2013 Carbon capturing paper

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International Journal of Greenhouse Gas Control 19 (2013) 396405

Contents lists available at ScienceDirect

International Journal of Greenhouse Gas Control

j ou rna l ho me p a g e : www.e l sev i e r. com/ loca t e / i j ggc

Evaluation of natural gas combined cycle power plant forpost-combustion CO2 capture integration

Chechet Biliyok , Hoi YeungProcess Systems Engineering Group,School of Engineering, Craneld University, Bedfordshire MK43 0AL, UK

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Article history:Received 19 March 2013Received in revised form 7 September2013Accepted 3 October 2013

Keywords:ModellingNGCCCCGTPost-combustionExhaust gas recirculation

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Over the coming decade, gas-red power plants are projected to account for a substantial share of globaloutput. CO

2 capture would be required to mitigate the associated emissions. Thus, high delity models of

a 440 MW natural gas combined cycle power plant, a CO2 capture plant and a CO2 compression train werebuilt and integrated for 90% capture level. Power output is observed to fall by 15%, while cooling waterdemand increases by 33%. A 40% exhaust gas recirculation (EGR) causes a 10MW power recovery, butincreases cooling water demand further. It is shown that higher exhaust gas CO2 concentration enhancesmass transfer in the capture plant, which reduces its steam requirement. Supplementary ring (SF) of the exhaust gas is observed to generally improve the plant output. Economic analysis, performed via abottom-up approach, reveals integrated plant overnight cost to be 58% higher thanthe power plant cost,discouraging deployment of CO2 capture. The impact of EGR is marginal, while SF implementation almostdoubles the overnight cost. Cost of electricity increases by 30% for the integrated plant, but only by 26%with EGR, and 24% with SF. However, the price of gas remains the largest contributor to cost of electricity.

Crown Copyright 2013 Published by Elsevier Ltd. All rights reserved.

1. Introduction

1.1. Background

The advent of cheap gas in the US engendered by shale gas pro-duction, accompanied by the global tilt towards harnessing shalereserves, gives natural gas added signicance in the future energymix. A lot of this gas is used to generate power, which bringsabout a substantial fall in greenhouse gas emissions as observedin the US over the past year ( EIA, 2012 ), and prompted recent UKenergy policy to encourage a dash for gas. This is because naturalgas combined cycle (NGCC) power plants produce around half theemissions that state-of-the-art coal-red power plants generate,but even if all coal consumption is replaced with natural gas, the

reductions would notbe enoughto meet the globalemissionreduc-tion targets proposed by the Intergovernmental Panel on ClimateChange ( IPCC, 2007 ).

Abbreviations: APEA,Aspen Process Economic Analyzer;EGR, exhaust gas recir-culation; FC, free carbon; HP, high pressure; IP, intermediate pressure; HRSG, heatrecovery steam generator; LCOE, levelised cost of electricity; LP, low pressure;NGCC, natural gas combined cycle; O&M, operational and maintenance; PCC, post-combustion carbon capture; SF, supplementary ring. Corresponding author. Tel.: +44 1234750111x5169.

E-mail address: [email protected] (C. Biliyok).

Carbon capture and sequestration (CCS) has been identied bythe International Energy Agency (IEA) as a crucial technology thatcan be used to meet emission reduction targets ( IEA, 2010 ), as theworld transitions to sustainable energy sources. Currently, thereare onlyeight large scale CCS facilities operatingworldwide ( GlobalCCS Institute, 2012 ). Thesefacilities areexpensiveinvestments,andrequire government regulation or subsidy to be competitive, lead-ingto recent cancellationsof somehigh prole CCSprojects( ProjectPioneer, 2012 ). This makesmodellingand simulationan invaluabletool for investigating integration challenges.

1.2. Motivation

The most pressing challenges of CCS is that it is estimated toreduce the plant efciency by 15% and increase the cost of elec-tricity by 60% when integrated with an NGCC power plant ( Cifernoet al., 2010 ). Recent literature highlights efforts targeted at theseissues, however doubts remainabout the accuracy of many of thesestudies, where the models used have not been validated ( Peeterset al., 2007;Berstadet al., 2011;Li etal., 2011a ). Where models havebeen validated, some questions remain. For instance, in the analy-sis performed by Sipcz and Tobiesen (2012) , it is reported that a440 MW NGCC Plant would only require a single 9.13m diameterabsorberwith26.9 m Mellapak250packingfor itspost-combustioncarboncapture(PCC)plant. This resultis arrived at after a PCCplantmodel, which was validated at pilot plant scale, was scaled up.

