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ScienceDirect Energy Procedia 114 (2017) 7638 – 7650

13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Economic Implications of CO2 Capture from the Existing as well as Proposed Coal-fired Power Plants in India under Various Policy Scenarios Udayan Singha, Anand B. Raob,*, Munish K. Chandelc a Department of Mechanical Engineering, National Institute of Technology Rourkela, Rourkela 769008, INDIA Centre for Technology Alternatives for Rural Areas & IDP in Climate Studies, Indian Institute of Technology Bombay, Mumbai 400076, INDIA c Centre for Environmental Science and Engineering (CESE), Indian Institute of Technology Bombay, Mumbai 400076, INDIA

b

Abstract India is a country with rising energy needs. Much of the energy demand is met by coal and there are dynamic links between coal consumption and economic growth. However, the increasing coal use is likely to result in increasing carbon dioxide emissions. India’s power sector contributes to about half of the all-India CO2 emissions. As a result, end-of-the-pipe abatement of CO2 in the power sector may be one of the prominent mechanisms to reduce India’s greenhouse gas (GHG) emissions. Carbon capture and storage (CCS) technology may provide such a means in the Indian coal-fired power plants. This paper initially makes an effort to assess the economic implications of this technology on existing Indian coal-fired power plants. Some characteristic features of Indian power plants are identified with special reference towards CCS deployment. The importance of proximity of coal linkage and sink location from the power plant is established using the studied examples. General trends on the estimates of cost of electricity (COE), emission factor and net plant efficiency are evaluated. Subsequently, the trends in costs are projected for the next three decades for the upcoming plants using CCS. In these predictions, three scenarios of CCS deployment are considered, with varying carbon price range. In a high carbon price scenario (C price of US$ 80/t-CO2 in 2030), CCS is firmly established as a useful technology for the Indian coal-fired power plants by the year 2050. 2017The TheAuthors. Authors. Published by Elsevier © 2017 © Published by Elsevier Ltd. Ltd. This is an open access article under the CC BY-NC-ND license Peer-review under responsibility of the organizing committee of GHGT-13. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: Indian coal-fired power plants; CO2 carbon and storage; clean coal technology; carbon mitigation

* Corresponding author. Tel.: +91-22-2576-7877; fax: +91-22-2576-7870. E-mail address: [email protected]

