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A novel methodology for comparing CO2 capture options for natural gas-fired combined cycle plants
Advances in Environmental Research 7 (2003) 901–911
A novel methodology for comparing CO2 capture options for natural gas-fired combined cycle plants Olav Bolland, Henriette Undruma,b,* a
Norwegian University of Science and Technology, NO-7491 Trondheim, Norway b Statoil R&D Centre, Postuttak, NO-7004 Trondheim, Norway Received 21 March 2002; accepted 9 July 2002
Abstract Three concepts for capturing CO2 from natural gas-fired combined gasysteam turbine power plants are evaluated and compared in this paper: (A) separation of CO2 from exhaust gas coming from a standard gas turbine power plant, using chemical absorption by amine solutions. (B) Gas turbine combined cycle (CC) using a semi-closed gas turbine with near to stoichiometric combustion using oxygen from an air separation unit as an oxidizing agent. This produces CO2 and water vapour as the combustion products. The gas turbine working fluid is mainly CO2. (C) Decarbonization, which comprises an autothermal reforming reactor with air-blown catalytic partial oxidation of gas natural gas, a water-shift reaction and a high-pressure CO2 capture process. The hydrogen-rich reformed fuel gas is combusted in a gas turbine CC, which is integrated (air, steam and heat) with the decarbonization process. A novel method is presented that compares power plant concepts including CO2 . Instead of using extensive thermodynamic calculations for these concepts, reaction equations for the conservation of molecular species together with specific energy consumption numbers for the different process sections are used to characterize the concepts with respect to fuel-to-electricity conversion efficiency. With a combined gasysteam turbine power plant giving 58% total fuel-toelectricity conversion efficiencies (no CO2 capture), calculations for the concepts with CO2 capture including CO2 compression gave: (A) 49.6%; (B) 47.2%; and (C) 45.3%. The mechanisms leading to a reduced efficiency for concepts A–C are discussed and quantified and compared to combined gasysteam turbine with no capture of CO2. 䊚 2002 Elsevier Science Ltd. All rights reserved. Keywords: Gas turbine; Combined cycle; CO2 capture; Absorption; Reforming; Air separation
1. Introduction The background to this paper are the man-made emissions of CO2, which may increase the greenhouse effect, so that unwanted climatic changes take place. Among the various sources of man-made emissions of CO2, this paper deals with power generation from *Corresponding author. Tel.: q47-73591604; fax: q4773598390. E-mail address: [email protected] (O. Bolland).
natural gas-fired gas turbine power plants where the CO2-gas is collected for storage on a long-term basis. It is assumed that 90% of the generated CO2 is to be captured and compressed to 100 bar. The natural gas used in the calculations consists of 80 vol.% methane, with a molecular weight of 20.6 and with a lower heating value of 45.5 MJykg. Three concepts (Fig. 1) for collecting CO2 from gas turbine power plants are evaluated and compared: (A) Separation of CO2 from exhaust gas coming from a standard gas turbine combined cycle (CC), using
1093-0191/03/$ - see front matter 䊚 2002 Elsevier Science Ltd. All rights reserved. PII: S 1 0 9 3 - 0 1 9 1 Ž 0 2 . 0 0 0 8 5 - 0
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Fig. 1. Three natural gas-fired power plant concepts with collection of CO2.
chemical absorption by amine solutions (Allam and Spilsbury, 1992; Suda et al., 1992; Bolland and Sæther, 1993; Erga et al., 1995; Chakma, 1995; Meisen and Shuai, 1997; Feron and Jansen, 1997; Falk-Pedersen ¨ 1997; Mimura et al., 1999; Undrum et and Dannstrom, al., 2000). The exhaust gas from the gas turbine CC goes into the CO2 capture plant consisting of exhaust gas preparation (cooling and a booster to overcome the exhaust gas pressure drop in the CO2 capture plant), CO2 absorption, amine solution CO2 stripping and CO2 compression. Low-pressure steam extracted from the steam turbine in the CC is used to cover the heat demand in the stripping process. (B) Gas turbine CC using a semi-closed gas turbine with near to stoichiometric combustion using oxygen (97%q purity) from an air separation unit as an oxidizing agent, and CO2 and water vapour are produced as the combustion products. The gas turbine working fluid is mainly CO2 (Hendriks and Blok, 1992; De Ruyck, 1992; Bram and de Ruyck, 1994; Bolland and Sæther, 1993 Bolland and Mathieu, 1998). There are various ideas about cycles including combustion with pure oxygen. Most of these imply the use of working fluid recycling in order to maintain turbine inlet temperatures within acceptable levels. In some cases the recycled working fluid may be liquid water (Mathieu, 2001; Bolland et al., 2001a), while in other cases it may be mainly gaseous CO2. The latter is chosen in the present work. (C) Decarbonization, which comprises a pre-reformer and an air-blown autothermal reforming reactor (ATR) for natural gas, water-shift reactors and a high-pressure CO2 capture process based on chemical absorption. The hydrogen-rich resulting gas is combusted in a gas turbine CC, which is integrated with the decarbonization process (Hendriks and Blok, 1992; Steinberg, 1994; IEA Report PH2y19, 1998). Air from the gas turbine
compressor exit is fed to the ATR. Medium-pressure steam is taken from the steam cycle and mixed with the natural gas before reforming. There is also integration between the power plant and the reforming process with respect to preheating of feed streams in the reformer. The heat recovery steam generator (HRSG) in the power plant has supplementary firing from approximately 600 to 750 8C. The exhaust gas heat between the two given temperatures is utilized for reformer preheating. The steam production based on exhaust gas heat, from 600 8C and downwards, is very much the same as for a gas turbine CC without any supplementary firing of the exhaust gas. There are different methods for reforming natural gas into a hydrogen-rich fuel, which enables pre-combustion capture of CO2. An air-blown ATR, together with water gas shift reactors and CO2 capture process; produce a fuel with approximately 50 vol.% hydrogen. Modern gas turbines with low-NOX combustors are restricted with regard to the hydrogen concentration of the fuel. Traditional steam reforming processes would, in this application, produce a fuel for the gas turbine with significantly higher hydrogen content. Therefore, the ATR method was chosen as a case in the present work (IEA Report PH2y19, 1998; Undrum et al., 2000; Lozza and Chiesa, 2000; Bolland et al., 2001b). This concept has the potential of being applied with gasification of solid fuels and integration of high temperature SOFC. Models that describe the fuel-to-electricity conversion efficiency and the mechanisms leading to reduced efficiency compared to power cycles with no capture of CO2 have been made to facilitate the comparison of these three concepts. The idea of these models is to express the efficiency of power plant concepts with CO2 capture based on a standard natural gas-fired CC, using specific energy consumption numbers to relate the efficiency penalties of the various process units to the
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Fig. 2. Fan work for compressing the exhaust gas going through the absorber, related to the content of CO2. The change in CO2 indicates the change in exhaust gas volumetric flow.
total plant efficiencies. The motivation for using these specific energy consumption numbers is to give a better understanding of energy consumption and efficiencies in the processes as well document and use years of accumulated knowledge from previous publications and ¨ studies. Previous work (Gottlicher and Pruschek, 1996; Akai and Kagajo, 1994) has given reviews of efficiencies for different power generation concepts including CO2 capture. The contribution of this paper is providing improved methodology for comparing options, and giving a relevant example reflecting the state of the art in gas turbine technology. 2. Models 2.1. Concept A The efficiency (hexh.abs.) for the concept with separation of CO2 from exhaust gas coming from a standard gas turbine power plant, using chemical absorption by amine solutions is: hexh.abs.shCCy (1)
2 ECO ECO2 a Cf rem,mechC y rem,heat str,atm LHV LHV
(2)
ECO2 Cf y comp LHV
(3)
(1)
(4)
(1) Efficiency of a standard natural gas-fired CC (set to 58%).
