.
1.5 ThesisobjectiveandoutlineThe main objective of this thesis is to determine the technoeconomic potential of
commercialscalegasificationsystemsproducingenergycarriersandotherchemicalswith
low CO2 emissions and to assess how and when flexibility improves the overall
performanceofthesegasificationsystems.
Thethreemainresearchquestionsare:
RQ.I Whatistheimpactofflexibleoperationofstateoftheartgasificationfacilitieson the technical and economic performance of integrated gasification
polygenerationfacilities?
RQ.II What is the potential improvement intechnicaland economic performanceofintegratedgasificationfacilitiesinthecomingdecades?
RQ.III WhataretheCO2avoidancecostsofgasificationfacilities,includingSMR,intheshorttolongterm?
Furthermore, literature indicates that performance of IGPG facilities can improve in the
future.[58,59]
However,therateofthisimprovementandthedriversbehinditisstillpoorly
understood.Inthisthesistheimprovementpotentialisanalysedusingtwoapproaches:
A bottomup analysis, giving insights into the extent of the potential costreductions and how they can be realised. This approach involves identifying
promising technologies, determining their current status and potential
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Introduction
25
development in the future and designing new process layouts of gasification
facilitieswhichtakeoptimaladvantageofnewtechnologies;
Atopdownanalysismakinguseofanaloguelearningcurvestudies,givesinsightsintohowcost reductionscoulddevelopover time.Thisapproachcombines the
required
growth
in
installed
capacity
with
scenario
projections
on
the
deploymentofgasificationfacilities.
Bycomparingthetwoapproachesamorerobustpredictionisobtainedonhow,whenand
towhatextentproductioncostsingasificationfacilitiescandecreaseinthefuture.
Table 1.1 gives an overview of the chapters of this thesis in which these research
questionsareaddressed.
Table1.1Structureofthethesis.RQ.I RQ.II RQ.III
Chapter2:Performanceofsimulatedflexibleintegratedgasificationpolygenerationfacilities.PartA:Atechnical
energeticassessment
Chapter3:Performanceofsimulatedflexibleintegratedgasificationpolygenerationfacilities.PartB:Economic
evaluation
Chapter4:Technicalandeconomicprospectsofcoal andbiomassfiredIGPGfacilitiesequippedwithCCSovertime
Chapter5:FuturetechnologicalandeconomicperformanceofIGCC
and
FT
production
facilities
with
and
without
CO2capture:
combiningcomponentbasedlearningcurveandbottomup
analysis
Chapter6:TechnoeconomicassessmentofCO2 captureatsteammethanereformingfacilitiesusingcommercially
availabletechnology
Chapter 2 aims to determine the technical impacts of flexibility in largescale IGPGfacilities.ThechapterprovidesanoverviewofthemajorcomponentsinanIGPGfacility.
For each component the possibilities, limitations and effects of flexible operation is
investigated.Thisinformationisusedtodevelopacomponentbasedcomputersimulation
model.Thismodelyieldsthemassandenergybalancesneededtodeterminethetechnical
performance of IGPG facilities and the impact flexibility has on overall IGPG facility
performance. The chapter also investigates the impact on the CO2 fraction that can be
captured in a flexible IGPG facility. The flexibility comprises both feedstock (biomass
pellets, torrefiedbiomasspelletsandcoal)andproduct (electricity, FTliquids,methanol
andurea).
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26
Chapter3 focuses on the impact of flexibility on the economics of IGPG facilities. Theresults of the technical model developed in Chapter 2 are combined with an economic
model to calculate production costs using the net present value (NPV) method. The
resulting production costs are used to identify under which conditions flexible IGPG
facilities
are
economically
more
attractive
than
static
IG
PG
facilities.
The
chapter
also
investigates the effect a CO2 credit price has on the profitability of the use of biomass
versuscoalasfeedstockandonventingCO2versusapplyingCCS.
