in particular , power plants produce both electricity and co2 by combusting fossil fuels , which is one of the major sources 
 of total man made co2 emissions worldwide .
future forecasts for the economic growth in asia pacific and industrial 
 development in africa indicate that the total world energy demand 
 will increase from 462 quadrillion british thermal units ( btu ) in 
 2005 to over 695 quadrillion btu by 2030 .
the exponential rise in emissions of co2 from fossil 
 fuel utilization to around 30 gt per year will lead to significant 
 climate change unless the emissions are captured and stored .
developing clean and affordable energy with abundant supply is 
 an issue of international concern . until recently ,
the prime focus 
 of the research on power generation was on improving energy efficiency 
 and switching from fossil fuels toward less carbon intensive ( renewable ) 
 energy sources .
the renewable energy technologies can reduce co2 emissions but are still costly . even if they are made cost - competitive 
 in the next few years
, they will still need time to penetrate the 
 market . some researchers consider coal as the primary source of energy 
 at least for the next 56 decades since its supply will last 
 over 150 years compared with 5060 years for oil and natural 
 gas .
thus , there is a large international 
 research effort toward developing technologies to use coal in an environmentally 
 sustainable manner . in the recent years
, carbon capture and storage ( ccs ) has been 
 considered to offer  end - of - pipe  technologies that 
 can allow continuous use of fossil fuels with low or almost negligible 
 emissions . a review by boot - handford et al .
has comprehensively discussed the recent developments , challenges , 
 and potential future improvements in different types of ccs technologies . 

table 1 shows a summary of a number of studies 
 on selection of a promising ccs technology that can produce electricity 
 and , in some cases , h2 from fossil fuels .
for instance , 
 chiesa et al . compared different scenarios 
 considering co2 venting and co2 capture using 
 integrated gasification combined cycle ( igcc ) technology for the production 
 of h2 and electricity from coal .
physical absorption and 
 adsorption processes were assumed for co2 and h2 separation , respectively .
they concluded 
 that , with an emissions constraint , there are very small thermodynamic 
 benefits of coproduction relative to stand - alone electricity and h2 production
reviewed 
 various concepts including oxyfuel combustion , membrane separation , 
 physical absorption , and chemical absorption processes for electricity 
 and h2 production from coal and natural gas with ccs .
a 
 number of critical factors were identified and compared , including 
 efficiency , cost of energy ( coe ) , cost of h2 ( coh ) , and 
 co2 avoidance costs .
also assessed were the impact of fuel 
 prices on electricity and h2 production costs for pulverized 
 coal ( pc ) , natural gas combined combustion ( ngcc ) , and igcc plants . 

the analysis showed that with co2 capture , the net electrical 
 efficiencies are 3035% for pc , 3240% for igcc , and 
 4350% for ngcc power plants . also , both the chemical and physical 
 absorption processes can achieve 8590% co2 capture 
 efficiency with the precapture technologies being more suitable for 
 igcc plants .
cormos describes the methodology 
 to evaluate the performance of a coproduction ( electricity and h2 ) igcc power plant with physical absorption ( selexol)-based 
 co2 capture technology .
the study examined the effect of 
 using different feed stocks such as coal , sawdust , municipal solid 
 waste , and food waste ( meat and bone ) on the power output .
later , 
 cormos compared different types of gasifiers 
 using only coal as fuel and investigated the energy integration aspects 
 in detail to optimize the overall plant efficiency of a coproduction 
 igcc plant with ccs .
the study concludes that an entrained flow gasifier 
 with dry feed and syngas heat recovery is a more promising concept 
 than slurry feed and water quench design .
further work by cormos presented a detailed methodology to assess the 
 performance of an iron - based clc system using critical design factors 
 such as gasifier selection , gasifier feeding system , and overall energy 
 efficiency .
this work suggested that a clc - based system has a low 
 energy penalty compared to liquid absorption process for co2 capture .
li and fan addressed the energy conversion 
 efficiencies for the chemical looping based coal conversion process . 

their study shows that efficiencies of syngas chemical looping process 
 is comparable with the current coal conversion processes for electricity 
 and h2 generation and could be considered as a retrofit 
 technology in the downstream of the present gasification processes . 

on the other hand , they found that coal direct chemical looping combustion 
 ( cdclc ) process is more energy efficient than coal gasification based 
 clc process .
in addition to the investigations on energy efficiency , there are 
 a few studies on the exergetic efficiency of various co2 capture technologies with combined electricity and h2 production .
exergy analysis combines the first and second laws of 
 thermodynamics to identify the irreversibility and losses related 
 to each unit or process of a system .
for instance , kunze , et al . presented the exergy analysis of an igcc process 
 by dividing the plant into three sections , the gasifier , gas treatment , 
 and combined cycle .
the analysis shows that 60% of the exergy is lost 
 in the overall process ; out of which , 31.1% is lost only in the combined 
 cycle section , making it the most inefficient part of the process , 
 followed by 17.1% in gas treating and 11.3% in the gasifier .
further , anheden and svedberg showed the exergy analysis of clc system with 
 different fuels and oxygen carriers ( ocs ) .
their results indicate 
 that efficiency of a clc system is similar or higher than that of 
 a conventional combustion process .
while the existing studies have provided useful evaluation of a 
 range of power ( and in some cases h2 ) generation schemes 
 with or without ccs , their assumptions and considerations vary with 
 respect to factors such as feedstock , power generation technology , 
 ccs technology , production scale , and modeling approaches adopted , 
 making it difficult to compare their results . to address this deficiency , 

