An assessment of different solvent-based capture technologies within an IGCC–CCS power plant

Energy 64 (2014) 268e276

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An assessment of different solvent-based capture technologies within an IGCCeCCS power plant Jeremy Urech a, b, Laurence Tock a, Trent Harkin c, Andrew Hoadley b, *, François Maréchal a a

Industrial Energy Systems Laboratory, Ecole Polytechnique Fédérale de Lausanne, Station 9, CH-1015 Lausanne, Switzerland Department of Chemical Engineering, Building 35, Clayton Campus, Monash University, Victoria 3800, Australia c Cooperative Research Centre for Greenhouse Gas Technologies, GPO Box 463, Canberra, ACT 2601, Australia b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 16 April 2013 Received in revised form 24 October 2013 Accepted 27 October 2013 Available online 23 November 2013

This study evaluates three different solvent absorption processes for the pre-combustion capture of CO2 for a black coal IGCC (Integrated Gasification Combined Cycle) power-plant, with the aim of determining the best solvent process for pre-combustion capture. The three solvent processes are MDEA (mono diethanolamine), hot potassium carbonate and SelexolÔ. The study involves detailed thermodynamic models of the entrained flow gasifier, synthesis gas processes, CO2 capture process and the gas turbine and steam turbine combined cycle plant. IGCC without capture yielded an efficiency of 45.02%. For the CO2 capture processes at 90% CO2 capture, the power generation efficiencies are almost identical for MDEA and SelexolÔ with 36.39% and 36.42%, respectively. The IGCC with the hot potassium carbonate process yielded the highest efficiency with 37.33%. This improvement is attributed to the higher operating temperature of the absorber which allows water vapor in the synthesis gas to be sent to the gas turbine resulting in a greater power production from the gas turbine. A multi-objective optimization is performed by varying different decision variables in the IGCC with the hot potassium carbonate capture process. By optimizing these variables, an efficiency of 39.31% is obtained e a 2% point improvement for 90% capture. Crown Copyright Ó 2013 Published by Elsevier Ltd. All rights reserved.

Keywords: Hot potassium carbonate Process design Process integration Thermo-modeling Pre-combustion capture Multi-objective optimization

1. Introduction The global electricity demand and greenhouse gas emissions from electricity production continue to increase. According to the IEA (International Energy Agency) Key World Energy Statistic [1], renewable energy is more and more promoted, but fossil fuels still supply at least 80% of the world’s energy demand (heat, electricity,.), coal being an important part with 26.5% of the energy production. In addition, fossil fuels are becoming depleted and thus the world is facing the dual challenge of energy supply security and climate change mitigation. To minimize the impact and reduce the atmospheric CO2 emissions, engineers are now looking for energy efficient solutions to retrofit existing coal power plants by reducing their CO2 emissions. Several concepts such as post-, oxy- and pre-combustion have been investigated to reduce greenhouse gas emissions by capturing the CO2 from the flue gas and sequestrating it. However, Carbon * Corresponding author. Tel.: þ61 3 99053421, þ61 4 18972579 (mobile), fax: þ61 3 99055686. E-mail addresses: [email protected] (J. Urech), laurence.tock@epfl.ch (L. Tock), [email protected] (T. Harkin), [email protected] (A. Hoadley), francois.marechal@epfl.ch (F. Maréchal).

Capture and Storage (CCS) introduces not only a financial penalty from the supplementary installations, but also an energy efficiency penalty in term of electricity production. For this reason, the CCS concepts will only become competitive, if new policies limiting greenhouse gas emissions or taxing CO2 are established. Indeed, a large amount of energy is required to separate the CO2 from the gas and to compress the CO2 for transport and sequestration. For separating the CO2 from the flue gas different technologies have been assessed [2e5]. Mature technologies are mainly based on adsorption and absorption principles. Membrane processes are considered as promising low-energy intensive alternatives, if selectivity, permeability, stability and cost issues can be solved [6e8]. Novel concepts are hydrate formation [9] and electrical desorption [2]. Pre-combustion CO2 capture involves removing the CO2 from synthesis gas before the combustion of this gas in a gas turbine. The process is known as Integrated Gasification Combined Cycle (IGCC) coal power plant and this process can reduce the CO2 emissions. According to the Special report on CO2 capture and storage to the Intergovernmental Panel on Climate Change [10], 90% CO2 capture in an IGCC power plant increases the electricity production cost by about 30% and decreases the efficiency by about 7e12% points.

