Understanding Carbon Capture

and Storage Potential In Indonesia

FINAL DRAFT 14 August 2009

Prepared by: Indonesia CCS Study Working Group

The assessment under the cooperation between Indonesia and United Kingdom:

Strategic Programme Fund-Technical Implementation On Understanding Carbon and Capture Potential in Indonesia

“LEMIGAS” British Embassy Jakarta Kementrian Lingkungan Hidup

PT PLN (PERSERO) PT Shell Indonesia Komite Nasional Indonesia

EXECUTIVE SUMMARY

The purpose of this study is to develop an understanding of the requirements

associated with deploying Carbon Capture and Geological Storage (CCS) in Indonesia

by addressing technical Commercial and Regulatory aspects of CCS deployment to

further stimulate the ongoing dialogue on potential application of such technology in

Indonesia. This assessment of carbon capture and storage feasibility in Indonesia

focuses on a number of factors. These factors include both technical aspects (e.g.

geological storage potential, CO2 capture from industrial sources) and non-technical

issues (e.g. regulatory framework on CCS implementation, business opportunity).

Carbon Capture and Storage (CCS) is typically defined as the integrated

process of gas separation at industrial plants, transportation to storage sites and

injection into subsurface formations. CCS offers great potential for reducing CO2

emissions from large point source emitters, such as coal-fired power plants and oil

and gas processing plants in Indonesia. For CO2 capture, various different

technologies can be used for separating CO2 – the principal methods are solvent

absorption, solid adsorption, semi-permeable membranes and cryogenic cooling.

Capturing of CO2 from existing gas sweetening plants provides the most cost-

effective source of CO2 for storage. The existing gas sweetening plants should be

surveyed to establish the practicability of this option. Having captured the CO2, the

next step in the CCS chain is to transport it to the storage site. Depending on the

geographical characteristics, quantities and the economics, transport can be done by

road tanker, rail tanker, pipelines or ship. The most intensive studies reveal that

available geological storages for CO2 are depleted oil and gas reservoirs, saline

aquifers, and coal seams. These geological formations have been considered as the

most economically feasible and environmentally acceptable storage option for CO2,

particularly given the experience already gained by the oil and gas industry.

Compressed CO2 can be injected into porous rock formations below the earth’s

surface using many of the same well-drilling technologies and monitoring methods

already used by the oil and gas industry.

}

There are multiple industrial sources of CO2 in Indonesia, from power plants,

oil and gas processing plants, steel and ammonia plants and cement factories.

Scouting work has revealed that most industrial sources are located in Java and

Sumatra, and to a lesser extent in Kalimantan and Sulawesi. Hence, these islands have

been the focus for further screening work.

On gas sweetening plant, Subang field located in West Jawa produces 200

MMscfd of gas with CO2 content of 23%. The cost of compressing the extracted CO2

(i.e. 22 kg/s) is $ 10.7/t CO2, which is relatively low compared with the power plant

examples.

For the next 2 decades, fossil fuels are still the main energy driver to fulfill

national energy demand growth and support economic growth, particularly in power

sector. It has been projected that the total CO2 emissions from 8 interconnected power

systems will be 1,938.5 million tonnes CO2 accumulated from 2008 – 2018. In 2008,

energy produced by coal power plant was about 46%, and will increase about 63 % in

2018. The average grid emission factor for the whole country would reduce from

0.787 kg CO2/kWh in 2008 to 0.741 kg CO2/kWh since the increased use of natural

gas, renewables energy and introduction of super-critical boilers for large steam coal

plants from year 2014 onwards.

In order to determine the amount of CO2 reduction, we need to

compare CO2 emissions per MWh (kg CO2/MWh) of the power plant with and

without capture. The net reduction in emissions as a result of capturing CO2 is the

amount of avoided emissions. This important item matches with the result of our

calculations which shows: i) for a 1000 MW supercritical power plant using sub-

bituminous coal in Indramayu, West Jawa, at the level 70% capacity factor the CO2

emissions per MWh decreases from 803 to 115 kg CO2/MWh, ii) for a 750 MW

NGCC in Bekasi, West Jawa, at the level 70% capacity factor the CO2 emissions per

MWh decreases from 340 to 40 kg CO2/MWh, iii) for a 600 MW sub-critical plant

using lignite coal, South Sumatera, at the level 65% capacity factor the CO2 emissions

per MWh decreases from 1061 to 149 kg CO2/MWh, and iv) for a 100 MW sub-

critical power plant using sub-bituminous coal in East Kalimantan, the CO2 emissions

per MWh decreases from 1037 to 145 kg CO2/MWh at the level 65% capacity factor.

CCS energy requirements increases the amount of fuel input per unit of net

power output in which capture of CO2 adds substantially to the cost of electricity

}

generation, and reduces the output of the plant to which it is fitted. This important

feature can be shown by comparing the levelized cost of electricity ($/MWh) of the

associated power plant with or without CCS. As the results of our calculation, for

large, efficient power plants the increase in cost of electricity generation varies

depending on the type of plant and the type of fuel burnt, for sub-bituminous coal the

increase is about 60%, for natural gas the increase is about 32% but for lignite the

increase is also about 60%.

Introducing CCS to power plants may influence the decision about which type

of plant to be installed and what kind of fuel to be used, then it’s important and useful

to know its avoided cost (versus a reference plant without capture). As the results of

our calculation, it shows that the cost of avoided emissions ($/t CO2) is lowest for the

lignite burning plant, and highest for the natural gas plant which reflects the relative

carbon contents of the various fuels; it is also high for the very small plant reflecting

efficiency and economy of scale penalties.

CO2 capture technology could be fitted to other industrial plant, such as

hydrogen and ammonia production plant, in some of the units in an oil refinery and in

certain chemical production plants. Some of these could provide relatively low cost

opportunities for capturing CO2. Further examination of the characteristics of the

particular industrial sites would be needed to determine their suitability for capturing

CO2. For Subang case (compression of CO2 from natural gas sweetening plant), our

result calculations shows the cost of compressing CO2 $10.7/tCO2.

Either using post-combustion or pre-combustion capture particularly for a new

power plant, would generate electricity at similar cost. Which option would be

chosen depends amongst other things, on the acceptability of IGCC as a large-scale

power generation technology in Indonesia. If it were felt that the reliability of this

technology were not yet high enough to justify its use, then the post-combustion

option for capturing CO2 from SC PF or NGCC plant would likely be preferred.

The size of a new plant with capture should be such that it can deliver

the required electricity service, which is likely to mean that the units should be larger

than would be the case without capture. This would also allow the operator to take

advantage of economies of scale in capture. Similarly, existing power plant could be

retrofitted with capture, or capture could be fitted as part of a rebuilding programme

where the efficiency of the base plant was also improved. It is not feasible to

}

generalise about the cost of retrofit or rebuilding because individual circumstances

vary so much.

Having captured the CO2, the next step in the CCS chain is to transport it to

the storage site. As we have acknowledged, the associated costs of the transportation

options either by using pipeline or marine transportation of CO2 mainly depend on the

distance and the quantity transported. Particularly in the case of pipelines, the

associated cost strongly depend on whether the pipeline is onshore or offshore,

whether the area is heavily congested, and whether will pass through mountain or

large rivers areas. The cost of pipelines includes construction, operation and

maintenance which strongly influenced by the capacity of the line, by the terrain

traversed, as well as the length of the line. Offshore pipelines tend to be more

expensive than onshore pipelines. Intermediate booster stations may be required to

compensate for pressure loss on longer pipelines. These associated important items

have been identified in this study.

Several cases have been identified where transporting CO2 from capture at a

power plant to storage could be done at low specific cost. These studies have also

shown that transporting small quantities of CO2 over moderate distances, or medium

quantities over long distances, would impose significant cost on a CCS project.

Nevertheless, in all of these cases the specific cost of transporting CO2 is less than the

specific cost of capturing and compressing it. These important items match with the

results of our calculations which shows that: i) for the West Jawa-Sumatera route case

(combined onshore and offshore pipelines), the average cost per tonne at full capacity

is $ 6.6/t CO2 and increases to $ 9.4/t CO2 at 70% capacity, ii) for the West Jawa

offshore case, the average cost per tonne at full capacity is $ 1.0/t CO2 and increases

to $ 1.4/t CO2 at 70% capacity, iii) for the South Sumatera onshore case, the average

cost per tonne at full capacity is $ 0.53/t CO2 and increases to $ 0.82/t CO2 at 65%

capacity, iv) for the East Kalimantan onshore case, the average cost per tonne at full

capacity is $ 1.2/t CO2 and increases to $ 1.8/t CO2 at 65% capacity, and v) for the

pipeline from the natural gas processing plant, Subang field case, the average cost per

tonne at outlet pressure 13. 0 Mpa is $ 7.8/t CO2 and decreases to $ 5.6/t CO2 at

outlet pressure 11.3 Mpa (lower pressure).

As we have mentioned in Chapter 4 previously, the costs presented in this

report can only be regarded as broadly indicative, they do provide some relevant

}

guidance for considering transport options for moving CO2 at the locations

considered. As the results of our calculation, 4 important items have been identified,

as follows:

As in the South Sumatera onshore case, onshore pipelines of reasonable length

(<100 km) carrying medium to large quantities of CO2 (>4 Mt/y) impose relatively

small specific costs ~ <$1/t CO2 on the CCS project,

Small quantities of CO2 (< 1 Mt/y) are relatively expensive to move, even over

moderate distances (~ 80 km), as shown by the Subang gas field case study,

As in the Java offshore case, offshore pipelines are relatively more expensive

but the cost may not be exceptional if the line is short, and

As in the Java-Sumatera case, transportation of CO2 over longer distances

imposes substantial costs on a CCS project. If CO2 could be collected from a number

of sources (producing about 20 Mt/y in total), the specific cost of transport (i.e. per

tonne of CO2) could be usefully reduced even with a longer line.

Concentrated sources of CO2, such as from gas processing plants, should offer

some of the lowest cost supplies available. However, the quantity of CO2 available

from any one plant may be relatively small so the cost of transport could be relatively

high. In order to take advantage of the low cost of CO2 separated at a gas processing

plant, it is likely to be necessary to find storage locations nearby, or to combine the

CO2 from one plant with that from other plants, so as to take advantage of the

economies of scale in pipelines.

Providing there are suitable places to store CO2 within several hundred km of

the large power stations in West Java or South Sumatera, it might be possible to

establish major CO2 pipeline systems. Such systems would connect several power

stations as well as other industrial sources, transporting larger amounts of CO2 than

have been considered here, in large diameter pipelines at low specific cost. Once such

a system had been established, it could take CO2 from smaller sources as well at

relatively low cost.

The key element for any CO2 storage site is to minimize the risk of leakage i.e.

any leakage into the geosphere, hydrosphere, biosphere or atmosphere during the full

life cycle (pre-injection, injection, post-injection and post-closure) of the project. A

site-specific risk-based Measurement, Monitoring and Verification plan (MMV)

should be in place for a storage complex.

}

The key issues with storage complex/site selection are: should fully protect

existing hydrocarbon, mineral and groundwater resources and needs to be backed up

by demonstrative models that identify potential leak paths. The leak scenarios,

however, need to be verified through baseline surveys and a robust MMV framework.

Five types of potential storage complexes (excluding EOR fields) have been

identified that are applicable in Indonesia (ie Producing fields, Abandoned fields,

Structures with dry wells, Undrilled structures and Deep saline formation). Structures

with abandoned fields and deep saline aquifers are the most likely storage containers

for future CO2 sequestration.

There are two major storage mechanisms that will operate to keep CO2

retained underground - physical and geochemical trapping. The effectiveness of

geological storage is determined by the overall combination of physical and

geochemical trapping mechanisms.

Fundamental methodology for storage site selection in conjunction

with EOR is slightly different from non-EOR, but many aspects are analogous. There

are two aspects that received attention firstly to the potential for incremental oil

recovery that can be obtained and secondly, aspects of leakage monitoring for storage

sites. Sufficient amount of oil remaining saturation is the most preferable criteria to

recover oil profitably. An effective CO2 injection method using CO2 miscible

flooding, furthermore, not only could achieve higher incremental oil recovery but also

significant amount of CO2 that retained in reservoir. Monitoring aspects should also

be noticed to trace CO2 in the reservoir and to verify the effectiveness of CO2 cycling

versus storage.

The long oil exploration and production history within Indonesia, there are

many depleted oil and gas fields options for potential storage whether they will be

later combined with CO2-EOR or used for storage purposes only by utilizing

abandoned oil and gas fields. This type of storage is popular due to geological

stability, well characterised, low population density and existing infrastructures.

Moreover, it will be more attractive since could reduce exploration cost to find new

sites, reuse the existing facilities and the future capacity of its storage will increase in

time as more fields are depleted. The sedimentary basins of South Sumatra, East

Kalimantan and Natuna represent key areas for potential CO2 sequestration. All the

elements that are required for the safe and long-term underground storage of CO2 are

}

believed to exist in these areas; this is based on the results of many decades of

hydrocarbon exploration and production. Abandoned oil and gas fields and deep

saline aquifers are the most likely storage containers for future CO2 sequestration.

Deployment of CCS also requires sound policy framework to minimize

risks related to policy and commercial aspects. Partnerships between governments,

international organizations and private sector are essential: government sets the policy

and provides support while private sector develops, delivers, and deploys the

technology.

Most of the non-technical challenges of deploying CCS evolve around the

regulatory and policy aspects. Currently there is existing global guidelines i.e. the

2006 IPCC (Intergovernmental Panel on Climate Change) Guidelines for National

Greenhouse Gas Inventories providing risk management methodologies for CCS

projects. These guidelines still need to be operationalized at national and local levels

with regard to detailed regulations treating each phase of a CCS project: capture,

transport and storage.

Parallel to establishing the regulatory regime, a key enabling policy is

international financing especially for CCS deployment in developing countries. This

is pivotal since CCS as CO2 mitigation effort generates no revenue stream other than

the CO2 price (if it is recognized to generate CO2 credits, which currently is not yet

the case) - which in the short-term may not be sufficient to deploy a CCS project.

There is, however, promising potential to use emissions trading schemes as a

mechanism for developed countries to finance CCS in developing countries. For such

scheme to work, countries will need to agree to a binding and meaningful CO2

reduction target whereas CCS is one of the crucial options that need to be deployed.

The most significant risks are commercial and policy related. At this

time, CCS is not commercially viable, due to the high cost of CCS and the currently

weak international carbon price signals. Moreover, there is no legal/regulatory regime

in place that would allow potential developers and investors to adequately assess and

manage their risks and liabilities in respect of CO2 storage.

Indonesia is in a privileged position to play an active role in CCS. It

has both CO2 sources that can be captured and the CO2 storage capacity. It is speeding

up its industrialization and growing power generating capacity which gives it an

opportunity to deploy CCS early and avoid higher cost to retrofit later. Development

}

and deployment of CCS in Indonesia offer strategic fit with the national energy policy

and development of contaminated oil and gas fields (particularly with high CO2

concentration). Indonesia has been recognized as an important country to the global

climate policy discussion as it hosted a successful UNFCCC meeting in Bali in 2007,

making Indonesia’s move towards CCS a significant one in mustering international

support.

CONTENTS Contents i

List of Tables ii

List of Figures iii

1. Introduction 1.1

1.1. National Energy Resources and Energy Policy 1.1

1.2. National Energy Mix and Related CO2 Emissions 1.1

1.3. Possibility of CCS Technology in Indonesia 1.1

1.4. Potential Role of CCS in Power and Oil & Gas Sectors 1.1

2. CO2 Emission Sources In Indonesia 2.1

2.1 Oil, Gas and Mining Industry 2.1

2.1.1 Introduction 2.1

2.1.2 Assessment of Industrial CO2 Sources in Indonesia 2.1

2.1.2.1 North Sumatra CO2 Emissions Sources 2.1

2.1.2.2 Central Sumatra CO2 Emissions Sources 2.1

2.1.2.3 South Sumatra CO2 Emissions Sources 2.1

2.1.2.4 West Java CO2 Emissions Sources 2.1

2.1.2.5 East Java CO2 Emissions Sources 2.1

2.1.2.6 Kalimantan CO2 Emissions Sources 2.1

2.1.2.7 Sulawesi CO2 Emissions Sources 2.1

2.1.3 Case Study - Screening CO2 sources in A High Graded

Area of Interest 2.1

2.2 Power Sector 2.2

2.2.1 Introduction 2.2

2.2.2 Indonesian Electricity Development 2.2

2.2.3 Projection of CO2 Emission 2.2

3. Capture Technology 3.1

3.1 Introduction to CO2 Capture 3.1

3.1.1 Issues for Capture of CO2 3.1

3.1.2 Characteristics of CO2 Sources 3.1

3.2 Introduction to CO2 Separation Methods 3.1

3.2.1 Options 3.1

}

3.2.2 Solvent Absorption Separation 3.1

3.2.2.1 Chemical Solvents 3.1

3.2.2.2 Physical Solvents 3.1

3.2.3 Solid Adsorption Separation 3.1

3.2.4 Membrane Separation 3.1

3.2.4.1 Membrane Performance 3.1

3.2.4.2 Novel Membrane Configurations 3.1

3.2.5 Cryogenic Separation 3.1

3.3 Application of CO2 Capture in Power Plants 3.1

3.3.1 Post-combustion Removal 3.1

3.3.1.1 CO2 Separation 3.1

3.3.1.2 Using Chemical Solvent Separation in Power Plants 3.1

3.3.2 Pre-combustion Removal 3.1

3.3.2.1 Coal Gasification-Based Power Generation 3.1

3.3.2.2 Addition of CO2 Capture to IGCC 3.1

3.3.2.3 Catalytic Shift Conversion 3.1

3.3.2.4 Modifications Required to the Gas Turbine in an IGCC

with Capture 3.1

3.3.2.5 CO2 Separation Processes for IGCC with Shift 3.1

3.3.2.6 Pre-combustion Removal of CO2 with Other Fuels 3.1

3.3.3 Modified Combustion Conditions 3.1

3.3.3.1 Oxyfuel Combustion (Coal) 3.1

3.3.3.2 Oxyfuel Combustion (Gas) 3.1

3.3.3.3 Chemical Looping Combustion 3.1

3.3.4 Allowing For the Energy Used in Capturing CO2 3.1

3.4 Application of CO2 Capture to Other Industrial Sources 3.1

3.5 Application of Capture to Existing Plant 3.1

3.5.1 Is the existing plant suitable for capture? 3.1

3.5.2 What are the options for capturing from the plant? 3.1

3.5.2.1 PF Retrofit 3.1

3.5.2.2 NGCC Retrofit 3.1

3.5.2.3 PF Rebuild 3.1

3.5.2.4 NGCC Rebuild 3.1

3.5.3 What affects the choice between options for capturing CO2

}

at an existing plant? 3.1

3.5.4 Designing New Plant to Facilitate Later Fitting of Capture 3.1

3.6 Cost of Power Plant with CO2 Capture 3.1

3.6.1 Key Features to be Considered in Assessing Economics 3.1

3.6.2 Approach to Generic Costs 3.1

3.6.3 Cost of Electricity 3.1

3.6.4 Relating Cost to Emissions Reduction 3.1

3.6.5 Overview of Costs 3.1

3.6.6 Costs of Capturing CO2 in PF, IGCC and NGCC Plants 3.1

3.6.6.1 Sub-critical PF 3.1

3.6.6.2 Super-critical PF 3.1

3.6.6.3 IGCC 3.1

3.6.6.4 NGCC 3.1

3.6.6.5 Summary of the Cost of Capturing CO2 3.1

3.6.7 Retrofit of CO2 Capture to Existing Power Plants 3.1

3.6.8 Potential Cost Reductions 3.1

3.6.9 Economics of Capture from Non-Power Generation Sources 3.1

3.7 Environmental Aspects, Risks, Safety and Other Considerations 3.1

3.7.1 Risks Involved in Capturing CO2 3.1

3.7.2 Health and Safety Aspects of CO2 Capture 3.1

3.7.3 Control Measures in Relation To Operation with CO2 3.1

3.7.4 Environmental Impact of CO2 Capture 3.1

3.8 Preliminary Assessment of Options in Indonesia 3.1

3.9 Implications for Use of CO2 Capture in Indonesia 3.1

4. Transportation Technology 4.1

4.1 Transportation Options and Conditions 4.1

4.1.1 Introduction 4.1

4.1.2 Methods of Transporting CO2 4.1

4.1.3 Characteristics of CO2 Supply 4.1

4.1.4 Demands of CO2 Storage 4.1

4.2 Conditioning For Transport 4.1

4.2.1 Purification 4.1

4.2.2 Pressurisation 4.1

4.2.3 Liquefaction 4.1

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4.3 Transport Options 4.1

4.3.1 Description of The Main Options 4.1

4.3.2 Road 4.1

4.3.3 Rail 4.1

4.3.4 Pipeline 4.1

4.3.5 Shipping 4.1

4.4 Receipt of CO2 At Storage Site 4.1

4.5 Comparison of Costs of Transport Options 4.1

4.5.1 Pipeline Costs 4.1

4.5.2 Shipping Costs 4.1

4.5.3 Comparison Between Costs of Shipping and Pipelines 4.1

4.6 Environmental Aspects, Risks, Safety and Other Considerations 4.1

4.6.1 Accident Rates of Established Transport Systems 4.1

4.6.2 Safety 4.1

4.6.3 Environmental Impact of Pipelines 4.1

4.6.4 Environmental Impact of Shipping 4.1

4.7 Preliminary Assessment of Options For Indonesia 4.1

4.7.1 Introduction 4.1

4.7.2 West Java/South Sumatera 4.1

4.7.3 West Java Offshore 4.1

4.7.4 South Sumatera 4.1

4.7.5 East Kalimantan 4.1

4.7.6 Natural Gas Processing Plant, Subang Field 4.1

4.7.7 Ship Transport of CO2 4.1

4.7.8 Conclusions about Transporting CO2 in the 5 Case Studies 4.1

4.7.9 Implications for Future CO2 Transport Systems in Indonesia 4.1

5. Methodology For Site Selection 5.1

5.1 For Non-Enhanced Oil Recovery (EOR) 5.1

5.1.1 Storage Complex Definition 5.2

5.1.2 Principles and Requirements For CCS Site Selection 5.2

5.1.3 Main Types of Storage Complexes 5.2

5.1.4 Storage Mechanisms 5.2

5.1.5 Site Selection Methodology 5.2

5.1.6 Technical Work Elements For Storage Complex Assessment 5.2

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5.1.6.1 Data collection 5.2

5.1.6.2 Simulation of The CO2 in The Subsurface 5.2

5.1.6.3 Security, Sensitivity and Hazard Characterisation 5.2

5.1.6.4 Performance Risk Assessment 5.2

5.1.6.5 Measurement, Monitoring & Verification (MMV)

As a site selection Criteria 5.2

5.2 For Enhanced Oil Recovery (EOR) 5.1

5.2.1 Storage Mechanisms in Enhanced Oil Recovery 5.1

5.2.2 Reservoir Screening 5.1

6. Geological Potential Storage 6.1

6.1 Introduction 6.1

6.2 Available Storage Formations and Global Capacity Estimates 6.1

6.2.1 Depleted Oil and Gas Fields 6.1

6.2.2 Saline Formations 6.1

6.2.3 Coal Seams - Enhanced Coal Bed Methane (ECBM) 6.1

6.3 Geological Setting 6.1

6.4 Indonesia’s Geological Potential Storage and Its Distribution 6.1

7. Existing and Required Regulatory Framework and Its Key Elements 7.1

7.1 Regulatory Framework 7.1

7.1.1 Global-Local Context and Key Issues 7.1

7.1.2 IPCC Guidelines 7.1

7.1.3 National and Local Regulatory Requirements 7.1

7.1.3.1 Capture Regulatory Guidelines 7.1

7.1.3.2 Transport Regulatory Guidelines Plants 7.1

7.1.3.3 Storage Regulatory Guidelines 7.1

7.1.3.3.1 Measurement, Monitoring, and Verification

(MMV) 7.1

7.1.3.3.2 Risk Assessment 7.1

7.1.3.3.3 Financial Responsibility 7.1

7.1.3.3.4 Property Rights and Ownership 7.1

7.1.3.3.5 Site Selection and Characterization 7.1

7.1.3.3.6 Site Closure 7.1

7.1.3.3.7 Post-Closure 7.1

7.2 Enabling Policies 7.1

}

7.2.1 International Financing 7.1

7.2.1.1 Complementing International Policy: A Proposal For

International Framework 7.1

7.2.1.2 The Shape of an Agreement 7.1

7.2.1.3 Supporting Infrastructure 7.1

7.2.2 Long-Term Liability 7.1

7.2.3 Public Acceptance 7.1

8. Conclusions and Recommendations 8.1

LIST OF TABLES

1.1 National Fossil and Renewable Energy Sources 2008 1.1

1.2 National Energy Mix 2008 1.1

1.3 National Energy Mix Target 2025 1.1

1.4 Total CO2 Accumulated Emissions Projection 2008 – 2018 1.1

2.1 Comparison of the different CO2 capture processing routes based on

current available technologies 2.1

2.2 Total estimated CO2 emissions from oil and gas processing 2.1

2.3 Source types, plant and company names for the major emission sources

in North Sumatra 2.1

2.4 Source types, plant and company names for major emission sources

in Central Sumatra 2.1

2.5 Source types, plant and company names for major emission sources

in South Sumatra 2.1

2.6 Source types, plant and company names for major emission sources

in West Java 2.1

2.7 Source types, plant and company names for major emission sources

in East Java 2.1

2.8 Source types, plant and company names for major emission sources

in Kalimantan 2.1

2.9 Source types, plant and company names for major emission sources

in Sulawesi 2.1

2.10 Yearly Energy Sales 2003-2007 2.1

2.11 Emission factor base on 2006 IPCC Guidelines for National Greenhouse

Gas Inventories Introduction 2.1

2.12 Total Accumulated CO2 Emissions 2.1

3.1 Typical CO2 concentrations for various potential sources 3.1

3.2 Some chemical solvents used for removal of CO2 3.1

3.3 Some physical solvents used for removal of CO2 3.1

3.4 Performance of typical adsorbents showing the effect of temperature 3.1

3.5 Some chemical solvents developed for removal of sulphur compounds 3.1

}

3.6 Estimates of space required (m2) for capture of CO2 at a 500 MW

power plant 3.1

3.7 Effect of capturing CO2 on the cost of pulverised coal-fired sub-critical

steam cycle power plant, based on NETL 3.1

3.8 Effect of capturing CO2 on cost of Super-critical steam cycle pulverised

coal-fired power plant, based on NETL 3.1

3.9 Effect of capturing CO2 on the cost of an IGCC plant, based on NETL 3.1

3.10 Effect of capturing CO2 on the cost of an NGCC plant, based on NETL 3.1

3.11 Impact of Residual Value on the Incremental Cost of Electricity for

A supercritical PF power plant 3.1

3.12 Examples of US Occupational Exposure Standards 3.1

3.13 Case 1: Illustrative costs for a 1000 MW supercritical power plant

with/without capture, Indramayu-West Java 3.1

3.14 Case 2: Illustrative costs for a 750 MW NGCC with/without capture,

Muara Tawar-West Java 3.1

3.15 Case 3: Illustrative costs for a 600 MW sub-critical power plant using

lignite fuel, with/without capture, Bangko Tengah-South Sumatera 3.1

3.16 Case 4: Illustrative costs for a 100 MW sub-critical power plant,

with/without capture, Muara Tawar-East Kalimantan 3.1

3.17 Case 5: Illustrative costs for compression of CO2 from natural gas

sweetening plant, Subang field 3.1

4.1 Statistics of serious incidents for various types of ship tankers and

bulk carriers 4.1

4.2 Summary of power plant assumptions West Java/South Sumatera case 4.1

4.3 Some of the assumptions for pipeline costing used in the IEA GHG Cost

Estimation Model 4.1

4.4 Case 1: Results from use of the Cost Estimation Model for the West Java/

Sumatera route 4.1

4.5 Case 2: Summary of power plant assumptions for NGCC 4.1

4.6 Case 2: Principal results from use of the Cost Estimation Model for the

West Java offshore case 4.1

4.7 Case 3: Summary of power plant assumptions in South Sumatera case 4.1

4.8 Case 3: Principal results from use of the Cost Estimation Model for

pipeline transport of CO2 on South Sumatera 4.1

}

4.9 Case 4: Summary of power plant assumptions in Kalimantan case 4.1

4.10 Case 4: Principal results from use of the Cost Estimation Model for the

Kalimantan onshore case 4.1

4.11 Case 5: Principal results from use of the Cost Estimation Model for the

Natural gas processing plant, Subang field case 4.1

6.1 Worldwide Geological Storage Capacity for Several Storage Options 6.1

LIST OF FIGURES 1.1 CO2 Emissions by Sectors 1.1

1.2 Global Energy Related CO2 Emisions 2005 1.1

1.3 Improvement of the National Energy Mix – 2025 1.1

1.4 Global Power Generation Abatement in 2050 – 18.3 GtCO2 1.1

1.5 Impact of CCS Implementation in Long-term National Energy Scenarios 1.1

1.6 CO2 Projection up 2018 of 4 Power Plants & 1 Gas Processing Plant 1.1

2.1 Flue gas and CO2 streams and their equivalent IPCC proposed capture

technologies and terminology 2.1

2.2 Regional map of main CO2 emission sources in the western and central

parts of Indonesia 2.1

2.3 CO2 emissions by sector as estimated by the World Resource Institute 2.1

2.4 CO2 in different regions of Indonesia 2.1

2.5 High level overview of industrial CO2 emissions in North Sumatra 2.1

2.6 Map of CO2 emission sources in North Sumatra 2.1

2.7 High-level overview of CO2 emissions in Central Sumatra 2.1

2.8 Map of CO2 emissions sources in Central Sumatra 2.1

2.9 High level overview of the CO2 emissions in South Sumatra 2.1

2.10 Map of CO2 emissions sources in South Sumatra 2.1

2.11 High level overview of CO2 emissions in West Java 2.1

2.12 High level overview of CO2 emissions in East Java 2.1

2.13 Map of CO2 emissions sources in East Java 2.1

2.14 High level overview of CO2 emissions in Kalimantan 2.1

2.15 Map of CO2 emissions sources for Kalimantan 2.1

2.16 High level overview of CO2 emissions in Sulawesi 2.1

2.17 Map of CO2 emissions sources for Sulawesi 2.1

2.18 Example of multi-disciplinary approach to integrating data sources

for CCS scouting assessments 2.1

2.19 Example of a screening map for further assessment of South Sumatra

CCS opportunities 2.1

2.20 Indonesian Power System 2.1

2.21 Input/Output Model for Generation Expansion Planning 2.1

2.22 The composition of Power Plants 2008 – 2018 Based on Energy

Primary Used 2.1

2.23 CO2 Emission in Interconnection Power System 2.1

3.1 Simulation of membrane separation of CO2 from H2 at different

levels of selectivity 3.1

3.2 Schematic diagram of post-combustion capture of CO2 3.1

3.3 Schematic diagram of IGCC using oxygen-blown gasifier 3.1

3.4 IGCC with sweet shift, CO2 capture and compression 3.1

3.5 IGCC with sour shift, CO2 removal and compression 3.1

3.6 Schematic diagram of an oxyfuel power plant burning pulverized coal 3.1

3.7 Schematic diagram of chemical looping combustion in a gas turbine

power cycle 3.1

3.8 The emissions from power plants with and without CO2 capture,

showing the effect of the extra energy used in the capture process 3.1

3.9 The dependence of the incremental cost of electricity on the cost

of natural gas 3.1

3.10 The effect on the cost of avoided CO2-emissions ($/t CO2) due to

variation in the cost of natural gas 3.1

4.1 Variation in cost of CO2 transport with flow rate in onshore and offshore

pipelines summarising a range of published reports 4.1

4.2 Cost of CO2 transport by pipeline showing the effect of distance and flow

rate 4.1

4.3 Annual cost of transporting CO2 in 30,000 t ships as a function of distance 4.1

4.4 Comparison of cost of transporting 6 Mt/y CO2 by pipeline or ship 4.1

5.1 Definition of a storage complex and the possible leak paths of CO2 5.1

5.2 Main subsurface uncertainties associated with a CO2 storage complex 5.1

5.3 The five scenarios for potential storage complexes. Storage options

in or near producing fields are excluded as non-EOR opportunities 5.1

5.4 Staircase of detailed technical work required for maturing a CO2 storage

complex 5.1

5.5 Maturation strategy for several CO2 storage container options in context

of uncertainty analysis and de-risking activities 5.1

5.6 Measurement, Monitoring and Verification (MMV) needs for different

domains during a CO2 injection and storage project’s lifecycle 5.1

6.1 Prospective areas in sedimentary basins where suitable

saline formations, oil or gas fields, or coal beds may be found 6.1

6.2 Coal Basins Distribution in Indonesia 6.1

6.3 Western Indonesia Neogene Sedimentary Basins 6.1

6.4 Western Indonesia Cronostratigraphic Tertiary Correlation Diagram 6.1

6.5 Indonesia’s Distribution Oil and Gas Basins 6.1

6.6 Potential areas for CCS in Indonesia 6.1

7.1 Key elements of CCS regulatory framework and enabling policies 7.1

7.2 Estimating, verifying, reporting emissions for CCS projects 7.1

7.3 CO2 potential leakage routes and remediation actions 7.1

7.4 Regulatory Needs and Liability for each stage of a CO2 storage project 7.1

7.5 Illustrative split of a developing country’s emissions reductions 7.1

7.6 Proposed model of project-based mechanism that enables CCS deployment:

Clean Technology Mechanism 7.1

7.7 Building blocks of an effective Post-2012 climate agreement 7.1

CHAPTER 1

INTRODUCTION

1.1 National Energy Resources and Energy Policy

Indonesia is the largest archipelago state of more than 6000 inhabited islands

and the world’s fourth most populous nation with around 240 million people spread

over the archipelago, and as a developing economy with average growth about 5% to

6% per-year and the world’s leading coal exporter, a substantial LNG exporter.

Population of Jawa island together with smaller islands of Madura and Bali is about

80% of the total population as the center of the country's economic activities and

accounts for only 7% of the Indonesia land area. As a result of population growth

projection, it has been identified that about 1.0% per year from 2002 to 2030, with the

increasing urban migration of 44 percent in 2002 to 68% in 2030. This fast rate of

urbanization which is in line with Indonesia’s population growth can lead to higher

demand for energy in residential, industry and transportation sectors as increase their

standard of living and demand for energy to support sustaninable economic growth.

As depicted by Table 1.1, Indonesia has been endowed with fossil and

renewable energy resources, although oil production is now decline. There is also a

substantial resource of coal bed methane. However its important role has not entered

yet into the national energy mix. Oil still dominates the national energy mix around

47.9% and natural gas around 18.7% in 2008. Energy intensity (primary energy

consumption per GDP) 656.3 TOE per Million USD GDP which is still high

compared to developed country. Primary energy consumption per-capita is about 0.62

TOE/capita and the trend of primary energy consumption is growing at about 5.5%

per year.

Indonesia’s primary energy consumption has grown rapidly for the last 5 (five)

years, which increased from 767.3 Thousand BOE in 2004 to 965.5 Thousand BOE in

2008, in which its rate of growth was about 5.9% per year compared with 5.1% per

year between 2000 (628.5 thousand BOE) and 2004. The coal consumption increased

at the rate of about 19.3% per year which was from 151.4 Thousand BOE in 2004 to

306.5 Thousand BOE in 2008. Natural gas grew at the rate of about 2.3% per year

driven by the industrial growth which was from 119.9 Thousand BOE in 2004 to

131.4 Thousand BOE in 2008.

Table 1.1 National Fossil and Renewable Energy Sources 2008

*) With assumption no exploration activity and no new field discovery

As described below by Table 1.2 (National Energy Mix 2008) and Table 1.3

(National Energy Mix Target 2025), fossil fuels will remain the dominant source of

energy and will have the biggest role in the national energy mix. In the next two

decades, the composition of Indonesia’s energy mix shows that fossil fuels are still the

main energy driver to fulfil energy demand growth and support economic growth. The

need to curb the growth in fossil-energy demand is more urgent than before as the link

between energy and climate change becomes stronger. This implies that Indonesia

must balance its national energy mix by geographic availability and sufficiently

diversify fuel supply to meet demand and mitigate climate change.

Table 1.2 National Energy Mix 2008

National Energy Mix 2008 Coal 29.6% Oil 47.9% Natural Gas 18.7% Geothermal 1.3% Hydro 2.6%

*) Temporary data (not yet consolidated)

NON-FOSSIL ENERGY RESOURCES INSTALLED CAPACITY

Hydro 75.670 MW (e.q. 845 million BOE) 4.200 MW

Geothermal 27.670 MW (e.q. 250 million BOE) 1.052 MW

Mini/Micro Hydro 500 MW 86,1 MW

Biomass 49.810 MW 445 MW

Solar 4,80 kWh/m2/day 12,1 MW

Wind 9.290 MW 1,1 MW

FOSSIL ENERGY RESOURCES RESERVES PRODUCTIONRSV/PROD

RATIO(YEARS)*)

Oil 56.6 billion barrels 8.2 billion barrels 357 million barrels 23

Gas 334.5 TSCF 170 TSCF 2.7 TSCF 63

Coal 104.8 billion tons 18.8 billion tons 229.2 million tons 82

Coal Bed Methane (CBM) 453 TSCF - - -

As stipulated in the National Energy Policy Objective which based on the

Presidential Decree No.5 of 2006 on National Energy Policy, improvement of the

national energy mix through reducing oil dependency, increasing the role of

renewable energy, and to reduce energy elasticity to below 1 (one) including

improvement of energy infrastructure are the key elements of the objective of the

present energy policy by 2025.

The national energy mix target 2025 as optimized energy-mix scenario can

only be achieved by implementing series of energy-related policy measures that have

been set, among others, the energy diversification and conservation policy. These

measures had been formulated in the National Energy Conservation Plan or RIKEN.

The government has been putting extra efforts in promoting and accelerating the

development of new and renewable sources as being part of the national

diversification program in diversifying the energy sources to strengthen the energy

security. This, coupled with the energy conservation program will be one of the

national efforts in mitigating energy-related green house gases.

Table 1.3 National Energy Mix Target 2025

1.2 National Energy Mix and Related CO2 Emissions

For the Indonesia case with reference to the emissions patterns according to

the Handbook of Indonesia’s Energy Economy Statistics 2005, as depicted by Figure

1.1 the CO2 emissions from energy sector in 2005 was 293.3 million tonnes with

average growth of around 6.6% per-year from 1990 to 2005. The main contributors to

those emissions particularly in 2005 were from industries, power generations and

transportations. The global energy related CO2 emisions 2005 were also the same

pattern as depicted by Figure 1.2.

Energy Mix Target 2025 · Coal ≥ 33% · Liquefied Coal ≥ 2% · Oil ≤ 20% · Gas ≥ 30% · Geothermal ≥ 5% · Biofuel ≥ 5% · Other Renewable Energy

(Biomass, Nuclear, Hydro, Solar, Wind) ≥ 5%

With the same current growth rate pattern, the emissions will still continue to

rise as Indonesia’s population grow and increase their standard of living and demand

for energy to support economic growth due to continuing reliance on fossil fuels in

the national energy mix. This pattern matches the trend of CO2 emissions projections

of non-OECD countries in World Energy Outlook 2008 under its reference scenario.

To support national mitigation efforts in energy sector and to achieve the

optimal energy mix as the above national long-term energy plan, as mentioned above

then three key programmes need to be considered and derived further: i) energy

diversification, ii) energy conservation, and iii) implementation of low carbon

technologies such as carbon capture and storage which can be a key solution.

Figure 1.1 CO2 Emissions by Sectors

Figure 1.2 Global Energy Related CO2 Emisions 2005

As a result of national long-term energy simulation shown by Figure 1.3, the

BAU scenario identified that emissions from national energy sector would reach about

1,150 million ton CO2e in 2025. As the key elements of the objective of the present

energy policy by 2025, improvement of the national energy mix through reducing oil

dependency, increasing the role of renewable energy, and to reduce energy elasticity

to below 1 (one) including improvement of energy infrastructure would reduce the

associated emissions in 2025 which will be around 950 million ton CO2e. However its

emissions trend still grows since introduction of large scale low carbon technologies

were not entered yet into the national energy path.

Figure 1.3 Improvement of the National Energy Mix - 2025

Firm actions are required to steer the national energy system onto sustainable

energy path while supporting national economic growth in rendering national energy

security and mitigating CO2 emissions enhancement. To establish future low-carbon

energy path, at least four actions need to be done: i) drive the energy system toward

low carbon energy sources, ii) develop and deploy low-carbon and carbon-free energy

technologies, iii) promote greater efficiency in energy production, and iv) efficient

distribution and energy use.

The National Action Plan Addressing Climate Change (RAN-PI, Rencana

Aksi Nasional Menghadapi Perubahan Iklim) stipulated that the country’s national

commitment is to reduce greenhouse gas emissions from energy sector, land use land

use change and forestry (LULUCF), while also increasing carbon sequestration as

national’s response to climate change issue. The strategy to deliver mitigation targets

in the priority economic sectors should therefore be formulated not only to take into

account each sector on its own, but also to consider a broader framework including

human wellbeing, productivity and the sustainability of natural services. Although this

approach is not primarily driven by Indonesia’s commitment under the Convention, it

nonetheless is a part of the strategy of national development that also plays a role to

ensure the achievement of climate change mitigation targets.

With the limitation of non renewable energy sources, then to fulfill future

energy need, then it should implement an integrated and optimal energy mix and have

to be in the direction to environmentally friendly energy technology base, compare to

the non renewable energy resource base. Therefore, technology improvement and

knowledge transfer in energy field become very important to be realised.

The achievement of energy technology development program should be based

on geographic position, population growth, economic growth, pattern and standard of

living and environmental along with other important aspects, that as a whole should

be implemented in the form of long-term energy plan that be executed wisely. Beside

that the factor of social readiness will decide the anticipation of energy consumers to

address climate change. Community readiness to change the pattern of energy

consumption should be conducted in every steps of energy policy that anticipate to

climate change should be considered as one strategic approach.

The widespread use of existing efficient technologies and the development and

deployment of new low carbon technologies will be necessary for reducing GHG

emissions in order to stabilize GHG atmospheric concentrations at a safe level. The

critical importance to achieving this target without undue sacrifice of economic

progress is the cost of emission mitigation and its supporting policies.

Moreover, it is important that the full range of technological options should be

eligible for use in abating climate change regardless their potential to reduce GHG

emissions safely and efficiently. Policy and regulations should establish performance

criteria, including environmental criteria, to be met bearing in mind that research and

innovation may to deliver acceptable solutions through a variety of technological

approaches.

There is no one single solution to limit CO2 emissions given the rising demand

for energy and our continued reliance on fossil fuels. However, CO2 Capture and

Storage (CCS) is one of the most significant tools available, with the technological

capability to account for a fifth of total emissions reductions needed to stabilize the

climate during this century. The development of CCS technologies is driven by the

need to mitigate climate change resulting from economic development. CCS

technology systems have the potential to achieve substantial reductions in global

energy-related CO2 emissions, if deployed at a significant scale, in a timely manner

and competitive costs needed to attract investments. CCS can be a major element of

low carbon energy economy. This is a strategy that renders a viable option in large

scale basis in addressing climate change. The growth of energy efficiency

improvements, the switch to less-carbon intensive fuels and renewable resources

deployment is still insufficient in the context CO2 emissions abatement.

1.3 Possibility of CCS Technology in Indonesia

Carbon Capture and Storage (CCS) is a chain of various alternative industrial

steps and systems with a very great potential to contribute in reducing emissions from

large point sources of CO2 emissions, for instance from coal-fired power plants and

enhance oil recovery in Indonesia’ case. This technology is generally compatible with

other climate change technologies and may be tailored to suit the scope, objectives,

regulatory framework and GHG source/sink profile of a given mitigation project.

Since its initiated negotiation under the UNFCCC, governments struggle to

assess and deploy CCS systems within their jurisdictions related to the long term

liability and its monitoring and evaluation processes, on top its high cost of

investment. The private sector, in response, appreciates the tremendous opportunities

in CCS, but often lacks the capacity to support or deploy CCS services and products.

The IEA’s blue map scenario 2008 identified that the use of CCS would

account for 26% of the global global power abatement in 2050 as an active mitigation

scenario relative to the baseline scenario as depicted by Figure 1.4. This blue map

scenario could be consistent with 450 ppm (depending on post-2050 emissions)

which. However this scenario is only possible if the whole world participates fully

which implies a completely different energy system.

Figure 1.4 Global Power Generation Abatement in 2050 – 18.3 GtCO2

As shown by Figure 1.5 below, simulations of 4 (four) long-term national

energy scenarios had been conducted in mid 2007 to assess the impacts of the CCS in

the national energy path. Each of the four long-term national energy scenarios had

different features, such as: i). BAU scenario which took into consideration the

National Energy Conservation Plan (RIKEN) as a based for energy utilization with

national primary energy supply target 2025 according to the Blueprint of National

Energy management 2005 (PEN) where in national energy mix oil: 41.7%, natural

gas: 20.6%, coal: 34.6%, hydro: 2%, and geothermal 1.1%, ii). PERPRES scenario

which fully adopted the National Energy Policy Objective which based on the

Presidential Decree No.5 of 2006 on National Energy Policy as mentioned above, iii)

Hybrid scenario was additional to the PERPRES scenario which took into

consideration more aggressive energy efficiency measures through introduction of

hybrid car technology into national transportation system, high efficiency of lighting

system and appliances in residential and commercial sectors, and iv) CCS scenario:

was additional to Hybrid scenario by introduction of CCS technology into national

energy path in after 2023. Eventhough further simulations have been required in order

to have realistic features based on realistic inputs including its key assumptions, the

role of CCS technology has been appropriately identified as a key mitigation

technology to reduce substantially CO2 emissions in national energy sector about

13.4% from the BAU scenario.