1750-5836/$ seefrontmatter. Crown Copyright 2013 Published by Elsevier Ltd. All rightsreserved.

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However, this is a very optimistic estimate, and is at odds withthe design of a PCC plant for a similar capacity NGCC plant, whichHetland et al. (2009) reported to require four 9.6m diameterabsorbers with 30m Mellapak 250 packing.

Various authors have also analysed the impact of exhaustgas recirculation (EGR) on the performance of the integratedprocess( Berstad et al., 2011; Li et al., 2011a,b; Sipcz and Tobiesen,2012; Botero et al., 2009; Jonshagen et al., 2011 ). It has been foundthat EGR is mostly benecial to an integrated plant due to a con-comitant fall inexhaustgas owrate, anincrease inexhaustgas CO 2concentration, and a reduced solvent pumping requirement. How-ever, the impactof EGR on the thermodynamicperformance on thePCCplant has notbeenexploredin detail, especially in regards to itsrole in solvent regeneration. This is important, as it may uncoverpotential avenues that can be explored to enhance the impact of EGR.

As a result, high delity models of a NGCC power plant and aPCC plant, which have been validated, are required for rigorousanalysis of the integration of the two plants. Chemical engineer-ing principles need to be applied in scaling up the PCC plantmodel that has been validated at pilot scale. An appropriatelysized compression train is also desirable to determine the addi-tional energy required to deliver the CO 2 to a nearby storage sitevia a pipeline. In this manner, the integrated plant performancecan be fully explored, along with estimated water requirementsin the whole process. Furthermore, as a performance improve-ment scheme, the impact of EGR on the PCC plant can also bethermodynamically investigated. In addition, the supplementaryring of turbine exhaust gas can be analysed in the integratedplant.

The implication here is that economic analysis performed withsuch models would inspire condence. Previous reported effortsare mainly based on cost factors and employ several technicaland economic assumptions that dramatically inuence results(Sipcz and Tobiesen, 2012; Rubin et al., 2007 ). In addition, theplant location, which is an inuential economic factor, is anotherparameter that is routinely neglected. Therefore, rigour in thisanalysis is ensured by eliminating assumptions and providinga suitable location for the facility. The location would providea basis for generating construction costs for the plant througha bottom-up approach, using material and labour costs in theregion.

1.3. Novelty

There are four novelties presented in this work: (a) evaluationof an integrated NGCC, PCC and CO 2 Compression plant using val-idated and well-sized models; (b) thermodynamic analysis of theimpact of EGR on the PCC plant performance, and hence on theintegrated plant performance as a whole; (c) the feasibility andbenets of supplementary ring of gas turbine exhaust on theRankine cycle design and PCC plant; and (d) economic analysisof the integrated plant located in Northern England, generatingcost estimates via a bottom-up approach, as opposed to using costfactors.

1.4. Outline

Modeldevelopment is covered in Section 2. Section 3 f ocuses onthe plant integration, EGR and its impact on performance. Insightsare drawn from the thermodynamic analysis of EGR on the PCCplant. Section 4 presents the supplementary ring of gas turbineexhaustand its inuenceon performance.Finallyan economicanal-ysis is presented in Section 5, with conclusions provided in Section6.

Table 1NGCC plant input anddesigndata.

Description Values

Fuel gas ow rate (kg/s) 15.69Fuel lower heat value (kJ/mol) 974.5Air to gas combustion ratio (wt) 43.76Turbine inlet temperature ( C) 1425Gas turbine inlet pressure (bar) 20.68HP turbine inlet pressure (bar) 124.00

IP turbine inlet pressure (bar) 28.65LP turbine inlet pressure (bar) 4.45Condensate pressure (bar) 0.04Superheated steam temperature ( C) 565Reheated steam temperature ( C) 558HRSG minimum approach ( C) 11Ambient temperature ( C) 15Cooling water exit temperature ( C) 25

2. Model development

2.1. NGCC power plant

A 440MW NGCC power plant is modelled in GEs GateCycle TM

turbine librarysoftware,an application thatuses the turbinedatato

determine the corresponding as-built performance. GateCycle TMmodels are used detailed engineering, design, retrotting, repow-ering and acceptance testing ( GE Energy, 2013 ). The plant consistsof an Ansaldo V94.3A gas turbine and a three pressure level steamcycle with reheat. Important model input and design data is givenin Table 1 . The model is replicated in Aspen HYSYS V8.0 by incor-porating the gas turbine performance and design parameters fromGateCycle TM. The thermodynamic properties of the Brayton cycledescribed by Peng Robinson equation of state, while that Rankinecycle is represented by steam tables. There aresixteen heat transferstages in the heat recovery steam generator (HRSG), and each oneis modelled individually as a heat exchanger.

