Analysis and optimization of CO2 capture in an existing coal-fired power plant in China

Energy 58 (2013) 117e127

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Analysis and optimization of CO2 capture in an existing coal-fired power plant in China Gang Xu, Yong-ping Yang*, Jie Ding, Shoucheng Li, Wenyi Liu, Kai Zhang Key Laboratory of Condition Monitoring and Control for Power Plant Equipment of Ministry of Education, School of Energy Power and Mechanical Engineering, North China Electric Power University, Beijing 102206, China

a r t i c l e i n f o

a b s t r a c t

Article history: Received 25 August 2012 Received in revised form 26 March 2013 Accepted 10 April 2013 Available online 15 May 2013

Retrofitting existing power plants for CO2 capture poses numerous constraints. The layout of the original process and the structure of the existing equipment cause various special problems in the design process as well as influence system performance. In view of these, this paper carries out process simulations, characteristic analysis, and system integration of CO2 capture based on an existing typical coal-fired power plant in China with supercritical parameters. The main constraints encountered in decarburized retrofitting of the existing power plants using monoethanolamine solution are analyzed. In addition, several special system integration schemes for CO2 capture in an existing 600 MW power generation unit are put forward. The results reveals that, due to the constraints in the layout of the original process and the structure of the existing equipment, efficiency penalty of CO2 capture in an existing power plant will be as high as 13.73%-points, higher than a newly redesigned power plant by 3.70%-points. And through special system integrations, the efficiency of such retrofitting existing power plant can increase by 4.15%points. The research of this paper may provide feasible technology solutions for the decarburized retrofitting of existing power plants and promote CCS (CO2 capture and storage) technologies into application. Crown Copyright Ó 2013 Published by Elsevier Ltd. All rights reserved.

Keywords: CO2 capture Existing coal-fired power plants Decarburized retrofitting Efficiency penalty System integration

1. Introduction The increasing concentration of CO2 and other greenhouse gases is the main reason behind alarming environmental phenomena such as global warming and rising sea levels [1,2]. China, one of the world’s largest producers of CO2, is responsible for approximately one-fifth of the world’s CO2 emissions [3]. Unlike many industrialized countries, China primarily uses coal for energy. Coal is cheap but carbon-intensive. Pulverized coal-fired power plants, whose total installed capacity is over 700 GW, provide nearly 80% of the total electricity in China. These power plants make up almost half of the total CO2 emission volume in the country [4]. Therefore, CO2 emission reductions in the electricity supply sector of China, especially in pulverized coal-fired power plants, will contribute significantly to the worldwide effort in reducing CO2. Although characterized by high costs and intensive energy requirements, CO2 capture and storage (CCS) has still attracted growing interest worldwide. It is regarded as a technically feasible

* Corresponding author. Tel./fax: þ86 10 61772011. E-mail addresses: [email protected], [email protected] (Y.-p. Yang).

method of making deep reductions in CO2 emissions from fossil energy utilization systems [5e11]. As of this writing, there are three basic technologies for capturing CO2 from energy systems: postcombustion capture, oxy-fuel combustion capture, and precombustion capture. As for CO2 separation process, generally there are four kinds of methods, that is, absorption (including chemical and physical absorption), adsorption, membrane, and cryogenic separation [1,12]. For pulverized coal-fired power plants, post-combustion capture with chemical absorption using an aqueous solution such as monoethanolamine (MEA) is recognized as one of the most feasible technologies. This process is regarded as a mature technology that is suitable for removing CO2 at low concentrations and for considerable improvements [7,8,12e15]. Numerous researchers have investigated CO2 recovery by chemical absorption during the past few decades [8,9,16e26]. Alie et al. presented a detailed simulation method for a typical CO2 capture process using MEA solvent and carried out the optimization of key operating variables [8]. Amann and Pellegrini analyzed the influence of different absorbents (MDEA-TETA and ammonia, respectively) for energy regeneration [9,16]. Mohammad et al. investigated the technical and economic performance of CO2 capture from power plants in detail [17,18]. Hetland et al. integrated a full carbon capture scheme into a 450 MW natural gas combined-cycle

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G. Xu et al. / Energy 58 (2013) 117e127