1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1896

Udayan Singh et al. / Energy Procedia 114 (2017) 7638 – 7650

1. Introduction India is a major developing economy with a Gross Domestic Product (GDP) of more than US$ 2 trillion. Although, the per-capita CO2 emissions of India are quite low (1.66 tonnes, compared to the world average of 4.94 tonnes), it contributes to almost 6% of the global CO2 emissions and is the third largest CO2 emitter after China and the USA [1]. Furthermore, the Maplecroft Climate Change vulnerability index 2015 ranked India as the 13th most vulnerable country with regards to climate change impacts [2]. The above facts necessitate effective climate policy on part of India. More than 50% of India’s CO 2 emissions within the organized sectors (industry and transport sectors) come from thermal power generation [3], which are large point sources (LPSs) that can be considered for CO 2 capture. Considering India’s increasing energy requirements, continued reliance on coal and the high CO 2 emission factor from coal-fired power plants, they will be the obvious targets for achieving the potential CO 2 emission abatement. There may be several mechanisms to ensure higher energy consumption without an increase in GHG emissions, which include improvement in energy efficiency, and use of low-carbon substitutes to the conventional fossil fuels. However, no single technology is likely to play a principal role in mitigation of GHG emissions [4]. Thus, it is important to analyze every aspect of each mitigating technology. Carbon Capture and Storage (CCS) is an important technology, which is believed to have a significant potential compared to other sizeable carbon mitigation options at a reasonable cost. Carbon Capture and Storage involves CO 2 capture from large point sources. As a result, it allows an easy way to properly manage CO 2 reductions. Furthermore, as coal happens to be India’s main source of energy, CCS will be a form of energy security for India [5]. Estimating the economic penalty of CCS would help in policy-framing in regards to the share this technology could have in climate mitigation. CCS is expected to result in large increase in cost of electricity (COE). This will go against the large-scale electrification efforts – especially designed and implemented to improve the access, availability, quality and affordability – targeting the rural households. Currently, there is a lack of accurate costs of CCS as a mitigation option with reference to India [6]. Several macro-modeling studies have used generalized international costs. However, Indian plants are quite different from their western counterparts as they are often characterized by much lower efficiency, capital costs and varying fuel quality [7, 8]. With ambitious electrification and climate targets, the Government of India has committed to increase the installed solar and wind capacity up to 160 GW by 2022, as a part of the INDCs submitted as per the Paris Climate Agreement. Nevertheless, coal-fired power plants are expected to remain key to India’s energy security at least upto 2050 [5, 9]. Therefore, for mitigation to meet the 2⁰C targets1, either CO2 capture and storage (CCS) or a strong reliance on renewable and nuclear energy will be needed. Shukla et al [10] have suggested that if conventional carbon mitigation strategies such as imposition of carbon taxes are utilized, CCS will have a higher role in mitigation. In such a scenario, they predict that the national CO2 intensity of energy supply would drop tenfold from the current 771 g-CO2/kWh to 66 g-CO2/kWh by 2050. This establishes a strong inter-linkage of CCS, India’s all India emissions and the power sector, and therefore necessitates the study of CCS in the Indian power sector. 1.1. Objectives and scope of this paper In this paper, an attempt has been made to simulate the typical units of Indian coal-fired power plants (existing and upcoming) so as to estimate the economic implications of implementing CO2 capture in such plants. The analysis has been carried out under a variety of scenarios characterized by the choice of the capture technology, availability of CO2 storage site, and the level of policy push. Initially, the effect of implementing CCS in existing power plants has been analyzed. Subsequently, for upcoming plants, one super-critical unit of 660 MW net capacity has been simulated, as a representative of the planned fleet of super-critical units in capacities of 660 MW or 800 MW. The simulations have been performed using the Integrated Environmental Control Model (IECM) developed by the Carnegie Mellon University, USA. A range of estimates have been obtained for each of these units based on the capture technology (amine, ammonia

1

For meeting the 1.5⁰C targets, bioenergy with carbon capture and storage (BECCS), may have to be deployed

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Udayan Singh et al. / Energy Procedia 114 (2017) 7638 – 7650

or membrane based), assumptions about the storage option and the assumptions about the financial parameters influenced by the policy scenario. Before proceeding to the main content of this paper, it would be useful for the reader to go through some definitions given in the nomenclature section to avoid any ambiguity or misunderstanding while interpreting the results of this paper. In this paper, two parameters of CCS cost estimation have been dealt with, viz, increase in LCOE and the cost of CO2 avoidance. The reader may refer to Rubin [11] for an explanation of such cost parameters. 2. CO2 capture and storage perspectives from India A number of studies have been performed with regards to CCS in India. They include studies ranging from capture to storage perspectives, and covering technological and financial challenges. 2.1. Overall Positioning of CCS in the energy system First of all, it is necessary to understand the role CCS could play in India’s power and industrial sectors. This may be projected in terms of emissions mitigated using CCS or the installed capacity of the plants with CO 2 capture. Alternatively, studies have also estimated using different scenarios, the comparison of CCS with renewable energy deployment. WICEE [12] completed a large system study for CCS in India and this is one of the most exhaustive studies on the subject so far. This study covered almost all aspects of CCS in India, but with regards to feasibility vis-à-vis renewable energy, the following can be noted: x x

The life-cycle GHG emissions of CCS based power plants are 12-20 times more than solar thermal power plants and 4-7 times more than solar PV plants. Renewable power will fare competitively against CCS post-2025 in terms of the cost of electricity.