Figure 1.5 Impact of CCS Implementation in Long-term National Energy Scenarios

1.4 Potential Role of CCS in Power and Oil & Gas Sectors

The growth of electricity demand in Indonesia is appeared to remain strong

particularly for the demand in business and residential sectors. This indicator has

convinced PT PLN (Persero) as a State Owned Enterprise that the potential of

electricity demand in Indonesia will be greater for the next ten years at least. This is

also supported by an independent study that indicates that every 1% of economic

growth will need 1.5% to 2.0% growth in electricity.

In line with this pattern, PLN forecasted the growth of electricity demand up

to year 2018. The remarkable demand projection made PLN to issue a Ten-Year

National Electricity Development Plan in January 2009 (RUPTL). The plan was

prepared based on the least cost principle. Long-term capacity expansion simulation

was constructed regarding to this plan and the resulted mostly the additional required

power plants would be dominated by steam coal power plant. In 2008, energy

produced by coal power plant is about 46%, and in 2018 will be about 63%.

200

300

400

500

600

700

800

900

1000

1100

1200

2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025

Em

isi C

O2

(Jut

a T

on)

Base Perpres Hybrid CCS

In line with the long-term projection of CO2 emissions from power sector

which were derived from capacity expansion plant up to 2018, it has been identified

that considerable amount of CO2 emissions would be contributed from coal power

plants. Projection of the total accumulated CO2 emissions for 4 islands from 2008 up

to 2018 can be seen in Table 1.4. Although in power sector side Indonesia at present

is not categorized as one of the major CO2 emitters countries, however in the next 2

decades its future CO2 emissions trajectory of long-term power sector development

with respect to the capacity expansion plan possibly would be in the increasing path.

Table 1.4 Total CO2 Accumulated Emissions Projection 2008 – 2018

No Interconnection Power System

CO2 Emissions (Million Ton)

1 Jawa - Bali 1,652.0 2 Sumatera 158.7 3 Kalimantan 93.0 4 Sulawesi 34.7

Total 1,938.5

Figure 1.6 CO2 Projection up 2018 of 4 Power Plants & 1 Gas Processing Plant

Therefore integrated firm actions would be further required to render low-

carbon energy path by mitigating CO2 emissions. To establish future low-carbon

Power Plant

Legend:

Storage Location

Pipeline

Note: Unscaled Map

Gas Processing Plant

GUU

U

Muara Tawar 2,3,4Combined Cycle Power Plant3 x 750 MWEmissions Projection up to 2018: 26.6 MtCO2

IndramayuSteam Coal Power Plant2 x 1000 MW Emissions Projection up to 2018: 65.8 MtCO2

Java Sea Offshore

South Sumatra Onshore

East Kalimantan Onshore

Bangko Tengah Steam Coal Power Plant4 x 600 MWEmissions Projection up to 2018: 11.5 MtCO2

SubangGas Processing PlantEmissions Projection up to 2018: 6.2 MtCO2

Muara JawaSteam Coal Power Plant2 x 100 MWEmissions Projection up to 2018: 10.6 MtCO2

60 km

60 km

320 km

35 km300 km

15 km

129.7 km

Power Plant

Legend:

Storage Location

Pipeline

Note: Unscaled Map

Gas Processing Plant

Power Plant

Legend:

Storage Location

Pipeline

Note: Unscaled Map

Gas Processing Plant

GUU

GUU

U

Muara Tawar 2,3,4Combined Cycle Power Plant3 x 750 MWEmissions Projection up to 2018: 26.6 MtCO2

IndramayuSteam Coal Power Plant2 x 1000 MW Emissions Projection up to 2018: 65.8 MtCO2

Java Sea Offshore

South Sumatra Onshore

East Kalimantan Onshore

Bangko Tengah Steam Coal Power Plant4 x 600 MWEmissions Projection up to 2018: 11.5 MtCO2

SubangGas Processing PlantEmissions Projection up to 2018: 6.2 MtCO2

Muara JawaSteam Coal Power Plant2 x 100 MWEmissions Projection up to 2018: 10.6 MtCO2

60 km

60 km

320 km

35 km300 km

15 km

129.7 km

energy path, several associated programs could be carried out such as energy

efficiency improvements, switching to less-carbon intensive fuels and renewable

resources deployment. However these efforts are still insufficient in the context CO2

emissions abatement particularly in large scale.

Currently, there is no one single solution to limit CO2 emissions given the

rising demand for energy and our continued reliance on fossil fuels, but Carbon

Capture Storage is considered as one of the most significant tools available, with the

technological capability to account for a fifth of total emissions reductions needed to

stabilize the climate during this century.

The separation of CO2 from industrial and energy-related sources such as

power plants, transport of the CO2 towards a storage location, and injection into a

subsurface reservoir and storing it there in long-term underground isolation from the

atmosphere are the main parts of the CCS technologies. CO2 sources from major

interconnected power systems will be matched with identification of geological

potential reservoirs.

LEMIGAS through its preliminary assessment on geological potential storage

for CO2, had been identified several regions that are likely favourable to store CO2 in

conjunction with CO2-enhanced oil recovery (EOR). It is estimated that CO2 volume

of 38 – 152 million tons may be possible to be stored in the depleted oil reservoirs in

East Kalimantan region, and potential oil recoveries of 265 – 531 million barrels

could be obtained. In South Sumatra region, CO2 volume of 18 – 36 million tons may

be possible to be stored in the depleted oil reservoirs with potential oil recoveries of

84 – 167 million barrels. Natuna area which has been identified as giant gas reserves

and dominated by 70% of CO2 likely in the future could be used as CO2 source. This

enormous CO2 source can be injected into oil and gas reservoirs or saline aquifer.

Java North Sea seems potentially available for CO2 storage due to many

brown fields located around this region although some fields are still productively

producing, but the oil production can be improved in conjunction of CO2-EOR. Its

location is also strategic for CO2 transportation which is close to Subang Natural Gas

Processing plant.

As depicted by Figure 1.6 above, it’s shown in more detail the associated CO2

emissions projection up to 2018 of 4 (four) planned power plants where the location

of 2 (two) power plants are in West Jawa, 1 (one) in South Sumatera and 1 (one) in

East Kalimantan and 1 (one) gas processing plant in West Jawa.

Subang Gas Processing Plant is located in Subang area (West Java) operated

by Pertamina. The gas production is 200 MMSCFD with 23% CO2 content. The C02

content of the processed gas is reduced to 5%, CO2 release is 36 MMSCFD or 1895

tonne/day or 624812 tonne/year. They use Amine System as CO2 removal with

licence technology from BASF. With the current production rate the Subang Gas

Field life time is calculated will be projected until year 2018. Distance from Subang

area to shore is 29.7 KM and 50 KM to offshore depleted field.

As the main part of this study, we conducted preliminary assessment of

options in Indonesia in which 5 (five) cases are examined. In line with Figure 1.6

above, the five cases are as follows:

1. Capture at a 1000 MW supercritical coal-fired power plant with a supercritical

steam cycle burning Sub-bituminous coal, located in Indramayu-West Java, and

transport to an onshore storage location in South Sumatera. The pipeline would

involve an onshore line (300 km in length) over cultivated land, followed by a 35

km subsea crossing, with a final 320 km onshore leg again over cultivated land.

2. Capture at a natural gas-fired combined cycle power plant (NGCC) rated at 750

MW, located in Muara Tawar-West Java, and transport to offshore storage

location in North Java sea. In this case, storage of CO2 captured at a power plant

close to the coast of West Java is piped to an offshore location through a short

(15km) subsea line.

3. Capture of CO2 at a 600 MW power plant using a sub-critical steam cycle, burning

lignite fuel, located at a mine site in Bangko Tengah-South Sumatera, and

transport to onshore location in South Sumatera. A 60 km onshore pipeline carries

the CO2 over cultivated terrain to the storage site.

4. Capture at a 100 MW coal-fired power plant with a sub-critical steam cycle,

burning Sub-bituminous fuel, located in East Kalimantan, and transport to onshore

storage location in Muara Jawa-East Kalimantan. Storage would be relatively

close to the power plant requiring an onshore pipeline length of 60 km.

5. In addition, a case is considered which does not involve a power plant; at a natural

gas processing plant in the Subang field in West Java, where CO2 is already

separated from the gas stream, the exhaust CO2 would be compressed for transport

to offshore storage location in North Java sea. The store is assumed to be 50km

offshore. The Subang gas field is onshore, 29.7 km from the coast which

necessitates an onshore pipeline and on offshore line; the terrain that the onshore

line crosses is cultivated.

It has been acknowledged that commercially available technologies could be

fitted to new power stations in Indonesia using either post-combustion capture or pre-

combustion capture technologies. A number of case studies are provided to illustrate

the cost of capture. It should be noted that the costs of these associated plants have

been derived from the costs for new construction by adapting its cases that were

presented in this study. For this reason, it need to be pondered that the same degree of

confidence cannot be assigned to the costs given here as would be expected for

engineering analyses as described in this report.

As one of the important item of this study, it’s expected that these results

would provide some useful guidance on the effects of scale and choice of fuel on the

cost of avoiding CO2 emissions, since our next important step is to elaborate further

by using these results to establish further a programme of CCS pilot project in

Indonesia.

With early opportunity to deploy this technology in Indonesia and also

supporting by compatibility with most current energy infrastructures, mature

technology transfer could be shortened in timely manner. A robust and established

CCS methodology would create good climate regarding associated cost that requires

significant amount of investment and economic justification. CCS currently may the

only technological approach that shows promise for enabling Indonesia to continue to

use the fossil energy while at the same time, achieving sufficient carbon dioxide

emissions reduction to address climate change.

The purpose of this study is to develop an understanding of the requirements

associated with deploying Carbon Capture and Geological Storage (CCS) in Indonesia

by addressing technical Commercial and Regulatory aspects of CCS deployment to

further stimulate the ongoing dialogue on potential application of such technology in

Indonesia. In order to promote this dialogue the study seeks to:

i) Strengthen the evidence base which supports a national mitigation program and

ambitious climate change decision making as important elements in the climate

mitigation efforts at both a national and an international level.

ii) Address issues related to the application of and investment in CCS in Indonesia

and indicate the feasibility of potential CCS project opportunities in Indonesia.

iii) Promoting discussion with the Indonesian Government on climate change issues

as part of the effort to build a global consensus on the scale of the challenge and

an international regulatory framework.

References:

· Handbook of Energy & Economic Statistic of Indonesia, 2008. Center for data and Information on Energy and Mineral Resources, Ministry Energy and Mineral Resources.

· Rencana Usaha Penyediaan Tenaga Listrik PT PLN (Persero) 2009 – 2018 (RUPTL - Ten Year National Electricity Development Plan, Indonesia State Electricity Corporation). PT PLN (Persero), Januari 2009.

· Energy Policy Review of Indonesia. International Energy Agency (IEA), 2008. · World Energy Outlook 2008. International Energy Agency, 2008. · APEC Energy Demand and Supply Outlook 2006: Projections to 2030 Economy

Review. Asia Pacific Energy Research Centre. Institute of Energy Economics, Japan. 2006

· Energy and Environment Data Reference Bank (EEDRB). International Atomic Energy Agency.

· Indonesia 1st National Communication to the UNFCCC, 1994. State Ministry of Environment.

· Indonesia Energy Outlook and Statistics 2006. Pengkajian Energi Universitas Indonesia (PEUI).

· International Energy Outlook 2008. Energy Information Administration (EIA). June 2008.

· National Action Plan Addressing Climate Change (RAN-PI). State Ministry of Environment. 2007.

· Ronnie S. Natawidjaja, Ph.D., Impact of Rising Energy Costs on the Food System in Indonesia. Center for Agricultural Policy an Agribusiness Studies. Padjadjaran University. 2006

· World Bank’s World Development Indicators (WDI). 2005.

CHAPTER 2

CO2 EMISSION SOURCES IN INDONESIA

2.1 Oil and Gas Industry

2.1.1 Introduction

There are multiple industrial sources of CO2 in Indonesia, from power stations,

oil and gas processing plants, steel and ammonia plants and cement factories.

Industrial CO2 sources can be subdivided (Figure 2.1) into two broad

groupings:

§ Flue gas: low CO2 content at low pressures – normal product of combustion.

§ CO2 streams: CO2 separated as an industrial by product to meet process stream

specifications.

Figure 2.1 Flue gas and CO2 streams and their equivalent IPCC proposed capture technologies and terminology (IPCC, 2005)1

1 Note that compression and conditioning facilities for CO2 have not been taken into account in this diagram

Flue gas capture will require the existing plant facilities to be retro-fitted (see

Figure 2.1) for CO2 capture, unlike plants that produce relatively pure CO2 streams.

Flue gas capture can deliver high volumes of CO2, but the initial installation costs are

high compared to a CCS project based using CO2 from a pure industrial stream. A

high level comparison of flue gas technologies and industrial streams is given in Table

2.1. For flue gas capture, three main processing routes are currently available: post-

combustion capture, pre-combustion capture and oxyfueling.

Table 2.1 Comparison of the different CO2 capture processes/streams 2

Pure streams of CO2 are generated from the following industrial processes:

1. Gas Processing Plants: Remove CO2 from produced gas down to market

specifications (2-5%). This delivers CO2 streams in suitable volumes close to

the producing fields where CO2 occurs as a natural contaminant in the

subsurface hydrocarbon gases.

2. LNG Plants: CO2 is removed from the feed gas down to 50-100ppm to avoid

freezing out in cryogenic processing. CO2 streams are available in sufficient

volumes for a medium scale CCS project (several million tonnes pa) due to the

large input of feed gas.

3. Refineries: Requires a refinery with H2 generation to generate clear CO2

streams. A suitable CO2 stream is usually only available if a hydrocracker is

present.

4. Ammonia Plants: Generates CO2 in suitable volumes due to H2 generation.

CO2 is often used to produce Urea in a neighbouring plant. Therefore, the

likelihood of CO2 being available for other purposes is low.

2 Colour coding is a qualitative ranking where red colour highlights higher costs, complexity etc for a potential CCS project; green colour highlights where factors are positive e.g. low costs, greater experience, greater volume availability etc; yellow colour highlights intermediate factors

5. Steel Plants: Specialized steel plants do have H2 units. Based on the available

data these specialised plants do not exist in Indonesia.

2.1.2 Assessment of Industrial CO2 Sources in Indonesia

The following assessment includes the considered onshore industrial CO2

emission sources in Indonesia (Figure 2.2) based on publicly available data. Scouting

work has revealed that most industrial sources are located in Java and Sumatra, and to

a lesser extent in Kalimantan and Sulawesi. Hence, these islands (high graded areas of

interest) have been the focus for further screening work identifying suitable CO2

sources for possible CCS projects.

Figure 2.2 Regional map of main CO2 emission sources in the western and central parts of Indonesia

The total energy-related estimated CO2 output for Indonesia in 2005 based on

questionnaires and statistical approaches is about 280 million tonnes pa

(guardian.co.uk). Figure 2.3 shows the volume split into different categories as

reported by the World Resource Institute (Earthtrends.wri.org).

Figure 2.3 CO2 emissions by sector as estimated by the World Resource Institute

An overview of the industry-generated CO2 emission volumes for flue gas

from power generation and CO2 streams from oil and gas processing (see introduction

section above) in the main industrial regions in Indonesia is given in Figure 2.4. The

total volume of CO2 accounts to some 80 million tonnes pa.

Figure 2.4 CO2 in different regions of Indonesia3

Table 2.2 is a summary of the emissions generated from oil and processing

(excluding commercial power generation).

Table 2.2 Total estimated CO2 emissions from oil and gas processing (lower case estimate based on publically available data; power stations are excluded)

2.1.2.1 North Sumatra CO2 Emissions Sources

The industrial sources of CO2 in Northern Sumatra are located along the

northern and north-eastern costal part of the area. The two main centres are around the

Arun LNG plant and the area of Medan. The gas fields in the north can contain high

volumes of CO2 (around 15% and higher), which leads to high volumes of CO2 being

stripped out in the gas processing plants and the Arun LNG plant. The main flue gas

3 Circle size is proportional to volumes. Aggregate numbers are based on summing the contribution from individual plants in publicly available databases (HIS Energy Database & carma.org) and from analogue plant data. Each pie chart segment represents the total flue gas or pure CO2 stream emissions in each region

Oil and gas processing CO2 emission (Million Tonnes)

Java 5.1 Sumatra 6.3 Kalimantan 3.4 Sulawesi 2.5 Total 17.3

producer in this region is the power plant in Medan. The total CO2 gas emission is

about 5.8 million tonnes pa with a flue gas emission component of about 1.6 million

tonnes pa. In addition seven more gas processing plants have been identified in this

region for which emissions volume estimates are unavailable.

Figure 2.5 High level overview of industrial CO2 emissions in North Sumatra *

* Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Table 2.3 Source types, plant and company names for the major oil and gas emission sources in North Sumatra

CO2 Source Plant Name Operator / owner

LNG plant (CO2 stream & flue gas) Arun 6 (Phase III) Arun / Pertamina/Exxon

Mobil

Refinery (H2Unit) (CO2 stream)

Pangkalan Brandan n/a

Gas Processing (CO2 stream) Pangkalan Brandan PT Pertamina / Indonesia

Gas Processing (CO2 stream) (Pangkalan Brandan City)

PT Pertamina / Indonesia

Gas Processing (CO2 stream) (Pangkalan Brandan North)

PT Pertamina / Indonesia

Gas Processing (CO2 stream) Arun Exxon

Gas Processing (CO2 stream) Lhok Suhon n/a

Gas Processing (CO2 stream) n/a n/a

Refinery (flue gas) Pangkalan Brandan n/a

Figure 2.6 Map of CO2 emission sources in North Sumatra

2.1.2.2 Central Sumatra CO2 Emissions Sources

The industrial sources of CO2 in Central Sumatra are mainly from the oil and

gas and the paper industries. The largest producer based is believed to be the Ombilin

Power station. The other two major producers are the Dumai and the Sumai Pakning

refineries. All of these sources produce flue gas. As the naturally-occurring

hydrocarbons contain only low volumes of CO2, no gas processing plants venting CO2

have been identified. As there is some heavy oil in the area, CO2 streams could be

provided from the H2 units of the Sungai Pakning Dumai refinery, but this has not

been verified. The total CO2 release in this area is estimated at about 1.7 million

tonnes pa.

Figure 2.7 High-level overview of CO2 emissions in Central Sumatra *

Table 2.4 Source types, plant and company names for major

emission sources in Central Sumatra

CO2 Source Plant Name Operator / owner

Refinery (flue gas) Dumai PT Pertamina / Indonesia

Refinery (H2 Unit) (CO2 stream) Dumai PT Pertamina / Indonesia

Refinery (flue gas) Sungai Pakning PT Pertamina / Indonesia

Refinery (H2 Unit) (CO2 stream) Sungai Pakning PT Pertamina / Indonesia

* Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Figure 2.8 Map of CO2 emissions sources in Central Sumatra

2.1.2.3 South Sumatra CO2 Emissions Sources

The industrial sources of CO2 in South Sumatra are from power plants, paper

factories and oil and gas processing facilities. The area has extensive oil and gas

production, and CO2 levels in producing fields can be up to 30%. Although, specific

data for the abundant gas processing could not be obtained, an estimate based on the

annual gas production of this area suggest CO2 volumes of about 2 million tonnes pa

are released through gas processing plants. Additional CO2 volumes will come from

flue gas of the abundant local power plants. Total volumes (flue gas) of CO2 for South

Sumatra are estimated at about 3.5 million tonnes pa.

Figure 2.9 High level overview of the CO2 emissions in South Sumatra*

* Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Table 2.5 Source types, plant and company names for major emission sources in South Sumatra

CO2 Source Plant Name Operator / owner

Refinery (flue gas) Jambi n/a

Refinery (flue gas) Musi (Muba) PT Pertamina / Indonesia

Refinery (flue gas) Musi (Plaju) PT Pertamina / Indonesia

Refinery (H2Unit) (CO2 stream) Jambi n/a

Gas Processing (CO2 stream) Nuenco n/a

Gas Processing (CO2 stream) PT Medco PT Medco Energy / data n/a

Gas Processing (CO2 stream) Gulf Resources Ltd Gulf

Gas Processing (CO2 stream) Perabumlih Pertamina / Indonesia

Gas Processing (CO2 stream) Conoco Phillips

Grealik Ltd Conoco Phillips

Gas Processing (CO2 stream) Suban Conocco Phillips

Gas Processing (CO2 stream) (North JambiI I) Petrochina / Pertamina & PetroChina

Gas Processing (CO2 stream) (North Jambi II) n/a

Figure 2.10 Map of CO2 emissions sources in South Sumatra

2.1.2.4 West Java CO2 Emissions Sources

West Java has the highest population density in Indonesia

(sedac.ciesin.columbia.edu). CO2 emissions predominantly come from power stations

and various kinds of heavy industries like cement and steel plants. The oil and gas

industry in West Java is largely based offshore, but with assets onshore that contain

high percentages of CO2. Only limited data are available for gas processing plants

onshore but these indicate that the percentage of the total CO2 emissions from gas

plants is low. The total volumes of CO2 emitted are about 50 million tonnes pa, with

higher volumes coming from local power plants and offshore gas processing plants.

Figure 2.11 High level overview of CO2 emissions in West Java*

* Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Table 2.6 Source types, plant and company names for major emission sources in West Java

CO2 Source Plant Name Operator / owner

Refinery (flue gas) Cilacap PT Pertamina / Indonesia

Refinery (flue gas) Balongan - Langit Biru PT Pertamina / Indonesia

Refinery (H2Unit) Cilacap PT Pertamina / Indonesia

Refinery (H2Unit) Balongan - Langit Biru PT Pertamina / Indonesia

Gas processing (CO2 stream)

North Cylamaya PT Pertamina / Indonesia

Gas processing (CO2 stream)

Subang PT Pertamina / Indonesia

Gas processing (CO2 stream)

Tugu Barat n/a

2.1.2.5 East Java CO2 Emissions Sources

East Java’s CO2 sources are similar to West Java, and are dominated by power

plants supplying energy for domestic use and for the needs of heavy industry like steel

and metal plants and refineries. Some gas processing plants are clustered around the

refineries, but no data on these is currently available. The emissions volumes below

will therefore be a conservative estimate.

Figure 2.12 High level overview of CO2 emissions in East Java*

* Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Table 2.7 Source types, plant and company names for major emission sources in East Java

CO2 Source Plant Name Operator / owner

Refinery (flue gas) Cepu Cepu LTD / Pertamina/Exxon

Refinery (flue gas) Tuban (NIORDC) n/a

Refinery (flue gas) Tuban (TPPI condensate)

n/a

Refinery (H2 Unit) (CO2 stream)

Cepu Mini 1 and 2 n/a

Refinery (H2 Unit) (CO2 stream)

Cepu Cepu LTD / Pertamina/Exxon

Refinery (H2 Unit) (CO2 stream)

Tuban (NIORDC) n/a

Refinery (H2 Unit) (CO2 stream)

Tuban (TPPI condensate)

n/a

Gas Processing (CO2 stream)

Cepu Cepu LTD / Pertamina/Exxon

Refinery (flue gas) Cepu Mini 1 and 2 n/a

Figure 2.13 Map of CO2 emissions sources in East Java

2.1.2.6 Kalimantan CO2 Emissions Sources

CO2 sources in Kalimantan are mainly related to the regional hydrocarbon

production. The largest emitter is the CO2 removal facility at the Bontang LNG plant.

Emissions volumes from the local gas processing plants are currently unavailable. The

flue gas contribution mainly comes from power generation associated with the local

LNG plant and other petrochemical facilities.

Figure 2.14 High level overview of CO2 emissions in Kalimantan*

Table 2.8 Source types, plant and company names for major emission sources in Kalimantan

CO2 Source Plant Name Operator / owner

LNG plant (Flue Gas) Bontang A B PT Pertamina / Indonesia

LNG plant (CO2 stream) Bontang A B PT Pertamina / Indonesia

Refinery (flue gas) Balikpapan Total

Refinery (H2 Unit) Balikpapan Total

Gas Processing (CO2 stream) Regional PT Medco Kalimantan

Gas Processing (CO2 stream) Regional Total

Gas Processing (CO2 stream) Regional Serica Energy PLT

* Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Figure 2.15 Map of CO2 emissions sources for Kalimantan

2.1.2.7 Sulawesi CO2 Emissions Sources

The industrial CO2 sources in Sulawesi are mainly linked to the petrochemical

industry. The largest volume of CO2 comes from gas sweetening at the Central

Sulawesi and Senkang Mini LNG plants. In addition to the petrochemical industry,

flue gas emissions are associated with the cement industry and power generation for

domestic use. In total, the CO2 output based on public sources is estimated to be about

2.5 million tonnes pa.

Figure 2.16 High level overview of CO2 emissions in Sulawesi4

4 Each pie chart segment represents the total flue gas or pure CO2 stream emissions in the region

Table 2.9 Source types, plant and company names for major emission sources in Sulawesi

CO2 Source Plant Name Operator / owner

Refinery (flue gas) Selayar n/a

Refinery (H2Unit) (CO2 stream) Selayar n/a

Refinery (flue gas) Parepare (Pinrang) n/a

Refinery (H2 Unit) (CO2 stream) Parepare (Pinrang) n/a

LNG plant (Flue Gas) Central Sulawesi Central Sulawesi /

Mitshibishi, Pertamina, Medco

LNG plant (Flue Gas) Sengkang Mini Phase 1

PT ENERGI SENGKANG / Indonesia

LNG plant (CO2 stream) Central Sulawesi Central Sulawesi /

Mitshibishi, Pertamina, Medco

LNG plant (CO2 stream) Sengkang Mini

Phase 1 PT ENERGI

SENGKANG / Indonesia

Figure 2.17 Map of CO2 emissions sources for Sulawesi

2.1.3 Case Study - Screening CO2 sources in A High Graded Area of Interest

It is advised that future assessments aimed at identifying CCS opportunities

within Indonesia should assess surface and subsurface, political, commercial criteria

and environmental issues, this information has be integrated using ArcGis map layers

(Fig. 2.18). ArcGis is a standard suite of geographic information system (GIS)

software packages (produced by ESRI) that help integrated data on digital map layers.

Figure 2.18 Example of multi-disciplinary approach to integrating data sources for CCS scouting assessments

The example given below looks further at a case investigating a CCS scheme

associated with an existing industrial CO2 stream in the South Sumatra region.

The advantages of locating such a CCS project in this area include:

§ Fields in the area have a medium to high CO2 content – CO2 is presently being

vented from several gas processing plants.

§ Existing infrastructure (roads, pipelines, etc) may help to support a CCS

project.

§ Basin-wide screening has identified the presence of the components that

support CO2 storage (reservoir, seal, structure), However, given the high

density of hydrocarbon-producing fields in the region, the integrity of the

existing wells will need to be evaluated in any future CO2 storage assessment.

Figure 2.19 Example of a screening map for further assessment of South Sumatra CCS opportunities

References

IPCC, 2005: Carbon dioxide capture and storage, - Bert Metz, Ogunlade Davidson, Heleen de Coninck, Manuela Loos and Leo Meyer (Eds.) Cambridge University Press, UK. pp 431or http://www.ipcc.ch/ipccreports/special-reports.htm http://www.guardian.co.uk/global/interactive/2008/dec/09/climatechange-carbonemissions http://earthtrends.wri.org/text/climate-atmosphere/country-profile-86.html Derived data from IHS Energy databases, Wood Mackenzie: Indonesia South East Asia Upstream services reports. www.Carma.org Population data: http://www.sedac.ciesin.columbia.edu/gpw

2.2 Power Sector

2.2.1 Introduction

Electricity demand in Indonesia is mostly provided by PT PLN (Persero) as a

State Owned Enterprise which consists of many scattered power systems such as

isolated and interconnected power systems. As depicted by Figure 2.20 below, PLN

has managed operationally more than 600 isolated power systems and 8 (eight)

interconnected power systems. These eight interconnected power systems are located

in 4 (four) islands namely, Jawa-Bali, Sumatera, Kalimantan and Sulawesi. The

largest power system in Indonesia is the Jawa-Bali interconnected power system,

which consumes more than 78% of the total power demand in the country. The second

largest is Sumatera power system, which consumes about 14% of the total power

demand. Sixty two percent of the populations in Indonesia have been connected to the

grid.

Figure 2.20 Indonesian Power System

In 2008, Indonesian power system has the total installed capacity about 25.6

GW in which Jawa-Bali interconnected power system has installed capacity about

18.5 GW, and the rest as outside of this interconnected power system has installed

capacity about 7.1 GW. The largest installed capacity in the total power generation

Bengkulu

Bangka

Sumsel-Lampung

Ketapang

PontianakSingkawang

Banjar

Mahakam

Tarakan

Sorong

B-Aceh

Medan

Padang

BimaSumbawa

Kupang

Ambon

Serui

Minahasa

Kotamobagu

Palu

Gorontalo

Jayapura

1

2

3

4

5

6

7

8

Bengkulu

Bangka

Sumsel-Lampung

Ketapang

PontianakSingkawang

Ketapang

PontianakSingkawang

Banjar

Mahakam

Tarakan

Sorong

B-Aceh

Medan

B-Aceh

Medan

Padang

BimaSumbawa

Kupang

Ambon

Serui

Minahasa

Kotamobagu

Palu

Gorontalo

Jayapura

1

2

3

4

5

6

7

8

345678

21 Northern Sumatera System

Southern Sumatera Power SystemJawa – Bali Power SystemSouth & Central Kalimantan Power SystemWest Kalimantan Power SystemEast Kalimantan Power SystemSouth Sulawesi Power SystemNorth Sulawesi Power System

345678

21 Northern Sumatera System

Southern Sumatera Power SystemJawa – Bali Power SystemSouth & Central Kalimantan Power SystemWest Kalimantan Power SystemEast Kalimantan Power SystemSouth Sulawesi Power SystemNorth Sulawesi Power System

composition is steam coal power plants with installed capacity about 26%, and the

steam non-coal power plant is about 8%. The second largest power plant is the

combine cycle power plant with installed capacity about 29%. The installed capacity

of the open cycle and renewables power plants are about 10% and 15%. In this

composition, the role of diesel power plant is only about 12% of total installed

capacity.

The growth of electricity demand in Indonesia is expected to remain strong

despite the advent of global financial crisis. Prior to the East Asian crisis of 1998, the

demand growth had been very strong in the range between 10 to 14% per year and

only suppressed for one year in 1998. Soon afterward, the demand recovered quickly

and grew steadily at about 7% per year. It is believed that this growth could have been

higher if there were enough capacity available to satisfy the high demand growth. It

should be mentioned here that since the East Asian crisis of 1998, the Indonesia’s

power sector has been marred by under-investment, so that the required capacity

expansion could not be fully implemented. Somewhat similar situation was observed

under current global crisis.

A sharp decline of electricity demand has been observed since Q3 of 2008,

especially in high voltage industrial sector, whilst the demand in business and

residential sectors has been quite strong. The decline of industrial sector seems

already hit the bottom and start to level, and compensating this decline, the public

utility observes an increase in the demand for medium voltage commercial customers.

Long waiting list of both residential and commercial customers in the last few years

convinced PLN that the potential of demand growth in Indonesia has been and will be

quite strong for the next ten years at least. This has been supported by an independent

study showing that every 1% of economic growth will need 1.5% to 2.0% growth in

electricity.

Responding to the demand forecast to year 2018, PLN issued a Ten-Year

Electricity Development Plan in January 2009 (RUPTL 2009 – 2018). The plan was

prepared based on the least cost principle for fossil-fuelled power plants, but

incorporating a large amount of renewable energy, most notably geothermal. As much

as 5,000 MW of geothermal has been planned by PLN to year 2018. Even under high

energy price as happened in 2008, the energy mix for electricity production would be

dominated by coal if intervention were not made to introduce renewable energy.

By year 2018, the share of coal would reach 65% of the total fuel mix, while

the share of gas would be 17% in Jawa-Bali power system. At the same year, the

share of geothermal would be 11% but the share of hydro power would be stagnant at

2% due to the limited hydro power potential that can be developed without causing

profound social and environmental impacts.

The situation in islands outside Java-Bali would be different, in that more

geothermal and hydro power would take greater roles, especially in Sumatra and

Sulawesi, such that the share of hydro power and geothermal would reach 19% and

16%, respectively, while coal would remain dominant at 51%.

2.2.2 Indonesian Electricity Development

Energy sales in 2007 is about 121.2 TWh, with non coincident peak load

about 21.1 GW. The average energy sales growth over the last 5 years was about

7.6%. The yearly energy sales from 2003 to 2007 can be seen in Table 2.10 below.

Table 2.10 Yearly Energy Sales 2003-2007

PLN’s long-term power system development plan has been established

through systematic approach. The objective function of the capacity expansion plan is

to obtain least cost configuration of power plants development through optimization

process by using dynamic programming which meets the assigned reliability criteria.

The simulation of power plant development is formulated by using the associated cost

function of each generation units which give the minimum NPV as shown in equation

2.1 below.

Region Average

å=

-+++=n

iiValueSalvageCostENSCostFuelCostMOCostCapFObj

1

)&.(. … (2.1)

Where: § Obj. F = Total Cost of Power Plant Development

§ i = Years

§ n = Length of study period

A simplified description of the model for generation expansion planning is

shown in the Figure 2.21.

Figure 2.21 Input/Output Model for Generation Expansion Planning

In line with the above description, according to the Indonesia National

Electricity Development Plan, as Ten-Year Electricity Development Plan of PLN

(RUPTL 2009 - 2018), the long-term electricity development of Indonesia based on

projected demand growth about 9.7 % annually, with the energy demand in 2008 was

129 TWh, and would increase to 325 TWh in 2018. Additional capacity needed for

this demand is 57 GW, in which about 5 GW would be renewables power plants.

The result of long-term capacity expansion simulation has shown that mostly

the additional required power plants would be dominated by steam coal power plants.

In 2008, energy produced by coal power plant was about 46%, and in 2018 will be

Demand Forecast and Its characteristic

Existing capacity, Committed and Candidate Project

Economic ParameterReliability Criteria

(LOLP & ENS)

Model for Expansion Planning

(WASP IV)

Optimal Additional Capacity

Fuel Cost, O&M Cost

Check Reliability System

Check Operational Method

Investment Cost

Fuel Consumption CO2 Emission

INPUT

OUTPUT

Demand Forecast and Its characteristic

Existing capacity, Committed and Candidate Project

Economic ParameterReliability Criteria

(LOLP & ENS)

Model for Expansion Planning

(WASP IV)

Optimal Additional Capacity

Fuel Cost, O&M Cost

Check Reliability System

Check Operational Method

Investment Cost

Fuel Consumption CO2 Emission

INPUT

OUTPUT

about 63 %. Figure 2.22, shows us the projection of the primary energy composition

from 2009 to 2018.

The Jawa-Bali power system is still the largest interconnected power system in

Indonesia. It consumed about 80% of the total Indonesia electricity demand. In 2008,

its annual electricity energy demand was around 100 TWh and would increase up to

around 250 TWh in 2018. Power plant composition of Jawa-Bali power system is

dominated by steam coal power plants. Within period of 2009 to 2018, projected

additional capacity required is around 40 GW. The primary energy composition in

2018 is projected approximately 66 % coal, 17 % natural gas, 11% geothermal, and

the rest would be from hydro and LNG.

The second largest power system in Indonesia is Sumatera power system. It

consumed about 10% of the total Indonesia electricity demand. The annual electricity

consumption was around 18 TWh in 2008, and would increase up to around 44 TWh

in 2018. The required primary energy composition is projected approximately 45%

coal, 24% geothermal, 21 % hydro, and other sources such as natural gas and oil.

Kalimantan electricity system consists of 3 interconnected power systems.

One of them is West Kalimantan power system, dominated by diesel power plants

with its annual electricity demand was around 1 TWh in 2008, and would increase up

to around 3 TWh in 2018. It has been planned that in near future Sarawak power

system will be connected with this power system to expedite the access of electricity

in this region. South and East Kalimantan is the other interconnection power system.

It consumed about 4 TWh in 2008 and will increase up to around 13 TWh in 2018.

Kalimantan has been endowed with coal resources, so the required additional capacity

of this region will be dominated by coal power plants. The required primary energy

composition is projected approximately 82% coal, 10% natural gas, 3% hydro and 5%

oil.

Sulawesi electricity system has two interconnection power systems which are.

South Sulawesi and North Sulawesi power systems. South Sulawesi power system

consumed around 3 TWh in 2018 and would increase up to around 10 TWh in 2018.

Steam coal power plants and hydro power plants dominate in this power system. The

electricity demand of North Sulawesi power system was around 0.8 TWh in 2008 and

will increase up to around 2 TWh in 2018. The required additional capacity will be

dominated by coal and geothermal power plants. The required primary energy

composition is projected approximately 37% coal, 36% of hydro, 15% natural gas, 8%

geothermal and 4% oil.

Figure 2.22 The composition of Power Plants 2008 – 2018 Based on Energy Primary Used (RUPTL 2009 – 2018)

2.2.3 Projection of CO2 Emission

The long-term projection of CO2 emissions from power sector under scenario

BAU (Business as Usual) which derived from capacity expansion plan up to 2018 will

be described more in detail in which CO2 sources from major interconnected power

systems will be elaborated further. This feature will be matched with identification of

geological potential reservoirs.

Although the level of CO2 emissions has not been considered in the objective

function of the capacity expansion plan, however this important environmental

variable is not neglected totally. The geothermal and hydro power plants have been

categorized as high priority power plants in the optimization process. Furthermore for

coal power plant with supercritical boiler has been entered as a part of capacity

expansion plan particularly in Jawa-Bali power system as an effort to increase

efficiency level of power plant.

The CO2 emissions from the power plants were calculated by certain

assumptions. The key assumptions have been taken from the 2006 IPCC Guidelines

for National Greenhouse Gas Inventories. As depicted by Table 2.11, the emission

2008

HSD 16%

MFO 9%

GAS17%

LNG0%

BATUBARA 46%

HYDRO 7%

PUMPED STORAGE

0%

GEOTHERMAL 5%

NUCLEAR0%

2018

HSD 1%

MFO 0%

GAS15%

LNG2%

BATUBARA 63%

HYDRO 6%

PUMPED STORAGE

1%

GEOTHERMAL 12%

NUCLEAR0%

COAL

COAL

-

50,000

100,000

150,000

200,000

250,000

300,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Year

Em

issi

on

CO

2 (t

CO

2)

Jawa - Bali Sumatera Kalimantan Sulawesi

factor for each of primary energy were applied according to the type of power plants.

Projection of CO2 emissions were calculated particularly for the interconnection

power systems in the main islands of Indonesia which are Jawa-Bali, Sumatera,

Kalimantan, and Sulawesi in which the associated results can be seen in Figure 2.23.

Table 2.11 Emission factor base on 2006 IPCC Guidelines for National GHG Inventories

Figure 2.23 CO2 Emission in Interconnection Power System

The projection of the total accumulated CO2 emissions for 4 islands above

from 2008 up to 2018 are shown in the Table 2.12 below.

Table 2.12 Total Accumulated CO2 Emissions

No Interconnection Power System

CO2 emission (Million Tones)

1 Jawa - Bali 1,652.0 2 Sumatera 158.7 3 Kalimantan 93.0 4 Sulawesi 34.7

Total 1,938.5

Fuel Oxidation Factor

MFO 40,766.7 KJ/liter 21.1 tC/TJ 100%

IDO 37,219.1 KJ/liter 20.2 tC/TJ 100%

HSD 36,757.9 KJ/liter 20.2 tC/TJ 100%

Coal 21,080.5 KJ/Kg 25.8 tC/TJ 100%

Natural Gas 1,148.1 BTU/SCF 15.3 tC/TJ 100%

NCV Emission Factor

Total projection of CO2 emissions by power plants in Indonesia was estimated

around 116 million tonnes in 2008, and would increase up to 270 million tonnes in

2018. Approximately 228 tonnes would be contributed by coal combustion which is

about 85% of the total emissions since the role of coal power plants will be dominant

in the long-term.

The average grid emission factor for Indonesia in 2008 is 0.787 kgCO2/kWh,

and in 2018 would become 0.741 kgCO2/kWh. The reduction of average grid

emission factor is mainly caused by the increased use of natural gas, renewables

energy, and introduction of super-critical boilers for large coal plants from year 2014

onwards as mentioned above. The role of renewable power plan is about 12 % in 2008

and would be around 17 % in 2018.

CHAPTER 3

CAPTURE TECHNOLOGY

3.1 Introduction to CO2 Capture

In order to prevent carbon dioxide (CO2) from anthropogenic sources reaching

the atmosphere, it must first be captured and then stored underground. Capture

involves separating the CO2 from the other components of a gas stream; the gas

stream may be the products of combustion or the fuel gas before combustion. After

separation the CO2 will need some preparation before being sent to storage; at the

very least this will involve compression to high pressure in order to economize on

transport and storage.

Various different technologies can be used for separating CO2 – the principal

methods are solvent absorption, solid adsorption, semi-permeable membranes and

cryogenic cooling. These will be described in this chapter, together with the ways

that they might be applied. After that, the ways of incorporating them into power

plants and other systems will be discussed including the health, safety and

environmental implications of CO2 capture. Finally some illustrations will be

presented of how CO2 capture might be used in Indonesia.

A necessary part of any CO2 capture and storage system is the compressor

which is used to pressurise the CO2 for transport - this is described in chapter 4 but,

by convention, its capital cost and electricity consumption are included in the cost of

the capture plant.

3.1.1 Issues for Capture of CO2

Factors that strongly influence the choice of separation technology include:

§ The concentration of CO2 in the gas stream - the higher the concentration, the

easier it is to separate the CO2;

§ The pressure of the gas stream – a higher pressure will make it easier to

separate CO2;

§ The composition of the gas stream itself e.g. its purity and its oxidising or

reducing nature - impurities in the gas stream may adversely affect the

separation of CO2, especially the durability of the process equipment; an

oxidative environment can cause degradation of components of certain capture

systems.

Capture can be done in various ways; for example, with a combustion process

it may be done:

§ Either after combustion, where the task is to separate CO2 from a mixture of

gases, principally nitrogen (as this is part of the air used for combustion); this

is referred to as post-combustion capture,

§ or by prior treatment of the fuel or syngas, before any mixing with nitrogen

has taken place, known as pre-combustion capture,

§ or by changing the combustion conditions to make for easier separation, by

keeping N2 out of the process entirely; in this case, a replacement may be

needed for the N2 to moderate the combustion temperature.

CO2 may also be captured from sources that do not involve combustion, for

example the “sweetening” of natural gas by removal of acid gases. In such cases,

separation is done using methods similar to those used for post-combustion removal

of CO2.

3.1.2 Characteristics of CO2 Sources

The concentrations of CO2 in gas streams from various possible sources are

illustrated in Table 3.1. Most of these gas streams are at or near atmospheric pressure

for the simple reason that they are exhaust streams from industrial processes. If the

industrial process can be adapted to produce a higher pressure exhaust stream, this

may be advantageous for capturing CO2, as will be illustrated later.

Table 3.1 Typical CO2 concentrations for various potential sources (IPCC, 2005 and other sources)

CO2 concentration

by volume Note

Combustion of fossil fuels (for power or heat)

3 - 15% Varies with fuel used

Cement production - kiln exhaust

14 - 33 % Includes CO2 released by calcination of raw materials as well as fuel

Steel production – blast furnace c.20% There is also c.20% CO which could be converted for capture

Ammonia production 20 – c.100% In many plants, CO2 is not released but used for urea manufacture

Hydrogen production 25% - c.100% Older H2 plant may emit high concentration CO2 but newer plants have lower concentrations

Natural gas sweetening up to 100% CO2 is removed in the sweetening process and expelled as a concentrated stream

Refinery processes from 3% to c.100% Depends on refinery unit Fermentation up to 100%

Some of these processes produce exhaust gases with significant levels of

acidic components (e.g. refineries) or particulates (e.g. blast furnaces, cement kilns),

so additional clean-up will be required before CO2 capture.

Although the concentration of CO2 in the gas stream from a power plant is

quite low, there are opportunities for changing the process, so as to increase the CO2

concentration and raise the pressure, as will be discussed later.

3.2 Introduction to CO2 Separation Methods

In this section the various methods of separating CO2 will be introduced.

3.2.1 Options

Broadly there are 4 types of CO2 separation technology: solvent absorption,

solid adsorption, cryogenic and membrane separations.

The performance and cost effectiveness of a separation process is mainly

determined by the degree of recovery that can be achieved and the purity of the CO2

product, factors which strongly influence the capital cost of the equipment and the

energy required to operate it. In some circumstances, a high degree of recovery can

only be achieved at the expense of product purity.

3.2.2 Solvent Absorption Separation

CO2 is captured by absorption by a solvent in a continuous process which

involves re-circulation of the solvent between an absorber (where the CO2 is taken

out of the process stream) and a regenerator, where a concentrated stream of CO2 is

released. Some processes use chemical solvents for this purpose and others use

physical solvents – each has advantages for particular applications. Both can be

configured to achieve high degrees of recovery and high product purity.

