CaO-Based Energy and CO2 Storage System for ... - ACS Publications

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CaO-Based Energy and CO2 Storage System for the Flexibilization of an IGCC Plant with Carbon Capture Annelies Vandersickel,†,⊥ Randall P. Field,§ Weibo Chen,∥ Nick D. Mancini,∥ and Alexander Mitsos*,‡ †

Department of Mechanical Engineering and §MIT Energy Initiative, Massachusetts Institute of Technology, Cambridge, Massachusetts 02139, United States ‡ AVT Process Systems Engineering (SVT), RWTH Aachen University, 52064 Aachen, Germany ∥ Creare Inc., Hanover, New Hampshire 03755, United States ABSTRACT: Integrated gasification combined cycle (IGCC) plants have significant potential for efficient power generation with carbon capture and storage (CCS). The IGCC process with CCS, however, has multiple temperature and flow constraints which severely limit its flexibility to meet the dynamic demands of the current grid. A novel energy and CO2 storage system based on the reversible reaction of CaO with CO2 has therefore recently been proposed, to enable a temporary increase in the IGCC peak power output. This is achieved by (1) providing additional high quality heat for electricity production and (2) providing temporary CO2 storage, thus reducing the parasitic load of the CCS system by reducing the energy requirements for acid gas removal (AGR) and CO2 compression. In contrast to existing concepts, the carbonation−calcination loop herein is operated in a cyclic mode; the CaCO3 produced during carbonation is not regenerated immediately, but stored until off-peak periods during which the CaCO3 is regenerated resulting in a concentrated CO2 stream ready for sequestration. The present article assesses the operating limits and thermodynamic performance of the integrated system. The latter includes a quantification of the cycle and round-trip efficiency, the energy loss factors, and a comparison with other load-shifting solutions proposed in the literature for a given load cycle. The CaO based energy storage system can be effectively used to modulate the IGCC net power output by about ±20−25% with respect to its nominal output, this while capturing 90% of the CO2 emissions. The load cycle considered results in 0.75%-pt (percentage point) efficiency penalty compared to continuous nominal operation, and this is within the literature range reported for other coal plants with CCS. The storage round-trip efficiency is about 60%. The makeup flow required to maintain the particle reactivity was found to be the key factor limiting the round-trip efficiency.

1. INTRODUCTION Integrated gasification combined cycle (IGCC) plants convert solid fuels to gaseous fuels to enable highly efficient power generation via a combined cycle instead of a Rankine cycle, as in convectional solid fuel plants. The gasification of the solid fuel further has significant potential for low air pollutant emissions such as SOx, NOx, and particulate matter by using fuel gas cleanupinstead of flue gas cleanup. Because of the high partial pressures, impurities such as mercury, sulfur, and CO2 can be removed more effectively and economically compared to conventional cleanup of the large volume flow of the combustion flue gas.1,2 Following the National Energy Technology Laboratory (NETL),3 high-pressure oxygen-fed gasification with subsequent water gas shift reactors creates a high CO2 partial pressure of more than 15 bar to facilitate carbon capture. This partial pressure advantage gives IGCC with carbon capture roughly 3 percentage points better efficiency (higher heating value (HHV) based) than a supercritical pulverized coal power plant (PC) with postcombustion capture at CO2 partial pressures of about 0.135 bar.3 The IGCC technology has therefore significant potential for efficient power production even when carbon capture is imposed. The cost of electricity and the capital costs for IGCC with capture are estimated to be similar to the costs for supercritical pulverized coal with carbon capture but with substantial variability based on the choice of gasification technology and other factors. For instance, estimates of the © 2014 American Chemical Society

cost of electricity from IGCC with capture range from 0.5 cent/ kWh less than a supercritical PC with capture to 1.3 cents/kWh more.3 Flexible operation of an IGCC plant, in order to accommodate the intermittent electricity production from renewable energy sources, is however significantly more complicated than PC ramping. The IGCC process is highly integrated and requires a complex control system that is sensitive to process changes, making load changes challenging.4 Apart from multiple temperature constraints within the process, the integration of the air separation unit (ASU) is an important factor limiting the ramp rate and turndown of an IGCC plant.4,5 The refractory in the gasifier is further very sensitive to thermal transients which limit the life span.4 Because of this, several IGCC configurations are being investigated, which would enlarge the IGCC electrical load range while baseloading the gasifier and hence avoiding life-shortening thermal transients. Current strategies for IGCC equipped with carbon capture and storage (CCS) are focusing on temporary storage of the hydrogen resulting from the gasification,5,6 coproduction, and temporary storage of methane,7 methanol,8 or other liquid fuels Received: Revised: Accepted: Published: 12032

April 9, 2014 June 29, 2014 July 10, 2014 July 10, 2014 dx.doi.org/10.1021/ie501475f | Ind. Eng. Chem. Res. 2014, 53, 12032−12043

Industrial & Engineering Chemistry Research

Article

Figure 1. Process scheme of the carbonator (left) and calciner (right).

is given by Dean et al.26 and Nguyen.27 These technologies include combined water gas shift−carbonation reactors, also called “sorption-enhanced water gas shift reactors”,28,29 and in situ CO2 capture performing the gasification, shift, and carbonation reactions in a single reactor (e.g., HyPr-RING30). The concurrent water gas shift (WGS) and CaO carbonation reaction enhances the H2 production by incessantly driving the equilibrium-limited water gas shift reaction forward by removing the carbon dioxide (CO2) product from the gas mixture. Similarly, in sorption-enhanced reforming technologies, CaO is used to shift the equilibrium of the WGS reaction and produce a high purity H2 stream based on hydrocarbon reforming. In contrast to the above concepts, the carbonation and calcination steps herein are separated in time: The CaCO3 produced during carbonation is not regenerated immediately, but is stored until off-peak periods, resulting in a temporary increase in the plant’s power output. During low electricity demand periods, the CaCO3 is regenerated and the formed CaO is stored until the next peak period. Because of its synergy with the CCS system, the CaO-based energy storage system proposed by the authors in ref 31 effectively combines energy storage and temporary CO2 storage for load shifting in an IGCC plant into a single system. Section 2 describes the energy storage system and its integration into the IGCC and details the modeling approach used. The remainder of the article explores the operating limits of the system and presents a detailed thermodynamic assessment of the proposed concept (section 3). The latter includes a quantification of the system’s efficiency, the energy loss factors, and a comparison with other load shifting solutions proposed in the literature. The solutions considered are flexible operation of power cycles with CCS (section 4) and electricity storage technologies (section 5).

