Studying heat integration options for steam-gas power plants retrofitted with CO2 post-combustion capture

Energy xxx (2015) 1e15

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Studying heat integration options for steam-gas power plants retrofitted with CO2 post-combustion capture Roberto Carapellucci*, Lorena Giordano, Maura Vaccarelli Department of Industrial and Information Engineering and Economics, University of L'Aquila, Via G. Gronchi 18, L'Aquila, 67100, Italy

a r t i c l e i n f o

a b s t r a c t

Article history: Received 28 November 2014 Received in revised form 11 March 2015 Accepted 29 March 2015 Available online xxx

Electricity generation from fossil fuels has become a focal point of energy and climate change policies due to its central role in modern economics and its leading contribution to greenhouse gas emissions. Carbon capture and sequestration (CCS) is regarded by the International Energy Agency as an essential part of the technology portfolio for carbon mitigation, as it can significantly reduce CO2 emissions while ensuring electricity generation from fossil fuel power plants. This paper studies the retrofit of natural gas combined cycles (NGCCs) with an amine-based postcombustion carbon capture system. NGCCs with differently rated capacities were analysed under the assumptions that the heat requirement of the capture system was provided via a steam extraction upstream of the low-pressure steam turbine or by an auxiliary unit that was able to reduce the power plant derating related to the energy needs of the CCS system. Different types of auxiliary units were investigated based on power plant size, including a gas turbine cogeneration plant and a supplementary firing unit or boiler fed by natural gas or biomass. Energy and economic analyses were performed in order to evaluate the impact of type and layout of retrofit option on energy, environmental and economic performance of NGCCs with the CCS system. © 2015 Elsevier Ltd. All rights reserved.

Keywords: Post-combustion CO2 capture Thermal integration Auxiliary system Derating Retrofitting

1. Introduction The increase in greenhouse gas (GHG) concentrations in the atmosphere is mainly the result of human activities, and it is leading to a progressive increase in the global mean temperature of the Earth's surface. Feedback effects of global warming include ice melting, rising sea levels, increases in extreme weather events, desertification and species extinction. Thus, global warming is widely recognized as the greatest challenge of the 21st century and has stimulated research of measures to reduce emissions of GHG. Despite the spread of cutting-edge renewable technologies, approximately 70% of the world's electricity production still relies on fossil fuel power plants, representing the largest source of carbon dioxide emissions [1]. As recently highlighted by the International Energy Agency in the Blue Map Scenario [2], carbon capture and sequestration (CCS) represents a key solution in order to achieve a significant reduction in CO2 emissions, without the need for dramatic transformation of the energy sector.

* Corresponding author. Tel.: þ39 0862 434320; fax: þ39 0862 434403. E-mail address: [email protected] (R. Carapellucci).

Natural gas combined cycle power plants constitute a widely used power generation technology today, thanks to low investment costs, short construction periods and short start-up times compared to large coal-fired power stations [3]. However, the retrofitting of an NGCC (natural gas combined cycle) with postcombustion CO2 capture is still a technological challenge due to the low concentration of CO2 in the flue gas and the high energy requirements for CO2 capture and compression. A reactive absorption with an aqueous amine solution is currently the most mature technology for post-combustion capture in existing power plants. The main issue of this technology is undoubtedly represented by the high thermal energy demand for solvent regeneration (3.5e3.8 MJ/kgCO2) that accounts for approximately 70e80% of global energy demand of the CCS process [4]. Hence, research activities are mainly focused on reducing the regeneration energy by improving the absorption process and integration between the power block and the CCS system. In this respect, a number of research groups are exploring the potential of new solvents with the aim of achieving better overall properties for applications in CO2 capture [5e7]. Other researchers are investigating alternative methods for solvent regeneration, such as those based on electrochemistry, photochemical processes or electromagnetic radiation [8,9].

http://dx.doi.org/10.1016/j.energy.2015.03.071 0360-5442/© 2015 Elsevier Ltd. All rights reserved.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

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Some system studies have explored ways to enhance CO2 concentrations in the flue gas from NGCC, with the aim to reduce reboiler duty and size of the capture island. Different methods, including exhaust gas recirculation (EGR), humidification and supplementary firing, have been investigated and compared, highlighting their impact on the CO2 capture system and on the turbomachinery and combustion processes [10,11]. Another research branch has examined heat integration between the main power plant and CCS system. The majority of these studies have focused on the location of steam extraction and steam cycle layout modification, with the aim to minimize the efficiency penalty [12e14]. Additionally, some researchers have explored the possibility of reducing the power plant derating due to heat and electricity requirements of the capture island by means of an auxiliary power system. The study in Ref. [15] investigated the techno-economic impact of integrating a CHP (combined heat and power) system based on a gas turbine in a coal-fired power station with CO2 capture. Referring to the same power plant technology, in Refs. [16e18], researchers compared different options to meet the heat requirements of the CCS system, which included steam production from an auxiliary boiler or a heat recovery steam generator (HRSG) fed by the exhaust flue gas of an additional gas turbine. Further investigations [19e21] attempted to quantify pros and cons of reducing the derating caused by the CO2 capture system through the integration of an additional natural gas combined cycle. Several approaches using solar-assisted post-combustion capture have also been investigated with the aim of improving energy performance of coal-fired power plants [22e27]. With regard to NGCCs, few studies addressed the integration of an auxiliary unit serving the CCS system. None of these examined the integration of a cogeneration unit based on gas turbine or supplementary firing, narrowing the investigation to natural gas [28] or biomass boilers [29]. Moreover they focused the attention on a specific power plant configuration, neglecting to assess the impact of the power plant layout on the energy and economic performances of the retrofitted NGCCs. In this paper, three combined cycle power plants with different plant layouts and rated capacities were retrofitted with a CO2 post-

combustion capture system based on MEA (Monoethanolamine) absorption. This study aims to investigate the possibility of reducing plant derating due to CO2 capture and compression processes by integrating an external auxiliary unit that provides heat and/or electricity to the CCS system. Three different types of auxiliary units will be considered: the first is a combined heat and power system based on a gas turbine, the second type is a supplementary firing unit that produces steam provided to the reboiler using the residual oxygen content of exhaust gases at gas turbine exit of the main power plant, and the last option includes a boiler, fed by natural gas or biomass and a back-pressure steam turbine, providing electricity through superheated steam expansion. Depending on the NGCC configuration, various options of CO2 capture retrofit were compared to conventional steam extraction from the main power plant. Energy and economic analyses of retrofitted NGCCs assessed the impact of the type and layout of auxiliary systems on the efficiency penalty and power plant derating, as well as on per unit cost of electricity (COE) and mitigation costs. 2. Post-combustion CO2 capture through amine-based absorption system Post-combustion CO2 capture is achieved through a chemical absorption system, based on an aqueous solution with 30%wt MEA. The capture island consists of two main units: the absorber, where CO2 is removed by the amine solution, and the regenerator, where CO2 is released and the regenerated solvent is recycled back to the absorption column. The stream of concentrated CO2 is then compressed to 138 bar and sent to a storage site. Solvent regeneration is an energy-consuming process, as it requires a huge amount of heat, supplied by the reboiler located at the bottom of the stripping column. Moreover, complete amine regeneration is not achievable because a small amount of CO2 remains in the lean solution. In this respect, CO2 lean loading (yCO2/MEA) defines the amount of CO2 per unit of MEA that has not been desorbed during the stripping process. It is well known that the heat provided in the reboiler by the condensing steam includes the latent heat of water vaporization,

Fig. 1. CO2 capture system layout.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

R. Carapellucci et al. / Energy xxx (2015) 1e15

Fig. 2. Effect of capture ratio on reboiler duty (a), condenser duty (b) and specific MEA requirements (c) while varying the CO2 lean loading.

the heat of CO2 desorption and the sensible heat to raise the temperature of the solvent to the reboiler temperature [5]. While the heat of desorption is almost constant at a fixed temperature, the heat of vaporization and the sensible heat show a

Fig. 4. Auxiliary units based on a) a gas turbine, b) a duct burner and c) a boiler.