3.2.2.1 Chemical Solvents

With a chemical solvent, the CO2 is captured by a chemical reaction; the

solvent is regenerated by heating and pressure reduction. Such processes are best

suited to removing CO2 at lower partial pressures (typically less than 100kPa) where

other separation processes are less effective (IPCC, 2005). For example, this is the

preferred approach for post-combustion capture because chemical solvents are able to

extract CO2 that is present in low concentrations in flue gas streams at near

atmospheric pressure. A wide range of chemical solvents are commercially available

for this purpose; some are listed in Table 3.2.

Mono-ethanolamine (MEA) is a widely used solvent. However, it is

handicapped by low CO2 loading (i.e. the amount of CO2 taken up by a unit of

solution), by the potential for equipment corrosion and amine degradation due to SO2

and O2 in the gas stream. In addition, MEA-capture has relatively high energy

consumption for regeneration of the solvent. Activated methyldiethanolamine

(aMDEA) is a proprietary solvent which can be designed for use with a specific acid

gas component with high selectivity; it can handle high loading of CO2 with relatively

small requirement for regenerator heating (IPCC, 2005). Some modern ammonia

production plants, especially those using natural gas feedstock, employ an amine

solvent-based process to separate CO2 (IPCC, 2005). Hot potassium carbonate is

another solvent that had been used for CO2 removal, especially in hydrogen

production.

Table 3.2 Some chemical solvents used for removal of CO2

Recent developments have focussed on novel proprietary solvents with higher

performance, such as sterically-hindered amines, and on use of ammonia as a solvent.

Protective agents to control corrosion and degradation will be added to most

solvents by the manufacturer. Additional components will be included in the system

design for removing corrosion and degradation products and solid particles, and to

make up for any shortfall in the amount of solvent.

3.2.2.2 Physical Solvents

Physical solvents are used with gas streams having relatively high CO2 partial

pressure (> 0.2 MPa) and/or high system pressure (IPCC, 2005). Regeneration of the

solvent is achieved by release of pressure, in one or more stages. For deeper

regeneration of the solvent, additional heating is applied. One process (Rectisol) uses

a methanol wash which requires refrigeration. Energy is also used for pumping the

solvent but even so the efficiency penalty can be significantly less than with a

chemical solvent. Some of the proprietary physical solvents currently available are

listed in Table 3.3.

Table 3.3 Some physical solvents used for removal of CO2

Chemical Proprietary name Vendor Methanol Rectisol Lurgi / Linde, Germany N-methyl-2-pyrolidone (NMP)

Purisol Lurgi, Germany

Dimethyl ethers of polyethylene glycol

Selexol Union Carbide, USA

Chemical Proprietary name Process vendors Monoethanolamine AmineGuard FS/Ucarsol UOP/Dow, USA Econamine Fluor, USA

aMDEA BASF, Germany Activated Methyldiethanolamine Elf, France UOP, USA Proprietary mixture of sterically-hindered amines

KS-1 MHI, Japan

Ammonia-based solution Alstom, Powerspan Potassium carbonate Benfield UOP, USA

3.2.3 Solid Adsorption Separation

CO2 can be captured by adsorption onto a solid, typically in a cyclic process

where the solid is subsequently regenerated either by pressure reduction or

temperature increase. These 2 regeneration options are known as pressure swing

adsorption (PSA) or temperature swing adsorption (TSA) respectively. Another

method of regeneration would be to use a sweep gas to clean the adsorbent but this is

not considered here because this would contaminate the CO2.

PSA is the preferred method of regeneration where high purity H2 is required

from the process; this approach is used in steam methane reforming (SMR) for H2

production. However, PSA is not highly selective for CO2 so the purity of the CO2 in

the waste stream of the SMR plant may be only 40-50% (IPCC, 2005), making it

necessary to purify the CO2 before sending it to storage.

A review of potential adsorbents for CO2 (Yong and Rodrigues, 2001) -

summarised in Ritter and Ebner (2005) - concluded that, at ambient temperature,

activated carbons and zeolites are superior to metal oxides and hydro-talcite

compounds for adsorption of CO2 from syngas (a mixture of H2, CO, CO2 and H2O as

would be found in pre-combustion capture schemes); at high temperatures, metal

oxides and hydrotalcite compounds show advantages (Reynolds et al., 2005).

However, adsorption capacity declines with temperature in all cases as shown in

Table 3.4; adsorbents for use at high temperatures are still in laboratory development.

Table 3.4 Performance of typical adsorbents showing the effect of temperature

TSA has been found (IEA GHG, 1993) to incur large energy penalty and has

only slow regeneration; it achieves only relatively moderate levels of CO2 recovery

(i.e. about 50%); the adsorbent must be capable of many cycles without degradation,

which is a very demanding requirement; for these reasons, TSA is not likely to be

competitive and is not discussed further here. The same study for the IEA Greenhouse

Gas R&D Programme (IEA GHG, 1993) concluded that adsorbents are most effective

Temperature oC

Adsorption capacity mol CO2/kg

25 1.5 - 2.0 Activated carbons 250 - 300 0.1 - 0.2

25 3 5A zeolite 250 0.2

for CO2 removal when the CO2 content of the process stream is between 400 ppm and

1.5%.

3.2.4 Membrane Separation

In gas separation membranes, one of the components present in a gas mixture

permeates faster through the membrane than the other. The driving force is the

difference in partial pressure across the membrane. The selectivity of the membrane

must be high; if it is not high enough, a multi-stage plant will be required, perhaps

with recycle of the permeate to improve the purity of the final product stream but this

would raise the capital cost of the process. Selectivity greater than 50 is needed to

achieve an efficient process for CO2 capture (Feron et al., 1992).

This can be illustrated (Fig. 3.1) using a simulation of a conceptual membrane

system for separating the components of a H2/CO2 gas stream (Goldthorpe, private

communication)/ In this simulation the separation process has been divided into 100

sequential stages. At each stage the flow of the gas mixture has been calculated,

depending on the selectivity of the membrane, and the composition of the remaining

gas has been determined before it passes onto the next stage.

80.0%

82.0%

84.0%

86.0%

88.0%

90.0%

92.0%

94.0%

96.0%

98.0%

100.0%

80.0% 82.0% 84.0% 86.0% 88.0% 90.0% 92.0% 94.0% 96.0% 98.0% 100.0%

Energy in H2 stream

CO

2 in

CO

2 st

ream

selectivity = 200

selectivity = 50

selectiivty = 22

selectivity = 10

Figure 3.1 Simulation of membrane separation of CO2 from H2 at different levels of

selectivity

Figure 3.1 shows that if 50:1 selectivity can be achieved, 85% CO2 capture

would result in only a 2% loss of H2 in the separated CO2. However, such membranes

are still being researched and are not yet available for commercial application. If a

higher degree of separation is required (e.g. 95% CO2 capture with only a 2% loss),

then selectivity would need to be of the order of 200:1. Membranes with such high

levels of selectivity have not yet been developed.

Where there is a high concentration of CO2, as may be the case in natural gas

sweetening, membrane systems may be more economical than solvent absorption

(IPCC, 2005), especially in remote locations where utility services are not available.

3.2.4.1 Membrane Performance

A wide range of polymeric membranes have been developed for gas

separation. Materials can be chosen that are selective for CO2 or selective for another

component, such as H2. For example, poly-dimethylsiloxane membranes have

selectivity of 5 for CO2 whilst polyimide membranes have selectivity of 10 for H2; the

latter are used in refineries and chemical plants to recover H2. However, in a range of

polymeric membranes surveyed by Ritter and Ebner (2005), selectivity for H2 over

CO2 did not exceed 15.

Rubber-type membranes have shown CO2/H2 selectivities of about 10 with

modest CO2 permeability; cross-linked polyethylene glycol membranes show similar

selectivity but reduced CO2 permeability (Ritter and Ebner, 2005). A few glassy

polymer membranes show high selectivity towards heavier gases but these materials

are still in the laboratory. The low values of selectivity for current materials suggest

they would not be very competitive for CO2 removal compared with other separation

techniques.

3.2.4.2 Novel Membrane Configurations

There are many ideas for alternative configurations to improve the

performance of membrane separations; some of them might be applicable to the

separation of CO2, especially where CO2 has to be separated from H2 in a syngas

mixture. For example:

§ Facilitated transport membranes rely on the formation of reversible chemical

compounds from a reaction between a component of the gas stream and the

membrane material. The reaction products are then transported through the

membrane. Many variants have been tried in the laboratory but these

membranes are still under development. Although selectivity seems to be

high, increased feed pressure reduces selectivity due to increased physical

absorption of the slower permeating compound.

§ Molecular sieves have pores that are designed to be similar in size to the

smaller of the molecular species to be separated (e.g. H2). This can be used to

make hydrogen-permeable membranes although these materials also allow

molecules other than H2 to pass through them. A target application is high

temperature gas-phase catalytic reactions; such membranes are expected to

have high selectivity but their behaviour at high pressure and their durability

are still being investigated.

§ Palladium-based membranes (either pure Pd or Pd/Ag alloy) are able to

separate H2 exclusively, making them useful for separating H2 from syngas at

high temperatures, especially in reactor vessels. However, their stability needs

to be demonstrated and the cost of these membranes makes it difficult to

justify them for CO2 separation.

§ A membrane absorber can be used in conjunction with a solvent instead of the

conventional absorber in a solvent absorption system - this is referred to as a

solvent-assisted membrane. It has been demonstrated with chemical solvents

up to industrial pilot scale (Falk-Pedersen, et al., 2001) but the advantages

over conventional chemical solvent absorption were not sufficient to justify

commercial exploitation of the new process.

Despite the range of industrial experience with membranes, they have not yet

been applied at the large scale required for CO2 capture in power generation, nor have

they been shown to satisfy the stringent requirements of reliability and low-cost

needed for this application (IPCC, 2005).

3.2.5 Cryogenic Separation

Carbon dioxide can be physically separated from other gases using low

temperatures to condense the CO2. The greatest removal of CO2 would be achieved by

using the lowest possible temperature. However, the triple point of CO2 (-56.6oC at

0.518 MPa) is indicative of the extent to which the temperature can be reduced before

the CO2 would freeze out. For a feed gas containing 40% CO2 at 2 MPa pressure, use

of a refrigeration temperature of -50oC would achieve about 70% recovery of the CO2

(IEA GHG, 1993). Raising the feed pressure to 8 MPa would allow more than 80%

of the CO2 to be recovered but even this would not be enough for CO2 capture and

storage purposes. Lower concentrations of CO2 may suffer from even less effective

separation. Thus cryogenic separation would only be competitive for CO2 separation

at high concentrations. In addition, a simple refrigeration process would be

insufficient to achieve high recovery of CO2.

Agarwal (2004) illustrated a possible application of cryogenic separation of

CO2 in conjunction with H2 production where an initial separation (such as by use of

membranes) raised the concentration of CO2 from 18 to 36 mol. percent. Cryogenic

separation would allow CO2 concentrations in the gas to be reduced to 15% by

chilling of the high pressure gas at the front end of the process. This would also

provide high pressure CO2 thereby reducing the power consumption of the subsequent

CO2 compressor. The remaining CO2 could then be recovered by use of PSA.

The limitations of a simple refrigeration process can be overcome by use of a

more complex process, such as the Ryan-Holmes process. This uses an intermediate

solvent such as propane to change the conditions for absorption of CO2 and overcome

problems if methane is present (as this would solidify with CO2 in a binary mixture),

thereby improving CO2 recovery.

In principle, cryogenics should be able to achieve recovery of more than 90%

of the CO2 in a gas stream. In practice, use of cryogenics is typically only considered

for use with gas streams containing more than about 40% CO2 where it should be

competitive with use of solvents1. It has not yet been used for capture from

combustion systems but cryogenic separation has been included in plans for the

separation of CO2 from natural gas (containing 70% CO2) produced from the Natuna

gas field but this scheme has not yet been implemented (Shook, 2008).

3.3 Application of CO2 Capture in Power Plants

The separation techniques described above may be applied in various ways to

capture CO2 for storage. The main options are:

§ Post-combustion

1 Sustainable Energy Solutions has recently announced a cryogenic separation system which is said to be suitable for use for flue gases but no independent analysis of the performance of this system has been reported yet.

§ Pre-combustion

§ or under Modified combustion conditions

These are discussed below, specifically in relation to use in power plants.

3.3.1 Post-combustion Removal

Most large fossil-fuel power plants either raise steam in a boiler to drive a

steam turbine to power the electricity generator, or produce a hot gas stream to drive a

gas turbine, with subsequent recovery of waste heat using a steam turbine, both of

which power the generator(s). The main fuels are natural gas and coal, and to a lesser

extent oil; biomass is starting to be used in large-scale power generation in many

Western countries. The 2 main types of plant are:

§ Coal-fired steam-cycle – this discussion will focus on the modern

supercritical2 steam-cycle using pulverised fuel (SC PF) burning bituminous

coal

§ Natural gas-fired combined cycle (NGCC)

The concentration of CO2 ranges from a very low level in the exhaust of a gas

turbine (c.3%) to a moderate level in the exhaust of a PF plant (c.14%).

Modern coal-fired power plants incorporate exhaust systems to trap

particulates and remove oxides of sulphur. In both SC PF and NGCC plants, the

combustion systems are designed to reduce the amount of nitrogen oxides that would

be formed. Other systems burn oil fuel in similar configurations or in reciprocating

engines but the latter are relatively small, where it would be relatively expensive to

capture CO2.

Post-combustion removal of CO2 involves adding separation equipment after

the other exhaust clean-up processes, just before the flue gases are sent to the stack

(see Fig 3.2). After separation the CO2 would be dried and compressed for transport.

3.3.1.1 CO2 Separation

The flue gases in a SC PF or NGCC are close to atmospheric pressure and

largely composed of N2; consequently the volumes to be handled are very large,

necessitating large ductwork and large units in the separation plant. Although no full

2 In a steam-cycle, the steam may be in a sub-critical state, as has been the standard for many years, or in a super-critical or ultra-supercritical state, which will improve the thermal efficiency of the power plant.

scale CO2 capture plants have yet been built for post-combustion removal, several

power plants have been fitted with CO2 separation on a part of the flue gas stream.

These units all use the chemical solvent separation process (see section 3.2.2.1) which

seems to be the best option for this purpose (Kohl and Nielsen, 1997) in view of the

low partial pressure of CO2 (less than 15 kPa). Physical solvents would not be

favoured because of the low pressure of the flue gas; nor would membranes, for the

same reason. Adsorbents have been proposed for this task but do not demonstrate a

clear advantage over chemical solvents (IEA GHG, 1993). Cryogenics would be

quite unsuitable because of the large amount of other gases in the flue gas stream.

Figure 3.2 Schematic diagram of post-combustion capture of CO2

3.3.1.2 Using Chemical Solvent Separation in Power Plants

The flue gas from the power plant may need to be cooled before entering the

chemical solvent scrubbing unit. This unit consists of separate towers for the absorber

and the regenerator, with solvent recirculation and cooling equipment, as well as a

means of adding additional solvent to make up for any losses. If the flue gas contains

acid components, such as NOx and SOx, these will have to be removed to a high

degree in order to protect the solvent against chemical degradation and formation of

heat stable salts. The danger of solvent degradation due to sulphur is more serious in

coal-fired power stations than in gas-fired power stations (where there will only be

Transport system

Pulverized Fuel

Air

Flue gas

Boiler Steam

Remaining flue gas

CO2

To stack

Turbo-generator

CO2 Separation

NOx contaminants in the flue gas). The acceptable level of SOx is determined by the

costs of solvent make-up and waste disposal – for MEA-based processes, some

proprietary solvents require SOx levels below 10 ppm; others may be able to tolerate

50 ppm (IPCC, 2005). Such low levels of SOx may not be achieved by a conventional

flue gas desulphurisation process, in which case additional sulphur removal would be

needed, using alkaline salt solutions in a pre-scrubber.

Up to 95% of the CO2 can be recovered from the flue gases – the exact

proportion is decided from an optimisation of the degree of recovery and the cost.

The purity of the CO2 produced by chemical solvent scrubbing can be very high – up

to 99.9% (IPCC, 2005). A further purification step can be used to raise the purity to

food grade levels, which is one of the main markets for CO2 at present.

The solvent regenerator is supplied with steam from the power plant. If the

steam is taken from the low pressure steam circuit, this reduces the electrical output of

the plant, necessitating consumption of more fuel, either in this plant or at another

power plant elsewhere on the grid.

The Future of Coal study (MIT, 2007) estimated that the extra energy needed

for regenerating the solvent would reduce the efficiency of an SC PF plant with post-

combustion capture (90% CO2 capture) by 5.6%-points3 below that of a SC PF plant

without capture; the energy needed for compression for transport would account for a

further 3.6%-points reduction. The IEA Greenhouse Gas R&D Programme

(IEAGHG, 2004) found a 5.2%-points reduction in efficiency as a result of post-

combustion capture using Fluor’s Econamine process but the proportion of CO2

captured was slightly less (87.5%) than in the MIT study; the energy used by the CO2

compressor accounted for about 4%-points further reduction in efficiency; a similar

post-combustion capture system but using the newer KS-1 solvent showed a lower

energy penalty of 4.4%-points.

In an NGCC the partial pressure of CO2 in the exhaust gases is lower than in a

SC PF – this means that even larger volumes of flue gas must be handled to extract

small amounts of CO2. As the fuel is relatively clean, little pre-treatment is needed to

protect the chemical solvent. The efficiency penalty for post-combustion capture

using Fluor’s Econamine process was found to be 6.2%-points (IEA GHG, 2004); use

of the KS-1 solvent incurred a smaller energy penalty of 4.0%-points; the CO2 3 For example, a 5.6%-point reduction would be the result of reducing efficiency from 40% to 34.4%.

compressor accounted for another 2%-points drop in efficiency; thus the newer

solvent (KS-1) could reduce the energy required for capture in a NGCC by about one-

third.

More than 28 plants have been built around the world using chemical solvent

scrubbing of flue gas streams (with both coal and gas fuels); most have capacity of

less than 100t/d but one captured as much as 1000t/d4, amounting to around 60% of

the CO2 in the flue gases from a natural gas fired power plant. This demonstrates a

level of commercial experience which is not matched by many of the competing

separation technologies. Even so, it would be necessary to increase capacity of the

separation plant by an order of magnitude in order to be able to cope with the whole

flue gas stream of a coal-fired power station. This could involve building absorption

towers with diameter about 15m, something which has already been done for amine

scrubbing processes used in the chemical industry (IEA GHG, 2004). This gives

confidence that chemical solvent absorption processes should be able to deliver

reliable and economical CO2 separation. Ongoing development programmes are

reducing the additional cost of such systems.

3.3.2 Pre-combustion Removal

In order to remove CO2 before combustion, the fuel is first converted into a

gas from which the CO2 can be separated. The concentration of CO2 can be

engineered to be quite high (c.40%) so making capture easier, which is also helped by

producing the fuel gas at elevated pressure.

For conversion of coal, a gasifier is used to partially oxidise the fuel,

producing a syngas consisting mainly of CO, CO2, H2 and H2O. Three designs of

gasifier account for 94% of the world syngas market (NETL, 2004): those designed

by Sasol/Lurgi, GE and Shell. Of these the Sasol/Lurgi gasifier has not been used in

power generation, so the focus of the discussion here will be on the other two. These

are entrained flow gasifiers (i.e. where the fuel and the oxidizing gas flow into the

gasifier in parallel streams); they can be used in a variety of configurations which

provides a broad range of options for CO2 capture. Important differences between the

Shell and GE designs include the method of introducing the coal (dry or slurry feed 4 It is not known to the author whether any CO2 separation plants have been constructed in Indonesia but it is likely that small plants (<100t/d) may have been installed in the same way that they have been constructed in many countries to serve the food industry.

respectively), and the method of cooling the synthesis gas produced (heat exchange or

quench with water respectively). These differences have implications for the thermal

efficiency of the plant and for the extra energy used when CO2 capture is added to the

design.

Similar processes could be used with other fuels as will be discussed below. 3.3.2.1 Coal gasification-Based Power Generation

A coal-fuelled power plant using gasification is typically referred to as an

Integrated Gasification Combined Cycle (IGCC) plant. The IGCC has been

developed over the past 40 years in order to generate electricity at higher efficiency

and with lower emissions than conventional pulverised coal-fired plant, together with

the potential to capture CO2 (although this has not yet been done in practice). As a

result the IGCC has the prospect of becoming one of the most efficient and least

polluting types of coal-power station in future.

A schematic diagram of an IGCC is shown in Figure 3.3. Coal is prepared and

supplied to the gasifier which is fed with oxygen from the air separation unit (ASU).

The air separation unit is supplied with air under pressure, perhaps from the IGCC’s

gas turbine. The synthesis gas (syngas) consists largely of CO, CO2, H2, H2O and

various other components, which vary between different types of gasifier. The syngas

must be cleaned prior to supply to the gas turbine for electricity generation; some of

the nitrogen produced by the ASU may be fed to the gas turbine to moderate

combustion temperature. Exhaust gases from the gas turbine are passed to the heat

recovery steam generator (HRSG) which supplies a steam turbine, generating

additional electricity.

In a variant of this process, the gasifier is supplied with air rather than oxygen.

Such air-blown gasifiers have been developed in USA, Japan and China. One US

electricity company continues to support the development of an air-blown gasifier

because of the higher efficiency this gives the IGCC.

Several demonstration IGCCs have been constructed in Europe, USA and

Japan with mixed results but no follow-up orders had been placed by electricity

companies until recently. This is mainly because of lack of experience with this type

of plant, its perceived unreliability and its higher cost than conventional pulverized

coal-fired power plant. With the attention now being given to tackling CO2

emissions, electricity companies in many countries have recently announced plans to

construct IGCCs with the potential to fit CO2 capture. No IGCCs have yet been

constructed which capture CO2 but several installations of this type are planned.

Figure 3.3 Schematic diagram of IGCC using oxygen-blown gasifier

3.3.2.2 Addition of CO2 Capture to IGCC

Addition of CO2 capture to an IGCC design involves incorporating a catalytic

shift converter to convert the CO to CO2 (and thereby producing a high concentration

of CO2 in a high pressure gas stream). This means that a physical solvent can be used

for capture; regeneration of such solvents can largely be achieved by pressure

reduction rather than by use of heat from the plant, thereby imposing less penalty on

efficiency; the additional cost of this type of capture is less than that of post-

combustion capture in a pulverised coal-fired power plant. As a result, although the

basic IGCC plant is more expensive than a conventional pulverised coal-fired power

plant, the overall costs of building and operating SC PF or IGCC plant fitted with

capture are expected to be broadly similar in Europe and USA.

The above remarks apply to an IGCC with an oxygen-blown gasifier; using

capture with an air-blown gasifier presents a similar situation to capture in a

pulverised coal-fired plant, so the separation of CO2 must be done in the presence of a

large amount of nitrogen. As a result, capture in an IGCC with an air-blown gasifier

would be much more expensive than one with an oxygen-blown gasifier. This would

Syngas

Gas turbine-generator

Coal

Air

Gasification

To stack

Turbo-generator

Preparation

ASU

N2

Acid gas removal

Sulphur recovery N2

O2

HRSG

Cleaned syngas

Steam

remove one of the main reasons for considering IGCC for capture so the air-blown

gasifier is not discussed further here.

3.3.2.3 Catalytic Shift Conversion

The purpose of the shift conversion stage is to convert much of the carbon

monoxide present in the syngas (together with some water vapour) to CO2 and

hydrogen (Figure 3.4). The resulting shifted-water-gas contains around 40% CO2 by

volume (at partial pressure of 0.8 to 1 MPa) with most of the rest being hydrogen. If

the sulphur removal is done before the shift, the latter is referred to as “clean” or

“sweet” shift. The alternative is for the shift conversion stage to be placed before the

removal of sulphur (Figure 3.5) which is referred to as “sour” shift.

Figure 3.4 IGCC with sweet shift, CO2 capture and compression

The attractiveness of sweet or sour shift depends on the method of application

(Weishaupt, 2006) such as the sulphur content of the syngas, the degree of CO

conversion required (clean shift can achieve lower levels of CO for a given amount of

steam), the ease of start-up of the plant and the durability of the catalysts (both of the

latter aspects favour sour shift).

Sour shift is strongly preferred for use with the GE gasifier (because of the

presence of steam in the syngas) but there is not such a clear distinction in the Shell

case. Sour shift has the advantage that removal of sulphur (in the form of H2S) and

Syngas

Gas turbine-generator

Coal

To CO2 transport system

Air

Steam

Gasification

To stack

Turbo-generator

CO2

CO2 Separation

Preparation

ASU

N2

Shift reactor

H2S removal

Sulphur recovery N2

O2

HRSG

H2

Steam

CO2 can be combined in the same unit; if the sulphur can be disposed of with the CO2,

this could have particular advantages but, even if the two gases have to be handled

separately, there may still be a benefit. Otherwise, chemical solvent scrubbing may

be used to remove sulphur from the shifted syngas before the CO2 is separated.

Use of a shift reactor reduces the power output of the IGCC by about 5% but

there may be some compensating benefits in system design – in fact this approach has

been proposed for use in one design of IGCC even without the use of CO2 capture

(O’Keefe et al., 2002).

Figure 3.5 IGCC with sour shift, CO2 removal and compression

After the shift conversion reactor, the CO2 is separated and compressed for

transportation to the storage site. The fuel gas resulting from CO2 separation is mainly

hydrogen which is supplied to the gas turbine. Nitrogen from the air separation unit is

also provided to the gas turbine in order to moderate combustion temperature.

3.3.2.4 Modifications Required to the Gas Turbine in an IGCC with Capture

The gas turbine is a key component of the IGCC. In existing IGCC designs

the gas turbine burns syngas – as the syngas has lower calorific value than natural gas,

some modifications need to be made to turbines originally designed to burn natural

gas. However, in an IGCC fitted with capture, the fuel for the gas turbine would be

mainly hydrogen. Hydrogen has very different characteristics from natural gas as a

Gas turbine-generator

Coal Syngas

To CO2 transport system

Air

Steam

Gasification

To stack

Turbo-generator

CO2

H2S & CO2 Separation

Preparation

ASU

N2

Shift reactor

COS hyrolysis

Sulphur recovery

N2

O2

HRSG

H2

Steam

fuel for a gas turbine – this presents challenges to the gas turbine designer but the

industry has experience of other relevant applications which is enabling it to adapt

standard gas turbines for use with H2-rich fuels. In particular, H2 can be diluted with

gases such as nitrogen or steam, making a fuel that is more compatible with current

gas turbines.

Gasification-derived fuel has been used in gas turbines in oil refineries and

petrochemical plants for more than 15 years (Shilling and Lee, 2003). However, the

most advanced and efficient turbines, such as the FA and FB series, which have

higher firing temperatures, would require some alterations in order to burn high levels

of H2. The reason for this is largely to do with the design of the “premix” combustors

which were originally developed to burn natural gas with minimal NOx emissions.

These combustors are limited to a maximum H2 content of 10% due to the potential

for flashback (Moliere, 2004). For higher H2 content fuels, the older “diffusion”

burner must be used which produces more NOx (Shilling and Jones, 2004). Dilution

of the hydrogen with N2 would have to be used to reduce NOx levels which would

reduce the efficiency of the turbine and could reduce the life of key components.

Development programmes are underway in Europe and USA to adapt gas turbines to

use H2-based fuel at higher efficiency but, for the present, an IGCC with capture

would not use the most efficient gas turbines.

3.3.2.5 CO2 Separation Processes for IGCC with Shift

The choice of separation technology for an IGCC is influenced by the

relatively low contamination of the CO2 as well as the need for a high degree of

recovery; this points to the use of solvent processes; chemical solvents could be used

but the preferred choice is a physical solvent that can take advantage of the elevated

pressure of the syngas; examples include Rectisol, Selexol and Purisol (see Table 3.3).

Sulphur-containing compounds may be removed before CO2 separation; this can be

done with a chemical solvent developed specifically for this task (Table 3.5).

Alternatively, a similar solvent as used for removing CO2, such as Selexol or

aMDEA, can be used.

Table 3.5 Some chemical solvents developed for removal of sulphur compounds

Chemical Proprietary name Process vendors

A mixture of tetrahydrothiophene 1,1-dioxide and water

Sulfinol Shell, Netherlands

Severely hindered amine Flexsorb ExxonMobil, USA

In the studies considered in IPCC (2005), the efficiency penalty for CO2

capture in an IGCC ranged from 5 to 8% points (including the energy used for CO2

compression).

Physical solvent scrubbers have already been constructed in the necessary size

for use in an IGCC – these are used for removal of CO2 after coal gasification, for

example in plants designed to make substitute natural gas or liquid transport fuels.

The coal gasification plant at Beulah, North Dakota uses a Rectisol unit to capture 3.3

Mt CO2/year, a capacity similar to what would be needed in a full size IGCC.

3.3.2.6 Pre-combustion Removal of CO2 with Other Fuels

Many schemes have also been proposed for use of pre-combustion removal of

CO2 with natural gas fuel. The options for fuel processing are: steam-methane

reforming (SMR); partial oxidation (POX); auto-thermal reforming, which is a

combination of SMR and POX.

In steam reforming, a high temperature (800-900oC) reaction converts the fuel

and steam, in the presence of a catalyst, into a mixture of H2 and CO. The reactor is

heated by burning some of the fuel. The water-gas produced is cooled in a boiler

which generates steam for the reactor. In industrial hydrogen production (the main

use of this process), one or more shift reactors are then used to convert CO to CO2;

after the gas has been cooled, the H2 is separated from CO2 using either chemical

solvent absorption or PSA (which produces high purity H2)5.

Partial oxidation, when used for making H2, involves the reaction of the

natural gas with pure oxygen at a high temperature (1250-1400oC) – no external heat

is required. The product gas is cooled, shifted and separated in the same way as for

5 In modern H2 plants using PSA, the off-gas is rich in CO2 but contains H2 and CH4 so is subsequently burnt in the reformer. As a result the CO2 would have to be captured post-combustion. Older H2 plants use chemical solvent separation, so release virtually pure CO2 from the solvent regeneration stage.

steam reforming. Although the efficiency of the process is lower than for reforming,

partial oxidation can handle a wider range of fuels. Several studies (e.g. IEA GHG,

2000a) have demonstrated that using air as oxidant for the partial oxidation process

will be worthwhile, saving the expense of an ASU.

In the power generation application, the hydrogen produced by either process

will be used as fuel for a gas turbine, so will likely be diluted with N2 as explained

above. These processes avoid the need to handle large volumes of flue gas to separate

CO2 post-combustion but at the price of high temperature reactors, which are not only

expensive but may also have operability problems, such as inadequately fast response

to changes in electricity demand, as needed for power generation plants.

3.3.3 Modified Combustion Conditions

This is the area of CO2 capture that has seen the largest number of novel ideas

in recent years. A corollary of such rapid innovation is that the practicalities of many

of the schemes are not yet known to anything like the same degree as for the

established capture processes described above. Nevertheless, it is worth reviewing

some of the concepts that have reached a stage of practical work to understand

whether they have the potential for major improvement in CO2 capture. The options

that will be considered are: oxyfuel combustion (coal), oxyfuel combustion (gas) and

chemical looping combustion.

3.3.3.1 Oxyfuel Combustion (coal)

In order to avoid the problem of separating CO2 from atmospheric nitrogen, a

plant could be constructed which uses pure oxygen for combustion. This is analogous

to established technology used in the glass and metallurgical industries. However, the

combustion temperature (up to 3500oC) would be excessive for normal boiler

materials, so some means of moderating the temperature is required so that the boiler

can be constructed in a similar way to existing steam cycle plant. The solution to this

problem is to recycle some of the combustion gases into the furnace of the boiler. As

a result, the concentration of CO2 is likely to be at a high level at the entrance to the

separation stage. The main components of the system are shown in Figure 3.6. Steam

is raised in the normal way in the boiler to drive a generator.

The combustion gases in such a process are mainly CO2 and H2O with small

amounts of SO2, SO3, etc. and some other impurities6. Cooling of the combustion

gases will remove the water component before recycling, and will also remove some

of the soluble acid gases such as SO3 and HCl, so that the recycled gases are

predominantly CO2. This also provides a ready source of CO2 for compression for

transport to storage.

The exhaust gases are cooled by pre-heating incoming gas, and cleaned before

being split in two – one part being returned to the boiler as a carrier of the pulverized

fuel, the other is cooled to condense the water out, leaving mainly CO2; some of this

gas is then returned to the boiler; the rest is cleaned of inert gases and acid gas

components before being compressed for transport to storage.

Figure 3.6 Schematic diagram of an oxyfuel power plant burning pulverized coal

The boiler is supplied with pulverized coal in the stream of recycled gas

together with oxygen from an air separation unit. It is suggested (IPCC, 2005) that

oxygen purity as low as 95% may be acceptable for this duty but that is something

that would need to be determined by optimisation of the overall design. This recycled

stream may contain water, if it is found that in practice the system does not need

complete drying of the recycled gas.

6 Impurities include nitrogen oxides and other impurities from the coal, as well as residual nitrogen and argon from the oxygen production and from air ingress into the furnace

CO2

Inerts

Compression/ Separation

Acid gases

Air

O2

Recycled gases

H2O

ASU

Fuel

Boiler

Cooling

Steam

The boiler is quite similar in design to conventional pulverized fuel boilers,

with adjustment to allow for the different balance of radiant and convective heat

transfer from the flames, if the excess oxygen is at a level comparable to combustion

in air. Other options exist, for example, in a more radical boiler design, only two-

thirds of the flue gas would be recycled, achieving an oxygen level of 35% by

volume; hot gas recycling could reduce the size of components downstream of the

boiler considerably (IPCC, 2005) which could offer significant equipment cost

savings.

CO2 purification may be done using cryogenic cooling – the high

concentration would make this an ideal application. This should allow separation of

NOx and SO2. However there will still be significant amounts of SO3 in the recycle to

the boiler which could build up in the system and increase the risk of corrosion – this

must be tackled either by removing the SO3 or by using corrosion-resistant

components.

The oxyfuel process is believed to be readily adaptable to existing boilers.

Similar technology could also be used in other applications – it has also been

suggested for use in cement production and oil refineries (de Mello, et al., 2008).

The Future of Coal study (MIT, 2007) estimated the performance of an

oxyfuel power plant with a super-critical steam cycle. The oxyfuel power plant

should have higher efficiency than a conventional SC PF power plant because of

improved boiler efficiency and lower energy use for emissions control but the extra

energy needed for the air separation unit would counterbalance this. The overall

efficiency is about 1%-point higher than the efficiency of the comparable SC PF case

with capture. This number should be treated with some caution since full size plants

have not yet been built. Nevertheless, it is noted that more efficient oxygen

separation technology would significantly improve the efficiency of the oxyfuel

power plant. Oxyfuel combustion for power generation is still in the early stages of

commercial development but appears to have potential. A commercial pilot plant has

recently been commissioned by Vattenfall at Cottbus in Germany; other units are

under construction in UK, Australia and elsewhere.

An alternative approach would be to recycle the water (steam) separated from

the combustion gases rather than CO2 – this steam could be used in the same way to

moderate combustion temperature. The thermal performance of such a system may be

similar to that of a system that recycles CO2 but would require a special steam turbine

that can work at relatively high pressures and temperatures (IEA GHG 2000b). The

cost of such a development makes this less attractive as an option than recycling CO2

but a similar approach is undergoing development for use with natural gas fuel as will

be discussed below; more recently this approach has also been proposed for use with

gas produced by gasification of coal (Jaeger, 2009).

3.3.3.2 Oxyfuel Combustion (gas)

To use oxyfuel combustion with natural gas requires roughly twice as much

oxygen for each CO2 molecule produced as when using oxyfuel with coal – this can

be understood by considering the chemistry of combustion; for methane this can be

represented as:

Whereas for coal7 the reaction is:

But this is compensated by the NGCC producing only half as much CO2 per

kWh as a coal-fired power plant. In such a scheme, the gas turbine would have to be

designed to use part of the recycled flue gas as its working medium – if this is the

recycled CO2, that would require a gas turbine designed for a heavier molecule with

different speed of sound than the (largely) N2 gas used in conventional gas turbines,

which would be a substantial change in design. Developing a new gas turbine

typically costs $1B (IEA GHG, 2000b) so cannot be justified for a special application

unless there is strong reason to anticipate sufficient market demand.

An alternative is to recycle the steam that is the other main constituent of the

flue gas from the combustor. A US company, Clean Energy Systems, is developing

such a process which combusts natural gas in oxygen; water is injected to moderate

the combustion temperature (IPCC, 2005). As a result the gas mixture produced is

90% (by volume) superheated steam and 10% CO2 at high temperature and pressure.

This is expanded through a multi-stage turbine expander to drive an electricity

generator. The steam/CO2 mixture is then cooled to condense the water which is

7 For the purpose of illustration, coal is assumed to have a C:H ratio of roughly 1:1

CH4 + 2O2 CO2 + 2H2O

CH + 1.25O2 CO2 + 0.5H2O

recycled to the combustor where it is injected as a liquid; the CO2 is purified and sent

to storage (or to EOR in the case of Clean Energy Systems’ favoured application). In

this system, combustion takes place in a modified rocket engine. Although

conventional steam turbines have been used in the prototypes, these are limited to

inlet temperatures of around 600oC; the process would achieve higher efficiency if

turbines capable of accepting steam at 1300oC were feasible. Clean Energy Systems

claim efficiencies could reach 55% (IPCC, 2005) if suitable process conditions could

be achieved.

3.3.3.3 Chemical Looping Combustion

In this concept, the oxidation of the fuel is performed by an oxygen carrier

rather than by gaseous oxygen – see Fig. 3.7. The carrier is typically a metal oxide;

this is chemically reduced in a reactor in the presence of hydrocarbon fuel (such as

natural gas). The carrier is prepared in a separate reactor where oxygen is separated

from the air by oxidation of the metal. These two parts of the cycle are physically

separate – the carrier, in the form of solid particles, is circulated between the two

reactors, using similar techniques to those used in circulating fluidised-bed

combustion. The physical separation of the processes of oxygen extraction and fuel

combustion means that no nitrogen is introduced into the combustion system so that

almost pure CO2 should be produced, which can be relatively easily prepared for

transport to storage. Nor is an ASU needed. The hot gas from the reduction reactor

can be used in a gas turbine to extract energy, although as the reactor may be limited

to temperatures of 800 to 1200oC, the thermal efficiency may not be as high as in a

conventional gas turbine using natural gas.

Figure 3.7 Schematic diagram of chemical looping combustion in a gas turbine power cycle

In principle the same process could be fuelled by coal but this would require

efficient separation of the ash from the recycled carrier, and elimination of fines

before the gas turbine – something similar to what is needed in a pressurised

fluidised-bed power plant, as few such plant have been built so there must be some

question about the practicability of this analogue.

An important requirement for the chemical looping combustion process is that

the carrier material can be circulated many times before it is degraded by use.

Substantial research is underway to identify the most prospective carriers (Pröll, et al.,

2008). Theoretical studies suggest that chemical looping combustion of natural gas,

used in a gas turbine combined cycle power plant, might achieve efficiencies of 45-

50% (IPCC, 2005). Whether this is sufficient advantage to justify development of a

whole new combustion technology is a matter of judgement.

3.3.4 Allowing For the Energy Used in Capturing CO2

As a result of introducing capture into a power plant, some of the energy

available has to be used for the separation process (e.g. solvent regeneration) and for

powering the CO2 compressor. In order to maintain electrical output, the size of the

power plant would have to be increased with consequent increase in energy use. This

means that the plant with capture would generate more CO2 than the plant without

capture. As a result the amount of CO2 captured is greater than the reduction in

Air

CO2

Metal oxidation

Oxide reduction

Oxide Metal

Fuel

H2O

Separation

Exhaust

emissions achieved, as shown in Fig. 3.8 (where both plants have been normalised to

the same electrical output). The extent of this effect depends on the configuration of

the plant and the type of separation used.

WithoutCapture

WithCapture

0 0.2 0.4 0.6 0.8 1.0 1.2

CO2 kg/kWh

CO2 avoided

CO2 captured

WithoutCapture

WithCapture

0 0.2 0.4 0.6 0.8 1.0 1.2

CO2 kg/kWh

CO2 avoided

CO2 captured

Figure 3.8 The emissions from power plants with and without CO2 capture, showing the effect of the extra energy used in the capture process

3.4 Application of CO2 Capture to Other Industrial Sources

As indicated in Table 3.1, there are various other industrial sources of CO2

where CO2 could be captured. These may conveniently be separated into different

types:

§ Those where the CO2 is already extracted from the process by a CO2

separation technique and is currently released to atmosphere as a concentrated

stream – examples are natural gas sweetening, ammonia production and the

older type of hydrogen production plant

§ Others where the CO2 is extracted by a process that could be adapted to

release a concentrated stream of CO2 – an example is the modern type of

hydrogen plant

§ Those where CO2 is released by a process equivalent to conventional power

generation – examples are boilers and refinery heaters

§ Or where the CO2, although available at a relatively high concentration, is part

of a gas stream that would need further treatment before conventional CO2

separation could be used – examples are cement production and blast furnace

off-gas.

The simplest option for capturing CO2 for emissions reduction purposes is the

first type – this in fact has been the basis for at least 4 of the existing CO2 capture

operations where CO2 is sent to storage (i.e. the Sleipner, Snøvhit, K12-B and In

Salah projects) as well as the Pernis refinery project in the Netherlands. Expenditure

on capture would be largely for compression and some piping; the extra energy used

would be essentially only that required for compression.

The second type would be relatively straightforward to implement, essentially

by replacing the acid gas system in the modern design of H2 plant (which uses PSA)

with a method more suited to production of a concentrated stream of CO2, such as

solvent scrubbing. This is likely to be considered once governments put a significant

price on the emission of CO2.

In the third case, the flue gases arise from combustion of fossil fuels in air.

This is similar to the power plant situation but the proportions of gases and the

impurities may vary. Similar techniques could be used as for post-combustion

capture, as described above.

The final type has been receiving R&D attention in Europe, with projects

examining ways of removing CO2 from blast furnaces gases (ULCOS), or supplying

blast furnaces with hydrogen-rich fuel, or capturing CO2 from cement kiln exhausts.

It is also worth mentioning that new facilities for producing transport fuels,

which may come to be used more in future, could incorporate CO2 capture in the

design to reduce emissions at the production stage – these processes include gas-to-

liquids conversion (Marsh et al., 2003), coal-to-liquids and hydrogen production.

3.5 Application of Capture to Existing Plant

Most of the published studies on capturing CO2 envisage fitting it to new

power plant during construction. Such plant would be likely to have state-of-the-art

efficiency and a long life over which to amortise the additional cost of the capture

equipment, thereby keeping down the cost of capturing each tonne of CO2. At the

same time there is a large stock of existing power plant which is likely to continue

operating for many years, so there is much interest in whether capture could be fitted

to such plants. For industrial processes other than power generation there are fewer

opportunities for fitting capture to new plant because relatively few oil refineries or

steel works, etc. are being designed and built today, so fitting capture to existing

industrial plant will be important for use of CCS.

The practicalities and cost of fitting capture to an existing power plant will

vary greatly depend on the design and layout of the installation; although many

boilers and turbines are of relatively standardised design, there can be great variation

in layout and circumstances between different plants; this makes it difficult to draw

generalised conclusions about fitting capture to such plants. Nevertheless, it is

possible to identify some key factors that will affect the attractiveness of fitting

capture to existing plant.

3.5.1 Is the existing plant suitable for capture?

Issues that need to be considered in considering whether a power plant would

be adaptable for capture include:

§ What type of plant is it? The large-scale fossil-fuelled generating technologies

currently in use are mainly PF and NGCC – fitting capture to a PF plant is

somewhat analogous to fitting flue gas desulphurisation (FGD), something

which has been done with existing plant in many countries, so the power

generation industry has experience with making such changes. On the other

hand, NGCC are designed as compact, self-contained units; there is no

experience of fitting large items of additional equipment to such plant; the

constraints on space around the turbines reduce the options for fitting capture;

so it may be more difficult to fit capture to an NGCC.

§ Is there sufficient space on site? This is a key issue, not only for fitting the

capture equipment but also for installing the CO2 compressor and the

associated pipe-work as well as for gaining access during construction. Some

examples of the amount of space required for retrofitting capture to 500 MW

power plants were estimated in a study for the IEA Greenhouse Gas R&D

Programme (IEA GHG, 2006) – these are shown in Table 3.6. Additional

space would also be needed during construction.

§ Outside the plant boundary, is there an acceptable route for the CO2 pipeline to

the storage location?

§ Will there be sufficient steam available from the plant (if needed)? If not, can

an alternative source of heat be installed to supply steam to the capture unit?

§ Are there other sources of electricity available that can make up for the

shortfall in output during the conversion? Also, after conversion is there an

alternative supply that can make up for the ongoing shortfall in production by

this plant?

Table 3.6 Estimates of space required (m2) for capture of CO2 at a 500 MW power plant

NGCC Ultra-supercritical PF

IGCC

Overall area (m2) 50,000 – 62,000 170,000 180,000

Capture option

Post-combustion 37,500 (250 x 150m) 9,525 (127 x 75m) n/a Pre-combustion 26,250 (175 x 150m) n/a small Oxyfuel n/a 9,600 (80 x 120m) n/a 3.5.2 What are the options for capturing CO2 from the plant?

