Carbon Capture Utilization and Storage (CCUS)

Policy Framework and its

Deployment Mechanism in India

Carbon Capture,

Utilization and

Storage (CCUS)

November 2022

Authors and Acknowledgements

Atanu Mukherjee, Principal Investigator,

M. N. Dastur & Co. (P) Ltd.

Saurav Chatterjee, Co-Principal Investigator,

M. N. Dastur & Co. (P) Ltd.

Authors Acknowledgment

The team is grateful for the mentorship and inputs provided by:

Dr. V. K. Saraswat, Member, NITI Aayog

Dr. Neeraj Sinha, Sr. Adviser (S&T), NITI Aayog

Shri Rajnath Ram, Adviser (Energy), NITI Aayog

Leadership

The study was carried out with the financial support of NITI Aayog,

Government of India and conducted by M. N. Dastur & Co. (P) Ltd.

The team is grateful for the input and contributions received from:

Shri Jawahar Lal, Deputy Chief Engineer, NITI Aayog

Shri Naveen Kumar Vidyarthi, Director (Energy), NITI Aayog

Shri Amit Verma, Director (Energy), NITI Aayog

Shri Manoj Kumar Upadhayay,

Deputy Advisor (Energy), NITI Aayog

Dr. Abhinav Trivedi, Consultant, NITI Aayog

Shri Akash Jain, Young Professional, NITI Aayog

Abhijit Sarkar, Vice President, Dastur International, Inc.

Dr. Suprotim Ganguly, Techno-Strategic Advisor,

M. N. Dastur & Co. (P) Ltd.

Arunava Maity, Sr. Principal Analyst, M. N. Dastur & Co. (P) Ltd.

Dr. Vikram Vishal, Convenor - National Centre of Excellence in

Carbon Capture and Utilization, IIT Bombay

Dr. Ken Medlock, Baker Institute, Rice University

Phil Amick, Principal, Dastur Energy Inc.

Dr. Susan D. Hovorka, The University of Texas at Austin

Saptarshi Bhattacharya, M. N. Dastur & Co. (P) Ltd.

Anand Senguttuvan, M. N. Dastur & Co. (P) Ltd.

Arnab Adak, M. N. Dastur & Co. (P) Ltd.

Debarka Chakraborty, M. N. Dastur & Co. (P) Ltd.

Anindya Majumdar, M. N. Dastur & Co. (P) Ltd.

Pratyush Kumar, M. N. Dastur & Co. (P) Ltd.

We would also like to thank the following organizations who provided

valuable inputs in shaping the report:

Shri A. Balan, Member (Planning),

Central Electricity Authority, India

Shri A K Rajput, Chief Engineer, Central Electricity Authority, India

Shri Neelesh Kr Sah, Joint Secretary,

Ministry of Environment, Forest and Climate Change, Govt. of India

Shri Gurdip Singh, Chairman and Managing Director,

National Thermal Power Corporation Ltd.

Shri Nalin Singhal, Chairman and Managing Director,

Bharat Heavy Electricals Ltd.

Shri U K Bhattacharya, Director,

National Thermal Power Corporation Ltd.

Shri Anirban Das Gupta, Director-in-Charge,

Steel Authority of India Ltd.

Shri Sanjay Shrivastava, Executive Director -

Chief Carbon Management & Sustainability Group,

Oil and Natural Gas Corporation Ltd.

Shri Peeyush Kumar, Officer on Special Duty,

Ministry of Coal, Govt. of India

Dr. Anita Gupta, Adviser / Scientist G,

Department of Science & Technology

Shri Sanjay Singh, Scientist G, Technology Information

Forecasting and Assessment Council

Dr. Deepak Saxena, Executive Director, Indian Oil Corporation Ltd.

Shri Pradeep, Executive Director, Technology Information

Forecasting and Assessment Council

Shri Gaurav Mishra, Executive Engineer,

Reservoir, Oil and Natural Gas Corporation Ltd.

Shri Sujit Mitra, General Manager - Reservoir,

Oil and Natural Gas Corporation Ltd.

Smt. Neha Verma, Director, Ministry of Steel, Govt. of India

Shri Paramjeet Singh, Additional Industrial Advisor,

Ministry of Steel, Govt. of India

Dr. Mukesh Kumar, Director - Steel Research & Technology

Mission of India, Ministry of Steel, Govt. of India

Shri Kumar Saurabh, Deputy Director,

Ministry of Power, Govt. of India

Ms. Soujanya Mondal, Senior Manager, Corporate Strategy,

Planning & Advocacy, Gas Authority of India Ltd.

Shri Rahul Buswala, Strategy Manager,

Carbon Capture, Bharat Heavy Electricals Ltd.

Acknowledgment

Available at:

NITI Aayog: www.niti.gov.in

Disclaimer

M. N. Dastur & Co. (P) Ltd. has received the financial assistance under the Research Scheme of NITI Aayog to prepare the report. While due care has

been exercised to prepare the report using the data from various sources, NITI Aayog does not confirm the authenticity of data and the accuracy of

the methodology to prepare the report. NITI Aayog shall not be held responsible for finding or opinions expressed in the document. This

responsibility completely rests with M. N. Dastur & Co. (P) Ltd.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

About DASTUR

M. N. Dastur & Company (P) Ltd. along with Dastur Energy (DASTUR)

conceptualizes, designs, and develops business, technology, engineering and policy

blueprints for clean energy systems for enterprises, governments, and institutions.

DASTUR envisions the enablement of an affordable and clean energy future

through industrial decarbonization, carbon capture, low-carbon alternative fuels

and low-carbon transformation of solid fuels and hydrocarbons. DASTUR has

conceptualized and designed several pioneering industrial-scale low-carbon

projects worldwide in hydrogen, methanol, chemicals, steel, hydrocarbons, power,

and carbon capture, and works with governments and international institutions on

policy and market design aspects for enabling a low-carbon economy. DASTUR’s

intellectual property and operating frameworks help design commercially viable

and sustainable energy solutions using low-carbon energy technologies and

carbon capture utilization and storage. DASTUR optimizes the design of integrated

clean energy systems for superior long-term techno-economic performance that

include emerging energy systems like industrial carbon capture systems, CO

utilization and sequestration, clean baseload power, clean hydrogen production,

net-negative gasifier complexes, methanol ecosystems, waste gas conditioning and

use, clean chemicals, and clean materials. DASTUR’s intellectual assets in clean

energy systems, economics, and finance help shape policies and strategies in clean

energy market designs, carbon capture, carbon credit & trade mechanisms,

regulatory frameworks, and macro-energy strategies for nations and institutions.

By designing scalable clean energy systems which are pragmatic, commercially

viable, and competitive, DASTUR makes sustainability and climate goals real,

achievable, and implementable.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary 15

1. Introduction 27

2. Analysis of Sector-wise CO

Emissions 35

3. Overview of CO

Capture & Utilization Technologies 67

4. Potential for CO

Storage in India 93

5. CCUS Policy Framework for India 111

6. Investment and Financing Mechanism 135

7. Conclusions 157

Bibliography 163

Contents

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

List of Figures

Figure E-1 The 70% Emissions Challenge

Figure E-2 Sector-wise CO

Emissions (in mtpa)

Figure E-3 Cost Curve for CO

Capture Across

Industries/Sectors

Figure E-4 Mega Scale CO

Cluster Model

Figure E-5 Region-wise Storage Clusters in India

Figure 1.1 The 70% Emissions Challenge

Figure 2-1 Illustration of Emission Types and Boundary

Consideration

Figure 2-2 Sector-wise CO

Emissions, mtpa

Figure 2-3 Break-up of Installed Generation Capacity, GW

Figure 2-4 Break-up of Generation, Billion Unit

Figure 2-5 Break-up of Thermal Power Plants by Fuel

(Power Sector at a Glance ALL INDIA)

Figure 2-6 PFD of Coal-fired TPP

Figure 2-7 Schematic Representation of Gas Turbine

Figure 2-8 NGCC Power Plant Schematic Diagram

Figure 2-9 Share of Total CO

Emissions by Each Prime

Mover, mtpa

Figure 2-10 State-Wise Analysis of CO

Emissions (mtpa)

Figure 2-11 Crude Steel Capacity & Production in Last

5 Years (in mtpa)

Figure 2-12 Process Route Wise Steel Production and

Contribution (in mtpa)

Figure 2-13 Various Iron and Steel Making Routes in India

Figure 2-14 CO

Emission (in tonne) per tonne of Finished

Steel BF-BF route

Figure 2-15 Region-wise Distribution and Total CO

Emissions (in mtpa)

Figure 2-16 Cement Production (in mtpa)

Figure 2-17 Per Capita Cement Consumption in 2018 (in kg)

Figure 2-18 Cement Production (in mtpa)

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Figure 2-19 Top 10 Cement Clusters Based on Cumulative

Capacity

Figure 2-20 Cement Demand (in mtpa) and Per-capita

Cement Consumption (in kg)

Figure 2-21 Typical Process Flow Diagram for Cement

Making

Figure 2-22 Typical CO

Cascade (in kg of CO

per tonne

of cement)

Figure 2-23 Cement Plant CO

Emission Projection

(in mtpa)

Figure 2-24 Simplified Block Flow Diagram of Hydrogen

Generation Units (HGUs)

Figure 2-25 Domestic Oil Production (in mtpa)

Figure 2-26 Natural Gas Production - FY 2014-15 to FY

2019-20 (in billion cubic meter)

Figure 2-27 Oil Production by Operator in FY 2019-20

(in mtpa)

Figure 2-28 Natural Gas Production in FY 2019-20 (in

billion cubic meters)

Figure 2-29 Carbon Emission by E&P Operator in FY

2019-20 (in mtpa of CO

eq)

Figure 2-30 Emissions Projection for 2030, MT CO

Figure 2-31 A Typical Coal Gasification Based Ecosystem

Figure 3-1 Scheme of Post-combustion, Pre-combustion &

Oxy-fuel combustion

Figure 3-2 Simplified Representation of CO

Capture

Technologies

Figure 3-3 Schematic Representation of Working Principle

of Solvent-Based CO

Capture

Figure 3-4 Schematic Representation of CO

Absorption

Capacity of Chemical and Physical Solvents as

a Function of the Partial Pressure of CO

Figure 3-5 Operating Regimes of Various Solvents for

Capture

Figure 3-6 Typical Flow Diagram of a Chemical Solvent

Based CO

Capture

Figure 3-7 Process Flow Diagram of Air Liquide’s Amine

Based CO

Capture

Figure 3-8 Process Flow Diagram of a Pilot Slipstream

Test Unit at National Carbon Capture Center,

USA using ION’s Proprietary ICE-21 Solvent for

Capture

Figure 3-9 Process Flow Diagram of KM CDR CO

Capture

using Proprietary KS-1 Solvent

Figure 3-10 Process Flow Diagram of the Amine Guard

™

Capture using Proprietary UCARSOL

™

Solvent

Figure 3-11 Process Flow Diagram of Baker Hughes Chilled

Ammonia Process (CAP) using Ammonium

Carbonate Solvent

Figure 3-12 Basic Process Flow diagram of the Rectisol

Process

Figure 3-13 Basic Process Flow Diagram of the Selexol

™

Process

Figure 3-14 Basic Process Flow Diagram of Air Products’

VSA Technology

Figure 3-15 Five-step Pressure-swing Cycle of UOP’s

Polybed

™

PSA Systems

Figure 3-16 Process Flow Diagram of the Cryocap

™

Technology

Figure 3-17 Summary of Major Large Scale Carbon Capture

Commercial Projects

Figure 3-18 Cost Curve for CO

Capture Across

Processes/Industries

Figure 3-19 Possible CO

Utilization Pathways

Figure 3-20 A Simplified Schematic of CO

Mineralization

Process

Figure 3-21 Typical Schematic for the CO

Hydrogenation

Process along with Integration with Carbon

Capture Unit

Figure 3-22 Systematic Indigenization of Technology

through Technology Transfer

Figure 3-23 Promising CO

Utilization Technology

Propositions

Figure 4-1 Working of CO

EOR

Figure 4-2 Working of CO

ECBMR

Figure 4-3 Classification of CO

Storage Potential of

Sedimentary Basins of India

Figure 4-4 Major Sedimentary Basins in India with their

Storage Potential

Figure 4-5 Seven RSCPs Funded by the US DOE

Figure 5-1 CCUS Hub and Cluster Framework

Figure 5-2 CCUS Cluster Around the World

Figure 5-3 Rotterdam CCS Cluster

Figure 5-4 Timeline Denver City Hub

Figure 5-5 Denver City Storage

Figure 5-6 ACTL Map

Figure 5-7 ACTL Timelines

Figure 5-8 Mega Scale CO

Cluster Model

Figure 5-9 Region-wise Storage Clusters in India

Figure 6-1 Utility Costs Considered

Figure 6-2 Sector-wise CO

emission and Contribution

Figure 6-3 Incentives such as the Product Linked

Incentive (PLI) scheme create a level playing

field for low-carbon products

Figure 6-4 CCUS Financing Mechanism

Figure 6-5 Results of CCUS Financing Analysis – Financing

Option 1 (Clean Energy Cess)

Figure 6-5 Results of CCUS Financing Analysis – Financing

Option 2 (Bonds and Govt. Budget Support)

Figure 6-6 SPV Framework to Finance Gasification

Projects in a Deficit-Neutral Way

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

List of Tables

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Table E-1 Estimated CO

Storage Capacity in India

Table E-2 Sector-wise Typical Carbon Capture Capital

Charge and Cash Cost

Table E-3 CCUS Funding through Clean Energy Cess

Table E-4 CCUS Funding with Bonds and Government

Budgetary Support

Table 1-1 Large Scale CCUS facilities in operation in 2020

Table 2-1 Flue Gas Characteristics of Coal-Fired Thermal

Power Plants

Table 2-2 Flue Gas Characteristics of Coal-Fired Thermal

Power Plants

Table 2-3 Overall Analysis of CO

Emissions from the Power

Sector in India

Table 2-4 CO

Emissions by Prime Mover for Plants with

Minimum 2 mtpa Capturable CO

Table 2-5 District-wise CO

Emission Analysis

Table 2-6 Energy & CO

Volume Projections for

FY 2029-30

Table 2-7 CO2 Direct Emission Intensities for Various Iron

Making Routes

Table 2-8 Major Players of Cement Industry and Capacity

in mtpa)

Table 2-9 State-wise Cement Capacity

Table 2-10 Top 20 Districts/Clusters and Aggregate Capacity

Table 2-11 Plant Capacity Distribution

Table 2-12 Consumption Parameters

Table 2-13 Gas Composition at Different Source Points

Table 2-14 CO

Concentration at Different Refinery Units

Table 2-15 Cracker Furnace Flue Gas Composition

Table 2-16 Total CO

Emissions from Refineries,

Petrochemicals & Fertilizers

Table 2-17 Total CO

Emissions from Oil & Gas Upstream

Operations

Table 2-18 Total CO

Emission from Coal Gasification

Table 2-19 Sector-wise CO

Emissions and Interventions

Required

Table 3-1 Comparison of Various Flow Schemes of UOP

Amine Guard

™

FS Technology

Table 3-2 Comparative Analysis of Various Classes of CO

Capture Technologies

Table 3-3 Various CO

Utilization Pathways

Table 4-1 CO

EOR Storage Capacity Estimates

Table 4-2 CO

ECBMR Storage Capacity Estimates

Table 4-3 CO

Storage Capacity Estimation for Deep

Saline Aquifers

Table 4-4 Basalt Formation CO

Storage Capacity Estimates

Table 4-5 Theoretical CO

Storage Capacity in India

Table 5-1 EU Funding Schemes for CCUS

Table 5-2 Carbon Pricing System Adopted by Different

Provinces of Canada

Table 5-3 Comparison of Carbon Credits/Incentives and

Carbon Tax Based Policy

Table 5-4 Key Elements of a CCUS Policy Framework

for India

Table 5-5 Sedimentary Basins Spanning Across Multiple

Regions

Table 6-1 Capex and Opex Considerations for CCUS Retrofit

Table 6-2 Sector-wise Typical Carbon Capture Capital Cost

Table 6-3 Sector-wise Typical Carbon Capture Cash Costs

Table 6-4 Sector-wise Typical Carbon Capture Cash Costs

and Capital Charges

Table 6-5 Carbon Capture Volume in Two Scenarios and

Tentative Investment

Table 6-6 Assumptions/Considerations for CCUS Financing

Analysis

Table 6-7 45Q Tax Credit Amounts

Table 6-8 Tax Credits for Hydrogen Production in USA -

Inflation Reduction Act of 2022

Table 6-9 Probable Distribution of 750 mtpa and low-C

Product Volume

Table 7-1 Sector-wise CO

Emissions and Interventions

Required

Table 7-2 Theoretical CO

Storage Capacity in India

Table 7-3 Key Elements of a CCUS Policy Framework

for India

Table 7-4 Sector-wise Typical Carbon Capture Capital

Charge and Cash Cost

Abbreviations

ACTL Alberta Carbon Dioxide Trunk Line

AD Accelerated Depreciation

ADB Asian Development Bank

ARRA American Recovery and Reinvestment Act

BEE Bureau of Energy Efficiency

BF Blast Furnace

BGS British Geological Society

BOF Basic Oxygen Furnace

BOO Build-Own-Operate

CAP Chilled Ammonia Process

CBAM Cross Border Adjustment Mechanism

CBM Coal Bed Methane

CCF Climate Change Fund

CCFC Carbon Capture Finance Corporation

CCL Central Coalfields Limited

CCM Carbon Concentrating Mechanism

CCUS Carbon Capture Utilization and Storage

CDU Crude Distillation Unit

FCC Fluid Catalytic Cracking

CEA Central Electricity Authority

CEIL Cairn Energy India Limited

CFD Contracts-for-Difference

CGP Co-Gen Plant

CIF CCUS Infrastructure Fund

CIFIA Infrastructure Finance and Innovation Act

CIL Coal India Limited

CIR Color Infrared

CO Carbon Monoxide

Coal DR Coal Based DR Processes

COG Coke Oven Gas

CRF Capital recovery factor

CRI Carbon Recycling International

DAC Direct Air Capture

DEPG Dimethyl Ether of Polyethylene Glycols

DGH Directorate General of Hydrocarbons

DOE Department of Energy

DRCF Dual Refrigerant CO

Fractionation

DVP Deccan Volcanic Province

E&P Exploration and production activities

EAF Electric Arc Furnace

EBP Ethanol Blend Petrol

ECBMR Enhanced Coal Bed Methane Recovery

ECL Eastern Coalfields Limited

EIB European Investment Bank

EMIT Electromagnetic Induction Tomography

EOR Enhanced Oil Recovery

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

EPA Environmental Protection Agency

ERT Electrical Resistance Tomography

ESP Electrostatic Precipitator

EU ETS European Union Emissions Trading System

EXIM Export Import Bank of the United States

FCC Fluid Catalytic Cracking

FECM Fossil Energy and Carbon Management

FT Fischer-Tropsch

FTE Full Time Equivalent

Gas DR Gas Based DR Processes

GBI Generation Based Incentives

GBS Gross Budgetary Support

GFANZ Glasgow Financial Alliance for Net Zero

GGPPA Greenhouse Gas Pollution Pricing Act

GT Giga Tonne

GTPA Gigatonne Per Annum

HGU Hydrogen Generation Unit

HP High Pressure

IEA International Energy Agency

IECM Integrated Environmental Control Model

IETF Industrial Energy Transformation Initiative

IF Induction Furnace

IFC International Finance Corporation

ION ION Clean Energy

IP Intellectual Property

IPCC Intergovernmental Panel on Climate Change

JTF Just Transition Fund

JTM Just Transition Mechanism

KM CDR

™

Kansai Mitsubishi Carbon Dioxide Recovery

LCA Life Cycle Analysis / Life Cycle Assessment

LCFS Low Carbon Fuel Standard

LETS Low Emission Technology Statement

LIC Life Insurance Corporation

LP Low-Pressure

MDEA Methyl diethanolamine

MHI Mitsubishi Heavy Industries Ltd

MRV Monitoring Reporting and Verification

framework

MTPA Million Tonne Per Annum

MVA Monitoring Verification and Accounting

NAS Non Aqueous Solvent

NCEEF National Clean Energy and Environment Fund

NETL National Energy Technology Laboratory

NEXI Nippon Export and Investment Insurance

NGCC Natural Gas Combined Cycle

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

OBPS Output Based Pricing System

OPC Ordinary Portland Cement

OPGC Odisha Power Generation Corporation Limited

OPGGSA Offshore Petroleum and Greenhouse Gas

Storage Act 2006

PLI Production Linked Incentive

PMAY Pradhan Mantri Awas Yojana

PP Power Plant

PPC Portland Pozzolana Cement

PSA Pressure Swing Adsorption

PSC Portland Slag Cement

RCF Rashtriya Chemicals & Fertilizers

RCP Rotterdam Cluster Project

RCSPs Regional Carbon Sequestration Partnerships

RRF Recovery and Resilience Facility

SAR Synthetic Aperture Radar

SECARB Southeast Regional Carbon Sequestration

Program

SECL South-Eastern Coalfields Limited

SMR Steam Methane Reforming

SSEB Southern States Energy Board

syngas Synthesis Gas

T&S Transport and Storage

TCF Trillion Cubic Feet

TIER Technology Innovation and Emissions Reduction

TIFAC Technology Information Forecasting and

Assessment Council

TSA Temperature Swing Adsorption

UIC Underground Injection Control

UKRI UK Research and Innovation’s

URR Ultimate Recoverable Reserves

USIDFC US International Development Finance

Corporation

VDU Vacuum Distillation Unit

VGas Volume of Methane

VRM Vertical Roller Mill

VSA Vacuum Swing Adsorption

VSP Vertical Seismic Profile

WCL Western Coalfields Limited

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive

Summary

Carbon Capture, Utilization and Storage is an Essential

Imperative for India to Reach its Decarbonization Goals

India is the 3rd largest emitter of CO

in the world

after China and the US, with estimated annual

emissions of about 2.6 gigatonne per annum (gtpa).

The Government of India has committed to reducing

emissions by 50% by 2050 and reaching net zero

by 2070. The growth of renewable power capacity has

been one of the key success stories of the clean

energy transition in India; however, the power sector

only contributes to about 1/3 rd of the aggregate CO

emissions, which will continue to abate as renewables

increasingly replace fossil fuel based power

generation. The growing industrial economy emits

close to another third of the aggregate emissions that

are hard to abate, and will continue to increase unless

new technologies and carbon abatement mechanisms

are deployed. At the same time, while India phases

down the use of coal over time, India will be

dependent on fossil energy sources like coal for a long

time to support the industry and meet the

requirements for affordable and reliable baseload

power. Therefore, India’s decarbonization pathway

has to also embrace technologies which will abate

emissions from the hard to abate industrial sectors as

well as for residual baseload power generation.

Carbon Capture Utilization and Storage (CCUS) has an

important and critical role to play in decarbonizing the

industrial sector, which is hard to electrify and hard to

abate, due to the use of fossil fuels not only as a

source of energy but within the process itself. CCUS

also has an important role to play in decarbonizing the

power sector, given India’s present reliance on coal

for meeting over 70% of its electricity needs. Even if

India is able to substantially green the grid and meet

the target of 500 GW installed capacity of renewables

by 2030, there would still be a need to meet the

baseload power demand from fossil fuels (most likely

coal) or other dispatchable sources, given the

intermittency and non-dispatchable nature of solar

and wind power.

Direct Air Capture (DAC) that directly captures dilute

(415 ppm) from the air, may also emerge as a

form of carbon capture that has wide applicability as it

is independent of the source and concentration of the

emission stream. However, DAC is still in its early

stages and the economics (present cost of DAC is

estimated to range between US$ 400-800/tonne of

) and scale of operations are yet to be established.

Figure E-1: The 70% Emissions Challenge

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Industry

Agriculture

Transport

Building

Electricity

31%

~30%

2.6

gtpa

~70%

India

A Policy Driven Approach is

Required for CCUS

Industrial Sector Needs to be

a Key Focus Area for CCUS

CCUS is key to ensuring sustainable development and

growth in India, particularly for the production of

clean products and energy, leading to an

Indian economy. The areas where CCUS can

contribute to sustained economic growth in India

are manifold:

a. Energy, materials & food security and

self-sufficiency: CCUS offers the only known

technology for decarbonizing the hard-to-electrify

and CO

- intensive sectors such as steel, cement,

oil & gas, petrochemicals & chemicals, and

fertilizers. These sectors are critical to the

continued growth of the Indian economy and for

ensuring energy, materials and food security for

the country.

b. Enabling the sunrise sectors of coal gasification

and low-carbon hydrogen economy: CCUS is

expected to play a major role in enabling the

hydrogen economy in India, through the

production of blue hydrogen (i.e. coal gasification

based hydrogen production coupled with CCUS)

based on the utilisation of India’s rich

endowments of coal. Given the current cost

structure of green hydrogen at US$ 5-6/kg,

cost-competitive blue hydrogen production at

around US$ 2/kg can provide a pathway for the

hydrogen economy in the future.

c. Sustenance of existing emitters: Nearly

two-thirds of India’s 144 mtpa crude steel capacity

and 210 GW of coal-based power capacity have an

age of less than 15 years and cannot be wished

away or stranded and need to be made

sustainable by retrofitting with CO

capture and

disposition infrastructure. Significant economic

costs and damages (estimated to be in the range

of US$ 6 billion/year by 2050) can be avoided by

ensuring the sustenance of existing emitters by

implementing CCUS.

While CCUS enables competitive and sustainable sunrise

industries in certain sectors in India, it also imposes

costs on other sectors – particularly for the adoption of

CCUS by existing emitters. The initial adoption of CCUS

implementation in such sectors will impose costs as

they start internalizing the negative externality of

emission of CO

into the atmosphere, whose cost is

currently borne by society. As more CO

utilization

technologies develop and learning curve effects set in,

CCUS costs can come down significantly and new

industries around carbon utilization will also develop.

Therefore, to enable the sustainable development of

the Indian economy, economy-wide adoption of CCUS

will require policy support to initiate and accelerate

deployment through economic incentives. These

economic incentives can take various forms like tax or

cash subsidy on the captured CO

, viability gap

funding, loan guarantee, demonstration project

support and R&D incentives.

India’s power and industrial sectors contributed

around 1,600 mtpa of CO

emissions (around 60%)

out of the total emissions of 2,600 mtpa in 2020.

The remaining 40% of emissions come from

distributed point emissions sources like agriculture,

transport, and buildings which are not amenable for

CCUS. Fuelled by economic growth across sectors as

well as rapid urbanization, emissions from these

sectors are expected to increase to nearly 2,300

mtpa by the year 2030, thus making their capture

and abatement critical.

1,004

1,210

177

240

450

196

325

2030 CO

emission

125

2020 CO

emission

2,291

102

1,621

Coal Gasifcation

NG based H

production Upstream O&G/Refinery/Chemicals

Cement

Iron & Steel

Power

Figure E-2: Sector-wise CO

Emissions (in mtpa)

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

CCUS has an integral role to play in the

decarbonization and sustenance of all these industries

and sectors, which are critical and vital pillars of the

Indian economy.

Steel: The future growth of the steel

industry in India is largely expected to be

based on fossil fuels and the CO

-intensive

BF-BOF route, given the scarcity of scrap

and natural gas in India. CCUS is

necessary for ensuring the sustainability of this

critical sector of the Indian economy and also

ensuring export competitiveness.

CCUS can also enable the scalable and profitable

conversion of waste gases from Blast Furnace, Coke

Oven and Basic Oxygen Furnaces of Integrated Steel

Plants to blue hydrogen at a cash cost of less than Rs.

100 per kg. Blue hydrogen can be used within the steel

plant as a source of clean energy or for producing clean

DRI. The blue hydrogen can also be sold to external

consumers, thus propelling the clean hydrogen

economy in India.

Cement: Cement is another major CO

emitting sector, where fossil fuels are

difficult to replace in the cement-making

process. The capture, sequestration and

conversion of CO

to aggregates and

other chemical products provide synergies for the

cement sector.

Oil & gas, refineries and chemicals: This

is another hard-to-abate sector, where

CCUS is essential for ensuring

sustainability. Carbon capture is inbuilt in

many of the processes, which makes CCUS costs

competitive for this sector.

Hydrogen production: The

cost-competitive production of blue

hydrogen using India’s rich coal

endowments is key to enabling the

hydrogen economy of the future. Carbon capture is

inbuilt in the H

production process, leading to

cost-competitive CCUS.

Coal gasification: Coal gasification is a

sunrise sector and key to ensuring the

materials and energy security of India,

based on India’s rich endowments of coal.

CCUS is critical to enabling the coal gasification

economy in India and the production of clean

products.

Thermal power: Even with the expected

growth in renewable energy capacities,

coal-based power will continue to meet

more than 50% of electricity demand in India in the

foreseeable future. As the largest emitter of CO

CCUS of the power sector is essential for meaningful

decarbonization and ensuring energy security in India.

Appropriate Carbon Capture

Technologies for Different

Applications

There are different categories and types of

commercial-scale carbon capture technologies and

their suitability or appropriateness for different

applications/sectors depends on the typical CO

gas

stream composition:

a. Chemical solvent-based CO

capture

technologies: preferred when dealing with gas

streams that are lean in CO

and have relatively

lower pressures, such as flue gas streams from

power plants, BF gases in steel plants, gas streams

in refineries or chemicals plants. The cost and

availability of steam is also a key factor as

regenerating the solvent requires large quantities

of steam.

b. Physical solvent-based CO

capture

technologies: these work well on gas streams with

relatively higher CO

concentration and pressure,

such as pre-combustion capture in the case of

gasification projects.

c. Adsorption-based CO

capture: suitable for gas

streams with moderate to high pressure and

moderate CO

concentration such as SMR flue gas

or BF gas.

d. Cryogenic CO

capture: preferred in cases where

the cost of power is low. This technology can be

applied for carbon capture from the PSA tail gas

of Steam Methane Reforming Units (for producing

) and provides a unique advantage of increasing

the yield/recovery of hydrogen production from

the same quantity of feedstock (natural gas).

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Carbon Capture Costs

Vary Widely Across

Industries/Sectors -

Policy Incentives Need to

be Appropriately Calibrated

Carbon capture costs (both capital cost and cash

cost) vary widely across industries and sectors, and

depend on CO

source characteristics (mainly

pressure & CO

concentration), capture technology,

power & steam sourcing costs. The estimated CO

capture cost curve for demo scale carbon capture

projects in each sector is provided below,

considering a reference plant size for each sector

and CO

delivery and disposition at 100 bar (a).

capture cost is the lowest for the gasification

process, as carbon capture is already integrated

within the process. So, the additional cost is only

around Rs. 400/tonneCO

, required for polishing and

compression of the CO

stream. The capture costs

for other production processes like SMR-based H

production, iron & steel, cement, etc. include the

costs for gas processing, carbon capture, and

compression and are hence higher.

Carbon capture costs are amongst the highest for

coal-based power plants, due to the low

Figure E-3: Cost Curve for CO

Capture

Across Industries/Sectors

1000

400

4100

0 1 2 3 4 5 6 7 8 9 10 11 12

mtpa

2000

3000

4000

5000

6000

Gasification based product

Cement

Iron & Steel

Coal based power

Refinery & Chemical

SMR based H

Note: The CO

capture costs depicted above include costs for

capture, conditioning and compression to 100 bar (a) and the

amortized capital costs

Converting Captured CO

Value Added Products -

Opportunity to Profitably

Abate CO

Emissions

Carbon utilization technologies can provide a wide

variety of opportunities to convert the captured CO

to value-added products with a ready market in

India, thus contributing to the circular economy. The

most promising utilization pathways are:

a. Green urea: Green urea can be produced from the

captured CO

and cost-competitive green

hydrogen, from renewable energy based

electrolysis of water. Green urea can

replace/complement the traditional LNG/NG

based production and import of ammonia and

urea. The total urea consumption in India is over

30 mtpa, and thus green urea provides a

significant opportunity for CO

utilization at scale.

b. F&B applications: CO

is utilized in F&B

applications such as carbonated drinks, dry ice,

and modified atmosphere packing; however, the

scales are much lower compared to green urea.

c. Building materials (concrete and aggregates):

There is a large market for aggregates and

concrete in a developing country like India,

providing a pathway for utilizing CO

for producing

building materials through concrete curing and

aggregate formation. In these applications

injected in a liquid state without any conversion,

thus reducing the energy requirements.

Additionally, large quantities of wastes such as

steelmaking slag are available as sources of

CaO/MgO, which can be utilized to produce

synthetic aggregates.

d. Chemicals (methanol and ethanol): Conversion

of CO

to methanol and ethanol from CO

proven at a commercial scale in different parts of

the world.

concentration of CO

in the power plant flue gas

stream. However, given the share of the power

sector in overall emissions, demo scale CCUS

projects in the power sector are also essential for

CCUS to meaningfully contribute to decarbonization

in India.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Methanol and ethanol both have important fuel

substitution applications; additionally, methanol is

an intermediate for the production of value-added

chemicals like acetic acid, MTBE, DME, and

formaldehyde, all of which have multiple

downstream applications and offer significant

import substitution opportunities. The conversion

of CO

to chemicals thus provides a large-scale

utilization and disposition pathway, given the

scale and potential of the downstream chemicals,

and can also help in reducing India’s import bill,

thus laying the foundation for an

economy.

e. Polymers (including bio-plastics): Conversion of

to various polymers has been attempted

globally at different scales, and presents another

possible CO

utilization route. These polymers

have multiple applications, such as laptop

packaging, cell phone casings, furniture etc. and

provide an interesting futuristic optionality for

utilization and conversion.

f. Enhanced Oil Recovery (EOR): CO

based EOR

has been successfully operating for decades for

producing low-carbon oil from maturing oil fields

in North America and other geographies. For

carbon capture projects in India with proximity to

oil fields, CO

EOR can play a role in residual oil

extraction that is environmentally sustainable and

economically feasible.

The technology, scale and economics for commercial

deployment are important determinants of how

existing carbon utilization technologies as well as

new technologies develop in India and compete in

markets. Policy support for carbon utilization and

conversion technologies through offtakes, PLI, price

support and R&D incentives will be necessary for

carbon utilization markets to develop.

However, one needs to be cognizant of the fact that

even with developed carbon utilization technologies,

the impact of carbon conversion technologies on

carbon abatement through carbon capture and

utilization will be modest. The sheer scale of CO

emission abatement requires that sequestration be

an essential complement to carbon utilization

technologies in the CCUS value chain.

Promoting Innovation,

Development, Transfer and

Adoption of CCUS

Technologies is Key to Rapid

Decarbonization in India

Government support and incentivization are needed

to promote the adoption and development of CCUS

technologies at a commercial scale in India.

A multi-pronged approach is recommended:

a. Technology transfer: Technologies for carbon

capture, CO

sequestration and EOR have been

demonstrated at a commercial scale for almost 50

years in many parts of the world and particularly

the US. While the development of indigenous

technologies is certainly desirable, the immediate

focus should be on the transfer, assimilation and

adoption of proven TRL 8 and 9 technologies in

the CCUS domain. The Government of India may

fund CCUS demonstration projects in sectors such

as coal-based power, steel, cement, refining &

petrochemicals based on commercially proven

technologies, thus reducing the technology risks,

operational risks and costs for CCUS projects in

India and avoiding the reinvention of the wheel.

Engagement with technology suppliers is also

important to ensure the transfer and

indigenization of technology and Intellectual

Property (IP). Policy support for the transfer of

technology and indigenization will not only

support the manufacturing of CCUS equipment for

India at a low cost, but also create export

opportunities.

b. Promoting R&D in novel CO

utilization

technologies: CO

utilization technologies are

relatively less developed, compared to capture

technologies. Technologies which have great

potential for India, such as CO

to methanol and

CO2 to aggregates, are at TRL levels of 4-5 and

6-7 only, respectively. Other propositions such as

to synthetic fuels, polymers and novel

materials like carbon nanotubes are even further

behind on the development curve.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

The Government of India should promote an

ecosystem to foster R&D and innovation in CO

utilization technologies and new products &

applications based on CO

utilization. Similarly, in

the area of capture technologies, the

Government’s policy incentives should encourage

R&D in DAC as a possible future option. The

developments are multi-faceted and given the

difficulty in predicting the innovation and

development trajectory, there is a need to fund,

foster and incubate innovation-based ecosystems

through national centres of excellence such as the

National Centre of Excellence in Carbon Capture

and Utilization at IIT Bombay.

c. Private sector participation: Private sector

participation is essential to promote the transfer

and commercialization of existing CCUS

technologies and also push the envelope for the

development of new and emerging technologies,

particularly CO

utilization technologies.

Public/government funding and favourable

policies are required to incentivize & de-risk CCUS

projects, promote private sector participation and

enable viable CCUS business models and value

chains to emerge. Similar to the US DOE and UK

Infrastructure Bank’s support for the development

of novel technologies and projects in CCUS, India

also needs government institutional frameworks

and grants to strategically support new and

emerging CCUS technologies, as well as CCUS

projects across the full project/funding cycle.

Geological Storage is Critical

for CO

Disposition at Scale

For effective CCUS adoption at scale, apart from the

conversion of CO

to useful value-added products, there

needs to be a clear strategy and pathway for the

disposition of the captured CO

through permanent

geological storage. Save any miraculous technological

innovation at the commercial scale for carbon

abatement technologies, the only commercial

large-scale (giga tonne scale) CO

disposition option is

geological sequestration.

The options for the geological storage of CO

include

EOR (Enhanced Oil Recovery), ECBMR (Enhanced Coal

Bed Methane Recovery) and permanent storage options

like saline aquifers and basalt storage. However, the

geological data on the pore space availability in India for

the storage of CO

is limited, especially for saline

aquifers and basaltic storage. In the case of EOR and

ECBMR, the data availability is better given the prior

exploration activities for facilitating hydrocarbon (both

oil & gas and coal) extraction.

Theoretical assessments and estimates by the British

Geological Society and IIT Bombay indicate a large

potential for CO

storage in India, to the tune of 400 –

600 Gt.

However, to make the geological storage of CO

reality, further work needs to be supported by the

Government of India, especially in the areas of

source-sink mapping, pore space mapping,

geological characterization of the most promising

storage regions & basins and developing the CO

storage infrastructure through characterization,

validation and development of commercial scale (at

least 1 mtpa) CO

injection programmes in the

selected sites. Similar programmes have been

funded in the US by the US DOE in the form of a

network of seven Regional Carbon Sequestration

Partnerships (RCSPs), to develop the regional

infrastructure for carbon capture and storage

across seven identified regions of the US.

A review of carbon capture projects around the world

reveals that a policy framework and Government

support for CCUS are key to managing project costs &

risks, incentivizing the private sector and establishing

the CCUS value chain comprising CO

capture,

transportation and storage.

Supportive Incentive Based

Policy Framework is Key to

CCUS Adoption in India

Table E-1: Estimated CO

Storage Capacity in India

3.4 Gt

Total

EOR

ECBMR

Saline

acquifers

Basaltic

formations

Well established in North

America; oil recovery possible

to the extent of 30-60%

3.5 - 3.7 Gt

injected in unmineable coal

seams; further R&D required

before commercial deployment

291 Gt

No economic benefit - but

potential of large scale CO

storage

97 - 315 Gt

More recent developments

vis-à-vis saline aquifers

400 - 600 Gt

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Hub and Cluster Model Critical to Drive CCUS Economics and

Implementation at Scale

Given the cost and risks associated with CCUS projects,

CCUS clusters are necessary to drive CO

capture,

transport and disposition at scale and create a

meaningful decarbonization impact. CCUS clusters

incentivize emission-intensive co-located facilities (both

industrial facilities and power plants) to form a capture

cluster and connect to large-scale CO

storage sites

using oversized shared transport infrastructure (which

can be shared by multiple emitters), as well as options

for utilization of CO

to produce low carbon

downstream products. The anchor project would be

large CO

emitters, viz. a thermal power plant or a large

industrial facility, which can cover the initial

infrastructure costs, thereby reducing the cost for new

joiners to the cluster. Similarly, CO

disposition clusters

can be spread across multiple but reasonably closely

located geological sequestration sites, oil fields for

enhanced oil recovery (EOR) or CO

utilization projects.

A carbon credits-based policy is most suited for a

developing country like India, to incentivize CCUS

adoption and bring down the cost of carbon capture,

establish markets for low-carbon products and

decarbonize India’s large and relatively young

industrial asset base by offsetting carbon capture

costs. The key elements for the recommended CCUS

policy framework for India are:

a. Policy path: CCUS policy in India should be

carbon credits or incentives based, to seed and

promote the CCUS sector in India through tax and

cash credits and provide early stage financing and

funding mechanisms for CCUS projects

b. Hub & cluster business model: The policy

framework should promote the creation of

regional hub & cluster models to drive economies

of scale across the CCUS value chain, with defined

roles for emitters, aggregators, hub operators,

disposers and conversion agents.

c. Low carbon products: Low carbon or

carbon-abated products need to be supported

through preferential procurement in Government

tenders and Production Linked Incentive (PLI)

schemes.

Emitters and storage sites can connect through

storage and transportation hubs, similar to natural

gas hubs for the collection and distribution of natural

gas across different producers and consumers.

The services provided by such hubs would include the

compression and transportation of CO

, and

substantially lower the cost of transportation

infrastructure between emitters and CO

injection points.

Because of the high mobilization and laying expenses,

the economics of CCUS cluster projects in the initial

years is quite challenging due to lower CO

volumes

and the outsized infrastructure created. This can be

overcome through long-term and low-cost financing

through Government support and access to

international clean funds.

d. Environmental and social justice: CCUS policy

should protect communities most affected by

environmental and climate change by ensuring

the distribution of the economic value created by

CCUS and the protection of jobs in traditional

sectors (viz. coal mining etc.) affected by

migration to clean energy systems.

e. Accounting and regulatory framework: To

incentivize carbon capture in different sectors,

there is a need to establish a baseline of regulated

emission levels and allowances for different

sectors, and also adopt a Life Cycle Analysis (LCA)

framework that looks beyond just the direct Scope

1 emissions and takes into account Scope 2 and

Scope 3 emissions and ensures effective carbon

abatement.

f. Risk mitigation: For CCUS policy to be effective

in India and encourage wider and private sector

participation, there is a need to de-risk CCUS

projects by limiting the liability and ownership of

across the CCUS value chain and monitoring

risk through appropriate Monitoring, Verification

and Accounting (MVA) frameworks.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Preliminary analysis shows that there is sufficient

potential for creating regional CCUS clusters in each of

five regions of India (North, South, East, West, and

North-East) and sequestration in deep saline aquifers

has the best potential in all the regions. However, due

to the lack of data on the northern sedimentary basins,

the theoretical storage capacity for the saline aquifers

is low. But as more exploratory activities focused on

storage are undertaken, the storage potential in

the northern region is likely to increase.

Figure E-4: Mega Scale CO

Cluster Model

Aggregator

Disposer

EOR Cluster

EOR

HUB

Conversion

Cluster

MeOH

EOR

Regulated Monopoly

Demand-Supply

Time Contracts

Regulated Monopoly

Emitters

Sequestration

Conv

Conversion

EOR

Enhanced Oil

Recovery

Mineral

Figure E-5: Region-wise Storage Clusters in India

Total Theoretical Storage Capacity of India = 395 - 614 Gt CO

7.21 GT

16.58 GT

10.13 GT

0.22 GT

9.01 GT

Region-wise estimated CO

emission volumes (2030-2050)

Northem Region: 7.65 Gt CO

Saline

aquifer

ECBMR EOR Basalt

7.34

0 0

0.31

Western Region: 388.9 Gt CO

Saline

aquifer

ECBMR EOR Basalt

304.9

0.9

80.8

2.3

Southern Region: 76.3 Gt CO

Saline

aquifer

ECBMR EOR Basalt

75.2

0.3 00.8

North-Eastern Region: 47.2 Gt CO

Saline

aquifer

ECBMR EOR Basalt

46.5

0 00.7

Eastern Region: 47.2 Gt CO

Saline

aquifer

ECBMR EOR Basalt

67.2

2.4 10.980

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Carbon Capture Finance Corporation of India –

Institutional Mechanism to Support CCUS Project

Funding, Capital and Cash Costs

Financing CCUS projects can be quite challenging in

a developing country like India, even with incentive

and credits-based policy support. For CCUS to take

off in India, it is important to fund and support initial

demonstration scale CCUS projects. The typical

capital cost and cash costs for CCUS projects in

different sectors can be quite different, depending

on the source and quality of the gas stream and the

extent of CO

capture targeted, as shown below.

While the funding for the initial demonstration

projects can be achieved through direct Government

grants and funds, for CCUS to reach scale in India, it

is also important to understand the CCUS

investment requirements over a long-term horizon

and establish a financial framework such as a Carbon

Capture Finance Corporation (CCFC) to support

CCUS projects across their lifecycle. This is

important as CCUS provides an unmatched

opportunity for turbocharging the growth of the

Indian economy by creating a clean-energy based

industrial sector, potentially leading to the

development of new technologies, skills and

high-value employment opportunities in India.

Table E-2: Sector-wise Typical Carbon Capture Capital Charge and Cash Cost

Industry

name

Ref. Plant

capacity

CCU capacity

(mtpa)

Capital Charges

(A), Rs./T

Cash Cost

(B), Rs./T

Total Capture Cost

(A+B), Rs./T

Capital Costs,

Rs. crores

Gasification

based

production

70 ktpa H

1 mtpa Rs. 80-100

Crore

90-120 250-300 340-420

NG based

SMR for H

production

130 ktpa H

0.7 mtpa Rs. 700-800

Crore

900-1,200 1,150-1,400 2,050-2,600

Cement 2.5 mtpa

clinker

2 mtpa Rs. 1,600 to

1800 Crore

800-1,000 1,050-1,600 1,800-2,600

Iron and

Steel

2.0 mtpa

BF-BOF

based ISP

2 mtpa Rs. 1,600-2,000

Crore

1,000-1,300 1,900-2,300 2,900-3,600

Refinery

(CDU & FCC)

5 mtpa crude

processing

1 mtpa Rs. 1,100-1,300

Crore

1,200-1,400 2,700-3,100 3,900-4,500

Coal-based

power

800 MW 5 mtpa Rs. 3,500-4,000

Crore

700-1,000 2,100-2,500 2,800-3,500

Total 11.7 mtpa Rs. 8,600 –

10,000 Crore

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

It is estimated that out of the total emissions

emanating from sectors such as coal-based power,

steel, cement, upstream oil & gas operations,

refineries, chemicals, hydrogen production and

gasification, about 85% will be capturable through

CCUS projects. Based on the trajectory of economic &

industrial development in India and the concomitant

growth in CO

emissions, it is expected that the

capturable emissions will reach about 2400 mtpa by

the year 2050, the year by which India has committed

to halving its emissions. For CCUS to make a

meaningful contribution to this lofty and laudable

goal, it is envisaged that CCUS projects should capture

at least 30% of the capturable emissions of 2400

mtpa, i.e. around 750 mtpa. To sufficiently incentivize

CCUS projects at the envisaged scale, the following

subsidies are suggested:

a. Subsidy for CO

sequestration/storage:

Rs. 4,100/tonne till 2040 and Rs. 3,000/tonne

till 2050

b. Subsidy for CO

EOR: Rs. 3,000/tonne till 2040

and Rs. 2,400/tonne till 2050

c. Subsidy for CO

utilization: Rs. 2,300/tonne

till 2050

The above subsidy amounts have been estimated

based on the likely CCUS costs in the Indian context

and the likely trajectory of cost reduction from the

increasing scale of CCUS projects, and also the

revenue streams from CO

EOR or the coversion of

to value-added products.

The total subsidy amount required by the year 2050 to

support 750 mtpa of CCUS is estimated to be around Rs.

210,000 crores. While this is a very significant amount, it

is a necessary expenditure required to support CCUS

and ensure the sustainability of the Indian economy. It is

proposed that the proposed CCFC be developed as a

financial institution to fund CCUS projects through

equity and debt participation, with the objective of

supporting and realizing the carbon neutrality goal. The

CCFC will be funded by low-cost sovereign or

International Green Funds, Carbon Bonds or Climate

Funds. By investing in CCUS projects, along with the

utilization of a part of the incremental tax revenue

generated, it should be possible to fund the carbon

capture credits, eventually leading to subsidy-neutral

CCUS operations. Two alternate mechanisms are

proposed to fund the CCFC.

a. Option 1: CCUS financing through ‘Clean Energy

Cess’ only

It is assumed that CCUS will be funded by the

Clean Energy Cess’ levied on coal. The ‘Clean

Energy Cess’ on coal @ USD 5.3/tonne (Rs. 400

per tonne) will be re-introduced from 1 April 2026,

as the GST compensation cess has been extended

till 31 March 2026. India’s coal and coke

consumption is expected to increase from the

current 1,050 mtpa to around 1,200 mtpa by 2030

at a 2% CAGR. Accordingly, the annual cess

collection is estimated to be around USD 6-7 BB$

(Rs. 48,000 – 53,000 crores). The surplus funds in

the initial period creates an opportunity for the

corpus to grow significantly through re-financing

through appropriate investment vehicles.

Table E-3: CCUS Funding through Clean Energy Cess

Year Fund. Req.,

Thou. crore

Fund available,

Thou. crore

Surplus/Shortfall,

Thou. crore

2023 - 23 23

2030 15 169 154

2040 89 603 514

2050 210 225 15

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

b. Option 2: CCUS financing through bond and gross

budgetary support

The government budget and bonds will finance the

subsidy (cash and tax credits) required for CCUS. It

is estimated that 30.5 BB$ (Rs. 2,29,000 crores) of

bonds with a 9% spread in re-investment return,

along with a maximum of 0.5% of the Government’s

spending or the ‘Gross Budgetary Support (GBS)’

can finance 750 mtpa of CCUS by 2050.

It is proposed that the bonds will be raised from the

low-cost national/international bond market and

invested in green projects in India with an assured

return of 9% spread. While the bonds will be raised

and re-invested in the initial years, projected

utilization has been estimated to limit the

government spending on CCUS to be about 0.5% of

the ‘Gross Budgetary Support’.

Table E-4: CCUS Funding with Bonds and Government Budgetary Support

Year Fund. Req.,

Thou. crore

Bond with Return,

Thou. crore

Gross Budgetary Support (GBS),

Thou. crore

2023 - - -

2030 15 - 15 (0.2% of GBS)

2040 89 36 53 (0.4% of GBS)

2050 210 107 103 (0.5% of GBS)

CCUS projects will require upfront capital

investments of US$ 100-150 billion [2022 dollars] for

750 mtpa of CO

capture, utilization, and storage.

These investments will develop the market for CO

and the positive impact on the Indian GDP is

estimated as US$ 100 to 150 billion over the next 30

years, based on the envisaged improvement and

indigenization of CCUS technology.

In particular, CCUS-enabled coal gasification projects

will generate clean value-added products like

methanol, ammonia, acetic acid, mono-ethylene

glycol, etc. and reduce their imports significantly.

India imports almost US$ 13 billion per annum of

organic chemicals and it is estimated that the

CCUS will have a Material Positive Impact on GDP, Employment

Growth, Energy and Material Security, and Import Substitution

indigenous production of these coal-based chemicals

can replace US$ 7-10 billion of imports by 2050 and

also contribute to the domestic GDP.

CCUS projects will also lead to significant

employment generation, both during the construction

phase and the operating phase, as well as create

significant indirect employment and shape the future

economic development of nearby areas. It is

estimated that the envisaged CCUS target of 750

mtpa by 2050 can create employment opportunities

of 8-10 million full time equivalent (FTE) years in a

phased manner, thus creating a compelling case for

investment in CCUS projects.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Executive Summary

Chapter 1

Introduction

1.1 Background

India is the 3rd largest emitter of CO

in the world

after China and the US, with estimated emissions of

2.6 gigatonne per annum (gtpa) in 2019, which

marginally reduced to 2.45 gtpa in 2020 due to the

impact of the COVID-19 pandemic. India’s per capita

emissions are about 1.9 tonnes per annum, which

is less than 40% of the global average and about

one-fourth of that of China. However, with rapid

economic growth, infrastructure and industrial

development, as well as a growing population

(expected to overtake China in the next decade and

cross 1.50 billion by 2036), the total CO

emissions is

expected to cross 4 gtpa by the year 2030. The

sectoral break-up of the CO

emissions reveals that

while renewable energy is making great strides in

India, it can theoretically contribute at most 30% of

the desired decarbonization by replacing fossil

fuel-based power generation.

What is CCUS?

The International Energy Agency (IEA) defines Carbon

Capture, Utilization and Storage (CCUS) as a group of

technologies for capturing of CO

from large and

stationary CO

emitting sources, such as fossil fuel

based power plants and other industries. CCUS also

involves the transport of the captured CO

(typically

by pipeline and in certain situations by through

shipping, rail or trucks also) to sites, either for

utilization in different applications or injection into

geological formations or depleted oil & gas fields for

permanent storage and trapping of the CO

CCUS also includes Direct Air Capture (DAC), which

involves the capture of CO

directly from the

atmosphere, although the same is not the focus of this

study, as DAC is still in its early stages and the

economics (present cost of DAC is estimated to range

between US$ 400-800/tonne of CO

) and scale of

operations are yet to be established.