0360-5442/$ e see front matter Crown Copyright Ó 2013 Published by Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.energy.2013.10.081

J. Urech et al. / Energy 64 (2014) 268e276

Compared to pulverized coal (PC) power plants with postcombustion capture, pre-combustion CO2 capture in IGCC power plants is more promising, because the higher partial pressure of CO2 reduces the CO2 capture penalty [11e13]. Several studies have already investigated CO2 capture options in IGCC coal power plants. Most studies evaluating CO2 capture focus on physical absorption with SelexolÔ solvent for separating the CO2. In the IEA and NETL (National Energy Technology Laboratory) reports (summarized in Ref. [10]), the reported efficiency of an IGCC without CO2 capture is between 43.1% and 47.4% and with CO2 capture between 34.5% and 40.1%. More especially, based on [13] and [14], IGCC with a Shell gasifier operating on bituminous coal yields an efficiency of 46.61% without capture and of 37.11% with SelexolÔ CO2 capture. Due to the fact that physical absorption with Selexol introduces a lower energy penalty in pre-combustion systems compared to chemical absorption with amines [14], MEA (monoethanolamine) or MDEA (mono diethanolamine) processes are much less evaluated in pre-combustion IGCC systems. In Refs. [15] and [16] an efficiency of 38.8% is reported for MDEAeDEA CO2 capture in an IGCC plant without taking into account CO2 compression. Although numerous separate studies are available in the literature, a comparison between the different technologies is difficult to perform. Indeed, the different gasification technologies (dry or slurry feed) that are considered and the simulation assumptions that are made do not give a consistent comparison on a common basis. In some studies, detailed flow sheeting is performed [13,14,17,18] while others are based only on a literature review [10,15]. In most studies the performance is evaluated based on the thermodynamic efficiency [13,15] and/or on the costs [17,18]. The power plant and the CO2 capture unit are often considered as two separate units; the only link being the steam extraction from the steam network. However, there are opportunities for improving the process performance by efficient heat and power integration and optimal heat exchanger network design. Only few rigorous studies have investigated this for power plants with CO2 capture [14,18e 22], while in comparative studies this aspect is rarely included. The purpose of this study is therefore to make a consistent comparison of different CO2 capture techniques applied to Integrated Gasification Combined Cycle (IGCC) coal power plants. By applying a systematic methodology, combining flow sheeting and energy integration in a multi-objective optimization framework, three different CO2 capture technologies are compared based on the same assumptions and constraints for the IGCC plant. The three absorption processes are chemical absorption with MDEA (monodiethanolamine), physical absorption with SelexolÔ, and chemical absorption with hot potassium carbonate (more specifically the UNO Mk1 system developed by the CO2CRC [23]). The systems are optimized with regard to the design and operating conditions, and their optimized results are compared with a conventional IGCC without capture in order to determine the energy penalty of CO2 capture. Through process integration solving the heat cascade by maximizing the heat recovery and optimizing the waste heat for heat and power generation, potential performance improvements are identified. The advantage of the current study is to include systematically process integration to make a consistent comparison between process options on a common basis. 2. Methodology The methodology used in this study combines flow sheeting, energy integration and performance evaluation in a multi-objective optimization framework following the approach described in Ref. [24]. After modeling the IGCC flowsheet, three different CO2 capture systems are simulated on the same IGCC basis. For each unit, thermodynamic models are developed and the technical performances are analyzed.

269

The thermodynamic models compute the system’s efficiency as a function of the decision variables and identify key parameters for process improvement. The thermodynamic model is divided into two parts. The process flowsheet is simulated with the commercial software Aspen PlusÔ [25] which solves for the physical and chemical transformations from the feedstock to the electricity product. The energy-integration model optimizes the heat recovery and the combined fuel, heat and power production by using the heat cascade constraints and then by solving a linear programming model minimizing the operating cost [26]. The process needs are satisfied by different utilities including waste and process gas combustion, a Rankine cycle steam turbine, gas turbine and cogeneration. A multi-objective optimization is conducted for the best of the three solvents in order evaluate the trade-off between competing objectives and identify the optimal process configurations and settings of key process parameters. This methodology has already been successfully applied to study systematically biomass conversion processes producing synthetic natural gas and biofuels based on biomass gasification [24,27] and to evaluate CO2 capture in hydrogen and electricity producing processes using natural gas or biomass as a resource [28]. 3. Flowsheet description The IGCC power-plant can be divided in different process units, being mainly the gasification itself, the gas cleaning and treatment, the gas turbine and the cogeneration unit, as shown in Fig. 1. The coal crushing part and the air separation unit ASU are not modeled. It is assumed that pure O2 is bought. For the gasification a Shell gasifier using steam/O2 as the oxidant is considered in this study. A sour Water Gas Shift (WGS) unit is introduced before the acid gas removal unit capturing the CO2 by absorption processes using MDEA, SelexolÔ or hot potassium carbonate. It is assumed that H2S is captured simultaneously with the CO2, therefore no Claus process for sulfur removal is included. 3.1. Feedstock In this study Coal Illinois#6 is used as feedstock. Table 1 describes the composition of the coal.  Air separation unit It is considered that the O2 is purchased and no on-site air separation is included. The costs are taken from Ref. [29]. A power consumption of 1080 kJ/kg O2 for the production of 99.5% pure oxygen [30] is taken into account in the efficiency calculation.  Gasification For the gasification a Shell slagging entrained flow gasifier fed with dry crushed coal [13,31] is modeled. This kind of gasifier is one of the most commonly installed and has the potential to maximize H2 production which also facilitates pre-combustion CO2 capture. The reactor is based on equilibrium consideration and atomic balances and all reactions are assumed to occur at equilibrium. Based on these calculations, at 30 bar, the gasification temperature of 2273 K is obtained, which is in the range appropriate for either a Shell or Prenflo Gasifier [31,32].  Syngas cooling and cleaning The syngas has first to be quenched to 1173 K by a cool recycle gas before being sent to a convective syngas cooler, because of the

