Enhanced Coal Bed Methane Recovery Worldwide Application and CO2
ENHANCED COAL BED METHANE RECOVERY WITH CO2 SEQUESTRATION
Report Number PH3/3 August 1999
This document has been prepared for the Executive Committee of the Programme. It is not a publication of the Operating Agent, International Energy Agency or its Secretariat. Title: Enhanced Coal Bed Methane Recovery with CO2 Sequestration Reference number: PH3/3 Date issued: August 1998
Other remarks:
Background to the Study
This study considers the global potential for using CO2 to enhance coalbed methane recovery, with simultaneous CO2 sequestration in the coal. Field tests indicate that carbon dioxide can be injected successfully into deep unminable coal seams and achieve these twin objectives. This process, called CO2 enhanced coalbed methane recovery (CO2-ECBM), has the potential to sequester large volumes of carbon dioxide while improving the efficiency and profitability of gas recovery.
This report defines the criteria which can be used to classify coal fields in terms of their potential for coalbed methane production and the extent to which that production would be enhanced using CO2 injection to enhance methane recovery. It assesses the geological properties of coalbeds which will determine their ability to release methane and adsorb CO2. It catalogues the world’s major coal areas in terms of their potential for enhanced methane recovery using CO2. From this and from previous analyses of the potential global capacity for coalbed methane production, an assessment is made of the global potential for enhanced gas recovery (EGR) using CO2 and for the carbon sequestration potential of the process. Also, the study assesses the broad economics of enhanced recovery of coalbed methane for a range of carbon dioxide storage costs. As with previous studies by the IEAGHG covering sequestration, the CO2 is delivered to site and power generation and capture are not considered.
The study was carried out by Advanced Resources International, Inc. from Arlington, Virginia, USA.
Results and Discussion
The following areas are described in the report
• Technical background • American and Canadian demonstrations
• Burlington Resources CO2 - ECBM pilot • Sources of carbon dioxide
• Reservoir screening criteria for CO2 - ECBM • Costs and sequestration potential for CO2-ECBM
Technical Background
Coal forms by the compaction of plant material. Gases, including methane, are generated during this process and are either adsorbed onto the coal surface or are dispersed into the pore spaces around the coal seam. The amount of gas formed depends on the rank of the coal. In addition, the maturation process releases large amounts of water so that the coalbeds formed are often water saturated. The surface area of the coal on which the methane is adsorbed is very large (20-200 m2/g) and, if saturated,
i coalbed methane reservoirs can have five times the amount of gas as that contained in a conventional sandstone gas reservoir of comparable size.
A number of patents have been issued during the past twenty years relating to the process of injecting carbon dioxide into methane-bearing coal seams. Each of these patents is based on the principle that CO2 adsorbs more readily onto the coal matrix compared to methane. Injected CO2 is preferentially adsorbed (and remains sequestered within the seam) at the expense of the coalbed methane, which is simultaneously desorbed and thus can be recovered as free gas. Because laboratory isotherm measurements demonstrate that coal can adsorb roughly twice as much CO2 by volume as methane, the working assumption is that the ECBM process stores 2 moles of CO2 for every 1 mole of CH4 desorbed. However, the physical chemistry of this process has not yet been fully defined, and there remains the possibility that there are other physical processes active within the reservoir which could alter this ratio. Coalbed methane (CBM) is conventionally recovered by means of reservoir pressure depletion which is a simple, but inefficient, process recovering typically only about 50% of the gas in place. Hydraulic fracture stimulation is used to assist recovery but, even so, because permeability is normally low, many well drillings are required to achieve adequate gas flow.
New technologies have been proposed for enhanced coalbed methane recovery (ECBM) to recover a larger fraction of gas in place. The two principle variants of ECBM are
• inert gas stripping using nitrogen injection and
• displacement desorption employing carbon dioxide injection.
Simulation and early demonstration projects by Amoco indicate that nitrogen injection ECBM is capable of recovering 90% or more of gas in place (N2-ECBM works using a different physical process - by lowering the partial pressure of methane to promote desorption). The CO2-ECBM process is less well documented but likewise shows significant promise for enhanced coalbed methane recovery. For the past three years, Burlington Resources along with their partner Amoco have been operating a 13-well CO2-ECBM demonstration in the San Juan Basin in the Southwestern United States. Initial results show improvement in methane recovery in some wells with minimal breakthrough of CO2.
American and Canadian demonstrations
Substantial CBM activity has taken place in the US over the last 15 years with current annual CBM production of 14 Mt CH4, 90% of which comes from the San Juan Basin in Colorado and the Black Warrior basin in Alabama. Estimates of CBM resources in the US range from 6-13 Gt CH4 and Canadian resources are of the same order of magnitude. Except for an experimental demonstration scheme in the USA (see below), all CBM production in the world uses primary, natural drive technology which is capable, at current economics, of recovering only a fraction of the potential CBM resource.
However, development of proven US gas recovery systems, to incorporate ECBM techniques, is a clear route forward. An economic analysis and ‘proof of concept’ study is currently taking place of ECBM in Alberta, Canada; this involves use of CO2 both for more efficient release of methane and also as a means of sequestering CO2. A practical research project has been established under the Implementing Agreement of the IEA Greenhouse Gas R&D Programme to enable international collaboration to support this work.
Burlington Resources CO2 ECBM demonstration
Burlington Resource's Allison Unit field contains the world's first (and to date only) experimental
ii CO2-ECBM recovery demonstration. The Allison Unit is located within the northern portion of the San Juan Basin, in northern New Mexico close to the Colorado border (Figure 1). The San Juan Basin is by far the most prolific coalbed methane development, currently accounting for over 75% of total worldwide CBM production and nearly 5% of the USA’s natural gas production. It is also the most thoroughly studied from a reservoir standpoint. Prior to CO2 injection, the Allison Unit had been considered a sub-average performer, with gas production rates less than half that of San Juan Basin Fairway wells but it was still economically viable. Another reason for selecting the demonstration location was its proximity to a major carbon dioxide pipeline that crosses the basin (Figure 1).
Figure 1. Location of the Burlington Resources CO2ECBM demonstration in the San Juan Basin, USA.
The Allison Unit demonstration comprises four CO2-injection wells and nine methane production wells. The report suggests that the enhanced production achieved by Burlington, in its best well, is illustrative of "best practice" CO2-ECBM, at least during the current preliminary development of this technology. Future R&D and operational experience should be expected to lead to further improvements in recovery.
CO2 Sources
A variety of CO2 sources, both natural and anthropogenic, may be used for CO2-ECBM recovery operations. Naturally occurring, high-pressure CO2 from underground reservoirs is currently the lowest cost source. The Allison demonstration utilises naturally occurring CO2 produced at the McElmo Dome field in southwestern Colorado and transported by pipeline across the San Juan Basin 3 to the Permian Basin of West Texas. Delivered cost is approximately $0.012/m ($0.50/Mcf) of CO2.
A second option is to utilise anthropogenic sources of CO2that currently are being vented to the atmosphere. For example, in the San Juan Fairway, the natural CO2 concentration of produced coal 3 seam gas is 6 to 12%. Approximately 4.3 million m /day (150MMcfd) of CO2 is currently separated from produced CBM and vented to enable the gas to meet pipeline specifications in the San Juan Basin.
Finally, and of particular relevance to the control of potential greenhouse gas emissions, industrial CO2 may also be used as injectant in ECBM operations. Potential industrial CO2 sources include primarily coal- or gas-fired power plants and other large industrial plants. Industrial CO2 is not readily available in the San Juan Basin, but could be a viable source in other coalbed methane basins. Unlike relatively pure natural formation CO2 sources, however, industrial emissions require processing to remove water, SOx, and other constituents. Industrial CO2 also requires compression. Nevertheless,
iii potential future restrictions on emissions could make industrial CO2 a cost-effective source. For example, an industrial emitter may find it economically attractive to pay a CBM operator to sequester CO2. Under this scenario, handling and disposing of CO2 injectant could actually became a revenue stream for a CBM operation, rather just than a cost. Reservoir Screening Criteria
Reservoir screening criteria are essential for locating favorable areas for the successful application of CO2-ECBM. This study has developed a preliminary list of reservoir characteristics that are likely to be important for CO2-ECBM application. These are:
• Homogeneous Reservoir: The coal seam reservoir(s) should be laterally continuous and vertically isolated from surrounding strata.
• Simple Structure: The reservoir should be minimally faulted and folded.
• Adequate Permeability: Although a minimum permeability cannot be specified, preliminary simulation indicates that at least moderate permeability is necessary for effective ECBM (1 to 5 mDarcy).
• Optimal Depth Range: Shallow reservoirs tend to be low in reservoir pressure and gas content, whereas deep reservoirs suffer from diminished permeability. For deep measures, CO2 injection may actually improve permeability by maintaining pore pressure. Normally,coal seams at depths of 300-1500m are considered to be appropriate for CBM.
• Coal Geometry: Concentrated coal deposits (few, thick seams) are generally favored over stratigraphically dispersed (multiple, thin seams) measures.
• Gas Saturated Conditions: Coal reservoirs that are saturated with respect to methane are preferred from an economic viewpoint. Undersaturated areas can experience delay in methane production, although CO2 injection could reduce delays by raising saturation. From a sequestration viewpoint, undersaturated coal seams are still effective reservoirs.
Other secondary reservoir criteria likely to affect ECBM recovery include coal rank (optimal Ro = 0.8- 1.5%), coal maceral composition (high vitrinite preferred), ash content (because ash does not adsorb methane), gas composition, and numerous other factors. These characteristics are shared in common with conventional CBM requirements, but for the most part they are expected to affect ECBM economics only marginally. Specifically, for CO2 sequestration the selected coal seams, after sequestration, will not be mined.
Costs and global sequestration potential for CO2-ECBM
The study examined the potential for the application of CO2-ECBM recovery and CO2 sequestration in worldwide coal basins, based on:
• the performance of the Allison Unit demonstration as a preliminary benchmark; • the reservoir and basin screening criteria outlined above and; • the contractors proprietary data base of CBM reservoir properties and costs in international coal basins.
The results show that the potential for this process is significant, both from the point of view of enhanced methane recovery and CO2 sequestration potential. Initially the study focused on geologically favorable basin settings where CO2-ECBM recovery could be profitably developed. A CO2 supply cost of $0.50/Mcf was assumed. For these areas the analysis indicated a sequestration potential worldwide of up to 7.1 giga tonnes of CO2. Far more CO2, perhaps 20 to 50 times as much,
iv could ultimately be sequestered in less favorable coal settings, but under sub-economic conditions as a net storage/disposal cost rather than a profitable venture (Table 1).
The initial focus of this study was on coal basins where reservoir and market conditions appear to be most favourable for ECBM. In these areas, ECBM and CO2 sequestration operations have a reasonable chance of being economically viable on a stand-alone basis, based on the current state of technology development as demonstrated by the Allison Unit. However, such unusually favourable settings probably represent only about 2 to 5% of the world-wide coal resource base.
Country Sequestration potential (GtCO2) USA 35 Australia 30 Indonesia 24 Russia., Ukraine 19 China 13 Canada 12 Zimbabwe 5.1 India 5 France/Germany 1.9 South Africa 1.7 Poland/Czech 1.6 Total 148.3
Table 1. Global sequestration potential for CO2-ECBM in geologically high-graded coal basins
Preliminary analysis of the CO2 sequestration potential for enhanced coalbed methane (ECBM) recovery projects indicates that approximately 148 Gt of CO2 could be sequestered in world-wide coal basins at total capital and operating costs of less than $110/tCO2($30/tC). An estimated 60 Gt of CO2 (16.4 GtC) could be sequestered at costs of under $50/tCO2, which is the range of costs for many competing sequestration options, as well as the initial level of Norway’s CO2 emissions tax. In the most favourable coal basins, an estimated 5 to 15 Gt of CO2 may be sequestered within profitable ECBM operations, generating profits of up to $20/t of sequestered CO2. The economics of world-wide CO2 sequestration using ECBM are summarised in Figure 2.
v Sequestered Profit (Cost) $/tCO 2 ($180.00)
($160.00)
($140.00)
($120.00)
($100.00)
($80.00)
($60.00)
($40.00)
($20.00) $0.50/Mcf CO2 Cost $0.00 Cost of CO2 = 0 $20.00 0 20 40 60 80 100 120 140 160
CO2 Sequestered (Gt)
Figure 2. CO2 Sequestration Using Enhanced Coalbed Methane Recovery in Major World-wide Coal Basins.
As illustrated in Figure 2, if restrictions were placed on future CO2 emissions, resulting in substantial taxes on emissions or subsidies on sequestration, a large additional sequestration potential would be available within other less favourable coal basins as well as in the geologically inferior portions of the high-graded basins. In these areas, CO2 may be sequestered in unprofitable but still moderately low-cost operations. It would be prudent to focus on the low-cost portion of this sequestration potential. Unless subsidies/taxes are extremely high, successful CO2 sequestration will still require generally favourable geologic and market conditions.
Expert Group Comments
The draft version of this report was sent to the twelve members of the Programme’s expert group. The general opinion was excellent and many of the comments were editorial although there were a number of specific requests. Most of the requests recommended by the expert group have been incorporated into the report, including most significantly:
• Expanded analysis of non-commercial ECBM applications to assess the total world-wide CO2 sequestration potential and economics.
• More complete citation of published coalbed methane resource studies for world-wide coal basins.
• Standard metric units to be used throughout the report, apart from the American technical specification cited for the US ECBM project.
Such was the interest in this area of work that many of the expert requests were for additional pieces of work that were outside the original specification. This has led to a number of recommendations for future work.
Major Conclusions
Injection of carbon dioxide into deep coal seams has the potential to enhance coalbed methane recovery, while simultaneously sequestering carbon dioxide. Analysis of production operations from the world's first carbon dioxide-enhanced coalbed methane demonstration plant, in the San Juan Basin,
vi indicates that the process is technically and economically feasible. A recent pilot scheme in Alberta Canada, should also help to confirm the technical and economic data of this process.
Costs estimates indicate that a typical San Juan Basin CO2-ECBM project would be economic at a current wellhead price for methane of $0.07/m3 ($2.00/Mcf). Projects outside the U.S. could require methane prices of $0.11/m3 ($3.00/Mcf) or more, depending on such considerations as infrastructure development and the existence of oil and gas industry services.
Key geological/reservoir conditions for successful ECBM include: thick, gas-saturated coal seams buried at suitable depth (300 to 1500 m); simple structural setting with minimal folding and faulting; and adequate in-situ coal seam permeability (>5 mDarcy).
Readily available supplies of low-cost CO2 are essential, whether derived from natural reservoirs or captured from anthropogenic sources such as power plant flue gas. The presence of efficient, long- term markets, the existence of pipeline infrastructure and favourable wellhead prices are all crucial to the economics of CO2-ECBM projects.
The San Juan Basin, Southwest USA, is the top-ranked CO2-ECBM coal deposit, both in terms of commercial viability and capacity to sequester carbon dioxide. Other highly prospective coal basins are: Uinta and Raton (USA); Bowen and Sydney (Australia); Cambay (India); Kuznetsk (Russia); and Sumatra (Indonesia).
Areas for CO2 sequestration have to be selected with care to avoid the escape of CO2 in future by subsequent mining at or near the coal seam where sequestration has taken place.
World-wide CO2 sequestration potential in deep coal seams is estimated to be around 150 Gt of CO2, based on the twenty coal basins estimated to have the best potential for commercial CO2-ECBM recovery. Of this total, perhaps 60 Gt of CO2 may be sequestered at costs of under $50/t of carbon dioxide.
Global, tradable credits for CO2 sequestration could dramatically improve the economics of CO2-ECBM.
Recommendations
This study has helped to highlight some of the key technical and economic issues affecting the application of CO2-ECBM technology. However, future work is needed in a number of areas where understanding is still limited:
• Reservoir Study: The Burlington Resources Allison Unit demonstration plant needs to be evaluated in further depth. A reservoir study involving rigorous history matching using a 3-phase reservoir simulator that models gas and water production, bottom-hole pressures, well completion and stimulation effectiveness, and other operational factors could provide a more precise understanding of the effectiveness of sequestration and enhanced recovery.
• Detailed Basin Evaluations: The high potential ECBM basins need to be examined in greater detail to confirm and quantify the CO2-ECBM/sequestration potential.
• Match CO2 with ECBM Resources: Better understanding of the world-wide availability of natural and anthropogenic CO2 sources is needed, particularly the location and supply costs of CO2 relative to prospective ECBM resources. The cost of collecting, processing, transporting, and injecting industrial CO2 needs particular study.
vii • CO2-ECBM Demonstration plant: The Allison Unit demonstration offers encouraging initial results, but is not an ideal test project due to proprietary considerations and because of varied well completion strategies and an inconsistent operational history. The Alberta project, involving a six month 5 spot pilot CO2-ECBM, built specifically for this task could be used/extended to answer crucial questions about this technology and offer a test bed for technology refinement.
• Combined power and sequestration (CPS): An evaluation should be carried out of a possible zero emission facility combining coal bed methane recovery, CO2 sequestration and power generation on the same site.
• Flue gas cleaning: A study could assess the possibilities for direct injection of flue gas from fossil fuelled power generation systems to enhance methane production , or in CBM exhausted coal seams just to store CO2
• Tradable CO2 Emissions Credits: The emergence of a trading system for CO2 emissions credits could dramatically improve the economics of CO2-ECBM projects by lowering CO2 supply costs. The impact of such a system on ECBM economics and investment is recommended, perhaps examining CO2 storage credits as case studies.
viii Enhanced Coalbed Methane Recovery: Worldwide Application and CO2 Sequestration Potential
IEA/CON/97/27
CO2 Injector Production Well ~"\ Production Well
Prepared for: IEA Greenhouse Gas R&D Programme Cheltenham, UK
Prepared by: Advanced Resources International, Inc. Arlington, Virginia USA
June 1998 A IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment
Table of Contents
Executive Summary 1
Section 1: Introduction 4 1.1 Overview of Study 4 1.2 The Coalbed Methane Industry 4 1.3 Enhanced CBM Recovery 5 1.4 Study Outline 6
Section 2: Reservoir Screening Criteria for CO2-ECBM 7 2.1 Introduction 7 2.2 Reservoir Homogeneity 7 2.3 Minimal Faulting/Folding 8 2.4 Optimal Depth Range 8 2.5 Concentrated Coal Geometry 9 2.6 Adequate Permeability 9 2.7 Other Criteria , 9
Section 3: Production Technology Sequestration Potential of CO2-ECBM 11 3.1 Introduction 11 3.2 Allison Unit CO2-ECBM Pilot, SanJuanBasin 11 3.3 Estimation of Enhanced CBM Recovery and CO2 Sequestration 24 3.4 Surface Components of a C02-ECBM Recovery System 27
Section 4: Costs and Economics of CO2-ECBM 29 4.1 Introduction 29 4.2 Capital and Operating Costs 29 4.3 CO2-ECBM Economics 33 4.4 Minimum Economic Gas Price 36
Section 5: Methodology for Ranking World Coal Deposits 37 5.1 Introduction 37 5.2 Data Sources 37 5.3 Definitions 38 5.4 Description and Classification of CBM Deposits 44
JAF98172.DOC Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment
Table of Contents
Section 6: Assessment of Worldwide CO2-ECBM Applicability and CO2 Sequestration Potential 46 6.1 USA 46 6.2 Canada 58 6.3 Australia 64 6.4 China 76 6.5 Indonesia 85 6.6 India 95 6.7 Southern Africa 102 6.8 Russia and Ukraine 110 6.9 Western and Central Europe 116 6.10 Ranking of World CO2-ECBM Coal Basins 123
Section 7: Preliminary Estimate of the Worldwide CO2 Sequestration Potential in Deep Coals 125 7.1 Conclusions 125 7.2: Methodology 125
Section 8: Conclusions and Recommendations for Future Work 129 8.1 Conclusions 129 8.2 Recommendations 130
Selected Bibliography 131
Appendix A: Patents for Enhanced CoalbedMethane Recovery 137
JAF98172.DOC Advanced Resources International, Inc. IRA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment
List of Exhibits
Exhibit 1: CO2 Sequestration Potential of Most Prospective Coal Deposits 2 Exhibit 2: Over C02 Sequestration Economics for Worldwide Coal Deposits 3 Exhibit 3-1: Location of Burlington Resources' CO2-ECBM Pilot in San Juan Basin, USA 12 Exhibit 3-2: Location of Production and Injection Wells, Allison Unit C02-ECBM Pilot, San Juan Basin 13 Exhibit 3-3: Burlington Resources Allison Unit CO2-ECBM Pilot, San Juan Basin 15 Exhibit 3-4: Cross-Section Diagram Through Burlington Resources Allison COa-ECBM Pilot, San Juan Basin, USA 17 Exhibit 3-5: Completion Schematic for CO2 Injection Well San Juan Basin, USA 19 Exhibit 3-6: Gas Production History for the Allison Unit CO2-ECBM Pilot 22 Exhibit 3-7: Water Production History for the Allison Unit CO2-ECBM Pilot 23 Exhibit 3-8: Gas and Water Production History for the Allison Unit #115 Well, Showing Typical CO2 Injection Rate 25 Exhibit 3-9: Comparison of Sorption Isotherms for Pure CO2 and CBLt (Gas Research Institute, 1995) 26 Exhibit 3-10: Components of a CO2-ECBM Recovery System 28
Exhibit 4-1: Estimated Costs for CBM and ECBM Projects in the San Juan Basin 30 Exhibit 4-2: ECBM Economics, San Juan Basin, USA 33 Exhibit 4-3: ECBM Economics, International Low Cost Case 34 Exhibit 4-4: ECBM Economics, International High Cost Case 35 Exhibit 4-5: Minimum Required Wellhead Gas Price for Alternative Cost/Enhancement Scenarios 36
Exhibit 5-1: Diagram Showing CBM Prospective Zones 39 Exhibit 5-2: Summary of CBM Parameter Ranking Schemes 43
Exhibit 6-1-1: Growth in U.S. Coalbed Methane Production 48 Exhibit 6-1-2: Gas Productivity in U.S. CBM Basins 49 Exhibit 6-1-3: U.S. CBMResource and Commercial ECBM Recovery Potential 47 Exhibit 6-1-4: USA Technical ECBM Recovery Potential 55 Exhibit 6-1-5: U.S. Commercial ECBM Recovery Potential 57
Exhibit 6-2-1: Canada Resource and Commercial ECBM Recovery Potential 58 Exhibit 6-2-2: Canada Technical ECBM Recovery Potential 61 Exhibit 6-2-3: Canada Commercial ECBM Recovery Potential 62
JAF98172.DOC Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM'Assessment
List of Exhibits
Exhibit 6-3-1: Australia Resource and Commercial ECBM Recovery Potential 65 Exhibit 6-3-2: Australia Technical ECBM Recovery Potential 71 Exhibit 6-3-3: Australia Commercial ECBM Recovery Potential 74
Exhibit 6-4-1: China CBMResource and Commercial ECBM Recovery Potential 76 Exhibit 6-4-2: China Technical ECBM Recovery Potential 81 Exhibit 6-4-3: China Commercial ECBM Recovery Potential 83
Exhibit 6-5-1: Indonesia Resource and Commercial ECBM Recovery Potential 85 Exhibit 6-5-2: Indonesia Technical ECBM Recovery Potential 91 Exhibit 6-5-3: Indonesia Commercial ECBM Recovery Potential 94
Exhibit 6-6-1: India Resource and Commercial ECBM Recovery Potential 95 Exhibit 6-6-2: India Technical ECBM Recovery Potential 99 Exhibit 6-6-3: India Commercial ECBM Recovery Potential 101
Exhibit 6-7-1: S. Africa Resource and Commercial ECBM Recovery Potential 102 Exhibit 6-7-2: Southern Africa Technical ECBM Recovery Potential 107 Exhibit 6-7-3: Southern Africa Commercial ECBM Recovery Potential 109
Exhibit 6-8-1: Russia, Ukraine Resource and Commercial ECBM Recovery Potential 110 Exhibit 6-8-2: Russia and Ukraine Technical ECBM Recovery Potential 114 Exhibit 6-8-3: Russia and Ukraine Commercial ECBM Recovery Potential 115
Exhibit 6-9-1: Europe Resource and Commercial ECBM Recovery Potential 116 Exhibit 6-9-2: Europe Technical ECBM Recovery Potential 120 Exhibit 6-9-3: Europe Commercial ECBM Recovery Potential 122
Exhibit 6-10-1: Ranking of World's Most Prospective Coal Deposits for CO2-ECBM Recovery Potential 124 Exhibit 7-1: Over CO2 Sequestration Economics for Worldwide Coal Deposits 126
JAF98172.DOC Advanced Rtsourcss International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment
List of Maps
Map 6.1 CO2 ECBM Potential of United States
Map 6.2 CO2 ECBM Potential of Canada
Map 6.3 CO2 ECBM Potential of Australia
Map 6.4 CO2 ECBM Potential of China
Map 6.5 CO2 ECBM Potential of Indonesia
Map 6.6 CO2 ECBM Potential of India
Map 6.7 CO2 ECBM Potential of Southern Africa
Map 6.8 CO2 ECBM Potential of Russian and Ukraine
Map 6.9 CO2 ECBM Potential of Western and Central Europe
JAF98172.DOC Advanced Resources International, Inc. TEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment
Unit Abbreviations and Conversions
Gm3 Giga (109) cubic meters Gt Giga (109) tonnes kPa Kilopascal md Millidarcy Mt Million (106) tonnes Mm3 Million (106) cubic meters Mpa Megapascal $ U.S. Dollar
U.S.A. Usage bwpd Barrels of water per day (1 barrel =159 liters) Bcf Billion (109) cubic feet (1 cubic meter = 35.31 cubic feet) Bcfd Billion (109) cubic feet per day Mcf Thousand cubic feet Mcfd Thousand cubic feet per day mi2 Square mile (1 mi2 = 2.61 km2) MMcfd Million cubic feet per day psi Pounds per square inch (1 psi = 7.03 kilopascal) Tcf Trillion (1012) cubic feet
JAF98172.DOC Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment
Executive Summary
Long-term field testing indicates that carbon dioxide can be injected into deep unmineable coal seams to enhance the recovery of methane gas. This process, called CCb-enhanced coalbed methane recovery (CCVECBM), has the potential to sequester large volumes of carbon dioxide while improving the efficiency and profitability of commercial natural gas operations.