power station [19]. Huang et al. conducted an industrial test and techno-economic analysis of CO2 capture in a Huaneng Beijing coalfired power station. These studies disclosed the basic characteristics of coal-fired power plants with chemical CO2 absorption processes, revealing that post-combustion is a feasible option for the capture of CO2 produced by commercial coal-fired power plants [20]. Several researchers have also paid attention to the integration of CO2 capture with power generation systems [21e26]. Sanpasertparnich et al. integrated post-combustion capture and storage technology into a pulverized coal-fired power plant [23]. Gibbins et al. put forward the CO2 capture ready (CCR) plant, which focuses on a newly built plant, and proposed three different turbine options for CCR plants [25]. However, most of these integration studies neglect the restriction on existing power generation assemblies and make many modifications in the steam system of the plant. In fact, such modifications made are only possible in thoroughly redesigned newly built plants, not for existing power plants. Retrofitting an existing power plant for CO2 capture poses numerous constraints. The layout of the original process and the structure of the existing equipment cause various special problems in the design process. These effects also deeply influence system performance, which, in turn, requires special considerations during system integration. However, few studies have paid much attention to these special phenomena in the research of large-scale CO2 capture in existing power plants. In one of our previous work [27], the optimization of CO2 capture process had been well studied, and some integration schemes of coal-fired power plant with CO2 capture was proposed. In this paper, the influence of the restrictions of the existing power plant on the design & performance of the decarburized retrofitting is quantitatively analyzed. Simultaneously, the special integration measures for existing power plant decarburization are summarized and proposed, and their effect on irreversibility reduction of the integrated system are deeply analyzed. Finally, the techno-economic analysis of each integrated scheme is also comprehensively studied. Through this study, the paper aims to provide feasible technology solutions for the decarburized retrofitting of existing power plants and promotes CCS technologies into application. 2. Particularities of CO2 capture in an existing power plant Coal-fired power plants that use chemical absorption in reducing CO2 emissions experience a decrease in thermal efficiency of 10e15%-points [23,24,28] to achieve a 90% CO2 recovery ratio. Most efficiency penalties come from the energy consumption of CO2 capture, particularly the heat requirement of solvent regeneration. In an amine scrubbing process, solvent regeneration requires 3.2 MJ/kgCO2 to 4.2 MJ/kgCO2 of heat energy [17,23,24]. The large amount of heat provided by solvent regeneration during CO2 capture in power plants mainly comes from the condensation of steam extracted from the steam turbine. However, compared with the virtual plant or redesigned newlybuilt plant, the steam/water cycle of an existing power plant can not be made a lot of changes because of process and device restrictions. 2.1. Restrictions of steam extraction parameters Solvent desorption temperatures in the CO2 chemical absorption capture process vary with different absorbents. However, most chemical absorption methods need to provide thermal energy temperatures of 100  Ce150  C for the stripping process. Take MEA for example, thermal treatment of 100  Ce140  C in the stripper releases CO2 and regenerates the CO2-rich amine [17,24,25,29]. The stripper makes use of the steam extracted from the steam/water

cycle of the power plant. As an economic consideration, the extracted steam at 2.1e3.4 bar is suitable to provide solvent regeneration heat. In early studies of the decarburizing of power plants with chemical absorption CO2 capture process, the steam with suitable parameter (i.e. the extracted steam at 2.1e3.4 bar) is directly extracted from steam turbine cycle. However, where to extract, how to extract the steam with such parameters, and the possibility of the extraction point selection is seldom taken into consideration [14e16]. For example, Pellegrini G. et al. simulated different flowsheets in which steam extraction was done directly from the LP (low pressure) turbines [16]. Unfortunately, on one side, in modern large scale steam turbine, the steam at 2.1e3.4 bar is always located within the LP turbine cylinder. On the other side, the amount of extracted steam is also enormous, which can be half of the total steam flow of the low pressure (LP) cylinders of the steam turbine [24,25], due to the extensive heat demand of solvent desorption. In fact, the large-scale steam extraction from the LP turbine is impossible. The reason lies in the fact that the steam turbine is a precise rotary machine with fixed rotate speed. Thus, the internal steam of the LP turbine is strictly in accordance with aerodynamic principles. Besides, the flow area of the each stage of LP turbine matches with the pressure, flow rate and flow direction of steam. If a large amount of steam is extracted, the steam pressure, flow rate and flow direction after the extraction point will vary greatly, leading to the unstable working condition and sharply decreased working efficiency of the turbine. Even worse, the fierce turbulence flow and vibration may also occur. Therefore, the only feasible steam extraction point for existing power plants may be located at the crossover pipe between the intermediate pressure (IP) and LP cylinders of the steam turbine [23,25]. For the reason that: (1) as the connection pipe instead of internal turbine, the large-scale steam extraction is possible in this place. (2) In addition, the parameter in this part is 5e12 bar, which is higher than needed 2.1e3.4 bar but still acceptable. Comparatively, pressure of the crossover pipe between the HP (high pressure) and IP cylinders reaches up to over 40 bar. Actually, in the recent researches about the application of chemical CO2 capture process in a coal-fired power plant, more and more scholars had chosen the connection pipe between the IP and LP turbine cylinders as the steam extraction point [25,30,31]. For example, Lucquiaud M. and Gibbins J. have pointed out that the best location to extract steam to provide solvent regeneration is the crossover pipe between the IP turbine and LP turbines [31]. Another fact is that, such crossover pipe is also the place to extract a large amount of steam for heat supply in numerous combined heat and power generation units [32e35]. In most supercritical or ultra-supercritical units, the pressure of steam extracted from the IP/LP cylinders can be as high as 9e12 bar [23,36,37], far higher than the required parameters of the stripper for absorbent regeneration, which will bring extra power loss. Fig. 1 shows the relationship of power loss per kg of extracted steam with its pressure. As shown in the figure, the higher the extracted pressure, the higher the specific power loss. When the pressure of extracted steam reaches 9e12 bar, the power loss will be almost 1.5 times as much as that of the steam extracted at 2.1 bar. 2.2. Off-design conditions of LP turbines due to large amounts of extracted steam As mentioned above, a large amount of heating steam will be extracted from the crossover pipe between the IP and LP turbines in CO2 capture retrofitting of existing power plants. This leads LP turbines to operating under off-design conditions. In this situation, the steam flow rate of LP turbines drops drastically, leading to the substantial deviation of steam parameters from rated values.

G. Xu et al. / Energy 58 (2013) 117e127

Power loss (kwh/kg)

0.20 kWh/kg

0.20

0.146 kWh/kg

0.16

2.1 bar

12 bar

9 bar

0.12 0

2

4

6

8

10

12

Steam extraction pressure bar Fig. 1. Relationship between power loss and steam extraction pressure.

However, the performance characteristics of steam parameters even under off-design conditions still comply with certain rules. If the steam velocity in a stage of a given stage group becomes equal to or greater than the critical velocity, the pressure behind that stage will influence the steam parameters in the preceding stages [37]. The flow rate with the same clear cross-sectional area will depend only on the steam parameters beforepthe ffiffiffiffiffiffiffiffiblade cascades of the preceding stages. The equation G ¼ A p=v determines this process, where G, A, p and v are the steam mass flow rate, turbine cross-sectional area, steam pressure and specific volume respectively.

