Optimal Design and Decision for Combined Steam Reforming Process

Article pubs.acs.org/IECR

Optimal Design and Decision for Combined Steam Reforming Process with Dry Methane Reforming to Reuse CO2 as a Raw Material Youngsub Lim,† Chul-Jin Lee,† Yeong Su Jeong,† In Hyoup Song,‡ Chang Jun Lee,§ and Chonghun Han*,† †

School of Chemical and Biological Engineering, Seoul National University, Gwanak-ro 1, Gwanak-gu, Seoul 151-742, South Korea LG Chem Research Park, 104-1 Monnji-Dong, Yusong-Gu, Daejeon, 305-380, South Korea § Samsung Corning Precision Materials, 544, Myeongam-ri, Tangjeong-myeon, Asan-city, Chungcheongnam-do 336-725, South Korea ‡

ABSTRACT: Carbon dioxide (CO2) conversion technology has been estimated as a potentially practical solution for global warming problems although it still has some weaknesses such as cost and energy consumption. In this study, a combined steam reforming process with dry methane reforming process for the CO2 treatment was investigated. Because the dry methane reforming process could generate synthesis gas from carbon dioxide, it could decrease the CO2 emissions from the existing steam reforming process. Models for the steam reforming process and the combined process were developed and extended mitigation cost was suggested to evaluate CO2 reduction of the overall process. The combined process could reduce net CO2 emission by 67% compared with the reference steam reforming process, and the extended mitigation cost of the combined process ranged from 21 to 26.5 (US$/CO2 ton) according to the change of the cost for CO2 transportation.

1. INTRODUCTION Increasing problems associated with climate change and global warming have led carbon dioxide (CO2) reducing technologies to receive increased attention. The Intergovernmental Panel on Climate Change (IPCC) has concluded that most of increases in temperature observed since the middle of the 20th century have been caused by increasing concentrations of greenhouse gases produced by anthropogenic activities such as the burning of fossil fuels and deforestation. CO2 is a very important greenhouse gas because nearly all types of human activities including chemical, biological, and industrial processes generate this gas. CCS is a technology designed to diminish CO2 emissions and is expected to be widely implemented in a short period of time; however, this may not be a fundamental solution because it cannot consume CO2 directly. As a result, even though there are obstacles to overcome such as high cost and additional energy consumption, CO2 conversion technology that uses CO2 as a raw material will likely become more common in the future. The combined steam reforming process with dry methane reforming (DMR) was focused on in this study. The steam reforming process is a conventional method used to produce synthesis gas, a mixture of carbon monoxide and hydrogen, which is a highly valuable feedstock in the chemical industry. DMR can also be used to produce synthesis gas from methane and is useful for the direct conversion of CO2 into other compounds. Accordingly, the use of a combination of steam reforming and DMR could have synergistic effects. Even though DMR has disadvantages such as easy deposition of carbon and deactivation of the catalyst, commercial processes to minimize these problems (i.e., CALCOR process1) are now available. Moreover, the utilization of existing steam reforming process is beneficial in that there is no need to add an additional CO2 separation process, because it is included in the steam reforming process usually. © 2012 American Chemical Society

Even though many studies have been conducted to investigate steam reforming and dry methane reforming, only a few have considered combination of these two processes. Avci et al.2,3 investigated the reaction of steam reforming of methane and butane, but their primary focus was the reaction and catalyst to produce hydrogen. Gadalla et al.4,5 studied catalysts to reform methane with CO2. Larentis et al.6,7 developed empirical models based on experiments and optimized the parameters involved in the synthesis gas process combined with CO2 reforming and partial oxidation of natural gas. Wang et al.8−10 researched about dry methane reforming via various catalysts. Choudhary et al.11,12 have studied a process to reform steam and CO2 with methane simultaneously. However, these studies focused on reforming methane and did not consider applicable process designs. Choi et al.13 solved an optimization problem regarding the superstructure of processes that included a steam reforming process and a dry methane reforming process. It reported that annual profit could be increased by optimization; however, a detailed design of the process unit and the amount of indirectly generated CO2 were not considered. A methodology to evaluate the cost required to reduce CO2 emissions is also required because known methods of mitigating costs are based on comparison between conventional processes and the CO2 capture processes without consumption, which are not applicable to CO2 conversion technology. In this study, we developed a model of a steam reforming process that included a CO2 separation process as reference process and a combined steam reforming process with dry methane reforming for CO2 conversion. We also suggested an extended methodology to evaluate the mitigation cost to reflect Received: Revised: Accepted: Published: 4982