Decarbonization Challenge and the Role of CCUS

The decarbonization challenge for India is to identify

scalable and economically sustainable solutions for

the decarbonization of sectors that contribute to 70%

of emissions. CCUS has an important and critical role

to play, especially for India to accomplish net-zero by

2070, as envisioned by the Hon’ble Prime Minister of

India. Though the target date is five decades away, as

the noted author Vaclav Smil has documented in his

work, energy transitions take decades. It is therefore

important to implement the framework and policy

instruments for CCUS to become a reality in India and

make a meaningful contribution to decarbonization

in India.

Figure 1.1: The 70% Emissions Challenge

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

Industry

Agriculture

Transport

Building

Electricity

31%

~30%

2.6

gtpa

~70%

India

This study has been prepared by M. N. Dastur & Co. (P)

Ltd. and Dastur Energy Pvt. Ltd., under the tutelage of

the National Institution for Transforming India (NITI

Aayog), Government of India and aims to provide the

policy framework and deployment mechanism for

CCUS at scale to become a reality in India. This study

focuses on CCUS for large point CO

emission sources

(with >100 ktpa of CO

emissions) such as coal based

power plants and industrial applications. CO

emissions from sectors such as agriculture,

transportation and buildings are distributed and

require interventions related to change in fuel (viz.

biofuels), electrification, enhancing thermal &

electrical efficiencies and are outside the purview of

this study.

In particular, industrial applications are hard to

electrify, and industrial CO

emissions are hard to

abate due to the use of fossil fuels not only as a

source of energy but also within the process itself.

Carbon Capture Utilization and Storage (CCUS) also

has applications for the power sector, given India’s

present reliance on coal for meeting over 70% of its

electricity needs; even in the future, if India is able to

substantially green the grid power and meet the

target of 500 GW installed capacity of renewables by

2030, there would still be a need to meet the baseload

power demand from fossil fuels (most likely coal) or

other dispatchable sources, given the intermittency

and non-dispatchable nature of solar and wind power.

Thus, CCUS also has a role to play in enabling clean

and green baseload power and ensuring the

sustenance and non-stranding of our over 210 GW of

coal and lignite based thermal power plants.

In their September 2020 report, the International

Energy Agency points out that reaching net-zero

without CCUS is virtually impossible. The

Intergovernmental Panel on Climate Change (IPCC)

also concludes that without CCUS, it would not be

possible to stabilize the CO

concentration in the

atmosphere between 450 – 750 ppmv (parts per

million by volume) and limit global temperature

rise between 1.5 to 2 degrees Celsius above

pre-industrial levels.

The adverse climatic effects of a rise in GHG

emissions and global temperatures rises are well

established and proven, and India too has not been

spared from adverse climatic events. As a signatory

of the Paris Agreement 2015, India has committed to

reducing emissions by 50% by the year 2050 and

reaching net zero by 2070. Given the sectoral

composition and sources of CO

emissions in India,

CCUS will have an important and integral role to play

in ensuring India meets its stated climate goals,

through the deep decarbonization of energy and CO

emission intensive industries such as thermal power

generation, steel, cement, oil & gas refining, and

petrochemicals. CCUS can enable the production of

clean products while utilizing our rich endowments

of coal, reducing imports and thus leading to an

Indian economy. CCUS also has an important

role to play in enabling sunrise sectors such as coal

gasification and the nascent hydrogen economy

in India.

1.2 Global CCUS Landscape

Globally there are about 21 CCUS facilities, with a

capacity of capturing about 40 mtpa of CO

or only

0.1% of the 40 gtpa global annual GHG emissions. The

first CCUS projects started in the 1970s and 1980s in

Texas for capturing CO

from natural gas processing

plants and supplying it to local oil producers for

utilizing the CO

for Enhanced Oil Recovery. Since

then, CCUS has spread to other regions and countries,

viz. Norway, Canada, Australia, Brazil, Canada, China,

Saudi Arabia and the United Arab Emirates. A list of

the operating CCUS facilities as of 2020 is tabulated in

Table 1-1. The extent of public funding support

provided to these CCUS facilities (where applicable) is

also provided.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

Table 1-1: Large Scale CCUS facilities in operation in 2020

Country Project Operations CO

Public Funding CO

capture CO

start source funding sources capacity disposition

(mtpa)

USA

1972Terrell natural gas plants

(earlier Val Verde)

Natural gas

processing

No 0.5 EORCapital cost: US$

27.6 mn

USA

1982Enid fertiliser Fertilizer

production

0.7 EORNot available

Norway

2008Snohvit CO

storage

project

Natural gas

processing

No 0.7 StorageNot available

USA

2013Lost Cabin Gas Plant Natural gas

processing

No 0.9 EORProject cost –

US$ 400 mn

USA

2013Coffeyville

Gasification

Fertilizer

production

No 1.0 EORNot available

Brazil

2013Petrobras Santos Basin

pre-salt oilfield CCS

Natural gas

processing

No 3.0 EORNot available

Saudi Arabia

2015Uthmaniyah CO

-EOR

demonstration

Natural gas

processing

No 0.8 EORNot available

Canada

2015Quest Hydrogen

production

Yes 1.0 StorageProject cost-

CAD 1.35 bn

Federal Govt. support

– CA$ 120 mn

Alberta Govt. –

CA$ 745 mn

Canada

2014Boundary Dam CCS Power

generation

(coal)

Yes 1.0 EORProject Cost –

CA$ 1.35 bn

Federal Govt.

support – CA$

240 mn

USA

2010Century plant Natural gas

processing

No 8.4 EORProject cost –

US$ 1.1 bn

USA

2013Air Products steam

methane reformer

Hydrogen

production

Yes 1.0 EORProject cost –

US$ 431 mn

US DOE funding –

US$ 284 mn

(through the

American

Recovery and

Reinvestment Act)

Norway

1996Sleipner CO

storage

project

Natural gas

processing

No 1.0 StorageProject cost –

US$ 100 mn

USA/Canada

2000Great Plains Synfuels

(Weyburn/Midale)

Synthetic

natural gas

Yes 3.0 EORProject cost –

US$ 80 mn

US DOE funding –

US$ 3 million

Canadian Govt.

funding- US$ 2 mn

USA

1986Shute Creek gas

processing facility

Natural gas

processing

No 7.0 EORInitial cost – US$

170 mn

Expansion cost –

US$ 80 mn

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

Country Project Operations CO

Public Funding CO

capture CO

start source funding sources capacity disposition

(mtpa)

UAE

2016Abu Dhabi CCS Iron and steel

production

Yes 0.8 EORPipeline capex –

US$ 200 mn

USA

2017Petra Nova Power

generation

(coal)

Yes

1.4 EORProject cost –

US$ 1 bn

US DOE –

US$ 167 mn

NRG Energy –

US$ 300 mn

JX Nippon – US$

300 mn

Debt funding from

Japan Bank for

International

Cooperation &

Mizuho Bank –

US$ 250 mn

USA

2017Illinois Industrial Ethanol

production

Yes

1.0 StorageProject cost –

US$ 208 mn

US DOE support –

US$ 142 mn

China

2018Jilin oilfield CO

-EOR Natural gas

processing

0.6 EORPhase 1 cost –

US$ 11 mn

Canada

2020Alberta Carbon Trunk

Line (ACTL) with

Agrium CO

stream

Fertilizer

production

0.3 - 0.6 EORCapital cost –

US$ 27.6 mn

Capital cost –

US$ 27.6 mn

Canada

2020ACTL with North West

Sturgeon Refinery

stream

Hydrogen

production

1.2 - 1.4 EOR

Australia

2019Gorgon Carbon

Dioxide Injection

Natural gas

processing

3.4 - 4.0 StorageProject total cost –

US$ 55 bn

Injection capex –

US$ 2 bn

Commitment from

Australian Govt. –

US$ 60 mn

Note: Large scale CCUS: at least 0.8 mtpa of CO

capture for coal based power plant and at least 0.4 mtpa for other industrial facilities, including NG based power

Source: International Energy Agency, MIT database, Dastur research

CCUS deployment has mostly been concentrated in

the US, due to the low cost of capture from NG

processing facilities, CO

demand for EOR, CO

pipeline networks and Government funding for CCUS.

The 2010 to 2020 time period was largely a decade of

misses for CCUS, with CCUS capacity only reaching 40

mtpa, vis-à-vis the IEA 2009 roadmap of 100 CCUS

projects with a capture capacity of 300 mtpa.

However, recent years have seen renewed global

interest in CCUS, particularly after the Paris climate

agreement of 2015, global focus and pledges on

reaching net-zero and the realization that renewable

energy can only solve a part of the decarbonization

challenge. Over 100 new CCUS projects have been

announced in the recent past, which are expected to

become operational by 2030 and take the aggregate

carbon capture capacity to 150 mtpa. These projects

span across regions (including many developing

countries) and are geared towards a diverse mix of

applications and disposition options.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

1.3 Decarbonization

Through CCUS

1.4 The CCUS Value Chain

CCUS can contribute to decarbonization and transition

to clean energy systems in various ways:

a. Hard-to-abate sectors: CCUS offers the only

known technology for the decarbonization of

hard-to-electrify CO

intensive sectors such as

steel, cement, oil & gas, petrochemicals &

chemicals, and fertilizers. These sectors are

important to the continued growth of the Indian

economy and for ensuring energy, materials and

food security. The maturity of technology

development in these sectors portends the

continued use of fossil fuels and concomitant CO

emissions from these sectors in the foreseeable

future, thus making CCUS critical in these sectors.

b. Low carbon hydrogen economy: CCUS is

expected to play a major role in enabling the

hydrogen economy in India, through the

production of blue hydrogen based on the

utilization of our rich endowments of coal. Given

the current cost structure of green hydrogen of

US$ 5-6/kg, cost competitive blue hydrogen

production (i.e. coal gasification based hydrogen

production coupled with CCUS) at around US$

2/kg can provide a pathway for the hydrogen

economy in the future.

c. Removal of the CO

stock from the atmosphere:

The race towards net zero and containing global

temperature within 1.5 degrees from pre-industrial

levels is not possible without the removal of

excess CO

from the atmosphere through Direct

Air Capture (DAC). DAC plants are in operation at

a small scale, due to their prohibitively high cost

of operations. With technological innovation and

focused policy interventions, CCUS through DAC

applications is also expected to have a role in the

net-zero transition journey.

d. Sustenance of existing emitters: Existing

thermal power plants and industrial plants (such

as steel and cement production facilities) can be

retrofitted with CO

capture infrastructure. Nearly

two-thirds of India’s 210 GW of coal-based power

capacity and 144 mtpa crude steel capacity have

an age of less than 15 years and cannot be just

Carbon capture has a critical role to play in the

decarbonization of hard to abate sectors and the path

towards the net zero transition. However, in order to

deploy carbon capture at scale, it is important to look

beyond just carbon capture technologies, and

holistically look at the CCUS value chain. The CCUS

value chain consists of three basic components

(source: Medlock, III, Kenneth B. and Keily Miller,

“Expanding Carbon Capture in Texas”, Baker Institute

Center for Energy Studies, January 2021):

i) Capture of carbon dioxide (CO

) from fuel

combustion or industrial gas streams,

compression, dehydration & purification of CO

the desired specifications;

ii) Transport of the CO

(generally via pipeline) to the

sink

iii) Disposition of the CO

, either through utilization

in applications such as Enhanced Oil Recovery

(EOR), food and beverage applications, or the

production of value-added products (viz. urea,

green methanol, cured concrete) or through

sequestration of CO

in permanent

geological storages

The success of the CCUS value chain depends on the

actors in each part of the CCUS value chain acting in

close coordination with each other. In order to

incentivize coordination between actors across the

CCUS value chain, there is a need for an appropriate

enabling policy framework and business model.

wished away or stranded and need to be made

sustainable through the application of CCUS.

Significant economic costs and damages can be

avoided by ensuring the sustenance of existing

emitters through the implementation of CCUS. As

per estimates provided in the article

“Understanding initial opportunities and key

challenges for CCUS deployment in India at

scale” by Professors Vikram Vishal, Debanjan

Chandra, Udayan Singh, Yashvardhan Verma, by

year 2050, about US$ 6 billion/year of economic

damage can be avoided through CCUS.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

1.5 CCUS in India

Presently carbon capture in India is confined to

certain industries/applications where the carbon

capture is part of the process, viz., the manufacture of

urea. India’s urea production is about 24 mtpa, where

capture CO

is utilized in the ammonia to urea

conversion process. CO

is also captured as part of the

gas conditioning process in the gasifiers of Reliance

Industries Limited in Jamnagar (10 mtpa of petcoke

gasification capacity) and JSPL in Angul (2 mtpa of

coal gasification capacity), but the CO

is largely

released to the atmosphere and not utilized or stored.

While there are few pilot scale carbon capture projects

(viz. IOCL R&D’s amine and biological enzyme based

carbon capture plant and Tata Steel Jamshedpur’s

pilot scale carbon capture plant for capturing 5 tonnes

per day CO

from Blast Furnace gases), there are no

commercial-scale dedicated CCUS projects in India.

While the sustainability of operations and carbon

footprint is a major concern for the promoters and top

management of most industries, the main impediments

to companies investing in CCUS projects are the lack of

any policy incentives and framework, lack of a viable or

established business model with independent players

providing services for the transportation and

disposition of CO

and lack of established pathways &

options for the utilization or storage of CO

at scale.

Given India’s climate and CO

emission reduction

commitments, there is a need to design and establish

a robust and effective CCUS policy framework to

enable projects across the CCUS value chain and at

scale for the major industrial sectors of the Indian

economy like power, steel, cement, chemicals, and

petrochemicals.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

1.6 Objectives of the Study 1.7 Structure of this Study

This study consists of the following chapters:

Executive Summary

Chapter 1 : Introduction

Chapter 2 : Analysis of Sector-wise CO

Emissions

Chapter 3 : Overview of CO

Capture &

Utilization Technologies

Chapter 4 : Potential for CO

Storage in India

Chapter 5 : CCUS Policy Framework for India

Chapter 6 : Investment and Financing Mechanism

Chapter 7 : Conclusions

1.8 Acknowledgement

We express our sincere gratitude and grateful

acknowledgement to the NITI Aayog, and especially

Dr V. K. Saraswat (Member, NITI Aayog), Shri Rajnath

Ram (Adviser – Energy) and Shri Jawahar Lal (Deputy

Chief Engineer, Energy) for the guidance and

cooperation extended during this study.

Against this backdrop, this study seeks to formulate a

framework for CCUS policies in India and a viable

economic model for CCUS adoption and

implementation in various industries and sectors. The

objectives of the study are as follows:

a. Recommend the most suitable CCUS policy

instrument & path for India, i.e. whether to pursue

an incentive or cash & tax credits based policy

(similar to the USA) or a carbon tax based policy

(similar to the EU)

b. A CCUS cluster framework: cluster design and

infrastructure to process, store, sell and transport

through centralized processing at each

cluster.

c. Creation of a CCUS business model, institutional

framework & opportunity: to provide a market and

an effective price/premium for low-carbon

products.

d. Conceptualize and articulate the need for a CCUS

technology and investment enabling carbon fund

for India, which will enable CCUS deployments to

be financially feasible in India; designing the

structure and deployment mechanism of the same

e. An industrial CCUS financing framework:

development of a CCUS technology and

infrastructure enabling funding mechanism.

f. Assessment of the socio-economic impact -

promoting new industries and job creation with a

reduction in overall GHG emissions

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Introduction

Chapter 2

Analysis of Sector-wise

Emissions

2.1 Introduction

The total CO

emissions from a system can be

categorized into three types (Figure 2-1)

a) Direct or scope 1 emissions: Emissions from the

production process from the combustion of fuel.

This typically occurs within the plant/facility

premises.

b) In-direct or scope 2 emissions: Emission

associated with the purchase of utilities. This is

generally an emission outside the plant boundary.

c) In-direct or scope 3 emissions: Indirect emissions

are associated with the entire value chain, starting

from equipment purchase, construction works, raw

material sourcing and product dispatch.

The objective of this chapter is to estimate the

capturable CO

volume within the plant boundary for

different target sectors; accordingly, Scope 1 emissions

have been estimated for the target sectors.

India’s power and industrial sectors contributed

around 1,600 mtpa of CO

emission (around 60%) out

of 2,600 mtpa in 2020. The remaining 40% CO

emissions are contributed by distributed point

emissions sources like agriculture, transport, and

buildings. Since carbon capture, utilization and storage

are not applicable for such sources, this chapter

focuses on power and key industrial sectors. Emissions

from these sectors are expected to increase to nearly

2,300 mtpa by the year 2030, fuelled by industrial

growth across multiple sectors as well as rapid

urbanization. The sector-wise emissions (current and

projected) are shown in Figure 2-2.

Figure 2-1: Illustration of Emission Types and Boundary Consideration

1,004

1,210

177

240

450

196

325

2030 CO

emission

125

2020 CO

emission

2,291

102

1,621

Coal Gasifcation

NG based H

production Upstream O&G/Refinery/Chemicals

Cement

Iron & Steel

Power

Figure 2-2: Sector-wise CO

Emissions, mtpa

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

Scope 1

Scope 2

Scope 3

Figure 2-3: Break-up of Installed Generation Capacity, GW

2.2 Analysis of Major Industrial CO

Sources (Power, Steel,

Chemicals, Cement & Gasification) in India

2.2.1 CO

Emissions: Indian Power Industry

2.2.1.1 Introduction

Being the third-largest producer and second-largest

consumer of electricity, the Indian power sector plays

a major role in the world energy scenario (IBEF, 2021).

India generated a total of 1382 TWh of electricity in FY

2020-21, about 2.5% less than the total generation in

FY 2019-20 (Ministry of Power Annual Report,

2020-21).

Given our rich endowments of coal, the major portion

of power demand is met by coal and lignite based

thermal power plants, along with power plants based

on other fossil fuels (natural gas and diesel). At the

same time, the last decade has seen considerable

additions of renewable energy generation capacity to

the energy mix, towards the path of achieving India’s

goal of achieving 175 GW of renewable energy capacity

by 2022 (IEA, India Energy Outlook, 2021). India has

also committed to generating 40% of electricity in the

future from non-fossil fuel sources (IEA, India Energy

Outlook, 2021). While the share of fossil fuel-based

energy is expected to reduce going forward, energy

demand is also expected to increase significantly from

the present levels, i.e., 25-30% by 2030 and 60-70%

by 2040 (IEA, India Energy Outlook, 2021). The major

share of the power demand will continue to be met

from coal in the foreseeable future, in order to secure

India’s energy security and ensure electricity for every

household. Thus, the power sector will continue to be a

major source of GHG emissions, and hence CCUS is of

prime importance for the abatement of CO

from

the sector.

2.2.1.2 Installed Capacity and Power Generation

As of January 2022, India’s total electricity generation

capacity was 395 GW, including 106 GW of renewable

energy capacity (Figure 2-3). Fossil fuels like coal,

natural gas, lignite, and diesel) contribute to almost

60% of total generation capacity, with coal-based

thermal power capacity alone accounting for around

52% (203 GW). The installed capacity of renewables

like solar, wind, biomass, etc. has increased significantly

in the last two years. Renewable capacity has increased

from 86 GW to 106 GW, an increase of 23% whereas

total capacity has increased by only 7%.

Thermal

236,

60%

Nuclear,

7, 1%

Hydro,

47, 12%

RES,

106,

27%

369

377

395

106

Jan-2020 Jan-2021 Jan-2022

Total RES

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

Source: CEA

Figure 2-6: PFD of Coal-fired TPP [Reproduced from (Breeze, 2019)]

Figure 2-4: Break-up of Generation, Billion Unit

(Ministry of Power Annual Report, 2020-21)

Though renewables contribute to around 30% of the

current capacity mix, due to their intermittent and

non-dispatchable nature, their share in power

generation was only 11% in FY 2021-22 (Figure 2-4).

Thus going forward also, even as India targets to

reach 450 – 500 GW of renewables capacity by the

year 2030, coal-based power generation will continue

to play an important role in the power mix of India.

2.2.1.3 Brief Description of Thermal Power Plants

The basic principle behind the working of a thermal

power plant is that they generate electricity using the

thermal energy from the combustion of fuels. Based

on the type of fuel used, thermal power plants can be

divided into four categories, coal, natural gas, lignite,

The process flow of power generation from coal

(process flow for lignite is also similar) and natural

gas-based power plants is described below.

a) Coal-fired thermal power plant

Coal-fired thermal power plants generate electricity

by burning coal as a fuel and using the heat to

produce steam from water. The steam is used to

generate electricity by passing through a steam

turbine generator. The various unit operations

involved in this process are illustrated in Figure 2-6

(Breeze, 2019).

Thermal, 913, 74%

Nuclear,39, 3%

Hydro,134, 11%

Bhutan, 7, 1%

RES, 141, 11%

Figure 2-5: Break-up of Thermal Power Plants by

Fuel (Power Sector at a Glance ALL INDIA)

and diesel. The share of diesel-based power capacity

in India is minimal; the major share of capacity is from

coal-powered thermal power plants, followed by

natural gas.

Coal, 203.9, 86%

Lignite, 6.6, 3%

Gas, 24.9, 11%

Diesel, 0.5, 0%

SlurryFly ash

Coal

Steam

Turbine

Warm water

Cold water

Condenser

Ash disposal

Stack

Water

Exhaust

Gas

Air

Coal

Pulverizer

Boiler

Selective Catalytic

Reduction Reactor

Electrostatic

Precipitator

Scrubber

Generator

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

Coal is received at the material handling yard and

thereafter undergoes crushing and beneficiation to

reduce the size/moisture/ash content, depending on

the quality and size of the coal. The coal is then

pulverized to coal fines that can be efficiently

combusted in the boiler. This pulverized coal is mixed

with air in the combustion chamber and controlled

combustion is performed to produce heat energy.

After the completion of the combustion process, the

ash residue is collected at the bottom of the

combustion chamber and is ejected as slag. The

combustion chamber and boiler are efficiently

integrated to minimize heat loss. The boiler has tubes

present in it, which carry water. The heat energy

released from combustion is absorbed by this water to

turn into steam. This steam is passed through steam

turbines. A series of high pressure (HP), intermediate

pressure (IP) and low-pressure (LP) turbines are

present to extract the maximum heat energy from the

steam. These steam turbines drive the generators to

produce electricity.

The flue gas is subjected to cleaning operations such

as a selective catalytic reduction reactor (for NOx),

electrostatic precipitator (for fly ash), and sulfur

dioxide scrubber. After the flue gas meets the

emission norms, it is emitted through flue gas stacks

in the atmosphere. The only source of Scope 1

emissions is the flue gas stack. The rest of the

operations incur Scope 2 emissions. Typical flue gas

characteristics of a coal-fired thermal power plant are

given in Table 2-1.

b) Natural Gas-fired Thermal Power Plant

Natural gas is a relatively cleaner fuel compared to coal

and has very few impurities. Gas turbine technology is

used to generate power from natural gas (Figure 2-7).

Air is sent to the compressor, where it gets pressurized.

This high-pressure air is sent to the combustion

chamber and mixed with the fuel (natural gas). This

mixture is ignited and the combustion results in hot flue

gases. This flue gas stream then drives the turbine

which is connected with the generator that uses the

kinetic energy to generate electricity. The turbine and

compressor are on the same shaft; thus, the compressor

energy requirement also decreases.

The flue gases released are still at a very high

temperature, indicating that more heat energy can be

extracted from this stream. Thus, the flue gases are

further fed to a heat recovery steam generator. Here,

the heat energy of flue gases is used to generate

steam from water which drives the steam turbine to

generate additional power. This increases the energy

conversion efficiency of plants. This type of plant is

termed as a “combined cycle power plant”. Figure 2-8

illustrates a schematic of a natural gas combined cycle

(NGCC) power plant.

Table 2-1: Flue Gas Characteristics of

Coal-Fired Thermal Power Plants

Figure 2-7: Schematic Representation of

Gas Turbine [Reproduced from (Breeze, 2019)]

Figure 2-8: NGCC Power Plant Schematic Diagram

[Reproduced from (Breeze, 2019)]

Component Unit Value

Temperature °C 150-180

Pressure atm 1

Composition

vol% 12-14

O vol% 8-10

vol% 3-5

vol% 72-77

ppmv 120-200

NOx ppmv 150-250

Fuel

Air inlet

Compressor Turbine

Flue gas

Atmosphere

Steam

Turbine

Generator

Flue gas

Compressor

Air

inlet

Natural

gas

Combustion

chamber

Combustion

chamber

Heat

recovery

steam

generator

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

The Scope 1 emissions are from the flue gas emitted to

the atmosphere at the end of the process. The rest of

the processes may involve Scope 2 emissions. Typical

flue gas characteristics of natural gas combined cycle

(NGCC) power plants are mentioned in Table 2-2.

2.2.1.4 CO

Emissions from the Power Industry

Globally the power sector accounts for the largest

share of GHG emissions; the sector accounted for

42% of the total anthropogenic CO

emissions of the

world in 2019 (IEA). In India, the power sector is

responsible for 51% of total anthropogenic emissions

(IEA). Thus, decarbonization of the power sector is

critical to lowering total anthropogenic CO

emissions

in India.

For the analysis of CO

emissions from the power

sector, merchant power plants (owned by Central

PSUs, State PSUs, JVs as well as private generators),

along with captive power plants of the aluminium

industry, have been considered. The CO

emission

intensity database is provided by Central Electricity

Authority (CEA) (CEA, 2020). The analysis was carried

out for the financial year FY 2021-22, using the actual

plant load factor of 57.02% (till 30 November 2021) to

calculate the emission figures. A total of 271 power

plants were analyzed. These plants have been

analyzed based on their district, state and the prime

mover used. The prime mover can be of 3 types:

steam, gas, and diesel.

Figure 2-9: Share of Total CO

Emissions by

Each Prime Mover, mtpa

Component Unit Value

Temperature °C 100-150

Pressure atm 1

Composition

vol% 4-10 vol%

O vol% 10-12 vol%

vol% 8-10 vol%

vol% 70-75 vol%

ppmv Low

NOx ppmv Low

Table 2-2: Flue Gas Characteristics of

Coal-Fired Thermal Power Plants

Component Value

Total number of power plants 271

No. of days of operation 330

Total emissions (mtpa) (PLF = 100%) 1760.8

Total emissions (mtpa) (PLF = 57.02%) 1,004

Total number of power plants with 159

greater than 2 mtpa CO

emissions

Total number of districts with 10

greater than 20 mtpa CO

emissions

Table 2-3: Overall Analysis of CO

Emissions from

the Power Sector in India

Coal and lignite based power plants use steam as the

prime mover, but have different CO

emission

intensities. An overall analysis is provided in Table

2-3. A minimum capturable CO

of 2 mtpa from a

single source is envisaged to be economically feasible.

For district-level analysis, districts with CO

emissions

(power-related) greater than 20 mtpa have been

considered.

Emissions by Prime Mover

Power plants can be categorized into three types

based on their prime mover, i.e. steam, gas, and

diesel. Coal and lignite have the largest installed

generation capacity in India, followed by natural gas

and a small share for diesel. The contribution of each

prime mover to the total CO

emissions from the

power sector is illustrated in Figure 2-9.

956

1,004

Steam Gas Diesel Total

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Carbon Capture Utilization and Storage (CCUS) –

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Emissions

Prime Mover No. of Total CO

plants Emissions (mtpa)

Steam 155 917

Gas 4 11

Diesel - -

Total 159 928

District Number of CO

Emissions

plants (mtpa)

Singrauli 5 52

Sonbhadra 6 49

Kutch 2 34

Korba 6 34

Nagpur 4 28

Angul 4 27

Raigarh 5 27

Cuddalore 5 25

Janjgir-Champa 4 24

Chandrapur 4 21

Total 45 321

Table 2-4: CO

Emissions by Prime Mover for Plants

with Minimum 2 mtpa Capturable CO

Table 2-5: District-wise CO

Emission Analysis

Figure 2-10: State-Wise Analysis of

Emissions (mtpa)

Considering a minimum of 2 mtpa of capturable CO

from each plant, the above analysis is presented in

Table 2-4.

Power plants with steam as the prime mover (both

coal and lignite-fired) have the highest emissions;

thus, CCUS projects need to be focused on these

plants. The emissions from power plants with gas and

diesel as the prime mover are significantly less and

these plants can be included in the scope of CCUS at a

later stage.

Emission by Region

In order to form a CCUS cluster, it is important to

perform a region-wise emission analysis of power

plants. The aim of the analysis is to identify the

hotspots/clusters of emissions that can be targeted

for CCUS. This would also help define the policy/

credit system suitable for that region. The region-wise

analysis can be carried out based on

a) Districts

b) States

The district-wise analysis yields information about

the highest emitting districts, which can be the focus

of initial CCUS projects in the Indian power sector.

A centralized CO

processing unit can be planned for

these districts, which will make the capture and

transportation of CO

more techno-economically

feasible. Only power plants with minimum CO

emissions of 2 mtpa have been considered in the

analysis. For district-wise analysis, districts that

emit more than 20 mtpa CO

have been considered.

Information about these districts is provided in

Table 2-5.

These districts account for about 32% of the total CO

emissions by the power sector in India.

Implementation of CCUS in these districts will lead to

significant CO

abatement. The state-wise analysis

(Figure 2-10) identifies the states to be prioritized for

CCUS implementation in India. The top 10 states

contribute 75% of the total CO

emission by the

power sector. Thus, incentivizing the implementation

of CCUS clusters through various policy mechanisms

suited to these states will help in quicker adoption &

implementation of CCUS and lead to significant

decarbonization of India’s power sector.

109

107

105

173

Maharashtra

Uttar Pradesh

Chhattisgarh

Madhya Pradesh

Gujarat

Tamil Nadu

West Bengal

Odisha

Andhra Pradesh

Rajasthan

Others

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Component Present (2022) FY 2029-30

Installed Capacity, GW

Thermal 236 (60%) 292 (36%)

Hydro 46 (12%) 66 (8%)

Nuclear 7 (2%) 19 (2%)

RES 106 (26%) 440 (54%)

Total 395 817

Gross Generation, BU

Thermal 913 (74%) 1393 (56%)

Hydro 134 (11%) 206 (8%)

Nuclear 39 (3%) 113 (5%)

RES 141 (11%) 804 (31%)

Total 1,227 2,516

Wtd. avg. CO

emisison intensity, kg/kWh 1.09 0.868

Total CO

emissions from thermal power plant 1,004 1,210

Table 2-6: Energy & CO

Volume Projections for FY 2029-30

2.2.1.5 CO

Emission Projections for the Power sector

According to CEA and IEEFA projections (Gujarat’s

Electricity Sector Transformation, 2019), the installed

capacity in India is expected to more than double and

reach around 820 GW by 2030 from the existing

capacity of around 400 GW. The projection of the

generation capacity by type is given in Table 2-6.

Thermal power (coal + gas) capacity in India is

expected to reach 290 GW by 2030. Although the

share of thermal capacity is expected to drop from the

present 60% to 36% in 2030, thermal power

generation is expected to still account for 56% of the

total electricity generation in India.

2.2.2 CO

Emissions: Indian Steel Industry

2.2.2.1 Introduction

The Indian iron and steel industry is primarily based

on the processing of virgin materials like iron ore,

coal, etc. and is hence an energy-intensive sector,

responsible for about 10% of the total CO

emissions

in India. Production of iron largely through the blast

furnace and coal-based DR route, combined with low

availability of scrap in India, make the Indian steel

industry a coal-intensive sector, leading to an

estimated 240 mtpa of direct CO

emissions for

supporting steel production of 109 mt in 2019. The

The drop in the share of installed generation capacity

of thermal power plants is due to the significant

increase in renewable energy capacity. However,

anthropogenic CO

emissions from the power sector

will still contribute to the majority of CO

emissions in

India. The CO

intensity will also increase in the future

with improved plant performance and PLF, the

retirement of old facilities and the operation of

super-critical or ultra super-critical units. Based on the

contribution of thermal power plants and their CO

emission intensity, the total scope 1 emissions from

thermal power plants is estimated to be around 1200

mtpa in 2030 (Table 2-6).

crude steel capacity and production for the last five

years are shown in Figure 2-11. Steel production has

grown at a compounded annual growth rate (CAGR)

of 6% from FY 2016-17, till the COVID-19 hit both

demand and production in FY 2020-21. However, steel

demand and production has sharply bounced back in

FY 2021-22 and a long term growth rate of 6% is

achievable for India. Steel demand and production in

India is expected to reach about 190 - 200 mtpa by

the year 2030. The share of different steel making

routes is unlikely to significantly change till 2030;

based on the same, CO

emission from the steel

sector is expected to reach 450 mtpa by 2030.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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2.2.2.2 Routes of Iron and Steelmaking in India

There are three steelmaking routes prevalent in India

(i) Basic Oxygen Furnace (BOF); ii) Electric Arc

Figure 2-11: Crude Steel Capacity & Production in Last 5 Years (in mtpa)

Figure 2-12: Process Route Wise Steel Production and Contribution (in mtpa)

128

138

142

144

103

111

109

104

FY16 FY17 FY18 FY19 FY20

Capacity Production

Furnace (EAF), and (iii) Induction Furnace (IF). The

contribution of different routes for the last five years

is shown in Figure 2-12.

FY16 FY17 FY18 FY19 FY20

BOF EAF IF

43%

46%

45%

44%

30%

26%

28%

30%

28%

FY16 FY17 FY18 FY19 FY20

BOF EAF IF

Source: JPC

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Emissions

Almost all the large integrated steel plants have

adopted the BOF route production because of its

robustness, scale, and reliability. The BOF route uses

85-95% hot metal in the charge mix, produced from

Blast Furnace/COREX/FINEX. On the other hand, the

induction furnace route is 100% solid-charge based,

and primarily uses DRI, pig iron, and scrap. IF-based

production is electric-energy intensive and suitable

for small-scale production. The EAF route is flexible

and ideal for mid-sized plants (0.5 to 1 mtpa) and can

be designed to take more than 80% hot metal,

whereas the conventional EAF design is based on

100% solid charge. Due to the operational robustness

& flexibility and superior techno-economics of BFs,

most EAFs in India use a certain percentage of hot

metal in the charge mix.

Figure 2-13: Various Iron and Steel Making Routes in India

In the BF route, iron is extracted as liquid hot metal

from sinter, pellet, and iron ore lumps, with coke and

pulverized coal being used as reductants. In smelting

reduction processes like FINEX & COREX, iron ore

fines and coal are used to produce hot metal. The

alternative iron-making routes encompass the

coal-based and gas-based DR processes that produce

solid iron known as DRI or sponge iron, which is

subsequently melted and refined in the EAF/IF

process. The unit processes are described below,

including the perspective of direct CO

emissions in

each process. An illustration of the various process

routes in India is given in Figure 2-13.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

2.2.2.3 Brief Description of Unit Processes

Coke making

Metallurgical coke is produced at scale

(typically 0.5 mtpa and higher) in

by-product recovery and non-recovery

coke ovens. By product recovery coke oven battery is

the preferred choice for the ISPs, while non-recovery

coke oven is generally adopted by merchant coke

producers. Coking is the process of heating coking coal

at a high temperature in the absence of air to expel its

volatile matter and obtain a strong porous coke.

Metallurgical or coking coal softens, swells, and

hardens with sufficient porosity and strength during

the coking process. The pulverized coal blend is

charged into the ovens and heated at 1100 C for about

16-20 hours (for by-product ovens) or about 45-50

hours (for non-recovery ovens). The hot coke is pushed

out of the ovens into a quenching car that is taken to

quenching stations for cooling before being conveyed

to the blast furnace. In by-product recovery ovens, the

gas coming out from the coking chamber is processed

in a chemical plant to produce clean coke oven gas

(COG) and several by-products such as tar, ammonium

sulphate, phenol, naphthalene and sulphur. Clean coke

oven gas, with high calorific value, is used as a fuel

source in downstream facilities after suitably mixing

with other fuel gases. In the non-recovery ovens, all the

gas emissions are utilized to produce steam, which is

subsequently used in power generation. The total

amount of CO

released from the coke oven flue stack

is estimated to be about 0.3 tonne per tonne of finished

steel.

Sintering

Sintering is a process of agglomeration of

ore fines along with fluxes to improve the

reducibility of the ore material and

decrease coke consumption in the blast

furnace. A sintering machine consists of a

travelling grate with air suction from its bottom all

along its length. A mixture of ore fines, fluxes, and

coke breeze is charged on the travelling grate and is

ignited on the surface by a hood near the beginning of

the strand. Due to the air suction and coke breeze, the

ignition front travels across the depth of the bed,

providing the heat for sintering. Sintering occurs at a

temperature of about 1300 C which results in melting

particles at the surface and agglomeration at the grain

level. At the end of the strand, the hot sinter is passed

through a roll crusher, screens, and coolers. The

off-gas from a sinter plant is released into the

atmosphere after recovery of the sensible heat. The

combustion of coke breeze and fuel gases in the

process contributes to about 0.43 tonne of CO

per

tonne of finished steel.

Pelletization

Pelletization is the process of

agglomerating very fine particles of iron

ore with fluxes, without any incipient

melting. The pelletization process consists of three

main steps: mixing of the feed particles with a binder,

making of raw pellet balls in a drum or disc pelletizer,

and heat hardening of raw pellets in a travelling

grate-rotary kiln-train at around 1300 C. Since the

bonding is established due to diffusion without any

melting, the pelletization process consumes

significantly less energy and emits significantly lower

vis-à-vis sintering.

Ironmaking

Iron making or production of hot metal in

India is primarily through the Blast Furnace

(BF) route; additionally, there are a few

COREX plants in India. In a BF, iron ore lumps and sinter

or pellets is charged from the top of the furnace along

with coke, limestone and dolomite. A hot blast of

preheated air with a temperature of over 900 C is

blown through the tuyeres from the bottom of the BF,

which burns the coke to produce heat and carbon

monoxide (CO). The coke reduces the iron oxide to

metallic iron, while producing BF gas. The fluxes help

the separation of gangue from the ore, thus forming

slag. A high temperature of 1400 C in the hearth of the

furnace enables the tapping of hot metal and slag in the

liquid form. The top gas (BF gas) is collected, cleaned

and cooled. Despite its lower CV, the large volume of

BFG generation makes it an important fuel that is used

in the various furnaces of the steel plant, that require

an external heat source. BF gas is also used in power

production after suitably mixing with other gases like

COG and BOFG. The direct CO

emission from the stove

flue stack accounts for 0.4 tonne of CO

per tonne of

finished steel. The CO

and equivalent CO

from the CO

in BF gas are emitted in the units which consume the

BF gas.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Figure 2-14: CO

Emission (in tonne) per tonne of Finished Steel BF-BOF route

Sinter Plant

0.27

0.39

0.03

66%

0.23

25%

0.63

18%

0.17 2.15

conc.

Coke Oven Blast Furnace BOF Calcining

Plant

Captive

Power Plant

Mills Total

0.43

8% 23% 23%

Basic Oxygen Steelmaking (BOF)

This is a refining process whereby oxygen

is blown through hot metal in a converter

to remove impurities like carbon, silicon

and phosphorous to produce liquid steel. The oxygen

blowing results in the formation of an emulsion of gas,

molten metal and fluxes, leading to high reaction rates

and making this a rapid process. The oxidized impurities

and fluxes form a basic slag that is tapped at the end,

separate from the tapping of steel. To consume the heat

released from the oxidation reactions, scrap or iron ore

is added as coolant. The oxidation of carbon releases CO

and CO

. Due to its high CO concentration, the cooled

and cleaned BOF off-gas is collected for further use.

Liquid steel from the BOF is further refined in

secondary steelmaking units like ladle furnace, VD,

VOD, RH-OB before being sent to the casters for

billet/bloom/slab production.

Rolling Mills

Semis from the steel melt shop are rolled for

production of final products like rebars, wire

rods, structural sections and hot rolled coils.

Cold billets/slabs are charged to a reheating furnace,

fueled by mixed gas, to reheat the semis to around

900-1000

C. The hot semis are passed through multiple

rolling stands before being cooled down in a cooling

station. The Scope 1 emissions are limited to the

reheating furnace flue gas only. It is estimated that 0.17

tonne of CO

per tonne of finished steel will be emitted

from the rolling mill.

Calcining Plant

For the refining of hot metal, calcined lime

and dolo are required in the SMS operations.

For the production of lime and dolo, raw

limestone/dolomite is charged into a kiln (vertical shaft

or horizontal kiln), where calcination occurs at a

temperature of around 1000

C. Heat is supplied by

in-plant fuel gas or purchased fuel. CO

is generated from

the combustion of fuel as well as from the decomposition

of CaCO

. The calcining process contributes around 0.23

tonne of CO

per tonne of finished steel.

Total CO

emission in a typical BF-BOF based ISP is

estimated at 2.15 tonne per tonne of finished steel

(Figure 2-14). The CO

concentration at each unit is

based on the typical specific fuel consumption and

fuel blend.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Coal Based DR Processes (Coal DR)

This route of iron making uses non-coking

coal as a reductant to obtain the solid

product of reduced iron, known as DRI or

sponge iron. DRI is further melted and refined in the EAF

to produce steel. Rotary kiln and rotary hearths are the

two major coal DR processes widely used in India. In the

rotary kiln process, sized lump ore or pellets, coal,

limestone and dolomite are charged from the feeding

end of a rotating kiln, while air and the heating source

are provided at the discharge end of the kiln. The

generation of CO enables the complete reduction of iron

oxide by the discharge end, which is later magnetically

separated out from other solid residues. The limestone

and dolomite calcine, releasing CO

and forming lime and

magnesia that act as desulphurizing agents. A

temperature of around 1000 C is maintained to enable

faster reactions as well as to minimize any fusion of

reaction products. The sensible heat of off-gas

containing N

& CO

is used for the production of power,

through utilization in a waste heat recovery boiler. Since

the coal DR processes involves solid-solid reactions, it is

not as efficient as the countercurrent gas-based blast

furnace process. This results in higher coal consumption

and higher CO

emission intensity.

Gas Based DR Processes (Gas DR)

Natural gas based DR production is a

continuous countercurrent moving bed

process employing vertical shaft furnaces to produce DRI

from lump ore or pellet charge and using reformed

natural gas as the reductant. The principle of iron ore

reduction is similar to the blast furnace, except that there

is no fusion and melting of solid products, thereby using

less energy and emitting less CO

directly. Iron ore pellets

are charged from the top of the shaft while reformed

natural gas is heated and injected from the bottom of the

reduction zone. The gas leaving the shaft from the top

(the top gas) has significant reducing power and calorific

value due to its unutilized CO and H

and is therefore

recycled back to the DR shaft after bringing down the

and N

fractions. The N

is lowered by splitting a

portion of the top gas to be use as a fuel for heating. The

in the remaining stream is lowered either by CO

separation or using the gas for dry reforming of

natural gas.

Midrex and Hyl are two the major gas DR processes

widely employed across the globe, with similar operating

principles. The Midrex process operates at low pressures

(< 2 bar) and uses dry reforming of natural gas. The Hyl

process operates at high pressure (6 to 8 bar) and hence

employs smaller shafts. Conventional Hyl uses steam for

reforming natural gas, while the Hyl-ZR process uses in

situ reforming and therefore the separated CO

during

the top gas cleaning is available for utilization or

sequestration.

Given the high CO

intensity of the BF-BOF route, CCUS is

critical to ensuring the long-term sustainability of the

Indian steel sector. CCUS can also enable the scalable

and profitable conversion of waste gases from Blast

Furnace, Coke Oven and Basic Oxygen Furnaces of

Integrated Steel Plants to blue hydrogen at a cash cost of

less than Rs. 100 per kg. Blue hydrogen can be used

within the steel plant as a source of clean energy or for

producing clean DRI. The blue hydrogen can also be sold

to external consumers, thus propelling the clean

hydrogen economy in India.

2.2.2.4 CO

Emissions from the Steel Industry

Based on the emission intensities of different processes

(Table 2-7) and production data for FY 2019-20, the total

volume of CO

emission from the three routes is

estimated to be 240 mtpa. Based on the current

momentum in steel demand, it is reasonable to consider

that the steel production will reach 190-200 mtpa by

2030 with demand growing at 6% CAGR. This is

corroborated by the fact that in addition to the existing

144 mtpa of steel production capacity (FY 20-21),

expansions of 63 mtpa BF-BOF based capacity have been

announced by various major steel players in the country.

The DRI production is expected to increase by 20% by

2030 to 41 mtpa, merely by the increase in capacity

utilization, which is currently at a low level of 70%. The

share of gas DR versus coal DR is expected to remain the

same, i.e. 20–80%. Scrap usage is expected to rise to 60

mtpa in 2030 from 30 mtpa in FY 2019-20.

Based on these considerations, hot metal production is

estimated to rise to 150 mtpa from 69 mtpa in FY

2019-20. Combining these estimates with the respective

emission intensities, it is estimated that the total CO

emission shall increase to 450 mtpa by 2030. It is

reasonable to assume that the route-wise distribution of

production will not change significantly. Accordingly, the

projected CO

volumes along with the region-wise

analysis are provided below.

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Carbon Capture Utilization and Storage (CCUS) –

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2.2.2.4 CO

Emissions from the Steel Industry

Based on the emission intensities of different processes

(Table 2-7) and production data for FY 2019-20, the total

volume of CO

emission from the three routes is

estimated to be 240 mtpa. Based on the current

momentum in steel demand, it is reasonable to consider

that the steel production will reach 190-200 mtpa by

2030 with demand growing at 6% CAGR. This is

corroborated by the fact that in addition to the existing

144 mtpa of steel production capacity (FY 20-21),

expansions of 63 mtpa BF-BOF based capacity have been

announced by various major steel players in the country.

The DRI production is expected to increase by 20% by

2030 to 41 mtpa, merely by the increase in capacity

utilization, which is currently at a low level of 70%. The

share of gas DR versus coal DR is expected to remain the

same, i.e. 20–80%. Scrap usage is expected to rise to 60

mtpa in 2030 from 30 mtpa in FY 2019-20.

Based on these considerations, hot metal production is

estimated to rise to 150 mtpa from 69 mtpa in FY

2019-20. Combining these estimates with the respective

emission intensities, it is estimated that the total CO

emission shall increase to 450 mtpa by 2030. It is

reasonable to assume that the route-wise distribution of

production will not change significantly. Accordingly, the

projected CO

volumes along with the region-wise

analysis are provided below.

In 2017, the Ministry of Steel published the National Steel

Policy for India, which projected a crude steel capacity of

300 mtpa and crude steel production of 255 mtpa by the

year 2030. The National Steel Policy is aspirational and

provides an upper bound on the likely growth of the

domestic steel sector. In case the targets and goals of

the National Steel Policy are realized, it will lead to much

higher CO

emissions of about 560 mtpa from the steel

sector, as shown in Figure 2-15.

India’s current cement production capacity is about

550 mtpa, implying capacity utilization of about 50%

only. While India accounts for 8% of global cement

capacity, India’s per capita cement consumption is only

235 kg, and significantly low compared to the world

average of 500 kg per capita, and China’s per capita

consumption of around 1700 kg per capita. It is

expected that domestic demand, capacity utilization

and per capita cement consumption will increase in the

next decade, driven by robust demand from rapid

industrialization and urbanization, as well as the Central

Government’s continued focus on highway expansions,

investment in smart cities, Pradhan Mantri Awas Yojana

(PMAY), as well as several state-level schemes.

2.2.3.2 Cement Plant Production and Capacity

Limestone is the major feedstock in cement production.

Hence most cement plants are built either close to

captive limestone quarries or are well connected with

limestone quarries. Therefore clinker based cement

plants are concentrated in South and North India. The

market for slag/fly ash-based cement has also evolved in

the last few years, with blast furnace slag/fly ash-based

cement plants expanding in Eastern India. The

region-wise cement production is shown in Figure 2-18

(Source: IBEF.org).

Product BF-BOF Coal Gas

DR-EAF/IF DR-EAF

t CO

/t product 1.8 - 2.2 2.6 - 3.0 0.6 - 0.8

Table 2-7: CO

Direct Emission Intensities for

Various Iron Making Routes

Figure 2-15: Region-wise Distribution and

Total CO

Emissions (in mtpa)

Figure 2-16: Cement Production (in mtpa)

561

240

2020

Western Northern Southern

450

2030e

2030e (NSP)

Eastern

2.2.3 CO

Emissions: Indian Cement Industry

2.2.3.1 Introduction

India is the second-largest cement producer in the world

after China. Over the last five years, cement production

has grown from 274 mtpa (FY 2015-16) to 381 mtpa (FY

2021-22) at a CAGR of 6% (Figure 2-16). Cement

demand and production in FY 2020-21 was impacted by

COVID-19, and has recovered in the subsequent year.

Figure 2-17: Per Capita Cement

Consumption in 2018 (in kg)

520

1700

235

World

China

India

274

273

291

329 329

294

381

FY16 FY17 FY18 FY19 FY20e FY21e FY22e

+6%

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

Cement production in India is dominated by private

players. Almost 98% of the cement capacity belongs to

private players like UltraTech, Shree Cements, Ambuja,

ACC, Dalmia Cement etc. The cement market is also

oligopolistic and the top 10 companies account for over

60% of the total capacity. The cement capacity of major

players is given in Table 2-8 (Source: Indian Minerals

Yearbook 2019 published by the Government of India).

The state-wise cement capacity is given in Table 2-9

(source: Indian Minerals Yearbook 2019 published by

Government of India). The top five states i.e., Rajasthan,

Andhra Pradesh, Karnataka, Tamil Nadu, and Gujarat,

account for almost 50% of the total capacity. Given the

proximity to limestone quarries, the majority of future

expansions are also planned in these states only.

Figure 2-18: Cement Production (in mtpa)

Company Name Capacity

Ultratech 125

Shree Cement 41

Ambuja 35

ACC 34

Dalmia 21

ICL 20

Jaypee Cement 17

Birla 15

Ramco 15

JK Lakshmi 15

Chettinad 14

Nirma 14

JSW 11

JK Cement 11

Kesoram Industries 11

Table 2-8: Major Players of Cement Industry

and Capacity (in mtpa)

Northern Southern Central Eastern Western

274 273 291 329 329 294 381

FY16 FY17 FY18 FY19 FY20e FY21e FY22e

16% 16% 15% 14% 15% 15% 15%

16% 17% 19% 19% 20% 20% 21%

16% 16% 16% 15% 16% 15% 15%

26% 27% 26% 29% 27% 28% 28%

26% 25% 24% 23% 22% 22% 22%

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

State No. of Plants Capacity (mtpa) % of total capacity

Rajasthan 24 87 15.7%

Andhra Pradesh 26 63 11.3%

Karnataka 18 49 8.9%

Tamil Nadu 22 42 7.6%

Gujarat 17 41 7.5%

Madhya Pradesh 13 39 7.0%

Telangana 18 34 6.2%

Maharashtra 13 32 5.8%

Chhattisgarh 13 31 5.6%

Uttar Pradesh 14 24 4.3%

West Bengal 16 22 4.0%

Himachal Pradesh 9 16 2.9%

Odisha 5 13 2.4%

Jharkhand 6 13 2.3%

Bihar 6 11 1.9%

Meghalaya 10 9 1.7%

Haryana 5 7 1.3%

Punjab 4 7 1.3%

Assam 6 5 0.9%

Uttarakhand 3 4 0.7%

Andaman Nicobar 1 2 0.3%

Kerala 2 1 0.2%

Jammu and Kashmir 3 1 0.1%

Goa 1 0.2 0.0%

Total 255 554 100%

Table 2-9: State-wise Cement Capacity

The district-wise distribution of cement plants has

also been analyzed to understand the clusters of

cement plant units. The top 20 districts/clusters

contribute to almost 50% of the total capacity

(Table 2-10) (Source: Indian Minerals Yearbook 2019

published by Government of India).

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Figure 2-19 below shows the top 10 cement clusters,

based on their capacity, along with the names of the

major producers in each cluster.

District name State name Capacity (mtpa)

Chittorgarh Rajasthan 25

Gulbarga Karnataka 23

Nalgonda Telangana 21

Chandrapur Maharashtra 20

Satna Madhya Pradesh 20

Sirohi Rajasthan 18

Raipur Chhattisgarh 15

Anantapur Andhra Pradesh 14

Pali Rajasthan 13

Ariyalur Tamil Nadu 13

Kurnool Andhra Pradesh 12

Solan Himachal Pradesh 12

Kadapa Andhra Pradesh 11

Surat Gujarat 10

Krishna Andhra Pradesh 9

Jaintia Hills Meghalaya 8

Amerli Gujarat 8

Durg Chhattisgarh 7

Junagadh Gujarat 7

Bardhaman West Bengal 7

Others 282

Total 554

Table 2-10: Top 20 Districts/Clusters and

Aggregate Capacity

Figure 2-19: Top 10 Cement Clusters

Based on Cumulative Capacity

Clusters

Chittorgarh, 25 mtpa Wonder Cement, UltraTech, Nirma, Birla

Rajasthan 5 units J.K Cement

Gulbarga, 23 mtpa UltraTech, Orient, Kesoram,

Karnataka 5 units Chettinad, Kalburgi

Nalgonda, 21 mtpa My Home, Sagar, Zuari, ICL Penna,

Telangana 12 units NCL, Deccan, etc.