G1 =G0 ¼

rffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi  .  p201  p2g1

p20  p2g

pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi ðT0 =T01 Þ

(1)

where, p0 , pg and T0 are the initial pressure, back pressure and initial temperature of steam at the rated flow rate G0 respectively; and p01 , pg1 and T01 are under changed conditions with the new flow rate G1 . When without consideration of the temperature variation, the formula becomes:

G1 =G ¼

rffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi .   p20  p2g p201  p2g1

(2)

Change ratio of LP turbine inlet pressure

Formula (1) or (2) is the famous Flugel formula [38,39], representing the relationship between the steam flow rate and steam 1.2

without the consideration of pressure loss with the consideration of pressure loss

1.0

0.8

0.6

0.4

0.2 8%

17%

25%

33%

42%

50%

58%

pressure in the turbine cylinders under subcritical working condition. For Formula (2), when the initial pressure remains unchanged (p01 ¼ p0 ), the relationship between the steam flow rate and steam pressure is in accordance with the elliptic rules and Formula (2) is referred as Elliptic Equation; when the back pressure remains unchanged (pg1 ¼ pg ), the relationship between the steam flow rate and steam pressure is in accordance with the hyperbolic rules and Formula (2) is referred as Hyperbolic Equation. Fig. 2 shows the performance curves under different steam extraction proportions. The dotted line represents the conditions without consideration to pressure loss. This means that the inlet steam pressure of the LP turbines is kept constant with part of the steam extracted (see dotted line in Fig. 2a), and the power loss of LP turbines is only caused by the fact that extraction steam doesn’t do any work (see dotted line in Fig. 2b). Obviously, this is an assumptive operation status and is impossible in an existing power plant. On the contrary, the solid line stands for practical operation conditions, that is, the steam turbines operating under off-design conditions when part of the steam is extracted from the system, which complies with Equation (2). Here, the inlet steam pressure of the LP turbines decreases with the increase in steam extraction proportion (see the solid line in Fig. 2a), leading to more power loss for LP turbines (see the solid line in Fig. 2b). This effect means that the pressure loss of LP turbines due to steam extraction brings about additional power loss (see space between the solid and dotted lines in Fig. 2b). For example, when the steam extraction proportion is 50% of the total steam flow of the LP turbines, the pressure loss is approximately 50% (Fig. 2a) and power output of the LP turbines is only 42% (Fig. 2a). Here, the extracted steam itself accounts for nearly 50% of power loss. Meanwhile, additional power loss caused by the pressure loss of steam extraction covers about 8%. In other words, large amounts of steam extraction not only bring significant reduction of steam flow in the LP turbines, but also cause the operation of the LP turbines to deviate greatly from the design condition. Therefore, large steam extractions lead to additional power loss and further efficiency decline, and the proportion of power loss caused by extra extraction is larger along with the increase in extraction proportion. 3. Case study based on an existing 600 MW supercritical unit 3.1. Base case: a typical 600 MW supercritical unit in China A typical 600 MW coal-fired power generation unit without CO2 capture in China is selected as the base case. The power plant is a pulverized coal-fired power generating unit with a 600 MW output

Change ratio of LP turbine power output

0.237 kWh/kg

0.24

119

without the consideration of pressure loss with the consideration of pressure loss

1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 8%

17%

25%

33%

42%

50%

Steam extraction proportion

Steam extraction proportion

(a) LP turbine inlet steam pressure

(b) LP turbine power output

Fig. 2. LP turbine performance trends with different steam extraction proportions.

58%

120

G. Xu et al. / Energy 58 (2013) 117e127

adopting a supercritical pressure steam/water cycle. Bituminous coal is selected as fuel. A schematic diagram of the supercritical coal-fired power plant without CO2 capture is shown in Fig. 3. The turbine consists of high pressure (HP), IP, and LP turbines connected to the generator with a common shaft. Steam from the exhaust of the HP turbine is returned to the boiler for reheating and then sent to the double flow IP turbine. Exhaust steam from the IP turbine then flows into the double cylinder/four-exhaust LP turbines. The overall performance of the unit is summarized in Table 1. The power generation unit is designed to generate about 1677.5 t/h of steam at nominal condition of 24.2 MPa and 566  C. The reheat steam is heated to 566  C, and (the condenser pressure) is 5.88 kPa. These values represent the typical parameters of existing power generation units in China. 3.2. Amine scrubbing process for post-combustion CO2 capture In this study, the design of CO2 capture process is based on a standard MEA absorption-desorption method. Fig. 4 shows the process of the CO2 separation unit. Flue gas from the power plant is first cooled down to a temperature of 40  Ce50  C and then desulfurized in a flue gas desulfurization (FGD) unit. After passing through a booster fan, the flue gas is absorbed by MEA in an absorber. The treated flue gas, from which most of the CO2 gas has been separated, is vented to the atmosphere. Rich solvent from the bottom of the CO2 absorber is delivered to a cross heat exchanger by a pump (P1). Having been heated in the heat exchanger, the rich solvent is delivered to a stripper for CO2 desorption by thermal treatment at 100  C up to 140  C. The CO2eH2O stream desorbed from the stripper is condensed and the moisture is removed to obtain purer CO2 in a condenser and a separator (Sp). The lean solvent is delivered to the cross heat exchanger by a pump (P2) and then to the absorber after the stream is cooled by a cooler (C1) to the designated temperature. Considering the degradation and volatilization of the MEA, the makeup of the MEA solvent is also added to the absorber. Usually, the CO2 separated from the stripper