Fig. 3. Effect of CO2 concentration on reboiler duty (a), condenser duty (b) and specific MEA requirement (c) while varying the capture ratio.

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Table 1 Main operating conditions of NGCCs. NGCC configuration Gas turbine Model Compressor pressure ratio Exhaust gas flow, kg/s Exhaust gas temperature,  C Power output, MW Net efficiency, % Combined cycle HP steam pressure, bar IP steam pressure, bar Deaerator pressure, bar HPEVAP DTpp,  C IPEVAP DTpp,  C LPEVAP DTpp,  C Condenser pressure, bar

NGCC-1P

NGCC-2P

NGCC-3PRH

ABB GT8C2 17.6 193.5 517.6 55.2 34.1

GE PG7161 (EC) 14.2 348.9 559.7 115.9 35.6

ABB GT26 30.0 558.4 647.8 257.3 37.7

65 20 5 10 e e 0.05

90 40 5 10 e 10 0.05

130 30 5 10 10 10 0.05

marked dependency on yCO2/MEA. Indeed, at a fixed capture ratio, the heat of vaporization decreases with lean loading as the equilibrium partial pressure of CO2 increases, thus reducing the amount of steam to be vaporized. The sensible heat has an opposite trend due to the increased liquid solvent flow rate required to achieve the CO2 capture efficiency target [30]. Due to the trade-off between latent and sensible heats, the reboiler duty is minimized by a certain lean loading value that depends on the operating conditions of the absorption system and the flue gas to be treated [30,31]. The identification of optimal lean loading requires an in-depth investigation that is beyond the scope of this study. In this paper, the energy analysis of an amine-absorption system is aimed at evaluating the influence of capture ratio (4) and CO2 concentration (xCO2) on main processing parameters at a fixed value of CO2 lean loading.

requirements per unit of CO2 captured (mMEA), assuming xCO2 ¼ 3.4%. As shown in Fig. 2c, the increase in the capture ratio increased the specific solvent requirement. The increased reboiler duty (Fig. 2a) was due to the higher energy needed for solvent heating and the higher latent heat of water vaporization, which in turn affected the condenser duty (Fig. 2b). Thus, assuming yCO2/ MEA ¼ 0.25 and increasing 4 from 80 to 95%, mMEA increased from 6.4 to 11.3 kgMEA/kgCO2,P, qREB increased by approximately 40% (4.4 MJ/kgCO2,P) and qCOND more than doubled (2 MJ/kgCO2,P). As expected, increasing yCO2/MEA to 0.3 at a fixed capture ratio led to an increase in mMEA. Under these operating conditions, the increase in sensible heat prevailed over the reduction of latent heat, thus leading to an increase in qREB, as shown in Fig. 2a. Moreover, increasing 4 from 80 to 95% led to an increase in mMEA from þ39% (8.9 kgMEA/kgCO2,P) to þ84% (20.8 kgMEA/kgCO2,P). However, the increase in qREB was far less pronounced, changing from þ3% (3.2 MJ/ kgCO2,P) to þ11% (4.8 MJ/kgCO2,P). Fig. 3 shows that the CO2 concentration influences process parameters to a different extent depending on the CO2 capture efficiency target. For instance, assuming yCO2/MEA ¼ 0.25 and 4 ¼ 90%, mMEA and qREB were reduced with an asymptotic decreasing trend, decreasing from 8.2 to 7 kgMEA/kgCO2,P and from 3.6 to 3.2 MJ/ kgCO2,P, respectively. As 4 increased to 95%, the impact of CO2 concentration was more pronounced; increasing xCO2 from 2 to 9% results in decreases in mMEA and qREB to 50% (8.8 kgMEA/kgCO2,P) and 30% (3.8 MJ/kgCO2,P), respectively. Reboiler duty and specific MEA requirements affect both energy and economic performance of the NGCC with CO2 removal. Hence, specific correlations for evaluating these process parameters were defined based on chemical absorption process simulations in Chemcad environment [32], varying the capture ratio, CO2 concentration in the exhaust flue gas to be treated and lean loading:

. mMEA ¼ 6:61 þ 0:002xCO2 þ 2:73=xCO2 þ 0:96 x2CO2

(1)

2.1. Energy analysis of CO2 capture island

. qREB ¼ 2:97 þ 0:01xCO2 þ 0:95=xCO2 þ 0:47 x2CO2

(2)

The capture island, shown in Fig. 1, was simulated using Chemcad 6.3 software [32]. Fig. 2 highlights the effect of 4 on reboiler (qREB) and condenser (qCOND) duties and solvent

assuming 4 ¼ 90% and yCO2/MEA ¼ 0.25. The derived equations fitted simulated data points with a correlation coefficient greater than 0.93.

Table 2 Cost models for CCS system and auxiliary unit equipment. Equipment

Cost function

CO2 capture system [37] Direct contact cooler þ Flue gas blower þ CO2 absorber vessel

CDCCþFBþAB ¼ 164010ðQFG =369Þ0:6

Heat exchangers þ Circulation pumps þ Desorber

CHXþPUMPþDS ¼ 492330ðMS =38Þ0:6

Sorbent reclaimer, Sorbent processing

CSRþSP ¼ 196350ðMCO2 =24Þ0:6

Reboiler

CRB ¼ 90ðMCO2 MMEA =56126Þ0:6

Drying and compression system [37] Drying and compression Auxiliary system Gas turbine [39] Duct burner [40] Natural gas/Biomass boiler [29] Back-pressure steam turbine [41] HRSG [41]

CDRYþCOMPR ¼ 682870ðMCO2 =24Þ0:6 0:73 CGT ¼ 7113PGT CDB ¼ 10363:7hcomb qf LHV 0:75 CNB=BB ¼ 899395:1Pth n o 0:7 CBPST ¼ 5745:2PST 1 þ ½0:05=ð1  hST Þ3 f1 þ 5exp½ðTSTin  866Þ=10:42g       0:8   P  Tsteam outi 830 Tgas outi 990 pi Qi þ 0:9 1 þ exp 0:097 30  1 þ exp CHRSG ¼ 6117:3 DTLMi 500 500 i

þ 19809:6

X

0:097

i

Pump [41]

 pi þ 0:9 Gsteami þ 2205:5G1:2 gas 30

  0:2 CPUMP ¼ 1044:5PP0:71 1 þ 1h P

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

R. Carapellucci et al. / Energy xxx (2015) 1e15 Table 3 Main economic assumptions for COE evaluation. Parameter

Value

Fixed O&M, $/kW-yr Variable O&M, mill$/kWh Sorbent cost, $/tonne Inhibitor cost, %MEA Further variable O&M, %MEA CO2 transport cost, $/tonne CO2 storage cost, $/tonne CO2 monitoring cost, $/tonne Operational period, yr Operational period, yr Yearly operating hours, h/yr Capital charge factor, yr1 Annual cost escalation rate, % Construction time, yr