If the power plant is judged to be suitable for fitting capture, what options are

available? Broadly there are two – retrofit or rebuild. Retrofit involves adding the

separation equipment and the CO2 compressor to the existing plant without major

change to the plant itself. Rebuild (also known as “repowering”) involves major

changes to the existing plant (such as replacing the boiler and turbines, or replacing a

sub-critical steam cycle by a supercritical one) with capture and compression installed

at the same time. The precise features will vary depending on the type of plant.

Whether or not to make up the lost power production on site or elsewhere is a

major issue for the retrofitting of capture. It is likely that, for a plant operating on a

well connected grid, the power lost by retrofitting capture would be made up by

another plant elsewhere on the grid. If this is not the case, it is likely that extra steam

raising capacity would be needed on site so that the output from the plant could be

maintained close to the previous level.

3.5.2.1 PF Retrofit

For retrofit of a PF plant, there are essentially only 2 options for separation:

post-combustion or oxyfuel. In either case, the CO2 compressor would also use a

significant amount of power. For post combustion capture, steam would be needed

for regeneration of the solvent – this could be taken from the plant’s own steam

system (this may be the least cost option). There would need to be take-off points to

extract steam from the low pressure circuits. This would involve substantial changes

on site, not least finding space for the scrubbers, the compressor and pipework.

Alternatively, especially in view of the relatively large amount of steam that would be

needed, an extra boiler might be constructed to supply heat to the solvent regenerator;

this would increase the site’s fuel consumption but avoid further reduction in power

output from the plant. In some studies (e.g. Ramezan, et al., 2006), this

supplementary boiler is assumed to be fired by natural gas rather than coal, which

makes it more difficult to identify the main influences on the cost of avoiding

emissions. Also, if the plant did not have FGD, or the level of SOx in the flue gas was

too high despite use of FGD, additional sulphur removal would have to be installed to

protect the amine in the capture system.

For the oxyfuel option, the air separation unit (ASU) would consume

significant amounts of electricity, so reducing plant output but there would be no

interference with the steam cycle. A key issue with oxyfuel is whether the flame

characteristics can be engineered to be similar to those of the existing burner. Most

important of all is whether the boiler can be sealed sufficiently that there is little

inward leakage of air, which would contaminate the recycle stream with extra inert

gases, especially N2.

3.5.2.2 NGCC Retrofit

For an NGCC, the only choice for retrofitting is to use post-combustion

capture. The potential reduction in output is less of an issue in the case of an NGCC

because, if significant amounts of steam were to be removed from the combined

cycle, this would unbalance the system. This means it is most likely that the extra

steam would have to be supplied by a supplementary boiler; this would be fired by

gas, so presenting fewer operational issues than would be the case for a

supplementary coal-fired boiler for a PF plant.

In practical terms, retrofitting would depend on being able to introduce large

diameter pipes in the relatively small space available around a typical NGCC.

3.5.2.3 PF Rebuild

In the case of a rebuild, the capture choices are wider and the efficiency

penalties will be less than for retrofitting because the efficiency of the base plant

would be raised at the same time that the extra heat load was being added. For a PF

plant, in addition to the post-combustion and oxyfuel options mentioned above, it

should also be possible to use pre-combustion capture, although this would be a

relatively complex rebuild with little remaining of the original plant other than the

coal handling facilities. In effect it would involve constructing an IGCC in place of a

PF plant.

Simbeck (as reported in MIT, 2007) examined various rebuild options for a

sub-critical PF plant; these designs were intended to maintain the same electrical

output as the original plant by upgrading to an ultra-supercritical steam cycle. The

efficiency of a rebuilt unit using MEA capture with an ultra-supercritical steam cycle

was estimated to be only 3.5%-points below the efficiency of the sub-critical plant

without CO2 capture. The efficiency of a rebuilt plant using an ultra-supercritical

steam cycle and oxy-fuel capture was only 1.8%-points less than the sub-critical plant

without capture. Rebuilding as an IGCC with CO2 capture resulted in efficiency

1.2%-points higher that the sub-critical plant without capture. It was also noted that

rebuilding a unit allows the optimum sizing of major pieces of equipment, which may

not be the case with a retrofit.

3.5.2.4 NGCC Rebuild

For an NGCC, rebuilding using a pre-combustion approach is a feasible

alternative to the retrofit of post-combustion capture. As a result of the rebuild, fuel

gas would be generated in an external unit (which could perhaps be on a different

site). As a result, there would be a wider choice of fuels since, in addition to pre-

combustion removal from natural gas fuel, it would also be feasible to gasify coal

with CO2 removal (essentially the scheme illustrated in section 3.3.2) – in other

words, convert the NGCC into an IGCC. Such a change would require considerably

more space than the retrofit; IEAGHG (2006) estimated an area of 475 x 375 m would

be needed to rebuild a 500MW NGCC using coal gasification with CO2 capture.

3.5.3 What affects the choice between options for capturing CO2 at an existing

plant?

From the above it is clear there is a wide range of options for capturing CO2 at

an existing power plant. When considering what could be done with a particular plant,

it will be possible to discard some of these options with very little thought. Others

will need deeper examination, which are probably best summarised in terms of their

effect on the economics of the plant. The main factors that influence the choice of

options for capture from an existing power plant include:

§ Reduction in efficiency from fitting capture. As the existing plant is likely to

have lower that state-of-the-art efficiency, the efficiency of the plant with

capture will be even lower than that of new plants with capture; this problem

will be made worse by the compromises that will have to be made in fitting

extra plant into an existing installation, so the overall efficiency will be even

worse than might otherwise be expected.

§ The amount of time off-line would be a major issue – this can seriously affect

the economics of any power plant retrofit. Retrofitting post-combustion

capture, especially if a supplementary boiler is used, should minimise the time

spent off-line, indeed the work might be integrated with normal maintenance

shut-down. More substantial changes, such as fitting oxyfuel, would involve

more time off-line. Rebuilding would involve the most extended period off-

line, not only for installing the new equipment but also for removal of those

parts of the existing plant that are no longer needed; the amount of time off-

line makes rebuilding the more questionable option unless there are sufficient

alternative supplies of electricity available on the grid.

§ Increased operating costs. In addition to the extra costs that would be incurred

by use of capture in a new plant, separate utility systems may have to be

installed for capture, thereby failing to gain any economies of scale in the

supply of utilities.

§ Remnant life of the plant. The remaining life of an existing power plant is

likely to be less than that of a new unit. This means that the extra capital

investment must be amortised faster than for a new plant, thereby adding to

the cost of electricity. It is unclear whether there would be any residual value

for any capture equipment still in operational condition at the end of the life of

the main plant. If the standard size of units (e.g. turbines, boilers) continued to

increase (as has been the trend in the past), the size of a redundant capture unit

might not be compatible with newer plant needing such equipment in future.

§ Changes in merit order position of the plant. On a grid with competing

capacity, the increased costs of the retrofitted plant could change the priority

given to the operation of this plant (this depends on how the reductions in CO2

emissions are imposed on the electricity industry). This could affect the

amount of time the plant is required to operate at part-load and the economics

of generation.

§ Ability to operate at part-load. The additional equipment will have different

characteristics from the existing plant when operating on part-load, such as its

ability to operate efficiently and smoothly. This will vary depending on the

type of plant but this could be especially an issue for plants using an ASU,

such as oxyfuel or IGCC, and for plants using gasifiers or reformers, such as

the precombustion options. This is an aspect of capture that has not been fully

investigated to date. Part-load operation will also have an effect on the CO2

transportation and storage system – it may involve undersizing the

transportation system and installing intermediate CO2 storage to balance

supply with the injection of CO2 underground.

§ What permits are required for modifications to the plant? This will need to be

considered as part of the process of deciding how to retrofit or rebuild.

Most of these factors will tend to make the cost of capture in a retrofitted

power plant more than in a purpose-designed plant. Similar arguments apply to

rebuilds but the strength of the argument will be less, because of the other changes in

the plant (such as improved efficiency), which will tend to mitigate the effect of

adding capture.

3.5.4 Designing New Plant to Facilitate Later Fitting of Capture

A related question is whether there would be advantages in designing a power

plant so as to make it easier to retrofit capture at a later date. The economic value of

preparing for CO2 capture can be calculated by comparing a plant designed to accept

capture with a plant not designed to do so. This approach has been followed in a

number of published studies. It has resulted in much discussion of the concept of

“capture-ready” power plants, with some parties seeing this as a way of justifying a

delay in fitting capture; this has become such a political issue that the term “capture-

ready” has become devalued and will not be used here. The likely requirements for

such plants are discussed in IEA GHG (2007).

The simplest change for adding capture would be in certain IGCC schemes - if

the design already uses a shift reactor (as some do), all that would be required would

be to replace the existing acid gas removal unit and add a CO2 compressor and

suitable pipe-work. Depending on the features of the gas turbine, some changes to

burners and controls might also be necessary, and perhaps a change in the amount of

N2 added at the gas turbine. Replacing an existing acid gas removal unit by one to

handle both sulphur and CO2 should cause only limited interruption to plant

operations.

More likely, an existing IGCC design would not include a shift reactor. In that

case, more extensive modification of the design would be required but, even so, the

change should be modest (compared with fitting post-combustion capture to a PF

plant). Nevertheless, there may be some small advantage in designing a new IGCC so

that it would be ready for fitting CO2 capture at a later date. In a study for EPRI,

Rutkowski et al. (2003) considered options for retrofitting an IGCC8 with CO2

capture. They examined cases where capture was added to a plant which had not been

prepared for it, or adding capture to a plant which had been designed for later

retrofitting. In the latter case, the gasifier would initially be oversized, so that the

later retrofit would not reduce the electrical output. Also, space would be allowed in

the design for installation of the extra equipment. The cost of electricity generation

was found to be 3% greater in the plant which had been prepared for retrofit compared

with the one which had not9. In contrast, once capture had been retrofitted, the cost of

electricity from the plant which had been pre-prepared was 3.5% lower than in the

plant which had not. This would seem to suggest that, under suitable circumstances, it

may be cost-effective to make preparation for capture when building a new IGCC

even if capture is not installed until some years later. However, the advantage is so

small that it might be difficult to justify the extra money to make the plant suitable for

later modification without a clear need for capture; if the case was sufficiently strong,

capture would probably be fitted from the start.

In all cases, CO2 compression and transportation pipework would have to be

constructed but typically this would be done external to the power plant building and

so would not present a significant disturbance to the operation of the unit.

For a PF plant, fitting capture after construction would involve more

substantial changes. A study for US DOE (NETL, 2008a) showed there would be

8 IGCC design using a GE-gasifier with quench 9 Using a 15% capital charge

economic advantage from designing a new supercritical PF plant so that CO2 capture

could be fitted at a later date; the authors found retrofitting capture to such a plant

would be significantly less expensive than retrofitting a plant that had not been

prepared for capture; the cost of electricity as a result of the retrofit would be

correspondingly smaller (about 20% less) for the prepared case compared with the

unprepared case. The savings result largely from installing a larger boiler in

anticipation of capture at a later date. Whether the savings are sufficient to justify the

extra investment would have to be decided by the plant owner – this would greatly

depend on the anticipated delay before reductions in CO2 emissions became

necessary.

The same study considered retrofitting capture to an IGCC; the incremental

cost of doing so in an IGCC prepared for capture was less than for an IGCC design

that had not been so prepared. However, the difference between these cases was less

than 10% of the total electricity cost which, in the authors’ opinion, was not sufficient

to persuade plant owners to invest in making preparations for capturing CO2 in an

IGCC design. It is noted that the size of the saving from preparing for capture was

broadly consistent with the reduction in cost found by Rutkowski et al. (2003).

A recent presentation (Tigges, et al., 2008) claimed that it would be possible to

design a state-of-the-art power station so that it could be converted to oxyfuel firing

without changing the type of coal burnt, keeping the same heat input, and being able

to operate in both air-firing mode and oxyfuel mode. However, the flue gas would

have significantly higher density in the oxyfuel case and there would be higher heat

transfer coefficient in the exhaust gas passages after the boiler. Such a design is

claimed to be capable of meeting burner operation targets both in air mode and

oxyfuel mode with similar flame shape and flame temperature. Heat transfer in the

convective pass of the boiler would be adjusted using the flow of recycled flue gas.

As a result, boiler efficiency would fall slightly. In addition to the ASU and CO2

compressor, an additional heat exchanger would be required to preheat the oxygen

supplied to the furnace. Overall efficiency would fall from 46% (LHV) in the air-fired

case to 34.3 % (LHV) in the oxyfuel mode. For an 820 MW plant, the ASU and

compressor would need an area of approximately 28,000 m² (typically 167x167m).

For an NGCC, as mentioned above, an IEA GHG study (IEA GHG, 2005)

found that post-combustion scrubbing would be the least-cost approach for retrofit of

capture; the alternative of rebuilding with pre-combustion capture would be more

expensive. Despite that conclusion, one NGCC is currently under construction in the

UK which has been designed so that coal gasification with capture could be added

later, if required.

3.6 Cost of Power Plant with CO2 Capture

The effect on the cost of a power plant of including capture is a key aspect of

assessing the prospects for CCS technology. There are many published estimates of

this cost, from a variety of sources, using a range of assumptions. Because of the

large degree of variation in the basis used for these estimates it is important to

recognise that cost data from different sources should not be compared unless steps

have been taken to put it on a similar basis (as was done, for example, in the IPCC

Special Report on CO2 Capture and Storage (IPCC, 2005)). A more robust basis for

understanding the effect of capture on plant economics is to use data from one source,

despite the fact that this may suffer from possible systematic errors, from being

related to just one location, and from being fixed at one point in time. However, this

is the least-worst means of providing an understanding of the generic costs of various

CO2 capture options, so this report will largely rely on data from one source but

discuss how the results compare with the IPCC (2005) data as a more general point of

reference.

3.6.1 Key Features to be Considered in Assessing Economics

The main elements of the cost of a power plant are the capital cost, the

operating and maintenance (O&M) cost and the fuel cost. In published estimates of

power plant costs, the capital cost is typically the project’s engineering, procurement

and construction (EPC) cost – essentially the cost of designing and building the plant.

This differs from the total cost to the owner of the project, which would include all the

costs of developing the project from initial concept to operating power plant; total

costs include, for example, the costs of permitting, fees and interest during

construction, as well as the costs of project development additional to the EPC cost,

such as acquiring the land, gaining permission for its use and site preparation. These

additional costs are difficult to assess until a project site has been identified and the

timing determined but they can add as much as 30% or more to the EPC cost. In this

report, only the EPC cost is considered.

The EPC cost is developed by estimating the equipment, materials, labour and

engineering costs for each main block of the plant together with an estimate for

contingencies. In addition, operating and maintenance (O&M) costs are also estimated

during the process of design. The fuel cost is estimated from the efficiency of the

plant and the assumed price of the fuel.

3.6.2 Approach to Generic Costs

There are various types of study from which generic data can be obtained.

Several organisations have commissioned engineering studies from professional

engineering contractors who may seek quotes for major items of equipment from

suppliers – examples of this type of study include the work of the IEA Greenhouse

Gas R&D Programme (IEA GHG), US Department of Energy (DOE), EPRI, CO2

Capture Project, etc. In some cases, the results of these studies are in the public

domain or have been summarised for dissemination in the technical community.

Typically the level of confidence in the results is ± 25%.

A second class of study makes use of the above studies, re-working them into

a comparable set so that the results can be more easily compared. A prime example is

the special report of IPCC on CCS (IPCC, 2005). The level of confidence is similar to

the first type.

A third type of study develops parametric analysis from the results of the first

2 types or by use of chemical engineering software. There is a lower level of

confidence in the results of this type of estimate but the advantage is that it enables

faster examination of the effects of different plant configurations.

Results of the first type of study are likely to be the most reliable and so are

used here.

The values of a number of key criteria must be decided before an assessment

begins, such as composition of the fuel to be used; the ambient temperature for the

site, including cooling water temperature; the plant size, duty and load factor; the

purity of CO2 to be produced and its export pressure; as well as certain economic

factors.

The introduction of CO2 capture into a power plant scheme will increase costs

and could reduce output compared with a similar plant without capture so it is

important to decide the basis for comparison. In particular what type of plant (without

capture) sets the basis for comparison and what size should it be?

The simplest approach is to compare a power plant with capture against a

similar type without capture. However, this approach must be used with care since

the answer only provides useful insight if the same type of plant would have been

constructed otherwise. The classic example of this problem can be seen in the

comparison of an IGCC with capture against an IGCC without – it is well known that

the resultant cost of capture appears very small but this is deceptive if an IGCC would

not otherwise have been built, which is likely to be the case as the IGCC is not the

industry norm.

A more practicable approach is to use the type of plant that would otherwise

have been built as the standard for comparison – this will depend on the local situation

so is more difficult to generalise but will produce a result which is more relevant to

practical decisions.

The size of the plant with and without capture is another important decision to

take before starting an assessment - as a result of introducing capture and

compression, the electricity production of a power plant scheme will be reduced. This

reduction can be substantial. As a consequence, the electricity network would need to

introduce extra plant elsewhere on the grid to compensate. In order to compare on a

like-by-like basis, the energy consumption and emissions of this additional plant

would have to be taken into account in the calculations of costs and emission

reduction from including capture. This is an impracticable basis for assessing power

plant options.

An alternative is to up-rate the plant fitted with capture so that it has the same

electrical output as one without capture. This makes for straightforward comparison

of electricity costs and emissions but can be regarded by engineers as unrealistic in

some cases because of the size of units required for such a design. Nevertheless, this

approach also has the advantage of allowing for economies of scale in the equipment.

This is the approach generally followed by the IEA Greenhouse Gas R&D

Programme in its assessments, using a plant size of 500 MW. US DOE (NETL,

2007) used this approach for pulverised coal plant but for plant using gas turbines

(such as NGCC or IGCC) DOE allowed the designers to vary the output sufficiently

to accommodate standard sizes of gas turbine10.

10 In that report (NETL, 2007), the nominal net plant output was set at 550 MW. Boilers and steam turbines used in the PF plant are readily available in a range of capacities so all of the PF cases were

The degree of CO2 capture is generally dealt with by engineering judgement –

typically 85% or sometimes 90% of the CO2 in the flue gas would be captured. This

will affect the cost and energy penalty of the plant with capture.

3.6.3 Cost of Electricity

In order to assess the economics of a plant, the capital, O&M and fuel costs

have to be related to each other, to the amount of electricity produced and to the

reduction in CO2 emissions; this involves judgement about the time value of money

something which is conventionally embodied in a discounted cash flow calculation;

the result is the “levelized cost of electricity”.

A key parameter is the discount rate (or the related inverse, the capital charge)

which reflects the opportunity cost of capital11. Costs are related to the amounts of

electricity produced, and to the amounts of CO2 emitted/captured each year – this

produces values of the levelized cost of electricity and the cost of avoiding CO2

emissions.

It should be noted that there are differences in published data depending on

which method of discounting has been used. For electricity production this is

generally not an issue but when comparing different methods of sequestering carbon it

can generate very different results. The method described here is the standard method

used in industry for assessment of the costs of electricity generation and emission

abatement processes.

3.6.4 Relating Cost to Emissions Reduction

In considering a simple process which handles a defined amount of CO2, such

as a CO2 transportation scheme (as will be described in chapter 4) the costs can be

related in a straightforward manner to the amount of CO2 to be handled. However,

for capture, the amount of CO2 captured is greater than the reduction in emissions

achieved because of the energy used by the capture and compression facilities (see

Fig. 3.8). This reduces the net output of the power plant so extra energy has to be

used to make up for the loss in generation; this gives rise to extra emissions. The assumed to have a net output of 550 MW. As the combustion turbines in the IGCC and NGCC are only manufactured in discrete sizes, the IGCC cases had net outputs between 636 and 517 MW, and the NGCC cases had net outputs of 560 or 482 MW. 11 In this study, a capital charge of 11% used, which is roughly equivalent to 10% discount rate for long life projects.

extent of these effects depends on the configuration of the plant and the type of

separation involved.

As shown in Fig 3.8, the net reduction in emissions as a result of capturing

CO2 is the amount of “emissions avoided”. This is the appropriate measure for

costing CO2 capture for abatement purposes12 and is the measure used in this chapter.

It should not be confused with the similar term used to describe national emissions

reductions which is calculated on a different basis.

Only new build power plant are considered in the case studies in this report, as

this focus provides a clear and straightforward basis for costing, so the results can be

interpreted more easily.

3.6.5 Overview of Costs

For the reasons given earlier, the best source of comparative information will

come from a study of different types of power plant carried out by the same

individuals under similar terms of reference. The most reliable information is likely

to come from engineering consultants who have access to manufacturers’ information

and cost data, and the results of recent projects. The most recent published

information on use of capture with new power plants that meets these conditions, as

far as the author is aware, is a US study on capture in bituminous coal plant (NETL,

2007).

In that study the cost data were obtained in December 2006, for a new plant

located in the Midwestern USA. Since the time of that study, there has been inflation

as well as deflation in plant costs; some elements of the cost of plant are likely to be

lower in Indonesia (e.g. ground work and on-site construction) whilst other items are

likely to be more expensive (e.g. imported gas turbines). On balance it is difficult to

say whether the costs from the study (NETL, 2007) are likely to be above or below

costs of similar plants to be constructed in Indonesia, so no change will be made in the

published capital and O&M costs in reporting them here.

One significant change to the NETL, 2007 that has been made in this study is

to alter the capital charge to 11% (the original study used 16% and 17.5%) as this will

12 In contrast, if the primary purpose of capture is to supply enhanced oil recovery, the appropriate measure would be the amount of CO2 captured.

enable easier comparison with other published studies, particularly IPCC, 2005

(which reported results using capital charges of typically 11 to 15%).

It should be noted that the costs presented here are intended to represent large-

scale deployment of CCS plant – the first plants to be built of this type are likely to

cost considerably more than these numbers would suggest.

Costs of transport or storage have not been included in the cost of avoided

emissions – the cost of transport and storage would add about $4/MWh for coal-fired

plant and $2/MWh for gas-fired plant according to DOE (NETL, 2007). The IPCC

special report on CCS (IPCC, 2005) assumed lower CO2 delivery pressure than DOE

(i.e. 8-14 MPa versus 15 MPa) which would slightly improve the efficiency.

3.6.6 Costs of Capturing CO2 in PF, IGCC and NGCC Plants

A number of the cases have been taken from (NETL, 2007) to illustrate the

generic costs of capturing CO2 with the established types of power generation

technologies; these are:

§ Sub-critical PF

§ Super-critical PF

§ IGCC, based on Shell gasifier

§ NGCC

These cases are presented below, and compared with the results reported in

IPCC (2005) for similar types of plant. A significant influence on these results is the

cost of fuel - the cost of coal used here is only slightly higher than in most of the

studies cited in (IPCC, 2005) but the cost of gas is substantially more. All of these

cases assume a capacity factor of 85%, which is higher than would be expected in

Indonesia. In a later section of this chapter (3.8), some of these cases will be

reworked using assumptions more relevant to application in Indonesia. However, in

this section we will start by examining the NETL (2007) results more or less as

published (except for the change to 11% capital charge) to see how these results

compare with other published data.

3.6.6.1 Sub-critical PF

The costs of subcritical PF plant with and without capture are shown in in

Table 3.7. These figures may be compared with (IPCC, 2005) but IPCC only reported

two sub-critical cases, only one of which involved the burning of bituminous coal.

The cost of electricity in Table 3.7 is about 15% above the value given by IPCC for

the bituminous coal case. The incremental cost of electricity in Table 3.7 is a little

above the value given by IPCC (2005).

Table 3.7 Effect of capturing CO2 on the cost of pulverised coal-fired sub-critical steam cycle power plant, based on NETL (2007).

Type of plant: Sub-critical PF with FGD

Sub-critical PF with FGD and CO2 capture

Fuel Bituminous coal Bituminous coal Calorific value 27113kJ/kg (HHV) 27113kJ/kg (HHV) Fuel cost $42.1/t $42.1/t Net output (MW) 550 550 Specific cost ($/kW) 1549 2895 Capacity factor 85% 85% Net plant efficiency (HHV) 36.8% 24.9% Net plant efficiency (LHV) 38.1% 25.8% Emissions (kg CO2/MWh) 855 126 Capture effectiveness - 90% CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

52.97 89.39

Incremental cost of electricity ($/MWh)

- 36.42

Avoided cost (versus sub-critical PF)

- $49.96/t CO2

Avoided cost (versus supercritical PF: see table 3.8)

- $55.0/t CO2

The cost of avoided emissions in Table 3.7 has first been calculated by

comparison with a similar sub-critical PF plant without capture.

However, it would be more relevant to compare against a super-critical PF

plant as this is closer to the state-of-the-art and is more likely to be the type of plant

that would be built today. Such comparison is shown in the final row of Table 3.7;

the fact that the cost of avoiding CO2 emissions is higher in this case than when

compared with a sub-critical plant indicates it would be cost-effective to invest in the

more efficient, super-critical plant whether or not capture is fitted.

3.6.6.2 Super-critical PF

The cost of electricity from a super-critical PF plant with capture (Table 3.8) is

similar to the results published in (IPCC, 2005) for supercritical plants burning

bituminous fuel (for comparison, the range of results given by IPCC was 43 to 52

$/MWh without capture, rising to 62 to 86 $/MWh with capture).

The capital costs of the plant, especially the case with capture, in Table 3.8 are

higher than the costs of all of the SC PF plants in (IPCC, 2005) reflecting, amongst

other things, the real inflation in costs in the intervening years. The thermal

efficiency of this plant is just below the lower end of the ranges quoted by (IPCC,

2005). For all of these reasons, the cost of CO2 emissions-avoided in Table 3.8 is

close to the upper end of the range of such costs quoted in (IPCC, 2005).

Table 3.8 Effect of capturing CO2 on cost of Super-critical steam cycle pulverised coal-fired power plant, based on NETL (2007)

Type of plant: Supercritical PF with FGD

Supercritical PF with FGD and CO2 capture

Fuel Bituminous coal Bituminous coal Calorific value 27113kJ/kg (HHV) 27113kJ/kg (HHV) Fuel cost $42.1/t $42.1/t Net output (MW) 550 546 Specific cost ($/kW) 1575 2870 Capacity factor 85% 85% Net plant efficiency (HHV) 39.1% 27.2% Net plant efficiency (LHV) 40.5% 28.2% Emissions (kg CO2/MWh) 804 115 Capture effectiveness - 90% CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

52.1 86.0

Incremental cost of electricity ($/MWh)

- 33.9

Avoided cost (versus supercritical PF)

- $49.2/t CO2

The cost of electricity is slightly lower than in the sub-critical case (Table 3.7)

reflecting the higher efficiency of the super-critical PF plant. This is particularly

apparent in the case with capture.

3.6.6.3 IGCC

The cost of electricity from an IGCC without capture in Table 3.9 is

significantly higher than the costs of the IGCC cases reported in (IPCC, 2005), most

of which fall in the range 41 to 53 $/MWh with an outlier at $61/MWh. Similarly, in

the case with capture in Table 3.9, the cost of electricity is above the range of the

results cited in (IPCC, 2005). Some of this may be due to substantially higher coal

costs than in the cases cited in (IPCC, 2005) but it also reflects a substantially higher

capital cost for the power plant. The results are only slightly different for other types

of gasifier considered in (NETL, 2007).

Table 3.9 Effect of capturing CO2 on the cost of an IGCC plant, based on NETL (2007)

Type of plant: IGCC (Shell gasifier) IGCC (Shell gasifier) with CO2 capture

Fuel Bituminous coal Bituminous coal Calorific value 27113kJ/kg (HHV) 27113kJ/kg (HHV) Fuel cost $42.1/t $42.1/t Net output (MW) 636 517 Specific cost ($/kW) 1977 2668 Capacity factor 80% 80% Net plant efficiency (HHV) 41.1% 32.0% Net plant efficiency (LHV) 42.6% 33.2% Emissions (kg CO2/MWh) 752 90.4 Capture effectiveness - 90% CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

62.3 81.7

Incremental cost of electricity ($/MWh)

- 19.4

Avoided cost (versus supercritical PF)

- $41.5/t CO2

3.6.6.4 NGCC

The efficiency of the NGCC with post-combustion capture in Table 3.10 is

similar to that in (IPCC, 2005) as are the capital costs. The cost of electricity is

substantially higher in Table 3.10 than in (IPCC, 2005) but the incremental cost of

electricity as result of capturing CO2 is at the top end of the IPCC range (12 to 24

$/MWh), probably because the fuel costs cited in (IPCC, 2005) were between $2.8

and 4.4/GJ, considerably lower than used here. Fuel costs can have a dramatic effect

on the economics of an NGCC with capture as is illustrated in Fig 3.9 and 3.10.

Table 3.10 Effect of capturing CO2 on the cost of an NGCC plant, based on NETL (2007)

Type of plant NGCC NGCC with post-combustion CO2 capture

Fuel Natural gas Natural gas Fuel cost $6.4/GJ $6.4/GJ Net output (MW) 560 482 Specific cost ($/kW) 554 1172 Capacity factor 85% 85% Net plant efficiency (HHV) 50.81% 43.7% Net plant efficiency (LHV) 55.9% 48.1% Emissions (kg CO2/MWh) 361 42 Capture effectiveness - 90% CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

64.3 84.3

Incremental cost of electricity ($/MWh)

- 20.0

Avoided cost (versus NGCC) - $62.7/ t CO2

No cases of pre-combustion capture with an NGCC were covered in NETL

(2007) so this option has not been presented in full here. It is noted that at least one

commercial scheme had been planned using this approach13 but the most up-to-date

published cost information on such scheme is an IEA Greenhouse Gas R&D

Programme report (IEA GHG, 2000a). According to the standardised data in (IPCC,

2005), such a POX-based scheme showed an increment in the cost of electricity of

$12.8/MWh due to capture and a cost of avoided emissions of $42/t CO2 at fuel cost

of $2/GJ; these figures are slightly higher than the corresponding numbers for the

post-combustion approach at the same fuel cost.

13 This was the BP/Scottish and Southern Electricity power plant planned to be constructed at Peterhead in the North of Scotland, with offshore storage of CO2 in an oil field. This project was cancelled in 2007.

10.00

15.00

20.00

25.00

0 1 2 3 4 5 6 7 8 9 10Gas cost ($/GJ)

Elec. cost inc. ($/MWh)

Figure 3.9 The dependence of the incremental cost of electricity (i.e. the cost of electricity from a plant with capture less the cost of electricity from a plant without capture) on the cost

of natural gas

30.00

35.00

40.00

45.00

50.00

55.00

60.00

65.00

70.00

75.00

80.00

0 1 2 3 4 5 6 7 8 9 10Cost of gas ($/GJ)

Cost of Emissions avoided ($/tCO2)

Figure 3.10 The effect on the cost of avoided CO2-emissions ($/t CO2) due to variation in the cost of natural gas

3.6.6.5 Summary of the Cost of Capturing CO2

The results in Tables 3.7 to 3.10 show that the cost of avoiding emissions lies

in the range from about $40 to 60/t CO2-avoided for new power plants, when

compared against the cost of the type of plant likely to be built otherwise. In addition

there will be extra costs for transport and storage of the CO2. The extra capital

investment required is around 80% for the coal-fired plant and 115% for the gas-fired

plant. The increase in cost of electricity due to capture is 55 to 70% for the coal-

fuelled plant and 30% for the NGCC.

3.6.7 Retrofit of CO2 Capture to Existing Power Plants

The cost and benefits of retrofitting capture to an existing power plant will be

strongly influenced by the layout of the plant and the circumstances of its operation.

For this reason, published data on economics of retrofit can be regarded, at best, as

only illustrative. The following review of the literature is presented in order to

provide directional messages about retrofit - the specific figures quoted should not be

considered as representative of the future retrofit of any particular power plant.

An early study on retrofit of capture (Bozzuto, et al., 2001) was carried out for

US Department of Energy (DOE); this evaluated the retrofit of capture to an existing

450 MW sub-critical PF plant in Ohio using a commercial MEA process. The study

found that retrofit would result in a substantial reduction in electrical output, involve

very high investment costs and a large increase in the cost of electricity. As a result,

DOE concluded that further study was needed to find a better way of retrofitting

capture to existing power plants.

A follow-up study (Ramezan, et al., 2006) examined the fitting of an advanced

amine scrubbing system in the same power plant. Four different levels of capture

were considered (90%, 70%, 50%, and 30%) although the lower levels of capture

seem irrelevant in the context of the global concern to reduce CO2 emissions. That

study also undertook a detailed analysis of the existing steam turbine to understand

how best to modify it, which had not been done in the earlier work; steps were also

taken to integrate the heat rejected from the CO2 capture/compression system into the

plant’s own steam/water cycle, thereby improving thermal efficiency; fewer but larger

scrubbers, compressors, etc. were used thereby taking advantage of economies of

scale; a more compact design was developed, using only 16,000m2 of space

(~127x127m). All in all these changes produced significant reductions in the energy

required for solvent regeneration but there was still a substantial decrease in overall

plant efficiency as a result of the retrofit (from 36.7% to 25.6% [LHV] with 90%

capture).

The specific investment costs were about half those found in the earlier study

but were still substantial at about $1,000/kW (2006$). The increase in the cost of

electricity was $39/MWh. The cost of avoiding CO2 emissions was found to be

lowest for 90% capture due to the effect of economies of scale, increasing slightly

(from $51 to $66/t CO2-avoided) as the CO2 capture level decreased from 90% to

30%.

Another retrofit option may be use of oxy-fuel; retrofit to a sub-critical PF

plant was examined by Bozzuto et al. (2001) and also by Simbek (2001); the Future

of Coal study (MIT, 2007) reported the reductions in plant output found by these 2

studies were 35.9% and 33.3% respectively. The corresponding efficiencies of the

plant with capture were 23.3% and 24.1% (LHV) respectively; these reductions are

similar to those in the more recent DOE study on post-combustion capture (Ramezan,

et al., 2006). The capital investment required for oxyfuel retrofit was estimated at

$1044/kW and 1060/kW, respectively. The cost of avoided emissions was $58/t CO2-

avoided (MIT, 2007). Consequently, we conclude14 that oxy-fuel retrofit would have

similar capital costs and incremental cost of electricity as would be achieved by a well

designed post-combustion retrofit but, as always, caution must used in comparing the

results of different studies done on different bases.

The addition of capture to an existing 785 MW NGCC was examined in an

IEA GHG study (IEA GHG 2005). This considered a number of options including the

retrofit of an amine scrubber for post-combustion capture, as well as pre-combustion

capture using reforming of natural gas, or gasification of coal. The pre-combustion

options were rebuilds rather than retrofits, with the treatment plant installed either on

the same site or at a different location (with connecting gas fuel pipeline). The results

indicated that, in the best case, efficiency was reduced by 11.5%-points; the retrofit

incurred a capital cost of at least $600/kW; the cost of electricity increased by

14 This conclusion is in contrast to the conclusions of the Future of Coal study because we have compared the oxyfuel results against the more recent post-combustion study.

between US$20 and 30/MWh15. The emission abatement costs were between $70 and

90/t CO2-avoided (not including transport and storage). Offsite fuel processing would

add significantly to this cost (equivalent to an extra $8/MWh). The conclusion of this

study was that post-combustion capture provided the lowest cost retrofit for an

NGCC.

The Future of Coal study (MIT, 2007) also provides a measure of the effect of

retrofitting a relatively new plant, one that has some residual value rather than one

which had been fully written down before the retrofit (Table 3.11). Variations in the

residual value were found to have a significant effect on the economics of retrofitting.

Table 3.11 Impact of Residual Value on the Incremental Cost of Electricity for the retrofit of capture to a supercritical PF power plant (MIT, 2007)

MEA Retrofit Oxy-fuel retrofit

Residual Capital Value as fraction of original cost

Increase in cost of electricity ($/MWh)

Increase in cost of electricity ($/MWh)

10% 4.3 4.0 25% 10.7 9.9 50% 21.4 19.8

The economics of rebuilding a coal-fired power plant were also reviewed in

(MIT, 2007) but these cases are not discussed here because, as the number of variants

is so large, it is not clear which, if any, are relevant to possible applications of capture

in Indonesia.

3.6.8 Potential Cost Reductions

The introduction of capture and storage into a power plant project will

increase costs substantially so there is a great deal of interest in the potential for cost

reductions – this can arise in a number of forms. For example, improvements in

performance (especially in the capture of CO2) will likely lead to reductions in cost of

abatement. As more of this type of plant is constructed, there will also be economies

of scale in construction; further economies of scale will arise from using larger units.

Many of these changes are recognised under a generic phrase “technology learning”.

This has been studied extensively as it can give an overall impression of the cost 15 Assumed price of gas = $3/GJ (LHV)

reductions achievable over time based on past experience with similar technologies.

No allowance has been made for “technology learning” in this study but neither has

there been any allowance for the extra costs of a “first-of-a-kind” project, such as

would be expected for using new technology in an established industry.

3.6.9 Economics of Capture from Non-Power Generation Sources

As mentioned above (section 3.4) there are many other potential sources

where CO2 could be captured. The opportunities which present the lowest additional

cost are those where the CO2 must be separated for other business reasons, such as

sweetening of natural gas. The purity of the separated CO2 may not be as high as

where capture is designed to produce a concentrated stream of CO2 for storage but it

may well be high enough – examples being the solvent scrubbing processes used at

Sleipner, K12-B and In Salah.

Because the separation of CO2 is already required in such plants for business

reasons, there is (in principle) no extra cost for capturing the CO2. In practice there

will be a costs associated with any extra clean-up needed, installation of extra piping,

as well as interruption of production. The major cost will be the installation of the

compressor (and the pipeline to transport the CO2 to storage but that is covered in

chapter 4). An example of the cost of adding a compressor is given in section 3.8.

3.7 Environmental Aspects, Risks, Safety and Other Considerations

The capture of CO2 will be done at an industrial facility (e.g. as part of a

power generation plant) so normally it would not be expected that it would present

significant risk to the safety of the general public as any escape of CO2 would be

contained on the premises. Thus the main risk from capture of CO2 is to the health of

workers on the plant, which will be discussed below. The exception to this might be if

a large volume of CO2 were held on site, especially under pressure, and it escaped.

This is only likely to be the case if intermediate storage is needed preparatory to

transport - this is discussed in chapter 4.

3.7.1 Risks Involved in Capturing CO2

As a normal constituent of the atmosphere, CO2 is considered harmless. The

capture of CO2 involves concentrating CO2, possibly under pressure, so the risks of

escape of CO2 would need to be taken into account in the health and safety plan for

any such installation. Any danger arising from the release of CO2 may be enhanced

because the gas is colourless, tasteless and is generally considered odourless unless

present in high concentrations.

CO2 is 1.5 times denser than air at normal temperature and pressure, so any

gas that leaks out of pipes or storage will tend to collect in hollows and other low-

lying confined spaces which could create hazardous situations.

When contained under pressure, escape of CO2 can present serious hazards,

for example asphyxiation, damage due to high noise level or from release of high

pressure gas. If CO2 escapes from a vessel under pressure, the consequent pressure

drop can cause a hazardous cold condition with danger of frostbite from cold surfaces,

or by coming into contact with solid CO2 (dry ice) or escaping liquid CO2.

3.7.2 Health and Safety Aspects of CO2 Capture

At normal conditions, the atmospheric concentration of CO2 is 0.037%, a non-

toxic amount. The impact on humans of elevated CO2 concentrations depends on the

concentration and duration of exposure. At concentrations up to about 1.5%, there

should be no noticeable physical consequences for healthy adults at rest from

exposure for an hour or more. Increased activity or temperature may affect how the

exposure is perceived. Longer exposure, even to less than 1% concentration, may

significantly affect health. Noticeable health effects will occur above this level,

particularly changes in respiration and blood pH level, which can lead to increased

heart rate, discomfort, nausea, and unconsciousness.

Higher concentrations or exposures of longer duration are hazardous – either

by reducing the concentration of oxygen in the air to below the 16% level required to

sustain human life16, or by entering the body, especially the bloodstream, and/or by

altering the amount of air taken in during breathing – such physiological effects can

occur faster than the effects of displacement of oxygen, depending on the

concentration of CO2.

16 Signs of asphyxia will be noted when atmospheric oxygen concentration falls below 16%. Unconsciousness, leading to death, will occur when the atmospheric oxygen concentration is reduced to ≤ 8% although, if strenuous exertion is being undertaken, this can occur at higher oxygen concentrations (Rice, 2004).

Acute exposure to CO2 concentrations at or above 3% may significantly affect

health. Hearing loss and visual disturbances can occur above 3% CO2. Healthy young

adults exposed to more than 3% CO2 during exercise experience adverse symptoms,

including laboured breathing, headache, impaired vision, and mental confusion. CO2

acts as an asphyxiant in the range 7-10% and can be fatal at this concentration; at

concentrations above 20%, death can occur in 20 to 30 minutes (Fleming et al., 1992).

The identification of CO2 intoxication is done by exclusion of other causes

because exposure to CO2 does not produce unique symptoms.

3.7.3 Control Measures in Relation to Operation with CO2

The health and safety plan for the plant must take into account the handling

and processing of CO2. Examples of the exposure limits set by some US standards for

workers who may be exposed to CO2 are shown in Table 3.12.

Table 3.12 Examples of US Occupational Exposure Standards

Time Weighted

Average (8 hour day/40 hour

week)

Short Term Exposure Limit

(15 minute)

Immediately Dangerous to Life

and Health

Permissible Exposure Limit17

5 000 ppm

Recommended Exposure Limit18

5 000 ppm 30 000 ppm 40 000 ppm

Threshold Limit Value19 5 000 ppm

Control procedures would include minimising any venting of CO2 except

where this cannot be avoided for safety or other operational reasons, and provision of

adequate ventilation when CO2 has to be discharged into the air, to ensure rapid

dispersion. Personnel should avoid entering a CO2 vapour cloud, not only because of

the high concentration of CO2 but also because of the danger of frostbite. High

concentrations of CO2 can occur in open pits, tanks and buildings, where it may not

disperse naturally. For this reason, monitors must be installed in areas where CO2

might concentrate, supplemented by use of portable monitors.

17 US Occupational Safety and Health Administration 18 US National Institute of Occupational Safety and Health 19 American Conference of Governmental Industrial Hygienists

3.7.4 Environmental Impact of CO2 Capture

Typically, an assessment of the environmental impact of the use of a

technology such as CO2 capture and compression would cover:

§ Emissions to atmosphere

§ Releases to water courses

§ Disposal of solid residues on land

§ Noise and vibration

§ Visual impact

§ Water usage

§ Raw material inputs

§ Consequence of accidents

§ Traffic to/from site

For the purposes of this discussion, we are concerned with the incremental

effects of adding capture and compression to a power plant scheme (i.e. as part of a

new design).

Compared with a similar plant without capture, emissions to atmosphere will

be substantially reduced (in terms of CO2) and other fuel-derived emissions may be

reduced slightly. There will be some release of chemical solvents, if used for capture,

due to “slippage” in the separation process but this release will be up the stack so

should have no local impact and will be dispersed along with the stack gases.

Releases to water may occur if water is used in the process, for example to remove

traces of solvent and products of degradation from the gas stream.

The increase in traffic to/from the site should be marginal (once construction

has been completed). Noise from plant may be increased slightly because of the extra

rotating equipment in use for capture and, especially, for compression of CO2 but this

can be handled by suitable design of the enclosures. There may be some increase in

visual impact, mainly because of the height of the absorber and regenerator of the

capture unit, but this should not make a substantial difference in view of the visual

impact of the power plant itself.

Raw material usage will be increased substantially: there is likely to be a 10-

30% increase in fuel use as well as the use of solvents. The main environmental

impact seems likely to be from the disposal of solid residues arising from use of

chemical solvents, especially MEA, depending on whether they are classified as

hazardous or not. Thus chemical solvent absorption seems likely to have more

environmental impact than other capture schemes, although none will have large

impact.

3.8 Preliminary Assessment of Options in Indonesia

Commercially available CO2 capture technologies could be fitted to new

power stations in Indonesia. A number of case studies are provided below to illustrate

the cost of capture; these all use post-combustion capture although in principle pre-

combustion capture technologies would also be usable but this would require a

decision on the type of power plant. The costs in these case studies have been derived

from the costs cited in section 3.6 for new construction by adapting the data presented

there. For this reason, it should be noted that the same degree of confidence cannot be

assigned to the costs as would be expected for engineering analyses, as was discussed

in section 3.6. Nevertheless, these results should provide some useful guidance on the

effects of scale and choice of fuel on the cost of avoiding CO2 emissions.

Five cases are examined, as follows

1. Capture at a 1000 MW coal-fired power plant with a supercritical steam

cycle burning Sub-bituminous fuel, located in Indramayu-West Java.

2. Capture at a natural gas-fired combined cycle power plant (NGCC) rated at

750 MW, located in Muara Tawar-West Java.

3. Capture of CO2 at a 600 MW power plant using a sub-critical steam cycle,

burning lignite fuel, located at a mine site in Bangko Tengah-South

Sumatera.

4. Capture at a 100 MW coal-fired power plant with a sub-critical steam cycle,

burning Sub-bituminous fuel, located in Muara Jawa-East Kalimantan.

5. In addition, a case is considered which does not involve a power plant; at a

natural gas processing plant in the Subang field in West Java, where CO2 is

already separated from the gas stream, the exhaust CO2 would be

compressed for transport to storage.