CCVECBM is being tested at one pilot production field in the San Juan basin 3 (southwestern U.S.). Operator Burlington Resources has injected over 57 Mm (2 Bcf) of CO2 through four injection wells during a 3-year period. Preliminary results indicate that full-field development of this process could boost recovery of in-place methane by about 75%. Present- value capital and operating costs for a typical San Juan basin CO2-ECBM project are estimated at $0.06/m3 ($1.75/Mcf) of enhanced methane production, which would be economic at current wellhead gas prices of $0.07/m3 ($2.00/Mcf). Other projects outside the U.S. could require gas prices of $0.10/m3 ($3.00/Mcf) or more.
The key technical and commercial criteria for successful application of COi-ECBM are expected to be a) Geology: favorable sub-surface reservoir conditions, such as thick, gas- saturated, coal seams that are buried at suitable depths (generally 300 to 1,500 m), located in simple structural settings, and have unusually high in-situ permeability (>5 md); b) Mining: to maintain sequestration, ECBM should focus on areas where future mining of deep coal seams is unlikely; c) COz Supplies: low-cost potential supplies of COa, either from naturally occuring reservoirs or from anthropogenic sources, such as power plant flue gas; d) Gas Demand: an efficient market for utilization of methane, including adequate pipeline infrastructure, long-term end-users, and favorable wellhead gas prices. The existence of oil and gas industry services to support efficient drilling and production operations would be helpful, particularly during the early phases of a project, but given a suitable investment climate these would be expected to develop over time.
Assessment of the major worldwide coal deposits indicates that large potential exists in certain basins for application of COa-ECBM technology (Exhibit 1). Some of the most prospective basins include the San Juan, Uinta, and Raton (U.S.); Bowen and Sydney (Australia); Cambay (India); Kuznetsk (Russia); and Sumatra (Indonesia). Future R&D into CO2-ECBM technology would be most effective if focused on well-characterized U.S. coal basins, because the reservoir processes that control CBM production in basins outside the U.S. are still poorly understood. Coal basins were ranked below on development quality (resource, CO2 availability, producibility, market) and on total CO2 sequestration potential. However, a great deal of uncertainty remains concerning these average values, and small high-graded prospects within the basin could have much higher development quality.
JAF98172.DOC 1 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment
Analysis of the economics of C02 sequestration in worldwide coal basins indicates that over 150 Gt of CO2 can be sequestered at unit costs of less than $100/t (Exhibit 2). Approximately 60 Gt of CO2 can be sequestered at unit costs of less than $50/t. An estimated 5 to 15 Gt of CO2 may be sequestered in profitable ECBM operations.
Exhibit 1: CO2 Sequestration Potential of Most Prospective Coal Deposits
A;, j^eojio^iiSijf -l^W llii^si||fii P^!i;!jiC|b||i|;i|i'p|: /^l^fe-^!,.', I 1 1 "il H«lli'WTf!*)'W 'I'l'IC/i' '[' I' 'j* sJJtL CTT)l ^ivf).U.lji!"! iiil 3C 'J' LITI^m' JCi* i-1 4 1 i 1 ^*i§ IL'jCTL". J'M'jt'jjjt -<• ' 1 "j- ^JRCJIiiJL'JiiilN jJfcJLflut.ij'jiii'i.i il^kwiSwiRS ''!-^ ligpli lifUl San Juan USA i 1,400 1 Uinta USA 2 230 9 Bowen Australia 3 870 3 Raton USA 4 85 13 Cambay India 5 74 14 Sydney Australia 6 150 11 Kuznetsk Russia 7 1,000 2 Sumatra Indonesia 8 250 8 SUB-TOTAL 4,059 Western Canada Canada 9 170 10 Damodar India 10 8 19 Donetsk Ukraine/Russia 11 26 15 NE China China 12 21 16 Ordos China 13 660 5 Clarence-Moreton Australia 14 260 7 Kalimantan Indonesia 15 850 4 Upper Silesian Poland/Czech 16 7 20 Saar Germany/France 17 9 18 Waterberg SA/Botswana 18 93 12 Zambezi Zimbabwe/Bots. 19 400 6 Main Karoo South Africa 20 10 17 TOTAL 6,480
JAF98172.DOC Advanced Resources International, Inc. Exhibit 2: Overall COa Sequestration Economics for Worldwide Coal Deposits
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$50.00 0 20 40 60 80 100 120 140 160 180
CO2 Sequestered (Gt)
JuneS, 1998 Advanced Resources International, fnc. IEA Greenhouse GasR&D Programme Worldwide COr-ECBM Assessment
Section 1 Introduction
1.1 Overview of Study
As part of its research into global sequestration of carbon dioxide, the IEA Greenhouse
Gas R&D Programme has recognized sequestration of CO2 within deep unmineable coal seams as a potential disposal technology (IEA, 1997). This process also has the potential benefit of increasing methane recovery from coal seams within commercial natural gas production projects.
Enhanced coalbed methane recovery using CO2. injectant (CO2-ECBM) is noteworthy in its potential to be profitable as a stand-alone commercial venture, more than a costly CO2 disposal process.
The CO2-ECBM process is a proprietary technology that is currently being field tested by natural gas operators within one coal basin in the United States. The results of this testing have not been published. Early results indicate that the technology works largely as theorized, by
enhancing methane recovery while simultaneously sequestering C02. However, much remains to be learned about the actual reservoir processes and field operating procedures that can optimize this process, as well as the associated costs and benefits. Even less is known about the
applicability of CO2-ECBM technology to other coal basins worldwide.
This study examines the technical and economic feasibility of the CO2-ECBM process and the outlook for applying this technology to coal basins worldwide. The study is very preliminary,
but is also the first to document the results of C02-ECBM testing that is taking place in the U.S., and the worldwide characteristics of major coal basins that are prospective for CBM development and CO2-ECBM application.
1.2 The Coalbed Methane Industry
During the past two decades, coalbed methane (CBM) has grown to become a significant component of natural gas supplies in the United States. From a small number of coal mine degasification wells drilled in the Warrior basin of Alabama during the 1970s, by 1996 the coalbed methane industry had grown to over 6,000 wells producing some 19 Mt (28 Mm3) of methane annually. Private investment in CBM wells in the U.S. alone has totaled more than $4,000 million (Stevens et al, 1996).
During 1997, CBM accounted for more than 5% of U.S. natural gas production. CBM production levels in the U.S. are significantly greater than total natural gas production in countries such as China or Ukraine. Development in the U.S. continues in new coal basins such as the Uinta, Raton and Powder River basins, even without the benefit of tax credits for CBM that expired in 1992. Coalbed methane hi the United States has been a remarkable success, bringing
JAF98172.DOC 4 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment on stream a previously overlooked class of natural gas resources, along with secondary benefits such as coal mine safety and mitigation of methane emissions.
Unfortunately, despite high expectations, CBM exploration and development outside the United States to date has been far less encouraging. During the past decade, natural gas production firms have attempted to apply U.S.-developed CBM technology to coal basins in other countries, including many promising high-methane areas. Most of these early CBM exploration efforts have met with failure, despite an estimated $200 million in expenditures by technology- savvy U.S. companies and much additional drilling by non-U.S. firms without CBM expertise.
Much still remains to be learned about the basic geologic and reservoir production mechanisms of most coalbed methane areas outside of the U.S. As discussed in Sections 5 and 6 of this report, geologic conditions in tested coal basins outside the U.S. frequently are less favorable for commercial development, with reservoir challenges such as undersaturation and restricted permeability. Commercial conditions outside the U.S. frequently are also less accommodating. This is why we recommend that near-term future research into CO2-ECBM technology be performed on a well-documented U.S. coal basin. Long-term studies should examine the applicability to other, as yet uncommercialized, coal basins outside the U.S.
1.3 Enhanced CBM Recovery
One potentially important technology currently under development for CBM extraction, which may help to overcome some of the technical development problems that exist outside the U.S., is enhanced coalbed methane recovery (ECBM). ECBM in coal reservoirs is broadly analogous to CO2 enhanced oil recovery, a technology that is increasingly employed within the U.S. at mature oilfields. The two principal variants of ECBM employ injection of N2 or C02 into the coal reservoir to increase methane recovery through, respectively, inert gas stripping or displacement desorption processes. Unlike conventional CBM recovery, which requires depletion of reservoir pressure and generally recovers around 50% of Gas-In-Place, ECBM allows maintenance of reservoir pressure. Simulation and early demonstration projects indicate that ECBM is capable of recovering 90% or more of methane in place, while accelerating methane recovery (Puri and Yee, 1990).
ECBM could be employed to sequester large volumes of carbon dioxide in deep coal seam reservoirs, thereby reducing emissions of this greenhouse gas. But ECBM may also help to commercialize coalbed methane resources that exist under the unfavorable reservoir conditions that apparently are common outside the U.S., particularly low permeability and undersaturation.
For example, maintaining reservoir pressure by injecting CO2 may keep coal cleats open and thus maintain permeability. The challenge will be to develop technologies that can make ECBM commercially feasible and then apply them effectively in the most appropriate coal reservoir settings throughout the world.
JAF98172.DOC 5 Advanced ResourcesInternational, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBU Assessment
Amoco's patented N2 flooding process has been extensively tested at three progressively larger pilot locations in the San Juan basin: the Simon 15 U-2, 28-7 Unit, and Tiffany Unit. While Amoco is continuing to evaluate the process and has yet to release extensive results, they estimate marginal extraction costs for N2 stripping to be favorable at $0.035/m3 ($1.00/Mcf), or less, of methane produced (Stevens et al., 1996). With marginal extraction costs only about two-thirds of current wellhead gas prices in the San Juan basin, this process may be economically viable.
C02-ECBM processes (Wilson et al., 1995) are equally promising but have undergone less thorough field demonstrations. Meridian (Burlington Resources) and Amoco currently are jointly testing a pilot CO2 flood in the San Juan basin. The Allison Unit project shows definite commercial promise, at least under the coal reservoir and economic conditions that prevail in the San Juan basin, and is discussed in Section 3. In a separate project funded by a government/industrial consortium, the Alberta Research Council plans to conduct an ECBM research project in the Fenn Valley later during 1998 (Gunter et al., 1996).
If captured anthropogenic C02 can be used in an ECBM project, there could be substantial environmental benefits in sequestering large volumes of CO2 and preventing its release to the atmosphere. Clearly, far more applied R&D is needed to demonstrate and disseminate the potential benefits of ECBM, as well as to investigate the application of ECBM to coal fields worldwide. It is our hope that this preliminary study will assist IEA and other groups in future R&D decisions.
1.4 Study Outline
This study was performed in a series of discrete tasks encompassing production technology and economics, screening criteria for coal reservoirs, and the geologic and commercial characteristics of worldwide coal basins. The methodology and results of the study are arranged in the following sections of this report:
2: Screening Criteria for C02-ECBM 3: CC-2-ECBM Production Technology 4: Costs and Economics of C02-ECBM 5: Methodology for Ranking World Coal Deposits 6: Assessment of Worldwide CO2-ECBM Applicability 7: Economics of Worldwide C02 Sequestration in Coal Deposits 8: Recommendations for Future Work
JAF98172.DOC 6 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment
Section 2 Reservoir Screening Criteria for CO2-ECBM
2.1 Introduction
The first task of the study was to define the principal technical criteria that are likely to be required for successful application of enhanced coalbed methane recovery (ECBM) using CO2. Following two decades of commercial CBM production experience, the reservoir processes that control conventional production of CBM in the United States are now relatively well (though not entirely) understood. However, because ECBM using C02 is an emerging technology, and has only been applied in pilot production at one small project in the San Juan basin, the requirements for successful worldwide application of ECBM are yet to be defined. Furthermore, the operators currently testing ECBM still consider this new technology to be proprietary, and thus critical operational and cost aspects of ECBM have not yet been published within the technical literature.
In this section of the report, we examine the reservoir criteria that are expected to be essential for efficient ECBM application. Our work indicates that certain key reservoir
characteristics are first-order screening criteria for selecting coal fields where CO2-ECBM processes may be used effectively. Additional secondary criteria are also identified. Substantially
all of these requirements must be successfully met for CO2 ECBM to be technically feasible (although not necessarily economic). These criteria are presented in order from greatest to least importance. The key reservoir screening criteria include:
• Reservoir Homogeneity • Minimal Faulting/Folding • Optimal Depth Range • Concentrated Coal Geometry • Adequate Permeability
(In addition to technical screening criteria, other non-reservoir factors also are important
for providing the necessary conditions for commercial CO2-ECBM application, including data availability, gas market, CO2 availability, etc.; these other factors are considered for each basin in Section 6.) The screening criteria are discussed in detail below.
2.2 Reservoir Homogeneity
Perhaps the most important reservoir criteria for effective ECBM is lateral structural and stratigraphic uniformity. Intense structural faulting and/or stratigraphic heterogeneities can effectively compartmentalize the coal reservoir into isolated blocks. In an ECBM production
project, compartmentalization could lead to channeling of injected CO2 preferentially into
JAF98172.DOC 7 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment sandstones, faults or other undesirable zones, bypassing the intended coal reservoir and precluding effective enhanced recovery of methane.
2.3 Minimal FaultingflFolding
The degree of structural complexity of a coal deposit — primarily post-depositional faulting and folding -- is another important reservoir characteristic. Just as with water flooding,
EOR, and other oilfield injection processes, CO2 ECBM is expected to be restricted to structurally simple settings. Generally, preferred areas have fewer and smaller faults with low structural inclinations (dip) of the coal seams. Coal basins that are heavily faulted, with closely spaced faults (0.1 to 5.0 km or less) and significant fault throws (1 m to 100 m or more), may be less appropriate for C02 ECBM application. This is because injected CO2 could be channeled by fault zones away from the coal reservoir (the Upper Silesian coal basin of Poland is a good example of a structurally complex basin).
We anticipate that the spacing between the bounding faults, which defines a prospective block, should ideally be more than 5 km; otherwise the CBM area may be too small for feasible development. In addition, small faults may exist within the candidate area, but faulting with
throws greater than about one-half of individual coal thickness are likely to seriously disrupt CO2 and methane flow across the reservoir. Relatively small faults, with throw less than one-half of seam thickness, would still affect fluid flow but may be less disruptive. (In heavily mineralized or metamorphosed areas, fault annealing due to mineralization or other obstruction of the fault plane
could prevent CO2 channeling, but the coal seam permeability in such areas generally is far too low for CBM production.)
Finally, structural dip due to folding and faulting can seriously complicate CBM development. Permeability in steeply dipping areas tends to be low, since these areas suffered deformation that usually damages the coal cleating systems that are largely responsible for permeability. The structural influence on ECBM is discussed further in Section 5.
2.4 Optimal Depth Range
There is an optimal depth "window" for commercial CBM production and probably also for effective ECBM. Coal seams need to be deep enough for adequate reservoir pressure and gas content. However, permeability also decreases with depth. This window varies by basin, based on factors such as permeability and reservoir pressure. Generally, coal seams buried at depths of approximately 300 to 1,500 m are considered to be appropriate for CBM. At this depth, coals can have a favorable combination of high gas content and adequate permeability; reservoir pressure also is adequate for displacement of methane by carbon dioxide.
JAF98172.DOC 8 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COz-ECBM Assessment
2.5 Concentrated Coal Geometry
Coal reservoir geometry must be relatively compact (rather than stratigraphically dispersed) to allow completion of sufficient coal thickness using a realistic hydraulic stimulation program (typically up to three "fracs" per well).
2.6 Adequate Permeability
Coal seam permeability at typical CBM target depths of 300 to 1,500 m is frequently too low for commercial development (<0.1 md). Adequate permeability for commercial CBM production (generally >1.0 md) requires unusually favorable conditions of cleat conductivity, enhanced fracturing, and low stress. Gas production in high-permeability areas (>30 md) may result in very high recovery of initial in-place methane (>70%); ECBM may be less feasible in such areas of high conventional recovery, although CO2 sequestration alone would be effective. ECBM may actually work more effectively than pressure depletion in areas with low to moderate permeability, such as Burlington Resources' San Juan basin pilot. Indeed, this was Amoco's intent in placing their N2-ECBM project at the 28-7 Unit in the San Juan basin, where permeability is an order of magnitude lower than in favorable parts of the basin.
2.7 Other Criteria
In addition to the first-order reservoir criteria presented above, the following second-order reservoir criteria also are expected to impact the efficiency of ECBM using CO2. Some of these second-order parameters influence first-order parameters, such as permeability.
• High Gas Saturation. Ideally, in-situ coal reservoir gas content should be approximately 90 to 100% of the sorption isotherm (saturated conditions). However, ECBM should also work in undersaturated areas with somewhat lower gas saturation, but methane recovery will be delayed and costly.
• Optimal Coal Rank: Rank is an indication of the thermal maturity of a coal, reflecting past burial pressure and temperature history, and in the CBM industry is generally measured using vitrinite reflectance (Ro). Traditionally, CBM operators held that optimal coal rank for CBM was in the range of Ro = 0.8% to 1.5%. More recent commercial CBM development in the Uinta and Powder River basins has shifted this range downward to approximately 0.6% to 1.2%. (Ro values cited in this report are mean maximum where available; otherwise the literature does not specify.)
• Low Ash Content: Because ash is not capable of storing (adsorbing) methane, lower ash content is desirable. In general, low-ash coals are more permeable,
JAF98172.DOC 9 ' Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBMAssessment
although San Juan basin Fruitland Formation coal seams can have permeabilities in excess of 100 md with high ash contents of 25-35%.
High Vitrinite Content. Vitrinite is the most brittle coal maceral (component). Coals that are high in vitrinite (rather than inertinite, a less brittle maceral) tend to be well cleated and thus more permeable.
JAF98172.DOC 10 ,j .„ Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COr-ECBU Assessment
Section 3 Production Technology and Sequestration Potential of CO2-ECBM
3.1 Introduction
Enhanced coalbed methane recovery is still at a nascent phase of development. A great deal more remains to be learned regarding efficient field development and operational practices for ECBM, as well as the potential for sequestering carbon dioxide in coal seams. This section takes an empirical approach to examining these issues based on initial results from the world's first (and to date only) CO2-ECBM pilot field. These field data, which are presented here for the first time in print, were then used to develop insights and empirical scaling factors for use in estimating enhanced methane recovery and sequestration of CO2. The ECBM pilot results are central to our methodology for assessing the applicability of this process to worldwide coal basins, which is presented in Sections 5 and 6.
Although ECBM technology is still new and evolving rapidly, it is apparent that to a significant extent conventional oilfield equipment can be readily adapted to this new application, largely without the need for development of specialized hardware. On the other hand, the field operating and reservoir management procedures that are optimal for CO2-ECBM are still under experimentation. In this section, we present information on the development and operating systems required to conduct CO2-ECBM, focusing in particular on Burlington Resources' CO2- ECBM pilot in the San Juan basin.
Factors for enhanced methane recovery and carbon dioxide sequestration have not been established for ECBM. Regardless of theoretical considerations, these factors are likely to vary widely based on specific reservoir conditions. In this section, we develop approximate first-order factors for these separate but related processes based both on empirical and theoretical evidence.
3.2 Allison Unit COrECBM Pilot. San Juan Basin
Overview
Burlington Resources (formerly Meridian Oil) and partner Amoco Production Company are conducting pilot testing operations on the world's first CO2-ECBM pilot in the San Juan basin, southwestern U.S.A. The Allison Unit is situated in the north-central portion of the 3,000- well San Juan basin, which produces fully 75% of worldwide CBM (Stevens et al., 1996). The ECBM pilot lies within the Allison Production Unit, which is a 35-well coalbed methane field located in northern New Mexico. The pilot comprises nine CBM production wells and four CO2- injection wells in T32N-R6,7W (Exhibits 3-1 and 3-2). To date about 2.5 years of enhanced
JAF98172.DOC 11 Advanced Resources International, Inc. Exhibit 3-1: Location of Burlington Resources' CO2 - ECBM Pilot San Juan Basin, USA
LA PLATA CO. ARCHULETACO.
McEimo Dome CO, Field
COLORADO NEW MEXICO Burlington Allison Unit Pilot
JAF00866.CDR Exhibit 3-2: Location of Production and Injection Wells, Allison Unit CO2- ECBM Pilot, San Juan Basin
•107.3124 -107.31.48 -107.31.12 -107.30.38 -107.30.0 -10759.24 -10758.48 -10758.12
3a.53.4B 22 23 ALLISON UNIT 18 17 36.58.48
112
39.58.12 ALLISON UNI1 Y ALLISON UNIT T32NR6W T32NR7\ ALLISON UNIT ^ 38.58.12 't* 130 142 ALLISON UNIT 25 24 19 & 20 t LLISON UNIT . 115 ALL|SON Uf IT ALLISON UN r # & 38.57.38 131 w ALLISON UNIT ALLISONS IT V J31 132 113 140 38.57.33 ALLISON UNI ALLISON UNIT •& J& 121 143 '
36 38.57.0 35 30 ALLISON UNIT 29 38.57.0
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•107.3!54 -107.31.46 -107.31.12 -107.30.36 -107.30.0 -107.2954 -107.28.48 -10758.12 ISA Greenhouse Gas R&D Programme Worldwide COr-ECBMAssessment production history data have been collected, which is marginally sufficient to support preliminary conclusions regarding the efficacy of the CO2-ECBM process.
The Allison Unit pilot is central to many of the assumptions on CO2-ECBM technology that are made in this study and is discussed in some detail within this section. The pilot is a particularly valuable demonstration for two reasons: a) Burlington Resources is the leading producer of coalbed methane in the U.S. and has extensive experience with pioneering new CBM technologies, such as the highly successful cavity completion; b) the Allison pilot is located in a geologically well-characterized portion of the San Juan basin, which itself represents the best studied CBM basin. Assessing the impact of this new technology first requires a thorough foundation of reservoir understanding, which is why we recommend that future funding for R&D into CCh-ECBM technology be focused on basins that already have established commercial CBM production.
However, there are two important limitations to the use of the Allison Unit pilot as a
standard for worldwide C02-ECBM technology: a) following conversion of the pilot to CO2- ECBM, some of the production wells were "recompleted" under a separate ongoing program. This recompletion program has complicated the comparison of before- vs. after-conditions that is
necessary to gauge production enhancement due to ECBM. In addition, injection of CO2 and production of methane has not been continuous, due to early corporate strategies and also to non- ECBM operational issues; this has probably resulted in water re-encroachment within the reservoir and less than optimal production results. Burlington is the first to point out that the Allison Unit ECBM project has not been conducted as an isolated scientific experiment, but rather as an opportunistic application within an ongoing commercial venture.
More importantly: b) the San Juan basin is far and away the most favorable geologic setting yet discovered for coalbed methane production. In this sense, it is not representative of worldwide coal basins, which generally have lower permeability and less favorable market/infrastructure conditions. Therefore, the Allison pilot is viewed as a "best case" scenario within this study. As documented in Section 6 .of this study, other coal basins elsewhere in the world have certain attractive characteristics, but none are known to approach the full set of favorable resource, producibility, pipeline infrastructure, etc. of the San Juan basin. While noting these limitations, we still maintain that the Allison Unit pilot provides a key (indeed the only) benchmark for worldwide application of CO2-ECBM technology.