16.2 0.56 2630 20 25 6 3 1 25 25 7446 0.13 3 2

3. Heat supply alternatives for retrofitting steam-gas power plants with a CO2 capture system Power plants retrofitted with CCS technologies require both heat and electricity for CO2 capture and compression processes. In post-combustion capture based on chemical absorption, the heat for solvent regeneration represents the major energy sink, accounting for approximately 70e80% of total energy expenses [4,33]. In a natural gas combined cycle (NGCC), the thermal requirement of the capture island is usually supplied via steam extraction located at a crossover pipe between the intermediate- and lowpressure steam turbines [14,28], thus reducing the power plant

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capacity and hence the net efficiency. As an alternative, the reboiler duty can be satisfied through steam production from an auxiliary unit [15e18,28,29] that reduces or eventually eliminates power losses resulting from steam extraction. In addition, power production arising from steam expansion can be used to meet a fraction of the electricity requirement of capture island ancillaries and the CO2 compressor unit. The additional flue gas stream arising from fuel combustion in the auxiliary system can be mixed with the NGCC exhaust gases or vented into the atmosphere [18]. In the first case, a huge removal system is required for the same capture ratio. In the second case, CO2 emissions increase unless biomass is burned in place of fossil fuels [34]. In this paper, three types of auxiliary systems will be investigated. The first one, represented in Fig. 4a, includes a gas turbine, fed by fresh air, a single pressure level HRSG (HRSG-1P) and a backpressure steam turbine (BP-ST). This plant layout is representative of three different cases (modes of operation): the simplest one (GT) has only the gas turbine, the second one (GT þ HRSG) also includes the HRSG, and the third one (GT þ HRSG þ ST) also has the BP-ST. In the simplest mode of operation (GT), the steam extraction is not eliminated, while the gas turbine provides the power capacity required to reduce or eliminate the derating of NGCC arising from CO2 separation and compression processes. Then, the exhaust gases are mixed with the main flue gas of the NGCC after cooling to the operating temperature of the absorber (40  C). In GT þ HRSG, steam extraction from the NGCC is partially replaced with steam production from the auxiliary unit as the exhaust flue gas from the GT is sent to HRSG-1P, producing a low-pressure saturated steam

Fig. 5. Layout of NGCC-3PRH retrofitted with a CO2 capture system.

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As shown in Fig. 4c, the third auxiliary system includes a boiler, which is fed by natural gas (NB) or biomass (BB) and a BP-ST. In the most complex mode of operation (NB/BB-ST), the auxiliary boiler produces superheated steam that meets a certain fraction of the CCS heat requirement after expanding in the BP-ST. Hence, the auxiliary unit reduces or eliminates the steam extraction, enabling the generation of additional power, while the exhaust gases of the auxiliary unit are mixed with the main flue gas stream after cooling to the operating temperature of the absorber or vented into the atmosphere.

Table 4 Description of CO2 retrofit options based on gas turbine for NGCC-3PRH. Case

Description

GT GT þ HRSG

Steam extraction from NGCC and integration of a gas turbine Integration of a gas turbine producing electricity and steam via the HRSG-1P Steam extraction and integration of a gas turbine with HRSG-1P and BP-ST Steam extraction and integration of a gas turbine with HRSG-1P, BP-ST and flue gas vented to the atmosphere

GT þ HRSG þ ST GT þ HRSG þ ST*

4. Assumptions for energy and economic analysis of NGCCs with CO2 capture

(TS ¼ 133.5  C, pS ¼ 3 bar). Compared to GT, the reduction of steam extraction enables the decrease of power required by the auxiliary gas turbine to eliminate the plant derating. In the most complex mode of operation (GT þ HRSG þ ST), HRSG-1P produces superheated steam (TS ¼ 540  C, pS ¼ 80 bar) that provides an additional power capacity by expanding in BP-ST. In the second type of auxiliary system (Fig. 4b), the gas turbine is replaced by a duct burner that accomplishes supplementary firing using the excess of air available in the exhaust flue gas from the gas turbine. Hence, the auxiliary unit, located between the gas turbine and the high pressure superheater, does not increase the exhaust flow rate to be treated. In the DB mode of operation, the increase in the flue gas temperature provided by the supplementary firing increases the highpressure steam production, mitigating power losses due to steam extraction. Hence, the power plant derating reduces in spite of an increase in the efficiency penalty. In DB þ HRSG, steam extraction can be entirely replaced by the saturated steam production from HRSG-1P, thus allowing a further reduction of power plant derating. In DB þ HRSG þ ST mode, the auxiliary unit acts as a cogeneration unit, providing both heat and electricity by superheated steam expansion.

The study cases are represented by three natural gas combined cycles having one, two and three pressure levels and reheated HRSG. These power plants, as well as the auxiliary combined heat and power units, have been simulated using the Gatecycle software [35]. It allows to evaluate the energy performances of NGCCs at design conditions and those resulting from a retrofit intervention with an amine-based absorption unit, assuming a CO2 capture ratio of 90% and a lean loading of 0.25 kgCO2/kg MEA. The main operating parameters of NGCCs under investigation are summarized in Table 1. Economic analysis based on the EPRI methodology [36] evaluated the cost per unit of electricity (COE), as well as the cost of retrofit intervention and the cost per unit of CO2 avoided for NGCCs with the CCS system. The cost of retrofit intervention comprises the cost of the aminebased absorption system and, according to the mode of integration between the power block and the capture island, the cost of steam extractor for the NGCC and the cost of the auxiliary unit that generates steam and/or electricity to satisfy the energy needs of the CCS system. Capital costs of the capture system equipment have been modelled by authors, as reported in Ref. [37], by fitting, with a

Table 5 Comparison of heat integration options with steam extraction and auxiliary system based on gas turbine for NGCC-3PRH.

Power section PGT [MW] PST [MW] mHPST [kg/s] mIPST [kg/s] mLPST [kg/s] mEXTR [kg/s] mEXH [kg/s] xCO2, EXH Capture section Pth to reboiler [MW] Specific reboiler duty [MJ/kg] PCP [MW] PCCS [MW] Auxiliary section mFUEL [kg/s] b [-] PGT NET [MW] PST NET [MW] mS [kg/s] pS [bar] TS [ C] mGAS OUT [kg/s] Power system with capture PNET [MW] hLHV [%] CO2, em [kg/MWh] EGR [%] 4 [%] Retrofit cost (M$) COE [$/MWh] CO2 avoided [$/tonne]

