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Energy 36 (2011) 6559e6566

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Energy

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Technoeconomic assessment of China’s indirect coal liquefaction projects withdifferent CO2 capture alternatives

Wenji Zhoua, Bing Zhua,b,*, Dingjiang Chena, Fangxian Zhaoa, Weiyang Feia

aDepartment of Chemical Engineering, Tsinghua University, Beijing 100084, Chinab International Institute for Applied Systems Analysis, Schlossplatz 1, A-2361 Laxenburg, Austria

a r t i c l e i n f o

Article history:Received 22 June 2011Received in revised form30 August 2011Accepted 4 September 2011Available online 1 October 2011

Keywords:ICL (Indirect coal liquefaction)CO2 captureTechnoeconomic assessment

* Corresponding author. Department of Chemical Esity, Beijing 100084, China. Tel./fax: þ86 10 62782520

E-mail address: bingzhu@tsinghua.edu.cn (B. Zhu)1 CtL (Coal to liquid) refers to the technologies th

liquid or gaseous fuels, and ICL (indirect coal liquefac2 Indirect coal liquefaction involves the production

conversion with an intermediate step involving synthgasification. ICL technology is less mature than direct

0360-5442/$ e see front matter � 2011 Elsevier Ltd.doi:10.1016/j.energy.2011.09.007

a b s t r a c t

ICL (Indirect coal liquefaction), an alternative fuel-supplying technology, has drawn much attention andcaused considerable debate in China’s energy sector. The hurdles to its development include the high riskof investment into large-scale installations, the high CO2 emissions and water resource consumption. Acomprehensive assessment of ICL is urgently needed. This study provides an economic assessment anda technical analysis based on process simulations. To address the future challenge of curbing CO2

emissions, three absorption methods are compared for capturing the CO2 released from the ICL process:DMC (a novel absorbent), MEA and Rectisol. The comparative results suggest that physical absorbents,represented by Rectisol and DMC, have a remarkable advantage over chemical absorption processes,represented by MEA. The Rectisol process costs the least, while the DMC process is close to the samelevel. As a novel absorbent, DMC has the potential to be widely used in the future. The economic analysisof ICL predicted a high capital cost of over 35 billion yuan and an overall product cost of approximately3800 yuan/ton for the baseline. In addition, via a sensitivity analysis, coal price, electricity price andcapacity factor were identified as the three most influential factors affecting the overall product cost.

� 2011 Elsevier Ltd. All rights reserved.

1. Introduction

CtL (Coal-to-liquid) technologies1 are drawingmuch attention inChina’s industrial sector at present, mainly because of energysecurity concerns, i.e., the coal-dependant energy reservesendowment and the high price of imported oil. Moreover, the ever-increasing dependence on imported oil exacerbates this anxiety. In2007, theNDRC (ChinaNational Development&ReformCommittee)published a long-termplan for coal chemical industry development,claiming that China intended to achieve an annual CtL productioncapacity of 30 million tons by the year 2020 [1]. In this regard, thelocal governments showed even more aggressive ambitions.According to an informal estimation from the NDRC [2], the aggre-gate capacity of CtL projects planned by China’s local governmentsand enterprises, most of which are ICL (indirect coal liquefaction)2

ngineering, Tsinghua Univer-..at can convert coal into anytion) is one such technology.of fuels via FischereTropschesis gas production from coalcoal liquefaction technology.

All rights reserved.

projects, reached as high as 40 million tons by the end of 2009,presenting a trend that goes far beyond a reasonable level ofdevelopment.

This trend has raised much debate on several fronts. First,China’s ICL technologies are still in the R&D stage and have notachieved complete commercial maturity. Though several func-tioning demo projects have reported positive results for some keyprojects, such as the catalysts and the reactors for FeT (Fischere-Tropsch) synthesis, their stabilities and performances need to befurther approved through scale-up. The costs, particularly theamount of capital investment, should be decreased as well. Second,ICL projects are characterized by high CO2 emissions. This issue isnot being adequately addressed because the associated carbonpenalties on CO2 emissions have not yet been imposed on China’senterprises. Third, the operation of ICL plants requires considerablewater resources, which are always in short supply and become thebottleneck of regional development in those regions with abundantcoal reserves. These weaknesses will inevitably hinder the wide-spread use of ICL in China.