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J. Urech et al. / Energy 64 (2014) 268e276

Water or recycled syngas

coal preparation

Gasification (Entrained flow gasifier)

Syngas Quench Cooling and cleaning

Slag

Steam

Sour WGS COS Hydrolysis

CO2 storage

Acid gas Removal+CO2 removal

O

Combined Cycle Steam - Gas turbine

Air

Power Fig. 1. Block flow diagram of an IGCC power-plant with CO2 capture.

very high temperature at the outlet of the gasification. After being cooled down in the convective cooler, it passes through a cyclone and bag filter unit to remove solid particles and tars.  Sour water gas shift The sour water gas shift reactor occurs before the H2S and CO2 removal section. Therefore the shift reactor and catalyst have to be sulfur tolerant (CoeMo). Furthermore the COS (Carbonyl Sulphide) is directly converted inside the shift reactor. To enhance the conversion of CO, the reaction eq. (1) takes place in two subsequent reactors operating at different temperatures. In the base case process configuration, the first reactor operates at 673 K and the second reactor at 527 K. The pressure of 30 bar abs is the same, as the outlet of the gasifier. The steam to carbon mole ratio is fixed at 2.

CO þ H2 O4H2 þ CO2

DHR ¼ 41ðkJ=molÞ

(1)

 Acid gas removal: H2S þ CO2 capture unit Three different absorption models, i.e. MDEA, SelexolÔ and hot potassium carbonate, are developed for CO2 capture. It is assumed that the CO2 and H2S are removed from the syngas together. If the H2S in the syngas constitutes less than 2e3 mol%, this flow scheme is usually acceptable. But when H2S is present in significant amounts, thermal regeneration is necessary, which induces

supplementary heat demand and increases the cost by adding a second absorber and stripper. After stripping the CO2 from the solvent, it is compressed to 100 bar for CO2 transport and storage. A 4 stage compressor (10/30/60/100 bar) with inter cooling between each stage is considered. For each solvent model, the capture rate is fixed at 90% by imposing this constraint on the solvent flow rate. Solvent losses for all three systems are assumed to be minimized through the use of a water washing stage above the solvent inlet to the absorber. This also protects the gas turbine from any damage that could be caused from entrained solvents in the synthesis gas. 3.1.1. MDEA In the chemical absorption MDEA process, the acid components react with an alkanolamine absorption liquid MDEA via an exothermic, reversible reaction in a gas/liquid contact or neutralizing the acidic compounds to turn the molecules into ions and dissolving them in the gas-scrubbing solution. The acid gas is then stripped from the solvent at low pressure (1e3 bar abs) and/or high temperature in a regenerator (inlet rich solvent temperature 380e 391 K [33]). The major drawback of this process is that a large amount of energy is required for solvent regeneration. In our model, the MDEA process consists of an absorber operating at 30 bar abs between 313 and 337 K, and a stripper operating at 2 bar and 380 K to remove the CO2 from the rich solvent. Both columns are simulated with a rate based model considering the design characteristics of Table 2 and

Table 1 Coal feedstock characteristics [11]. Bituminous Illinois No.6 (wt.%)

As received Dry

Moisture

Carbon

Hydrogen

Nitrogen

Chlorine

Sulfur

Ash

Oxygen

HHV [MJ/kg]

LHV [MJ/kg]