Production Well Drilling and Completion
The Allison Unit production wells were drilled and completed using relatively standard CBM production technology. Drilling and completion data were acquired from records filed at the New Mexico Oil Conservation Division. As summarized in Exhibit 3-3, the wells were
JAF98172.DOC 14 Advanced Resources International, Inc. Exhibit 3-3: Burlington Resources Allison Unit CO2-ECBM Pilot, San Juan Basin
Well Completion Summary
Allison Unit Wells, Producers
GENERAL ORIGINAL COMPLETION PERFS RECOMPLETION WELL SPUD COMP TD ELEV FRUITLAND (f Csg Set Csg Set Liner Set Tubing Set Top Base Recomp Liner Set Perfor ations Comments DATE DATE (ft) (ft) TOP I BASE (in) (ft) (in) (ft) (in) (ft) (in) (ft) (ft) (ft) Date (in) (ft) Top Base 112 12/14/88; 12/31/88:3148 6517 29001 3148 95/8 235 7 3030! - 23/8 3111 OPEN HOLE 5/13/95 5.5 3125 3038 3124 Recavitate 113 6/20/89 7/12/89J 3094 6437 2855I 3094 95/8 235 7 3012 5.5 3095 23/8 3062 3011 3093 NA 114 12/20/88 1/15/89J 3149 6513 2965 j 3149 95/8 223 7 3077 5.5 3149 23/8 3133 3059! 3148 NA 115 12/6/88 12/29/88 3170! 6522 2935! 3170 95/8 237 7 3083 5.5 3170 23/8! 3153 3081 3168 NA 120 6/4/89J 6/24/89! 3087 6402 2708! 3087 95/8 251 7 3001 5.5 3086 23/8 3059 2998 3083 4/22/96 Underream and recavitate 121 11/27/88 12/22/88 3246! 6572! 3094! 3246 95/8 231 7 3178 5.5 3246 23/8J 3240 3159 3245 .NA 130 12/31/88 2/4/89 3?00 6442 3025: 3200 95/8 241 7 3101 .. _ 23/8 3162 OPEN HOLE 5/23/93 5.5 3198 3057 3198 Cavitated, installed liner 131 12/28/88 1/31/89J 3245J 6503J 3030J 3245 95/8 239 7 3111- 4.5 3240 23/8 3191 3123 3203 4/4/96 5.5 3200 3067 3199 Sidetrack, cavitate, hole probs 132 6/11/89 6/24/89! 3169 6470 2970! 3169 95/8 252! 7 3111; 5.5 3168 23/8 3141 3080 3167 12/2/93 5.5 3165 3076 3165 Recavitate
Allison Unit Wells, CO2 Injectors
GENERAL ORIGINAL COMPLETION PERFORATIONS WELL SPUD COMP TD ELEV RUITLAND (ft Csg Set Csg Set Liner Set Tubing Set Top Base Top Base DATE DATE (ft) (ft) TOP | BASE (in) (ft) (in) (ft) (in) (ft) (in) (ft) (ft) (ft) (ft) (ft) 140 11/11/94 11/23/94 3436 6468 3010! 3365! 8 5/8 358 5.5 3435J - _ 27/8 3062 3090 3110! 3119 3134 _ 141 11/5/94! 11/17/94! 3430 6452! 2991! 3354! 8 5/8 382 5.5 3426 _ 27/8 3050! 3090! 3138! 142 10/30/94! 11/14/941 3386! 6449! 2965 j 3328185/8 384 5.5 3385; - - 27/8 3022! 3049 3078 3092 3104 143 11/18/94} 12/5/94 3379J 6400 2965! 3328! 8 5/8 374 5.5 3376J - 27/8! 2950! 29965301 8* 3082 3097*
*Fracced with 1,000 gal 15% HCI and 637 Mcf N2
•"Fracced with 1,000 gal 15% HCI and 784 Mcf N2
April 10, 1998 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment completed and recompleted using a variety of methods: five wells were cavitated or recavitated (#112, 120, 130, 131, 132), while the remaining four wells were completed unstimulated and "natural." (It is unusual to complete CBM wells unstimulated, since production is normally far higher using hydraulic or cavity stimulation.)
Exhibit 3-4 is a cross-sectional view through the Allison Unit pilot, from west to east, illustrating the different completion style of wells in this unit. The cross-section shows the relative positions and completion method of two production (#112 and #114) and one injection (#142) well. The #112 well was completed open-hole (no casing across the Fruitland coal) and cavitated, whereas the #114 well is a cased-hole completion that was perforated in the Fruitland and unstimulated. The #142 injector well was cased through the Fruitland, perforated and unstimulated.
The key stages of drilling and completing a production well at Burlington's Allison Unit pilot are summarized as follows:
• Drill surface hole to a depth of about 75 m, using a rotary rig equipped with a 12 1/4-inch bit and running light-weight drilling mud. • Run 9 5/8-inch surface casing and cement in place. Run back in the hole with 8 3/4- inch bit and drill to just above Fruitland coal (915 m). • Run 7-inch intermediate casing and cement in place. • Run back in with 6 1/4-inch bit and drill through Fruitland coal to total depth of about 975 m. • Complete open-hole or position pre-drilled 5 1/2-inch liner across coal seams to complete the well. • Leave well unstimulated (natural) or stimulate using cavitation (in most other basins hydraulic stimulation would be more appropriate). • Set a production packer above the Fruitland and equip the well with 2 7/8-inch production tubing and Moyno or beam pump set to the base of the coal. • Install wellhead and hook up to the field gas and water gathering system.
Injection Well Drilling and Completion
The CO2 injection wells at the Allison Unit production wells represent a new technological application for CBM, although they are actually quite similar to enhanced oil recovery COa- injection applications, such as applied in the Permian oil fields of West Texas. Separately, Amoco notes that drilling and testing procedures for nitrogen ECBM injectors also follows generally established procedures for injection wells (Seidle et al, 1997). However, it is likely that considerable room exists for improving the drilling, completion and ~ most particularly ~ the operation of CO2 injectors.
JAF98172.DOC 16 Advanced Resources International, Inc. Exhibit 3-4: Cross-Sectional Diagram Through Burlington Resources Allison CO^-ECBM Pilot San Juan Basin, USA #112 #142 #114 Injector Production Well dt>UUTt X 3000ft 1 Surface elev.65171 <<— NQ5E e^ JV.6449 N80E ' 0
200 200 J\AS
D CD T3 f 2800 2800J (U Q
3000 3000
3200 BMO- BMP 3200
3400 3400 TD=3390' Note: Depths, elevations, thicknesses expressed in feet /Advanced Resources International, Inc. April10i1998 IEA Greenhouse Gas R&D Programme Worldwide CO >3-ECBM Assessment
Exhibit 3-5 shows a completion schematic of a typical CO2 injection well (#140). The four injection wells were completed in largely uniform style: cased through the Fruitland, and then perforated and unstimulated. (Only the #143 was broken down with a small nitrogen-HCl treatment with no sand proppant.) The key procedures for drilling and completing the injection wells in Burlington's Allison Unit pilot were obtained from records filed at the New Mexico Oil Conservation Division and are summarized as follows:
• Drill surface hole to a depth of about 105 m, using a rotary rig equipped with a 12 1/4-inch bit and running light-weight drilling mud. • Run 8 5/8-inch surface casing and cement in place. • Run back in with 7 7/8-inch bit and drill through the Fruitland coal to a total depth of about 1,010 m. • Run 5 1/2-inch production casing and cement in place (fiberglass tubulars required only if CO2 has not been thoroughly dehydrated). • Perforate the casing across the Fruitland coal section (acidizing and fraccing probably not desirable). • Set injection packer just above Fruitland and install 2 7/8-inch injection tubing. • Install wellhead and link to the field CO2 distribution pipeline. Install glycol heater if necessary to raise CO2 temperature to reservoir levels (49° C).
Source
The Allison Unit pilot uses carbon dioxide injectant that is transported from McElmo
Dome in southwestern Colorado, which is an essentially pure natural CO2 deposit stored within an underground reservoir located about 150 km northwest of the ECBM pilot. The CO2 for the pilot is taken from an existing pipeline which runs nearby, connecting McElmo dome with primary-
consumer CO2-enhanced oil recovery (EOR) projects in West Texas. Shell CO2 Co. is the operator of both McElmo Dome field and the C02 pipeline. Because the West Texas EOR fields constitute one of the world's largest C02 floods, the availability and costs of C02 are unusually favorable in this part of the country.
Burlington's original operating permit envisioned utilizing waste CO2 from their nearby Val Verde CBM gas processing plant. At this plant, significant quantities of C02 are removed from CBM production in the San Juan Fairway to enable the methane to meet pipeline
specifications (the Fruitland coal in this area contains 8-12% natural CO2). The waste stream from the plant is a by-product of normal oil & gas operations and thus may be considered anthropogenic. However, utilizing carbon dioxide from Shell's McElmo Dome field proved to be
the preferred option for a short-term pilot of unknown duration, primarily because the waste CO2 at Val Verde would require large capital investment for compression to enable it to be used in ECBM.
JAF98172.DOC 18 Advanced Resources International, Inc. EXHIBIT 3-5: COMPLETION SCHEMATIC FOR CO2 INJECTION WELL SAN JUAN BASIN, USA
ALLISON UNIT #140 BASIN FRUITLAND COAL SEC. 19, T32N.R6W, SAN JUAN COUNTY,NM
CEMENT
2-7/8" TBG SET @3376'
DV TOOL SET ©3376'
PACKER SET ©3059'
PERFORATED INTERVALS ©3109-3376
4-1/2" CSG SET @ 3436' CMT CIRC. TO SURFACE
Advanced Resources International, Inc. April 10,1998 19 ISA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment
Burlington Resources purchases CO2 from Shell at an undisclosed price estimated at 3 $0.012/m ($0.50/Mcf) delivered. A 50-km long lateral pipeline was constructed to bring C02 from the Cortez main line to the Allison lease. C02 delivered to the lease boundary is of high purity (essentially 100%) and at line pressures of 1,500 pounds per square inch (psi). This C02 source is largely water-free, thus obviating the need for costly corrosion-resistant stainless steel or breakage-prone fiberglass tubulars (which Burlington actually employed for extra caution). In contrast, industrial CO2 sources are high hi water vapor and dehydration is likely to be a significant cost.
ECBM Operations
Perhaps the least well understood aspect of CO2-ECBM application is the area of field operations and reservoir management. Reservoir characteristics of the coal seams ~ such as the distribution of permeability, gas saturation, coal structure and many other complex variables - invariably have unpredictable natural variations that impact ECBM. Operational factors — such as the effectiveness of stimulation, formation damage due to drilling, selection of completion intervals and other engineering aspects ~ also are crucial to commercial production. This is why situating the pilot field in a well-studied area is so essential and efficient.
Most of the production wells in the Allison Unit were originally completed during 1988-89 and produced using conventional pressure depletion methods for a period of about 6 years. During this period, the reservoir was largely dewatered. In late 1994, Burlington installed the
injection wells and began to inject C02 intermittently starting May 1995. Injection has been continuous since July 1996, apart from a 5-month gap to coat and bury the COa lines under the ground surface during late 1997. Downhole injection pressure has been maintained at approximately 1,100 psi, which is safely below the fracture gradient for this area.
Allison Unit Production History Analysis
Analysis of actual production data is the only way to empirically gauge the effectiveness of
CO2-ECBM. Gas and water production data for the pilot were downloaded from the proprietary Dwight's Production Data Base Service. Production is reported on a monthly basis; this was converted to daily per-well production rates for ease of comparison.
The use of a sophisticated coalbed methane reservoir simulator thai is capable of modeling
reservoir mechanisms is key to understanding efficient C02-ECBM operations. The simulator should have capability to model three-phases of flow (water, methane, CO2), as well as the unique storage and release (sorption and desorption) mechanisms of coal reservoirs. We used ARI's proprietary COMET2 simulator, which has these capabilities, to perform preliminary scoping simulation.
JAF98172.DOC 20 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBU Assessment
Summaries of gas and water production rates for the nine wells are presented in Exhibits 3-6 and 3-7, respectively. As can be seen from these production plots, the initial five wells of the pilot produced at relatively high water and low gas rates starting in August 1989. As is normal for CBM wells, production improved gradually over the next three years: water rates declined in normal CBM production style from initial rates of 100 to 200 bwpd to around 30 bwpd in July 1992, while gas rates improved from 5,700 m3/d (200 Mcfd) initially to about 28,000 m3/d (1 MMcfd) over the same period. An unexplained increase in water rates took place during a one- year period until May 1993, with a concomitant pause in the inclining rate of gas increase of most wells.
By early 1995, concurrent with installation of the CO2 injection wells, gas production had attained rates of 28,000 to 57,000 m3/d (1 to 2 MMcfd) per well and was still climbing, while water production had fallen to favorably low levels of under 10 bwpd. This production level represents somewhat better than average San Juan basin conditions, but still significantly below the rates for superior Fairway wells 140,000 to 280,000 m3/d (5 to 10 MMcfd) per well.
The Allison Unit C02 injectors were completed during late 1994 and injection commenced on May 1, 1995, although injection was continuous only from July 1, 1996. Injection ceased again during the fourth quarter of 1997 so that the CO2 distribution lines could be buried; Burlington's BLM temporary operating permit had allowed for surface lines. Starting from July 1996, C02 injection rates have averaged about 21,000 m3/d (750 Mcfd) per injector, for a total 4- 3 well total injection of about 85,000 m /d (3 MMcfd). Burlington reports that C02 levels in produced gas have remained low, increasing only marginally from initial concentrations of 0.3% by volume to about 0.4% CO2 at latest report. This indicates that CO2 breakthrough has not occurred, at least not at this early stage in the project.
Immediately following the start of CO2 injection, water rates increased dramatically to around 100 bwpd/well. Gas rates, in contrast, have fallen for some wells but risen for others in a complex pattern that is difficult to explain. A detailed reservoir simulation study is needed to elucidate the critical production mechanisms of this pilot.
JAF98172.DOC 21 Advanced Resources International, Inc. Exhibit 3-6: Gas Production History for the Allison Unit CO2-ECBM Pilot
ALLISON 112 ALLISON 113 ALLISON 114 ALLISON 115 -*- ALLISON 120 -•-ALLISON 121 ALLISON 130 to ALLISON 131 10 ALLISON 132
Aug Jan Jun Nov Apr Sep Feb Jul Dec May Oct Mar Aug Jan jn Nov Apr Sep Feb ul Dec 1989 1990 1990 1990 1991 1991 1992 1992 1992 1993 1993 1994 1994 1995 1995 1995 1996 1996 1997 997 1997
TIME
CO2 Injection Began Wells Shut-In Exhibit 3-7: Water Production History for the Allison Unit CO2-ECBM Pilot
7000
Allison 112 6000 •—Allison 113 allison 114 -X—Allison 115 -*— Allison 120 5000 5 -•—Allison 121 e. —f— Allison 130 ——Allison 131 4000 Allison 132 sl 3000
2000
1000
Aug Jan Jun Nov Apr Sep Feb Jul Dec May Oct Mar Aug Jan Nov Apr Sep Feb ul Dec 1989 1990 1990 1990 1991 1991 1992 1992 1992 1993 1993 1994 1994 1995 5 1995 1996 199S 1997 997 1997 TIME CO2 Injection Began Wells Shut-In IEATT^A^ Greenhouse , r*Gas R&Doj-n Programmep World-wide COfECBUAssessment
3.3 Estimation of Enhanced CBM Recovery and COi Sequestration
A rigorous full-field simulation of the Allison Unit is beyond the scope of the present study
(although recommended for future work on CO2-ECBM). Instead, we examined the production enhancement at a representative individual well within the project and developed general factors for ECBM recovery in the San Juan basin. We then developed a range of enhancement and sequestration factors for application to other basins, where permeability and other reservoir properties are likely to be different (less favorable) than in the San Juan.
Geometrically, a central producing well surrounded by four injection wells would have the maximum ECBM benefit, and would also represent the long-term production enhancement in a large commercial ECBM field. Production wells and injectors would be evenly spaced, so such a central well would represent average field conditions. The complex completion and operations . pattern at the Allison Unit precluded this preferred approach. Instead, we chose the Allison #115 well as representative of optimal ECBM operations. The #115 shows a high degree of enhanced production. Furthermore, it is the only well within the pilot to have been produced continuously and without re-completion since its original completion date of 1989. Prior to injection (January 1995), gas production from the #115 well had improved steadily to about 14,000 m3/d (500 Mcfd) with negligible water production. Following injection, gas rates climbed sharply to about 35,000 m3/d (1.25 MMcfd) and were continuing to improve as of latest report, while water jumped to a still quite manageable 60 Bwpd.
The magnitude of production enhancement at the Allison Unit #115 (about 21,000 m3/d)
is comparable to the CO2 injection rate for one injection well (Exhibit 3-8). Production using primary pressure depletion for this well is preliminarily simulated to result in methane reserves of approximately 170 Mm3 (2.0 Bcf), which represents a recovery of an estimated 33% of initial in- place CBM. ECBM is projected to increase recovery levels by about 100% to an absolute level of 66% of initial in-place methane, boosting reserves by about 2 Bcf to a total of 4.0 Bcf. ECBM also accelerates recovery to the early less-discounted years of the project, improving project economics.
In theory, CC^-ECBM has the potential to recovery 100% of original Gas-In-Place, which for the example of the Allison Unit #115 well implies a boost in recovery by 200% to about 6 Bcf. Future refinement of the ECBM process may allow such very high recoveries. However, as discussed in Section 5.3, we estimated a range in ECBM recovery from 0% to maximum 75% over conventional pressure-depletion methods in evaluating worldwide ECBM potential.
JAF98172.DOC 24 AdvancedResources International, Inc. Exhibit 3-8: Gas and Water Production History for the Allison Unit #115 Well, Showing Typical CO2 Injection Rate
2500 -r120
—•—Gas — »- Water
2000
1500
u to
1000
500
Aug Dec Apr Aug Dee Apr Aug Dec Apr Aug Dec Apr Aug Dec Apr Aug Dec Apr Aug Dec Apr Aug Dec Apr Aug Dec 1989 1989 1990 1990 1990 1991 1991 1991 1992 1992 1992 1993 1993 1993 1994 1994 1994 1995 1995 1995 199S 199S 199S 1997 1997 1997
JAF00482.PPT IEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment
Sequestration of CO2 is an additional benefit of the ECBM process. No study has been published that explicitly documents the ratio of carbon dioxide injected to enhanced methane recovered. Given that the sorption isotherm for CO2 is about twice as high as that of methane, 3 3 under ideal conditions approximately 2 m of CO2 will be sequestered for every 1 m of ECBM production (Exhibit 3-9). This ratio has been adopted as a working value by most investigators, but should be viewed as approximate until the full range of reservoir processes has been examined.
Exhibit 3-9: Comparison of Sorption Isotherms for Pure CO2 and CILj (Gas Research Institute, 1995)
1,000 Decreasing Pressure Sequence Points Increasing Pressure Sequence Points Regression Fit Relationship
Core Gas Content 518.7+30.7 scf/ton
200 400 600 800 1,000 Pressure (psia)
JAF98172.DOC 26 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme World-wide COfECBM Assessment
In actual applications, however, this ratio is likely to be higher (3 or more) due to channeling of COa through faults and other high-permeability pathways, or to re-saturation of
naturally undersaturated reservoirs. Serious by-passing and production of CO2 would require costly removal at the wellhead for most utilization options. The economics of ECBM is very
sensitive to this CCVCHt ratio. Encouragingly, the lack of significant increase in C02 levels in production wells at the Allison Unit pilot indicates that ECBM -- at least in this location and over a relatively short time duration of several years — is effective and that the reservoir is sequestering C02 at close to the theoretical level. For this study, we assumed a CO2 sorbed to CBU displaced ratio of 2 for ECBM projects in all basins.
3.4 Surface Components of a CO2-ECBM Recovery System
Based on the design and operation of Burlington Allison pilot, it is possible to envision a CO2-ECBM recovery system designed to produce enhanced levels of methane from coal seams
while sequestering CO2. Exhibit 3-10 illustrates the surface layout of such a system.. The key elements of such a system are:
• Carbon dioxide for injectant can be sourced from either industrial or natural reservoir sources. • Industrial flue gas could be processed to remove water and other contaminants, and then compressed for transport in a dedicated CO2 supply pipeline. • Most natural CO2 reservoirs could supply injectant with minimal (if any) processing and compression, but still would require a C02 supply pipeline. • The CO2 supply pipeline would carry pressurized carbon dioxide injectant to the injection well, where pressure and temperature would be adjusted to downhole requirements. • Injection of CO2 would take place at pressures and completion intervals that optimize ECBM processes within the reservoir. • Methane produced at the nearby production well would flow into the gas gathering system, while water production would flow through a separate gathering system for treatment and disposal. • A central gas processing unit would separate CO2 from methane for potential recycling and reinjection, while methane would be compressed for use nearby or fed into a regional gas pipeline network.
As discussed in Section 4.0, the cost of reservoir CO2 injectant -- if located nearby to the CBM field and of reasonably pure concentration and high natural pressure — could be
considerably less than the cost of supplying industrial C02. This is why Burlington chose to use reservoir CO2, even though low-pressure anthropogenic CO2 (the Val Verde gas processing plant) was free and reasonably nearby.
JAF98172.DOC 27 Advanced Resources International, Inc. Exhibit 3-10: Components of a CO2 - ECBM Recovery System
CARBON DIOXIDE SOURCES
Industrial Natural Gas Gas Field Flue Gas Gas Concentrated Processing CH< and Separator/ Compressor Compressor CO, CO, Plant CO, Dehydrator (if needed) (if needed)
CH4
.0. Q. Compressor/ Recycled CO, 3 Dehydrator re to CO
C02 Io> Injection o; Well CBM MARKETS Gas Separator Methane Production e Well
ECBM PRODUCTION Local Water Industrial, Commercial Distant Disposal or Residential Consumers Markets
JAJFOO93E3.COR IEA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment
Section 4 Economics of CO2-ECBM
4.1 Introduction
ECBM development, like all oil & gas exploration and development, is a high-risk venture that differs fundamentally from more predictable enterprises such as factory production. This is primarily due to the great natural variability in reservoir parameters, which for CBM are principally gas saturation and permeability. Development costs too can vary regionally, depending on the maturity and competiveness of the local oilfield service industry. Finally, the wellhead price for methane and the cost for CO2 will depend on pipeline infrastructure, as well as local supply/demand dynamics. Each of these factors must be assessed in evaluating ECBM economics.
The economics of the C02-ECBM and CO2 sequestration process are highly site-specific, depending upon the reservoir quality and cost/price relationships found in each individual basin and specific project. For example, until a thorough reservoir evaluation is performed on Burlington Resources' Allison Unit pilot field in the San Juan basin, it is not possible to rigorously assess the economics of this project. Nor is it practical to evaluate with a high degree of confidence the economics of speculative CBM and ECBM resource development in other, currently non-producing countries and basins.
Recognizing this uncertainty, this section sets forth some of the approximate costs and
benefits of C02-ECBM application, focusing on a theoretical San Juan basin benchmark, but also with specific adjustments for development in other basins/countries. Our preliminary analysis shows that the economics of CO2-ECBM application can be favorable in the San Juan, but considerably less favorable in other areas with poor producibility and market conditions. For all areas outside the U.S., costs are assumed to incorporate the benefit from economies of scale for large well programs, rather than the current extremely high costs for limited (<100-well) exploration programs.
4.2 Capital and Operating Costs
Investment Costs
The primary investment costs for a CBM project include geological, geophysical and lease acquisition outlays; well drilling, completion and stimulation; installation of gas production and collection facilities; and, construction of a water disposal system. These costs are summarized in Exhibit 4-1.
JAF98172.DOC 29 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBMAssessment
Exhibit 4-1: Estimated Costs for CBM and ECBM Projects in the San Juan Basin
s •« Geological, Geophysical, Lease 25 20 Acquisition Costs Production Well Drilling, Completion, 300 Stimulation Costs Injection Well D&C Costs 300 Production Equipment Costs 200 50 Engineering Overhead (10%) 50 40 TOTAL CAPITAL COSTS 575 410
.Operations & Maintenance ($000/well-yr) 10 Water Disposal Costs ($/nr) 0.0018 0.0018 Gas Gathering, Treating, Compression 0.0088 0.0088 Costs ($/m3) 3 CO2 Costs ($/m ) 0.0177-0.0706
Geological, geophysical and lease acquisition. Prior to acquiring a lease position, geological and geophysical expenditures and engineering-based feasibility studies are often conducted. In addition, outlays are generally required for oGtaining the lease and its associated permits. These front-end costs will vary greatly but may range from $20,000 to $30,000 per well for a commercial scale project.