(2) Efficiency penalty for consumption of mechanical work or electricity in the CO2 absorption process. The main consumer is the exhaust gas fan, which is required in order to overcome the exhaust gas pressure drop in the absorption tower. The Erem,mech describes the consumption, see Fig. 2, and depends upon the pressure drop and volumetric flow rate. In Fig. 2, the fan work is given as a function of the CO2 content. If exhaust gas recycle back to the gas turbine compressor is used, the fan work can be reduced. For a modern gas turbine, approximately 30–40% of the exhaust may be recycled, in principle. However, there is some uncertainty about the pressure drop through the absorber and the connected ducting, with values ranging from 50 to 150 mbar. In the present study it is assumed that no exhaust gas recycle is used, and a value of 0.34 MJykg CO2 (150 mbar pressure drop) was chosen according to Fig. 2. Additionally, the power demand for pumps etc. in the CO2 capture process was estimated to be 0.05 MJykg CO2. (3) Efficiency penalty for the extraction of steam from the steam turbine to the stripper in the CO2 absorption plant. The Erem,heat describes the heat consumption, which will be approximately 3–5 MJykg CO2 captured (3.8 used in the calculations). The solubility for CO2 in the absorbent depends on the temperature. The heat consumption is required in order to cycle the absorbent between low (absorber) and high (stripper) temperature. Approximately 50% of the heat
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Fig. 3. The ratio (a) of incremental power reduction to incremental heat output when extracting steam at given pressures from a steam turbine. The calculations are made for a large high-efficiency CC with triple-pressure reheat steam cycle with a condenser pressure of 0.04 bar. The extracted steam is desuperheated in order to deliver saturated steam at all pressures. The condensate return temperature is held constant at 70 8C.
consumption in the stripper is used to break the chemical bond between CO2 and the absorbent, while the rest is the supply of sensible heat for the temperature cycling and heat losses from the system. The heat losses include both convectiveyradiation losses as well as evaporation losses for the absorbent and water from the stripper. The CO2 loading of the absorbent is a very important parameter with respect to heat consumption. There seems to be a potential to reduce the heat consumption down to approximately 3 MJykg CO2 . The a expresses the loss of steam turbine power output compared to the heat of the steam (Fig. 3). When extracting steam, the steam turbine power output is reduced less than the heat content of the steam. The reason for this is that the exergy content of the steam is only a fraction of the heat, and therefore the heat of the extracted steam could not have been converted fully to mechanical power in the steam turbine. For an atmospheric absorption process, the steam temperature for heating the stripper is typically 120–150 8C, which gives a(0.23. The C gives the ratio between formed CO2 and consumed fuel; 44m. The f is the fraction of CO2 captured in the absorption process, and is set to 90%.
(4) Efficiency penalty for compressing the captured CO2 to the transport pressure. The Ecomp describes the consumption (Fig. 4). An end pressure of 100 bar was selected in the present work, and Ecomps0.33 MJykg CO2. 2.2. Concept B The efficiency (hO2yCO2) for the concept with gas turbine power plant and near to stoichiometric combustion with oxygen, producing CO2 and water vapour as the combustion products, is: hO2yCO2shCC,Oy 2 (1)
2 EO2C ECO C y comp R LHV LHV
(2)
(2)
(3)
(1) A standard gas turbine cannot be used for the purpose of a stoichiometric combustion with O2 supplied from an air separation unit. A new gas turbine was defined, with the same technology level as for an existing 250–300 MW class gas turbine that would give a CC efficiency of 58%. It is questionable if such a high efficiency can be obtained because the optimal gas
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Fig. 4. Work for compression CO2 from atmospheric pressure to a given end pressure. Compression with 3 intercoolers (15 8C) and compressor adiabatic efficiency ranging from 75% (high-pressure) to 85% (low-pressure).
turbine pressure ratio is significantly higher than for gas turbines operating with air. The pressure ratio was set to 35 (see Bolland and Sæther, 1993; Bolland and Mathieu, 1998) instead of the more typical 14–18, which is typically found in existing gas turbines. The efficiency of the modified CC (with ‘free’ O2) was calculated to 61–62%, depending upon the temperature of supplied O2 (200–500 8C). In the present work 61.0% was chosen. (2) Efficiency penalty for producing oxygen for the gas turbine combustion. The E O2 describes the energy consumption in the air separation unit. For large cryogenic units, this is typically approximately 0.9–1.0 MJy kg O2 (atmospheric, 97%q purity), of which most is for compressing air to 5–7 bar. Additionally, work is needed for compressing the O2 to slightly above the gas turbine combustor pressure. This compression work constitutes approximately 0.54 MJykg O2 (pressure ratio 35:1, intercooled compression). The R is the ratio between produced CO2 and consumed O2 for a given fuel molecule CmHn, see Eqs. (3) and (4). (3) Efficiency penalty for compressing the captured CO2 to the transport pressure (as explained for concept A). Note that in this concept 100% of the generated CO2 is captured (fs1). The combustion stoichiometry for a general fuel molecule CmHn is
B nE n CmHnqCmq FO2mmCO2q H2O, D G 4 2
(3)
and R, the ratio between produced CO2 and consumed O2, is then: mMWCO2 , nE Cmq FMWO2 D 4G Ž(0.69 kg CO2ykg O2 for CH4.
Rs
B
(4)
2.3. Concept C Auto-thermal reforming consists of both partial oxidation and steam reforming. The partial oxidation, Eq. (7) can be written as the sum of Eqs. (5) and (6). m n CmHnq O2mmCOq H2 2 2
(5)
n n n H2q O2m H2O 2 4 2
(6)
CmHnq
2mqn n O2mmCOq H2O 4 2
(7)
The reaction in Eq. (6) will take place as long as there is oxygen present and this reaction consumes all the hydrogen produced in the reaction given in Eq. (5).
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The steam reforming is: CmHnq2mH2OmmCO2q
4mqn H2 2
(8)
The reaction in Eq. (7) supplies the heat required for the reaction given in Eq. (8). The natural gas feed is desulphurized and prereformed before the ATR-reactor (at f500 8C). For this concept it is assumed that the fuel reforming process is integrated with the CC in order to obtain a high fuel-to-electricity conversion efficiency. The integration comprises the use of compressed air from the gas turbine compressor exit (15 bar), and exchange of steam. The extraction of air from the gas turbine compressor (in excess of 10% of the compressor flow) cannot be done satisfactorily with respect to gas turbine performance and efficiency without replacing the lost volume in front of the turbine. From the ATR, watershift reactors and CO2 capture process, the fuel to the gas turbine (in this study assumed to 53% H2, 43% N2, 2% CO2 and 1% H2O, molecular weight 14) implies a volume that more or less replaces the lost volume caused by the air extraction. The problem with balancing the volumes is well known from IGCC plants. It is assumed that all of the methane in the ATR is reformed. This is not necessarily true. The efficiency (hprecomb) for the pre-combustion decarbonization option is: hprecombs
hCC,H2j tH2OmhevapaATR y 1qc LHV (1)
(2)
CO2 ˙ m c DTaHP,steam Ecomp Cf q reform,ex P y LHV LHV (3)
˙ Eabs.exitm y comp abs,exit LHV
(4)
(9)
(5)
In Eq. (9) all terms are related to the heating value of the natural gas fed to the reforming process (LHV). No flow rates appear in Eq. (9), meaning that the terms are expressed on a specific basis with respect to the flow of natural gas to be reformed. The fuel reforming, water-shift reaction and capture of CO2 take place at a pressure that is about the same as in the gas turbine combustor. There is no term for any penalty related to heating of the stripper in the CO2 capture process. The CO2 capture process here is different from that of concept A because the absorptionydesorption processes operate not only between two temperature levels with different solubility, but there is also a pressure difference between absorptionydesorption causing an additional change in solubility. Therefore less heat is required compared to the CO2 capture process in concept A. The heat demand depends on the stripper pressure. When using a rather low stripper pressure, there is enough