Chapter 4 assesses the potential improvement in overall performance of static IGPGfacilitiesproducingelectricityortransportationfuels,withorwithoutCCSfromeithercoal
or biomass using a bottomup analysis. For each component, possible improvements in
existing technologies, as well as advanced alternative technologies are identified. The
improvementsandadvancedtechnologiesarecategorizedinthreedifferenttimeperiods
basedontheirexpectedcommercialisationperiod.Foreachtimeperiod,aprocesslayout
ofthe IGPG facility ismadeusingthetechnologiesavailable forthattimeperiod.These
processlayouts
are
used
in
the
technical
and
economic
models
developed
in
Chapters
2
and3.Thisresultsininsightsintothepotentialreductioninproductioncostsandintothe
extentthedifferentimprovementscouldpotentiallycontributetothatreduction.
Chapter5aimstoassessthepotentialimprovementinoverallperformanceofstaticIGPGfacilitiesproducingelectricityortransportationfuel,withorwithoutCCSfromeithercoal
orbiomassusingatopdownapproach.Learningcurveanalysis isapplied inthischapter
basedoncurrentandprojectedinstalledcapacitiesofmajorIGPGcomponents.Basedon
theseresults,productioncostsforelectricityandFTliquidsarecalculated,aswellasthe
impactonCO2emissions,uptill2050.TheresultsarecomparedwiththeresultsofChapter
4.
Chapter6aimstodeterminetheoptimalstateoftheartCO2capturesystemformodernsteam methane reforming (SMR) facilities using process simulations. A stepbystep
methodologyisdevelopedtoidentifytheoptimalCO2capturesystemforanSMRfacility,
withtheaimofreducingtheenergypenaltyandminimisingCO2avoidancecosts,without
compromisingH2purityorSMRavailability.Thechapterassessesthe locationoftheCO2
captureunitwithintheSMRprocess,theCO2capturesolventandthedimensionsofthe
absorberandregenerator.
Chapter7summarisestheobjectives,approachandkeyfindingsofthisthesis.Besidesthemainconclusions,recommendationsforfurtherresearcharegiven.
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27
2 Performanceofsimulatedflexibleintegratedgasificationpolygenerationfacilities.PartA:A
technical-energeticassessment
HansMeerman,AndreaRamrez,WimTurkenburg&AndrFaaij
RenewableandSustainableEnergyReviews15(2011)256387
DOI:http://dx.doi.org/10.1016/j.rser.2011.03.018
AbstractThis article investigates technical possibilities and performances of flexible integrated
gasification polygeneration (IGPG) facilities equipped with CO2 capture for the near
future.These facilitiescanproduceelectricityduringpeakhours,whileswitching to the
productionofchemicalsduringoffpeakhours.
SeveralsimulationswereperformedtoinvestigatetheinfluenceofsubstitutingfeedstockandproductiononIGPGfacilityoutput,loadandefficiency.Thesesimulationsweredone
usingadetailedAspenPlussimulationmodelofaShellentrainedflowgasifiercombined
with conversion facilities. In this model carbonrich feedstocks (oil residues, coal and
biomass)wereconvertedtoavarietyofproducts(H2,electricity,FTliquids,methanoland
urea) using stateoftheart technology. The size of the gasifier was limited to the
equivalentof2000MWthIl#6coalinput.
Overallefficiencyofthesimulatednonflexibleconfigurationstoconvertpurecoalorpure
woodpelletstoelectricity (40%HHVvs.38%HHV),FTliquids (60%HHVvs.55%HHV),methanol
(53%HHVvs.
49%HHV)
or
urea
(51%HHV
vs.
47%HHV)
are
in
good
agreement
with
the
literature.
Using torrefiedwoodpellets instead ofpurewoodpellets reduces thepenaltydrop in
efficiency compared to coal.Moreover, torrefiedwood pellets have superior energetic
density,handlingandfeedingcomparedtowoodpellets.