Table 1 Overall performance of the base case. Items Fuel parameters Coal heat input (HHV) Coal heat input (LHV) Steam/water cycle parameters Existing steam turbine generator output Total auxiliary power Net output Overall plant performance parameters Net efficiency Net coal consumption rate Net heat rate Overall plant CO2 emissions CO2 emissions

Units MJ/kg, MJ/kg,

Value

ar ar

23.92 22.76

MW MW MW

601.20 30.22 570.98

% g/kWh kJ/kWh

40.08 305 8937.1

g/kWh

867.8

is compressed to the required pressure and temperature by the multistage compressor (CP) for CO2 transportation. The main parameters of the absorption process based on the MEA are listed in Table 2. The stripper is set to 2.1 bar and 115  C. The entire flue gas stream enters the absorber tower, and the CO2 recovery ratio reaches over 90%. Furthermore, the mass purity of the CO2 reaches 99.8%, which is high enough for CO2 storage and many other industrial applications. 3.3. Capture case 1: CO2 capture without consideration to the constraints of the existing power plant Case 1 is a typical 600 MW coal-fired power generation unit combined with the CO2 capture system. A simplified process flow diagram of Case 1 is shown in Fig. 5. As seen from the figure, the flue gas of the generation unit directly enters the absorber of the capture process. The thermal energy consumed by the stripper reboiler is supplied by the steam extracted from the steam turbine subsystem. Steam with a pressure of 2.7 bar is directly extracted from the LP cylinders of the steam turbine, supplying thermal energy with temperatures of 130  C for the stripper reboiler in conventional way. The selected pressure ensures a reasonable temperature differential in the reboiler. However, this scheme neglects the constraints of the existing power plant. The power generation in Case 1 is the same as the base case. The input fuel, boiler capacity, main steam, and reheated steam flow rate also equal those of the base case. Large amounts of 2.7 bar steam is directly extracted from the turbine system to provide thermal energy for MEA regeneration without consideration of the pressure change and flow disturbance in the LP cylinders. 3.4. Capture case 2: CO2 capture with consideration to the constraints of the existing power plant

Fig. 3. Schematic diagram of the 600 MW supercritical coal-fired power plant without CO2 capture process.

As shown in Fig. 6, the steam extraction point of Case 2 is located at the crossover pipe between the IP and LP cylinders of the steam turbine, which may be the only feasible point to achieve high steam extraction in an existing power plant. Here, the steam pressure of the crossover pipe between the IP and LP cylinders can reach 9.32 bar, much higher than the required steam pressure for absorbent regeneration (about 2.7 bar), which must be reduced by adding a throttling valve but brings extra power loss [30]. Furthermore, the extra pressure loss and additional power loss of LP turbines due to the large amount of extracted steam are considered in Case 2. The steam extraction for amine absorption process also accounts for approximately 50% of the total steam flow exhausted from IP turbine, which may lead to unstable operating conditions and several safety problems. For example, the drop to a low level

G. Xu et al. / Energy 58 (2013) 117e127

121

CO2 Product Condenser Vent Gas C1

Sp

Make-up Water + MEA

Booster fan

Absorber

Stripper

Cp

Flue gas FGD Heat Exchanger

Rich Amine Solution P1

Reboiler Lean ammonia Solution

P2

High pressure CO2

Fig. 4. Schematic diagram of CO2 capture process.

pressure at the exhaust of the existing IP turbine results in increased mechanical loading of the IP blades, especially the last stages of the IP turbine. Another example is, a large decrease in steam flow will lead to unstable operating conditions in the LP turbine since the flow area of LP turbine is not variable. 3.5. Thermal performance analysis The performance analysis of the three cases are listed in Table 3. The simulation & calculation of these cases as well as the following cases are conducted by using ASPENPLUS. The three cases are the following: ➢ Base Case: A typical 600 MW supercritical power generation unit, as discussed in Section 3.1. ➢ Case 1: CO2 capture case without consideration to the constraints of the existing power plant, as discussed in Section 3.3. ➢ Case 2: CO2 capture case with consideration to the constraints of the existing power plant, as discussed in Section 3.4. Since Case 1 and Case 2 are based on the same base case and adopt the same MEA CO2 capture process, the process configuration and several basic parameters of these two cases, such as coal input rate, reboiler heat duty, CO2 capture amount, and CO2 compression work, are similar to each other, as shown in Table 3. However, because of the difference in the extracted locations and the parameters of steam extraction of the two capture cases, large differences are present in the performance parameters of the plant, such as net power output and net efficiency. As is shown in Table 3, the power output of steam turbine Case 2 is only Table 2 Main performance parameters with MEA-based CO2 capture process. Items

Value

Desorber pressure (bar) Temperature of reboiler ( C) CO2 recovery ratio (%) CO2 lean loading (molCO2/molMEA) CO2 rich loading (molCO2/molMEA) Energy consumption of reboiler (MJ/t CO2) Energy consumption of condenser (MJ/t CO2) Mass purity of CO2 (%) Mole purity of CO2 (%)