In benchmarking the model from GateCycle TM to Aspen HYSYSV8.0, the effects of turbine blade cooling on the gas turbine per-

formance introduced some challenges. These have been handledusing techniques described by Jonsson et al. (2005) , which enablesthe Brayton cycle in Aspen HYSYS to be tuned to be the exact rep-resentation of the one in GateCycle TM. On the other hand, Rankinecycle calculations of both models are identical.

2.2. PCC plant

The rate-based column in Aspen HYSYS is used to developa PCC plant model with MEA solution as solvent. This model isunderpinned by the two-lm theory, which describes diffusion of components across the vapour and liquid lms of minuscule thick-ness, with a phase equilibrium existing in the interface betweenthelms. Chemical reactionis also accounted for and is assumed to

occur in the liquid lm. The following kinetic expressions describethese chemical reactions:

CO2 + OH HCO3 (1)

HCO3 CO2 + OH (2)

MEA + CO2 + H2 O MEACOO + H3 O+ (3)

MEACOO + H3 O+ MEA + CO2 + H2 O (4)

Electrolytic interactions suchas water dissociation,bicarbonatedissociation and MEA hydrolysis also accounted for in the liquidlm:

2H2 O H3 O+ + OH (5)

HCO3

+ H2O H

3O+ + CO

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2 (6)


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398 C. Biliyok, H. Yeung / International Journal of Greenhouse Gas Control 19 (2013) 396405

Table 2PCC plant design and operations.

Preliminary design Operations

Absorber column number 4 Capture level (wt%) 90.00Absorber diameter (m) 10 Lean loading (mol CO 2 /mol MEA) 0.2340Absorber packing height (m) 15 Rich loading (mol CO 2 /mol MEA) 0.4945Regenerator column number 1 Flue gas inlet temp ( C) 40.00Regenerator diameter (m) 9 Absorber pressure (bar) 1.013Regenerator packing height (m) 15 Regenerator Pressure (bar) 1.500

MEAH+ + H2 O MEA + H3 O+ (7)

Globally,electrolyte NRTL activitycoefcient is used to describethe system. Kinetic parameters of reaction (1) are taken fromPinsent et al. (1956) and those for reaction (2) are derived usingequilibrium constants from Hikita et al. (1977) while consideringthe reversibility of (1) and (2) . These are then adapted to the powerlaw by AspenTech (2008) , who also provide the kinetic parametersof reactions (3)and(4) , alongwith the equilibrium constants of Eqs.(5)(7) .

Such a model is the highest level of modelling packed columns(Keniget al., 2001 ), as boththe physicaland thechemicalbehaviourof all components in the system are individuallyrepresented, with-out using enhancement factors. The True Species simulationapproach is utilised,whereall components CO 2 ,MEA,H2 O, H3 O ,OH , HCO3 , CO3 2 , MEAH+ and MEACOO are accounted for, asopposed to the ApparentSpecies approach, where the ionic com-ponents are reduced to their corresponding stable states of CO 2 ,MEA andH 2 O.

This model has been validated previously with pilot plant data(AspenTech, 2008 ). The model is scaled up to handle the exhaustgas from the NGCC power plant. Scale-up techniques described byLawal et al. (2012) w ere utilised, with Mellapak 250X packing. Thelean solvent recycle to the absorber was closed, ensuring that themodel remains a good representation of the PCC plant ( Lawal et al.,2010; Biliyok et al., 2012 ). Preliminary design and operations datais provided in Table 2 .

2.3. Compression train

A CO2 compression train is sized and modelled to appropriatelyaccount for its energy demands required to compress the capturedCO2 . A nal compression stage discharge pressure of 110bar isspecied according to KEPCO/MHI application ( IPCC, 2005 ), whereCO2 is at itssupercritical or dense phase, forefcient pipeline trans-port. Pure CO 2 becomes supercritical at a pressure of 96bar, andremains so at all temperatures ( IPCC, 2005 ), however the higherpressure of 110 bar provides allowance for impurities present. Amolecular sieve is added to the model to remove water and ensurea 99.5% nal CO 2 concentration. A pump is provided that is capable

of increasing CO 2 pressure to 175 bar, to account for an increasingreservoir pressure, as more and more CO 2 is stored underground.The model is described by REFPROP database.

