Production of hydrogen-rich fuels for pre-combustion carbon capture in power plants: A thermodynamic assessment

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1 international journal of hydrogen energy 7 (2012) 7554e7564 Available online at journal homepage: Production of hydrogen-rich fuels for pre-combustion carbon capture in power plants: A thermodynamic assessment Fontina Petrakopoulou a,b, *, George Tsatsaronis a a Technische Universität Berlin, Marchstr. 18, Berlin, Germany b IMDEA Energy Institute, c/tulipán s/n, 289 Mostoles, Madrid, Spain article info Article history: Received 21 October 2011 Received in revised form 2 January 2012 Accepted 28 January 2012 Available online 6 March 2012 Keywords: Hydrogen production Exergetic analysis Pre-combustion CO 2 capture Combined-cycle power plant Methane steam reforming Autothermal reforming abstract Hydrogen-fueled plants can play an important role in the field of carbon capture and storage, because they facilitate the mitigation of harmful emissions. In this paper, two combined-cycle power plants with pre-combustion CO 2 capture are examined, in which natural gas is converted into a hydrogen-rich fuel through reforming. The first plant considered operates with a hydrogen-separating membrane and the second with an autothermal reformer. The two plants are compared to a reference plant without CO 2 capture and briefly to alternative oxy-fuel and post-combustion capture technologies. It is found that both plants suffer high penalties caused by the high energy requirements of the reforming components and the CO 2 compression units. Additionally, both plants appear inferior to alternative capture technologies. When comparing the two reforming plants, the plant with the hydrogen-separating membrane operates somewhat more efficiently. However, in order to make these technologies more attractive, their thermodynamic efficiency must be enhanced. The potential for improving the efficiencies of these plants is revealed by an exergetic analysis. Copyright ª 2012, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved. 1. Introduction Hydrogen is an energy carrier that does not generate greenhouse gases when combusted. Due to this trait, hydrogen has attracted attention as a potential alternative to fossil fuels for high efficiency and minimization of harmful exhausts. Hydrogen can be produced from fossil fuels and water using various technologies [1]. Fossil-fuel conversion technologies for the production of hydrogen are well developed and can be used in large scale in the short term. Specifically, gasification (e.g., [2,]) methane steam reforming (e.g., [4e6]) and partial oxidation (e.g. [7,8]) have been widely studied as potential alternatives to producing hydrogen-rich fuels with promising results. Gasification is one of the best known ways to produce a hydrogen-containing gas from solid fuels (e.g., coal and biomass) that can then be used, in integrated gasificationcombined-cycle (IGCC) power plants [2]. Although some IGCC plants have already been constructed, economic and reliability issues delay the wider implementation of the technology. In addition to the concept of gasification, methane steam reforming and partial oxidation are suggested as alternative means to produce hydrogen from natural gas. Carbon capture and storage is a way suggested to mitigate emissions generated from the combustion of fossil fuels [9]. Carbon capture methods can be separated into three groups: post-combustion, oxy-fuel combustion and pre-combustion [10]. Pre-combustion methods involve the conversion of a carbon-based fuel into a clean, hydrogen-based fuel. * Corresponding author. IMDEA Energy Institute, c/tulipán s/n, 289 Mostoles, Madrid, Spain. Tel.: þ ; fax: þ address: fontina.petrakopoulou@imdea.org (F. Petrakopoulou) /$ e see front matter Copyright ª 2012, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved. doi: /j.ijhydene