Chandrapur, 20 mtpa UltraTech, Ambuja, ACC, Dalmia

Maharashtra 5 units

Satna, 20 mtpa Prism Cement, UltraTech, Birla, KJS

MP 6 units Cement, Jaypee Cement

Sirohi, 18 mtpa UltraTech, JK Laxmi Cement

Rajasthan 2 units

Raipur, 15 mtpa Shree Cement, UltraTech, Nirma,

Chhattisgarh 6 units Ambuja

Anantapur, 14 mtpa Penna Cement, UltraTech, Sagar Cement

AP 4 units

Pali, 13 mtpa Shree Cement, Nirma, Ambuja

Rajasthan 4 Units

Ariayalur, 13 mpta Chettinad cement, UltraTech, Dalmia,

Tamil Nadu 5 units ICL

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

2.2.3.3 Medium-term demand projection

The 10% decrease in cement demand in FY 2020-21

was temporal and due to the COVID-19. Cement

demand is expected to grow going forward based on

investments towards the infrastructure and housing

sectors. It is envisaged that cement demand per

capita will grow at around 6% CAGR to FY 2029-30.

Thus, cement consumption per capita will reach 300

kg per capita by 2025 and 400 kg per capita by 2030.

Thus cement demand is estimated to be around 440

mtpa by 2025 and about 650 mtpa by 2030,

considering a population growth rate of 2%

year-on-year and growth in cement consumption per

capita at 6% per year.

Analysis of the capacity distribution of individual

cement plants reveals that the average capacity for

the 255 cement plant units is 2.2 mtpa, whereas the

capacity of most of the cement plants is between

1 to 3 mtpa.

2.2.3.4 Typical Cement Manufacturing Process

Cement can be primarily categorized into three types,

based on the clinker factor and usage of other

ingredients i.e. fly ash or slag:

a) Ordinary Portland Cement (OPC): OPC is the

most common type and is used widely in

construction activities. The clinker factor is

generally above 90% for OPC cement.

b) Portland Pozzolana Cement (PPC): Since fly ash

is abundantly available at a low cost, the share of

PPC-type cement has increased significantly over

the last decade. The clinker factor is less than

60%. PPC is advantageous over OPC due to

fineness, resistance to corrosiveness, and

impermeability.

c) Portland Slag Cement (PSC): Blast furnace slag

is predominantly used for the production of PSC.

PSC is used in applications where concrete is

exposed to rough weather like marine

applications, high-rise buildings, etc.

The process route for different types of cement

production is almost similar except for the final

blending and grinding process steps. The dry-type

technology predominant in the Indian cement industry

is described below and depicted in Figure 2-21.

a) Mining

The manufacturing process starts from

mining limestone, which is the primary

ingredient for cement production. The

limestone is primarily excavated from open cast mines

after drilling and blasting and loaded onto dumpers.

Dumpers transport the limestone and unload it into

hoppers of limestone crushers. Other feed materials

like sand, coal, pet coke etc., are sourced

from outside.

b) Screening & Crushing

The raw materials are crushed in the primary

crushing unit and then fed into the

secondary crushing unit (along with the

mixing of additives) to reduce the material

size. The raw mix is conveyed to a circular

storage unit called the raw mix storage. The mix is

reclaimed from the stockpile by reclaimers and

conveyed to the raw mix bin for grinding. High purity

limestone and coal/pet coke generally have dedicated

crushing and storing systems. However, other

additives like sand are crushed in a common or shared

crushing system.

Capacity range No of plants % share

Less than 1.0 mtpa 63 25%

1.0 mtpa to 2.0 mtpa 85 33%

2.0 mtpa to 3.0 mtpa 55 22%

3.0 mtpa to 4.0 mtpa 29 11%

4.0 mtpa to 5.0 mtpa 11 4%

Greater than 5.0 mtpa 12 5%

Table 2-11: Plant Capacity Distribution

Figure 2-20: Cement Demand (in mtpa)

and Per-capita Cement Consumption (in kg)

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

327

443

654

235

297

397

100

200

300

400

500

600

700

2020e 2025f 2030f

Demand Kg/Capita

c) Raw meal drying, grinding, and homogenization

Additives like iron ore/red mud are blended with

limestone with the help of weigh feeder before drying

and grinding to get the desired composition and

properties. The raw mill consists of two chambers,

namely a drying chamber and a grinding chamber,

separated by a diaphragm. The hot flue gas from a

preheater (preheater/kiln system) is used for drying.

Then the materials enter the grinding chamber of the

raw mills for fine grinding. The grinding mill can be of

the conventional and simple ball mill type, or the

advanced and complex Vertical Roller Mill (VRM) type.

The hot gas, along with grinding materials, is fed to a

separator that separates fine and coarse products.

The course product is returned to the grinding unit.

The hot gas and fine materials are passed through a

cyclone unit to separate fine materials and gases. The

fine material is collected from the multi-cyclone. The

very fine materials carried away by flue gas to an

electrostatic precipitator (ESP), where the finer

particles are separated from gases. The ESP dust is

collected from bag filters and fed into screw

conveyors, and mixed with the fine material. Raw

meal/kiln feed is stored in a blending silo for

homogenization before being fed to the top of the

preheater for pyro-processing.

Figure 2-21: Typical Process Flow Diagram

for Cement Making

d) Clinkerisation

Cement clinker is made by pyro-processing the kiln

feed in the preheater-kiln system. The preheater-kiln

system consists of a multi-stage (generally more than

five) cyclone preheater, combustion chamber, riser

duct, rotary kiln, and grate cooler. In the preheater

section, heat transfer depends on the number of

stages of the preheater. Additionally, coal is also fired

for additional heat requirements. The preheater helps

in removing moisture from the feed, as well as raising

the temperature of the feed through countercurrent

heat transfer with hot flue gas.

The preheated kiln feed is partially calcined in a

combustion chamber and riser duct and then

completely calcined in a rotary kiln and heated to

approximately 1400-1500

C to form the clinker

components. Coal is fed through a burner which is the

primary source of heat for the calcination. However,

alternative fuels like petcoke, biomass, and other solid

waste are also used. Hot clinker is discharged to the

grate cooler for cooling from 1350-1450

C to around

1200

C with atmospheric air. The cooled clinker is

then conveyed to hoppers for clinker storage.

e) Cement grinding and storage

Clinker and gypsum for OPC, fly ash for PPC, and slag

for PSC is transferred from individual hoppers and fed to

the cement mills. The mill discharge is fed to the screen,

which separates fine and coarse products. The course

product is returned to the mill inlet for regrinding, and

the final product is stored in concrete silos.

f) Packing

Cement is conveyed from silos to the automatic

packers, where it is packed in 50 kg bags and

dispatched to the market.

2.2.3.5 CO

Emissions from Cement Manufacturing

In 2018, cement production contributed about 12% or

264 mtpa of anthropogenic CO

emissions in India

(source: IEA). The emissions will rise with the sustained

increase in cement demand and production in the near

future. CO

emissions vary widely from plant to plant

depending on specific factors such as product type,

plant efficiency, fuel usage, plant capacity etc.

Raw Material incl. additives

(High grade limestone, sand

iron ore fines, red mud, clay

Screening & Crushing

Pre-blending &

Proportioning

Grinding Grinding

Rejects

Final Grinding

Storage & Dispatch

Fuel

(Coal/Pet coke/Bio)

Additives

(Gypsum/Fly ash)

Homogenising

Pre-heating

Clinkerisation

Cooling & Storage

of Clinker

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Particulars Unit Global Avg. India Best India Average

Specific Electrical Energy Consumption kWh/tonne of cement 91 64 80

Specific Thermal Energy Consumption GJ/tonne of clinker 3.5 2.83 3.1

Table 2-12: Consumption Parameters

Figure 2-22: Typical CO

Cascade

(in kg of CO

per tonne of cement)

Figure 2-23: Cement Plant CO

Emission

Projection (in mtpa)

The average CO

emission intensity per tonne of

cement was 576 kg in 2018. The Scope 1 and Scope 2

emissions are primarily from three sources:

a. Emission from process calcination (CaCO3 -> CaO)

accounts for 57-60% of total emissions

b. Emission from process heating in terms of

thermal energy usage contributes around 27-31%

c. Emission from power usage for grinding, process

fans, etc., accounts for 10-13%.

d. Limestone mining also has a small contribution to

the total CO

emission (limited to 1-2%).

A typical CO

cascade is shown in Figure 2-22.

The CO

emission intensity is expected to reduce to

500-520 kg per tonne with further improvement in

the cement production process, through higher

production of blended cement, using vertical roller

mills, installing WHRB, etc. The total CO

emission

from the cement sector has been estimated to reach

325 mtpa by the year 2030, considering 0.5 tonne of

emissions per tonne of cement.

346

156

75 576

Calcination Thermal Energy Power Total

196

244

325

2020e 2025f 2030f

Hence an average CO

emission per tonne of cement

has been used to calculate the total CO

emissions

at the current and project level of cement demand

and production.

The Indian cement industry is focused on sustainability

and environmental impact, vis-à-vis its peers.

According to an April 2018 publication by CDP, a

UK-based organization, five out of the top ten global

cement companies in terms of low carbon transitions

are from India. Indian cement companies are ahead of

the global average in terms of specific electrical and

thermal energy consumption (Table 2-12). This is

primarily due to fly ash/slag usage in the blend,

efficient dry processes, and alternate fuel usage.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Source: Cement Manufacturing Association

2.2.4 CO

Emissions: Indian Oil & Gas and

Chemical Industry

2.2.4.1 Introduction

The chemical industry is another energy-intensive

sector and produces materials used in multiple

downstream sectors. The Indian chemical industry is

ranked as the 6

largest in the world and the 3

largest in Asia. India is one of the largest production

hubs of chemicals and in the next 5-10 years the

industry is expected to have a high growth trajectory,

which would result in a significant increase in

emissions.

The chemical sector is recognized by the Indian

government as one of the country’s primary growth

drivers and is expected to grow at 9.3% to reach US$

304 billion by 2025, based on rising demand from the

end-user segments, especially for speciality chemicals

and petrochemicals. In July 2020, production volumes

of key chemicals stood at around 0.9 mtpa and

petrochemicals at 1.9 mtpa. India ranks 14

in global

exports and 8

in global imports of chemicals

(excluding pharmaceuticals).

In 2020, the chemical industry accounted for about 160

mtpa of CO

emissions (7% of total emissions), which is

expected to increase to approximately 220 mtpa by

2030, fueled by growth in speciality chemicals,

petrochemicals and fertilizers. This chapter focuses on

emissions from the production of different

segments of the chemicals sector, viz. refinery &

petrochemical products, fertilizers, hydrogen,

methanol and synthesis gas via coal/coke gasification.

Hydrogen

Hydrogen is widely considered a future

energy carrier due to its potential uses

across multiple sectors like refinery, steel,

petrochemicals, power, transportation etc., with

(potentially) zero CO

footprint and its potential role in

the decarbonization of energy systems and as a low

carbon fuel & chemical feedstock. Additionally,

development and innovation in electrolyzer

technologies and the availability of renewable power

make the prospect of green hydrogen also realistic in

the future. However, to be deployed at scale,

hydrogen needs to compete with existing fossil fuels

and other emerging low carbon alternatives, such as

battery electric vehicles. Despite being inexpensive and

2.2.4.2 Type of Primary Chemicals

plentiful, there will be competing needs for low-carbon

power, and hydrogen production via electrolysis is an

extremely electro-intensive process. As a result, it’s

critical to analyze hydrogen’s potential role from a

systems viewpoint, considering the different end-uses,

production routes, and value-chain combinations.

Hydrogen demand in India is currently 6 mtpa, and is

confined to fertilizer plants and refineries. The

development of new uses of hydrogen, cost

reductions in key technologies, as well as the growing

requirement to decarbonize the energy system could

push hydrogen demand to roughly 11 mtpa by 2030

and 28 mtpa by 2050. Demand will remain mostly

concentrated in industrial sectors, either expanding in

existing sectors like fertilizers and refineries or

extending into new ones like steel. Hydrogen will also

have a minor role in the electricity sector as a

long-term storage vector, and in the transportation

sector in heavy-duty and long-distance segments.

Demand for green hydrogen is expected to continue

to rise after 2050, particularly in the steel and road

transportation industries, as well as shipping and

aviation.

Methanol

Methanol is an essential chemical building

block for hundreds of everyday products

and applications, including plastics, paints, car parts

and construction materials. Methanol is also an

alternative clean energy resource that can be blended

in existing fuels and used in cars, trucks, buses, ships,

fuel cells, boilers and cooking stoves. India’s current

methanol production capacity is 0.7 mtpa, which is

less than one-third of the country’s total demand. The

market is heavily reliant on imports from the Middle

East, which account for more than 75 percent of

methanol consumed in India. Methanol demand in

India was 2.26 mtpa in FY 2020-21 and is expected to

rise to 4.1 million tonnes by FY 2029-2030.

India has developed an indigenous technique for

converting high-ash Indian coal to methanol and has

set up its first pilot plant in Hyderabad for producing

0.25 tpd of 99 percent purity methanol. Conversion of

coal to methanol will provide an alternate route for

producing methanol and increase India’s self

dependence in this important energy carrier of the

future, thus providing a pathway to India to lower both

its crude imports and CO

emissions (i.e. when the

methanol production is combined with CCUS).

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Ammonia

India is the fourth-largest ammonia

producer in the world, with production of

15.4 mtpa in 2020 and also one of the

largest ammonia importers in the world. The largest

demand for ammonia is for producing urea,

ammonium nitrate and ammonium phosphate, which

are major compounds for nitrogen-based fertilizers.

Urea and ammonium phosphate fertilizers account for

over 90% of ammonia demand in India.

Urea production in India is about 25 mtpa. With a

growing population and food demand, the demand for

urea and ammonia is also expected to grow. Ammonia

is also an essential chemical needed for refrigerants.

With rapid urbanization the demand for refrigerants is

expected to increase, in turn impacting the demand

for ammonia. Ammonia is also a basic building block

for various compounds used in producing household

products, cosmetics, pharmaceuticals, and in metal

treating. Ammonia can also play a role in the future

energy transitions as a hydrogen carrier for storing

and transporting the chemical energy of hydrogen,

and can be used as a transport fuel, particularly in the

shipping industry.

Synthetic Gas

Synthesis gas (syngas) production

provides the foundation of many

industries. Syngas is a mixture of H

/CO and is

produced from gasification (coal, heavy hydrocarbons

coke) or reforming (light hydrocarbons). Steam,

oxygen, carbon dioxide or mixtures of them act as

reforming agents and react with the carbon source at

high temperatures, producing syngas of varying

compositions.

The desired composition of syngas depends on the

downstream applications; the most common H

/CO

ratio is 2:1 for methanol and Fischer-Tropsch synthesis,

or higher for hydrogen production. The generation of

ethanol and higher alcohols, dimethyl ether, and

oxo-alcohols use lower H

/CO ratios of about 1. When

the carbon source is natural gas (methane), the

conversion to syngas process is called reforming. The

common technologies offer syngas with high hydrogen

content (Steam Methane Reforming or SMR) or with

reduced operating investment (Partial Oxidation or

POX, Auto-thermal Reforming or ATR and Combined

Reforming or CR). Newer technologies, which can

consume CO

(Dry Methane Reforming or DMR,

Bi-reforming or BR and Tri-reforming TR) are also

interesting options, even though they are more

cost-intensive or produce syngas with lower H

/CO

ratios, due to their reduced environmental impact

under specific situations. Reliance Industries Ltd’s

(RIL) Jamnagar plant has the only petcoke gasification

unit in India having a capacity of producing 12 mtpa of

synthesis gas, which can be further used to produce

various chemicals. The synthesis gas has a typical

composition of H

30-35 vol%, CO 35-40 vol% & CO

15-20 vol%.

Petrochemicals

Petrochemicals provide the basic raw

materials for products of daily use.

Petrochemicals are primarily of two types:

olefins and aromatics. The demand for petrochemicals

is expanding rapidly and is expected to reach 35 mtpa

by FY 2029-30. Within petrochemicals, the production

of ethylene and propylene are the most emission

intensive processes after ammonia. These chemicals

are the building blocks for the polymer industry and

are increasingly being used across diverse

applications as they provide varied operational

benefits over their metal counterparts.

2.2.4.3 Process Description of Various

Sources

a) Refinery Unit

India’s oil consumption is forecast to increase from 5

million barrels/day in 2020 to 7.2 million barrels/day

in 2030 and 9.2 million barrels/day in 2050. The total

refining capacity in India is about 250 mtpa, with total

CDU capacity of 2300 thousand barrel/day & FCC

capacity of 938 thousand barrel/day. For any complex

refinery, there are multiple CO

emission sources such

as Hydrogen Generation Unit (HGU), Power Plant/

Co-Gen Plant (PP/CGP), Fluid Catalytic Cracking (FCC),

Crude Distillation Unit (CDU) / Vacuum Distillation Unit

(VDU) as well as heaters and boilers. Amongst these,

the HGUs generate the most concentrated gas

streams in terms of CO

(20-70 vol%), followed by

CDU/VDU (10-12 vol.%), FCC (8-16 vol.%) and PP / CGP

(4-8 vol%). The majority of CO

emissions in a typical

refinery is contributed by the hydrogen generation

unit, FCC, boilers, and process heaters. A brief

description of HGU and FCC are given below:

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Fluid Catalytic Cracking (FCC):

FCC helps in

improving the recovery from crude through cracking

higher hydrocarbons. Crude is allowed to react with

steam in a fluidized bed (or fluid-bed) of catalyst

particles. When the heated catalyst particles come in

the presence of the feed, they evaporate it, and

cracking begins as the gas oil vapors and catalyst

particles migrate upward in the reactor. During the

upward movement, the temperature of the catalyst

particles reduces as the gas oil evaporates and

endothermic cracking processes occur. Cracking

processes also deposit a coke layer on the catalysts,

causing them to become inactive. The coked catalyst is

transferred to the regeneration unit before they are

reintroduced to the riser. After being separated from

the catalyst particles in the upper section of the

reactor, the cracking products are transferred to the

fractionator for recovery. In the regeneration unit, the

deposited coke layer of catalyst is burnt at around

700-800

C, and this is a primary source of CO

emission. The CO

concentrations at different units of

a typical refinery operation, as shown in Table 2-14,

vary depending on the respective processes.

Hydrogen generation unit: Hydrogen is indispensable

in refinery operations for handling sour crudes as well

for meeting stringent fuel norms. In India, almost all

refineries produce hydrogen from natural gas (as well

as naptha) through steam methane reforming (SMR).

Only RIL has a petcoke based gasifier at Jamnagar,

which caters to a part of the total hydrogen

requirement. In the SMR process, natural gas is fed to

the reformer to react with steam over special

catalyst-filled tubes to produce hydrogen and carbon

monoxide. The gas stream from the SMR is

conditioned in a water gas shift reactor to maximize

the H

recovery. In the WGS, the carbon monoxide

reacts with steam to form hydrogen and carbon

dioxide. The hydrogen is then separated in a Pressure

Swing Adsorption unit. Pure hydrogen with 99.9%

purity is sent to end-user and the tail gas is used as

fuel in the reformer unit.

The hydrogen production process and the possible

capture points are schematically depicted in

Figure 2-24. The three gas streams where CO

can be

captured are marked as 1, 2 and 3. Gas composition at

these identified sources is given in Table 2-13. While

Parameter Shifted syngas (vol.%, db) PSA tail gas (vol.%, db) Flue gas, (vol. %, db)

Carbon Dioxide 20 64 18-20

Hydrogen 77 26

Carbon Monoxide 0.7 7

Nitrogen 58

Table 2-13: Gas Composition at Different Source Points

Figure 2-24: Simplified Block Flow Diagram of

Hydrogen Generation Units (HGUs)

NG: Natural Gas; SMR: Steam Methane Reforming; WGS: Water Gas Shift;

PSA: Pressure Swing Adsorption

PSA Tail Gas

Shifted

Syngas

Flue

Gas

Feed (NG)

SMR WGS PSA

Fuel (NG)

Steam

capture from tail gas or syngas (1 & 2) ensures the

lowest cost of capture because of higher

concentration and partial pressure of CO

, it can

capture only 60% of total direct CO

emissions,

whereas flue gas capture ensures over 95% direct

capture.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

b) Petrochemical Unit

The petrochemical industry generates various kinds

of chemical products such as polymers, fibers or

rubber, from such raw materials as petroleum, LPG,

natural gas, and other hydrocarbons through

different production processes. The source

feedstock, i.e. light or heavy hydrocarbons, are

used to produce a variety of components including

ethylene, propylene, butadiene and pyrolysis

gasoline through non-catalytic thermal

decomposition reaction with steam (thermal

cracking). Pyrolysis of hydrocarbons is the most

critical process in petrochemical production and

presents the main source for most basic organic

industrial raw materials: α-olefins (ethylene,

propylene, isobutane, butene), butadiene, and

aromatic hydrocarbons (BTX = benzene, toluene,

xylene). The most CO

emission intensive process is

the production of ethylene through the following

processes:

Table 2-14: CO

Concentration at Different Refinery Units

Unit Section CO

vol% (db)

FCC FCCU Regenerator 8.5

SMR Reformer Flue 18-22

CDU Crude distillation Unit 11

DCU Coke heater 8.5

Reformer Reformer heater 4

heater

VDU Vacuum Unit 11

Naphtha Reformer-Naphtha 8.5

splitter splitter

HC Hydrocracker 8.5

HC-Heater Hydrocracker Heater 8.5

HDS Hydrodesulfurization 8.5

HDS-Heater HDS- Charge heater 4

SRU Sulfur removal & 4

tail gas treatment

FCCU Heater FCCU heater 4

Table 2-15: Cracker Furnace Flue Gas Composition

Parameter vol% (db)

11-13

3-4

85-87

CO 100-200 ppm

Steam Cracking: In steam cracking, a gaseous or

liquid hydrocarbon feed-like ethane, propane, butane,

naphtha, gas oil is diluted with steam and then

heated in a furnace without oxygen. Typically, the

endothermic reaction temperature is very hot

(around 850

C) and allowed to take place with short

residence time (resulting in gas velocities reaching

speeds beyond the speed of sound) in the furnace

coils. In modern cracking furnaces, the residence

time is reduced to milliseconds in order to improve

the yield of the desired products. After the cracking

temperature has been reached, the gas is quickly

quenched to stop the undesirable reaction in the

downstream transfer line exchanger. The products

produced in the reaction depend on the composition

of the feed, on the hydrocarbon to steam ratio and

on the cracking temperature and furnace residence

time. The flue gas temperature is at around

1100-1200

C depending upon fuel gas composition.

Light hydrocarbon feeds (such as ethane, propane,

or light naphtha) give product streams rich in the

lighter alkenes, including ethylene, propylene, and

butadiene while heavier hydrocarbons (full range

and heavy naphtha as well as other refinery

products) feeds give some of these, but also give

products rich in aromatic hydrocarbons and

hydrocarbons suitable for inclusion in gasoline or

fuel oil. The higher cracking temperature favors the

production of ethylene and benzene, whereas lower

severity produces relatively higher amounts of

propylene, C4 cut, and liquid products.

Gas composition: The exhaust flue gas is a CO

rich

product, depending upon the type of fuel, combusted

in modern low SOx-NOx burners. Normally the

methane content varies from 60-70 vol% in the

gaseous fuel. The typical flue gas composition with

10-15 vol% excess air is given Table 2-15.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

c) Fertilizer Unit

A typical fertilizer unit comprises hydrogen

production, ammonia production and urea production.

Most fertilize plants in India operate with natural gas

based SMR for hydrogen production, which is similar

to refineries. However, CO

removal after the water

gas shift reactor is an added process in fertilizer

plants, since CO

is required for production of urea. In

a fertilizer complex, the majority of CO

emission is

contributed by hydrogen production. A part of CO

consumed in downstream urea production. A brief

description of the ammonia and urea production

process is given below:

Ammonia production: The Haber process, in which

nitrogen and hydrogen combine in the presence of an

iron catalyst to make ammonia, is the most common

method of producing ammonia. The cooled,

compressed gas combination is supplied into the

ammonia production loop. The incoming gas stream

is mixed with a mixture of ammonia and unreacted

gases that have already travelled around the loop

and chilled to 5

C. The ammonia is removed, and the

unreacted gases are heated to 400

C and passed

over an iron catalyst. 26 percent of the hydrogen and

nitrogen are transformed to ammonia under these

conditions. The ammonia converter’s discharge gas is

cooled from 220 to 230

C. Moreover half of the

ammonia is condensed during the cooling process,

which is subsequently separated. The residual gas is

combined with incoming gas that has been cooled

and compressed. The ammonia is compressed quickly

to 24 barg. The ammonia recovery machine removes

the gas mixture above the liquid ammonia (which also

includes considerable levels of ammonia).

Urea production: Urea is produced from ammonia

and carbon dioxide. A mixture of compressed CO

and ammonia at 240 barg is reacted to form

ammonium carbamate in two stage reactors. The

major impurities in the mixture at this stage are

water from the urea production reaction and

unconsumed reactants (ammonia, carbon dioxide and

ammonium carbamate). The unconsumed reactants

are removed in three stages with a series of pressure

reduction and heating. By the time the mixture is at

0.35 barg, a solution of urea dissolved in water and

free of other impurities remains. The urea solution is

heated under vacuum, which increases the urea

concentration from 68% to 80% w/w. At this stage

some urea crystals also form. The solution is then

heated from 80

C to 110

C to redissolve these

crystals prior to evaporation. In the evaporation

stage molten urea (99% w/w) is produced at 140

Urea is sold as 2 - 4 mm diameter granules. These

granules are formed by spraying molten urea onto

seed granules which are supported on a bed of air.

2.2.4.4 CO

Emissions from the Chemical Industry

Based on the CO

emission intensities for various

process units in the chemical industry, the direct

process emissions may considered for CO

capture

and further utilization or sequestration. Based on the

production data from various industries, the

sector-wise production of different chemicals

through various routes and the associated CO

emissions have been estimated.

The major sources of CO

emissions are hydrogen

production in refineries, production of olefin, urea &

syngas. Out of these emissions, only those from direct

processes, apart from the utility CPP associated with

these units, account for the capturable CO

volumes

due to their possibility of integration with CCU

facilities. The distribution of CO

emitted by the

chemical industry is provided in Table 2-16.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Figure 2-25: Domestic Oil Production (in mtpa)

FY15 FY16 FY17 FY18 FY19 FY20

Products Production in Emission Intensity, CO

emissions in Expected Estimated CO

2020, mtpa TCO

/TProduct 2020, mtpa production emissions in

2030, mtpa 2030, mtpa

Ethylene 7.2 1.2 8.6 10.5 12.6

Methanol 0.7 0.5 0.4 4.1 2.1

Ethylene Oxide 1.36 0.5 0.7 2.2 1.1

Syngas (via coke) 10 2 20 12 24.0

SMR based hydrogen* 6 8.5 - 11 56 11 102

Refinery (CDU & FCC) 250 0.2 50 350 70.0

Vinyl Chloride 1.6 0.3 0.5 2 0.6

Urea 25 0.7 17.5 40 28.0

DAP 4.65 0.73 3.4 8 5.8

Complex + SSP 10 0.76 7.6 19 14.4

Total 165 261

Table 2-16: Total CO

Emissions from Refineries, Petrochemicals & Fertilizers

Note: *Most SMRs have the flexibility to take both NG and naphtha as feed, depending on the price. For calculating the CO

emissions,

we have assumed 70% production from NG & 30% from naphtha.

2.2.5.1 Introduction

Exploration and production activities (E&P) to extract

oil and gas from the subsurface are crucial in order

to reduce the import dependency of petroleum and

natural gas and ensure energy security. The fossil

fuels thus produced are further refined to produce

various value-added products that empower the

Indian economy. The domestic production of oil and

gas from FY 2014-15 to FY 2019-20 has been on a

decline, as shown in Figure 2-25 and Figure 2-26.

37.45 36.96

35.68

34.2

32.17

-3%

Figure 2-26: Natural Gas Production -

FY 2014-15 to FY 2019-20 (in billion cubic meter)

FY15 FY16 FY17 FY18 FY19 FY20

33.65 32.25

31.9

32.65

32.88

31.18

-2%

In the year FY 2019-20, ONGC accounted for about

64% of the crude oil production, followed by CEIL

(Cairn Energy India Limited), accounting for 24% of

crude oil production and OIL, with 10% of the total

crude oil production.

2.2.5 CO

Emissions: Upstream Oil & Gas Exploration

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Figure 2-27: Oil Production by Operator in FY 2019-20 (in mtpa)

2.2.5.2 CO

Emission from the E&P Industry

The majority of the emissions in the upstream oil and

gas exploration and production consists of methane,

with some CO

also being released during flaring and

during power generation required to operate drilling

and other necessary equipment. The methane

emissions thus need to be considered along with the

emissions and represented in terms of CO

eq.

To estimate the emissions from the upstream oil &

gas operations, an emission intensity factor has

been estimated. This has been done using the

Others

OIL

CEIL

Total

ONGC

31.2

1.9

2.67

23.89

2.72

CEIL

OIL

Others

Total

ONGC

32.2

0.53

3.11

20.8

7.77

In the year FY 2019-20, natural gas production was

also led by ONGC, producing 76% of the total

natural gas production. It was followed by OIL

accounting for 9% and CEIL accounting for 6% of

the total production (India’s Hydrocarbon Outlook,

2020).

Figure 2-28: Natural Gas Production in FY 2019-20 (in billion cubic meters)

emissions data for oil and gas production activities

provided in World Energy Outlook (2018). The

emission intensity factor thus obtained has been

adjusted for the Indian scenario and used to

estimate the CO

eq emissions from the oil and gas

production data. The emission intensity for

upstream activities for crude oil production is

calculated to be 0.04 tCO

eq/toil and for upstream

activities involved in natural gas production, the

emission intensity is calculated to be 0.2

tonneCO

eq/bcmgas. Accordingly, the total CO

emissions have been tabulated in Table 2-17.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

ONGC is the largest producer of crude oil and

natural gas and has the lion’s share of the total

Products Units Production CO

emission, mtpa of CO

Crude Oil mtpa 32.17 9.43

Natural Gas billion cubic meter 31.18 6.24

Total 15.7

Table 2-17: Total CO

Emissions from Oil & Gas Upstream Operations

emission from the upstream E&P sector, followed by

CEIL (Cairn Energy India Limited) and OIL.

The forecasted domestic production data for oil in

FY 2029-30 is expected to decline to 27 mtpa of oil,

while natural gas production is expected to increase

to 55 billion cubic meters (source: India Energy

Outlook, 2021). Based on these forecasts, the

corresponding emissions have been estimated for

Figure 2-29: Carbon Emission by E&P Operator in FY 2019-20 (in mtpa of CO

eq)

CEIL

OIL Others TotalONGC

10.87

2.66

1.45

0.70 15.70

FY 2029-2030 using the emission intensity factors.

The increase in natural gas production will result in

higher CO

emission volumes, and will offset the

decrease due to lower crude oil production. Overall

emissions in FY 2029-30 from upstream oil & gas

operations is expected to reach 19 mtpa CO

eq.

Figure 2-30: Emissions Projection for 2030, MT CO

2020

Oil

2030e

Natural Gas

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

2.2.6 CO

Emisisons: Gasification

2.2.6.1 Introduction

In India, coal is the most abundant and important

fossil fuel. Despite a drop in demand due to the

COVID-19 pandemic, India’s coal production reached

730 mtpa in the fiscal year FY 2019-20 and 716 mtpa

in FY 2020-21. The gasification of coal produces

synthesis gas, which can be converted into a diverse

slate of products such as hydrogen, methanol,

ethanol, olefins, ammonia, acetic acid, DME and

others. The Hon’ble Prime Minister has set a lofty

goal of gasifying 100 mtpa of coal by the year 2030.

Coal gasification can help India become by

substituting imports of crude oil and other

value-added chemicals to meet the needs of a

growing and resource-hungry nation. It is imperative

for coal gasification to be combined with CCUS and

provide a sustainable and clean pathway for

producing chemicals and transportation fuels. In

order to support this infant industry, financial

support from the Government of India is necessary

to help CCUS-enabled coal gasification projects

compete with the conventional and carbon unabated

fossil fuel (primarily NG) based manufacturing

routes of these products.

As of today, there is only one commercial-scale coal

gasifier operating in India, at JSPL Angul. The syngas

feeds to a gas-based DRI unit. Given the importance

of developing gasification technologies and projects

suitable for high ash Indian coals, the Ministry of Coal

has planned a three phase strategy for developing

commercial-scale gasification projects:

i) Phase I: Establishing a pilot project through two

gasification projects for gasifying about 4 mtpa of

coal. These projects are the Talcher Fertilizer

Plant and the Dankuni Methanol complex. The

Talcher Fertilizer Plant is a joint venture of Coal

India Limited (CIL), Rashtriya Chemicals &

Fertilizers (RCF), and GAIL India Limited, and will

be based on gasification of high ash coal with

petcoke blending. The methanol plant in Dankuni

will use low-ash coal from the country’s eastern

region and will be built under the

Build-Own-Operate (BOO) method with an

estimated investment of Rs. 20,000 crore.

ii) Phase II: Coal India Limited has identified four

key gasification projects to be implemented

through its subsidiaries: Eastern Coalfields

Limited (ECL), South-Eastern Coalfields Limited

(SECL), Central Coalfields Limited (CCL), and

Western Coalfields Limited (WCL). These projects

aim to gasify 6 mtpa of coal for producing

different chemicals such as methanol, ammonium

nitrate and synthetic natural gas.

iii) Phase III: Phase III aims to gasification the

balance quantity of coal (as per the vision of the

Government) by identifying new projects,

following the successful implementation of the

Phase II projects.

2.2.6.2 Process Description

A typical block flow diagram is shown in Figure 2-31.

Details of major blocks like gasification and gas

processing part is explained below:

Gasification: Coal after beneficiation and grinding is

fed to the gasifiers. The coal reacts with steam and

oxygen to produce syngas comprising of H

, CO, CO

along with H

S and other impurities. The hot gas is

passed through a cooler where high pressure steam

is generated through a heat exchanger. The steam is

recycled partially in the gasifier and the balance is

used for downstream gas conditioning units. Syngas

comes out of cooler is passed through a series of

filters to remove the particulate matters present in

the gas. The particulate matters are recycled in the

gasifier. Further, the cooled and particulate free

syngas is scrubbed with water to remove corrosive

chlorides present in the syngas. From the scrubber,

the syngas is piped to the water gas shift reactor for

gas conditioning.

Water gas shift: Based on the downstream

requirements, the raw syngas needs to be processed

to conform to a certain hydrogen/carbon monoxide

/CO) ratio, depending on the downstream

application. To achieve the desired H

/CO ratio, the

syngas is passed through a double-stage fixed bed

reactor containing shift catalysts. This process

converts a part of the CO and water of the syngas to

additional CO

and H

. This process increases the

/CO ratio as well as CO

content in the shifted gas.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Analysis of Sector-wise CO

Emissions

Figure 2-31: A Typical Coal Gasification Based Ecosystem

2.2.6.3 CO

Emission from the Gasification Industry

Though the Government of India has envisioned 100

mtpa of coal gasification by 2030, actual

implementation may be delayed given the progress

of the existing projects and the long gestation period

and uncertainties involving gasification projects. The

emissions have been estimated considering the

announced projects, as well as 1 mtpa hydrogen

production from coal gasification. Based on the

values of emission intensities for various end

product through syngas route, the capturable direct

process emissions have been considered. The actual

emissions will vary based on the actual

downstream products produced from the syngas.

Excess moisture present in the syngas takes part in

the shift reaction to achieve the required H

/CO

composition. The required additional steam is

injected to the reactor.

Acid gas removal: Syngas conditioned in the water

gas shift process contains CO

and H

S which are

removed in the acid gas removal unit. CO

captured and sent to the carbon dioxide processing

hub for compression. The H

S in the syngas is also

captured and sent to the sulphur recovery unit.

There are multiple commercially proven absorption

processes using both physical and chemical solvents.

However, due to the high concentration of CO

at the

inlet of the acid gas removal process, a physical

solvent based acid gas removal system is

generally used.

Ammonia

Plant

Gasifier

Air

Separation

Plant

Gasifier

Heat

Recovery

Water

Gas Shift

/CO : 2.3

Rich

Gas

Electric

Power

Air

Steam

46% gas by-pass for Methanol

and IGCC Plant

Sulphur

S Rich

Gas

EOR

Field

Carbon

Processing

Hub

Chemical Block

IGCC Block

Steam

Flue

Electric

Power

Capture

Ammonia

Plant

Hydrogen

Plant

Methanol

Plant

Heat

Recovery

Steam

Turbine

Gas

Turbine

Compression

Sulphur

Recovery

Syngas

Cooling

Particulate

Removal

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

Table 2-19: Sector-wise CO

Emissions and Interventions Required

2.3 Key Interventions Required

The estimated CO

emissions from key sectors of the Indian economy requiring CCUS interventions are

tabulated below:

Thermal power

generation

Even with RE growth, coal-based power

will continue to meet more than 50% of

electricity demand. As the largest emitter

of CO

, CCUS of the power sector is

essential for meaningful decarbonization

and ensuring energy security in India

Establish CCUS clusters in

key identified districts

1,004 1,210

Steel

Future steel growth is largely based on

the BF-BOF route, where use of fossil

fuels is hard to replace. CCUS is

necessary for sustainability and also

ensures export competitiveness

Establish CCUS for

Integrated Steel Plants,

particularly in Eastern India

240 450

Cement

Another major CO

emitter, where fossil

fuels are difficult to replace. Utilization of

in aggregates has synergies with the

cement business

Establish CCUS clusters in

key identified areas/districts

196 325

Oil & gas upstream,

refineries &

chemicals

Hard to abate sector. CCUS essential for

the sustainability of the sector; carbon

capture inbuilt in many of the processes

Decarbonize key applications

like urea, olefins, syngas

from petcoke

125 177

Hydrogen

Blue hydrogen is key to the hydrogen

economy of the future. Carbon capture is

unbuilt in the H

production process

Establish pathways for CO

utilization and storage

56 102

Coal gasification

Sunrise sector - key to materials and

energy security of India, based on India’s

rich endowments of coal

Establish pathways for CO

utilization and storage

- 27

Total 1621 2291

Products Emission Intensity, Expected production CO

emission projection

TCO

/TProduct 2030, mtpa in 2030, mtpa

Hydrogen 13 - 15 1 14.0

Methanol 2 – 2.7 2 5.0

Ammonia 3 - 3.5 1.4 4.6

Urea 1.5 - 1.7 2 3.2

Total 27

Table 2-18: Total CO

Emission from Coal Gasification

Sector Rationale for CCUS Key interventions

required

2020 2030

Estimated CO

emissions (in mtpa)

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

The categorization of emissions depending on CO

concentration, stream, pressure, synergy with

existing operations, as well as CO

emission

baselining is an immediate requirement for the

development of carbon capture projects in India.

Capturing from high concentration CO

sources

(more than 30%) like HGU tail gas, gasification, etc.

will reduce the CO

footprint with a low to moderate

cost impact; however, the capturable CO

volume is

limited to 100-150 mtpa i.e., 4 to 6% only of overall

emissions. So, it is important to prioritize carbon

capture demonstration projects for high CO

concentration and low to medium volume sources.

Once technologies, as well as the disposition

strategy, are finalized and demonstrated at a certain

scale, carbon capture for low concentration and high

volume sources such as power plants, steel &

cement plants can be gradually taken up. However,

the CO

volume for power and steel plants is often

more than 5 mtpa, which is significantly higher than

any other industry. So, it will be advantageous to

develop CCU cluster infrastructure based on

large-scale power or steel projects as anchor

projects, which will lower the CCUS infrastructure

costs for small and medium scale CO

emitters and

enable them to adopt carbon capture projects.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Analysis of Sector-wise CO

Emissions

Chapter 3

Overview of CO

Capture & Utilization

Technologies

3.1 Introduction to Carbon Capture Technologies

capture technologies separate carbon dioxide from

gas streams that are released from industrial processes

such as power plants, chemical production, cement

production or steel making. There are three different

broad categories of technologies for capturing CO

post-combustion capture, pre-combustion and oxy-fuel

combustion. The operating principles of each is

depicted in Figure 3-1.

(i) Post-combustion technologies: CO

is separated

from the flue gas after combustion. Fossil fuels

like coal, oil, NG etc., are burnt in the presence of

air; hence the flue gas is rich in N

, and the CO

percentage typically varies between 3% to 15%.

Since the partial pressure of CO

in the flue gas is

quite low, very high-volume chemical solvent

(amine) circulation is required for CO

capture,

making post-combustion technologies energy and

cost-intensive.

(ii) Pre-combustion technologies: they involve

removing CO

through the upstream treatment of

fossil fuels prior to combustion. The major

difference between pre-combustion and

post-combustion is that the former is favoured in

cases where the gas stream has a higher partial

pressure of CO

, such as in gasification of fossil

fuels, NG based H

production or sour gas

processing. Since no chemical bonds need to be

broken for solvent regeneration, the thermal

energy penalty is much lower.

The regeneration of the physical solvent is

primarily achieved by reducing pressure.

(iii) Oxy-fuel combustion technologies: While

post-combustion and pre-combustion carbon

capture technologies have been commercially

established, oxy-fuel combustion technologies are

still in the developmental stage. Oxy-fuel

combustion represents an emerging novel

approach to near zero-emission. It is accomplished

by burning the fuel in pure oxygen (O

) instead of

air (O

and N

). The flue gas stream would be

primarily composed of water and CO

, rather than

. High purity CO

can be recovered by the

condensation of water.

Direct Air Capture (DAC): DAC directly captures

dilute CO

(at 415 ppm) from the air, and may also

emerge as a form of carbon capture that has wide

applicability, as it is independent of the source and

concentration of the emission stream. However, DAC

is still in early stages and the economics and scale of

operations are yet to be established.

Figure 3-1: Scheme of Post-combustion, Pre-combustion & Oxy-fuel combustion

Pre-Combustion1

Post-Combustion2

Oxy-Combustion3

SynGas for

DR Plant

Methanol,

Power, etc.

Impurities

Air O

Fuel

Air

Partial Oxidation

capture

Air

Separation

Plant

Syn Gas

(>25%)

Flue Gas

(3-15%)

Combustion

O &

Impurities

Air O

Fuel

Combustion

capture

Air

Separation

Plant

Flue Gas

(>90%)

Removing

prior to

their

combustion

Removing

after

combustion

Removing

after

combustion in

controlled

environment

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

3.2 Mature and Commercially Proven CO

Capture Technologies

The mature and commercially proven CO

capture

technologies can be broadly classified into three

groups, as shown below. Additionally, there are

membrane, microbial and algae-based CO

capture technologies, but these are at the

developmental stage.

i) Solvent-based absorption

a) Physical solvent based absorption

b) Chemical solvent based absorption

ii) Adsorption

iii) Cryogenic separation

Brief descriptions of the aforementioned commercially proven and matured carbon capture technologies are provided.

Figure 3-2: Simplified Representation of CO

Capture Technologies

Figure 3-2: Simplified Representation of CO

Capture Technologies

Physical solvent based

Feed

Gas

Other

components

Physical

Solvent

Chemical solvent based

(i) Solvent based absorption

(ii) Adsorption (iii) Cryogenic separation

Feed

Gas

Feed

Gas

Other

components

Other

components

Adsorbent

Capture

Chemical

Water

(Base solvent)

Feed

Gas

Other

components

A simplified schematic depiction of these matured technologies is shown in Figure 3-2.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

Figure 3-4: Schematic Representation of

Absorption Capacity of Chemical and

Physical Solvents as a Function of

the Partial Pressure of CO

3.2.1 Solvent-Based Absorption

Solvent-based CO

capture processes have been used for

over half a century for processing natural (sour) gas,

combustion flue gas and Fischer-Tropsch (FT) synthesis

products. The fundamental principle on which

solvent-based CO

capture technologies work is ‘selective

absorption’ of CO

over the other gaseous constituents.

The working principle of solvent-based CO

capture is

depicted in a schematic flow diagram in Figure 3-3.

While the CO

present in the feed/process gas is first

selectively absorbed in an absorber using a solvent

(physical or chemical), the CO

lean gas exits the

absorber. Next, the CO

rich solvent is sent to a

stripper-type configuration where the CO

is released

from the solvent and the lean solvent is regenerated for

reuse. The CO

rich stream needs to be purified,

dehydrated, and compressed to raise the pressure to the

required level: supercritical CO

for pipeline

transportation or liquefied CO

for ship or road

transportation. Supercritical CO

can be obtained at

pressures of >74 bar(a) at ambient temperature, whereas

liquefied CO

can be obtained at pressures of 6-7 bar(a) at

a temperature of about -50 °C. In the case of pipeline

transportation to oilfields for EOR, the exit pressure at

the carbon capture complex is determined based on the

transportation distance and miscibility pressure

requirements in the oil reservoir.

The solvent-based CO

capture technologies are

distinguished based on whether CO

reacts with the

solvent chemically (chemical absorption) or dissolved

physically (physical absorption). A schematic depiction of

the relationship between the CO

absorption capacities of

chemical and physical solvents (known as ‘solvent

loading’) and partial pressure of CO

in the gas stream is

provided in Figure 3-4.

Figure 3-3: Schematic Representation of Working Principle of Solvent-Based CO

Capture

Physical solvent

Chemical solvent

Partial pressure of CO

Absorption Capacity /

Solvent Loading

Favors Physical solventFavors Chemical solvent

lean gas

lean solvent

rich solvent

Reboiler

Compressor

EOR / F&B / Storage

Feed gas

Absorber

Stripper

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Chemical absorption based CO

capture is better

suited for gas streams having a low concentration and

partial pressure of CO

due to the high chemical

affinity of CO

to amine-/carbonate-based chemical

solvents as well as faster rate kinetics. While the

chemical solvents can achieve high absorption

capacity at low partial pressures of CO

, a

non-reactive or physical solvent performs well at

higher partial pressures of CO

. As shown in Figure

3-4, the solubility curve for a physical solvent typically

follows Henry’s law, i.e., a linear relationship with the

partial pressure of CO

A chart depicting the operating ranges of various

solvents for CO

capture is shown in Figure 3-5 and

forms the basis for selecting suitable CO

solvents.

The low CO

partial pressures in the flue gas of

coal-fired power plants make amine-based chemical

absorption the preferred technique. However,

relatively higher gas stream pressure and CO

concentration, such as in the syngas of gasifiers

and SMRs make physical absorption-based capture

more suitable.

3.2.1.1 Chemical Solvent-Based Absorption

A basic flow diagram for a chemical solvent-based CO

capture is depicted in Figure 3-6. The chemical

reaction between CO

and the chemical solvent is an

exothermic reaction and hence favoured at lower

temperatures. Hence it is necessary to pre-cool the

feed gas. During the cooling of the feed gas, water

condenses out of the wet gas.

Figure 3-5: Operating Regimes of Various Solvents for CO

Capture

Physical solvent,

hybrid, or hot

potassium

carbonate

Physical solvent

Hybrid

-1

Amine

Partial pressure of acid gas in feed, psia

Activated hot potassium carbonate or amine

Physical solvent or activated hot potassium carbonate

Partial pressure of acid gas in product, psia

Line of equal inlet and outlet pressures

Activated hot potassium carbonate

or inhibited concentrated amine

Source: NETL, US Department of Energy (DOE)

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The cooled gas stream reacts with the amine-based

solvent at 40-60°C via a countercurrent flow reaction

within the absorber column, resulting in:

a) CO

free gas stream; and

b) Solvent with chemically bound CO

Multiple stages of structured packing in the absorber

columns maximize the contacting surface area and

mass transfer rate of CO

in the solvent during the

countercurrent flow. While the CO

depleted gas

stream leaves the absorber from its top stage, the CO

rich solvent stream exits the absorber column from its

bottom stage, and is pumped to the stripper, where

the application of higher temperatures (100-140°C)

results in regeneration of the solvent by breaking the

chemical bonds between CO

and the chemical

solvent. The heat required for the regeneration of the

solvent is provided by a reboiler, supplied with steam

extracted from captive CHPs/CGPs. Such a heat and

strip operation for the regeneration of the solvent

leads to a high thermal energy penalty. Depending on

the solvent used and system configuration, the steam

consumption for solvent regeneration can range from

1.1 to 1.5 t/tCO

While the dense CO

stream exits the stripper from its

top stage, the CO

lean solution is cooled and

recirculated to the absorber. Typically, the absorber and

stripper’s operating pressures for chemical

solvent-based capture are low, ranging from 1 – 4 bar(a).

The primary characteristics of a solvent that need to be

analyzed to determine its efficacy are as follows:

a) Rate kinetics: Faster rates of reaction between

the solvent and CO

ensure better mass transfer

performance at the gas-liquid interface, thus

facilitating a smaller absorber volume and a lower

cost of capture.

b) CO

carrying capacity: A higher CO

carrying

capacity of the solvent reduces the regeneration

load, auxiliary unit costs and energy

requirements.

c) Reaction enthalpy: A lower enthalpy for the

reaction between the solvent and CO

transpires

into lower energy requirements to break the

solvent-CO

bond during desorption.

d) Water content: A decrease in water content in

the solvent (aqueous solution) decreases the

energy loss associated with vaporizing water

(during CO

stripping at high temperatures) and

increases the CO

carrying capacity of the solvent.

e) Other desirable characteristics of the solvent:

- Low CO

equilibrium backpressures at

absorption conditions

- Easy reversible reactions at regeneration

temperatures

- Low volatility of the solvent

- High resistance of solvent to oxidative and

thermal degradation

Figure 3-6: Typical Flow Diagram of a Chemical Solvent Based CO

Capture

Flue gas to stack

>95% pure CO

to compression (2 bar)

90% captured

Lean solvent

2.1 bar

115

23 bar

~130

saturated

Water wash

LP steam

Condensate

Flue gas

Water make-up Rich solvent

Absorber tower (40

Stripper tower

Reflux drum

Wash water

cooler

Lean solvent

cooler

Reflux

condenser

Solvent

reboiler

Flue gas

cooler

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A multitude of chemical solvents have shown varying

degrees of success, including amine-based (primary/

secondary/tertiary/hindered), non-aqueous solvent

(NAS), carbonate-based and phase change. While

primary and secondary amines (such as MEA, DGA,

AEE, DEA) have higher reaction rates and lower CO

carrying capacities, tertiary, and polyamines (such as

MDEA and piperazine) have lower reaction kinetics and

higher CO

carrying capacities. Due to competing

characteristics, often blends of varying solvent

compositions are used to exploit high reaction rates

and CO

carrying capacity along with lower

regeneration loads. Specifically, for MEA based

systems, the steam (LP steam at ~3 bar(a)) energy

requirement for solvent regeneration can range from

3.6 to 7 GJ/t CO

, depending on the system

configuration and heat integration. A few of the proven

and emerging solvent-based technologies are

described below:

a) Air Liquide Amine

Both generic and proprietary amine-based

solvents are used in the carbon capture solutions

provided by Air Liquide. A process flow diagram

for carbon capture using Air Liquide’s

amine-based solvent is depicted in Figure 3-7. The

major process units include:

 - Pre-cooler: cools the feed gas to the desired

temperature

- Absorber: CO

is absorbed in the solvent

through a chemical reaction, facilitated by the

countercurrent flow of the solvent and the

feed gas

- Regenerator: recovers the solvent by CO

stripping and recirculates the solvent back to

the absorber

The proprietary OASE

(or former aMDEA

patented by BASF) amine solvent is also used

apart from generic amine solvents. The main

characteristics of the amine-based BASF OASE

solvent are as follows:

 - Proprietary composition: most likely consists

of blends of amines (primary/secondary/

tertiary/hindered) and activators

(heterocycles, primary or secondary

alkanolamines, alkylenediamines or

polyamines)

- Solvent stability: Higher stability than MEA

- Energy consumption for CO

stripping and

solvent regeneration:

• Significantly lower (2.4 to 2.6 GJ/t CO

)

compared to MEA (3.6 to 7 GJ/t CO

)

• Similar to piperazine (2.4 to 2.6 GJ/t CO

)

Figure 3-7: Process Flow Diagram of Air Liquide’s Amine Based CO

Capture

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Acid Gas

(to LTGT

)

Clean Gas (to DMR)

Demin

Water

Feed

Gas

Absorption RegenerationHP-Flash

Flash Gas

(to CLS)

Source: Air Liquide Technology Handbook 2017

b) ION Clean Energy’s Proprietary Amine-Organic

Solvent

In collaboration with the US DOE NETL, ION Clean

Energy (ION) has developed a proprietary solvent

consisting of a low aqueous amine with an

‘organic liquid’ as the solvent (instead of water).

