ccs potential indonesia

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Understanding Carbon Capture

and Storage Potential

In Indonesia

FINAL DRAFT14 August 2009

Prepared by:

Indonesia CCS Study Working Group

The assessment under the cooperation between Indonesia and United Kingdom:

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

LEMIGAS British Embassy Jakarta Kementrian Lingkungan Hidup


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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 CO 2

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 earths

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

already used by the oil and gas industry.


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There are multiple industrial sources of CO2in 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 CO2content 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 CO2emissions from 8 interconnected power

systems will be 1,938.5 million tonnes CO2accumulated 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 CO2emissions 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 CO2emissions

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 CO2emissions

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


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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 its 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 CO2from 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


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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 CO2mainly 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 CO2over 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 CO2is 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 CO 2and increases

to $ 1.4/t CO2at 70% capacity, iii) for the South Sumatera onshore case, the average

cost per tonne at full capacity is $ 0.53/t CO2and increases to $ 0.82/t CO2at 65%

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

capacity is $ 1.2/t CO2and increases to $ 1.8/t CO2at 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


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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

(4 Mt/y) impose relatively

small specific costs ~


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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 CO2in the reservoir and to verify the effectiveness of CO2 cycling

versusstorage.

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 CO2are


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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 CO2sequestration.

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 CO2mitigation effort generates no revenue stream other than

the CO2price (if it is recognized to generate CO2credits, 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 CO2sources that can be captured and the CO2storage 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


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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 Indonesias move towards CCS a significant one in mustering international

support.


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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 CO2Emissions 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. CO2Emission 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 CO2Sources in Indonesia 2.1

2.1.2.1 North Sumatra CO2Emissions Sources 2.1

2.1.2.2 Central Sumatra CO2Emissions Sources 2.1

2.1.2.3 South Sumatra CO2Emissions Sources 2.1

2.1.2.4 West Java CO2Emissions Sources 2.1

2.1.2.5 East Java CO2Emissions Sources 2.1

2.1.2.6 Kalimantan CO2Emissions Sources 2.1

2.1.2.7 Sulawesi CO2Emissions Sources 2.1

2.1.3 Case Study - Screening CO2sources in A High Graded

Area of Interest 2.1

2.2 Power Sector 2.2

2.2.1 Introduction 2.22.2.2 Indonesian Electricity Development 2.2

2.2.3 Projection of CO2Emission 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 CO2Sources 3.1

3.2 Introduction to CO2 Separation Methods 3.1

3.2.1 Options 3.1


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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 CO2Capture in Power Plants 3.1

3.3.1 Post-combustion Removal 3.1

3.3.1.1 CO2Separation 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 CO2Capture 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 CO2Separation Processes for IGCC with Shift 3.1

3.3.2.6 Pre-combustion Removal of CO2with 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 CO2Capture 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


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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 CO2Capture 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 CO2in 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 CO2Capture 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 CO2Capture 3.1

3.7.3 Control Measures in Relation To Operation with CO2 3.1

3.7.4 Environmental Impact of CO2Capture 3.1

3.8 Preliminary Assessment of Options in Indonesia 3.1

3.9 Implications for Use of CO2Capture in Indonesia 3.1

4. Transportation Technology 4.1

4.1 Transportation Options and Conditions 4.1


4.1.2 Methods of Transporting CO2 4.1

4.1.3 Characteristics of CO2Supply 4.1

4.1.4 Demands of CO2Storage 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 CO2At 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


4.7.2 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

4.7.6Natural Gas Processing Plant, Subang Field 4.1

4.7.7 Ship Transport of CO2 4.1

4.7.8 Conclusions about Transporting CO2in the 5 Case Studies 4.1

4.7.9 Implications for Future CO2Transport 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 CO2in 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 Indonesias 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

7.1.3National 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


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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


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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 CO2Accumulated Emissions Projection 2008 2018 1.1

2.1 Comparison of the different CO2capture processing routes based on

current available technologies 2.1

2.2 Total estimated CO2emissions from oil and gas processing 2.1

2.3 Source types, plant and company names for the major emission sourcesin North Sumatra 2.1

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

in Central Sumatra 2.1


in South Sumatra 2.1


in West Java 2.1


in East Java 2.1


in Kalimantan 2.1


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 CO2Emissions 2.1

3.1 Typical CO2concentrations 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


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3.6 Estimates of space required (m2) for capture of CO2at a 500 MW

power plant 3.1

3.7 Effect of capturing CO2on the cost of pulverised coal-fired sub-critical

steam cycle power plant, based on NETL 3.1

3.8 Effect of capturing CO2on cost of Super-critical steam cycle pulverised

coal-fired power plant, based on NETL 3.1

3.9 Effect of capturing CO2on the cost of an IGCC plant, based on NETL 3.1

3.10 Effect of capturing CO2on 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 CO2from 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 CO2on South Sumatera 4.1