April 23, February February February

2011 17, 2012 23, 2012 23, 2012

dx.doi.org/10.1021/ie200870m | Ind. Eng. Chem. Res. 2012, 51, 4982−4989

Industrial & Engineering Chemistry Research

Article

Figure 1. Block diagram of reference steam reforming process.

Figure 2. Block diagram of combined SR+DMR process.

Figure 3. Concept of (a) mitigation cost and (b) extended mitigation cost considering both CO2 capture and consumption.

CO + H2O ↔ CO2 + H2

CO2 consumption and cost for transportation and storage. The steam reforming process and combined SR+DMR process were optimized, evaluated, and compared as a CO2 reduction process.

2.2. Dry Methane Reforming Process. The main reaction of dry methane reforming (DMR) is described in eq 3, and this reaction is endothermic, which requires heat. Excess CO2 is required to increase the conversion of the reaction. Because the reverse water gas shift reaction (RWGS, eq 4) is also accompanied with DMR reaction, the excess CO2 and generated hydrogen can be converted into carbon monoxide. Accordingly, the amount of hydrogen generated by DMR is less than that produced in the steam reforming process. DMR can be connected to steam reforming process as shown in Figure 2, in which case the existing process to separate CO2 and hydrogen could be used; however, the amount of CO2 that flows into the separation process may be limited by the capacity of the separation process. The recycled CO2 could be split in steam reformer or dry methane reformer and additional CO2 feed could be added without CO2 compression, transportation, and storage, if effective. In some case a strategy might be selected to increase the flow rate of CO2 recycled into the steam reformer to induce RWGS reaction, if effective.

2. BACKGROUND 2.1. Reference Steam Reforming Process. Figure 1 shows a block diagram of reference steam reforming process. Various hydrocarbons can be used as a raw material for steam reforming. In this study, liquefied petroleum gas (LPG) that primarily consisted of n-butane was considered as the feed. The major steam reforming reaction occurred according to eq 1.3 Equation 2 shows the water gas shift reaction (WGS) which always takes place with the presence of carbon monoxide, carbon dioxide, and water at high temperatures in a steam reformer. Generally the conventional steam reforming process is operated at high temperature from 700 to more than 900 °C with excess steam to increase the conversion.3,14 If there is little CO2 in the steam reformer, the equilibrium of the WGS reaction shifts forward, resulting in the conversion of carbon monoxide into CO2. In order to prevent this loss of carbon monoxide, CO2 is recycled into the reformer after separation. The remaining CO2 is captured, transported, and stored by CCS technology. Additional CO2 feed could be added into steam reformer without CO2 compression, transportation, and storage, to induce reverse water−gas shift reaction in steam reformer to consume more CO2, if effective. C4 H10 + 4H2O ↔ 4CO + 9H2

(2)

CH 4 + CO2 ↔ 2CO + 2H2

(3)

CO2 + H2 ↔ CO + H2O

(4)

2.3. Method for Evaluation. As a useful method to evaluate the cost of reducing CO2 emission, the mitigation cost (MC) was developed.15 MC represented the difference of cost

(1) 4983



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Figure 4. Model for reference steam reforming process.

was used for the flash of CO2 separation in FL2, because PR was inaccurate to calculate the solubility of CO2 in water and PSRK shows better results.16,17 As an absorbent, 30 wt % monoethanolamine (MEA) was used.18 n-Butane (C4H10) was assumed to be the representative component of LPG for the feed stock of the steam reformer. In the process, the feed stream (C4FEED) was mixed with the steam (STEAMFEED) and recycled CO2 stream (CO2REC), heat-exchanged (1-2), and then preheated (1-3) for steam reforming. In the steam reformer, it was assumed that the all butane was converted into synthesis gas with high excess of water based on plant operation data and the WGS reaction was at equilibrium. Equation 7 was used to obtain the equilibrium constant.19

per ton of CO2 emissions avoided between the reference plant and capture plant for a power plant in eq 5 and Figure 3a. MC =