Due to its lower sensible and latent heats, organic

liquid results in a lower thermal regeneration

energy duty compared to water. Their system

design also includes process modifications such as

cold rich gas bypass and intercooling, which

further lowers the reboiler duty. A process flow

diagram for carbon capture using ION’s

proprietary ICE-21 solvent is depicted in Figure

3-8. The major process units include:

 - Pre-scrubber: Removes SOx, other harmful

gases and most of the particles

- Direct contact cooling unit: Controls inlet

flue gas temperature and humidity

- Absorber: A packed column removes CO

using the proprietary ICE-21 solvent through a

chemical reaction, facilitated by countercurrent

flow of the solvent and feed gas

- Water wash: Removes solvent droplets and

vapors from the exhaust gas

 - Regenerator: Recovers the solvent by CO

stripping and recirculates the solvent back to

the absorber

Figure 3-8: Process Flow Diagram of a Pilot Slipstream Test Unit at National Carbon Capture Center,

USA using ION’s Proprietary ICE-21 Solvent for CO

Capture

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Source: ION Report 2018

Absorber Column

Direct Contact Cooler

Flue Gas From Polisher

Flue Gas

Steam (Sat.)

Condensate

Regeneration

Column &

Reboiler/Thermosiphon

Flue Gas Blower

Clean Flue Gas

Purge

Wash Water

Column

Solvent Surge Tank

Mist Separator

Process

Water Tank

Cool Rich Solvent

Hot Rich

Solvent

Warm Lean

Solvent

Hot Lean

Solvent

Shell & Tube

Thermosiphon Reboiler

Lean

Solvent

Trim

Solvent

Cooler

Economizer

The main characteristics of ION’s proprietary

amine-organic solvent are as follows:

- Proprietary composition (ICE-21 and ICE-31):

Amine with an organic solvent; low water content.

- Solvent stability: Resistant to thermal

degradation with low heat stable salt buildup on

exposure to SOx and NOx

- Energy consumption for CO

stripping and

solvent regeneration:

• Significantly lower (1.6 to 2.5 GJ/t CO

)

compared to MEA (3.6 to 7 GJ/t CO

)

• Solvent regeneration in flash vessels

instead of conventional packed bed

stripper columns and reboilers lowers

capital costs

- Solvent recirculation rate: ~30% lower than

MEA for 90% CO

capture; lowers capital costs of

the pumps, heat exchangers and flash vessels

c) Kansai Mitsubishi Carbon Dioxide Recovery

(KM CDR

)’s Proprietary Amine solvent

The advanced amine-based absorption technology

named Kansai Mitsubishi Carbon Dioxide

Recovery (KM CDR

) was jointly developed by

Mitsubishi Heavy Industries Ltd. (MHI) & Kansai

Electric Power Co. Inc. The KM CDR process has

historically used the proprietary solvent named

the KS-1

solvent, with the potential to capture

over 90% of the CO

from a flue gas stream and

generate CO

with over 99.9% purity. The KS-1

solvent is an advanced sterically hindered amine.

The development of a new solvent has improved

the original KM-CDR process: KS-21

. A process

flow diagram for carbon capture using KM CDR’s

proprietary KS-1

solvent is depicted in

Figure 3-9.

Figure 3-9: Process Flow Diagram of KM CDR CO

Capture using Proprietary KS-1 Solvent

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Source: US DOE NETL Compendium of Carbon Capture Technology 2020

Flue Gas

Outlet

Condenser

REGENERATOR

ABSORBER

C.W.

Flue Gas

Quencher

Reboiler

Steam

Purity: 99.9%

The major process units include:

- Flue gas pretreatment: Cools the flue gas to

the desired process temperature and also

enables trim acid gas removal along with gas

scrubbing to remove contaminants in a deep

polishing scrubber

- Absorber: CO

is absorbed in the proprietary

KS-1

solvent through a chemical reaction,

facilitated by the countercurrent flow of the

solvent and the feed gas

- Regenerator: Recovers the KS-1

solvent

by CO

stripping and recirculates the solvent

back to the absorber

The main characteristics of KM CDR KS-21

solvent

are as follows:

- Proprietary composition: sterically hindered

amine

- Recovery of 95% of the CO

from the flue gas

- Low solvent volatility, which reduces the height of

the water wash section of the CO

absorber

- Improved thermal stability of the solvent

allows the regenerator to operate at a higher

pressure and temperature

- Low heat of absorption: allows high circulation

rate and low steam consumption.

- Good resistance to oxidative degeneration

that reduces solvent loss

d) UOP Solvent Systems

UOP has several solvent-based solutions for CO

capture, including Amine Guard

FS, Benfield

and SeparALL

. Amongst these, the Amine

Guard

FS is arguably the most widely accepted

technology. It uses the proprietary UCARSOL

chemical solvents (MDEA based), formulated by

The Dow Chemical Company. The solvents have a

high affinity for acid gas components. UOP

Benfield

uses a chemical solvent that is made up

of activated hot potassium carbonate. A process

flow diagram for carbon capture using UOP’s

Amine Guard

FS solvent is depicted in Figure

3-10. The major process units include:

 - Absorber: CO

absorption in the proprietary

UCARSOL

solvent through a chemical

reaction, facilitated by the countercurrent

flow of the solvent and the feed gas

- Regenerator: Recovers the UCARSOL

solvent by CO

stripping and recirculates the

solvent back to the absorber

- HP & LP flash columns: Higher pressure

operations allow exploitation of flash

regeneration

Figure 3-10: Process Flow Diagram of the Amine Guard

FS CO

Capture

using Proprietary UCARSOL

Solvent

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Source: UOP Technical paper

Apart from the conventional flow scheme, other flow

schemes are also possible depending on the feed gas

characteristics and final product specifications, as

depicted in Table 3-1.

Table 3-1: Comparison of Various Flow Schemes of UOP Amine Guard

FS Technology

Scheme Configuration Feed gas Desired product Solvent Cons. Reboiler duty,

quality quality MBTU/lb CO

removed

Conventional

Low acid gas (<7%)Absorber + thermal

regeneration

50 ppmv

Lowest 45-60

Flash only

Very high acid

gas (>12%)

Absorber + flash

column

>2% CO

Low 8-10

1-stage

High acid gas

(7-12%)

Absorber + flash

column + thermal

regeneration

50-1000

ppmv CO

Higher than

flash only

32-40

2-stage

Very high acid

gas (>12%)

1-stage + semi-lean

solvent stream

500 ppmv

Highest 12-18

The main characteristics of the proprietary

UCARSOL

solvent are as follows:

- Proprietary composition: MDEA based

solvent with low activator concentrations;

solvent formulation can be tailored to achieve

specific levels of CO

absorption. Amine

Guard

II uses inhibitors to increase the

alkanolamine strength

- Fast kinetics: Activator accelerates the slow

overall kinetics of the chemical reaction

between CO

and MDEA

- Reduced packing height of absorber column:

Use of an activator facilitates reduced

column heights

- High thermal and chemical stability

- Non-corrosive solvent: No corrosion

inhibitors needed

- No foaming problems

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e) Baker Hughes Chilled Ammonia Process (CAP)

A process flow diagram for carbon capture using

the Baker Hughes Chilled Ammonia Process (CAP)

is depicted in Figure 3-11.

Figure 3-11: Process Flow Diagram of Baker Hughes Chilled Ammonia Process (CAP)

using Ammonium Carbonate Solvent

An ammonia-based solvent, ammonium carbonate

solution, is used for the absorption of CO

from flue

gas at low temperature in the Chilled Ammonia

Process (CAP). The ammonium carbonate solution

reacts with CO

present in the flue gas to form

ammonium bicarbonate. The regeneration of solvent

and release of CO

from the solution is facilitated by

raising the temperature in the regenerator.

The major process units of the CAP include:

- Flue gas cooling: Cools the flue gas to the

temperature desired for absorption

- Pretreatment: for removal of NOx, SOx and

other contaminants to acceptable levels

- Absorber: CO

is absorbed in the ammonium

carbonate solvent through a series of

chemical reactions.

- Ammonia-based chiller system: Reduces

ammonia volatility.

- Sulfuric acid supply: Enables reduction of

ammonia emissions into the atmosphere to

acceptable levels.

- Stripper: Recovers the solvent by stripping

from ammonium bicarbonate solution and

recirculates the solvent back to the absorber.

The stripping operation can take place at

higher pressure as the solvent can tolerate

higher temperatures.

The main characteristics of the process include:

- High purity CO

and delivery pressure

- Tolerant to oxygen and flue gas impurities

- No degradation of solvent

- No emission of trace contaminants

- Efficient capture of CO

(90%)

- Low-cost, globally available reagent

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Source: Baker Hughes

3.2.1.2 Physical Solvent-Based Absorption

The major difference between chemical solvent-based

capture and physical solvent-based capture is that the

latter is favored in cases where the gas stream has a

higher partial pressure of CO

, such as in gasification,

sour gas processing or syngas from SMRs. There is no

chemical reaction involved in the capture process as it

is guided purely by physisorption. Since no chemical

bonds need to be broken for solvent regeneration, the

thermal energy penalty is much lower. The

regeneration of the physical solvent is achieved by

reducing pressure. However, the operating

temperatures of physical solvent-based capture

processes are much lower (ranging from -70°C to

+20°C) compared to chemisorption-based capture,

thus necessitating higher power consumption. The two

major commercially available physical

absorption-based technologies are discussed.

a) Rectisol

In the Rectisol

process, the shifted syngas (after

the WGS stage in the HGU) needs to be cooled

first and then sent to the absorber column. The

physical solvent used for CO

absorption is chilled

methanol (at sub-zero temperatures). CO

stripped from the CO

rich solvent in the stripper

and compressed for transportation. The

regenerated solvent is recycled and reused in the

absorption unit. One advantage of this process

route is that water levels in the exit CO

rich

stream are very low, thus eliminating the

dehydration facility requirement. The process flow

diagram is depicted in Figure 3-12 below.

b) Selexol

The Selexol

process uses a mixture of dimethyl

ether of polyethylene glycols (DEPG) and has two

variants. The first variant removes all the acid gas

components (H

S and CO

) in one step; the second

is a dual-stage process where H

S is removed first,

followed by CO

The typical process operating temperature is

between 0-20°C, which saves on the refrigeration

cost compared to the Rectisol® process. The feed

gas is supplied at a pressure of 2-15 MPa with a

partial pressure of 0.7-3 MPa. A basic process

flow diagram of the Selexol

process is depicted

in Figure 3-13.

Figure 3-12: Basic Process Flow diagram of the Rectisol

Process

Syngas

CO, H

Refrigerant

CO shift

conversion

Heat

exchanger

Cooler

Absorber

Flash

regeneration

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Figure 3-13: Basic Process Flow Diagram of the Selexol

Process

Treated gas

Lean solvent

Flue gas

Heat

exchanger

Rich solvent

Make-up Water

to compression

Absorber tower

Stripper tower

Knock-out drum

condenser

Reboiler

Lean solvent

filtration

Lean solvent

cooler

Rich solution

flash drum

3.2.2 Adsorption

In the adsorption-based CO

capture process, the CO

molecules selectively adhere to the surface of the

adsorbent material and form a film, as shown in Figure

3-2 (ii) earlier. This is possible because of the difference in

diffusivities and heat of adsorption values for the feed

gas stream components.

The working principle of adsorption-based CO

capture

can be described in three primary steps:

- CO

adsorption on the surface of the adsorbent

material

- Diffusion of other gaseous molecules through the

adsorbent material and exit from the system

- CO

desorption by either decreasing pressure or

increasing temperature. While the former is known

as Pressure Swing Adsorption (PSA), the latter is

called Temperature Swing Adsorption (TSA)

Since TSA operations involve high temperatures, it

may lead to degradation of the desirable products and

reduce the life of the adsorbent material. Since there

is no need for heating/cooling in the PSA route, the

cycle time is significantly reduced to the order of a

few minutes. Hence, adsorption through the PSA route

is the preferred choice, allowing the economical

removal of a large number of impurities.

The PSA route comprises timed cycles of adsorption,

pressure equalization, depressurization, blowdown,

purge and re-pressurization across multiple fixed

beds. These beds consist of different types of

adsorbent materials, such as activated alumina, silica

gel, activated carbon or molecular sieves. Few

relevant PSA based technologies for carbon capture

are described below:

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3.2.2.1 Air Products Vacuum Swing Adsorption (VSA)

The process flow diagram of the Air Products’ VSA technology is depicted in Figure 3-14.

Figure 3-14: Basic Process Flow Diagram of Air Products’ VSA Technology

Source: IEAGHG 2018 Report on “The Carbon Capture Project at Air Products’ Port Arthur Hydrogen Production Facility”

The various features and steps of the process are

outlined below:

- The SMR syngas is cooled in the cold process

condensate separator

- VSA vessels (fixed beds) consist of high surface

area adsorbent material, on which the CO

molecules are selectively adsorbed

- The SMR syngas at high pressure is sent to one

vessel for adsorption, while the other vessels

undergo low-pressure regeneration

- The H

rich sweet syngas (devoid of CO

) is sent to

the existing PSAs for purification

- A series of pressure equalizations are performed

in the VSA vessels at reduced pressures before a

vacuum pump removes the CO

- The blowdown gas is taken from the intermediate

pressure bed during a ‘rinse step’. This gas is

compressed and fed to a higher pressure bed to

improve the CO

recovery

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3.2.2.2 UOP Polybed

PSA systems

Typically, a five-step pressure swing cycle is followed

in UOP’s Polybed

PSA systems. The steps are shown

Figure 3-15: Five-step Pressure-swing Cycle of UOP’s Polybed

PSA Systems

- Step 1 (Adsorption): The feed gas (usually flowing

in the upward direction) enters an adsorber vessel

at high pressure. Once the adsorbent material is

saturated, the vessel is taken offline and the feed

is automatically switched to a fresh vessel

- Step 2 (Co-current depressurization): The

adsorbed vessel is co-currently (in the same

direction of feed gas flow) depressurized to

recover the residual product components. This

residual product gas is used internally to

repressurize and purge other adsorbers

- Step 3 (Countercurrent depressurization): Right

after the co-current depressurization step, the

adsorbent is partially regenerated by

counter-currently depressurizing the adsorber to

the tail gas pressure. At the same time, the

impurities are rejected

- Step 4 (Purge): Further regeneration of the

adsorbent is achieved by purging it with a

high-purity stream obtained from Step 2

- Step 5 (Re-pressurization): On repressurizing

(with the gas stream from Step 2 and a slipstream

from the product or the feed), the adsorber

reaches the adsorption pressure and is ready for

the next adsorption step. This marks the

completion of the cycle

3.2.3 Cryogenic Separation

Cryogenic separation for CO

capture is similar to the

conventional distillation process, except that it involves

the separation of components from a gaseous mixture

(instead of liquid) based on the difference in their

boiling points. A simple schematic illustration is

provided in Figure 3-2 (iii). The feed gas stream is

cooled to sub-zero temperatures (lower than -50°C) to

separate CO

from the other components. Due to the

extreme operating conditions of high pressure and low

temperature, it is an energy intensive process. The

energy consumption can range from 600-660 kWh/t

recovered in liquid form. Few relevant cryogenic

separation-based technologies for carbon capture are

described herein.

schematically in Figure 3-15, where red and blue

represent the impurities and the product, respectively.

Product To Next

Vessel

Feed Tail Gas

Purge

From

Product

From Other

Vessel

Tail Gas

Red: impurity | Blue: product

Step 1:

Adsorption

Step 4:

Purge

Step 2:

Co-current

depressurization

Step 3:

Counter current

depressurization

Step 5:

Re-pressurization

Source: UOP White Paper

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Figure 3-16: Process Flow Diagram of the Cryocap

Technology

3.2.3.1 Air Liquide’s Cryocap

Technology

The Cryocap

technology for CO

capture is based on

the principle of cryogenic separation combined with

Natural

gas

Fuel

Residue

to fuel gas

Product

SMR Shift

Membranes

Cold

Box

-PSA

membrane separation. The process flow diagram of

the Cryocap

technology is depicted in Figure 3-16.

The important features of this technology are listed

below:

- A combination of partial condensation and

distillation is utilized for CO

separation from the

other components

- The non-condensed gases are recycled through a

membrane system to recover H

and CO

- Over 98% CO

recovery is possible

- Additional (13 to 20%) H

production can be

achieved with the same amount of SMR feed i.e.

natural gas. The credit of the additional H

savings in natural gas consumption for the

production of the same quantity of hydrogen (as

the case may be) reduces the overall cost of

carbon capture

- The residual gas is utilized as a fuel for the

reformer (SMR)

- It is possible to produce food-grade CO

by adding

a step of catalytic bed purification to destroy all

the remaining hydrocarbons and alcohols

- Lower area footprint is required compared to

amine-based systems

3.2.3.2 UOP’s Ortloff Dual Refrigerant CO

Fractionation (DRCF)

- The Ortloff Dual Refrigerant CO

Fractionation

(DRCF) technology is similar to Air Liquide’s

Cryocap

technology. Some of the key features

include:

- Recovery of CO

in the liquid state

- Low energy consumption due to liquid state

separation (no need to solidify CO

)

- Additional recovery is possible from the residue

gas stream by coupling DRCF with a physical

solvent like Selexol™ or membranes

- Lower area footprint than amine-based systems

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

3.3 R&D in Direct Air Capture

DAC directly captures dilute CO

( 415 ppm) from the

air, and may also emerge as a form of carbon capture,

as it has wide applicability and is independent of the

source and concentration of the emission stream. DAC

is still in its early stages and the economics (present

cost of DAC is estimated to range between US$

400-800/tonne of CO

) and scale of operations are

yet to be established. Given the wide applicability of

DAC as also the opportunity to remove CO

stock from

the atmosphere, it is important from a policy

perspective to support R&D in DAC technologies.

3.4 Microalgae Based

Carbon Capture

Microalgae cultivation has piqued the curiosity of the

research community for its application in the field of

carbon sequestration and further production of various

value-added products such as renewable biofuels,

bio-fertilizers, bioactive substances, etc. They utilize

the sparsely concentrated CO

from the atmosphere

via Carbon Concentrating Mechanism (CCM) thus are

well qualified for CO

capture from a more

concentrated stream of flue gas. These can be

cultivated in saline water systems as well and do not

compete with food crops for arable land for cultivation.

Due to the faster growth cycle of these microalgae,

they can typically entrap 10-50 times more CO

compared to terrestrial plants. They can also deacidify

the seawater or wastewater used for their cultivation.

Owing to these factors, microalgae have been studied

for carbon capture and sequestration by several

researchers as well as industries around the globe.

The basic philosophy behind the process of carbon

capture by microalgae is the use of CO

as a nutrient

for the cultivation of microalgae. The selected strains

of microalgae can be cultivated in ponds or

vertical/horizontal photo-bioreactors. The flue gas

stream after removal of traces of heavy metals and

other harmful components can be mixed in the

ponds/photo-bioreactors, cultivating selected strains

of microalgae. The CO

will be absorbed by the

microalgae and the resulting gas will leave the

cultivation system. Selection of appropriate strain of

algae and maintaining its growth condition is critical

to this process of carbon capture.

The technology is in its nascent stages, with a

majority of tests being performed at lab and pilot

scales. The capture rate would vary with the climatic

conditions, location, algae strain, and other relevant

parameters. A demonstration was performed at

NALCO’s coal-based captive power plant facility in

Angul, Odisha in 2017, where algal productivity of 20

tons ac

-1

year

-1

was achieved, leading to a carbon

sequestration capacity of 32 tons ac

-1

year

-1

. A

simulation based study was also carried out for

simulation of algal productivity techno-economic

feasibility study for Odisha Power Generation

Corporation Limited (OPGC)’s coal-based power plant

in Jharsuguda, led by P. Balasubramanian et al. (2019).

The maximum average algal productivity achieved in

the biophysical model on MATLAB was 111.39 Kg ha

-1

enabling CO

sequestration of 147.03 Kg ha

-1

. This

translates to the sequestration figure of 1.32 Kg CO

Kg algal biomass produced in one hectare in a day.

The maximum growth varied each month with the

highest growth being observed in the month of

February. The techno-economic modelling was

performed in SuperPro Designer. The study revealed

that the production cost came out to be US$

58.41/metric tonne of algal biomass. The algal paste

could further be sold as a fertilizer which would lead

to an evaluated revenue generation. The technology

needs to further develop in both upstream (cultivation

and harvesting) and downstream (value added

products synthesis) stages for commercialization.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Overview of CO

Capture & Utilization Technologies

Summary of the CO

capture technology types and

applicability to carbon capture:

- Chemical solvent-based CO

capture

technologies: Preferred when dealing with gas

streams that are lean in CO

and have relatively

lower pressures, such as flue gases. The cost and

availability of steam is also a key factor as

regenerating the solvent requires large quantities

of steam.

- Physical solvent-based CO

capture

technologies: These work well on gas streams

with relatively higher CO

concentration and

pressure.

- Adsorption-based CO

capture: They are suitable

for pre-combustion capture, where the gas stream

has high pressure and a high CO

concentration.

- Cryogenic CO

capture: Preferred in cases where

the cost of power is low. This technology also

provides a unique advantage of generating

additional hydrogen without increasing the

amount of feedstock (natural gas)/ producing the

same quantity of hydrogen with lower natural gas

consumption.

The applicability of the various CO

capture

technologies viz., physical solvent, chemical solvent,

adsorption and cryogenic, depends on the project

objectives and the project-specific and gas stream

characteristics, including:

- CO

capture volumes targeted/desired

- CO

end usages and CO

purity required

- Source gas characteristics (CO

concentration,

pressure and volumes)

- Availability and cost of utilities such as steam,

power, water, fuel, etc.

- Plot availability and space constraints

3.5 Comparative Analysis of Various CO

Capture Technologies

Table 3-2: Comparative Analysis of Various Classes of CO

Capture Technologies

Chemical

Solvent

• Chemical reaction between

and solvent

• Governed by rate kinetics

& thermodynamics

• High absorption at low

partial pressure of CO

• Selective capture and

high purity CO

product

High energy (steam)

requirements for

solvent regeneration

• BASF / OASE®

• ICE-21, ICE-31

• KS-1

, KS-21

• UCARSOL

• CAP

Physical

Solvent

• Absorption due to CO

solubility in the solvent

• Governed by Henry’s Law

• Suitable for gas streams

with high partial

pressure of CO

• Regeneration through

low temperature flashing

or pressure reduction

• High absorption capacity

& lower solvent

recirculation rates

• Low energy efficiency

for low partial

pressure of CO

• High compression

requirement for low

pressure feed gas

• H

S often absorbed

more effectively than

• Rectisol

• Selexol

Adsorption

• Selective adsorption due

to difference in diffusivity

& heat of adsorption

• Governed by pressure

change

• Selective capture

• Can be performed at

normal temperatures

• Batch process

• Complex pressure

balancing

management system

• High electrical energy

consumption

• PSA

• VSA

• TSA

Cryogenic

Separation

• Low-temperature

separation through

liquefaction

• Governed by temperature

change

• Selective capture and

high purity CO

• Liquefied CO

product

• Food grade CO

• Almost no steam

consumption

• Low area footprint

• High energy

requirement

• High operating

pressure

• Cryocap

• Ortloff Dual

Refrigerant CO

Fractionation

(DRCF)

Process Working Principle Advantages Limitations Examples

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Overview of CO

Capture & Utilization Technologies

3.7 CO

Capture Cost Across Processes/Industries

The capital cost and cash costs of carbon capture

depends on CO

source characteristics (pressure &

concentration), capture technology, power &

steam sourcing costs. Given the trajectory of growing

emissions in India and the nascent stage of CCUS

in India, it is envisioned that by 2030, at least one

demonstration scale project carbon capture should be

implemented in each of the identified sectors.

The estimated CO

capture cost curve for demo scale

carbon capture projects in each sector is shown in

Figure 3-18. This curve is based on the CO

capture

potential in each sector, and the typical costs for

carbon capture projects, considering Indian costs and

conditions. Since the CO

source characteristics are

generally process-driven, the typical capture cost of

(including cash costs & capital charges) has been

estimated for a reference plant size for each sector.

delivery from the plant gate has been assumed at

100 bar (a) for each case.

capture cost is the lowest for the gasification

process, as carbon capture is already integrated

within the process. So, an additional cost of around

Rs. 400/tonne of CO

is estimated for polishing and

compression of the CO

stream. The capture costs for

other production processes like SMR-based H

production, iron & steel, cement, etc. include the costs

for gas processing, carbon capture, and compression

and are hence higher. Since CO

concentration is the

lowest for coal-based power plants, the capture cost is

the highest out of all major industries.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

Cement

Production

Iron & Steel

Production

Waste to

Energy

Power

Generation

Natural Gas

Power

Generation

Coal

Hydrogen

Production in

Reﬁnery

Chemical

Production

(Others)

Ethanol

Production

Fertisliser

Production

Natural Gas

Processing

Applications 1972 2010 2015 2020 2025

1.0 Mtpa OF C0

0.2 Mtpa OF C0 5.0 Mtpa OF C0

Size of the circle is

proportionate to the capture

capacity of the facility.

Chart indicates the primary

industry type of each facility

among various options.

IN OPERATION

IN CONSTRUCTION

ADVANCED DEVELOPMENT

3.6 Summary of Major Large Scale Carbon Capture

Commercial Projects

BREVIK NORCEM

ABU DHABI

CCS 1

SHUTE

CREEK

TERRELL

ABU DHABI

CCS 2

UTHMANIYAH

GORGON

QATAR LNG CCS

CNPC JILIN

SLEIPNER SNØHVIT

LOST CABIN

PETROBRAS

SANTOS

CENTURY

PLANT

SANTOS

COOPER

BASIN

CORE ENERGY

ENID FERTILISER WABASH

COFFFEYVILLE

PCS NITROGEN

ACTL NUTRIEN

GREAT

PLAINS

SINOPEC QILU

YANCHANG

LAKE

CHARLES

KARAMAY DUNHUA

SINOPEC

ZHONGYUAN

ILLINOIS INDUSTRIALBONANZA BIOENERGYARKALON

QUEST

BOUNDARY DAM

PETRA NOVA

PRAIRIE

STATE

SAN

JUAN

GERALD

GENTLEMAN

PROJECT

TUNDRA

CAL CAPTURE

MUSTANG STATION

PLANT DANIEL

FORTUM OSLO VARME ZEROS

ACTL

STURGEON

AIR PRODUCTS

SMR

Source: Global Status of CCS 2020 Report

Figure 3-17: Summary of Major Large Scale Carbon Capture Commercial Projects

Figure 3-18: Cost Curve for CO

Capture Across Processes/Industries

1000

400

4100

0 1 2 3 4 5 6 7 8 9 10 11 12

mtpa

2000

3000

4000

5000

6000

Gasification based product

SMR based H

Cement

Iron & Steel

Coal based power Refinery & Chemical

Note: The CO

capture costs depicted above include costs for capture, conditioning and compression to 100 bar (a) and the amortized capital costs

Figure 3-19: Possible CO

Utilization Pathways

3.8 Overview of CO

Utilization Technologies

Thways for utilization of the captured CO

are

primarily EOR, green urea production (conversion of

green ammonia to green urea using the captured CO

)

and utilization of CO

in food & beverage applications.

With the rising interest in CCUS as a decarbonization

solution across industries, there is also a need to look

at the CO

utilization pathways and technologies that

EOR Green Urea F&B usage

Building Material Chemicals Polymers

Proven Technologies

New Technologies

CaCO

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

are most appropriate for India. The possible CO

utilization pathways are illustrated in Figure 3-19.

(i) Enhanced Oil Recovery (EOR): Using CO

for EOR

has been successfully carried out for decades to

produce low-carbon oil from maturing oil fields in

North America and other geographies. With Indian

oil fields progressing towards their maturity, CO

EOR can play an important role in residual oil

extraction that is environmentally sustainable and

economically feasible.

(ii) Green urea: Urea production from green ammonia

can utilize a significant part of CO

. India’s current

production of ammonia and urea is primarily

based on imported LNG. So, renewable

energy-based ammonia can replace conventional

ammonia production with an increased scale of

renewables and a competitive cost of green

hydrogen production. While renewable-based

hydrogen is still in a nascent stage in India, the

new green hydrogen policy will boost electrolysis

based hydrogen production in the near future.

(iii) F&B applications: The utilization of CO

in F&B is

in applications such as carbonated drinks, dry ice,

and modified atmosphere packing; however,

the scales are quite small compared to the volume

of CO

generation/emissions.

Additionally, there are other promising propositions

for the utilization of CO

. The relatively matured CO

utilization pathways are:

(i) Building material (concrete and aggregates): A

high-level review of the new technologies

indicates that utilizing CO

for producing building

materials (aggregates and concretes) is likely to

be the most attractive and feasible option. There

is a large market for aggregates and concrete in a

developing country like India. CO

can be used

both during concrete curing and aggregate

formation. Since CO

is injected in a liquid state

without any conversion, relatively little energy is

consumed. Moreover, large volumes of alternative

feedstock, such as steelmaking slag, are available

sources of CaO/MgO which can be utilized to

produce synthetic aggregates. The simplified

schematic for the CO

mineralization process has

been illustrated in Figure 3-20.

(ii) Chemicals (methanol and ethanol): The

production of chemicals such as methanol and

ethanol from CO

have been proven at commercial

scales by various companies around the world. India

has ambitious plans for increasing indigenous

methanol production capacity and to that extent,

the NITI Aayog has also launched ‘Methanol

Economy’ programme. Methanol is a low carbon

hydrogen carrier fuel that can support

applications like fuel substitution, as well as an

intermediate for the production of various

speciality chemicals like acetic acid, MTBE, DME,

and formaldehyde which produce essential

products like adhesives, foams, plywood subfloors

etc. Thus, the proposed methanol economy

programme would not only bring down the crude oil

import bill and GHG emissions but also can establish

a billion-dollar methanol based economy.

Figure 3-20: A Simplified Schematic of CO

Mineralization Process

Carbon

Mineralization

Source

CaO & MgO from

waste concrete

Concrete for

new applications

vkREkfuHkZj

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

hydrogenation process is used to convert the

captured CO

into methanol. The typical

schematic for the CO

hydrogenation process

along with integration with the carbon capture

unit has been illustrated in Figure 3-21. The

hydrogenation reaction takes place in the

presence of a suitable catalyst.

The major challenges to this technology include

sourcing raw materials (H

, CO and CO

), their

capture and conditioning, sourcing clean power

for operations, and the conversion process. Some

technology suppliers in this field are Carbon

Recycling International (CRI), Thyssenkrupp and

Mitsui Chemical.

The Government has also set out a target for 20%

Ethanol Blend Petrol (EBP) by 2030. Ethanol can

be produced by ethylene hydration or biological

processes like using H

, CO and CO

by biological

gas fermentation process. Recently, Twelve (a

carbon transformation company) and LanzaTech

(a biotechnology company) have announced a

research and development partnership for CO

ethanol conversion that would eventually aid in

scaling up the process to the commercial level. In

2021, LanzaTech and Twelve had also announced

plans to develop propylene from CO

Conversion of CO

to methanol and ethanol

present attractive opportunities for India. Apart

from obvious advantages like reduction in oil

import bill and GHG emissions, it would also give

boost to commodity production in the country and

thus contribute to economic development and job

creation.

(iii) Polymers (including bio-plastics): The conversion

of CO

to polymers presents another possible CO

utilization route. Various kinds of polymers, such

as polyether carbonates, polycarbonates, diphenyl

carbonate, cyclic carbonates etc. have been

manufactured globally at different scales.

However, the polymer product named AirCarbon,

produced by the company named Newlight, has

found multiple applications (laptop packaging, cell

phone casings, furniture, etc.).

The development of new utilization technologies and

pathways would enable a circular carbon economy in

the country. The need of the hour is to support

research development and demonstration (RD&D) of

such technologies to establish their viability and aid

them in commercialization. The following table

summarizes the products, technologies and

production scales based on the new technologies for

utilization.

Figure 3-21: Typical Schematic for the CO

Hydrogenation Process

along with Integration with Carbon Capture Unit

Gas Processing &

Boosting Station

Capture Unit

to Methanol Unit

Electrolysis based H

Generation Unit

Pure CO

MethanolHydrogen

Sources

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

Table 3-3: Various CO

Utilization Pathways

Building

materials

Concrete San Francisco Bay

Aggregates LLC, USA

Blue Planet 33 ktpa (Phase-I)

Product Sub-category Project &

Location

Technology

Provider

14 ktpa (Phase-I)

Concrete Thomas Concrete, USA CarbonCure

Technologies

1.8 million yd

4500 tpa (across its

US operations)

Lightweight

construction

aggregates

AVR’s Energy from

waste plant, Duiven,

Netherlands

Carbon8 Systems 100 tonnes of

building product

(pilot level)

Concrete bricks Ghent Footpath

Construction, Belgium

Carbstone Innovation Unknown 1 m

of carbstone

bricks stores a net

350 kg of CO

Concrete Masonry

Unit (CMU)

- Carbicrete Unknown 3 kg CO

removed

per CMU

Chemicals

Methanol Shunli CO

-to-Methanol

plant, China

Carbon Recycling

International (CRI)

110,000 tpa 150,000 tpa

Methanol George Olah Renewable

Methanol plant, Iceland

Carbon Recycling

International (CRI)

4000 tpa 5500 tpa

Polymers

Bio-plastics

(AirCarbon)

• Dell Latitude series

laptop packaging

• Sprint cell phone cases

• KI plastic chair

components

Newlight > 23 ktpa Unknown

Polyether

carbonate

Cardyon mattresses,

Germany

Covestro 10 ktpa

Mattresses formed

of 20 % CO

Methanol ThyssenKrupp

Duisburg Steel Plant,

Germany

ThyssenKrupp Unknown Unknown

Ethanol Beijing Shougang

LanzaTech New

Energy, China

LanzaTech 60 kt (since May

2018)

100 kt CO

(since May 2018)

Ethanol Steelanol,

ArcelorMittal, Belgium

LanzaTech 80 million litres of

bio ethanol (aim)

~1.5 mtpa CO

(aimed)

Quantity of

utilized

Production

Capacity

3.9 Promoting the Adoption of CCUS Technologies in India

The envisaged CCUS policy needs to adopt a

multi-pronged approach to promote the adoption of

CCUS technologies in India. The key elements of the

approach need to incentivize the following:

i) Technology transfer: Carbon capture, CO

sequestration and CO

EOR technologies are

already demonstrated at commercial scale in

different parts of the world and particularly in the

US for nearly 50 years. Hence the focus for

India should be on technology transfer,

assimilation and adoption of such proven

technologies (TRL 8 and 9), rather than

reinventing the wheel. This would reduce the

technology risks, operational risks and costs for

CCUS projects in India. Pre-combustion and

post-combustion carbon capture technologies

(whether solvent, adsorption or cryogenic based)

are deployed in commercial scale projects and

available from multiple technology providers.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

The modalities of the technology transfer could

be international collaboration between the

suppliers of commercially proven carbon capture

technologies and premier Indian engineering

consultants for the development and engineering

of the Process Development Package and

subsequent fabrication & manufacturing of

equipment at Indian manufacturing plants,

leading to implementation of successful

demonstration projects. The collaborating model

needs to build in considerations of IP rights

transfer/use mechanisms, manufacturing

capability and quality, and performance fidelity of

operations for transferred technology through

EPC implementation in India. The project

structure can also be in the form of a consortium

of partners with shared incentives to support the

technology transfer and technology suppliers as

part of the project consortium. This will drive the

incentive to successfully transfer technology

while retaining control of the IP of the originating

technology partner. This will eventually support

the Make-in-India programme, enable

technology/IP exports from the originating

country, will be less expensive, reduce equipment

imports and increase domestic expertise in India.

Government funding for demonstration projects

should be through stage gates, with the project

partners also contributing to the cost share of the

project, typically in the form of in-kind

contributions. This kind of model has been

successfully implemented by the US DOE for

funding carbon capture projects in the US,

primarily in the NG based power generation and

more recently in other hard to abate industrial

sectors. The typical stage gates could be project

conceptualization & Pre-FEED, FEED and

demonstration of the project, with outputs and

parameters being defined at each stage, based on

which the funding decision for the subsequent

stage is made. A staged approach will also help in

developing and detailing the potential technology

transfer model, as the details of technology and

engineering dependencies across the project life

cycle become better defined. It will be necessary

to clearly delineate the technology interfaces so

that once the project is implemented, the

technology performance responsibilities can be

assured across the parties.

ii) Promoting R&D in novel technologies: While

carbon capture technologies and technologies for

EOR and sequestration are well developed

and implemented at a commercial scale,

technologies for the utilization of CO

are

relatively less developed. Even the relatively

more developed technologies for CO

utilization

such as CO

to methanol and CO

to aggregates

are at TRL levels of 4-5 and 6-7 only respectively.

Other promising technology propositions such as

to synthetic fuels, polymers and novel

materials like carbon nano tubes are even further

behind on the technology development and

deployment curve.

There is an opportunity to engage with such

technology suppliers for deploying these proven

technologies in demonstration scale projects

across different industries, viz. coal-based power,

steel, cement, refining & petrochemicals.

The Government of India, through its Department

of Science and Technology, may fund such CCUS

demonstration projects, with the twin objectives

of promoting CCUS projects at demonstration

scale, as well as to initiate the process of

technology transfer, based on Intellectual

Property (IP) use and transfer. The key steps in

the technology transfer transfer process,

ultimately leading to manufacturing leadership is

demonstrated in Figure 3-22 below.

Figure 3-22: Systematic Indigenization of

Technology through Technology Transfer

Start up again with

new technology

Turn into

manufacturing

leaders

Scale

implementation

Indigenize

technology

Full localisation

& ToT

First of a kind

partial ToT

License &

transfer programme

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

Figure 3-23: Promising CO

Utilization Technology Propositions

MethanolAggregate Novel MaterialsFuel Polymers

CaCO

TRL 4-5 TRL 6-7 TRL 4-5 TRL 3-4 TRL 3-4

The Government of India should support and

promote an ecosystem that promotes and fosters

R&D and innovation in the development of CO

utilization technologies and also develops new

products & applications based on the utilization of

the captured CO

. The other technology areas to

support could be the relatively nascent oxy-fuel

combustion, membrane, microbial & algae-based

capture technologies and calcium looping,

which potentially could have a role to play in

India’s net zero and clean energy transition

journey. Similarly, in the area of capture

technologies, the Government’s policy incentives

should encourage R&D in DAC as a possible

future option.

These developments are mutli-faceted and across

different applications, viz. the development of

to materials, carbon injection, new CO

capture technologies etc. and many of the

developments are also happening in India through

international collaborations and support, such as

at the National Centre of Excellence in Carbon

Capture and Utilization at IIT Bombay. It is

difficult to pronounce a verdict on the developing

technologies as innovation and technology

development follow their own trajectory.

Therefore there is a need to fund, foster and

incubate an innovation-based ecosystem, both

through national centers of excellence such as

the IIT Bombay as well as jointly fund pilot-scale

projects with private sector participation.

iii) Private sector participation: Private sector

participation is quintessential to promote the

transfer and commercialization of existing CCUS

technologies and also push the envelope for the

development of new and emerging technologies

in both capture and utilization. One need not look

further than the US DOE or the Build Back

Greener programme of the UK Government

regarding the institutional frameworks created

for leveraging private investments in clean

energy and CCUS technology and project

development. Early investment and signalling

through public/government funding, long term

policies to incentivize & de-risk CCUS projects and

viable CCUS business models and value chains

are needed to encourage and leverage private

investment and participation in the development

of CCUS technologies and projects. While the

funding provided by the US DOE for the

development of novel technologies and projects

in CCUS is well known, recently the UK

Infrastructure Bank has been set-up for

promoting the development of new clean energy

technologies, particularly for scaling early-stage

technologies beyond the R&D phase, where

typically more Government support is required.

The Bank has initial funding of £12 billion and

seeks to pull in private investment to accelerate

the net-zero transition in the UK. Similarly in

India, governmental institutional frameworks and

grants are needed to strategically support new

and emerging CCUS technologies, as well as CCUS

projects. This will lower the risk for private sector

participation and investment, as CCUS scales up

and moves to the commercial scale in India. Given

the nascent stage of CCUS in India, the

Government would need to support the full

project/funding cycle, from emerging

technologies to part-funding actual CCUS

implementations and projects.

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Overview of CO

Capture & Utilization Technologies

Chapter 4

Potential for CO

Storage in India

4.1 Introduction

4.2 CO

Storage Options

The end use of the captured CO

can be either

utilization or permanent storage. Utilization can be

done in various areas such as urea manufacturing,

conversion to other chemicals (methane, methanol,

ethanol), and evolving applications like aggregates. An

alternative is the permanent storage of the captured

in deep underground geological reservoirs like

depleted oil and gas reservoirs (for enhanced oil

production or EOR), deep saline aquifers, and in

basaltic rock formations.

For carbon capture at scale, it is important to estimate

the CO

storage capacity in the geological formations

in the Indian subcontinent. This section focuses on the

potential CO

storage capacities in India for utilization

pathways such as EOR (Enhanced Oil Recovery) &

ECBMR (Enhanced Coal Bed Methane Recovery) and

permanent storage options like saline aquifers &

basaltic storage. In India, exploration activities have

been performed with hydrocarbon extraction as the

primary target and not CO

storage. Thus, the values

are theoretical capacities derived from hydrocarbon

exploration data available in the public domain.

In-depth and detailed studies are required for more

accurate CO

storage capacity estimation.

4.2.1 Enhanced Oil Recovery (EOR)

Oil recovery techniques can be categorized as

primary, secondary, and tertiary recovery techniques.

Primary techniques rely on natural reservoir pressure

and the use of pumps to bring oil to the surface, but

the recovery is only about 10%. The secondary

techniques involve the injection of water or gas in the

reservoir to drive the oil to the production wellbores.

This helps in the recovery of 20-40% of the original

oil in place. To further improve the production

performance of wells, tertiary techniques are used.

Figure 4-1: Working of CO

EOR

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Potential for CO

Storage in India

Tertiary techniques of recovery include thermal

recovery (steam injection), gas injection (CO

injection), and chemical injection (use of polymers or

surfactants). These help in the production of 30-60%

of the original oil in place.

Injection of CO

for EOR has been studied and applied

for years, especially in North America. CO

miscible with crude oil which helps in recovering oil

not possible by secondary methods. This also

helps in permanently storing CO

in oil reservoirs,

thus making CO

EOR a sustainable option for

abating CO

In CO

EOR, compressed CO

is injected into the

reservoir. At high densities, CO

is readily miscible

with oil. It swells the oil and reduces its viscosity,

thereby driving it away from rock formations and

towards the production wells. A minimum pressure is

required for CO

and oil to be miscible. To prevent

lower viscosity CO

from escaping the reservoir, water

and CO

are injected alternatively.

4.2.2 Enhanced Coal Bed Methane

Recovery (ECBMR)

Coal bed methane (CBM) can be produced from coal

seams and can contribute to the energy security of

India. In ECBMR, CO

is injected into unmineable coal

seams under supercritical conditions. The CO

injected

is accumulated in the coal cleats in a dense gas phase.

This CO

is adsorbed and absorbed in the coal. Since

has a higher affinity for coal than CBM, it pushes

the coal bed methane towards production wells, thus

enhancing its primary recovery. Similar to CO

EOR,

ECBMR can help in permanently storing CO

and the

recovered methane can also help offset the cost of

carbon capture. This can be a viable option for thermal

power plants as many large coal based power plants

are located near coalfields. Figure 4-2 gives a pictorial

representation of the ECBMR process.

Several pilot tests for ECBMR have been performed

across the world, but there is no commercial-scale

ECBMR plant (Mazzotti, Pini, & Storti, 2009). Thus,

further R&D is required before commercial deployment.

Figure 4-2: Working of CO

ECBMR

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

4.2.3 Storage in Deep Saline Aquifers

Captured CO

can be permanently stored in deep

saline aquifers. Unlike EOR and ECBMR, injection of

in deep saline aquifers has no economic benefit.

Deep saline aquifers are spread across very large

areas and thus have the potential to store very large

quantities of CO

Deep saline aquifers consist of porous rock formation

that contains high quantities of unusable saltwater.

The salt/mineral content is very high in this water

rendering it unusable for human use. The brine water

is called formation liquid and it is trapped by an

impermeable rock called the caprock.

Supercritical CO

can be injected into the saline

aquifers. Brine water has a higher density compared

to the injected CO

; thus, CO

rises towards the

caprock and is trapped in the saline aquifer. This is

also termed structural/ stratigraphic trapping. While

injecting, some CO

might occupy the pore spaces by

displacing the previously present fluid. This is known

as residual trapping. Some of the injected CO

also

dissolves in the brine. This mixture is denser than the

surrounding brine and thus settles down. This is called

solubility trapping. CO

dissolves in water to form a

weak carbonic acid that can react with minerals over

time to form solid carbonate minerals. This process is

termed mineral trapping.

4.2.4 CO

Storage in Basalts

Recently studies have been carried out to learn about

the CO

storage potential of basaltic rocks. Basaltic

rock constitutes divalent cations of Ca, Mg, and Fe.

They can react with the CO

dissolved in water to form

stable carbonate minerals and thus can offer a safe

sequestration method for an extended period.

Compared to mineralization in saline aquifers, basalt

rocks offer faster reaction kinetics due to the

abundance of iron, calcium, and magnesium oxides.

The abundance of basalts on the earth’s surface is

also a reason for the rising interest in CO

storage

research and development programmes in basalts.

According to calculations done by researchers, the

global CO

storage capacity of basalts is estimated to

be around 8000-41000 Gt of CO

(Vikram,

Yashvardhan, Debanjan, & Dhananjayan, 2021).

4.3 Capacity Assessment

for CO

Storage

Based on secondary research, the estimated CO

storage capacity of India for each of the options

discussed above has been presented in this section.

Due to the absence of high-level data focused on CO

storage, all the capacities presented here are

theoretical calculations and estimations. Further work

is required to acquire real-time storage data for these

options.

Currently, initial storage assessment is being carried

out in India. These are focused on the feasibility of

EOR through seismic, geomechanical, and

reservoir studies based on initial surveys by ONGC.

Research on the possibility of CO

storage in saline

aquifers and basalts, predicting and monitoring of CO

plume by seismic methods has also been done by

some authors. The Technology Information,

Forecasting, and Assessment Council (TIFAC), Govt of

India, has identified CO

EOR and ECBMR as the two

immediate pathways for CO

sequestration in India

(TIFAC, 2018). However, there are no elaborate or

dedicated geological, geomechanical or seismic

studies ‘focused’ on country-wide CO

storage.

4.3.1 CO

EOR Storage Capacity Assessment

India has a total of 26 sedimentary basins. The

Directorate General of Hydrocarbon’s (DGH) 2020

India Hydrocarbon Outlook report divides these basins

into three categories, namely category I, category II,

and category III basins.

Category I basins are the ones where commercial oil &

gas exploration and production activities are ongoing.

There are 7 basins in category I. Extensive data for

these basins are available due to the exploratory

efforts of oil and gas companies. However, these

basins have not been explored with the intention of

storage. Thus, the data of in-place hydrocarbon

resources and Ultimate Recoverable Reserves (URR)

provided by DGH in the recent exploration assessment

has been used with a suitable Recovery Factor for

EOR (RF

EOR

= 10%) to calculate the total pore volume.

A conversion factor of 1.165 is used to convert the

values of MMTOE to Mm

. This pore volume is used

along with the formation volume factor (B

) and CO

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

Table 4-1: CO

EOR Storage Capacity Estimates

density at reservoir conditions to calculate the

quantity of CO

that can be stored in a particular

basin. The calculation formulae in equations (1) and (2)

are used.

V = URR + (OOIP x RF

EOR

) (1)

M = V B

CO2

(2)

The theoretical capacity estimates of the seven

category I basins have been listed in Table 4-1.

Basin Storage Capacity

(mt CO

)

Krishna-Godavari 658.69

Mumbai 1597.24

Assam shelf 667.48

Rajasthan 312.52

Cauvery 99.50

Assam-Arakan 67.01

Cambay 657.25

Total 3402.43

Thus, a total of 3.4 Gt of theoretical storage capacity

is estimated to be available for EOR. The Bengal basin

has also started producing oil in late 2020, but it has

been excluded due to the lack of availability of data

about the reserves. The CO

EOR capacities are

expected to increase as more basins are explored for

hydrocarbon production.

4.3.2 CO

ECBMR Storage Capacity Assessment

Indian coal reserves mostly comprise anthracite and

bituminous coal, spread across the Gondwana basin

and scattered in some parts of north-eastern India.

These coalfields are rich in CBM, and the CH

to CO

ratio may vary in the range of 1:2 to 1:3. Since several

large-scale thermal power plants are located near

coal fields, ECBMR presents a promising opportunity

for CO

utilization and storage.

Information about several parameters is required for

a high-level estimation of the CO

storage capacity in

coal reserves. Since it is difficult to get information

about each of these parameters, a few empirical

equations have been used to calculate the storage

capacity. In the referred work (Vikram, Yashvardhan,

Debanjan, & Dhananjayan, 2021), four equations, given

by Kim, Ryan, Mavor, and Langmuir, were used to

estimate the volume of methane (VGas) present in the

coal formations. This volume thus calculated indicates

the amount of CO

that can be stored in the coal

formations using equation (3).

CO2

= 3V

Gas

x Q

coal

x ρ

CO2

(3)

CO2

is the quantity of CO

adsorbed in the coal seam,

coal

is the quantity of coal resources and ρ

CO2

is the

density of CO

at coal formation depths. The

calculations according to the formula of Kim and

Langmuir get results close to each other and are

considered as appropriate estimations in this study.

Kim’s formula considers the coal properties and depth

of reserve, while Langmuir’s formula relies on

sorption properties. Mavor’s formula was found to be

the simplest as it only took ash and moisture content

into account. Ryan’s formula is dependent on vitrinite

reflectance. Based on the above analysis, the results

for each coalfield have been tabulated in Table 4-2.

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

Table 4-2: CO

ECBMR Storage Capacity Estimates

Coalfield Kim Ryan Mavor Langmuir

(Gt CO

) (Gt CO

)

Bokaro 0.28 0.32 0.30 0.20

North Karanpura 0.28 0.38 0.35 0.21

Raniganj 0.50 0.59 0.44 0.52

Sohagpur 0.09 0.16 0.19 0.07

Sonhat 0.03 0.06 0.07 0.03

South Karanpura 0.08 0.16 0.13 0.11

Wardha Valley 0.06 0.15 0.15 0.09

Birbhum 0.08 0.14 0.11 0.10

Godavari 0.23 0.53 0.50 0.32

Mand–Raigarh 0.25 0.60 0.53 0.35

Rajmahal 0.16 0.30 0.31 0.13

Singrauli 0.10 0.26 0.29 0.10

Tatapani–Ramkola 0.05 0.08 0.07 0.05

Ib river 0.17 0.41 0.34 0.19

Talcher 0.32 0.80 0.61 0.41

Makum 0.01 0.01 0.01 0.00

Jharia 0.47 0.55 0.41 0.51

Ramgarh 0.01 0.03 0.04 0.01

Auranga 0.02 0.06 0.07 0.03

Hutar 0.00 0.00 0.01 0.00

Daltonganj 0.00 0.00 0.00 0.00

Deogarh 0.00 0.01 0.01 0.00

Johilla 0.00 0.00 0.01 0.00

Pench–Kanhan 0.03 0.06 0.07 0.02

Pathakhera 0.01 0.01 0.01 0.00

Singrauli 0.09 0.23 0.20 0.10

Jhilimili 0.00 0.00 0.01 0.00

Chirimiri 0.00 0.01 0.01 0.00

Bisrampur 0.01 0.02 0.05 0.00

Lakhanpur 0.00 0.00 0.01 0.00

Hasdo–Arand 0.04 0.08 0.10 0.02

Sendurgarh 0.00 0.00 0.01 0.00

Korba 0.06 0.16 0.18 0.06

Kamptee 0.02 0.06 0.06 0.03

Umrer–Makardhokra 0.00 0.01 0.01 0.00

Nand–Bander 0.00 0.01 0.02 0.00

Total 3.5 6.3 5.7 3.7

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

Table 4-3: CO

Storage Capacity Estimation for Deep Saline Aquifers

Based on Kim and Langmuir’s formula, the CO

storage

capacity has been estimated storage to be between 3.5

Gt to 3.7 Gt of CO

, respectively. More pilot tests are

required to generate data for ECBMR in the Indian

context, which would pave the way for the commercial

deployment of this technology.

4.3.3 Deep Saline Aquifer CO

Storage Capacity

Assessment

Indian deep saline aquifers are distributed in the 26

sedimentary basins and are categorized into 3

categories, namely category I, II & III basins.

Category I basins have the most detailed lithological

data. Additional exploration is needed to obtain

high-quality data for category II & III basins.

The CO

storage capacity estimation has been done by

using the volume of formation being considered for

storage and appropriate storage efficiency factors.

The storage efficiency factors account for the

dominant lithology of a formation or basin and help in

calculating a more accurate capacity. The formula

used for calculation has been given in equation (4).

The storage capacity estimates for each basin have

been tabulated in Table 4-3. Capacity estimation has

not been possible for seven basins of category III due

to lack of data.

CO2

= AhφρE (4)

In the above equation, A is the area covered by the

basin, h is the gross thickness of the formation, φ is the

average porosity, ρ is the CO

density at reservoir

conditions and E is the storage efficiency factor that

takes area, thickness, porosity, volumetric displacement,

and microscopic displacement efficiency into account.