2 international journal of hydrogen energy 7 (2012) 7554e However, although the combustion of pure hydrogen produces only water vapor and heat, the processes used to obtain hydrogen generate harmful emissions. These emissions must be treated and removed. The present paper is part of a study that compares different technologies for CO 2 capture under similar conditions. All CO 2 capture plants are based on the same reference power plant, making possible the comparison of their performance at the same size and structural characteristics. Here, two power plants that convert methane into hydrogen-based fuels are presented and evaluated. The first plant includes a hydrogenseparating methane steam reforming membrane (MSR plant) [11e1], and the second, an autothermal reformer (ATR plant), where complete and partial oxidation of methane take place [14,15]. The plants are analyzed using an exergetic analysis [16] and are compared to a reference plant that does not include CO 2 capture. Additionally, for a more complete overall evaluation of the pre-combustion technologies, the plants are briefly compared with plants that incorporate postcombustion and oxy-fuel capture technologies [10,17,18]. Using the results of the exergetic analysis we can improve the overall efficiency of the plant by decreasing the inefficiencies of its individual components. By increasing the efficiency of the overall plant, the fuel input required for the production of a given product output decreases, reducing the emissions per unit of output. 2. The power plants 2.1. Reference plant The reference plant is a combined-cycle power plant with a three-pressure-level heat-recovery steam generator (HRSG). A simplified diagram of the plant is shown in Fig. 1. A detailed description of the operation of the plant and the results of its exergy-based examinations can be found in [17,19,20] Plant using a methane steam reforming membrane with hydrogen separation (MSR plant) A simplified diagram of the plant is shown in Fig. 2, while its detailed structure can be seen in Fig. A.1. The hydrogenseparating membrane (Fig. ) uses thermal energy from the flue gases of the plant to reform the methane entering the plant into CO 2,H 2 and H 2 O. To simulate a best-case scenario, we assume a sequence of H 2 separation steps according to Jordal et al. [6], until we achieve the separation of 99.7% of the generated hydrogen in the membrane. The hydrogen is then swept by intermediate-pressure steam at 17 bar and led to the combustion chamber (CC) of the plant. The remaining gases (CO 2 and H 2 O) exit the membrane and the CO 2 is captured after water condensation [5,6]. Initially, methane is mixed with steam (mass ratio 1:4) extracted from a high-pressure steam turbine (HPST) at 50 bar. The mixture is preheated in a natural gas preheater (NGPH) and led to the feed side of the reactor of the plant at a temperature of 600 C. The reforming process is a strongly endothermic reaction, for which thermal energy is provided by the combustion products of the plant. After the reforming process, the exothermic shifting reaction follows. 99.8% of the incoming methane is reformed and 99% of the produced CO is shifted [4]. The hydrogen formed is continuously transported through the membrane, which separates the feed and permeate sides of the reactor, and is swept from the permeate side of the reactor by intermediate-pressure (IP) steam. To have sufficient energy for the reforming process of the reactor and for the HRSG of the plant, a supplementary firing (duct burner, DB) is added after the CC, increasing the temperature of the combustion gases to 960 C [6]. Fig. 1 e Simplified diagram of the reference plant [10].

3 7556 international journal of hydrogen energy 7 (2012) 7554e7564 Fig. 2 e Simplified diagram of the MSR plant (grey box highlights differences with the reference plant) [10]. 2.. Plant using an autothermal reformer (ATR plant) In the ATR plant, both partial and complete combustion give the necessary heat for reforming the methane. In more detail, an ATR is an adiabatic vessel, where the catalyst is placed, and the three main reactions occur (shown on the right side of Fig. 4) [8]. The first two reactions represent the steam reforming and water shift reactions, whereas the third reaction is a combination of the total combustion that usually takes place in an oxygen-rich environment and the catalytic partial oxidation (CPO). CPO has received considerable attention in recent years because of its close to 100% CH 4 conversion and its high H 2 yields. The amount of methane converted in the reaction depends on the steam to carbon (S/C) and the carbon to oxygen (C/O) ratios. As a result of the work of Luwei Chen et al. (2007), an optimal C/ O ratio of 2 was set for an ATR operating at 15 bar and 850 C, allowing x and y of the CPO to be set to 1.2 and 0.9, respectively, as shown in Equation (1). The S/C ratio was also set to 2. CH 4 þ 0:95O 2 #1:2H 2 þ 0:9CO þ 0:8H 2 O þ 0:1CO 2 (1) Air is supplied to the ATR by compressor extraction (Fig. 4 and Fig. A.2). The equilibrium temperature of the mixed stream is approximately 80 C, a temperature too low for the ATR that operates at 850 C. For this reason, the ATR outlet stream, a mixture of the combustion and the reforming products that exits the unit at 850 C is used to preheat the ATR inlet stream to 640 C in the NGPH of the plant. After the ATR, the gas is sent to the two shift reactors of the plant, where the produced CO is converted to CO 2 and H 2 O. The simulation of the shift reactors has been realized by calculating the equilibrium constants of the reaction, which are controlled by the equilibrium temperature. Because of the high percentage of nitrogen in the gas, chemical absorption is used to capture the produced CO 2. Therefore, the gas is cooled to 60 C and sent to a chemical absorption unit (CAU). The necessary thermal energy for the regeneration of the chemical solvent (monoethanolamine, MEA) is provided from a lowpressure steam extraction. After the CAU, the captured CO 2 is led to the compression unit, while the hydrogen-rich gas (fuel) is sent to the CC. Fiaschi and Tapinassi [15] have performed research on the integration of an autothermal reformer into a gas turbine system. However, the plants they examined do not include bottoming steam cycles. In the same work, the required heat demand of the endothermic steam reforming is provided by thermal energy of the flue gases, while CO 2 separation is performed with DEA and MDEA. In an attempt to decrease the size of the syngas treatment section and to facilitate the CO 2 separation, an air membrane-atr that operates with an oxygen separating membrane has been examined in [21]. However, the plant also resulted in a relatively high energy penalty of approximately 10 percentage points. Fig. e Configuration of the MSR reactor and the chemical reactions [10].