our work uses a single basis of analysis in terms of the feedstock 
 type , production scale , and modeling assumptions .
this makes it easier 
 and more straightforward to compare various gasification - coupled coal 
 power plants with and without the ccs producing electricity and possibly 
 h2 .
this work provides a methodology to assess different 
 co2 capture technologies based on mainly energy , exergy , 
 and co2 capture efficiencies .
the processes evaluated here 
 include ( i ) igcc for power generation without ccs , ( ii ) igcc for power 
 ( and h2 ) generation with two different precombustion ccs 
 options based on physical absorption and adsorption , and ( iii ) power 
 ( and h2 ) generation with clc .
comparison is also made on 
 the basis of the effect of asu and gt unit integration for each of 
 the three capture technologies .
the effect of different operating 
 conditions such as air reactor temperature and water cooling of the 
 air reactor in the clc process on the net electrical efficiency is 
 another distinct feature of the present work .
the findings of this 
 work evaluate the suitability of physical absorption , physical adsorption , 
 and clc based co2 capture technologies for coal power plants 
 by indicating the differences in overall plant performance with each 
 type of capture technology .
this article also predicts the behavior 
 of the clc process at different operating conditions ( as stated above ) , 
 which can be useful in pilot scale experimental studies .
a literature review of advanced ccs technologies has been first 
 carried out to gather information on technical inputs and parameters 
 such as the component flow rates , temperature , pressure , and efficiencies 
 for various units , required for process modeling .
the chemical process 
 simulation tool aspen plus , was used to develop the flowsheet models 
 for seven different coal gasification based power plant configurations 
 at a nominal power output of up to 467 mw . the electricity generation , 
 h2 production ,
co2 emission and other performance 
 indicators such as energy and exergy efficiencies are subsequently 
 analyzed .
seven different 
 types of coal gasification based power plant configurations , with 
 and without co2 capture , at a power output between 141 
 and 467 mw have been considered .
the chemical process simulation 
 tool aspen plus was used to develop and simulate a process flowsheet 
 for each case . the base case ( case 0 ) considered in this work
the flowsheets for cases 14 are conventional igcc process 
 with precombustion based co2 capture and cases 56 
 are gasification - coupled clc process for co2 capture .
cases 
 1 , 2 , and 5 generate electricity only while the cases 3 , 4 , and 6 
 produce both electricity and h2 .
a stand - alone asu generating 
 95% pure o2 has been used in all seven cases , followed 
 by an o2-blown entrained flow shell gasifier operating 
 at 30 atm , and fuel conversion ratio of 99.9% . the power consumption by the asu is assumed to be 225 kwh / tonne 
 of o2 produced .
the dry pulverized 
 coal ( 100 m in size ) is pressurized in a lock hopper and fed 
 to the gasifier vessel along with o2 from the top .
the 
 coal is partially oxidized by o2 in the gasifier to produce 
 syngas , which mainly consists of co and h2 .
the exothermic 
 nature of the partial oxidation reaction of coal inside the gasifier 
 provides the heat to achieve and maintain the desired temperature 
 of 1300 c which is above the melting point of ash .
the excess heat generated in the gasifier is 
 removed by the generation of high pressure ( hp ) steam .
the slag in 
 liquid form flows down the walls and comes out at the bottom with 
 syngas .
the syngas can be either quenched with water or cooled in 
 radiative and convective heat exchanger .
water quenching degrades the thermal energy of the hot syngas stream . 
 therefore , in our study , the syngas from the gasifier is cooled in 
 a heat exchanger , which allows production of hp steam .
this section describes the configuration of cases 
 1 to 4 , which use psa and selexol technologies for co2 capture . 

first , an igcc process producing only electricity with psa technology 
 for co2 capture ( case 1 ) , shown in figure 1a , was developed .
the detailed process flow diagram of case 
 1 can be seen in supporting information ( si ) figure s.1 . in this process ,
the hot syngas stream at 1300 
 c from the gasifier is cooled to 350 c in a convective 
 heat exchanger in the heat recovery steam generation ( hrsg ) unit where 
 hp water used for cooling is converted into a hp steam .
the cooled 
 syngas at 350 c is sent to two water  gas shift reactors 
 ( wgs-1 and wgs-2 ) aligned in series operating at temperatures 350 
 and 178 c , respectively .
the wgs-1 reactor is 
 supplied with steam at 30 atm and 350 c generated in the hrsg . 