produced from excess syngas, O2 production and storage during off-peak demand,9 and a temporary reduction of the energy penalty associated with the carbon capture process. The latter is possible in multiple ways, including suspending CO2 capture either by temporary venting of CO2 gases into the atmosphere or by storing CO2-loaded solvent.9 The current article investigates an alternative approach to temporarily increase the power output of the IGCC plant, while maintaining its 90% CO2-capture rate. The approach is based on the reversible reaction of CaO with the CO2 present in the syngas. The effect of this exothermic reaction is twofold. It temporarily increases the IGCC peak power by (1) directly providing high-quality reaction heat for steam and electricity production (via the exothermic reaction of CaO to CaCO3 taking place at 650 °C) and (2) providing temporary CO2 storage, reducing the parasitic load of the primary CCS system. Reversible chemical reactions using metal oxides, including CaO, have been explored in laboratory-scale experiments for thermal storage at temperatures ranging from 300 to 900 °C.10 The potential of CaO/CaCO3 as an energy carrier for the superregional transport of solar energy from the earth’s sun belt to energy consumption sites in the western world has been explored by Müller et al.11 A continuous calcium-looping cycle is under intensive study for postcombustion CO2 capture using CaO as a CO2 sorbent. With an energy penalty of 6−8%-pt (percentage points)12,13 for coal-fired power plants, this calcium looping may bring efficiency benefits with respect to current energy penalties of 8−10%-pt for postcombustion CO2 capture with amine scrubbing.3,14 In the context of calcium looping, there is now a large body of research papers that have investigated different important aspects of the carbonation/ calcination reaction, including sorbent performance and reaction kinetics at different temperatures and pressures,15,16 CaO reactivity with CO2 and SO2,17 decay in sorbent CO2capture capacity with the carbonation/calcination cycles,18−20 and sorbent improvement methods (for a detailed review, see Blamey et al.12). Several configurations have been studied for the practical implementation of the CaO system based on turbulent and fluidized beds.21 Furthermore, recently initial experimental results from pilot-scale reactors have been reported.21−25 The reversible CaO/CaCO3 reaction also forms the basis for a range of advanced precombustion CO2-capture technologies focusing on improved H2 production from syngas. An overview

2. SYSTEM DESCRIPTION AND MODELING The considered energy storage system and its integration into the IGCC plant have been described in detail in a previous publication,31 and thus only the major points are summarized here. The analysis presented herein is based on the IGCC model32 developed in the commercial software Aspen Plus extended with a flow sheet simulation of the energy storage system as detailed by Vandersickel et al.31 Minor changes to the 12033

dx.doi.org/10.1021/ie501475f | Ind. Eng. Chem. Res. 2014, 53, 12032−12043


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system is to allow an increase in the IGCC power production during peak demand periods without increasing the total amount of CO2 emitted. To achieve this objective, the CO2capture rate in the carbonator has been fixed at 90% and the amount of CaO fed into the carbonator is adjusted accordingly. The latter CaO feed stream and hence the total solid inventory required reduces rapidly as the makeup rate and thus the chemically reactive fraction Xf increase. In addition to reduced solid inventory costs, the reduced solid feed rate also induces lower system costs, as smaller reactors and storage vessels can be used. However, as will be discussed in detail in section 3.4, a high makeup rate leads to increased losses associated with nonrecovered chemical energy in the purge and hence ultimately leads to lower storage round-trip efficiencies. To balance the system cost and energetic performance, a relatively small makeup of 5.13% has been selected herein, resulting in 23.3% CaO conversion in the carbonator. Similar particle conversions have also been reported by Abanades et al.13,23,34 Rodriguez et al.34 for example found that, depending on the coal considered, a chemically reactive fraction between 0.2 and 0.3 is optimal in order to minimize the energy demand in the calciner. The energy for the endothermic reaction and the preheating of the solid particles in the calciner is supplied through syngas oxy-combustion. Cleaned syngas from the IGCC plant has been selected in order to avoid the issues related to the sulfur and ash originating from direct coal combustion observed in Ca-looping studies with direct, coal-fired calciners. The choice for oxycombustion is motivated by the need for a pure CO2 stream at the calciner outlet. The additional O2 required can be supplied by the ASU, which needs to be oversized accordingly. A portion of the hot CO2/H2O stream leaving the calciner can be recycled back to the inlet to facilitate fluidization of the particles and temper the combustion product gas temperature. This CO2 recirculation has not been modeled explicitly because the hot recirculation has little influence on the exhaust stream composition and no influence on the energy requirements of the calciner, while explicit modeling significantly increases computation time. As shown in Figure 1, the hot CO2 stream leaving the calciner is used for preheating of the solid stream entering the calciner as well as for preheating of the syngas before its expansion. The solid gas heat exchanger introduces an additional component and thus cost into the system. Following Martinez at al.,33 however, this heat exchange can be implemented as a simple regenerative bubbling bed and leads to significant savings in the amount of syngas required for calcination. Finally, the thermal energy recovered from cooling of the CO2 and solid purge stream is used for steam and electricity production. 2.2. Integration in the IGCC. The reference IGCC considered in this article is reported by Field et al.32 It includes an oxygen-fed entrained-flow gasifier with a Selexol carbon capture system. It has a net electrical power output of 550 MW and a net efficiency (lower heating value (LHV)) of 33.7%. The relevant technical data of the plant are summarized in Table 1. Further details can be found in papers by Vandersickel et al. and Field et al.31,32 To clarify the integration of the storage system in the IGCC plant with CCS, a simplified scheme of the process with integrated carbonator and calciner is shown in Figure 2. The proposed storage system allows the gasifier, scrubber, and WGS units to operate at full capacity through all modes (normal,