Cases 1 and 2 are close analogies to some of the examples considered in

section 3.6 so it should be relatively accurate to derive illustrative costs by scaling the

data in these cases. Because of the wider range of fuels than in (NETL, 2007), the

CO2 emission factors for the coals have been taken from the values quoted in Table

A1.13 in the IPCC Special report on CCS (IPCC, 2005)

In case 1, the plant (1000MW) is larger than the supercritical power plant

considered in section 3.6, so it should have significantly lower specific cost (i.e.

$/kW). The capital costs have been adjusted for size using a cost exponent of 0.820 but

no improvement in thermal efficiency has been assumed (because of lack of data)

even though such improvement might well be achieved by such an increase in the size

of the plant. The capacity factor has been reduced to 70% to correspond to the load

factor expected of such a plant in the Jawa-Bali power system. The calorific value and

cost of the coal has been adjusted to correspond to the location. The results are given

in Table 3.13.

The incremental cost of electricity is about 25% greater than in the comparable

case in section 3.6, due to the lower capacity factor and the higher cost of fuel. As a

result the cost of avoided emissions is higher by a similar amount.

In case 2, the 750 MW NGCC is larger than the one modelled in section 3.6;

this should reduce the specific cost. The capital costs (Table 3.14) have been adjusted

from the values in NETL, 2007 to represent a 750 MW plant using a cost exponent of

0.8; both of the plants, i.e. with and without capture, are assumed to have this output

(which is different from the assumption in NETL, 2007) but no improvement in

thermal efficiency has been assumed as the plant would probably consist of multiple

units or several trains rather than just larger machines. The capacity factor of 70%

corresponds to the load factor expected of such a plant in the Jawa-Bali power system.

The incremental cost of electricity as a result of fitting capture is $21.5/MWh

(compared with $20/MWh for the 560/482 MW cases considered in section 3.6). The

cost of avoiding emissions is slightly greater than that reported by NETL (2007),

which may be due to using a more appropriate basis for comparison in the with-

capture case. The effect of lower capacity factor is not as great as in the previous PF-

case, because the capital investment in the NGCC has less influence on the overall

economics than in the more expensive PF cases.

20 This factor determines how the cost varies with size – based on (IEA GHG, 2002) the capital cost of the 1000MW plant is related to the cost of the 550MW plant studied in (NETL, 2007) by the ratio (1000/550)0.8

Table 3.13 Case 1: Illustrative costs for a 1000 MW supercritical power plant with/without capture, Indramayu-West Java

Type of plant: SC PF SC PF with CO2 capture

Fuel Sub-bituminous coal Sub-bituminous coal Calorific value 5100kCal/kg 5100kCal/kg Fuel cost $65/t $65/t Fuel cost $2.94/GJ (HHV) $2.94/GJ (HHV) Net output (MW) 1000 1000 Specific cost ($/kW) 1398 2543 Capacity factor 70% 70% Net plant efficiency (HHV) 39.1% 27.2% Net plant efficiency (LHV) 40.5% 28.2% Emissions (kg CO2/MWh) 803 115 Capture effectiveness 90% 90% Amount of CO2 sent to store - 1039 kg/MWh CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

69.8 112.4

Incremental cost of electricity ($/MWh)

- 42.7

Avoided cost (versus 1000MW plant without capture)

- $62.1/t CO2

As a possible variant on this case, the use of a lower discharge pressure from

the compressor has been considered by approximation, because this might be relevant

for the transport case study (see chapter 4). The effect of reducing discharge pressure

from 15.3 MPa to 13 MPa would add about 0.2%-points to the efficiency of the plant

with capture and reduce the capital cost by less than 1% so, within the accuracy of this

study, it is not appropriate to adjust the results for such changes which are well within

the uncertainties.

Table 3.14 Case 2: Illustrative costs for a 750 MW NGCC with/without capture, Muara Tawar-West Java

Type of plant: NGCC NGCC with CO2 capture

Fuel Natural gas Natural gas Calorific value 47764 kJ/kg (HHV) 47764 kJ/kg (HHV) 39 MJ/scm (HHV) 39 MJ/scm (HHV) Fuel cost $6.4/GJ (HHV) $6.4/GJ (HHV) $0.25/scm (HHV) $0.25/scm (HHV) Net output (MW) 750 750 Specific cost ($/kW) 523 1072 Capacity factor 70% 70% Net plant efficiency (HHV) 50.8% 43.7% Net plant efficiency (LHV) 55.9% 48.1% Emissions (kg CO2/MWh) 340 40 Capture effectiveness - 90% CO2 delivery pressure - 15.3 MPa Amount of CO2 sent to store - 356 kg/MWh Capital factor 11% 11% Levelized cost of electricity ($/MWh)

66.2 87.7

Incremental cost of electricity ($/MWh)

- 21.5

Avoided cost (versus NGCC) - $71.4/ t CO2

Case 3 is a sub-critical power plant burning lignite fuel; this does not have a

close analogue amongst the studies reported in section 3.6 – the closest is the sub-

critical power plant burning bituminous coal which has been used as the basis for this

case study (Table 3.15). The effect on capital cost of the change in size (to 600MW)

has been approximated using a 0.8 exponent; the thermal efficiency of the plant has

been estimated from data on US power plants burning lignite21; the calorific value and

cost of the fuel has been substituted by values appropriate for this location. The

capacity factor has been reduced to 65% to correspond to the load factor expected of

such a plant in the Sumatera power system. The fixed operating costs (essentially

staff) have been kept the same as in the sub-critical case in section 3.6 but the variable

operating costs have been adjusted for the differences in the amount of fuel used. The

physical size of the plant has not been changed because of the larger volume of fuel

used, so the capital cost is likely to be underestimated for this reason. All these

21 US power plants with rating > 400 MW burning lignite have been reported to have thermal efficiency (average of a 13 plants) of 31.2% (LHV) (NETL, 2008b)

changes mean that the results are quite far removed from the engineering numbers

quoted in section 3.6, so should be treated with considerable caution.

With the strong caveats expressed above, the 600MW sub-critical plant

burning lignite would have an incremental cost of electricity as a result of fitting

capture (compared with a plant of the same output without capture) of $51.3/MWh.

As a result the cost of avoiding emissions would be $56.2/t CO2-avoided. The

relatively high incremental cost reflects the lower efficiency expected for this plant

with the type of fuel used. However, the greater volume of CO2 produced by this fuel

has meant that the cost of avoided emissions is below that in case 1.

Table 3.15 Case 3: Illustrative costs for a 600 MW sub-critical power plant using lignite fuel, with/without capture, Bangko Tengah-South Sumatera

Type of plant: Sub-critical PF Sub-critical PF with CO2 capture

Fuel Lignite Lignite Calorific value 4200kCal/kg 4200kCal/kg Fuel cost $55/t $55/t Fuel cost $3.0/GJ $3.0/GJ Net output (MW) 600 600 Specific cost ($/kW) 1523 2843 Capacity factor 65% 65% Net plant efficiency (HHV) 31.1% 22.2% Net plant efficiency (LHV) 32.2% 23.0% Emissions (kg CO2/MWh) 1061 149 Capture effectiveness 90% 90% Amount of CO2 sent to store - 1339 kg/MWh CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

84.6 135.9

Incremental cost of electricity ($/MWh)

- 51.3

Avoided cost (versus 600MW plant without capture)

- $56.2/t CO2

In case 4, the plant is much smaller (100MW) than in any of the examples

considered in section 3.6 so the results should only be regarded as indicative of the

effect of capturing CO2 in a small power plant (Table 3.16). The effect of the change

in size on the capital cost has been represented using an exponent of 0.8 on the cost of

the sub-critical power plant described in section 3.6. The thermal efficiency of the

100 MW plant has been based on US power plants fitted with FGD in the range 100 to

200 MW (NETL, 2008b); the fixed part of the operating cost has been left unchanged

as the number of staff is likely to be similar for the smaller plant; the initial fuel

charge has been reduced to reflect the smaller amount of fuel used by this plant. The

capacity factor of 65% corresponds to the load factor expected of such a plant in the

Kalimantan power system. The calorific value of the fuel and the cost correspond to

values appropriate to the location.

The incremental cost of fitting capture is $68.1/MWh compared with a similar

sized plant without capture. The cost of avoiding emissions is $76.3/t CO2-avoided.

Both of these are larger than the corresponding increments in case 1 due to the less

efficient plant and its smaller size, only partly offset by the lower cost of fuel.

Table 3.16 Case 4: Illustrative costs for a 100 MW sub-critical power plant, with/without capture, Muara Tawar-East Kalimantan

Type of plant: Sub-critical PF Sub-critical PF with CO2 capture

Fuel Sub-bituminous coal Sub-bituminous coal Calorific value 5300kCal/kg 5300kCal/kg Fuel cost $40/t $40/t Fuel cost $1.74/GJ (HHV) $1.74/GJ (HHV) Net output (MW) 100 100 Specific cost ($/kW) 2180 4069 Capacity factor 65% 65% Net plant efficiency (HHV) 30.3% 21.7% Net plant efficiency (LHV) 31.4% 22.5% Emissions (kg CO2/MWh) 1037 145 Capture effectiveness 90% 90% Amount of CO2 sent to store - 1305 kg/MWh CO2 delivery pressure - 15.3 MPa Capital factor 11% 11% Levelized cost of electricity ($/MWh)

103.3 171.4

Incremental cost of electricity ($/MWh)

- 68.1

Avoided cost (versus 100 MW plant without capture)

- $76.3/t CO2

The final case, number 5, involves a different source of CO2. In this case the

CO2 is the waste product of an existing gas sweetening plant. This plant uses a BASF

amine separation system to remove CO2 from the natural gas stream, producing a

concentrated stream of CO2. It is assumed this gas just needs compression before

transportation, so this should be a low cost source of CO2 for storage.

The gas field is in the Subang field (West Java); it produces 200 MMscfd of

gas with CO2 content of 23%. The amine scrubbing system at the processing plant

reduces the CO2 content of the gas to 5%, releasing 1895 tonne of CO2 per day. The

CO2 will be directed to the compressor, where the inlet pressure is assumed to be

0.1MPa; discharge from the compressor is at 15.0 MPa. The compressor has been

costed using the IEA Greenhouse Gas R&D Programme’s pipeline cost estimation

model which is described in Chapter 4. The relevant cost assumptions are as shown

in chapter 4, Table 4.3, namely S.E. Asia costing; 2007 basis for cost data. The

results are shown in Table 3.17.

Table 3.17 Case 5: Illustrative costs for compression of CO2 from natural gas sweetening plant, Subang field

Type of plant: Natural gas sweetening

Natural gas production 200 MMscfd Amount of CO2 extracted 22kg/s CO2 inlet pressure 0.2MPa CO2 delivery pressure 15.0 MPa Compressor rating 8.8MW Capital cost of compressor $13.6 M Operating cost $5.93 M/y Capital factor 11% Annual charge $7.4 M/y Cost of compressing CO2 $10.7/t CO2

The cost of compressing the CO2 reflects the high pressure ratio required but

reducing the delivery pressure to 13MPa would only cut the cost per tonne of CO2

delivered by about 4%. In other such applications of capture from natural gas

sweetening, the gas has been injected into a nearby geological formation so the

pressure required for transport would not be as high. In a purpose designed

installation, the separation system might be designed to take advantage of the natural

pressure available in the gas stream, thereby providing higher pressure CO2 at the

inlet of the compressor, with consequent lower costs. Nevertheless the cost of

avoided emissions is relatively low compared with the power plant examples.

3.9 Implications for Use of CO2 Capture in Indonesia

For new power plant, use of either post-combustion or pre-combustion capture

would generate electricity at similar cost. Which option would be chosen depends,

amongst other things, on the acceptability of IGCC as a large-scale power generation

technology in Indonesia. If it were felt that the reliability of this technology were not

yet high enough to justify its use, then the post-combustion option for capturing CO2

from SC PF or NGCC plant would likely be preferred.

Capture of CO2 adds substantially to the cost of electricity generation, and

reduces the output of the plant to which it is fitted. For large, efficient power plants

the increase in cost of electricity generation varies depending on the type of plant and

the type of fuel burnt – for Sub-bituminous coal the increase is about 60%, for natural

gas the increase is about 32% but for lignite the increase is also about 60%.

Conversely, the cost of avoided emissions is lowest for the lignite burning plant, and

highest for the natural gas plant reflecting the relative carbon contents of the various

fuels; it is also high for the very small plant reflecting efficiency and economy of

scale penalties. In order to justify the extra costs, the owners of power plants

wishing to fit capture would need to find additional sources of revenue, such as

international emissions trading allowances or international support for emission

reduction projects.

The size of a new plant with capture should be such that it can deliver the

required electricity service, which is likely to mean that the units should be larger than

would be the case without capture. This would also allow the operator to take

advantage of economies of scale in capture.

CO2 capture technology could be fitted to other industrial plant, such as

hydrogen and ammonia production plant, natural gas sweetening plant, in some of the

units in an oil refinery and in certain chemical production plants. Some of these could

provide relatively low cost opportunities for capturing CO2. Further examination of

the characteristics of the particular industrial sites would be needed to determine their

suitability for capturing CO2.

Similarly, existing power plant could be retrofitted with capture, or capture

could be fitted as part of a rebuilding programme where the efficiency of the base

plant was also improved. It is not feasible to generalise about the cost of retrofit or

rebuilding because individual circumstances vary so much.

References

Agarwal, P., 2004: Ammonia: The Next Step. http://www.cheresources.com/ammonia.shtml Bozzuto, C. R., Nsakala, N., Liljedahl, G., Palkes, M., Marion, J., Vogel, D., Fugate, M., Guha, M., “Engineering Feasibility and Economics of CO2 Sequestration/Use on an Existing Coal-Fired Power Plant. Volume I: AEP’s Conesville Power Plant Unit No. 5 Retrofit Study,” Prepared for the Ohio Department of Development, Ohio Coal Development Office and US Department of Energy, National Energy Technology Laboratory (June 30, 2001). Falk-Pedersen, O., H. Dannström, M. Grønvold, D.-B. Stuksrud, O. Rønning, 2001: Gas treatment using membrane gas/liquid contactors. Published in Proceedings of the 5th International Conference on Greenhouse Gas Control Technologies, (Williams, D., Durie, B., McMullan, P, Paulson, C., and Smith, A., (eds.)) pp 115-120. CSIRO, Australia. Feron, P.H.M. et al., 1992: Membrane technology in carbon dioxide removal. Report number 92008, TNO, Apeldoorn, Netherlands. Fleming, E.A., L.M. Brown, R.I. Cook, 1992: Overview of Production Engineering Aspects of Operating the Denver Unit CO2 Flood, paper SPE/DOE 24157 presented at the 1992 SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, 22—24 April. Society of Petroleum Engineers Inc., Richardson, TX, USA. IEA GHG, 1993: Capture of CO2 from fossil fuel fired power stations. Report SR2. IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2000a: Leading options for the capture of CO2 emissions at power stations. Report PH3/14. IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2000b: Key components for CO2 abatement: gas turbines. Report Ph3/12. IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2002: Workbook for screening options to reduce CO2 emissions from existing power stations. Report Ph4/7. IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2004, Improvement in power generation with post-combustion capture of CO2, report PH4/33. IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2005, Retrofit of CO2 capture to natural gas combined cycle power plants, report 2005/1, IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2006, CO2 Capture as a factor in power station investment decisions, report 2006/8, IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IEA GHG, 2007, CO2 capture ready plants, report 2007/4. IEA Greenhouse Gas R&D Programme, Cheltenham, UK

IPCC, 2005: IPCC Special report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [Metz, B., O. Davidson, H.C. de Coninck, M. Loos and L.A. Meyer (eds.)]. Cambridge University Press, Cambridge, UK. Jaeger, H., 2009: Oxyfuel repowering can achieve near 100% CO2 capture and big power boost. Gas Turbine World, 39 (1) 16-24. Kohl, A. L. and R.B. Nielsen, 1997: Gas Purification. Gulf Publishing Company, Houston, TX, USA. Marsh, G., J. Bates, H. Haydock, N. Hill, C. Clark, P. Freund, 2003: Application of CO2 removal to the Fischer-Tropsch process to produce transport fuel. Proc 6th Int Conf Greenhouse Gas Control Technologies, Gale and Kaya (eds), Pergamon, 2003. de Mello, L.F., R.D.M. Pimenta, G.T. Moure, O.R.C. Pravia, L. Gearhart, P. B. Milios, T. Melien, 2008: A technical and economical evaluation of CO2 capture from FCC units. In proceedings of the 9th international conference on greenhouse gas control technologies, to be published, Elsevier Science MIT, 2007: The Future of Coal - options for a carbon-constrained world, MIT, Cambridge, MA, USA. Moliere, M., 2004: Hydrogen-fuelled Gas Turbines: Status and Prospects. Presented at 2nd CAME GT conference. Bled, Slovenia NETL, 2004: World Gasification Survey 2004. National Energy Technology Laboratory, 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, PA 15236, USA. NETL, 2007: Cost and Performance Baseline for Fossil Energy Plants; Volume 1: Bituminous Coal and Natural Gas to Electricity, August 2007, report DOE/NETL-2007/1281. NETL, 2008a: CO2 Capture-Ready Coal Power Plants, Final Report, April 2008, DOE/NETL- 2007/1301. NETL, 2008b: NETL Coal Plant Database, 2008. National Energy Technology Laboratory, 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, PA 15236, USA. O’Keefe, L. F., J. Griffiths, N. East, J. M. Wainwright, R. A. De Puy, 2002: A Single IGCC Design for Variable CO2 Capture, Fifth European Gasification Conference, April 2002. Pröll, T., K. Mayer, J. Bolhàr-Nordenkampf, P. Kolbitsch, T. Mattisson, A. Lyngfelt, H. Hofbauer, 2008: Natural minerals as oxygen carriers for chemical looping combustion in a dual circulating fluidized bed system. In proceedings of the 9th international conference on greenhouse gas control technologies, to be published, Elsevier Science

Ramezan, M., N. ya Nsakala, G. N. Liljedahl, L.E. Gearhart, R. Hestermann, B. Rederstorff, 2006, “Carbon Dioxide Capture from Existing Coal-Fired Power Plants” report prepared for DOE/NETL, number 401/120106, December 2006 Reynolds, S.P., A.D. Ebner, J.A. Ritter, 2005: New pressure swing adsorption cycles for carbon dioxide sequestration. Adsorption 11 (2005) 531-536. Rice, S.A., 2004: Human health risk assessment of CO2: survivors of acute high-level exposure and populations sensitive to prolonged low level exposure. Poster 11-01 presented at 3rd Annual conference on carbon sequestration, 3-6 May 2004, Alexandria, VA, USA. Ritter, J.A. and A. D. Ebner, 2005: Separation technology R&D needs for hydrogen production in the chemical and petrochemical industries. Report prepared for US DOE and Chemical Industry Vision 2020 Technology Partnership. http://chemicalvision2020.org. Rutkowski, M.D., R.L. Schoff, N.A.H. Holt, G. Booras, 2003: Pre-Investment of IGCC for CO2 Capture with the Potential for Hydrogen Co-Production. Presented at US Gasification Technologies Conference, 2003 Shilling, N.Z. and R.M. Jones, 2004: Gas turbine experience with high hydrogen fuels. Presented at Power-Gen Europe, 2004. Shilling, N.Z. and D.T. Lee, 2003: IGCC - Clean power generation alternative for solid fuels. Presented at Powergen Asia, 2003. Shook, B., 2008: Exxon develops cheaper, easier CO2 separation system. World Gas Intelligence, 14 May 2008. Simbeck, D., 2001: CO2 Mitigation Economics for Existing Coal-Fired Power Plants, in First National Conference on Carbon Sequestration, Washington, DC. Tigges, K.-D., F. Klauke, C. Bergins, K. Busekrus, J. Niesbach, S. Wu, A. Kukoski, M. Ehmann, B. Vollmer, T. Buddenberg, 2008: Oxyfuel Combustion Retrofit for Existing Power Stations, presented at Power Plant Air Pollutant Control Symposium August 25, 2008, Baltimore, MD. Weishaupt, R., 2006: Purification and CO conversion downstream the gasification. Paper presented at 7th European Gasification Conference, Barcelona, 2006. Yong, Z. and A. E. Rodrigues, 2001: Adsorbent materials for Carbon Dioxide. Adsorption Science and Technology 19 (2001) 255-266.

CHAPTER 4

TRANSPORTATION TECHNOLOGY

4.1 Introduction to Transportation options and conditions

Having captured the CO2, the next step in the CCS chain is to transport it to

the storage site. This needs to be done at the lowest cost and with the greatest

confidence for safe delivery of the CO2. There are several modes of transport that

could be used, as will be described below. A number of factors have to be taken into

account in considering transport, for example what preparation of the CO2 is needed

for the chosen method of transport and, once the CO2 has been delivered to the

storage site, what further conditioning is needed, such as raising the pressure to a level

suitable for injection underground? So the requirements of the preceding and the

following stages of the CCS chain will affect the design of the transport system, as

will be discussed below. After that a number of cases will be examined where CO2

might be transported in Indonesia in future. This will allow us to discuss some of the

factors that determine the cost of transportation for CCS projects.

4.1.1 Methods of transporting CO2

Various options are available for transporting CO2 including road tankers, rail

tankers, pipelines and ship tankers. Each will have its particular niche in the market

place – in broad terms, road and rail tankers are appropriate for delivering quantities

of tens to hundreds of tonnes at a time. Pipelines are the industry standard method of

moving millions of tonnes of CO2 per year especially over distances of hundreds of

kilometres. They can be used both onshore and subsea. Ship tankers are capable of

delivering thousands of tonnes in one cargo currently, and could be used to deliver

tens of thousands of tonnes in future. However, such ships would be restricted to

capture and storage locations which could be served from the sea. Otherwise,

pipelines would be required to bring CO2 to the port or to take it from the receiving

port to the storage site.

4.1.2 Characteristics of CO2 Supply

The physical and chemical condition of the CO2 delivered by the capture

facility will depend on the particular type of capture technology. It is likely that the

CO2 will be cleaned and dried as part of the capture facility but the extent to which

further clean-up is needed will depend on the transport mode to be used, as will be

discussed later. For pipelines, the CO2 would be compressed, putting it into the

‘dense phase’ where the density is nearly as great as that of liquid water. As a result,

relatively small diameter pipelines (up to one metre in diameter) can be used to handle

large quantities of CO2 (e.g. from several full size power plants).

For transport in ships, the CO2 would be refrigerated to a liquid state, which

allows use of storage tanks operating at lower pressure than used in pipelines, and

hence lower cost.

In the case of road, rail or ship transport, there may be a need for an

intermediate storage facility to match the production rate of the capture facility with

the off-take by the transport system. This is not as necessary for pipeline transport but

even there it may be necessary to match intermittent production of CO2 with

continuous flow along a pipeline. Such intermediate storage could be done in tanks or

underground in geological formations.

4.1.4 Demands of CO2 Storage

The needs of the storage facility will impose requirements on the condition of

the CO2 delivered to the site - these will influence the design of the transport system,

mainly in terms of required delivery pressure. The requirements of the storage system

in terms of CO2 purity will be no more severe than the requirements of the transport

system in terms of purity. Indeed in places such as Canada, geological storage is

already used to dispose of acid gases (i.e. mixtures of H2S, CO2); in such cases the

transport pipeline has to be made resistant to corrosion by the acid gases. This is not

expected to be the case in Europe, where it is likely that only almost pure CO2 would

be accepted for injection underground. It is assumed that the same will apply in

Indonesia, so a basic assumption of this chapter is that the gases to be transported will

consist predominantly of CO2.

The injection facility might be designed to use CO2 in the condition in which it

is delivered to the site; otherwise, the pressure of the CO2 will have to be raised before

injection, so as to meet the reservoir engineering requirements. This is most likely to

be the case if there is substantial distance between capture and storage locations. The

extent to which the pressure falls during transport will depend on many factors; re-

pressurisation may be needed at an intermediate point in the pipeline, using a booster,

although the pipeline designer may be able to avoid this by increasing the diameter of

the pipeline.

4.2 Conditioning for Transport

4.2.1 Purification

The standards for the purity of CO2 admitted into a pipeline are determined by

the operator; these will reflect the need to protect the pipeline against corrosion, as

well as to protect the neighbourhood through which it passes (in case of leaks), as

well as to serve the needs of the end-user (i.e. the storage facility).

For example, in the case of the CO2 pipeline from Beulah (USA) to Weyburn

(Canada), the CO2 stream typically contains 95.95% CO2, with approximately 0.8%

H2S. The rest of the gas consists of small amounts of various hydrocarbons such as

ethane, methane, propane, etc. which are acceptable for injection into the oil field at

Weyburn.

Pipelines are typically constructed from carbon-manganese steels, using

welded joints; dry CO2 does not corrode such steel (IPCC, 2005); indeed moisture up

to 60% relative humidity can be tolerated, even in the presence of N2, NOx and SOx.

However, the presence of free water would lead to rapid corrosion, in which case

stainless steel pipe would be needed, which is much more expensive. The diameter of

the pipeline is determined as an optimisation between the size of the pipe and the

number of booster stations required en route to raise the pressure. Block valves are

included at regular intervals so as to be able to isolate lengths of line; the separation of

the block valves is determined by the potential amount of gas that could be released in

the event of an accident and the possible risk this could present to neighbours.

If the liquid CO2 is to be transported as a refrigerated liquid, any moisture in

the gas could block the liquefaction process or form hydrates in the lines; such water

can be removed in the process of compression, at the entry to the liquefaction unit,

followed by solid absorption (PSA) to remove final traces. Any other impurities will

have to be removed at the capture plant.

4.2.2 Pressurisation

CO2 is compressed for pipeline transport, raising the pressure to a level greater

than 7.4MPa (74bar), the pressure of the critical point, so that the density is more than

700 kg/m3. At these pressures CO2 is said to be in its ‘dense phase’. The temperature

of the CO2 in the pipeline will vary – being highest at the point of discharge from the

compressor (the precise value being dependent on the design of compressor). It then

declines to ambient temperature as the CO2 moves along the pipeline (the rate of

decline of temperature will be influenced by many site-specific factors). For the parts

of the line where the temperature is more than 31.1oC, the CO2 will be in the

supercritical state.

By convention in performance assessments of power plants, compression is

considered together with the capture stage because the initial compressor would

typically be located on the power station site, so the electricity consumed by it will be

included with other ancillary uses. However, it is more appropriate to discuss the

technology of compression in the context of transport as this is what determines the

compressor’s duty.

Industrial experience with gas compression is available to design and

manufacture compressors for CO2 - the large scale of these machines and the

conditions of operation mean this is a specialised design task; there are only a few

compressor manufacturers worldwide able to provide suitable machines. The largest

system currently in use for CO2 is at the Dakota Gasification plant in USA where 3

internally-geared centrifugal compressors (in parallel) supply CO2 through a pipeline

to the Weyburn oil field (for details of this line, see 4.3.4 below). Each of these 15

MW compressors has a capacity of approximately 1.6 Mt CO2/y, raising the CO2

pressure from about 0.05 MPa above ambient, as received from the capture unit, to

nearly 18.5 MPa for injection into the pipeline. In other oil fields, reciprocating

compressors are used for similar duties.

4.2.3 Liquefaction

In order to transport CO2 by ship, it is first necessary to liquefy it. This will be

done at an onshore liquefaction plant, probably close to the docks. As the shipping

operation consists of a cycle of load-transport-offload-return, there would need to be

storage facilities to hold liquefied CO2 at the loading point and possibly at the

discharge point.

Several gases are shipped today in liquid form (e.g. LNG, LPG). In order to

put CO2 into a liquid state, it would first be pressurised and then cooled for transport;

this is analogous to how LPG is transported by ship. The conditions for transport of

liquid CO2 are likely to be about 0.7 MPa pressure (7 bar) at -50oC.

The largest pressurised, refrigerated LPG ships currently in use have capacity

of about 30,000m3, with the cargo held in a number of separate tanks. It is expected

that similar technology could be used to construct CO2 carriers. In a study for the

IEA Greenhouse Gas R&D Programme (IEAGHG, 2004), a range of capacities of

CO2 carriers was considered: – 10,000t, 30,000t and 50,000 t1.

If CO2 is captured in a power plant, it is likely to be available from the capture

unit at a pressure slightly above atmospheric. At the liquefaction plant, the CO2

would first be compressed, then dried and cooled using an external refrigeration

system; after that it would be partially depressurised to reach the shipping pressure;

the depressurisation stage would also provide an extra degree of cooling. If the

liquefaction unit was not close to the capture plant, the captured CO2 would be first

compressed and then transported through a pipeline to the liquefaction unit thereby

avoiding the need for further pressurisation at the liquefaction plant.

Buffer storage at the loading port would consist of pressurised spherical tanks,

each with capacity of 10-20,000m3, similar to the capacity of the tanker vessel itself.

Loading of the ships in port would be done by pumping the liquid through

booms similar to those developed for LPG and LNG, using pumps adapted for high

pressure/low temperature service.

4.3 Transport Options

4.3.1 Description of the Main Options

Transport of CO2 is routinely done today using road, rail and ship tankers as

well as pipelines. Road tankers are most suitable for small quantities (i.e. tens to

hundreds of tonnes per day), whilst rail and ship tankers and pipelines can handle

1 For comparison with the LPG example, it may be noted that the density of liquid CO2 in the tanker would be slightly more than 1t/m3.

progressively larger amounts. IPCC (2005) reported that design studies for the

SACROC project in the USA (which handles 4.4Mt/y of CO2 for enhanced oil

recovery) found that road and rail options would have cost more than twice as much

as the pipeline method.

4.3.2 Road

Road tankers are used today for distributing CO2 to local users. The CO2 may

be handled as pressurised gas or refrigerated liquid or as dry ice2. Typical tanker

capacities are up to about 20t of CO2 per vehicle. Thus a 500 MW coal-fired power

station (where around 2Mt/y of CO2 might be captured) would require 10 vehicles per

hour, 24 hours/day.

Even ignoring issues such as the amount of fuel used by these vehicles (and

the consequent emissions) road transport seems unlikely to be a feasible solution for

transporting large amounts of CO2 captured at a full-size power station. A more

realistic scale for use of road transport is that of the CO2SINK research project in

Germany which receives about 20,000t of CO2/y by road from a chemical plant.

4.3.3 Rail

The use of trains to transport liquids and gases is well established in countries

with suitable rail networks. This mode is used, for example in the UK, by CO2

suppliers for bulk transport of CO2 (in quantities of hundreds of tonnes of CO2)

between production sites and distribution terminals, where it is trans-shipped for

distribution to customers by road or converted into dry ice for use by the food

industry.

Rail transport could be used for moving CO2 to storage locations onshore. In

the case of offshore storage, a rail system could only meet part of the transport need,

so would have to deliver CO2 to an alternative method of transport to convey it

offshore, with consequent extra costs due to duplication of systems and potential

losses in transhipment. As it seems likely that, in Indonesia, storage would be

offshore or involve a sea crossing, use of rail would imply extra transhipment. For

this reason, rail transport is not considered further here.

2 Dry ice is mainly used for food refrigeration applications.

4.3.4 Pipeline

Pipelines are the established method of transporting CO2 in bulk for industrial

uses. There is a total of 2600km in operation today (Gale and Davison, 2002) mainly

onshore in USA. These long distance pipelines have capacity for 50 Mt CO2/y; the

oldest of these was built in 1984. Thus there is a significant body of experience

familiar with onshore CO2 pipelines. Some examples are indicated below.

Typically, pipelines are constructed in mild steel using welded joints and are

coated to protect against external corrosion. In the case of wet CO2, pipelines would

need to be constructed in stainless steel to resist internal corrosion. Onshore pipelines

are normally buried in trenches, filled after emplacement to protect the line from

disturbance.

Once permission has been received for construction of a line, an onshore

pipeline is constructed from sections of pipe which are then moved to the site, welded,

coated and placed in the trench. After hydrostatic testing, the line is dried and the

trench backfilled. Offshore, the process is more complicated, which adds to the cost.

For small diameter lines, up to 450mm diameter, the sections of line are welded

together onshore and placed on a reel; the reel is loaded onto a ship and unwound into

the sea where it is allowed to fall, as a suspended span, into its final position on the

seabed. This method was used for installing the 150km CO2 line from Melkøya

island to the Snøhvit storage site in the Barents Sea, offshore Norway. For larger

diameters, each section of line is joined to the previous one by welding, on a lay-

barge, and is then coated; the barge, which is moored or dynamically positioned, is

moved forward gradually, drawing the line into the sea. Typically, if trenching is

needed, this is done after the line has been laid on the seabed.

The difficulty of construction is roughly proportional to the depth of sea

multiplied by the diameter of the line (IPCC, 2005). Special measures are needed

close to the shore and in crossing the beach to protect the line and avoid

environmental damage in such a sensitive environment.

The SACROC enhanced oil recovery project in the USA is supplied by a

pipeline operated at 9.6 MPa (so that the CO2 is in the dense phase); the operators

considered whether to use a lower operating pressure (4.8 MPa) but found that use of

the higher pressure reduced overall costs by 20%. This line is 352 km long and has

capacity to carry 5.2 Mt/y of CO2, captured at gas processing plants in Texas, to oil

fields in other parts of the state.

Currently the largest CO2 pipeline, the Cortez line, with diameter 760mm, has

capacity to carry 19.3 Mt/y from a natural CO2 field in Colorado to oil fields in Texas.

The 500mm diameter Bravo Dome line (USA) carries 7.3 Mt/y of CO2 over a distance

of 350km.

A 328 km pipeline carries CO2 captured at the gasification plant in Beulah in

North Dakota (USA) to the Weyburn oil field in Canada. For the first half of the

distance, the pipe has outside diameter of 356mm; for the remaining distance within

the USA and for the whole distance in Canada, a line with diameter of 305mm is

used. CO2 is supplied to the line at 18.5 MPa pressure and is delivered to the oil field

at 15.1 MPa without any intermediate re-pressurisation. At 11 locations along the

line, tapping points were installed during construction (in 2000) to allow easy off-take

of CO2 to serve potential customers at oil fields in the region.

In planning a pipeline, one important aspect is the economics of the line – this

includes the cost of acquiring access to the land, purchase and installation of the

pipeline and any related facilities, such as booster compressors, as well as monitoring

the line during its use. Although it is not expected that such lines will leak (other than

in exceptional circumstances), the possible consequences of leakage will also be

considered during the design process (Barrie et al, 2005); the effects of leakage can be

mitigated by choosing an appropriate distance between block valves to limit the

amount released, by suitably locating the pipeline (i.e. away from habitation, taking

account of the fact that CO2 is denser than air and so will sink into hollows) and by

limiting the impurities present in the CO2 (e.g. avoiding appreciable amounts of H2S

which would present a hazard).

Accidents on the existing CO2 pipelines have been found to occur with similar

frequency to those on other long-distance pipelines (IPCC, 2005). Preventative

measures, such as increasing the depth at which a line is buried from 1m to 2m, have

been found to reduce the frequency of damage to natural gas pipelines by a factor of

10 in rural areas and 3.5 in suburban areas (Gujit, 2004). Similar measures should

also be used in design of CO2 pipeline systems.

There has been interest in various places in reusing existing pipelines for

transporting CO2 – for example, in the Netherlands the first project which transports

CO2 over a long distance reuses parts of a disused oil pipeline; in the UK a study was

commissioned to assess opportunities for reusing gas pipelines in the Southern North

Sea; in Scotland (part of the UK), a recently announced project has proposed using a

surplus onshore natural gas pipeline to transport CO2 to the shore terminal, where

another existing (gas) pipeline would be used to transport the CO2 to a disused gas

field. As well as potentially saving money by re-using existing assets, this approach

could also have advantages in terms of speed in establishing CO2 transportation since

the formalities of introducing a pipeline to the area would already have been satisfied

- all that would be needed would be permission to change its use.

Indonesia already has several long-distance pipelines for transporting natural

gas – it is not known whether any of these might become available for transporting

CO2 at some time in the future but this opportunity would be worth further

investigation as reuse of an existing pipeline could be a means of initiating CO2

transport in the region. Eventually, purpose-made lines would be needed for

development of a widespread CO2 transportation system.

4.3.5 Shipping

Transport by ship holds the CO2 cargo at a temperature of about -50oC and

pressure of 0.7 MPa; these conditions are broadly similar to those used for transport of

LPG (IPCC, 2005) but differ from those used in the low temperature refrigerated

vessels used for LNG. Nevertheless, LPG and LNG tankers carry similar liquids so,

by analogy, it can be assumed that CO2 tankers might be built with similar capacities,

up to 200,000t of CO2. In practice, vessels of one-tenth of that capacity would be

appropriate for transporting the CO2 captured at one large power station – these would

be similar to tankers used to transport LPG today. There are already smaller tankers

in use in different parts of the world carrying CO2 as commercial cargoes.

An assessment carried out for the IEA Greenhouse Gas R&D Programme

(IEA GHG, 2004) examined 3 sizes of ship – vessels of 10,000 tonne and 30,000

tonne capacity would have 4 spherical insulated storage tanks, and a 50,000 t ship

would have 5 such tanks. These ships could travel at speeds of 15 or 18 knots (27.8,

33.3 km/h respectively). A number of distances for shipment were considered,

between 200 km and 12000 km, the lower end of the range being appropriate for

schemes involving regional storage, such as the North Sea; the upper end of the range

being appropriate for possible intercontinental shipment of CO2 from major sources

(such as Japan or Europe) to areas where geology provides large potential capacity for

storage (for example, the Middle East). In the longer distance cases, a fleet of 10 -15

vessels would be needed to maintain continuity in the movement of CO2 to store.

4.4 Receipt of CO2 at Storage Site

The CO2 delivered by pipeline should be ready for injection underground,

although some increase in pressure may be needed to meet the design conditions of

the store.

For ship transport of CO2, it may be necessary to construct buffer storage

facilities at the storage site if the injection facilities cannot cope with an intermittent

supply of CO2. This storage would be similar to that used at the loading point. In the

IEA GHG study (IEA GHG, 2004), buffer capacity was not included as it was

assumed the storage facility could cope with variations in supply. At the discharge

point, once the tanks were emptied of liquid, they would be refilled with dry gaseous

CO2 to avoid humid air contaminating them before the ships returned to the loading

point.

4.5 Comparison of Costs of Transport Options

In considering how to present information on costs of CCS, it is important to

recognise that the quantity of CO2 transported is similar to the amount of CO2

captured – but both of these are greater than the amount of emissions-avoided because

of the ancillary energy used by the capture and transport systems. This has to be

taken into account in assembling the overall costs of a CCS project.

4.5.1 Pipeline Costs

The cost of pipelines includes construction, operation and maintenance. It is

strongly influenced by the capacity of the line, by the terrain traversed, as well as the

length of the line. Offshore pipelines tend to be more expensive than onshore

pipelines. Intermediate booster stations may be required to compensate for pressure

loss on longer pipelines. The cost of transport rises proportionally with distance - this

is typically expressed as a specific cost per unit length i.e. $/t CO2/250km, as shown

in Figure 4.1. Please note that this simplified diagram is not intended to represent the

cost of any particular line and does not specifically include booster compressors

which may be needed in some longer lines.

The initial projects in a region are likely to transport CO2 from one power

plant to one storage location; such an approach may suffer disproportionately high

costs for transport. If several power plants were to be equipped with capture, the

transport costs (per tonne) could be reduced by sharing a (larger) diameter pipeline.

However, establishing such a system would require larger initial investment which

may not be remunerated by the level of use in the early years.

Figure 4.1 shows that transporting 6 Mt/y CO2 over a distance of 250km

would cost about $2-3/t onshore and $3-4/t offshore (IPCC, 2005). The reason for the

difference in cost between onshore and offshore lines reflects the different techniques

that were described in 4.3.4 above. Smaller quantities would cost considerably more

(per tonne) to transport; for example transport of 3 Mt/y onshore would cost about $3-

5/t over a distance of 250km.

Figure 4.1 Variation in cost of CO2 transport with flow rate in onshore and offshore pipelines (IPCC, 2005) summarising a range of published reports – solid lines indicate lower bound,

dashed lines indicate upper bounds for each set.

For onshore projects in the USA, the Future of Coal study (MIT, 2007)

indicated that pipeline costs would vary with distance and quantity transported, as

shown in Figure 4.2. Transport costs are highly non-linear for the amount

transported3, with full economies of scale only being achieved at throughput above

about 10 Mt CO2/yr. Although Figure 4.2 shows typical values, these costs can vary

greatly from project to project due to both physical and political considerations.

The design of a possible pipeline network in/around the Humber Estuary in

North East England was studied for Yorkshire Forward (2008). A range of designs

was considered (with lengths ranging from 100 to 400km) collecting CO2 from a

number of industrial sources onshore for transportation to storage offshore. The

amount of CO2 transported by the system would peak at about 40-50 Mt CO2/y.

Figure 4.2 Cost of CO2 transport by pipeline (in $/t/100km) as a function of mass flow rate

(in Mt/y) from (MIT, 2007).

In the “Central” scenario used by Yorkshire Forward, a total of 846 Mt of CO2

would be transported between 2008 and 2040. The capital cost of the pipelines was

estimated at about £2000M (c.$3000M). Over the projected 32 year life of the project

(to 2040), total operating costs would amount to £6300M (c.$9000M). The present

value of the cost of CO2 transport was found to be £1.7/t ($2.4/t); this figure may be

approximately converted into a measure comparable to those in the study (MIT, 2007)

– in these terms, the specific cost of CO2 transport is $0.6 - 2.4/t CO2/100km (at

current exchange rates), somewhat higher than the MIT value. These figures are

influenced by many factors, not least the higher cost of UK operations and the cost of

laying pipelines offshore rather than onshore. Nevertheless, this does help to

3 This non-linearity reflects the fact that the capacity of a line is proportional to the square of the diameter of the line so that lines less than about 300mm diameter carry disproportionately higher initial and fixed costs because of the small amount of CO2 being transported; for larger quantities, these costs are spread over larger amounts of CO2.

demonstrate the potential for larger pipeline networks to reduce the specific cost of

transporting CO2.

4.5.2 Shipping Costs

The cost of ship transport of CO2 to storage is not known with as much

confidence as the cost of pipelines (IPCC, 2005) because no large-scale systems have

been built. Capital and operating costs of the various elements of the system can be

estimated by normal engineering studies but until these systems have been constructed

and operated there must be substantial uncertainty associated with the results. The

components to be costed include the ships themselves, the port operations, the

liquefaction unit, and any intermediate storage. A few design studies have been

carried out but published costs vary significantly. IEA GHG (IEA GHG, 2004)

showed that costs depend only weakly on distance for short distances (less than

1000km) but strongly on distance for longer trips (>3000km) – see Fig. 4.3. This

study also found that the economies of scale became saturated for ship sizes larger

than several thousand tonnes (the specific point at which this happens was not

identified specifically).

Statoil (IPCC, 2005; Aspelund et al, 2006) considered a shipping system with

capacity 5.5 Mt/y with distance from source to store of 7600km. The speed of the

ships was 20 knots (35km/h). The costs of the ships were 30 to 50% more than a

similar size ship designed to carry LPG, i.e. between $50M and $70M for a 20,000 to

30,000 t ship (IPCC 2005). In comparison, the IEA GHG study (IEA GHG, 2004)

estimated the cost of a 30,000t ship at $60M.

A major influence on the cost of these schemes is the liquefaction unit; the

cost of this can be considerably reduced if the CO2 is supplied under pressure (e.g. 10

MPa) as would be the case for delivery by pipeline. However, there is considerable

disagreement between published sources about the cost of liquefaction. Statoil

estimated that a liquefaction unit suitable for 1Mt/y of CO2 would cost between $35

and $50M; the IEA GHG study estimated the cost of a 6.2 Mt/y unit be $80M, which

is not much greater despite the considerably larger size of plant. This suggests that

the specific cost of the Statoil unit was 30 to 90% higher than the cost of the IEA

GHG unit. As no CO2 liquefaction has been built at this size, it is very difficult to

know which of these figures might be more accurate.

Specific costs for transport of 5.5Mt/y were found by Statoil to be $55/t CO2

(including compression of CO2 prior to liquefaction) or $42/t without compression

(i.e. assuming this is done at the power plant). IEA GHG (2004) showed that for

shorter transport distances (less than 1000km) costs are spread roughly evenly

between the ships, and the harbour facilities / liquefaction plant (see Fig.4.3),

amounting to a total of $17 to 20/t CO2 for 6.2Mt/y CO2 (with CO2 supplied at

atmospheric pressure, using 30,000t ships).

0

100

200

300

400

Annual charge ($M)

200 500 1000 3000 6000 12000

Distance (km)

Shipping cost

Liquefaction Tank Loading Ship Harbour fee

Figure 4.3 Annual cost of transporting CO2 in 30,000 t ships as a function of distance

For longer distance transport of the same amount, the cost rises to $27/t CO2 at

3000km and to $58/t CO2 at 12000 km (for 30,000t ships with CO2 supplied at

atmospheric pressure) mainly because of the need to purchase extra ships. The cost

would reduce to $10-12/t in the shorter distance case, if CO2 were supplied at pressure

(e.g. 10 MPa) reflecting the importance of pressurisation in the cost of the liquefaction

plant.