Inthisanalysis,theH2:COratioofthesweetsyngaswasfixedtomatchFTliquidscriterion.
Asaresult,overallCO2captureratesarelow,around5665%,dependingonthefeedstock
used. Still, especially with FTliquids and methanol production, CO2 emissions at the
facility are significantly reduced; less than 20% of the carbon feedstock entering the
facility is emitted with the flue gas. Applying biomass and CO2 capture shows great
opportunitiesto
produce
CO2
neutral
electricity
or
chemicals.
When
the
biomass
fraction
exceeds 40% on an energy basis, production is CO2neutral, independent of what is
produced.
Biomasscanbecofedup till50%onanenergybasis.Higher fractionscausesignificant
fouling on cooling equipment. A small partload penalty is observed during the
substitutionofcoalbybiomass.Whenchangingfrompurecoaltopurewoodpellets,the
powercasesuffersa2.5%efficiencydrop,whileallthreechemicalcaseshaveanefficiency
dropoflessthan1%.Atthesametimetotaloutputisreducedto6769%,mainlybecause
ofthelowerenergydensityofbiomass.Byoverdimensioningthegasifierandgascleanup
andoptimisation
section
this
drop
can
be
eliminated.
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Chapter2
28
The syngas can be tailored to the desired composition regardless of the used feedstock.
Therefore,thechemicalconversionsectionsonlyhavetocopewithareductioninsyngas
flowandnotwithachangeinsyngascomposition.Alteringproductionbetweenchemicals
and electricity is possible, although the load of the conversion sections should remain
between 40% and 100% to prevent operational problems. This gives a high degree offlexibility.
Complete substitution between chemical and power production while using the same
feedstockispossibleforthemethanolandureacases.TheFTliquidscaseisrestrictedto
60100% load of the chemical conversion section to prevent that the gas turbine load is
reducedbelow40%.
TheeconomicaspectsofflexibleIGPGfacilitiesareaddressedinpartB.
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Performanceoffacilities.PartA:Atechnicalenergeticassessment
29
2.1 IntroductionIn 2008 global fossil fuel consumption was around 410 EJ. About 40% of this camefrom
crude oil.[68,69]
These fossil fuels power the economies of today. However, their use has
several drawbacks. Fossil fuel resources are finite and their consumption results in large
CO2 emissions (unless carbon capture and storage is applied) as well as otherenvironmental effects. Moreover, their consumption may result in high import
dependence which may threaten supply security, for example in the European Union.
Lastly, largescale implementation of solar and wind power socalled intermittent
renewables requires largescale backup electricity generation capacity. The output of
backup facilities must be easily adjustable in case solar and wind electricity production
changes.[70]
Also, the operating hours of these backup facilities will be relatively low
comparedtobasepowerplants.
A technology that can partly help to overcome these drawbacks is gasification. Through
gasification (renewable) biomass, coal and oil residues can be converted into syngas,which can subsequently be converted into electricity, transportation fuels and other
chemicals(Figure2.1).Naturalgascanbeconvertedintosyngasusingreforming.
Figure2.1Conversionofcarbonrichfeedstockstodifferentproducts.
ToreduceCO2emissions,CO2canbeextractedfromprocessandfluegases,compressed
to30110bar,transportedandstoredinundergroundfields(generallyknownasCCS).In
this way, electricity and hydrogen can be produced with minimal CO2 emissions. CCS at
IGPGfacilitiescanbeaccomplishedatreducedcosts.[24,71]
Thereasonforthis istwofold.
First,thechemicalconversionprocessesalreadyrequireremovalofCO2fromthesyngas.
Second, the higher partial pressure of the CO2 makes precombustion capture using
physical solvents possible. This lowers the energy requirements for the CO2 capture and
subsequent compression. By combining gasification and CCS it is possible to drastically
reduce global CO2 emissions without drastic changes to the current infrastructure.Furthermore, cofeeding biomass allows the production and use of liquid hydrocarbon
transportation fuels with no net CO2 emissions.[22,72]
At large biomass fractions even net
negativeCO2emissionscanbeachieved.