previously published modeling approach are pointed out below. For further details, the reader is referred to Vandersickel et al.31 2.1. Storage System. The CaO/CaCO3 energy storage system relies on the reversible dissociation of CaCO3 to CaO and CO2 to store excess energy (from the combustion of excess syngas) during low demand periods. Upon peak demand, the stored CaO is recombined with the CO2 in the syngas extracted from the IGCC plant. The resulting heat from the exothermic recombination reaction is then used to produce additional steam and thus electricity to meet peak demand. In this recombination process, the storage system also serves to capture CO2 and stores it temporarily as CaCO3. Because of this CO2-capture ability, the carbonator acts as a CO2 scrubber, allowing the existing CCS system to be turned down to further increase the IGCC net power output. The storage consists of two chemical reactors, one for the carbonation and one for the calcination, combined with two storage tanks, one for CaO and one for CaCO3. To ensure sufficient contact between the gaseous and solid reactants, fluidized bed reactors are used. An attractive feature of this design is that the discharge/charge power (megawatts) and the storage capacity (megawatt hours) are uncoupled. This significantly facilitates scaling of the storage capacity from 1 h to multiple days, by simply increasing the solid inventory and sizing the CaO and CaCO3 tanks accordingly. The reactor sizing and designs are independent of the storage capacity. An overview of the storage system layout and operating conditions is given in Figure 1. The carbonation takes place at 650 °C and 32 bar; the calcination takes place at 950 °C and 1 bar. The operating conditions are based on chemical equilibrium considerations, as well as constraints imposed by the integration of the storage within the IGCC plant. As a result, several of the IGCC process gas streams need to be depressurized to the required pressure level in the energy storage system. Turbines are assumed to be installed in order to recuperate this expansion work. Herein, a constant turbine efficiency of 80% has been assumed. To reduce preheating loads, the solid streams leaving the fluidized beds are stored at their respective reactor temperatures. The ambient storage pressure is motivated by the storage vessel cost. Future work, including a technical design of the proposed concept, will be required to establish the optimal technology for the pressurization (lock hopper, dry solid pumps) and transport of the solids (pneumatic or mechanical conveying) and the corresponding energy requirements. The energy requirements for the solid handling are therefore currently not modeled. To compensate for the decaying reactivity of the CaO particles with each carbonation/calcination cycle as well as to deal with attrition, part of the CaO/CaCO3 stream fed into the calciner is purged in each cycle and replaced by a makeup flow of fresh CaCO3. Assuming that the residence time in the reactor is long enough to allow 80% conversion of the chemically reactive particle fraction,33 the fraction of CaO which converts to CaCO3 in the carbonator Xf can be computed as a function of the makeup rate (MR) following13 ⎡ ⎤ fm (1 − fw )MR X f = 0.8⎢ + fw ⎥ ⎢⎣ MR + (1 − MR)(1 − fm ) ⎦⎥

The empirical constants f m and f w depend on the limestone type. The values for the natural limestone measured by Abanades et al.,13 i.e., f m = 0.77 and f w = 0.17, are used here. As discussed in the Introduction, the purpose of the proposed 12034



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Table 1. Key Data of the Reference IGCC Plant32 wet coal feed rate (t/h) (11.12% moisture) gross power generation (MWe) net power generation (MWe) net plant efficiency (% LHV) CO2 capture (%) CO2 emissions (kg/MWh)

before the Selexol unit. The formed CaCO3 is sent to the storage tank, whereas the resulting reaction heat is used for water preheating, steam generation, and thus electricity production. The integration of these heat sources into the IGCC steam cycle requires an additional steam turbine to accommodate the additional steam production. (The maximum load of a steam turbine is typically only 5% above its nominal load.38) As discussed by Vandersickel et al.,31 the thermal-toelectrical-energy conversion of the above heat streams is therefore not explicitly modeled herein, but calculated assuming a conversion efficiency of 40%. As the carbonator is designed to capture 90% of the CO2 in the syngas, the CO2-depleted syngas leaving the carbonator can bypass the existing CCS system (Selexol and CO2-compression units) and be reintroduced into the IGCC plant at the entrance of the gas turbine. This partial bypass allows a turndown of the CCS system from full to part load, resulting in a reduction of the corresponding energy penalty and hence a further increase of the net output of the IGCC power plant. The syngas extracted before the Selexol process still contains sulfur (0.6 vol % H2S), which needs to be removed before combustion in the gas turbine. This can be done in several ways, e.g., high temperature desulfurization with a ZnO-based adsorbent process,39 running the Selexol unit as a sulfur scrubber only, or reaction of H2S with CaO in the carbonator and removal of the formed CaS/CaSO4 via the purge flow rate. The latter solution would eliminate the need for an additional sulfur removal unit. The cocapture of CO2 and H2S at high pressure in the carbonator is however a complex competition process. Also, the oxidation of the formed CaS in the calciner strongly depends on the conditions in the calciner and is