Design case

ST-EXTR

GT

GT þ HRSG

GT þ HRSG þ ST

(GT þ HRSG þ ST)*

257.3 125.7 81.1 89.2 95.2 0.0 550.3 4.5

254.3 110.0 83.3 90.5 54.3 46.5 352.2 7.0

254.3 108.1 83.3 90.4 47.8 53.7 435.8 6.5

254.3 113.2 83.3 90.7 63.5 36.4 424.3 6.5

254.3 111.2 83.3 90.6 58.2 42.2 414.7 6.6

254.3 112.6 83.3 90.7 62.0 38.0 352.2 7.0

e e e e

109.6 3.2 9.9 7.0

125.1 3.2 11.3 8.7

123.0 3.2 11.1 8.5

121.2 3.2 10.9 8.3

109.6 3.2 9.9 7.0

e e e e e e e e

e e e e e e e e

1.9 24 40.6 0.0 0.0 e e 83.6

1.6 24 35.0 0.0 16.6 3.0 133.5 72.1

1.4 24 30.3 6.4 9.3 3.0 173.5 62.5

1.3 24 27.3 5.8 8.4 3.0 173.5 56.3

383.0 56.2 356.6 0.0 e e 53.9 e

347.4 50.9 39.3 35.0 90 168.4 76.6 71.8

383.0 49.2 40.6 35.0 90 212.2 77.8 75.6

383.0 50.1 39.9 35.0 90 210.3 76.8 72.5

383.0 50.8 39.3 35.0 90 211.8 76.2 70.3

383.0 51.3 69.0 35.0 82 194.8 74.4 71.5

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

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correlation coefficient greater than 0.97, data provided by the IECM software [38], varying the CO2 capture ratio and the exhaust gas flow rate to be treated. Table 2 summarizes the cost capital functions of the CCS system and auxiliary unit equipment. The per unit cost of electricity is determined by summing the contributions related to capital charge (COECAP), O&M (COEO&M), fuel consumption (COEFUEL) and CO2 transport, storage and monitoring (COETS&M) according to the methodology outlined by the authors in Ref. [42]. In this respect, COECAP was evaluated considering 2011 as the base year for capital costs and using a levelization period of 25 years. COEO&M and COETS&M were assessed on the basis of the assumptions summarized in Table 3. 5. Effect of heat integration options on energy and economic performance of NGCCs In this study, NGCCs were retrofitted with an amine-based absorption unit, capturing 90% of CO2 in exhaust flue gases. Hence, the power plant layout was modified by introducing a partial recirculation of the exhaust flue gas that increased CO2 concentration and reduced the flue gas flow rate, with beneficial effects on reboiler duty and size of capture island [43]. Exhaust gas recirculation (EGR) was set to 35%, with the aim of ensuring a proper level of oxygen at compressor inlet (higher than 16%) and hence the flame stability inside the gas turbine combustor [10]. For each NGCC configuration, various options for integration of the capture island have been investigated and compared to conventional steam extraction (ST-EXTR). The influence of type and layout of the auxiliary unit supplying heat and electricity to the CCS system, efficiency penalty (DhLHV), power plant derating (a) and CO2 emissions of NGCCs were evaluated through an energy analysis of various retrofit options. From an economic point of view, retrofit options were compared with respect to the per unit cost of electricity (COE), the cost of retrofit intervention and the cost of CO2 avoided. 5.1. Triple-pressure and reheat steam-gas power plant The combined cycle with a three-pressure reheat HRSG (NGCC3PRH) was based on an ABB gas turbine (GT26) with a rated capacity of 257.3 MW. As shown in Fig. 5, the bottoming cycle comprises three steam turbines (HPST (high-pressure steam turbine), IPST, LPST), a condensing system and an HRSG, including a preheater (WHTR), three economizers (HPECON, IPECON, LPECON), three evaporators (HPEVAP, IPEVAP, LPEVAP), three superheaters (HPSHT, IPSHT, LPSHT) and a reheater (RHTR) located downstream of the HPSHT. At design conditions, the net power output of the NGCC-3PRH was approximately 383 MW, while the LHV efficiency and specific CO2 emissions were 56.2% and 356.6 kg/MWh, respectively. The design plant layout was modified through EGR in order to accommodate the post-combustion CCS system. Hence, a 35% fraction of exhaust flue gas leaving WHTR was cooled down to 25  C by a two-stage flash separator, recirculated back and mixed to the air at the compressor inlet. The CO2 capture retrofit with a conventional stream extraction from the NGCC-3PRH was compared to the heat integration by an auxiliary unit based on a gas turbine or duct burner. 5.1.1. Integration of an auxiliary unit based on a gas turbine Considering the different modes of operation of an auxiliary system based on a gas turbine, four options to supply heat to the reboiler were compared to conventional steam extraction (STEXTR), as summarized in Table 4.

Fig. 6. Thermal power (a) and steam flow rate (b) required by a reboiler for retrofit options with steam extraction and auxiliary systems based on a gas turbine.

The main results of the energy and economic analysis of NGCC3PRH with and without post-combustion CO2 capture are summarized in Table 5. For conventional steam extraction (ST-EXTR), the total thermal power required for solvent regeneration amounts to approximately 110 MWt, being the specific reboiler duty of 3.2 MJ/kg. Bearing in

Fig. 7. Effect of b on auxiliary unit rated power for retrofit options based on gas turbine integration.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

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R. Carapellucci et al. / Energy xxx (2015) 1e15

Fig. 8. COE and mitigation cost for NGCC-3PRH with steam extraction and an auxiliary unit based on a gas turbine.

mind the total energy requirements for CO2 capture and compression processes, the power plant derating compared to design conditions was approximately 9%, leading to an efficiency penalty greater than 5% pts. However, specific CO2 emissions were drastically reduced to 39.3 kg/MWh. In retrofit options based on a gas turbine integration, the auxiliary system was sized in order to eliminate the power plant derating arising from CCS system integration. Assuming b ¼ 24 and TIT ¼ 1350  C, the rated capacity of the gas turbine was approximately 40.6 MW in GT and decreased to 35 MW with the production of saturated steam (GT þ HRSG) due to the reduction of steam extraction from the NGCC. In GT þ HRSG þ ST, the gas turbine rated power was further reduced to approximately 30 MW, due to the contribution of the back-pressure steam turbine (6.4 MW). However, if flue gases from the additional gas turbine were vented to the atmosphere (GT þ HRSG þ ST*), the required power capacity of the auxiliary unit was 33 MW, with the gas turbine contributing approximately 80% (27.3 MW). With the exception of GT þ HRSG þ ST*, the auxiliary unit led to an increase in the CCS heat requirement due to the greater flue gas flow rate to be treated. As shown in Table 5, the thermal power required by the reboiler ranged from 121.2 MWt (þ11%) of GT þ HRSG þ ST to 125.1 MW (þ14%) of GT, leading to an efficiency penalty of 5.4% pts and 7% pts, respectively. GT þ HRSG þ ST* showed the best energy performance (DhLHV ¼ 4.9% pts, a ¼ 0) in spite of an increase in CO2 emissions of up to 69 kg/MWh due to the reduced capture ratio (4 ¼ 82%). Fig. 6 highlights that the pressure ratio of the additional gas turbine weakly influenced the CCS heat requirement, but it did affect the relative contribution of steam extraction for retrofit options with auxiliary steam production. Hence, increasing b from 12 to 36 increased the contribution of steam extraction due to the decreased exhaust flue gas temperature from the additional gas turbine, which reduced the steam produced by HRSG-1P. In GT þ HRSG, the auxiliary steam production decreased from 21.6 kg/ s to 14.8 kg/s, while corresponding contribution by the CCS heat requirement decreased from 38% (46.8 MW) to 26% (32.1 MW). In the other retrofit options, the incidence of the auxiliary steam on thermal power provided to the reboiler was reduced from 23 to 15% for the same increase in b. As a consequence of greater steam extraction, the auxiliary unit power capacity was increased by 4e6%. Fig. 7 highlights that the increase of gas turbine capacity was more pronounced (17e18%) in the retrofit options of