Well drilling, completion and stimulation. Coalbed methane wells tend to be shallower than conventional gas wells, thus drilling and completion costs are often considerably lower. In the San Juan basin, coalbed methane wells are usually rotary drilled with a mud-based fluid system and are cased to total depth. Recently, open-hole cavity completions, where the coal section is left uncased and allowed to naturally cavitate, have gained in popularity. The drilling and completion costs for a 900-meter coalbed methane well in the San Juan basin range from $250,000 to $350,000. In the shallower Warrior basin, coalbed methane wells are typically rotary-percussion drilled with air. Although single-zone, open-hole completions were once standard, today multi-zone, cased-hole completions are more common. Typical well drilling and completion costs in this basin range from $100,000 to $120,000 for a multiple-zone completion, 600-meter well.
In cased wells, some form of hydraulic stimulation is generally used to achieve favorable rates of gas flow from coals. Gel- and water-based fluids with proppant are commonly used for
JAF98172.DOC 30 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBU Assessment stimulation, however the size of the treatments is smaller and the cost is lower than those used for deep, low-permeability reservoir wells. The stimulation costs range from about $25,000 per zone for the thin, shallow coal seams hi the Warrior basin up to $100,000 for completing a thick sequence of deeper coals in the San Juan basin.
Production equipment and facilities. Producing coalbed methane wells will require specialized lease and production equipment. Most coalbed methane production in the U.S. is associated with the co-production of substantial quantities of water. Therefore, surface facilities need to include artificial lift, gas and water separation, and water disposal. For lifting water, a sucker-rod or progressive cavity pump is the favored design in the Warrior basin, while a sucker- rod or gas lift system is preferred in the San Juan basin. Surface facility costs can reach $200,000 per well in the San Juan basin, once water disposal and gas gathering facilities are allocated on a per-well basis.
Gas treating and compression. Gas treating and compression are signficant costs associated with coalbed methane. Because wells are generally operated at low (less than 100 psi; 700 kPa) backpressures, compression is required for most coalbed methane wells to increase the wellhead pressure to pipeline pressures of 600 to 1,000 psi (4 to 7 Mpa). Gas processing is required in the San Juan basin to remove carbon dioxide, typically 4 to 6% (but at times over 10%). Gas compression and treatment investment and operating costs are often borne.by the pipeline or the gas gathering company; however, these costs are recouped by discounting the wellhead price paid to the producer with a typical charge being $0.0035 to $0.0053 per m3 ($0.10 to $0.15 per Mcf). Less compression may be required in CO2-ECBM operations because reservoir pressure is maintained by injection of CC>2.
Water handling and disposal. Water disposal is a significant cost for coalbed methane development. In the Warrior basin, water is usually piped to a central treatment facility and disposed into a surface stream. In the San Juan basin, because of higher total dissolved solids (TDS) in the produced water, disposal wells are used. Here, a fully equipped disposal well and facility, capable of treating and injecting 20,000 barrels (3,200 m3) per day and linked to 30 to 40 production wells, will cost $1.5 to $2.0 million.
Other costs. Engineering, administrative support and contingencies add about 10% to investment costs.
Operating and Maintenance (O&M) Costs
Operating and maintenance costs for coalbed methane wells are usually higher than those for conventional wells. Beyond normal well and lease maintenance, coalbed methane wells require more extensive gas handling and water disposal. Operations and maintenance include daily activities such as field manpower, well workover, facilities maintenance, and power. O&M
__ _ __- 31 Advanced Resources International, Inc. JAryol.72.lJUTA 01 0 U IEA Greenhouse Gas R&D Programme Worldwide CO^ECBM Assessment include daily activities such as field manpower, well workover, facilities maintenance, and power. O&M costs are typically $6,000 to $10,000 per year per well. Engineering and support costs, allocated on a well basis, range from $2,000 to $5,000 per year per well depending on the complexity and size of the operation. Water disposal costs for the produced water may range from $0.10 to $1.00 per barrel of water produced, depending on the disposal technique used. Gas processing and compression may cost $0.0035 to $0.0088 per m3 ($0.10 to $0.25 per Mcf), depending on volume and type of facility used.
CO2 Costs. CO2 costs for naturally occurring deposits in underground reservoirs are relatively low, approximately $0.0177 per m3 ($0.50/Mcf) in the western U.S. Most anthropogenic CO2 could be considerably more costiy because it must be: (a) collected from industrial sources; (b) processed to remove water and other impurities; (c) compressed to reservoir injection pressures of 1,000 psi or higher; and (d) transported to the ECBM injection
wells. Conversely, development of CO2 emission restrictions and a CO2 trading system could lower CO2 costs substantially, or even generate additional revenue for an ECBM project for CO2 sequestration. This would dramatically improve the economics of CO2-ECBM operation.
4.3 CO,-ECBi —M Economic- s j
Simple cash-flow evaluations of CO2-ECBM economics were prepared for several scenarios of alternative enhanced recovery factors and development costs. The analysis
indicates that CO2-ECBM in the San Juan basin is economic at a minimum wellhead gas price of around $0.0618/m3 ($1.75/Mcf) which at current actual prices of >$0.0706/m3 ($2.00/Mcf) indicates that ECBM is profitable in this basin (Exhibit 4-2).
Economic runs representing other scenarios outside the U.S. were also run, with higher development costs and lower enhanced recovery factors (Exhibits 4-3 and 4-4). Not surprisingly, a much higher wellhead gas price is required for these cases, as summarized in Exhibit 4-5.
JAF98172.DOC 33 Advanced Resources International, Inc. San Juan Basin - Base CBM Economics Exhibit 4-2: ECBM Economics $1.75/Mcf Minimum Economic Gas Price San Juan Basin, USA
Total Wens 1 Operating Costs (Base; $ per well-month) $1.4 InlUal Gas Price (S/Mct; 1998) . $1.75 Operating Cost Inrlator Gas Price Inflator (% per year) Gas Gathering/Treat/Compr. Costs (per Mcf) $0.25 Royalty 0% Gas Shrinkage (Fuel, C02) 8% Severance Tax 0% Total New Wen Cost (S per WeH) $600 Discount Rate (per year) 11.5% SUmulatlon Cost ($ per Wen) $80 Section 29 Tax Credit (per Mcf; esL 1995) Drilling Cost (S per Wen) $330 Lease Equipment / Gathering Cost (S per WeD) S190
Item | Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 i2007 2008 2009 2010 2011 2012 2013 2014 20IS 2016 2017 Total Total Base Production (Met) 127.750 182.500 273.750 365.000 321.200 282.656 248,737 218,889 192.622 169.507 149.167 131.267 115.515 101,653 89,455 78.720 69.274 60,961 53.645 47.208 3,279,475' Gas Shrinkage (McD 10220 14600 21900 29200 25696 22612 19899 17511 15410 13561 11933 10501 9241 8132 7156 6298 5542 4877 4292 3777 262358 Net Base Production (Met) 117530 167900 251850 335800 295504 260044 228838 201378 177212 155947 137233 120765 106273 93521 82298 72422 63732 56084 49354 43431 3017117 Gas Price (S/Mct) J1.75 51.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 51.75 $1.75 $1.75 $1.75 $1.75 $1.75 Gross Revenues (S thousands ) S206 $294 $441 $588 S517 $455 $400 $352 $310 $273 $240 $211 $186 $164 $144 $127 $112 $98 $86 $76 $5,280 Royalty (S thousands) 10 $0 $0 $0 $0 $0 $0 SO $0 $0 SO $0 SO $0 $0 $0 $0 $0 $0 SO $0 Gross Rev Less Royalty ($ thousands) $206 $294 $441 $588 $517 $455 $400 $352 $310 $273 $240 $211 $186 $164 $144 $127 $112 $98 $86 $76 $5,280 Severance ($ thousands) $0 $0 $0 $0 $0 SO $0 $0 $0 SO $0 $0 SO $0 $0 $0 $0 $0 $0 $0 $0 Net Revenues ($ thousands^ $206 $294 $441 $588 $517 $455 5400 $352 $310 $273 $240 $211 $186 $164 $144 $127 $112 $98 $86 $76 $5,280 Investment (S thousands) ($600) ($600) Base Operating Costs ($ thousands) $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $336 Calhertng/Comprs Costs (S thousands) $29 $42 $63 $84 $74 $65 $57 $50 $44 $39 S34 $30 $27 $23 $21 $18 $16 $14 $12 $11 $754 Before Tax Net Cash Flow ($ thousand ($441) $235 $361 $487 $426 $373 $326 $285 $249 $217 $189 $164 $143 $123 $107 $92 $79 $67 $57 S48 $3,590 Federal/State Taxes $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 Section 29 Tax Credit $0.0 SO.O SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 SO.O $0.0 SO.O $0.0 $0.0 $0.0 $0.0 After Tax Net Cash Flow (5 thousands ($441) $235 $361 $487 $426 $373 S326 $285 $249 $217 $189 $164 $143 $123 $107 $92 S79 $67 $57 $48 $3,590 Discount Factor 1.00 0.90 0.80 0.72 0.65 0.58 0.52 0.47 0.42 0.38 0.34 0.30 0.27 0.24 0.22 0.20 0.18 0.16 0.14 0.13 Net Disc. Cash Flow ($ thousands) ($441) $211 $290 $351 $276 S2I7 $170 $133 $104 $82 $64 S50 $39 $30 $23 $18 $14 $11 $8 $6 51,655
Financial Performance NPV® 12% 51,655 IRR 74.0%
San Juan Basin - Incremental CO2-ECBM Economics
Total Wens I Operating Costs (Base; $ per weB-monlh) $1.5 InlUal Gas Price (S/Mcr; 1998) $1.75 Operating Costlnflator Incremental Production (%) 75% C02 Costs (S/Mcf) " $0.50 Gas Price Inflator(% per year) Gas Gathering/Treat/Compr. Costs (per Mcf) $0.25 Royally 0% Gas Shrinkage (Fuel, CO2) 8% Severance Tax 0% Injection Wei Cost ($ per Well) $350 DlscountR«te(peryear) 11.5% Stimulation Cost($perWeO) $0 Section 29 Tax Credit (per Mcf; est, 1995) Drilling Cost ($ per WcO) $200 Lease Equipment / Gathering Cost ($ per Well) $150
Item Year 1998 199? 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Total Total Base Production (Mel) 95.813 136,875 205.313 273.750 240.900 211.992 186,553 164.167 144.467 127.131 111,875 98.450 86.636 76.240 67.091 59.040 51,955 45.721 40.234 35,406 2,459,606 Gas Shrinkage (Met) 7665 10950 16425 21900 19272 16959 14924 13133 11557 10170 8950 7876 6931 6099 5367 4723 4156 3658 3219 2832 196768 Net Base Production (Men 88148 125925 188888 ,251850] 221628 195033 171629 151033 132909 116960 102925 90574 79705 70140 61724 54317 47799 42063 37015 J32574J 2262838 *MUVAWW Gas Price (S/Mcr) $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 $1.75 S1.75 $1.75 Gross Revenues (S thousands) $154 $220 $331 $441 $388 $341 $300 5264 $233 $205 $180 $159 $139 $123 $108 $95 $84 $74 $65 $57 $3,960 Royalty ($ thousands) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO SO $0 $0 $0 SO $0 Gross Rev Less Royally (S thousands) $154 $220 $331 $441 $388 $341 $300 $264 $233 $205 $180 $159 $139 $123 $108 $95 $84 $74 $65 $57 $3,960 Severance (S thousands) $0 $0 $0 $0 $0 $0 $0 $0 $0 • $0 $0 SO $0 $0 $0 $0 $0 $0 $0 SO $0 Net Revenues ($ thousands) $154 $220 $331 $441 $388 $341 $300 v^SJMjL. $180 $159 $139 $123 $108 $95 $84 $74 $65 $57 $3,960 JSOLv. sK$2ttvv> AMMuuwAv Investment ($ thousands) ($350) ($350) Base Operating Costs (S thousands) $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $336 CO2 Costs ($ thousands) $96 $137 $205 $274 S241 $212 $187 $164 $144 $127 $112 $98 $87 $76 $67 $59 $52 $46 $40 $35 $2,460 GatheringfComprs Costs ($ thousands) $22 $31 $47 $63 $55 $49 $43 $38 S33 $29 .^$26, $23 $20 $18 $15 $14 $12 $11 $9 $8 $566 Before Tax Net Cash Flow ($ thousand ($330) $35 $61 $87 $75 $64 $54 $46 $38 $32 $26 $21 $16 $12 $9 $6 $3 $1 ($2) ($3) $249 Federal/State Taxes $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 SO.O $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 Section 29 Tax Credit SO.O $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 After Tax Net Cash Flow ($ thousands) ($330) $35 $61 S87 $75 $64 $54 $46 $38 $32 $26 $21 $16 $12 $9 $6 S3 $1 ($2) ($3) $249 Discount Factor 1.00 0.90 0.80 0.72 0.65 0.58 0.52 0.47 0.42 OJ8 034 030 0.27 0.24 0.22 0.20 0.18 0.16 0.14 0.13 Net Disc. Cash Flow ($ thousands) ($330) S32 $49 $63 $48 $37 $23 $21 $16 $12 $9 $6 $4 $3 $2 $1 $1 $0 (SO) (SO) $1
Financial Performance NPV® 12% SI ERR 11.6% Base CBM Economics Exhibit 4-3: ECBM Economics S2.25fM.cf Minimum Economic Gas Price; SJB+25% Cost; +40% Enhanced Recovery International - Low Case
Total Wens Operating Costs (Base; $ per weD-month) SI.4 InlUal Gas Price (S/Mcf; 1998) 52.25 Operating Cost Inflator Gas Price Inflator (•/• per year) Gas Gathering/Treat/Compr. Costs (per Met) 50.25 Royalty 0% Gas Shrinkage (Fuel, CO2) 8% Severance Tax 0°/< Total New Wen Cost($ per WeU) S600 Discount Rate (per year) 11.5% Stimulation Cost (S per Wen) 580 Section 19 Tax Credit fper Mcf; est 1995) Drilling Cost (S per Wen) $330 Lease Equipment / Gathering Cost (S per WeH) 5190
2014 2016 Total Itenil^ Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 .WAM.W.WWi VWAWW*.' <«2SJS~ «2£i2». Total Base Production (Mcf) 127.750 182,500 273.750 365.000 321,200 282.656 248.737 218,889 192.622 169,507 149.167 131.267 115,515 101.653 89.455 78,720 69,274 60,961 53.645 "Twos" 3,279,475 Gas Shrinkage (Mcf) 10220 14600 21900 29200 25696 22612 19899 17511 15410 13561 11933 10501 9241 8132 7156 6298 5542 4877 4292 3777 262358 Net Base Production (Mel) 117530 167900 251850 335800 295504 260044 228838 201378 177212 155947 137233 120765 106273 93521 82298 72422 63732 56084 49354 43431 3017117 Gas Price (Sfltfcf) $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $2.25 $235 $2.25 $2.25 $2.25 $2.25 $2.25 Gross Revenues (S thousands ) $264 $378 $567 S756 $665 $585 $515 $453 $399 $351 $309 $272 $239 $210 $185 $163 $143 $126 Sill $98 $6,789 Royally ($ thousands) JO $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 $0 $0 $0 Gross Rev Less Royalty (5 thousands) $264 $378 $567 $756 $665 $585 $515 $453 $399 $351 $309 $272 $239 $210 $185 S163 $143 $126 $111 $98 $6,789 Severance (S thousands) 10 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 $0 $0 $0 Net Revenues (S thousands) $264 $378 $567 $75S $665 $585 $515 $453 $399 $351 $309 $272 $239 $210 $185 $163 $143 $126 $111 $98 J&22L, Investment (S thousands) ($750) ($750) Base Operating Costs ($ thousands) $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $336 Gathering/Comprs Costs (S thousands) $29 $42 $63 184 $74 $65 $57 $50 $44 $39 $34 $30 $27 $23 $21 $18 $16 $14 $12 $11 $754 Before Tax Net Cash Flow ($ thousand ($532) $319 $487 $655 $574 $503 $441 $386 $338 $295 $258 $225 $196 $170 $148 $128 Sill $95 $82 $70 $4,948 Federal/State Taxes $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 Section 29 Tax Credit $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 After Tax Net Cash Flow ($ thousands) ($532) $319 $487 $655 $574 $503 $441 $386 $338 $295 $258 $225 $196 $170 $148 $128 $111 $95 $82 $70 $4,948 Discount Factor 1.00 0.90 0.80 0.72 0.65 0.58 0.52 0.47 0.42 0.38 034 0.30 0.27 0.24 0.22 0.20 0.18 0.16 0.14 0.13 Net Disc. Cash FlowlS thousands) ($532) $285 $392 $472 $372 $292 $229 $180 S141 $111 $87 $68 $53 $41 $32 $25 $19 $15 $12 $9 $2,305
Financial Performance NPV@ 12% 52,305 JRR 82.0%
Incremental COZ-ECBM Economics
Total Wens 1 Operating Costs (Base; $ per wen-month) $1.5 InlUal Gas Price (S/Mcf; 1998) $255 Operating Cost Inflator Incremental Production (%) 40V. C02 Costs ($/McQ $0.50 Gas Price Inflator (9% per year) Gas Catherlng/TreaL/Compr. Costs (per McQ 50.25 Royalty Of. Gas Shrinkage (Fuel, CO2) 8% Severance Tax 0% Injection Wen Cost (5 per Well) $350 Discount Rate (per year) 11.5% SUmulatlon Cosl (S per Wen) $0 Section 29 Tax Credit (per Mcf: est. 1995) Drilling Cost ($ per Wen) $200 Lease Equipment /Gathering Cost (S per Wen) $150
Item Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Total Total Base Production (Mcf) 51.100 73.000 109,500 146.000 128,480 113,062 99.495 87.556 77,049 67,803 59.667 52,507 46,206 40,661 35,782 31,488 27.709 24,384 21.458 18.883 1,311,790 Gas Shrinkage (McO 4088 5840 8760 11680 10278 9045 7960 7004 6164 5424 4773 4201 3696 3253 2863 2519 2217 1951 1717 1511 104943 Net Base Production (Mel) 47012 67160 100740 134320 118202 104017 91535 JjJSSJ^ *J70885~ ^62379^ 54893 48306 42509 37408 32919 28969 25493 22434 19742 17373 1206847 vjrstfxtvj, SV-tHAV.W. Gas Price (S/Mct) SZ25 $2.25 $2.25 52.25 $125 $2.25 SZ25 "stus" "s^S"" "sJS'" $2.25 S2.25 $2.25 SZ25 $2.25 $2.25 $Z25 $2.25 $2.25 SZ25 Gross Revenues ($ thousands ) $106 $151 $227 $302 $266 $234 $206 $181 $159 S140 $124 $109 $96 $84 $74 $65 $57 $50 S44 $39 52,715 Royalty (S thousands) $0 SO $0 $0 SO SO $0 $0 $0 $0 $0 $0 $0 $0 SO $0 SO SO SO SO $0 Gross Rev Less Royalty ($ thousands) $106 $151 $227 $302 $266 $234 $206 $181 $159 $140 $124 $109 $96 $84 $74 S65 $57 $50 $44 S39 $2,715 Severance (S thousands) $0 SO $0 $0 $0 $0 $0 SO $0 $0 $0 $0 $0 $0 $0 $0 SO SO SO SO $0 Net Revenues (S thousands) $106 $151 S227 $302 $266 $181 $140 $124 $109 $96 $84 $74 $65 $57 $44 $39 52,715 VWMWWVt IMMMrVUMCV WMMWAV «££L, ^206^ ivmvwwtt .jy.jL.. VhMWWWU WVW.WWV WUWtAMttfV MWAWVAV ..vjSm. WWAWW.' UWWAWW MUWUUUUWAWV nvestment ($ thousands) ($438) ($438) Dase Operating Costs ($ thousands) $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 SI7 $336 C02 Costs ($ thousands) $51 $73 $110 $146 $128 $113 $99 $88 $77 $68 $60 $53 $46 $41 $36 $31 $28 S24 $21 $19 51,312 Gathering/Comprs Costs ($ thousands) $12 $17 $25 $34 $30 $26 $23 $20 $18 $16 S14 $12 $11 $9 58 $7 $6 $6 $5 $4 $302 Before Tax Net Cash Flow ($ thousand ($411) $45 $75 $106 $91 $78 $67 $57 $48 $40 $33 $27 S22 $17 S13 $10 $6 $4 $1 (SI) $328 Tederal/State Taxes $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 Section 29 Tax Credit $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 SO.O SO.O $0.0 SO.O SO.O SO.O $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 After Tax Net Cash Flow (S thousands) ($411) $45 $75 $106 $91 $78 $67 $57 $48 $40 S33 $27 $22 $17 $13 $10 $6 S4 $1 (SI) $328 Discount Factor 1.00 0.90 0.80 0.72 0.65 0.58 0.52 0.47 0.42 0.38 034 OJO 0.27 0.24 0.22 0.20 0.18 0.16 0.14 0.13 Net Disc. Cash Flow(S thousands) ($411) $40 $60 $76 $59 $45 $35 $26 $20 $15 $11 $8 S6 $4 $3 52 $1 $1 SO ($0) $2 1 Financial Performance i NPV® »y. S2 V TRIt. TT.6V. Base CBM Economics Exhibit 4-4: ECBM Economics $3.25/Mcf Minimum Economic Gas Price; SJB+50% Cost; +20% Enhanced Recovery International - High Case
Tola! Wells Operating Costs (Base; $ per well-month) S1.4 Initial Gas Price (S/McT; 1998) $3.25 Operating Cost Inllator Gas Price Jnllalor (V* per year) Cas Galherlng/TreaL/Compr. Cosls (|HT Met) S0.2S Royally 0% Gas Shrinkage (Fuel, CO2) 8V. Severance Tax 0% Total New Well Cost ($ per Well) $600 Discount Rate (per year) n.sv. Stimulation Cost ($ per Well) $80 Section 29 Tax Credit (per Mcf; esL 1995) Drilling Cost (S per Well) $330 Lease Equipment / Gathering Cost ($ per Well) $190
Item | Year 1998 1999 2000 2001 2002 2003 2004 200S 2006 2007 2008 2009 2010 2011 2012 2013 2014 201S 2016 2017 Total Total Base Production (Mel) 127.750 18WOO 273.750 365.000 321.200 282.6S6 248.737 218.889 192.622 169.507 149.167 131.267 115.515 101.653 89.455 78.720 69.274 60.961 53.645 47.208 3,279,475 Gas Shrinkage (Mcf) 10220 14600 21900 29200 25696 22612 19899 17511 15410 13561 11933 10501 9241 8132 7156 6298 5542 4877 4292 3777 262358 Net Base Production (Md) 117530 167900 251850 335800 295504 2(0044 228838 201378 177212 155947 137233 120765 106273 93521 82298 72422 63732 56084 49354 43431 3017117 Gas Price (S/Md) $3.25 $3.25 $3.25 $3.25 $3.25 S3.25 $3.25 $3.25 $3.25 $3.25 $3.25 $3.25 $3.25 $3.25 $3.25 $3.25 $3.25 S3.25 $3.25 $3.25 Gross Revenues ($ thousands ) $382 $546 $819 $1,091 $960 $845 $744 $654 $576 $507 $446 $392 $345 $304 $267 $235 $207 $182 $160 $141 $9,806 Royalty (S thousands) SO $0 $0 $0 $0 $0 $0 SO SO $0 $0 $0 SO SO SO SO $0 SO SO SO $0 Gross Rev Less Royalty ($ thousands) $382 $546 $819 $1.091 $960 $845 $744 $654 $576 $507 $446 $392 $345 $304 $267 $235 $207 $182 $160 $141 $9,806 Severance (S thousands) 10 $0 $0 $0 $0 $0 SO $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO TetRevenues ($ thousands) $382 S546I $819 $1.091 $960 $845 lS744 $654 $576 $507 $446 $392 $345 $304 S267 $235 $207 $182 $160 $141 JSiiJL. Investment (S thousands) ($750) ($750) Base Operating Costs (S thousands) $17 $17 $17 $17 $17 S17 $17 $17 $17 $17 $17 $17 S17 $17 $17 S17 S17 $17 $17 $17 $336 Gathertng/Comprs Costs^S thousands) $29 S42 $63 $84 $74 $65 $57 $50 $44 S39 $34 $30 S27 $23 $21 $18 $16 $14 $12 $11 $754 Before Tax Net Cash Flow (S thousands ($414) $487 $739 $991 $870 $763 $670 $587 $515 $451 $395 $345 $302 $264 $230 $200 S174 $151 $131 $113 $7,965 Federal/Slate Taxes $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 Section 29 Tai Credit $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 Alter Tax Net Cash Flow ($ thousands) ($414) $487 $739 $991 $870 $763 $670 $587 $515 $451 $395 $345 $302 $264 $230 $200 $174 $151 $131 $113 $7,965 Discount Factor 1.00 0.90 0.80 0.72 0.65 0.58 0.52 0.47 0.42 038 034 030 0.27 0.24 0.22 0.20 0.18 0.16 0.14 0.13 Net Disc. Cash Flow (S thousands) ($414) $437 $594 $715 $563 $443 $349 $274 $216 $169 $133 $104 $82 $64 $50 $39 $31 $24 $19 $14 $3,904
Financial Performance NPVffl 12% $3,904 IRR 148.9V.