Planning a sound development roadmap for ICL requires a broadand comprehensive assessment; technoeconomic analysis is anessential part of this process. More importantly, the role of CO2capture in ICL development has to be taken into considerationbecause of climate change; moreover, the status of international

W. Zhou et al. / Energy 36 (2011) 6559e65666560

climate change negotiations is still ambiguous. Previous researchemphasized conceptual designs and performance analyses of coal-based coproduction or polygeneration systems [3e6], withoutproviding a detailed description of the CO2 capture method chosen.A handful of related studies evaluated the economics of ICL underdifferent capacities from the perspective of the Western markets[7,8]. Their results showed considerable disparities with the roughestimations provided in research done from China’s perspective[9e11]. To obtain an unprejudiced understanding of ICL in China,this article uses process simulation results to assess the economicfeasibility of ICL in China by considering different CO2 captureabsorption methods, i.e., DMC (dimethyl carbonate), MEA (mono-ethanol amine) and Rectisol.

The article is organized as follows. After this introduction,Section 2 describes the entire ICL process, the key assumptions andthe basic results of the simulations. The three considered CO2capture methods are explained. Section 3 compares the three CO2capture alternatives in terms of energy and cost requirements.Section 4 assesses the economic performance of the entire ICLprocess with the least-cost CO2 capture unit selected from Section 3and identifies the most influential factors in the cost calculation.Section 5 presents the conclusions.

2. Process simulation

2.1. Process description

Regardless of the specific techniques adopted, generally, thewhole process of ICL consists of six generic subsystems, includingan ASU (air separation unit), coal gasification, WGS (water-gasshift), AGR (acid gas removal), FeT synthesis and syncrude refiningand power generation3. The block flow diagram is shown in Fig. 1.Coal is first fed into a gasifier to produce synthetic gas (syngas),a mixture mainly composed of CO and H2, with O2 generated froman ASU. The raw syngas is cooled and washed to remove particu-lates and trace components. Awater-gas shift unit is then employedto adjust the ratio of H2 to CO in the syngas stream to meet therequirement of the in FeT synthesis. As a result of the water shiftreaction, the concentration of CO2 is increased in this unit. An acidgas removal system sequentially removes H2S and CO2 from the gasstream. The cleaned syngas is then sent into the FeT reactor tosynthesize hydrocarbon liquids. In the outlet of the FeT reactor, theunconverted syngas is recycled by mixing with incoming syngas tomaximize the liquids production, as the conversion rate does notachieve 100% per pass. After the conversion is maximized, the off-gas leaving the synthesis unit, mainly consisting of gaseousproduct, is compressed and sent to a gas turbine and a sequentialsteam turbine to generate electricity. Detailed descriptions of thesimulation conditions for each unit are presented below.

2.1.1. Air separation unitThe air separation unit provides high-purity O2 for the coal

gasification. Among the various technological options, cryogenic airseparationwas employed in the research because of the maturity ofthe process for large-scale applications. Air is first compressed,cleaned and sent into an air separation tower that separates air intoO2, N2 and Ar. O2 with 95% purity is pretreated and used as anoxidant in the coal gasification unit. The separated N2 is used toprovide cooling or as the stripping gas in the CO2 capture module.

3 The demo projects in China have not yet implemented a power generation unitbecause gas turbine technology is not well developed domestically, which results ina higher cost. However, from the perspective of maximizing energy efficiency, weinclude this component to offset part of the electricity use in the plant.

2.1.2. Coal gasificationShenhua coal was selected as the feedstock; its LHV (lower

heating value) is 25.87 MJ/kg. The gasification unit produces syngasusing a pressurized water-slurryefed gasifier operating at 25 bar,with 95% purity O2. The coal undergoes partial combustion,releasing heat that causes the gasification reactions to proceedrapidly and the ash to fuse and flow. The heat released in thereactions raises the temperature of the syngas leaving the gasifierto approximately 1300 �C. Hot raw gas exiting from the gasifier iscooled to approximately 230 �C. The waste heat from this cooling isused to generate high-pressure steam. Particulates are thenremoved through a cyclone and a barrier filter.

2.1.3. Water-gas shiftThe raw syngas leaving the particulate filter system mostly

consists of hydrogen, CO, CO2, water vapor, nitrogen, H2S, COS andmethane. The molar ratio of H2 to CO has to be adjusted to 2.1through the water-gas shift reaction, as presented in Eq. (1), inorder to achieve the highest conversion rate of syngas (CO plus H2)possible in the FeT synthesis unit.