4 international journal of hydrogen energy 7 (2012) 7554e Fig. 4 e Simplified diagram of the plant with an ATR (grey box highlights differences with the reference plant).. Methodology The evaluation of the plants has been performed at the component level using an exergetic analysis [16,22,2]. The rate of exergy of the product of component k, _ E p;k, is the exergy of the desired output resulting from the operation of the component, while the rate of exergy of the fuel of the same component, _ E F;k, is the expense in exergetic resources for the generation of the desired output. The rate of exergy destruction within component k, _ E D;k, is calculated as the difference between its rate of fuel and product exergy ð _ E D;k ¼ _ E F;k _ E P;k Þ. General guidelines for defining exergetic efficiencies have been proposed by Lazzaretto and Tsatsaronis (2006) and have also been used here. Definitions of exergy of the fuel and product and efficiencies for selected components of the MSR plant (based on Fig. A.1) are shown in Table 1. Similar definitions have been followed for the ATR plant as well. Important variables of the exergetic analysis are the exergy destruction ratio, y D, and the exergy loss ratio, y L. The latter is only defined for the overall system. The exergy destruction ratio can be used to compare dissimilar components of the same system, while the total exergy destruction and exergy loss ratios can be used to compare different thermodynamic systems. Table 1 e Definition of exergy of the product and fuel and exergetic efficiency of selected components of the MSR plant. _E P;k C1 _ E2 _ E 1 _W _ EF;k _W _E 2 E _ 1 CC E4 _ E 2 E49 _ E49 _E 4 E _ 2 GT1 _W E4 _ E W 5 _E 4 E _ 5 RH E27 _ E _ 26 E8 _ E _ E27 _ E _ 26 9 _E 8 E _ 9 HPST _W E9 _ E _ 40 E W 48 _E 9 E _ 40 E _ 48 COND e _ E4 _ E 46 e k With an exergetic analysis the main sources of thermodynamic irreversibilities within a plant are identified. If necessary, modifications to the plant can then be applied, in order to reduce these inefficiencies. Since the adoption and/or the development of systems are mainly driven by economics, the thermodynamically optimal design can be used as the starting point for cost reduction and eventually cost minimization. 4. Results and discussion The overall results of the exergetic analysis for the reference and the two pre-combustion plants are shown in Table 1. Detailed stream and component data of the plants with CO 2 capture can be found in Tables A.1 and A.2. All examined plants are provided with the same amount of natural gas and the small differences in the exergy of the fuel for the total plant ð _ E F;tot Þ are associated with slightly different amounts of air required in each plant. The derived rate of the total exergy of the product ð _ E P;tot Þ depends on the individual operating characteristics of the plants and the requirements of the respective CO 2 capture technology. The reference plant performs with an exergetic efficiency of 56.5%. Both of the plants that incorporate CO 2 capture present high efficiency penalties. The ATR plant performs better than the MSR plant, but it still suffers a penalty of 10 percentage points, relative to the reference plant. This result agrees with the work presented by Romano et al. [24] and Ertesvag et al. [14]. In [24], various software was used for the simulation of the different parts of the power plant, while MDEA is used for the capture of the CO 2. The relatively lower penalty calculated there (8 percentage points when compared with a reference plant) is mainly associated with the lower assumed energy penalty of the CO 2 capture (0.99 MJ/kg CO 2 while here we assumed an MEA regeneration penalty of 1.1 MJ/kg CO 2 )(Table 2). With respect to the ATR plant, in the MSR plant the gas turbine (GT) system and the steam turbine (ST) generate less power, while more power is required by the CO 2 compressors (C2-C5 in Fig. A.2). Thus, the overall net power of the MSR plant and its efficiency are found to be lower than those of the ATR plant.