The compression train comprises of centrifugal compressors,aftercoolers and scrubbers. A maximum uid head (polytropic)of 3050m is enforced at each compression stage/impeller, due toequipment mechanical limitations ( Brown, 2005 ). As this is a CO 2compression application, a maximum compressor discharge tem-perature of 120 C is imposed, which in turn limits the numberimpellers in a singlecompressor without intercoolingto two. Com-pressor maps/curves, which are compressor manufacturer (OEM)proprietary data, have also been used. These provide a relation-ship between actual volume ow rate at the suction, compressionefciency and uid head. In this case, data for a natural gas com-

pression application, manufactured by the Elliot Group has been

appropriately scaled (considering gas molecular weight differ-ences) and used. The design and performance is given in Table 3 .

3. Process integration

3.1. Consideration

There are four main integration points ( Fig. 1):

[A] exhaust gas fed to the PCC plant,[B] steam extracted from the NGCC plant to the reboiler at PCCplant,

[C] condensate returned to the NGCC plant from the reboiler, and[D] captured CO 2 from the regenerator to the CO 2 compressiontrain.

Pre-treatment of the exhaust gas is performed before it is fedinto the PCC absorber. It passes through a desulphurisation unit toremove SOxgases andan electrostatic precipitation unit to removeNOx gases. It is assumed that oxygen inhibitors are used to limitMEA solvent degradation. A direct contact cooler (DCC) then coolsthe gas to around 40 C for favourable absorption conditions in theabsorber, and condenses water out of the gas.

Steam is drawn from the cross-over of the IP and LP turbinesthrough a throttle valve, which limits pressure losses, and thenused to regenerate the solvent in the PCC plant. The condensatefrom the reboiler is returned to the condenser of the NGCC plant.This position is chosen due to the steam quality of 4.5 bar, which issaturated at 148 C. Pressure losses occur over the cross-over lineand the reboiler tubes, so a reasonable pressure drop is assumedand the steam condenses at 3 bar, with a saturation temperatureof 134 C. At this temperature, an appropriate minimum approachcan be maintained in the reboiler, where the solvent tempera-ture is constrained to a maximum of 120125 C to avoid thermaldegradation. An attemperator is used to control the temperatureof the steam draw, spraying condensate to ensure the temperatureremains just above saturation. For this study, it is assumed that theLP turbine can handle large ow rate variations with negligible fallin efciency.

CO2 is captured at the regenerator pressure of 1.5 bar and sentto the compression train where it is compressed to a supercriti-cal state. Supercritical CO 2 is sent to a nearby saline aquifer forsequestration. Therefore, the steam extracted from the Rankinecycle, along with power demands of the gas blower, solvent pumpsand CO 2 compressors, all add up to a parasitic load on the NGCCpower plant. The performance of the integrated plant is given inTable 4 .

Table 3Compression train design and operation data.

Description Value

Number of compressors 5Compressor efciency range (%) 78.083.5Aftercoolers exit temperature ( C) 40Compressor speed (rpm) 6000


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Fig. 1. Process ow diagram of integrated NGCC, PCC and compression plant.

3.2. Exhaust gas recirculation

Part of the exhaust gas from the HRSG exit is cooled to aroundambient conditions using a DCC, and then sent back to the inlet of the air compressor. EGR has the following advantages:

a fall in exhaust gas ow rate, which reduces the required PCCplant capacity;

an increase in exhaust gas CO 2 concentration, leading to a moreefcient CO 2 capture; and

a reduced solvent circulation in the PCC plant, resulting in lesspumping required.

A 40% EGR is imposed, i.e. 40% of the exhaust gas is returned tothe compressor inlet. This is a recommended maximum needed topreserve ame stability in the gas turbine ( Elkady et al., 2009 ). Thecapture level of the integrated plant with EGRis maintained at 90%.The results are also provided in Table 4 .

3.3. Discussion of results

3.3.1. Integrated plant scenarioConsidering Table 4 , it is observed that the power plant net out-

put falls by about 14.7% when the PCC plant and compression trainare integrated, and this amounts to a 10% point efciency loss. Thelargest driver of this fall in output is the steam draw that diverts58% of steam meant for the LP turbine to the reboiler in the PCCplant for solvent regeneration. While maintaining HRSG minimumapproachtemperature,steam generation is increasedslightly,how-ever it is still observed that heat transfer is less effective as theexhaust temperature is 25 C higher for the integrated plant com-pared to that of theNGCC plant.The reduced heat transfer is causedby the condensate that returns to the NGCC plant at a higher tem-perature, i.e. just below saturation at 3bar, before it is sent to thelowpressure economiser section of theHRSG. Theimplicationhereis that a redesignof the HRSG, to accountfor the steam draw, wouldpotentially improve heat transfer with the exhaust gas. In the end,

Table 4Process performance comparison.