Coþ H2O/CO2 þ H2 (1)

The ratio of H2 to CO is achieved by sending part of the streaminto the water-gas shift reactor and having the rest of the streambypass the reactor without getting shifted. Here, we assume thatthe reaction could reach a high level of chemical equilibrium (90%conversion rate), and an adiabatic reactor is used because it is moreeconomically attractive.

2.1.4. Acid gas removal/CO2 captureThe acid gases CO2, H2S and COS contained in the raw syngas

need to be removed prior to FeT synthesis to avoid catalystpoisoning. A number of methods have been used in variousindustrial sectors, including natural gas purification andammonia and hydrogen production. Absorption methods, eitherchemical or physical in nature, are the most widely used. Thepotential of adsorption methods to reduce CO2 emissions in largeindustrial sources, such as power plants, has been intensivelyassessed. Here, we compare a novel absorbent, DMC (dimethylcarbonate), which has not been commercially available, with twomature absorbents MEA (monoethanol amine) and Rectisol(methanol as absorbent), to seek the most economically accept-able option for China’s CtL projects to cope with high CO2emissions.

2.1.4.1. DMC. DMC has a high solubility level for CO2 and a lowtoxicity. Recent experimental studies show a better solutionperformance for CO2 in DMC over traditional physical solvents in anappropriate temperature range [12,13]. For example, at 280e290 K,the solubility of CO2 in DMC is approximately 50% higher than thatin PC (propylene carbonate). The same is true formethanol at 250 K.These positive results imply that DMC has the potential to bea highly effective absorbent with regard to CO2 emissions reduc-tion, though at present, it is mostly used as an important inter-mediate for organic synthesis rather than as an acid gas absorbentin industrial applications.

The moderate conditions needed for DMC absorption simplifythe process flow design, as depicted in Fig. 2. Raw syngas fromWGScontains a CO2 concentration of 20%. Lean DMC solvent contacts thegas fed into the absorber counter-currently at 15 �C and 30 bar. Theresulting rich solvent goes through two-stage flashes at decreasingpressure levels to regenerate the lean solvent. After mixing withfresh makeup to compensate for absorbent losses, the lean solventis then pressurized and recycled to the absorber. High-purity CO2

Coal Slurry Preparation

Gasification Quench

Power Generation

Ash

Water Gas Shift

H2S Removal

CO2

Removal

F-T Synthesis

Hydro-treating & Separation

Naphtha

Diesel

SulfurClaus Unit

CO2

Compression

CO2

Coal

Air

O2

ASU

Unconverted Syngas

H2S

Electricity

Fig. 1. Indirect coal liquefaction process diagram.

W. Zhou et al. / Energy 36 (2011) 6559e6566 6561

(at w95%) streams released from different flashes are compressedand sent out of the plant, without further sequestration or otherprocessing.

2.1.4.2. Rectisol. The Rectisol acid gas removal system uses meth-anol as the working fluid. The first Rectisol installation was startedup at SASOL, the world’s only commercial operator of CtL plants,whichproved a successful integration of Rectisol into CtL technology.In China, Rectisol is widely used in large-scale ammonia plants. Asa physical sorbent, the principle flow scheme of the Rectisolabsorption process is similar to that of DMC (as shown in Fig. 2), yetthe configuration is much more complex because the low operationtemperature (approximately �58 �C) involves a more complex heatexchange system and different materials. However, the high capitalcost of Rectisol can be offset to some extent by its lower operationcost. Because of the strong solubility of acid gases in cold methanol,the solvent flow rate is low, thus resulting in less regenerationenergy. Because of the low operation temperature, Rectisol is alsofavorable for cryogenic downstream processes, like liquid nitrogenwashing; thus, a plant that combines an air separation unit with theICL process would also increase the economic performance.

2.1.4.3. MEA. The MEA process has been used in the industrialsector for almost 7 decades. It is frequently studied as a mature gasstream scrubbing method. In particular, the MEA process is used asa way for power plants to reduce CO2 emissions and is calleda “postcombustion” capture system. This developing method hasalso been modified to incorporate inhibitors to resist solventdegradation and equipment corrosionwhen applied to CO2 capture.MEA, or aqueous amine in a broader sense, is better suited toremove CO2 at lower partial pressure than physical absorbents are;

Absorber

Feed GasHP Flash

Rich

Treated Gas

PumpLean

LP-Flash

CO2

Fig. 2. Simplified flowsheet of CO2 absorption by DMC.

treating flue gas is an example of this. Despite this, it can also beused for syngas cleanup at medium/high CO2 partial pressures; forexample, China has quite a few ammonia plants fueled by naturalgas that reportedly employ the MEA scrubbing method to recoverCO2 from syngas [14].