5 7558 international journal of hydrogen energy 7 (2012) 7554e7564 Table 2 e Selected results of the exergetic analysis. Ref. plant ATR plant MSR plant tot (%) _E P;tot _E D;tot _E L;tot y D,tot (%) To obtain an idea of the overall performance of the considered plants, we compare them with other CO 2 capture technologies. The most widely known and easily applicable method to capture CO 2 from power plants is post-combustion capture with chemical absorption using monoethanolamine (MEA plant) [25]. The results of the considered MEA plant can be found in [26]. When compared to the reference plant, the post-combustion plant shows an efficiency penalty of 8 percentage points, thus performing more efficiently than the ATR plant by 2 percentage points. Additionally, if we compare the ATR and MSR plants to oxy-fuel alternatives [10,27], their efficiency penalties appear even more severe. The justification of these results for the ATR plant is that it combines two costly CO 2 capture methods: chemical absorption and fuel decarbonization. Chemical absorption requires large amounts of thermal energy, while the de-carbonization process includes a, strongly endothermic, reforming reaction that is fueled by supplementary fuel burning. The low efficiency of the MSR plant can be primarily explained by its high rate of exergy loss (7.8% of the E _ F;tot ), which is associated with the high exergy of the flue gases exhausted to the environment ð E _ L;tot Þ. As can be seen from the results of the exergetic analysis (Table A.2), the combustion chambers are responsible for the highest exergy destruction among the plant components. Apart from the dominant influence of the combustion chambers on the operation of the plants, other components also appear to play significant roles. In the ATR plant, the second highest exergy destruction is found within the ATR, followed by the CAU. Specifically, within the ATR and the CAU, 7% and 4% of the plant s E _ F;tot is destroyed. In the DB of the MSR plant approximately 12% of the exergy of the fuel is destroyed, while in the MSR reactor approximately 1%. The compressor and the expander of the main GT system (C1 and GT1) also present relatively high exergy destruction. When comparing the pressure levels in each HRSG of the plants, the high-pressure level (HPSH, HPEV and HPEC) is found to be the most important part, followed by the low-pressure level (LPSH, LPEV and LPEC). Lastly, in the MSR plant, the CO 2 compression unit (C2eC5, COOL1-COOL4, FG COND) is responsible for destroying approximately % of the E _ F;tot. Using the results of an exergetic analysis, we can improve the effectiveness of energy conversion systems by changing the design and operation of components with a high overall influence. By applying measures to decrease a component s exergy destruction, we can eventually decrease the irreversibilities of the overall structure. Improvement steps based on the findings of this study will be realized and reported in future work by the authors. Although the simulation of the presented plants is based on the same reference plant, when evaluating the overall performance and risks associated with different technologies, some additional parameters must be accounted for as well. These parameters differ among the plants and depend on technology, structural complexity and operation. An important factor is that the plants presented here employ already commercially available technology, whereas for example oxyfuel plants, include components not yet available on the market and are therefore associated with higher uncertainty. Components under development should satisfy safety constraints and must be examined under realistic conditions. Safety and maintainability are important issues when CCS technologies are considered. Additionally, the higher the complexity of a plant, the higher its operating challenges. Structural subsystems, such as recirculation gas routes, make the start-up, operation and maintenance of a plant more complex. Another evaluation criterion could be the quantity of resources (e.g., water) required for the operation of a plant. In the plants examined here, the need for a constant additional water supply is dominant, due to the water leaving the Rankine cycle and used in different parts of the plants. The water condensed in plant components, for example during CO 2 compression, could be re-used in the Rankine cycle after appropriate treatment. Also, in both plants steam generated in the Rankine cycle is mixed with the incoming natural gas. In the ATR plant, steam is also used in the chemical absorption unit, while in the MSR plant steam is used as the sweep gas of the membrane. This additional water demand requires specific conditions and extra environmental consideration. Lastly, additional safety considerations are needed to sequester the captured CO 2 and to examine all possible options thoroughly before large-scale facilities for CO 2 capture are established. 5. Conclusions In this paper, two power plants (one with a hydrogenseparating steam reforming membrane and one with an autothermal reformer) with CO 2 capture have been compared and evaluated from a thermodynamic viewpoint. The plants perform pre-combustion carbon capture by converting the carbon-based fuel (methane) into a hydrogen-based fuel that is then combusted in the reactors of the plants. The structure and main operating characteristics of the plants were based on a reference plant that does not include CO 2 capture. The two pre-combustion plants were evaluated relative to both the reference plant and other proposed CO 2 capture technologies. The plants were examined using an exergetic analysis. It was found that the largest part of exergy destruction is present within the combustion chambers of the plants, while high irreversibilities are also noted in the reforming components. Using the results of the presented analysis, improved structures of the plants can be obtained through the minimization of the exergy destruction within individual plant components of high importance. When compared to the reference plant, the plants with CO 2 capture perform thermodynamically poorly with a minimum efficiency penalty of approximately 10 percentage points, calculated for the plant that includes the autothermal reformer. The plant with the methane steam reforming membrane was found to have an additional penalty of 0.8 points. Lastly, when compared to