11.12 0.00

63.75 71.71

4.05 5.06

1.25 1.41

0.29 0.33

2.51 2.82

9.70 10.91

6.88 7.75

27.11 30.51

26.15 29.54

J. Urech et al. / Energy 64 (2014) 268e276 Table 2 Absorber and stripper design parameters with 50% wt MDEA in the solvent mixture. Absorber design parameters MDEA 50% wt

Absorber

Stripper

Type of calculation Type of column Number of stages Diameter [m] Height [m] CO2 lean loading [mol CO2/mol amine] Pressure [bar]

Rate-based Packing 14 7.25 14 0.08 30

Equilibrium Packing 10 7.3 10 0.08 2

the thermodynamic model of MDEA from Ref. [25]. This model leads to a stripper heat load between 1.53 and 1.84 GJ/ton CO2. The condensate water is removed from the syngas before being sent to the absorber. The percentage of MDEA (in wt.%) mixed in the solvent mixture has an influence on the capture process. The literature [34] gives a possible operating range between 30 and 50% wt MDEA in the lean solvent. The design parameters of the absorber and the stripper have to be adapted for each case. The main design parameters for the case with 50% wt MDEA in the solvent is described in Table 2. 3.1.2. SelexolÔ SelexolÔ is the commercial name for DEPG, which is a mixture of Dimethyl Ether of Polyethylene Glycol (CH3(C2H4O)nCH3 (n is between 2 and 9)). This solvent is used to physically absorb H2S and CO2. DEPG is non-corrosive, relatively non-toxic, has chemical and thermal stability and requires only carbon steel construction. The quoted operating absorption temperature range 313e253 K covers most of the commercial applications [35]. For warm climate operations, such as Australia, the operating temperature is limited to 313 K without using a refrigeration system. The condensate water is removed from the syngas before being sent to the absorber, which operates at 30 bar abs. A series of 3 flashes (18, 2.0, 0.3 bar abs) remove the CO2 from the rich solvent. Compared to chemical absorption, this has the advantage that no reboiler heat duty is required for solvent regeneration. The main design parameters for the Selexol capture are listed in Table 3. 3.1.3. Hot potassium carbonate The hot potassium carbonate process is a chemical absorption process which can operate at higher absorption temperatures. Compared to amine based solvents, the use of potassium carbonate has some advantages. The reaction with CO2 occurring in the process shows an equilibrium behavior. This equilibrium is favorable to absorption even at elevated temperatures. Therefore the absorber can operate at high temperature and steam is not required to reheat the solution to the stripping temperature. Hot potassium carbonate is less toxic and less prone to degradation effects that are commonly seen with amines at high temperature and in presence of O2 [36]. The investment costs can also be lower than with ordinary amine solvents, because solvent heat exchangers are not required. Table 3 Absorber and stripper design parameters for the selexol capture.

The concentration of potassium carbonate K2CO3 in the aqueous solution is 30% wt. With the potassium carbonate solvent, the absorber can operate over a wide temperature range of 393e493 K at the pressure of the syngas, 30 bar. At these temperatures the water present in the syngas is not condensed before being sent to the absorber. Also the rich solvent does not have to be reheated before entering into the stripper. The rich solvent is flashed to 3 bar before being sent to the stripper and the CO2 removed by flashing reduces the heat duty requirements. The potassium carbonate model is based on experimental results from pilot scale gasification trials at 7 bar, reported by Smith et al. [37]. The main design parameters for carbonate capture are listed in Table 4.  Combined cycle gas turbine The H2-rich gas (with 90% of its CO2 removed) is sent into the gas turbine. The gas turbine exhaust stream is sent to a heat recovery steam generator where superheated steam is produced. This steam is converted into electricity in a steam turbine. The water content of the syngas before the expander is constrained to a maximum of 15 mol%, which is close to the upper limit to accommodate turbine blade material constraints. In the hot carbonate system, the syngas is first cooled down to condense the right amount of water in order to respect this limit. For the other capture systems which are cooled to 313 K, there is already less than 15 mol% water remaining. The syngas is then pre-heated to 773 K before entering the combustion chamber and combustion with an excess of compressed air occurs at 1568 K. The flue gas is sent to an expander having an isentropic efficiency of 90% and is then passed through a heat recovery steam generator with the potential of recovering heat down to 313 K (40  C). In reality, the flue gas exits at around 380 K, depending on the process. The heat excess is recovered and valorized in a Rankine cycle for power production. The thermodynamic model of the cogeneration steam cycle consists of three pressure levels high, medium and low (HP, MP, LP), which could be optimized to get the best efficiency. The HP stage production is imposed at 125 bar. Then the pressure for the MP, LP drawoff stage and the condensation stage are optimized for each case. The main design parameters for each unit are described in Table 5 for the base case scenario. 4. Results from carbon capture cases The competitiveness of the different process options are assessed using the simulation results for with and without CO2 capture cases. The comparison is based on the thermodynamic analysis. The performance is expressed by the overall energy efficiency given by the ratio between the net electricity production (electricity production by the gas and steam turbines, EGT and EST, minus electricity consumed by the process) and the thermal energy

Table 4 Absorber and stripper design parameters for the hot potassium carbonate capture.