Category Basin Capacity (Gt)

Category I Krishna–Godavari 13.39

Mumbai offshore 9.26

Assam Shelf 14.16

Rajasthan 7.34

Cauvery 16.08

Assam-Arakan fold belt 32.3

Cambay 16.13

Saurashtra 39.74

Kutch 15.6

Category II Vindhyan 11.81

Mahanadi–NEC (North East Coast) 3.25

Andaman–Nicobar 12.35

Kerala–Konkan–Lakshadweep 25.33

Bengal–Purnea 51.58

Ganga–Punjab -

Pranhita–Godavari 6.14

Satpura–South Rewa–Damodar 1.87

Himalayan Foreland -

Chhattisgarh 0.11

Category III Narmada -

Spiti–Zanskar -

Deccan Syncline -

Cuddapah 14.24

Karewa -

Bhima–Kaladgi 0.41

Bastar -

Total 291.09

Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

Table 4-4: Basalt Formation CO

Storage Capacity Estimates

The total theoretical storage capacity is estimated to

be 291.1 Gt CO

for deep saline aquifers. This

estimation will increase based upon the availability of

more data on the seven category III basins for which

calculations could not be done. Deep saline aquifers

offer immense storage potential and thus more studies

and pilot tests are required to generate the baseline

data for CO

sequestration operations in India.

4.3.4 Basalt Rock CO

Storage Capacity

Assessment

Basalt formations in India have been discovered in the

Deccan Volcanic Province (DVP) and Rajmahal trap

(Vikram, Yashvardhan, Debanjan, & Dhananjayan,

2021). The DVP basalts are spread across the

north-western region, covering nearly 500,000 km

area. The volume of these formations is estimated to

be close to 512,000 km

. A relatively smaller basalt

formation is present in the eastern part of India in the

Rajmahal traps. This trap consists of 450 to 600 m

thick basalt, and spread across an area of

18,000 km

The CO

storage capacity for basalts has been

estimated by using the methodologies used by

Sænbjörnsdόttir et al. (Sænbjörnsdόttir, 2014) and

McGrail et al. (McGrail, 2006). The formula used for

calculation has been described in equation (5).

CO2

= AhφE

CO2

(5)

In the above equation, A is the area of basalt

formation, h is the net thickness of formation,

φ is the

average porosity and E

CO2

is the storage efficiency

factor. The methodology used by Sænbjörnsdόttir

considers three geothermal systems in Iceland, Krafla,

Hellisheidi, and Reykjanes, where the CO

content per

square meter of surface area was measured. Reykjanes

provided the lower limit of CO

storage efficiency while

Krafla provided the upper limit. McGrail assumed 10

suitable interflow zones, average porosity of 15%, and

1000 m as the targeted depth of injection.

These two methodologies have been applied to Indian

basalts to generate the CO

storage efficiency factors

and, ultimately, the storage capacity estimates. The

efficiency factor results and the storage capacity

estimates for the two basalt formations of India have

been tabulated in Table 4-4.

Sænbjörnsdόttir al. (2014) McGrail et al. (2006)

Low High

Storage Efficiency (Kg/m

) 18.8 48.7 40.65

Storage Capacity (Gt)

Deccan Volcanic Province (DVP) 94 243.5 304.88

Rajmahal Traps 3.38 8.77 10.98

Total (Gt) 97.38 252.27 315.85

100

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

4.4 Overall CO

Storage

Capacity in India

The overall CO

storage capacity assessment for the

four options discussed above has been summarized in

Table 4-5.

Table 4-5: Theoretical CO

Storage Capacity in India

EOR 3.4

ECBMR 3.5-3.7

Deep Saline Aquifers

291

Basalts 97-315

Total 395-614

EOR and ECBMR provide relatively low storage

capacity in comparison to deep saline aquifers and

basalts. However, EOR is a more researched and

tested technology in major carbon capture projects

across the globe and thus can be probably more easily

101

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Carbon Capture Utilization and Storage (CCUS) –

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implemented in the Indian scenario. ECBMR requires

more dedicated studies and pilot tests for the Indian

coal beds since no commercial-scale project is active

in the world.

Deep saline aquifers offer great CO

storage potential

for India. Since waste material injection is not an

industrial practice in India, data related to storage in

deep saline aquifers is not readily available. Thus,

characterization of the various onshore/ offshore

saline formations and improving the quality of data

available should be part of future studies for saline

aquifers. Based on the recommended CCUS cluster

framework, field/basin-specific studies need to be

undertaken for regions of higher priority. The pilot

tests will further help in preparing baseline data for

the development of commercial-scale injection of CO

in saline aquifers. Basalt formations are concentrated

in the western part of the country and offer a good

storage option for emitters in the western states of

India like Maharashtra, Gujarat, and parts of Madhya

Pradesh. Some basalts are also found in Eastern India

in the Rajmahal traps. Further studies are required to

get a better understanding of storage mechanisms in

these traps. Pilot tests need to be carried out to

further develop the industrial CO

sequestration

framework and infrastructure.

Potential for CO

Storage in India

Theoretical Storage

Capacity (Gt)

Storage

Pathways

4.5 CO

Storage Capacity in India - Earlier Work and Future Work

4.5.1 Assessment by the British

Geological Society

Some of the earliest work done with regard to the

assessment of the potential of CO

storage in

geological reserves in India was done by the British

Geological Society (BGS). The BGS report submitted in

2008, covered the Indian subcontinent (India,

Pakistan, Bangladesh and Sri Lanka) and was

commissioned by the International Energy Agency

Greenhouse Gas R&D Programme. The potential

geological storage sites were divided into three

categories. The categories, along with the estimated

storage capacity, is given below:

- Oil fields – 1 to 1.1 Gt

- Coal seams – 0.345 Gt

- Saline water-bearing reservoir rocks – 142 Gt

Thus, the total CO

storage capacity estimated was

143 Gt, which is a significant number considering the

annual CO

emissions in India of 2.6 Gt. However, the

BGS study did not consider the potential CO

storage

capacity in basaltic rock formations due to the relative

immaturity of the technology but noted the potential

of CO

storage in the thick basaltic formations of the

Deccan trap and the smaller Rajmahal trap. The BGS

study also involved a high-level source-sink mapping

based on which the sources in the north-west and

south-eastern coast of India were identified to have

good nearby storage potential, whereas the sources in

south-east, central and northern India were not found

to have good nearby storage potential.

4.5.2 Assessment by IIT Bombay

Building on the earlier work of the BGS, an assessment

was recently undertaken by Professors Vikram Vishal,

Yashvardhan Verma, Debanjan Chandra, Dhananjayan

Ashok of IIT Bombay. Their paper “A systematic

capacity assessment and classification of geologic CO

storage systems in India” has reviewed and applied

different methodologies for estimating CO

storage

capacities in different types of geological formations in

India. The study identified four storage pathways with

adequate potential for CO

storage:

- CO

storage in deep saline aquifers – 291 Gt

- CO

storage in basalt formations – 97 to 316 Gt

- CO

based enhanced oil recovery (EOR) – 3.4 Gt

- Enhanced coalbed methane recovery (ECBMR) – 3.7 Gt

The study also categorized the sedimentary

basins of India based on CO

storage prospects as

well as the feasibility of CO

storage; the same is

depicted in Figure 4-3.

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

Figure 4-3: Classification of CO

Storage Potential of Sedimentary Basins of India

Storage prospectivity

Storage capacity (Gt)

Very high potential

High potential

Moderate potential

Low potential

Assam-Arakan fold belt

Saurashtra

Bengal-Purnea

Kerala-Konkan

Cuddapah

Andaman-Nicobar

Kutch

Vindhyan

Assam shelf

Cauvery

Cambay

Krishna-Godavari

Rajasthan

Mumbai

offshore

Mahanadi

Bhima-Kaladgi

Satpura-South

Pranhita

Chhatisgarh

Godavari

10 20 30 40 50

Storage feasibility

103

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Carbon Capture Utilization and Storage (CCUS) –

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Storage in India

Figure 4-4: Major Sedimentary Basins in India with their CO

Storage Potential

EOR

(Gt)

ECBMR

(TCF)

Saline Aquifers

(Gt)

storage capacity

0 500

E 75

E 80

E 85

E 90

E 95

E 100

Sedimentary basins

Precambrian basement

Basins with insufficient data

Category-I basins Category-II basins Category-III basins

storage capacity in basalt (Gt)

Shallow water areas

Unassessed deepwater areas

E 75

E 80

E 85

E 90

E 95

E 100

1. Krishna-Godavari

2. Mumbai Offshore

3. Assam-Shelf

4. Rajasthan

5. Cauvery

6. Assam-Arakan Fold belt

7. Cambay

8. Saurashtra

9. Kutch

10. Vindhyan

11. Mahanadi

12. Andaman

13. Kerala-Konkan

14. Bengal-Purnea

15. Ganga-Punjab

16. Pranhita-Godavari

17. Satpura-South Rewa-Damodar

18. Himalayan Foreland

19. Chhattishgarh

20. Narmada

21. Spiti-Zanskar

22. Deccan Syncline

23. Cuddapah

24. Karewa

25. Bhima-Kaladgi

26. Baster

0.5

Although the estimated storage capacity for EOR and

ECBMR is relatively smaller, they still offer an attractive

option due to the following:

- Provide an option to store CO

emissions from nearby

large point sources

- Economic value creation through enhanced oil and

methane production, thus offsetting part of the

CCUS costs

- Availability of exploration data, geological information

and infrastructure in existing oil fields and coal fields

The CO

storage potential of the different basins in India is depicted in Figure 4-4.

104

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Carbon Capture Utilization and Storage (CCUS) –

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Potential for CO

Storage in India

4.5.3 Future Work Required

Existing studies show enormous CO

storage potential

in India; however, further actions are needed to make

geological storage of CO

a reality in India. Some of

the key steps which need to be funded/promoted by

the Government of India are:

- Source sink mapping to prioritize the regions and

basins most opportune for CO

storage in terms of

storage capacity and feasibility

- Pore space mapping and characterization of the

most promising CO

storage regions and basins –

geological characterization and exploration for CO

storage. In the US, the US Department of Energy

(US DOE) has funded a network of seven Regional

Carbon Sequestration Partnerships (RCSPs) across

the country. The aim of the RSCP program is to

develop the regional infrastructure of carbon

capture and storage across seven identified

regions of the US. The seven RSCPs are depicted in

Figure 4-5.

- For the prospective regions identified in India,

developing the CO

storage infrastructure would

consist of the following steps:

i) Characterization: characterization and

geological modelling of the prospective regions

for assessing the potential to store CO

different types of geological formations.

This would include mapping the large point

sources of CO

in the region, characterizing

prospective sites for CO

storage, and ranking

the sites for future CO

storage projects. The

characterization would provide the requisite

data for mapping sites to the large CO

point

sources, develop a better understanding of the

transportation & storage costs and create a

business case for the envisaged CCUS projects.

ii) Validation: undertaking lab-scale field projects

in different types of storage fields across EOR,

ECBMR, saline aquifers and basaltic formations

to gather information about the CO

storage

sites, and validation of the characterization and

modelling work done. This would help in

validating the most promising CO

storage sites

in each region.

iii) Commercial-scale Development: undertake

commercial-scale (at least 1 mtpa of CO

) CO

injection in selected sites. The projects would be

optimized through the implementation of an

appropriate Monitoring, Verification and

Accounting (MVA) framework and risk

management measures, and also help in proving

the permanence of CO

storage in the

subsurface and monitoring the extent &

movement of CO

plume.

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Figure 4-5: Seven RSCPs Funded by the US DOE

RCSP Abbreviation Lead Organisation

Big Sky Carbon Sequestration Partnership BSCSP Montana State University Bozeman

Midwest Geological MGSC Illinois State Geological Survey

Sequestration Consortium

Midwest Regional Carbon MRCSP Battelle Memorial University

Sequestration Partnership

Plains CO

Reduction PCOR University of North Dakota Eenergy

Partnership and Environmental Research Center

Southeast Regional Carbon SECARB Southern States Energy Board

Sequestration Partnership

Southwest Regional Partnership on SWP New Mexico Institute of Mininig

Carbon Sequestration and Technlology

West Coast Regional Carbon WESTCARB California Energy Commission

Sequestration Partnership

Source: US DOE National Energy Technology Laboratory

Potential for CO

Storage in India

4.6 SECARB

The Southeast Regional Carbon Sequestration

Program (SECARB) is one of the prominent RSCPs,

setup with US DOE funding for the development and

management of CO

storage and CO

storage

infrastructure across 13 south-eastern states of the

US. SECARB was set up in 2003 and is managed by

the Southern States Energy Board (SSEB). The main

goal was to identify major sources of carbon

emissions, characterize the geology of the 13 states

with respect to CO

storage (both EOR and

sequestration), identify the most promising sites and

sequestration technologies and validate the same

through extensive field testing.

The key phases of the SECARB program and

accomplishments/developments in each phase are

as below:

i) Phase I (2003 – 2005): Phase I focussed on

characterizing the geology and CO

storage

potential of different sequestration options in the

SECARB area, based on which an action plan was

developed for undertaking small-scale field

demonstration of CO

sequestration in the

subsequent phase of the program.

ii) Phase II (2005 – 2010): During Phase II, three

types of small scale field tests were conducted in

four locations. These were:

a. Enhanced Oil Recovery: Ageing oil fields

along the US Gulf Coast have an estimated

storage potential of 31 Gt and are an ideal

target for geological storage of CO

. SECARB’s

Gulf Coast Stacked Storage Field Test ran

from 2008 to 2015 and was the first RSCP

Phase II program to inject more than 500 ktpa

of CO

b. Coal bed methane: Two field tests were

conducted at an existing CNX gas well in

Russel County, Virginia and near Tuscaloosa,

Alabama.

c. Saline aquifers: CO

injection in saline

aquifers was conducted at the Mississippi

Power Company’s Victor J. Daniel coal-fueled

power plant.

iii) Phase III (2007 – 2017): Phase III consisted of

two large CO

volume storage projects, namely:

a. CO

EOR at the Cranfield oilfield: The

SECARB “Early Test” ran from 2009 to 2015

and the cumulative volume of stored CO

that

was monitored during this period was about

5.4 million tonnes. The CO

volumes were

monitored using a variety of MVA technologies

to determine the commercial viability of

the project.

b. CO

sequestration at Citronelle oilfield: The

SECARB “Anthropogenic Test” ran from 2012

to 2014 during which 114 ktpa of CO

captured

from Alabama Power Company’s James M.

Barry Electric Generating Plant in Bucks,

Alabama was transported (through pipeline)

about 19 km and sequestered in a deep saline

formation. MVA technologies were applied to

monitor the movement of the CO

plume in the

sub-surface.

The role of both the SECARB Phase III projects in

advancing the understanding of CO

storage

technologies has been recognized internationally and

has also helped in the development of international

guidance, best practices and standards for carbon

capture, transportation, and storage.

The key learning and finding from the SECARB is that

once site selection & design, project management and

logistical issues are managed, operations of CO

storage projects are simple and without any effect or

manifestation on the surface. SECARB also

demonstrates the criticality of project planning and

coordinating the various elements of the CCUS value

chain and the importance of site-specific public

outreach with local government leaders, community

representatives, and sharing details of the project and

address their questions & apprehensions about the

project risks. The success of the SECARB project has

also led to other commercial-scale CCUS projects

being constructed in the SECARB area.

The success of the SECARB program demonstrates

how Government funding and support can lay the

seeds and develop a CCUS value chain. The

Government of India may also consider similar

programs for the regions that prima facie have good

prospects for CCUS, viz. the Krishna Godavari basin,

Mumbai offshore, Cambay and eastern parts of the

Bay of Bengal basin, especially around Haldia.

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4.7 MVA (Monitoring Verification and Accounting)

The storage of CO

in geological storage sites requires

a variety of tools to monitor the volume of CO

stored,

as well as to prevent CO

leakages and releases from

the storage sites. These tools are used for monitoring

the CO

in the atmosphere, near the surface and the

sub-surface. The MVA framework provides the tools

and approaches required for ensuring the safe,

effective and permanent geological storage of CO

MVA plans are needed for all CO

geological storage

projects, covering aspects of CO

storage, quality

control, as well as verification and accounting of CO

volumes stored, which would be eligible for earning

incentives/credits linked to carbon abatement, viz. the

45Q tax credits in the US. MVA plans need to be

developed specific to sites, given the variance of

geological conditions across storage sites. Risk

management is an important component of the MVA

framework for ensuring the safe, effective, and

permanent storage of CO

across a variety of geologic

formations and avoiding CO

releases & leakages. It is

also important to monitor the location and movement

of the CO

plume in the subsurface and ensure that

the water table is not polluted. In the case of CO

EOR,

the monitoring and tracking of the CO

plume may be

easier due to the presence of a number of oil wells; at

the same time there is more complexity due to the

presence of oil and gas.

The key goals of MVA for CO

storage sites are as

follows (source: US DOE):

- Improve understanding of the CO

storage

processes and confirm the storage effectiveness

- Evaluate the reaction and interaction of CO

with

the formation solids and fluids.

- Assess the likely environmental, safety, and health

impacts in case of a CO

leakage event and

evaluate the remedial actions required.

- Provide a technical basis in case of events such as

groundwater impacts, seismic events, crop losses

as a result of the CO

sequestration.

For any geological sequestration project, the MVA

activities are carried out in four phases:

i) Pre-Operation Phase: Project design,

establishing baseline conditions,

characterization of the site geology and

identification of risks.

ii) Operation Phase: Period of CO

injection in

the storage site.

iii) Closure Phase: Period of closing and plugging

the sites, removal of equipment and facilities

and undertaking site restoration. However,

necessary monitoring equipment are retained

at the site.

iv) Post-Closure Phase: Ongoing monitoring is

undertaken before making a decision that

further monitoring is not required, except in

case of any incidents like leakage, or legal

cases, for which new information is required

about the storage project/site.

Each monitoring phase has specific monitoring tools

and techniques to address the specific atmospheric,

near-surface hydrologic, and deep-subsurface

monitoring needs. These are tabulated below:

Table 4-6: List of Monitoring Techniques for CO

Storage Projects

Area of Monitoring Monitoring Techniques

- CO

Detectors: Sensors for monitoring CO

either intermittently or

continuously in the air.

- Eddy Covariance: Atmospheric flux measurement technique to measure

atmospheric CO

concentrations at a height above the ground surface

- Advanced Leak Detection System: sensitive three-gas detector

(CH

, Total HC, and CO

) with a GPS mapping system carried by aircraft or

terrestrial vehicles

Atmospheric

Monitoring Techniques

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Area of Monitoring Monitoring Techniques

Near-Surface

Monitoring

Subsurface

Monitoring

- Laser Systems and LIDAR: Open-path device that uses a laser to shine a

beam with a wavelength that CO

absorbs

- Tracers or Isotopes: Natural isotopic composition and/or compounds

injected into the target formation along with the CO

- Ecosystem Stress Monitoring: Satellite or airplane-based optical method.

- Tracers: CO

soluble compounds injected along with the CO

. into the

target formation

- Groundwater Monitoring: Sampling of water or vadose zone/soil (near

surface) for basic chemical analysis.

- Thermal Hyperspectral Imaging: An aerial remote-sensing approach

primarily for enhanced coalbed methane recovery and sequestration.

- Synthetic Aperture Radar (SAR & InSAR): Satellite-based technology in

which radar waves are sent to the ground to detect surface deformation.

- Color Infrared (CIR) Transparency Films: Vegetative stress technology

deployed on satellites or aerially.

- Tiltmeter: Measures small changes in elevation via mapping tilt , either on

the surface or in subsurface.

- Flux Accumulation Chamber: Quantifies the CO

flux from the soil, but

only from a small, predetermined area.

- Induced Polarization: Geophysical imaging technology commonly used in

conjunction with DC resistivity to distinguish metallic minerals and

conductive aquifers from clay minerals in subsurface materials.

- Spontaneous (Self) Potential: Measurement of natural potential

differences resulting from electrochemical reactions in the subsurface.

Typically used in groundwater investigations and in geotechnical

engineering applications for seepage studies.

- Soil and Vadose Zone Gas Monitoring: Sampling of gas in vadose

zone/soil (near surface) for CO

- Shallow 2-D Seismic: Closely spaced geophones along a 2-D seismic line.

- Multi-component 3-D Surface Seismic Time- lapse Survey: Periodic

surface 3-D seismic surveys covering the CCS reservoir.

- Vertical Seismic Profile (VSP): Seismic survey performed in a wellbore

with multi-component processes. Can be implemented in a “walk-away”

fashion in order to monitor the footprint of the plume as it migrates away

from the injection well and in time-lapse application.

- Magnetotelluric Sounding: Changes in electromagnetic field resulting

from variations in electrical properties of CO

and formation fluids.

- Electromagnetic Resistivity: Measures the electrical conductivity of the

subsurface including soil, groundwater, and rock.

- Electromagnetic Induction Tomography (EMIT): Utilizes differences in

how electromagnetic fields are induced within various materials.

Potential for CO

Storage in India

- Injection Well Logging (Wireline Logging): Wellbore measurement using a

rock parameter, such as resistivity or temperature, to monitor fluid

composition in wellbore

- Annulus Pressure Monitoring: Mechanical integrity test on the annular

volume of a well to detect leakage from the casing, packer or tubing.

- Pulsed Neutron Capture: A wireline tool capable of depicting oil

saturation, lithology, porosity, oil, gas, and water by implementing pulsed

neutron techniques.

- Electrical Resistance Tomography (ERT): Use of vertical arrays of

electrodes in two or more wells to monitor CO

as a result of changes in

layer resistivity.

- Sonic (Acoustic) Logging: A wireline log used to characterize lithology,

determine porosity, and travel time of the reservoir rock.

- 2-D Seismic Survey: Acoustic energy, delivered by explosive charges or

vibroseis trucks (at the surface) reflecting back to a straight line of

recorders (geophones). After processing, the reflected acoustic signature

of various lithologies is presented as a 2-D graphical display.

- Time-lapse Gravity: Use of gravity to monitor changes in density of fluid

resulting from injection of CO

- Density Logging (RHOB Log): Continuous record of a formation bulk

density as a function of depth by accounting for both the density of matrix

and density of liquid in the pore space.

- Optical Logging: Device equipped with optical imaging tools is lowered

down the length of the wellbore to provide detailed digital images of the

well casing.

- Cement Bond Log (Ultrasonic Well Logging): Implements sonic

attenuation and travel time to determine whether casing is cemented or

free. The more the cement which is bonded to the casing, the greater will

be the attenuation of sounds transmitted along the casing.

- Gamma Ray Logging: Use of natural gamma radiation to characterize the

rock or sediment in a borehole.

- Microseismic (Passive) Survey: Provides real-time information on

hydraulic and geomechanical processes taking place within the reservoir in

the interwell region, remote from wellbores by implementing surface or

subsurface geophones to monitor earth movement.

- Crosswell Seismic Survey: Seismic survey between two wellbores in

which transmitters and receivers are placed in opposite wells. Enables

subsurface characterization between those wells. Can be used for

time-lapse studies.

- Aqueous Geochemistry: Chemical measurement of saline brine in storage

reservoir.

- Resistivity Log: Log of the resistivity of the formation, expressed in

ohm-m, to characterize the fluids and rock or sediment in a borehole.

Area of Monitoring Monitoring Techniques

Source: Best Practices for Monitoring, Verification, and Accounting of CO

Stored in Deep Geologic Formations (US DOE NETL)

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Examples of successful MVA programs are the MVA

programs funded by the US DOE with the goal of

demonstrating 95% and up to 99% retention of CO

through geological storage by ensuring leakages are

contained up to 5% and 1% of the stored CO

volumes. The US DOE’s Carbon Sequestration

Program supports the development of technologies in

this domain through the Regional Carbon

Sequestration Partnerships (RCSP) Program. Some of

the early projects/CO

storage sites where the US

DOE supported the MVA program are given below.

The portfolio of sites was selected to ensure variety in

the type and geology of site, CO

application,

formation depth and porosity, pressure and

temperature conditions, to maximize the

understanding of the behaviour of the stored CO

different operating and geological regimes.

i) Gulf Coast Mississippi Strandplain Deep

Sandstone Test in Mississippi: moderate

porosity and permeability storage site

ii) Nugget Sandstone Test in Wyoming: high depth,

low porosity and permeability site

iii) Cambrian Mt. Simon Sandstone Test in Illinois:

moderate depth, low porosity and permeability site

iv) San Joaquin Valley Fluvial-Braided Deep

Sandstone Test in California: high porosity and

permeability site

v) Williston Basin Deep Carbonate Test in North

Dakota: EOR site

The US DOE also supported the MVA program at the

Petro Nova project in Texas for CO

capture from NRG

Energy’s WA Parish Unit 8 (a 640 MW coal fired

power plant) and storage in the West Ranch oilfield.

The MVA program was conducted by the University of

Texas at Austin’s Bureau of Economic Geology and

consisted of the following components:

i) Modeling: development of a fluid flow simulation

model using actual logging and production data

ii) Mass balance accounting: accounting for

injected CO

iii) Pressure monitoring: monitoring pressure in

10 dedicated AZMI (above zone monitoring

intervals) wells

iv) Fluid sampling: collection of pre-injection fluids

(brine, gas, oil) in the injection and AZMI zones

v) Groundwater monitoring: one year of baseline

and periodic ongoing sampling of groundwater at

several groundwater wells

vi) Soil gas monitoring: characterization of soil

gases at several sites

vii) Additional monitoring: additional monitoring of

the surface level and downhole pressure by the

oilfield operator

storage in geological formations (both

sequestration and EOR to a limited extent) is the most

likely pathway for the disposition of CO

at scale, and

hence critical to the implementation of CCUS at scale

in India, especially for the decarbonization of large

emitters of CO

such as coal-based power plants. The

emissions for a 660 MW supercritical coal based

power plant is estimated to be about 4 mtpa of CO

Given the safety concerns about underground CO

storage as well as for accounting CO

volumes eligible

for credits/incentives, it is necessary to develop CO

storage demonstration projects and develop robust

MVA programs for them. These CO

storage

demonstration projects should be at identified sites

across the different prospective regions in India. In

order to develop a holistic perspective, it is also

important to implement projects at different types of

storage sites, such as saline aquifers, basaltic

traps and oilfields amenable for EOR. The MVA

programs and best practices developed by the US

DOE and ISO 14064 & ISO 14065 standards developed

for GHG accounting, verification and validation

provides a good starting point based on which site

specific MVA programs can be developed and

implemented.

Chapter 5

CCUS Policy

Framework for India

robust CO

injection regime in the state and established

mechanisms to manage the long-term liability with CO

storage. It is expected that owing to their extensive oil

and gas industry presence and favourable geology,

Texas and Louisiana stand to gain significant carbon

storage market share if they can successfully obtain

primacy and establish regulatory frameworks that

meet EPA’s standards and provide the industry with

planning certainty.

5.2.1.4 SCALE Act

The SCALE (Storing CO

and Lowering Emissions) Act

was proposed by a bipartisan coalition in 2021. The

Act aims to assist the development of vital CO

transit

and storage infrastructure to support CCUS and CO

removal technologies, as well as regional economic

prospects and jobs in the US. The key goals are:

a. Establishing a CO

Infrastructure Finance and

Innovation Act (CIFIA) programme to stimulate the

development of shared CO

transportation

infrastructure through flexible and low-interest

loans and grants. This federal funding mechanism

is aimed to reduce overall costs by enabling

economies of scale through interconnected

transport systems

b. Supporting commercial geologic CO

storage

initiatives with grants.

c. Promoting CO

utilization through legislation

allowing the US DOE to grant financing to

municipalities and states to enable procurement

of low carbon products and equipment.

d. Supporting legal and regulatory authorizations for

permitting Class VI CO

storage wells

5.2.2 European Union

The EU has been at the forefront of CCUS technology

development and has employed a variety of measures

to support, fund and incentivize CCUS. These support

measures are in the form of grant funds and

legislative & policy initiatives for CCUS, which have

been crucial in supporting the CCUS R&D, pilot and

demonstration projects across EU countries. A few

active funding programmes for CCUS in the EU region

are summarized in Table 5-1.

5.2.1.1 45Q

The 45Q provides tax credits for CCUS, starting from

USD 12.83 for each tonne of CO

utilized for EOR in

2017, linearly increasing to US$ 35/tonne in 2026.

Similarly, for CO

captured and geologically stored,

the tax credit was US$ 22.66/tonne in 2017, rising

linearly to US$ 50/tonne of CO

in 2026. Post-2026,

the credit shall be inflation-adjusted. Few mandatory

criteria must be met by emitters in order to avail the

tax credit, such as:

- facilities must begin construction before

1 January 2026

- the credit can be claimed over a 12-year period

after operations commence

- a minimum volume of CO

must be captured and

sequestered or utilized, which depends upon the

type of the emitting industry, as below:

• Non-EOR carbon utilization: 25-500 ktpa

of CO

• Industrial and DAC: 100 ktpa of CO

• Power plants: 500 ktpa of CO

The Global CCS Institute has long hailed USA’s 45Q

tax credit mechanism as the “most progressive

CCS-specific incentive globally”. The 45Q credits

lower a firm’s tax liability; in case there is no tax

liability, the credits can be traded in the tax equity

market. Tax credits have been successful in spurring

renewable energy projects in the US over the last two

decades. An important component for the successful

implementation of the 45Q or any tax incentive-based

system is designing a Monitoring Reporting and

Verification framework (MRV) to ensure compliance

of the projects seeking the 45Q credits.

The recently enacted Inflation Reduction Act of 2022

has substantially increased the maximum level of

credits available from US$ 50 to US$85/tonneof CO

sequestered and upto US$180/tonne of CO

for DAC.

5.2.1.2 California Low Carbon Fuel

Standard (LCFS)

The Low Carbon Fuel Standard (LCFS) in California is

a trading mechanism aimed at lowering the CO

intensity of the state’s fuel mix. A CCUS protocol for

the LCFS was agreed upon in January 2019, allowing

transportation fuels whose lifecycle emissions have

been lowered using CCUS to qualify for credits. The

protocol covers a wide range of CCUS applications

involving permanent storage of captured CO

depleted oil and gas reservoirs or saline formations or

used for enhanced oil recovery in oil and gas

reservoirs. Project credits are based on life cycle

emission reductions and granted if the reported

reductions have been validated.

LCFS is a strong motivator for CCUS deployment in

California. In 2020, the carbon credits obtained

through the LCFS roughly translated to USD 200 per

tonne of CO

. While the eligibility standards are strict,

several new project announcements have stated that

LCFS credits have been considered in their evaluation

and analysis of cost economics. The LCFS programme

offers several credit-generating possibilities to boost

low-carbon fuel supply and usage, viz:

i) Fuel pathway-based crediting: Low carbon fuels

generate credits based on emissions reduced

compared to the established baseline. These

credits incentivize developers to bring more clean

fuel options to California.

ii) Project-based crediting: This category includes

projects for reducing emissions across the

petroleum supply chain using measures such as

CCUS and direct air capture.

iii) Zero-emissions vehicle infrastructure

(capacity-based) crediting: Installation of

hydrogen and fast-charging DC infrastructure can

generate credits based on capacity.

5.2.1.3 State Primacy for CO

Storage

In 2010, the US EPA created the sixth well class (Class

VI) specifically to regulate the injection of CO

into

deep subsurface rock formations. At the time, very

few projects were sequestering CO

solely to reduce

greenhouse gas emissions, but the EPA anticipated

that technology development would be key to

achieving domestic emissions reductions. Wyoming

and North Dakota have been approved by the US

Environmental Protection Agency (EPA) to take

primary responsibility (‘primacy’) for regulating CO

injection for dedicated geological storage in Class VI

wells under the Underground Injection Control

(UIC) Program.

Texas and Louisiana have also stepped up efforts to

assume regulatory authority for CO

dedicated storage.

Louisiana has already applied for primacy, based on a

5.1 Introduction

The key to a successful CCUS policy for India is a

framework that supports the creation of sustainable

and viable markets for CCUS projects. The framework

must consider the fact that the private sector is

unlikely to invest in CCUS unless there are sufficient

incentives to do so (or conversely penalties from

inaction), or unless it can benefit from the sale of CO

or gain credits for emissions avoided under carbon

pricing regimes. Direct capital grants, tax credits,

carbon pricing schemes, operational subsidies,

regulatory requirements, and public procurement

preference for low-carbon products are some of the

policy measures required for CCUS to become a

reality in India.

5.2 Review of Policy

Instruments and

Strategies Adopted by

Various Countries and

Institutions

Local market conditions and institutional factors, such

as the current stage of CCUS infrastructure

development, emission targets, domestic energy

resources and mix, availability and cost of alternative

approaches to cutting emissions, all influence the

appropriate choice or mix of instruments for each

country. The appropriateness of each form of policy

instrument varies depending on the CCUS application.

Some applications of carbon capture, such as natural

gas processing, are well-established and relatively

inexpensive and need only minor policy changes.

Other applications, such as the CCUS in heavy

industries such as steel, are still in the early stages of

development. High CO

capture costs and their impact

on the cost/price and competitiveness of the final

product are major hurdles to CCUS adoption.

Government support for project developers is key to

managing the costs and risks associated with CCUS

projects, across the value chain of capture,

transportation and storage and establishing and

expanding CCUS in a meaningful way in India.

5.2.1 USA

The US leads the world in CCUS deployment, with the

earliest CCUS projects being implemented in the 1970s.

There are 14 operating CCUS facilities in the US, with a

combined carbon capture capacity of more than 25

mtpa. The US has heavily invested in CCS R&D since the

early 2000s. The US DOE has funded research and

development (R&D) in aspects of CCS since 1997 within

its Fossil Energy and Carbon Management Research,

Development, Demonstration, and Deployment

programme (FECM) portfolio. Since 2010, the US

Congress has provided USD 7.3 BB$ for DOE’s

CCS-related activities, including annual increases in

recent years. In 2021, the US Congress provided USD

750 MM$ to FECM, of which USD 228.3 MM$ was

earmarked for CCUS.

Apart from the DOE funding, CCUS projects received a

major fillip in 2009 when the US Federal Government

enacted the American Recovery and Reinvestment Act

(ARRA), which provided another USD 3.4 BB$

specifically for CCS projects and R&D activities. Nine

individual projects accounted for USD 2.65 BB$ out of

the ARRA funding, with each receiving in excess of USD

100 MM$. Five out of the nine projects are large scale

demonstration projects intended to capture CO

from

electric power plants. The balance four are in the

industrial sector. While some of the projects have faced

implementation challenges and delays, the policy intent

in USA has clearly focused on developing large scale

demonstration plants for CCS through government

support and funding. A large number of CCUS projects

are under different stages of conceptualization and

development, and CCUS is integral to the emission

reduction and net-zero commitments of a large number

of corporations in different sectors such as coal & NG

based power plants, waste-to-energy plants, cement,

ethanol facilities, and chemical production.

Some of the key enablers of CCUS in the US are the

45Q tax credits, California’s LCFS standards, State

Primacy for CO

injection and the SCALE Act; these are

describe herein:

CCUS Policy Framework for India

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robust CO

injection regime in the state and established

mechanisms to manage the long-term liability with CO

storage. It is expected that owing to their extensive oil

and gas industry presence and favourable geology,

Texas and Louisiana stand to gain significant carbon

storage market share if they can successfully obtain

primacy and establish regulatory frameworks that

meet EPA’s standards and provide the industry with

planning certainty.

5.2.1.4 SCALE Act

The SCALE (Storing CO

and Lowering Emissions) Act

was proposed by a bipartisan coalition in 2021. The

Act aims to assist the development of vital CO

transit

and storage infrastructure to support CCUS and CO

removal technologies, as well as regional economic

prospects and jobs in the US. The key goals are:

a. Establishing a CO

Infrastructure Finance and

Innovation Act (CIFIA) programme to stimulate the

development of shared CO

transportation

infrastructure through flexible and low-interest

loans and grants. This federal funding mechanism

is aimed to reduce overall costs by enabling

economies of scale through interconnected

transport systems

b. Supporting commercial geologic CO

storage

initiatives with grants.

c. Promoting CO

utilization through legislation

allowing the US DOE to grant financing to

municipalities and states to enable procurement

of low carbon products and equipment.

d. Supporting legal and regulatory authorizations for

permitting Class VI CO

storage wells

5.2.2 European Union

The EU has been at the forefront of CCUS technology

development and has employed a variety of measures

to support, fund and incentivize CCUS. These support

measures are in the form of grant funds and

legislative & policy initiatives for CCUS, which have

been crucial in supporting the CCUS R&D, pilot and

demonstration projects across EU countries. A few

active funding programmes for CCUS in the EU region

are summarized in Table 5-1.

5.2.1.1 45Q

The 45Q provides tax credits for CCUS, starting from

USD 12.83 for each tonne of CO

utilized for EOR in

2017, linearly increasing to US$ 35/tonne in 2026.

Similarly, for CO

captured and geologically stored,

the tax credit was US$ 22.66/tonne in 2017, rising

linearly to US$ 50/tonne of CO

in 2026. Post-2026,

the credit shall be inflation-adjusted. Few mandatory

criteria must be met by emitters in order to avail the

tax credit, such as:

- facilities must begin construction before

1 January 2026

- the credit can be claimed over a 12-year period

after operations commence

- a minimum volume of CO

must be captured and

sequestered or utilized, which depends upon the

type of the emitting industry, as below:

• Non-EOR carbon utilization: 25-500 ktpa

of CO

• Industrial and DAC: 100 ktpa of CO

• Power plants: 500 ktpa of CO

The Global CCS Institute has long hailed USA’s 45Q

tax credit mechanism as the “most progressive

CCS-specific incentive globally”. The 45Q credits

lower a firm’s tax liability; in case there is no tax

liability, the credits can be traded in the tax equity

market. Tax credits have been successful in spurring

renewable energy projects in the US over the last two

decades. An important component for the successful

implementation of the 45Q or any tax incentive-based

system is designing a Monitoring Reporting and

Verification framework (MRV) to ensure compliance

of the projects seeking the 45Q credits.

The recently enacted Inflation Reduction Act of 2022

has substantially increased the maximum level of

credits available from US$ 50 to US$85/tonneof CO

sequestered and upto US$180/tonne of CO

for DAC.

5.2.1.2 California Low Carbon Fuel

Standard (LCFS)

The Low Carbon Fuel Standard (LCFS) in California is

a trading mechanism aimed at lowering the CO

intensity of the state’s fuel mix. A CCUS protocol for

the LCFS was agreed upon in January 2019, allowing

transportation fuels whose lifecycle emissions have

been lowered using CCUS to qualify for credits. The

protocol covers a wide range of CCUS applications

involving permanent storage of captured CO

depleted oil and gas reservoirs or saline formations or

used for enhanced oil recovery in oil and gas

reservoirs. Project credits are based on life cycle

emission reductions and granted if the reported

reductions have been validated.

LCFS is a strong motivator for CCUS deployment in

California. In 2020, the carbon credits obtained

through the LCFS roughly translated to USD 200 per

tonne of CO

. While the eligibility standards are strict,

several new project announcements have stated that

LCFS credits have been considered in their evaluation

and analysis of cost economics. The LCFS programme

offers several credit-generating possibilities to boost

low-carbon fuel supply and usage, viz:

i) Fuel pathway-based crediting: Low carbon fuels

generate credits based on emissions reduced

compared to the established baseline. These

credits incentivize developers to bring more clean

fuel options to California.

ii) Project-based crediting: This category includes

projects for reducing emissions across the

petroleum supply chain using measures such as

CCUS and direct air capture.

iii) Zero-emissions vehicle infrastructure

(capacity-based) crediting: Installation of

hydrogen and fast-charging DC infrastructure can

generate credits based on capacity.

5.2.1.3 State Primacy for CO

Storage

In 2010, the US EPA created the sixth well class (Class

VI) specifically to regulate the injection of CO

into

deep subsurface rock formations. At the time, very

few projects were sequestering CO

solely to reduce

greenhouse gas emissions, but the EPA anticipated

that technology development would be key to

achieving domestic emissions reductions. Wyoming

and North Dakota have been approved by the US

Environmental Protection Agency (EPA) to take

primary responsibility (‘primacy’) for regulating CO

injection for dedicated geological storage in Class VI

wells under the Underground Injection Control

(UIC) Program.

Texas and Louisiana have also stepped up efforts to

assume regulatory authority for CO

dedicated storage.

Louisiana has already applied for primacy, based on a

CCUS Policy Framework for India

113

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

robust CO

injection regime in the state and established

mechanisms to manage the long-term liability with CO

storage. It is expected that owing to their extensive oil

and gas industry presence and favourable geology,

Texas and Louisiana stand to gain significant carbon

storage market share if they can successfully obtain

primacy and establish regulatory frameworks that

meet EPA’s standards and provide the industry with

planning certainty.

5.2.1.4 SCALE Act

The SCALE (Storing CO

and Lowering Emissions) Act

was proposed by a bipartisan coalition in 2021. The

Act aims to assist the development of vital CO

transit

and storage infrastructure to support CCUS and CO

removal technologies, as well as regional economic

prospects and jobs in the US. The key goals are:

a. Establishing a CO

Infrastructure Finance and

Innovation Act (CIFIA) programme to stimulate the

development of shared CO

transportation

infrastructure through flexible and low-interest

loans and grants. This federal funding mechanism

is aimed to reduce overall costs by enabling

economies of scale through interconnected

transport systems

b. Supporting commercial geologic CO

storage

initiatives with grants.

c. Promoting CO

utilization through legislation

allowing the US DOE to grant financing to

municipalities and states to enable procurement

of low carbon products and equipment.

d. Supporting legal and regulatory authorizations for

permitting Class VI CO

storage wells

5.2.2 European Union

The EU has been at the forefront of CCUS technology

development and has employed a variety of measures

to support, fund and incentivize CCUS. These support

measures are in the form of grant funds and

legislative & policy initiatives for CCUS, which have

been crucial in supporting the CCUS R&D, pilot and

demonstration projects across EU countries. A few

active funding programmes for CCUS in the EU region

are summarized in Table 5-1.

Table 5.1: EU Funding Schemes for CCUS

Funding scheme Fund sizeObjectives

EU Innovation Fund - Fund for demonstration of - EUR 38 billion support for 2020-2030,

low carbon technologies depending on the carbon price

- Part of the fund allocated to CCUS

Connecting Europe - Supports cross-border - EUR 25.8 billion CEF

Facility (CEF) CO

transportation transport budget

- EUR 11 billion budget for

cohesion countries

Recovery and Resilience - Mitigate the economic and - Funds raised by issuing

Facility (RRF) social impact of COVID bonds on behalf of the EU

- Investment in flagship areas (including - EUR 723.8 billion funds

CCUS & renewable energy) available

- EUR 385.8 billion in loans and

EUR 338 billion in grants

Just Transition - Support provided to territories - EUR 19.2 billion fund

Fund (JTF) facing socio-economic challenges

due to climate neutrality transitions

Horizon Europe - Programme supports the R&D and - EUR 95.5 billion budget for the

demonstration of CCUS period of 2021-2027

related projects

5.2.1.1 45Q

The 45Q provides tax credits for CCUS, starting from

USD 12.83 for each tonne of CO

utilized for EOR in

2017, linearly increasing to US$ 35/tonne in 2026.

Similarly, for CO

captured and geologically stored,

the tax credit was US$ 22.66/tonne in 2017, rising

linearly to US$ 50/tonne of CO

in 2026. Post-2026,

the credit shall be inflation-adjusted. Few mandatory

criteria must be met by emitters in order to avail the

tax credit, such as:

- facilities must begin construction before

1 January 2026

- the credit can be claimed over a 12-year period

after operations commence

- a minimum volume of CO

must be captured and

sequestered or utilized, which depends upon the

type of the emitting industry, as below:

• Non-EOR carbon utilization: 25-500 ktpa

of CO

• Industrial and DAC: 100 ktpa of CO

• Power plants: 500 ktpa of CO

The Global CCS Institute has long hailed USA’s 45Q

tax credit mechanism as the “most progressive

CCS-specific incentive globally”. The 45Q credits

lower a firm’s tax liability; in case there is no tax

liability, the credits can be traded in the tax equity

market. Tax credits have been successful in spurring

renewable energy projects in the US over the last two

decades. An important component for the successful

implementation of the 45Q or any tax incentive-based

system is designing a Monitoring Reporting and

Verification framework (MRV) to ensure compliance

of the projects seeking the 45Q credits.

The recently enacted Inflation Reduction Act of 2022

has substantially increased the maximum level of

credits available from US$ 50 to US$85/tonneof CO

sequestered and upto US$180/tonne of CO

for DAC.

5.2.1.2 California Low Carbon Fuel

Standard (LCFS)

The Low Carbon Fuel Standard (LCFS) in California is

a trading mechanism aimed at lowering the CO

intensity of the state’s fuel mix. A CCUS protocol for

the LCFS was agreed upon in January 2019, allowing

transportation fuels whose lifecycle emissions have

been lowered using CCUS to qualify for credits. The

protocol covers a wide range of CCUS applications

involving permanent storage of captured CO

depleted oil and gas reservoirs or saline formations or

used for enhanced oil recovery in oil and gas

reservoirs. Project credits are based on life cycle

emission reductions and granted if the reported

reductions have been validated.

LCFS is a strong motivator for CCUS deployment in

California. In 2020, the carbon credits obtained

through the LCFS roughly translated to USD 200 per

tonne of CO

. While the eligibility standards are strict,

several new project announcements have stated that

LCFS credits have been considered in their evaluation

and analysis of cost economics. The LCFS programme

offers several credit-generating possibilities to boost

low-carbon fuel supply and usage, viz:

i) Fuel pathway-based crediting: Low carbon fuels

generate credits based on emissions reduced

compared to the established baseline. These

credits incentivize developers to bring more clean

fuel options to California.

ii) Project-based crediting: This category includes

projects for reducing emissions across the

petroleum supply chain using measures such as

CCUS and direct air capture.

iii) Zero-emissions vehicle infrastructure

(capacity-based) crediting: Installation of

hydrogen and fast-charging DC infrastructure can

generate credits based on capacity.

5.2.1.3 State Primacy for CO

Storage

In 2010, the US EPA created the sixth well class (Class

VI) specifically to regulate the injection of CO

into

deep subsurface rock formations. At the time, very

few projects were sequestering CO

solely to reduce

greenhouse gas emissions, but the EPA anticipated

that technology development would be key to

achieving domestic emissions reductions. Wyoming

and North Dakota have been approved by the US

Environmental Protection Agency (EPA) to take

primary responsibility (‘primacy’) for regulating CO

injection for dedicated geological storage in Class VI

wells under the Underground Injection Control

(UIC) Program.

Texas and Louisiana have also stepped up efforts to

assume regulatory authority for CO

dedicated storage.

Louisiana has already applied for primacy, based on a

114

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

The OBPS is a carbon emission performance-based

system and is similar to the EU ETS, and brings

various industrial sectors under the federal carbon

pricing mechanism. A standard level of carbon

emission is set for each industry. Plant or facilities

emitting more than the limit shall be charged for the

additional emissions on a per tonne of CO

basis.

Plants and facilities that emit less than the set level

earn credits, which can be used to offset future

emissions or sold to other emitters who have higher

emission levels.

This kind of performance-based system incentivizes

industries to be energy efficient and limit Scope 1

carbon emissions through CCUS measures. The

prerequisites for a plant or facility to be covered

under the federal OBPS are that they should have

reported emission of at least 50,000 tonne of CO

e in

2014 or later and be located in a province following

the federal pricing system. The sectors covered in the

OBPS are oil and gas production, mineral processing,

chemical production, pharmaceutical production, iron

& steel, metal production, mining & ore processing,

electricity generation, fertilizer production, food

processing, pulp & paper processing and automotive

assembly.

The system aims to be revenue neutral, wherein the

proceeds from the fuel charge and OBPS is disbursed

back to the territories and provinces that have joined

the federal system. Provinces or territories that do not

join the federal system can formulate their own

provincial systems, which meet the minimum national

stringency standards or the federal benchmark or be

replaced by the federal system. In such regions, the

proceeds from the provincial system are to be

delivered back to the individuals, families, and

businesses through payments and climate action

programmes. Table 5-2 shows the carbon pricing

system opted for by the different provinces of Canada.

This is accompanied by the progressive withdrawal

of free CO

emission allowance for emission

intensive sectors, as allowed by the EU ETS

- Introduction of a Cross Border Adjustment

Mechanism (CBAM) to prevent carbon leakage

and substitution of goods produced in the EU by

imported goods from a country with lower or no

carbon price or CO

abatement requirements.

Importers would need to buy CBAM certificates

for the embedded carbon emission in their goods,

thus creating a level playing field between EU and

non-EU (high CO

emitting) manufacturers.

- Decouple economic growth from resource

exploitation, i.e., GHG emission reductions must

happen alongside enhanced resource usage

efficiency. This will require technological

advancements and fast adoption, rethinking and

change in lifestyles, communities and businesses

- Inclusive green transition to alleviate

socio-economic impacts of the energy transition.

The EU has devised the Just Transition

Mechanism (JTM), aimed to provide targeted

support to mobilize € 55 billion in 2021-2027

period for the most affected regions

The financing requirement of the European Green

Deal is estimated at €1 trillion, and is expected to be

financed from the EU budget and EU ETS (50) and the

InvestEU programme (balance 50%).

5.2.2.3 Norway

Within the EU, member countries, such as Norway have

their own individual legislations and regulatory

requirements to support the R&D and deployment of

CCUS technologies. An example of this is the LongShip

(‘Langskip’ in Norwegian) project which has been

successful due to the Norweigian Government’s support

in terms of economic benefits and stimulus for CCUS.

The LongShip project is a CCS demonstration project in

Norway, where annually about 400 ktpa of carbon

captured from the Norcem’s cement factory in Brevik is

transported by tankers to a reception terminal in the

west coast of Norway, and then injected into saline

aquifer storage formation through pipelines. Northern

Lights (a JV of Equinor, Shell and Total) has developed

the transport and storage solution, while Norcem

developed the carbon capture section. The LongShip

project is expected to ramp up CO

capture and storage

to 1.5 mtpa for 25 years. Two-thirds of the funding

requirement of around USD 2.7 BB$ is expected to be

funded from public sources.

The success of the LongShip project is largely owing

to the CO

transport and storage infrastructure

developed by the Northern Lights project. Initially able

to store 1.5 mtpa of CO

per year, the Northern Lights

project has the capacity to increase storage to 5 mtpa

of CO

per year. Incremental commercial CO

volumes

can be transported and stored at the Northern Lights

facilities, thereby reducing the unit cost of CO

storage. However, while LongShip has been hailed as

a success, the estimated CCUS cost of €144/tonne

(capture costs of €104/tonne and €40/tonne for CO

transport and storage costs) is significantly higher

than the prevailing EU ETS carbon price as of early

2022. Also, one key risk is the CO

leakage from the

underground geologic storage, as previous studies at

the Sleipner project in the North Sea have shown the

potential for significant leaks.

The Norwegian Government also plans to support

CCUS projects at waste incineration plants in Bergen,

Trondheim and Stavanger. The Government is keen to

develop CCS in Waste-to-Energy projects as this has

the potential of net removal of CO

from the

atmosphere, which is vital for achieving the EU’s

net-zero emission targets by 2050.

5.2.3 Canada

Canada has a policy mechanism for supporting its

2030 GHG reduction target of 40% from 2005 levels.

Canada also plans to adopt a carbon pricing

mechanism, with carbon emission emissions exceeding

certain limits to be taxed based on a carbon pricing

system, as stipulated by the Greenhouse Gas Pollution

Pricing Act (GGPPA) of 2018. The GGPPA defines two

separate pricing mechanisms: a) Federal Fuel Charge;

and b) Output Based Pricing System (OBPS).

The fuel charge is levied on 21 types of fuel that are

produced (including imports) or used or on any waste

used for the purpose of generating heat or energy.

The fuel charge came into effect in April 2019 and the

charge was set at CAD $ 20 per tonne of fuel. This

charge will be stepped up by CAD $10 every year, till it

reaches CAD $50 in 2022. The fuel charge is levied at

the registered distributor level, as they are one of the

earliest participants in the supply chain.

The different funding schemes cater to different

aspects of technology development. The Innovation

fund and Horizon Europe programme specifically

focuses on R&D of different low carbon technologies,

including CCUS. It also supports the demonstration of

these technologies at pilot scale. The Innovation Fund

is funded by the revenues collected from the EU

Emissions Trading System (EU ETS) and unspent

funds from the NER 300 programme. The fund

supports both small scale (<EUR 7.5 million capital

cost) and large scale (> EUR 7.5 million capital

cost) projects.

The CEF was established to support transport

networks across Europe, including cross-border CO

transportation infrastructure. The REF and JTF are

emergency funds deployed to support EU countries

transition to climate-neutral solutions in difficult

times, like the coronavirus pandemic. This kind of

support fund ensures that the countries do not deter

from their climate goals in times of crisis.

Horizon Europe (started in 1984) is one of the most

significant research and innovation support

mechanisms across Europe. It has collaboration with

several research bodies and large-scale industries and

links them to develop industrial solutions including

CCUS. The programme has been responsible for

increasing the TRL of several technologies by

supporting their demonstration at pilot scale.

The EU has also enacted various policy initiatives to

support CCUS technologies and projects. The CCUS

Directive of 2009 provides the legal framework for

environmentally safe geological storage of CO

ensuring risk minimization from CO

storage, such as

damage to human health and the environment. The

restructured Renewable Energy Directive now

supports fuels produced by CCUS.