the co in the syngas stream is partially converted to co2 by the steam in wgs-1 reactor generating more h2 in the 
 syngas .
the syngas and steam exiting the wgs-1 reactor at 350 c 
 are cooled to 178 c before both are fed to the wgs-2 reactor 
 where up to 98% of the remaining co is converted to co2 .
the heat released by the cooling of 
 syngas from 350 to 178 c is used for preheating the boiler feedwater 
 in the hrsg .
the conversion of co into co2 in the wgs reactors 
 is an exothermic process which needs continuous removal of the excess 
 heat to maintain the required reaction temperatures .
the syngas 
 exiting the wgs-2 reactor at 178 c is further cooled to 35 c 
 in the hrsg which condenses the steam and removes it before the syngas 
 is sent to an acid gas removal ( agr ) unit or a selexol unit to remove 
 sulfur ; here nearly 99.9% of the hydrogen sulphide ( h2s ) 
 is stripped from the syngas using selexol ( dimethyl ether of polyethylene 
 glycol ) . the sulfur removed from the 
 syngas in the form of h2s could be converted into elementary 
 sulfur in a claus plant .
the selexol 
 in the sulfur removal unit is regenerated by heating which removes 
 the dissolved sulfur and co2 . after removing sulfur ,
the 
 syngas stream is passed through the psa - co2 unit where 
 co2 is adsorbed by the adsorbent material ( activated carbon ) 
 and the remaining gases ( tail gas1 ; see figure 1a ) exits with a pressure drop of 0.49 atm .
the co2 separation efficiency of the psa unit is assumed 
 to be between 90% and 95% .
the adsorbent 
 material in the psa - co2 chamber is regenerated by lowering 
 the pressure to nearly atmospheric pressure level to release co2 .
case 1 does not produce any h2 , and therefore h2-rich tail gas-1 follows route ii ( as seen in figure 1a ) , which is then supplied to the combustor of the gt unit 
 after reheated to 350 c .
the high temperature exhaust gases 
 from the gt are cooled in the hrsg unit before it is finally released 
 to the atmosphere .
the syngas and flue gas stream temperatures for 
 case 1 are noted in si table s.1 .
the hp 
 steam generated at 600 c in the overall process ( gasifier , heat 
 exchangers , hrsg ) is expanded through the hp , intermediate pressure 
 ( ip ) and low pressure ( lp ) steam turbines .
the exhaust steam from 
 the hp and ip steam turbines are reheated to 600 c before further 
 expansion through the ip and lp turbines .
the details of water and 
 steam cycle as well as the temperature and mass flow rate of steam 
 and water for case 1 are provided in the si section s.1 and table s.2 , respectively .
simplified block flow diagrams of coal gasification - based power 
 plant : ( a ) igcc with psa based co2 capture technology ( cases 
 1 and 3 ) ; ( b ) igcc with selexol based co2 capture ( cases 
 2 and 4 ) ; ( c ) gasification - coupled clc based co2 capture 
 producing electricity only ( case 5 ) ; ( d ) gasification - coupled clc 
 based co2 capture producing combined electricity and h2 ( case 6 ) .
case 2 , which uses a selexol - based physical absorption co2 capture unit ( also known as acid gas removal or agr unit ) instead 
 of a psa - co2 unit after sulfur removal , is shown in figure 1b . in this process
, the outgoing gas stream from 
 the sulfur removal unit , containing mainly co2 and h2 , is passed through the agr - co2 unit which separates 
 co2 from rest of the gases .
the selexol is regenerated 
 by reducing the pressure to atmospheric level which releases the absorbed 
 co2 .
the co2 is 
 then compressed to up to 150 atm after condensing any vapor present 
 in the stream .
after co2 removal , the remaining gases ( tail 
 gas-1 ) are used in the gt unit as in case 1 , following route ii .
case 3 , which is shown in figure 1a , is 
 a variant of case 1 , with combined electricity and h2 production . 

the stream from psa - co2 enters psa - h2 installed 
 for h2 separation , following route i instead of route ii . 

a 99.99% pure stream of h2 exits the psa - h2 unit 
 after 0.49 atm of pressure drop . the separation 
 efficiency for h2 in the psa - h2 unit is assumed 
 to be 85% .
the output h2 stream is compressed 
 to 60 atm for transportation and storage . the leftover gas ( tail gas-2 ) after h2 separation leaves 
 psa - h2 at nearly atmospheric pressure ; hence , it needs 
 to be compressed to the gt combustor pressure ( 21 atm ) .
if more electrical 
 energy is required , some amount of separated pure h2 can 
 be purged to the gt combustor according to the requirement .
the 
 high temperature gt exhaust is passed through the hrsg to produce 
 hp steam and for steam reheating .
case 4 , shown in figure 1b , has an agr - co2 unit for co2 removal instead of a psa - co2 unit used in case 3 .
apart 
 from this difference , the rest of the downstream path after co2 removal is same as described above for case 3 , which is following 
 route i instead of route ii .
a clc process 
 is based on transferring oxygen to the fuel from air or steam by means 
 of a oc .
an oc could be made of metal or synthetic material that is 
 capable of carrying oxygen and has excellent mechanical properties 
 to withstand attrition , agglomeration and physical stress of recycling 
 at high temperatures .
this work assumes hematite ( fe2o3 ) as the oc , supported with 15% aluminum oxide ( al2o3 ) and 15% silicon carbide ( sic ) to enhance its mechanical 
 and physical properties .
parts c and 
 d of figure 1 show the block diagram of cases 
 5 and 6 , respectively . in cases 5 and 6 ,
the syngas from the coal 
 gasifier is cooled to 35 c in hrsg and supplied to a selexol 
 based sulfur removal unit .
the syngas is then sent to a fluidized 
 bed fuel reactor of the clc process ( after reheated to 350 c ) 
 represented by two fuel reactors , fr 1 and fr 2 ( see figure 1c , d ) . in the fuel 
 reactors , h2 and co
the fe2o3 is first partially reduced to magnetite 
 ( fe3o4 ) in fr 1 and then completely reduced 
 to wustite ( fe0.947o ) in fr 2 , as shown in figure 1c and d. a cyclone separator 
 removes the reduced oc particles from the hot gases coming out of 
 the fr 2 .
these hot gases are cooled in a hrsg unit to condense the 
 water vapor and produce a pure stream of co2 , which is 
 compressed to 150 atm for storage . the sensible heat lost by the hot 
 gases from the clc fuel reactor
is used to generate hp steam and for 
 steam reheating . in case 5 ,
the reduced oc particles ( fe0.947o ) are fully regenerated to fe2o3 in the air 
 reactor where they are oxidized by pressurized air , which also helps 
 in circulation of oc in the system .
the air reactor is maintained 
 at 1300 c by supplying excess air than usually required for 
 oc regeneration .
the hot pressurized 
 air exiting the air reactor is separated from the oc particles in 
 a cyclone separator and expanded in an air turbine .
the air turbine exhaust 
 has a high temperature and , therefore , is sent to the hrsg unit for 
 heat recovery before released to the atmosphere .
the steam generated 
 in the whole process ( i.e. , gasifier , clc reactors , hrsg and other 
 heat exchangers ) is used to drive the hp , ip , and lp steam turbines . 