2.1 115 90 0.3 0.45 3404 684 99.8 99.6

460.18 MW, 52.93 MW less than that of Case 1, mainly because of the larger power loss of the LP turbines due to the higher extraction pressure. This in turn leads to the obvious drop of net power output and net efficiency of Case 2 when compared with Case 1. Eventually, the efficiency penalty of Case 2 reaches 13.73%-points, 3.70%-points higher than that of Case 1. Although the performance of Case 2 seems worse, the constraints of the existing power plant are fully considered in this case, which is closer to the practice. Even for a newly built power plant, the same constraints in the CO2 capture retrofitting are still encountered if the plant adheres to the traditional design ideas. In other words, for large-scale decarbonization of a pulverized coalfired power plant by chemical absorption method, its practical efficiency penalty may be much higher than that of the theoretical analysis if no special integration arrangements are made. 3.6. Exergy analysis Table 4 illustrates the exergy analysis results of Base Case and Case 2. As shown in the table, the exergy efficiency of Case 2 is only 25.25% with 13.16%-points efficiency penalty compared to Base Case. Apart from the exergy loss in the CO2 separation and CO2 compression process, exergy loss in the throttling of extracted steam, heat dissipation of CO2 capture unit and extra pressure loss caused by large-scale steam extraction is comparatively high. Specifically: (1) the exergy loss caused by extracted steam throttling in Case 2 reaches as high as 32.15 MW, bringing 2.16%-points efficiency penalty; (2) the exergy loss in the heat dissipation is also considerable, which arrives at 41.32 MW, bringing 2.78%-points efficiency penalty; (3) extra pressure loss of steam entering the LP turbine also brings 16.09 MW of extra exergy loss, accounting for1.08%-points efficiency penalty. Thus, from above analysis, energy-saving potential may exist in surplus pressure utilization of extracted steam, waste heat utilization of CO2 capture unit and relief of the pressure loss caused by large-scale steam extraction for CO2 capture. 4. Special integration for CO2 capture in the existing power plant With full consideration of the engineering constraints in the existing power plant, a series of special integration methods are proposed in this section. Based on these integration methods, a

122

G. Xu et al. / Energy 58 (2013) 117e127

Fig. 5. Decarburized power plants without consideration of equipments restrictions (Case 1).

new integrated decarbonization coal-fired power plant is established (Case 3). Fig. 7 illustrates the main flow sheet of the new integrated plant. As shown in Fig. 7, the main integration methods can be classified into three sorts, that is, utilization of the surplus pressure in extracted steam, thermal energy integration and throttling one of LP cylinders.

4.1. Surplus pressure utilization of extracted steam As shown in Fig. 7, the surplus pressure utilization of extracted steam mainly contains: (1) adding a new letdown steam turbine; (2) adopting a steam ejector. The specific integration scheme will be analyzed below.

Fig. 6. Decarburized power plants with consideration of equipments restrictions (Case 2).

G. Xu et al. / Energy 58 (2013) 117e127 Table 3 Thermal performance of Base Case, Case 1, and Case 2.

Coal input rate (kg/s) CO2 capture amount (kg/h) CO2 capture rate (%) Reboiler heat duty (MW) Extracted steam flow (kg steam/kg CO2) CO2 compression work (kWh/ton CO2) Power output of steam turbine (MW) Auxiliary work (MW) Net power output Net efficiency (%) Efficiency penalty (%-points)

Base case

Case 1

Case 2

46.66      601.20 30.22 570.98 40.08 

46.66 447,423 90 420.83 10489 39.91 513.74 85.66 428.08 30.05 10.03

46.66 447,423 90 420.83 1.439 39.91 460.81 85.44 375.37 26.35 13.73

Addition of a new letdown steam turbine generator: The steam pressure of the IP-LP crossover pipe (9.32 bar) is much higher than the required steam pressure for solvent regeneration (about 2.7 bar). Thus, a new letdown steam turbine generator (LSTG) is proposed to utilize the surplus pressure for power generation (Fig. 7). The improvement is not only simple and easy to implement, but also remarkable to increase power plant efficiency because of the effectiveness in retrieving the surplus pressure. Fig. 8 gives the variation trend of the power output and the extraction steam flow when the LSTG outlet pressure is changed. As is shown in Fig. 8, with the decline of LSTG outlet pressure, the power output of LSTG will increase quickly (Fig. 8b), while the flow of the extracted steam is also slightly increasing (Fig. 8a). The reason lies in that the temperature and enthalpy of the exhaust steam of LSTG will slightly decrease with the drop of LSTG outlet pressure. As a consequence, it needs more extraction steam flow so as to provide the same energy for solvent desorption. And the increase in extracted steam flow will contribute to the growth in LSTG power output. Besides, the decrease of LSTG outlet pressure will remarkably enlarge the pressure ratio since its inlet steam pressure is approximately maintain 9.32 bar, which will also lead to the rapid growth in LSTG power output. Table 4 Exergy analysis of Base Case and Cases 2. Base case

Exergy input of coal Exergy output Net electricity Separated CO2 Exergy loss CO2 recovery unit CO2 separation Heat dissipation CO2 compression HE2 Throttling Subtotal Power generation system Boiler HPT IPT LPT Extra loss High pressure regenerative heater Low pressure regenerative heater Condenser Other equipments Subtotal Exergy of exhaust gas Exergy efficiency, %