5.2.2.1 EU Emissions Trading System (EU ETS)

The European Union Emissions Trading System (EU

ETS) is the world’s first GHG emissions trading

scheme. The salient features of EU ETS are as follows:

- Applicable for all EU countries, plus Iceland,

Liechtenstein and Norway

- Limits emissions from around 10,000 GHG emitters

across power and industrial sector, as well as

airlines operating between participating countries

- Covers around 40% of the total GHG emissions of

the participating countries

- The EU ETS framework has been revised multiple

times since its inception in 2005. Presently, the

trading phase is underway (2021-2030). The

legislative framework for this 4

phase was

revised to ensure emissions reductions in line with

EU’s 2030 emissions reduction target, i.e., ~40%

reduction in GHG emissions by 2030 as compared

to 1990 levels

- Follows a ‘cap and trade’ mechanism, where a cap

(or limit) is set on each installation/facility for

total permissible GHG emissions, where the cap is

reduced over time. Within the cap, installations

buy and receive emission allowances (i.e.,

emissions trading) with each other. The market

determines the emissions trading price and hence

adds a carbon cost to the industry.

Facilities participating in the EU ETS scheme have

reduced their GHG emissions by 35% in 2019, compared

to 2005, indicating the success of the scheme. The EU

policy support for CCUS is further strengthened by the

European Green Deal and 2030 Climate and Energy

Framework, wherein CCUS will be an integral tool in

achieving the target of reducing net GHG emissions by

at least 55% below the 1990 levels and EU becoming

the first climate-neutral continent by 2050.

5.2.2.2 European Green Deal

The European Green Deal was approved in 2020 and

provides a set of policy initiatives aimed at making EU

climate neutral by 2050, i.e., no net GHG emissions by

2050. The 2030 GHG emissions reduction target is

55% below 1990 levels. The Green Deal proposes to

review existing climate goals and redesign public

policies, and also introduce new legislation across EU

ETS, energy taxation, energy efficiency,

aviation/transport fuel regulations, GHG emissions

standards and regulations, land use, forestry and

agriculture regulations, creating a social climate fund

and carbon border adjustment mechanism. The three

main goals of the European Green Deal are:

- Achieve net-zero emissions by 2050 by proposing

specific strategies that can help curb emissions

across all sectors, with a strong focus on energy,

which makes up more than 75% of the total

EU-27’s greenhouses gas emissions.

- Reduction of the emissions cap allowed under the

EU ETS, so that the ETS is aligned to the “Fit for 55”

target of 55% GHG reduction by the year 2030.

115

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

The OBPS is a carbon emission performance-based

system and is similar to the EU ETS, and brings

various industrial sectors under the federal carbon

pricing mechanism. A standard level of carbon

emission is set for each industry. Plant or facilities

emitting more than the limit shall be charged for the

additional emissions on a per tonne of CO

basis.

Plants and facilities that emit less than the set level

earn credits, which can be used to offset future

emissions or sold to other emitters who have higher

emission levels.

This kind of performance-based system incentivizes

industries to be energy efficient and limit Scope 1

carbon emissions through CCUS measures. The

prerequisites for a plant or facility to be covered

under the federal OBPS are that they should have

reported emission of at least 50,000 tonne of CO

e in

2014 or later and be located in a province following

the federal pricing system. The sectors covered in the

OBPS are oil and gas production, mineral processing,

chemical production, pharmaceutical production, iron

& steel, metal production, mining & ore processing,

electricity generation, fertilizer production, food

processing, pulp & paper processing and automotive

assembly.

The system aims to be revenue neutral, wherein the

proceeds from the fuel charge and OBPS is disbursed

back to the territories and provinces that have joined

the federal system. Provinces or territories that do not

join the federal system can formulate their own

provincial systems, which meet the minimum national

stringency standards or the federal benchmark or be

replaced by the federal system. In such regions, the

proceeds from the provincial system are to be

delivered back to the individuals, families, and

businesses through payments and climate action

programmes. Table 5-2 shows the carbon pricing

system opted for by the different provinces of Canada.

This is accompanied by the progressive withdrawal

of free CO

emission allowance for emission

intensive sectors, as allowed by the EU ETS

- Introduction of a Cross Border Adjustment

Mechanism (CBAM) to prevent carbon leakage

and substitution of goods produced in the EU by

imported goods from a country with lower or no

carbon price or CO

abatement requirements.

Importers would need to buy CBAM certificates

for the embedded carbon emission in their goods,

thus creating a level playing field between EU and

non-EU (high CO

emitting) manufacturers.

- Decouple economic growth from resource

exploitation, i.e., GHG emission reductions must

happen alongside enhanced resource usage

efficiency. This will require technological

advancements and fast adoption, rethinking and

change in lifestyles, communities and businesses

- Inclusive green transition to alleviate

socio-economic impacts of the energy transition.

The EU has devised the Just Transition

Mechanism (JTM), aimed to provide targeted

support to mobilize € 55 billion in 2021-2027

period for the most affected regions

The financing requirement of the European Green

Deal is estimated at €1 trillion, and is expected to be

financed from the EU budget and EU ETS (50) and the

InvestEU programme (balance 50%).

5.2.2.3 Norway

Within the EU, member countries, such as Norway have

their own individual legislations and regulatory

requirements to support the R&D and deployment of

CCUS technologies. An example of this is the LongShip

(‘Langskip’ in Norwegian) project which has been

successful due to the Norweigian Government’s support

in terms of economic benefits and stimulus for CCUS.

The LongShip project is a CCS demonstration project in

Norway, where annually about 400 ktpa of carbon

captured from the Norcem’s cement factory in Brevik is

transported by tankers to a reception terminal in the

west coast of Norway, and then injected into saline

aquifer storage formation through pipelines. Northern

Lights (a JV of Equinor, Shell and Total) has developed

the transport and storage solution, while Norcem

developed the carbon capture section. The LongShip

project is expected to ramp up CO

capture and storage

to 1.5 mtpa for 25 years. Two-thirds of the funding

requirement of around USD 2.7 BB$ is expected to be

funded from public sources.

The success of the LongShip project is largely owing

to the CO

transport and storage infrastructure

developed by the Northern Lights project. Initially able

to store 1.5 mtpa of CO

per year, the Northern Lights

project has the capacity to increase storage to 5 mtpa

of CO

per year. Incremental commercial CO

volumes

can be transported and stored at the Northern Lights

facilities, thereby reducing the unit cost of CO

storage. However, while LongShip has been hailed as

a success, the estimated CCUS cost of €144/tonne

(capture costs of €104/tonne and €40/tonne for CO

transport and storage costs) is significantly higher

than the prevailing EU ETS carbon price as of early

2022. Also, one key risk is the CO

leakage from the

underground geologic storage, as previous studies at

the Sleipner project in the North Sea have shown the

potential for significant leaks.

The Norwegian Government also plans to support

CCUS projects at waste incineration plants in Bergen,

Trondheim and Stavanger. The Government is keen to

develop CCS in Waste-to-Energy projects as this has

the potential of net removal of CO

from the

atmosphere, which is vital for achieving the EU’s

net-zero emission targets by 2050.

5.2.3 Canada

Canada has a policy mechanism for supporting its

2030 GHG reduction target of 40% from 2005 levels.

Canada also plans to adopt a carbon pricing

mechanism, with carbon emission emissions exceeding

certain limits to be taxed based on a carbon pricing

system, as stipulated by the Greenhouse Gas Pollution

Pricing Act (GGPPA) of 2018. The GGPPA defines two

separate pricing mechanisms: a) Federal Fuel Charge;

and b) Output Based Pricing System (OBPS).

The fuel charge is levied on 21 types of fuel that are

produced (including imports) or used or on any waste

used for the purpose of generating heat or energy.

The fuel charge came into effect in April 2019 and the

charge was set at CAD $ 20 per tonne of fuel. This

charge will be stepped up by CAD $10 every year, till it

reaches CAD $50 in 2022. The fuel charge is levied at

the registered distributor level, as they are one of the

earliest participants in the supply chain.

- The EU ETS framework has been revised multiple

times since its inception in 2005. Presently, the

trading phase is underway (2021-2030). The

legislative framework for this 4

phase was

revised to ensure emissions reductions in line with

EU’s 2030 emissions reduction target, i.e., ~40%

reduction in GHG emissions by 2030 as compared

to 1990 levels

- Follows a ‘cap and trade’ mechanism, where a cap

(or limit) is set on each installation/facility for

total permissible GHG emissions, where the cap is

reduced over time. Within the cap, installations

buy and receive emission allowances (i.e.,

emissions trading) with each other. The market

determines the emissions trading price and hence

adds a carbon cost to the industry.

Facilities participating in the EU ETS scheme have

reduced their GHG emissions by 35% in 2019, compared

to 2005, indicating the success of the scheme. The EU

policy support for CCUS is further strengthened by the

European Green Deal and 2030 Climate and Energy

Framework, wherein CCUS will be an integral tool in

achieving the target of reducing net GHG emissions by

at least 55% below the 1990 levels and EU becoming

the first climate-neutral continent by 2050.

5.2.2.2 European Green Deal

The European Green Deal was approved in 2020 and

provides a set of policy initiatives aimed at making EU

climate neutral by 2050, i.e., no net GHG emissions by

2050. The 2030 GHG emissions reduction target is

55% below 1990 levels. The Green Deal proposes to

review existing climate goals and redesign public

policies, and also introduce new legislation across EU

ETS, energy taxation, energy efficiency,

aviation/transport fuel regulations, GHG emissions

standards and regulations, land use, forestry and

agriculture regulations, creating a social climate fund

and carbon border adjustment mechanism. The three

main goals of the European Green Deal are:

- Achieve net-zero emissions by 2050 by proposing

specific strategies that can help curb emissions

across all sectors, with a strong focus on energy,

which makes up more than 75% of the total

EU-27’s greenhouses gas emissions.

- Reduction of the emissions cap allowed under the

EU ETS, so that the ETS is aligned to the “Fit for 55”

target of 55% GHG reduction by the year 2030.

116

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

Table 5 2: Carbon Pricing System Adopted by Different Provinces of Canada

The OBPS is a carbon emission performance-based

system and is similar to the EU ETS, and brings

various industrial sectors under the federal carbon

pricing mechanism. A standard level of carbon

emission is set for each industry. Plant or facilities

emitting more than the limit shall be charged for the

additional emissions on a per tonne of CO

basis.

Plants and facilities that emit less than the set level

earn credits, which can be used to offset future

emissions or sold to other emitters who have higher

emission levels.

This kind of performance-based system incentivizes

industries to be energy efficient and limit Scope 1

carbon emissions through CCUS measures. The

prerequisites for a plant or facility to be covered

under the federal OBPS are that they should have

reported emission of at least 50,000 tonne of CO

e in

2014 or later and be located in a province following

the federal pricing system. The sectors covered in the

OBPS are oil and gas production, mineral processing,

chemical production, pharmaceutical production, iron

& steel, metal production, mining & ore processing,

electricity generation, fertilizer production, food

processing, pulp & paper processing and automotive

assembly.

The system aims to be revenue neutral, wherein the

proceeds from the fuel charge and OBPS is disbursed

back to the territories and provinces that have joined

the federal system. Provinces or territories that do not

join the federal system can formulate their own

provincial systems, which meet the minimum national

stringency standards or the federal benchmark or be

replaced by the federal system. In such regions, the

proceeds from the provincial system are to be

delivered back to the individuals, families, and

businesses through payments and climate action

programmes. Table 5-2 shows the carbon pricing

system opted for by the different provinces of Canada.

States

Federal

system

Provincial

system

Federal cum

provincial system

Yukon √

Nunavut √

Manitoba √

Alberta √

Saskatchewan √

Ontario √

Prince Edward Island √

British Columbia √

Northwest Territories √

Quebec √

Newfoundland and Labrador √

Nova Scotia √

New Brunswick √

This is accompanied by the progressive withdrawal

of free CO

emission allowance for emission

intensive sectors, as allowed by the EU ETS

- Introduction of a Cross Border Adjustment

Mechanism (CBAM) to prevent carbon leakage

and substitution of goods produced in the EU by

imported goods from a country with lower or no

carbon price or CO

abatement requirements.

Importers would need to buy CBAM certificates

for the embedded carbon emission in their goods,

thus creating a level playing field between EU and

non-EU (high CO

emitting) manufacturers.

- Decouple economic growth from resource

exploitation, i.e., GHG emission reductions must

happen alongside enhanced resource usage

efficiency. This will require technological

advancements and fast adoption, rethinking and

change in lifestyles, communities and businesses

- Inclusive green transition to alleviate

socio-economic impacts of the energy transition.

The EU has devised the Just Transition

Mechanism (JTM), aimed to provide targeted

support to mobilize € 55 billion in 2021-2027

period for the most affected regions

The financing requirement of the European Green

Deal is estimated at €1 trillion, and is expected to be

financed from the EU budget and EU ETS (50) and the

InvestEU programme (balance 50%).

5.2.2.3 Norway

Within the EU, member countries, such as Norway have

their own individual legislations and regulatory

requirements to support the R&D and deployment of

CCUS technologies. An example of this is the LongShip

(‘Langskip’ in Norwegian) project which has been

successful due to the Norweigian Government’s support

in terms of economic benefits and stimulus for CCUS.

The LongShip project is a CCS demonstration project in

Norway, where annually about 400 ktpa of carbon

captured from the Norcem’s cement factory in Brevik is

transported by tankers to a reception terminal in the

west coast of Norway, and then injected into saline

aquifer storage formation through pipelines. Northern

Lights (a JV of Equinor, Shell and Total) has developed

the transport and storage solution, while Norcem

developed the carbon capture section. The LongShip

project is expected to ramp up CO

capture and storage

to 1.5 mtpa for 25 years. Two-thirds of the funding

requirement of around USD 2.7 BB$ is expected to be

funded from public sources.

The success of the LongShip project is largely owing

to the CO

transport and storage infrastructure

developed by the Northern Lights project. Initially able

to store 1.5 mtpa of CO

per year, the Northern Lights

project has the capacity to increase storage to 5 mtpa

of CO

per year. Incremental commercial CO

volumes

can be transported and stored at the Northern Lights

facilities, thereby reducing the unit cost of CO

storage. However, while LongShip has been hailed as

a success, the estimated CCUS cost of €144/tonne

(capture costs of €104/tonne and €40/tonne for CO

transport and storage costs) is significantly higher

than the prevailing EU ETS carbon price as of early

2022. Also, one key risk is the CO

leakage from the

underground geologic storage, as previous studies at

the Sleipner project in the North Sea have shown the

potential for significant leaks.

The Norwegian Government also plans to support

CCUS projects at waste incineration plants in Bergen,

Trondheim and Stavanger. The Government is keen to

develop CCS in Waste-to-Energy projects as this has

the potential of net removal of CO

from the

atmosphere, which is vital for achieving the EU’s

net-zero emission targets by 2050.

5.2.3 Canada

Canada has a policy mechanism for supporting its

2030 GHG reduction target of 40% from 2005 levels.

Canada also plans to adopt a carbon pricing

mechanism, with carbon emission emissions exceeding

certain limits to be taxed based on a carbon pricing

system, as stipulated by the Greenhouse Gas Pollution

Pricing Act (GGPPA) of 2018. The GGPPA defines two

separate pricing mechanisms: a) Federal Fuel Charge;

and b) Output Based Pricing System (OBPS).

The fuel charge is levied on 21 types of fuel that are

produced (including imports) or used or on any waste

used for the purpose of generating heat or energy.

The fuel charge came into effect in April 2019 and the

charge was set at CAD $ 20 per tonne of fuel. This

charge will be stepped up by CAD $10 every year, till it

reaches CAD $50 in 2022. The fuel charge is levied at

the registered distributor level, as they are one of the

earliest participants in the supply chain.

- The EU ETS framework has been revised multiple

times since its inception in 2005. Presently, the

trading phase is underway (2021-2030). The

legislative framework for this 4

phase was

revised to ensure emissions reductions in line with

EU’s 2030 emissions reduction target, i.e., ~40%

reduction in GHG emissions by 2030 as compared

to 1990 levels

- Follows a ‘cap and trade’ mechanism, where a cap

(or limit) is set on each installation/facility for

total permissible GHG emissions, where the cap is

reduced over time. Within the cap, installations

buy and receive emission allowances (i.e.,

emissions trading) with each other. The market

determines the emissions trading price and hence

adds a carbon cost to the industry.

Facilities participating in the EU ETS scheme have

reduced their GHG emissions by 35% in 2019, compared

to 2005, indicating the success of the scheme. The EU

policy support for CCUS is further strengthened by the

European Green Deal and 2030 Climate and Energy

Framework, wherein CCUS will be an integral tool in

achieving the target of reducing net GHG emissions by

at least 55% below the 1990 levels and EU becoming

the first climate-neutral continent by 2050.

5.2.2.2 European Green Deal

The European Green Deal was approved in 2020 and

provides a set of policy initiatives aimed at making EU

climate neutral by 2050, i.e., no net GHG emissions by

2050. The 2030 GHG emissions reduction target is

55% below 1990 levels. The Green Deal proposes to

review existing climate goals and redesign public

policies, and also introduce new legislation across EU

ETS, energy taxation, energy efficiency,

aviation/transport fuel regulations, GHG emissions

standards and regulations, land use, forestry and

agriculture regulations, creating a social climate fund

and carbon border adjustment mechanism. The three

main goals of the European Green Deal are:

- Achieve net-zero emissions by 2050 by proposing

specific strategies that can help curb emissions

across all sectors, with a strong focus on energy,

which makes up more than 75% of the total

EU-27’s greenhouses gas emissions.

- Reduction of the emissions cap allowed under the

EU ETS, so that the ETS is aligned to the “Fit for 55”

target of 55% GHG reduction by the year 2030.

CCUS development in Canada is concentrated in

Alberta and Saskatchewan. Both the provinces have

CCUS supportive regulations equivalent to the GGPPA

norms. The province of Saskatchewan has entered

into an agreement with the Federal Government

wherein at least 40% of electricity shall be generated

from non-emitting sources, which would lead to the

phasing out of coal based power plants without CCUS.

This would also incentivize retrofitting coal-based

power plants with CCUS technology to ensure their

continued operations.

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Alberta has adopted the Technology Innovation and

Emissions Reduction Implementation Act (TIER). TIER

is a provincial policy measure which sets the CO

emission benchmark for emission-intensive industries

and a CO

price of CAD $30 per tonne for emissions

above the benchmark. Facilities with emissions below

the benchmark earn emission performance credits,

which can be traded/sold with other regulated

authorities. CCUS is an eligible technology for CO

emission reduction under TIER. The Government of

Alberta has also supported and funded CCUS project

development through a CAD 80 MM$ Industrial

Energy Efficiency and Carbon Capture Utilization and

Storage Grant Program, for funding up to 75% of

project expenses up to CAD 20 MM$. Grant support

has been provided to many CCUS projects such as

Boundary Dam (2014), Quest (2015), ACTL-Agrium

(2020), and ACTL- North West Sturgeon Refinery

(2020). In particular, the ACTL project has received

grant support CAD 558 MM$ from the Government of

Alberta and Canada. To address CO

storage risks, the

Canadian Government has also introduced laws

regarding the long-term liabilities surrounding CO

storage.

5.2.4 UK

The UK Government’s decarbonization plans are

guided by four main principles:

- no mandates on consumers to replace existing

products or infrastructure

- implementation of fair carbon pricing by the

Government

- economic assistance to low-income consumers

- incentives to businesses for deploying low-carbon

technology

A new element of the UK’s policy is the carbon price.

In 2021, a new UK Emissions Trading Scheme covering

energy-intensive industries, power generation, and

certain parts of aviation was implemented. By 2023,

an emissions cap will be implemented for a net zero

trajectory and strategy. The aim is to have CCUS

projects for capturing 10 mtpa CO

by 2030, to be

expanded to 20–30 mtpa subsequently. The CCUS

deployment goal aims at establishing two CCUS

clusters by 2025 and two more by 2030. Clusters

would be based on the co-location of coast based

industries and electricity generating facilities and CO

storage facilities, similar to the approach taken in the

United States, Australia and China.

The Climate Change Act of 2008 has mandated the

creation of “carbon budgets,” which set

emissions-reduction objectives in five-year intervals.

The UK has nearly eliminated coal based electricity

generation, increased industrial and building

efficiency, and reduced methane emissions from fossil

fuels. According to the most recent carbon budget,

the UK will need to collect 47 mtpa of CO

per year by

2050 to achieve net-zero emissions. Accordingly, the

2018 CCUS Deployment Pathway Action Plan outlines

the targets for addressing policy impediments and

establishing market mechanisms for CCUS. The

approach is based on industry consultation and

identification of viable CCUS business models and

supply chains.

The UK government has also invested in R&D and

CCUS demonstration projects and has allocated USD

61.2 MM$ for the same. The UK Government is also

supporting the CCUS Innovation 2.0 competition,

which pledges USD 26.5 MM$ in grants to new

technologies or processes that reduce the cost of

CCUS.

Additionally, the UK Government is considering

economic support for projects in different parts of the

CCUS value chain, including CO

transit and storage,

industrial and power projects with CCUS. The UK

Government is employing a “build it and they will

come” strategy for CO

transportation and storage,

providing funding to the first movers ready to build

CCUS infrastructure and guaranteeing a rate of

return. When supply is likely to surpass demand

during the initial phases, the USD 1.4 BB$ CCUS

Infrastructure Fund (CIF) will help in covering capital

expenses. Then, under an Economic Regulatory

Regime, transportation and storage providers will be

granted licences to charge user fees to CO

emitters

at a regulated rate of return.

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Industrial CCUS will also be provided financial

assistance similar to transportation and storage.

Industrial facilities using CCUS can seek funding from

the USD 435 MM$ CIF or the Industrial Energy

Transformation Initiative (IETF) to de-risk feasibility

studies and early deployment projects. Mining,

manufacturing, material recovery and recycling, and

data centres are eligible for the IETF. An Industrial

Carbon Capture contract between the project owner

and a government-appointed counterparty will provide

ongoing financial support. The counterparty will pay a

strike price based on estimated operational costs that

have been negotiated. Power plants with CCUS will not

receive capital support for construction but can receive

ongoing economic support and operational subsidies.

Power plants with CCUS will enter into Dispatchable

Power Agreements with a government-appointed

counterparty, which will pay an availability payment for

capacity and a variable payment so that electricity from

CCUS based plants is less expensive than from

unabated fossil fuel based plants.

The deployment strategy for CCUS in the United

Kingdom focuses on creating CCUS clusters in industrial

hubs around the country. The two CCUS clusters

initially identified are the Teeside and Humber cluster

on the North Sea. The Scottish cluster has been

designated as a “reserve cluster” in the event that one

of the two selections fails to reach an agreement with

the UK Government during discussions. The clusters

plan to capture carbon from fossil fuel power

generation, biomass power production, hydrogen

production, nitrogen production, steel production, and

waste-to-energy initiatives. The selected clusters, as

well as other clusters that have been evaluated, are

primarily located near the North Sea, home to much of

the UK’s oil and gas production. The UK Government is

also supporting the domestic oil and gas industry in

lowering carbon emissions by supporting joint

investments of up to USD 4 BB$ in CCUS projects.

5.2.5 Australia

Australia has been working proactively towards

achieving its emissions reduction targets and aims to be

a net-zero economy by 2050. The Australian

Government has identified CCUS as a crucial element of

achieving net-zero and articulated the same in their

Low Emission Technology Statement (LETS). The

Australian Government is providing grant funding,

regulation amendment and policy support for

promoting the development of CCUS infrastructure.

By 2030, the Australian Government plans to invest

AUD 20 BB$ in low emissions technology, including

CCUS, and have made a series of investments in CCUS

technology development in the form of grant support.

In 2021, the Australian Government also launched an

AUD 250 MM$ programme called the “CCUS Hubs and

Technologies Programme” to develop collaborative

partnerships and make CCUS deployment affordable at

a commercial scale. A part of the programme

(“Technology stream”) will fund R&D for scaling up of

CCUS technologies and identification of viable CO

storage sites; the second part (“Hubs stream”) will fund

the design and development of CCUS transportation

and hubs infrastructure that can be shared by

co-located CO

emitters.

Another example of grant support by the Australian

Government is the Carbon Capture, Use and Storage

Development Fund of AUD 50 MM$, which supports six

projects for the development of carbon capture

technology and demonstration in different industries,

along with CO

storage or utilization.

The Australian Government has also implemented

regulations to incentivize private sector investment in

CCUS to ensure emission reductions. The “Offshore

Petroleum and Greenhouse Gas Storage Act 2006

(OPGGSA)” was amended in May 2020 to allow CO

injection and storage across state and territorial

jurisdictions. The Australian Government has also made

emission reduction performance-based regulatory

standards and obligations a requisite for the approval of

storage projects. An example is the Gorgon CCUS

project, where a necessary condition for project

approval was the injection of at least 80% of the CO

emitted by the plant.

One of the key risks in CCUS projects is the long-term

storage liability of CO

, which demotivates private

investors. As a risk mitigation measure, the Australian

Government has enacted legislation related to long

term storage liability, which enables project

developers/CO

storage site owners to obtain a

declaration for the end of the “Closure Assurance

Period” 15 years after a CCUS site closure, post which

the project developer/CO

storage site owner shall no

longer be liable for damages to the storage site and will

have indemnity for any liability occurring after the

Closure Assurance Period.

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5.3 CCUS Policy Framework for India

Based on the review of the prevailing policy mechanisms in different parts of the world, it is clear that there are two

clear policy choices/approaches for India to adopt, i.e.

a) Carbon credits/incentives based policy

b) Carbon tax based policy

A comparison of the two policy approaches is provided in Table 5-3.

Table 5-3: Comparison of Carbon Credits/Incentives and Carbon Tax Based Policy

Policy type Carbon tax based policyCarbon credits based policy

- Incentivizes CCUS adoption & drives down

the cost of capture

- Establishes markets for

carbon-based products

- Offsets carbon capture costs through

financial instruments and future taxes &

growth

- Most suitable for decarbonization of

existing industrial asset base

Tax credit equity trading

- US 45Q tax credits

- Netherlands’ SDE++ scheme

- UK power sector

Contracts-for-Difference (CfD)

- UK CCUS Infrastructure fund

- EU Innovation fund

- Petra Nova CCUS (USA)

- Gorgon LNG (Australia)

- US 45Q tax credit:

• up to 60 USD/t CO

for EOR & conv.

• up to 85 USD/t CO

for storage

• up to 180 USD/t CO

for DAC

- Australia: AUD 60 MM$ for

Gorgon LNG project

- Canada: CAD 865 MM$ for Quest

Developing economy like India

- May not directly incentivize CCUS

- CCUS not established in India -

acceptability and affordability of

carbon tax is uncertain

- Eventually required in the long term

- Potential near term problems:

• May lead to industrial migration

and loss of competitiveness

• Effectiveness questionable

in the near term

Carbon emissions trading

- EU ETS

- China ETS

- Norway CO

tax

- Canada Output-Based

Pricing System (OBPS)

- California cap-and-trade

- Sleipner (Norway)

- Snøhvit (Norway)

- EU ETS: 34 Eur/t CO

- Canada ETS:

• 2021: 30 USD/t CO

• 2030: 170 USD/t CO

- Norway:

• 2021: 590 NOK (~70 USD) /t CO

• 2030: 2000 NOK (~237 USD)/t CO

Developed economies like EU

Key aspects of

the Policy

Trading scheme

Application

examples

CCUS project

examples

Suitability

Carbon subsidy/tax

examples

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The oversized carbon disposition infrastructure would

be too large for single users but rather be designed for

multiple users/emitters.

The anchor project would be large CO

emitters, viz. a

thermal power plant or a large industrial facility, which

can cover the initial infrastructure costs, thereby

enabling cost-effective CCUS deployment based on

incremental capital and operating expenses. Emitting

industrial clusters are frequently co-located with power

generation facilities, thus providing substantial

capturable CO

sources. The CO

disposition can be

spread across multiple but reasonably closely located

geological sequestration sites and/or oil fields for

enhanced oil recovery (EOR).

Both emitters and storage sites need to interconnect

through hubs, similar to the natural gas distribution

industry, where pipeline networks are interconnected

in order to collect gas from many different production

fields, and to distribute the gas in the market. One hub

would service the collection of CO

from a capture

cluster or distribution of CO

to a storage cluster, as

depicted in Figure 5-1. Hubs can be built at the capture,

collection, or storage end of a multi-user pipeline or

both (forming capture/collection or storage hubs).

Depending on the individual emissions sources within

the cluster, the volume and composition of the

captured CO

can vary significantly. Collection and

storage hubs will offer compressed CO

transportation

services, thus substantially lowering the cost of

transportation infrastructure between point source

emitters and CO

injection points.

The elements along the CCUS value chain (CO

source,

capture, transport, injection, and storage) are brought

together in a CCUS hub and cluster network, with

multiple co-located (clustered) source capture

facilities (of the same or different types) supplying

to a shared “oversized” transport and storage

system. With the growth of the CO

supplier or emitter

base, the transport and storage infrastructure must

expand through multiple transport pipelines, injection

facilities, and storage formations (depending upon

local geological characteristics). Multiple and high

concentration sources of CO

in a close geographical

location with neighbouring storage capacity will make

the CCUS infrastructure effective & economical.

Table 5-4: Key Elements of a CCUS Policy Framework for India

The key elements to be considered while formulating a CCUS policy framework for India are tabulated in Table 5-4.

Element Details

- In the near term, CCUS policy should be carbon credits or incentives based, to seed

and promote the CCUS sector in India through tax and cash credits

- Over time (probably beyond 2050), the policy should transition to carbon taxes, so

as to enable reaching India’s net zero goals by 2070

- The policy should establish early stage financing and funding mechanisms for

CCUS projects

- Regional hub & cluster models need to be established to drive economies of scale

- The role of emitters, aggregators, hub operator, disposers and conversion agents

needs to be defined

- Preferential procurement in Government tenders for low carbon or

carbon abated products

- Incentives to foster innovation for low carbon products through schemes like PLI

- Distribution of benefits of economic value added created to communities most

affected by environmental and climate change

- Protection of communities and jobs, especially in sectors affected by clean energy

regulations

- Regulated emission levels and allowances for different sector

- Adoption of Life Cycle Analysis (LCA) framework to take into account Scope 2 and

Scope 3 emissions and drive effective carbon abatement

- Limiting the CO

liability and ownership of participants across the

CCUS value chain

- Monitoring, Verification and Accounting (MVA) framework and monitoring

for risk management

Policy path

Hub & cluster

business model

Low carbon products

Environmental and

social justice

Accounting and

regulatory framework

Risk mitigation

5.4 CCUS Clusters for CO

Capture and Disposition at Scale

The key to a successful CCUS policy for India is a

framework that supports the creation of sustainable

and viable markets for CCUS projects. The framework

must consider the fact that the private sector is

unlikely to invest in CCUS unless there are sufficient

incentives to do so (or conversely penalties from

inaction), or unless it can benefit from the sale of CO

or gain credits for emissions avoided under carbon

pricing regimes. Direct capital grants, tax credits,

carbon pricing schemes, operational subsidies,

regulatory requirements, and public procurement

preference for low-carbon products are some of the

policy measures required for CCUS to become a

reality in India. In this section we look at the concept

of CCUS clusters required for CO

capture and

disposition at scale, and how policy mechanisms can

drive and support the same.

5.4.1 Basic Concept

The concept of clusters is well established in the

economics of industrial development. An industry

cluster is a geographic concentration of

interconnected businesses, suppliers, and associated

organizations in a specific geographical area. For

CCUS, clusters will be advantageous for

emissions-intensive facilities (both industrial facilities

and power plants) co-located in geographical clusters

and provide incentives to CO

emitters to form a

capture cluster, which can be connected to a

large-scale CO

storage site using an oversized

shared transport infrastructure, as well as options

for utilization of CO

to produce low carbon

downstream products.

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The oversized carbon disposition infrastructure would

be too large for single users but rather be designed for

multiple users/emitters.

The anchor project would be large CO

emitters, viz. a

thermal power plant or a large industrial facility, which

can cover the initial infrastructure costs, thereby

enabling cost-effective CCUS deployment based on

incremental capital and operating expenses. Emitting

industrial clusters are frequently co-located with power

generation facilities, thus providing substantial

capturable CO

sources. The CO

disposition can be

spread across multiple but reasonably closely located

geological sequestration sites and/or oil fields for

enhanced oil recovery (EOR).

Both emitters and storage sites need to interconnect

through hubs, similar to the natural gas distribution

industry, where pipeline networks are interconnected

in order to collect gas from many different production

fields, and to distribute the gas in the market. One hub

would service the collection of CO

from a capture

cluster or distribution of CO

to a storage cluster, as

depicted in Figure 5-1. Hubs can be built at the capture,

collection, or storage end of a multi-user pipeline or

both (forming capture/collection or storage hubs).

Depending on the individual emissions sources within

the cluster, the volume and composition of the

captured CO

can vary significantly. Collection and

storage hubs will offer compressed CO

transportation

services, thus substantially lowering the cost of

transportation infrastructure between point source

emitters and CO

injection points.

The elements along the CCUS value chain (CO

source,

capture, transport, injection, and storage) are brought

together in a CCUS hub and cluster network, with

multiple co-located (clustered) source capture

facilities (of the same or different types) supplying

to a shared “oversized” transport and storage

system. With the growth of the CO

supplier or emitter

base, the transport and storage infrastructure must

expand through multiple transport pipelines, injection

facilities, and storage formations (depending upon

local geological characteristics). Multiple and high

concentration sources of CO

in a close geographical

location with neighbouring storage capacity will make

the CCUS infrastructure effective & economical.

Figure 5-1: CCUS Hub and Cluster Framework

Source: Global CCS Institute

STEEL PLANT

FERTILISER

PLANT

NATURAL GAS

PROCESSING

REFINING

POWER PLANT

CEMENT PLANT

BIOMASS

OFFSHORE

STORAGE

ONSHORE

STORAGE

HYDROGEN

PRODUCTION

COLLECTION HUB

TRANSPORT

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5.4.2 Economic and Business Rationale for

CCUS Hubs and Clusters

The development and deployment of CCUS at scale

requires the development of not only the technologies

for CO

capture and use, but also the implementation

of enabling transportation infrastructure and markets

at Giga-tonne (GT) scale, along with the development

of a complete value chain of capture, aggregation,

transportation, disposition and use or storage. An

effective CCUS hub and cluster framework will

incentivize participants across the CCUS value chain by

providing seamless access to CCUS infrastructure,

minimize costs and coordination issues, offer

opportunities to maximize benefits/profits and de-risk

investments by widening the market, and abrogate the

necessity of bilateral agreements between CO

sources

and sinks.

For CCUS hubs and clusters to be effective,

they need to:

- Provide sufficient incentives for both sources (CO

emitters) and sinks of CO

(CO

end-users) to

participate in the market, as well as CO

aggregators and CO

marketers. This is especially

relevant when entry involves large fixed costs that

could limit participation

- Aggregate carbon emissions across emitters to

create economies of scale

- Exploit different storage and use patterns across

geographical regions or clusters

- Enable market clearing of CO

demand and

supply within and across regions through

interconnecting hubs

- Recognize the heterogeneity of emitters, and

provide them open access to the hub and cluster

network for CO

disposition

Pricing and the Necessity of Markets

Capture costs are dependent on a number of factors,

including the source, density and purity of the CO

emission stream. Transportation costs depend on

volume and distance, and injection costs depend on

volume and site location. If a utilization opportunity

exists, the costs depend on the application, with

enhanced oil recovery (EOR) being an injection activity

while applications like chemicals or advanced materials

being dependent on a host of other factors. The build

up of these costs across the CCUS value chain can

become the substantial and prevent the development

and implementation of CCUS projects.

Hence there is a necessity for a market model for

encouraging and incentivizing scale & innovation,

leading to lower costs and prices for participants

across the CCUS value chain.

Innovations in the CCUS context could involve

technologies and applications leading to creation of

value added products from CO

, such CO

to chemicals,

cement and advanced carbon materials. As with any

innovation, it is difficult to predict which of these

applications will reach commercialization earlier than

the others. Innovation could reduce costs across the

CCUS value chain or also bring forth new pathways for

using CO

as a feedstock, leading to higher demand and

prices for carbon and CCUS.

Prices will be governed by both expectations of future

demand-supply as well as the level of competition in

the market on both the demand and supply side.

Sufficient competition is necessary for efficient pricing,

leading to efficient allocation of resources for CCUS

and sharing of gains between the supply and the

demand side. On the supply side, the market needs to

incentivize participation by sellers that can supply CO

at the lowest cost. On the demand side, the CO

should

be allocated to buyers that have the highest value

usage and ability to pay the CO

price.

Auctions provide a way for the efficient allocation of

resources. Consumers of CO

can compete against

each other so that the final bids reflect the

highest-value use for CO

. A higher price for CO

implies that demand is higher than supply and should

incentivize new CO

emitters (supply) to capture CO

and enter the CCUS value chain/market. However,

during the initial operations of the CCUS value chain

with a small market and limited number of participants,

emitters may need additional incentives to enter

the market, through measures such as administered

pricing mechanisms. It is likely that more efficient and

purely demand-supply based pricing mechanisms will

emerge as markets mature and grow in size.

Hubs and clusters provide a valuable market-making

mechanism for de-risking investments and

incentivizing participation in the CCUS value chain.

During their initial period, Government support (either

in the form of federal & private investments, tax

credits, carbon taxes) is critical for ensuring sufficient

participation and success, till the market reaches scale

and efficiency. The next section discusses some of the

CCUS hubs and clusters in different parts of the world.

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

Long term economic analysis reveals the potential

to capture up to 62 mtpa of CO

considering the

available onshore and offshore reservoirs.

iii) Transport: CO

will be transported by a dedicated

pipeline to a depleted gas field located 25 km

offshore. The pipeline will be insulated to ensure

the CO

is warm enough to be injected into the low

pressure depleted reservoir. In subsequent phases

of the project, other sources would be connected to

the offshore section of the line, which will be

modified to transport up to 5 mtpa. This phase will

also include a network extension to connect more

sources and sinks, along with assessments of

connectivity to other prospective CO

hub locations

which can share the transportation infrastructure.

iv) Storage: Initially, the CO

is planned to be stored in

the offshore P18 field’s reservoirs 6, 5 and 2, which

have a capacity of up to 42.4 mtpa. Initial

investigations also reveal the possibility of storing

up to 259 mtpa of CO

in other fields in the area.

v) Funding: The Dutch Government will be granting

the project consortium (which includes Royal Dutch

Shell and ExxonMobil) around USD 2.4 BB$ in

subsidies for what is set to become one of the

largest CCUS projects in the world.

vi) Value proposition: The main value proposition is

the competitive cost structure of the Rotterdam

hub vis-à-vis CCUS projects worldwide, providing a

one-stop CO

disposition solution for CO

emitters

and making carbon abatement a part of the

Rotterdam city’s and port’s goals. The competitive

cost structure is driven by the favourable location,

with sources and offshore sinks co-located, making

transport simpler and less expensive. Other

reasons are the economies of scale and the

potential of CO

being shipped to the cluster from

other CO

emitting areas, thus leading to high

capacity utilization.

vii) Revenue streams: The main revenue stream will

be from the CO

transit charge collected from

emitters. There is also an option of the Government

providing loans or investments for early project

development, with analysis indicating that the

revenues to the Government from royalties and

taxes earned through CO

EOR will compensate

underwriting the initial project costs and risks.

Figure 5-2: CCUS Cluster Around the World

5.4.3 Review of CO

Clusters Around the World

The major CCUS cluster around the world are illustrated below. Many of the clusters are located near ports with large

industrial footprints, and provide regions and countries a competitive advantage in a carbon-constrained world.

5.4.3.1 Rotterdam Cluster Project (RCP),

Netherlands

i) Outline: This cluster is supported principally

through the Rotterdam Climate Initiative, which is a

partnership between the City of Rotterdam, the

Port of Rotterdam, DCMR Environmental

Protection Agency Rijnmond, and Deltalinqs, an

association of industrial enterprises in the

Rotterdam area. The initiative started with the

objective of reducing CO

emissions by 50% within

2030. The vision includes a full CO

network

capturing CO

from the power plants and industries

in the Rotterdam area and transporting the CO

for

offshore storage. The long term vision is to extend

beyond the Rotterdam region and also to

neighbouring countries and beyond the Dutch

continental shelf. The plan is to develop the project

as an integrated CCUS cluster project, termed as

ROAD (Rotterdam Opslag en Afvang Demonstratie,

or Rotterdam Storage and Capture Demonstration)

ii) Capture: The ROAD project initially had a capacity

of 1.1 mtpa with a single carbon capture unit for

capturing 25% of the flue gas from a coal-fired

power plant. A collection of projects have entered

into cooperation agreements, which may increase

the capture volume by an additional 5 mtpa. The

Rotterdam area has outsized CCUS infrastructure,

which can capture and sequester up to 17.5 mtpa of

by 2025 and become a regional centre by

storing CO

from other parts of the Netherlands,

and potentially the neighbouring countries of

Germany and Belgium.

Le Havre cluster

(COCATE)

14.5 mtpa

Teesside cluster

26 mtpa

Yorkshire cluster

60 mtpa

Firth of Forth

7.6 mtpa

Skagerrak/

Kattegat cluster

14 mtpa

Rotterdam

climate project

(RCP)

17.5 mtpa

Shenzhen City

cluster

43 mtpa

Marseille cluster

(VASCO)

35.5 mtpa

Gulf Coast

cluster

7.6 mtpa

Denver City Hub

cluster

8.4 mtpa

Rocky Mountain

cluster

9.5mtpa

Alberta CO

Truck Line

(ACTL)

14.6 mtpa

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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CCUS Policy Framework for India

The anchor emitter will inject 5 mtpa of CO

in the

hub, and the capacity will increase with other

emitters joining the hub. These emitters would be

across industries such as power plants, steel

plants, chemical plants, petroleum refineries,

biomass based plants and other sources.

Additionally, a new IGCC plant using underground

coal gasification is also being explored.

iii) Transport: The hub has been designed with a

notional 200 km offshore line that can reach

several potential storage sites, along with the

possibility of shipping during the capacity

build-up phase.

iv) Storage: Studies have identified a handful of

prospective offshore storage sites within a

200-kilometer radius. Further studies on the

characterization of the reservoirs is being

undertaken. The high-level storage costs are

predicted to be between £12 – 14 per tonne of CO

v) Funding: The project has secured about USD 39

MM$ 28m of public funding from the UK Research

and Innovation (UKRI) Industrial Decarbonisation

Challenge fund.

vi) Value proposition: The core value proposition for

participating industries is avoiding payments on

emission certifications, as pooling transportation

and storage facilities will make CCUS less

expensive. Teesside’s proximity to storage

locations makes it a low-cost option for CCUS in

the UK.

vii) Revenue streams: The main revenue stream

would be transport and storage payments from

emitters, either in the form of tariffs or based on

equity/cost recovery arrangements. Government

support would be needed to cover the business

risks in the form of CO

floor prices, CCUS fees,

and demonstration project funding.

viii)Business model: To further support the

development of the CCUS hubs and clusters, the

UK Government, in consultation with the industry,

is also developing a business model for Industrial

Carbon Capture (ICC) projects. The key elements

addressed by the business model are:

- Commercial framework for ICC projects,

including the payment mechanism between

different counterparties in the CCUS value chain

- Transport and Storage (T&S) fees

- Carbon price

- Conditions and time period for which capital

grant and ongoing revenue support will be

provided by to eligible projects by the

Government

- Risk allocation and mitigation

- Carbon intensity of industrial products and

free allowances

- Legal contractual framework and draft

contract for Industrial Carbon Capture

between CO

emitters and counterparties

- Conditions precedent and milestones

- Metering and reporting requirements

5.4.3.3 Denver City Hub Cluster, USA

i) Outline: The Denver City hub is located in Texas

and is part of the trunk line for transporting CO

from naturally occurring underground resources to

EOR projects. Several long-distance CO

pipelines

converge at Denver City in Texas, from where CO

is distributed to over 40 oilfields for EOR. Kinder

Morgan is the primary partner in the Denver City

hub and operates a variety of oil & gas production

and distribution facilities in addition to the CO

business. Other large oil and gas firms, such as

Occidental, BP, Amerada Hess, and Exxon Mobil,

are co-owners and operators of parts of the

system. There are efforts to expand the hub to

other locations for CO

EOR as well as large

sources of anthropogenic CO

emissions.

ii) Capture: Presently the CO

entering the system

comes from natural CO

reservoirs. The plan is to

inject CO

emissions from natural gas processing

plants in the region, given the total system capacity

of 45 mtpa, considering the four main pipelines and

the available natural CO

reservoirs in the hub.

iii) Transport: Transportation is by

supercritical-pressure pipeline, and additions are

common in both design and operation. A

160-kilometer pipeline has been built from the

facility to the Denver City hub for the Century

natural gas processing project of Occidental

Petroleum in West Texas, which is the largest

carbon capture plant in the world, with a capacity

of 8.4 mtpa of CO

capture.

Figure 5-3: Rotterdam CCS Cluster

Long term economic analysis reveals the potential

to capture up to 62 mtpa of CO

considering the

available onshore and offshore reservoirs.

iii) Transport: CO

will be transported by a dedicated

pipeline to a depleted gas field located 25 km

offshore. The pipeline will be insulated to ensure

the CO

is warm enough to be injected into the low

pressure depleted reservoir. In subsequent phases

of the project, other sources would be connected to

the offshore section of the line, which will be

modified to transport up to 5 mtpa. This phase will

also include a network extension to connect more

sources and sinks, along with assessments of

connectivity to other prospective CO

hub locations

which can share the transportation infrastructure.

iv) Storage: Initially, the CO

is planned to be stored in

the offshore P18 field’s reservoirs 6, 5 and 2, which

have a capacity of up to 42.4 mtpa. Initial

investigations also reveal the possibility of storing

up to 259 mtpa of CO

in other fields in the area.

v) Funding: The Dutch Government will be granting

the project consortium (which includes Royal Dutch

Shell and ExxonMobil) around USD 2.4 BB$ in

subsidies for what is set to become one of the

largest CCUS projects in the world.

vi) Value proposition: The main value proposition is

the competitive cost structure of the Rotterdam

hub vis-à-vis CCUS projects worldwide, providing a

one-stop CO

disposition solution for CO

emitters

and making carbon abatement a part of the

Rotterdam city’s and port’s goals. The competitive

cost structure is driven by the favourable location,

with sources and offshore sinks co-located, making

transport simpler and less expensive. Other

reasons are the economies of scale and the

potential of CO

being shipped to the cluster from

other CO

emitting areas, thus leading to high

capacity utilization.

vii) Revenue streams: The main revenue stream will

be from the CO

transit charge collected from

emitters. There is also an option of the Government

providing loans or investments for early project

development, with analysis indicating that the

revenues to the Government from royalties and

taxes earned through CO

EOR will compensate

underwriting the initial project costs and risks.

Rotterdam CCS cluster - Locations of licensing blocks

with depleted fields identified as suitable for CO

storage

5.4.3.2 Teesside UK Cluster, UK

i) Outline: A significant number of large CO

emitting

industries are located around the mouth of the

River Tees on England’s NE coast. Net Zero

Teesside is a carbon capture, utilization, and

storage (CCUS) initiative in the Teesside region of

England that aims to reduce industrial emissions. It

entails the construction of an 840 MW gas-fired

power station fitted with carbon capture

technology, as well as the creation of CO

collection network to enable low-carbon hydrogen

production. Initially, the project aims to capture up

to 10 mtpa of CO

emissions. Along with the

Teeside cluster, another CCUS cluster is also

coming up around the river Humber on the East

Coast of England. The CO

from both projects will

be permanently stored in a geological aquifer in the

Southern North Sea.

ii) Capture: The project includes a single-source initial

anchor project, as well as other small, medium, and

large CO

emitters.

ROAD (Rotterdam Opslag en Afvang Demonstratie,

or Rotterdam Storage and Capture Demonstration)

ii) Capture: The ROAD project initially had a capacity

of 1.1 mtpa with a single carbon capture unit for

capturing 25% of the flue gas from a coal-fired

power plant. A collection of projects have entered

into cooperation agreements, which may increase

the capture volume by an additional 5 mtpa. The

Rotterdam area has outsized CCUS infrastructure,

which can capture and sequester up to 17.5 mtpa of

by 2025 and become a regional centre by

storing CO

from other parts of the Netherlands,

and potentially the neighbouring countries of

Germany and Belgium.

iv) Storage: The CO

is entirely utilized for EOR projects

and there are no projects purely for storage.

v) Value proposition: The current CO

value

proposition is based on the profitability of

extracting additional oil using CO

EOR. The costs

per tonne of CO

delivered hence should be

substantially lower than the value of the extra oil

recovery. Recent contracts have also incorporated

specific carbon credit provisions, based on the

minimum offtake of CO

vi) Revenue streams: Transportation tariffs and CO

sales are the two main revenue streams, apart

from the potential revenues from the credits

earned through the project.

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

Netherlands

Rotterdam

K12

P15

P18

The anchor emitter will inject 5 mtpa of CO

in the

hub, and the capacity will increase with other

emitters joining the hub. These emitters would be

across industries such as power plants, steel

plants, chemical plants, petroleum refineries,

biomass based plants and other sources.

Additionally, a new IGCC plant using underground

coal gasification is also being explored.

iii) Transport: The hub has been designed with a

notional 200 km offshore line that can reach

several potential storage sites, along with the

possibility of shipping during the capacity

build-up phase.

iv) Storage: Studies have identified a handful of

prospective offshore storage sites within a

200-kilometer radius. Further studies on the

characterization of the reservoirs is being

undertaken. The high-level storage costs are

predicted to be between £12 – 14 per tonne of CO

v) Funding: The project has secured about USD 39

MM$ 28m of public funding from the UK Research

and Innovation (UKRI) Industrial Decarbonisation

Challenge fund.

vi) Value proposition: The core value proposition for

participating industries is avoiding payments on

emission certifications, as pooling transportation

and storage facilities will make CCUS less

expensive. Teesside’s proximity to storage

locations makes it a low-cost option for CCUS in

the UK.

vii) Revenue streams: The main revenue stream

would be transport and storage payments from

emitters, either in the form of tariffs or based on

equity/cost recovery arrangements. Government

support would be needed to cover the business

risks in the form of CO

floor prices, CCUS fees,

and demonstration project funding.

viii)Business model: To further support the

development of the CCUS hubs and clusters, the

UK Government, in consultation with the industry,

is also developing a business model for Industrial

Carbon Capture (ICC) projects. The key elements

addressed by the business model are:

- Commercial framework for ICC projects,

including the payment mechanism between

different counterparties in the CCUS value chain

- Transport and Storage (T&S) fees

- Carbon price

- Conditions and time period for which capital

grant and ongoing revenue support will be

provided by to eligible projects by the

Government

- Risk allocation and mitigation

- Carbon intensity of industrial products and

free allowances

- Legal contractual framework and draft

contract for Industrial Carbon Capture

between CO

emitters and counterparties

- Conditions precedent and milestones

- Metering and reporting requirements

5.4.3.3 Denver City Hub Cluster, USA

i) Outline: The Denver City hub is located in Texas

and is part of the trunk line for transporting CO

from naturally occurring underground resources to

EOR projects. Several long-distance CO

pipelines

converge at Denver City in Texas, from where CO

is distributed to over 40 oilfields for EOR. Kinder

Morgan is the primary partner in the Denver City

hub and operates a variety of oil & gas production

and distribution facilities in addition to the CO

business. Other large oil and gas firms, such as

Occidental, BP, Amerada Hess, and Exxon Mobil,

are co-owners and operators of parts of the

system. There are efforts to expand the hub to

other locations for CO

EOR as well as large

sources of anthropogenic CO

emissions.

ii) Capture: Presently the CO

entering the system

comes from natural CO

reservoirs. The plan is to

inject CO

emissions from natural gas processing

plants in the region, given the total system capacity

of 45 mtpa, considering the four main pipelines and

the available natural CO

reservoirs in the hub.

iii) Transport: Transportation is by

supercritical-pressure pipeline, and additions are

common in both design and operation. A

160-kilometer pipeline has been built from the

facility to the Denver City hub for the Century

natural gas processing project of Occidental

Petroleum in West Texas, which is the largest

carbon capture plant in the world, with a capacity

of 8.4 mtpa of CO

capture.

iv) Storage: The CO

is entirely utilized for EOR projects

and there are no projects purely for storage.

v) Value proposition: The current CO

value

proposition is based on the profitability of

extracting additional oil using CO

EOR. The costs

per tonne of CO

delivered hence should be

substantially lower than the value of the extra oil

recovery. Recent contracts have also incorporated

specific carbon credit provisions, based on the

minimum offtake of CO

vi) Revenue streams: Transportation tariffs and CO

sales are the two main revenue streams, apart

from the potential revenues from the credits

earned through the project.

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Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

The anchor emitter will inject 5 mtpa of CO

in the

hub, and the capacity will increase with other

emitters joining the hub. These emitters would be

across industries such as power plants, steel

plants, chemical plants, petroleum refineries,

biomass based plants and other sources.