as in cases without clc , the exhaust steam from the hp and ip steam 
 turbines is reheated in the hrsg unit to 600 c before expanding 
 through ip and lp steam turbines . in case 6 ,
the reduced oc 
 from the fuel reactors is partially oxidized to fe3o4 in the steam reactor using steam at 30 atm and 350 c 
 generated in the hrsg unit .
this oxidation reaction of the oc is an 
 exothermic process that generates h2 , which with some steam 
 and oc particles comes out from the exhaust of the steam reactor maintained 
 at 550 c through hp water / steam cooling .
the oc particles are 
 separated from the steam and h2 in a cyclone separator 
 and sent for complete oxidation to fe2o3 by 
 compressed air ( which is again an exothermic reaction ) in an air reactor 
 ( see figure 1d ) . the hot mixture of h2 and steam after oc separation is cooled in hrsg unit that causes 
 the steam to condense , generating a pure stream of pressurized h2 for further compression to 60 atm and storage .
the hot pressurized 
 air from the air reactor is expanded in an air turbine and then supplied 
 to the hrsg unit before it is finally released to the atmosphere . 

equations 1 to 7 represent 
 the reactions taking place inside the reactors of a clc process using 
 an iron based oc . the key modeling information and choices used in the simulations 
 are shown in tables 3 and 4 .
table 3 shows the physical and chemical 
 properties of illinois # 6 type coal used as fuel in all the cases . 

the 
 databanks selected for aspen plus simulations are combust , inorganic , 
 solids , and pure22 .
coal 
 and ash used in the simulation models are considered as nonconventional 
 components ; therefore , information about their physical and chemical 
 properties is needed .
the property methods used for coal and ash are 
 hcoalgen and dcoaligt , respectively .
the 
 oc and support materials are entered as solid in the component input 
 data in aspen plus .
the barin equation is used to calculate the physical 
 properties of the solid compounds .
the 
 model retrieves the cpsxp ( a  h ) coefficients from the inorganic 
 databank of aspen . the key conditions and input parameters of each process unit such 
 as gasifier , asu , turbines , and reactors are presented in table 4 . in all the seven processes studied in this work , 
 the raw syngas is produced in a conventional gasification process 
 represented by a ryiled decomposer and a rgibbs gasifier unit .
four - stage adiabatic compressors represented by the mcompr 
 model in aspen plus , are used for gas compression .
these compressors 
 need the discharge pressure from the final stage and isentropic efficiency 
 as the input to the aspen plus model .
the aspen plus pump models with 
 an isentropic efficiency of 90% have been used to simulate pressurization 
 of the water needed for steam generation . for heat recovery steam 
 generation ( hrsg ) , mheatx type counter current heat exchangers are 
 used .
the built - in aspen plus reactor models ryield and rgibbs are used 
 to design different reactive processes including ( i ) gasification , 
 ( ii ) wgs reaction , ( iii ) oxidation of fuel in fuel reactor , and ( iv ) 
 oc regeneration in steam and air reactor .
a dry feed type entrained 
 flow shell gasifier is considered in this work due to its dominance 
 in the commercial igcc plant designs .
an ryield reactor block is used 
 to decompose the pulverized coal powder into its conventional constituent 
 elements and also calculates the heat required for it .
the conventional 
 elements provided after decomposition of coal are fed to the rgibbs 
 reactor block , which determines the possible products and their composition 
 at equilibrium conditions .
the rgibbs reactor is an equilibrium based 
 reactor , which restricts individual equations to equilibrium and does 
 not take account of the reaction kinetics .
this type of reactor considers 
 all the components as possible products , which is useful when there 
 are many reactions between several components and the reaction kinetics 
 is unknown .
the operating temperature , pressure and o2 to 
 coal ratio are the key parameters required as input to the rgibbs 
 reactor .
these reactors are supplied 
 with hot syngas and steam at 30 atm at 350 and 178 c , respectively . 

a wgs reactor is modeled by using a requil block , which is an equilibrium 
 based reactor in aspen plus .
this block is useful when there are few 
 reactions and the reaction kinetics is unknown .
the temperature , 
 pressure , and the chemical reaction equations are the key parameters 
 required as input to a requil reactor .
the reactants 
 and products of the clc fuel reactors are assumed to be well - mixed . 