Anattractivefeatureofgasificationis itspotentialflexibility.Especiallythefollowingtwo
combinations of flexible integrated gasification polygeneration (IGPG) facilities are
interesting:
(1) Coal substitution by biomass can facilitate the use of biomass as feedstockwithoutbeingdependentonaconstantbiomasssupply.
Coal
Biomass
Heavyoil
Gas
Electricity
Hydrogen
FTliquids
Methanol
Urea
Syngas
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Chapter2
30
(2) Chemicalplantsproducingmidloadelectricitycanreducetheneedofdedicatednatural gas fired midload power plants. Midload plants are operated when
electricitydemandexceedsthebase load.As intermittentrenewableselectricity
generation capacity is everincreasing, midload power plants will increasingly
havetoactasbackuppowerplantsfortheseintermittentrenewables.ThismaycreateopportunitiesforflexiblelargescaleIGPGfacilities.
Multifeedstock polygeneration (XtY)3 system integration has seen a lot of attention in
literature. A brief overview of studies highlighting results relevant for this study is given
below.
2.1.1 GeneralCummerandBrown investigated themajorancillary components, i.e. pretreatmentand
gas cleaning, in integrated gasification combined cycle (IGCC) facilities.[73]
They
investigated whether components specifically designed for coal could also handle
biomass. They also determined the stage of development of ancillary equipment forbiomass fired IGCC. Their conclusion is that most of the ancillary equipment is not yet
commerciallyavailable.
2.1.1.1 Electricity productionElectricity production using coalfired IGCC combined with CCS has received quite some
attention. A recent study by NETL indicates that, based on stateoftheart (SOTA) Shell
gasificationtechnology,a636MWeIGCCcanachieveanoverallefficiencyof41%HHV,while
emitting750kgCO2/MWh.EquippedwithCO2capture,plantefficiencywouldatpresent
dropto32%HHVandCO2emissionsto90kgCO2/MWh.[74]
Similarvaluesarepresentedby
the IEAGHG with 40%HHV efficiency for Shell IGCC without CO2 capture and 32%HHV with
CO2capture.[49,50]
2.1.1.2 Fischer-Tropsch fuels productionAlthough there is some variation in final efficiency among the literature, reported XtL
conversion efficiencies lay between 46%HHV and 56%HHV. Boerrigter calculated an overall
conversion efficiency of 56%HHV for a noncapture CtL facility.[75]
Larson et al., calculated
an overall conversion efficiency for a noncapture CtL facility of 49%HHV (33% FT + 17%
power). Introducing CO2 capture and compression lowers the power output by 3%pt.
Converting a mixture of switch grass and coal to FTliquids with CO2 capture could be
performed with an overall conversion efficiency of 47%HHV.[76]
This efficiency was
confirmedbyastudyofHamelincketal.TheycalculatedthatbiomasscanbeconvertedtoFTliquidswithCO2captureat46%HHVefficiency(33%FT+13%power).
[77]
2.1.1.3 Methanol productionA CtM studybased onthe liquid phase methanol (LPMeOH
TM) demonstration process at
the Eastman Chemical Company in Kingsport was performed by Heydorn and Diamond
3 Facilities or systems where feedstocks are gasified and converted into products are
referred to as XtY systems. The X is often substituted if a specific feedstock is used:
biomass(BtY),torrefiedbiomass(TtY)orcoal(CtY).TheYisoftensubstitutedifaspecific
outputisproduced:electricity(XtP),FTliquids(XtL),methanol(XtM)orurea(XtU).