Additionally, a new IGCC plant using underground

coal gasification is also being explored.

iii) Transport: The hub has been designed with a

notional 200 km offshore line that can reach

several potential storage sites, along with the

possibility of shipping during the capacity

build-up phase.

iv) Storage: Studies have identified a handful of

prospective offshore storage sites within a

200-kilometer radius. Further studies on the

characterization of the reservoirs is being

undertaken. The high-level storage costs are

predicted to be between £12 – 14 per tonne of CO

v) Funding: The project has secured about USD 39

MM$ 28m of public funding from the UK Research

and Innovation (UKRI) Industrial Decarbonisation

Challenge fund.

vi) Value proposition: The core value proposition for

participating industries is avoiding payments on

emission certifications, as pooling transportation

and storage facilities will make CCUS less

expensive. Teesside’s proximity to storage

locations makes it a low-cost option for CCUS in

the UK.

vii) Revenue streams: The main revenue stream

would be transport and storage payments from

emitters, either in the form of tariffs or based on

equity/cost recovery arrangements. Government

support would be needed to cover the business

risks in the form of CO

floor prices, CCUS fees,

and demonstration project funding.

viii)Business model: To further support the

development of the CCUS hubs and clusters, the

UK Government, in consultation with the industry,

is also developing a business model for Industrial

Carbon Capture (ICC) projects. The key elements

addressed by the business model are:

- Commercial framework for ICC projects,

including the payment mechanism between

different counterparties in the CCUS value chain

- Transport and Storage (T&S) fees

- Carbon price

- Conditions and time period for which capital

grant and ongoing revenue support will be

provided by to eligible projects by the

Government

- Risk allocation and mitigation

- Carbon intensity of industrial products and

free allowances

- Legal contractual framework and draft

contract for Industrial Carbon Capture

between CO

emitters and counterparties

- Conditions precedent and milestones

- Metering and reporting requirements

5.4.3.3 Denver City Hub Cluster, USA

i) Outline: The Denver City hub is located in Texas

and is part of the trunk line for transporting CO

from naturally occurring underground resources to

EOR projects. Several long-distance CO

pipelines

converge at Denver City in Texas, from where CO

is distributed to over 40 oilfields for EOR. Kinder

Morgan is the primary partner in the Denver City

hub and operates a variety of oil & gas production

and distribution facilities in addition to the CO

business. Other large oil and gas firms, such as

Occidental, BP, Amerada Hess, and Exxon Mobil,

are co-owners and operators of parts of the

system. There are efforts to expand the hub to

other locations for CO

EOR as well as large

sources of anthropogenic CO

emissions.

ii) Capture: Presently the CO

entering the system

comes from natural CO

reservoirs. The plan is to

inject CO

emissions from natural gas processing

plants in the region, given the total system capacity

of 45 mtpa, considering the four main pipelines and

the available natural CO

reservoirs in the hub.

iii) Transport: Transportation is by

supercritical-pressure pipeline, and additions are

common in both design and operation. A

160-kilometer pipeline has been built from the

facility to the Denver City hub for the Century

natural gas processing project of Occidental

Petroleum in West Texas, which is the largest

carbon capture plant in the world, with a capacity

of 8.4 mtpa of CO

capture.

v) Value propositions: The major value proposition is

the delivery of CO

to CO

-EOR projects at a

reasonable cost. Another advantage is the

opportunity to minimize the “tax” on CO

emissions

imposed by the Alberta Government and access to

Government and private funding for carbon

abated projects.

vi) Revenue streams: The project is being funded

through Government support for investments and

private venture capital. The main revenue sources

are the payments received for the CO

delivered

for EOR.

Figure 5-4: Timeline Denver City Hub

Figure 5-5: Denver City Storage

iv) Storage: The CO

is entirely utilized for EOR projects

and there are no projects purely for storage.

v) Value proposition: The current CO

value

proposition is based on the profitability of

extracting additional oil using CO

EOR. The costs

per tonne of CO

delivered hence should be

substantially lower than the value of the extra oil

recovery. Recent contracts have also incorporated

specific carbon credit provisions, based on the

minimum offtake of CO

vi) Revenue streams: Transportation tariffs and CO

sales are the two main revenue streams, apart

from the potential revenues from the credits

earned through the project.

Time line Denver Cirty Hub

pre1990 1990 2000 2010 2020 2030 2040 2050

Development of natural

business ~45 mtpa

Invt

Business development

Century gas plant capture

8.4 mtpa added

Potential for expansion

by capture

5.4.3.4 The Alberta Carbon Dioxide

Trunk Line (ACTL)

i) Outline: The project is based on the synergy

between oil producers who can benefit from

-EOR and CO

emitters, particularly from the oil

& gas industry, who can abate their CO

emissions.

The project consists of a central CO

trunk pipeline,

similar to trunk lines in the oil & gas industry.

The first phase consists of two capture locations.

The CO

pipeline will be constructed and operated

by Enhance Energy, for transporting the CO

for

EOR. The EOR operations will also include

monitoring of the stored CO

plume, design of wells

and the injection programme and reservoir

management.

ii) Capture: The project started with two CO

sources:

an Agrium fertilizer facility and the Sturgeon heavy

oil upgrading refinery. The capture costs are CAD

21/tonne at Agrium (for 1.2 mtpa of CO

) and CAD

12/tonne at Sturgeon (for 0.4 mtpa). The trunk line

capacity is expected to be expanded to 14.6 mtpa,

which allows headroom for adding further emitters.

iii) Transport: The CO

is transported over a 242 km

pipeline (12 km having 12” dia and 220 km having

16” dia). The pipeline stretches from the Edmonton

industrial area to the Clive oil field, south of the

city. A spare 12” line will be constructed where the

12” portion crosses the Saskatchewan river. The

line has a maximum allowable working pressure

(MAWP) of 179 bar and is sunk to a minimum depth

of 1.2m. The CO

is delivered at a pressure of 137

bar. There is no intermediate pumping in the initial

phase; pumping stations would be required when

the pipeline reaches the maximum capacity of 14.6

mtpa. The main line will be made of 14.3mm thick

welded carbon steel, and does not require crack

arrestors due to its thickness.

iv) Storage: The Clive oil field will be the first

storage site, with CO

injected into the Nisku and

Leduc horizons for improved oil recovery. Based

on re-pressurizing to the initial discovery

pressure of 165 bar from the current depletion

pressure of roughly 125 bar, the estimated CO

capacity is 18.9 mt (1800psig). However, the

regional storage potential is significantly larger,

estimated at 2000 mt.

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Carbon Capture Utilization and Storage (CCUS) –

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CCUS Policy Framework for India

McElmo Dome

EOR

capture

Natural CO

source

Doe Canyon

Sheep Mtn.

Bravo Dome

TEXAS

MEXICO

Figure 5-6: ACTL Map

Figure 5-7: ACTL Timelines

Time line for Alberta CO

Trunk Line

pre1990 1990 2000 2010 2020 2030 2040 2050

Inception

Invt

Business development

First projects 1.6 mtpa (firm 2015)

Expansions to 14.6 mtpa

v) Value propositions: The major value proposition is

the delivery of CO

to CO

-EOR projects at a

reasonable cost. Another advantage is the

opportunity to minimize the “tax” on CO

emissions

imposed by the Alberta Government and access to

Government and private funding for carbon

abated projects.

vi) Revenue streams: The project is being funded

through Government support for investments and

private venture capital. The main revenue sources

are the payments received for the CO

delivered

for EOR.

5.4.4 Critical Assessment of CO

Clusters

Based on the review of global CCUS clusters, clusters

based on the utilization of CO

for EOR applications are

the most successful. For projects involving the

sequestration or the storage of CO

, the funding/cost

gap for large scale CCUS deployment (whether as hub

and spoke clusters or point-to-point projects), needs

Government support and policies to incentivize carbon

capture and sequestration. Economies of scale exist in

merging CCUS infrastructure and result in lowering

pipeline and transportation costs. However,

Government support is required for funding the capital

costs, de-risking CCUS projects and building confidence

amongst emission sources in the cluster to move

forward with their plans.

The other major benefits offered by clusters could

result from combining organizational costs, acquiring

permissions, winning public acceptability, and pooling

professional services such O&M of carbon capture

facilities, chemical supply & waste disposal, and CO

measurement & accounting services.

Because of the high mobilization and laying expenses,

cost reductions for CCUS cluster projects are greater

for offshore and distant storage locations. The

economics of such CCUS cluster projects in the initial

years are quite challenging due to lower CO

volumes

and the outsized infrastructure created. This can be

overcome if long-term and low-cost financing are

available for clusters with competitive locations, both

through Government support and access to

international clean funds.

5.4.3.4 The Alberta Carbon Dioxide

Trunk Line (ACTL)

i) Outline: The project is based on the synergy

between oil producers who can benefit from

-EOR and CO

emitters, particularly from the oil

& gas industry, who can abate their CO

emissions.

The project consists of a central CO

trunk pipeline,

similar to trunk lines in the oil & gas industry.

The first phase consists of two capture locations.

The CO

pipeline will be constructed and operated

by Enhance Energy, for transporting the CO

for

EOR. The EOR operations will also include

monitoring of the stored CO

plume, design of wells

and the injection programme and reservoir

management.

ii) Capture: The project started with two CO

sources:

an Agrium fertilizer facility and the Sturgeon heavy

oil upgrading refinery. The capture costs are CAD

21/tonne at Agrium (for 1.2 mtpa of CO

) and CAD

12/tonne at Sturgeon (for 0.4 mtpa). The trunk line

capacity is expected to be expanded to 14.6 mtpa,

which allows headroom for adding further emitters.

iii) Transport: The CO

is transported over a 242 km

pipeline (12 km having 12” dia and 220 km having

16” dia). The pipeline stretches from the Edmonton

industrial area to the Clive oil field, south of the

city. A spare 12” line will be constructed where the

12” portion crosses the Saskatchewan river. The

line has a maximum allowable working pressure

(MAWP) of 179 bar and is sunk to a minimum depth

of 1.2m. The CO

is delivered at a pressure of 137

bar. There is no intermediate pumping in the initial

phase; pumping stations would be required when

the pipeline reaches the maximum capacity of 14.6

mtpa. The main line will be made of 14.3mm thick

welded carbon steel, and does not require crack

arrestors due to its thickness.

iv) Storage: The Clive oil field will be the first

storage site, with CO

injected into the Nisku and

Leduc horizons for improved oil recovery. Based

on re-pressurizing to the initial discovery

pressure of 165 bar from the current depletion

pressure of roughly 125 bar, the estimated CO

capacity is 18.9 mt (1800psig). However, the

regional storage potential is significantly larger,

estimated at 2000 mt.

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

EOR projects

Clive

Camrose

Tofield

Alberta Industrial Heartland

Leduc

ACTL

First capture locations

North

First injection site

Edmonton

5.5 Hub and Cluster

Framework for India

The merits of a hub and cluster framework make it the

best suited for implementing CCUS in India. The first

step is to map identified industry-wise clusters and

suitable storage clusters in India. A cluster framework

is both advantageous and necessary for incentivizing

capture from both large and small emitters. The

underlying principles for a potential CCUS cluster

framework in India are provided below:

5.5.1 Principles of Proposed Framework

5.5.1.1 Evolutionary and Phase Cluster Model

An evolutionary and phased cluster model would be

appropriate for India, as there no commercial-scale

CCUS projects in operation. CCUS can be deployed in

a phased manner, prioritizing regions and industrial

clusters based on their total CO

emissions. The

cluster framework should also be adaptable and

accommodate new local networks as and when they

develop. This type of approach to CCUS deployment

will enable India to build a scalable network, whereas a

single point-to-point approach may not be scalable in

the future and face issues of alternative storage

spaces or lack of buyers for CO

in the future. A

cluster model will ensure a robust market for the

captured CO

by efficiently integrating the supply and

demand sides.

5.5.1.2 Hub Based Cluster Clearing Model

The cluster networks that will obtain CO

from emitters

will supply CO

to the parties responsible for its

utilization or sequestration. In case there is excess

(greater than the demand for utilization or

storage) present with the cluster network, the excess

can be transferred to other networks that may

have higher CO

demand. This transfer can be

executed by centralized bodies or hubs. Hubs need to

be created for the smooth operation of the CO

transfer process between the existing and upcoming

cluster networks. These hubs will act as an exchange

point for the cluster networks and enable the physical

switching of CO

. Hubs will also ensure the de-risking

of CO

transport network assets, thereby making the

entry to hub and cluster systems more profitable.

5.5.1.3 Hub Investment as a Signal of Cluster

Growth and Evolution.

Each hub can be the representative of certain clusters

associated with it. Investment in the hub

infrastructure will lead to the growth of various

cluster networks connecting to it. This will lead to the

evolution of cluster networks to cater to the CO

demand of multiple parties, who may be involved in

either utilization, EOR or sequestration of CO

. Each

cluster network will be a profit-maximizing cluster

network. The profitability of these cluster networks

will ensure the inflow of investment into the hubs &

clusters, which would help them grow their operations.

These clusters may be operated by a Government

appointed body as a regulated monopoly and the

pricing of CO

can be regulated throughout the

value chain.

5.5.1.4 Accounting for Innovation on the Supply

and Demand Side

The possibilities of innovation on both the supply side

(capture and transportation) and demand side (new

pathways for CO

utilization) will be embedded in the

design of the cluster framework. The innovations in the

supply side can reduce the social cost of carbon capture.

Innovations on the demand side will have a more

prominent effect as it may generate new CO

based

products. These additional competing uses of CO

with

efficient pricing will result in resources being directed to

the highest social value uses at any given time.

5.5.2 Architecture of Evolutionary Cluster Model

The grid design for the hub and cluster model is

illustrated in Figure 5-8. This includes the various

participants in an evolutionary cluster framework,

such as emitters, local network (cluster),

sequestration party, utilization party (EOR, conversion

to chemicals, etc.).

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

Aggregator

Disposer

EOR Cluster

EOR

HUB

Conversion

Cluster

MeOH

EOR

Regulated Monopoly

Demand-Supply

Time Contracts

Regulated Monopoly

Mineral

Figure 5-8: Mega Scale CO

Cluster Model

The emitters (E

, E

) form the CO

emission

cluster, with similar types of industries placed in an

emission cluster and being connected to their local

cluster network, which is operated by a CO

aggregator as a regulated monopoly. The storage

operators (S

, S

) represent the storage cluster, where

will be sequestered without recovering any

economically beneficial product. Similarly, there are

clusters for EOR and CO

utilization.

The emitters have CO

capture technology suited to

their quality of gas streams. The cluster will be

initiated by an emitter with very large CO

emissions.

This emitter is termed an anchor project. High purity

captured from emitters is transported to the local

cluster network. These emitters will have to pay a

fixed cost for using the local network’s infrastructure.

The transport infrastructure for the cluster is

maintained by the local network bodies, thereby

reducing the risk for individual industries. This

increases the incentive for industries to join this kind

of cluster network.

The captured CO

is then sent to the hub and from the

hub to either sequestration sites S

or S

, to be stored

in geological formations of deep saline aquifers or

mineralized in the basalt formations. In return, the hub

pays S

a regulated charge based on the CO

volumes being stored. A similar process is followed for

disposition of the CO

either through EOR or for

utilization of the CO

for producing methanol, mineral

aggregates or other value-added products. The

emitters are agnostic to the final CO

disposition; the

disposition pathway is dynamically determined by the

hub operator based on the demand-supply scenario.

In the future, a new cluster with a local network may

want to join this hub, which would be possible due to

the evolutionary model of hub and cluster systems.

This will also bring in additional investments into the

hub, leading to its growth. This new cluster may or

may not have an emission source. In case it does not

have an emission source, it will procure CO

from the

hub. A new emission source may also come up in the

future, which can be integrated with the new

cluster network.

5.5.3 Region-wise Cluster Potential for India

The cluster potential has been analyzed for the five

regions of India: North, South, East, West, and

North-East. By identifying the nearest state/UT to the

storage locations mentioned, the storage sites can be

classified and mapped to the various regions. A similar

practice has been carried out with the emission

sources. The estimation of region-wise emission for

the year 2030 is considered for analyzing the CO

volume emitted for the duration 2030 - 2050. Figure

5-9 illustrates the region-wise cluster potential data

for India.

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

Emitters

Sequestration

Conv

Conversion

EOR

Enhanced Oil

Recovery

Figure 5-9: Region-wise Storage Clusters in India

Total Theoretical Storage Capacity of India = 395 - 614 Gt CO

7.21 GT

16.58 GT

10.13 GT

0.22 GT

9.01 GT

Northem Region: 7.65 Gt CO

Saline

aquifer

ECBMR EOR Basalt

7.34

0 0

0.31

Southern Region: 76.3 Gt CO

Saline

aquifer

ECBMR EOR Basalt

75.2

0.3 00.8

North-Eastern Region: 47.2 Gt CO

Saline

aquifer

ECBMR EOR Basalt

46.5

0 00.7

Eastern Region: 47.2 Gt CO

Saline

aquifer

ECBMR EOR Basalt

67.2

2.4 10.980

Western Region: 388.9 Gt CO

Saline

aquifer

ECBMR EOR Basalt

304.9

0.9

80.8

2.3

Region-wise estimated CO

emission volume (2030-2050)

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

Table 5-5: Sedimentary Basins Spanning Across Multiple Regions

Basin name Basin category State/UT Theoretical storage potential

(Gt of CO

)

Vindhyan Category II Madhya Pradesh/ 11.81

Uttar Pradesh/ Rajasthan

Satpura- Category III Madhya Pradesh/ 1.87

South Rewa- Damodar Chhattisgarh/Jharkhand

Bhima-Kaladagi Category III Maharashtra/ Karnataka 0.41

Total 14.09

ECBMR: The potential for ECBMR is localized in the

eastern region due to the presence of major

coalfields. These can be storage clusters for

industries that are close to the coalfields, such as

steel and power plants.

EOR: The potential for EOR will increase in the future

as more wells are maturing and newer wells may be

discovered through exploratory activities.

Storage in basalt formations: Mineralization in

basalt formations provides a large opportunity for

storage in the western region, but is currently in a

nascent stage of development.

Comparing the region-wise emission volumes during

the time horizon of 2030 – 2050 and the theoretical

storage capacity, sufficient storage capacity is

available for cluster formation in each region. The

formation of hubs will result in a smooth transfer of

between clusters of different regions. Apart from

the four CO

disposition options discussed above,

several other CO

utilization clusters (CO

chemicals, new utilization techniques, etc.) can evolve

and become more viable over time, thus increasing

the options for abatement of enhanced volumes of

from the power and industrial sector.

5.6 Key Risks Associated

with CCUS

The CCUS policy framework for India should also

address the key risks associated with the CCUS value

chain. CCUS projects integrate various sub-systems

such as carbon capture, transportation, and

sequestration. The interfaces between the

sub-systems projects involve complex interfaces and

lead to risks associated with CCUS projects. Some of

the key risks and their mitigation measures are

described below:

5.6.1 Technical Risks

5.6.1.1 Reservoir Suitability for CO

Flooding

for EOR

The extent of CO

abatement possible through EOR

depends on the comparative performance and

cost-effectiveness of CO

EOR vis-à-vis other methods

of tertiary recovery like nitrogen injection, polymer

injection, steam injection, natural gas injection, and

the use of foaming agents. Some of the current

developments, such as the use of foams or other

chemicals to improve sweep efficiency may reduce the

attractiveness of CO

EOR, while on the other hand,

The region-wise storage cluster formation shows that

sequestration in deep saline aquifers has the best

potential in all the regions. Due to the lack of data on

the northern sedimentary basins, the theoretical

storage capacity for saline aquifers is low. But as more

exploratory activities are carried focused on CO

storage, the storage potential in the northern region is

likely to increase. Few sedimentary basins span across

multiple states and they have been mentioned in

Table 5-5.

exploration and production from more complex

hydrocarbon resources may increase the role of CO

Hence it is necessary to monitor the developments of

other tertiary recovery systems, as well as use

improved reservoir simulation tools to understand

flooding and EOR performance. It is also

important to calibrate financial commitments to

capacity expansions based on assured future offtakes

for CO

to mitigate this risk.

5.6.1.2 Change in Processes Emitting Industries:

This risk emanates from the possibility of using

electricity or new clean energy carriers to replace the

use of fossil fuels in industrial processes like iron &

steel or cement, thereby substantially impacting the

emissions available for capture. Even the power

sector is not immune to such changes: for example,

base-load plants may transition to only peaking

operations, limiting the quantity of CO

emissions.

Therefore it is important to develop a understanding

of the industrial processes and the likely trajectory of

technological innovation in the industry, as well as the

risk of the end-products of the industry getting

replaced by alternate products.

5.6.1.3 Offshore Unloading & Condition of

Shipped CO

shipping is considered a future alternative to CO

piping and would involve vessels similar to

semi-refrigerated LNG/LPG carriers that use

pressurized tanks. Compared to a fixed pipeline based

distribution network, CO

shipping provides flexibility

to adjust to demand-supply dynamics and deploy

ships/barges to different consumption points and

allows for more gradual expansion of the CCUS

system. One key issue is converting liquid CO

from

temperatures as low as -50°C to a temperature

suitable for injection. Significant heat energy would be

required, involving cost and emissions, if done with

fossil fuels. The logistics of ship unloading also need

to be addressed, including issues related to ship

loading & unloading rates to limit demurrage as well

as using floating barges for offshore offloading.

5.6.1.4 CO

Specification Challenges

Most carbon capture solutions try to address and

meet the required CO

specifications. The key

requirement is adequate dehydration, along with

other impurity tolerances depending on the CO

source and capture process. However, problems may

arise when integrating multiple CO

sources and

capture processes, and additional treatment of the

captured raw CO

may be required, depending on the

disposition pathway for the CO

. These requirements

would depend on the diversity of CO

sources in a

particular cluster, which increases the likelihood of

mixing issues. The other issues to be handled are

the concentration of non-condensable and inert

impurities such as nitrogen and argon, that have an

effect on pipeline and reservoir capacity.

5.6.2 Financial Risks

5.6.2.1 Cost of Capture

The main cost driver in the CCUS value chain is the

capture cost. In industrial processes such as natural

gas processing and gasification, carbon capture is part

of the process itself and hence there is no additional

cost of carbon capture. However, in the case of thermal

power plants and other industrial processes, there are

significant capital and cash costs, leading to financial

risks for the entire CCUS value chain, which need to be

mitigated through suitable commercial arrangements.

Significant resources have been invested in developing

more efficient and cost-effective carbon capture

technologies, and the cost range for most

commercial-scale carbon capture technologies is well

established. It may be worthwhile to focus further R&D

efforts on finding creative ways to sell or consume the

product in new ways or optimize opex through

low-cost sources of low-grade heat/steam for solvent

regeneration and meet the electricity duty

requirements of other carbon capture technologies.

5.6.2.2 Financing Risks

The CCUS value chain consists of several connected

sub-systems and functions that must act in

coordination for the overall success of the project.

Multiple sources or sinks in a cluster mitigate the risk

and may require more elaborate transport and storage

infrastructure, leading to higher capital costs and

financing requirements, particularly in the early

“anchor” stages of the project. The risk of financing

delays or inadequacy leads to cost escalation and

hence needs to be mitigated through measures such as

meticulous planning, access to bridge financing during

the early stage of the project and making realistic

provisions for additional funding to cover the

contingency of delays.

5.6.2.3 Loss of Storage Site

Complications during CO

injection may lead to the

stoppage of operations at CO

storage sites. Although

reservoir management should provide adequate warning

of such occurrences, there are technical risks in

estimating/predicting the final capacity of a new storage

site with certainty. Relying on a single site or a single

well is a key technical risk. Hence there is a need to

prove new storage sites to ensure continued operations.

Careful long-term planning and contracting of multiple

sites can mitigate this risk. Drilling additional wells or

temporarily increasing the injectivity of existing wells

can boost the short-term capacity of alternate sites.

Hence, it is recommended that contingency plans be

developed for additional storage capacity via additional

wells or reservoirs. If rigs and requisite well supplies

are available, new wells can be drilled and completed

fast. It is therefore prudent to ensure rapid access to

drilling rather than storing spare wells, as well as

developing and assessing multiple storage locations.

5.6.2.4 Price of Green Products

The issue of “inadequate prices” for low carbon or

green products is a major risk factor. To address this

risk, renewable energy has widely used feed-in tariffs,

but only until it became cost-competitive. The tariff is

paid centrally and passed on to consumers via taxation

or a general price increase. However, the system is

inflexible as the pre-determined feed-in tariff rates may

become inappropriate and may need to be lowered.

Ultimately the higher costs for the commitment for

green products has to be passed on to customers and

businesses, since the Government’s revenues comes

from citizens and businesses.

5.6.2.5 Lack of Tradeable Long Term CO

Emission

Reduction

CCUS ensures long-term emission reductions and

requires long term investments and financing having

time horizons of up to 40 years. There is a need to

design financial instruments where the payoffs/rewards

are directly related to CO

abatement levels. The

probable investors/buyers would be organizations that

need to achieve future carbon reductions. The potential

to invest directly in the best CCUS locations/projects

should be less expensive than purchasing abatement

certificates. There is thus a need to structure financial

products directly linked to specific CO

abatement,

transportation, and storage quantities, which can be

marketed to different types of investors (viz.

individuals, institutions and industrial enterprises), and

preferably in a globally tradable manner.

5.6.2.6 Withdrawal of Key Partners & Delay

The CCUS value chain requires the interplay and

association of multiple partners and the

withdrawal/loss of a partner in the value chain can

compromise the entire system. Contracts need to be

designed to prevent the same, as well as protect the

project from changes in ownership or divestments.

However, there is the residual risk of a business

partner’s insolvency or business failure. One model

could be to centralize the core activities related to the

CCUS value chain within one dedicated well-funded

organization (with a lower probability of failure or

disruption) rather than having multiple partner

organizations and procuring the balance support

services from the market.

5.6.3 Safety Risks

5.6.3.1 Pipeline Incidents

Pipeline related accidents and incidents are significant

safety risks and need to be mitigated through adequate

insurance to cover the costs of paying compensation to

affected parties and the cost of repairing the pipeline.

Permanent disruption or permanent stoppage of CO

transportation may occur if the entire CCUS

facility/infrastructure has been destroyed.

The effect of one pipeline incident may spill over to the

development of the CCUS industry and operations of

already commissioned CCUS facilities, who would need

to upgrade their operations and safety protocols.

Fortunately, there have been no major failures or

disasters to date in the CCUS industry. At the same

time, it is necessary for strict international safety

standards to be adopted to preemptively avoid any

incident. The safety standards followed in the

international seaborne movement of LNG provides an

excellent example worth emulating.

5.6.3.2 Large Dia Pipeline in Populated Areas

Historical pipeline incident records reveal that larger

diameter lines generally have a lower frequency of

incidents. In order to avoid any incidents, automatic

isolation valves at short intervals and leak monitoring

systems are two solutions adopted by some projects.

is not dangerous in moderate quantities and

becomes life-threatening only above certain

threshold levels. However, adequate safety and

failsafe precautions need to be adopted for dense

phase or supercritical CO

pipeline transport in

populated areas, as may be required for developing

large scale CCUS projects in densely populated

countries like India, along with clearly defined and

established emergency response and communication

protocols.

132

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

CCUS Policy Framework for India

exploration and production from more complex

hydrocarbon resources may increase the role of CO

Hence it is necessary to monitor the developments of

other tertiary recovery systems, as well as use

improved reservoir simulation tools to understand

flooding and EOR performance. It is also

important to calibrate financial commitments to

capacity expansions based on assured future offtakes

for CO

to mitigate this risk.

5.6.1.2 Change in Processes Emitting Industries:

This risk emanates from the possibility of using

electricity or new clean energy carriers to replace the

use of fossil fuels in industrial processes like iron &

steel or cement, thereby substantially impacting the

emissions available for capture. Even the power

sector is not immune to such changes: for example,

base-load plants may transition to only peaking

operations, limiting the quantity of CO

emissions.

Therefore it is important to develop a understanding

of the industrial processes and the likely trajectory of

technological innovation in the industry, as well as the

risk of the end-products of the industry getting

replaced by alternate products.

5.6.1.3 Offshore Unloading & Condition of

Shipped CO

shipping is considered a future alternative to CO

piping and would involve vessels similar to

semi-refrigerated LNG/LPG carriers that use

pressurized tanks. Compared to a fixed pipeline based

distribution network, CO

shipping provides flexibility

to adjust to demand-supply dynamics and deploy

ships/barges to different consumption points and

allows for more gradual expansion of the CCUS

system. One key issue is converting liquid CO

from

temperatures as low as -50°C to a temperature

suitable for injection. Significant heat energy would be

required, involving cost and emissions, if done with

fossil fuels. The logistics of ship unloading also need

to be addressed, including issues related to ship

loading & unloading rates to limit demurrage as well

as using floating barges for offshore offloading.

5.6.1.4 CO

Specification Challenges

Most carbon capture solutions try to address and

meet the required CO

specifications. The key

requirement is adequate dehydration, along with

other impurity tolerances depending on the CO

source and capture process. However, problems may

arise when integrating multiple CO

sources and

capture processes, and additional treatment of the

captured raw CO

may be required, depending on the

disposition pathway for the CO

. These requirements

would depend on the diversity of CO

sources in a

particular cluster, which increases the likelihood of

mixing issues. The other issues to be handled are

the concentration of non-condensable and inert

impurities such as nitrogen and argon, that have an

effect on pipeline and reservoir capacity.

5.6.2 Financial Risks

5.6.2.1 Cost of Capture

The main cost driver in the CCUS value chain is the

capture cost. In industrial processes such as natural

gas processing and gasification, carbon capture is part

of the process itself and hence there is no additional

cost of carbon capture. However, in the case of thermal

power plants and other industrial processes, there are

significant capital and cash costs, leading to financial

risks for the entire CCUS value chain, which need to be

mitigated through suitable commercial arrangements.

Significant resources have been invested in developing

more efficient and cost-effective carbon capture

technologies, and the cost range for most

commercial-scale carbon capture technologies is well

established. It may be worthwhile to focus further R&D

efforts on finding creative ways to sell or consume the

product in new ways or optimize opex through

low-cost sources of low-grade heat/steam for solvent

regeneration and meet the electricity duty

requirements of other carbon capture technologies.

5.6.2.2 Financing Risks

The CCUS value chain consists of several connected

sub-systems and functions that must act in

coordination for the overall success of the project.

Multiple sources or sinks in a cluster mitigate the risk

and may require more elaborate transport and storage

infrastructure, leading to higher capital costs and

financing requirements, particularly in the early

“anchor” stages of the project. The risk of financing

delays or inadequacy leads to cost escalation and

hence needs to be mitigated through measures such as

meticulous planning, access to bridge financing during

the early stage of the project and making realistic

provisions for additional funding to cover the

contingency of delays.

5.6.2.3 Loss of Storage Site

Complications during CO

injection may lead to the

stoppage of operations at CO

storage sites. Although

reservoir management should provide adequate warning

of such occurrences, there are technical risks in

estimating/predicting the final capacity of a new storage

site with certainty. Relying on a single site or a single

well is a key technical risk. Hence there is a need to

prove new storage sites to ensure continued operations.

Careful long-term planning and contracting of multiple

sites can mitigate this risk. Drilling additional wells or

temporarily increasing the injectivity of existing wells

can boost the short-term capacity of alternate sites.

Hence, it is recommended that contingency plans be

developed for additional storage capacity via additional

wells or reservoirs. If rigs and requisite well supplies

are available, new wells can be drilled and completed

fast. It is therefore prudent to ensure rapid access to

drilling rather than storing spare wells, as well as

developing and assessing multiple storage locations.

5.6.2.4 Price of Green Products

The issue of “inadequate prices” for low carbon or

green products is a major risk factor. To address this

risk, renewable energy has widely used feed-in tariffs,

but only until it became cost-competitive. The tariff is

paid centrally and passed on to consumers via taxation

or a general price increase. However, the system is

inflexible as the pre-determined feed-in tariff rates may

become inappropriate and may need to be lowered.

Ultimately the higher costs for the commitment for

green products has to be passed on to customers and

businesses, since the Government’s revenues comes

from citizens and businesses.

5.6.2.5 Lack of Tradeable Long Term CO

Emission

Reduction

CCUS ensures long-term emission reductions and

requires long term investments and financing having

time horizons of up to 40 years. There is a need to

design financial instruments where the payoffs/rewards

are directly related to CO

abatement levels. The

probable investors/buyers would be organizations that

need to achieve future carbon reductions. The potential

to invest directly in the best CCUS locations/projects

should be less expensive than purchasing abatement

certificates. There is thus a need to structure financial

products directly linked to specific CO

abatement,

transportation, and storage quantities, which can be

marketed to different types of investors (viz.

individuals, institutions and industrial enterprises), and

preferably in a globally tradable manner.

5.6.2.6 Withdrawal of Key Partners & Delay

The CCUS value chain requires the interplay and

association of multiple partners and the

withdrawal/loss of a partner in the value chain can

compromise the entire system. Contracts need to be

designed to prevent the same, as well as protect the

project from changes in ownership or divestments.

However, there is the residual risk of a business

partner’s insolvency or business failure. One model

could be to centralize the core activities related to the

CCUS value chain within one dedicated well-funded

organization (with a lower probability of failure or

disruption) rather than having multiple partner

organizations and procuring the balance support

services from the market.

5.6.3 Safety Risks

5.6.3.1 Pipeline Incidents

Pipeline related accidents and incidents are significant

safety risks and need to be mitigated through adequate

insurance to cover the costs of paying compensation to

affected parties and the cost of repairing the pipeline.

Permanent disruption or permanent stoppage of CO

transportation may occur if the entire CCUS

facility/infrastructure has been destroyed.

The effect of one pipeline incident may spill over to the

development of the CCUS industry and operations of

already commissioned CCUS facilities, who would need

to upgrade their operations and safety protocols.

Fortunately, there have been no major failures or

disasters to date in the CCUS industry. At the same

time, it is necessary for strict international safety

standards to be adopted to preemptively avoid any

incident. The safety standards followed in the

international seaborne movement of LNG provides an

excellent example worth emulating.

5.6.3.2 Large Dia Pipeline in Populated Areas

Historical pipeline incident records reveal that larger

diameter lines generally have a lower frequency of

incidents. In order to avoid any incidents, automatic

isolation valves at short intervals and leak monitoring

systems are two solutions adopted by some projects.

is not dangerous in moderate quantities and

becomes life-threatening only above certain

threshold levels. However, adequate safety and

failsafe precautions need to be adopted for dense

phase or supercritical CO

pipeline transport in

populated areas, as may be required for developing

large scale CCUS projects in densely populated

countries like India, along with clearly defined and

established emergency response and communication

protocols.

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exploration and production from more complex

hydrocarbon resources may increase the role of CO

Hence it is necessary to monitor the developments of

other tertiary recovery systems, as well as use

improved reservoir simulation tools to understand

flooding and EOR performance. It is also

important to calibrate financial commitments to

capacity expansions based on assured future offtakes

for CO

to mitigate this risk.

5.6.1.2 Change in Processes Emitting Industries:

This risk emanates from the possibility of using

electricity or new clean energy carriers to replace the

use of fossil fuels in industrial processes like iron &

steel or cement, thereby substantially impacting the

emissions available for capture. Even the power

sector is not immune to such changes: for example,

base-load plants may transition to only peaking

operations, limiting the quantity of CO

emissions.

Therefore it is important to develop a understanding

of the industrial processes and the likely trajectory of

technological innovation in the industry, as well as the

risk of the end-products of the industry getting

replaced by alternate products.

5.6.1.3 Offshore Unloading & Condition of

Shipped CO

shipping is considered a future alternative to CO

piping and would involve vessels similar to

semi-refrigerated LNG/LPG carriers that use

pressurized tanks. Compared to a fixed pipeline based

distribution network, CO

shipping provides flexibility

to adjust to demand-supply dynamics and deploy

ships/barges to different consumption points and

allows for more gradual expansion of the CCUS

system. One key issue is converting liquid CO

from

temperatures as low as -50°C to a temperature

suitable for injection. Significant heat energy would be

required, involving cost and emissions, if done with

fossil fuels. The logistics of ship unloading also need

to be addressed, including issues related to ship

loading & unloading rates to limit demurrage as well

as using floating barges for offshore offloading.

5.6.1.4 CO

Specification Challenges

Most carbon capture solutions try to address and

meet the required CO

specifications. The key

requirement is adequate dehydration, along with

other impurity tolerances depending on the CO

source and capture process. However, problems may

arise when integrating multiple CO

sources and

capture processes, and additional treatment of the

captured raw CO

may be required, depending on the

disposition pathway for the CO

. These requirements

would depend on the diversity of CO

sources in a

particular cluster, which increases the likelihood of

mixing issues. The other issues to be handled are

the concentration of non-condensable and inert

impurities such as nitrogen and argon, that have an

effect on pipeline and reservoir capacity.

5.6.2 Financial Risks

5.6.2.1 Cost of Capture

The main cost driver in the CCUS value chain is the

capture cost. In industrial processes such as natural

gas processing and gasification, carbon capture is part

of the process itself and hence there is no additional

cost of carbon capture. However, in the case of thermal

power plants and other industrial processes, there are

significant capital and cash costs, leading to financial

risks for the entire CCUS value chain, which need to be

mitigated through suitable commercial arrangements.

Significant resources have been invested in developing

more efficient and cost-effective carbon capture

technologies, and the cost range for most

commercial-scale carbon capture technologies is well

established. It may be worthwhile to focus further R&D

efforts on finding creative ways to sell or consume the

product in new ways or optimize opex through

low-cost sources of low-grade heat/steam for solvent

regeneration and meet the electricity duty

requirements of other carbon capture technologies.

5.6.2.2 Financing Risks

The CCUS value chain consists of several connected

sub-systems and functions that must act in

coordination for the overall success of the project.

Multiple sources or sinks in a cluster mitigate the risk

and may require more elaborate transport and storage

infrastructure, leading to higher capital costs and

financing requirements, particularly in the early

“anchor” stages of the project. The risk of financing

delays or inadequacy leads to cost escalation and

hence needs to be mitigated through measures such as

meticulous planning, access to bridge financing during

the early stage of the project and making realistic

provisions for additional funding to cover the

contingency of delays.

5.6.2.3 Loss of Storage Site

Complications during CO

injection may lead to the

stoppage of operations at CO

storage sites. Although

reservoir management should provide adequate warning

of such occurrences, there are technical risks in

estimating/predicting the final capacity of a new storage

site with certainty. Relying on a single site or a single

well is a key technical risk. Hence there is a need to

prove new storage sites to ensure continued operations.

Careful long-term planning and contracting of multiple

sites can mitigate this risk. Drilling additional wells or

temporarily increasing the injectivity of existing wells

can boost the short-term capacity of alternate sites.

Hence, it is recommended that contingency plans be

developed for additional storage capacity via additional

wells or reservoirs. If rigs and requisite well supplies

are available, new wells can be drilled and completed

fast. It is therefore prudent to ensure rapid access to

drilling rather than storing spare wells, as well as

developing and assessing multiple storage locations.

5.6.2.4 Price of Green Products

The issue of “inadequate prices” for low carbon or

green products is a major risk factor. To address this

risk, renewable energy has widely used feed-in tariffs,

but only until it became cost-competitive. The tariff is

paid centrally and passed on to consumers via taxation

or a general price increase. However, the system is

inflexible as the pre-determined feed-in tariff rates may

become inappropriate and may need to be lowered.

Ultimately the higher costs for the commitment for

green products has to be passed on to customers and

businesses, since the Government’s revenues comes

from citizens and businesses.

5.6.2.5 Lack of Tradeable Long Term CO

Emission

Reduction

CCUS ensures long-term emission reductions and

requires long term investments and financing having

time horizons of up to 40 years. There is a need to

design financial instruments where the payoffs/rewards

are directly related to CO

abatement levels. The

probable investors/buyers would be organizations that

need to achieve future carbon reductions. The potential

to invest directly in the best CCUS locations/projects

should be less expensive than purchasing abatement

certificates. There is thus a need to structure financial

products directly linked to specific CO

abatement,

transportation, and storage quantities, which can be

marketed to different types of investors (viz.

individuals, institutions and industrial enterprises), and

preferably in a globally tradable manner.

5.6.2.6 Withdrawal of Key Partners & Delay

The CCUS value chain requires the interplay and

association of multiple partners and the

withdrawal/loss of a partner in the value chain can

compromise the entire system. Contracts need to be

designed to prevent the same, as well as protect the

project from changes in ownership or divestments.

However, there is the residual risk of a business

partner’s insolvency or business failure. One model

could be to centralize the core activities related to the

CCUS value chain within one dedicated well-funded

organization (with a lower probability of failure or

disruption) rather than having multiple partner

organizations and procuring the balance support

services from the market.

5.6.3 Safety Risks

5.6.3.1 Pipeline Incidents

Pipeline related accidents and incidents are significant

safety risks and need to be mitigated through adequate

insurance to cover the costs of paying compensation to

affected parties and the cost of repairing the pipeline.

Permanent disruption or permanent stoppage of CO

transportation may occur if the entire CCUS

facility/infrastructure has been destroyed.

The effect of one pipeline incident may spill over to the

development of the CCUS industry and operations of

already commissioned CCUS facilities, who would need

to upgrade their operations and safety protocols.

Fortunately, there have been no major failures or

disasters to date in the CCUS industry. At the same

time, it is necessary for strict international safety

standards to be adopted to preemptively avoid any

incident. The safety standards followed in the

international seaborne movement of LNG provides an

excellent example worth emulating.

5.6.3.2 Large Dia Pipeline in Populated Areas

Historical pipeline incident records reveal that larger

diameter lines generally have a lower frequency of

incidents. In order to avoid any incidents, automatic

isolation valves at short intervals and leak monitoring

systems are two solutions adopted by some projects.

is not dangerous in moderate quantities and

becomes life-threatening only above certain

threshold levels. However, adequate safety and

failsafe precautions need to be adopted for dense

phase or supercritical CO

pipeline transport in

populated areas, as may be required for developing

large scale CCUS projects in densely populated

countries like India, along with clearly defined and

established emergency response and communication

protocols.

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Carbon Capture Utilization and Storage (CCUS) –

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CCUS Policy Framework for India

Chapter 6

Investment &

Financing

Mechanism

6.1 Introduction

6.2 Estimation of Capital Costs

and Cash Costs for Demo

Scale CCUS Projects

Financing CCUS projects can be quite challenging in a

developing country like India, even with policy support,

whether be it incentive or tax based. With an inherently

lower ability to absorb reduced tax revenues than a

developed nation like the USA, India would initially need

to look for international financial support for CCUS

projects. India should create a financial framework

around the CCUS value chain to support and expedite

carbon capture adoption across industries. This chapter

discusses different options for financing CO

capture,

utilization and storage projects in a subsidy-neutral

way for achieving decarbonization and ensuring the

sustainability of the Indian economy.

CCUS represents an unmatched opportunity for

turbocharging the growth of the Indian economy

through large-scale ‘carbon-friendly’ investments in the

industrial sector. These investments will help create a

clean-energy based industrial sector, potentially

leading to the development of new technologies, skills

and high-value employment opportunities in India. With

time, the clean-energy industrial sector will develop

expertise and value-added low-carbon products that

can be exported to other countries. CCUS also provides

an opportunity for private enterprises to invest in the

development of a new low-carbon emissions industrial

infrastructure that will provide increasing returns on

investments as the industry develops over time.

An active energy market backed up with a proper

national CCUS policy to support the entire chain of

operations can attract investments. This has to be

ensured by designing ‘Integrated Energy’ policies that

support primary manufacturing industries along with

CCUS, leading to energy and materials security for

India and attracting diverse foreign enterprises and

private equity companies to engage in sustainable

energy businesses in India.

To support CCUS in India, it is important to fund and

support demonstration scale projects. This section

estimates the capital costs and cash costs for one

demo scale CCUS project in each of the sectors under

consideration. The costs vary widely, as even with the

same CO

stream, carbon capture cash costs vary

widely depending on the unit costs of power and

steam. The basis of estimation of the capital and cash

costs is listed below:

- It is envisaged that the proposed carbon capture

projects/units will be retrofitted to existing

plants/units

- All the cost parameters are based on currently

available technologies and Indian conditions

& costs

- All auxiliary facilities like pre-treatment of gases

or compression are considered as part of the

carbon capture project

- Power required for the carbon capture project will

be sourced from existing operations

- The steam requirements of the carbon capture

project will be met from natural gas-based boilers

for refineries or petrochemical projects and from

coal-based boilers for other sectors

- For carbon capture projects for existing power

plants, the steam will be sourced from existing

power plant operations. The cost of steam will be

considered at the opportunity cost

- Costs towards manpower, solvent make up,

consumables, repair & maintenance, cooling water,

make up water etc. have been considered on a

normative basis for Indian conditions and costs

- The capital costs for the carbon capture units

include all the hard and soft costs, including

applicable taxes & duties, owner’s cost,

financing cost

- Capital recovery factor (CRF) has been estimated

on the basis of 8% financing cost and 20 years

of life

- The utility costs considered are shown in

Figure 6-1.

Figure 6-1: Utility Costs Considered

3,000

750

1,500

NG based steam, Rs./TCoal based steam, Rs./TPower, Rs./MWh

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Investment & Financing Mechanism

The key considerations for calculations of the capital and cash costs for CCUS units in each sector/application is

provided below:

Sector CO

stream sources CO

stream spec. Considerations

Table 6-1: Capex and Opex Considerations for CCUS Retrofit

Gasification based

production

Outlet of the acid

gas removal unit

- CO

removal and capture are part of the process.

- CCUS unit will undertake purication and

compression of high conc. CO

stream for further

disposition

- Accordingly, only CO

polishing and compression

facilities have been considered

- 90% CO

conc

- 1-5 bar (a) pressure

NG based SMR for

production

Tail gas from PSA

- Depending on the extent of decarbonization

targeted, the carbon capture source and

technology will change. While CO

capture from

tail gas will give the lowest capture cost for around

60% CO

reduction, capture from ue gas will

ensure 95% capture with a higher cost of capture

- Cryogenic separation has been considered for CO

capture from tail gas as it ensures high purity CO

(99.9%) with additional H

recovery

- Overall CO

reduction will be limited to 60-70%

- ~65%+ CO

conc.

- Near atm. pressure

Cement Flue gas

- A hybrid (PSA + cryo) solution has been

considered

- ~20% CO

conc.

- Near atm. pressure

Iron and steel BF gas

- An integrated steel plant has multiple CO

sources

with dierent characteristics. However,

pre-combustion capture from BF gas will ensure at

least 50% capture with minimum cost of capture.

- Water gas shift has been considered to ensure

maximum CO

capture from a single point and

potential H

recovery from the BF gas

- ~20% CO

conc.

- Near atm. pressure

Refinery and

chemical

Flue gas

- Since a renery has multiple sources of CO

aggregation is dicult due dierent stream

characteristics as well as space constraints of

existing layout of typical reneries

- CDU & FCC unit are considered for carbon capture

- Amine based carbon capture is considered to be

the most economical solution

- 7-20% CO

conc.

- Near atm. pressure

Coal-based power Flue gas

- Amine based carbon capture considered

- All retrotting required for carbon capture like

SOx, NOX removal, steam extraction, ue gas

treatment has been considered as part of the

carbon capture unit

- 8-15% CO

conc.

- Near atm. pressure

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Investment & Financing Mechanism

The typical capital costs for CCUS demo projects in each sector is tabulated below:

Note: The capital costs are on a net of GST basis and include cost towards plant & equipment, construction cost, applicable taxes & duties, licensing cost, financing

cost, owner’s cost, etc.

Table 6-2: Sector-wise Typical Carbon Capture Capital Cost

Sector Ref. Plant CCU CO

intensity CO

capture Capital Source

capacity capacity percentage Cost1

Gasification 70 ktpa H

1 mtpa 13-15 T/TH

Around 90% Rs. 80-100 - Dastur estimate for

based Crore similar projects

production - Cost of capturing CO

from industrial sources

(DOE/NETL-2013/1602)

NG based SMR 130 ktpa H

0.7 mtpa 8-9 T/TH

60-65% Rs. 700-800 Dastur project database &

for H

production Crore IEA Technical Report

Cement 2.5 mtpa 2 mtpa 0.7-0.9 T/ Around 90% Rs. 1,600 to Dastur project database &

clinker TClinker 1800 Crore IEA Technical Report

Iron and steel 2.0 mtpa BF-BOF 2 mtpa 1.8-2.2 T/TSteel Around 50% Rs. 1,600- Dastur project database &

based ISP 2,000 Crore IEA Technical Report

Refinery 5 mtpa crude 1 mtpa 0.2 T/TCrude Around 90% Rs. 1,100- - Dastur estimate for

(CDU & FCC) processing 1,300 Crore similar facilities

- IEA Technical Report

Coal-based 800 MW 5 mtpa 0.85-1.1 T/MWh Around 90% Rs. 3,500- - Integrated Environmental

power 4,000 Crore Control Model (IECM)

Version 11.5

- NETL

- IEA Technical Report

Total 11.7 mtpa - - Rs. 8,600 –

10,000 Crore

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Similarly, the typical cash costs for CCUS demo projects in each sector are tabulated below:

Note:

- Other costs include costs towards water, consumables, repair & maintenance, manpower, and other miscellaneous items

- Typical cost numbers include the cash costs for carbon capture only. The cost of transportation, sequestration, monitoring, etc. will be an additional US$ 10-15 per

tonne depending on distance, sub-surface characteristics, etc. CO

quality of 100 bar(a) pressure and 95% plus purity has been assumed for all cases.

Table 6-3: Sector-wise Typical Carbon Capture Cash Costs

Gasification 70-90 Negligible 210-270 Negligible 25-30 250-300

based

production

NG based SMR 220-250 Negligible 660-750 Negligible 450-600 1,150-1,400

for H

production

Cement 340-370 Negligible 720-1,110 Negligible 300-450 1,050-1,600

Iron and steel 170-190 1.3-1.5 510-570 975-1125 400-600 1,900-2,300

Refinery 110-130 1.2-1.5 330-390 1,800-2,250 500-700 2,700-3,100

(CDU & FCC)

Coal-based 250-300 1.3-1.55 750-900 975-1,165 800-1000 2,100-2,500

power

Sector Electricity

Consumption,

kWh/TCO

Steam

Consumption,

T/TCO

Electricity

Cost,

Rs./TCO

Steam

Cost,

Rs./TCO

Other

Costs,

Rs./TCO

Total Cash

Costs,

Rs./TCO

The sector-wise levelized cost of carbon capture per tonne of CO

, consisting of both capital charges and cash costs,

is tabulated below.

Table 6-4: Sector-wise Typical Carbon Capture Cash Costs and Capital Charges

Gasification based 70 ktpa H

1 mtpa 90-120 250-300 340-420

production

NG based SMR 130 ktpa H

0.7 mtpa 900-1,200 1,150-1,400 2,050-2,600

for H

production

Cement 2.5 mtpa 2 mtpa 800-1,000 1,050-1,600 1,800-2,600

clinker

Iron and steel 2.0 mtpa BF- 2 mtpa 1,000-1,300 1,900-2,300 2,900-3,600

BOF based ISP

Refinery 5 mtpa crude 1 mtpa 1,200-1,400 2,700-3,100 3,900-4,500

(CDU & FCC) processing

Coal-based power 800 MW 5 mtpa 700-1,000 2,100-2,500 2,800-3,500

Industry

name

Ref. Plant

capacity

CCU capacity Cash Costs (B),

Rs./TCO

Capital Charges (A),

Rs./TCO

Total Cost (A+B),

Rs./TCO

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6.3 Aggregate CCUS Investment Requirements at Country Level

emissions in India from the hard to abate sectors

like steel, cement, coal-based power, chemical, etc. is

estimated to reach around 2,300 mtpa by the year

2030. The details of the CO

emissions from each

sector are given in Figure 6-2.

In addition to the investments required for funding

demo scale projects, the aggregate CCUS investment

requirements at the country level have been

estimated for two scenarios of CO

abatement in the

year 2030: the base case and the optimistic case. The

investment numbers have been estimated based on

typical sector-wise capital costs for carbon capture,

transportation pipeline and sequestration. While

the base case represents a carbon capture volume of

20 mtpa, the optimistic case represents a target of

approximately 35 mtpa of carbon capture by 2030.

The carbon capture volumes under the two scenarios

are given in Table 6-5. The type of industry, the ease

of implementation and likely cost impact has been

considered while estimating the capital costs for

each industry.

Figure 6-2: Sector-wise CO

emission and Contribution

1,621

2,291

2020 2030

Gasifcation based productionSMR based H

productionCementIron & SteelO&G Upstream/Refinery/ChemicalsPower

53%

20%

14%

1,004

1,210

177

450

325

102

125

240

196

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Investment & Financing Mechanism

Note:

- For the gasification industry, carbon capture is part of the process. The high concentration CO

stream has to be purified and compressed for further

disposition. Hence, only the capital cost of CO

purification and compression has been considered.

- Delivery pressure of product CO

is considered as 100 bar (a) for all cases.

- The capital costs have been calculated considering the capital cost for similar projects in different parts of the world and adapting the same to Indian costs

and conditions.