GT þ HRSG þ ST and GT þ HRSG þ ST* due to the concurrent reduction in the power production from BP-ST. Moreover, the increase in the pressure ratio from 12 to 36 positively affected the energy performance of retrofit options. This is more apparent in GT and GT þ HRSG, where the efficiency increases from 48.2 to 49.6% and from 49.5 to 50.2%, respectively. Comparing retrofit options from an economic perspective shows that the cost of retrofit intervention was approximately 170 M$ in ST-EXTR, while it substantially increased with the size of the auxiliary system in other cases (Table 5). GT, in spite of the greater simplicity, suffered the same increase in retrofit cost (þ26%) as GT þ HRSG þ ST, due to the higher costs of the additional gas turbine (24 M$) and CO2 capture island (188.2 M$). In other retrofit options, increases ranged from þ16% for GT þ HRSG þ ST* to 25% for GT þ HRSG, with the cost of auxiliary unit accounting for less than 15%. Fig. 8a summarizes the impact of CCS system on COE, assuming a natural gas cost of 6 $/GJ. With conventional steam extraction from the NGCC (ST-EXTR), COE reached 76.6 $/MWh, increasing by more than 40% compared to design conditions. Against this case, retrofit options based on auxiliary system integration showed a slight increase in COEFUEL (þ1e5%) due to reduced efficiency and a more pronounced reduction in COEO&M (4e6%); this was a result of greater power production. Hence, the COE increase was reduced from 44 ÷ 46% to approximately 41% from GT to GT þ HRSG þ ST, representing the best retrofit option with 4 ¼ 90%. Indeed, in GT þ HRSG þ ST*, the COE increase was reduced to 38% at the expense of a decrease in the capture ratio. Fig. 8b highlights that the cost of CO2 avoided was approximately 71.8 $/tonne in ST-EXTR, which was reduced with the increase in the pressure ratios for GT and GT þ HRSG, which were 74.6 and 72 $/tonne, respectively. GT þ HRSG þ ST provided the lowest mitigation cost for each value of b (70.3÷70.9 $/tonne).

Table 6 Description of CO2 capture retrofit options based on duct burner for NGCC-3PRH. Case

Description

DB DB þ HRSG DB þ HRSG þ ST

Steam extraction from NGCC and integration of a DB DB and steam production via the HRSG-1P Steam extraction and integration of a DB with HRSG-1P and BP-ST

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

R. Carapellucci et al. / Energy xxx (2015) 1e15

9

Table 7 Comparison of heat integration options with steam extraction and auxiliary system based on duct burner for NGCC-3PRH.

Power section PGT [MW] PST [MW] mHPST [kg/s] mIPST [kg/s] mLPST [kg/s] mEXTR [kg/s] mEXH [kg/s] xCO2, EXH Capture section Pth to reboiler [MW] Specific reboiler duty [MJ/kg] PCP [MW] PCCS [MW] Auxiliary section mFUEL [kg/s] TBURNER [ C] PST NET [MW] mS [kg/s] pS [bar] TS [ C] mGAS OUT [kg/s] TGAS OUT [ C] Power system with capture PNET [MW] hNET [%] CO2, em [kg/MWh] EGR [%] 4 [%] a [%] Retrofit cost [M$] COE [$/MWh] CO2 avoided [$/tonne]

Design

ST-EXTR

DB

DB þ HRSG

DB þ HRSG þ ST

257.3 125.7 81.1 89.2 95.2 0.0 550.3 4.5

254.3 110.0 83.3 90.5 54.3 46.5 352.2 7.0

254.3 117.6 89.2 95.3 57.3 47.5 351.9 7.2

254.5 135.0 89.2 96.3 101.8 0.0 349.6 8.7

254.4 125.1 89.2 95.9 78.7 24.6 350.4 8.2

e e e e

109.6 3.2 9.9 7.0

112.4 3.2 10.1 7.0

133.9 3.2 12.1 7.0

126.7 3.2 11.5 7.0

e e e e e e e e

e e e e e e e e

0.4 684.0 0.0 0.0 e e 553.3 684.0

3.1 869.7 0.0 61.7 3.0 133.5 556.1 676.9

2.2 808.9 21.8 30.4 3.0 146.5 555.2 679.3

383.0 56.2 356.6 0.0 0.0 e e 53.9 e

347.4 50.9 39.3 35.0 90 9.3 168.4 76.6 71.8

354.8 50.7 39.4 35.0 90 7.4 170.1 76.4 71.1

370.3 44.2 45.1 35.0 90 3.3 195 83.5 95.3

382.8 48.4 41.3 35.0 90 0.0 202.1 78.2 77.1

5.1.2. Integration of an auxiliary unit based on duct burner Table 6 summarizes retrofit options with an auxiliary system based on a duct burner that have been compared to conventional steam extraction. The energy and economic performances of these options were evaluated assuming a maximum overload in the high-pressure steam turbine (HPST) of 10%. As shown in Table 7 for DB, the power plant derating was reduced compared to ST-EXTR to

approximately 7.4%, while the efficiency (hLHV ¼ 50.7%) and the specific CO2 emissions (CO2, em ¼ 39.4 kg/MWh) remained virtually unchanged. If the steam extraction was entirely substituted by saturated steam production from HRSG-1P (DB þ HRSG), the burner temperature significantly increased, increasing from 684 to 870  C. Moreover, the thermal power required by the reboiler increased to 134 MWt (Fig. 9a) due to the higher CO2 content of the exhaust flue gas to be treated (xCO2,EXH ¼ 8.7%). Thus, the power

Fig. 9. Thermal power (a) and steam flow rate (b) required by the reboiler of retrofit options with steam extraction and an auxiliary system based on a duct burner for NGCC-3PRH.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

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R. Carapellucci et al. / Energy xxx (2015) 1e15

plant derating was further reduced to 3.3% at the expense of a substantial increase in efficiency penalty (12% pts) and specific CO2 emissions (45.1 kg/MWh). In DB þ HRSG þ ST, the auxiliary unit was sized in order to eliminate power derating of NGCC-3PRH. As shown in Fig. 9, steam extraction was only partially substituted by the auxiliary steam production (30.4 kg/s), accounting for approximately 53% of the thermal power required by the reboiler (127 MWt). The power production from the back-pressure steam turbine (21.8 MW) compensated the energy losses due to capture and compression processes. Compared to the previous option, the efficiency penalty was reduced to 8% pts and CO2 emissions to 41.3 kg/MWh. Unlike auxiliary units with gas-turbine, those based on supplementary firing affect the HRSG temperature profiles, being located upstream of HPSHT. The temperature profile variation is produced by the increase of exhaust flue gas temperature at HRSG inlet, the extent of which is related to the maximum allowable steam turbine overload. In this respect, Fig. 10 shows the HRSG temperature profiles in the case of the retrofit option DB þ HRSG þ ST. Due to integration of the auxiliary unit, the temperature of the exhaust flue gas at HRSG inlet rises from 648  C (design case) to 679  C, thus promoting the increase of HP superheated steam flow rate (þ10%). Due to greater simplicity of the auxiliary unit and lower size of capture system, the retrofit costs of heat integration options based on supplementary firing were lower than those based on gas turbine, ranging between 170.1 M$ (DB) and 202.1 M$ (DB þ HRSG þ ST) (Table 7). As expected, the economic performance of DB (COE ¼ 76.4 $/ MWh, CO2, avoided ¼ 71.1 $/tonne) was quite comparable to that of ST-EXTR; in contrast, Fig. 11 shows that when the power plant derating is eliminated (DB þ HRSG þ ST), the COE reached approximately 78.2 $/MWh due to the increase in fuel consumption and TS&M contributions (þ5%), while the mitigation costs increased up to 77.1 $/tonne. 5.2. Dual-pressure steam-gas power plant The dual-pressure combined cycle (NGCC-2P) was based on a General Electric gas turbine (PG7161) with a rated capacity of 115.9 MW. Compared to NGCC-3PRH, the HRSG had no intermediate heat exchange sections (IPSHT, IPEVAP, IPECON). Hence, water from the intermediate-pressure pump (IPPUMP) was entirely sent to the high-pressure economizer (HPECON) after compression at a high pressure. Moreover, the steam from the high-pressure steam turbine was directly sent to the intermediate pressure steam turbine, as there was no reheater. According to design conditions, the power plant produced a net power output of 171.3 MW, while the LHV efficiency and specific CO2 emissions were 52.7% and 380.9 kg/MWh, respectively. The analysis of thermal integration between the power block and the capture unit was performed for conventional steam extraction (ST-EXTR) and cases with an integrated auxiliary unit based on a duct burner, as described in Table 6. Retrofit options based on gas turbine integration were not been considered, as the capacity of NGCC-2P would lead to a GT rated power that is too low to justify adoption of an auxiliary system based on this technology. 5.2.1. Integration of an auxiliary unit based on duct burner Table 8 compares steam extraction from NGCC-2P with retrofit options based on supplementary firing and a maximum HPST overload of 10%. In ST-EXTR, the power plant capacity decreased to 152.4 MW (11.1%) and the net efficiency decreased to 46.8% (6% pts). Assuming 4 ¼ 90%, the CCS system allowed for a reduction in