COEcap − COE ref Eref − Ecap

(5)

where COEref = cost of electricity in the reference plant COEcap = cost of electricity in the capture plant Eref = quantity of CO2 emitted from the reference plant without capture process Ecap = quantity of CO2 emitted from the capture plant with capture process A similar concept of this mitigation cost, increased process cost versus net CO2 emission avoided, could also be used to evaluate the combined SR+DMR process when compared with the reference process in this study. However, in this concept of MC, the effect of the consumed CO2 is not included and captured CO2 requires additional costs associated with transportation and storage when compared with consumed CO2. To reflect the effect of consumed CO2, additional terms are required. Therefore, we suggest the extended mitigation cost (EMC) shown in eq 6 and Figure 3b. A detailed description of EMC is provided in section 3.3. EMC =

K eq = exp(4577.8/T − 4.33)

The reactor effluent (2-1) from the steam reformer went through HX1 with a minimum temperature approach of 25 °C. Next, the heat-exchanged stream (2-2) was cooled to 60 °C in the cooler (C1) for CO2 absorption, after which condensed water (W-H2O-1) was removed by FL1. In the ABSORBER, CO2 in the feeding stream (2-4) was absorbed by absorbent, and the top stream (GASOUT) of the absorber after removal of the CO2 was sent to the hydrogen separation process to produce synthesis gas and additional hydrogen byproduct. As a constraint, the mole fraction of CO2 in GASOUT should be less than 0.1%. Then, the amount of the lean CO2 absorbent stream (3-4) could be adjusted to satisfy the constraint of CO2 in GASOUT. The loading value (mol CO2/mol MEA) and the temperature of stream 3-4 was 0.32 and 40 °C, respectively, according to the literature.18 The CO2 rich MEA stream (3-1) from the bottom of the ABSORBER was heat-exchanged and flows into the STRIPPER. In the STRIPPER, CO2 was separated from the absorbent by heating, after which it flowed out to the top stream (CO2OUT-1). The regenerated CO2 lean MEA stream (3-3) from the bottom of the STRIPPER was heat-exchanged and recycled to the ABSORBER (3-4). An ABSORBER with three equilibrium stages at 110 kPa with a pressure drop of 4.8 kPa and a STRIPPER with eight equilibrium stages at 150 kPa with a pressure drop of 30 kPa were used.18 Stripped CO2 (CO2OUT-1) was flashed to remove the remaining wastewater (W-H2O-2) and to ensure the purity of CO2 to be more than 95% which is a common condition of CO2 from an amine-based capture system with cooling water of normal temperature.20 The remaining CO2 (CAPTURED) was captured and moved to the next process of transportation and storage. The production rate of synthesis gas

TACcp − TACref Eref − (Ecp − Ccp)

(7)

(6)

where TACref = total annual cost of the reference SR process TACcp = total annual cost of the combined SR+DMR process Eref = quantity of CO2 emitted from the reference SR process with capture process Ecp = quantity of CO2 emitted from the combined SR + DMR process Ccp = quantity of CO2 consumed in the combined SR + DMR process

3. MODELING, SIMULATION, AND OPTIMIZATION 3.1. Reference Steam Reforming Process. As a reference process, the conventional steam reforming process model was simulated as shown in Figure 4. ASPENPLUSTM 7.2 was used as a simulator, and the Peng−Robinson (PR) equation of state was used as the main property method. For the calculation of absorption reaction, the Aspen amine property method was used in the absorber and stripper. The P-SRK property method 4984



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Figure 5. Model for combined steam reforming process with dry methane reforming process.