NGCC plant only Integrated plant Integrated plant + EGR

Power plant netoutput(MW) 440.6 376.0 386.1

Power loss due to PCC & comp. (%) 14.66 12.37Plant net efciency (%) 59.62 49.38 50.71Total cooling water demand (tonne/s) 7.72 10.29 10.62Cooling water increase (%) 33.34 37.62Gas turbine net output (MW) 287.7 287.7 287.6Exhaust gas ow rate (kg/s) 693.6 693.6 416. 1Exhaust gas CO 2 content (mol%) 3.996 3.996 6.610Exhaust gas outlet temp. ( C) 99.5 125.0 120.7Steam generated (kg/s) 103.8 106.6 109.0Steam draw-off ow rate (kg/s) 61.87 57.25Absorber column number 4 3Absorber L/G ratio (mol basis) 1.31 2.09Total Solvent circulation rate (kg/s) 721.6 675.3Steam/CO 2 captured (kJ/kg) 4003 3724Additional PCC plant demand (MW) 6.25 3.74Compression train inlet rate (kg/s) 39.61 39.41Compression power demand (MW) 13.37 13.25Net Specic Emission (kg CO 2 /MWh) 354.5 40.1 39.5


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0.0

1.0

2.0

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0.00 5.00 10.00 15.00

T r u e C O

2 t o A p p a r e n t C O

2 R a o x 1 0 4

Absorber Packing Length - Top to Bo om (m)

Without EGRWith EGR

Fig. 2. True CO 2 to apparent CO 2 content ratio in solvent along absorber length.

is using a rotating packed bed for the absorber and regeneratorcolumns ( Tan and Chen, 2006 ).

4. Supplementary ring of gas turbine exhaust

4.1. Consideration

AsawayofincreasingtheCO 2 concentration inthe gasthat is fedto thePCC plant, the exhaust gasexiting the gas turbine can be redusing a burner placed in the duct connecting the gas turbine outletto the HRSG inlet to burn additional natural gas ( Li et al., 2011a ).Not only does the supplementary ring (SF) of gas turbine exhaustincrease the CO 2 concentration, but it also provides more energyfor the HRSG to generate additional steam, and reduces the oxygencontent of the gas, which in turn results in decreased oxidativedegradation of the solvent ( Fig. 3).

SF is implemented for the 40% EGR scenario, with the steamcycle redesigned to account for SF. The ow rate of the exhaustgas around the burner is 702kg/s, with an initial oxygen contentof 7.54mol%, equating to an oxygen ow rate of 59kg/s, which ismore than enough for complete combustion of additional gas to bered. Therefore, to maintain rigour in the analysis, the followingassumptions are made:

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0.0 0.5 1.0 1.5 2.0

m o l a r o w r a t e ( k m o l / s )

M o l a r F r a c o n X 1 0 2

Supplementary gas mass ow rate (kg/s)

CO2 molar frac onO2 molar frac onExhaust gas ow rate (kmol/s)

Fig. 4. Changing composition of exhaust gas with SF.

Complete combustion of added natural gas is reached due to theexcess oxygen available.

There is negligible energy loss to the surroundings, as the burneris located in the gas turbine-HRSG connecting duct.

Flamestabilisationis achieveddue to the excess oxygen availablefor combustion. The conguration and tube placements in the HRSG remain

unchanged. Superheated steamtemperature is limited to 600 C due tosteam

turbine design constraints. A minimum approach temperature of 11 C is maintained in the

evaporators. Pressure drops are constant in the HRSG tubes.

With no HRSG conguration changes to be made, steam genera-tion is limited to the subcritical region. Therefore, SF is explored fora range of 0.52.0 kg/s of additional gas. HRSG operational param-eters with SF are provided in Table 5 .

The ow rate of the exhaust gas increases marginally, howeverits composition changes signicantly, particularly its CO 2 and O 2content, as O 2 is consumed in combustion. The impact of this isshown in Fig. 4 .

The increasing CO 2 concentration would require longer packingin both columns in the PCC plant to retain the same capture levelfor the four SF scenarios with a reasonable reboiler duty. Therefore,

NaturalGas

Air

HRSG

GAS TURBINE ENGINE

HP SteamTurbine

GasTurbine

Air Compressor

MainSteam

SupplementaryGas

RecycledExhaust Gas

CombustionChamber

GasBurner

To Reheat

Fig. 3. Implementation of supplementary ring of exhaust gas.


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Table 5HRSG operational parameters with SF.