heat available for that purpose from the cooling of the products from the water-shift reactor. The terms in Eq. (9) are explained in the following: (1) Efficiency of a standard CC fired with a fuel containing hydrogen and an LHV of f9 MJykg (as given above) including air extraction of 12–13% of the compressor inlet airflow (oxygenycarbon ratio tO2f0.44 in the ATR-reactor). The hCC,H2 depends strongly on the fuel temperature. A simulation of a CC was done GTPRO (1999) in order to compare the performance using natural gas and the hydrogen-rich fuel with air extraction. If the hydrogen-rich fuel is fed to the gas turbine with a temperature approximately 200–250 8C, the power output and efficiency are very much the same as with natural gas firing (sensitivity for hCC,H2 is f1%-pointy100 K). A value of 58% for hCC,H2 was chosen. The symbol j characterizes the change of LHV in the reformation of the fuel. The j was calculated to 0.9, which means that 10% of the natural gas feed is lost in terms of LHV. This may look like a high cold gas efficiency, but one should bear in mind that the integration with the power plant makes it somewhat difficult to compare j here with other reforming processes. The efficiency is also corrected for the use of fuel for supplementary firing in the HRSG. The value of c was set to 0.15 (the ratio between fuel energy to the HRSG supplementary firing and to the gas turbine), corresponding to an exhaust gas temperature increase caused by the supplementary firing from 600 to 750 8C. It is assumed that all the heat added by the supplementary firing is used for preheating purposes related to the reforming process. (2) Efficiency penalty for extraction of steam from the steam turbine to the ATR-reactor. Steam to carbon ratio (tH2O) of 2 was assumed (both pre-reformer and ATR-reactor included). The steam pressure required for the ATR is approximately 15 bar, and the a is consequently set to 0.31 according to Fig. 3. (3) Efficiency benefit for utilization of high-pressure steam from the cooling of the ATR-reactor products. The flow rate of reformed gas is given by Eq. (10). The specific heat of the reformed gas (cP) was calculated to f1.95 kJy(kg K). The DT for the cooling of the reformed gas was calculated to nearly 600 K. The aHP,steam was estimated to 0.40 (GTPRO, 1999), meaning that for every MJ of steam heat put back to the steam turbine, 0.40 MJ of electricity is produced. This is somewhat lower than in Bolland and Undrum (1998), but this is caused by the difference in a which depends on whether superheated or saturated steam is applied. When cooling the reformer exit flow, ‘metal dusting’ may occur at temperatures approximately 600–700 8C and where CO is present. In order to avoid this problem the reformer exit flow is cooled in a heat exchanger where boiling water keeps the metal temperatures well below the level where such problems may occur. This
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means that the steam cannot be superheated. The steam is returned to the HRSG high-pressure superheater inlet. (4) Efficiency penalty for compressing the captured CO2 to the transport pressure. This is very similar to that of concept A, and the values used in this term are the same as for concept A. An exception is the f, which is set to 99.8%. This may seem high, but is possible for a process where pressure reduction is used to strip off the CO2-gas. In principle, for this process the CO2-gas could be at an elevated pressure before the compression. This requires that the CO2 is captured without fully utilizing the pressure reduction in order to remove it from the absorbent. (5) Efficiency penalty for compressing the fuel gas to the required gas turbine pressure. The air extracted from the gas turbine compressor exit is looping in this process with respect to the pressure. The reformed fuel is injected into the gas turbine in the combustors, which are close to the compressor exit. There must be compensation for pressure drop and the required fuel nozzle pressure difference in this loop, which means that a compressor must be applied. A compressor could be added for compressing the air that goes to the ATR. This is the point in the loop with the minimum flow rate. In the ATR, the flow rate increases as steam and natural gas is added to the air. Compression work is proportional to the inlet temperature, and an obvious possibility for locating the compressor, is at the exit of the CO2 absorber. Calculations were made to evaluate the location with respect to energy consumption. It was found that compressing the air before the ATR requires an intercooled compression (to approximately 100 8C) in order to be at the same level as the compression after the CO2 absorber exit. It was chosen to locate the compressor at the absorber exit. Ecomp was calculated to 0.21 MJykg gas at the CO2 absorber exit. A total compression efficiency of 70% was assumed, and a compressor inlet temperature of 323 K. Ecomp is related to the absorber exit gas flow rate, see Eq. (11) The ATR-reactor exit flow (kgykmol CmHn) can be calculated as B tO
E MWair qtH2OMWH2OF D yO2,air G qMWm,n,
˙ reform,exsmC m
2
(10)
and the flow leaving the exit of the absorber of the CO2 capture process is: tH2O n my tO2 2 ˙ abs,exsm ˙ reform,exyCfy m MWH2O tH2O q1 tO2 2
(11)
The second term in Eq. (11) is the CO2 captured in the absorber in the CO2 capture plant. The last term in
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Eq. (11) is the water remaining after the reforming process, which is to a large extent condensed and drained out before the CO2 capture process. 3. Results Calculations were made for concepts A, B and C using the models described in Eqs. (1), (2) and (9). Parameters were chosen according to the discussions given above for these equations. The total fuel-toelectricity conversion efficiencies were calculated to be: (A) 49.6%; (B) 47.2%; and (C) 45.3%. These numbers include the compression of CO2 to 100 bar. These efficiencies are comparable to a CC with no capture of CO2 giving an efficiency of 58%. The results are given in Fig. 5. (A) The main reduction in efficiency (f4.5%-points) is caused by the heat requirement in the CO2 capture process. The use of mechanical power in connection with the CO2 capture implies a 1.8%-point loss in efficiency, while compression of the captured CO2 results in a close to 2%-points reduction in efficiency. (B) The efficiency penalty for producingycompressing O2 is nearly 12%-points. Some of these losses are recovered (the difference between 61.5 and 58%) because the O2 that is fed to the gas turbine, at an elevated temperature and pressure, brings some exergy into the gas turbine. The efficiency penalty for O2 production (B) seems to be significantly higher than for the capture of CO2 from exhaust gases (A). Cryogenic separation of O2 from air is burdened with larger irreversibility (pressure drop, heat transfer losses) than the absorption process for capturing CO2 from the exhaust gas. (C) A major cause of the reduction in efficiency (f6%-points) compared to a standard CC is the loss of fuel heating value in the reforming process (see bar 1a in Fig. 5). A further reduction (f7%-points) is caused by the use of reformed fuel for supplementary firing in the HRSG. It is assumed that the heat of this fuel does not add directly to power generation in the power plant, but is fully utilized for preheating feed streams in the reforming process. The two mentioned losses should be considered as being interchangeable. The latter loss can be reduced or avoided if one could use the ATR-reactor exit stream for preheating the gas phase streams. Metal dusting is the obstacle here. The medium-pressure steam used in the ATR-reactor gives a 3.8%-points loss in efficiency. All the three losses discussed above can be recovered to some extent to power (f7%-points) by the production of high-pressure saturated steam that comes from the cooling of the ATR-reactor exit stream. The high-pressure steam is utilized in the power plant for power generation. The reduction in the efficiency caused by the compression of CO2 is approximately 2%-points. Finally, there is a
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Fig. 5. Efficiency profiles for the three concepts. The numbers in parentheses in the vertical text refer to the different terms in Eqs. (1), (2) and (9) for concepts A, B and C, respectively. (a) Separation of CO2 from exhaust gas coming from a standard gas turbine CC, using chemical absorption by amine solutions. (b) CC using a gas turbine with near to stoichiometric combustion with oxygen from an air separation unit as oxidizing agent, including exhaust recycle, producing CO2 and water vapour as the combustion products. (c) Decarbonization, which comprises an air-blown ATR for natural gas, water-shift reactors and a high-pressure CO2 capture process based on chemical absorption. The hydrogen-rich resulting gas is combusted in a gas turbine CC. The black bars represent efficiencies and belong to the ‘Efficiency’-axis. The grey bars represent efficiency penaltiesybenefits and belong to the ‘Efficiency reduction’-axis.