Fig. 3 shows a typical simplified diagram of CO2 capture byMEA.Because the partial pressure of CO2 in syngas is relatively high, itmakes sense to flash the rich solvent exiting the absorber prior tothe thermal regeneration of the lean solvent via the reboiler of thedesorber.

2.1.5. Sulfur recoveryCO2 of 95% purity captured from the acid gas removal section is

then compressed to 150 bar and sent outside the plant. Sulfur in thesynthesis gas must be reduced below 200 ppb to avoid catalystpoisoning. Prior to the FischereTropsch reactor, sulfide in thesyngas, such as H2S and COS needs to be removed, normallythroughwith a zinc oxide and activated carbon sorbent. Most of thesulfur, mainly derived from stripped H2S, is sent to the Claus unit,where H2S is oxidized to SO2 and eventually converted into theform of solid sulfur as a byproduct, as in Eqs. (2) and (3), whichpresent the main reactions.

2H2Sþ 3O2/2SO2 þ 2H2O (2)

2H2Sþ SO2/2H2Oþ 3S (3)

2.1.6. FeT synthesisThe ICL pilot projects owned by China’s coal companies,

including Yitai Group, Yankuang Group and Lu’an Group, have re-ported successful operation of slurry-bed FeT synthesis reactors inrecent years. The advantages of slurry-bed reactors over fixed-bed

Absorber Desorber

Pump

HeatX

Feed Gas

Treated Gas

Rich

Cooler

Lean

Flash

CO2

Fig. 3. Simplified flow diagram of MEA absorption.

Table 1Generic parameter assumptions for the three processes.

Parameter Value Parameter Value

ASU FeT synthesisPower, kWh/t (for 95% purity O2) 433 Reactor temperature, �C 220

Pressure, bar 21GasificationGasifier temperature, �C 1280 Power generationPressure drop, bar 3 Gas turbine inlet temperature, �C 1290Heat loss, GJ/hr 167 Pressure ratio 16

Isentropic efficiency of expander, % 92Water-gas shift Isentropic efficiency of compressor, % 83Reaction temperature, �C 280 Turbine inlet temperature, �C 535Pressure, bar 40 Turbine inlet pressure, bar 125/25/3Pressure drop, bar 1 (High/Intermediate/Low)

Isentropic efficiency, % 88

Table 2Feedstock for the indirect coal liquefaction plant.

Temperature,�C

Pressure,bar

Flow rate,tons/hr

Coal 30 68 1800Oxidant (95% mol O2,

from ASU)100 68 1410

Water 30 68 630Cooling water 20 68 3600

W. Zhou et al. / Energy 36 (2011) 6559e65666562

reactors include less capital cost and less catalyst consumption. Torepresent the real installations in the demo projects, we adoptedslurry-bed FeT synthesis in ourmodel with iron-based catalyst. Theprocess of converting the sulfur-free syngas into hydrocarbonproducts operates at 220 �C and 21 bar Eq. (4) shows the mainmechanism of the FeT reaction, where eCH2e serves as thebuilding block for the various products of the synthesis.

COþ 2H2/� CH2 �þH2O (4)

The product composition is predicted by the triple-a modelfrom Fox and Tam [15]. Most of the unconverted syngas iscompressed and recycled directly back into the FeT reactor. Theliquid product leaving the FeT reactor is separated into light-gas,diesel, naphtha, and heavy waxes. In order to produce the more-desirable light products, an additional refinery unit is required tocatalytically crack the wax in a high-pressure hydrogen environ-ment. Diesel and naphtha are considered the two main finalproducts. The light gas from the liquid production processes servesas the fuel for the power generation unit.

2.1.7. Power generationThe power generation unit consists of a gas turbine and a steam

turbine system, where a HRSG (heat recovery steam generator) is

Table 3Specifications for simulating the three CO2 capture methods.

DMC Rectisol

Lean temperature, �C 30 Lean temperature, �C

Absorber AbsorberNumber of stages 10 Number of stagesTop stage pressure, bar 28 Top stage pressure, barStage pressure drop, bar 0.2 Stage pressure drop, bar

Flash FlashTemperature, �C 30 Temperature, �CPressure, bar 5/1 (High/Low) Pressure, bar

set up to match the characteristics of the gas turbine exhaust gas.Heat generated from different units, such as gasification andsynthesis, is also considered.