Ul Incremental CO2-ECBM Economics
Total Wells 1 Operating Costs (Base; $ per well-month) $1.5 Initial Gas Price (S/Mcf; 1998) $3.2! Operating Cost Inflator Incremental Production (%) 20V. CO2 Costs ($/Md) $0.50 Gas Price Inllator (% per year) Gas Gatherlng/TreaUCompr. Costs (per Mel) $0.25 Royalty ov. Gas Shrinkage (Fuel, CO2) 8% Severance Tax 0% Injection Well' Cost ($ per Well) $350 Discount Rate (per year) 11.5V. Stimulation Cost (S per Well) $0 Section 29 Tax Credit foer Mcf! esL 1995) Drilling Cost (S per Well) $200 Lease Equipment / Gathering Cost ($ per Well) SI50
Item | Year 1998 1999 2000 2001 2002 2003 2004 ZOOS 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Total Total Base Production (Md) 25.550 36.500 54.750 73.000 64.240 56.531 49.747 43.778 38424 33.901 19.833 26.253 23.103 20331 17.891 15,744 13.855 12.192 10.729 9.442 655,895 Gas Shrinkage (McO 2044 2920 4380 5840 5139 4522 3980 3502 3082 2712 2387 2100 1848 1626 1431 1260 1108 975 858 755 52472 Nrt Base Production (Md) 23506 33580 50370 67160 59101 52009 45768 40276 35442 31189 27447 24153 21255 18704 16460 14484 12746 11217 9871 8686 603423 Gas Price (S/McQ $3.25 53.25 $3.25 $3.25 S3.25 $3.25 $3.25 $3.25 $3.25 S3.25 $3.25 53.25 $3.25 $3.25 S3.2S $3.25 $3.25 $3.25 S3.25 $3.25 Gross Revenues (S thousands ) $76 $109 $164 $218 $192 $169 $149 $131 $115 $101 $89 $78 $69 $61 $53 $47 $41 $36 $32 $28 $1,961 Royalty ($ thousands) $0 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 $0 $0 SO $0 $0 $0 $0 $0 $0 SO Gross Rev Less Royalty (S thousands) $76 $109 $164 $218 $192 $169 $149 $131 $115 $101 $89 $78 $69 $61 $53 $47 $41 $36 $32 $28 $1,961 Severance <$ thousands) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 $0 SO Net Revenues (^thousands) $76 $109 $164 $218 $192 $169 $149 $131 $115 S101 $89 S78 S69 $61 S53 $47 $41 $36 $32 $28 $1,961 Investment f$ thousands) ($438) ($438) Base Operating Costs (S thousands) SI7 $17 $17 $17 $17 $17 $17 S17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $17 $336 CO2 Costs (S thousands) $26 $37 $55 $73 $64 $57 $50 $44 $39 $34 $30 $26 $23 $20 $18 $16 $14 $12 $11 $9 S6S6 Gathering/Comprs Costs (S thousands) $6 S3 $13 $17 $15 $13 $11 $10 $9 $8 $7 $6 $5 $5 $4 $4 $3 $3 $2 $2 $151 Before Tax Net Cash Flow (S thousands (S409) $47 $80 $112 $96 $83 $71 $60 $51 $43 $36 $29 $24 $19 $15 $11 $8 $5 $2 ($0) $381 Federal/State Taxes $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 SO.O $0.0 SO.O $0.0 $0.0 $0.0 $0.0 $0.0 Section 29 Tax Credit $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 SO.O $0.0 $0.0 $0.0 $0.0 Alter Tax Net Cash Flow (S thousands) ($409) $47 $80 $112 $95 $83 $71 $60 S51 S43 $36 $29 $24 $19 $15 $11 $8 $5 52 (SO) $381 Discount Factor 1.00 0.90 0.80 0.72 0.65 OJ8 0.52 0.47 0.42 038 034 030 0.27 0.24 0.22 0.20 0.18 0.16 0.14 0.13 Net Disc. Cash Flow (S thousands) ($409) $43 $64 $81 $62 $48 S37 $28 $21 $16 $12 $9 $6 $5 $3 $2 $1 $1 $0 (SO) $30 Financial Performance NPV Exhibit 4-5: Minimum Required Wellhead Gas Price for Alternative 3 Cost/Enhancement Scenarios ($0.0177/m CO2 Cost) fail Low Costs, +75% Enhancement San Juan $0.0618 ($1.75/Mcf) SIB + 25% Costs/+40% Enhancement Bowen (Australia) $0.0794 ($2.25Mcf) SJB + 50% Costs/+20% Enhancement Sydney (Australia) $0.1147 ($3.25/Mcf) 4.4 Minimum Economic Gas Price Based on likely capital and operating costs for CO2-ECBM, including notably injection 3 well capital costs of $300,000 and C02 supply costs of $0.0177/m ($0.50/Mcf), and likely incremental methane production rates, the minimum economic methane price for the San Juan basin was determined to be about $0.0618/m3 ($1.75/Mcf). This cost is well below the current realized wellhead price of about $2.00/Mcf. Based on these assumptions, CO2-ECBM recovery is expected to be profitable in the San Juan basin. JAF98172.DOC 36 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COz-ECBU Assessment Section 5: Methodology for Ranking World Coal Deposits 5.1 Introduction Some of the technical criteria crucial to evaluating an in-situ coalbed methane resource were introduced and defined in Section 2. Also included were the factors controlling the recoverability of methane by conventional means as well as through enhanced recovery using COz injection. Section 5 explains how these and other criteria have been applied to classify and rank the world's major coal deposits (basins) in terms of their potential for enhanced recovery of methane using CC>2. This section also gives the background to the data sources and provides definitions for terms used in the basin analyses. The technical and economic merits of individual coal basins are then presented in Section 6. The primary focus is on the most promising CBM resources, regardless of geographical location. In the case of countries such as the United States, India and others which are endowed with multiple large coal deposits, the analysis concentrates on the few most favorable areas; other deposits within the country are named as lower-order prospects but are not discussed in detail. In this way, a balanced global perspective is achieved while at the same time maintaining attention on the major resource areas. These include both intensively mined and undeveloped coal deposits. 5.2 Data Sources There is a very limited body of published literature on worldwide CBM reservoir properties. This information tends to be very general in nature, lacks critical (usually proprietary) testing results and is often inaccurate. On its own, therefore, this information is woefully inadequate to characterize the world's coal deposits in terms of CBM production potential and the application of C02 flooding for enhanced CBM recovery. A wealth of geological information is generally available in regions with a history of coal mining. In many instances, however, the data are concentrated in the shallower, minable parts of the basin; the deeper areas which host the prospective CBM resource are less well known or may even be totally unexplored for coal. While this published information can be helpful in evaluating the in-place CBM resource, it is typically geared towards the mining sector and frequently lacks the type of information which is important for gauging CBM producibility. 37 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment In order to complete the comprehensive technical assessment of worldwide CBM resources presented in this section, ARI has supplemented the published data by drawing upon our (proprietary) in-house data base and experience in international CBM exploration and production. This information has been acquired during more than a decade of feasibility studies and exploration drilling projects for a number of public institutions and private clients. ARTs experience is briefly summarized below. • United States. ARI has carried out studies in most major U.S. coalbed methane basins, mainly on behalf of the Gas Research Institute, the U.S. Geological Survey and the U.S. Department of Energy. Projects range from resource evaluation, through reservoir analysis and field testing, to economic modeling. Methodologies developed by ARI for these studies have been widely adopted by the private sector and have helped operators establish commercial CBM production. • International. ARI has provided technical support on CBM projects to oil companies, national ministries and other authorities worldwide. Our geologic appraisal and well testing operations experience has given us detailed understanding of the coal basins in China, Australia, India, Southern Africa, Indonesia, Russia, Poland and other countries (although CBM exploration in all countries outside of the U.S. is still at a preliminary stage). 5.3 Definitions The results of a resource/reserve evaluation will be determined by how the input parameters are defined. Therefore, prior to discussing the potential for CC^-enhanced recovery of CBM from the world's major coal deposits, it is necessary that all such parameters be clearly defined and justified. Many of the key resource parameters are also illustrated diagramatically in Exhibit 5-1. Basin Area. This is the total area of the geological basin containing the coal-bearing formation(s). It is usually much larger than the area on which the CBM resource is calculated. (The coal- bearing formation may underlie only a part of the basin; in turn, only the more favorable portions of the formation may be considered as resource.) Data Control. The amount and quality of data available is described in degrees from "very good" to "poor". The designation "very good" applies to regions with widespread, abundant and reliable surface and subsurface (drilling) geological information providing control on coal. seam development. These regions also include coal quality, coal rank, and gas content data; in some cases coal seam permeability and sorption isotherm data will be available. "Poor" is used when limited subsurface information is available, accompanied by few or no coal analyses or JAF98172.DOC 38 Advanced Renources International, Inc. Exhibit 5-1: Diagram Showing CBM Prospective Zones PLAN Too Deep (>1,500m) Too Shallow (<300m) Coal Basin Underground Fault Prospective Strong Coal-Bearing Surface Mine Zone Zone Folding Formation Mine Boundary (shaded) 1,500m Enlargement shows completable coal based on three 30m fracture intervals. SECTION JAF00902.CDR 39 ISA Greenhouse Gas R&D Programme Worldwide COj-ECBM Assessment gas content measurements. Gross Coal Thickness. The total cumulative coal seam thickness (excluding partings) located within the 300-1,500 m depth range generally considered optimal for CBM development. It applies only to the "prospective" part of the basin, defined later. Completable Coal Thickness. That part of the gross coal thickness which can be contacted by typical hydraulic stimulation well completion technology. The specific assumptions are: a) 30-m "frac" height growth per stimulation; b) three fracs per well; and c) minimum of 3 m net coal per interval. (Although coal completion strategies vary depending on a number of local factors, the configuration adopted in this study is typical of CBM production operations.) Average Prospective Coal Depth. The average depth of the three completion intervals making up the completable coal thickness, weighted for coal thickness. The optimal depth "window" for CBM production is about 300-1,500 m. (This parameter does not directly enter the resource calculation, but coal rank and gas content are influenced by depth. Depth influences reservoir pressure and is one of the input parameters in gas-production simulations.) Prospective Area — All Coal. That part of the basin area where completable coal is present at a depth between 300 m and 1,500 m, but excluding structurally disturbed areas. Prospective Area - Non-Minable Coal. As above, but excluding in addition areas deemed to be minable in the medium term (next 50 years). This is, hi practical terms, the area most likely to be available for CBM development. Based on current mining activity, location and other factors, a judgment has been made as to whether future mining will be confined to open-pit operations (<300 m depth, minimal potential conflict with CBM development) or could also include deeper underground mining which would limit the area available for independent CBM development. Coal Resource. The coal tonnage targeted by CBM development, hence the amount of coal potentially available for sequestration of C02. Calculated as: CR = Anm * He * Dc * [100 - (fa + fm)] where: CR = Completable coal resource A^ = Non-minable area (km2) Ho = Completable coal thickness (m) DO = Coal density (1.36 g/cc assumed for bituminous coal) fa = Ash content (%) fm = Moisture content (%) JAF98172.DOC 40 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide CO z-ECBM Assessment Carbon Dioxide Sequestration Potential. The maximum amount of C02 that could remain adsorbed to coal following injection. This is based on the estimated enhanced recovery of 3 methane, using a factor of 2 volumes of CO2 needed to displace 1 volume of CHj. One Gm of CO2 has a mass of 1.855 Mt. Average Coal Rank. Describes, in terms of vitrinite reflectance (Ro%) and conventional mining nomenclature, the average rank (thermal maturity) of coal in the prospective region. The optimal rank for CBM production is high-volatile A to medium-volatile bituminous. In terms of Ro, the most favorable range is generally 0.7-1.2%, although gas production has been achieved from coal with rank ranging from 0.3% to 1.5%. Average Gas Content. Measured, or estimated based on saturated gas content (dry, ash-free) typical of coal at the rank and depth indicated for the prospective region. Gas contents of 10 m3/t or more are generally favorable, although gas contents as low as 4 m3/t could still be viable. Gas-In-Place. The in-situ volume of methane adsorbed to completable coal. Calculated as: where: GIF = Completable gas-in-place (Gm3) Anm = Non-minable area (km2) Ho = Completable coal thickness (m) GC = Gas content (m3/tonne; dry, ash-free basis) DC = Coal density (1.36 g/cc assumed for bituminous coal) fa = Ash content (%) fm = Moisture content (%) fi = Fraction of inert (non-methane) gas It is difficult to place a lower limit on what constitutes an attractive in-place resource because the resource concentration and producibility also need to be considered, as well as extraction costs and market conditions. However, 140 Gm.3 (5 Tcf) or more can generally be considered a very promising resource. Gas-In-Place Concentration. The "richness" of the prospective region oGtained by dividing the gas-in-place by the non-minable area.. Resource concentration above roughly 130 Mm3/km2 (12 Bcf/mi2) can be considered attractive. Stress Regime. Describes the horizontal tectonic forces currently acting on the CBM reservoir. Some stress measurements are available, but stress regime is usually inferred from the structural setting of the coal basin. Generally, extensional (pull-apart) or relaxed (neutral) stress are JAF98172.DOC 41 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide CO^ECBMAssessment preferable to compressive stress since they promote open coal cleats/fractures, thus enhancing permeability. Structure. This describes the extent of deformation of the coal-bearing formation. The angle of dip provides a possible indication of the amount of compression undergone by the formation in the past, although the present stress regime is most important. Undeformed (horizontal) coal seams are optimal not only from the point of view of the stress regime but also because they facilitate well construction and the design of large CBM fields, which typically consist of hundreds to thousands of production wells. Faulting can cause problematic geometrical relationships and in some cases can provide avenues for seam degassing. For these reasons, intensely folded and faulted regions are excluded from the CBM prospective area. Permeability. Permeability measurements are available for some regions. In most cases, an estimate has been made based on stress regime and coal characteristics. Early results of Meridian's San Juan basin pilot suggest that permeabilities less than about 5 millidarcies (md) may be too low for economically feasible ECBM using CO2, while values greater than 10 md are quite favorable. Technically Recoverable Resource —. Pressure Depletion. The portion of the gas-in-place estimated to be recoverable (i.e. the reserves) using conventional pressure depletion methods. Generally conservative estimates were made based on the producibility ranking (see later, also Exhibit 5-2). It is estimated that a resource with a producibility ranking of 5 will have reserves equivalent to 30% of the GIP. At the other end of the scale, the reserves are zero if the producibility ranking is 1. Producibility rankings of 2, 3 and 4 will yield reserves equal to 5%, 10% and 20% of GIP, respectively. Outside of the U.S., a minimum of 30 Gm3 (1 Tcf) is probably required for a commercial operation. Technically Recoverable Resource — CC^-Enhanced Recovery. The portion of the gas-in-place estimated to be recoverable using CC^ injection in addition to conventional pressure depletion methods. The enhanced COa production ranges between 0% and 75% of the pressure-depletion recovery on a scale linked to the producibility ranking (ske later, also Exhibit 5-2). The maximum percentage recovery enhancement (75%) is based on Meridian's San Juan basin pilot. JAF98172.DOC 42 Advanced Resources International, Inc. CO2-ECBM Cost/Market CBM Resource 3 TI o 3 2 Prospectiv e Ga s I n Technicall y Recov < Resourc e Concent r Developmen t Cos CB M Producibilit y C0 -ECB M Poten t (Bm ) C0 Availabilit y CB M Marke t (MMm /km ) 2 2 0 o '•''*• » a 00 fr« §: CD - n o9 il 5* I—I • i_i *"^ % *^. Q- 15" /-^ p * I B- &5 &. * , V /"~N % o cr % g y* 0 ^ CD CD >— / s ^ O <~N CO ^ c*•«r• s <^ S \ "*•-.•. S s ^ . "a A o o o to A o o li o LA o o 0^ o o "• •. "• i 2? •. •. s : % to o - \ 3 H-4 03 LO o Ul vj O o * 1 1— I 1 S. 1— I N° h—» o g a o o o ^ i — i ~* c? CD 0^ + O o o o o O ft.. §-. f W CD CD s= ^ w t-p. O *-* a '" g ELS SL t_k "o O CD O CD 01 g o o o 1—> 1 PL. __ p, x^V o o o CD M CD a >-$ s LO to JO to - 3 0 3 o 0 - + - to O 0 o o S- <-«• S- «-»• ^ "o CD ,O CD ,,Q o 0 S, 3 o^- !± 0 s - ^ _ g. 3- - , "-d Vto M tf» th to Q ' CD LO E O p, . o o to QO **—sgL o o o + o O ^~^ «a g 1 LO LO Q- o. + to o "o o ^ S3 O O o o E s^ 0 11 0 TO % W 00 t/J 3 W V O 8 8 W S . V LO LO V i ' ' - i S3" CD CD Ul O LO TO S o SN "o o cT rT o o 3 {j\ £ 3- a TO o^ ' Wjj* j£ SB LA Ul Ul LO £S JMM M^^ I'll' i IEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment 5.4 Description and Classification of CBM Deposits The principal coalbed methane basins of the world are described in Section 6 and ranked according to their potential for ECBM recovery using CO2 flooding. The basin descriptions comprise a resource analysis, an economic analysis and an outline of CBM activity to date. The resource and economic analysis sections are divided into distinct data groups, each containing information used to define one quality critical to the basin's potential for ECBM recovery. The data groups, as well as certain other important parameters, are individually ranked on a scale of 1 to 5 (lowest to highest). Exhibit 5-2 summarizes the ranking schemes and explains the basis for ranking allocations. The CBM activity section is not ranked because activity levels vary widely and activity is not necessarily a measure of potential. The resource analysis includes: Location and General. This gives the general geographical location, the breakdown of the different coal basins or coal fields, and the gross surface area excluding any offshore portion of a basin. (Offshore CBM deposits are assumed to be too costly to develop.) There is a brief statement on general economic development and infrastructure (apart from pipelines which are included in the economic analysis section). The level of data control is rated. This data group does not carry a ranking. • Coal Seam Geology. The geological formation(s) constituting the CBM target is identified. The information centers on how much of the coal present is effectively available as a CBM resource, i.e., the thickness, distribution and depth of the seams. The ash and moisture contents are also important parameters. [San Juan basin ranking: 4] Prospective Gas-In-Place. This data group provides additional parameters (prospective area and gas content) required to calculate the in-place CBM resource and the resource concentration. (A significantly greater resource concentration would be attained in selected high-grade parts of the overall prospective area.) Information is also provided on the coal rank, the methane content of the seam gas and the coal tonnage available for CO2 sequestration. [San Juan basin ranking: 3] Producibility. The factors controlling how much of the in-place CBM resource is recoverable -- either by conventional means or using CO2-enhanced recovery - are reviewed here. The technically recoverable methane resource, and the amount of CO2 that could be sequestered, are estimated. The most important parameter is seam permeability, which in turn is influenced by the tectonic stress regime and cleat/fracture development. [San Juan basin ranking: 5] JAF98172.DOC 44 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COx-ECBU Assessment The economic analysis includes the following information: Development Costs. The costs to develop and operate a CCvenhanced CBM recovery project are an important component of overall economic feasibility. Capital costs include drilling, completion, stimulation, and production equipment costs. Operating costs include well maintenance, electricity, water disposal, and C02 costs. Costs are highly dependent upon economies of scale as well as distance from existing suppliers and services. [San Juan basin ranking: 5] Coalbed Methane Market. General information is provided on the location and nature of potential CBM market. Existing gas pipeline infrastructure is noted. Market potential is rated as good, moderate or poor in the summary tables; "developed" indicates the existence of commercial production. [San Juan basin ranking: 4] Carbon Dioxide Availability. General information is provided on possible sources of both anthropogenic and naturally occurring COa which could be sequestered within an ECBM recovery process. The summary tables rate C02 availability as good, moderate or poor. [San Juan basin ranking: 5] CBM Activity. Finally, the section on CBM activity provides non-proprietary exploration and testing data, summarizes the current CBM leasing status and describes commercial production, if any. This section is not ranked because activity levels vary widely and activity is not necessarily a measure of potential. JAF98172.DOC 45 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Section 6 Assessment of Worldwide CO2-ECBM Applicability and CO2 Sequestration Potential Twenty coal deposits from fifteen countries are evaluated below in terms of their potential to support significant CO2-ECBM recovery operations. The coal deposits were selected on the basis of the screening criteria discussed in Section 2 of this report. The coal deposits are subsequently ranked according to their overall ECBM prospectivity, and those with greatest potential are identified for possible future detailed investigation. The data presented in Section 6 were obtained from published sources (listed in the Bibliography) as well as from ARI's proprietary data base. Output results (such as resource volume) have been calculated from input parameters (such as completable coal thickness), based on the methodologies and assumptions described in Section 5. Section 7 provides an estimate of the total worldwide sequestration potential in coal seams, including basins that would not likely be profitable on enhanced methane recovery alone. 6.1 USA 6.L1 Summary The United States has by far the brightest outlook for successful near-term application of CCb-ECBM technology for both enhanced methane recovery and carbon sequestration. This is because: a) CBM resources in several basins are geologically suitable for enhanced recovery technology; b) Large CO2 resources are accessible via established pipeline systems, and anthropogenic COa sources are also available for injectant; c) The U.S. natural gas pipeline infrastructure and -end-use market are well developed; d) U.S. production companies have expertise in and are confident investing in CBM technology and field development, and e) Service companies and equipment manufacturers compete within an efficient supply market, driving down CBM development costs. Coalbed methane production and producing wells have grown sharply during the past decade (Exhibit 6-1-1). Current production levels are about 28 Gm3/yr (1 Tcf/yr) from a total of over 7,000 producing wells (Stevens et al., 1996). This represents about 5% of total U.S. natural gas production. The San Juan basin dominates the industry, accounting for over 80% of total CBM production with high per-well production, but other productive basins are beginning to emerge (Exhibit 6-1-2). JAF98172.DOC 46 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment Exhibit 6-1-3: U.S. CBM Resource and Commercial ECBM Recovery Potential IPliSilliilll''WlWd^Hiii lLKiS!!$%i^ 1 Recoverable ECBM 380 63 23 o" (Gm3) COz Sequestration 1,400 230 85 i Potential (Mt) Gas Market Excellent Excellent Good S-J UJ2 CO Availability Excellent Good Excellent 2>UJ 2 Leasing/Testing Fully leased, Mostly leased, Partly leased, 1| fully developed partly developed partly developed Commercial Production (MnrVyr) 25,800 672 310 World Ranking (1-20) 1 2 4 Three coal basins in the western U.S. were identified as having particular promise for C02-ECBM application (Map 6-1). The San Juan basin is the site of the first commercial CO2- and nitrogen-ECBM pilots, demonstrating that this basin is geologically suited to the enhanced recovery process. Natural and anthropogenic sources of CC^ are reasonably abundant. The San Juan has a mature CBM production and service industry, with very favorable development costs. We estimate that enhanced methane recovery in the San Juan could total 380 Gm3 (13 Tcf), with an associated CO2 sequestration potential of about 1,400 Mt. Although coal basins in other countries also have large potential, the San Juan will probably become the first basin to fully adopt ECBM technology during the medium-term (10 years). Two other CBM basins in the United States were identified as having significant ECBM potential. The Uinta and Raton basins are emerging CBM areas that are geologically prospective for CBM, but to date are less prolific than the San Juan. Carbon dioxide is available, primarily from natural reservoirs. Natural gas pipelines are generally adequate. We estimate the enhanced methane recovery in the Uinta and Raton basins to be 63 Gm3 (2.2 Tcf) and 23 Gm3 (0.8 Tcf), respectively. Significant untested CBM resources also exist within these basins outside of current production areas which could provide additional long-term development potential. C02 sequestration potential is estimated at 230 Mt and 85 Mt, respectively. JAF98172.DOC 47 Advanced Resources International, Inc. Exhibit 6-1-1: Growth in U.S. Coalbed Methane Production 1100 1,003 973 to 1000 900 858 D Other 800 748 a0). D Appalachian 700 59- 600 M Warrior E 500 • San Juan O 400 - 73 300 - O 200 - 100 - m 10 o 0 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 Years Exhibit 6-1-2: Gas Productivity in U.S. CBM Basins 900 800 600 o 500 -San Juan Basin (3016 Wells) S3 -Uinta Basin - Drunkards Wash (33 Wells) O 0) -Raton Basin -Spanish Peaks (71 Wells) 300 f - C. Appalachia - Oakwood Field (179 Wells) I • Warrior Basin (2758 Wells) 100 May-90 Dec-91 Aug-93 Apr-95 Dec-96 Advanced Resources International, Inc. 1 JAf(HM82.P!T Map 6-1: CBMResources Total Over 400 Tcf (11,300 Bm3) in the U.S. of Which More Than 15 Tcf (425 Gm3) of Proved Reserves Have Been Booked Western Washington Powder River 24 Tcf , 30 Tcf Northern Wind River Appalachian 2 Tcf Greater Green River 84 Tcf Central Appalachia Piceance 5 Tcf 84 Tcf San 1.2 FruitIandCoal = 50Tcf Menefee Coal = 34 Tcf 13 Established CBM Basin Emerging CBM Basin 1.3 Frontier CBM Basin Reserve Additions (Tcf) 11 Advanced Resources International, Inc. JAr00482.PPT IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment •There is additional potential for enhanced CBM recovery application in several other coal basins (Appalachian, Greater Green River, Piceance, Warrior). These basins face significant reservoir challenges, such as low permeability and undersaturation, and their potential is estimated in Section 7. 