1.3%-point reduction due to the compression of the reformed fuel gas before the gas turbine. It is assumed that there is no methane going through the reforming process, though there will be some in practise. One consequence of that is that there will be more CO2 emissions caused by methane combustion in the gas turbine. Another consequence is that the plant efficiency is enhanced as the fraction of methane in the fuel increases. 4. Technological maturity For concept A, the gas turbineysteam turbine cycle components need only minor or no modifications. The CO2 capture technology based on chemical absorption, is used for natural gas (at elevated pressures) and there
are also a number of applications with capture at atmospheric pressure. However, for large-scale applications, such as in power generation, this technology has yet to prove acceptable in terms of energy consumption and levels of toxic waste effluent. This technology can be regarded as commercially available, but should be developed somewhat further before large-scale application. For concept B, a major disadvantage is the need to develop a gas turbine operating on mainly CO2 as the working fluid that uses stoichiometric combustion. For such a gas turbine it is not a matter of modifying existing equipment, but rather a completely new design. On the other hand, air separation is a mature technology. If such a gas turbine could be developed with advanced technology, such as in modern power generation gas
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turbines, this concept looks attractive because of its simplicity. The major drawback is that it makes no sense using such a gas turbine if CO2 is not collected and stored. Despite the Kyoto agreement, it is difficult to foresee a major market for such a gas turbine. On the other hand, one could realize this concept more easily by using a conventional steam plant with a steam boiler modified for stoichiometric combustion, including recycling of the combustion products in order to reduce the flame temperature. With a conventional steam cycle, attainable efficiencies would be 30–35% compared to 47–48% for concept B. The gas turbine technology for this concept does not exist, and it is not likely that such a gas turbine will be developed in the foreseeable future. Concept C consists of components which by themselves can be regarded as proven technologies. This also includes to some extent the combustion of hydrogenrich fuels in gas turbines. The integration of the gas turbineysteam turbine cycles with the pre-combustion decarbonization process (slightly modified H2-plant) is not a mature technology despite a number of similar applications for IGCC plants. One can question to what extent the most advanced high efficiency gas turbine technology can be applied. The fraction of hydrogen is approximately 50 vol.%. This is much above what is acceptable for natural gas low-NOX burners in modern gas turbines. However, tests have been carried out with IGCC burners (Todd and Battista, 2000). The results of these tests are very promising with respect to NOX formation when the fuel contains approximately 50% or less hydrogen. NOX emission values of approximately 10 ppm (15% O2, dry) are reported. Combustion issues should be addressed, but except for that it seems that there are no major obstacles for commercial implementation of this technology. 5. Conclusions A novel method of comparing power plant concepts including CO2 capture is presented. Instead of using extensive flowsheet calculations for these concepts, reaction equations for conservation of molecular species together with specific energy consumption numbers for the different process sections are used to characterize the concepts. Compared to results from rigorous simulations, which typically consist of a lot of detailed information and an aggregated number describing the plant efficiency, the present method may make it easier to understand the relation between loss mechanisms and total efficiency. When selecting between these three concepts (A, B and C), efficiency will probably not be the major decisive factor based on the results of the present calculations. It is obvious that investment costs will be
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very high. It is likely that the investment cost of the three concepts would more than double that of a large standard CC power plant that is comparable in power output. The fuel cost will be higher due to reduced efficiency, and there will be increased operating costs as well as reduced availability. The differences in efficiencies do not rule out any of the concepts. Only concepts A and C are commercially available technologies. One should bear in mind that the present study is about reducing emissions of CO2 from a technology that in fact does have low emissions without using any particular measures for removing CO2 (natural gas, f60% efficiency). If CO2 from large point sources such as power plants is to be collected and stored, natural gas-fired CCs may not be the most obvious candidate. Coal fired power plants should also be regarded as an alternative. Nomenclature C (kgykmol): ratio between formed CO2 and fuel, 44m cP (MJy(kg K)): specific heat capacity of reformed gas 2 ECO comp (MJykg CO2): power requirement for compression of CO2 2 ECO rem,heat (MJykg CO2): heat required for atmospheric stripping of CO2 from absorbent 2 (MJykg CO2): mechanical work required for ECO rem,mech atmospheric stripping process EO2 (MJykg O2): energy required for producing oxygen (MJykg): energy required for compressing the Eabs.exit comp absorber exit flow (GT-fuel to the required gas turbine pressure f (–): fraction of CO2 captured in the chemical absorption process hevap (MJykmol): heat of condensation for steam to ATR-reactor LHV (MJykmol): lower heating value for natural gas m (mol):number of mole carbon in fuel molecule MW (kgykmol): molecular weight MWm,n (kgykmol): molecular weight fuel molecule, 12mqn ˙ abs,ex (kgykmol): gas flow rate per kmol of natural m gas feed (absorber exit in CO2 capture process) ˙ reform,ex (kgykmol): reformed gas flow rate per kmol m of natural gas feed (ATR exit) n (mol): number of mole hydrogen in fuel molecule R (kg CO2 ykg O2): ratio between produced CO2 and consumed O2 for CmHn y (–): mole fraction
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a (MJel yMJheat): steam turbine, ratio of incremental power reduction to incremental heat output hCC (–): efficiency for a natural gas-fired CC hCC,H2 (–): efficiency for a CC integrated with ATR hCC,O2 (–): efficiency for a CC with stoichiometric combustion with O2 tO2 (mol O2ymol C): oxygen to carbon ratio for the ATR-reactor tH2O (mol H2Oymol C): steam to carbon ratio for the ATR-reactor j (MJyMJ): LHV ratio of reformed fuel and natural gas feed (concept C) c (MJyMJ): ratio between fuel energy to HRSG supplementary firing and GT (concept C)
References Akai, M., Kagajo, T., 1994. Performance evaluation of fossil power plant with CO2 recovery and sequestering system. Proceedings of the Second International Conference on Carbon Dioxide Removal, Kyoto. Allam, R.J., Spilsbury, C.G., 1992. A study of extraction of CO2 from the flue gas of a 500 MW pulverised coal fired boiler. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. Bolland, O., Sæther, S., 1993. New concepts for natural gas fired power plants which simplify the recovery of carbon dioxide. Energy Convers. Manage. 33 (5–8), 467–475. Bolland, O., Undrum, H., 1998. Removal of CO2 from gas turbine power plants: evaluation of pre- and postcombustion methods. Proceedings of the Fourth International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland. Bolland, O., Mathieu, P., 1998. Comparison of two CO2 removal options in combined cycle power plants. Energy Convers. Manage. 39 (16–18), 1653–1663. Undrum, H., Bolland, O., Aarebrot, E., 2000. Economical assessment of natural gas fired combined cycle power plant with CO2 capture and sequestration. Presented at the Fifth International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, August 2000. Bolland, O., Kvamsdal, H.K., Boden, J.C., 2001a. A thermodynamic comparison of the oxy-fuel power cycles watercycle, graz-cycle and matiant-cycle. Published in the Proceedings of The International Conference Power Gener` ation and Sustainable Development, Liege, Belgium, 8–9 October. Bolland, O., Ertesvaag, I.S., Speich, D., 2001b, Exergy analysis of gas-turbine Cocmbined Cycle with CO capture using auto-thermal reforming of natural gas. Published in the Proceedings of the International Conference Power Genera` tion and Sustainable Development, Liege, Belgium, 8–9 October. Bram, S., de Ruyck, J., 1994. Exergy analysis and design of
mixed CO2 ysteam gas turbine cycles. Proceedings of the Second International Conference on Carbon Dioxide Removal, Kyoto. Chakma, A., 1995. Separation of CO2 and SO2 from flue gas streams by liquid membranes. Energy Convers. Manage. 36 (6–9), 405–410. De Ruyck, J., 1992. Efficient CO2 capture through a combined steam and CO2 gas turbine cycle. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. Erga, O., Juliussen, O., Lidal, H., 1995. Carbon dioxide recovery by means of aqueous amines. Energy Convers. Manage. 36 (6–9), 387–392. ¨ H., 1997. Separation of carbon Falk-Pedersen, O., Dannstrom, dioxide from offshore gas turbine exhaust. Energy Convers. Manage. 38 (Suppl.), S81–S86. Feron, P.H.M., Jansen, A.E., 1997. The production of carbon dioxide from flue gas by membrane gas absorption. Energy Convers. Manage. 38 (Suppl.), S93–S98. ¨ Gottlicher, G., Pruschek, R., 1996. Comparison of CO2 removal systems for fossil-fuelled power plant processes. Proceedings of the Third International Conference on Carbon Dioxide Removal, Cambridge. GTPRO, 1999. Thermoflow Inc., Gas TurbineyCombined Cycle computational code. Hendriks, C.A., Blok, K., 1992, Carbon dioxide recovery using a dual gas turbine IGCC plant. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. IEA Report PH2y19, 1998. Precombustion decarbonisation. Study by Foster-Wheeler for IEA GHG and Statoil. Lozza, G., Chiesa P., 2000, Natural gas decarbonization to reduce CO2 emission from combined cycles. Part A: partial ¨ Oxidation. Presented at the ASME Turbo Expo in Munchen, 8–12 May, 2000-GT-163. Mathieu, P., 2001, Zero emission power plants as future CO2 control technologies. International Symposium on Greenhouse Gas Control and Utilization, American Chemical Society meeting, San Diego, 2 April. Meisen, A., Shuai, X., 1997. Research and development issues in CO2 capture. Energy Convers. Manage. 38, S37–S42. Mimura, T., Satsumi, S., Iijima, M., Mitsuoka, S., 1999, Development on energy saving technology for flue gas carbon dioxide recovery by the chemical absorption method and steam system in power plant. Proceedings of the Fouth International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland, 71–76. Steinberg, M., 1994. The Hy–C process (thermal decomposition of natural gas) potentially the lowest cost source of hydrogen with the least CO2 emission. Proceedings of the Second International Conference on Carbon Dioxide Removal, Kyoto. Suda, T., Fujii, M., Yoshida, K., 1992. Development of flue gas carbon dioxide recovery technology. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. Todd, D.M., Battista, R.A., 2000, Demonstrated applicability of hydrogen fuel for gas turbines. Presented at the IchemE conference ‘Gasification 4 the future’, Amsterdam, 11–13 April.
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Olav Bolland graduated as M.Sc. from the Norwegian University of Science and Technology in 1986, and as Dr Ing in 1990. He has since then been working as associate professor at the Department of Thermal Energy and Hydropower. The main focus of his work is on thermal power generation in general and CO2 capture in particular.
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Henriette Undrum graduated as M.Sc. from the Norwegian University of Science and Technology in 1995. She worked the two years for the research foundation SINTEF before she started to work for the oil&gas company Statoil. The main focus of her work has been on technology surveys and CO2 capture.