Garg et al [13] investigated the penetration of CCS in India’s power sector in various policy scenarios using six integrated assessment models (IAMs). They have pointed out a higher degree of CCS deployment in coal and natural gas based power plants with strong policy incentives and more stringent targets for atmospheric stabilization of CO 2. Of course, different models show significant variations in the same scenario, thus necessitating construction of better modeling techniques for such applications. 2.2. Performance analysis of CO2 capture in Indian power plants CO2 capture in power plants leads to significant impacts on their performance. This may be manifested by the derating of the gross/net size of the plant due to the large energy penalty, decrease in the net plant efficiency increase in the consumption of coal, water and other reagents per unit of electricity delivered or the change in the emission rate of various air pollutants Table 1 enlists the studies estimating the energy penalty of CCS in Indian power plants Table 1. Impacts of CO2 capture on the performance of the coal-fired power plants in India Reference and type of capture technique Type of boiler Value Suresh et al [14] – Supercritical and ultra-supercritical 29.79%-31.67% double reheat system Retrofitting Oxyfuel Combustion Karmakar and Kolar [15] – Monethanolamine Subcritical 31-40% (MEA) capture Karmakar et al [16] Subcritical, supercritical and ultra- 29-43% supercritical boilers Singh and Rao [17] – Amine, Ammonia, Subcritical and supercritical boilers 39-53% Membrane, Oxyfuel; use of auxiliary gas boiler

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2.3. Performance analysis of CO2 capture in Indian power plants Table 2 shows some of the recent cost estimates for CO 2 capture and storage in the Indian power sector. Study Viebahn et al [18] TERI [19] Rao and Kumar [20] Garg & Shukla [5] Mott Macdonald [21]

Yadav et al [22]

Table 2: Recent estimates of cost penalties due to CCS in coal power plants in India Parameter Value Remarks Increase in LCOE 45-51% Integrated study of the Indian power sector covering all aspects of CCS implementation 47% Studies covering UMPPs only 63-75% Deterministic case studies of four existing power plants Cost of CO2 avoidance US$ 50-60/t-CO2 Estimates based on expert elicitations US$ 35-42/t-CO2 Study covering Ultra Mega Power Plants (for inland sites) (UMPPs) only US$ 36-42/t-CO2 (for coastal sites) US$ 42.3-81.9/t-CO2 Deterministic case studies of several existing power plants considering four capture technologies

However, there is a need for a detailed study for estimating the CCS costs in India in the light of the recent discussions over calculating CCS costs using a common methodology and involving standard cost metrics [11]. Also, the decrease in gross size due to sorbent regeneration requirements and O&M costs of individual plants were not considered by prior studies with regard to India. Thus, in this paper, we have carried out a simulation study for estimation of the CO2 capture costs for new plants and on old plants using retrofitting of CO2 capture equipment. 3. CCS costs for existing plants The first area this paper looks into is the cost implications that arise when existing plants are retrofitted with CO 2 capture facilities. This comprises of simulating few existing power plants and then studying the effects of implementing CCS in such plants. 3.1. Methodology 3.1.1. Selection of units In this study, an attempt is made to capture the entire diversity of the Indian power plants. So, plants with wide variation of parameters such as plant load factor (PLF), coal quality and price, age and efficiency are studied. Some of the units are infeasible for CCS deployment, either because of age (25-30 years since commissioning) or poor performance in terms of load factor or efficiency. This again will lead to high cost requirement for deployment of CCS and therefore such units are not considered for our study. Next, seven representative units (wherein the prospects of CCS may be gauged), have been considered and their relevant data is summarized in Table 3. 3.1.2. Simulation Procedure The Integrated Environmental Control Model (IECM-cs v9.2.1) software has been used to perform this study. This software, which has been developed at the Carnegie Mellon University, USA, provides a graphical user interface and allows the user to change performance and economic inputs and displays multiple results based on the same. The reference plants (i.e. without CCS) have been simulated at first in the IECM-cs framework using the data inputs listed in Table 3. Other relevant parameters (Table 4) have been taken from Singh and Rao [23], who performed a similar study for SO2/NOx control systems.