Case 2

MW

%

MW

%

1486.67

100

1486.67

100

570.98 0

38.41 0

375.37 85.63

25.25 5.76

e e e e e e

e e e e e e

66.07 41.32 5.43 13.64 32.15 158.74

4.44 2.78 0.37 0.92 2.16 10.68

754.50 14.31 7.99 28.78 e 5.41 5.85 30.81 9.32 856.97 59.56 38.41

50.75 0.96 0.54 1.94 e 0.36 0.39 2.07 0.63 57.64 4.01

755.61 14.31 7.99 12.30 16.09 5.45 2.16 13.90 7.88 835.69 38.53 25.25

50.83 0.96 0.54 0.83 1.08 0.37 0.15 0.93 0.53 56.21 2.59

123

Addition of a steam ejector: By installing a steam ejector, the surplus pressure of the extracted steam (about 9.3 bar) can be used to improve the pressure of the sixth-stage extracted steam (about 1.1 bar) to the reboiler requirement pressure (2.7 bar). Fig. 9 shows a simplified structure of a steam ejector. The core component of steam ejector is a Laval nozzle, where the highpressure working fluid passes through and flows out with supersonic speed but negative pressure, thus, the low-parameter ejection fluid can be induced to mix with it and finally the mixed fluid is formed with intermediated pressure. From Fig. 8, it can be found that the new letdown steam turbine can significantly increase the power output, but simultaneously increase the extracted steam flow. Meanwhile, the steam ejector not only reasonably utilizes the surplus pressure of high-parameter steam, but also reduces the flow rate of the high-parameter steam. For instance, in this paper, by adopting the steam ejector, the extracted steam with 0.93 MPa and 61 t/h is extracted to inject the sixth-stage steam extraction with 0.11 MPa and 20 t/h. The mixed steam is of 0.27 MPa and 81 t/h, which meets the requirements of the reboiler operation. As a consequence of which, the steam extraction between the IP and LP turbine is obviously reduced and the pressure variation caused by large-scale steam extraction can also be relieved. 4.2. Thermal energy integration between CO2 capture process and steamewater cycle The CO2 separation unit in a MEA-based CO2 capture process needs a large amount of intermediate temperature steam extracted from the steam turbine cycle to regenerate the solvent. In contrast, the CO2 separation unit also releases a large amount of low temperature heat, such as the heat released by the CO2eH2O condenser of the stripper and the intercooler of the CO2 multistage compressor (Fig. 4). If these low temperature heat can be used efficiently, the energy consumption of CO2 capture will be reduced dramatically. In view of this, this section proposes a special integration scheme between CO2 capture process and steamewater cycle with full consideration of engineering constraints in the existing power plant. As shown in Fig. 7, the main heat integration measures can be summarized as follows: (1) The condensed water is heated by the thermal energy released from CO2 cooler (HE3) and the CO2 compression intercoolers (HE4). This integration scheme can replace the original lowpressure regenerative heaters (RH6-RH8), in raising the temperature of the condensed water to approximately 122  C. (2) The initial fifth-stage regenerative heater (RH5) is retained. In this integration scheme, the steam pressure in the fifth-stage regenerative heater remains 3.7 bar, which can which can further increase the temperature of the condensed water to 139  C. Thus, the steam extraction from the outlet of IP turbine with 9.32 bar, which is delivered to the deaerator, can be dramatically reduced. (3) After recovering the surplus pressure within LSTG, the extracted steam is first sent to heat the condensed water (HE2) and then to the reboiler of the stripper (HE1). The purpose is to reduce the superheat of the extracted steam and protect the absorbents. Simultaneously, part of surplus heat can be recycled back to the condensed water. As a whole, in this integration scheme, the condensed water passes through HE3, HE4, RH5 and HE2 successively and its temperature can be raised to approximately 160  C, as a consequence, the steam extraction from the fourth-stage regenerative heater for deaerator can be greatly reduced.

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G. Xu et al. / Energy 58 (2013) 117e127

Fig. 7. Schematic scheme of a new integrated decarbonization power plant (Case 3).

4.3. Throttling one of LP cylinder in steam turbine The flow rate of steam extraction for MEA solvent regeneration is almost half of the total inlet steam flow of the original LP cylinders. Since there are two LP cylinders in the steam turbine, the flow rate of low pressure steam after extraction is approximately equal to that of one cylinder in design conditions. In view of this, if we let the low pressure steam flow into only one LP cylinder instead of two cylinders after extraction, the steam flow rate of the operating LP cylinder is similarly equals the design parameters. As a result, the large-scale extra pressure drop of LP cylinder caused by steam extraction can be avoided. However, for a conventional existing power plant, all of the turbine cylinder rotors are connected in the same shaft and it is impossible to completely clutch them from the machine. Thus, throttling can be used to make most of the steam flow into one of

the LP cylinder; a small amount of steam enters the other cylinder for heat dissipation. Fig. 7 shows the process scheme. As seen in the figure, the huge pressure drop in the LP cylinder is avoided, which ensures the increment of the steam turbine’s power output as well as the net efficiency. 4.4. Thermal performance analysis Performance analyses of the integrated decarbonization plant and the reference plants are listed in Table 5. As is shown in Table 5, adding a new letdown steam turbine generator can increase power output by 40.77 MW, while the adoption of the steam ejector reduces the steam flow with 9.32 bar for reboiler operation by 34 t/h. In addition, the heat integration of steam turbine cycle with the CO2 capture process can recover 62.06 MW thermal energy from CO2 capture process. Besides, if one LP cylinder in the steam turbine 60 50

600

LSTG output (MW)

Extracted steams flow (t/h)

700

500 400 300 200

40 30 20 10

100 0

0 7

6

5

4

3

LSTG outlet pressure (bar)

(a) Extracted steam flow

2

7

6

5

4

3

LSTG outlet pressure (bar)

(b) Power output of new LSTG

Fig. 8. Variation trends of steam cycle performances with different LSTG outlet pressures.

