economic implications of co capture from the existing as

Available online at www.sciencedirect.com

ScienceDirect

Energy Procedia 00 (2017) 000–000

www.elsevier.com/locate/procedia

1876-6102 © 2017 The Authors. Published by Elsevier Ltd.

Peer-review under responsibility of the organizing committee of GHGT-13.

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. Rao

b,*, Munish K. Chandel

c

aDepartment of Mechanical Engineering, National Institute of Technology Rourkela, Rourkela 769008, INDIA bCentre for Technology Alternatives for Rural Areas & IDP in Climate Studies, Indian Institute of Technology Bombay, Mumbai 400076, INDIA

cCentre for Environmental Science and Engineering (CESE), Indian Institute of Technology Bombay, Mumbai 400076, INDIA

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.

© 2017 The Authors. Published by Elsevier Ltd.

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]

2 Singh et al./ Energy Procedia 00 (2017) 000–000

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 CO2 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 CO2 capture.

Considering India’s increasing energy requirements, continued reliance on coal and the high CO2 emission factor

from coal-fired power plants, they will be the obvious targets for achieving the potential CO2 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 CO2 capture from large point sources. As a result, it allows

an easy way to properly manage CO2 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

Singh et al./ Energy Procedia 00 (2017) 000–000 3

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 CO2 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:

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 CO2.

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] – Retrofitting Oxyfuel Combustion

Supercritical and ultra-supercritical double reheat system

29.79%-31.67%

Karmakar and Kolar [15] – Monethanolamine

(MEA) capture

Subcritical

31-40%

Karmakar et al [16] Subcritical, supercritical and ultra-

supercritical boilers

29-43%

Singh and Rao [17] – Amine, Ammonia, Membrane, Oxyfuel; use of auxiliary gas boiler

Subcritical and supercritical boilers 39-53%


2.3. Performance analysis of CO2 capture in Indian power plants

Table 2 shows some of the recent cost estimates for CO2 capture and storage in the Indian power sector.

Table 2: Recent estimates of cost penalties due to CCS in coal power plants in India

Study Parameter Value Remarks

Viebahn et al [18] Increase in LCOE

45-51% Integrated study of the Indian power sector

covering all aspects of CCS implementation TERI [19] 47% Studies covering UMPPs only

Rao and Kumar [20] 63-75% Deterministic case studies of four existing

power plants Garg & Shukla [5] Cost of CO2 avoidance

US$ 50-60/t-CO2 Estimates based on expert elicitations

Mott Macdonald [21] US$ 35-42/t-CO2

(for inland sites) US$ 36-42/t-CO2

(for coastal sites)

Study covering Ultra Mega Power Plants

(UMPPs) only

Yadav et al [22] 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 CO2

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.


Table 3: Data considered for simulating existing coal-fired power plants in India

Plant Unit Owner Year Size (MW) Capital Cost

(M$)a

O&M Cost

$/MWhb

BE (%)c Coal Linkage

a, # Coal Cost

($/t)b

HHV

(kJ/kg)b PLF (%)

b

Vindhyachal VIII NTPC 2000 500 501.44*

4.6

87.77

Nigahi Mines 24.61 13673 91.1

Vindhyachal X NTPC 2007 500 501.44 85.14

Talcher Kaniha IV NTPC 2004 500 428.9 4.65 85.59 Talcher CF – MCL 15.86 16360 81.6

Rihand IV NTPC 2005 500 438.61 4.25 87.12 Amlori/Dudhichua/A

mloric Expansion 23.85 14355 92.4

Kahalgaon V NTPC 2007 500 442.46 5.66 82.73 Rajmahal 30.54 10966 71.7

Sipat IV NTPC 2007 500 564.46 4.32 84.91 Dipika Mines SECL 31.04 15401 96.5

Simhadri III NTPC 2011 500 399.38 3.75 84.5 Kalinga – TCF 39.78 13685 96.1

a 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. b 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. c 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

Economic Lifetime years 30

Fixed charge factor %/year 11.42

Project contingency %PFC 11.67

Process contingency %PFC 0.3

Fuel cost escalation rate %/year 6.62

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:

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].


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:

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

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

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


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 Deviation

Range

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:

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.

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.

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.


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 CO2 sequestration in the unmineable coal seams

around the area may also be studied to explore more economic mechanisms of CO2 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 CO2 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

(<40%), as compared to the Talcher plant (~47%). Still, because of the increasing trend of coal imports in the former

(Fig. 3), the cost of CO2 avoidance is higher by 28%, compared to the latter. Thus, deployment of CCS in power

plants located close to the coal-bearing areas has the dual advantage of lower coal costs as well as lower CO2

transport costs.


Fig. 2: Possibility of transport of CO2 emitted from Kahalgaon power station to the (a) Jharia/Bokaro coalfields, (b) Rajmahal traps. Images have

been generated using Google Maps.