simple rgibbs reactor blocks of aspen plus are used for the simulation 
 of the clc fuel oxidization process under equilibrium conditions . 

the operating temperature , pressure , and molar flow of oc particles 
 and syngas are the key input parameters required for this model .
the reactions 
 taking place inside the fuel reactors are endothermic and require 
 heat , which is provided by high temperature oc particles ( fe2o3 ) supplied from the air reactor .
the steam 
 reactor of a clc system uses steam to partially oxidize the reduced 
 oc particles to fe3o4 while generating h2 as a product at thermodynamic equilibrium .
the h2 yield of the steam reactor is directly proportional to the oc conversion . 

the steam reactor was modeled in aspen plus by using a single rgibbs 
 reactor block .
the key operating parameters used for modeling the 
 steam reactor are operating temperature , pressure and molar flow ratio 
 between steam and oc .
the air reactor effected complete oxidization 
 of the reduced oc particles to fe2o3 and was 
 modeled as an entrained bed reactor with air and oc particles flowing 
 cocurrently through the vessel .
the combustor model , operating at 
 a constant temperature and pressure , was used to predict the excess 
 heat produced and the possible products .
all of the combustion reactions 
 are assumed to be fully completed in the combustor and this was sufficiently 
 modeled using a rgibbs model .
the ratio between oc and air supplied 
 and the operating temperature are the key variables for the air reactor 
 model .
all 
 cases were evaluated from both the energy and exergy point of view . 

the assessment of the overall performance of all the processes was 
 performed using streamflow data , for example , mass flow of the components , 
 pressure , temperature , power , and energy output provided by the simulation 
 of each process configuration .
gross electrical efficiency ( gross ) indicates the overall electricity produced by the steam 
 and gas turbines used in the process .
it does not consider the energy 
 consumed by the auxiliary elements needed to run the plant and can 
 be calculated using eq 8.8 net electrical efficiency ( net ) shows the actual electrical power produced by the system .
this 
 is calculated by deducting all the auxiliary energy consumed from 
 the gross electricity produced , as shown in eq 9.9 h2 energy efficiency ( h2 ) applies to cases 3 , 4 , and 6 which produce both h2 and 
 electricity .
the term indicates the efficiency of the system in producing 
 h2 from the coal feed .
the thermal energy of h2 is used to calculate h2 efficiency , as shown by eq 10.10 overall energy efficiency ( overall ) for cases 
 1 , 2 , and 5 producing only electricity is the same as the net electrical 
 efficiency shown by eq 9 . for the cases 3 , 4 , 
 and 6 ,
overall is calculated by adding both electrical 
 and h2 energy efficiency as shown by eq 11.11 specific co2 emission ( seco2 ) 
 gives the amount of co2 released to the atmosphere by the 
 system for per mw of energy generated , which is equal to the net electrical 
 energy output for cases producing only net electricity , and electrical 
 plus thermal energy of h2 for cases with coproduction . 