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


Kalimantan onshore case 4.1


Natural gas processing plant, Subang field case 4.1

6.1 Worldwide Geological Storage Capacity for Several Storage Options 6.1


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LIST OF FIGURES

1.1 CO2Emissions by Sectors 1.1

1.2 Global Energy Related CO2Emisions 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 CO2Projection up 2018 of 4 Power Plants & 1 Gas Processing Plant 1.1

2.1 Flue gas and CO2streams and their equivalent IPCC proposed capture

technologies and terminology 2.12.2 Regional map of main CO2emission sources in the western and central

parts of Indonesia 2.1

2.3 CO2emissions 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 CO2emission sources in North Sumatra 2.1

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

2.8 Map of CO2emissions sources in Central Sumatra 2.1

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

2.10 Map of CO2emissions 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 CO2emissions sources in East Java 2.1

2.14 High level overview of CO2 emissions in Kalimantan 2.1

2.15 Map of CO2emissions sources for Kalimantan 2.1

2.16 High level overview of CO2 emissions in Sulawesi 2.1

2.17 Map of CO2emissions 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


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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 CO2Emission in Interconnection Power System 2.1

3.1 Simulation of membrane separation of CO2from H2at 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, CO2capture and compression 3.1

3.5 IGCC with sour shift, CO2removal 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 CO2capture,

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 CO2transport with flow rate in onshore and offshore

pipelines summarising a range of published reports 4.1

4.2 Cost of CO2transport by pipeline showing the effect of distance and flow

rate 4.1

4.3 Annual cost of transporting CO2in 30,000 t ships as a function of distance 4.1

4.4 Comparison of cost of transporting 6 Mt/y CO2by 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 CO2storage

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


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domains during a CO2injection and storage projects 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 Indonesias 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 CO2potential leakage routes and remediation actions 7.1

7.4 Regulatory Needs and Liability for each stage of a CO2storage project 7.1

7.5 Illustrative split of a developing countrys 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


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CHAPTER 1

INTRODUCTION

1.1National Energy Resources and Energy Policy

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

and the worlds 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 worlds 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 Indonesias 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.

Indonesias 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


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

131.4 Thousand BOE in 2008.

Table 1.1National 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 Indonesias 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 1.2National Energy Mix 2008

National Energy Mix 2008Coal 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 - - -


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As stipulated in the National Energy Policy Objective whichbased 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 1.3National Energy Mix Target 2025

1.2 National Energy Mix and Related CO2Emissions

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

the Handbook of Indonesias 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

Liquefied Coal

Oil

Gas

Geothermal

Biofuel

Other Renewable Energy(Biomass, Nuclear, Hydro, Solar, Wind)


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

rise as Indonesias 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 CO2emissions 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 CO2Emissions by Sectors

Figure 1.2 Global Energy Related CO2Emisions 2005


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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 countrys national

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


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

nationals 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 Indonesias 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 CO2emissions given the rising demand

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


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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 CO2emissions 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 IEAs 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.


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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.


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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

EmisiCO2(JutaTon

Base Perpres Hybrid CCS


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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 CO2emissions 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 CO2emitters 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 CO2Accumulated Emissions Projection 2008 2018

NoInterconnection Power

SystemCO2Emissions(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 CO2Projection 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

Muara Tawar 2,3,4Combined Cycle Power Plant

3 x 750 MW

Emissions Projection up to

2018: 26.6 MtCO2

IndramayuSteam CoalPower Plant

2 x 1000 MW


2018: 65.8 MtCO2

Java Sea Offshore

South SumatraOnshore

East KalimantanOnshore

Bangko TengahSteam Coal Power Plant

4 x 600 MW


2018: 11.5 MtCO2

SubangGas Processing Plant

Emissions Projection up to2018: 6.2 MtCO2

Muara JawaSteam Coal Power P lant

2 x 100 MW


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


Power Plant

Legend:

Storage Location

Pipeline

Note: Unscaled Map


Muara Tawar 2,3,4Combined Cycle Power Plant

3 x 750 MW


2018: 26.6 MtCO2

IndramayuSteam CoalPower Plant

2 x 1000 MW


2018: 65.8 MtCO2

Java Sea Offshore

South SumatraOnshore

East KalimantanOnshore

Bangko TengahSteam Coal Power Plant

4 x 600 MW


2018: 11.5 MtCO2

SubangGas Processing Plant

Emissions Projection up to2018: 6.2 MtCO2

Muara JawaSteam Coal Power P lant

2 x 100 MW


2018: 10.6 MtCO2

60 km

60 km

320 km

35 km300 km

15 km

129.7 km


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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 CO2in

conjunction with CO2-enhanced oil recovery (EOR). It is estimated that CO2volume

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, CO2volume 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 CO2likely in the future could be used as CO2source. This

enormous CO2source 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 CO2transportation which is close to Subang Natural Gas

Processing plant.

As depicted by Figure 1.6 above, its shown in more detail the associated CO 2

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.


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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 CO2captured 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 CO2at 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 CO2over 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 CO 2 is already

separated from the gas stream, the exhaust CO2would 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


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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, its expected that these results

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

cost of avoiding CO2emissions, 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.


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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 Banks World Development Indicators (WDI). 2005.


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CHAPTER 2

CO2EMISSION SOURCES IN INDONESIA

2.1 Oil and Gas Industry

2.1.1 Introduction

There are multiple industrial sources of CO2in 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 CO2content at low pressures normal product of combustion.

CO2streams: CO2separated as an industrial by product to meet process stream

specifications.

Figure 2.1 Flue gas and CO2streams and their equivalent IPCC proposed capturetechnologies and terminology (IPCC, 2005)1

1Note that compression and conditioning facilities for CO2have not been taken into account in this

diagram


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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/streams2

Pure streams of CO2are generated from the following industrial processes:

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

specifications (2-5%). This delivers CO2streams 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 CO2being available for other purposes is low.

2

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


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Figure 2.2 Regional map of main CO2emission sources in the western and central parts of Indonesia


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The total energy-related estimated CO2output 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 CO2emissions 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 CO2streams 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 CO2accounts to some 80 million tonnes pa.


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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 estimatebased on publically available data; power stations are excluded)

2.1.2.1 North Sumatra CO2Emissions 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 CO2being

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

3Circle 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 fromanalogue plant data. Each pie chart segment represents the total flue gas or pure CO2 stream emissionsin each region

Oil and gas processing CO2emission(Million Tonnes)

Java 5.1

Sumatra 6.3

Kalimantan 3.4

Sulawesi 2.5

Total 17.3


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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


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

CO2Source Plant Name Operator / owner

LNG plant (CO2stream & fluegas)

Arun 6 (Phase III)Arun / Pertamina/Exxon

Mobil

Refinery (H2Unit) (CO2

stream)Pangkalan Brandan n/a

Gas Processing (CO2stream) Pangkalan BrandanPT Pertamina /

Indonesia

Gas Processing (CO2stream)(Pangkalan Brandan

City)PT Pertamina /

Indonesia

Gas Processing (CO2stream)(Pangkalan Brandan

North)PT Pertamina /

Indonesia

Gas Processing (CO2stream) Arun Exxon

Gas Processing (CO2stream) Lhok Suhon n/a

Gas Processing (CO2stream) n/a n/a

Refinery (flue gas) Pangkalan Brandan n/a


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Figure 2.6 Map of CO2emission sources in North Sumatra


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2.1.2.2 Central Sumatra CO2Emissions 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


Refinery (flue gas) Dumai PT Pertamina / Indonesia

Refinery (H2Unit) (CO2stream) Dumai PT Pertamina / Indonesia

Refinery (flue gas) Sungai Pakning PT Pertamina / Indonesia

Refinery (H2Unit) (CO2stream) Sungai Pakning PT Pertamina / Indonesia



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Figure 2.8Map of CO2emissions sources in Central Sumatra


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


Refinery (flue gas) Jambi n/a

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

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

Refinery (H2Unit) (CO2stream) Jambi n/a

Gas Processing (CO2stream) Nuenco n/a

Gas Processing (CO2stream) PT MedcoPT Medco Energy / data

n/a

Gas Processing (CO2stream) Gulf Resources Ltd Gulf

Gas Processing (CO2stream) Perabumlih Pertamina / Indonesia

Gas Processing (CO2stream)Conoco Phillips

Grealik LtdConoco Phillips

Gas Processing (CO2stream) Suban Conocco Phillips

Gas Processing (CO2stream) (North JambiI I)Petrochina / Pertamina &

PetroChina

Gas Processing (CO2stream) (North Jambi II) n/a


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Figure 2.10Map of CO2emissions sources in South Sumatra