Fig. 3: Trend of imported coal share and overall coal cost (per unit heating value) for the Simhadri Power Plant. Source:

http://www.cercind.gov.in/NTPC.html.

4. CCS costs for upcoming plants

While considering the upcoming power plants in India, following factors have to be incorporated within the

modeling analysis:

For CCS to be successful in India, carbon prices have to be put in as a major policy instrument .

The availability of ultra-supercritical (USC) boilers is expected to further act as an enabler towards CCS

implementation.

Learning in CO2 capture technologies can bring down associated capital and O&M costs.

Here, an attempt has been made to consider the first two factors for CCS cost analysis for upcoming plants upto the

year 2050.

http://www.cercind.gov.in/NTPC.html


Table 8: Assumptions used for simulating upcoming coal plants

Parameter Unit Nominal Value Range

Net Capacity MW 660 660 (fixed)

Gross Capacity MW 702.57 680.6-715.4

Aux. Consumption % 6.45 3.12-8.44

Unit type Super-critical

Type of firing Tangential

Boiler Efficiency % 86 84-88

Source of Coal Talcher coalfield

Coal Property

Carbon % 40.56

Sulphur % 0.38 Ash % 40

Moisture % 6.37

Calorific value kJ/kg 16,360

Plant load factor % 90 80-100

ESP Efficiency % 99.7 99.5-99.9

4.1. Methodology

In this section, a supercritical and USC unit of 660 MWnet capacity are simulated using the IECM-cs framework,

with similar assumptions, as made in the previous section. The technical parameters, such as boiler efficiency, load

factor etc., are taken from Singh and Rao [23] in a probabilistic manner, as shown in Table 8. Contrary to the

requirement of keeping the coal intake constant, we now assume that the net size of the plant remains the same, with

and without CCS deployment.

Further, three scenarios have been considered for comparing the various levels of CCS deployment, carbon taxes

and USC boiler availability, as shown in Table 9. It should be noted that a higher level of CCS deployment, a lower

concentration stabilization scenario (characterized by higher carbon prices) and earlier availability if ultra-

supercritical boilers are all features that are indicative of financial and policy support of the government towards

CCS.

Table 9: Scenarios for assessment of CCS costs from 2020 to 2050

Scenario CCS deployment, based

on IESS 20472

Stabilization Scenario Time of availability of ultra-

supercritical boilers

S1 (Lowest support to CCS) Level 2 650 ppmv Post 2050

S2 (Medium CCS support) Level 3 450 ppmv From 2040 S3 (Highest CCS Support) Level 4 450 ppmv From 2030

The decade-wise installed capacity and the average carbon taxes are shown in Table 10.

Table 10: Decade-wise average carbon price and electricity generation

Average carbon price ($/t-CO2) Electricity generated with CCS (GWh)

S1 S2 S3 S1 S2 S3

2020-2030 6 66 66 323,091 1,606,425 2,760,542

2030-2040 10.5 110.5 110.5 1,450,149 3,680,210 4,699,080

2040-2050 16.5 167.5 167.5 2,577,207 5,753,996 6,637,618

The carbon prices in Table 10 have been derived from Shukla et al [32], while the electricity generation has been

obtained by compounding the installed capacity with a load factor of 90%.

2 The NITI Aayog, Government of India projected four scenarios for four scenarios of CCS deployment in India in the India Energy Security

Scenarios 2047 (IESS, http://indiaenergy.gov.in/supply_css.php). Level 1 depicts CCS implementation post 2025 and installed CCS capacity till 2047 being 8 GW. This capacity for Levels 2, 3 and 4 are 35, 80 and 90 GW respectively. Level 1 of deployment has not been covered in this

paper as it indicates a minimal interest towards CCS.


4.2. Results

The first important set of results is the comparison of the supercritical and ultra-supercritical plants for their

suitability for CO2 capture. As expected, USC plants demonstrate a lower economic as-well-as energy penalty from

CCS implementation. For instance, the increase in cost of electricity for USC plants is US$ 35-50/MWh, while that

for a supercritical plant is US$ 40-57/MWh. The energy penalty observed for USC plants is also about 4.8-5.4% less

than that for the supercritical plants.

If a carbon price scenario is introduced, the increase in the cost of electricity is shown in Fig. 4. The figure shows

a point of intersection for the CCS and non-CCS curves at just greater than US$ 60/t-CO2. The cost of avoidance for

the supercritical plants (US$ 53-72/t-CO2) and USC plants (US$ 51-69/t-CO2) are both strongly aligned to a

stabilization scenario of 450 ppmv levels, by the year 2025. This is so because the predicted carbon price in such a

scenario would increase from US$ 46/t-CO2 to US$ 86-t/CO2.