2

G. Xu et al. / Energy 58 (2013) 117e127

125

Table 6 Exergy analysis of Case 2 and Cases 3. Case 2

Fig. 9. Simplified structure of a steam ejector.

is throttled and the steam enters the other LP cylinders, the huge pressure drop in the LP cylinder is avoided. The two integration measures contribute to 18.45 MW power output of steam turbines. Finally, compared to Case 2 without system integration, Case 3 presents a better thermal performance with 59.1 MW and 4.15%points net power output increment and net efficiency increment, respectively. Compared with the Base Case, the efficiency penalty of Case 3 is only 9.58%-points, dramatically less than that of Case 2 (13.73%-points). 5. Further discussion 5.1. Exergy analysis To reveal the internal phenomena of the new integration system, an exergy analysis is performed for Case 2 and Case 3. The results are listed in Table 6. The exergy analysis is based on the assumption that the same quantity of coal is consumed. Case 3 adopts a new LSTG, a steam ejector to replace the throttling process in Case 2. As shown from Table 6, the exergy loss (32.15 MW) of throttling is eliminated with only 8.66 MW exergy loss of the new LSTG and the steam ejector. At the same time, due to the adoption of the new LSTG and the steam ejector, the superheat degree of the steam inlet HE2 is reduced from 227  C to 113  C, which also contributes to the 11.11 MW exergy loss reduction of HE2. To sum up, the total exergy loss of added LSTG, steam ejector and HE2 in Case 3 is much less than that of Case 2 by 34.60 MW, which is the main benefits brought by added LSTG and steam ejector. Besides, heat integration of CO2 capture process with steam/ water cycle is realized in Case 3. As proposed in Section 4.2, the thermal energy released from CO2 cooler and CO2 compression intercoolers are successively recovered to heat the condensed water in the power generation unit. As shown from Table 6, the exergy loss (41.32 MW) of heat dissipation in Case 2 is reduce to 23.11 MW

Table 5 Thermal performance comparison of Base Case, Cases 2 and Case 3.

Coal input rate (kg/s) CO2 capture amount (kg/h) CO2 capture rate (%) Reboiler heat duty (MW) CO2 compression work (MW) Outlet pressure of LSTG (bar) Steam extraction for reboiler/9.32 bar (ton/h) Heat recovery from CO2 capture (MW) Power output of steam turbine (MW) Power output of LSTG (MW) Gross power output (MW) Auxiliary work (MW) Net power output Net efficiency of plant (%) Efficiency penalty (%-points)

Base case

Case 2

Case 3

46.66 e e e e e e

46.66 447,423 90 420.83 39.91 2.7 685

46.66 447,423 90 420.83 39.91 2.7 652

e 601.20 e e 30.22 570.98 40.08 e

0 460.81 0 460.81 85.44 375.37 26.35 13.73

62.06 479.26 40.77 520.03 85.56 434.47 30.50 9.58

Exergy input of coal Exergy output Net electricity Separated CO2 Exergy loss CO2 recovery unit CO2 separation Heat dissipation CO2 compression HE2 HE3 & HE4 Throttling Steam injector Add LSTG Subtotal Power generation system Boiler (Fuel combustion) HPT IPT LPT Extra loss due to pressure drop High temperature heater Low temperature heater Condenser Other equipments Subtotal Exergy of exhaust gas Exergy efficiency, %

Case 3

MW

%

MW

%

1486.67

100

1486.67

100

375.37 85.63

25.25 5.76

434.47 85.63

29.22 5.76

66.07 41.32 5.56 13.64 e 32.15 e e 158.74

4.44 2.78 0.37 0.92 e 2.16 e e 10.68

66.07 23.11 5.43 2.53 5.45 e 2.49 6.17 111.25

4.44 1.55 0.37 0.17 0.37 e 0.17 0.42 7.48

755.61 14.31 7.99 12.30 16.09 5.45 2.16 13.90 7.88 835.59 38.53 25.25

50.83 0.96 0.54 0.83 1.08 0.37 0.15 0.93 0.53 56.21 2.59

754.55 14.31 7.99 13.27 1.17 5.45 0.71 14.16 7.36 857.50 38.53 29.14

50.75 0.96 0.54 0.89 0.08 0.37 0.05 0.95 0.50 57.68 2.59

of Case 3 with only 5.45 MW exergy loss of the new HE3&HE4, which is the main benefits brought by heat integration. Focus on the extra pressure loss of the LP turbine cylinders, Case 3 also adopts throttling one of LP cylinders (Section 4.3). As shown in Table 5, the exergy loss of extra pressure loss in Case 3 is only 1.17 MW and is approximately 15 MW less than that of Case 2, which is also the main reason for the performance improvement of Case 3. In comparison of Case 2 and Case 3, the exergy efficiency of Case 3 is 29.14%, 3.89%-points higher than that of Case 2. Therefore, for existing power plant, system integration of steamewater cycle with CO2 recovery process and the cascade utilization of thermal energy should be paid great attention for its great energy-saving effects. 5.2. Techno-economic analysis The specific techno-economic analysis of Base case, Case 2, and case 3 is conducted in this section. The basic economic assumptions employed here include: (1) The assumed coal price, 4.09 $/GJ LHV (750 ￥/t-standard coal), was the average cost to China electric generators in 2012. It has to be noted that China’s coal price is higher compared to other countries, because of the high energy requirement and corresponding policies [40]. (2) The exchange rate is set as 6.25 ￥/$. (3) Operation and maintenance (O&M) costs are fixed at 4% of TPI per year. (4) The annual utilization hours is assumed to be 5000 h per year. The specific techno-economic analysis is shown in Table 7. As shown in the Table, the TPI of Base case (420 M$) is estimated according to the related data of typical 600 MW coal-fired power plants in China from 2007 to 2012 [20,41]. Its specific investment cost is 700 $/kw (approximately 4400 ￥/kw). Here, it is worthy to stress that due to the rather cheap labor which is very common in China, the cost of the coal-fired power plants in China is lower compared to other countries especially western ones, which is presented in some literature [20,42].