Fig. 10. Temperature profiles of NGCC-3PRH for the retrofit option DB þ HRSG þ ST (þ10%).

CO2 emissions to 42.8 kg/MWh. The addition of a duct burner for supplementary firing (DB) increased the heat requirement for solvent regeneration from 52.8 to 56 MW (þ5%) due to the higher CO2 molar fraction in the exhaust flue gas (xCO2, EXH ¼ 5.6%). The increase in the amount of high-pressure steam production allowed for a reduction in the power plant derating to 8.7% at the expense of an increase of the efficiency penalty (7% pts) and the specific CO2 emissions (þ2.5%). As for NGCC-3PRH, the retrofit option DB þ HRSG did not eliminate the power plant derating (a ¼ 4.5%) but did lead to an efficiency penalty greater than 12% pts. In DB þ HRSG þ ST, the steam extraction accounted for 43% of thermal power requirement, while the remainder was provided by the auxiliary unit that cogenerated the power required (11.7 MW) to eliminate the plant derating by expanding the superheated steam in the BP-ST. As a result, the efficiency penalty was approximately 9% pts, while specific CO2 emissions were 45.4 kg/MWh. The retrofit options based on supplementary firing were thoroughly analysed, investigating the influence of HPST overload on energy and economic performances of NGCC-2P with CO2 capture. Fig. 12 highlights the sensitivity of thermal power and steam

Fig. 11. COE for NGCC-3PRH with steam extraction and an auxiliary unit based on a duct burner.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

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Table 8 Comparison of heat integration options with steam extraction and auxiliary system based on duct burner for NGCC-2P.

Power section PGT [MW] PST [MW] mHPST [kg/s] mLPST [kg/s] mEXTR [kg/s] mEXH [kg/s] xCO2, EXH Capture section Pth to reboiler [MW] Specific reboiler duty [MJ/kg] PCP [MW] PCCS [MW] Auxiliary section m FUEL [kg/s] TBURNER [ C] P ST NET [MW] mS [kg/s] pS [bar] TS [ C] mGAS OUT [kg/s] TGAS OUT [ C] Power system with capture PNET [MW] hLHV [%] CO2, em [kg/MWh] EGR [%] 4 [%] a [%] Retrofit cost [M$] COE [$/MWh] CO2 avoided [$/tonne]

Design

ST-EXTR

DB

DB þ HRSG

DB þ HRSG þ ST

115.9 55.4 45.4 55.6 0.0 348.6 3.4

114.1 47.5 46.2 34.2 24.0 223.0 5.3

114.2 51.6 50.0 36.2 25.3 222.7 5.6

114.2 59.7 50.0 59.7 0.0 221.6 6.7

114.2 55.5 50.0 48.5 12.0 221.9 6.4

52.8 3.2 4.7 4.5

55.5 3.2 5.0 4.5

65.4 3.2 5.9 4.4

62.6 3.2 5.6 4.4

e e e e e e e e e e e e

e e e e e e e e

0.2 592.8 0.0 0.0 e e 345.6 592.8

1.5 743.5 0.0 30.1 3.0 133.5 346.9 586.7

1.2 703.6 11.7 16.2 3.0 146.5 346.6 588.7

171.3 52.7 380.9 0.00 0.00 e e 57.9 e

152.3 46.8 42.8 35.0 90 11.1 115.3 87.9 88.4

156.4 45.9 43.9 35.0 90 8.7 117.2 88.2 89.8

163.6 40.2 49.7 35.0 90 4.5 129.2 95.6 113.8

171.4 44.0 45.3 35.0 90 0.0 136.2 89.5 93.9

provided to the reboiler with a variation in HPST overload (mSH) between 0 and 20%. In DB, the situation with a zero overload coincides with ST-EXTR. If mSH increases from 0 to þ20%, the thermal power required by the reboiler increases to approximately 8% (57.1 MW). The greater steam extraction (mEXTR ¼ 26 kg/s) was more than offset by the increase in HP steam flow, increasing from 46.2 to 54.5 kg/s. Hence, the plant derating was reduced to approximately 6%, while the efficiency penalty was 7% pts. In DB þ HRSG, the heat for solvent regeneration reached approximately 68 MW, thus increasing the auxiliary steam requirement up to 31 kg/s (þ8%) and the burner temperature from 709 to 776  C (Figs. 12b and 13). With the same increase in HP steam production, the plant derating reduces to less than 2% while increasing the efficiency penalty to less than 1% pts (hLHV ¼ 39.9%). In DB þ HRSG þ ST, increasing HPST overload, the heat provided to the reboiler was almost unchanged (approximately 63 MW), while the contribution of auxiliary steam was reduced from 74% (46.6 MW) to 40% (24.9 MW), being constrained by the power required from the BP-ST to eliminate plant derating. Indeed, the increase in HP steam production mitigated the plant capacity losses due to steam extraction, thus reducing the power required by the auxiliary unit from 15.2 to 8.1 MW. Moreover, due to the decreased auxiliary steam production, the burner temperature was slightly reduced with mSH, to approximately 700  C (Fig. 13). Conversely, LHV efficiency increased from 43.8 to 44.3%. The cost of retrofit intervention was 115.3 M$ in ST-EXTR, while it increased in the other cases due to the additional cost of the auxiliary unit and the increase in CCS system costs arising from a greater thermal requirement for solvent regeneration (Table 8). Such an increase was more pronounced with the increase of mSH in

Fig. 12. Effects of mSH on thermal power (a) and steam flow rate (b) required by the reboiler of retrofit options for NGCC-2P.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

12

R. Carapellucci et al. / Energy xxx (2015) 1e15 Table 9 Description of CO2 capture retrofit options for NGCC-1P. Case

Description

DB þ HRSG þ ST

Steam extraction and integration of a DB with HRSG-1P and BP-ST Steam extraction and integration of an NB with BP-ST Steam extraction and integration of an NB, with BPST and flue gas vented to the atmosphere Steam extraction and integration of a BB with BP-ST and flue gas vented to the atmosphere

NB þ ST NB þ ST* BB þ ST

Fig. 13. Effects of mSH on the burner temperature of the retrofit options for NGCC-2P.