223.9 737.0 549.9 33.7 90.3 93

peak, off-peak) such that these capital-intensive assets and especially the gasifier are fully utilized and do not undergo lifeshortening thermal gradients. Cycling of the integrated plant is hence limited to the storage system, the Selexol and CO2compression units, the ASU, and the power block. In the absence of part-load performance and operation data for the power block, a constant pressure operation has been assumed in the heat recovery steam generator (HRSG) and the efficiency values of the gas and steam turbines are kept constant for all conditions investigated. Due to the integration with the gasifier, the reduction of the steam mass flow through the turbine during calcination is limited to 5−10%, such that a constant steam turbine efficiency is an accurate enough approximation. Within the operating limits discussed in section 3.1, leading to a maximum turndown of the gas turbine of 22%, the efficiency loss due to part-load operation of the gas turbine is limited to about 4−5%.35 Neglect of this efficiency drop is considered acceptable herein, as efficiency losses in the turbines can be compensated by optimization of the cycle parameter not yet considered here.36,37 2.2.1. Carbonation. During peak periods, CaO is fed from the storage tank into the carbonator, where it reacts with the CO2 present in the syngas extracted from the IGCC plant

Figure 2. Integration of carbonator (top) and calciner (bottom) in the base IGCC plant. 12035



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can be diverted, leading to a maximum downturn of the IGCC of 111 megawatts electric (MWe). During carbonation, substantial capacity turndown (>70%) in the Selexol unit can be achieved by adjusting the solvent recirculation rates to maintain the same gas/liquid ratio in the absorber columns.41 Again, the compressor train is the limiting factor. Operating only one of the compressor trains defined above at 100−75% load, the CO2 flow can be reduced by 33− 50% of the nominal value. Correspondingly, between 33 and 50% of the syngas can be diverted from the Selexol unit to the carbonator. For 50% syngas rerouting to the carbonator, this leads to a maximum power increase of 141.8 MWe with respect to the nominal value. The integration of the energy storage system hence allows increasing the IGCC net power output by 25% (141.8 MWe) during peak times, while it can be reduced by 20% (111 MWe) during off-peak times relative to the nominal net power of 550 MWe. Note that, to achieve this extended load range, in addition to the energy storage system a new 120 MWe steam turbine should be installed to handle the steam produced in the carbonator as well as additional ASU and CO2 compression capacity. 3.2. Load Range for Reference Case. For a more detailed analysis of the components contributing to the load variation, a representative case has been defined taking the above load bounds and operating limits of the CO2-compressor train into account. An overview of the operating conditions is given in Table 2. The longer regeneration time allows operating the

kinetically limited by the expansion of CaCO3, CaS, and CaSO4 product layers, a mechanism which requires further investigation. In this work, complete removal of H2S prior to the carbonator is therefore assumed, albeit not modeled as the optimal method remains to be defined. 2.2.2. Calcination. During off-peak periods, the gasifier is operated constantly at base load while the power block is turned down to reduce power generation. The excess syngas produced is diverted from the gas turbine to the calciner, where it is combusted with oxygen to supply the energy for the calcination. The additional power required in the ASU for the production of the additional O2 stream for the oxy-combustion follows from the reference IGCC model. In the calciner fed from the CaO/CaCO3 storage tank, all CaCO3 decomposes into CO2 and CaO. The regenerated CaO is sent to the storage tank and stored at 950 °C, the thermal energy of which will be recuperated during the next carbonation phase. The CO2 stream exiting the calciner is cooled, dried, and reintroduced in the CO2-compression block of the CCS unit. Since the primary CO2-compression train is sized to handle the CO2 captured in the Selexol unit operating in nominal mode, additional CO2-compression capacity will be required to handle the additional CO2 stream from calcination. During calcination, the net output of the IGCC plant thus reduces due to both the turndown of the combined cycle and the increased parasitic load of the ASU and the CO2-compression unit.

3. PERFORMANCE RESULTS 3.1. Maximum Load Range. A key metric to quantifying the performance of the IGCC with integrated storage is the maximum load range achievable through the integration of the storage. The latter can be quantified through the maximum power increase during peak demand (carbonation) versus the maximum downturn in off-peak periods (calcination). In view of renewable electricity integration into the grid, the difference between the peak and off-peak power output can be regarded as the maximum amount of renewable power capacity which can be accommodated by the integrated plant. To assess the maximum achievable load variation, the load restrictions of the combined cycle (calcination) and the Selexol and CO2-compression units (carbonation) must first be identified. For the F-class gas turbine in the reference IGCC, a minimum part-load operation of 36% is reported.40 Crossover issues in the HRSG further limit the syngas extraction to 22% for the specific HRSG configuration in the reference IGCC model. The limiting component however is the CO2compressor unit. To accommodate the additional CO2 stream released from the CaCO3 during calcination while allowing sufficient turndown of the CO2 compressor during carbonation, two CO2-compressor trains need to be installed. To maintain high operating efficiency, a typical CO2-compression system should not reduce its flow rate below approximately 75% of full flow at constant discharge pressure. 9 Assuming both compressor trains run at this minimum capacity of 75% during nominal IGCC operation, a maximum of 33% increase in the CO2 flow rate can be handled during calcination when running both compressor trains at full load. To keep the additional CO2 flow originating from the calciner within this 33% limit, the CaCO3 feed to the calciner should be limited accordingly. The maximum CaCO3 feed in turn defines the maximum syngas flow required for calcination and hence the maximum syngas flow which can be diverted from the gas turbine to the calciner. In this case, a maximum of 19% of the flow to the gas turbine

Table 2. Operating Conditions Reference Case

a

quantity (unit)

value

carbonator temp (°C), press. (bar) calciner temp (°C), press. (bar) CO2-capture rate (%) syngas flow to carbonator (% of flow to GT)a syngas flow to calciner (% of flow to GT) oxygen flow to calciner (% of flow to gasifier) carbonation period (h) calcination period (h) makeup ratio MR (%) particle conversion in carbonator (%)

650 °C, 32 bar 950 °C, 1 bar 90 40 16.7 26.2 4 8 5.1 23.3

GT, gas turbine.

calciner with a solid flow rate only half of the solid flow rate fed into the carbonator. All results presented in the remainder of the paper refer to this reference case. Table 3 details the contribution of the different components of the IGCC and energy storage system to the increase and reduction of the integrated plant’s power output. For this reference case, the inclusion of the carbonator allows an increase in the IGCC net power of 118 MWe, an increase of 21.5% with respect to the nominal IGCC net output. Of this increase, 78% can be attributed to the additional steam production in the carbonator, whereas the remaining 22% results from the reduction of the CO2-capture penalty in both the CO2 and Selexol/Claus units. During calcination, the net output of the integrated IGCC plant reduces by 97 MWe, a reduction of 18% with respect to the nominal output. About 12% of this reduction can be attributed to the increased ASU load, 12% to the increased CO2-compression load, and the remaining 75% to the net reduction in the output of the combined cycle. The latter reduction is due to the combustion 12036



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as the ratio of the additional electricity production during operation in carbonation mode to the electricity penalty during operation in calcination mode. This efficiency needs to be evaluated over a full charge/discharge cycle and is defined as follows. (See Figure 3 for the nomenclature.)