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The total investment of CO2 capture process in Case 2 reaches 128.35 million dollars (802.22 million CNY), which is estimated by refering to the data of some demonstration stations in China [41]. After connected with the CO2 capture process, the TPI of Case 2 has reached up to 548.36 million dollars (3427.22 million CNY). Specific costs of additional components are shown in Table 8 [43]. It can be seen from Table 8 that compared to Case 2, total additional investment of Case 3 is 14.12 M$, so the TPI of Case 3 increases to 562.47 million dollars (3515.34 million CNY). It can be easily found that the TPI of Case 2 is 1.31 times of Base Case. However, due to the huge reduction of net power output in Case 2, the specific plant investment (SPI) of Case 2 is 1.99 times of Base Case. As for Case 3, its SPI reduces to 1294.61 $/kw with the obviously increase of net power output. The cost of electricity (COE) of each case is also given in Table 7. COE can be calculated as follows:

COE ¼

Table 8 Specific investment cost of additional components in Case 3. Component

Investment cost

Small turbine (M$) Heat exchangers (M$) Steam ejector (M$) Pump (M$) Pipeline (M$) Total additional investment (M$)

4.8 2.88 0.02 0.12 6.3 14.12

6. Conclusions This paper carried out the process simulation, characteristic analysis, and system integration of CO2 capture based on an existing Chinese coal-fired power plant with supercritical parameters. Important conclusions are drawn and several interesting integration measures are put forward from the work completed.

½ðCRFÞðTotal plant investmentÞ þ ðAnnual O&M costÞ þ ðAnnual cost on fuelÞ Annual electricity production

where, CRF is the capital recovery factor, which is related to the discounted rate (k) and the life of equipments (n), and is calculated as: CRF ¼ ½k,ð1 þ kÞn = ½ð1 þ kÞn  1, [1,16]. Here, the discounted rate (k) and the life of equipments (n) are set as 12% and 30 years respectively. Thus, CRF is equal to 0.124 [44,45]. As shown in the Table, we can find that, (1) compared to Base Case, COE of Case 2 greatly increases by 1.71 times due to the increased investment and reduced net power output; (2) after system integration, the net power output in Case 3 increases obviously while the gradual increment of TPI is unconspicuous, as a result of which, the COE of Case 3 is 91.39 $/MWh, with reduction of 12.18% when compared to Case 2. Besides, the cost of CO2 avoided is shown in Table 7, with definition as:

Cost of CO2 avoided ¼

COEavd  COEref Erref  Ercapture

(4)

where, ‘Er’ means the CO2 emission rate; the subscripts ‘capture’ and ‘ref’ refer to the plant with and without CO2 capture, respectively [45]. It can be seen from Table 7 that, like COE, the variation trend of the CO2 avoidance cost is gradually reduced both in Case 2 and Case 3. Among these, the CO2 avoidance cost of Case 3 reaches 39.44 $/ t CO2 and is 30% less than that of Case 2. To sum up, with the deep integration efforts, the net efficiency and net power output of the decarbonized power plants increase while specific plant investment, COE and the cost of CO2 avoided reduce, which reflects the benefits caused by the system integration. Table 7 Techno-economic performance of Base Case, Cases 2 and Case 3.

Net efficiency of plant (%) Net power output (MW) Total plant investment (TPI, M$) Specific plant investment (SPI, $/kW) Cost of electricity (COE, $/MWh) CO2 emission (Mt/yr) CO2 captured (Mt/yr) CO2 emission rate (tCO2/MWh) CO2 avoided rate (tCO2/MWh) Cost of CO2 avoided ($/t CO2)

Base case

Case 2

Case 3

40.08 570.98 420 731.97 60.86 2.49 0 0.868 0 0

26.35 375.37 548.36 1460.84 104.06 0.25 2.24 0.134 0.733 56.73

30.50 434.47 562.47 1294.61 91.39 0.25 2.24 0.117 0.751 39.44

(3)

(1) When an existing power plant is transformed into a CO2 capture plant using chemical absorption methods, several special problems are encountered different from those in a virtual plant. On one hand, it is difficult to find a suitable extraction point for the large amount of steam extracted to provide heat energy for MEA regeneration. On the other hand, several components of the existing power plant, especially the steam turbine, significantly deviate from their original design conditions because of the large amount of steam extracted from the steam/water cycle, thus resulting in a large efficiency penalty. (2) When retrofitting existing power plants, the energy penalty of CO2 capture tends to be higher because of the constraints of the existing equipment. Additional power loss is inevitable because the parameters of steam extraction do not match with the steam parameters of CO2 capture. Eventually, the efficiency penalty of CO2 capture in an existing power plant (Case 2) will be 3.70%-points higher than that of a newly redesigned power plant (Case 1). (3) In this study, through special system integrations, the efficiency of an existing 600 MW supercritical power plant increases by 4.15%-points, from 26.35% (Case 2) to 30.50% (Case 3). The overall studies show that if MEA absorption is adopted to recover CO2 from flue gas of a power plant, with a CO2 recovery ratio of 90%, the efficiency penalty of the decarburized retrofitting power plant with special system integrations can be 9.58%-points, which is much better than that of capture case without system integrations (Case 2, 13.73%-points) (4) Techno-economic analysis reveals that, with fully system integrations (Case 3), although the total investment slightly increases, the SPI, COE and CO2 avoidance cost can greatly reduced by 11.38%, 12.18% and 30.5% respectively when compared to Case 2, due to the obviously increase of net power output. It means that system integration not only brings great benefits to the overall thermal performance, but also improves the techno-economic performance. Acknowledgments The paper is supported by the National Nature Science Fund of China (51006034, 51061130538), the 111 Project (B12034), National

G. Xu et al. / Energy 58 (2013) 117e127

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