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showing a CtM efficiency of 60%HHV assuming a gasification efficiency of 80%HHV and a
syngasenergytoelectricityefficiencyof40%HHV.[78]
TwodifferentCtMconfigurationswere
analysed by Larson and Tingjin.[79]
They calculated an efficiency of 47%HHV for
oncethroughand63%HHVforsyngasrecycle.ABtMefficiencywascalculatedbyWilliams
et al., at 61%HHV.
[80]
Hamelinck and Faaij calculated a BtM efficiency of 51%HHV using afluidisedbedsystem.[81]
2.1.1.4 Urea productionUreasynthesisviagasificationhasreceived little interest in open literature.Neelisetal.,
found an energy consumption of 21 GJLHV/t urea, resulting in a CtU energy conversion
efficiencyof44%LHV.[82]
2.1.2 ObjectivesAll these studies do not investigate variation in feedstock or production during the
operationofthefacility.ArecentstudyfromIEAGHGhasmadeafirstassessmentofthe
flexibility between hydrogen and electricity production, but only at two different
production ratios.[49]
To our knowledge that is the only study which investigated the
possibilities of flexible IGPGfacilities andthe impact offlexibility on overallefficiencies.
Thisstudyaimstofillthisgap.Theobjectivesofthisstudyaretherefore:
First,to identify which bottlenecks occurwhen altering feedstock or productionandhowthesebottleneckscanberesolved;
Second,toanalysesystembehaviourandchangesintheoverallefficiencyandintheenergy,massandcarbonbalanceswhenalteringfeedstockorproduction;
Third, to analyse the effect of flexibility on the CO2 balance and emissions andcomparethebalanceandemissionswiththosefromdedicatedXtYfacilities.
In this study the focus is on the performance of SOTA commercial technologies relevant
for XtY systems. To study these systems, an AspenPlus flowsheet process model of a
flexibleIGPGfacilitywasbuildtogenerateenergyandmassbalancesfordifferentIGPG
facilities.Toallowaccuratemodelling,dataonthetechnicalbottlenecksasminimal load
constraintsandpartloadbehaviourofthevariouscomponentswerecollected.
Thestructureof this article is asfollows: Section 2describes the commodities, including
the different feedstock characteristics. In Section 3 the different components, including
feedstock pretreatment, syngas cleaning and syngas conversion, and their operating
conditions are described. Section 4 gives the process model and plant configurations. In
Section 5 the case studies are defined. Section 6 gives the simulation results, including
overallperformanceandtheeffectofflexibilityonoverallIGPGperformance.InSection7
a discussion of the results and used assumptions is given. Finally, Section 8 contains the
conclusions.
In this study, units are in SIunits and heating values are in higher heating value (HHV),
unlessstatedotherwise.
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2.2 Commodities2.2.1 FeedstocksFor this study three representative solid carboncontaining feedstocks were selected.
Eucalyptuspellets(EP),torrefiedwoodpellets(TOPS)andIllinois#6coal.Theirpropertiesare given in Table 2.1. Short rotation trees, of which Eucalyptus is one of them, is a
potentiallyimportantbiomasssource.[83,84,85]
Thebiomassisdirectlypelletisedortorrefied
andthenpelletisedasthisdrasticallyimprovesbiomassproperties,likeheatingvalueand
moisture content (Table 2.2). This results, among others, to a more efficient
transportation and handling of the biomass.[22,84,86,87]
Illinois #6 coal is a Bituminous coal
typeoftenusedinandcommonlyusedasreferencecoal.[74,79,88,89]
Table2.1Feedstockparametersusedinthisstudy.
Composition Unit(1)
EP[90]
TOPS[90]
Il#6coal[74]
Heatingvalue MJHHV/kga.r. 17.29 20.51 27.14Moisture wt%a.r. 10.00 5.00 11.12
VolatileMatter wt%dry 86.60 75.90 44.50
FixedCarbon wt%dry 12.83 24.10 44.59
Ash wt%dry 0.50 1.34 10.91
C wt%d.a.f. 49.77 54.63 80.50
H wt%d.a.f. 5.80 5.67 5.68
O wt%d.a.f. 44.20 39.45 8.70
N wt%d.a.f. 0.14 0.22 1.58
S wt%d.a.f. 0.03 0.02 3.17
Cl wt%d.a.f. 0.06 0.01 0.37
(1) The composition is on as received (a.r.), moisture free (dry) or moisture and ash free (d.a.f.)
basis.