Table 6-5: Carbon Capture Volume in Two Scenarios and Tentative Investment

Gasification based production 27 4 10

SMR/ATR based H

production 102 2 2.5

Cement 325 2 2

Iron and Steel 450 4 5

Refinery and Chemical 177 - 0.5

Coal-based power 1,210 8 15

Total 2,291 20 35

Investment Required BB$ 4.0 6.7

Rs. crores 30,000 50,000

Industry CO

Emissions

in 2030, mtpa

Capture in Base

Case, mtpa

Capture in

Optimistic Case, mtpa

6.4 CCUS Financing

Mechanism

In the absence of any tax incentives or supporting

market conditions for low carbon footprint products,

emerging ‘low-carbon’ technologies cannot compete

with traditional fossil fuel-based technologies. Under

such scenarios, deploying public procurement

programmes that favor low-carbon products or ensure

a guaranteed minimum price for products generated

from CCUS equipped operations, along with CO

tax

credits, can provide the foundations of a level playing

field for investors.

Incentives from the Government in the form of tax

credits, cash credits, or Product Linked Incentives

(PLI) can boost CCUS technology implementations.

Figure 6-3 shows how incentives can create a level

playing field for CCUS projects. Also, incentivizing

investments through capture credits enables

progressive reduction of capture costs and establishes

markets for low carbon-based products.

The likely required investment in carbon capture will

be 4 BB$ (Rs. 30,000 crores) to 6.7 BB$ (Rs. 50,000

crores), depending on the carbon capture volume. An

additional amount of around 1.5 BB$ (Rs. 11,000

crores) to 2.5 BB$ (Rs. 19,000 crores) will be

necessary for the transportation and storage

infrastructure.

These estimates are based on the installation and

costs of the best and commercial-scale technologies

currently available. The investment can reduce with

strategic aggregation at scale and the usage of

common CCUS infrastructure. Further, improved scale

and breakthrough novel technologies can also reduce

the costs significantly.

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Investment & Financing Mechanism

The decarbonization costs will have a varying impact

on the unit cost/price of products in different

industries, viz. power, cement, steel, etc. Hence it is

suggested to have a well-considered policy that takes

care of the CCUS cost structure in domestic and

international markets and the decarbonization cost for

each industry without compromising product

competitiveness and India’s industrial and economic

development goals. An incentive for low-C production

should be primarily guided by the following parameters:

a) Carbon capture/abatement cost;

b) CO

emission intensity of the conventional process;

c) Cost structure of alternative process/production

route (if any) for the production of green or low-C

products; and

d) India’s energy security and sustainability goals.

While the initial demo scale projects can be funded

through grants or project specific support, in the long

term it is necessary to also create an institutional

framework to finance and support CCUS projects at

scale, so that CCUS can make a meaningful

contribution to decarbonization and the clean energy

future of India. Therefore, it is proposed to develop a

“Carbon Capture Finance Corporation (CCFC)”, as a

financial institution which will participate in CCUS

projects through equity or debt participation, with the

Figure 6-3: Incentives such as the Product Linked Incentive

(PLI) scheme create a level playing field for low-carbon products

Traditional Fossil-

based products

Low-C products

+ PLI

objective of supporting and realizing the carbon

neutrality goal. The CCFC will be funded by low-cost

sovereign or International Green Funds, Carbon

Bonds or Climate Funds. By investing in CCUS

projects, along with a part of the incremental tax

revenue generated, it should be possible to fund the

carbon capture credits, eventually leading to

subsidy-neutral CCUS operations.

As a signatory of the Paris Agreement of 2015, India

has committed to reducing CO

emissions by 50% by

the year 2050 and reaching net zero by 2070. Given

the trajectory of capturable CO

emissions, this study

envisions that at least 30% of the emissions should be

captured through CCUS projects, for CCUS to make a

meaningful contribution and providing a pathway for

reaching net zero by the year 2070. Thus, a CCUS

target volume of 750 mtpa has been considered for

analyzing the institutional financial frameworks

required to support the lofty and ambitious goal of net

zero by 2070.

Two financing options have been evaluated and

analyzed for CCUS financing with the target CCUS

volume of 750 mtpa. A general schematic has been

presented in Figure 6-4.

Financing Option 1: CCUS financing through only the

‘Clean Energy Cess’

Financing Option 2: CCUS financing through bond

and gross budgetary support

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Carbon Capture Utilization and Storage (CCUS) –

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Carbon Capture Utilization and Storage (CCUS) –

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Investment & Financing Mechanism

Figure 6-4: CCUS Financing Mechanism

In both options, it is proposed to develop the CCFC

with seed funding and support from the Government

of India. The surplus funds will be re-financed to

generate earnings at an 8-10% spread. The CCFC will

subsidize the cash costs of CCUS projects through

cash credit, while the capital charges will be

subsidized as a tax credit. Since the cash credit and

tax credit required for each industry will be different

and critical for the adoption of CCUS, it is proposed to

finalize the same based on CCUS demonstration

projects based on different technologies, FEED study

for the projects and discussion with industries. The tax

credit created by the CCUS projects can be either

availed by the parent company or can be sold in the

‘carbon market’.

In financing option 1, it is assumed that the ‘Clean

Energy Cess’ on coal @ USD 5.3/tonne (Rs. 400 per

tonne) will be re-introduced from 1 April 2026, as the

GST compensation cess has been extended till 31

March 2026. India’s coal and coke consumption is

expected to increase from the current 1,050 mtpa to

around 1,200 mtpa by 2030 at a 2% CAGR.

Accordingly, the annual cess collection is estimated to

be around USD 6-7 BB$ (Rs. 48,000 – 53,000 crores).

The maximum cash credit requirement by the year

2030 is estimated to be around USD 2 BB$ (Rs. 15,000

crores) considering the optimistic case i.e 35 mtpa of

capture and disposition. So, the surplus funds in the

initial period will create an opportunity for the CCFC

to grow the corpus significantly through re-financing

through appropriate investment vehicles.

In financing option 2, the Government budget and

bonds will finance the subsidy (cash and tax credits)

required for CCUS. It is estimated that 30.50 BB$ (Rs.

2,29,000 crores) of bonds with a 9% spread in

re-investment return, along with a maximum of 0.5% of

the Government’s spending or the ‘Gross Budgetary

Support (GBS)’ can finance 750 mtpa of CCUS by 2050.

International/National

Boad market

CCFC

Clean Cess Fund/

Budgetary Support

Investment

Vehicle

Guarantees

& Equity

Coupon

Payment

Funding for CCUS

Assessment,

Credit Guarantee

Commercial Banks/

Bonds/ NBFCs/ Private Equity

Promoters/Institutions

Equity

Debt

Assured return @ X%

Information

Carbon Capture

Utilization & Storage

(CCUS) Projects

Cash

Credit

Tax/

Cess

Carbon

Credit

CCMB

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Table 6-6: Assumptions/Considerations for CCUS Financing Analysis

Current CO

emissions from 1600 mtpa

industries & power sector

CAGR of CO

emissions 4% till 2030

2% from 2031-40

1% from 2041-50

Capturable CO

85% of emissions

Current coal consumption 1050 mtpa

CAGR of coal consumption 2% till 2035, no increase after that

Clean energy cess 400 Rs./tonne Existing rate of Rs. 400/tonne, to be

effective from 1 April 2026

Subsidy for storage 4.1k Rs./tonne till 2040 Based on the average CCUS cost for

3.0k Rs./tonne till 2050 industries and power

Subsidy for EOR usage 3.0k Rs./tonne till 2040 Based on the average CCUS cost for industries

2.4k Rs./tonne till 2050 and power, adjusted for benefits from EOR

Subsidy for utilization for 2.3k Rs./tonne Based on average CCUS cost for industries and

value-added products power, adjusted for benefits from value-added

product

Return on corpus/bond 9%

re-investment

GDP growth rate 8% till 2030

5% for 2031-2050

Govt. expenditure as a 18% Based on the FY 2022-23 budget allocation

percenatge of GDP

Parameters Remarks

It is proposed that the bonds will be raised from the

low-cost national/international bond market and

invested in green projects in India with an assured

return of 9% spread. While the bonds will be raised

and re-invested in the initial years, the projected

utilization has been estimated to limit the government

spending on CCUS to be less than 0.5% of the “Gross

Budgetary Support”.

The assumptions/considerations and the results of the

analysis are presented below.

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Investment & Financing Mechanism

capture progression, in mtpa

Annual cess, Thou. Crore

Coal cons. , mtpa

Figure 6-5: Results of CCUS Financing Analysis –

Financing Option 1 (Clean Energy Cess)

Capture CO

Capture

Earning from InvestmentTotal Cess Collection

1,360

2023 2030 2040 2050

1,790

2,182

218

747

2,410

31%

10%

Coal consumption & ‘Clean Energy

Cess’ Collection

Clean energy cess fund with

re-investment @9%, Thou. crore

1,050

2023 2030 2040 2050

1,206

53 53

1,332 1,332

2023 2030

190

2040 2050

162

679

345

1,024

1212

735

1,947

2023 - 23 23

2030 15 169 154

2040 89 603 514

2050 210 225 15

Year Fund. Req.,

Thou.creore

Bond With Return,

Thou. crore

Gross Budgetary Support

(GBS), Thou. crore

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Carbon Capture Utilization and Storage (CCUS) –

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Investment & Financing Mechanism

Figure 6-5: Results of CCUS Financing Analysis –

Financing Option 2 (Bonds and Govt. Budget Support)

capture progression, in mtpa

Capture

Capturable CO

1,360

1,790

2,182

2,410

2023 2030

218

747

2040 2050

10%

31%

7,823

20,758

1,12,208

2,743

68,880

42,285

4,465

24,675

2023 2030 2040 2050

Bond

Earnings from Investment

Govt. expenditure

GDP

Govt. bonds & budget support with

re-investment @ 9% Thou. crore

Progression of GDP & Govt.

expenditure @18.5%, Thou. crore

221

664

1,076

2023 2030 2040 2050

154

229

436

229

847

2023 - - -

2030 15 - 15 (0.2% of GBS)

2040 89 36 53 (0.4% of GBS)

2050 210 107 103 (0.5% of GBS)

Year Fund. Req.,

Thou.creore

Bond With Return,

Thou. crore

Gross Budgetary Support

(GBS), Thou. crore

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6.5 Carbon Capture Finance Corporation (CCFC)

It is proposed that the Government of India set-up a

financial institution for the promotion and

development of CCUS projects in India. The financial

institution, which can be called the “Carbon Capture

Finance Corporation (CCFC)” shall provide tax and

cash credits for carbon capture projects in India. The

CCFC may also participate in certain carbon capture

projects through equity and debt funding & financing.

Whilst the detailing the implementation framework for

the CCFC is a separate exercise, the salient features of

the envisaged framework are enumerated below:

i) Timelines: It is envisaged that the CCFC should be

set up by the year 2023 or 2024 to kick start CCUS

projects in India and continue to support carbon

capture projects till the year 2050, i.e. the target

year for CCUS volumes to reach 750 mtpa or about

30% of the capturable emissions in 2050. In this

context, it may be noted that the 45Q carbon tax

credits prevailing in the US originally came into

vogue in 2008 and their validity was extended from

1 January 2026 to 1 January 2033 by the recent

Inflation Reduction Act of 2022. The total timeframe

for the 45Q credits is hence about 25 years, which is

a reasonable timeframe to consider for CCUS to

reach scale and make a meaningful contribution to

India’s energy transition & decarbonization journey

and also cover the depreciable project life of an

infrastructure/CCUS project for recovering the

capital costs. A similar timeframe from 2023 or

2024 to 2050 is also proposed for the CCFC in India,

so that investors in CCUS projects have a long

enough cash flow visibility over the depreciable life

of the assets. Projects need to begin construction

before a specified cut-off date to be eligible for the

credits.

ii) Types of credits: It is proposed that the CCFC

shall extend both tax credits and cash credits to

eligible CCUS projects; the tax credits shall be for

the recovery of the capital costs and the cash

credits shall be for the recovery of the operating

costs of CCUS projects. In this context, it may be

noted that similar incentives are already available

in India for wind power projects. Wind power

projects enjoy the benefit of Accelerated

Depreciation (AD), which was first introduced as

early as 1994, with a depreciation rate of 100%.

The depreciation rate was reduced to 80% in 2002

and the AD scheme was subsequently withdrawn in

2012. There was a steep reduction in wind sector

capacity additions post 2012, and the scheme was

re-introduced in 2014 (with an 80% depreciation

benefit) and made applicable for plants installed on

or after 1 April 2014. Additionally, Generation

Based Incentives (GBI) has also been available for

wind power to the extent of INR 0.50 per kWh for

the period of up to 31 March 2022. A similar

combination is also envisioned for CCUS projects,

with the following features to maximize the

envisaged CCUS outcomes:

a. Combination of Accelerated Depreciation

(AD) and GBI: A combination of AD and GBI

may be provided, with the caveat the CCUS

projects should operate at a certain minimum

level of utilization to be eligible for the AD; else

the AD shall be recovered along with interest.

b. Capital cost recovery: Tax credits such as AD

for the recovery of capital costs & charges

should reward actual performance and CO

tonnage abated, rather than just capacity

addition, regardless of actual operating

performance. This will also incentivize project

proponents and by extension, technology

providers to invest time and effort in reducing

capital costs over time.

c. Adequate monitoring/auditing mechanisms:

There should be mechanisms for monitoring

and auditing the reported performance of CCUS

projects through independent organizations,

since both tax credits and cash credits shall be

tied to actual operating performance.

d. Transferability of tax credits: The tax credit

should be tradeable or transferable to third

parties in lieu of cash. This ensures a market for

the tax credits so that even emitters which may

not have a tax liability have incentives to

participate in CCUS projects.

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Investment & Financing Mechanism

Given this backdrop, it is suggested to have

different levels of credit for each industry,

depending on the CO

concentration & pressure,

power & steam penalties, Scope 2 emissions,

technology maturity and the typical cost of

capture. Since carbon capture projects are still at

the pilot stage in India (except for fertilizer and

gasification plants), FEED studies and actual

demonstration stage projects are required to

finalize the level of credits that are provided. It

may also be worthwhile to look at providing

incentives for emerging technologies in the areas

of carbon utilization as well as direct air capture,

to promote their development and implementation

in India.

iv) Production Linked Incentive (PLI): An

alternative to tax and cash credits is offering

production linked incentives or PLI to carbon

abated products. The PLI scheme has been in

vogue in India since March 2020 and is applicable

to multiple manufacturing sectors, with benefits

applicable for a period of four to six years. The

goals of the PLI scheme are the creation of large

scale manufacturing capacity in India, import

substitution and employment generation, and

resonate well with the goals of CCUS in India.

Table 6-7: 45Q Tax Credit Amounts

2022 $37.86 $17 $85 $36 $180 $25.13 $12 $60 $26 $130

2023 $40.90 $17 $85 $36 $180 $27.59 $12 $60 $26 $130

2024 $43.94 $17 $85 $36 $180 $30.05 $12 $60 $26 $130

2025 $46.98 $17 $85 $36 $180 $32.51 $12 $60 $26 $130

2026 $50.00 $17 $85 $36 $180 $35.00 $12 $60 $26 $130

2027+ $50.00 as $17 $85 $36 $180 $35.00 as $12 $60 $26 $130

adjusted adjusted for

for inflation inflation

Carbon Captured and

Sequestered ($/metric ton)

Carbon Captured and Used

($/metric ton)

IRA for Industrial

Capture

IRA for Direct

Air Capture

IRA for Industrial

Capture

IRA for Direct

Air Capture

Prior

Law

Prior

Law

Year

Base Bonus Base Bonus Base Bonus Base Bonus

iii) Level of credits: The 45Q tax credits offered in

the USA may serve as a reference point for the

level of tax credits offered for carbon capture

utilization and sequestration projects. The recently

enacted Inflation Reduction Act of 2022 has

substantially enhanced the maximum level of

credits available from US$ 50 to US$ 85 per

tonne of CO

sequestered. However, the level of

credits are the same irrespective of the source and

concentration of the CO

captured and creates a

disparity of incentives for different types of

emitters, viz. an ethanol plant with almost 100%

pure CO

vs. a coal based power plant with 8-15%

concentration in the flue gas stream.

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Coal gasification (with CCUS) is an important and

strategic sector for ensuring the future energy and

materials security of India and reduce

import-dependence for critical chemicals and

commodities. It is recommended to set up a special

purpose organization to drive and promote coal

gasification in India, including the production of blue

hydrogen to enable the hydrogen economy. The key

areas of focus for the envisaged SPV would be to

conceptualize and strategize the implementation of

coal gasification projects in emerging areas,

identification and implementation of pilot and demo

projects, arranging financing of projects, promoting

and enabling policy research and advocacy, support

start-ups etc. The organization may be formed with

participation from the concerned PSUs from the

Ministry of Coal, Ministry of Heavy Industries,

Ministry of Steel, academic institutes and think tanks

working in these areas.

Additionally, viable financing mechanisms may be

adopted for promoting coal gasification and CCUS

projects. A suggested mechanism is described below:

It is proposed to develop an institutional financing/

SPV framework supported by the Government of

India. The illustrated SPV framework in the example

below (Figure 6-6) is based on mega-scale coal

gasification-based projects that promote and

accelerate the adoption of CCUS, thus enabling a

low-carbon economy. The SPV shall use equity and

debt raised through the international bond markets

to finance the carbon capture costs. The equity will

be funded through the participation of sovereign

funds, government bodies, and private investment

bodies.

The SPV will act as a self-financing funding vehicle

for integrated coal gasification and CCUS projects,

with a likely fund size of between 5-10 BB$ (Rs.

37,500 – 75,000 Crores). The coupon payment and

equity return would be ensured from the returns on

the SPV’s investment in the gasification and CCUS

economy.

6.6 Mechanisms for Promoting Coal Gasification

Projects with CCUS

Table 6-8: Tax Credits for Hydrogen Production in USA - Inflation Reduction Act of 2022

4 – 2.5 6% $0.60

2.5 – 1.5 7.5% $0.75

1.5 – 0.45 10% $1.00

0.45 – 0 30% $3.00

Life Cycle CO

Emissions

(kg of CO

e / kg of H

)

Investment tax credit Production tax credit

(2022 US$ / kg of H

)

It is reported that the Government of India is

contemplating extending the PLI scheme for the

production of green hydrogen in India; the same

should be considered for CCUS also. In order to

implement PLI for CCUS projects, it is important to

define the extent of PLI that will be available for

different levels of decarbonization or abatement,

and an independent organization would need to

define the baselines and certify the

extent of decarbonization/greenness of the

products for which the PLI is being claimed. An

example is again provided by the Inflation

Reduction Act of 2022, which provides hydrogen

producers different levels of investment or

production tax credits, depending on the extent

of CO

produced per tonne of hydrogen, as

tabulated below.

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The carbon credit incentives would be primarily

offset by the tax generated from the indigenous coal

gasification-based economy and generating

value-added products like methanol, power, other

chemicals, hydrogen, steel, and fertilizers. By

investing the funds in the gasification economy,

along with a part of the tax revenue generated from

gasification-based operations, it should be possible to

fund the carbon capture credits of 1-3 BB$

(Rs. 7,500 – 22,5000 Crore)/year – eventually

leading to subsidy-neutral CCUS operations. Also,

investment in gasification projects will enable the

SPV to access, monitor, and enforce CO

capture

through a Carbon Capture Monitoring Board (CCMB).

Additionally, the SPV will create revenue of ~ 0.6 BB$

(Rs. 4,500 Crore) through innovative fund design.

The key recommendations for the CCUS financing

framework are summarized below:

a) A statutory body like the ‘Bureau of Energy

Efficiency (BEE)’ needs to be created for the

assessment, baselining, and monitoring of CO

emissions for each industry. It will also identify the

best practices to reduce carbon footprint and

design the incentive mechanism for the adoption

of best practices and technologies.

b) PLI for low carbon products should be linked with

the decarbonization goal and the cost

disadvantages of renewable-based/

non-conventional greener production.

Figure 6-6: SPV Framework to Finance Gasification Projects

in a Deficit-Neutral Way

International

Sovereign Fund

66 BB$

500 MM$

Euity

Carbon Bonds

Taxv Revenue

GOI

Carbon Capture

Monitoring Board

Gasification Projects

(MeOH, Ammonia,

Steel)

Equity

Debt

4500 MM$

Bonds

4500 MM$

Assessment,

Credit Guarantee

Information

Return @

20% RoE

Commercial

Banks/Bonds

/NBFCs

/Private Equity

Promoters

/Institutions

Return @

20% RoE

Guarantees

& Equity

Equity

44 BB$

5 BB$

22 BB$

5 BB$

1 BB$

630

MM$

SPV

International

Bond Market

(1-3)

BB$

0-3

BB$

Carbon Credit

Tax

Investment

(Debt for

Equity swap)

Securitized

Carbon Bonds

(6% coupon

rate)

270

MM$

100

MMS

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Source: Dastur research

6.7.1 Green Bonds

Ever since its inception, the green bond market has

seen significant growth, especially in the last five

years. The growth has been fueled by the resolution

of various nations and companies towards a net-zero

economy. The year 2021 saw outstanding

participation of investors in the green bond market,

as a result of which the green bond market rose to

over USD 517 BB$ (from USD 350 BB$ in 2020). This

is the highest since the market’s inception (source:

climatebonds.net). With more investors joining the

bond market, many developing nations and emerging

economies like India are introducing sovereign green

6.7 Evaluation of Various

Funding Sources

c) The cost of CO

abatement will be subsidized

through cash credits and tax credits. Cash costs

will be subsidized as cash credits, while the capital

cost will be subsidized through tax credits.

d) The cash credit and tax credit levels should be

different for different industries since the cost of

capture varies widely depending on CO

concentration & pressure of sources, as well as

technology selection and synergy with existing

operations.

e) Cash credit and tax credit numbers for each

industry should be finalized based on

demonstration projects and/or FEED studies.

Demonstration projects are essential to find out

the best technologies and the possible

optimization through learning and R&D. FEED

studies as well as implementation of

demonstration plants should be supported by the

Government through loan guarantees or a

mandate for PSUs.

f) The cash credit and tax credit mechanism should

be reviewed every 3 to 5 years depending on the

progress, adoption and challenges.

g) Life cycle assessment (LCA) of CCU should be a

mandatory evaluation criterion for finding out the

best possible technologies. To implement LCA, an

India-specific life cycle inventory database and a

framework sho

uld be created on a priority basis.

bonds. Companies can also issue green bonds to

raise funds for environmentally sustainable projects.

Green bonds have attracted considerable attention in

India since it was first issued in 2015. In 2021, India

had the highest issuance of green bonds since 2015,

amounting to USD 6.11 BB$. With India’s plans to

introduce sovereign green bonds in FY 2022-23, it

could attract a significant number of investments

from foreign green bonds, hedge funds, investors,

etc. Being an emerging market, India has a

tremendous economic growth potential which is

attractive to foreign investors. A portion of the

money raised from these bonds could be utilized for

funding CCUS projects and cluster development.

6.7.2 Clean Technology Fund (CTF)

The CTF fund is a USD 5.3 BB$ fund and a part of

Climate Investment Funds. The fund is aimed at

supporting low carbon technology and upscaling to

mitigate long term GHG emissions. 85% of the funds

are approved for projects in renewable energy,

energy efficiency and clean transportation sector.

The fund has supported low carbon projects in 19

countries. In India, the CTF investment plan is worth

USD 775 MM$ and a large share of it has supported

the development of 3 GW solar power capacity and

supporting transmission infrastructure (source:

climateinvestmentfunds.org).

6.7.3 National Clean Energy and Environment

Fund (NCEEF)

The NCEEF was formulated and announced in the

Finance Bill of FY 2010-2011; it was then known as

National Clean Energy Fund (NCEF). The fund was

sourced from the coal cess collected from coal

producers and importers, and cess from other

industries like pan masala, tobacco, aerated water

etc., to finance India’s transition to a low carbon

economy. Apart from renewables and energy

efficiency-related projects, the fund has also

identified CCUS and coal gasification projects as

eligible for funding. However, these funds had been

diverted to support the Goods and Services Tax

(Compensation to States) Act 2017 to compensate

the states for five years (thereafter extended) for

potential losses on account of GST implementation.

This extended period is expected to end in 2026,

after which the funds are expected to be utilized to

support low carbon technologies and projects.

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Identification of the right financing partners is

critical to the success of CCUS projects. Based on

the financial analysis of projects, the weightage of

equity and debt financing for projects must be

decided. Sources of equity financing can be large

government/ private corporations owning the

emitter projects (steel, cement, power plants,

fertilizer & chemical plant owners), carbon capture

technology suppliers working on Build Own Operate

(BOO) model and CO

storage site owners. Debt

financing can be obtained from various financial

institutions like banks, hedge funds, financial

corporations, etc.

6.8.1 Potential Sources of Debt

6.8.1.1 Project Finance Loans

Project lenders, typically banks and insurance

corporations with both their sources of funding and

debt raised from public and institutional investors,

provide most of the capital needed for project

finance. In Indian projects, project lenders are in the

form of commercial banks, regional banks,

investment banks, and even hedge funds. Examples

include:

6.8 Private Investment

Requirements

6.7.4 Carbon Capture and Storage Fund

This fund is managed by ADB and was started as a

single partner fund with Australia as a partner in

2009; The United Kingdom subsequently joined the

fund in 2012, making this a multi-partner trust fund.

The fund was established for accelerating CCS

technology demonstration, aiding in the

identification and reduction/elimination of possible

country-specific barriers to CCS technology

demonstrations and mitigating the real or perceived

risks related to carbon capture, transport or storage

technology demonstration. The fund supports

capacity development, geological investigations, and

social awareness and support programmes. All ADB

developing member countries are eligible to receive

support through this fund, with priority given to India

and other Asian countries like the People’s Republic

of China, Indonesia, and Vietnam. (source adb.org)

a) The Life Insurance Corporation (LIC) is the doyen

of the insurance industry in India, with a total of

INR 31 Lakh cr (almost USD 410 BB$) in AUM.

They have invested in infrastructure and

industrial projects, including running several

dedicated infrastructure and industrial funds,

and could be a source of funds for CCUS projects.

b) MUFG is the largest Japanese bank and has been

operating in India since 1953. It has recently

renewed its commitment to Indian corporates

and projects with its move to its new 30,000 ft

headquarters in BKC in Mumbai. With USD 17 BB$

in sustainable investments globally and a long

record of investing in developing countries,

including India, MUFG could be a source of funds

for CCUS projects.

c) BNP Paribas has been around since the 1850s

and is a tour de force in Europe’s investing

landscape, with about EURO 470 billion under

management at the end of 2019. With a special

focus on sustainable projects, BNP was the

number 3 participant worldwide in the green

bond market at the end of 2019 and signed 3.7

billion euros of Sustainability Linked Loans at the

end of 2019, a financing instrument indexed on

environmental, social, and governance (ESG)

criteria. They were awarded World’s Best Bank

for corporate responsibility in 2019 by

Euromoney and can be a potential source for

project finance for CCUS projects and CCUS

cluster development.

6.8.1.2 Commercial Bank Long Tenor Loans

Commercial banks raise funds from customer

deposits and allocate a part of their portfolio to

long-tenured industrial loans for infrastructure and

industrial projects. This group would include:

a) Indian Nationalized Banks like State Bank of India

(SBI), Punjab National bank (PNB), and others.

b) Foreign banks such as FAB, Credit Suisse, JP

Morgan, HSBC, Lloyds banking group and

Goldman Sachs, and others.

6.8.1.3 Development Financial Loans

Development finance loans are more specialized and

typically originate from banks and corporations with

lending mandates for sustainable development and

emerging markets. Examples are:

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a) International Finance Corporation (IFC): One of

the earliest corporations to issue a green bond in

2010, through its Green Bond Programme. IFC

has issued USD 10.50 BB$ across 178 bonds in 20

currencies. Being one of the largest financiers for

climate-smart projects, IFC has supported these

initiatives and projects with more than USD 28

BB$ in long-term financing.

b) The World Bank: With USD 17 BB$ equivalent,

the World Bank is one of the largest issuing

bodies for green bonds. They have issued green

bonds through 200 bonds in 24 currencies. The

main objectives of the World Bank CCS Capacity

Building Trust Fund (WB CCS TF) is to support

capacity and knowledge building around CCS in

developing nations. It aims to help the developing

countries to explore CCS potential and to

integrate CCS options into their strategies and

policies developed for sustainable growth. Close

to USD 70 MM$ of funds have been granted in

two phases to developing countries like Mexico

and South Africa for pilot demonstration of CCS.

c) Asian Development Bank (ADB): The ADB

works closely with governments and private

bodies to support India’s inclusive

transformation. ADB has set up a Climate Change

Fund (CCF), as an enabler to address

environmental and climate challenges through

participation in low-carbon and climate-resilient

development. “From 2011 to 2020, the ADB has

approved about USD 41.6 BB$ in climate

financing. ADB’s own resources provided USD

36.2 BB$, while external resources contributed

almost USD 5.4 BB$. ADB supports green growth

in Asia and the Pacific through financing and

innovative technologies. Through mechanisms

such as the Climate Investment Funds,

multilateral development banks have mobilized

billions for climate action in

developing countries.

d) European Investment Bank (EIB): EIB has been

operating in India since 1993 and has extended

financial support towards a wide variety of

themes, including climate action and sustainable

economic development. With lifetime finance of

over USD 4.45 BB$ in India, they have made

major investments in the transport and energy

sector. EIB and SBI have jointly launched the 100

million climate action initiative to support MSMEs

working in the clean energy sector, transport

(EV), and circular economy projects.

e) US International Development Finance

Corporation (USIDFC) is America’s development

bank, partnering with private sector equipment

suppliers and service providers to finance

numerous projects in the developing world.

USIDFC invests across sectors including energy,

healthcare, critical infrastructure, and

technology and provides the developing world

with financially sound alternatives to

unsustainable and irresponsible state-directed

initiatives. In India, the USIDFC has been seeking

investment opportunities in India’s crucial

sectors, including financial services, health

infrastructure, food security, etc. A fund of

around USD 350 MM$ has been earmarked for

the same. The development bank of America has

already approved loans of around USD 142 MM$

for one of India’s leading renewable energy IPP

(Independent Power Producer), ReNew Power,

and also has loans with Sitara Solar Energy to

build solar power plants in Rajasthan.

f) Glasgow Financial Alliance for Net Zero

(GFANZ) consists of more than 450 leading

financial institutions representing over USD 130

trillion in assets across the globe in various

financial sectors such as banks, asset managers,

asset owners, insurers, and financial service

providers (stock exchange, rating agencies,

auditors and investment consultants), supporting

the UN’s Race to Zero campaign.

The GFANZ essentially provides a platform where

financial firms can team up or work in

partnership to discuss various issues and come

up with innovative solutions that would support

the decarbonization of the world economies,

companies by accelerating green financing

across the globe. They are also dedicated to

mobilizing investment of private capital into

emerging markets and developing countries.

Furthermore, GFANZ consists of sector-specific

alliances like Net Zero Banking Alliance, Net Zero

Asset Managers Alliance, Net Zero Asset Owner

Alliance, Net Zero Insurance Alliance, Net Zero

Financial Service Providers Alliance, Net Zero

Investment Consultants Initiative, and the Paris

Aligned Investment Initiative. The financial

institutions who are members of these alliances,

based on their region of operations, can be

potential sources of green funding for CCUS

projects and cluster development.

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6.9 Socio-Economic Impact

of CCUS

6.8.1.4 Export Credit Agencies

Financing CCUS projects in emerging markets can

pose risks to foreign investors. Export Credit

Agencies (ECA) can play a pivotal role in reducing

the risk of investment/ debt financing for such

projects by providing financing solutions and risk

insurance. Examples include:

a. Export Import Bank of the United States

(EXIM): EXIM provides trade financing solutions,

including export credit insurance, working capital

guarantees, and guarantees of commercial loans

to foreign buyers, to empower exporters of US

goods and services. EXIM works closely with both

US-based suppliers of equipment and services,

as well as with foreign buyers of the same. US

EXIM Bank is an independent federal agency that

fills gaps in private export finance. The US EXIM

Bank was first active in India in the 1950s and

today supports a significant volume of US

exports to India.

b. Nippon Export and Investment Insurance

(NEXI): NEXI is the official export credit agency of

Japan. In 2019, NEXI launched a “Loan insurance

for green innovation”. This insurance was made

for the financing of projects in the field of

environmental protection/ climate change

prevention. This product has been designed

specifically for Japanese companies (exporters or

equity investors) who implement projects in the

field of renewable energy, energy conservation,

and projects utilizing new technologies that

contribute to global environmental protection (like

CCUS, hydrogen-related technology, fuel-cell).

6.8.2 Potential Sources of Equity

a. Large corporations like NTPC, RIL, Adani Group,

IOCL, SAIL, Tata Steel, JSW, IFFCO, etc. can be

equity investors in carbon capture projects

constructed at their plants.

b. Technology and operational investors like Air

Liquide, Honeywell UOP, Mitsubishi Heavy

Industries Ltd., ION Clean Energy, Baker Hughes,

etc. can be equity partners in such projects.

c. Sequestration/EOR site operators like crude oil

and natural gas producers (ONGC) can be equity

investors in carbon capture and cluster

development projects, as they will be utilizing the

captured CO

for EOR.

The socio-economic impact of the CCUS project is

manifold. CCUS will help in the production of low-C

products through the decarbonization of

hard-to-abate industries and power plants. Thus, it

will create export opportunities for green products

with a significant premium and also enable new

coal-based industries such as gasification-based

production of chemicals and power. At the same

time, other manufacturing and service sectors will be

benefitted from large investments across the carbon

value chain (capture, processing, transportation,

utilization, storage, and EOR). This will have a

beneficial effect on existing as well as new industries.

With targeted capture of 750 mtpa by 2050, India

could become a global leader in CCUS technology,

thus creating significant export opportunities.

Additionally, coal-based chemical production at a

competitive cost can reduce the import of chemicals

like methanol, ammonia, MEG, etc. This will reduce

the foreign exchange outgo and also ensure energy

security in future.

The additional oil produced from CO

-EOR will

substitute crude oil imports to India and, therefore will

decrease the current account deficit of India.

Additionally, the direct and indirect tax revenues

generated from the project and the incomes from

direct and indirect employment will also generate

significant tax revenues in India. Direct, indirect, and

induced employment both during the engineering and

construction phase will have a significant social and

development multiplier. Although rigorous

Input-Output modelling is not possible at this stage, the

baseline parameters indicative of the socio-economic

impact of the project are provided below:

- Economic Activity Parameters:

• Value addition and GDP contribution

• Investment and GDP contribution

• Tax revenues

- Employment Generation Parameters:

• Direct, indirect (including induced) and total

employment during construction & operations

- Import Substitution Parameter:

• Value of import of products substituted

• Contribution to the reduction in current account

decit/surplus.

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6.9.1 Net CO

Reduction from the Industrial &

Power Sector

CCUS is the only sustainable and feasible solution to

support India’s growing demand for energy and rapid

industrialization and meet the aspiration of over 1.3

billion Indians. The Indian industrial and power sector

emits about 1.6 Gtpa of anthropogenic CO

today,

which is expected to increase to 2.3 Gtpa by 2030

and 2.8 Gtpa by 2050. With the envisaged capture of

around 0.75 Gtpa by 2050, CO

emissions will reduce

by around 30%. Out of 0.75 Gtpa, a majority will be

contributed by steel, cement and power industries in

addition to new gasification-based industries. A

probable distribution of 0.75 Gtpa across different

sectors and the corresponding low-C production is

shown in Table 6-9.

However, most of the currently available

technologies for carbon capture are

energy-intensive. Conventional technologies like

amine-based carbon capture consume large

quantities of steam for regeneration, while

non-conventional technologies like

PSA/cryo/membrane consume power. Since steam

can only be produced efficiently through the burning

of fossil fuels in boilers, there will be CO

emissions

for steam production. With proper sourcing of steam

and fuel selection, CO

emissions from boilers can be

reduced, reducing the net CO

emission by 20-40%,

depending on the industry. Waste heat recovery (if

available) is ideal for the generation of steam,

especially for cement and steel plants. On the other

hand, Scope 2 emissions for electricity-based

technologies will depend on the grid emission

intensity. With the increased share of renewables,

grid CO

intensity will reduce over time, which will

benefit electricity-based technologies.

6.9.2 GDP & GVA Impact

A total of around USD 100-150 BB$ [2022 dollars]

of investments are required over the next few

decades for 750 mtpa CO

capture, utilization, and

storage. Since the investment will be across the CO

value chain, it will help develop the market for CO

This preliminary estimation has been done based on

the envisaged improvement of technology as well

as cost reductions expected through indigenization.

During the implementation stage, the impact on

GDP has been assessed as US$ 100 to 150 BB over

the next 30 years.

Coal gasification projects will generate value-added

products like methanol, ammonia, acetic acid,

mono-ethylene glycol, etc. A significant part of these

chemicals are presently imported to India; presently,

India imports almost USD 13 BB$ per annum of

organic chemicals. Coal-based production through

gasification will help in significantly reducing imports.

Table 6-9: Probable Distribution of 750 mtpa and low-C Product Volume

Thermal power generation 530 80-100 GW

Steel 100 40-50 mtpa

Cement 50 80-100 mtpa

Refineries & chemicals 10 40-60 mtpa

Hydrogen 10 ~ 2 mtpa

Coal gasification 50 5 mtpa H

or 25 mtpa

Methanol or 16 mtpa Ammonia

Total 750

Capture volume, mtpa Equi. Low-C product

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The contribution to the GDP from gasification-based

products will be in the form of revenues from the

production of methanol, ammonia, acetic acid,

mono-ethylene glycol, etc. Revenues throughout the

operating life cycle have been considered for

estimating the GDP contribution from gasification

projects. Depending on the product-mix

(methanol/MEG/AA), coal based chemicals

production can replace 7-10 BB$ of imports by 2050.

Coal gasification projects will generate multiple tax

streams for the Government exchequer. The major

sources of tax, like the tax on the purchase of capital

goods (during the construction stage) and the

corporate tax (throughout the economic life of the

project) have been assessed. Additionally, there will

be a cascading effect due to the significant

employment generation as well as economic

development in the vicinity of the project, which is

difficult to ascertain; hence the same has not been

assessed.

Contribution to the GVA for value addition has been

estimated as the revenue generated from the low-C

products, less the cost for the intermediate inputs.

The EBITDA (Earnings Before Interest Tax

Depreciation and Amortization or the operating

profits) throughout the economic life of the project

have been used for calculating the GVA. Considering

a minimum premium of 10% over conventional

products, GVA for decarbonized products is

estimated at around 10 BB$.

6.9.3 Potential Direct & Indirect Employment

Creation

During the construction stage, the generation of

temporary employment for construction works

(skilled, semi-skilled, and unskilled) will be one of the

major impacts of CCUS projects. Additionally, high

skilled and valued resources will be required by

contractors, technology suppliers, and project

proponents for project management, administration,

and supervision. The employment of construction

workers from the nearby area will boost the regional

economic conditions. As there is a multiplier effect

on consumption, savings, taxes, etc. the projects will

help in shaping the future economic development of

the nearby areas. The indirect employment is likely

to be 3-5X of the direct employment generated.

Additionally, jobs for O&M of the entire carbon value

chain will progressively expand. These persons will

mostly be skilled personnel and SMEs in the required

fields. The total impact has been estimated based on

the annual requirement of manpower multiplied by

the economic life of the project, considered as 25

years of operations. As the indirect employment

multiplier is a function of the salary, savings, and

domestic consumption, indirect employment will be

around 5-7X of the direct employment.

Based on the above, it is estimated that India’s CCUS

ambitious target of 750 mtpa by 2050 can create

employment of over 8-10 million full time equivalent

(FTE) years in a phased manner.

6.9.4 Potential FDI

Primary industries are capital cost intensive and

CCUS will increase the cost further. CCUS

implementation for a volume of 750 mtpa will cost

more than 100 BB$ over the next two to three

decades. The Government of India should work with

international partners, technology suppliers,

policymakers, etc. to support India’s decarbonization

goal through technology transfer and financing

capital cost-intensive CCUS projects. Additionally,

decarbonization will gradually become one of the key

criteria for attracting international financing. So,

projects with CCUS may be able to secure low-cost

financing from outside India.

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Chapter 7

Conclusions

This chapter summarizes the findings and

recommendations of this study, as below:

1. Carbon Capture Utilization and Storage (CCUS)

has an important and critical role to play for India

to halve CO

emissions by 2050 and accomplish

net-zero by 2070, as envisioned by the Hon’ble

Prime Minister of India. Energy transitions take

decades and hence it is important to implement

the framework and policy instruments for CCUS to

become a reality in India and make a meaningful

contribution to decarbonization in India.

2. CCUS is required for the decarbonization of both

industrial applications and the power sector:

a. Industrial applications: Industrial applications

are hard to electrify, and industrial CO

emissions are hard to abate due to the use of

fossil fuels not only as a source of energy but

within the process itself. Thus CCUS is

imperative to decarbonize the industrial

sector, which accounts for over 30% of total

emissions in India.

b. Clean products: CCUS can enable the

production of clean products while utilizing our

rich endowments of coal, reducing imports and

thus leading to an Indian economy.

CCUS also has an important role to play in

enabling sunrise sectors such as coal

gasification and the nascent hydrogen

economy in India.

c. Power: India relies on coal for meeting over

70% of its electricity needs; even if India is

able to meet the renewables target of 500 GW

installed capacity by 2030, there would still be

a need to meet baseload power demand from

fossil fuels (most likely coal) or other

dispatchable sources, given the intermittency

and non-dispatchable nature of solar and wind

power. Thus, CCUS has a role to play in

enabling clean and green baseload power and

ensuring the sustenance and non-stranding of

our over 210 GW of coal and lignite-based

thermal power plants.

3. CCUS can contribute to decarbonization and

transition to clean energy systems in various ways:

a. Ensuring the sustenance of existing emitters

b. Decarbonizing hard to abate sectors

c. Promoting the low carbon hydrogen economy

d. Removal of the CO

stock from the atmosphere

4. Scope 1 emissions from India’s power and

industrial sectors (primarily steel, cement, H

production, oil & gas, refineries, chemicals and

coal gasification) amount to 1,600 mtpa of CO

which is around 60% of the total CO

emissions

(2,600 mtpa) in India in 2020. The remaining 40%

emissions are contributed by distributed point

emissions sources like agriculture, transport, and

buildings, which are not amenable to carbon

capture. Emissions from these sectors (power and

industries) are expected to increase to nearly

2,300 mtpa by the year 2030, fuelled by India’s

strong GDP growth outlook.

5. The key CCUS related interventions required for

the CO

intensive sectors of the Indian economy is

tabulated below:

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Conclusions

Total

6. Commercially proven carbon capture technologies:

The mature and commercially proven CO

capture

technologies may be broadly classified into the

following types:

a. Chemical solvent-based CO

capture

technologies: preferred when dealing with gas

streams that are lean in CO

and have relatively

lower pressures, such as flue gases. The cost and

availability of steam is also a key factor as

regenerating the solvent requires large

quantities of steam.

b. Physical solvent-based CO

capture

technologies: these work well on gas streams with

relatively higher CO

concentration and pressure.

Steel Future steel growth is largely based on

the BF-BOF route, where the use of fossil

fuels is hard to replace. CCUS is

necessary for sustainability and also

ensures export competitiveness

Establish CCUS for

Integrated Steel Plants,

particularly in Eastern India

240 450

Cement Another major CO

emitting sector,

where fossil fuels are difficult to replace.

Utilization of CO

in aggregates has

synergies with the cement business

Establish CCUS clusters in

key identified areas/ districts

196 325

Oil & gas upstream,

refineries &

chemicals

Hard to abate sector. CCUS essential for

the sustainability of the sector; carbon

capture inbuilt in many of the processes

Decarbonize key applications

like urea, olefins, syngas

from petcoke

125 177

Hydrogen Blue hydrogen is key to the hydrogen

economy of the future. Carbon capture is

unbuilt in the H

production process

Establish pathways for CO

utilization and storage

56 102

Coal gasification Sunrise sector - key to materials and

energy security of India, based on India’s

rich endowments

Establish pathways for CO

utilization and storage

- 27

1,621 2,291

c. Adsorption-based CO

capture: they are

suitable for pre-combustion capture, where the

gas stream has high pressure and a high CO

concentration.

d. Cryogenic CO

capture: preferred in cases

where the cost of power is low. This technology

also provides a unique advantage by

generating additional hydrogen without

increasing the amount of feedstock (natural

gas)/ producing the same quantity of hydrogen

with lower natural gas consumption

7. CO

utilization: The pathways for utilization of the

captured CO

are primarily:

Thermal power

generation

Even with RE growth, coal-based power

will continue to meet more than 50% of

electricity demand. As the largest emitter

of CO

, CCUS in the power sector is

essential for meaningful decarbonization

and ensuring energy security in India

Establish CCUS clusters in

key identified districts

1,004 1,210

Table 7-1: Sector-wise CO

Emissions and Interventions Required

Sector

2020 2030

Estimated CO

emissions (in mtpa)

Rationale for CCUS Key interventions

required

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a. Enhanced Oil Recovery (EOR): CO

for EOR

has been successfully carried out for decades

to produce low-carbon oil from maturing oil

fields in North America and other geographies.

EOR could also be feasible for maturing

Indian oil fields.

b. Green urea: Urea production from green

ammonia can utilize a significant part of

captured CO

. Renewable energy-based ammonia

(green ammonia) can replace conventional

ammonia production from LNG if green

hydrogen is available at a competitive cost.

c. F&B applications: CO

utilization in F&B

applications comprise of carbonated drinks,

dry ice, and modified atmosphere packing;

however, the scales are quite small compared

to the volume of CO

generation/emissions.

d. Additionally, there are other promising

propositions for the utilization of CO

. The

relatively matured CO

utilization pathways

are: chemicals (methanol and ethanol),

building materials (concrete and aggregates)

and polymers

8. Notwithstanding the above-mentioned

opportunities for CO

utilization, the permanent

sequestration or geological storage of CO

saline aquifers and basaltic traps, EOR and

Enhanced Coal Bed Methane Recovery (ECBMR)

are the only available pathways for CO

disposition at scale. The overall CO

storage

capacity assessment for India (based on

theoretical assessments) for the four options is

tabulated below.

9. Existing studies by the British Geological Society

and IIT Bombay indicate a large CO

storage

potential in India; however, further actions need to

be supported by the Government of India to make

geological storage of CO

a reality in India:

a. Source sink mapping to prioritize the regions

and basins most suitable for CO

storage in

terms of storage capacity and feasibility

b. Pore space mapping and characterization of

the most promising CO

storage regions and

basins – geological characterization and

exploration for CO

storage, similar to the

seven Regional Carbon Sequestration

Partnerships (RCSPs) funded by the US

Department of Energy (US DOE).

c. For the prospective regions identified in India,

developing the CO

storage infrastructure

through characterization, validation and

commercial scale development.

10. The key to a successful CCUS implementation in

India is to enact a policy framework that supports

the creation of sustainable and viable markets for

CCUS projects. The private sector is unlikely to

invest in CCUS unless there are sufficient

incentives or unless it can benefit from the sale of

or gain credits for emissions avoided under

carbon pricing regimes.

EOR Relatively more researched area; technology tested in

major carbon capture projects across the globe

3.4

ECBMR Requires more dedicated studies and pilot tests for

Indian coal beds; no commercial-scale project

3.5-3.7

Deep Saline

Aquifers

Offers great CO

storage potential; however, limited

data available on storage in deep saline aquifers

291

Basalts Studies required for understanding storage

mechanisms in basaltic traps

97-315

Total 395-614

Table 7-2: Theoretical CO

Storage Capacity in India

Storage Pathways

Theoretical Storage Capacity (Gt) Extent of Existing Research

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carbon capture costs through financial

instruments and future taxes & growth. On the

other hand, the effectiveness of a carbon tax

based policy is questionable for a developing

country like India and may lead to industrial

migration and loss of competitiveness.

12. The key elements of the proposed carbon credits

and incentives based CCUS policy framework for

India are tabulated below:

13. Financing CCUS projects can be quite challenging

in a developing country like India, even with policy

support. To support CCUS in India, it is important

to fund and support demonstration scale projects.

The typical cost structure of potential CCUS

Table 7-3: Key Elements of a CCUS Policy Framework for India

Element Details

- In the near term, CCUS policy should be carbon credits or incentives based, to seed

and promote the CCUS sector in India through tax and cash credits

- Over time (probably beyond 2050), the policy should transition to carbon taxes, to

enable reaching India’s net zero goals by 2070

- The policy should establish early stage financing and funding mechanisms for

CCUS projects

- Regional hub & cluster models need to be established to drive economies of scale

- The role of emitters, aggregators, hub operator, disposers and conversion agents

needs to be defined

- Preferential procurement in Government tenders for low carbon or carbon abated

products

- Incentives to foster innovation for low carbon products through schemes like PLI

- Distribution of benefits of economic value added created, to communities most

affected by environmental and climate change

- Protection of communities and jobs, especially in sectors affected by clean energy

regulations

- Regulated emission levels and allowances for different sectors

- Adoption of Life Cycle Analysis (LCA) framework to take into account Scope 2 and

Scope 3 emissions and drive effective carbon abatement

- Limiting the CO

liability and ownership of participants across the CCUS value

chain

- Monitoring, Verification and Accounting (MVA) framework and monitoring for risk

management

Policy path

Hub & cluster

business model

Low carbon products

Environmental and

social justice

Accounting and

regulatory framework

Risk mitigation

demonstration projects in India for different

sectors can be quite different, depending on the

source and quality of the gas stream and the

extent of CO

capture targeted; the same is

summarized below.

Based on the review of the prevailing policy

mechanisms in different parts of the world, there

are two clear policy choices/approaches for India

to adopt, i.e. either carbon credits/incentives

based policy or carbon tax based policy.

11. A comparison of the two approaches reveals that

a cash and tax credit based policy is more likely to

incentivize CCUS adoption in India, by establishing

markets for carbon-based products and offsetting

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Table 7-4: Sector-wise Typical Carbon Capture Capital Charge and Cash Cost

Gasification 70 ktpa H

1 mtpa Rs. 80-100 90-120 250-300 340-420

based Crore

production

NG based 130 ktpa H

0.7 mtpa Rs. 700-800 900-1,200 1,150-1,400 2,050-2,600

SMR for H

Crore

production

Cement 2.5 mtpa 2 mtpa Rs. 1,600 to 800-1,000 1,050-1,600 1,800-2,600

clinker 1800 Crore

Iron and 2.0 mtpa BF 2 mtpa Rs. 1,600- 1,000-1,300 1,900-2,300 2,900-3,600

Steel BOF based ISP 2,000 Crore

Refinery 5 mtpa crude 1 mtpa Rs. 1,100- 1,200-1,400 2,700-3,100 3,900-4,500

(CDU & FCC) processing 1,300 Crore

Coal-based 800 MW 5 mtpa Rs. 3,500- 700-1,000 2,100-2,500 2,800-3,500

power 4,000 Crore

Total 11.7 mtpa Rs. 8,600 –

10,000 Crore

Industry

name

Ref. Plant

capacity

CCU capacity

(mtpa)

Capital Costs,

Rs. crores

Capital

Charges (A),

Rs./TCO

Cash Cost

(B), Rs./TCO

Total Capture

Cost (A+B),

Rs./TCO

The financing of CCUS projects at scale can be

considered through options:

a. Option 1: CCUS financing through ‘Clean Energy

Cess’ only

b. Option 2: CCUS financing through bond and gross

budgetary support

In both options, it is proposed that a “Carbon Capture

Finance Corporation (CCFC)” be developed as a

financial institution to fund CCUS projects through

equity or debt participation, with the objective of

supporting and realizing the carbon neutrality goal.

The CCFC will be funded by low-cost sovereign or

International Green Funds, Carbon Bonds or Climate

Funds. By investing in CCUS projects, along with a part

of the incremental tax revenue generated, it should be

possible to fund the carbon capture credits, eventually

leading to subsidy-neutral CCUS operations.

14. The other measures required for promoting CCUS

projects are as follows:

a. A statutory body like the ‘Bureau of Energy

Efficiency (BEE)’ is required for the

assessment, baselining, and monitoring of CO

emissions for each industry.

b. PLI for low carbon products should be linked

with the decarbonization goal and the

additional cost required for producing

green/clean products.

c. The cost of CO

abatement should be

subsidized through cash credits (for cash

costs) and tax credits (for capital costs). The

levels should be commensurate to the industry

cost structure and be finalized based on

demonstration projects and/or FEED studies.

The cash and tax credit mechanism should be

reviewed every 3 to 5 years.

d. Demonstration projects are essential to find

out the best CCUS technologies for different

sectors and applications in the Indian context,

based on Life Cycle Assessment (LCA) of the

CCUS projects. FEED studies, as well as the

implementation of demonstration plants

should be supported by the Government/PSUs.

15. Promoting CCUS adoption and implementation in

India requires a multi-pronged approach to

incentivize the following:

a. Technology transfer of commercially proven

CCUS technologies

b. Promoting R&D in novel technologies,

particularly in the area of CO

utilization

c. Encouraging private sector participation in

implementing CCUS demo projects

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Conclusions

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164

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India

Carbon Capture Utilization and Storage (CCUS) –

Policy Framework and Deployment Mechanism in India