6.1.2 Resource Analysis Coalbed methane resources in the United States may be divided into two broad groups of differing geologic age and reservoir characteristics. Basins in the western U.S. are generally of Cretaceous age, with minimal faulting and moderate-high permeability. Eastern U.S. basins are older (Carboniferous) and have experienced considerably more faulting and folding; permeability in these basins generally is low to moderate. Our analysis indicates that CO2-ECBM would be most applicable to three basins in the western U.S.: the San Juan, Uinta and Raton basins. CBM resources in these basins are proven to be highly productive, with favorable permeability and gas saturation. Other U.S. coal basins tend to have less favorable reservoir conditions. Warrior and Appalachian basin coal seams are shallow, thin, and low to moderately permeable; gas production is marginal and unlikely to support the added costs of CO2-ECBM, although CO2 sequestration potential still exists. Powder River basin coals are highly permeable, but also quite shallow and reservoir pressure is low. CBM testing in the Greater Green River shows high permeability but also serious undersaturation; vast amounts of COa could be stored in low-gas coal seams there but ECBM economics would probably be unfavorable. Finally, the Piceance basin has deep, high- rank coal containing a large CBM resource, but deliverability is poor. SAN JUAN BASIN Location and General The San Juan basin is located in the southwestern U.S. in northern New Mexico and southern Colorado (Map 6-1). Extending over an area of about 19,000-km2, the San Juan was a long-established gas-producing basin even before CBM development accelerated during the early 1990s, thus the existing gas pipeline system is extensive. The most productive area is the 2,000-km2 "Fan-way" in the northern portion of the basin, where wells average 85 MmVday (3 MMcfd). Infrastructure is well developed even though the area is sparsely populated. Data control is excellent. JAF98172.DOC 51 Advanced Resources International, Inc. IEA Greenhouse GasR&D Programme Worldwide COr-ECBMAssessment Coal Seam Geology (Ranking: 4). The main coal-bearing sequence is the Cretaceous Fruitland Formation, which contains a stratigraphically concentrated coal package. Completable coal thickness averages about 20 m. The average prospective coal depth is about 1,000 m. Ash and moisture contents average 25% and 2%, respectively. Prospective Gas-In-Place (Ranking: 3). The prospective gas-in-place resource in Fruitland coal seams has been assessed at approximately 1,420 Gm3 (50 Tcf), with an average resource concentration of 270 Mm3/km2 (25 Bcf/mi2; Kelso et al, 1988). More recent work shows that the actual resource is probably 20% larger (1,700 Gm3; 60 Tcf). This is a very large resource with a most favorable gas concentration. Coal mining in the San Juan basin currently is not significant. We anticipate that only a minimal proportion of the 6,300 km2 prospective area available for ECBM will be affected by mining during the medium- to long-term. Coal rank increases regionally from sub-bituminous in the southern San Juan basin to medium-volatile bituminous in north-central fairway. Gas content ranges from 7 to 20 m3/t, averaging about 16 m3/t. Most areas are gas saturated. A methane content of 90% is estimated; some of the most productive areas have 8 to 12% CC«2. Producibility (Ranking: 5). Technically recoverable CBM in the San Juan basin is estimated at approximately 510 Gm3 (18 Tcf), using conventional pressure-depletion techniques. Application of CC-2-ECBM recovery could increase methane recovery by about 380 Gm3 (13 Tcf). Approximately 1,400 Mt of CO2 could be permanently sequestered in the San Juan basin if ECBM were fully applied. The stress regime in the San Juan basin is generally low, as is structural dip into the basin's center. The coal is extremely well cleated. Faulting is minimal with good reservoir continuity and lateral communication. Permeability ranges from 1 to over 100 md, averaging about 20 md. The excellent producibility of the San Juan basin results in very high gas rates from CBM production wells, as well as a high recovery of original gas-in-place using conventional pressure-depletion recovery; CO2-ECBM recovery in the most permeable areas may not be as profitable because most of the gas can be recovered by less costly conventional means. TJINTA BASIN Location and General. The Uinta basin is located in the southwestern U.S. in east- central Utah (Map 6-1). Extending over a gross area of about 37,000 km2, the Uinta basin is an established gas-producing basin with existing gas pipeline infrastructure. CBM development is still at an early stage, and the only productive development to date is a small (500 km2) area in the south-central portion of the basin, where wells average 14,000 m3/day (500 Mcfd; Lamarre and JAF98172.DOC 52 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide CO^ECEM Assessment Burns, 1997). Infrastructure is well developed in this sparsely populated basin. Data control is good. Coal Seam Geology (Ranking: 2). The main productive coal-bearing sequence is the Perron Sandstone member of the Cretaceous Mancos Shale, although coal seams are present in other adjacent units Completable coal thickness averages a relatively modest 7.3 m. The average prospective coal depth is about 800 m. Ash and moisture contents average 20% and 5%, respectively. Prospective Gas-In-Place (Ranking: 2). CBM resources in the Uinta basin have not yet been thoroughly assessed. Prospective gas-in-place is estimated at approximately 280 Gm3 (10 Tcf) in the Perron coal alone (Tabet et al., 1995), with an average resource concentration in the more favorable areas of 90 Mm3/km2 (8.3 Bcfi'mi2). This represents a significant resource with moderate gas concentration. Coal mining in the Uinta basin occurs along the southern margin of the basin and is more significant than in the San Juan basin. However, we anticipate that only a small proportion of the 3,150 km2 prospective area will be affected by mining during the medium- to long-term. Coal rank increases with depth from high-volatile C bituminous near the surface. Gas content is anomalously high, averaging about 12.5 m3/t within the Perron coal. Most areas are gas saturated or oversaturated. Methane content is high at approximately 98%, with low levels of CO2. Producibility (Ranking: 5). Technically recoverable CBM resources in the Uinta basin are estimated at approximately 84 Gm3 -(3.0 Tcf), using conventional pressure-depletion techniques. Of this, 11 Gm3 has already been booked. Application of CCVECBM recovery could increase methane recovery by about 63 Gm3 (2.2 Tcf). Approximately 230 Mt of CC«2 could be permanently sequestered in the Uinta basin if ECBM were applied to this resource. Permeability of coal seams in the Uinta basin has not been well documented, but production levels indicate substantial permeability (>5 md). Faulting is minimal with good reservoir continuity and lateral communication. JAF98172DOC ^3 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment RATON BASIN Location and General. The Raton basin is located in the southwestern U.S. in north- central New Mexico and south-central Colorado, extending over a gross area of about 5,600 km2 (Map 6-1). It is unusual for the Rocky Mountain region in not being a productive natural gas province; this lack of existing gas pipeline infrastructure has hindered CBM development. However, a new pipeline reaches into the center of the basin and initial CBM development has begun. CBM wells average 8,500 m3/day (300 Mcfd) and are still improving as they dewater. Data control is fair to good. Coal Seam Geology (Ranking: 2). The main productive coal-bearing sequences are the Cretaceous Vermejo and Raton Formations. Completable coal thickness averages a relatively modest 8 m. The average prospective coal depth is about 800 m. Ash and moisture contents average 15% and 5%, respectively. Prospective Gas-In-Place (Ranking: 2). A detailed resource evaluation of the Raton basin estimated total CBM resources to be 285 Gm3 (10.2 Tcf; Stevens et al, 1992). Resource concentration varies widely throughout the basin, but averages about 90 Mm3/km2 (8.5 Bcf7mi2). Similar to the Uinta basin, this represents a significant resource with moderate gas concentration. Coal mining in the Raton basin takes place along the western basin margin, but has declined markedly from earlier levels. We anticipate that a neglible proportion of the 3,150 km2 prospective area will be affected by mining during the medium- to long-term. Coal rank increases with depth and towards a maturation high located in the north-central portion of the basin, averaging high-volatile A bituminous. Gas content is highly variable, averaging about 11 m3/t. Methane content is generally high at approximately 98%, with low levels of CO2. Producibility (Ranking: 4). Technically recoverable CBM resources in the Raton basin are estimated at approximately 57 Gm.3 (2.0 Tcf) using conventional pressure-depletion techniques. Application of CO2-ECBM recovery could increase methane recovery by an 3 estimated 23 Gm (0.8 Tcf). Approximately 85 Mt of C02 could be permanently sequestered in the Raton basin if ECBM were widely applied. Permeability of coal seams in the Raton basin has not been well documented, but production levels indicate substantial permeability (>5 md). Faulting is minimal with good reservoir continuity and lateral communication. Undersaturation is locally a problem. Well completion can be challenging, as hydraulic fracs tend to link up with aquifers, inhibiting dewatering. JAF98172.DOC 54 Advanced Resources International, Inc. JEA Greenhouse Gas R&DProgramme Worldwide COrECBMAssessment Exhibit 6-1-4; USA Technical ECBM Recovery Potential 2 ;JMiilPliiiWilli Prosp. Basin Area (km ) 6,300 3,150 3,150 Coal Resource (Gt) 120 23 26 Gas-In-Place (Gm3) 1,700 280 285 Off Cone. (Mm3/km2) 270 90 90 Technically Recoverable 510 84 57 CBM(Gm3) Technically Recoverable 380 63 23 3 CO2 -ECBM (Gm ) COa Sequestration 1,400 230 85 Potential (Mt) 6.1.3 Economic Analysis The U.S. has a mature CBM production industry. Services and equipment for CBM development are well established in producing basins. Development costs for large ECBM projects would be relatively low hi the San Juan, Uinta and Raton basins. Environmental approvals for large well programs consisting of hundreds to thousands of wells can require several years and considerable expense. Natural gas pipeline infrastructure and markets in U.S. CBM areas are generally well established (apart from the Raton basin). Carbon dioxide is widely available throughout the Rocky Mountain region, either from natural reservoirs or from industrial emissions. SAN JUAN BASIN Development Cost (Ranking:5) CBM costs in the San Juan basin are quite low for a large-scale project, due to its proximity to existing petroleum supply centers. Coalbed Methane Market (Ranking: 4). The San Juan basin currently produces about 71 Mm3 (2.5 Bcfd) of coalbed methane, most of which is transported out of the basin to urban areas such as Los Angeles. Increased production from ECBM would probably offset declining conventional CBM production, thus new pipeline infrastructure probably would not be necessary. Due to long-standing oversupply of natural gas in the Rocky Mountain region, wellhead natural gas prices are lower than in other parts of the U.S., averaging about $0.05 to $0.07/m3 ($1.50 to $2.00Mcf) over the long term. Advanced Resources International, Inc. JAF98172.DOC 55 1EA Greenhouse GasR&DProgramme Worldwide CO^ECB^tAssessment Carbon Dioxide Availability (Ranking: 5). Dedicated CO2 pipelines traverse the San Juan basin, connecting McElmo Dome CO2 deposits in southwestern Colorado with enhanced oil recovery fields in West Texas. In addition, the gas processing plants located within the producing areas remove about 6 MmVday (200 MMcfd) of C02 from coalbed methane production, which currently is vented to the atmosphere. A small amount of industrial CO2 emissions are generated by local coal-fired power stations. TJINTA BASIN Development Cost (Ranking: 5). Equivalent to San Juan basin costs for a large-scale project. Coalbed Methane Market (Ranking: 4). Good pipeline access through existing systems, but long-term wellhead prices are depressed compared with San Juan basin due to more limited marketing options ($0.035/m3; $1.50/Mcf). Carbon Dioxide Availability (Ranking: 5). Numerous reservoirs contain high-CO2 levels in the CBM development areas. These include the Farnham Dome, Gordon Creek, and Emery Unit fields. Reservoirs rich in C02 include the Devonian through Jurassic units. Anthropogenic CO2 emissions are limited from this lightly settled area. RATON BASIN Development Cost (Ranking: 5). Equivalent to San Juan basin costs for a large-scale project. Coalbed Methane Market (Ranking: 4). Reasonably good pipeline access through a limited existing system. Long-term wellhead prices are depressed compared with San Juan basin due to more limited marketing options ($0.0350/m3; $1.50/Mcf). Carbon Dioxide Availability (Ranking: 5). Numerous reservoirs contain high-CO2 levels close to the CBM development areas. These include the currently shut-in Des Moines field located along the eastern margin of the Raton basin, which contains 98.6% CO2 within the Abo Formation. To the southeast of the Raton basin, the Bravo Dome is a major CO2 production field with 480 Gm3 (17 Tcf) of reserves; current production of more than 7.8 MnrVday (270 MMcfd) is piped to West Texas EOR fields at a wellhead price of about $0.02/m3 ($0.50/Mcf). Anthropogenic CO2 emissions are very limited near the lightly populated Raton basin. JAF98172.DOC 56 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide CO2-ECBMAssessment Exhibit 6-1-5: US Commercial ECBM Recovery Potential Gas Market Long-distance pipeline Long-distance Long-distance to Los Angeles pipeline pipeline CO2 Availability McElmo Dome field; Devonian-Jurassic Coal-fired industrial Gas processing plants, reservoirs; Limited emissions; Natural Limited coal-fired coal-fired industrial CO2 reservoirs industrial emissions emissions 6.1.4 Coalbed Methane Exploration and Production Commercial coalbed methane production is currently taking place within a total of nine U.S. coal basins (San Juan, Warrior, C. and N. Appalachian, Uinta, Raton, Powder River, Mid- Continent, and Piceance basins; Stevens et al, 1996). However, the San Juan basin dominates the CBM industry, accounting for over 80% of total production. The San Juan also has the highest average per-well gas productivity (Exhibit 6-1-2), and is the most economically successful basin as well. The Warrior basin ranks second in production, but gas production averages only 3,400 m3/day/well (120 Mcfd/well), which is only marginally economic without tax credit subsidies. The Central Appalachian basin benefits from higher gas prices and is more economically viable, but per-well gas rates are similar to the Warrior's and soon this basin will be fully developed. Major coalbed methane producing companies include Burlington Resources, Amoco, ARCO, Phillips, as well as numerous smaller independents producers. Near-term future growth in CBM production is expected to take place primarily within the Uinta and Raton basins. Operators such as Texaco and River Gas have announced large drilling programs. The Greater Green River and Piceance basins are important frontier areas that will require improved technology and understanding to bring onstream. Advanced Resources International, Inc. JAF98172.DOC 57 Worldwide COr-ECBM Assessment IEA Greenhouse Gas R&D Programme 6.2 Canada 6.2.1 Summary Canada's large CBM potential, concentrated in the Western Canada sedimentary basin of Alberta (Map 6-2), has so far not been realized. Conventional natural gas supplies within most of the CBM areas are abundant, and wellhead prices are low. Initial CBM testing has been discouraging, although not conclusive given the large potential resource; commercial production is still negligible. Although more than $40 million has been invested in CBM testing to date, no producer with U.S. CBM development experience has yet made a determined effort to produce CBM in Canada. Exhibit 6-2-1 provides an overview of the potential for C02-ECBM recovery in the Western Canada basin. Recycling of vented industrial emissions, principally from coal-fired power plants, constitutes the primary source of carbon dioxide for ECBM recovery. CO2 sequestration potential in high-graded areas is large, estimated at approximately 170 Mt. Exhibit 6-2-1: Canada Resource and Commercial ECBM Recovery Potential i J 11 tt!M6*CfK''l*'W'Jy w JLJC/JOLt'D'Wl j ' ! ''ii v' v1 1it !i ' I'lti "!' lii t (ri J Recoverable ECBM (Gm3) 45 p COa Sequestration §u1o Potential (Mt) 170 _i Gas Market Moderate ^P 01 Z CO2 Availability Good oa Leasing/Testing Active CD — « Commercial Production Minor (MirrVyr) World Ranking (1-20) 9 JAF98172.DOC 58 Advanced Resources International, Inc. Wi vo Fenn Big Valley Sequestration IEA Greenhouse Gas R&D Programme WESTERN CANADA Map 6-2 ECBM Reserves: 45 Gm3 CO, - ECBM Potential of Canada CO2 Sequestration: 170 Mt CO2-ECBM Basins 500 1,000 Other Coal Basins Kilometers AAdvanced Resources International, Inc. JAF00935.CDR JEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment 6.2.2 Resource Analysis The vast majority of Canada's coal resources are contained within the large Western Canada sedimentary basin, which is the focus of this analysis. Coal is also extensively mined in the intramontane basins of central British Columbia, but the high degree of structural deformation greatly reduces the potential for CBM production. A number of small coal basins, constituting less than 5 percent of Canada's coal resources, are located along the Atlantic coast of Canada and are not discussed in this report. WESTERN CANADA BASIN Location and General. The Western Canada sedimentary basin extends across an area of more than 200,000 km2. The region of greatest coalbed methane potential encompasses the southern plains of Alberta where coal is extracted mainly by open-cast mining. Major population centers include Calgary and Edmonton. Infrastructure is locally well developed. The western and eastern foothills of the Rocky Mountains in British Columbia and Alberta, respectively, are also part of the Western Canada basin, but these areas are overall less suitable for CBM production due to incised topography, structural complexity and lack of infrastructure (Map 6-2). Data control is unevenly distributed across the region, being good in areas of coal and petroleum exploration but poorer elsewhere. Overall data control is considered to be fair. Coal Seam Geology (Ranking: 3). The main CBM targets are the Manville Fm. (Cretaceous) and the Scollard Fm. (Cretaceous-Tertiary). The Manville Fm. contains half a dozen coal seams between 1 m and 5 m thick over a 50 m interval, while the Scollard Fm. includes a concentrated zone with up to 24 m of coal. Seams in both formations are laterally persistent. Average completable coal thickness is around 12 m. (The Rocky Mountain foothills region tends to have thicker coals.) The average prospective coal depth is around 900-1,100 m. Ash and moisture contents average 15% and 5%, respectively. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource is estimated to be 2,240 Gm3 (79 Tcf), with an average resource concentration of 56 Mm3/km2 (5.2 Bcfftni2). This is a large resource by international standards, although the average resource concentration is relatively low. The prospective surface area is estimated at 40,000 km2, all of which is assumed to remain non-minable for several decades. The contained coal resource available for C02 sequestration is calculated at 473 Gt. JAF98172.DOC 60 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COx-ECBMAssessment Coal rank increases from east to west across the basin, ranging from sub-bituminous to high-volatile bituminous. Vitrinite reflectance is in the 0.5-0.8% range. An average gas content of 5 m /t is reported to be representative of the Alberta plains region, although gas contents average at least 10 m3/t in the Rocky Mountain foothills. Gas saturation information has not been released. A methane content around 95% can be expected. Produdbility (Ranking: 3). It is estimated that technically recoverable gas, or potential reserves, is of the order of 225 Gm3 (8 Tcf) using conventional pressure-depletion techniques. 3 Enhanced gas recovery using CO2 flooding could raise this by 45 Gm (1.6 Tcf) About 170 Mt of CO2 could be permanently sequestered. The stress regime is relaxed to mildly compressive. Dips are sub-horizontal to low. Permeability is reported to average around 1-3 md, which is lower than the 5 md conceptual cutoff for ECBM, but is likely to be higher in "sweet spot" areas. Exhibit 6-2-2: Canada Technical ECBM Recovery Potential 2 Prospective Basin Area (km ) 40,000 Coal Resource (Gt) . 473 3 Gas-In-Place (Gm ) 2,240 GIF Cone. (Mm3/km2) 56 Technically Recoverable 225 CBM (Gm3) Technically Recoverable 45 3 CO2 -ECBM (Gm ) CO2 Sequestration 170 Potential (Mt) 6.2.3 Economic Analysis WESTERN CANADA BASIN Canada has a thriving oil & gas industry, with modern services and a high level of efficiency. Although a significant CBM industry has not yet evolved, the basic conditions of oilfield services availability, competition, and high efficiency ensure that long-term development costs will be comparable to those of the U.S., if perhaps slightly higher due to higher labor costs and more severe weather (+10%). JAF98172.DOC 61 Advanced Resources International, Inc. Worldwide COr-ECBM Assessment ISA Greenhouse Gas R&D Programme Natural gas market conditions are not as favorable, given the current and forecasted future surplus of natural gas supplies and pipeline transportation constraints. Wellhead prices are likely to be significantly lower than in the San Juan basin. Development Cost (Ranking: 5). Comparable to San Juan basin costs (+10%). CoalbedMethane Market (Ranking: 3). The Alberta plains region is a major producer of conventional natural gas, most of which is exported out of the region. Coalbed methane would either have to compete with this probably lower cost gas, or target markets outside the existing gas distribution network. CBM could be well placed to supply a limited volume of natural gas for use in local industry or for commercial and residential heating in the more remote small to medium-sized communities which rely on expensive diesel for their energy needs. Access to established pipeline and other natural gas infrastructure would facilitate commercialization of CBM. In the Maritime provinces of eastern Canada, where limited and lower quality CBM resources are present, market conditions are much more favorable due to the shortage of alternative energy supplies. Carbon Dioxide Availability (Ranking: 4), Both naturally occurring C02 and industrial emissions are potential sources of vented COa available for ECBM recovery in western Canada. Numerous currently shut-in CO2 reservoirs exist in close proximity to CBM resources. In addition, most of the region's electricity is generated in coal-fired power plants concentrated in the major coalfields. Since these power plants are frequently located in the vicinity of the CBM resources, they are well suited to a C02 sequestration program involving ECBM recovery. Exhibit 6-2-3: Canada Commercial ECBM Recovery Potential Gas Market Local industry, commercial and residential heating CO2 Availability Natural reservoirs and coal- fired power plant emissions JAF98172.DOC 62 Advanced Resources International, Inc. IEA Greenhouse GasR&D Programme Worldwide COr-ECBMAssessment 6.2.4 Coalbed Methane Exploration and Production CBM testing has been conducted by over 20 companies in Canada, with more than 140 coreholes and test wells drilled in 30 different areas (Sinclair and Cranstone, 1997). However, testing results to date have been disappointing. Many of the operators that tested CBM in Canada did not have previous experience with this unconventional resource, resulting in numerous technical failures. Current CBM production in Canada is extremely limited: four wells at Fenn- Big Valley average 2,000 to 3,700 m3/d (70 to 130 Mcfd) per well, below Warrior basin gas rates and well below the commercial threshold in this region of low wellhead gas prices. CBM production in Canada is currently 1/7,500 of U.S. levels. Canadian CBM exploration began during the 1970s in the Alberta foothills region and in Nova Scotia. Activity peaked in the early 1990s with efforts shifting to the southeastern British Columbia foothills and the Alberta plains. Much of the work in the latter region involved testing and re-completing coals encountered in conventional petroleum wells. By 1997, about 140 wells had been tested for CBM. Half of these were drilled specifically for CBM, while 17 have undergone production testing. Some wells were stimulated by hydraulic fracturing or cavity completion. Exploration has diminished in recent years. Despite modest exploration effort to date, the CBM potential of the Western Canada basin is still considered to be attractive. Early investigations were lured by the thick, high-rank coals with high gas contents of the Rocky Mountains foothills, but other factors conspire to make this a relatively unprospective region. For example, permeability is inhibited due to severe structural deformation and the rugged terrain raises development costs. Experience in the United States has shown that relatively low rank coals can be productive and that the structurally simpler Alberta plains region is probably the more favorable part of the basin. However, much of the CBM work in this area has involved recompletion of depleted petroleum wells which may not be optimally located to maximize the important CBM parameters. Also, access to some of the more prospective CBM acreage has in the past been restricted by extensive petroleum leasing. Western Canada is the site of the Alberta Research Council's planned CO2-ECBM test at Fenn-Big Valley, about 120 km northeast of Calgary, which is scheduled to take place later during 1998. JAF98172.DOC 63 Advanced Resources International, Inc. IEAGreenhouseGaSR&D Programme - Worldwide COrECBM Assessment 6.3 Australia 6.3.1 Summary Australia is the only country, outside of the United States, to have achieved commercial production of coalbed methane from non-minable coal seams (although production is still very limited at less than 1% of U.S. levels). Vast CBM resources exist and many new projects are at various stages of exploration. Given the favorable market conditions, developed pipeline and other infrastructure, and a rational regulatory environment, Australian CBM production is likely to grow steadily in the years ahead. Recycling of vented industrial emissions, principally from coal-fired power plants, constitutes the primary source of carbon dioxide for potential ECBM recovery in Australia. Conventional natural gas fields located close to CBM areas tend to have low CO2 content and are not considered an important source. CO2 sequestration potential in high-graded areas is estimated at approximately 1,300 Mt. Australia's most prospective coal basins for CCVECBM recovery are the Sydney, Bowen and Clarence-Moreton basins located along the Pacific coast (Map 6-3). Several other basins have CBM potential (Gunnedah, Galilee, Cooper) but appear to have lower development potential and/or less favorable gas market conditions. Exhibit 6-3-1 provides an overview of the potential for CO2-ECBM recovery in Australia. Established markets for natural gas exist, particularly in the more populated and industrialized regions of eastern New South Wales (NSW) and Queensland. About three-quarters of gas demand comes from industry, the balance being split between commercial and residential use. NSW is supplied by a pipeline system originating in the mature conventional gas fields of the Cooper basin. Queensland receives gas piped from the dwindling Roma fields in the southern Bowen basin as well as from the Cooper basin; in addition, a small volume (11,000 m3/d) of CBM is produced from non-minable coal seams and fed into Queensland's distribution system. The average price in 1995 of gas delivered to industrial consumers was $0.15 and $0.21 per m3 ($4.30 and $6.00 per Mcf) in NSW and Queensland, respectively. Upward pressure on prices is expected to be exerted by supply limitations in the face of steady growth in demand. The Australian Bureau of Agriculture and Resource Economics predicts that gas supply to NSW will decline sharply after the year 2000 and that an annual supply shortfall of some 2 Gm3 may develop by 2004. The Australian Gas Association projects that, at current rates of gas supply, a shortfall will also develop in Queensland early in the next century. JAF98172.DOC 64 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COr-ECBU Assessment Exhibit 6-3-1: Australia Resource and Commercial ECBM Recovery Potential Recoverable ECBM (Gm3) 40 240 70 OLLJ COa Sequestration Potential (Mt) 150 870 260 Gas Market Good Developed Moderate CO2 Availability Good Moderate Fair Leasing/Testing Active Active Active Commercial Production None 41 None (Mm3/yr) (Mine drain: 260) (+Mine drain: 24) World Ranking (1-20) 15 JAF98172.DOC 65 Advanced Resources International, Inc.