2.2. Flowsheet simulation

The three different CO2 capture processes were simulatedindependently by the flowsheet simulation software Aspen Plus.Other than the CO2 capture process, the other components arespecified identically to facilitate a fair comparison between thesethree CO2 capture methods. Table 1 presents the basic parametersof all the generic sections apart from the acid gas removal system.

Table 2 summarizes the generic feedstock conditions of thethree processes. The flow rate of coal is specified as 1800 tons/hr inan attempt to match an annual production capacity of 3 milliontons, which is the minimum scale required by the NDRC fora commercial installation [16]. Table 3 specifies the key parametersfor simulating the three CO2 capture processes.

Table 4 presents the basic simulation results and summarizesthe general performance of the overall ICL process. Electricityoutput is not included because the electricity use in the CO2 captureunit varies among the three different methods, which is analyzedand compared in Section 3. The two main FeT liquid products,diesel and naphtha, account for 65% and 35%, respectively, of theproduct composition. The total output amount of liquid fuelproduction reaches approximately 3 million tons per year. Theresults in Table 4 also imply that the average CO2 emissionproduced per ton of fuel would be approximately 6.91 tons, and theannual CO2 emissions would reach as high as 20 million tons.Considering a scenario in which FeT liquid fuels replace half ofChina’s refined oil supply, the nationwide total CO2 emission fromFeT liquid production would reach 800 million tons when using

MEA

�58 wt% of Lean MEA 35Lean loading (mol CO2/mol MEA) 0.3

Absorber10 Number of stages 1040 Top stage pressure, bar 280.15 Stage pressure drop, bar 0.1

Regeneration�50 Number of stages 1210/1 (High/Low) Top stage pressure, bar 2

Stage pressure drop, bar 0.1

Table 6Performances of DMC, Rectisol and MEA for capturing CO2 from the ICL process.

DMC Rectisol MEA

Lean solvent flow rate,a ton/hr 29,182 4461 53,606Solvent loss,b kg/hr 946 836 4718Heat duty,a,c MWth e 175 2532Power,a MWe 629 83 416Chiller duty,b MWth 29 364 e

Cooling water,b ton/hr 18,923 25,981 305,292Compression work,a MWe 719 451 365

Comprehensive energy use,d

GJ/ton CO2 captured1.75 1.57 4.33

a From the simulation results.b From a literature survey.c For low-pressure steam, the conversion factor was specified as an average value

of 2.927 GJ/ton steam.d The results for DMC and Rectisol already considered taking advantage of the

cooling load of nitrogen generated from the ASU, which can totally or partiallycompensate for the chiller duty in the two processes. In addition, the chiller duty hasto be converted into power consumption for refrigeration to calculate thecomprehensive energy use, in which the conversion factor is taken as 0.32.

Table 4Basic performance of the indirect coal liquefaction plant.

Parameter Value

Coal consumption, tons/day 43,200Diesel production, tons/day 6617Naphtha production, tons/day 3504Sulfur production, tons/day 1045CO2 captured, tons/day 66,509CO2 emissions (without capture), tons/day 69,899CO2 capture rate 95%Purity of CO2 captured �95%Capacity factor 0.8

W. Zhou et al. / Energy 36 (2011) 6559e6566 6563

2010 data, for example (China’s refined oil production was 238million tons in 2010, calculated from [17]). This rough estimationproves that without CO2 capture, ICL cannot be accepted as a fuel-supplying alternative for wide application because of the urgencyof mitigating greenhouse gas emissions.

3. Comparison of the three CO2 capture methods

3.1. Utilities and energy requirements

AnumberofCO2removalmethodshavebeenapplied innumerousindustrial scenarios, yet noneof themcouldbeused for everyprocess.The selection of CO2 removalmethod has to address not only the inletgas conditions from the upstream unit but also the requirements forthe downstream treatment. In addition, some important factors, suchas the feedstock type, the gasification approach, and the treatment ofCO2 captured, should also be taken into account.

Similar to the concept of precombustion capture, the ICL processyields a high partial pressure of CO2 in the raw syngas, as shown inTable 5. Based on the simulation conditions specified in Table 3, theoperating performances of the three CO2 capture alternatives wereanalyzed by combining the simulation results with related datacollected from the literature [14,18,19], as shown in Table 6.

The key information delivered in Table 6 can be summarized asfollows:

� The MEA process requires the highest capture energy, mainlybecause the chemical absorption process consumesmuchmoresteam in the reboiler to heat up the rich solution and separateCO2. In the Rectisol and DMC processes, most of the CO2 isreleased in multistage flashes; hence, their heat duties aremuch lower. Besides this, the advantage of utilizing cryogenicnitrogen from ASU also partly contributes to the huge energygap between the later two and MEA.