DB (þ1.7e2.8%) and DB þ HRSG (þ10.4e13.5%), while it was reduced in DB þ HRSG þ ST (þ16e20%) due to the lower costs of the auxiliary unit that accounted for approximately 9e12% of the total retrofit cost. As shown in Fig. 14, the COE in the case of conventional steam extraction started at 87.8 $/MWh and increased by more than 50% compared to design conditions, while the mitigation cost was 88.4 $/tonne. With regard to retrofit options based on the auxiliary unit, the COE was slightly reduced with increasing mSH due to the reduction of COECAP (2 ÷ 4%) and COEO&M (2 ÷ 3%). Hence, the increase in mSH positively affected the cost of CO2 avoided, which was reduced by approximately 1e3%. At mSH ¼ þ20%, the economic performances of DB (COE ¼ 87.7 $/MWh, cost of CO2 avoided of 88.4 $/tonne) were almost the same as those of ST-EXTR. Eliminating the power plant derating (DB þ HRSG þ ST) with the same HPST overload led to a COE and mitigation cost increase of up to 88.9 $/MWh and 92.2 $/tonne, respectively. 5.3. Single-pressure steam-gas power plant Compared to NGCC-2P, the single-pressure combined cycle (NGCC-1P) was based on an ABB gas turbine (GT8C2) with a net

power output of 55.2 MW. The HRSG included high-pressure heat exchange sections (HPSHT, HPEVAP, HPECON), a low-pressure evaporator producing the steam required by the deaerator and a preheater (WHTR). The rated capacity of NGCC-1P was 77.9 MW, with an LHV efficiency of 48.1% and specific CO2 emissions of 417.6 kg/MWh. The CO2 capture retrofit based on stream extraction from NGCC1P has been compared to integration of an auxiliary unit with supplementary firing. Based on the results of NGCC-2P, attention was focused on the retrofit option DB þ HRSG þ ST with mSH ¼ þ20%. A moderate power plant capacity also led us to investigate a heat integration option based on a cogeneration unit, with a boiler fed by natural gas or woody biomass (LHV ¼ 19.0 MJ/ kg) [29]. Retrofit options with the auxiliary unit, which are summarized in Table 9, were sized in order to eliminate the plant derating arising from the CO2 capture retrofit. 5.3.1. Integration of an auxiliary unit based on duct burner or boiler Table 10 summarizes the energy and economic performances of NGCC-1P with and without the CCS system. For ST-EXTR, the integration of a CO2 capture system involved a power plant derating of 11.4%, thus reducing the net efficiency by 6% pts. By assuming 4 ¼ 90%, specific CO2 emissions were reduced to 47.6 kg/MWh. Eliminating plant derating with a duct burner-based cogeneration unit (DB þ HRSG þ ST) resulted in an increase in the solvent regeneration thermal power to 31.2 MW (þ17%) due to the increased CO2 concentrations in the flue gas (xCO2, EXH ¼ 5.7%). As shown in Fig. 15, compared to ST-EXTR, steam extraction was reduced from 12.3 to 8.4 kg/s and accounted for approximately

Fig. 14. COE and mitigation cost of NGCC-2P with steam extraction and an auxiliary unit based on a duct burner.

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

Table 10 Comparison of heat integration options with steam extraction and auxiliary system for NGCC-1P.

Power section PGT [MW] PST [MW] mHPST [kg/s] mEXTR [kg/s] mEXH [kg/s] xCO2, EXH Capture section Pth to reboiler [MW] Specific reboiler duty [MJ/kg] PCP [MW] PCCS [MW] Auxiliary section mFUEL [kg/s] PST NET [MW] mS [kg/s] pS [bar] TS [ C] mGAS OUT [kg/s] TGAS OUT [ C] Power system with capture PNET [MW] hNET [%] CO2, em [kg/MWh] EGR [%] 4 [%] Derating [%] Retrofit cost [M$] COE [$/MWh] CO2 avoided [$/tonne]

Design

ST-EXTR

DB þ HRSG þ ST

NB þ ST

NB þ ST*

BB þ ST

55.2 22.7 22.5 0.0 193.5 3.0

54.2 19.6 22.9 12.3 123.6 4.8

54.2 24.9 27.1 8.4 123.1 5.7

54.2 21.8 22.9 3.8 136.0 5.2

54.2 22.1 22.9 2.9 123.6 4.8

54.2 22.1 22.9 2.9 123.6 4.8

26.7 3.3 2.4 2.5

31.2 3.2 2.8 2.5

31.8 3.2 2.8 2.7

26.7 3.3 2.4 2.5

26.7 3.3 2.4 2.5

e e e e e e e e e e e

e e e e e e e

0.59 4.1 5.7 3.0 146.5 191.2 576.2

0.64 7.5 10.5 3.0 149.0 12.4 90

0.56 6.5 9.2 3.0 149.0 10.8 90.0

1.48 6.5 9.2 3.0 149.0 10.7 130

77.9 48.1 417.6 0.0 0.0 e e 63.9 e

68.9 42.1 47.6 35.0 90 11 77.9 102.7 105.0

77.9 40.3 49.6 35.0 90 0 88.2 102.6 105.3

77.9 39.8 50.3 35.0 90 0 107.7 107.8 119.7

78.0 40.7 113.3 35.0 77 0 98.4 103.2 129.4

78.0 40.6 42.3 35.0 90 0 98.5 102.5 102.9

Fig. 15. Thermal power (a) and steam flow rate (b) required by the reboiler for the retrofit options of NGCCe1P.

60% of the total heat provided to the reboiler. Energy losses due to capture islands are balanced by the power produced from superheated steam expansion (4.1 MW). Hence, the efficiency penalty increased to 8% pts, while CO2 emissions were 49.6 kg/ MWh. In the case of the auxiliary unit with a natural gas boiler (NB þ HRSG þ ST), the increase in the thermal power for solvent regeneration (31.8 MW) was due to the increase in the flue gas flow rate (þ10%). Steam extraction from the NGCC-1P was reduced to 3.8 kg/s (Fig. 15a), accounting for less than 30% of the CCS heat requirement, while the remainder was provided by the natural gas boiler (23.2 MWt) (Fig. 15b). In spite of the reduced stream extraction, an increase in auxiliary power capacity was required to eliminate the derating (7.5 MW) due to the higher flue gas flow rate, which affected the electricity requirements for CO2 capture and compression. Due to the increase in low grade heat production, the efficiency penalty exceeded 8% pts. If flue gases from the additional unit were vented into the atmosphere (NB þ HRSG þ ST*), the thermal power required by the reboiler was the same as that in ST-EXTR, with a 24% steam extraction contribution (6.5 MWt) (Fig. 15b). The efficiency penalty was slightly lower than that in DB þ HRSG þ ST, while the capture ratio was reduced to 77%, thus increasing CO2 emissions up to 113.3 kg/MWh. Substituting natural gas with woody biomass (BB þ HRSG þ ST) allows the exhaust flue gas to be vented into the atmosphere without substantially increasing CO2 emissions. Indeed, considering that CO2 from combustion process balances the CO2 absorbed by photosynthetic fixation, the only CO2 source is related to the collection and transportation of biomass [29]. Unlike the previous retrofit option, the capture ratio remains virtually unchanged (89.9%), and specific CO2 emissions were reduced to 42.3 kg/MWh. From an economic point of view, DB þ HRSG þ ST showed the lowest increase in retrofit cost (þ13%) compared to ST-EXTR (77.9 M$). With regard to options based on natural gas or biomass boiler, the retrofit cost ranged from 98.4 M$ (NB þ ST*) to

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071

14

R. Carapellucci et al. / Energy xxx (2015) 1e15

Fig. 16. Effects of retrofit options on the COE (a) and CO2 capture cost (b) for NGCC-1P.