was fixed to 200 kgmol/h with the same ratio of carbon monoxide and hydrogen (1:1), and the flow rate of the raw material feed was adjusted to satisfy the required production rate. 3.2. Combined Steam Reforming Process with Dry Methane Reforming. The dry methane reforming process was combined with the reference steam reforming as shown in Figure 5. The basic data and specifications were the same as those in the reference process. The recycled CO2 (CO2REC) or supplied CO2 (CO2FEED) could now be split into both SR (RECTOSR) and DMR (RECTODMR). The C1FEED was mixed with CO2 (RECTODMR), heat-exchanged (D-3), and then preheated (D-4) for dry methane reforming. A plug flow reactor with reaction kinetics obtained from the literature21 was used for the dry methane reforming reactor (DMR). The diameter to length ratio of the DMR reactor was fixed, and the length was adjusted to ensure that the conversion of methane in DMR is more than 99.9%. Reactor effluent (D-5) from DMR was heat-exchanged through HX3, and the heat-exchanged flow (D-6) was mixed with the outlet flow from SR and then cooled down in the cooler (C1). The remaining processes were the same as in the reference process. 3.3. Economic Evaluation. As mentioned in eq 6 in section 2.3, EMC was defined as the difference of cost over the net CO2 emission. The cost difference was calculated based on the total annual cost (TAC) of the process with a fixed production rate of synthesis gas and transportation and storage cost. As shown in eq 8, the TAC is composed of the annualized cost of raw materials (CRM), heating (CHt), cooling water (Ccw), electricity (CEle), hydrogen purification (CPu), CO2 treatment (CTre), capital cost (CCDMR) for an additional reactor, blower, and heat exchanger for DMR, and credit of byproduct hydrogen (BCH2). The costs of raw materials consist of the cost of butane, methane, and hydrogen. When the production rate of hydrogen was greater than the required production rate, the remaining hydrogen could be used as a byproduct, which reduced the TAC. Conversely, when the production rate of hydrogen was insufficient, the raw material cost of hydrogen was added to TAC since an additional purchase of hydrogen was required. It was assumed that the purchased hydrogen has a 20% higher cost than the selling price. Heating cost was defined as the sum of the cost of preheating, reaction heat for reactors, and reboiling heat for stripper. The calculation of heating cost was based on the coal heat price. The Guthrie correlation was used to estimate the capital cost for the DMR reactor. The

costs of raw materials and utilities are shown in Table 1. The cost of CO2 treatment included the cost of compression Table 1. Costs of Raw Materials and Utilities cost butane (C4)

595

methane (C1)

370

hydrogen

1.5−2.0

coal

70

water

0.35

heating cost

unit $/metric ton $/metric ton $/kg $/metric ton $/m3

6.3

$/MMBtu

40.5

mills/kWh

H2 separation

0.5

cents/Nm3

CO2 compression

10.5

electricity

$/tCO2

ref Kuwait Petroleum Corporation (KPC), 200923 Coalbed Methane Association of Alabama, 200724 U.S. EIA, 2008,25 Ball and Wietschel26 U.S. EIA, 200827 industiral water pricing in OECD country, 199928 based on the heat content of coal and 50% efficiency, U.S. EIA, 200629 based on the fossil steam plant, U.S. EIA, 200930 U.S. DOE, hydrogen production costs, 199931 D. L. McCollum and J. M. Ogden, 200632

(CCom), transportation (CTrs), and storage (CSto) for captured CO2 and the cost of transportation for additional CO2 feed into SR or DMR, as shown in eq 9. TAC = [CRM − BCH2 + CHt + Ccw + CEle + CPu + C Tre + CCDMR ]annualized (8)

C Tre = (C Trs + CSto) ·FCO2cap + C Trs·FCO2feed

(9)

The total CO2 emissions included direct and indirect CO2 emissions from heating, electricity, purchased hydrogen production, and compression of CO2 captured. The CO2 emissions from heating were calculated based on the CO2 emissions from bituminous coal. Table 2 shows the indirect CO2 emissions from energy uses. The net CO2 emission was calculated from the difference between the amount of CO2 produced and the amount of CO2 consumed. The amount of CO2 captured was defined as the flow rate of pure CO2 in the outlet stream from the stripper except for the amount of CO2 recycled, and the amount of CO2 consumed was defined as the 4985



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Table 2. Indirect CO2 Emissions from Using Energy, Producing Hydrogen, and Processes of CO2 Compression value

unit

heating electricty hydrogen production

205.3 0.89 45.2

lb CO2/MMBtu ton CO2/MWh lb CO2/gge H2

CO2 compression

0.11·0.89

MWh/tCO2 compressed·tCO2/ MWh

ref based on bituminous coal, U.S. EIA, 199433 greenhouse gas emissions coefficients of bituminous coal, Korea Power Exchange, 200934 centralized hydrogen production from coal gasification with sequestration, U.S. DOE, 200535 A. Aspelund and K. Jordal20