Another interesting variant (one that was not explored in the IEA GHG study)

is for shipping smaller quantities of CO2 over short distances (for example, this might

be a relevant situation in the early stages of development of a CCS-chain). A rough

estimate based on the case above with CO2 supplied at atmospheric pressure but in

half the quantity (3.1Mt/y), suggests that the cost of shipping CO2 over a 200km

distance would be around $25/t CO2 (i.e. about 50% increase on the full size system).

4.5.3 Comparison between Costs of Shipping and Pipelines

IPCC (2005) presented a graph illustrating the cost of transporting 6 Mt/y of

CO2 as a function of distance for offshore pipelines and ship transport; an example of

onshore pipeline costs is also shown although this is not directly comparable with the

shipping case. Shipping costs included intermediate storage facilities, harbour fees,

fuel costs and loading/unloading activities as well as the additional costs for

liquefaction (Fig 4.4).

Figure 4.4 Comparison of cost of transporting 6 Mt/y CO2 by pipeline or ship (IPCC, 2005).

Fig. 4.4 illustrates that at a certain distance (around 1000km in this graph) the

cost of shipping CO2 is similar to that of using an offshore pipeline to transport the

CO2 this cost is about $14/t CO2. This particular result is specific to the case of

transporting 6Mt/y; in practice the break-even distance will depend on many factors.

At smaller distances or larger quantities, a pipeline would be the cheaper option. At

greater distances the cost of shipping would be considerably less than for use of a

pipeline. There is substantial uncertainty in these numbers as only 2 published studies

were found by IPCC (2005) that provided cost data.

Increasing the annual quantities transported will tend to shift the break-even

point (where shipping becomes competitive with pipelines) towards longer distances.

For smaller quantities, the break-even distance might be less than shown but this

tentative conclusion would need to be confirmed for any particular case of interest.

4.6 Environmental Aspects, Risks, Safety and Other Considerations

Pipeline and marine transportation systems have an established and good

safety record (IPCC, 2005). An impression of the likelihood of accidents with the new

concept of CO2 transport can be found by considering the performance of related but

established systems, such as those used for natural gas transport. This can provide

useful insight into the likely safety of CO2 transport, not least in addressing the public

acceptability of CO2 transport, as these established systems are more familiar to

society at large.

4.6.1 Accident Rates of Established Transport Systems

In view of the relatively small number of CO2 tankers in use at present, it is

more useful to consider the statistics of accidents to comparable ship tankers and

similar vessels. Between 1978 and 2000, there were 41,086 incidents affecting such

vessels, according to Lloyds Maritime Information Service (IPCC, 2005). Of these,

2129 were classified as “serious” – these are summarised in Table 4.1. LNG tankers

are carefully designed and operated so there have been no accidental losses of cargoes

from such ships. LPG tankers have experienced a slightly higher frequency of

incidents. It is expected that CO2 tankers would be designed to similar standards as

LPG tankers and operated in a similar way. This suggests that a very low accident

rate would be expected for CO2 tankers.

Table 4.1 Statistics of serious incidents for various types of ship tankers and bulk carriers (IPCC, 2005)

Ship type Number of ships 2000

Serious incidents 1978-2000

Frequency (incidents/ship-year)

LNG tankers 121 1 0.00037 LPG tankers 982 20 0.00091 Oil tankers 9678 314 0.00144 Cargo/bulk carriers 21407 1203 0.00250

For pipelines, statistics are available from the USA for CO2 pipelines (Gale

and Davison, 2002). These show that there were 10 incidents between 1990 and

2002, with an incident rate of 0.00032/km.y. There were no injuries to people or

fatalities from these accidents; total damage to property from these incidents was US$

469,000. The main reasons for these accidents were:

§ Relief value failure

§ Weld/gasket/valve packing failure

§ Corrosion

§ Outside force

For natural gas lines, the most frequent cause of accident is outside force.

Even so the frequency of incident was below 0.0002/km.y in 2002 (Gujit, 2004). In

the USA, incidents that led to fatality, inpatient hospital treatment or property damage

of more than US$50,000 occurred with a frequency of 0.00011/km.y. In view of the

different sample sizes (i.e. CO2 v natural gas), it is concluded that these data support

the hypothesis that the frequency of incidents would be similar for these 2 different

uses of pipelines.

However, the consequences of failure would be different – for example, the

flammability and explosive potential of natural gas can have serious consequences in

terms of damage. In contrast, due its lack of flammability, leaks of CO2 would not

cause so much damage but could threaten human and animal life as CO2 is denser

than air and has the potential to cause asphyxiation. This is explored in the next

section.

4.6.2 Safety

CO2 is a normal constituent of the atmosphere, where it is present in low

concentrations (0.037%) and is generally considered harmless. Most people with

normal cardiovascular, pulmonary-respiratory, and neurological functions can tolerate

without harm exposure to CO2 in concentrations between 0.5% and 1.5% CO2 for

several hours. Exposure to higher concentrations or longer duration is hazardous –

either by reducing the concentration of oxygen in the air to below the 16% level

required to sustain human life, or by entering the body, especially the bloodstream,

and/or altering the amount of air taken in during breathing. The U.S. occupational

exposure standard allows eight hours continuous exposure with a maximum

concentration of 0.5% CO2 in air; the maximum concentration to which operating

personnel may be exposed for a short period of time is 3.0% (IPCC, 2005).

As it is denser than air at normal temperature and pressure, there will be a

tendency for any leaking CO2 to collect in hollows and other low-lying confined

spaces which might create hazardous situations - the potential hazard is enhanced

because the gas is colourless, tasteless and generally considered odourless.

If CO2 is released from pressurised containment, such as a large pipeline, the

consequent pressure drop might cause a hazardous cold condition with danger of

frostbite from contact with cold surfaces, solid CO2 or escaping liquid CO2. This

might also lead to embrittlement of nearby facilities, if these were affected by the cold

gas. Escape of pressurised CO2 also presents risks of elevated noise level and impact

of high pressure gas causing physical damage to people or equipment. Preparations

for the handling and processing of CO2 must take into account these potential hazards

in developing the health and safety plan for the installation.

Thus health risks to the nearby population could occur if a release of CO2 were

to produce:

§ relatively low concentrations of CO2 for prolonged periods,

§ or intermediate concentrations of CO2 in relatively anoxic environments,

§ or high concentrations of CO2.

Certain sub-groups in the population may be more sensitive than the general

population to elevated CO2 levels. Such groups include those suffering from certain

medical conditions and those susceptible to panic, as well as individuals with

pulmonary disease resulting in acidosis, children and people engaged in complex

tasks (IPCC, 2005).

Such knowledge influences the standards for minimum leakage that would be

acceptable from transport facilities, and what should be done in the event of leakage.

The design of a pipeline must conform to the relevant industrial standards and codes.

For example, in the USA, the Department of Transportation’s Pipeline Safety

Regulations Code has a section on transportation of hazardous liquids by pipeline

(Title 49, Part 195) which was used in the design of the pipeline from Beulah to

Weyburn (as well as other applicable US and Canadian codes, regulations and

standards).

A related potential source of risk is that hydrates, or ice plugs, can form in the

piping of CO2 facilities and flowlines, especially at pipe bends, in depressions, and at

locations downstream of restriction devices. It is not necessary for the temperature to

fall below 0oC for hydrates to form - at elevated pressures hydrates could form at up

11oC. This needs to be taken into account in the design of pipework and related

components.

Installing a pipeline in Indonesia would have to take account of seismic risk.

Other types of pipeline have been installed in seismically active areas, which may

provide some indication of steps that could be taken to protect a CO2 pipeline. For

example, if potential fault zones can be identified, the layout of the line could be

adjusted so as to minimise the stresses if a movement occurs in the fault. Reducing

soil resistance along the line would allow freer movement of the supporting material

in the event of earth movement, which might also help to protect the line. Leak

detection would be installed to detect pressure drop; detectors sensitive to acoustic

noise arising from a leak have also been used in oil pipelines for this purpose.

In marine transportation, hydrocarbon gas tankers are potentially dangerous

but recognition of the potential hazards has led to very high standards of design,

construction and operation, so that serious incidents are rare, as was discussed above

(IPCC, 2005). Similar high standards are expected in the case of CO2 tankers.

The analogous LNG tanker has a good accident record, with only one example

of a grounding of an LNG cited by IPCC (2005) and that event took place without

accidental release of cargo. Adherence to similar standards of navigation and

operation would be expected for CO2 carriers.

The design of CO2 tankers would be carried out under the International Gas

Carrier Code to prevent damage to the storage tanks from accidents affecting the ship.

In the event of spillage, the loss of (cold) CO2 onto the sea could be thought of as

analogous to the loss of (even colder) natural gas from an LNG tanker but, as far as is

known, no modelling has been done to determine the consequences of an accidental

release of CO2 at sea.

A closely related issue is the environmental impact of the transport facility –

this is discussed next, separately for pipelines and for ships.

4.6.3 Environmental Impact of Pipelines

The environmental impact of pipelines has a number of aspects:

§ the effects of installing the pipeline,

§ the impact of the pipeline in use,

§ the impact of its removal at the end of its life,

§ the effect of any leakage from the pipeline during operation.

The first 3 aspects are common to all pipelines4 so this discussion is focussed

on the last one, which is specific to the carriage of CO2.

The quality of the CO2 that is admitted into a pipeline must meet the standards

set by the operator in order to protect the integrity of the pipeline. Where the pipeline

is close to inhabited areas, there will be additional requirements to protect people and

the environment against the effects of CO2 leaking from the line. In particular this

may influence the amount of impurities, such as sulphur compounds, that are allowed

in the line.

Loss of CO2 from pipelines in normal operation is typically very small (IPCC,

2005) but accidents can occur as described above (see 4.6.1). Various preventative

measures can be taken to prevent accidents and to mitigate their effects, so as to limit

the consequences of any release. In particular, design of the line will include over-

pressure protection, leak detection, isolation (block) valves and automatic control

systems. The block valves will be spaced at suitable distances so as to limit the

amount of CO2 that can be released as a result of an accident. Also the route will be

chosen so as to minimise the exposure of neighbours to high concentrations of CO2 in

the event of a release.

Accidental release of CO2 from a buried pipeline could also affect plants

growing above the line - low concentrations of CO2 can enhance plant growth but, if

the concentration of CO2 is more than 10% at the roots, this could affect plant growth,

or even kill the plants (IEA GHG, 2007). Nevertheless, the most likely situations are

either no leakage or a substantial leak, so that in most cases it is unlikely that there

will be any effect on plants growing close to the line. There could also be effects on

the pH of the subsoil and changes in the microbial population of the soil, both leading

to environmental impact, but it is difficult to draw general conclusions about such

possibilities.

Monitoring of a pipeline transporting CO2 would focus on detecting leakage

from the line, both to ensure that there would be no significant greenhouse gas

emissions (thereby partly negating the purpose of the line) and also to protect the local 4 The use of booster compressors is common to many types of pipeline but in this case (given that the purpose of the line is to reduce CO2 emissions) it will also be relevant to take account of the greenhouse gas emissions arising from use of these compressors.

population and ecosytems. In the event of minor leakage, remedial steps would need

to be taken to deal with the leak. For larger leaks, the risks to local inhabitants might

become more significant so management of the risks would also include warning

these people and, if necessary, evacuating them from the affected area until the gas

had dispersed. In all cases, the leakage would probably have to be quantified and

reported to the relevant authorities as this would be debitted against any emission

reduction credits5 arising from capturing the CO2.

4.6.4 Environmental Impact of Shipping

There may be additional, specific issues related to the environmental impact of

ships used to transport CO2.

A release of CO2 from a ship during transport would have an impact on the

surrounding ocean – some of the CO2 would dissolve in the water, forming carbonic

acid (H2CO3) which would acidify the water. However, this is a slow process and the

impact of an individual release is likely to be limited to the near-surface and will be

dispersed rapidly.

During loading or unloading operations a leak of CO2 would pose a significant

hazard to people in the immediate vicinity of any release. Populations further away

may also be at risk if the gas cloud were to be blown inland. It has been shown

(Vendrig et al, 2003) that a catastrophic failure of a tanker containing an inventory of

around 18,000 t of CO2 could produce hazardous concentrations at large distances.

For example, a release onto water could generate a CO2 concentration of 1.5% at a

distance of 925 metres, suggesting that, closer to the release, potentially harmful

concentrations could occur.

Various international conventions are, in principle, relevant to the international

shipment of CO2, in particular the Basel Convention on “Control of trans-boundary

movement of hazardous wastes and their disposal”. However, providing CO2 is not

classified as a hazardous waste, the Basel Convention should not constrain the

transport of CO2. It seems reasonable to treat pure CO2 as non-hazardous but if it

contained impurities, such as SO2 or NOx, the classification might be different.

5 The precise nature of the means of payment for emission reductions will depend on the decisions of the Indonesian government once targets are set for national emissions reduction. At present, in Europe, the issue of leakage from pipelines is still being examined by the authorities responsible for the Emissions Trading Scheme and the final policy on repayment of credits in the event of leakage has not yet been announced.

Emissions of CO2 will arise from the operation of the liquefaction plant, by

boil-off from the storage tanks onshore and onboard ship, and from the ships’ engines.

IPCC (2005) estimates that emissions may be 3 to 4% of the cargo for a 1000km

journey if the liquefaction plant is supplied with CO2 at 10 MPa. IEA GHG (2004)

indicates that these emissions could rise to around 12%, if the CO2 were supplied to

the liquefaction unit at atmospheric pressure (because of the extra electricity that

would have to be generated to run the plant). Increasing the distance for transporting

the CO2 would also increase emissions – to about 18% of the cargo for a distance of

12000km using a ship with capacity 50,000t. The boil-off losses could be reduced to

1 to 2% by capture of the boil-off and re-liquefaction.

4.7 Preliminary Assessment of Options for Indonesia

4.7.1 Introduction

The key parameters for assessing transport options are the quantity of CO2 to

be shipped, the distance between capture site and storage, the nature of the terrain to

be crossed, and its location, especially whether it is onshore or offshore. A number of

case studies are examined, related to the capture case studies in chapter 3. These

studies demonstrate a number of important features about the economics of CO2

transport.

In agreement with the other members of the study team, the following cases

have been selected for outline costing:

1. Capture at a 1000MW supercritical coal-fired power plant in Indramayu-West

Java and transport to an onshore storage location in South Sumatera.

2. Capture at a natural gas combined cycle power plant (NGCC) in Muara

Tawar-West Java and transport to offshore storage, North of Java.

3. Capture at a lignite-fired power plant in Bangko Tengah-South Sumatera and

transport to onshore storage.

4. Capture at a coal-fired power plant in Muara Jawa-East Kalimantan and

transport to an onshore storage location on Kalimantan.

5. One case does not involve a power plant – the source of CO2 is a gas

processing plant at the Subang gas field in West Java, with storage offshore.

For reasons explained above, pipeline transport is the most appropriate option

for the specific locations considered and the quantities of CO2 to be transported.

4.7.2 West Java-South Sumatera

The storage location considered for CO2 captured at Indramayu power plant in

the northern part of West Java is onshore in South Sumatera. The pipeline would

involve an onshore line (300 km in length) over cultivated land, followed by a 35 km

subsea crossing, with a final 320 km onshore leg again over cultivated land. The

source of CO2 would be a new 1000 MW supercritical power plant burning Sub-

bituminous coal (see Table 3.13). If operated continuously, this plant would send

9.1Mt/y of CO2 to storage. In fact the capacity factor of the plant is expected to be

70%, thereby reducing the amount of CO2 sent to store over the year. The

characteristics of the plant are summarised in Table 4.2. The pipeline has been sized

to accept the peak flow of CO2 even though it will not handle this much continuously.

Alternatively, a smaller line could be used but this would require an intermediate store

to handle the intermittent supply of CO2, for which cost data are not available at

present. It is assumed that the line can be started up and shut down without penalty.

Table 4.2 Summary of Indramayu power plant assumptions West Jawa-South Sumatera case

Output 1000 MW Fuel Sub-Bituminous coal Maximum rate of CO2 delivery 289 kg/s Capacity factor of power plant 70%

The cost of the pipeline has been estimated using the IEA Greenhouse Gas

Programme’s pipeline costing model (IEA GHG, 2009). The model was originally

devised in 2002 and updated and extended in 2007. The IEA GHG Cost Estimation

Model was developed as a high level analysis tool for the comparison of options for

transportation of natural gas, hydrogen, coal, oil and electricity, and for CO2

gathering, transport and storage. The cost estimation in the model is based on

industry standard sizing techniques and industry norms but the developers do not

warrant the suitability of the model for any use other than its original purpose.

For costing CO2 pipelines, the model has built-in optimisation procedures

which allow it to select pipeline size and the number of booster stations, given certain

user-specified values such as pipeline inlet pressure. Alternatively the model can be

run in manual mode with pipeline sizes selected by the user. For the purposes of this

exercise, the model was mostly run in automatic mode, except where necessary to

achieve the desired delivery pressure to the storage site, which is assumed to be at

least 10 MPa. Other assumptions used in the runs of the model for the West Java-

Sumatera case are summarised in Table 4.3.

Table 4.3 Some of the assumptions for pipeline costing used in the IEA GHG Cost Estimation Model

Factor Value Location S E Asia Cost index Chemical Process Cost date 2007 Annual capital charge 11% Natural gas cost 2.14 US $/GJ Electricity cost 5.04 US ¢/kWh CO2 delivery pressure from capture plant 15.0 MPa Minimum CO2 pressure for delivery to storage 10.0 MPa

The results are shown in Table 4.4. Relatively large pipelines have been

selected for onshore duty because of the large amount of CO2 to be moved and the

distances involved. At the start of the subsea section, a pressure booster is used to

restore the pressure to 15 MPa again; another booster is used at the start of the second

onshore section for the same reason. These boosters have electrical rating 1.4 and 1.3

MW respectively. No intermediate boosters are used in the onshore or offshore

sections.

Table 4.4 Case 1: Results from use of the Cost Estimation Model for the West Java-Sumatera route

Case West Java/Sumatera Onshore pipeline diameter 900 mm Length onshore 300 km No. of inline boosters 0 Offshore pipeline diameter 600 mm Length offshore 35 km Initial booster 1 (1.4 MW) No. of inline boosters 0 Onshore pipeline diameter 900 mm Length onshore 320 km Initial booster 1 (1.3 MW) No. of inline boosters 0 Maximum Flow rate 289 kg/s Pipeline inlet pressure 15.0 MPa Outlet pressure 11.7 MPa Capex pipelines $ 512.8 M Capex initial boosters $ 29.7 M Capex inline boosters 0 Total capital cost $ 542 M Opex (at full capacity) $ 9.9 M/y Annual charge $ 60 M/y Average cost / tonne (at full capacity6) $ 6.6/t CO2 Average cost / tonne (at 70% capacity) $ 9.4/t CO2

Overall the cost of transport is significant, although still relatively small

compared with the specific cost of capture. Running the line at 70% capacity

imposes a penalty of about $2.8/t CO2 on its use. The subsea section only accounts

for about 9% of the total capital expenditure on the pipeline because of the short

distance offshore, even though the offshore line is about 25% more expensive per

kilometre than the onshore lines.

Significantly smaller pipelines could be used onshore if, for example,

intermediate pressure boosters were used but there might be maintenance concerns

about having so many pumps; the overall cost is also likely to be slightly greater in

that case. These results should be regarded as merely indicative of the cost of pipeline

transport and would need to be confirmed by detailed engineering design.

Building and using a line capable of handling the CO2 from several sources on

Java would lead to significant reduction in the specific cost of transporting CO2, albeit

at greater overall investment cost. 6 The term “full capacity” indicates use of the pipeline continuously throughout the year at the maximum flow rate.

4.7.3 West Java Offshore

In this case, storage of CO2 captured at a power plant close to the coast of

West Java is piped to an offshore location through a short (15km) subsea line.

The source of captured CO2 is a newly constructed 750 MW Muara Tawar

combined cycle power plant burning natural gas as described in Table 3.14. Key

assumptions are summarised in Table 4.5. This plant would send 2.3Mt/y CO2 to

store if operated continuously but at the expected 70% capacity factor, the annual

delivery would be 1.6Mt of CO2. The pipeline has been sized for the maximum

flowrate with no intermediate storage.

Table 4.5 Case 2: Summary of power plant assumptions for Muara Tawar NGCC

Output 750 MW Fuel Natural gas Maximum rate of CO2 delivery 74 kg/s Capacity factor of power plant 70%

The pipeline has been costed using the IEA GHG model. Other assumptions

are similar to those used in case 1 (Table 4.3) but in practice the pressure of the CO2

delivered to the pipeline inlet need not be as high as assumed in the earlier case -

13MPa would be sufficient for this task. The results of costing this line are shown in

Table 4.6. Because of the relatively small diameter of the pipe, it is possible this

could be laid using the reel laying method, so a dedicated lay-barge would not be

needed for this task. Small diameter lines are normally placed into trenches for

protection from drag-net fishing or the anchors of vessels – such dangers would need

to be considered in any site investigation for such a project.

Table 4.6 Case 2: Principal results from use of the Cost Estimation Model for the West Java offshore case

Case West Java offshore Pipeline diameter 300 mm Length offshore 15 km No. of Boosters 0 Maximum Flow rate 74 kg/s Pipeline inlet pressure 13.0 MPa Outlet pressure 11.0 MPa Capex pipeline $ 17.7 M Capex boosters 0 Total capital cost $ 17.7 M Opex $ 0.31 M/y Annual charge $ 1.95 M/y Average cost / tonne (full capacity7) $ 1.0/t CO2 Average cost / tonne (70% capacity) $ 1.4/t CO2

The specific cost (i.e. $/t CO2) of transporting CO2 from West Java to the

offshore storage site is much less than in the first case, because of the relatively short

distance required to transport the CO2. These results should be regarded as merely

indicative of the cost of pipeline transport and would need to be confirmed by detailed

engineering design.

4.7.4 South Sumatera

In this case, the source of CO2 is a capture unit at Bangko Tengah coal-fired

power plant situated at the mouth of a mine in South Sumatera. The power plant burns

lignite, generating 600 MW. The cost and performance data on this power plant are

given in Table 3.15 and the main features are summarised in Table 4.7. In continuous

operation, this plant would send 7.0 Mt/y of CO2 to store but, as it is expected to

operate at 65% capacity factor, annual storage would be 4.6Mt/y. A 60km onshore

pipeline carries the CO2 over cultivated terrain to the storage site. The pipeline has

been sized for maximum duty with no intermediate storage.

7 The term “full capacity” indicates use of the pipeline continuously throughout the year at the maximum flow rate.

Table 4.7 Case 3: Summary of Bangko Tengah power plant assumptions in South Sumatera case

Output 600 MW Fuel lignite Maximum rate of CO2 delivery 223 kg/s Capacity factor 65%

The assumptions used in the pipeline costing model for the South Sumatera

case are as shown in Table 4.3. The results are presented in Table 4.8.

Table 4.8 Case 3: Principal results from use of the Cost Estimation Model for pipeline transport of CO2 on South Sumatera

Case South Sumatera Pipeline diameter 550 mm Length 60 km No. of Boosters 0 Maximum Flow rate 223 kg/s Pipeline inlet pressure 15.0 MPa Outlet pressure 10.5 MPa Total capital cost $ 22.9M Opex $ 1.2M/y Annual charge $ 2.5M/y Average cost / tonne (full capacity8) $ 0.53/t CO2 Average cost / tonne (65% capacity) $ 0.82/t CO2

The cost of transport is low, as expected for shipping such a quantity of CO2

over a short distance onshore. These results should be regarded as merely indicative

of the cost of pipeline transport and would need to be confirmed by detailed

engineering design.

4.7.5 East Kalimantan

For this case, the CO2 would be captured at a relatively small Muara Jawa

power plant located in the Eastern part of Kalimantan Province. Storage would be

relatively close to the power plant requiring an onshore pipeline length of 60 km.

The source of CO2 is a newly constructed coal-fired power plant burning Sub-

bituminous coal. The performance and cost of this plant are given in Table 3.16; key

assumptions are summarised in Table 4.9. If operated continuously, this plant would

8 The term “full capacity” indicates use of the pipeline continuously throughout the year at the maximum flow rate.

deliver 1.1Mt/y to store; at the expected 65% capacity factor, annual delivery would

be 0.7 Mt/y.

Table 4.9 Case 4: Summary of Muara Jawa power plant assumptions in Kalimantan case

Output 100 MW Fuel Sub-bituminous coal Maximum rate of CO2 delivery 36 kg/s Capacity factor 65%

The plant is located on the coastal plain; the pipeline crosses cultivated terrain.

The pipeline has been sized for maximum delivery without intermediate storage and

has been costed using the IEA GHG model. A lower delivery pressure would be

adequate for this line, which would reduce the capture/compression costs slightly.

Other assumptions are as given in Table 4.3. The results are given in Table 4.10.

Table 4.10 Case 4: Principal results from use of the Cost Estimation Model for the Kalimantan onshore case

Case Kalimantan onshore Pipeline length 60 km Pipeline diameter 250 mm No. of Boosters 0 Maximum Flow rate 36 kg/s Pipeline inlet pressure 15.0 MPa Outlet pressure 10.5 MPa Total capital cost $ 9.4 M Opex $ 0.36 M/y Annual charge $ 1.03 M/y Average cost / tonne (full capacity9) $ 1.2/t CO2 Average cost / tonne (65% capacity) $ 1.8/t CO2

Although this case involves shipment of only a relatively small amount of

CO2, the specific cost (i.e. $/t CO2) of transport is not high because of the relatively

short distance and the fact that the line is entirely onshore. These results should be

regarded as merely indicative of the cost of pipeline transport and would need to be

confirmed by detailed engineering design.

9 The term “full capacity” indicates use of the pipeline continuously throughout the year at the maximum flow rate.

4.7.6 Natural Gas Processing Plant, Subang Field

In this case, the source of the CO2 is a natural gas processing plant in the

Subang field (West Java). The CO2 is separated from the natural gas stream using an

amine system. A continuous stream of CO2 at a rate of 22kg/s is pressurised at the

processing plant (see chapter 3) before being piped to store. The store is assumed to

be 50km offshore. The Subang gas field is onshore, 29.7 km from the coast which

necessitates an onshore section of the pipeline and an offshore section; the terrain that

the onshore line crosses is cultivated; no allowance has been made for the cost of a

shore terminal (if needed).

The cost of the pipeline has been calculated using the IEA GHG model.

Although the Subang gas field may have a relatively short operational life, it is

assumed that the pipeline will continue to be used for handling CO2 from other

sources after the processing plant at Subang has ceased operation. If this is not the

case, the capital charge used in these calculations would need to be changed. Other

assumptions are similar to those given in Table 4.3. In order to minimise the overall

cost of the pipeline, the diameter of the lines have been chosen so as to avoid use of

booster compressors. The results are given in Table 4.11. The delivery pressure to

the storage site is probably higher than required (13 MPa) so an alternative case has

been run with lower inlet pressure and lower discharge pressure which is also shown

in Table 4.11. Because of the relatively small diameter of the pipe, it is possible this

could be laid using the reel laying method, so that a dedicated lay-barge would not be

needed for this task.

Table 4.11 Case 5: Principal results from use of the Cost Estimation Model for the pipeline from the natural gas processing plant, Subang field

Case Subang gas processing Subang gas processing

(lower pressure) Onshore pipeline diameter 250 mm 250 mm Pipeline length onshore 29.7 km 29.7 km No. of boosters 0 0 Offshore pipeline diameter 250 mm 250 mm Pipeline length offshore 50 km 50 km No. of Boosters 0 0 Flow rate 22 kg/s 22 kg/s Pipeline inlet pressure 15.0 MPa 13.0 MPa Outlet pressure 13.0 MPa 11.3 MPa Total capital cost $ 39.5 M $ 28.1 M Opex $ 1.03 M/y $ 0.77 M/y Annual charge $ 5.4 M/y $ 3.9 M/y Average cost / tonne $ 7.8 /t CO2 $ 5.6/t CO2

The specific cost of transporting CO2 is relatively high in this case because the

quantities to be transported are modest and a fairly long subsea line is required (the

offshore line accounts for 84% of the capital cost of this pipeline project). A

significant reduction in cost of the pipeline would be possible if lower pressure was

used (this depends on the design of the injection facilities) but this has only minor

effect on the cost of the compressor. These results should be regarded as merely

indicative of the cost of pipeline transport and would need to be confirmed by detailed

engineering design.

This is an example of a source of CO2 associated with the oil and gas industry

where CO2 could be captured for storage. Similar real-life applications of this type

have used storage closer to the site of capture (e.g. at Sleipner, the injection is over a

distance of 3km from the capture facility), which would reduce the cost of transport.

Alternatively, the cost of transporting CO2 might be reduced by carrying CO2 from a

number of such sources to a single store.

4.7.7 Ship Transport of CO2

None of the above cases have involved use of a ship to transport CO2 because

it was judged the distances across seas were too short to justify this. There could be

situations in Indonesia where the movement of CO2 over longer distances might be

considered (for example from Java to East Kalimantan); in such cases ship transport

might be competitive with pipelines but these would be expensive projects, whichever

mode of transport was used. Such cases have not been examined here.

4.7.8 Conclusions about Transporting CO2 in the 5 Case Studies

Although the costs presented here can only be regarded as broadly indicative,

they do provide some relevant guidance for considering transport options for moving

CO2 at the locations considered:

1. Onshore pipelines of reasonable length (say <100 km) carrying medium to

large quantities of CO2 (say >4 Mt/y) impose relatively small specific costs

(<$1/t CO2) on the CCS project, as in the South Sumatera onshore case.

2. Small quantities of CO2 (< 1 Mt/y) are relatively expensive to move, even

over moderate distances (~ 80 km), as shown by the Subang gas field case

study.

3. Offshore pipelines are relatively more expensive but the cost may not be

exceptional if the line is short (as in the Java offshore case).

4. Transporting CO2 over longer distances, as in the Java/Sumatera case,

imposes substantial costs on a CCS project. If CO2 could be collected from a

number of sources (producing, say, 20 Mt/y in total), the specific cost of

transport (i.e. per tonne of CO2) could be usefully reduced even with a longer

line.

4.7.9 Implications for Future CO2 Transport Systems in Indonesia

Several opportunities have been identified in Indonesia where transporting

CO2 from capture at a power plant to storage could be done at low specific cost.

These studies have also shown that transporting small quantities of CO2 over

moderate distances, or medium quantities over long distances, would impose

significant cost on a CCS project. Nevertheless, in all of these cases the specific cost

of transporting CO2 is less than the specific cost of capturing and compressing it.

Providing there are suitable places to store CO2 within several hundred km of

the large power stations in West Java or South Sumatera, it might be possible to

establish major CO2 pipeline systems. Such systems would connect several power

stations as well as other industrial sources, transporting larger amounts of CO2 than

have been considered here, in large diameter pipelines at low specific cost. Once such

a system had been established, it could take CO2 from smaller sources as well at

relatively low cost.

Concentrated sources of CO2, such as from gas processing plants, should offer

some of the lowest cost supplies available. However, the quantity of CO2 available

from any one plant may be relatively small so the cost of transport could be relatively

high. In order to take advantage of the low cost of CO2 separated at a gas processing

plant, it is likely to be necessary to find storage locations nearby, or to combine the

CO2 from one plant with that from other plants, so as to take advantage of the

economies of scale in pipelines.

If there was a need (at some time in the future) to store more CO2 than could

be accommodated in geological formations on/near West Java or South Sumatera,

there might be a case for transporting CO2 over longer distances, perhaps to

Kalimantan. This would certainly be more expensive than the local transport cases

examined in this report – whether pipelines or ship tankers would be used cannot be

decided at this time because there are too many unknowns. The competitiveness of

ship transport should be examined if/when a need for long-distance transport of CO2

develops.

References

Aspelund, A., M.J. Mølnvik and G. De Koeijer, 2006: Ship Transport of CO2: Technical Solutions and Analysis of Costs, Energy Utilization, Exergy Efficiency and CO2 Emissions, Chemical Engineering Research and Design 84 (9) 2006, pp 847-855. Barrie, J., K. Brown, P.R. Hatcher and H.U. Schellhase, 2005: Carbon dioxide pipelines: A preliminary review of design and risks. Proc 7th Internationl conference on greenhouse gas control technologies, Elsevier, 2005. Gale, J and J. E. Davison, 2002: Transmission of CO2 – safety and economic considerations. Proc 6th Internationl conference on greenhouse gas control technologies, Elsevier, 2003. Gujit, W., 2004: Analyses of incident data show US, European pipelines becoming safer. Oil and Gas Journal, January 26, pp 68-73. IEA GHG, 2004: Ship Transport of CO2. Report Ph4/30, IEA Greenhouse Gas R&D Programme, Cheltenham, UK IEA GHG, 2007: Study of potential impacts of leaks from onshore CO2 storage projects on terrestrial ecosystems. Report 2007/3, IEA Greenhouse Gas R&D Programme, Cheltenham, UK IEA GHG, 2009: Energy and transport cost estimation model. Report 2009/03, IEA Greenhouse Gas R&D Programme, Cheltenham, UK. IPCC, 2005: IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [Metz, B., O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp. MIT, 2007: The Future of Coal - options for a carbon-constrained world, MIT, Cambridge, MA, USA. Vendrig, M., J. Spouge, A. Bird, J. Daycock, O. Johnsen, 2003: Risk Analysis of the Geological Sequestration of Carbon Dioxide, report prepared for UK DTI, DNV Consulting, Norway. Yorkshire Forward, 2008: A carbon capture and storage network for Yorkshire and Humber, report prepared for Yorkshire Forward by AMEC plc, Darlington, UK

CHAPTER 5

METHODOLOGY FOR SITE SELECTION

5.1 For Non- Enhanced Oil Recovery (EOR)

The key element for any CO2 storage site is to minimise the risk of leakage i.e.

any leakage into the atmosphere, biosphere, hydrosphere or geosphere during the full

life cycle (pre-injection, injection, post-injection and post-closure) of the project. This

can be addressed by maturing a set of alternative storage complex options through the

early stages of technical assessment. This will maximise the chance of feasible

options emerging that can ensure CO2 containment for the entire life cycle of a storage

project. The high-graded options will then undergo a more detailed appraisal and

technical analysis to support site selection.

A site-specific risk-based Measurement, Monitoring and Verification plan

(MMV) should be in place for a storage complex. A MMV plan will be developed

during the technical maturation of a storage complex.

5.1.1 Storage Complex Definition

For a Carbon Capture and Storage (CCS) project, a detailed site

characterisation is required for the entire CO2 storage complex. A storage complex is

defined as a multiple barrier system of working reservoir and seals pairs below the

overburden (Figure 5.1).

Any potential CO2 storage complex must prove that it can safely store CO2,

with no migration or seeping to any sensitive zones for the life cycle of the project.

Migration is defined as the lateral and vertical sub-surface movement of the injected

CO2, in relation to the project activity, within the defined storage complex or in

geological formations adjacent to the storage complex (in the event of significant

irregularities) including the overburden. Seepage stands for the emissions of injected

greenhouse gases from the sub-surface storage complex, via the overburden, into the

atmosphere (or ocean/surface water in the case of offshore injection) arising as a

result of the project activity, including any other greenhouse gases mobilised in the

sub-surface and released from the geosphere as a consequence of the project activity.

In addition, a storage complex has to be able to maintain injectivity, provide

sufficient storage capacity and be able to be monitored for the entire life cycle of the

project. A storage complex approach introduces a significant safe-storage concept

with increased operating safety margins that is analogous to an engineered storage

system such as a tank farm. In a tank farm, there is a primary vessel and primary seal

(the tank and tank walls), there is also a secondary containment system comprising a

concrete apron and bund-wall, and there may be subsequent barriers and controlling

drainage systems. In subsurface terms this may mean a primary reservoir with primary

seal with secondary containment potential provided by subsequent (non-sensitive)

reservoir/ seals or through attenuation. These secondary and tertiary systems are

safety features designed in such a way that seepage from primary containment does

not lead to emissions to sensitive domains.

Figure 5.1 Definition of a storage complex and the possible leak paths of CO2. A storage complex is defined as all the reservoir-seal pairs from the primary reservoir up to the ultimate

seal.

Basin wide screening and appraisal drilling should be undertaken to identify

the presence of the components that support CO2 storage (reservoir, seal, structure), to

collate available data and to identify knowledge gaps that will be addressed through

appraisal and studies activities. Potential storage sites should be screened for capacity,

injectivity and life cycle containment criteria and to demonstrate the acceptability of

the CO2 source composition. Potential storage complexes are evaluated in the context

of other economic interest – hydrocarbons, minerals, potable water, biosphere/marine

biosphere and atmosphere (environmental, HSE, population). Locating,

characterising, screening and risk assessing a preferred storage complex in a time

effective and technically robust manner should be performed within a well-defined

framework that has been developed through extensive project expertise (Figure 5.2).

Figure 5.2 Main subsurface uncertainties associated with a CO2 storage complex

5.1.2 Principles and Requirements for CCS Site Selection

The key issues with storage complex / site selection are:

§ The site selection should fully protect existing hydrocarbon, mineral and

groundwater resources.

§ The site selection needs to be backed up by demonstrative models that identify

potential leak paths.

§ The leak scenarios need to be verified through baseline surveys and a robust

MMV framework.

Appropriate storage complex selection excludes key risks by a principle of

avoidance (de-selection) leaving residual risk elements that require robust assessment

and mitigation. This means avoiding (maximising separation &/or barriers) possible

potential leak features, for example: legacy & future wells and densely faulted areas,

also areas of economic activities (existing fields, potable aquifers).

Sufficient data should be collected through appraisal and studies activities to

construct volumetric and dynamic three-dimensional (3-D)-earth models that include

the cap rock, and the surrounding hydraulically connected areas. These models will

address the following elements, which are essential aspects of a robust assessment of

a storage complex and have been described in the joint Shell-ERM report for the

International Energy Agency Greenhouse Gas Research and Demonstration

Programme (IEA GHG R&D Programme) “Carbon Dioxide Capture and Storage in

the Clean Development Mechanism - Possible Approaches to Clean Development

Mechanism (CDM) Methodology Issues”, October 2006:

§ A thorough understanding of the storage complex leak features & processes

§ A capacity estimation of the storage complex

§ A thorough definition of primary & secondary sub-surface storage formations

§ A detailed understanding of the interactions and consequences of location

choice for above-ground installations & pipelines

§ Clear definition and assessment of sensitive zones which surround or overlie

the sub-surface storage complex

§ An assessment of the potential for sustained injectivity into the container

5.1.3 Main Types of Storage Complexes

Five types of CO2 storage complexes (Figure 5.3) have been identified that are

applicable within an Indonesian context.

1. Producing fields: A hydrocarbon-bearing field itself is a potential site for CO2 injection. Injection into a producing field could be an Enhanced Oil Recovery (EOR) opportunity. Injection into the flank close to a producing asset where EOR is not an objective carries a potential risk of interference with the production stream.

2. Abandoned fields: Abandoned fields represent a good opportunity for CO2 sequestration. These have a proven trap and seal, as well as a known capacity. The number and integrity of the abandoned or shut-in wells can be a key containment risk factor for this storage complex type.

3. Structures with dry wells: As structures with dry exploration or appraisal wells typically represent a failed hydrocarbon test, all hydrocarbon play elements have not been proven. A dry hole analysis would be needed to assess the containment risk. If containment cannot be proven, injection into the top of the structure or the flank should be avoided.

4. Undrilled structures: Undrilled structures require a robust assessment of hydrocarbon potential to rule-out alternative

economic development and to validate capacity, injectivity and containment potential for CO2.

5. Deep saline formations: These are defined as aquifers containing no potable (drinkable) water. The aquifers would typically be large enough that any future CO2 injection & plume migration would not affect any field, leak path or potable aquifer.

Structures with abandoned fields and deep saline aquifers are the most likely

storage containers for future CO2 sequestration. They are associated with a relatively

low risk of interference with present or future oil production containment and a low

risk of containment loss (although, for abandoned fields this will depend on the

number and conditions of the wells present).

Figure 5.3 The five scenarios for potential storage complexes. Storage options in or near producing fields are excluded as non-EOR opportunities

5.1.4 Storage Mechanisms

CO2 storage is generally expected to take place at depths below 800m, where

the ambient pressures and temperatures will result in CO2 being in a liquid or

supercritical state. This supercritical state (temperature = 31.1°C and pressure = 72.9

atm) yields rather uncommon properties. It can adopt properties midway between a

gas and a liquid. Under these conditions, the density of CO2 will range from 50 to

80% of the density of water. This is also close to the density of some crude oils. Being

in dense form, CO2 storage in geological formations provides the potential for

efficient utilisation of underground storage space in the pores of sedimentary rocks.

Moreover several storage mechanisms also occur in geological formations,

consequently enhancing the overall storage capacity.

There are two major storage mechanisms that will operate to keep CO2

retained underground - physical and geochemical trapping. These two trapping

mechanisms consist of specific mechanisms that could either act essentially alone or

in combination. The effectiveness of geological storage is determined by the overall

combination of physical and geochemical trapping mechanisms.

Physical trapping is usually described by the existence of physical barriers to

prevent CO2 migrating upward. This type of trapping is provided by very low

permeability seals that usually comprise certain rock types such as shale or salt beds.

In geochemical trapping, there two trapping mechanisms occur sequentially.

When CO2 enters sedimentary basins, it starts to dissolve in the formation water, and

the CO2 no longer exists as a separate phase. By being in one phase, the buoyant

forces that drive CO2 upwards will be eliminated. This trapping mechanism is referred

to as solubility trapping. The next geochemical mechanism is the formation of ionic

species as the rock dissolves, accompanied by a rise in pH (IPCC, 2005), resulting in

some fraction being converted to stable carbonate minerals. This trapping mechanism

is often called mineral trapping; in saline formations it can operate on timescales up to

a thousand years and result in the most permanent form of geological storage.

5.1.5 Site Selection Methodology

The CCS maturation plan should be robust through consideration of

alternative injection sites. This proposed methodology differs from an approach in

which a single, initially high-graded container option alone would be matured.

It is possible that several storage complex options within a basin meet the

initial screening criteria. The final selection of a preferred storage complex will take

place at the end of a maturation process (Figure 6.4) that will have as its highest

priority the avoidance of containment risk as, while also securing adequate injectivity

and capacity.

A detailed framework has been developed for the technical work requirements

needed to assess a CCS project during the different phase of its maturation process.

The main technical maturation steps are shown in figure 6.5; these are linked to a

transparent and structured risk assessment approach. It is recommended that maturity

levels I to II should be completed successfully before the actual CO2 injection takes

place, along with the first stages of a measurement, monitoring and verification

(MMV) programme.

Figure 5.4 Staircase of detailed technical work required for maturing a CO2 storage complex

Figure 5.5 Maturation strategy for several CO2 storage container options in context of uncertainty analysis and de-risking activities. Through maturation, some options will remain feasible storage complexes (Accept), while for others, a high containment risk will remain

(Reject)

5.1.6 Technical Work Elements For Storage Complex Assessment

The characterisation and assessment of a storage complex should be

precautionary and existing equity interests, mineral and groundwater resources need

to be fully protected. As there is no significant statistical base for long-term

containment, known high-risk seepage features should in the first instance be avoided,

then the residual risk minimised by distance. In particular, this means avoiding, as

much as possible, known seepage risk features such as legacy and future wells.

Storage complex selection needs to be backed up by demonstrative models that

identify potential seepage paths. The seepage scenarios need to be verified through

base level surveys and a robust monitoring and verification framework.

It is recommended that any storage complex identification contain the

following technical assessments as a minimum (these are further explained below):

§ Data collection on, and assessment of the storage complex

§ Simulation of the post-injection subsurface movement of CO2 within the

storage complex

§ Security, sensitivity and hazard characterisation

§ Performance risk assessment

§ Measurement, Monitoring and Verification (MMV) plan

5.1.6.1 Data collection

Sufficient data should be collected regionally and locally to identify the

knowledge gaps and identify the elements that will support CO2 storage (reservoir,

seal, structure). The storage complex selection needs to be backed up by

demonstrative models that identify potential seepage paths. The seepage scenarios

need to be verified through base level surveys and a robust monitoring and

verification framework.

5.1.6.2 Simulation of the CO2 in the Subsurface

When data gathering and screening has been completed, sufficient data should

be available for the most feasible storage complex options. Based on these data,

volumetric and dynamic three-dimensional (3-D)-earth models can be constructed that

include the cap rock, and the surrounding hydraulically connected areas. The

simulations will be based on identifying and applying sensitivities to key parameters

in the static geological earth model(s), and dynamic modelling tools. Any significant

sensitivity shall be taken into account and incorporated in the performance risk and

uncertainty assessment.

These models can be used to provide a detailed insight into:

§ Pressure volume behaviour vs. time within the storage complex

§ Areal and vertical extent of CO2 vs. time

§ The nature of CO2 flow in the reservoir including phase behaviour

§ CO2 trapping mechanisms and rates (including spill points and lateral and

vertical seals)

§ Secondary/tertiary containment systems in the overall storage complex

§ Storage capacity and pressure gradients in the storage complex

§ The risk of fracturing the cap rock

§ The risk of CO2 entry into the cap rock (e.g., due to exceeding the capillary

entry pressure of the cap rock or due to cap rock degradation)

§ The risk of seepage through abandoned or inadequately sealed wells

§ The rate of migration (in open-ended reservoirs)

§ Fracture sealing rates

§ Changes in formation(s) fluid chemistry and subsequent reactions (e.g. pH

change, mineral formation) and inclusion of reactive modelling to assess

affects

§ Displacement of formation fluids and minerals

5.1.6.3 Security, Sensitivity and Hazard Characterisation

Hazard characterisation should cover a range of potential scenarios including

simulated migration of the CO2 plume beyond the primary seal (but within the storage

complex) and lateral and vertical migration of CO2 across the boundaries of the

storage complex into potentially sensitive domains or seepage to the

atmosphere/hydrosphere. The purpose is to further understand CO2 plume migration

within the storage complex, to accurately define seepage pathways and to support the

accurate definition of a monitoring and verification programme.

