How-to, Tips and Articles: A Consistent Comparison of IGCC Coal Power-plants With Three Different Pre-combustion CO2 Capture Technologies

Abstract

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 Selexol™. 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 Selexol™ 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 - a 2% point improvement for 90% capture.

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 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 7-12% points.

Compared to pulverized coal (PC) power plants with post- combustion 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 Selexol™ 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 Selexol™ 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 MDEA-DEA 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 Selexol™, 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 betweenprocess 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.

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 Plus™ [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, Selexol™ or hot potassium carbonate. It is assumed that H2S is captured simultaneously with the CO2, therefore no Claus process for sulfur removal is included.

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

3.1. Feedstock

In this study Coal Illinois#6 is used as feedstock. Table 1 describes the composition of the coal.

1. 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.

2. 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].

3. 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 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.

4. 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 (Co-Mo). 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.

5. Acid gas removal: H2S þ CO2 capture unit

Three different absorption models, i.e. MDEA, Selexol™ 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 2-3 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 (1-3 bar abs) and/or high temperature in a regenerator (inlet rich solvent temperature 380 - 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 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.

Table 1 Coal feedstock characteristics [11].

Table 2 Absorber and stripper design parameters with 50% wt MDEA in the solvent mixture.

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. Selexol™

Selexol™ 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 313-253 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.

Table 3 Absorber and stripper design parameters for the selexol capture

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.

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 393-493 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.

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

6. 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.

Table 5 Characteristic parameters for base cases simulations.

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

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.

Table 6 Comparison with literature data for IGCC plants with and without CO2 capture.

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.

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

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 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.

4.3. IGCC with pre-combustion CO2 capture with SELEXOL

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

Fig. 2. Comparison of the power produced and power consumed in the IGCC power- plant 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.

Despite the fact that the physical absorption with Selexol™ 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 pre- combustion 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 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.

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).

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.

Table 8 Original decision variables and MOO-optimized decision variables for the IGCC with hot potassium carbonate CO2 capture for 90% CO2 capture.

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.)

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

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 Selexol™ 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 power- plant with the hot potassium carbonate (UNO MK1) CO2 capture for the starting point IGCC-UNO and the MOO-IGCC UNO 90%.

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 Selexol™ 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 thermo- economic 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.

Source: 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
b Department of Chemical Engineering, Clayton Campus, Monash University
c Cooperative Research Centre for Greenhouse Gas Technologies, Canberra

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A Consistent Comparison of IGCC Coal Power-plants With Three Different Pre-combustion CO2 Capture Technologies