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2.1.2.4 West Java CO2Emissions Sources

West Java has the highest population density in Indonesia

(sedac.ciesin.columbia.edu). CO2emissions 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 CO2emitted are about 50 million tonnes pa, with

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

Figure 2.11High level overview of CO2 emissions in West Java



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


Refinery (flue gas) CilacapPT Pertamina /

Indonesia

Refinery (flue gas) Balongan - Langit BiruPT Pertamina /

Indonesia

Refinery (H2Unit) CilacapPT Pertamina /

Indonesia

Refinery (H2Unit) Balongan - Langit BiruPT Pertamina /

Indonesia

Gas processing

(CO2stream)North Cylamaya

PT Pertamina /Indonesia

Gas processing

(CO2stream)Subang

PT Pertamina /Indonesia

Gas processing

(CO2stream)Tugu Barat n/a

2.1.2.5 East Java CO2Emissions Sources

East Javas CO2sources 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



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

CO2Source

Plant Name Operator / owner

Refinery (flue gas) CepuCepu LTD /

Pertamina/Exxon

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

Refinery (flue gas)Tuban (TPPIcondensate)

n/a

Refinery (H2Unit)

(CO2stream)Cepu Mini 1 and 2 n/a

Refinery (H2Unit)

(CO2stream)Cepu

Cepu LTD /Pertamina/Exxon

Refinery (H2Unit)

(CO2stream)Tuban (NIORDC) n/a

Refinery (H2Unit)

(CO2stream)Tuban (TPPIcondensate)

n/a

Gas Processing

(CO2stream)Cepu

Cepu LTD /Pertamina/Exxon

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


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2.1.2.6 Kalimantan CO2Emissions Sources

CO2 sources in Kalimantan are mainly related to the regional hydrocarbon

production. The largest emitter is the CO2removal facility at the Bontang LNG plant.

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


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

LNG plant (CO2stream) Bontang A B PT Pertamina / Indonesia

Refinery (flue gas) Balikpapan Total

Refinery (H2Unit) Balikpapan Total

Gas Processing (CO2stream) Regional PT Medco Kalimantan

Gas Processing (CO2stream) Regional Total

Gas Processing (CO2stream) Regional Serica Energy PLT



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Figure 2.15 Map of CO2emissions sources for Kalimantan


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2.1.2.7 Sulawesi CO2Emissions Sources

The industrial CO2sources 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 CO2output 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

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


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


Refinery (flue gas) Selayar n/a

Refinery (H2Unit) (CO2stream) Selayar n/a

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

Refinery (H2Unit) (CO2stream)Parepare (Pinrang) n/a

LNG plant (Flue Gas) Central SulawesiCentral Sulawesi /

Mitshibishi, Pertamina,Medco

LNG plant (Flue Gas)Sengkang Mini

Phase 1PT ENERGI

SENGKANG / Indonesia

LNG plant (CO2stream) Central SulawesiCentral Sulawesi /Mitshibishi, Pertamina,

Medco

LNG plant (CO2stream)Sengkang Mini

Phase 1PT ENERGI

SENGKANG / Indonesia


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Figure 2.17 Map of CO2emissions sources for Sulawesi


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2.1.3 Case Study - Screening CO2sources 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 CO2stream 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 CO2content CO2is presently being

vented from several gas processing plants.

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

project.


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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 CO2storage assessment.


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


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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 431orhttp://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


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2.2 Power Sector

2.2.1 Introduction

Electricity demand in Indonesia is mostly provided by PT PLN (Persero) as aState 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 2.20Indonesian 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 7.1GW. The largest installed capacity in the total power generation

Bengkulu

Bangka

Sumsel-Lampung

Ketapang

PontianakSingkawang

Banjar

Mahakam

Tarakan

Sorong

B-Aceh

Medan

Padang

Bima Sumbawa

Kupang

Ambo

n

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

Bima Sumbawa

Kupang

Ambo

n

Serui

Minahasa

Kotamobagu

Palu

Gorontalo

Jayapura

1

2

3

4

5

6

7

8

345678

21 Northern Sumatera System

Southern Sumatera Power System

Jawa 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 System

Jawa Bali Power SystemSouth & Central Kalimantan Power SystemWest Kalimantan Power SystemEast Kalimantan Power SystemSouth Sulawesi Power SystemNorth Sulawesi Power System


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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 Indonesias

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 ye

ccs potential indonesia

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