Table 3. Power Generation and Requirements during Nominal IGCC Operation and Changes with Respect to These Nominal Operation Values during Carbonation (τd = 4 h) and Calcination (τc = 8 h) Phasesa nom operation (12 h) power generation (MW) gas turbine sweet gas expander steam turbine power cycle storage (ηst = 0.4) syngas/O2 expanders power consumption (MW) steam cycle ASU Claus CO2 unit Selexol auxiliaries net power production (MW) efficiency (% LHV)

carbonation mode (4 h)

calcination mode (8 h)

power

power

Δpower

power

Δpower

464.3 8.2

464.6 4.9

+0.3 −3.3

387.0 8.2

−77.3 0

264.5 −

271.1 91.8

+6.6 +91.8

229.7 30.1

−34.8 +30.1

−

3.4

+3.4

8.6

+8.6

5.2 117.4 1.1 28.3 16.7 18.5 549.9

4.6 116.6 0.7 17.0 10.0 18.5 668.2

−0.6 −0.8 −0.4 −11.3 −6.7 0 +118.3

4.8 129.6 1.1 40.5 16.7 18.5 452.6

−0.4 +12.2 0 +12.2 0 0 −97.3

33.7

40.9

−

27.7

−

Figure 3. Illustration of reference profile used to define the electric-toelectric round-trip efficiency.

As illustrated in Figure 4, over the entire calcination phase, the energy reduction with respect to nominal IGCC operation is 778 MWh. During carbonation, an additional 473 MWh is produced, resulting in a 61% round-trip efficiency. Note that this round-trip efficiency accounts for both the efficiency of the thermochemical energy storage system itself, and losses and gains through changes in the energy penalties. As will be discussed in detail in section 5, these efficiency values lie within the range reported for existing load-balancing solutions and electrical energy storage systems. A detailed analysis of Figure 4 allows differentiating between penalties shifted from the carbonation to the calcination phase and vice versa and additional losses incurred through the integration of the storage (305 MWh). The exact values of the different contributions can be taken from Table 4. The combustion of a significant fraction of the syngas in the calciner instead of the gas turbine is one of the major contributors to the losses incurred. As indicated by the reduction in the combined cycle output shown in Figure 4, combusting this amount of syngas in the combined cycle would have resulted in 897 MWh electricity. When expanded and combusted in the calciner, however, only 76% of this energy is recovered either immediately during calcination (35%) or stored and recovered during carbonation (41%). 9% leaves the system as heat losses due to the lower efficiency of the steam power cycle vs the combined cycle. The remaining 15% leaves the system with the solid purge. The latter loss can be attributed to the diffusion-limited reaction rate of the carbonation reaction. Due to the fact that only a fraction of the CaO can recombine with CO2 within practical time scales, and this fraction drops with each subsequent calcination/ carbonation cycle, a solid stream of partially carbonated CaO/ CaCO3 particles is continuously purged from the system and replaced by fresh CaCO3. About 77% (mole based) of this purge stream consists of CaO. The chemical reaction energy required for the initial decomposition of this fraction is not recovered but leaves the system via the purge.42 As the carbonator has taken over part of the carbon separation duty of the Selexol unit, the penalty associated with the Selexol unit (both due to auxiliary power requirements and steam extraction) has been avoided. However, during the calcination phase, this penalty reduction is more than offset by the additional ASU penalty related to the additional O2 required for the particle regeneration in the calciner. The increased work of the air compressor in the ASU is partially compensated by a reduction in the power requirements of the

a

The calciner and carbonator operating conditions are given in Table 2.

of 16.6% of the syngas in the calciner instead of in the gas turbine. During calcination, power output is reduced by 97 MWe and energy is stored chemically and thermally as hot CaO. As will be discussed in section 3.4, 61% (round-trip efficiency) of the energy output reduction during calcination can be recuperated as electricity during carbonation. The maximum discharge power of the carbonator is 118 MWe. Taking into account that only 23.3% of the CaO in the carbonator converts to CaCO3, the carbonator requires a total CaO feed rate of 273 kg/s or a solid inventory of 983 tons of CaO/h discharge capacity. With an averaged CaO particle density of 960 kg/m3 and a packing density of 0.7, the corresponding tank volume of the CaO tank is about 1500 m3/h discharge capacity. (The packing density is the volume fraction of solids in a packed bed of particles.) 3.3. Average Cycle Efficiency. To account for the inherent time-variable aspect of operation with energy storage, the cycle efficiency needs to be evaluated over a longer time period, including a full charge/discharge cycle. For this purpose, a reference cycle has been considered consisting of a peak load of 668 MW for 4 h a day, a nominal/medium load of 550 MW for 12 h a day, and an off-peak load of 453 MW for 8 h during the night. The different load levels correspond to the reference case presented in section 3.2, the results of which are presented in Table 3. Using a quasi-steady-state approach, the cycle efficiency η̅LHV averaged over the defined load cycle was found to be 32.9% (LHV), a 0.8% drop with respect to 24 h of operation at nominal conditions. 3.4. Round-Trip Efficiency and Identification of Losses. Another important performance metric is the electric-to-electric round-trip efficiency. The latter is defined 12037



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Figure 4. Net change in the energy production of the integrated IGCC during calcination and carbonation over a full charge/discharge cycle and contributions of the different units to this change.

the fact that all CO2 leaves the calciner at 1 bar, whereas part of it would have been available at 11 bar when separated via the Selexol unit. Finally, small changes in the expansion work from the sweet gas expander and the expander at the inlet of the carbonator, as well as small variations in the pumping requirements of the steam cycle, alleviate about 6 MWh of the losses.