DEPG absorber design parameters Type of calculation Type of column Number of stages Absorber diameter [m] Absorber height per stage[m] Pressure [bar] Solvent mass-flow[kg DEPG/kg CO2]

271

Equilibrium Packing 16 7.9 1 30 27.03

Hot potassium carbonate parameters

Absorber

Stripper

Type of calculation Type of column Number of stages Diameter [m] Height [m] CO2 lean loading [mol CO2/mol K2CO3] Pressure [bar]

Rate-based Rate-based 10 5.45 15 0.2 30

Rate-based Rate-based 10 7.91 15 0.2 3

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J. Urech et al. / Energy 64 (2014) 268e276

Table 5 Characteristic parameters for base cases simulations. Design parameters

Value

Coal thermal input [MW] Gasification temperature [K] Gasification pressure [bar] Type of quench cooling WGS: steam/carbon ratio [e] WGS: 1st reactor temperature [K] WGS: 2nd reactor temperature [K] GT: pre-heat syngas temperature [K] GT: pre-heat air before combustion chamber [K] GT: combustion temperature [K] Process: cooling temperature [K] Process: pump efficiency (isentropic) [e] Process: compressor efficiency (isentropic) [e] Process: expander efficiency (isentropic) [e]

1200 2273 30 Recycle quench 2 673 527 773 No pre-heat 1568 313 0.8 0.85 0.9

entering the system in the form of coal (expressed on the lower heating value basis) eq. (2):

3

¼

 ðEGT þ EST Þ  EO2 þ EGasification þ Equench þ EWGS pumps þ ECO2

4.3. IGCC with pre-combustion CO2 capture with SELEXOLÔ For the IGCC process with Selexol CO2 capture, an efficiency of 36.42% is reached for an absorber temperature of 313 K. This

 capture

(2)

_ coal *DH 0 m coal

To assess the CO2 emissions reduction potential, the specific CO2 emissions after the capture unit and the total CO2 emission after the gas turbine per MWh of electricity produced are computed in Table 6. The analyses are based on a plant installation of 1200 MW coal thermal input. The performance results are summarized in Table 6. 4.1. IGCC without CO2 capture Two IGCC cases without CCS are compared. In Case 1 the synthesis gas was shifted to produce a higher H2 content and in Case 2 the synthesis gas bypassed the WGS reactor. Case 1 gave the highest efficiency of 45.0% compared with 44.62% for case 2 (Table 7). This higher efficiency was due to the greater syngas flow rate in Case 1, which led to a greater power output from the gas turbine. Case 1 is subsequently used as the base case for determining the energy penalty associated with the three capture processes. 4.2. IGCC with pre-combustion CO2 capture with MDEA Different cases are simulated with the MDEA solvent by varying the MDEA mass fraction present in the solvent (between 33 and 50% wt). The MDEA case with 50% wt MDEA and with an absorber Table 6 Comparison with literature data for IGCC plants with and without CO2 capture. Cases

operating temperature of 313 K yields the highest efficiency with 36.39%. The efficiency is slightly higher than with 33% wt. MDEA and 40% wt MDEA, because less solvent is required to capture the same amount of CO2 which leads to a lower reboiler heat duty to regenerate the solvent and a lower pumping power. Sensitivity analyses have been performed to study the influence of the temperature of both the solvent and the syngas entering the absorber by varying the temperature between 313 and 338 K. Simulations show that the reboiler heat duty increases with the increasing temperature of the absorber. At higher temperatures the reaction rate is increased, but the solubility of the CO2 in the solvent is decreased. Consequently, more solvent is required and the reboiler heat duty is increased, thus the efficiency is decreased.