� The electricity consumption for DMC is much higher than forRectisol; the situation is reversed for the chiller duty. There aretwo reasons for this. First, the circulation rate of lean solvent inthe DMC process is significantly larger than that for Rectisol,which correspondingly requires more power to pressurize andcirculate the lean solvent. Second, the relative moderateoperating temperature of DMC leads to a smaller refrigeration

Table 5Inlet syngas conditions of the CO2 capture process.

Component Composition,mol%

Temperature, �C 301 H2 28.81Pressure, bar 68 CO 13.31Mass flow, ton/hr 6133.67 CO2 22.17

H2O 30.77N2 8.94CH4 0.07H2S 5.96

need in contrast with Rectisol. Because the cooling needs of theRectisol process that could be offset by cold nitrogen are muchgreater than those of the DMC process, the former hascomparatively lower energy requirement in the presence ofASU integration.

� The compression work also varies among the three methods.The pressure of the CO2 stream from theMEA regenerator is thehighest of the three, while the pressure loss in the DMCvacuum flash is the most significant. Accordingly, for an iden-tical outlet pressure of the final CO2 effluent, they require,respectively, the least and the most work for compression.

One should note that one advantage of the two physical absor-bents over MEA, specifically for Rectisol, is the nitrogen streamcoming from the ASU unit at very low temperature. The coldnitrogen stream has a higher cooling power, and the surplus coolcontent within it could be used for some industrial purposes thuswill create value for the whole process. In this case, the final resultsof the three methods regarding the economics might be changed tosome extent. While in this research, this factor is not taken intoaccount in order to make comparisons with other researches undera similar circumstance.

3.2. Cost analysis

To estimate the operating cost, the purchase prices of utilitieswere gathered from a market survey and are provided in Table 7.

The equipment employed in these three processes was sizedbased on flowsheet simulations. Subsequently, the capital costswere calculated by adjusting the cost of reference systems,according to Eq. (5):

Ci ¼ Ci;ref$

Si

Si;ref

!fi

(5)

Table 7Price specifications for operating cost calculation.

Parameter Pricea

Methanol, yuan/ton 3000MEA, yuan/ton 9000DMC, yuan/ton 8000Low pressure steam, yuan/ton 70Electricity, yuan/MWh 450Cooling water, yuan/ton 0.1

a The current exchange rate: $1 is approximately equal to 6.6 yuan.

Rectisol MEA DMC

capital cost 97.50 56.57 66.95

operating cost 175.91 257.47 210.62

0.00

70.00

140.00

210.00

280.00

350.00 Y

uan/

ton

CO

2

Fig. 4. Costs of the three CO2 capture methods.

Table 9Main results for an ICL plant.

Value

Total capital investment, M yuan 3.56 � 104

Total installation cost, M yuan 2.89 � 104

Annual liquid fuel output, M tons/yr 2.96Electricity output, MWh/yr 5.71 � 106

Amortized capital investment, M yuan 2.58 � 103

Capital investment per unit capacity,yuan/(ton/yr)

1.21 � 104

W. Zhou et al. / Energy 36 (2011) 6559e65666564

where Ci is the capital cost of equipment i, Ci,ref is the cost ofequipment i in the reference systems, Si is the scale parameter ofequipment i, Si,ref is the corresponding scale parameter of equip-ment i in the reference systems, and fi is the scale factor. Theinformation on the reference systems was collected from theliterature [14,18,20].

The results of the cost analysis are presented in Fig. 4; the capitalcost was amortized according to the capturing unit CO2 amount.The results show that to capture a ton of CO2 in the ICL process, theMEA process costs themost, the Rectisol process costs the least, andthe DMC process cost is closest to the cost of the Rectisol process.

The order of the three methods in terms of total cost per ton ofCO2 captured is exactly the same as that from the energyconsumption comparison, despite the fact that the huge gapbetween MEA and the other two substantially shrinks. Thisshrinkage is primarily caused by two factors. On the one hand, theelectricity is more expensive compared with low-pressure steam ifmeasured in terms of per unit energy supply. As a result, theoperating cost of the MEA process, which primarily consumeslow-pressure steam, can be reduced to some extent. On the otherhand, the cryogenic operation conditions of Rectisol determinesthat its capital cost is significantly higher than that of MEA andDMC; for instance, the use of low-temperature carbon steel forequipment and pipelines materials increases the purchase cost.