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Table 3: Data considered for simulating existing coal-fired power plants in India Capital Cost O&M Cost Coal Cost HHV Unit Owner Year Size (MW) BE (%)c Coal Linkagea, # (M$)a $/MWhb ($/t)b (kJ/kg)b

Plant Vindhyachal

VIII NTPC

2000 500

501.44*

87.77 4.6

Vindhyachal

Nigahi Mines

24.61

13673

91.1

85.59

Talcher CF – MCL

15.86

16360

81.6

4.25

87.12

Amlori/Dudhichua/A 23.85 mloric Expansion

14355

92.4

442.46

5.66

82.73

Rajmahal

30.54

10966

71.7

2007 500

564.46

4.32

84.91

Dipika Mines SECL 31.04

15401

96.5

2011 500

399.38

3.75

84.5

Kalinga – TCF

13685

96.1

NTPC

2007 500

501.44

Talcher Kaniha IV

NTPC

2004 500

428.9

4.65

Rihand

IV

NTPC

2005 500

438.61

Kahalgaon

V

NTPC

2007 500

Sipat

IV

NTPC

Simhadri

III

NTPC

a

b

c

* #

X

PLF (%)b

85.14

39.78

Capital cost and coal linkage have been obtained from NTPC website (www.ntpc.co.in/) for all plants. Costs have been normalized to constant 2011 US Dollars. O&M Costs,coal costs, coal higher heating value (HHV) and plant load factor (PLF) have been obtained from CERC website (http://www.cercind.gov.in/NTPC.html) for all plants. Details for boiler efficiency for all plants have been obtained from CEA [24]. Capital cost of unit VIII has been assumed as same as the unit X because separate capital cost estimate is not available and also because we assume that after 15 years the base plant capital costs are amortized fully. Coal composition for all the units has been taken from Mittal et al [25] for all units except for Talcher, for which it is derived from Chandra and Chandra [8]. Table 4: Some financial parameters assumed in this study [23] Parameter Unit Nominal Value years 30 Economic Lifetime %/year 11.42 Fixed charge factor %PFC 11.67 Project contingency %PFC 0.3 Process contingency %/year 6.62 Fuel cost escalation rate Raw materials cost Activated Carbon Cost $/tonne 1,215 Alum Cost $/tonne 500.7 Ammonia Cost $/tonne 376.7 Caustic (NaOH) Cost $/tonne 424.6 Dibasic Acid Cost $/tonne 1094 Flocculant Polymer Cost $/tonne 2977 Lime Cost $/tonne 144.6 Limestone Cost $/tonne 55.10 MEA/Amines Cost $/tonne 1,580 SCR Catalyst Cost $/cu m 6,102 Urea Cost $/tonne 455.7

The next step in the process is to model the CO2 capture process. For this, we need to make three crucial assumptions different from our baseline case: x x

A part of the capital cost of the boiler has been already amortized. This will depend upon the number of years the plant has already been operated before being retrofitted with a CO2 capture unit. There will be a retrofit factor i.e. an additional capital cost will have to be added to the estimate because of limited space that the total fuel input needs to remain the same. Since, CCS results in a high energy penalty; the net output reduces substantially. For the present study, we have assumed a retrofit factor of 1.1, considering an optimistic scenario [26].

Udayan Singh et al. / Energy Procedia 114 (2017) 7638 – 7650

x

Solvent based capture processes (amine and ammonia-based) lead to an increase in the steam cycle heat rate. The resultant reduction in the gross size of the plant needs to be assumed. The resulting gross size is characterized by: ‫ܩ‬஼஼ௌ ൌ ‫ܩ‬௥௘௙ ൈ

ܴ௥௘௙ ܴ஼஼ௌ

where, GCCS = Gross size of plant with capture Gref = Gross size of base plant RCCS = Steam cycle heat rate of plant with capture Rref = Steam cycle heat rate of base plant Other assumptions used for simulating the CO2 capture unit are same as IECM defaults and assumed in [17] and are listed in Table 5. For sink selection, suitable storage sites close to the individual plants are assumed. Table 5: Configuration of the CO2 Capture Unit. Amine Ammonia Membrane CO2 Removal Efficiency (%) 90 Particulate Removal Efficiency (%) 50.00 100.0 100.0 Amount of CO2 captured (tonne/hr) 450-500 Maximum Train CO2 Capacity (tonne/hr) 208.7 907.2 Number of Operating Absorbers 4 1 Max CO2 Compressor Capacity (tonne/hr) 299.4 299.4 No. of Operating CO2 Compressors 3 3 Sorbent Concentration (wt%) 30 14.40 Regenerator Heat Requirement (kJ/kg-CO2) 3,747 2,363 CO2 Product Pressure (MPa) 10 Minimum Pressure at storage site (MPa) 8 Transport Mode Pipeline Geologic Storage Reservoir Saline Aquifer/Coal Seams (as per location)