Table 4. Energy Losses and Penalty Reductions over a Full Carbonation/Calcination Cycle increased losses

MWh

net loss due to combustion in calc/carb steam cycle vs IGCC combined cycle 136.7 MWh loss via purge 82.9 MWh loss via difference in efficiency of steam cycle vs combined cycle net loss due to additional ASU work due to the O2 required for calcination 149.5 MWh due to additional air compression work at ASU inlet (26.2% more O2) partly compensated by: −51.9 MWh less N2 compression work (less N2-dilution in gas turbine) −3.0 MWh less O2/N2 need during carbonation net loss due to additional CO2-compression needed, of which 15.2 MWh due to compression of CO2 originating from the calcination of the CaCO3 make-up stream 37.0 MWh due to compression of CO2 from calciner at 1 bar (vs 11 bar from Selexol unit) savings

219.6

4. COMPARISON WITH OTHER LOAD FLEXIBLE OPERATION STRATEGIES In Figure 5, the proposed IGCC with integrated CaO storage is compared with other load flexible operation strategies proposed in the literature with respect to efficiency and specific CO2 emissions. To capture variations in the performance throughout a flexible load operation scheme, both quantities have been evaluated for the same 24 h cycle.43 The evaluation is based on the reference cycle introduced in section 3.3, including a full charge/discharge cycle of the CaO energy storage system: a peak load of 668 MW for 4 h a day, a nominal/medium load of 550 MW for 12 h a day, and an off-peak load of 453 MW for 8 h during the night. To illustrate the flexibility penalty for each technology, the flexible and full-load cases are shown for each technology option. The investigated CaO system aims to increase the plant’s load flexibility without increasing its CO2 emissions. Only power plants which fulfill the same requirement and hence with continuous carbon capture have therefore been considered in the comparison. The selection of test cases for comparison is limited by the lack of part-load data for carbon capture plants as well as a lack of detail on modeling assumptions and coal composition in the open literature. Results for three indicative cases have been compiled, and both the daily averaged cycle efficiency and specific emissions have been computed, using a quasi-steady-state approach which considers the subsequent stationary operating modes (nominal, peak, off-peak) and accounts for the changes in the operating efficiency when a different operating mode is activated. The three cases are: 1. IGCC with Selexol CCS unit and H2 storage:5 The IGCC has a full-load efficiency of 31.4% (LHV) for a 90% CO2capture rate. During off-peak periods excess syngas is sent to a

94.5

52.2

MWh

reduction in power consumption of Selexol & Claus −28.0 increased power production in combined cycle due to reduced steam −27.6 need for Selexol reduced pumping requirements in steam cycle during calcination −5.2 mode net expansion work during carbonation mode −0.3 net total losses MWh net total losses (increased losses + savings)

305.2

N2 compressor, due the reduced need for N2 dilution in the gas turbine. The net penalty to the additional O2 required in the calciner therefore reduces to 94.5 MWh. A comparison of the CO2 penalty during carbonation and calcination reveals that the energy/CO2 storage system not only delays the penalty of the CO2-compression step, but also incurs an additional energy penalty. Of this additional penalty, 29% originates from the additional CO2 resulting from the calcination of the makeup flow. The remaining penalty results from the combined effect of a slightly higher fraction of impurities (N2, O2) in the CO2 stream exiting the calciner and 12038



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Figure 5. Comparison of specific CO2 emissions and daily averaged efficiency for the reference load cycle based on data compiled from Zebian et al.37 (oxy-combustion), Linnenberg et al.45 (supercritical coal with MEA), and IEA5 (H2 storage).

storage tank. The stored syngas is then used during peak periods for additional power production. For this comparison, the gasifier, ASU, and acid gas removal (AGR) are scaled to meet the nominal load of 550 MWe, while the power block is scaled to meet the peak load of 668 MWe. 2. Pressurized oxy-combustion plant:37 The base plant has a full-load efficiency of 34.4% (LHV) for a 94% CO2-capture rate and is dimensioned to meet the peak load of 668 MWe. Medium and off-peak loads are achieved through part-load operation of the plant. The part-load efficiencies have been computed based on work by Zebian et al.37 3. Supercritical pulverized coal plant with monoethanolamine (MEA) scrubbing:14,44 As for the oxy-combustion case, the base plant is dimensioned for a peak load of 668 MW and in partload operation to achieve the medium and off-peak outputs. The plant has a full-load efficiency of 35.5% (LHV) for a 90% CO2-capture rate. To maintain this capture rate, the MEA unit follows the part-load operation of the main plant. Part-load efficiencies are taken from Linnenberg et al.14,44 Within the uncertainty of modeling assumptions, all these alternative technologies achieve comparable efficiencies (in Rieger et al.46 for example the efficiency estimates for IGCC with CCS have been reviewed and were found to range from 31 to 41%). As can be seen from Figure 5, for all cases, the flexible operation schedule causes a 0.7−0.8%-pt drop in efficiency compared to operating 24 h at full load. The IGCC with CaO storage (0.75%-pt) hence achieves a very comparable efficiency drop value compared to all above load flexible technologies. The shown variations in the specific CO2 emissions ECO2 can be traced back to the differences in the CO2-capture rate and daily averaged cycle efficiency values η̅LHV per the following equation:

with dependences on the carbon content and LHV of the coal and the molecular weights of CO2 and carbon (MWCO2 and MWC). The above corroborates that efficiency improvement remains a priority for carbon capture plants, not only for fullload operation but also for part-load operation, as the latter impacts the daily averaged efficiency. For storage solutions (H2 or CaO storage system), additionally an improvement of the storage round-trip efficiency should further be sought as the daily averaged cycle efficiency is linked to the round-trip efficiency ηrt as follows: ηLHV = ηLHV,nom + ̅

(ηrt − 1)(Pn − Pc)τc ṁcoal LHV(24 h)

Recall that this round-trip efficiency includes both the roundtrip efficiency of the storage system itself and its impact on the base plant (e.g., off-design operation, shift in auxiliary demand). Further evaluation metrics such as investment and operation costs, dynamic operational flexibility, and lifetime reduction through thermal cycling should complement the above performance metrics. The latter is not in the scope of this work.