The comparison with regards to energy and cost performanceamong the three methods indicates the advantage of a physicalabsorbent over a chemical absorbent for capturing CO2 in the ICLprocess. More specifically, Rectisol, because of its process maturity,performs best in terms of total cost, but the novel DMC process is

Table 8Factors and indices for ICL economic assessment.

Value

Construction time, years 3Plant life, years 30Discounted rate, % 6Localization factor,a % PECb 65e100BOP, % TPECc 15Indirect cost, % TPEC 25Contingency, % TICd 20Working capital, % TIC 12Capacity factor 0.8

a The localization factor measures the extent of cost reductiondue to the localization of specific technology and associatedequipment. A lower localization factor leads to a lower cost.

b PEC: purchased equipment cost.c TPEC: total purchased equipment cost.d TIC: total installation cost.

almost at the same level. In light of the comparative result, Rectisolwas selected for the economic assessment of the overall ICL process.

4. Economic assessment of ICL

4.1. Capital cost

The cost of single pieces of equipment scaled to new sizes wascalculated according to Eq. (5). Moreover, some equipment requiresseveral units operating in parallel; gasifiers are an example of this.To calculate the overall train costs of these processes, Eq. (6), sug-gested by Kreuz et al. [3], was applied.

Ci;m ¼ Ci$nmi (6)

where Ci,m is the train cost, Ci is the cost of a single unit, ni is thenumberofunits andm is the train factorwithavalueof0.9 [3]becauseof the sharing of installation materials. Table 8 lists the importantfactors and indices for this economic assessment. The BOP (balance ofplant) cost was assumed to be 15%, according to Lin et al. [5].

The cost of the reference system was collected from the litera-ture [3e5,14,18e20], and different exchange rates were used thatcorresponded with the year when each study was conducted.Table 9 lists the main results for an ICL plant. The total capitalinvestment for an ICL plant with a 3 million tons/yr scale isapproximately 35,561 million yuan. The amortized capital invest-ment over 30 years of plant life, calculated as the total investmentcost times the CRF (capital recovery factor), is 2583 million yuan.The capital investment per unit capacity is 1.21�104 yuan/(ton/yr),approximately 20%w30% higher than preliminarily estimated inprevious studies on China’s ICL projects [9e11].

Dividing the overall cost into each of the six subsystems, the costcomposition was obtained as presented in Fig. 5. The compositionshows that the coal gasification unit constitutes the largest part,accounting for 35% of the overall capital investment. Powergeneration and FeT synthesis also contribute remarkable shares,

Fig. 5. Cost compositions among the six subsystems.

Table 10Parameters and variable specifications in the operating cost calculation.

Parameter Value Variable Value

Coal consumption, M tons/yr 12.61 Coal price, yuan/ton 600Water consumption, M tons/yr 38.76 Water price, yuan/ton 3.5Electricity output, MWh/yr 5.71 � 106 Electricity price, yuan/

MWh450

Sulfur output, M tons/yr 0.31 Sulfur price, yuan/ton 1500Labor amount 920 Unit labor cost, yuan/

(capita/yr)50,000

Auxiliary feedstock factora 0.25Indirect cost factor 0.32

a Auxiliary feedstock factor refers to the ratio of the auxiliary feedstock cost to thecost of main feedstock.

W. Zhou et al. / Energy 36 (2011) 6559e6566 6565

occupying 23% and 16% respectively. The proposed costs of the sixsubsystems not only depend on their material requirements andinstallation complexities but are also strongly associated with theirdevelopment stages in China. A localization factor was employed toreflect this influence. For example, China does not possess thecapability of manufacturing large-scale gas turbines for powergeneration; therefore, the localization factor for this equipmentwas specified as being higher to account for this reality.

4.2. Operating cost

The operating cost consists of feedstock purchase, wastedisposal, labor payment and taxes, etc. The revenue from sellingbyproducts, such as electricity and sulfur, should be considered asa negative item in the cost calculation. The operating cost model wedeveloped previously was employed in this study [21]. The mainvariables include feedstock prices, byproduct prices, and laborwages. Table 10 summarizes the specifications of these variables forthe model used in this study.

The calculation result shows that the operating cost per ton ofproduct is 2945 yuan. Not surprisingly, coal consumption is thelargest portion of the cost. Taking into account the amortizedcapital cost, 866 yuan/ton, the total product cost is 3811 yuan/ton.This result is close to the cost estimated by Mantripragada andRubin [7], though some variable specifications, such as coal price,are different to some extent.