6 international journal of hydrogen energy 7 (2012) 7554e power plants that incorporate other capture alternatives, the considered plants perform significantly less efficiently. Nevertheless, steps for decreasing the exergy destruction of the plants will be performed and presented in future publications, in order to reveal the potential for improvement of these carbon capture technologies. Acknowledgments This research was funded by the European Commission s Marie Curie 6th Framework Programme as part of the Research Training Network, INSPIRE, MRTN-CT The authors would like to thank Evonik Energy Systems GmbH for their support with the software Ebsilon Professional. Nomenclature _E Exergy rate, MW _m Mass flow, kg/s p Pressure, bar T Temperature C y Exergy destruction ratio, % _Y Component-related environmental impact, Pts/h Subscripts D Exergy destruction F Fuel (exergy) P Product (exergy) i,j Stream k Component L Loss Greek symbols Exergetic efficiency, % Abbreviations APH Air preheater ATR Autothermal reformer C(1e6) Compressor CAU Chemical absorption unit CC Combustion chamber CCS Carbon capture and storage COND Condenser COOL Cooler CPO Catalytic partial oxidation CT Cooling tower DB Duct burner EC Economizer EV Evaporator FG Flue gas GT Gas turbine HP, IP, LP High pressure, intermediate pressure, low pressure HRSG Heat recovery steam generator HX Heat exchanger IGCC Integrated gasification combined-cycle LCA Life cycle assessment M, Mix Mixer MEA Monoethanolamine MSR Methane steam reformer MUW Make-up water NG Natural gas P Pump PF Pollutant formation PH Preheater RH Reheater SH Superheater ST Steam turbine WPH Water preheater Appendix Fig. A.1 e Structure of the MSR plant. The component abbreviations are explained in the nomenclature of the paper.