It is noteworthy that an increase in carbon prices would result in a rapid increase in COE without CCS. It also

means that the payment towards the carbon tax goes on becoming a major chunk of the total cost. For instance, the

carbon tax makes up only about 10-14% of the total COE, when carbon price is US$ 10/t-CO2. When this increases

to US$ 110/t-CO2, the carbon tax becomes 56-63% of the total COE. This creates a favorable case for CCS as a

consumer has to pay 2.3-2.7 times for the electricity produced from a non-CCS power plant. The relative share of the

carbon tax in the COE for typical supercritical plants is shown in Fig. 5. It is evident that in a higher carbon price

scenario, the sensitivity towards plant-level factors such as load factor and boiler efficiency is more pronounced,

which is manifested by the thickening of both the curves at the end.

4.2.1. Scenario Analysis

Fig. 4: Variation of COE with carbon price. Fig. 5: Share of carbon revenue in total COE.

Coming to the scenario analysis, the S1 scenario has total cost of electricity generation of US$ 0.28-0.41 trillion

during 2020-2050 without CCS, as against US$ 0.41-0.61 trillion with CCS during the same period. However, if

CCS is deployed for the required capacity, the net emission reduction during 30 years would be about 3266-3415

million tonnes of CO2. This is equivalent to reduction of one year of annual CO2 emissions from India in the 2020

levels [33]. However, substantive cost reduction can of course be possible with earlier deployment of USC boilers.

In the S2 scenario, it has been assumed that all the new boilers being commissioned after 2040 are of USC type.

This would mean that around 32% of the total power generation post-2040 will be from USC boilers. The cost of

electricity generation during the 30 years if CCS is not implemented is US$ 1.83-2.24 trillion, as opposed to US$

1.19-1.71 trillion with CCS.

Thus, in a high carbon tax scenario, electricity generation is expected to cost around 31-54% times higher without

CCS. In such a case, CCS implementation is justified as the cost reduction is an ancillary benefit in addition to the

CO2 emission reduction of about 8500 million tonnes of CO2 over 30 years. This is about three times of India’s

annual CO2 emissions in the present day scenario.


The S3 scenario has further enhanced support towards CCS, as compared to S2. In this scenario, USC boilers are

assumed to be deployed as early as 2030. This means that USC boilers will contribute to 38% of CCS-based power

in 2030-2040 and 53% of CCS-based power in 2040-2050. In such a scenario, the cost of electricity generation with

CCS is estimated to be US$ 2.7-3.9 trillion, as against US$ 4.2-5.1 trillion without CCS during 2020-2050. The CO2

emission reduction during these 30 years is expected to be about 10-11 million tonnes, which is expected to be thrice

the annual CO2 emission of 2020. Thus, CCS can indeed play a critical role in sizeable emission reduction in high

carbon price scenarios.

5. Conclusion

In this paper, a systematic economic analysis for coal-fired power plants with CCS in India has been carried out.

Initially, seven existing units of the state-owned NTPC have been considered and the impact of retrofitting of CO2

capture units on their performance, costs and emissions has been estimated. Unlike the previous economic studies

for CCS in India, the advanced amine based capture and the losses due to sorbent regeneration have been considered.

As a result, the energy penalty for the eight units ranges from 34% to 53%, while the cost of CO2 avoidance is US$

66-109/t-CO2. Some suitable features of various plants are annotated which are likely to act as enablers towards CCS

implementation in India. For instance, units close to coal-bearing areas can have a lower CO2 capture and

sequestration chain cost because of low transportation investments for coal as well as CO2. This has been established

by the case of the Talcher power plant. Our analysis can also be said to be partially validated since our reference

plant emissions are quite close to the ones calculated by Mittal et al [25].

Subsequently, an analysis for upcoming power plants in India has been carried out and the cost and environmental

benefits of implementing carbon prices have been suggested in various scenarios. For instance, in a low carbon price

scenario, CCS fails to become economically competitive against the currently established coal-fired power

generating units. At high carbon prices and with active deployment of ultra-supercritical units, a cost reduction of

almost 24-35% with use of CCS is expected during 2020-2050.

While high carbon prices shall make the CCS more favorable, the overall cost of electricity will be driven high. If

these costs can come down with indigenous development of collectors as well as learning, they shall become

comparable to the costs of coal-based power with CCS. As a result, CCS will face stiff competition from the

renewable sector. Therefore, a significant degree of learning is also required in the CO2 capture systems to drive

down overall cost of electricity.

Advanced coal technologies (ACTs) are the need of the hour. The Government of India has clearly indicated a

great deal of support for ACTs, with the Prime Minister himself inviting investments in this area. However, for CCS

to develop, it is necessary that the perspective towards CCS is as an important ACT rather than as an expensive and

‘foreign’ technology. It is expected that the costing results obtained in this study shall be useful in modelling and

planning of the Indian energy system and further studies shall be undertaken to strengthen the research base in this

area.

Acknowledgements

The authors are grateful to the GTWG-ACT project of the Department of Science and Technology (DST),

Government of India, for financial support. Authors also thank the IECM team at the Carnegie Mellon University,

USA, for making the tool freely available.

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economic implications of co capture from the existing as

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