107.7 M$ (NB þ ST), with the auxiliary system accounting for approximately 20% (Table 10). For conventional stream extraction, the increase in COE with respect to design conditions exceeded þ60% (102.7 $/MWh). As shown in Fig. 16a, COE remained almost unchanged from ST-EXTR to DB þ HRSG þ ST, as the increase in COEFUEL due to lower efficiency was balanced by the reduction in COECAP; the mitigation costs slightly increased (105.3 $/tonne) as a result of higher CO2 emissions. The analysis of retrofit options based on the auxiliary boiler showed that switching from natural gas to biomass reduced the COE from 107.8 $/MWh (NB þ ST) to 102.5 $/MWh (BB þ ST), while the mitigation cost decreased from 119.7 to 102.9 $/tonne (Fig. 16b). 6. Conclusions The aim of this paper was to analyse steam-gas power plants retrofitted with an amine-based post-combustion carbon capture unit. The investigation concerned three NGCCs with differently rated capacities and HRSG layouts. For each NGCC configuration, several options to fulfil the heat requirement of the CCS system were explored, including conventional steam extraction from the power block and integration of an auxiliary cogeneration unit. Energy and economic analyses of NGCC-3PRH showed that by being retrofitted with steam extraction, power plant derating was approximately 9% and thus involved an efficiency penalty of 5% pts. With a retrofitting cost of 170 M$, the COE increased by approximately 40% (76.6 $/MWh), while the mitigation cost was 71.8 $/tonne. To reduce power plant derating due to the CCS system, the integration of an auxiliary unit based on a gas turbine or supplementary firing unit were explored. The results showed that all retrofit options based on gas turbines eliminated power plant derating. Moreover, GT þ HRSG þ ST also provided the best energy and economic performances. When compared to ST-EXTR, the efficiency penalty and CO2 emissions remained unchanged, while the COE (76.2 $/MWh) and mitigation costs (70.3 $/tonne) were slightly reduced. For integration of a supplementary firing unit, power plant derating was eliminated only in DB þ HRSG þ ST, at the expense of an increase in the efficiency penalty (8% pts). Due to greater simplicity of the auxiliary unit, the cost of retrofit intervention was reduced by approximately 5% (202.1 M$) compared to GT þ HRSG þ ST. Conversely, the COE and mitigation costs increased to 78.2 $/MWh and 77.1 $/tonne.

For the NGCC-2P configuration, the power output was reduced by approximately 11% in ST-EXTR, leading to an efficiency penalty of 6% pts. The CO2 capture retrofit increased the COE by 50% (87.8 $/ MWh), leading to a mitigation cost of 88.4 $/tonne. Due to the lower rated capacity of NGCC-2P (171.3 MW), the investigation of alternative heat integration options only addressed cases based on a supplementary firing unit. The integration of a duct burner (DB) allowed for a reduction in plant derating by up to 6% (mSH ¼ þ20%), while keeping economic performance unchanged. DB-HRSG þ ST eliminated the plant derating and thus increased the COE and mitigation costs to 88.9 $/MWh and 92.2 $/tonne. Despite the lower rated capacity, the retrofit of NGCC-1P with steam extraction led to values of efficiency penalty and power derating comparable to that of NGCC-2P. The COE exceeded 102 $/ MWh, while the mitigation cost was 105 $/tonne. Eliminating the derating with a supplementary firing unit (DB þ HRSG þ ST) increased the efficiency penalty by up to 8% pts, and the economic performance was comparable to that of ST-EXTR. The efficiency penalty remained almost unchanged when substituting the supplementary firing unit with a natural gas boiler, while the COE and mitigation cost increased by þ5% and þ14%, respectively. Using biomass in place of natural gas (BB þ ST) reduced the size of the capture island, as exhaust flue gas was vented into the atmosphere without increasing CO2 emissions. This aspect positively affected the COE and the cost of CO2 avoided, reducing their values to 102.5 $/MWh and 102.9 $/tonne. References [1] International Energy Agency (IEA). Key world energy statistics, Paris. 2013. [2] International Energy Agency. Technology roadmap carbon capture and storage, Paris. 2009. [3] Balling L, Baumgartner R. Forty years of combined cycle power plants. ASME Power Division Special Section; October 2002. [4] Notz R, Mangalapally HP, Hasse H. Post combustion CO2 capture by reactive absorption: pilot plant description and results of systematic studies with MEA. Int J Greenh Gas Control 2012;6:84e112. [5] Oexmann J, Kather A. Minimising the regeneration heat duty of post combustion CO2 capture by wet chemical absorption: the misguided focus on low heat of absorption solvents. Int J Greenh Gas Control 2010;4:36e43. [6] Lindqvist K, Jordal K, Haugen G, Hoff KA, Anantharaman R. Integration aspects of reactive absorption for post-combustion CO2 capture from NGCC (natural gas combined cycle) power plants. Energy 2014;78:758e67. [7] Van Wagener DH, Liebenthal U, Plaza JM, Kather A, Rochelle GT. Maximizing coal-fired power plant efficiency with integration of amine-based CO2 capture in greenfield and retrofit scenarios. Energy 2014;72:824e31.

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Glossary Symbols CO2avoided: Cost of CO2 avoided, $/tonne CO2em: Specific CO2 emissions, kg/MWh m: Mass flow rate, kg/s P: Power, MW p: Pressure, bar q: Heat, MWt T: Temperature,  C x: Molar fraction, % Greek letters

a: Plant derating, % b: Pressure ratio h: Efficiency, %

4: CO2 capture ratio, % Subscripts CCS: Carbon capture and storage COND: Condenser CP: Compression EXH: Exhaust EXTR: Extraction GT: Gas turbine HPST: High-pressure steam turbine IPST: Intermediate-pressure steam turbine LPST: Low-pressure steam turbine MEA: Monoethanolamine REB: Reboiler s: Steam SH: Superheated ST: Steam turbine Acronyms AUX: Auxiliary system BB: Biomass boiler BP-ST: Back pressure steam turbine CCS: Carbon capture and storage COE: Cost of electricity DB: Duct burner EGR: Exhaust gas recirculation GT: Gas turbine HRSG: Heat recovery steam generator LHV: Lower heating value MEA: Monoethanolamine NB: Natural gas, Natural gas boiler NGCC: Natural gas combined cycle O&M: Operating and maintenance 1P: Single-pressure level 2P: Two-pressure levels 3PRH: Three-pressure levels with reheat

Please cite this article in press as: Carapellucci R, et al., Studying heat integration options for steam-gas power plants retrofitted with CO2 postcombustion capture, Energy (2015), http://dx.doi.org/10.1016/j.energy.2015.03.071