IGCC

IGCC

IGCC

IGCC Reference: NETLeIEA report

Coal inlet: 1200 [MWth] No CCS- MDEA Selexol UNO Without WGS CCS CCS CSS capture Efficiency [%] 45.02 CO2 capture comparison e CO2 emission rate after CO2 capture unit [kg CO2/MWhe] 713.7 Total CO2 emission rate (after gas turbine) [kg/MWhe]

With capture

36.39 36.42

37.33 43.1e47.4 34.5e40.1

86.25 86.76

82.57 e

101.9 99.9

98.6

70e142

682e763 e

Table 7 Performance comparison for IGCC plants with and without CO2 capture. Cases

IGCC

IGCC

IGCC

IGCC

IGCC

No CCS- No CCS- MDEA CCS WGS WGS

Selexol CCS UNO CSS

Without Without Solvent:317 capture capture [K] Syngas: 313 [K]

Solvent: 313 [K] Syngas: 313 [K]

CO2 capture rate e [%] Efficiency [%] 45.02 542.15 Net electricity production [MWe] Steam network 188.76 production [MWe] 417.87 Gas turbine production [MWe] Power 64.48 consumption [MWe] CO2 capture comparison CO2 emission rate 713.7 [kg/MWhe] CO2 emission rate e after capture [kg CO2/MWhe] CO2 avoided e [kg CO2/MWhe] Reboiler heat e [GJ/tCO2] Installation characteristics Solvent vol-flow e [m3/sec] Absorber diameter e [m] Absorber stages e [e] Stripper diameter e [m] Stripper stages e

e

90

90

Solvent: 425.1 [K] Syngas: 395.5 [K] 90

44.62 537.33

36.39 438.17

36.42 438.54

37.33 449.56

191.16

172.95

185.08

171.37

410.35

360.59

357.35

374.23

64.18

95.37

103.89

96.04

99.9

98.6

86.76

82.57

720.6 e

e

101.9 86.25

618.6

620.6

622.1

e

1.53

e

2.27

e

0.85

2.48

1.34

e

7.25

7.9

5.45

e e e

14 7.3 10

16 e e

10 7.91 10

J. Urech et al. / Energy 64 (2014) 268e276

273

corresponds to a reduction in efficiency of 8.6 %pts due to carbon capture, which is identical to that obtained by Cormos [13]. If the absorber operates at higher temperatures, the same conclusion could be drawn as for the MDEA case. A column operating at higher temperatures decreases the solubility of the CO2 into the solvent. An increase of the absorption temperature of 11 will reduce the efficiency to 35.83%. 4.4. IGCC with pre-combustion CO2 capture with hot potassium carbonate The absorber temperature can be varied to a much greater degree for the hot potassium carbonate process and because of this; a number of different simulations were performed to determine an operating temperature range for the solvent and the syngas entering into the absorber. The optimization of these temperatures shows that the efficiency increases, if the solvent is slightly hotter than the syngas because less water is absorbed with the solvent. Therefore the mass-flow of the syngas into the gas turbine is higher and the power production increases. The best efficiency of 37.33% occurs when the lean solvent temperature is 425.1 K and the syngas temperature entering the absorber is 395.5 K. 5. Discussion In order to assess the competitiveness of the different scenarios previously described, the performance results are compared in detail and summarized in Table 7. The comparison of the power balance (Table 7, Fig. 2 and Fig. 3) shows that the traditional solvent absorption (MEAeMDEA) operating at low temperature creates thermodynamic inefficiencies and alters the water content in the treated syngas, which leads to a reduction of the power production in the gas turbine. Although, the hot potassium carbonate process requires a higher reboiler heat duty leading to a lower cogeneration potential in the Rankine cycle compared to the MDEA process, the syngas which is sent to the gas turbine has a higher mass flow resulting in more power generated in the gas turbine. Indeed, by operating at a higher absorption temperature, the water present in the syngas is not condensed before the absorber. This is achieved by

Fig. 2. Comparison of the power produced and power consumed in the IGCC powerplant without and with different CO2 capture technologies. In the positive area, the sum of the net electricity production and the power consumption represent the total power produced by the gas turbine and the steam turbine. Details about the power production are represented in the negative area.

Fig. 3. Detail of power consumption in the studied IGCC power-plants without and with different CO2 capture technologies.