- ^S^Dat!6vh11 :llPJSI«s,5giiJ!S;^sf:!sSI::i:!.t ECBM Reserves: 240 Gm CO2Sequestration:870 Mt I^Jgockhampton ladstone :'r::Lt-ti?:tr^iii;;:::,';;^ii:i.'?^;y:5a;x;;~ar*!!;ks:sj;!-!-3:'ssix1'si-3!^!:: ::;V:;K s:::;:i:si:;;5;?' *5,.i.r,K!;x£', -*;•*; i ,: : s"?: --. \ -.1* !"^^--i^;-5!""-.;r^"Xi^ •" ".:;;;*-ii if.t.ix^z^r,'.;:/ j-'^iis^j1^ oO\\ j^. iKssijiJSjjjjiijK'KivjfjSj'ri'^iijjijjjjjjjj^jS^jj CLARENCE-MORETON Gunnedah ECBM Reserves: 70 Gm3 CO2 Sequestration: 260 Mt Greenhouse Gas R&D Programme ECBM Reserves: 40 Gm CO2 Sequestration: 150 Mt Natural Gas Pipeline CO2-ECBM Basins Other Coal Basins Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment 6.3.2 Resource Analysis Six major coal-bearing basins occur along a semi-continuous belt in eastern Australia (Map 6-3). These are the Sydney, Bowen, Clarence-Morerton, Galilee, Cooper and Gunnedah basins. The first three have been selected for analysis because they combine large CBM resources with a real potential for commercial CO2-ECBM recovery. The other basins are, on the whole, less prospective: the Galilee basin has low gas contents and lacks access to markets; well developed coal in the Cooper basin is too deep for feasible CBM production (> 2,000 m); and testing in the Gunnedah basin indicates reservoir problems, such as low permeability and undersaturation. SYDNEY BASIN Location and General. The Sydney basin covers a large area of almost 50,000 km2 in eastern New South Wales (Map 6-3). It is one of the world's major coal-producing regions, with numerous underground and surface mines (Hunter Valley, Newcastle, Southern and other coalfields) located towards the basin perimeter. The Sydney basin lies in the most densely populated part of Australia and infrastructure is highly developed. Data control within the basin is on the whole very good. A wealth of geological information is available over most of the basin, including the records of dozens of deep petroleum exploration wells and thousands of coal exploration boreholes. Regional- and local-scale geophysical surveys have been carried out. ARI performed a detailed evaluation of the Sydney basin for a private client in 1995. Coal Seam Geology (Ranking: 3). Virtually the entire Sydney basin is underlain by the well developed Illawarra Coal Measures and their regional equivalents, which are of Permian age. Individual seams 3 to 10m thick are common. Seam multiplicity and concentration are variable but gross coal thicknesses of 20-40 m are typical over a 200-300 m interval. Average completable coal thickness is around 15 m, while average prospective coal depth is in the 650-750 m range. Ash and moisture contents average 15% and 5%, respectively. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource is estimated to be 2,040 Gm3 (72 Tcf), with an average resource concentration of 170 Mm3/km2 (15.7 Bcf/mi2). This is a very large resource with attractive concentration. The prospective surface area is estimated at 15,000 km2, of which 12,000 km2 is assumed to remain non-minable for several decades. The contained coal resource — the amount of coal that would be contacted during CBM production and hence available for COa sequestration ~ is JAF98172.DOC 67 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment calculated at 190 Gt. However, environmental concerns and land-use conflicts are likely to reduce this effective area and resource potential by an as yet unknown factor. Coal rank is generally high-volatile bituminous. Vitrinite reflectance (0.7-1.3%) is highly favorable for CBM development. Seams are generally gas-saturated with an average gas content of 12 m3/t, except for degassing due to uplift in the western part of the basin. Methane content is usually over 90% but COa can be abundant locally. Producibility (Ranking: 3). It is estimated that technically recoverable gas resources ("potential reserves") in the Sydney basin are approximately 205 Qm3 (7.2 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using COa flooding could 3 add a further 40 Gm (1.4 Tcf). About 150 Mt ofCO2 could be permanently sequestered. The stress regime is one of mild to moderate compression. Dips tend to be low. In-situ stress measurements have been made across the basin to depths below 1,000 m and it is possible to identify regions of lower horizontal stress. Although permeabilities up to 10 md have been measured in coal at shallow depth, most values recorded below about 300 m are less than 1 md. However, many of these measurements were made in the Southern Coalfield, where relatively high stress combines with frequent mineralization of the cleats. Other areas have not been thoroughly tested. The Sydney basin coals tend to be moderately well cleated but there is usually some degree of cleat mineralization. BOWEN BASIN Location and General. The Bowen basin occupies an area of approximately 75,000 km2 in east-central Queensland (Map 6-3). It is Australia's largest coal-producing region with a predominance of surface mining. Except in the south, the basin is sparsely populated with limited infrastructure. Overall data control is moderate but varies across the basin. Borehole data are plentiful in the coal-mining districts while information at greater depth is available from petroleum exploration wells. Coal Seam Geology (Ranking: 3). Important coal-bearing sequences include the Moranbah and Rangal Fomations. Seams are relatively few in number but are commonly 2-10 m thick and tend to be laterally continuous. Gross coal thickness is typically 20-35 m over a 200- 300 m interval, of which an average of 15 m is completable. Average prospective coal depth is around 750-850 m. Ash and moisture contents average 15% and 5%, respectively. Prospective Gas-In-Place (Ranking: 4). A very large and attractive prospective gas- in-place resource is estimated at 2,940 Gm3 (104 Tcf), with an average resource concentration of approximately 134 Mm3/km2 (12 Bcf/mi2). JAF98172.DOC 68 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBMAssessment The prospective surface area is estimated to be 25,000 km2, of which 22,000 km2 is assumed to remain non-minable for many decades. The contained coal resource available for CO2 sequestration is calculated at 350 Gt Unlike the environmentally sensitive Sydney basin, there are likely to be fewer constraints to CBM development in the Bowen basin. The coal rank, which increases from west to east, is generally medium to low-volatile bituminous. Vitrinite reflectance is commonly greater than 1.0%. Widespread coking of coals by igneous intrusions has taken place in the northern part of the basin. Average gas content is estimated to be 10 m3/t and appears to be saturated in many areas. Methane content is usually close to 100%, except near intrusions where replacement of methane by CC*2 can occur within a radius of several kilometers. Producibttity (Ranking: 4). Technically recoverable gas, or potential reserves, is estimated to be 590 Gm3 (21 Tcf) using conventional pressure-depletion techniques. Enhanced 3 gas recovery using CO2 flooding could provide an additional 240 Gm (8.3 Tcf). About 870 Mt of CC*2 could be permanently sequestered. A mild to moderate compressive stress regime is overprinted in some regions with extensional tectonics (rifting) and pockets of favorable permeability exist. Gentle folding is prevalent over most of the basin interior. Clearing is moderately well developed, aided by medium vitrinite content. Few permeability measurements have been released but values in the 1- 10 md range could be expected in areas with favorable stress conditions. CLARENCE-MORETON BASIN Location and General. The Clarence-Moreton basin covers an area of about 40,000 km2 straddling the New South Wales - Queensland border (Map 6-3). Located close to Brisbane and other centers, the area possesses well developed infrastructure. Data control is good to moderate. Some 50 deep petroleum wells have been drilled, plus a large number of coal and other mineral exploration core holes. Gravity, magnetic and seismic data are also available. Coalbed methane exploration in the Clarence-Moreton basin is at an early stage and information from CBM tests has not yet been released. Coal Seam Geology (Ranking: 3). The CBM target formation is the Jurassic age Walloon Coal Measures, which underlies at least two-thirds of the basin and rarely exceeds 1,500 m in depth. Gross coal thickness from multiple seams ranges from 10 m along the basin edges up to 40 m towards the center in northern NSW. There are few seams more than 2 m thick. Average computable coal thickness is about 13 m. The average prospective coal depth is around 750-850 m. Ash and moisture contents average 15% and 5%, respectively. JAF98172.DOC 69 Advanced Resources International, Inc. ISA Greenhouse GasR&D Programme Worldwide COrECBMAssessment Prospective Gas-In-Place (Ranking: 2). The prospective gas-in-place resource is estimated to be 875 Gm3 (31 Tcf), with an average resource concentration of 117 Mm3/km2 (10.8 Bcf/mi2). The prospective surface area is estimated at 8,000 km2 mostly in the NSW portion of the basin. Almost all of this area (7,500 km2) is expected to be non-minable for several decades. About 100 Gt of coal resource is available for CO2 sequestration. Just as in the Sydney basin, environmental and land-use concerns could sterilize an undetermined fraction of prospective area in the Clarence-Moreton basin. The coal is high- to medium-volatile bituminous in rank. Vitrinite reflectance in the Walloon Coal Measures increases west to east from 0.6% to 1.8%, which is a range favorable for CBM development. Gas content data are not available but an average value of 9 m3/t is inferred. The degree of gas saturation is not known. Methane content is expected to be around 95%. Producibility (Ranking: 4). It is estimated that, using conventional pressure-depletion methods, around 175 Gm3 (6.2 Tcf) is technically recoverable. An extra 70 Gm3 (2.5 Tcf) could be oGtained by application of COa-ECBM recovery techniques. About 260 Mt of CC^ could be sequestered in the process. The basin has a history of tensional tectonics, continuing to the present, that is expected to result in a relatively low stress regime which favors cleat dilation and permeability enhancement. Dip angle is favorably low, averaging about 5°. No permeability measurements are available but the favorable stress regime and vitrinite-rich coal could place seam permeability in the 2-10 md range. JAF98172.DOC 70 Advanced Resources International, Inc. 1EA Greenhouse Gas R&D Programme Worldwide COi-ECBMAssessment Exhibit 6-3-2: Australia Technical ECBM Recovery Potential ItiraJlilffiraftWIM1! ' 1 ''ifeplWjWffltt I'iSS^Jiffill || Prospective Basin Area (km2) 12,000 22,000 7,500 Coal Resource (Gt) 190 350 100 Gas-In-Place (Gm.3) 2,040 2,940 875 GIF Cone. (MnrVkm2) 170 134 117 Technically Recoverable CBM 205 590 175 (Gm3) Technically Recoverable 40 240 70 3 CO2 -ECBM (Gm ) CO2 Sequestration Potential 150 870 260 (Mt) 6.3.3 Economic Analysis The costs of CBM development in Australia are likely to be much higher than in the U.S., as is the situation with conventional oil & gas development costs. In CBM test programs conducted to date in Australia, labor costs and restrictions on efficiency have increased drilling and completion costs by typically 50% compared with U.S. costs, while tighter environmental restrictions also raise costs considerably. The onshore market for petroleum equipment and services is much smaller than in the U.S., resulting in less competition and fewer economies of scale. SYDNEY BASIN Development Cost (Ranking: 3). Based on about a dozen CBM test wells drilled in the Sydney basin, development costs for a commercial CBM project are likely to be higher than in the U.S. We anticipate that the costs of developing and operating a large ECBM program in the Sydney basin would be approximately 50% higher than those of the San Juan basin standard. Coalbed Methane Market (Ranking: 4). The CBM resources of the Sydney basin lie in the most urbanized and industrialized part of Australia. Sydney and the industrial cities of Newcastle and Wollongong are currently major gas markets but there are also several smaller markets. In addition, potential markets exist for dedicated, on-site CBM supply to power and other industrial plants in more isolated regions. JAF98172.DOC 71 Advanced Resources International, Inc. JEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment Industry accounts for about 70% of natural gas purchases in New South Wales, with the remainder evenly split between commercial and residential customers. The average price in 1995 of gas delivered to industrial, commercial and residential consumers was $0.15, $0.28 and $0.37 per m3, respectively. Current gas supply is from mature conventional fields in the Cooper basin, South Australia. The Moomba-Sydney-Newcastle pipeline traverses the Sydney basin (Map 6-3). The Australian Bureau of Agriculture and Resource Economics (ABARE) predicts annual gas supply to NSW levelling off at around 3.1 Gm3 in the 1990s, followed by a steep decline after 2000. At the same time, demand is projected to show steady growth. ABARE expects a supply shortfall to develop by the end of the century which may reach 2.0 Gm3 in 2004. Carbon Dioxide Availability (Ranking: 4). Industrial emissions represent the main source of vented CCb available for ECBM recovery in the Sydney basin. Most of the region's electricity is generated in coal-fired power plants concentrated in the major coalfields. Since these power plants are frequently located a few tens of kilometers at most from the CBM resources, they are well suited to a COa sequestration program involving ECBM recovery. Carbon dioxide constitutes about 18% of the raw natural gas treated at the Moomba plant in the Cooper basin. At current levels of methane sales (5 Gm3/year), about 1.3 Gm3 of vented CO2 could be available for ECBM if a pipeline were constructed. BOWEN BASIN Development Cost (Ranking: 4). Cost data on over 20 CBM test wells drilled in the Bowen basin indicate that development costs for a commercial CBM project are likely to be higher than in the U.S. Environmental and land-use restrictions on CBM will probably be less severe than in the Sydney basin. We anticipate the costs of developing and operating a large ECBM program in the Bowen basin to be approximately 25% higher than those of the San Juan basin standard. CoalbedMethane Market (Ranking: 4). The market for Bowen basin CBM would principally be in the Brisbane area of southeastern Queensland, with demand also coming from other coastal cities such as Gladstone and Rockhampton. Additional markets could exist for on- site electricity generation in remote areas. About 85% of gas demand in Queensland is for industrial use. The average price of natural gas delivered to industrial consumers was $0.21/m3 in 1995. Until recently, Queensland's gas demand was supplied from the Roma field, near Wallumbilla in the southern Bowen basin, via pipelines to Brisbane and the Gladstone- JAF98172.DOC 72 Advanced'Resources International, Inc. JEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment Rockhampton area. The dwindling reserves at Roma (remaining life of 6 years) were supplemented in 1997 by about 1,220 Mm3/year flowing through a new pipline connecting the existing system to the Cooper basin fields at Ballera in southwestern Queensland. The Australian Gas Association projects that demand from existing customers will rise to 1,250 Mm3/year by the year 2000, and to 1,400 MmVyear if potential new markets are factored in. These figures suggest that, barring much stronger delivery from the Cooper basin, a supply shortfall could develop early in the next century. Carbon Dioxide Availability (Ranking: 3). Industrial emissions represent the best source of vented CO2 available for ECBM recovery. Queensland's electricity is generated by coal-fired power plants, many of which are located close to CBM resources and are hence well placed for COj-ECBM recovery. As described earlier, the Cooper basin gas fields generate about 1.3 Gm3 of by-product COa annually but there is no pipeline. The Roma gas field is much closer to the CBM resources of the Bowen basin but cannot be considered a long-term source of carbon dioxide. CLARENCE-MORETON BASIN Development Cost (Ranking:3). Although a few CBM test coreholes have been drilled in the Clarence-Moreton basin, no CBM production wells have as yet been completed and we do not have cost data specifically for this basin. However, we expect that developing and operating costs for a commercial ECBM project will be comparable to those of the Sydney basin, which would be approximately 50% higher than those of the San Juan basin standard. Coalbed Methane Market (Ranking: 3). The principal market for Clarence-Moreton basin CBM is Brisbane and the rapidly expanding Gold Coast region of SE Queensland. On-site electricity generation is also a possibility. The Roma-Brisbane gas pipeline passes through the northern part of the basin, about 150 km north of the prospective area. Future gas demand, gas prices and other market information in this region were provided in the discussion of the Bowen basin. Carbon Dioxide Availability (Ranking: 2). Availability of carbon dioxide for CO2- ECBM recovery in the Clarence-Moreton basin is limited. There is relatively little industry in the prospective area which could supply flue-gas, nor is there any ready source of natural CO2. JAF98172.DOC 73 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Exhibit 6-3-3: Australia Commercial ECBM Recovery Potential Gas Market Ind., com. & res. in Industry in Brisbane Industry in Sydney and other and other SE Qld. Brisbane and other NSW centers centers SE Qld. centers C02 Availability Industrial emissions, Industrial emissions, Limited industrial esp. coal-fired power esp. coal-fired power emissions plants plants 6.3.4 Coalbed Methane Exploration and Production SYDNEY BASIN The Sydney basin was the focus of some of the earliest CBM exploration and testing outside of the United States. The presence of thick, gassy coal seams was verified and around 50 CBM test coreholes were drilled between 1981 and 1995. Some wells reportedly produced over 2,800 mVday (100 Mcf/day) during several months of testing, although this production rate would still be sub-commercial given local gas prices and development costs. Much of the exploration effort has been centered on the Southern Coalfield, drawn by methane control problems within deep mines in this area. However, success has been limited by poor coal seam permeability due to the high stress regime and cleat mineralization in this region. As a result, exploration activity has diminished in recent years, leaving the rest of the basin largely untested. Nevertheless, there are recent indications of renewed interest in other parts of the Sydney basin. Most of the basin is currently under lease for CBM, apart from the degassed western margin. Methane is currently being produced from the mine workings at BHP's Appin and Tower collieries in the Southern Coalfield where it is used to generate electricity on a small scale for on- site use and sale to the regional power grid. Figures have not been released but industry estimates places output at 710,000 m3 (25 MMcf) per day. While such methane drainage operations are not candidates for C02-ECBM recovery, because any sequestered C02 would soon be liberated by subsequent mining, they are encouraging signs that CBM technology is in place and that good market conditions exist in the Sydney basin. JAF98172.DOC 74 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment BOWEN BASIN The Bowen basin has experienced more CBM exploration than any other Australian coal basin, and is the only basin outside the U.S. to have achieved commercial production of gas (other than methane drainage from mines for safety purposes). Testing continues apace and nearly all areas with coal of suitable depth for CBM development are currently under lease. At least 50 production test wells and many more slim-hole exploration coreholes have been drilled to date. Conoco began selling CBM gas at the end of 1996 from 31 wells near Moura, via a 35 km connector into the Roma-Gladstone/Rockhampton gas pipeline. Combined output is about 113,000 mVday. Additional exploration wells are being drilled and tested. BHP has drilled 14 production wells between its Moura coal mine and Conoco's lease, and has completed a study to investigate using CBM for the manufacture of 140,000 tonnes per annum of ammonium nitrate. This would complement BHP's in-mine methane drainage operations which release 65,000 m3/day from the Moura mine into the Roma- Gladstone/Rockhampton gas pipeline via a 21-km connector. Tri-Star Petroleum was expected in late 1997 to begin flowing 106 Mm3/year for 15 years into the Roma-Brisbane pipeline from its Fairview field north of Wallumbilla. CLARENCE-MORETON BASIN Exploration for CBM in the Clarence-Moreton basin commenced in 1993. A large part of the basin was at one point under lease but interest is now concentrated in the central part of the basin, near the town of Lismore, NSW. Drilling continues but no test results have yet been made public. Activity ceased in Queensland due to poorly developed coal seams and the prevalence of igneous intrusions. JAF98172.DOC 75 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment 6.4 China 6.4.1 Summary Two coal regions in China have significant potential for CO2-ECBM: the Ordos basin in north-central China and the Northeast China coal region in east-central China (Map 6-4). Preliminary CBM exploration testing has been conducted in each of these basins, with some encouraging results. Government support of CBM development has been strong. Large industrial CO2 sources are located within the NE coal region, as are natural C02 deposits. Gas pipelines and markets are limited but expanding. Overall, China has good potential for CO2- ECBM application. Exhibit 6-4-1 provides an overview of the potential for CO2-ECBM recovery in the Ordos basin and the NE China coal region. Exhibit 6-4-1: China CBM Resource and Commercial ECBM Recovery Potential ^SMsS^S^kM n^mM^ Recoverable ECBM 180 5.5 i (Gm3) UJQ CO2 Sequestration 660 21 Potential (Mt) -< i Gas Market Fair Good CO2 Availability Poor Good Leasing/Testing ARCO, Phillips, Texaco TIVIT Y POTENTIA L CB M COMMERCI / Amoco < Commercial Production None (MnrVyr) None (Mine drainage: 600) World Ranking (1-20 ) 13 12 Of the two basins, the Ordos has better technical potential for CO2-ECBM recovery, and is the focus of aggressive exploration testing by U.S. major oil companies (ARCO, Phillips). However, it is located far from existing natural gas markets and lacks large industrial and reservoir sources for CO2. JAF98172.DOC 76 Advanced Resources International, Inc. isSssfc^SiBjlS: JSSslte? ECBM Reserves: 180 Gm NE CHINA CO,Sequestration: 660 Mt COAL REGION ECBM Reserves: 5.5 Gm3 CO,Sequestration: 21 Mt !!SK:««SiMs:»:s^:K;iK,feg|fe,!^ts^«^jis!sa:'sss-iiS!BK! S'lS.VSrr*X,!:£!3SSF!S3g&SiSSSSr. "Si.HSS£i.'--ir-r-'ksKK\i!SS:: IEA Greenhouse Gas R&D Programme CO, - ECBM Potential of China Natural Gas Pipeline CO,-ECBM Basins Advanced Resources International, Inc. JAF00939.CDR ISA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment The Northeast China coal region -- comprising a number of small to medium sized coal fields that account for most of China's coal production -- is better situated to potential natural gas markets and CO2 sources. However, CBM testing results to date throughout this region generally have been discouraging. Numerous other coal basins exist in China, but appear to have lower potential or are less well documented. CO2 sequestration potential for high-graded ECBM areas these two coal regions is estimated at approximately 680 Mt. NE China has a dearth of natural gas supplies, and the government has recognized the need to develop natural gas resources (including CBM) to reduce the country's heavy reliance on coal for primary energy. Most coal production is from deep underground mines which frequently are gassy and prone to accidents. A new government organization, China United Coalbed Methane Corporation, was formed in 1996 to administer CBM leasing and development. Several Chinese service companies have begun to acquire CBM production technology, and a degree of competition is developing within this market. Two major new gas pipelines were completed in 1997 linking conventional gas fields in the Ordos basin with the Beijing and Xian urban markets. These and other factors are expected to encourage commercial production of CBM from the Ordos and NE China basins during the next decade. Separately, China recovers and utilizes a total of approximately 1.6 MmVday (58 MMcfd) of low calorific value coal-mine methane from gassy mines, mostly for safety purposes in NE China (Zhang et al, 1996). However, this amounts to only 1% of San Juan basin CBM production on an energy-equivalent basis; expansion potential of coal-mine methane is limited. 