Figure 6. Mass balances at the optiaml point (a) of the reference steam reforming process, (b) of the reference process with decreasing amount of CO2 recycled (Case RP-1), and (c) of the reference process with whole recycling and additional feeding of CO2 (Case RP-2) (unit: kg mol/h).

and water. Although the increased amount of hydrogen gives more credit to the process cost, the increased cost of raw material and CO2 compression, transportation, and storage made TAC increase. Conversely, when the amount of CO2 recycled is increased by feeding additional CO2 into the steam reformer with recycled CO2 (Case RP-2) as shown in Figure 6c, although the amount of raw material feed required is decreased, the decreased amount of hydrogen produced made TAC increase. Figure 7a shows these TAC of Case RP-opt, RP1, and RP-2. Since hydrogen credit has a non-negligible effect on TAC which consists primarily of the raw material cost, the optimal condition is changed by the cost of hydrogen. When the cost of hydrogen is decreased, the optimal point moves to add additional CO2 feed into the steam reformer for consumption with recycled CO2 because the effect of the hydrogen credit decreases and therefore EMC increases, as shown in Figure 7b. If the cost of hydrogen is increased, reference steam reforming process could decrease both TAC and CO2 emissions due to the increased hydrogen credits. When the CTrs+Sto is decreased, EMC is also decreased because CO2 transportation cost for additional CO2 feed is reduced, as shown in Figure 7c. 4.2. Combined SR+DMR Process. The optimization of the combined process is slightly different from the reference process; the amount of CO2 fed into DMR, as well as it into steam reformer, becomes a key variable to optimize the process. If the more CO2 is fed into the DMR, the less the amount of the raw material feed required. Figure 8 shows the mass balance at the optimal point of combined process (CP-opt) when the hydrogen cost and CO2 transportation and storage cost are 1.8 (US$/kg) and 60 (US$/tCO2), respectively. The TAC of combined process increased due to the additional capital cost, CO2 transportation cost for additional CO2 feed, and decreased

flow rate of CO2 fed into reactor except for the amount of CO2 recycled. 3.4. Optimization. Objective function was defined to minimize the EMC of the combined process. Design variables were the flow rate of CO2 supplied into the DMR (CO2FEED), the amount of CO2 recycled into steam reformer (RECTOSR), and the amount of CO2 recycled into the DMR (RECTODMR). Since the EMC was influenced by the cost of hydrogen (CH2) and the transportation and storage cost of CO2, the optimal solution also changed as those variables changed. Accordingly, sensitivity analysis was conducted by changing those two variables. The range of CH2 for sensitivity analysis was set at 1.5−2.0 (US$/kg); the estimated cost of the production cost of hydrogen was less than about 2 (US$/kg) even though the cost could be changed for different raw materials and production methods, and the target cost of hydrogen is 1.5 (US$/kg) by 2015. The range of CTrs+Sto was set from 30 to 60 (US$/CO2 ton) to include the estimated range of CTrs+Sto.22 A built-in Aspen optimization tool using SQP (sequential quadratic programming) was employed to minimize the objective function of EMC. A series of sensitivity analysis was carried out to check a local minimum.

4. RESULTS AND DISCUSSION 4.1. Reference Steam Reforming Process. Because it has a trade-off between raw material costs and hydrogen credit by changing the amount of CO2 recycled into steam reformer, the amount of CO2 recycled is a key variable in optimization of the steam reforming process. Figure 6a shows the optimal results of reference steam reforming process (Case RP-opt). When the amount of CO2 recycled is decreased (Case RP-1), as shown in Figure 6b, the equilibrium of the WGS reaction shifts forward to produce more hydrogen by consuming carbon monoxide 4986



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Figure 7. (a) Total annual cost, (b) extended mitigation cost vs hydrogen cost, and (c) extended mitigation cost vs CO2 transportation and storage cost of the reference steam reforming process.

Figure 8. Mass balances at the optimal point of the combined SR+DMR process when cost of hydrogen and transportation + storage were 1.8 (US $/kg H2) and 60 (US$/tCO2) (unit: kg mol/h).