2.2.2 End-productsSyngas can be converted into a wide variety of endproducts. The main endproducts
evaluated in this study are electricity, FTliquids, methanol and urea. An important
intermediateproductishydrogen.
2.2.3 By-products
TwoimportantbyproductsofXtYfacilitiesareslagandelementalsulphur.Slagisaninertglasslike material consisting mainly of minerals. It is formed as the ash in the feedstock
meltsand issubsequentlyquenched.Slag is,amongothers,usedasconcreteadditiveor
road surface coating compound.[91]
The amount and quality of the slag depends on the
used feedstock. Coal generally produces more slag than woody biomass. Almost all
sulphur inthefeedstock isrecoveredaselementalsulphur.Itisused inawidevarietyof
processes, including vulcanisation, bleaching and the production of fertilizers and
viscose.[92]
Coalgenerallycontainsmoresulphurthanbiomass.
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2.3 ProcessdescriptionIn this section a technical description and partload performance of the different
components used in a flexible IGPG facility is presented. For all components only
commercial available technologies were investigated. The key processesare displayed in
Figure2.2.
Figure2.2SimplifiedprocesslayoutofaflexibleIGPGfacilityusingSOTAcommerciallyavailable
technology.Waste,heatandrecyclestreamsarenotdisplayed.
2.3.1 PlantflexibilityA flexible IGPG facility must be designed to cope with alterations in feedstock, syngas
flowandheatstreams.Amongothers, itmustbeabletoadjusttheH2:COratio.Physical
limitationsrestricttheflexibilityoftheconversionprocesses.Forexample,separatorsare
usually unable to operate properly below 40% volume load.[93,94]
Also, gas turbines havedifficulties maintaining the desired flue gas exit temperature below this load.
[95] In the
subsequent paragraphs the load restrictions and partload behaviour of the various
componentsarediscussed.
2.3.2 Pre-treatmentThe gasifier has several minimal requirements concerning the feedstock (see 2.3.5). To
fulfil these requirements, the feedstock, especially biomass, needs pretreatment, like
pelletisingandtorrefactioncombinedwithpelletising.Theeffectsofthesetechniquesare
giveninTable2.2.Forcomparisontheaveragecoalcharacteristicsarealsogiven.
The pretreatment can be performed at the harvesting, central gathering or factory
location.[22,86]
Itcanalsobedividedovertheselocations.Inthisstudyitwasassumedthat
thebiomassisalreadytorrefiedorpelletisedwhenarrivingattheIGPGfacility.Themost
importantpretreatmenttechniquesaredescribedbelow.
Prepared
feedstock
ASU
GasifierGas
Cleanup
Power
production
FTliquids
production
H2production
AGR
MeOH
production
Urea
production
CO2compression
Claus/
SCOT
FTfuel
MeOH
Urea
LiquidS
H2
O2
O2
N2
CO2
H2S
ScompoundsCO2
Sweet
WGSSour
WGS
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Table2.2Overviewofchemicalpropertiesofdifferentfueltypes.
PropertyIl.#6coal
79
(Bituminous)
Fresh
Wood[90]
Wood
pellets[96]
TOPS
[97]
Heatingvalue(MJHHV/kga.r.) 27 1011 1820 2024
Massdensityofbulkmaterial(kg/m3) 600 350 500650 850
Energydensityofbulkmaterial(GJ/m3) 1617[97] 34 913 1721
Moisturecontent(wt%) 11 50 610 15
C/Hratio(wt)1
1316 ~8 ~8 91087
C/Oratio(wt)2
710 1 1 1287
Flammability3
o ++ +++ ++98
Hydrophobicity + +
(1) GasifyingafeedstockwithahigherC/HratioresultsinmoreCOandlessH2.