Description 0.5 kg/s 1.0 kg/s 1.5 kg/s 2.0 kg/s

HP turbine inlet pressure (bar) 143.60 176.60 196.60 213.60IP turbine inlet pressure (bar) 30.71 33.21 38.21 40.21LP turbine inlet pressure (bar) 4.36 4.36 4.36 4.36Superheated steam temperature ( C) 596 600 600 600Reheated steam temperature ( C) 595 600 600 600

Table 6SF Updated PCC plant design and operations data.

Preliminary design Operations

Absorber column number 3 Capture level (wt%) 90.00Absorber packing height (m) 25 Steam/CO 2 captured (kJ/kg) 3700Regenerator column number 1 Lean loading (mol CO 2 /mol MEA) 0.3200Regenerator packing height (m) 25 Rich loading (mol CO 2 /mol MEA) 0.5300

to provide a basis for comparison, the same design and operat-ing parameters for the PCC plant is used for all four cases and theupdated values are provided in Table 6 .


4.2.1. Impact of SF on the EGR scenarioItis shown in Fig. 5 that SF generally improves the performance

of the plant. Net power output increases proportionally with theadditional gas red in the burner, reaching a maximum of 435MWwith the ring of 2kg/s of natural gas, while plant net efciencyremains relatively constant at a 50.8%. The implication here is thatas long as complete combustion (limited by available oxygen) canbe maintained, with minimal environmental heat losses, then asmuch natural gas as possible can be red in the gas burner toenhance the output of an NGCC plant integrated with a PCC plantand compression train.

The main driver for this rise in output is the increase in quan-tity and quality of steam generated in the HRSG, as observed in

Fig. 6, which in turn increases power generation in the steam tur-bines. Although there is an increase in the absolute value of steamextracted from the Rankine cycle for solvent regeneration, due totherisingCO 2 captureratedisplayed in Fig.7, thepercentage of gen-erated steam that is extracted drops almost linearly to 48% when2kg/s of additional gas is red, leading to a higher proportion of the steam being fed into the LP turbine. This also contributes tothe higher integrated plant output. Fig. 7 also shows that powerdemands of compression train increases proportionally with theCO2 capture rate, the additional power generated using SF morethan compensates for the increasing compression load. These all

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0.0 0.5 1.0 1.5 2.0

E ffi c i e n c y ( % )

P o w e r ( M W )


Net Power Output (MW)

Plant Efficiency (%)

Fig. 5. SF power output and netefciency.

contribute to make the net specic emissions stabilise at about39.5kg CO 2 /MWh, even with increasing SF.

With the existing HRSG conguration, updating the operationparameters with SF also provides an opportunity to maximise heattransfer in the HRSG. As a result, it is observed in Fig. 8 that HRSG

exhaust gas temperature, which is an indication of heat transfer,drops with from 121 C when only EGR is implemented to 109 Cwith SF of 2 kg/s of additional gas. Theimpact of this improved heattransfer is reected in the additional steam generated, which is of higher quality. On the other hand, the cooling water requirementsfor plant increase with increasing SF to a maximum of 12,106kg/s.This is driven by the DCCs for exhaust gas, the condenser in the

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E x t r a c o n l e v e l ( % )

S t e a m o w r a t e ( k g / s )


Steam Generated (kg/s)

Steam extracted (kg/s)

Percentage extracted (%)

Fig. 6. SF steam generation and extraction.

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P o w e r ( M W )

M a s s o w r a t e ( k g / s )


CO2 Capture rate (kg/s)

Compression load (MW)

Fig. 7. SFCO2 capture rate and compression load.


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o w r a t e

( t o n n e

/ s )

T e m p e r a t u r e

( o C )


HRSG Exhaust Gas Temperature (C)Cooling Water Demand (tonne/s)

Fig. 8. SF HRSG exhaust gas temperature and cooling water demand.

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S o l v e n t c i r c u l a o n r a t e

( k g / s )

F C R a o 1 0 4


FC Ra o

Solvent circula on rate (kg/s)

Fig. 9. PCC plant FC ratio and solvent circulation rate due to SF.

PCC plant and the aftercoolers in the compression train, which are

dealing with increasing ue gas ow rates.

4.2.2. Thermodynamic analysis of supplementary ring on thePCC plant

With an increasing SF of natural gas, there is an increasingCO2 concentration in the exhaust gas that is fed to the PCC plant(Fig. 4). To maintain the 90% capture level, solvent circulation rateis increased, as opposed to reducing the lean loading of 0.3200.