adjusting the inlet temperature of the syngas and the hot potassium carbonate solvent, so that water is not absorbed by the solvent but remains in the syngas. Therefore, with a higher syngas mass flow, more power can be produced in the gas turbine. Despite the fact that the physical absorption with SelexolÔ does not require a stripper with a reboiler, the overall IGCC efficiency is only slightly higher than for the IGCC plant with MDEA capture. Indeed the steam network produces more power with the Selexol unit, but the higher solvent volume flow-rate and the flash under vacuum conditions cause a larger penalty in terms of electricity consumption (Fig. 4). Additionally, the syngas has to be cooled down to 313 K before entering the absorber, which limits the syngas mass flow by condensing the water. Finally, the comparison of the energy requirements illustrated by the composite curves in Fig. 4 underline these conclusions. The comparison of the cogeneration potential shows that, the IGCC precombustion CO2 capture process using the hot potassium carbonate leads to the lowest power generation in the Rankine cycle, with 171 MWe compared to 185 MWe for the CO2 capture with Selexol and 173 MWe for the CO2 capture with MDEA. However, in the hot potassium carbonate IGCC process, the gas turbine generates with 374.1 MWe the largest amount of electricity, compared to 357.35 MWe in the Selexol case and 360 MWe in the MDEA case, respectively. As illustrated in Fig. 3, the energy consumption associated with the purchased O2 production gives rise to the main power consumption, and in addition there is the compression needed (O2 and steam) in the gasification unit and for the CO2 compression (100 bar) in the CO2 capture unit. These results show that each CO2 capture process has its advantages and disadvantages in terms of energy penalty. The thermodynamic efficiency and the potential CO2 emissions reduction of the different IGCC pre-combustion processes are comparable. Nevertheless, it seems that the hot potassium carbonate capture process is the most promising, based on the overall efficiency. However, before drawing final conclusions on the competitiveness of the different solvent processes, it is necessary to examine the capital and operating costs of the respective systems. Each absorption system involves different amounts of equipment. The two ambient absorbers require more heat exchange area, but the higher density and lower flow rate of the colder gas may lead to a smaller diameter absorption column. Also the pressure drop across the equipment items has not been taken into account in this comparative study and if there are different pressure drop allowances, this

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Fig. 4. Integrated composite curve with steam network integration (grey curve) for the IGCC with hot potassium carbonate, MDEA and Selexol CO2 capture (at the tail of each curve is a shaded area where the energy cannot be recovered).

may also impact on the sizing of the equipment. Finally, other factors that impact the overall comparison include the rate of degradation of the three solvents, the ability to regenerate them and their availability and purchase price, and all of these factors could impact the relative economic performance of the three processes. Therefore a full economic evaluation should be made, before making the final selection. 6. Multi-Objective optimization of the hot potassium carbonate process In the previous studies a CO2 capture rate of 90% and base case operating conditions have been considered. By changing the operating conditions of the different process units the performance could be improved due to a better process integration. In order to assess this issue, a multi-objective optimization (MOO) is performed for the IGCC system with the hot potassium carbonate CO2 capture. The decision variables are summarized in Table 8. These are mainly intensive variables that characterize thermodynamic performances to be reached by the process operation. The Shell gasifier temperature (2273 K) and pressure (30 bar) are considered as constants. Table 8 presents the decision variables for each unit.

In the multi-objective optimization the objectives are to maximize the overall efficiency eq. (2) and to maximize the overall CO2 capture rate. The Pareto curve is presented in Fig. 5 showing the trade-off between the energy efficiency and the CO2 capture rate. By increasing the CO2 capture rate the efficiency is reduced due to the energy demand for CO2 capture and compression. Compared to the starting point with 90% CO2 capture represented by the red arrow (in the web version) on Fig. 5, the efficiency of the IGCC power-plant with 90% capture rate can be improved from 37.33% to 39.31% through optimization of the operating conditions. A maximum efficiency of 42.66% is reached with 70.01% CO2 capture, while for 97.88% CO2 capture the efficiency is reduced to 38.31%. The CO2 capture rate [70e98%], the absorber temperature (i.e. the solvent and syngas inlet temperature) in the CO2 capture unit and the air pre-heat in the gas turbine unit have the largest influence on the efficiency. The improvement potential with the air preheating is illustrated by Fig. 6. Utilizing the heat from the high temperature available in the process (see the circle heat recovery pocket in Fig. 6), the air sent into the gas turbine could be significantly pre-heated. Therefore a higher air mass flow is used to maintain the temperature of the combustion chamber at 1568 K.

J. Urech et al. / Energy 64 (2014) 268e276

275

Table 8 Original decision variables and MOO-optimized decision variables for the IGCC with hot potassium carbonate CO2 capture for 90% CO2 capture. Value range Moo results Starting point Moo-IGCC IGCC-K2CO K2CO390% (90% capture)3 (90% capture) Decision variables: gasification Steam pre-heat [K] O2 pre-heat [K] Decision variables: WGS Steam-Carbon mole ratio [e] WGS Reactor 1 temperature [K] WGS Reactor 2 temperature [K] Decision variables: absorber Temperature of the syngas IN [K] Temperature of the solvent IN [K] CO2 capture rate [%] Decision variables: Steam network Condensation pressure [bar] LP pressure stage [bar] MP pressure stage [bar] Decision variable: Gas turbine Fuel pre-heat [K] Air pre-heat [K]

527e990 350e990

738.9 687.9

673 673

2e3 623e823 423e623

2.3 726.9 602.1

2 673 527

393e493 393e493 70e98

393.1 455.7 90.27

395.5 425.1 90

0.05e0.8 3e8 31e50 423e990 423e990

0.059 4.94 31.27 648.15 989.9

0.053 4.69 31.35 773 e

Fig. 6. Illustration of the air pre-heat in the gas turbine unit for IGCC power-plant with hot potassium carbonate (UNO MK1) CO2 capture (the shaded grey area illustrates the energy that cannot be recovered).