5. COMPARISON WITH LARGE-SCALE ELECTRICITY STORAGE As discussed in section 3.1, the increased load range of the IGCC plant with a nominal capacity of 550 MWe can accommodate additional renewable electricity in the generation mix. For the reference case discussed herein, the increased power capacity of 118 MWe during carbonation combined with the 97 MWe reduction during calcination can accommodate up to 215 MWe of solar based electricity production, for example. The integration of the thermal CaO-storage system hence could reduce the need for another large-scale electricity storage system, such as batteries, compressed air energy storage systems (CAES), pumped hydro storage, and power-to-gas plants. In Figure 6, the potential of the proposed CaO-storage system is compared with the storage capacity and power output potential of several existing electricity storage solutions,

ECO2 = carbon content ·MWCO2/MWC(1 − CO2 capture rate) ηLHV ̅ ·LHV 12039



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low-carbon alternative for long-term energy storage, especially in view of the fact thatdue to the low costs for the storage medium CaCO3the storage cost is estimated to scale with the storage thermal power rather than the storage capacity.

6. DISCUSSION The integration of the proposed CaO-based energy storage system into the IGCC increases the load range of the base IGCC plant from +25 to −20% with respect to the nominal IGCC output of 550 MWe, so enabling load shifting while continuing to capture 90% of the CO2 produced. The main advantage of the solution proposed is that it allows the gasifier to operate at full capacity through all operation modes, such that this capital-intensive unit is fully utilized and does not undergo life-shortening thermal gradients. For the reference cycle considered herein, flexible operation of the IGCC with storage causes a 0.75%-pt efficiency penalty compared to continuous operation. With this value, the proposed storage solution was found to have a comparable efficiency drop compared to the other load flexible plant considered herein. There are however also some challenges and open issues which still need to be addressed. 6.1. Dynamic Operational Flexibility. As mentioned in section 5, the dynamic flexibility of the IGCC with the proposed CaO storage system might be limited compared to electricity storage systems such as CAES or battery storage, primarily due to the inertia of the Selexol and ASU units. With respect to the Selexol unit, dynamic modeling performed by Robinson et al.8 indicates that with an appropriate control structure a 2 h period is required to reach steady state after a 10% step change in the Selexol feed flow. However, already after about 45 min power demand and emission values are within a few percent of their final value. For the ASU unit, Air Liquide has demonstrated that load change rates of at least 5%/ min can be achieved.53 For operating schedules such as the one proposed herein, the buffer time between two mode changes should be sufficient to allow for a controlled transition from one to the other operating mode. If faster transients are required, an indirect fired calciner heated by an external airblown combustion could also be considered. Such a calciner would eliminate the need for additional O2 during calcination and hence cycling of the ASU. As the same limitations also apply for oxy-combustion (ASU inertia) and postcombustion MEA-based CO2 capture (scrubber inertia), the flexibility of the proposed solution is estimated to be comparable with the latter plants. Further dynamic simulations should be conducted to compare the ramp rates of the different load flexible solutions proposed. 6.2. Purity of CO2 Stream at the Exit of the Calciner. Due to the impurities in the O2 stream fed into the calciner and the high N2 and Ar contents of the syngas resulting both from the oxygen fed into the gasifier and a small N2-purge stream added in the Selexol process considered herein, the concentration of N2 and Ar in the final dried CO2 stream might be unacceptably high. As a certain degree of excess O2 is further required to ensure complete combustion of the syngas, also the O2 concentrations in the final CO2 stream could be too high. Depending on the desired purity specification for the CO2 stream at the exit of the calciner, further processing of the CO2 stream might therefore be required. CO2 purity is an issue any oxy-combustion system is faced with. For such highly concentrated CO2 streams, the energy penalty and capital costs to have a cryogenic separation (down to −55 °C) are

Figure 6. Power output and energy storage capacity potential for largescale energy storage systems; adapted from Fraunhofer ISE47 based on data compiled from Ibrahim et al. and Specht et al.48,49

whereas Figure 7 compares their respective electric-to-electric round-trip efficiencies.

Figure 7. Electric-to-electric round-trip efficiency of existing storage technologies; information compiled from Ibrahim et al., Dunn et al., Buttler et al., ADELE, and Begluk et al.7,48,50−52

Figures 6 and 7 demonstrate that the investigated CaO system could provide a viable alternative to CAES and hydropower storage systems in terms of both size and efficiency. The power-to-gas technology is expected to allow for even higher storage capacities at very high energy densities (10−33 vs 0.06−0.200 kWh/kg for batteries47,48). Electrolysis units are however prohibitively expensive and the life expectancy is very limited.48 Furthermore, the overall efficiency of the process is limited to 35−40%,7 substantially lower than the 54−70% computed for the storage system presented herein (depending on the makeup flow ratio selected). Batteries on the other hand provide highly efficient electricity storage, and several of the proposed battery systems have reached a high maturity level. Their main inconvenience is their low cycle lifetime (approximately 1000 cycles) coupled with high cost. Furthermore, as shown in Figure 6, they are less suited for large-scale energy storage as required to enable a significant increase of renewable electricity production in the grid. Note that, in contrast to the technologies discussed here, the CaOstorage system is coupled to a fossil fueled power plant and cannot store external electricity produced, e.g., by wind or solar farms. The system hence does not support 100% renewable electricity production. The ramp rate of the proposed IGCC with integrated CaO storage further remains to be defined and might be limited compared to the other storage solution shown in Figure 6, primarily due to the inertia of the Selexol and ASU units. However, in view of its high power and storage capacity rating and the correspondingly large modulation of the IGCC plant output, the proposed system could present a promising 12040