5.1.6.4 Performance Risk Assessment

The risk assessment provides the key element for the site selection. The

quality of a risk assessment and the confidence in taking a quality decision depends

on the level of technical maturity. Increasing the maturity of an assessment would

allow definition of activities to systematically accept or exclude identified storage

complex options. The intent is to identify at an early stage the options that offer a low

life-cycle seepage risk whilst excluding others with a high life-cycle seepage risk.

The storage complex as well as containment mechanisms must be well

described. Each potential storage complex system requires a risk mitigation strategy

for the main seepage risk factors and an evaluation of the main geological constraints

that govern seepage processes and features. Risk factors will assess the time-

dependent issues of CO2 plume migration within the storage complex, also the

potential seepage across the storage complex boundaries, and will detail trapping

mechanisms and their contribution to overall storage security. Performance risk

assessment shall also identify and assess the possible sources for human error during

the operation of the injection facilities and the storage complex. A site-specific risk

assessment for each individual container provides the basis for any further MMV

plan.

5.1.6.5 Measurement, Monitoring & Verification (MMV) as a site selection

Criteria

There are three main aims of an MMV plan:

§ Monitor for HSE purposes to detect early warning signs of significant

irregularities or actual seepage emissions (e.g. loss of wellbore integrity) and if

deemed necessary to activate the recovery measures that can be put in place to

bring the potential seepage hazard under control.

§ Verification and validation of dynamic earth models in the short term to

estimate the long-term behaviour of CO2 plume, to inform the frequency and

duration of the monitoring plan and to confirm secure containment.

§ Accounting for seepage of CO2 back to the atmosphere within a crediting

period and beyond.

Without fulfilling these aims the project proponent cannot be considered to act

as a responsible operator, and is unlikely to run a well managed storage complex. To

achieve these aims, all phases of the project (i.e. pre-injection, injection, closure,

aftercare and post-liability transfer) need to be monitored, as well as all the

environmentally sensitive domains in proximity to the storage complex (geosphere,

hydrosphere, biosphere and atmosphere) – Figure 5.6. This can only be achieved

against agreed base levels, which allow accurate accounting of CO2 entering and

leaving the storage complex and must be agreed with the regulatory authorities of the

host country.

Consequently storage complex selection needs to be backed up by

demonstrative models that identify potential migration and seepage paths within the

defined storage complex boundaries. The migration and seepage scenarios need to be

verified through a site-specific MMV plan linked to the key risk features identified in

the risk assessment (e.g. wells, faults and fractures, seals and the boundary of CO2

plume – Fig. 5.1). A MMV plan has to be site-specific due to the inherent

heterogeneity of the subsurface and the seepage pathways unique to the specific

storage complex.

Figure 5.6 Measurement, Monitoring and Verification (MMV) needs for different domains during a CO2 injection and storage project’s lifecycle

5.2 For Enhanced Oil Recovery (EOR)

The methodology for site selection for enhanced oil recovery (EOR) is slightly

different from non-EOR, but many aspects are analogous. Two aspects that have

received attention for the EOR methodology relate firstly to the potential for

incremental oil recovery that can be obtained and secondly, aspects of leakage

monitoring for storage sites during pre-injection, injection and post injection. Because

CO2 flow paths in the reservoir are not always understood, monitoring is an essential

technology to trace CO2 in the reservoir and to verify the effectiveness of CO2 cycling

versus storage. In several EOR projects, monitoring is being performed and examples

will be outlined in the sections below.

Injecting CO2 into an oil reservoir to improve oil recovery has been applied for

more than three decades and should be considered an established technology. The

United States is the world leader in CO2-Enhanced Oil Recovery (EOR) technology

using some 32 million tonnes of CO2 per year, resulting in the recovery of 206,000

BOPD. EOR through CO2 flooding offers potential economic gains from incremental

oil production with an incremental oil recovery of 7-23% (average 13.2%) (IPCC,

2005). However, this is dependent on key reservoir characteristics.

5.2.1 Storage Mechanisms in Enhanced Oil Recovery

CO2 storage in depleted oil reservoirs is often regarded as a tertiary

hydrocarbon production method (EOR). Revenues can be generated from EOR; hence

such activities might be construed as preferable to simply storing CO2 in depleted oil

reservoirs. Moreover, the existing facilities and infrastructure can be re-used to

transport and inject the CO2.

By injecting CO2 into oil reservoirs, oil is mobilised through miscible or

immiscible displacement, which may increase oil recovery. A miscible flood is more

advantageous than immiscible flood, because it results in higher oil recovery factors.

Oil displacement by CO2 injection relies on the phase behaviour of CO2 and

crude oil mixtures that are strongly dependent on reservoir temperature, pressure and

crude oil composition. These mechanisms range from oil swelling and viscosity

reduction for injection of immiscible fluids (at low pressures) to completely miscible

displacement in high-pressure applications.

The injected CO2 will generally occupy the pore volume previously occupied

by oil and/or natural gas and usually trapped by capillary forces. But, not all the

previously pore space will be available for CO2 because some residual water may be

trapped in the pore space due to capillarity, viscous fingering and gravity effects.

Using this method, more than 50% and up to 67% of the injected CO2 returns with the

produced oil. All produced CO2 is typically captured/separated and recompressed for

re-injection into the production zone to minimize operating costs. The remainder is

trapped in the oil reservoir by various means, such as irreducible saturation and

dissolution in reservoir oil that is not produced, and in pore space that is not

connected to the flow paths into the producing oil wells. The CO2 storage in case of

miscible EOR ranges from 2.4 to 3 tonnes of CO2 per tonne of oil produced (IEA,

2004).

In the Weyburn project in Canada, circa 5,000 tonnes of CO2 per day (with a

purity of 95%) has been injected into a carbonate reservoir since 2000, with the

purpose of enhancing oil production. An extensive monitoring programme was also

initiated in this project to study CO2 behaviour in the reservoir; time-lapse (4D)

geophysical monitoring proved to be a successful tool. Water-gas geochemical

monitoring has been performed on reservoir levels up to the surface. These

monitoring programmes make the Weyburn project different from a conventional

EOR project.

5.2.2 Reservoir Screening for CO2-EOR

Reservoir screening criteria for site selection should be based on data

availability, laboratory and reservoir simulation works. Moreover, the availability of

good site characterisation data is critical for the reliability of models. There are three

major steps for reservoir screening to determine the suitability of reservoir that can

meet the need for CO2 injection and storage:

1. Pre-screening of the reservoirs and oils in the candidate field(s), based on the

following criteria (Green, et al., 1998):

§ Depth: > 2,500 feet

§ Oil composition: high % C5-C12

§ Oil viscosity: <10 cP

§ Reservoir temperature: up to 28-120 oC

§ Reservoir Pressure >Minimum Miscible Pressure (MMP) and < Fracture

Pressure (Pf)

§ Current oil saturation: >20% Pore Volume

§ Formation thickness not critical

§ Porosity not critical

§ Permeability >5mD

§ Formation type: Sandstone/Carbonate

2. Screening for whether a miscible or immiscible CO2 flood would be required.

Injection of immiscible fluids must often suffice for heavy-to-medium-gravity oils

(oil gravity 12–25 API). The more desirable miscible flooding is applicable to

light, low-viscosity oils (oil gravity 25–48 API).

3. The next step is to estimate the minimum miscibility pressure (MMP) for each of

these reservoirs using industry-standard correlations. To accomplish this, both

Yellig-Metcalfe and Holm-Josendal correlations are employed to estimate the

MMP based on reservoir temperature. MMP depends on oil composition and

gravity, reservoir temperature and CO2 purity.

To achieve effective removal of the oil, additional preferred criteria for both types of

flooding include:

§ High reservoir angle

§ Homogenous reservoir with low vertical permeability

§ For horizontal reservoirs, no natural water flow, major gas cap or major

natural fractures are desirable

§ Reservoir thickness and permeability are not critical factors

§ Núñez-López et al. (2008) consider only reservoirs that are at least 6000 ft

(1828 m) deep and that have already been water flooded (secondary recovery)

or that would be at the stage in their production life where CO2-EOR would be

suitable (i.e., most of the mobile oil would have been produced and the

remaining oil is residual oil that cannot be produced without EOR). Previous

waterflooding is not applied as a screening criterion for large, deep reservoirs

where vaporizing gas-drive miscibility can be achieved and where CO2-EOR

can be applied directly after primary production.

For enhanced CO2 storage in EOR operations, oil reservoirs may need to meet

additional general criteria as follow:

§ Adequate storage volume

§ Sufficient permeability to allow injection (good injectivity)

§ Low permeability cap rock (clay or salt)

§ Sufficiently stable geological environment to avoid compromising the

integrity of the storage site

§ Low number of wells penetrating the area of influence, which should be

defined based on the pressure perturbation as a result of injection rather than

the extent and reach of the injected CO2

On the other hand, poor characteristics for CO2 storage could be identified using

following parameters such as:

§ Thin layers (≤1000 m)

§ Poor reservoir and seal relationships

§ Highly faulted and fractured

§ Within fold belts

§ Strongly discordant sequences

§ Have undergone significant digenesis

§ Overpressured reservoirs

The integrity of the CO2 that remains in the reservoir is well-understood and

very high, as long as the original pressure of the reservoir is not exceeded. Although

EOR operation in conjunction of CO2 storage is well understood, the presence of

wells penetrating the subsurface in mature sedimentary basins can create potential

CO2 leakage pathways that might compromise the security of a storage site. Therefore

a number of protocols have also been instituted to ensure containment of CO2 – for

example, pre-injection well-integrity verification, a radioactive tracer survey run on

the first injection, injection-profile tracer surveys, mechanical integrity tests, soil gas

surveys and round-the-clock field monitoring.

In spite of the fact that the purpose of CO2-EOR is primarily oil production,

but most of the injected CO2 remains in the reservoir. On average, 40-50% of the total

volume of injected CO2 is trapped (stored) in CO2-EOR operations. Some studies

conducted by LEMIGAS show some of depleted oil fields in Indonesia match to CO2-

EOR screening criteria, nonetheless there are particular reservoirs screened out due to

insufficient MMP. The overall depleted oil fields in Indonesia, however, have not

been characterised and specifically evaluated for CO2-EOR applicability.

CHAPTER 6

GEOLOGICAL POTENTIAL STORAGE

6.1 Introduction

The previous chapter proposed a site characterisation methodology that can be

used to screen for storage complexes. This chapter will describe in greater detail the

difference between saline formations, depleted oil and gas fields and unminable coal

fields as storage options, as well as examining high-level capacity estimates and

possible locations for CCS projects in Indonesia.

6.2 Available Storage Formations and Global Capacity Estimates

CO2 occurs naturally in sedimentary basins around the world and

hydrocarbons are often found in association with CO2. There are numerous examples

world-wide, for example, the Natuna D Alpha gas field in Indonesia, Sliepner gas

field in the Norwegian North Sea, and the Zakum & Fatch fields, Abu Dhabi, UAE to

name but a few. Hence there is a wealth of geological evidence that CO2 is naturally

stored for millions of years in the subsurface. Thus storing undertaking CCS activities

in sedimentary basins can be regarded as mimicking the natural system. Figure 6.1

highlights the large number and aerial extent of sedimentary basins around the world

that could be used for CCS activities.

Figure 6.1 Prospective areas in sedimentary basins where suitable saline formations, oil or gas fields, or coal beds may be found (IPCC, 2005)

Currently, depleted oil and gas reservoirs, saline formations (also referred to as

deep saline aquifers), and coal seams are considered the most prospective geological

formations for CO2 storage; high-level storage estimates are summarised in table 6.1.

For oil and gas reservoirs, estimation was conducted based on the replacement of

hydrocarbon volumes with CO2 volumes. While this may represent some over

estimate of capacity (because the capillary entry pressure for CO2 is different to oil

and gas, meaning that a smaller column of CO2 can be held under the same caprock

compared to methane) it nevertheless serves as a reasonable first pass approximation.

If depleted fields are located near sources of CO2, they will provide an important

storage option for CCS activities. Much greater capacity is potentially provided by

saline formations. Unmineable coals provide another potential CO2 storage option, as

coal seams can adsorb twice as much CO2 onto their surface than methane. However,

accurate global capacity estimates are difficult to calculate due to the issues of

subsurface heterogeneity, interlinked process of reactive flow, geomechanical and

pressure foot prints associated with CO2 injection. Despite the broad range of capacity

estimates, there appears to be sufficient CO2 capacity in the subsurface for tens and

possibly hundreds of years of large-scale CCS.

Table 6.1 Worldwide geological storage capacity for several storage options (IPCC, 2005)

Reservoir Type Lower Estimate of Storage

Capacity (GtCO2) Upper Estimate of Storage

Capacity (GtCO2)

Oil And Gas Fields 675 900

Unminable Coal Seams (ECBM) 3-15 200

Deep Saline Formations 1000 Uncertain, but possibly 104

6.2.1 Depleted Oil and Gas Fields

The potential utilisation of depleted oil and gas fields for CO2 storage has a

number of advantages and disadvantages:

Advantages

§ Reduce the exploration cost to find new sites

§ Higher data density due to exploration and production data – including

computer models that have been developed to predict the CO2 movement,

displacement behaviour and trapping of hydrocarbons

§ Injectivity may be easier

§ Lateral migration leakage risks are minor

§ These reservoirs are proven traps known to have kept liquids and gasses for

million years

EOR is possible if CO2 breakthrough time is set to coincide with abandonment time of

field.

Disadvantages:

§ Containment risks are higher due to need for integrity of existing well stock

not specifically designed for CO2 storage

§ Geo-mechanically these fields are stressed through depletion

§ Field might not facilitate supercritical injection (if pressure is below super

critical point) leading to faster plume migration

§ Very low pressures in field can pose stability problems while injecting CO2

(transition of supercritical CO2 in well-bore to sub-critical CO2 in the

reservoir)

§ Operational HSE exposure maybe higher due to layout of old facilities

It cannot be assumed however that the depleted fields can hold a similar

volume of CO2 compared to hydrocarbons. The CO2 storage capacity from depleted

fields has to be carefully estimated based on the new geomechanical regime created

during the production of hydrocarbons and also be limited by the need to avoid

exceeding pressures that damage the caprock.

A range of factors affect the containment security of a depleted field. The

main issues are associated with the integrity of old wells, the fault and fracture regime

and the caprock. Depleted fields typically contain a greater number of wells compared

to saline formations. The integrity of the cement and abandonment techniques of old

wells must be technically assured prior to CO2 injection, to assure containment can be

achieved. The fault density in depleted fields can be greater than saline formations.

Hydrocarbon fields are typically found in structural traps e.g. anticlines that have low

angle faults at the crest. The production of hydrocarbons will have affected the

geomecahical regime of the reservoir. Lab and modelling studies are required to

assure safe injection pressures do not impact the fault systems of the injection

formations (see Chapter 5). The caprock must be proven to act as an effective seal for

CO2. Laboratory and modelling studies on the caprock, combed with tracer

monitoring and pressure tests could confirm the condition of depleted field caprock.

Overall, the main advantage of CO2 injection into depleted fields is the greater wealth

of data available for site characterisation.

A clear distinction exists between CCS in depleted fields and CO2 EOR. CCS

in depleted field is designed for the long-term storage of CO2. The primary driver for

CO2 EOR is to increase hydrocarbon production and only leads to partial amounts of

CO2 being trapped in the subsurface. To date there is no CO2 storage in abandoned oil

and gas fields in Indonesia. There are a number of projects that have successfully

injected and stored CO2 in depleted or depleting fields. For example, the CO2CRC

Otway pilot project is storing CO2 in an abandoned gas field in Australia. The

Weyburn EOR project in Canada has injected and stored about 7 million tonnes of

CO2 to date. It is the fourth largest CCS project in the world. The In Salah project in

Algeria is injecting CO2 into the water leg of a producing gas field. It aims to store 17

million tonnes of CO2 in total. The methodology for selecting CO2-EOR fields has

been described in Chapter 5.

Due the long exploration and production history within Indonesia, there are

many depleted oil and gas fields options for potential CCS or CO2-EOR use.

Substantial oil and gas exploration activities have taken place in Sumatra, Kalimantan

and Java. Some oil and gas fields in these regions have reached their mature

production stage and many of them are depleted. The future capacity of CO2 storage

will increase in time as more fields are depleted. If hydrocarbon fields are still in

production, a CO2-EOR / EGR flood might be considered to optimise oil (or gas)

production.

6.2.2 Saline Formations

The second type of CCS storage option considered suitable to sequester CO2 is

saline formations or deep saline aquifers. Saline formations are deep sedimentary

rocks filled with brines containing high concentrations of dissolved salts, which

makes them unsuitable for potable water or for agricultural use (IPCC, 2005). Saline

formations can either be found in carbonate or siliciclastic rocks (e.g. sandstones).

Compared with depleted or depleting hydrocarbon fields, saline formations have a

number of potential advantages and disadvantages associated with their use for CCS.

Advantages:

§ Operational Heath, Safety and Environmental (HSE) risk lower, with no

simultaneous operations (no production)

§ Containment risk low

§ Few puncture points (old wells) in the caprock

§ Tectonically less stressed than for depleted fields (fewer faults – aquifers not

typically in anticline structure)

§ Chemical reactivity may lead to increase or decrease in capacity or injectivity

§ Vast aquifer size makes it easier to locate areas at the right depth to sustain

supercritical state of CO2

§ No additional costs to assess integrity of old wells

Injection of CO2 into deep saline aquifers would use techniques similar to

those for oil and gas fields.

Disadvantages:

§ Data density lower – may require a higher number of appraisal wells

compared with depleted field option

§ Lateral migration of CO2 plume more uncertain due to few structural closures

in aquifer settings

§ 3D seismic less likely to be available, therefore higher appraisal costs

§ Lower injection rates to start with, due to comparatively higher pressures

§ More prone to digenesis

§ Aquifers typically do not have a proven ability to contain large amounts of

gases and have not been studied so extensively as hydrocarbon structures.

§ The estimates of potential storage volume are lower – to what extent the

aquifer pore volume can be filled with CO2

Current CCS project in saline aquifers has been demonstrated in Sleipner,

Norway. Since 1996, annually approximately 1 million tons of CO2 is removed from

natural gas and boosted to 80 bar and injected into the Utsira formation, 1000 m

below the sea floor of the North Sea. A total of 20 Mt is expected to be stored over the

project’s lifetime. Several other CO2 storage projects in saline formations are

currently underway including Otway (Australia); In Salah (Algeria); CO2SINK

(Germany). At the moment, deep saline aquifer is predicted to be identified in Natuna

region. However, there has been no detailed study to identify saline aquifer storage

opportunities in Indonesia presently. The capacity and its distribution still remain

questioned.

6.2.3 Coal Seams - Enhanced Coal Bed Methane (ECBM)

Another potential storage option is unminable coal seams, which can be

commercially exploited by Coal Bed Methane (CBM) production. Coal seams often

contain methane that is adsorbed in the coal matrix and in the cleats. Methane that

exists in coal seams can be extracted by depressurisation (CBM development) though

this typically recovers only 50% of the gas in place. Injection of CO2 into coal seams

will displace methane from the coal’s micropores and enables more methane to be

produced; this process is analogous to Enhanced Oil Recovery (EOR) and is called

Enhanced Coal Bed Methane (ECBM). At the same time, the injected CO2 would

replace the methane adsorbed onto the coal surface, hence locking it up permanently.

Coal has higher affinity to CO2 than methane, it appears that it may be able to

adsorb about twice as much CO2 by volume as methane. Due to adsorption

mechanisms that appear in coal surface, only less free CO2 is present, unlike in oil and

gas reservoirs where trapped CO2 caused by capillary pressure not adsorbed in pore’s

wall. Because of this and also the integrity to held methane for million years, coal

seams are considered as safe storage reservoirs. Consequently, the risk of leakage in

coal seams is expected to be smaller than for hydrocarbon reservoirs and deep saline

aquifers.

ECBM can be applied to certain coal seams (IEA, 2004) with:

§ A homogeneous reservoir, laterally continuous and vertically isolated from

surrounding strata;

§ Minimally faulted and folded;

§ At least 1-5 millidarcies (mD) permeability. Most coal seams are much less

permeable;

§ High methane content;

§ Stratigraphically concentrated coal seams are preferred over multiple thin

seams;

§ A possibility to use or export methane (pipeline) and CO2 availability (local

power plant, industry or pipeline).

The only commercial ECBM operation to date is the Allison unit in the San

Juan Basin in the USA. Although this commercial project is achieving the desired

results, it is not representative because of very specific and favourable conditions such

as homogenous reservoir with thick coal seams, minimal faulting and high

permeability (around 40 mD). Most coal seams outside this area have a much lower

permeability, are thinner, and are structurally more complex (high faulting).

Permeability should be at least 1 milliDarcy for effective CBM production (CCSTLL,

2004).

Figure 6.2 Coal basins distribution in Indonesia

Indonesia has abundant coal seam reserves, particularly low rank coal deposits

that are distributed across eleven onshore coal basins (Figure 6.2). An ARI study

(2003) supported by the Directorate General of Oil & Gas and Asian Development

Bank reported that Indonesia has vast CBM resources (approximately 453 Tcf).

Storage of CO2 in this geological formations, in conjunction with enhanced coal bed

methane (ECBM) production, is potentially attractive because of revenue of enhanced

production of methane can be used to offset the costs of CO2 storage. ECBM is

considered a niche option in Western Europe, but it cannot be neglected as a CCS

option in Indonesia. Unfortunately, many of coal seams in Indonesia are still in a non-

producing phase at the present.

Overall the ECBM technology is not well developed, and a better

understanding of injection and storage processes in coals is needed. Coal also tends to

swell when in contact with CO2 thus decreasing the permeability and resulting in

unfavourable injectivity. As CO2-ECBM is at an early stage of technical development

then, its prospects remain uncertain.

JAF01836.CDR

Singapore

BruneiMedan

0o

5 No

5 So

Active Volcano Subduction Zone Strike-Slip Fault Relative Plate Motion

P a c i f i c O c e a nP l a t e

I n d i a n O c e a n P l a t eA U S T R A L I A

0 1000Kilometers

Banjarmasin

JATIBARANGBASIN

Jakarta

KUTEIBASIN

KALIMANTANBalikpapan

N. TARAKANBASIN

PASIR ASEM ASEM

BASINS

AND

BARITOBASIN

SOUTH SUMATRABASIN

SUM

ATRA

JAVA

CENTRALSUMATRA

BASIN

OMBILINBASIN

DuriSteamflood

SULAWESI

SOUTHWESTSULAWESI

UjungPandang

BENGKULUBASIN

I N D O N E S I A

BERAUBASIN

Pakanbaru

Palembang

CENTALSUMATERA

52.5 Tcf

OMBILIN0.5 Tcf

SOUTH SUMATERA183.0 Tcf

BENGKULU3.6 Tcf

JATIBARANG0.8 Tcf

BARITO101.6 Tcf

DuriSteamflood

PASIR ANDASEM ASEM

3.0 Tcf

SOUTHWESTSULAWESI

2.0 Tcf

BERAU8.4 TcfKUTEI

80.4 Tcf

N. TARAKAN17.5 Tcf

JAF01836.CDR

Singapore

BruneiMedan

0o

5 No

5 So

Active Volcano Subduction Zone Strike-Slip Fault Relative Plate Motion

P a c i f i c O c e a nP l a t e

I n d i a n O c e a n P l a t eA U S T R A L I A

0 1000Kilometers

Banjarmasin

JATIBARANGBASIN

Jakarta

KUTEIBASIN

KALIMANTANBalikpapan

N. TARAKANBASIN

PASIR ASEM ASEM

BASINS

AND

BARITOBASIN

SOUTH SUMATRABASIN

SUM

ATRA

JAVA

CENTRALSUMATRA

BASIN

OMBILINBASIN

DuriSteamflood

SULAWESI

SOUTHWESTSULAWESI

UjungPandang

BENGKULUBASIN

I N D O N E S I A

BERAUBASIN

Pakanbaru

Palembang

CENTALSUMATERA

52.5 Tcf

CENTALSUMATERA

52.5 Tcf

OMBILIN0.5 Tcf

OMBILIN0.5 Tcf

SOUTH SUMATERA183.0 Tcf

SOUTH SUMATERA183.0 Tcf

BENGKULU3.6 Tcf

BENGKULU3.6 Tcf

JATIBARANG0.8 Tcf

JATIBARANG0.8 Tcf

BARITO101.6 TcfBARITO

101.6 Tcf

DuriSteamflood

DuriSteamflood

PASIR ANDASEM ASEM

3.0 Tcf

PASIR ANDASEM ASEM

3.0 Tcf

SOUTHWESTSULAWESI

2.0 Tcf

SOUTHWESTSULAWESI

2.0 Tcf

BERAU8.4 TcfBERAU8.4 TcfKUTEI

80.4 Tcf

KUTEI80.4 Tcf

N. TARAKAN17.5 Tcf

N. TARAKAN17.5 Tcf

6.3 Geological Setting

Six general petroleum system habitats are identified in the producing basins of

Indonesia: Sumatra, West Java, West Natuna, East Java and Kalimantan in West

Indonesia, and Irian Jaya-Ceram in East Indonesia.

A regional study of crustal type and present tectonic setting has identified 60

Tertiary basins which in western Indonesia developed mostly in the Neogene Period

and in eastern Indonesia during Palaeogene. The basin type is also important for

hydrocarbon accumulation in which nearly 80% recoverable oil and gas reserves are

obtained in the back arc, chiefly in the western part of Indonesia, with subordinates in

foreland, passive margin and delta type basins. In terms of the basin status, most of

the explored basins are situated in western Indonesia, consisting of commonly

producing, non-producing with discoveries, explored but no discovery basins due to

low geological risks, as well as higher prospectivity and easier operating conditions.

Based on tectonostratigraphy, there are three potential areas for CO2 storage,

namely South Sumatra, East Kalimantan, and Natuna areas. The Neogene sedimentary

basins of western Indonesia (Figure 6.3), seem to have been tectonically stable

because they were not affected by Neogene tectonic development. In the case of

seismicity, no earthquake hypocentres have so far been noted in the Natuna or Kutai

(East Kalimantan) basins; in the South Sumatra basins, if present the distribution of

earthquake hypocentres is deep (>150 km), and only very scattered.

Figure 6.3 Western Indonesia Neogene Sedimentary Basins

The chronostratigraphy of the Western Indonesia basins (Figure 6.4) is formed

by Paleogene rift and Neogene post rift and Syn-orogenic regression phases.

Figure 6.4 Western Indonesia Cronostratigraphic Tertiary Correlation Diagram

South Sumatra is part of Sumatra island which is situated on the southern edge

of the stable Sunda land/shield north of the Sunda Trench. South Sumatra is

favourable for coal beds and depleted reservoirs. Tectonically, the South Sumatra

basin was formed by extensional rifting which resulted in the development of normal

faults and grabens or half grabens during Palaeocene. The basin is classified as a

backarc basin. In South Sumatra the tectonic activity was apparently quiescent as the

sea regressed in middle Miocene. During the last tectonic event from Pliocene to the

present, significant hydrocarbons became trapped within clastic and carbonate

reservoirs of Oligocene and Miocene in age. Intraformational shales and claystones

within the Talang Akar and Gumai Formations provide the main seal for the reservoir

targets. The main oil and gas producer in South Sumatra Basin is the Eocene-

Oligocene sandstones of the Talang Akar Formation, carbonate reefs of the Batu Raja

Formation and sandstones of the Air Benakat Formation.

The present-day Sunda platform includes the large area of shallow seas (the

“Sunda shelf”) between Indochina, Kalimantan, The Malay-Thai Peninsula, Sumatra

and Java, and the land areas around this shelf. Most of the shelf is extremely shallow,

with depths considerably less than 200 m, and was emergent at times during the

Pleistocene. It was described that the Sunda Platform is widely regarded as a region of

stability, which has remained underformed and close to sea level since the Mesozoic.

The Location of the Natuna Basin is in the northern tip of the Indonesia Island

Arc System, which was developed as an intra-continental rift basin within the Sunda

Platform. The Eocene to Oligocene extensional phase and Miocene to Present day

contraction and inversion affected the basin formation. The Natuna Basin is

favourable for depleted reservoirs and saline aquifers. The reservoir rocks in the West

Natuna area are mainly sandstones of Lama/Benua Formation, Lower Gabus

Formation and Keras Formation. Carbonate build-ups of the Terumbu Formation are

the main reservoir in the East Natuna area. The Barat and Arang Formations

predominantly comprise shales, therefore, they act as suitable regional seals/cap

rocks, as well as shales of the Muda Formation.

East Kalimantan is often considered a relatively stable area. Kalimantan has

little or no seismicity, some young but few active volcanoes, and rather low

mountains which are less than 2.5 km high (with the exception of Mt Kinabalu in

Sabah). The Kutei basin, situated on the east coast of Kalimantan, is characterised by

a regressive clastic facies. The basin was filled by thick sedimentary deposits (more

than 20,000 feet) overlying the pre-Tertiary basement. The sedimentary fill of the

basin began in the early Miocene when the sea was regressing, producing a deltaic

sedimentary type. The source of sediments was from the west , formed by fluvial

deposits debouched at river mouths and then redistributed by coastal currents. The

basin is favourable for depleted reservoirs.

6.4 Indonesia’s Geological Potential Storage and Its Distribution

Indonesia has a lot of sedimentary basins located across many islands. There

are basins also formed near uplifted areas, which are tectonically unstable and may be

less suitable for CO2 storage, though perhaps through cautious selection they could be

possible as storage sites candidates.

One of the main geological storage options in Indonesia are oil and gas

reservoirs. After more than a century of intensive petroleum exploitation, thousands of

oil and gas fields in Indonesia are approaching the ends of their economically

productive stage. The future CCS potential will increase in time as more fields are

depleted. These depleted oil and gas reservoirs are prime candidates for CO2 storage.

Several reasons make this type of storage more attractive such as, having well known

geological structure, supplied with adequate data for better characterisation, the

established infrastructures would simplify for further development, and there is a

possibility to obtain additional recovery by utilising depleted oil and gas reservoirs.

Therefore this storage type offers a promising medium to deploy CCS. Despite the

fact that Indonesia has abundant coal seams, this type of storage container for CO2 is

not well characterised, remaining unexploited and still requiring (experimental)

research and field tests. Saline aquifers has also show great potential, but presently

have not been full characterised.

In total, Indonesia has 60 oil and gas sedimentary basins that spread across all

the islands (Figure 6.5). These sedimentary basins are relatively large and located

both onshore and offshore. Twenty-three identified basins are located geographically

in the western part of Indonesia and mainly comprise onshore basins, while the rest

(37 basins) are in the eastern part of Indonesia and chiefly located in deep water.

Figure 6.5 Indonesia’s distribution oil and gas basins

The basins highlighted in red in Figure 6.5 show the hydrocarbon-producing

basins that are mostly located in the western part of Indonesia and near to the main

islands such Sumatra, Java and Kalimantan. Many oil and gas fields in Sumatra,

Kalimantan and Java islands have been producing for a few decades, with hundreds of

producing wells having been drilled. Most of the reservoirs in those regions have

reached their mature stage or are in the state of being depleted and some are already

depleted. The utilisation of depleted oil reservoirs in conjunction with CO2-enhanced

oil recovery (EOR) seems also prospective due to the incremental oil recovery that

could be obtained to generate additional revenue thus might offset the cost of

investment. This approach looks like the most suitable for Indonesia’s oil production

condition.

This contrasts with the eastern part of Indonesia where there are only a few

producing oil and gas basins, and the rest are still to be drilled basins with no

hydrocarbon discoveries yet (highlighted in green in figure 6.5). The possibility to

store CO2 in this regions is likely less attractive, since many basins are at an early

stage of commercial development, with higher uncertainties as potential targets for

CO2 storage because of the limited availability of geological information.

The Natuna D Alpha offshore field is known as one of the biggest gas reserves

in the world and is dominated by CO2; this could represent a potential project for CO2

source and storage. The Natuna field is expected to require CO2 capture where CO2

excess after gas processing could be injected into geologic layers in the basin. Besides

the hydrocarbon accumulation, saline aquifers are also expected to exist in this area.

LEMIGAS has conducted several studies related to the estimates of potential

CO2 that could be stored in East Kalimantan and South Sumatra. This study is aimed

at determining the preliminary CO2 potential storage capacity and incremental oil

recovery from CO2 injection in several oil reservoirs. “Rule-of-Thumb” methods were

first applied to estimate storage volumes from CO2 injection and potential oil

recoveries. To accomplish this several input assumptions are required as follows:

§ Incremental oil recovery (%OOIP) from the CO2 – EOR project based on field

experiences is usually in the 8-16% range.

§ Gross CO2 utilisation ratio (MCF/BBL): the total amount of CO2 injected for

the project including CO2 recycle volumes that based on experience is usually

in the 5-10 Mcf/bbl range.

§ Net/gross utilisation ratio (fraction): the fraction of the total injected volume of

CO2 that is actually purchased (i.e., purchased CO2 divided by total injected

CO2, which includes recycle volumes). This is the volume of CO2 assumed to

be left in the reservoir at the end of the project life (i.e., sequestered) that

based on experience; this value is usually in the order of 0.5.

Figure 6.6 Potential areas for CCS in Indonesia

It is estimated that a CO2 volume of 38 – 152 million tonnes (Figure 6.6) may

be possible to be stored in the depleted oil reservoirs in East Kalimantan region, and

potential oil recoveries of 265 – 531 million barrels could be obtained. In South

Sumatra region, a CO2 volume of 18 – 36 million tonnes may be possible to be stored

in the depleted oil and gas reservoirs with potential oil recoveries of 84 – 167 million

barrels.

From this initial assessment to identify potential geological storage sites in

Indonesia, several recommended sites could be proposed as CO2 storage. The prospect

of CO2 storage in Indonesia’s geological formations at the moment are more

preferable to deploy in the South Sumatra basins, Kutai Basins (East Kalimantan) and

Natuna basins due to good reservoir characterisation, geologically stable, existing

infrastructures, and low population density.

Reference:

Davison, J., Freund, P., and Smith, A., 2001, Putting Carbon Back Into The Ground, IEA Greenhouse Gas R&D Programme. European Carbon Dioxide Network (CO2 net), 2004, Capturing and Storing Carbon Dioxide: Technical lessons learned, R&D and Technology Exploitation For CO2 Sources, Transport, Geological Storage. Holloway, S., Chadwick, A., Lauriol, I. C., and Arts, R., 2004, Best Practice Manual: Saline Aquifer CO2 Storage Project, Appendix A Statoil Research Center. IEA, 2004, Energy Technology Analysis: Prospects For CO2 Capture And Storage, International Energy Agency. Metz, B., Devidson, O., Coninck, H., Loos, M., and Meyer, L., 2005, IPCC Special Report: Carbon Capture and Storage. Núñez-López, V., Holtz, M.H., Wood, D.J., Ambrose, W.A., Hovorka, S.D., 2008. Quicklook assessment to identify optimal CO2 EOR storage sites. Env. Geol. 54(8), 1695-1706. Green, D. W., and Willhite, G.P., 1998, SPE Text Book Series Vol 6: Enhanced Oil Recovery. SPE Richardson, Texas USA.

CHAPTER 7

CCS REGULATORY FRAMEWORK AND ENABLING POLICIES

Most of the non-technical challenges of deploying CCS evolve around the

regulatory and policy aspects. CCS deployment as a climate change mitigation effort

is a recent concept and therefore many of the supporting policies are yet to be

developed.

This chapter addresses the existing global guidelines and required regulatory

framework at the national / local levels. It starts with the internationally recognized

methodology to account greenhouse gas in energy sectors including CCS provided by

the 2006 IPCC Guidelines for National Greenhouse Gas Inventories. It then continues

to discuss derivative regulatory guidelines that need to be developed at national and

local levels around the main phases of a CCS project: capture, transport, and storage.

Regulatory developments on CO2 storage primarily deal with Measurement,

Monitoring and Verification (MMV), risk assessment, site selection and

characterization, injection operations, site closure, and post-closure.

Deployment of CCS also requires enabling policies to minimize risks related

to policy and commercial aspects. Partnerships between governments, international

organizations and private sector are essential: government sets the policy and provides

support while private sector develops, delivers, and deploys the technology. Effective

partnerships on CCS require three key elements: first, an international financing

framework that incentivize CCS as a climate mitigation effort; second, clear and

workable arrangements around long-term liability of the stored CO2; and third, public

acceptance of CCS driven by shared concerns of climate change and the need to

substantially mitigate CO2 released into the atmosphere.

Figure 7.1 Key elements of CCS regulatory framework and enabling policies

7.1 Regulatory Framework

7.1.1 Global-Local Context and Key Issues

In developing regulatory framework for CCS, one must consider and

interweave the global and local contexts to achieve an optimum framework. The most

referenced and internationally recognized methodology for greenhouse gas accounting

in the energy sectors (including CCS) is the 2006 IPCC Guidelines for National

Greenhouse Gas Inventories principles35. It is binding for Annex 1 parties to Kyoto

Protocol to comply with the Guidelines and capacity building needs to take place in

non-Annex 1 countries.

The Guidelines present a useful de facto accounting procedure covering the

selection and management of storage sites, and it is important to take the Guidelines

as a starting point when developing national and eventually local regulatory

framework to ensure cross-jurisdictional consistency. Key elements of the Guidelines

will be discussed in section 3.2. IPCC Methodology.

National and local regulations need to operationalize the agreed global

framework. However, some existing national / local environmental protection

legislation could at best create ambiguities over the legality of CO2 injection and

storage, and at worst prohibit such activities. In addition to the national and local

environmental regulations, amendment and creation of laws in the following areas is

thus needed:

§ clarification of CCS under waste, water and environmental laws;

35 IPCC (2006) IPCC 2006 Guidelines for National Greenhouse Gas Inventories – Volume 2; Chapter 5: Carbon Dioxide Transportation, Injection and Geological Storage.

Capture

REGULATORY FRAMEWORK

Transport StorageNATIONAL/LOCAL REGULATIONS

IPCC GuidelinesGLOBAL METHODOLOGY

ENABLINGPOLICIES

LONG-TERM

LIABILITY

PUBLIC ACCEPTANCE

INTERNATIONAL FINANCING

PROMPT DEPLOYMENT

OF CCS

§ development of permitting regimes applicable to CCS (including nomination

of appropriate competent authorities); and

§ development of regulatory requirements of monitoring and containment of

CO2 that has been captured and stored.

CCS activities could lead to potential conflicts with other interests such as

hydrocarbon extraction activities and also groundwater users. Allocation of rights

with respect to the storage of CO2 in subsurface pore space that takes into account the

following elements is required:

§ creation and disposition of new subsurface interests for CO2 storage (e.g.,

developing new leases for CO2 storage, process for public sale);

§ potential competing and co-existing rights of different users of the subsurface;

§ possible changes of use relating to modifying hydrocarbon production to CO2

storage licenses; and,

§ consideration of surface users overlying any geological storage site.

Regulation defining the liabilities for CO2 storage operators with respect to the

following elements is needed:

§ short-term potential operational liabilities linked to local (environment, health

and property) and global (climate change) damages related to CO2 leakage

from a storage site; and,

§ long-term limits of liability for CCS operator in respect of any damages

arising from leakage over the long term (e.g. liability transfer post closure).

With regard to the consideration of third party access (TPA) issues in the

context of pipelines and storage sites, developer should get exclusive rights, and only

when an asset becomes significantly under-utilised, the owner is forced to offer TPA.

Hence, by using the global methodology as a starting point, this chapter will

deal mostly with establishing national and local regulatory framework in the areas of

capture, transport, and storage. It ends by providing a brief overview on the evolution

of CCS regulatory framework development worldwide.

7.1.2 IPCC Guidelines

The IPCC has stated that CO2 leakage rates of less than 1% are likely over

1000 years for appropriately selected and managed storage sites, and further that the

environmental impact risks from CCS activities are comparable with those of natural

gas storage. In the event of a CO2 release, technologies are available to monitor CO2

levels and provide appropriate warnings.

Risk management to minimize the risk should include the entire phase of CCS

application: pre-injection (characterization of the site, long-term risk assessment,

monitoring, remedial measures); operation (short-term prediction, monitoring of the

site); abandonment (update of long-term assessment, decide on duration of site-

specific monitoring); and post-abandonment (update assessment and transfer of

liability, site-specific monitoring, if necessary) as outlined in the 2006 IPCC

Guidelines for National Greenhouse Gas Inventories (IPCC, 2006).

Figure 7.2 Estimating, verifying, reporting emissions for CCS projects

(2006 IPCC Guidelines for National GHG Inventories)

To understand the fate of CO2 injected into geological reservoirs over long

period, assess its potential to be emitted back to the atmosphere or seabed via the

leakage pathways, and measure any fugitive emissions, it is necessary to:

§ Properly and thoroughly characterize the geology of the storage site and

surrounding strata.

§ Model the injection of CO2 into the storage reservoir and the future behavior

of the storage system.

SITE CHARACTERIZATION

ASSESSMENT OF LEAKAGE RISK

MONITORING

REPORTING

• Confirm that geology of storage site has been evaluated

• Confirm that local and regional hydrogeology and leakage pathways have been identified

• Confirm that potential for leakage has been evaluated through a combination of site characterization and realistic models that predict movement of CO2 over time and locations where emissions might occur

• Ensure that an adequate monitoring plan is in place

• Monitoring plan should identify potential leakage pathways, measure leakage and/ or validate update models as appropriate

• Report CO2 injected and emissions from storage site

§ Monitor the storage system.

§ Use the results of the monitoring to validate and/or update the models of the

storage system.

Proper site selection and characterization build confidence of minimal leakage,

improve modeling capabilities and results–and ultimately reduce the level of

monitoring needed. Further information on site characterization is available from the

International Energy Agency Greenhouse Gas R&D Programme.

Monitoring technologies have been developed and refined over the past 30

years in the oil and gas, groundwater and environmental monitoring industries. The

suitability and efficacy of these technologies can be strongly influenced by the

geology and potential emissions pathways at individual storage sites, so the choice of

monitoring technologies will need to be made on a site-by-site basis. Monitoring

technologies are advancing rapidly and it would be good practice to keep up to date

on new technologies.

The principal risks associated with CCS arise during CO2 storage site

injection and immediately after site closure. The main risks of CO2 geological storage

arise from the following conditions (Heidug, 2006):

§ inadequate (poorly designed and/or aging) injection wells;

§ unidentified and/or poorly abandoned wells;

§ inadequate cap rock characterisation; and

§ seismic events and migration via natural fractures or hydrologic flow.

The most prevalent risk is the migration of CO2 within well bores, through the

interfaces between the well, the cement and the geological formation, or through the

un-cemented or poorly cemented portions of a well. In the presence of water, CO2

becomes acidic. This can affect the integrity of the wellbore cement, although some

cement may also form a protective layer of carbonate that will stop further cement

degradation.

Methodologies have been developed for cementing oil and gas well bores,

even in high CO2 and H2S environments such as the Caspian Sea and deep gas

reservoirs in the foreland basins of the Rocky Mountains, but these wells typically

have a life of only a few decades. CO2 storage will require assured isolation for

hundreds of years, and industry standards (and technologies) need to be developed

accordingly. New methodologies need to be developed to test the integrity of the

cementing material in presence of supercritical CO2 along with CO2-resistant

materials that provide long-term integrity.

Remediation options to control possible CO2 escapes are summarized in

Figure 7.2, although it is not expected that such escapes should happen in well-

selected and designed storage sites.

Figure 7.3 CO2 potential leakage routes and remediation actions

7.1.3 National and Local Regulatory Requirements

CCS regulations need to evolve as scientific and technical experience grows.

CCS regulations will need to be adaptive to the developments and learnings. Full-

scale CCS demonstration projects will accelerate the learning curve, provide

important data and experience with CO2 retention monitoring and verification

procedures and technologies. Learnings and key insights from such demonstration

projects will need to be fed back into regulatory development.

Initially, full-scale demonstrations are likely to be operated under existing

regulations, modified to account for specific CCS issues, covering the injection of

liquid wastes, oilfield brines, natural gas, acid gas, steam and other fluids. Data from

early projects can then be used to help develop more broadly applicable CCS

regulations that can govern commercial deployment. The transition from early to

mature regulations could be accomplished through existing regulatory bodies. New

institutions and/or mechanisms may also be required to co-ordinate and integrate

emerging knowledge and establish the long-term regulatory and legal framework for

CCS.

Governments should guard against becoming tied to a regulatory structure that

may be appropriate for early demonstration projects but suboptimal for the

widespread commercial use of CCS.

The expansion of CCS will raise a number of legal and regulatory issues. The

most important of these include: developing regulations for CO2 transport;

establishing jurisdiction among international, national, state/provincial and local

government actors; establishing ownership of storage-space resources and legal means

for acquiring the rights to develop/use such resources, including access rights;

developing clear guidelines for site selection, permitting, monitoring and verifying

CO2 retention; clarifying long-term liabilities and financial responsibility for CO2

storage operations; and, in the case of offshore CO2 storage, complying with

appropriate international marine environment protection instruments (IEA, 2008).