7. Conclusions This then leads to a higher flue gas mass flow passing through the expander, which in turn produces more electricity. The detailed comparison between the base case process design and the IGCC plant with hot potassium carbonate (UNO MK1) CO2 capture for 90% capture are presented in Table 8. Regarding the performance results, the difference in the power balance for the IGCC process for the “MOO-IGCC UNO” and the starting point “IGCC-UNO” are illustrated in Fig. 7. The syngas composition sent to the gas turbine is optimized by varying the steam to CO ratio in the WGS unit, the WGS reactor temperatures (both reactors), and the absorber temperature in the hot potassium carbonate CO2 capture unit. As has already been discussed, the water management (amount of water) in the syngas, varies significantly with the inlet absorber temperatures (solvent and syngas), and this in turn highly influences the efficiency. The efficiency improvements identified in the MOO optimization need to consider the cost of the operations and equipment in addition to just the efficiency. By introducing an economic objective in the optimization the trade-offs between the environmental advantage and the cost and energy penalty of CO2 capture could be assessed.

Fig. 5. Pareto curve for the overall optimization of the IGCC with hot potassium carbonate (UNO MK1)CO2 capture process. The red point represents the base case (Table 8 starting point). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

A consistent comparison of IGCC coal power-plants with three different pre-combustion CO2 capture technologies such as the chemical absorption with amine MDEA and hot carbonate potassium and the physical absorption with SelexolÔ solvent is made. The goal of the study is to assess the penalty of the pre-combustion CO2 capture systems by making a systematic comparison of the energy efficiency of an IGCC power-plant operating without and with different capture technologies. The CO2 capture unit introduces a penalty in terms of thermal energy due to the heat required to separate the CO2 from the solvent and to compress it for the transport and storage. This study provides a comparison of different CO2 capture systems with the same IGCC basis, and the same simulation hypotheses.

Fig. 7. Comparison of the power produced and power consumed in the IGCC powerplant with the hot potassium carbonate (UNO MK1) CO2 capture for the starting point IGCC-UNO and the MOO-IGCC UNO 90%.

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Different cases are simulated without CO2 capture. The best efficiency of 45% is reached by passing through the WGS unit and by cooling down the syngas before the gas turbine till the maximum water content is reached (15% mole fraction before the expander). Three different units are compared which capture CO2 and H2S together. The highest efficiency of 37.33% with 90% CO2 capture is obtained from the IGCC with hot potassium carbonate CO2 capture, followed by the IGCC with the SelexolÔ CO2 capture with an efficiency of 36.42% and the IGCC with MDEA CO2 capture obtains an efficiency of 36.39%. Despite the fact that the reboiler heat duty is higher with the hot potassium carbonate capture compared to the MDEA cases, the mass-flow of the syngas leaving the absorber and going to the gas turbine is higher, because the water is not condensed and separated before the absorber. Therefore the IGCC with the hot potassium carbonate CO2 capture unit yields the highest efficiency by optimizing the inlet temperature of the syngas (395 K) and the solvent (425 K). Through multi-objective optimization the efficiency of the IGCC with UNO CO2 capture is further increased from 37.33% to 39.31%. The key point of the efficiency improvement is the air pre-heat before the combustion chamber in the gas turbine. The power produced in the gas turbine is increased by recovering the high temperature heat available in the process. The highest efficiency does not necessarily give the most economic cost of electricity or lowest cost of CO2 capture. Therefore this study provides a solid foundation in term of energy efficiency and opens the door to a full economic evaluation and thermoeconomic optimization. Pre-combustion capture decreases the efficiency by between 7.6% and 8.6% points. However, IGCC with the pre-combustion CO2 capture system is promising and constitutes a competitive option for the production of electricity from coal in a more environmentally sustainable manner.

Acknowledgments This work was jointly funded by the EPFL and the CO2CRC. The latter is funded through the Australian governments CRC program, other federal and state programs and the CO2CRC participants.

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