seco2 is calculated by eq 12.12 exergy is the maximum 
 work that can be extracted from a system interacting with a reference 
 environment , which is taken as 1 atm and 25 c for this study . for a process stream , its exergy can be divided 
 into two parts ( physical and chemical ) .
physical exergy ( exph ) equals to the maximum reversible amount of work 
 obtainable when a stream of substance is brought from its actual state 
 to the environmental state .
the physical processes involve only thermal 
 and mechanical interaction with the environment which is defined by 
 pressure p0 and temperature t0 , respectively .
assuming that potential and kinetic energy can 
 be neglected , the physical exergy is expressed by eq 13:13where h and s are specific molar enthalpy ( kj / kmol ) and specific molar entropy 
 ( kj / kmol k ) , respectively ; h0 and s0 are the values of h and s at standard conditions ( t0 , p0 ) . chemical exergy ( exch ) of a substance is the maximum 
 amount of work obtainable by bringing it from the environmental state 
 ( t0 , p0 ) to 
 a full equilibrium with the chosen environment .
the molar chemical 
 exergy of an ideal mixture is expressed by eq 14 as14where xi and exchi are molar fraction and molar chemical exergy 
 ( kj / kmol ) , respectively , of each component in the mixture , and r is the universal gas constant .
exergy loss ( exloss ) of each individual unit can be 
 calculated by finding the difference between the exergy of input and 
 output streams of this unit:15 total exergy ( extotal ) of stream is 
 taken as the sum of its physical and chemical exergy:16 chemical exergy of coal ( excoal ) : in calculation of 
 the total exergy of coal , its physical exergy is considered to be 
 zero , because the input coal feed is in the physical equilibrium with 
 the environment .
these equations 
 are only applicable when the oxygen to carbon ratio in the given coal 
 feed is less than 0.667.17 cv is the net calorific value of illinois # 6 type coal in kj / kg , w is the percentage of moisture content in the coal , hfg is the latent heat of water in kj / kg at temperature , to , and s denotes the mass fraction 
 of sulfur in the fuel .
the term dry is be calculated 
 by using the eq 18.18where c , h , o , and n represents the mass 
 fractions of carbon , hydrogen , oxygen , and nitrogen in the coal feed , 
 respectively .
h2 exergy efficiency ( exh2 ) is taken as the ratio of the total exergy content in h2 product to the chemical exergy of the coal feed:19 exergy efficiency ( ex ) of a system is the ratio 
 of total exergy output to the total exergy given to the system .
for 
 the cases considered in this study , the total exergy output is the 
 sum of electrical work output and chemical exergy of h2 stream produced in the process whereas the chemical exergy of the 
 coal feed is taken as the exergy input to the system , as shown in 
 eqs 20 and 21:2021
the net electrical efficiency and co2 captured shown in 
 tables 5 and 6 are the 
 two main investigated parameters , which are discussed in this section 
 to compare clc , psa , and selexol based capture technologies .
the simulation 
 results of the clc process that produces only electricity ( case 5 ) 
 give an overall electrical efficiency of 38.7% , which is close to 
 what is observed by a previous study .
the psa ( case 1 ) and selexol ( case 2 ) based processes showed an 
 overall electrical efficiency of 37.4 and 36.4% , respectively , which 
 is lower than case 5 . the electrical efficiency achieved for case 
 5
is also found to be substantially higher as compared with amine - based 
 postcombustion capture technology , which has efficiency between 26.7 
 and 35.3% .
the overall co2 capture efficiency of the clc process is 99.9% compared with 89.9% 
 for psa and 93.5% for selexol processes .
this lower overall capture 
 efficiency of psa and selexol process is mainly due to the following 
 reasons : ( i ) the 98% co conversion efficiency of wgs reactors compared 
 to 99.99% conversion in the clc fuel reactor and ( ii ) 90.3% co2 capture efficiency for the psa and 95.0% for selexol units , 
 compared to the assumed complete capture by clc .
the unconverted co 
 from the wgs reactor is oxidized in a combustor after the co2 removal step in the presence of air to produce co2 .
this 
 co2 along with the uncaptured co2 from the co2 removal unit is expanded in a gt before it is finally vented 
 to the atmosphere with the other flue gases .
figure 2a shows the variation in electricity 
 production and carbon emissions for all the three different co2 capture cases with electricity production only .
compared 
 with the clc process ( case 5 ) that emits 0.0006 t / mwh of co2 at an emission rate of 0.28 t / h , the psa ( case 1 ) and selexol ( case 
 2 ) technologies emit 0.079 and 0.051 t / mwh of co2 at an 
 emission rate of 33.6 and 21.1 t / h , respectively .
figure 2b shows a comparison between cases 0 , 1 , 2 , and 
 5 for gross power output , power consumption , and net power produced . 

clc process ( case 5 ) produces less power from the gt unit , but it 
 generates more power from the steam turbines , which results in more 
 net electricity production ( 436.9 mw ) compared with case 1 ( 421.1 
 mw ) and case 2 ( 409.6 mw ) .
( a ) relation between electricity production and co2 emissions 
 for cases 0 , 1 , 2 , and 5 and ( b ) relation between power production , 
 power consumption and net power output for cases 0 , 1 , 2 , and 5 .
table 5 shows the results 
 of case 0 , which is taken as a base case that produces only electricity 
 without any co2 capture . in case 0 ,
the syngas stream from 
 the wgs reactors is supplied to the combustor unit eliminating the 
 co2 scrubbing step .
the unconverted co , and h2 from the wgs reactor unit are oxidized in the combustor in the presence 
 of air .
the product stream from the combustor is expanded through 
 the gt and sent to hrsg before it is finally vented to the atmosphere . 