0.498 mol of CO2 were consumed by DMR and RWGS, respectively, based on the simulation results. In this case, the overall heat of reaction in dry methane reformer was about 0.15 MJ/mol of CO2 consumed. Therefore, about (4 molemitted/ MJ)·(0.15 MJ/molconsumed) = 0.6 mol of CO2 was released from coal burning for every 1.0 mol of CO2 consumed by reforming. (2) Dry methane reforming requires relatively lower heat to produce carbon monoxide compared with the steam reforming. The heat of the main reaction (eq 1) of steam reformer is 651.5 kJ per mole of butane to produce carbon monoxide. To produce 1 mol of carbon monoxide by steam reforming, about 162.9 kJ is required, and this value is higher than 247/2 = 123.5 kJ of dry methane reforming. Therefore, dry methane reforming produces less indirect CO2 emissions from a heating source than steam reforming does. (3) The reduced amount of

hydrogen credit, as shown in Figure 9a, although the cost for raw material and utilities decreased. However, the net CO2 emission was decreased by 67% due to the consumed CO2 and reduced indirect CO2 emissions caused by heating for steam reformer and regeneration in stripper, as shown in Figure 9b. The EMC at this point was 26.5 (US$/tCO2). The main reasons to decrease net CO2 emission in combined process are as follows: (1) In dry methane reformer, CO2 is also consumed by the reverse water−gas shift reaction which has a lower heat of reaction.9 The heat of reaction of RWGS reaction (eq 4) is 41.1 (kJ/mol), which is lower than that of DMR reaction (247 kJ/mol, eq 3), and when these reactions occurred at the same time, the overall heat of reaction is lower than that of DMR itself. When 1 mol of CO2 was consumed in dry methane reformer, the simulation results showed 0.502 and 4987



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Figure 9. (a) Total annual cost, (b) net CO2 emissions, and (c) EMC of the combined SR+DMR process.

When the cost of CO2 transportation and storage changed from 30 to 60 (US$/tCO2), the EMC of the combined process varied from 21 to 26.5 (US$/tCO2).

CO2 before CO2 capture process by dry methane reforming can also abate the required regeneration energy required in the CO2 capture process. As shown in Figure 9c, the cost of hydrogen does not have a big effect on the EMC of the combined process because the flow rate of byproduct hydrogen was nearly zero at the optimal point of the combined process. Decreasing cost of CO2 transportation could reduce the EMC of the combined process. As a result, the combine SR+DMR process showed lower EMC compared with the reference SR process when the hydrogen cost was less than 1.7 (US$/kg). The EMC of the SR+DMR was 21−26.5 (US$/tCO2) according to the change of CO2 transportation cost.

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AUTHOR INFORMATION

Corresponding Author

*Tel.: 82-2-880-1887. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This research was supported by the second phase of the Brain Korea 21 Program in 2012, Institute of Chemical Processes in Seoul National University, Strategic Technology Development and Energy Efficiency & Resources Development of the Korea Institute of Energy Technology Evaluation and Planning (KETEP) grant funded by the Ministry of Knowledge Economy (MKE) and grant from the LNG Plant R&D Center funded by the Ministry of Land, Transportation and Maritime Affairs (MLTM) of the Korean government.

5. CONCLUSION In this study, a combined process of steam reforming (SR) with dry methane reforming (DMR) was suggested as a CO2 consumption process. Also, the extended mitigation cost (EMC) was developed for evaluation considering CO 2 consumption. The combined SR+DMR process was optimized, evaluated, and compared with the reference steam reforming process. The combined process can reduce net CO2 emission by 67% at the optimal condition compared with the reference SR process. When the hydrogen cost is lower than 1.7 (US $/kg H2), the combined process showed lower EMC than the reference SR process. Because the optimal condition was set to minimize byproduct hydrogen, the EMC of the combined process was shown to be insensitive to the hydrogen cost.