A novel methodology for comparing CO2 capture options for natural gas-fired combined cycle plants Olav Bolland, Henriette Undruma,b,* a
Norwegian University of Science and Technology, NO-7491 Trondheim, Norway b Statoil R&D Centre, Postuttak, NO-7004 Trondheim, Norway Received 21 March 2002; accepted 9 July 2002
Abstract Three concepts for capturing CO2 from natural gas-fired combined gasysteam turbine power plants are evaluated and compared in this paper: (A) separation of CO2 from exhaust gas coming from a standard gas turbine power plant, using chemical absorption by amine solutions. (B) Gas turbine combined cycle (CC) using a semi-closed gas turbine with near to stoichiometric combustion using oxygen from an air separation unit as an oxidizing agent. This produces CO2 and water vapour as the combustion products. The gas turbine working fluid is mainly CO2. (C) Decarbonization, which comprises an autothermal reforming reactor with air-blown catalytic partial oxidation of gas natural gas, a water-shift reaction and a high-pressure CO2 capture process. The hydrogen-rich reformed fuel gas is combusted in a gas turbine CC, which is integrated (air, steam and heat) with the decarbonization process. A novel method is presented that compares power plant concepts including CO2 . Instead of using extensive thermodynamic calculations for these concepts, reaction equations for the conservation of molecular species together with specific energy consumption numbers for the different process sections are used to characterize the concepts with respect to fuel-to-electricity conversion efficiency. With a combined gasysteam turbine power plant giving 58% total fuel-toelectricity conversion efficiencies (no CO2 capture), calculations for the concepts with CO2 capture including CO2 compression gave: (A) 49.6%; (B) 47.2%; and (C) 45.3%. The mechanisms leading to a reduced efficiency for concepts A–C are discussed and quantified and compared to combined gasysteam turbine with no capture of CO2. 䊚 2002 Elsevier Science Ltd. All rights reserved. Keywords: Gas turbine; Combined cycle; CO2 capture; Absorption; Reforming; Air separation
1. Introduction The background to this paper are the man-made emissions of CO2, which may increase the greenhouse effect, so that unwanted climatic changes take place. Among the various sources of man-made emissions of CO2, this paper deals with power generation from *Corresponding author. Tel.: q47-73591604; fax: q4773598390. E-mail address: [email protected] (O. Bolland).
natural gas-fired gas turbine power plants where the CO2-gas is collected for storage on a long-term basis. It is assumed that 90% of the generated CO2 is to be captured and compressed to 100 bar. The natural gas used in the calculations consists of 80 vol.% methane, with a molecular weight of 20.6 and with a lower heating value of 45.5 MJykg. Three concepts (Fig. 1) for collecting CO2 from gas turbine power plants are evaluated and compared: (A) Separation of CO2 from exhaust gas coming from a standard gas turbine combined cycle (CC), using
1093-0191/03/$ - see front matter 䊚 2002 Elsevier Science Ltd. All rights reserved. PII: S 1 0 9 3 - 0 1 9 1 Ž 0 2 . 0 0 0 8 5 - 0
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Fig. 1. Three natural gas-fired power plant concepts with collection of CO2.
chemical absorption by amine solutions (Allam and Spilsbury, 1992; Suda et al., 1992; Bolland and Sæther, 1993; Erga et al., 1995; Chakma, 1995; Meisen and Shuai, 1997; Feron and Jansen, 1997; Falk-Pedersen ¨ 1997; Mimura et al., 1999; Undrum et and Dannstrom, al., 2000). The exhaust gas from the gas turbine CC goes into the CO2 capture plant consisting of exhaust gas preparation (cooling and a booster to overcome the exhaust gas pressure drop in the CO2 capture plant), CO2 absorption, amine solution CO2 stripping and CO2 compression. Low-pressure steam extracted from the steam turbine in the CC is used to cover the heat demand in the stripping process. (B) Gas turbine CC using a semi-closed gas turbine with near to stoichiometric combustion using oxygen (97%q purity) from an air separation unit as an oxidizing agent, and CO2 and water vapour are produced as the combustion products. The gas turbine working fluid is mainly CO2 (Hendriks and Blok, 1992; De Ruyck, 1992; Bram and de Ruyck, 1994; Bolland and Sæther, 1993 Bolland and Mathieu, 1998). There are various ideas about cycles including combustion with pure oxygen. Most of these imply the use of working fluid recycling in order to maintain turbine inlet temperatures within acceptable levels. In some cases the recycled working fluid may be liquid water (Mathieu, 2001; Bolland et al., 2001a), while in other cases it may be mainly gaseous CO2. The latter is chosen in the present work. (C) Decarbonization, which comprises a pre-reformer and an air-blown autothermal reforming reactor (ATR) for natural gas, water-shift reactors and a high-pressure CO2 capture process based on chemical absorption. The hydrogen-rich resulting gas is combusted in a gas turbine CC, which is integrated with the decarbonization process (Hendriks and Blok, 1992; Steinberg, 1994; IEA Report PH2y19, 1998). Air from the gas turbine
compressor exit is fed to the ATR. Medium-pressure steam is taken from the steam cycle and mixed with the natural gas before reforming. There is also integration between the power plant and the reforming process with respect to preheating of feed streams in the reformer. The heat recovery steam generator (HRSG) in the power plant has supplementary firing from approximately 600 to 750 8C. The exhaust gas heat between the two given temperatures is utilized for reformer preheating. The steam production based on exhaust gas heat, from 600 8C and downwards, is very much the same as for a gas turbine CC without any supplementary firing of the exhaust gas. There are different methods for reforming natural gas into a hydrogen-rich fuel, which enables pre-combustion capture of CO2. An air-blown ATR, together with water gas shift reactors and CO2 capture process; produce a fuel with approximately 50 vol.% hydrogen. Modern gas turbines with low-NOX combustors are restricted with regard to the hydrogen concentration of the fuel. Traditional steam reforming processes would, in this application, produce a fuel for the gas turbine with significantly higher hydrogen content. Therefore, the ATR method was chosen as a case in the present work (IEA Report PH2y19, 1998; Undrum et al., 2000; Lozza and Chiesa, 2000; Bolland et al., 2001b). This concept has the potential of being applied with gasification of solid fuels and integration of high temperature SOFC. Models that describe the fuel-to-electricity conversion efficiency and the mechanisms leading to reduced efficiency compared to power cycles with no capture of CO2 have been made to facilitate the comparison of these three concepts. The idea of these models is to express the efficiency of power plant concepts with CO2 capture based on a standard natural gas-fired CC, using specific energy consumption numbers to relate the efficiency penalties of the various process units to the
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Fig. 2. Fan work for compressing the exhaust gas going through the absorber, related to the content of CO2. The change in CO2 indicates the change in exhaust gas volumetric flow.
total plant efficiencies. The motivation for using these specific energy consumption numbers is to give a better understanding of energy consumption and efficiencies in the processes as well document and use years of accumulated knowledge from previous publications and ¨ studies. Previous work (Gottlicher and Pruschek, 1996; Akai and Kagajo, 1994) has given reviews of efficiencies for different power generation concepts including CO2 capture. The contribution of this paper is providing improved methodology for comparing options, and giving a relevant example reflecting the state of the art in gas turbine technology. 2. Models 2.1. Concept A The efficiency (hexh.abs.) for the concept with separation of CO2 from exhaust gas coming from a standard gas turbine power plant, using chemical absorption by amine solutions is: hexh.abs.shCCy (1)
2 ECO ECO2 a Cf rem,mechC y rem,heat str,atm LHV LHV
(2)
ECO2 Cf y comp LHV
(3)
(1)
(4)
(1) Efficiency of a standard natural gas-fired CC (set to 58%).