3.2. Results 3.2.1. Analysis of capture type suitable at Talcher Kaniha plant It is found that the unit of Talcher Kaniha power station of the NTPC is one of the most suitable units. The plant is assumed to have coal linkage from Talcher coalfield, whose ultimate analysis has been taken from Chandra and Chandra [8]. Table 6: Result of simulations on the cost and performance of Talcher Kaniha plant Without CCS Gross Size (MW) 545.9 Net Capacity (MW) 500 Coal consumption (kg/kWh) 0.64 Coal consumption (t/hour) 320.4 Net Plant Efficiency (%) 34.34 Net Plant Heat rate (kJ/kWh) 10,480 CO2 emission rate (kg/kWh) 0.95 Cost of Electricity ($/MWh) 37.96 With CCS Amine Ammonia Membrane Gross Size (MW) 433.5 467.2 545.9 Net Capacity (MW) 339.8 330.7 310.6 Coal consumption (kg/kWh) 0.94 0.97 1.03 Net Plant Efficiency (%) 23.34 22.71 21.33 Net Plant Heat rate (kJ/kWh) 15,420 15,850 16,880 CO2 emission rate (kg/kWh) 0.14 0.14 0.15 Cost of Electricity ($/MWh) 91.98 100.8 114.9 Energy Penalty (%) 47.13 51.21 60.99 Increase in COE ($/MWh) 54.02 62.84 76.94 Cost of CO2 avoided ($/t) 66.69 77.58 96.18

It is evident from the simulations that amine based capture is the most cost-effective mechanism for CO2 capture.

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Even without a carbon price scenario, the cost of CO2 avoidance is about US$ 66/t-CO2. Some improvements in capture technology can lead to this reducing below US$ 60/t-CO2, at which point it can be realistic to think of CCS in India. Here, the sink location is assumed to be the Talcher coalfield, with normal sequestration i.e. without enhanced coalbed methane (ECBM). While it is true that the Talcher coalfield is significantly less gassier than some other coalfields like Jharia and North Karanpura [27], some prospects of ECBM can reduce the cost of CO2 avoidance further by US$ 6-10/t-CO2. A point that deserves mention here is that the Government of India has announced special incentives for Indian gas extraction companies, so that they can fairly compete with gas importing companies. Thus, there is an additional incentive for ECBM operation in coalfields, especially in the eastern India, wherein a large number of UMPPs are coming up, in areas with vicinity to the coal-bearing areas. 3.2.2. Some trends in CCS costs for existing plants Table 7. Summary of simulation results of amine based capture case for some existing units in India. Mean Median Standard Range Deviation Without CCS Gross Size (MW) 544.73 543.10 3.73 540.30-552.70 Net Capacity (MW) 500 500 0.0 500 (fixed) Coal consumption (kg/kWh) 0.75 0.71 0.11 0.64-1.00 Coal consumption (t/hour) 374.77 358.50 54.52 320.40-500.60 Net Plant Efficiency (%) 34.34 34.33 0.75 32.78-35.39 Net Plant Heat rate (kJ/kWh) 10,490 10,490 232.75 10,170-10,980 CO2 emission rate (kg/kWh) 0.92 0.95 0.08 0.77-1.01 Cost of Electricity ($/MWh) 64.21 60.23 16.42 37.96-90.11 With CCS Gross Size (MW) 438.81 433.50 9.96 426.90-454.90 Net Capacity (MW) 340.51 337.40 13.48 326.70-363.40 Coal consumption (kg/kWh) 1.10 1.07 0.17 0.94-1.48 Net Plant Efficiency (%) 23.38 23.34 0.95 22.12-24.92 Net Plant Heat rate (kJ/kWh) 15,424 15,420 624.1 14,440-16,280 CO2 emission rate (kg/kWh) 0.14 0.14 0.02 0.11-0.15 Cost of Electricity ($/MWh) 129.21 123.40 23.84 91.98-174.5 Energy Penalty (%) 47.07 48.19 5.67 37.64-53.00 Increase in COE ($/MWh) 65.01 65.98 10.24 51.18-84.39 Cost of CO2 avoided ($/t) 82.98 80.27 11.75 66.69-108.19