(2) AlowerC/Oratioresultsinalowerheatingvalue(HHV)ofthefuel.Inagasifieritalsoresultsin
lowerexternalO2consumption.
(3) Theflammabilityofcoalwassetonaverage.Woodiseasiertocombust,butitshighmoisture
contentlowersflammabilityslightly.Duringpelletisation,thismoistureisremoved.TOPShasa
lowmoisturecontent,butduringthetorrefactionprocessitlostmostofitsvolatilecompounds,therebyloweringitsflammability.
2.3.2.1 TorrefactionTorrefaction transforms biomass into a brittle, moisturepoor, hydrophobic solid with an
increased energy density compared to the original biomass.[86,99]
In short: the biomass
becomes more coallike. Another benefit is better storage properties as deterioration is
muchslowerthanrawbiomass.Thetorrefactionprocessconsistsoffourstages:heating,
drying,torrefactionandcooling.Duringthetorrefactionstage,thebiomassisheatedina
moving bed reactor to 200300C for several minutes. H2O, CO2 and other volatile
compounds evaporate, resulting in an increased C/O ratio of the solid product. Besides
thissolid,alowcaloricgasisproduced.Onaverage,thebiomasswilllose30%ofitsmass
and 510% of its energy, depending on the biomass used and the original moisture
content.Thelowcaloricgasiscombustedandusedasheatingsource.Additionalbiomass
is combusted to supply the remaining heat demand, resulting in an almost completely
selfsufficientsystem.[86,99]
Torrefactionisabatchprocessrequiringstoragewhenapplied
inacontinuousprocess,suchasanIGPGfacility.Storagealsofitstopartloadoperation
of the facility. The torrefaction process is operated at full load, regardless of the IGPG
facility load. When the storage bins are filled, the torrefaction process is shutdown. It is
restartedwhenthefeedstockinthestoragebinscomesbelowacertainthresholdvalue.
2.3.2.2 PelletisingPelletising increases the energy density of biomass feedstocks. This, among others,
reduces transportation costs. During pelletising the biomass is highly compressed. If the
biomass is torrefied, pelletising is mandatory except if the torrefied product is used
immediately. When using raw biomass, the pelletising process consists of four stages:
dryingandgrinding,steamconditioning(tosoftenthefibres),pressurisationandcooling.
Topreventpelletdisintegration,glueisneeded.Whenpelletisingat150Cthelignininthe
biomass which softens above 100C is used as glue.[86]
The energy density of the
biomassincreasesbyaboutafactorof2(Table2.2).Electricityconsumptionofpelletising
is90160MJe/tinput.[86]
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Combiningtorrefactionwithpelletisingresultsinafactor3increaseinbulkenergydensity
comparedtorawbiomass(Table2.2)andahalvingoftheelectricityconsumptionofthe
pelletising process. It isbest topelletisethe biomassdirectly after the torrefaction step.
This reduces the pelletising process to pressurisation and cooling only. Like torrefaction,
pelletisingisabatchprocess.Therefore,thesamepartloadbehaviourapplies.
2.3.2.3 SizingSizing reduces the particle size of solid feedstocks, making transporting and feeding the
feedstock more efficient and easier. It also improves drying, torrefaction and pelletising.
ShellEFgasifiers demand particles smallerthan 0.1 mm for coaland smaller than 1mm
forbiomass.Biomassparticlescanbelargerastheyaremorereactivethancoal.[100]
Hard
brittlefeedstocks(TOPS,coal)aregroundusingcrushers.Morefibrousfeedstocks(rawor
pelletisedbiomass)aregroundusingahammermill.Grindingbiomassto1mmandcoalto
0.1mmrequiresanenergyconsumptionof0.010.02kWe/kWth grindingbiomassto0.1
mm would require 0.08 kWe/kWth.[100]
Sizing has good partload behaviour. By reducing
the speed of the conveyer belt and the sizing equipment, partload operation can be
achievedwithoutlowerefficiencies.