the base case has a higher net electrical efficiency of 41.4% compared 
 to the other cases ( cases 1 , 2 , and 5 ) , which produce only electricity 
 with co2 capture .
figure 3 shows 
 that case 2 using the selexol process suffers the highest net energy 
 penalty of 57.2 mw versus case 0 compared to 29.9 mw for clc and 45.7 
 mw for psa - based processes .
the results from table 6 indicate that per mw decrease in energy production compared 
 to the base case , the clc process captures significantly higher co2 ( 9.3 t / h ) compared to psa ( 5.3t / h ) and selexol ( 4.5 t / h ) 
 process .
the relative decrease in the net electrical efficiency in 
 comparison to base case ( case 0 ) for precombustion based capture processes 
 ( case 1 and 2 ) is lower than the energy penalty of 2029% for 
 the amine based postcombustion capture methods described in a report 
 of the iea .
energy and efficiency penalty in cases 1 , 2 , and 5 with reference 
 to the case 0 .
table 7 shows 
 the energy consumption in co2 compression work for psa , 
 selexol and clc processes .
it can be seen that the clc process ( case 
 5 ) requires only 10.2 mw for compressing 278 t / h of co2 whereas the igcc with psa ( case1 ) and igcc with selexol ( case 2 ) 
 processes require 26.3 mw and 29.9 mw , respectively , even though they 
 compress less co2 compared to the clc .
this is due to the 
 fact that the co2 stream available for compression in this 
 clc process is already at elevated pressure levels of approximately 
 30 atm , and therefore , less energy is required for compressing co2 to 150 atm . on the other hand ,
the co2 streams 
 available for compression in the cases of the psa and selexol processes 
 are very close to atmospheric pressure , which explains the higher 
 compression energy requirement for these two technologies .
further 
 analysis can be made to consider the co2 stream being produced 
 from the system at a pressure of 1 atm . for cases 1 and 2
, this would 
 mean that the co2 compression step is eliminated . in case 
 5
, this analysis assumes that the pressurized ( 30 atm ) co2 stream from the fuel reactor is expanded in an expander , which will 
 produce an extra 5.11 mw of power . as shown in table 7 , the clc process will still be more energy efficient than 
 the selexol and psa processes and attain a net electrical efficiency 
 of 40.0% .
some consider that this analysis could be useful if the 
 co2 captured from the power plant were to be used in other 
 industries , instead of sequestration .
for example , the food and chemical 
 sectors may have no need for compressed co2 .
however , very 
 few processes other than enhanced oil recovery ( eor ) and potentially 
 the production of urea are likely to be able to utilize a significant 
 fraction of the co2 produced by a gasifier producing 467 
 mwe .
one of the main objectives of this work was to investigate the suitability 
 of the gasification - coupled clc process ( case 6 ) compared to igcc 
 with psa ( case 3 ) and selexol ( case 4 ) technologies for combined electricity 
 and h2 generating plants .
table 8 summaries the results of these cases for identical h2 production rates ( 524 mw ) from each process .
case 6 with clc yields 
 an overall energy efficiency ( 59.4% ) , which is marginally higher than 
 case 4 selexol ( 59.1% ) .
case 6 has a lower overall efficiency compared 
 to the case 3 psa ( 60.0% ) process owing to two main reasons : ( i ) lower 
 gt inlet temperature of 727 c compared to 1185 c for case 
 3 and ( ii ) higher power consumption by the air compressor in air reactor .
figure 4 shows the trade - off between the 
 electrical , h2 and overall efficiencies for case 6 .
the 
 overall efficiency increases with the h2 production rate 
 whereas the electrical efficiency shows an opposite trend .
the decrease 
 in electrical power is the result of less h2 being available 
 for combustion in the gt combustor unit .
the h2 produced 
 in the steam reactor of the clc system can be used for electricity 
 generation during periods of high electricity demand by simply burning 
 it in a separate combustor and expanding through the gt along with 
 the hot air reactor exhaust .
variation of electrical , h2 , and overall efficiency 
 versus the h2 output for case 6 .
tables 5 and 8 show 
 the results of exergy analysis for all the seven cases .
the study 
 indicates an overall exergetic efficiency of 53.6% for case 3 with 
 the psa process producing combined electricity and h2 , 
 which is the highest among all the seven cases analyzed here .
the 
 other two cases for electricity and h2 production using 
 selexol ( case 4 ) and clc ( case 6 ) process have exergetic efficiencies 
 of 52.7 and 53.0% , respectively .
the exergetic efficiency of clc process 
 is higher compared to selexol and psa processes in cases with electricity 
 production only .
it is also seen that the captured co2 stream 
 contains 7.510.2% of the total chemical exergy of the coal 
 used as the fuel to the system .
if this exergy of the captured co2 stream is considered to recognize the effort dedicated to 
 co2 capture , it would make the clc process more exergetically 
 efficient among the cases with combined h2 and electricity 
 production .
all the configurations with co2 capture , represented by cases 16 , assumed that n2 from the asu is added to the feed to the gt unit to enhance 
 its power output .
the n2 stream produced in the asu is 
 compressed ( 22 atm for the cases without clc process and 32 atm for 
 clc ) and supplied to the combustors ( in cases without clc ) and to 
 the air reactors ( in cases with clc ) eventually for expansion through 
 the gt / air turbine .
figure 5 shows that all 
 the processes benefit , in terms of their power output , from the integration 
 of asu with the gt unit . the gasification - coupled clc process ( cases 
 5 and 6 ) is least effected by asu integration .
in contrast , case 1 
 experiences 4.7% increase in the net electrical efficiency which is 
 the highest among all six cases .
the results show that integrating 
 n2 stream with the gt cycle can improve the overall electrical 
 efficiency of the process despite the extra work required for n2 compression .
potentially , further integration can be done to use the air from 
 the more efficient compressor of the gt power cycle to supply compressed 
 air to the asu .
the main limitation of 
 such integration is that the asu can not start unless the gt starts 
 running .
this problem can be resolved by using a separate air compressor 
 for the asu to start up the process . with the model of gasification - coupled 
 clc ( case 5 ) , the effect of change in air reactor temperature on the 
 net electric power produced has been analyzed .
figure 6a shows that the net power production increases with the air 
 reactor temperature .
the power is produced in the gt unit , which is 
 supplied with hot exhaust from the air reactor , and in the steam turbine 
 unit .
steam is generated by the hrsg unit which recovers heat from 
 the hot exhaust of the fuel reactor and that of the gas turbine .
the 
 air reactor regulates its temperature via the amount of excess air 
 supplied to the reactor beyond what is required by complete combustion . 