The amount of steam energyrequired to strip thesolvent of 1 kgof captured CO 2 is preserved at a value of 3700kJ. This is notwith-standing the fact that more CO 2 is being captured with increasingSF (Fig. 7) and therefore being stripped from the solvent. As cov-ered in Section 3.3.3 , the rising solvent circulation rate should alsobring about an increase in steam energy requirement. However,

this is not the case because a change in the absorption mechanismoffsets this energy requirement to maintain the value of 3700 kJ. Ithas been shown previously in Section 3.3.3 that an increasing CO 2concentration increases mass transfer in the absorber, which thenreduces theoverallheat of absorption. Theimpactof thisis exploredin Fig. 9 , which shows how the FC ratio of the PCC plant increaseswith increasing SF of natural gas in the NGCC plant, conrming theimproved mass transfer.

Compared to the analysis in Section 3.3.3 , which was tem-pered by a reduced solvent circulation rate, Fig. 9 clearly revealsan increasing circulation rate with increasing SF. However, dueto the increasing mass transfer of CO 2 diffusing into the solvent

Table 7Economic analysis cost inputs.

Description Value

Gas price ( D /GJ) 8.10MEA price ( D /tonne) 2000Interest rate (%) 12.0Contingency (%) 15.0Project economic life (year) 30Capital escalation (%/year) 5.0

Raw material escalation (%/year) 3.5

in the absorber, accompanied with the decreasing chemical reac-tions, thereducedheat ofabsorptioncompensatedfor theincreasedheat required by a rising solvent circulation rate, which lead to theattainment of same amount of energy required to strip the solventof 1kg of captured CO 2 for all four SF scenarios.

5. Economic analysis

5.1. Cost estimation

Economic analysis is performed in Aspen Process Economic

Analyzer

(APEA) V8.0, an industry standard tool known to be farmore accurate than factor-based costing approaches ( Whiteside,2005 ), and which uses data from the 1st quarter of 2012. APEAgenerates capital costs via a bottom-up approach, relying on mate-rial costs and wage rates to estimate equipment fabrication andinstallation costs. Simulation unitoperations are mapped to appro-priate equipment cost models, which are then sized and designedaccording to relevant design codes. For example, British Standard5500pressurevesseldesign codewas speciedfor thisanalysis. Theequipment costs are then estimated by simulating vendor fabri-cation procedures. Piping and instrumentation diagrams, attachedto process equipment, are used to estimate associated bulk costsof plant piping and instruments. Civil costs are a function of theequipment weight and size.

The cost of a hypothetical plant, located in Northern England, isevaluatedusingmaterial costs and wage rates from the UK.Indirectproject costs, including engineering costs and owners costs, areaccounted for using wage rates and construction equipment rentalrates. The following assumptions are made:

The captured CO 2 has neither economic value nor disposal costs,but is sequestered in a nearby saline aquifer.

All electricity requirements, including those for equipmentmotors and control process elements are generated in the plant

Cooling water is sourced from a nearby body of water at cost of pumping and operation of a cooling tower.

Important cost inputs are provided in Table 7 , with the costs

given in Euro.Three key cost metrics are evaluated for the stand-alone NGCCplant, the integrated plant, the integrated plant with EGR and the2 kg/s SF scenario:

Overnight cost, which is the capital requirement butassumes theplant can be constructed in a day and excludes interest.

Levelised cost of electricity (LCOE), which is the unit cost of elec-tricity generation over the life of the power plant, accounting foroperating and maintenance cost.

Cost of CO2 Avoided, which is calculated as:

Cost of CO 2 Avoided =[LCOE]withCCS [LCOE]withoutCCS

[tonne CO2

Emitted/MW]withoutCCS

[tonne CO2

Emitted/MW]withCCS

(9)


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Table 8Economic performance.

NGCC plant only Integratedplant

Integratedplant+ EGR

Integratedplant+EGR+SF

Overnight cost ( D /kW) 749 1185 1153 1422Increase in overnight cost (%) 58 54 90LCOE (D /MWh) 54 70 68 67Increase in LCOE (%) 30 26 24CO2 avoided cost ( D /tonne CO 2 ) 51 44 43


Results are provided in Table 8 and it is observed that theovernight cost increases by 58% for the integrated plant comparedto the original cost of D 749 per kW for the NGCC plant. This is asignicant increase in the capital requirement, and must be over-come to encourage thedeploymentof CCSwithNGCC plants. WhenEGR is implemented, the overnight cost is still 54% greater thanthe stand-alone NGCC plant cost. Althoughthe number of absorbertrains required for the EGR scenario is 3 compared to the 4 for theintegrated plant, the DCC required for the recycled exhaust gasandthe increased cooling water tower capacity, only translates to afour percentage point reduction from the cost without EGR. Thiscost reduction is mainly driven by the 10MW output recovered byimplementing EGR.