Policies regulating CCS36 in principle covers the following objectives

depending on the phase of the project:

6. Ensure CO2 sequestration is effective—that is, the vast majority of injected CO2 is permanently trapped in the subsurface, and any leakage to the surface does not negate the benefits of sequestration.

7. Protect the health of those adjacent to sequestration projects. 8. Prevent degradation of underground sources of drinking water

(USDWs). 9. Prevent degradation of ecosystems adjacent to sequestration

projects. 10. Prevent degradation of adjacent mineral resources and protect

access to those resources. 11. Ensure that pore space is utilized efficiently. 12. Ensure that pore space can be acquired through a process that is

fair to pore space owners and project developers, as well as being reasonably predictable.

13. Develop regulations and regulatory structure that is responsive to new knowledge generated from early sequestration projects.

14. Encourage developers and operators to minimize the long-term cost of the project to the public after closure.

36 The CCSReg Project (2009)

15. Minimize regulatory risk to the project developers while still adequately fulfilling other regulatory objectives.

16. Ensure that greenhouse gas emissions avoided through carbon sequestration are accounted for accurately and are fungible in a carbon market.

17. Encourage efficient coordination between capture, transport and sequestration operations.

Figure 7.4 Regulatory Needs and Liability for each stage of a CO2 storage project

Regulatory responsibility for CCS will include authorities at the international,

national, provincial and local levels. When CCS deployment occurs in linkages with

CO2 emissions trading or any other support mechanisms, verifying and trading of CO2

allowances will require national oversight, even within international schemes.

Offshore CO2 storage projects will be subject to international and national regulations

to a greater extent than onshore projects. However, environmental and health issues

might be best addressed at the provincial or local level. As a result, CCS deployment

will require extensive coordination between supranational, national and provincial and

local jurisdictions.

Since pore space access for CO2 storage can potentially interfere with

hydrocarbon interests in many jurisdictions, CO2 storage licensing regimes that

defines CO2 storage property and pore space access rights should be handled by the

same regulator with responsibilities for hydrocarbon licensing.

Provincial or local government responsibilities for CCS projects might

include, among other things:

§ issuing air and other environmental permits;

§ issuing injection permits and/or oil and gas management rules for enhanced oil

recovery (EOR);

§ siting approvals for plants, pipelines or transmission pathways;

§ regulatory approval for higher consumer electricity rates; and

§ assignment of physical and financial risks.

Local regulators are also likely to play an important role in areas like CO2

injection and the regulation of health, safety and environmental concerns. Regulators

at all levels will need sufficient resources to allow them to increase their expertise to

manage the growing area of CCS regulation.

Local and global environmental risks of CO2 storage can best be managed

accomplished through the establishment of a sound set of monitoring and reporting

guidelines for site selection, monitoring and verification. Local risks include: the

seepage of CO2 to the atmosphere or near the surface; migration to sensitive

ecosystems and/or groundwater aquifers; and direct human exposure to concentrated

CO2. In addition to local risks, there are also global environmental risks if stored CO2

leaks to the atmosphere and compromises the effectiveness of a national or

international system for GHG emissions reductions. Such risks can have important

financial and contractual implications.

7.1.3.1 Capture Regulatory Guidelines

CO2 separation has been widely applied in industrial processes and for natural

gas processing, but their use for commercial-scale power plants need to be

demonstrated properly. CO2 can be captured either before or after combustion using a

range of existing and emerging technologies. Therefore, demonstrations of all capture

approaches (pre-combustion, post-combustion and oxy-fuel combustion) are urgently

needed on commercial-scale power plants to prove the technologies. Key regulatory

guidelines around the capture of CO2 are (WRI, 2008):

§ There should be recognition of the potential challenges in achieving the

theoretical maximum capture potential before the technologies are proven at

scale. This may necessitate flexibility in establishing appropriate capture rates

for early commercial-scale projects with the amount of CO2 captured at a

facility dependent on both technology performance and the specific goals of

the project.

§ Standards for the levels of co-constituents have been proposed by some

regulators and legislators; however, there is potential risk that this could create

disincentives for reducing sources of anthropogenic CO2 if the standard is set

too stringently. Ultimately, the emphasis should be on employing materials,

procedures, and processes that are fit-for-purpose and assessing the

environmental impacts of any co-constituents, along with the benefits of CO2

emissions reduction, as part of a comprehensive CCS risk assessment. Facility

operators, regulators, and other stakeholders should pay particular attention to

potential impacts of co-constituents in the transport and storage aspects of the

project.

§ Options for minimizing local and regional environmental impacts associated

with air emissions, use of water, and solid waste generation should be

evaluated when considering technologies for capture.

§ Use of capture technologies could result in hazardous or industrial waste

streams. Operators must follow guidelines and regulations for the handling and

disposal of industrial or hazardous wastes.

§ Operators should investigate the use of combustion wastes as beneficial

byproducts.

7.1.3.2 Transport Regulatory Guidelines

There are different options for transporting CO2 from capture sites to storage

locations, including pipelines and pressurised road and sea tankers. Given the large

volumes of CO2 that are likely to need to be injected, pipelines offer the most cost-

effective means of transport. As a result, most governments are focusing in the near-

term on pipeline regulations. The most difficult issues in CO2 pipeline regulations

relate to funding, pipeline siting, and pipeline access.

Given decades of international experience with the transport of natural gas by

pipeline with few safety and environmental incidents, CO2 transport is not expected to

create major concerns (IPCC, 2005). A number of early EOR projects already

transport CO2 through pipelines in the United States, Canada, and other jurisdictions.

The main differences between transporting natural gas and CO2 via pipeline from an

environmental regulatory perspective are:

§ when CO2 mixes with water it becomes acidic and corrosive

§ CO2 is heavier than air

§ CO2 is transported at almost double the pressure of natural gas

§ CO2 is odorless

§ CO2 is not flammable

It is envisaged that many of the safety measures and monitoring techniques

employed by the natural gas industry can be applied to CO2 transport via pipeline,

with modifications to take into account the differences between natural gas and CO2.

The requirements include assignment of liability for leakage or other hazard to the

pipeline owner and development of appropriate standards for the design, construction

and maintenance of pipelines.

Given the anticipated increases in the volumes of CO2 being transported to

accommodate the expansion of CCS, there will be a major need for new CO2

pipelines, which will require existing regulatory frameworks to be adapted. Key

regulatory guidelines around the transport of CO2 are (IEA, 2008; WRI, 2008):

§ Siting a new CO2 pipeline will involve determining the route, acquiring the

rights of way, and assessing the environmental impacts of the proposed route.

The right of way typically involves gaining access to a portion of a current

access route, or obtaining access via easement or other mechanism to private

property. The pipeline owner must acquire the use of the land along the

pipeline right of way. A pipeline developer can either use an existing right of

way corridor or create a new one by negotiating with each landowner along

the route.

§ Regulators may need to secure land for CO2 pipeline infrastructure where that

is deemed to be in the public interest.

§ There will also be a need to evaluate the necessary pipeline capacities for

particular regions as CO2 storage activities expand.

§ CO2 pipeline design specifications should be fit-for-purpose and consistent

with the projected concentrations of co-constituents, particularly water,

hydrogen sulfide (H2S), oxygen, hydrocarbons, and mercury.

§ Existing industry experience and regulations for pipeline design and operation

should be applied to future CCS projects.

§ Operators should follow the existing Occupational Safety and Health

Administration (OSHA) standards–or equivalent–for safe handling of CO2.

§ Pipelines located in vulnerable areas (populated, ecologically sensitive, or

seismically active areas) require extra due diligence by operators to ensure

safe pipeline operations. Options for increasing due diligence include

decreased spacing of mainline valves, greater depths of burial, and increased

frequency of pipeline integrity assessments and monitoring for leaks.

§ If the pipeline is designed to handle H2S, operators should adopt appropriate

protection for handling and exposure.

§ Considering the extent of CO2 pipeline needs for large scale CCS, a more

efficient means of regulating the siting of inter-province CO2 pipelines should

be considered at the federal level, based on consultation with states, industry,

and other stakeholders.

§ As a broader CO2 pipeline infrastructure develops, regulators should consider

allowing CO2 pipeline developers to take advantage of current state

condemnation statutes and regulations that will facilitate right-of-way

acquisition negotiations.

§ As a CO2 transport system develops from a series of unlinked provincial or

national pipelines to a network of regional or inter-province pipelines, there

will be a need to harmonise CO2 pipeline regulations across province or

national borders to eliminate inconsistencies in pipeline access and CO2 purity

requirements.

§ The national government should consult with industry and provinces to

evaluate a model for setting rates and access for inter-provinces CO2 pipelines.

Such action would facilitate the growth of an inter-provinces CO2 pipeline

network.

§ One approach that is already used in the natural gas sector to streamline

pipeline construction and access is to create a “one stop” agency for pipeline

permitting, where various approvals are handled by one entity in consultation

with stakeholders

7.1.3.3 Storage Regulatory Guidelines

The injection of CO2 in deep geological formations involves many of the same

technologies that have been developed in the oil and gas exploration and production

industry; including well drilling, fluid injection, computer simulation of storage

reservoirs and monitoring.

A priority for governments should be to undertake bottom-up capacity

assessments for CO2 storage, taking into account specific concerns for each type of

geological storage. Regulatory developments on CO2 storage primarily evolve around

Measurement, Monitoring and Verification (MMV); risk assessment; financial

responsibility; property rights and ownership; site selection and characterization;

injection operations; and site closure.

7.1.3.3.1 Measurement, Monitoring, and Verification (MMV)

§ MMV requirements should not prescribe methods or tools; rather, they should

focus on the key information an operator is required to collect for each

injection well and the overall project, including injected volume; flow rate or

injection pressure; composition of injectate; spatial distribution of the CO2

plume; reservoir pressure; well integrity; determination of any measurable

leakage; and appropriate data (including formation fluid chemistry) from the

monitoring zone, confining zone, and underground sources of drinking water.

§ Operators should have the flexibility to choose the specific monitoring

techniques and protocols that will be deployed at each storage site, as long as

the methods selected provide data at resolutions that will meet the stated

monitoring requirements.

§ MMV plans, although submitted as part of the site permitting process, should

be reviewed and updated as needed throughout a project as significant new

site-specific operational data become available.

§ The monitoring area should be based initially on knowledge of the regional

and site geology, overall site specific risk assessment, and subsurface flow

simulations. This area should be modified as warranted, based on data

obtained during operations. It should include the project footprint (the CO2

plume and area of significantly elevated pressure, or injected and displaced

fluids).

§ MMV activities should continue after injection ceases as necessary to

demonstrate non-endangerment, as described in the post-closure section.

7.1.3.3.2 Risk Assessment

§ For all storage projects, a risk assessment should be required, along with the

development and implementation of a risk management and risk

communication plan. At a minimum, risk assessments should examine the

potential for leakage of injected or displaced fluids via wells, faults, fractures,

and seismic events, and the fluids’ potential impacts on the integrity of the

confining zone and endangerment to human health and the environment.

§ Risk assessments should address the potential for leakage during operations as

well as over the long term.

§ Risk assessments should help identify priority locations and approaches for

enhanced MMV activities.

§ Risk assessments should provide the basis for mitigation/ remediation plans

for response to unexpected events; such plans should be developed and

submitted to the regulator in support of the proposed MMV plan.

§ Risk assessments should inform operational decisions, including setting an

appropriate injection pressure that will not compromise the integrity of the

confining zone.

§ Periodic updates to the risk assessment should be conducted throughout the

project life cycle based on updated MMV data and revised models and

simulations, as well as knowledge gained from ongoing research and operation

of other storage sites.

§ Risk assessments should encompass the potential for leakage of injected or

displaced fluids via wells, faults, fractures, and seismic events, with a focus on

potential impacts to the integrity of the confining zone and endangerment to

human health and the environment.

§ Risk assessments should include site-specific information, such as the terrain,

potential receptors, proximity of underground sources of drinking water,

faults, and the potential for unidentified borehole locations within the project

footprint.

§ Risk assessments should include non-spatial elements or non-geologic factors

(such as population, land use, or critical habitat) that should be considered in

evaluating a specific site.

7.1.3.3.3 Financial Responsibility

§ Based on site-specific risk assessment, project operators/ owners should

provide an expected value of the estimated costs of site closure (including well

plugging and abandonment, MMV, and foreseeable mitigation (remediation)

action) as part of their permit application. These cost estimates should be

updated as needed prior to undertaking site closure.

§ Project operators/owners should demonstrate financial assurance for all of the

activities required for site closure.

§ Policies should be developed for adequately funding the post-closure activities

that become the responsibility of an entity assuming responsibility for long-

term stewardship, as described in the Post-Closure section.

§ Because of the public good benefits of early storage projects and the potential

difficulty of attracting investment, policymakers should carefully evaluate

options for the design and application of a risk management framework for

such projects.

§ This framework should appropriately balance relevant policy considerations,

including the need for financial assurances, without imposing excessive

barriers to the design and deployment of CCS technology.

7.1.3.3.4 Property Rights and Ownership

§ Potential operators should demonstrate control of legal rights to use the site

surface and/or subsurface to conduct injection, storage, and monitoring over

the expected lifetime of the project within the area of the CO2 plume and

(where appropriate) the entire project footprint. Regulators will also need

access for inspection.

§ Continued investigation into technical, regulatory, and legal issues in

determining pore space ownership for CCS is warranted at the state and

federal levels. Additional legislation to provide a clear and reasonably

actionable pathway for CCS demonstration and deployment may be necessary.

§ MMV activities may require land access beyond the projected CO2 plume;

therefore, land access and any other property interest for these activities

should be obtained.

§ Operators should avoid potential areas of subsurface migration that might lead

to claims of trespass and develop contingencies and mitigation strategies to

avoid such actions.

7.1.3.3.5 Site Selection and Characterization (also refers to Methodology section

in the previous chapter)

§ General Guidelines for Site Characterization and Selection

· Potential storage reservoirs should be ranked using a set of criteria

developed to minimize leakage risks. Future work is needed to clarify

such ranking criteria.

· Low-risk sites should be prioritized for early projects.

· As required by regulation, storage reservoirs should not be freshwater

aquifers or potential underground sources of drinking water.

· Confining zones must be present that possess characteristics sufficient

to prevent the injected or displaced fluids from migrating to drinking

water sources or the surface.

· Site-specific data should be collected and used to develop a subsurface

reservoir model to predict/simulate the injection over the lifetime of

the storage project and the associated project footprint. These

simulations should make predictions that can be verified by history-

matching within a relatively short period of time after initial CO2

injection or upon completion of the first round of wells. The reservoir

model and simulations should be updated periodically as warranted and

agreed with regulators.

· Saline formations and mature oil and gas fields should be considered

for initial projects. Other formations, such as coal seams, may prove

viable for subsequent activity with additional research.

§ Guidelines for Determining Functionality of Confining Zones

· Confining zones must be present and must prevent the injected or

displaced fluids from migrating to drinking water sources as well as to

economic resources (e.g., mineral resources) or the surface.

· Operators should identify and map the continuity of the target

formation and confining zones for the project footprint, and confirm

the integrity of the confining zones with appropriate tools. Natural and

drilling or operationally induced fractures (or the likely occurrence

thereof) should be identified.

· Operators should identify and map auxiliary or secondary confining

zones overlying the primary and secondary target formations, where

appropriate.

· Operators should identify and locate all wells with penetrations of the

confining zone within the project footprint. A survey of these wells to

assess their likely performance and integrity based on completion

records and visual surveys should be conducted. These data should be

made publicly available.

· Operators should identify and map all potentially significant

transmissive faults, especially those that transect the confining zone

within the project footprint.

· Operators should collect in-situ stress information from site wells and

other sources to assess likely fault performance, including stress tensor

orientation and magnitude.

§ Guidelines for Determining Injectivity

o If sufficient data do not already exist, operators should obtain data to

estimate injectivity over the projected project footprint. This may be

accomplished with a sustained test injection or production of site

well(s). These wells (which could serve for injection, monitoring, or

characterization) should have the spatial distribution to provide

reasonable preliminary estimates over the projected project footprint.

o Water injection tests should be allowed in determining site injectivity.

o Operators should obtain and organize porosity and permeability

measurements from core samples collected at the site. These data

should be made publicly available.

§ Guidelines for Determining Capacity

o Operators should estimate or obtain estimates of the projected capacity

for storing CO2 with site-specific data (CO2 density at projected

reservoir pressure and temperature) for the project footprint. This

should include all target formations of interest, including primary and

secondary targets. Capacity calculations should include estimates of

the net vertical volume effectively utilized or available for storage and

an estimate of likely pore volume fraction to be used (utilization

factor).

o Operators should collect and analyze target formation pore fluids to

determine the projected rate and amount of CO2 stored in a dissolved

phase. These data should be made publicly available as necessary for

permitting and compliance purposes.

o Operators should obtain estimates of phase-relative permeability (CO2

and brine) and the amount of residual phase trapping. One possible

approach is to use core samples with sufficient spatial density to

confirm the existence of the trapping mechanisms throughout the site

and to allow their simulation prior to site development. Estimates

should be updated with site-specific monitoring and modeling results.

These data should be made publicly available as necessary for

permitting and compliance purposes.

§ Guidelines for Injection Operations

o CO2 streams injected for the purpose of climate change mitigation that

meet the following requirements should not be classified as waste:

Ø Streams that consist of high purity (i.e. containing only

incidental amounts of associated substances)37 and;

Ø Streams where no wastes or other matter are added for the

purpose of disposing of those wastes or other matter.

o Workable and consistent specifications for CO2 purity are required that

are based on balancing the cost and benefits for meeting defined purity

37 Amendments to the London Protocol use the term "overwhelmingly CO2".

standards. CO2 streams meeting the purity standards should not be

classified as waste, and must not be subject to restrictions in relation to

trans-border shipment or import/export. CO2 injection should be

considered as a separate issue relative to injection of acid gas or other

hazardous waste undertaken for reasons other than climate change

mitigation.

o A field development plan should be generated early on in the

permitting phase.

o Operators should develop transparent operational plans and

implementation schedules with sufficient flexibility to use operational

data and new information resulting from MMV activities to adapt to

unexpected subsurface environments.

o Operational plans should be based on site characterization information

and risk assessment; they should include contingency

mitigation/remediation strategies.

o Storage operators should plan for compressor and well operations

contingencies with a combination of contractual agreements relating to

upstream management of CO2, backup equipment, storage space, and,

if necessary, permits that allow venting under certain conditions.

o Wells and facilities should be fit-for-purpose, complying with existing

federal and state regulations for design and construction.

o The reservoir and risk models should be recalibrated (or history-

matched) periodically, based on operational data and re-run flow

simulations. Immediate updates should be made if significant

differences in the expected and discovered geology are found.

o The casing cement in the well should extend from the injection zone to

at least an area above the confining zone.

o Well integrity, including cement location and performance, should be

tested after construction is complete, and routinely while the well is

operational, as required by regulation.

o Water injection tests should be allowed at all prospective CCS sites.

o Injection pressures and rates should be determined by well tests and

geomechanical studies, taking into account both formation fracture

pressure and formation parting pressure. Rules should not establish

generally applicable quantitative limits on injection pressure and rates;

rather, site-specific limitations should be established as necessary in

permits.

o Operators should adhere to established workplace CO2 safety

standards.

o Operators should implement corrosion management approaches, such

as regularly checking facilities, wells and meters for substantial

corrosion.

o Corrosion detected should be inhibited immediately, or damaged

facility components should be replaced. Dehydration of the injectate

should be required to prevent corrosion, unless appropriate metallurgy

is installed.

o Operational data should be collected and analyzed throughout a

project’s operation and integrated into the reservoir model and

simulations. The data collected should be used to history-match the

project performance to the simulation predictions.

7.1.3.3.6 Site Closure

§ Continued monitoring during the closure period should be conducted in a

portion of the wells in order to demonstrate non-endangerment, as described

below.

§ For all other wells, early research and experience suggest that conventional

materials and procedures for plugging and abandonment of wells may be

sufficient to ensure project integrity, unless site-specific conditions warrant

special materials or procedures. A final assessment should include a final

cement bond log across the primary sealing interval of all operational wells

within the injection footprint prior to plugging, as well as standard mechanical

integrity and pressure testing.

§ Operators should assemble a comprehensive set of data describing the

location, condition, plugging, and abandonment procedures and any integrity

testing results for every well that will be potentially affected by the storage

project.

§ Satisfactory completion of post-injection monitoring requires a demonstration

with a high degree of confidence that the storage project does not endanger

human health or the environment. This includes demonstrating all of the

following:

o the estimated magnitude and extent of the project footprint (CO2 plume

and the area of elevated pressure), based on measurements and

modeling;

o that CO2 movement and pressure changes match model predictions;

o the estimated location of the detectable CO2 plume based on

measurement and modeling (measuring magnitude of saturation within

the plume or mapping the edge of it);

o either (a) no evidence of significant leakage of injected or displaced

fluids into formations outside the confining zone, or (b) the integrity of

the confining zone

o that, based on the most recent geologic understanding of the site,

including monitoring data and modeling, the CO2 plume and formation

water are not expected to migrate in the future in a manner that

encounters a potential leakage pathway; and

o that wells at the site are not leaking and have maintained integrity.

§ Project operators who have demonstrated non-endangerment should be

released from responsibility for any additional post-closure MMV, and should

plug and abandon any wells used for post-injection monitoring. At this point,

the project can be certified as closed, and project operators should be released

from any financial assurance instruments held for site closure. In the event that

regulators or a separate entity decide to undertake post-closure monitoring that

involves keeping an existing monitoring well open or drilling new monitoring

wells, project operators should not be responsible for any such work or

associated mitigation or remediation arising out of the conduct of post-closure

MMV.

§ If one does not already exist in a jurisdiction, a publicly accessible registry

should be created for well plugging and abandonment data.

§ As a condition of completing site closure, operators should provide data on

plugged and abandoned wells potentially affected by their project to the

appropriate well plugging and abandonment registry. This would include the

location and description of all known wells in the storage project footprint, and

the drilling, completion, plugging, and integrity testing records for all

operational wells.

§ The site-specific risk assessment should be updated based on operational data

and observations during closure.

7.1.3.3.7 Post-Closure

§ Certified closed sites should be managed by an entity or entities whose tasks

would include such activities as operating the registries of sites, conducting

periodic MMV, and, if the need arises, conducting routine maintenance at

MMV wells at closed sites over time.

§ These entities need to be adequately funded over time to conduct those post-

closure activities for which they are responsible.

7.2 Enabling Policies

The need for incentives, regulation, and technology transfer means that

evolution of public policy on CCS is imperative. All elements of CCS technology

(CO2 capture, transportation, storage and monitoring) exist today and have been

commercially deployed in various industries, specifically oil and gas production.

However, these technology elements have not been integrated into large-scale CCS

projects such as coal-fired power plants and other large-scale stationary sources.

The most significant risks are commercial and policy related. At this time,

CCS is not commercially viable, due to the high cost of CCS and the currently weak

international carbon price signals. Moreover, there is no legal / regulatory regime in

place that would allow potential developers and investors to adequately assess and

manage their risks and liabilities in respect of CO2 storage. Policy framework for CCS

should consider demo projects and funding, capacity building, regulations, and project

support mechanisms.

7.2.1 International Financing

CCS could be a technology that is implemented wherever it is technically

possible, but it needs incentives for deployment due to the additional costs of capture,

transport and storage. Certain “early opportunities” for CCS deployment could be

incentivized via the international climate regime that provides valuable learning

effects for wider deployment of CCS in the medium-term. Whilst the potential to

mitigate climate change from CCS is significant in both developed and developing

countries, the IPCC Special Report on Carbon Dioxide Capture and Storage indicates

that a large number of the most cost-effective ‘early opportunities’ for CCS projects

are located in developing countries.

Today there is a focus on incorporating CCS within a project-based

mechanism such as the Clean Development Mechanism (CDM) and/or its successor.

Whilst this would be an important policy development in that it opens the door to

CCS projects within developing countries, the way in which it is implemented could

be important for future trading development.

An immediate solution to CCS in any project-based mechanism is to develop a

methodology that covers all aspects of CO2 storage, carbon capture, CO2 transport and

sustainable development. This would work well in the short term and provides an

immediate solution to the issue. However, it also supports the notion that over the

CCS in developing country are effectively financed by the developed countries in the

foreseeable future. The most promising financing mechanism is the one that utilizes

the carbon market or emissions trading schemes. Such mechanism will allow

developing countries to reduce their emissions further from the business as usual

(BAU) case and Nationally Appropriate Mitigation Actions with funding from the

developed countries (cf. Figure 7.5).

Figure 7.5 Illustrative split of a developing country’s emissions reductions

Whilst the project-based mechanism in tandem with emissions trading system

may be used for several decades, many developing countries must be in a position to

tackle their own emissions through their own projects in the medium term. To do this

they will want to implement national policy instruments such as emissions trading,

renewable certificates and standards. They will also need to engage in international

trade of CO2 instruments to maximise flexibility in achieving national targets.

With an eye on the future, there is a case for the development of an

international tradable carbon sequestration unit (CSU) that is based on internationally

accepted criteria for the longevity of storage. This could apply anywhere in the world

and would be awarded on the basis of ensuring long-term storage according to

procedures detailed in the 2006 IPCC Guidelines for National Gas Inventories.

Initially the CSU would support a CCS project in a project-based mechanism.

Whilst the project itself would need to meet the various criteria, the storage of CO2

would be credited outside the mechanism. The number of CERs awarded to a project

would remain as the net emissions relative to a national baseline, for which a certain

number of CSUs would be required.

Initially the CSU could support a CCS project in the CTM (Clean Technology

Mechanism). The number of Certified Emission Reduction (CER) units awarded to

the project would depend on the emissions performance of the project as a whole and

not just on the amount of CO2 stored, as certified by the CSU. However, the CSUs

linked to that CER award would then be tied to the project and no longer tradable

independently.

The CSU could be developed by any number of international bodies, including

the UNFCCC. However, in the interests of the technology itself the best home would

be a body dedicated to CCS, such as the recently announced Global CCS Institute (an

Australian initiative) or the International Performance Assessment Centre for CCS (a

Canadian initiative). Importantly, the CSU underpins the necessary development of

institutional capacity building for CCS measurement, reporting and verification.

The existence of a CSU opens up the possibility of a range of policy options

for the expanded deployment of CCS. For example, with an initial CCS industry

established in a developing country through CDM / CTM and other funding

mechanisms, the institutional capacity would exist to introduce a fossil power

generation standard (e.g. grams of CO2 per kWhr) backed by the CSU. In addition,

because of its international recognition, power generators could meet their obligation

by purchasing CSUs on the international market. Similarly, the CSU could back CO2

storage in any emissions trading system, in the same way that the EU CCS Directive

backs CCS in the EU-ETS.

Figure 7.6 Proposed model of project-based mechanism that enables CCS deployment: Clean Technology Mechanism

CDM / JI (Kyoto 2008-2012)• Small / Moderate scale• Development “dividend”• SD criteria• Additionality• Exhaustive project by project process

Cost of abatement€/tCO2e

AbatementGtCO2e per year in 2030

CO2 Storage Certificate• Recognises CCS globally• Certifies tonnes sequestered• Standardised rules• Potentially tradable

CO2 Storage Certificate• Recognises CCS globally• Certifies tonnes sequestered• Standardised rules• Potentially tradable

Clean Development Mechanism• Existing CDM rolls forward• Smaller scale than CTM• Development agenda• Focus on less developed economies

Clean Technology Mechanism• Focussed on the higher end of the

abatement curve• Principally clean electricity• Recognises CCS• Drives sector-based approach

Clean Technology Mechanism• Focussed on the higher end of the

abatement curve• Principally clean electricity• Recognises CCS• Drives sector-based approach

CO2 Storage Certificate• Recognises CCS globally• Certifies tonnes sequestered• Standardised rules• Potentially tradable

CO2 Storage Certificate• Recognises CCS globally• Certifies tonnes sequestered• Standardised rules• Potentially tradable

Clean Development Mechanism• Existing CDM rolls forward• Smaller scale than CTM• Development agenda• Focus on less developed economies

Clean Technology Mechanism• Focussed on the higher end of the

abatement curve• Principally clean electricity• Recognises CCS• Drives sector-based approach

Clean Technology Mechanism• Focussed on the higher end of the

abatement curve• Principally clean electricity• Recognises CCS• Drives sector-based approach

7.2.1.1 Complementing International Policy: A Proposal for International Framework

Climate change presents the world with a complex challenge – arguably too

complex to meet with a single approach, such as was delivered by the Montreal

Protocol (to protect the ozone layer). Nevertheless, we do have some notion as to the

end-game policy structure – namely a framework to encourage the discovery,

development and demonstration of new technologies supported by a global market

based approach to drive technology deployment. The deployment step must be

combined with a capacity building step to support the projects in developing

countries.

Policy development is key to addressing climate change whilst meeting energy

needs. A market need for low CO2 emission projects will not develop without the

creation of demand of some sort, either through establishing a “cap-and-trade”

system, setting a standard or creating a baseline for a project.

National thinking has largely dominated the discussion so far, but a further

dimension to consider is the economic sector. Action on that basis, in combination

with or as a complement to national policy, may deliver a more manageable approach

to the issue.

The ability for developing countries to take on targets is also key to the

sustainability of any international agreement on climate change. Yet many developing

countries lack the capacity to manage emissions across the economy and may not

have the necessary technical expertise and know how to implement the necessary

projects.

The international agreement that is forged in Copenhagen and beyond will

likely have at its core some form of long-term goal and an agreed direction for

developed countries – probably comprising absolute emission reduction targets. This

is the basic framework of the agreement, but over time absolute emission reduction

targets must become more widespread if the overall long-term goal is to be reached.

An overarching pathway through which developing countries can

progressively adopt targets will be required, offering the necessary funding and

capacity building such that those countries can then realistically manage CO2

emissions going forward. An approach that focuses on key sectors within developing

country economies is one possible solution.

7.2.1.2 The Shape of an Agreement

Such a framework, as might be agreed in 2009 in Copenhagen, would start

with a global long-term goal. This would not just be some distant aspiration, but a

pathway with intermediate targets, the first of which should be in 2020, no later. Such

a pathway will provide context for the necessary reductions at national and regional

level.

Coming directly from the global pathway will be targets for developed

countries. These will have a near term focus, say 2020 and will then drive mitigation

programmes in those countries.

Over time, the number of countries in this category must increase, but this

requires further structure.

Figure 7.7 Building blocks of an effective Post-2012 climate agreement

7.2.1.3 Supporting Infrastructure

Five infrastructure “pillars” must be in place as part of the agreement to

support developing country action and to facilitate the development of global markets

that will stem from the policies implemented in developed countries.

Copenhagen AgreementCopenhagen Agreement

Long term goal

Developed Country Targets

Developed Country Action

Developing Country Action

“Satellite” Agreements- clear purpose and end-point

- built on the foundation elements- negotiated separately (by a limited number of parties)

- typically focussed on a sector- technology capacity building

“Satellite” Agreements- clear purpose and end-point

- built on the foundation elements- negotiated separately (by a limited number of parties)

- typically focussed on a sector- technology capacity building

CleanTechnology

Funds

SupportingMechanisms

CarbonMarketInfra-

structure

AdaptationFunding

MeasurableReportableVerifiable

CleanTechnology

Funds

SupportingMechanisms

CarbonMarketInfra-

structure

AdaptationFunding

MeasurableReportableVerifiable

1. Clean technology funds, which can be used to support the discovery, development

and large-scale demonstration of a range of low CO2 emission energy technologies

and other technologies that reduce CH4 and other GHG emissions.

2. Project based mechanisms to facilitate the deployment of clean technology – with

the best example today being the CDM. The existing Clean Development

Mechanism (CDM) should be revised to financially support and deliver large-scale

mitigation actions, principally involving the removal of GHGs through destruction

(e.g. HFCs), storage (CCS and land-use) and substitution (e.g. renewable energy).

A broadly based mechanism such as this must also be backed by sufficient

liquidity and critical mass in developed country “cap-and-trade” systems to absorb

the flow of Certified Emission Reduction Units (CERs). Importantly, all ETS

systems must recognise it and not try to develop their own offset / project criteria.

A family of approaches may evolve, for example;

· CCS Mechanism – Recognition of CCS as a valid CO2 mitigation

project. In tandem and supporting this, an international CO2 storage

certification process is developed that delivers a tradable certificate for

one tonne of CO2 stored underground. This would apply anywhere in

the world and would not be dependent on any special development

criteria.

· Programmatic CDM - Allows the CDM to operate on a programmatic

basis at a national sectoral level. Such an expansion would allow a

'project' to be defined more broadly, for example an absolute emissions

reduction in a given manufacturing sector.

· Land Use Mechanism – Market mechanisms with CO2 emissions

reduction certificates could help financial incentives flow into the

sector where specific emission reduction opportunities can be

identified, measured and verified.

· Development Mechanism – A streamlined version of the current CDM

would catalyse clean energy for development. It would typically

operate on a modest scale.

3. Infrastructure to facilitate the development of a global greenhouse gas market.

Today that consists of the International Transaction Log. This continues the role of

the UNFCCC to provide the infrastructure to support the development of emissions

trading.

4. Measurement, Reporting and Verification (MRV) – A series of robust processes to

ensure that actions taken are measurable, reportable and verifiable.

5. Adaptation Funding – This important area of action needs specific funding, but the

funding solutions need to remain separate to those for mitigation actions.

Whilst these infrastructure pillars are important for developed country action,

a major reason for their existence is to support the path forward for developing

countries.

7.2.2 Long-Term Liability

Liability arising from local damages (other than climate change liabilities) (i.e.

health and property damages) during operation and post closure phases can

appropriately lie with the site operator. This liability is similar to that oil and gas

companies routinely assumes in the operation of other production, processing,

refining and transport facilities.

Storage site operators should be responsible for making reasonable efforts to

ensure that the injected CO2 remains in place during and after the operating life of the

storage facility. Operators should be responsible for monitoring and maintaining the

integrity of the storage site, and also for offsetting or re-injecting any volume of CO2

re-emitted to the atmosphere for some period of time following the decommissioning

of the site.

Meanwhile, liability for global damages (i.e. carbon reversal) should be

covered through an “offset” approach whereby operators re-inject and/or purchase

emissions trading units to an equal amount of CO2 as estimated to have leaked38.

Long-term liability for CCS raises unique concerns because the time frame

stretches forward in perpetuity. On the other hand, the potential risk of leakage

diminishes over time as the forms of CO2 trapping mechanism becomes more stable,

and plume migration ceases or is reduced39. This means that the residual liability

38 Although this could be open to gaming by operators, and relies on regulators setting an effective price for carbon in order to avoid creating perverse incentives for releasing CO2 from storage sites. 39 See: IPCC SRCCS, Page 2008.

associated with storage sites should diminish over time following cessation of

injection operations.

Public companies are under a fiduciary duty to clearly report all residual

liabilities to shareholders. In the absence of a cap on liability, companies would have

a difficult time fulfilling this duty and other disclosure obligations. This difficulty is

especially focused on potential tort litigation alleging climate change damages to the

global environment if CO2 leaks from a carbon storage facility. There is little way to

meaningfully quantify such potential future liability. In addition, nation states are

better placed to manage very long term liabilities than private companies because of

the relative differences in the lifespan of companies compared to nation states.

There are several different ways of addressing the concerns about long-term

liability:

· One approach is for liability to be shared between the operator and the state, with

liability passing to the state upon presentation of appropriate evidence suggesting

that long-term stable storage has been achieved40.

· Another approach is for the government to legislatively limit tort liability for

global climate change damages. Although an operator would presumably need to

remedy a leak by replenishing CO2 or purchasing ETS credits (as noted above), a

liability cap or bar would prevent the most unpredictable and unquantifiable

liability.

· If liability cannot otherwise be prevented or limited, it could be made manageable

through an industry risk-pooling mechanism. This could be structured with

greater or lesser government involvement.

7.2.3 Public Acceptance

Although the capture, transport, and geological storage of CO2 are safe when

done properly, the public may have some reservations to CCS projects especially

when such projects are taking place near residential area. Most of the reservations are

due to lack of information and resistance to something new.

Public acceptance of CCS must begin with building awareness of the need and

the feasibility of CCS deployment through public discussions and media coverage.

40 It should be noted that governments may demand stricter closure standards if they will be assuming the liability.

This can be done among others by public statements, public seminars, television

coverage, newspaper articles, and other means of public communication.

It is also important to highlight the context in which CCS technology require

widespread deployment i.e. environmental stress caused by climate change means

there is pressing need to drastically reduce CO2 emissions, whereas international

collaboration in mitigation technology (including CCS) must be deployed soon.

In fact, to ensure the engagement process is seen as genuine and not

advocating for any one particular solution, discussion about CCS needs to be

undertaken within the broader context of climate change and the range of options,

which may form part of a more sustainable future.

Annex: Development of Enabling Regulatory Framework Worldwide

Regulatory frameworks in nearly all jurisdictions remain at an early stage of

evolution:

A.1 Australia

Australia has published a draft CCS Bill41, which is now subject to its third

reading in Parliament (18/9/2008). The draft Bill has not been reviewed extensively

herein. Suffice to say it contains detailed provisions for storage site exploration,

retention of tenure during development phases, an injection license regime which

allows for the use of subsurface geological formations for storing greenhouse gases

(which can be applied for through transfer of production licensing), closure

procedures, license surrender procedures, use of securities, modifications to allow for

greenhouse gas pipeline developments, closure provisions linked to long-term storage

performance assessments. It also includes allows for development of TPA rights for

pipelines and storage sites.

A.2 European Union

The European Commission has published a draft CCS Directive released in

January 2008. This Directive proposes dis-applying waste and water laws from CO2

storage operations, conferring EIA requirements, and introducing a new free-standing 41 Offshore Petroleum Amendment (Greenhouse Gas Storage) Act 2008

permitting regime for storage sites, covering inter alia site characterisation, risk

assessment and monitoring. Liabilities will be managed through the existing

Environmental Liability Directive for in situ damages. Global damages will be

managed through the European Union Emissions Trading Scheme by way of “offset”

obligations.

The draft Directive also includes an obligation for operators to take out an up

front financial provision to cover future decommissioning and “corrective measures”,

and sets down rules on TPA to pipelines and storage sites. With modifications, the

European Parliament approved the CCS Directive in October 2008. The UK and

Netherlands are also pursuing the development of national legislation to accommodate

forthcoming CCS projects. The Netherlands Mining Act 2003 acknowledges CCS,

and includes licensing procedures covering Storage Permits, storage plans, and a

monitoring and reporting obligations. The UK will create primary enabling

legislation in a 2008 Energy Bill. In November 2007, the Government published a

consultation paper on CCS regulations in the UK.

A.3 United States

Although there is currently no comprehensive legal and regulatory framework

for CO2 storage in the US, the Underground Injection Control (UIC) Program is likely

to serve as the basis for development of CCS regulation. In March 2007 The

Environmental Protection Agency issued interim guidance for approving pilot CCS

wells, emphasizing the need for flexibility in regulating a developing technology. In

September 2007, the Interstate Oil and Gas Compact Commission (in US and Canada;

IOGCC) has also proposed a CCS model rule.

More recently, in July 2008 the EPA published a proposed Rule for Federal

Requirements under UIC for CCS, which establishes a new well class VI specific to

CO2 injection. Class VI wells would be subject to site characterisation, CO2

resistivity requirements in well design, monitoring and recalibration of modelled

behaviour, introduction of post-injection monitoring, and the use of financial

securities to provide assurance of the availability of funds for well plugging, site care,

closure, and emergency and remdial responses. Competition for siting of the federally

funded FutureGen clean coal project has prompted some U.S. states to pass laws that

transfer liability from project developers to the state post-closure; however, it is

questionable whether this approach would be used for commercial CCS deployment.

A.4 Canada

In Canada, some provinces (Alberta, Saskatchewan, BC) have well evolved

legislation for injection covering EOR, natural gas storage and acid-gas injection,

which will likely provide the basis for CO2 storage regulations, albeit with a need to

consider additional questions around long-term monitoring and remediation (e.g.

liability provisions). In 2007 Alberta enacted the Climate Change and Emissions

Management Amendment Act (CCEMAA), which was the first ‘negative incentive’

legislation for GHG emissions by any level of government in Canada.

In addition to introducing mandatory emission reduction targets for specified

facilities, CCEMAA provides the necessary property rights for a CCS projects in the

future. CCEMAA defines a ‘sink’ as a ‘geological formation or any constructed

facility, place or thing used to store specified gases (including CO2)’ and provides for

regulations governing the legal and commercial interests in a sink. Upon their

enactment, such regulations will likely supersede the existing property rights

governing the storage of gases in subsurface formations.

References CCS National Workshop (2008) Summary of Carbon Capture and Storage National Workshop, Jakarta 30-31 October 2008 ESDM (2006) Blueprint Pengelolaan Energi Nasional 2006-2025. Jakarta: Departemen Energi dan Sumber Daya Mineral Republik Indonesia Heidug, W. (2006) A Matter of Permanence: Geological Storage of CO2 and Emission Trading Frameworks”, www.iea.org/textbase/work/2006/ghget/heidug.pdf IEA (2007) Legal Aspects of Storing CO2. Paris: International Energy Agency IEA (2008) CO2 Capture and Storage – A Key Carbon Abatement Option. Paris: International Energy Agency IPCC (2005) IPCC Special Report on Carbon Dioxide Capture and Storage. Cambridge: Cambridge University Press IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Institute for Global Environmental Strategies (IGES) IPCC (2007) Climate Change 2007: Working Group III Contribution to the Fourth Assessment Report of the IPCC. Cambridge: Cambridge University Press PEUI (2006) Indonesian Energy Outlook and Statistics 2006. Pengkajian Energi Universitas Indonesia Rubin, E. (2007) Accelerating Deployment of CCS at US Coal-Base Power Plants”, presentation at the 6th Annual Carbon Capture and Sequestration Conference, Pittsburgh (May 8) The CCSReg Project (2009), Briefing on the interim report, Washington D.C., Jan. 9, 2009 WRI (2008) Guidelines for Carbon Dioxide Capture, Transport and Storage. Washington, DC: World Resources Institute

CHAPTER 8

CONCLUSIONS AND RECOMMENDATIONS Conclusions: § Industrial and energy-related activities across Indonesia are currently venting

an estimated 293 million tonnes of CO2 per annum to the atmosphere. The

capture and sequestration of this CO2 represents a significant opportunity to

reduce overall national emissions. The most significant source of CO2 is from

flue (exhaust) gases in the power generation sector; capture of this CO2 will be

associated with significant costs and will require substantial investments to be

made. A secondary, potentially lower cost opportunity for sequestration is

from a variety of existing CO2 streams that are generated as an industrial by-

product e.g. from gas plants that are processing and purifying natural gas

contaminated with naturally occurring CO2, and from refineries.

§ There are several favourable geological storages that can be proposed as major

CO2 containment options that correspond to this preliminary assessment

namely South Sumatra, East Kalimantan and Natuna sedimentary basins.

These regions are deliberately chosen due to geological stability, well

characterised, low population density and existing infrastructures.

§ CO2 injection in conjunction with enhanced oil recovery (EOR) is most likely

an early option for Indonesia since this technology is established and it

generates income.

§ Abandoned oil and gas fields and deep saline aquifers are the most likely

storage containers for future CO2 sequestration. A robust methodology exists

that can be used to identify subsurface storage containers for CO2 needed for

commercial-scale projects.

Recommendations: § The goals of national energy security and environmental protection need to be

reconciled, which requires strong and coordinated government action and

public support. To establish future low-carbon energy path, firm action is

needed to steer the national energy system onto sustainable energy path while

supporting national economic growth.

§ There has been important progress in the area of CCS technology development

in recent years globally. However, at the national level more actions are still

needed, particularly in the areas of public consultation and raising awareness

of the stakeholders.

§ Detailed engineering studies to estimate national geological storage capacity

are necessary in order to give higher degree of storage sites confidence.

§ Early deployment of CCS technology in Indonesia supported by existing

energy infrastructures will accelerate CCS technology transfer. To render its

long-term viability, associated issues that need to be elaborated further relate

to site characterization, appropriate legal & regulatory frameworks,

monitoring, liability and long-term ownership, and business risk.

§ Overall, the global deployment of Carbon Capture & Storage (CCS) is

hampered less by technical challenges (e.g. the hydrocarbon industry has more

than 30 years of experience with CO2 injection projects for Enhanced Oil

Recovery), than by the commercial factors that need to provide incentives to

undertake CCS projects. To enable the widespread deployment of CCS in

Indonesia the following activities are recommended:

· A number of demonstrator CCS projects should be initiated and

funded, to demonstrate successful sequestration in an Indonesian

setting, and to develop the regulatory framework that will need to be in

place for the approval and management of CCS projects.

· Major CO2 emissions sources should be prepared for a possible future

requirement for sequestration, by preparing a plan for the deployment

of carbon capture technology, and investigating options for subsurface

storage following the proposed site selection methodology.

· Incentive mechanisms that will promote CCS within Indonesia should

be examined, and a funding solution developed that will meet country

needs during the transition to a global carbon trading or taxation

system.

· There is a need to expand Indonesia’s involvement in international

dialogues and collaboration to accelerate the development of CCS

demonstration projects in Indonesia.

§ Measurement, monitoring and verification of CO2 containment should take

place throughout the lifecycle of the project, and beyond.