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The operating pressure of both calciner and carbonator have been chosen based on pressure constraints of the IGCC, limitations of the chemical equilibrium, and practical considerations such as the simplicity associated with operation and storage at atmospheric conditions. The operating temperatures have been chosen according to suggestions for CaOlooping systems applied for carbon capture. Further optimization of the above parameters specifically for the energy storage application presented in the current work could hence allow for further improvement in the system’s efficiency.

however reasonable and acceptable to separate the light gases and reduce the N2, Ar, and O2 to meet the sequestration specifications. Alternatively, in the present CaO-based storage system, an indirectly fired calciner could be considered, in which no direct contact exists between the syngas combustion gases and the calciner streams. As an indirectly fired calciner also avoids cycling of the ASU unit, this option has been further investigated in ref 54. 6.3. Sulfur Removal. The possibility to simultaneously capture both CO2 and H2S in the carbonator could eliminate an additional sulfur unit. The cocapture of CO2 and H2S as well as the subsequent oxidation of the formed CaCO3/CaS mixture in the calciner is however a complex process which requires further investigation. The impact of the latter reactions on the required purge rate as well as the required operating conditions in the calciner to avoid release of SO2 or H2S in the CO2 stream therefore remains to be defined. 6.4. Round-Trip Efficiency. Finally, as pointed out in section 3.4, improvement of the storage round-trip efficiency should be strived for in order to minimize the efficiency penalty for flexible operation. A key factor which limits the round-trip efficiency of the proposed CaO-storage system is the decreasing reactivity of the CaO particles which requires a relatively high purge rate resulting in a substantial amount of chemical energy leaving the system. Several approaches are currently being studied to maintain the reactivity of the particle, allowing higher particle conversion in the carbonator and hence alleviate the above energy penalty. Among the proposed strategies33,55 are the use of doped limestone,56 sorbent reactivation through steam injection,57 and synthetic CaCO3.58,59 Alternatively, a substantial reduction of the makeup rate to values below 1% could be considered, using only the residual capture capacity of the CaO particles.20 Although this would lead to very large reactors and storage vessels, a low makeup flow rate has the potential not only to improve the system’s efficiency (reduced losses via purge and less additional CO2 production) but also to reduce the operating cost associated with the makeup, which for a lime price of $50/ton of CaCO3 can amount to $18,000 per charge/discharge cycle (4 h/8 h) or $23/MWh. Future work expanding the model to include such approaches would help to establish the optimum method to reduce the energy penalty associated with the purge stream and hence further improve the round-trip efficiency for this application. Another option to reduce the penalty and cost associated with the purge is selling the purged solids for use in cement manufacturing. Due to the fact that calcination of CaCO3 is responsible for about 50% of the CO2 emissions from cement manufacture, use of the purge stream in the cement industry would markedly reduce the industry’s CO2 emissions and the energy requirements for the calcination process.12 An additional factor that limits the efficiency of the energy storage system, irrespective of the makeup flow used, is the need for O2 to combust the syngas in the calciner. To avoid the associated energy penalty of the ASU, alternative options to provide the necessary heat for calcination should be considered. Calciner designs with indirect heat transfer allow combustion of the syngas with air to provide regeneration heat.60 Another option could be heat extraction directly from the gasifier or radiant quench cooler using a high-temperature heat exchanger and working fluid as explored by Botros.61 As the latter solution would not impact the amount of syngas produced, this solution only affects the performance of the steam cycle, not the gas turbine, and might therefore result in higher efficiencies.

7. CONCLUSIONS In this article, a utility-scale energy storage system based on the reversible reaction of CaO with CO2 has been proposed for increased load flexibility of an IGCC plant. Based on Aspen Plus simulations of the storage system integrated in IGCC, the system’s performance has been analyzed in detail. Major sources of inefficiencies have been identified, and further improvement areas have been suggested. It was found that the CaO-based energy storage system can be effectively used to modulate the IGCC net power output from +25 to −20% with respect to the nominal IGCC of 550 MWe, while capturing 90% of the CO2 produced. The thermal cycling required for flexible operation has been successfully limited to part of the IGCC plant. The flexibility burden has been shifted from the gasifier (1370 °C, 56 bar) to the calciner (950 °C, 1 bar) and carbonator (650 °C, 32 bar) operating at substantially lower pressure and temperature and hence subjected to lower stresses. For the conditions investigated in this work, the system’s round-trip efficiency is 61%. A key factor influencing the latter is the amount of makeup flow to maintain the particle reactivity as well as the O2 production required for the particle regeneration. Finally, the integration of the CaO-based energy storage system was found to result in cycle efficiency drops comparable with other load-balancing solutions. In terms of storage size and power as well as round-trip efficiency, the CaO storage further presents a valuable alternative to large-scale electricity storage systems such as CAES, although no external electricity can be stored. Dynamic and financial metrics will also need to be considered to further evaluate and compare strategies to accommodate the intermittent power generation from renewable sources.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Present Address ⊥

A.V.: Institute for Energy Systems, Technische Universität München, D-80333 München, Germany.

Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This material is based upon work supported by the Department of Energy under Award No. DE-SC0008425. The views and opinions expressed in this article do not necessarily state or reflect those of the U.S. Government or any agency thereof. The authors also thank Aspen Technology Inc. for providing access to Aspen Plus software utilized for this research. 12041



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