7 7560 international journal of hydrogen energy 7 (2012) 7554e7564 Fig. A.2 e Structure of the plant with an autothermal reformer (ATR plant). The component abbreviations are explained in the nomenclature of the paper. Table A.1 e Results at the component level for the ATR plant (left) and MSR plant (right). Component, k _ E F;k _ EP;k _ ED;k k (%) y D,k (%) Component, k _ E F;k _ EP;k _ ED;k k (%) y D,k (%) C C CC CC GT DB HPSH GT HPSH GT HPEV RH HPEC HPSH RH HPEV RH HPEC IPSH IPSH IPEV IPEV IPEC IPEC LPSH LPSH LPSH LPEV LPEV LPEC LPEC NGPH NGPH HPST H2 PH IPST APH IPST WPH LPST WPH MSR-H WPH COND P HPST LPP IPST HPP IPST IPP LPST MUW P ST C ATR e e 7.09 C SHIFTER e.4 e 0.47 C SHIFTER e 0.6 e 0.09 C CAU.54 e e 4.10 De-aerator COND P M HPP M IPP M

8 international journal of hydrogen energy 7 (2012) 7554e Table A.1 e (continued) Component, k _ E F;k _ EP;k _ ED;k k (%) y D,k (%) Component, k _ E F;k _ EP;k _ ED;k k (%) y D,k (%) LPP M MUW P M C FG COND e e 2.06 C COOL e 0.60 e 0.08 C COOL e 0.85 e 0.12 C COOL 0.89 e 0.80 e 0.11 De-aerator COOL e 0.8 e 0.11 M COND 4.02 e 2.99 e 0.41 M CT 2.9 e 1.62 e 0.22 M Total M Exergy loss M M M Mix CH 4 /Air Mix CH 4 /H 2 O COOL CAU 1.71 e 12.6 e 1.7 COOL1 0.7 e 0.67 e 0.09 COOL e 0.56 e 0.08 COND 5.17 e.85 e 0.5 CT 2.50 e 1.48 e 0.20 Total Exergy loss 2.75 Table A.2. e Results at the stream level for the ATR plant (left) and MSR plant (right). Stream, j _m j (kg/s) T j ( C) p j (bar) EPH;j m j (kg/s) T j ( C) p j (bar) _E PH;j (continued on next page)

9 7562 international journal of hydrogen energy 7 (2012) 7554e7564 Table A.2. e (continued) Stream, j _m j (kg/s) T j ( C) p j (bar) EPH;j m j (kg/s) T j ( C) p j (bar) _E PH;j

10 international journal of hydrogen energy 7 (2012) 7554e Table A.2. e (continued) Stream, j _m j (kg/s) T j ( C) p j (bar) EPH;j m j (kg/s) T j ( C) p j (bar) _E PH;j C ST ST ST ST COND P LPP HPP IPP GT GT MUW P C C ST C ST C ST C ST tot COND P LPP IPP HPP C MUW P C C C GT ST tot 9.81 references [1] U.S. Department Of Energy - Hydrogen and Fuel Cells Program, last accessed September [2] Stiegel GJ, Ramezan M. Hydrogen from coal gasification: an economical pathway to a sustainable energy future. International Journal of Coal Geology 2006;65(e4):17e90. [] Gnanapragasam NV, Reddy BV, Rosen MA. Hydrogen production from coal gasification for effective downstream CO 2 capture. International Journal of Hydrogen Energy 2010; 5(10):49e4. [4] Bottino A, Comite A, Capannelli G, Di Felice R, Pinacci P. Steam reforming of methane in equilibrium membrane reactors for integration in power cycles. Catalysis Today 2006;118:214e22. [5] Johannessen E, Jordal K. Study of a H 2 separating membrane reactor for methane steam reforming at conditions relevant for power processes with CO 2 capture. Energy Conversion and Management 2005;46:1059e71. [6] Jordal K, Bredesen R, Kvamsdal HM, Bolland O. Integration of H 2 -separating membrane technology in gas turbine processes for CO 2 capture. Energy 2004;29:1269e78. [7] Chen L, Hong Q, Lin J, Dautzenberg FM. Hydrogen production by coupled catalytic partial oxidation and steam methane reforming at elevated pressure and temperature. Journal of Power Sources 2007;164:80e8. [8] Horn R, Williams KA, Degenstein NJ, Bitsch-Larsen A, Nogare DD, Tupy SA, et al. Methane catalytic partial oxidation on autothermal rh and pt foam catalysts: oxidation and reforming zones, transport effects, and approach to thermodynamic equilibrium. Journal of Catalysis 2007;249: 80e9.

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