2.3.2.4 DryingThehighmoisturecontentinrawbiomassmakesitunsuitableforgasification freshwood
hasatypicalmoisturecontentofaround50wt%.[90]
Dryingispreferredbeforepelletising
or long distance transport. Active drying of biomass below 10 wt% moisture is not
practical as drying efficiency drops dramatically below that value.[101]
Heat demand
depends among others on initial and final moisture content, particle size and
hydrophobicity of the feedstock. This heat can be supplied by waste heat of other
processes.Dryinghasgoodpartloadbehaviour.Justlikesizingthespeedoftheconveyerbeltandtheamountofheataddedtothefeedstockcanbereduced.Inthisstudythecoal
was dried to 2.5 wt% using waste heat of the IGPG facility. Biomass did not receive
furtherdryingasitsmoisturecontentwasalreadybelow10wt%.
2.3.3 PressurisingandfeedingPrevious research indicated that pressurised gasifiers have significant advantages over
atmospheric gasifiers. The most important advantages are smaller downstream
equipmentandhavingagasstreamatelevatedpressure.[77]
Asmostchemicalconversion
processes and the gas turbine operate at higher pressure, the latter advantage
significantly lowers compression requirements. However, using pressurised gasifiers alsorequires pressurised feeding. For solid feedstocks, the pressurising and feeding systems
dependontheparticledensityandsize.Coal isusuallyfedbya lockhoppersystemwith
pneumaticfeed.Fresh(orpelletised)biomassneedsadifferentfeedingsystemasitistoo
fibrous. This can lead to blockage of the lockhopper feeding system. Due to the larger
particle size of biomass, a hydraulic piston system with screw feeding can be used. The
torrefaction process destroys the fibres, allowing TOPS to use both feeding systems.
However,screwfeedingismoreefficientthanpneumaticfeeding.[100]
Asbothsystemsare
batch systems, they are equipped with pressurised storage bins, allowing homogeneous
and continuous feeding. As pressurising agent, CO2 was used. Energy consumption
dependsontheusedprocessandisneededforCO2compressionandthehydraulicpiston
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Chapter2
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feedersystem.Inthisstudyseparatefeedingsystemforthebiomassandcoalwereused.
Partloadoperationonlyaffectsthefrequencyatwhichthestoragebinsarerefilled.The
effectoffeedingthedifferentfeedstocksisgiveninTable2.3.[100]
Table2.3Feedstockpressurisationcharacteristics.[100]
Il.#6coal(1)
TOPS(1)
EP(1)
CO2consumption Nm3
CO2/tfeedstock 3.7 0.2 0.2
ofwhich:togasifier 2.1 0.1 0.1
toatmosphere 1.6 0.1 0.1
Electricalconsumption kWh/tfeedstock 46.7 42.5 42.5
(1) Basedonalockhoppersystemwithpneumaticfeedingforcoalandahydraulicpistonsystem
withscrewfeedingforbiomass.
2.3.4 Airseparationunit(ASU)The use of pure oxygen (95%) instead of air leads to a lower syngas volume and higher
syngas energy density. There are three different air separation techniques available toextractoxygenfromair:(vacuum)pressureswingadsorption,membraneseparation,and
cryogenicseparation.[102]
Largescalemembraneseparationshowshighpotentialbutisstill
in the demonstration phase. Of the other options, cryogenic separation is currently the
most economical option when high purity (>95%) and throughput (>2.5 t/h) are
required.[103,104]
Energy savings can be accomplished by integrating the ASU with thegas
turbine. An integrated ASU receives (part of) its air already partly compressed from the
gas turbine. Although this increases efficiency, plant flexibility and reliab
top related