4.3. Sensitivity analysis

The product costs of China’s ICL projects estimated by otherresearchers [9e11] differ significantly from the results of thisstudy. Though the disparities in the model construction partlyaccounts for the difference between these results, some keyparameter specifications, for instance, the coal price, have a moredirect influence. Thus, a sensitivity analysis is necessary, which

2500 3000 3500 4000 4500 5000

Unit labor cost 35000:50000:65000

Water price 2.5:3.5:4.5

Sulfur price 1200:1500:1800

Auxiliary feedstock factor 0.2:0.25:0.3

Indirect cost factor 0.24:0.32:0.4

Capital cost 70:100:130

Capacity factor 0.7:0.8:0.9

Electricity price 300:450:600

Coal price 450:600:750

yuan/ton

Fig. 6. Sensitivity results of the product cost.

makes it possible to add some uncertainty to those variables thatchange because of variations in market conditions or otherfactors. The crucial variables and the key parameters wereselected to perform the sensitivity analysis. The results are pre-sented in Fig. 6. The center line represents the baseline result,namely, 3811 yuan/ton. The bars on the right/left side correspondwith higher/lower results based on the variable value specified inthe labels of the vertical axis. Because the changes of electricityprice and sulfur price negatively affect the cost result, thesedifferences from other variables are marked with light and darkcolors.

The sensitivity analysis shows that the most influential effectson the product cost come from the coal price, the electricity priceand the capacity factor, while the sulfur price, the water price andthe unit labor cost have very subtle effects. The results also showacceptable economic viability under a high oil price of over $100/barrel. However, a striking increase in coal prices (more than1000 yuan/ton in some coastal regions of China) would substan-tially narrow the profit of ICL projects in China. The influence ofextreme fluctuations in the international oil market would alsoaffect the profits.

5. Conclusions

The analysis presented in this study compares the energy andcost requirements of three CO2 capture alternatives for the ICLprocess: DMC, MEA and Rectisol. The comparative results highlightthe remarkable advantages of physical absorbents over chemicalabsorbents at the current technological level. Because of itscommercial maturity, Rectisol was found to be the most economicoption for capturing CO2 in the ICL process, if taking advantage ofrefrigeration from cold N2 provided by the air separation unit. DMCwas almost at the same level as Rectisol in terms of economicperformance because of its moderate operation conditions and theresulting lower capital costs. Therefore, as the technology matures,this new absorbent can be expected to be widely used. Besides CO2capture for controlling CO2 emission in ICL process, some otheralternatives, such as the utilization of biomass partly or totallyreplaces coal for producing liquid fuel, remain as the hot topics inthe academic research and the industrial practice. The main diffi-culties of the biomass approaches lie in its high cost and theacquisition of biomass resource [22,23].

This study also assesses the economics of China’s ICL projectwith a government-regulated scale of 3 million tons. The resultsinclude a capital cost of more than 35 billion yuan and an overallproduct cost of approximately 3800 yuan per ton of synthetic fuel.The high capital cost requires a very cautious investment decision-making process, within an uncertain environment in particular. Theproduct cost, combined with sensitivity analysis, gives aneconomically acceptable market condition that is much higher thansuggested by previous research. The three most influential vari-ables were also identified, namely, coal price, electricity price andcapacity factor. In addition, localization factor, reflecting thedevelopment level of domestic technology, also places a consider-able impact on the capital investment. China has madecommendable progress in key technologies for coal chemicalindustry development including large-scale coal gasification anddirect- and indirect coal liquefaction [24], indicating that lowercapital cost is still expectable in the near future.

The water price had a fairly subtle effect on the final productcost. This fact highlights a weakness of this studydfailing to reflectthe bottleneck effect of water shortages in those regions where ICLprojects were planned or pilot plants were built in China. Given thefact that ICL is regarded as one of the key technologies to fulfilla sustainable development of western China [25], this concern can

W. Zhou et al. / Energy 36 (2011) 6559e65666566

never be ignored. Hence, further studies are anticipated that willincorporate investigations into the ecological and environmentaleffects of China’s ICL projects.

Acknowledgment

The authors would like to acknowledge the financial supportfrom the National Natural Science Foundation of China (NSFC), thePh.D. Program Foundation of theMinistry of Education of China andthe National Key R&D Program (No. 20876087, No. 200800030049and No. 2009BAC65B03, respectively).

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