figure 6a shows that as the temperature of 
 the air reactor increases , both the power from the stream turbine 
 unit and that from the gt unit increase .
effect of ( a ) air reactor temperature and ( b ) water - cooling of 
 the air reactor on the power output for clc process .
the exhaust gases from the air reactor are expanded through the 
 gt , which gives a higher yield when operated at a higher temperature 
 range .
this provides the explanation behind the increase in gt power 
 output with air reactor temperature . when the air reactor is maintained 
 at higher temperature , the temperature of oc supplied to the fuel 
 reactor from the air reactor is also high and hence is higher the 
 fuel reactor temperature .
this means a high temperature fuel reactor 
 exhaust is available in the hrsg for steam generation , explaining 
 the reason behind the gain in steam turbine power output with increase 
 in air reactor temperature .
the clc system ( case 5 ) was examined 
 for the effects of using water - cooling of the air reactor instead 
 of excess air supply as an alternative to maintain the required temperature 
 of 1300 c throughout the study .
the hp water after absorbing 
 heat from the air reactor is converted into hp steam , which is used 
 for power generation .
it has been found from the sensitivity analysis 
 that an excess air supply of 81.14% can maintain the desired air reactor 
 temperature without requiring any cooling by water .
figure 6b indicates that the use of water - cooling results 
 in decrease in the feed to the gt , gross , and net power output of 
 the system , whereas the steam turbine output power increase due to 
 more steam available for the steam turbines . completely using water / steam 
 cooling for
however , this can help in reducing the size of the air reactor , compressor , 
 gas  solid separator , and gt , and hence , the capital cost of 
 the plant .
this article investigates the performance characteristics of seven 
 different types of gasification based coal power plants with and without 
 the co2 capture using psa , selexol and clc processes .
cases 
 0 , 1 , 2 , and 5 produced only electricity while cases 3 , 4 , and 6 produced 
 combined electricity and h2 .
the results generated from the flowsheet simulation 
 models were compared based on the electrical efficiency , h2 production , and co2 emissions .
the effect of asu and 
 gt integration on the performance of all co2 capture cases 
 was estimated .
sensitivity analysis was performed for the clc process 
 to study the plant behavior with respect to air reactor temperature 
 and water cooling of the air reactor . among the systems producing only electricity with co2 capture
, the clc based process achieves the highest electrical efficiency 
 ( 38.7% ) compared with psa ( 37.4% ) and selexol ( 36.4% ) based processes . 
 in electricity and h2 cogeneration cases ,
the clc - based 
 process has marginally lower ( by 0.6% ) and higher ( by 0.3% ) net electrical 
 efficiencies than the psa and selexol based process , respectively
. 
 however , clc process can capture 99.9% of co2 produced , 
 which is potentially higher in comparison to 89.9% for psa and 93.5% 
 for selexol based processes .
further comparison among the three capture 
 processes could also be made , based on the cost and life cycle analysis 
 in order to assess the combined techno - economic viability , but such 
 a comparison is beyond the scope of our present study .
the asu and 
 gt integration results in higher power output for all the cases ; however , 
 the cases with clc process have the least effect .
the sensitivity 
 analyses performed on clc process shows that it is favorable to operate 
 the air reactor at higher temperatures for more net power output . 

also it has been concluded that cooling of air reactor ( while maintaining 
 1300 c ) by using excess air supply instead of pressurized water 
 tends to increase the net power output of the clc system .
in addition to the factors considered in the current work , a number 
 of potential improvements will be studied in future investigations . 

these include extracting and utilizing the heat released by the intercooled 
 compressors , and replacing the cryogenic asu with membrane - based technology , 
 which can possibly be more efficient when integrated with the gt unit . 
 a detailed sensitivity analysis of the three capture technologies 
 at all different possible operating conditions will be considered 
 in future work to further study and understand the plant behavior 
 in order to assist the optimization of power plants .
the clc process 
 has comparatively more scope of efficiency improvement in future by 
 directly using the solid coal fuel into the fuel reactor , eliminating 
 a separate gasification and asu , which are responsible for high exergy 
 losses in the system .
 seven different types of gasification - based coal conversion processes 
 for producing mainly electricity and in some cases hydrogen ( h2 ) , with and without carbon dioxide ( co2 ) capture , 
 were compared on a consistent basis through simulation studies . 
 the 
 flowsheet for each process was developed in a chemical process simulation 
 tool  aspen plus  . 
 the pressure swing adsorption ( psa ) , 
 physical absorption ( selexol ) , and chemical looping combustion ( clc ) 
 technologies were separately analyzed for processes with co2 capture . 
 the performances of the above three capture technologies 
 were compared with respect to energetic and exergetic efficiencies , 
 and the level of co2 emission . the effect of air separation 
 unit ( asu ) and gas turbine ( gt ) integration on the power output of 
 all the co2 capture cases is assessed . 
 sensitivity analysis 
 was carried out for the clc process ( electricity - only case ) to examine 
 the effect of temperature and water - cooling of the air reactor on 
 the overall efficiency of the process . 
 the results show that , when 
 only electricity production in considered , the case using clc technology 
 has an electrical efficiency 1.3% and 2.3% higher than the psa and 
 selexol based cases , respectively . 
 the clc based process achieves 
 an overall co2 capture efficiency of 99.9% in contrast 
 to 89.9% for psa and 93.5% for selexol based processes . 
 the overall 
 efficiency of the clc case for combined electricity and h2 production is marginally higher ( by 0.3% ) than selexol and lower 
 ( by 0.6% ) than psa cases . 
 the integration between the asu and gt units 
 benefits all three technologies in terms of electrical efficiency . 
 
 furthermore , our results suggest that it is favorable to operate the 
 air reactor of the clc process at higher temperatures with excess 
 air supply in order to achieve higher power efficiency . 
Introduction
Methodology
Results and Discussions
Summary and Conclusions