(2) Efficiency penalty for consumption of mechanical work or electricity in the CO2 absorption process. The main consumer is the exhaust gas fan, which is required in order to overcome the exhaust gas pressure drop in the absorption tower. The Erem,mech describes the consumption, see Fig. 2, and depends upon the pressure drop and volumetric flow rate. In Fig. 2, the fan work is given as a function of the CO2 content. If exhaust gas recycle back to the gas turbine compressor is used, the fan work can be reduced. For a modern gas turbine, approximately 30–40% of the exhaust may be recycled, in principle. However, there is some uncertainty about the pressure drop through the absorber and the connected ducting, with values ranging from 50 to 150 mbar. In the present study it is assumed that no exhaust gas recycle is used, and a value of 0.34 MJykg CO2 (150 mbar pressure drop) was chosen according to Fig. 2. Additionally, the power demand for pumps etc. in the CO2 capture process was estimated to be 0.05 MJykg CO2. (3) Efficiency penalty for the extraction of steam from the steam turbine to the stripper in the CO2 absorption plant. The Erem,heat describes the heat consumption, which will be approximately 3–5 MJykg CO2 captured (3.8 used in the calculations). The solubility for CO2 in the absorbent depends on the temperature. The heat consumption is required in order to cycle the absorbent between low (absorber) and high (stripper) temperature. Approximately 50% of the heat
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Fig. 3. The ratio (a) of incremental power reduction to incremental heat output when extracting steam at given pressures from a steam turbine. The calculations are made for a large high-efficiency CC with triple-pressure reheat steam cycle with a condenser pressure of 0.04 bar. The extracted steam is desuperheated in order to deliver saturated steam at all pressures. The condensate return temperature is held constant at 70 8C.
consumption in the stripper is used to break the chemical bond between CO2 and the absorbent, while the rest is the supply of sensible heat for the temperature cycling and heat losses from the system. The heat losses include both convectiveyradiation losses as well as evaporation losses for the absorbent and water from the stripper. The CO2 loading of the absorbent is a very important parameter with respect to heat consumption. There seems to be a potential to reduce the heat consumption down to approximately 3 MJykg CO2 . The a expresses the loss of steam turbine power output compared to the heat of the steam (Fig. 3). When extracting steam, the steam turbine power output is reduced less than the heat content of the steam. The reason for this is that the exergy content of the steam is only a fraction of the heat, and therefore the heat of the extracted steam could not have been converted fully to mechanical power in the steam turbine. For an atmospheric absorption process, the steam temperature for heating the stripper is typically 120–150 8C, which gives a(0.23. The C gives the ratio between formed CO2 and consumed fuel; 44m. The f is the fraction of CO2 captured in the absorption process, and is set to 90%.
(4) Efficiency penalty for compressing the captured CO2 to the transport pressure. The Ecomp describes the consumption (Fig. 4). An end pressure of 100 bar was selected in the present work, and Ecomps0.33 MJykg CO2. 2.2. Concept B The efficiency (hO2yCO2) for the concept with gas turbine power plant and near to stoichiometric combustion with oxygen, producing CO2 and water vapour as the combustion products, is: hO2yCO2shCC,Oy 2 (1)
2 EO2C ECO C y comp R LHV LHV
(2)
(2)
(3)
(1) A standard gas turbine cannot be used for the purpose of a stoichiometric combustion with O2 supplied from an air separation unit. A new gas turbine was defined, with the same technology level as for an existing 250–300 MW class gas turbine that would give a CC efficiency of 58%. It is questionable if such a high efficiency can be obtained because the optimal gas
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Fig. 4. Work for compression CO2 from atmospheric pressure to a given end pressure. Compression with 3 intercoolers (15 8C) and compressor adiabatic efficiency ranging from 75% (high-pressure) to 85% (low-pressure).
turbine pressure ratio is significantly higher than for gas turbines operating with air. The pressure ratio was set to 35 (see Bolland and Sæther, 1993; Bolland and Mathieu, 1998) instead of the more typical 14–18, which is typically found in existing gas turbines. The efficiency of the modified CC (with ‘free’ O2) was calculated to 61–62%, depending upon the temperature of supplied O2 (200–500 8C). In the present work 61.0% was chosen. (2) Efficiency penalty for producing oxygen for the gas turbine combustion. The E O2 describes the energy consumption in the air separation unit. For large cryogenic units, this is typically approximately 0.9–1.0 MJy kg O2 (atmospheric, 97%q purity), of which most is for compressing air to 5–7 bar. Additionally, work is needed for compressing the O2 to slightly above the gas turbine combustor pressure. This compression work constitutes approximately 0.54 MJykg O2 (pressure ratio 35:1, intercooled compression). The R is the ratio between produced CO2 and consumed O2 for a given fuel molecule CmHn, see Eqs. (3) and (4). (3) Efficiency penalty for compressing the captured CO2 to the transport pressure (as explained for concept A). Note that in this concept 100% of the generated CO2 is captured (fs1). The combustion stoichiometry for a general fuel molecule CmHn is
B nE n CmHnqCmq FO2mmCO2q H2O, D G 4 2
(3)
and R, the ratio between produced CO2 and consumed O2, is then: mMWCO2 , nE Cmq FMWO2 D 4G Ž(0.69 kg CO2ykg O2 for CH4.
Rs
B
(4)
2.3. Concept C Auto-thermal reforming consists of both partial oxidation and steam reforming. The partial oxidation, Eq. (7) can be written as the sum of Eqs. (5) and (6). m n CmHnq O2mmCOq H2 2 2
(5)
n n n H2q O2m H2O 2 4 2
(6)
CmHnq
2mqn n O2mmCOq H2O 4 2
(7)
The reaction in Eq. (6) will take place as long as there is oxygen present and this reaction consumes all the hydrogen produced in the reaction given in Eq. (5).
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The steam reforming is: CmHnq2mH2OmmCO2q
4mqn H2 2
(8)
The reaction in Eq. (7) supplies the heat required for the reaction given in Eq. (8). The natural gas feed is desulphurized and prereformed before the ATR-reactor (at f500 8C). For this concept it is assumed that the fuel reforming process is integrated with the CC in order to obtain a high fuel-to-electricity conversion efficiency. The integration comprises the use of compressed air from the gas turbine compressor exit (15 bar), and exchange of steam. The extraction of air from the gas turbine compressor (in excess of 10% of the compressor flow) cannot be done satisfactorily with respect to gas turbine performance and efficiency without replacing the lost volume in front of the turbine. From the ATR, watershift reactors and CO2 capture process, the fuel to the gas turbine (in this study assumed to 53% H2, 43% N2, 2% CO2 and 1% H2O, molecular weight 14) implies a volume that more or less replaces the lost volume caused by the air extraction. The problem with balancing the volumes is well known from IGCC plants. It is assumed that all of the methane in the ATR is reformed. This is not necessarily true. The efficiency (hprecomb) for the pre-combustion decarbonization option is: hprecombs
hCC,H2j tH2OmhevapaATR y 1qc LHV (1)
(2)
CO2 ˙ m c DTaHP,steam Ecomp Cf q reform,ex P y LHV LHV (3)
˙ Eabs.exitm y comp abs,exit LHV
(4)
(9)
(5)
In Eq. (9) all terms are related to the heating value of the natural gas fed to the reforming process (LHV). No flow rates appear in Eq. (9), meaning that the terms are expressed on a specific basis with respect to the flow of natural gas to be reformed. The fuel reforming, water-shift reaction and capture of CO2 take place at a pressure that is about the same as in the gas turbine combustor. There is no term for any penalty related to heating of the stripper in the CO2 capture process. The CO2 capture process here is different from that of concept A because the absorptionydesorption processes operate not only between two temperature levels with different solubility, but there is also a pressure difference between absorptionydesorption causing an additional change in solubility. Therefore less heat is required compared to the CO2 capture process in concept A. The heat demand depends on the stripper pressure. When using a rather low stripper pressure, there is enough