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NOMENCLATURE CO2 = carbon dioxide DMR = dry methane reforming LPG = liquefied petroleum gas NG = natural gas WGS = water gas shift reaction MC = mitigation cost dx.doi.org/10.1021/ie200870m | Ind. Eng. Chem. Res. 2012, 51, 4982−4989


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(15) David, J. Economic evaluation of leading technology options for sequestration of carbon dioxide. M.S. Thesis, Massachusetts Institute of Technology, 2000. (16) Adams, T. A.; Barton, P. I. High-efficiency power production from coal with carbon capture. AIChE J. 2010, 56 (12), 3120−3136. (17) Carroll, J. J.; Slupsky, J. D.; Mather, A. E. The solubility of carbon dioxide in water at low pressure. J. Phys. Chem. Ref. Data 1991, 20 (6), 1201−1209. (18) Abu-Zahra, M. R. M.; Schneiders, L. H. J.; Niederer, J. P. M; Feron, P. H. M.; Versteeg, G. F. CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine. Int. J. Greenhouse Gas Control 2007, 1 (1), 37−46. (19) Moe, J., Design of water-gas shift reactors. Chem. Eng. Prog. (U. S.) 1962, 58, (3). (20) Aspelund, A.; Jordal, K. Gas conditioningThe interface between CO2 capture and transport. Int. J. Greenhouse Gas Control 2007, 1 (3), 343−354. (21) Olsbye, U.; Wurzel, T.; Mleczko, L. Kinetic and reaction engineering studies of dry reforming of methane over a Ni/La/Al2O3 catalyst. Ind. Eng. Chem. Res. 1997, 36 (12), 5180−5188. (22) Carbon Capture & Storage: Assessing the Economics; McKinsey & Company: London, U.K., 2008. (23) Kuwait Petroleum Corporation. http://www.ameinfo.com/ 211316.html, 2009. (24) Coalbed Methane Association of Alabama. http://coalbed.com/ displaycommon.cfm?an=1&subarticlenbr=14, 2007. (25) The Impact of Increased Use of Hydrogen on Petroleum Consumption and Carbon Dioxide Emissions; SR-OIAF-CNEAF/200804; U.S. EIA: Washington, DC, 2008. (26) Ball, M.; Wietschel, M. The Hydrogen Economy: Opportunities and Challenges; Cambridge University Press: New York, 2009. (27) Steam Coal Prices for Industry; http://www.eia.gov/emeu/ international/stmforind.html; U.S. EIA: Washington, DC, 2010. (28) Industrial Water Pricing in OECD Countries; ENV/EPOC/ GEEI(98)10/FINAL; OCED, 1999. (29) Gross Heat Content of Coal Production; http://www.eia.gov/ emeu/international/coalother.html; U.S. EIA: Washington, DC. (30) Average Power Plant Operating Expenses for Major U.S. InvestorOwned Electric Utilities; U.S. EIA: Washington, DC, 2009. (31) Hydrogen Production CostsA Survey; DOE/GO/10170-778; U.S. DOE: Washington, DC, 1997. (32) McCollum, D. L.; Ogden, J. M. Techno-Economic Models for Carbon Dioxide Compression, Transport, and Storage & Correlations for Estimating Carbon Dioxide Density and Viscosity. University of California−Davis, 2006. (33) Carbon Dioxide Emission Factors for Coal; DOE/EIA-0121(94/ Q1); U.S. EIA: Washington, DC, 1994. (34) Korea Power Exchange. Greenhouse Gas Emission Coefficients of Bituminous Coal, http://www.kpx.or.kr/, 2009. (35) Centralized Hydrogen Production from Coal Gasification with Sequestration; U.S. DOE: Washington, DC, 2005.

EMC = extended mitigation cost MEA = monoethanolamine TACref = total annual cost of the reference process TACcp = total annual cost of the combined process Eref = quantity of CO2 emitted from the reference process Ecp = quantity of CO2 emitted from the combined process CRM = cost of raw material CHt = cost of heating Ccw = cost of cooling water CEle = cost of electricity CPu = cost of hydrogen purification CCDMR = capital cost BCH2 = credit of byproduct hydrogen CH2 = cost of hydrogen CCom = cost of CO2 compression CTrs = cost for CO2 transportation CSto = cost for CO2 storage FCO2 cap = flow rate of CO2 captured FCO2 feed = flow rate of CO2 feed

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REFERENCES

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Optimal Design and Decision for Combined Steam Reforming Process

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