Finally, when SF of 2 kg/s of gas is implemented onto the EGR scenario, the overnight costs increases further by 90% compared tothe NGCC plant cost. This is partially driven by the higher capac-ity requirements for the PCC plant, compression train and coolingwater tower. However,the crucialcauseof thisincreaseis the largersteam cycle capacity in the power plant i.e. larger steam turbinesand HRSG.In fact,the higherpressures inthe HRSG requiredthickerheat exchanger tubes that are more expensive. Therefore, withovernight costs almost doubling when the steam cycle is designedto account for SF, it is unlikely to be considered a viable option inimproving the performance of an NGCC plant integrated with CCS.

The LCOE for the integrated plant is 30% greater than the LCOE

for the NGCC plant. When EGR is then implemented, this falls to26%, which is only a modest improvement. Designing the steamcycle for SF of2 kg/s ofgas reduces this further by2%,however sucha drop is unlikely to justify the additional capital outlay required.In fact, Fig. 10 reveals that the largest driver for the LCOE remainsthe cost of natural gas for all scenarios under consideration, withthe xed operational and maintenance (O&M) costs (made up of running labour cost) estimated to be a greater proportion of theLCOE than the capital requirements. Only the variable O&M costs,which is made up of solvent make up costs, is less than the capitalproportion of the LCOE, butit is likelyto also be greater in scenarios

0

10

20

30

40

50

60

70

80

NGCC Plant Integrated Plant Integrated+EGR Integrated+EGR+SF

L C O E

( / M W

h )

Variable O&M CostsFixed O&M CostsFuel CostsCapital Costs

Fig. 10. Distributionof costs in LCOE.

whereCO 2 disposalcosts arealso considered.Therefore,integratinga PCCplant and compressiontrainto anNGCCplant does not changethe signicance of gas prices on the LCOE.

The CO2 avoided cost for the integrated plant is estimated tobe D 51 per tonne of CO 2 captured. These are comparable to val-ues in previously published studies, which fall between D 45 andD 90 ( Finkenrath, 2011 ). However, this value would be greaterwhen CO 2 transport and storage costs are also accounted for. Withthe implementation of EGR, the CO 2 avoided cost drops to D 44per tonne of CO 2 captured, which the SF of 2kg/s of additionalgas only improves this marginally to D 43 per tonne of CO 2 cap-tured.

6. Conclusions

High delity models of a 440 MW NGCC power plant, PCC plantand CO 2 compression train were built in Aspen HYSYS V8.0. Thepower plant model is tuned and validated with data from GEsGateCycle TM gas turbine library, the rate-based PCC plant modelis scaled up from a validated model, and the compression trainmodel is sized with compressor curves to determine the addedenergy requirement. The three plants are integrated for 90% cap-ture level and it is observed that net power output falls by 15%,while cooling water demand rises by 33%. A 40% EGR resultsin a 10MW power output recovery, but cooling water demandincreases further by 4% compared to the stand-alone NGCC plantrequirements. The increased exhaust gas CO

2 concentration due

to EGR was shown to enhance CO 2 mass transfer in the PCC plantabsorber, which led to a reduction in steam demands by the PCCplant regenerator from the NGCC plant. The implication here isthat using other method to enhance mass transfer, such as a rotat-ing packed bed application, should also result in reduced steamrequirements. Design of the steam cycle due to SF of the gas tur-bine exhaust was explored, and it was shown to improve poweroutput in proportion to the amount of additional natural gas thatis red.

Economic analysis of the plant located in Northern Englandis performed by generating construction costs from a bottom-upapproachandthe integrated plant overnight costis 58%higher thancost of the NGCC plant, discouraging the deployment of CCS. WithEGR,overnight costis 54%greater thanthe originalcost, while addi-tion of 2 kg/s SF of gas makesit 90%greater. Onthe other hand, LCOEis estimatedto increase by 30% forthe integrated plant,a value thatreduces to 26% with EGR, and then drops further to 24% with SF.In all cases, the cost of natural gas is the largest driver for LCOE.Finally, the cost of CO 2 avoided is determined to be D 51 per tonneof CO2 for the integrated plant, D 44 per tonne of CO 2 when EGR is considered, and D 43 per tonne of CO 2 with implementation of SF.

Acknowledgements

The authors would like to acknowledge the nancial supportfrom the Engineering and Physical Sciences Research Council UK(Ref.: EP/J020788/1).


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