heat available for that purpose from the cooling of the products from the water-shift reactor. The terms in Eq. (9) are explained in the following: (1) Efficiency of a standard CC fired with a fuel containing hydrogen and an LHV of f9 MJykg (as given above) including air extraction of 12–13% of the compressor inlet airflow (oxygenycarbon ratio tO2f0.44 in the ATR-reactor). The hCC,H2 depends strongly on the fuel temperature. A simulation of a CC was done GTPRO (1999) in order to compare the performance using natural gas and the hydrogen-rich fuel with air extraction. If the hydrogen-rich fuel is fed to the gas turbine with a temperature approximately 200–250 8C, the power output and efficiency are very much the same as with natural gas firing (sensitivity for hCC,H2 is f1%-pointy100 K). A value of 58% for hCC,H2 was chosen. The symbol j characterizes the change of LHV in the reformation of the fuel. The j was calculated to 0.9, which means that 10% of the natural gas feed is lost in terms of LHV. This may look like a high cold gas efficiency, but one should bear in mind that the integration with the power plant makes it somewhat difficult to compare j here with other reforming processes. The efficiency is also corrected for the use of fuel for supplementary firing in the HRSG. The value of c was set to 0.15 (the ratio between fuel energy to the HRSG supplementary firing and to the gas turbine), corresponding to an exhaust gas temperature increase caused by the supplementary firing from 600 to 750 8C. It is assumed that all the heat added by the supplementary firing is used for preheating purposes related to the reforming process. (2) Efficiency penalty for extraction of steam from the steam turbine to the ATR-reactor. Steam to carbon ratio (tH2O) of 2 was assumed (both pre-reformer and ATR-reactor included). The steam pressure required for the ATR is approximately 15 bar, and the a is consequently set to 0.31 according to Fig. 3. (3) Efficiency benefit for utilization of high-pressure steam from the cooling of the ATR-reactor products. The flow rate of reformed gas is given by Eq. (10). The specific heat of the reformed gas (cP) was calculated to f1.95 kJy(kg K). The DT for the cooling of the reformed gas was calculated to nearly 600 K. The aHP,steam was estimated to 0.40 (GTPRO, 1999), meaning that for every MJ of steam heat put back to the steam turbine, 0.40 MJ of electricity is produced. This is somewhat lower than in Bolland and Undrum (1998), but this is caused by the difference in a which depends on whether superheated or saturated steam is applied. When cooling the reformer exit flow, ‘metal dusting’ may occur at temperatures approximately 600–700 8C and where CO is present. In order to avoid this problem the reformer exit flow is cooled in a heat exchanger where boiling water keeps the metal temperatures well below the level where such problems may occur. This
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means that the steam cannot be superheated. The steam is returned to the HRSG high-pressure superheater inlet. (4) Efficiency penalty for compressing the captured CO2 to the transport pressure. This is very similar to that of concept A, and the values used in this term are the same as for concept A. An exception is the f, which is set to 99.8%. This may seem high, but is possible for a process where pressure reduction is used to strip off the CO2-gas. In principle, for this process the CO2-gas could be at an elevated pressure before the compression. This requires that the CO2 is captured without fully utilizing the pressure reduction in order to remove it from the absorbent. (5) Efficiency penalty for compressing the fuel gas to the required gas turbine pressure. The air extracted from the gas turbine compressor exit is looping in this process with respect to the pressure. The reformed fuel is injected into the gas turbine in the combustors, which are close to the compressor exit. There must be compensation for pressure drop and the required fuel nozzle pressure difference in this loop, which means that a compressor must be applied. A compressor could be added for compressing the air that goes to the ATR. This is the point in the loop with the minimum flow rate. In the ATR, the flow rate increases as steam and natural gas is added to the air. Compression work is proportional to the inlet temperature, and an obvious possibility for locating the compressor, is at the exit of the CO2 absorber. Calculations were made to evaluate the location with respect to energy consumption. It was found that compressing the air before the ATR requires an intercooled compression (to approximately 100 8C) in order to be at the same level as the compression after the CO2 absorber exit. It was chosen to locate the compressor at the absorber exit. Ecomp was calculated to 0.21 MJykg gas at the CO2 absorber exit. A total compression efficiency of 70% was assumed, and a compressor inlet temperature of 323 K. Ecomp is related to the absorber exit gas flow rate, see Eq. (11) The ATR-reactor exit flow (kgykmol CmHn) can be calculated as B tO
E MWair qtH2OMWH2OF D yO2,air G qMWm,n,
˙ reform,exsmC m
2
(10)
and the flow leaving the exit of the absorber of the CO2 capture process is: tH2O n my tO2 2 ˙ abs,exsm ˙ reform,exyCfy m MWH2O tH2O q1 tO2 2
(11)
The second term in Eq. (11) is the CO2 captured in the absorber in the CO2 capture plant. The last term in
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Eq. (11) is the water remaining after the reforming process, which is to a large extent condensed and drained out before the CO2 capture process. 3. Results Calculations were made for concepts A, B and C using the models described in Eqs. (1), (2) and (9). Parameters were chosen according to the discussions given above for these equations. The total fuel-toelectricity conversion efficiencies were calculated to be: (A) 49.6%; (B) 47.2%; and (C) 45.3%. These numbers include the compression of CO2 to 100 bar. These efficiencies are comparable to a CC with no capture of CO2 giving an efficiency of 58%. The results are given in Fig. 5. (A) The main reduction in efficiency (f4.5%-points) is caused by the heat requirement in the CO2 capture process. The use of mechanical power in connection with the CO2 capture implies a 1.8%-point loss in efficiency, while compression of the captured CO2 results in a close to 2%-points reduction in efficiency. (B) The efficiency penalty for producingycompressing O2 is nearly 12%-points. Some of these losses are recovered (the difference between 61.5 and 58%) because the O2 that is fed to the gas turbine, at an elevated temperature and pressure, brings some exergy into the gas turbine. The efficiency penalty for O2 production (B) seems to be significantly higher than for the capture of CO2 from exhaust gases (A). Cryogenic separation of O2 from air is burdened with larger irreversibility (pressure drop, heat transfer losses) than the absorption process for capturing CO2 from the exhaust gas. (C) A major cause of the reduction in efficiency (f6%-points) compared to a standard CC is the loss of fuel heating value in the reforming process (see bar 1a in Fig. 5). A further reduction (f7%-points) is caused by the use of reformed fuel for supplementary firing in the HRSG. It is assumed that the heat of this fuel does not add directly to power generation in the power plant, but is fully utilized for preheating feed streams in the reforming process. The two mentioned losses should be considered as being interchangeable. The latter loss can be reduced or avoided if one could use the ATR-reactor exit stream for preheating the gas phase streams. Metal dusting is the obstacle here. The medium-pressure steam used in the ATR-reactor gives a 3.8%-points loss in efficiency. All the three losses discussed above can be recovered to some extent to power (f7%-points) by the production of high-pressure saturated steam that comes from the cooling of the ATR-reactor exit stream. The high-pressure steam is utilized in the power plant for power generation. The reduction in the efficiency caused by the compression of CO2 is approximately 2%-points. Finally, there is a
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Fig. 5. Efficiency profiles for the three concepts. The numbers in parentheses in the vertical text refer to the different terms in Eqs. (1), (2) and (9) for concepts A, B and C, respectively. (a) Separation of CO2 from exhaust gas coming from a standard gas turbine CC, using chemical absorption by amine solutions. (b) CC using a gas turbine with near to stoichiometric combustion with oxygen from an air separation unit as oxidizing agent, including exhaust recycle, producing CO2 and water vapour as the combustion products. (c) Decarbonization, which comprises an air-blown ATR for natural gas, water-shift reactors and a high-pressure CO2 capture process based on chemical absorption. The hydrogen-rich resulting gas is combusted in a gas turbine CC. The black bars represent efficiencies and belong to the ‘Efficiency’-axis. The grey bars represent efficiency penaltiesybenefits and belong to the ‘Efficiency reduction’-axis.