Table 7 gives a summary of simulation results of amine based capture case for the existing units listed in Table 3. Before moving on to discussion for individual units, it would be pertinent to discuss some general trends. It should be mentioned that since amine based capture is noted to be most cost and energy efficient technique, the following results are summarized for the same: x A significant energy penalty is incurred for sorbent regeneration, apart from the energy use for capture and compression. This is evident because of the decrease in gross size by 14-21 percent. The importance of this decrease can be understood with the example that if a power plant is operating in a 6×500 MW configuration, with a gross size of 3240 MW, it would require a seventh identical unit just to meet the sorbent regeneration requirements. As a result, capital investments, land requirements, labor needs etc. would all increase by around 17 percent. x Apart from the above derating, CO2 capture and compression requirements also take up a significant chunk of the energy share of the plant. As a result, the net size decrease amounts to 25-35% in all the cases. The CO2 capture energy requirement is around 7.5%. This is somewhat closer to the ranges from 8.2% for the best performing subcritical unit, for which the corresponding requirement is 8.2%, but increases sharply up to 11% for the Rihand plant. The sensitivity is less in terms of CO2 capture and compression uses, and larger for the sorbent regeneration requirements. x The energy penalty is estimated to be ranging from 32-53%. This is considerably higher than the estimate of 17-22% suggested by Rao and Kumar [20]. One of the probable reasons for this difference is that the said study did not consider the gross size reduction due to sorbent regeneration.

Udayan Singh et al. / Energy Procedia 114 (2017) 7638 – 7650

x

Coming to the cost parameters, we find that the increase in the cost of electricity is strongly related to the plant efficiency. The two Vindhyachal units studied have a difference in COE increase of about US$ 4.5 because of the difference in boiler efficiency of ~2.6%.

The marginal abatement cost curve for the units studied in this paper is shown in Fig. 1.

Fig. 1. Marginal Abatement Costs (MAC) curve for the units studied 3.3. Discussion Next, some of the features of the individual units being considered in this study have been discussed. Although, we have not considered The Sipat Thermal Power Station (STPS) located in Madhya Pradesh in this study, it has been evaluated as one of the best power plants deployable for CO2 capture. The plant, which has been amongst the best performing units in the country was the first NTPC owned plant to be installed with a supercritical unit. As stated earlier, the plant can offer significant advantages in terms of cost and performance for implementing CCS as the increase in the COE is estimated as the lowest. It has been reported that the Talaipalli coal block will be used to supply coal to the STPS. This coal block is owned by NTPC itself. It is expected to be operated as an 18.72 MTPA opencast-cum-underground mining project, which will supply indigenous, high quality coal. This can be expected to drive down coal transportation costs. Possibilities of CO 2 sequestration in the unmineable coal seams around the area may also be studied to explore more economic mechanisms of CO 2 storage. The formations of the eastern region can be said to have the largest scope for CO2 sequestration. This is so because Holloway et al [28] have suggested that CCS deployment in India will be largely linked to the development of the ultra-mega power plants (UMPPs), which are expected to emit 28-29/Mt-CO2 annually. Three of these UMPPs are proposed in the states of Bihar and Jharkhand. The Kahalgaon power station studied in this paper also belongs to the state of Bihar. As seen in Fig. 2 (a), this power plant lies almost in a straight line with the locations of the proposed Banka and Deoghar UMPPs and therefore may be selected together for CO 2 storage in the Jharia or Bokaro coalfields having high degree of gassiness [29]. Alternatively, as illustrated in Fig. 2 (b), the basalt formations of the Rajmahal traps can be utilized for this purpose due to the closer proximity from the Kahalgaon power plant. In some earlier papers, it has been suggested that plants using imported coal may be considered as the first priority for CO2 capture [30]. While such a suggestion is noteworthy because imported coal with lower ash content shows better performance in terms of sorbent regeneration, the related economic implications should also be observed. For instance, the Simhadri plant is shown to have decent performance in terms of the energy penalty (

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