1.3%-point reduction due to the compression of the reformed fuel gas before the gas turbine. It is assumed that there is no methane going through the reforming process, though there will be some in practise. One consequence of that is that there will be more CO2 emissions caused by methane combustion in the gas turbine. Another consequence is that the plant efficiency is enhanced as the fraction of methane in the fuel increases. 4. Technological maturity For concept A, the gas turbineysteam turbine cycle components need only minor or no modifications. The CO2 capture technology based on chemical absorption, is used for natural gas (at elevated pressures) and there
are also a number of applications with capture at atmospheric pressure. However, for large-scale applications, such as in power generation, this technology has yet to prove acceptable in terms of energy consumption and levels of toxic waste effluent. This technology can be regarded as commercially available, but should be developed somewhat further before large-scale application. For concept B, a major disadvantage is the need to develop a gas turbine operating on mainly CO2 as the working fluid that uses stoichiometric combustion. For such a gas turbine it is not a matter of modifying existing equipment, but rather a completely new design. On the other hand, air separation is a mature technology. If such a gas turbine could be developed with advanced technology, such as in modern power generation gas
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turbines, this concept looks attractive because of its simplicity. The major drawback is that it makes no sense using such a gas turbine if CO2 is not collected and stored. Despite the Kyoto agreement, it is difficult to foresee a major market for such a gas turbine. On the other hand, one could realize this concept more easily by using a conventional steam plant with a steam boiler modified for stoichiometric combustion, including recycling of the combustion products in order to reduce the flame temperature. With a conventional steam cycle, attainable efficiencies would be 30–35% compared to 47–48% for concept B. The gas turbine technology for this concept does not exist, and it is not likely that such a gas turbine will be developed in the foreseeable future. Concept C consists of components which by themselves can be regarded as proven technologies. This also includes to some extent the combustion of hydrogenrich fuels in gas turbines. The integration of the gas turbineysteam turbine cycles with the pre-combustion decarbonization process (slightly modified H2-plant) is not a mature technology despite a number of similar applications for IGCC plants. One can question to what extent the most advanced high efficiency gas turbine technology can be applied. The fraction of hydrogen is approximately 50 vol.%. This is much above what is acceptable for natural gas low-NOX burners in modern gas turbines. However, tests have been carried out with IGCC burners (Todd and Battista, 2000). The results of these tests are very promising with respect to NOX formation when the fuel contains approximately 50% or less hydrogen. NOX emission values of approximately 10 ppm (15% O2, dry) are reported. Combustion issues should be addressed, but except for that it seems that there are no major obstacles for commercial implementation of this technology. 5. Conclusions A novel method of comparing power plant concepts including CO2 capture is presented. Instead of using extensive flowsheet calculations for these concepts, reaction equations for conservation of molecular species together with specific energy consumption numbers for the different process sections are used to characterize the concepts. Compared to results from rigorous simulations, which typically consist of a lot of detailed information and an aggregated number describing the plant efficiency, the present method may make it easier to understand the relation between loss mechanisms and total efficiency. When selecting between these three concepts (A, B and C), efficiency will probably not be the major decisive factor based on the results of the present calculations. It is obvious that investment costs will be
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very high. It is likely that the investment cost of the three concepts would more than double that of a large standard CC power plant that is comparable in power output. The fuel cost will be higher due to reduced efficiency, and there will be increased operating costs as well as reduced availability. The differences in efficiencies do not rule out any of the concepts. Only concepts A and C are commercially available technologies. One should bear in mind that the present study is about reducing emissions of CO2 from a technology that in fact does have low emissions without using any particular measures for removing CO2 (natural gas, f60% efficiency). If CO2 from large point sources such as power plants is to be collected and stored, natural gas-fired CCs may not be the most obvious candidate. Coal fired power plants should also be regarded as an alternative. Nomenclature C (kgykmol): ratio between formed CO2 and fuel, 44m cP (MJy(kg K)): specific heat capacity of reformed gas 2 ECO comp (MJykg CO2): power requirement for compression of CO2 2 ECO rem,heat (MJykg CO2): heat required for atmospheric stripping of CO2 from absorbent 2 (MJykg CO2): mechanical work required for ECO rem,mech atmospheric stripping process EO2 (MJykg O2): energy required for producing oxygen (MJykg): energy required for compressing the Eabs.exit comp absorber exit flow (GT-fuel to the required gas turbine pressure f (–): fraction of CO2 captured in the chemical absorption process hevap (MJykmol): heat of condensation for steam to ATR-reactor LHV (MJykmol): lower heating value for natural gas m (mol):number of mole carbon in fuel molecule MW (kgykmol): molecular weight MWm,n (kgykmol): molecular weight fuel molecule, 12mqn ˙ abs,ex (kgykmol): gas flow rate per kmol of natural m gas feed (absorber exit in CO2 capture process) ˙ reform,ex (kgykmol): reformed gas flow rate per kmol m of natural gas feed (ATR exit) n (mol): number of mole hydrogen in fuel molecule R (kg CO2 ykg O2): ratio between produced CO2 and consumed O2 for CmHn y (–): mole fraction
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a (MJel yMJheat): steam turbine, ratio of incremental power reduction to incremental heat output hCC (–): efficiency for a natural gas-fired CC hCC,H2 (–): efficiency for a CC integrated with ATR hCC,O2 (–): efficiency for a CC with stoichiometric combustion with O2 tO2 (mol O2ymol C): oxygen to carbon ratio for the ATR-reactor tH2O (mol H2Oymol C): steam to carbon ratio for the ATR-reactor j (MJyMJ): LHV ratio of reformed fuel and natural gas feed (concept C) c (MJyMJ): ratio between fuel energy to HRSG supplementary firing and GT (concept C)
References Akai, M., Kagajo, T., 1994. Performance evaluation of fossil power plant with CO2 recovery and sequestering system. Proceedings of the Second International Conference on Carbon Dioxide Removal, Kyoto. Allam, R.J., Spilsbury, C.G., 1992. A study of extraction of CO2 from the flue gas of a 500 MW pulverised coal fired boiler. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. Bolland, O., Sæther, S., 1993. New concepts for natural gas fired power plants which simplify the recovery of carbon dioxide. Energy Convers. Manage. 33 (5–8), 467–475. Bolland, O., Undrum, H., 1998. Removal of CO2 from gas turbine power plants: evaluation of pre- and postcombustion methods. Proceedings of the Fourth International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland. Bolland, O., Mathieu, P., 1998. Comparison of two CO2 removal options in combined cycle power plants. Energy Convers. Manage. 39 (16–18), 1653–1663. Undrum, H., Bolland, O., Aarebrot, E., 2000. Economical assessment of natural gas fired combined cycle power plant with CO2 capture and sequestration. Presented at the Fifth International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, August 2000. Bolland, O., Kvamsdal, H.K., Boden, J.C., 2001a. A thermodynamic comparison of the oxy-fuel power cycles watercycle, graz-cycle and matiant-cycle. Published in the Proceedings of The International Conference Power Gener` ation and Sustainable Development, Liege, Belgium, 8–9 October. Bolland, O., Ertesvaag, I.S., Speich, D., 2001b, Exergy analysis of gas-turbine Cocmbined Cycle with CO capture using auto-thermal reforming of natural gas. Published in the Proceedings of the International Conference Power Genera` tion and Sustainable Development, Liege, Belgium, 8–9 October. Bram, S., de Ruyck, J., 1994. Exergy analysis and design of
mixed CO2 ysteam gas turbine cycles. Proceedings of the Second International Conference on Carbon Dioxide Removal, Kyoto. Chakma, A., 1995. Separation of CO2 and SO2 from flue gas streams by liquid membranes. Energy Convers. Manage. 36 (6–9), 405–410. De Ruyck, J., 1992. Efficient CO2 capture through a combined steam and CO2 gas turbine cycle. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. Erga, O., Juliussen, O., Lidal, H., 1995. Carbon dioxide recovery by means of aqueous amines. Energy Convers. Manage. 36 (6–9), 387–392. ¨ H., 1997. Separation of carbon Falk-Pedersen, O., Dannstrom, dioxide from offshore gas turbine exhaust. Energy Convers. Manage. 38 (Suppl.), S81–S86. Feron, P.H.M., Jansen, A.E., 1997. The production of carbon dioxide from flue gas by membrane gas absorption. Energy Convers. Manage. 38 (Suppl.), S93–S98. ¨ Gottlicher, G., Pruschek, R., 1996. Comparison of CO2 removal systems for fossil-fuelled power plant processes. Proceedings of the Third International Conference on Carbon Dioxide Removal, Cambridge. GTPRO, 1999. Thermoflow Inc., Gas TurbineyCombined Cycle computational code. Hendriks, C.A., Blok, K., 1992, Carbon dioxide recovery using a dual gas turbine IGCC plant. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. IEA Report PH2y19, 1998. Precombustion decarbonisation. Study by Foster-Wheeler for IEA GHG and Statoil. Lozza, G., Chiesa P., 2000, Natural gas decarbonization to reduce CO2 emission from combined cycles. Part A: partial ¨ Oxidation. Presented at the ASME Turbo Expo in Munchen, 8–12 May, 2000-GT-163. Mathieu, P., 2001, Zero emission power plants as future CO2 control technologies. International Symposium on Greenhouse Gas Control and Utilization, American Chemical Society meeting, San Diego, 2 April. Meisen, A., Shuai, X., 1997. Research and development issues in CO2 capture. Energy Convers. Manage. 38, S37–S42. Mimura, T., Satsumi, S., Iijima, M., Mitsuoka, S., 1999, Development on energy saving technology for flue gas carbon dioxide recovery by the chemical absorption method and steam system in power plant. Proceedings of the Fouth International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland, 71–76. Steinberg, M., 1994. The Hy–C process (thermal decomposition of natural gas) potentially the lowest cost source of hydrogen with the least CO2 emission. Proceedings of the Second International Conference on Carbon Dioxide Removal, Kyoto. Suda, T., Fujii, M., Yoshida, K., 1992. Development of flue gas carbon dioxide recovery technology. Proceedings of the First International Conference on Carbon Dioxide Removal, Amsterdam. Todd, D.M., Battista, R.A., 2000, Demonstrated applicability of hydrogen fuel for gas turbines. Presented at the IchemE conference ‘Gasification 4 the future’, Amsterdam, 11–13 April.
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Olav Bolland graduated as M.Sc. from the Norwegian University of Science and Technology in 1986, and as Dr Ing in 1990. He has since then been working as associate professor at the Department of Thermal Energy and Hydropower. The main focus of his work is on thermal power generation in general and CO2 capture in particular.
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Henriette Undrum graduated as M.Sc. from the Norwegian University of Science and Technology in 1995. She worked the two years for the research foundation SINTEF before she started to work for the oil&gas company Statoil. The main focus of her work has been on technology surveys and CO2 capture.