6.4.2 Resource Analysis China ranks first in world coal production and has one of the largest in-place CBM resource bases (16,000 to 35,000 Gm3; 560 to 1,200 Tcf; Zhang and Zhang, 1995). The most prospective regions for CBM development are the Ordos basin and the Northeast China coal region. Vast additional coalbed methane resources are contained in coal fields within Sichuan, Hunan, and Guizhou provinces in the south; Qinghai and Xinjiang in the west; and Heilongjiang, northeast Inner Mongolia, and Jilin in the far northeast. However, the latter appear to hold less promise for commercial CO2-ECBM recovery due to the combined effects of poor producibility and market accessibility, limited sources of carbon dioxide, and high development costs. ORDOS BASIN Location and General The large (250,000-km2) Ordos basin stretches across the provinces of Shared, Shaanxi, Ningxia, and Inner Mongolia in north-central China (Map 6-4). The city of Xian at the south end of the basin is a light industrial center, while Baotou in the north is a center for steel-making and other heavy industries. Most of the basin is too deep or high-rank JAF98172.DOC 78 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment for CBM development. The prospective CBM area extends in an arc approximately 1,000 km long along the northeast, east and southeast edge of the basin, with total area still extensive at an estimated 20,000 km2. Infrastructure, including basic roads and communication, within this area is poorly developed. Data control is fair, but better near coal mine development areas. Coal Seam Geology (Ranking: 4). The coal-bearing sequences are the Permo- Carboniferous Shanxi and Taiyuan Formations containing multiple but relatively concentrated coal seams frequently thicker than 2 m. Completable coal thickness averages 12 m out of a gross thickness of around 25 m. The average prospective coal depth is 1,000 m. Ash and moisture contents average 20% and 5%, respectively. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource is estimated to be 2,220 Gm3 (78 Tcf), with an average resource concentration of 123 Mm3/km2 (11 Bcf/mi2). This is a very large resource with a favorable concentration. Coal mining in the Ordos basin is a relatively recent development, with major investment arriving only since the 1980s. Most mines are surface or moderately shallow underground mines (<300 m). We anticipate that only about 10% of the 20,000-km2 surface area will be affected by mining during the medium- to long-term, leaving a total surface area for CC>2 sequestration of about 18,000 km2. The contained coal resource available for CO2 sequestration is calculated to be 218 Gt (dry, ash-free basis). Coal rank increases regionally from sub-bituminous in the northeast Ordos to high-volatile bituminous in the east, attaining low-volatile bituminous to semi-anthacite rank in the south near Xian. Coal rank also increases with depth within the basin. Gas content in the Ordos varies considerably with rank and depth, averaging about 11 m3/t; most areas appear to be gas saturated. A methane content of at least 95% is estimated. Producibility (Ranking: 4). Technically recoverable CBM in the Ordos basin is estimated at approximately 445 Gm3 (16 Tcf), using conventional pressure-depletion techniques. Application of COa-ECBM recovery could increase methane recovery by about 180 Gm3 (6.4 Tcf). Approximately 660 Mt of CO2 could be permanently sequestered in the Ordos basin if ECBM was fully applied. The stress regime in the Ordos basin is apparently low, as is structural dip into the basin's center. The coal is well cleated. Faulting is minimal with good reservoir continuity and lateral communication. No permeability data are publicly available but values are estimated to average in the range of 1 to 10 md. The producibility of the Ordos CBM resource is expected to be much better than that of NE China. JAF98172.DOC 79 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide CO i-ECBM Assessment NE CHINA COAL REGION Location and General. The NE China coal region is an informal grouping of isolated coal fields of varying size in east-central China, These basins contain Permian coal that is broadly correlative with Ordos basin coal sequences, but are individually much smaller due to subsequent tectonic disturbance. The NE China coal region stretches across the provinces of Shanxi, Hebei, Henan, Anhui, Shandong, and Jiangxi and comprises several dozen individual coal fields (Map 6- 4). A number of major cities are located within this region, including Beijing in the northeast, Taiyuan in the north, Zhengzhou in the center and Shanghai in the southeast. The area's economy includes considerable coal mining, heavy and light industry, as well as intensive agriculture. NE China's largest individual basin is the Qinshui basin in Shanxi province, with gross area of approximately 10,000 km2. However, coal seams in the Qinshui basin are primarily of semi-anthracite to anthracite rank, which is too mature for CBM development, or are too deep. A low-volatile bituminous area exists near Luan with a prospective area (300 to 1,500 m depth) of about 1,000 km2. Most of the other coal fields in NE China are similarly small (100 to 2,000 km2), notably Huainan and Huaibei coal fields in Anhui province; Pingdingshan, Jiaozuo, and Zhengzhou in Henan province; Tangshan in Hebei province; among numerous others. Although gross area is much larger, the total coal basin area prospective for CBM development is estimated at approximately 15,000 km2. Data control for CBM evaluation is good across this area, including primarily coal exploration corehole data but also some early CBM reservoir test information. Coal Seam Geology (Ranking: 3). The main coal-bearing formations are the Permian and Carboniferous Shanxi, Taiyuan, and Shihezi Formations. As in the adjacent Ordos basin, multiple but relatively concentrated seams make up an average of about 20 m of gross coal thickness inNE China, with individual seams moderately thick at 1.0-4.0 m. Completable coal is estimated to be 10 m at an average depth of 900 m. Ash and moisture contents average 15% and 4%, respectively. JAF98172.DOC 80 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBMAssessment Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource in the NE China coal region is estimated to be 1,110 Gm3 (40 Tcf), with an average resource concentration of 111 Mm3/km2 (10 Bcf/mi2). This is a large and relatively concentrated resource. Unfortunately, as previously mentioned, the resource is distributed amongst a number of small to medium-sized coal fields rather than in a continuous belt as in the Ordos basin, which complicates development. The prospective surface area of NE China is estimated at approximately 15,000 km2, of which around 10,000 km2 in the deeper portions of the basin is assumed to remain non-minable for several decades. The contained coal resource available for CO2 sequestration is calculated at 109 Gt (dry, ash-free basis). Coal rank is predominantly medium- to low-volatile bituminous, with substantial high- volatile bituminous and anthracite coal also present. Since most mines are extremely gassy, methane levels are closely monitored. Gas contents across the coal fields average about 11 m3/t but undersaturation is an occasional problem in this area of uplift and prior degassing (a major Permian-Quaternary unconformity is ubiquitous at the top of the coal section). Methane content is around 95% with low CO2 levels. Producibility (Ranking: 2). Despite the attractive CBM resource in the Northeast China coal region, producibility of this resource is likely to be poor due to low permeability and fault compartmentalization. It is estimated that technically recoverable gas (potential reserves) is on the order of 55 Gm3 (1.9 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using CC«2 flooding could raise this by an estimated 5.5 Gm3 (0.2 Tcf), while permanently sequestering about 21 Mt of C02. Exhibit 6-4-2: China Technical ECBM Recovery Potential 1!flgiiiti&tti iiii^iiiiiii Prospective Basin Area (km2) 18,000 10,000 Coal Resource (Gt) 220 110 Gas-In-Place (Gm3) 2,220 1,110 GIF Cone. (Mm3/km2) 123 111 Technically Recoverable 445 55 CBM (Gm3) Technically Recoverable 180 5.5 3 CO2-ECBM(Gm ) CO2 Sequestration Potential 660 21 (Mt) JAF98172.DOC 81 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Moderate to steep dips, which can exceed 35 degrees, attest to a past compressive stress regime, although the current Neogene tectonic setting is extensional. Coal cleats are well developed, but mineralization is a local problem. Permeability has tested low, generally from less than 0.1 md to about 1 md, which would be subcommercial. Faulting is pervasive and of large throw, causing severe compartmentalization of the coal reservoir into small blocks that would be inappropriate for ECBM operations. 6.4.3 Economic Analysis China has a fairly mature onshore oil and gas industry, but as there is no CBM production or service industry for ECBM projects, development costs are expected to be higher than in the San Juan basin. Futhermore, most coal field and CBM resources are located far from existing petroleum centers and mobilization is costly. Costs for ECBM development are expected to be high, but could fall rapidly with the government emphasis on technology transfer and the relatively streamlined environmental approval process. On the other hand, natural gas markets in China are growing rapidly from low utilization levels and there is significant demand potential, including gas-fired power generation and urban and industrial use. Natural gas still accounts for only 2% of China's primary energy supply but is expected to grow from current levels of about 60 Mm3/day (2.0 Bcfd). ORDOS BASIN Development Cost (Ranking:3) Approximately 50% higher than San Juan basin costs for a large-scale project, due to remoteness from existing petroleum supply centers and to poor infrastructure and rugged topography. Coalbed Methane Market (Ranking: 2). The Shaanganning conventional natural gas field in the central Ordos basin has over 200 Gm3 (7 TCI) of proved gas reserves. Two new pipelines were completed during 1997 to bring this gas to market (Map 6-4): once fully operational, the Ordos-Beijing pipeline will transport 4.1 MmVday (145 MMcfd), while the Ordos-Xian pipeline will flow 2.1 MmVday (73 MMcfd) of natural gas. The small size of these pipelines relative to proved reserves in the Shaanganning field means that CBM will have a difficult time competing with low-cost conventional natural gas. Most likely, new gas pipelines would be required to transport CBM out of the Ordos basin, possibly to Taiyuan city in Shanxi province. Carbon Dioxide Availability (Ranking: 2). The Ordos basin is not an. area that is rich in natural reservoir CO2 (Dai etal, 1996). Furthermore, industrial emissions of C02 in the sparsely JAF98172.DOC 82 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment populated area of the eastern Ordos basin are limited, particularly compared with the NE China coal region. NE CHINA COAL REGION Development Cost (Ranking: 4). Approximately 25% higher than San Juan basin costs for a large-scale project. Many mature petroleum fields and experienced Chinese service companies are located within this area. Some units have U.S. CBM testing equipment and considerable well testing expertise. These units are starting to compete for foreign service and equipment contracts in CBM development. Coalbed Methane Market (Ranking: 4), Favorable market conditions exist for CBM hi NE China. Several hundred million people live in this relatively industrialized region, and some of China's largest cities are located there (Beijing, Tianjin, Shanghai, etc.). Coal currently accounts for the bulk of primary energy production in NE China, resulting hi considerable air pollution. The Beijing-Tianjin corridor alone has large estimated natural gas demand (in excess of 14 MmVday; 500 MMcfd), as do many other urban areas. Existing long-distance pipeline infrastructure is limited to the Ordos-Beijing and Ordos-Xian pipelines, but most cities hi the region have reticulation systems for low calorific value coke-oven gas. Carbon Dioxide Availability (Ranking: 4). Anthropogenic C02 emissions from heavily industrialized urban areas (Beijing, Zhengzhou, Taiyuan, Xian and many other cities) is available in close proximity to CBM resources within the NE China coal region. In addition, the NE China region is rich in natural gas deposits with high CO2 concentrations (>90%), particularly within extensional basins along the Tanlu Fault stretching from near Nanjing to Harbin (Dai et al., 1996). However, these carbon dioxide resources have not yet been developed on a large scale for EOR operations and no COa pipelines are known to have been constructed. Exhibit 6-4-3: China Commercial ECBM Recovery Potential Gas Market Long-distance pipeline to Nearby cities and Beijing, Xian, Taiyuan industrial users CO2 Availability Limited coal-fired Coal-fired industrial emissions; industrial emissions Natural CO2 reservoirs JAF98172.DOC 83 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment 6.8.4 Coalbed Methane Exploration and Production China has been one of the most active countries for coalbed methane exploration and production testing. However, testing remains at an early phase and commercial production of CBM has not yet been achieved (apart from small coal-mine methane recovery and utilization). Testing has been conducted by both Chinese and foreign companies. The Chinese E&P effort is currently being led by China United Coalbed Methane Corporation. However, units of the Ministry of Geology and Natural Resources, the Ministry of Coal Industry, and China National Petroleum Company, and others have all been active and continue to conduct CBM testing. An estimated total of more than 100 CBM test coreholes and production wells have been drilled by the Chinese government throughout the country during the past decade, focusing on NE China and the Ordos basin. The most encouraging project to date has been MGMR's Liulin pilot in the eastern Ordos basin, where gas production wells have averaged 1,400 to 7,100 m3 (50 to 250 Mcfd) per well. Foreign operators have drilled an nearly 20 test coreholes and production wells to date in China. Enron Exploration drilled 8 test coreholes and 3 production wells in China during the period 1992-1996, testing CBM reservoir properties in four different coal basins. Enron reported encouraging results from cavitated production wells in the eastern Ordos basin. ARCO purchased Enron's concession in late 1996 and has drilled several additional test coreholes. Phillips has drilled one test corehole in the northeastern Ordos basin and plans additional drilling during 1998; Amoco drilled one test corehole in the southeastern Ordos basin but has suspended operations. Lowell Petroleum and Shell drilled and fracced three production wells in the eastern Ordos. Finally, Texaco, which has obtained the first formal production sharing contract for CBM in China, plans to drill 4 test coreholes at Huaibei coal field in the NE China coal region later during 1998. Most results from these reservoir testing programs remain confidential. JAP98172.DOC 84 Advanced Resources International, Inc. JEA Greenhouse Gas R&D Programme Worldwide COrECBUAssessment 6.5 Indonesia 6.5.1 Summary Indonesia (Sumatra) is a top-ranked area for CO2-ECBM recovery and carbon dioxide sequestration. Coalbed methane resources, CO2 sources and market conditions are all highly favorable. Total C02 sequestration potential is estimated at approximately 1,100 Mt. However, CBM development in Indonesia is at a very preliminary (planning) stage. Commercial application of ECBM using CO2 will require development of a viable production industry, which could take one or more decades. Indonesia's most prospective coal basins for CO2-ECBM recovery are located in eastern Kalimantan and southern Sumatra (Map 6-5). Exhibit 6-5-1 provides an overview of the potential for CO2-ECBM recovery in Indonesia. Exhibit 6-5-1: Indonesia Resource and Commercial ECBM Recovery Potential |g*pM$Sff" jp!^wi«oiosiiis 3 0< Recoverable ECBM (Gm ) 230 68 §z C02 OuJ w\- Sequestration Potential (Mt) 850 250 UIQ •831 Gas Market Poor Good 0< ££ C02 Availability (MnvVday) Poor Good (3.6) ig Leasing and Testing None None II Commercial Production None None (Mm3/yr) Overall Ranking (1-20) 15 8 JAF98172.DOC 85 Advanced Resources International, Inc. SUMATRA Kilometers 1000 ECBM Reserves: 100 Gm3 KALIMANTAN 3 CO2 Sequestration: 370 Mt ECBM Reserves: 330 Gm CO2 Sequestration: 1,200 Mt Duri Steamflood n xxxxtx*M***rxirxtr*xx xjx, +t * IEA Greenhouse Gas R&D Programme CO2 - ECBM Potential of Indonesia Natural Gas Pipeline £| CO2-ECBM Basins I N D O N ML Advanced Resources International, Inc. JAF00942.CDR JEA Greenhouse Gas R&D Programme Worldwide COi-ECBMAssessment While the two regions are equally very attractive from the resource point of view, Sumatra holds a far greater potential for commercial C02-ECBM recovery. A defined market for methane exists at Caltex Pacific Indonesia's Duri heavy-oil steamflood operation in north-central Sumatra. A pipeline is under construction between Duri and Asamera's Corridor conventional gas field (140-280 Gm3 of reserves) 540 km to the south in the South Sumatra basin. Corridor is expected to satisfy only about two-thirds of Duri's gas requirements, placing CBM hi a strong position to capitalize on the demand shortfall. Furthermore, the Corridor field contains on average 30% carbon dioxide and could generate about 3.6 MmVday for use in a CO2-ECBM recovery operation. Adding compression to the Corridor-Duri pipeline could more than double methane and CO2 production. In addition, the Natuna Island conventional gas discovery located 850 km northeast of the Sumatra CBM areas in the South China Sea, when developed by Exxon and other partners, could constitute one of the largest anthropogenic CO2 sources in the oil & gas industry. Carbon dioxide 3 accounts for about 70% of Natuna Island's total 4,530 Gm gas reserves, and CO2 production rates could reach 30 Mm3/day. Current plans are to re-inject waste COa into the reservoir, but a pipeline conceivably could be constructed to bring this gas to the Sumatra coal fields for ECBM. In Kalimantan, very limited potential CBM markets exist for electricity generation or for industrial consumption in a few centers. Possible sources of CO2 include small levels of industrial emissions and a LNG plant processing natural gas from conventional fields, but natural CO2 levels are much lower than in Sumatra. Most importantly, the lack of pipeline infrastructure or plans, and the glut of conventional natural gas production are likely to inhibit development of CBM in Kalimantan. 6.5.2 Resource Analysis KALIMANTAN Location and General. Eastern Kalimantan, on the Indonesian portion of the island of Borneo, contains a very large coal resource consisting of thick, low-rank sub-bituminous coal. Eastern Kalimantan comprises several contiguous and geologically similar coal basins, including the Kutei basin (100,000 km2) in E. Kalimantan, Barito basin (60,000 km2) in S.E. Kalimantan and Tarakan basin (26,000 km2) inN.E. Kalimantan (Map 6-5). Eastern Kalimantan has experienced rapid growth in coal mining since the 1980s and has helped to establish Indonesia as a major coal producer and exporter. The lion's share of coal production comes from the coastal area of the Kutei basin, but mines are also located in the east Barito and south Tarakan basins. There is mining in the Pasir and Asem Asem basins, in the extreme southeast of the island, but this area is not considered to be prospective for CBM. JAF98172.DOC 87 Advanced Resources International, Inc. 1EA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment The region hosts a number of oil and gas fields, particularly in the Kutei basin coastal zone and offshore. Apart from the coal mines and petroleum fields, industrial activity is mainly concentrated around the cities of Banjarmasin, Balikpapan and Samarinda. Infrastructure is poorly developed across much of the region. During 1997, ARI performed a confidential evaluation of Indonesia's CBM potential for a private client. Detailed geologic and analytical data are provided by (proprietary) deep petroleum exploration wells and seismic, and by coal mining activity. Overall, data control can be described as fair, although there is a range from poor to good across the region. Coal Seam Geology (Ranking: 3). Coal is best developed in the Late Tertiary formations which are broadly correlatable across the region. Local formation names include Warukin, Prangat, Tabul, Latih and others. Multiple coal seams are dispersed throughout these formations. Seams 3-7 m thick are common although thicknesses up to 50 m have been reported. The gross coal thickness is typically in the 40-70 -m range, of which 20 m is completable on average. The average prospective coal depth is 700-800 m. Ash contents are fairly low at around 10%, while the moderately high moisture content (15%) reflects fairly low coal rank. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource in Kalimantan is estimated to be approximately 2,830 Gm3 (100 Tcf), with an average resource concentration of 95 Mm3/km2 (8.7 Bcf/mi2); this is an extremely large resource by international CBM standards. The prospective surface area is estimated at 30,000 km2. Since coal is mined entirely by open pit, and large, shallow reserves have been blocked out, it is expected that the CBM resource in the whole of the prospective area will remain effectively non-minable for many decades. The contained coal resource — the amount of coal that would be contacted during CBM production and hence available for CO2 sequestration — is calculated at 590 Gt. Coal rank at surface is sub-bituminous to high-volatile bituminous. Gas contents have not been measured in these or other Indonesian coals. However, strong methane kicks directly associated with coal seams have been recorded in the mud gas logs of petroleum wells, indicating that the coals are mature enough to be gas-bearing. Based on coal seam rank and depth, the gas content is estimated at 5 m3/t. Analyses of produced gas show that it is composed predominantly of methane ~ 95% is assumed; the non-methane portion generally is made up of other hydrocarbons with low CO2 levels. JAF98172.DOC 88 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment Producibility (Ranking: 4). It is conservatively estimated that technically recoverable gas, or potential reserves, in Kalimantan are of the order of 570 Gm3 (20 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using CO2 flooding could raise this by 230 3 Gm (8 Tcf). About 850 Mt of CO2 could be permanently sequestered. The stress regime is relaxed through most of the region, with the possible exception of transpression in the far north (Tarakan basin). The Barito basin is largely undeformed except in the north and at its eastern edge along the Meratus thrust zone. Gravity-induced folding in the Kutei basin has generated narrow, relatively steep anticlines separated by broad, gently dipping synclines which would be favorable sites for CBM development. No direct coal seam permeability measurements have been performed in Kalimantan (nor elsewhere in Indonesia). Cleating is not clearly described but is likely to be poorly developed compared with higher rank coals. However, vitrinite content in parts of the Kutei and Tarakan basins is high, which would promote cleat development. Based on this information, and the generally favorable stress regime, we estimate high-graded permeability to be in the range of 1-5 md in east Kalimantan. SUMATRA Location and General After Kalimantan, Sumatra contains the next most important coal resouces in Indonesia. Indonesia's most important coal mining district (Bukit Asam mines) is centered around the town of Muara Enim in southern Sumatra. The southern half of the island includes two adjacent and geologically similar coal basins: the South Sumatra basin (100,000 km2) and the Central Sumatra basin (80,000 km2), shown on Map 6-5. There are several large petroleum fields, mainly oil, in each basin. The main industrial centers are Palembang, Jambi, Padang and Pakanbaru. Infrastructure is moderately to poorly developed. Detailed geologic and analytical data are provided by deep petroleum exploration wells and seismic, and by coal mining activity. Data control is good in the South Sumatra basin and fair in the Central Sumatra basin. Coal Seam Geology (Ranking: 4). The main coal-bearing formations are the correlative Late Tertiary Muara Enim Formation in the South Sumatra basin and the Korinci Formation in the Central Sumatra basin. Coal is better developed in the South Sumatra basin, where some of the thicker seams have been followed for over 50 km. Multiple seams are present in both formations, but the Muara Enim frequently has concentrated groups of seams whereas the Korinci seams are more dispersed. JAF98172.DOC 89 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBMAssessment Individual seams 3 to 8 m thick are common in the South Sumatra basin, with a maximum of 35 m; in the Central Sumatra basin the seams are generally less than 4 m thick. Gross coal thickness ranges between 30 and 65 m, with computable coal averaging an estimated 23 m for the region (30 m in South Sumatra and 16 m in Central Sumatra). The average prospective coal depth is 600-700 m, and ranges from outcrop down to the assumed maximum 1,500-m cutoff for CBM development. Ash content is fairly low (10%) but the moisture content is moderately high (20%) due to the low rank of the coal. Vitrinite content can be relatively high (70%). Prospective Gas-In-Place (Ranking: 5). The prospective gas-in-place resource in Sumatra is calculated to be 3,400 Gm3 (120 Tcf), with an average resource concentration of 106 Mm3/km2 (9.8 Bcf/mi2). This, too, is an extremely large resource by world standards. The prospective surface area is estimated to be 32,000 km2. Here, as in Kalimantan, coal is mined entirely by open pit and there are large, shallow reserves. It is therefore expected that the CBM prospective area will remain effectively non-minable for many decades because it is much deeper than currently targeted coal reserves. The contained coal resource is calculated at 680 Gt. Coal rank at surface is generally lignite to sub-bituminous. Rank may be locally ameliorated to bituminous or higher in the proximity of igneous intrusions. Coal rank at depths of 300 m to 1,500 m are expected to be sub-bituminous to locally bituminous, or higher in areas of igneous activity. Gas contents have not been measured in Sumatran coals. However, mud logs frequently record distinct methane kicks at coal seams. Based on rank and target depth, the gas content is estimated to average 5 m3/t. It is likely that igneous activity has introduced carbon dioxide into the seams at the expense of methane, which is consequently estimated at 70% of total seam gas. Removal and re-injection of this CC>2 could provide a viable source for ECBM operations. Producibility (Ranking: 3). A conservative estimate for technically recoverable coalbed gas, or potential reserves, in Sumatra is of the order of 340 Gm3 (12 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using CO2 flooding could increase this by 3 68 Gm (2.4 Tcf). In the process, about 250 Mt of CO2 could be sequestered within coal reservoirs. f The overall stress regime in the South and Central Sumatra basins is transpressional, but there are sizeable areas of extension or relaxation interspersed among the zones of compression. Dips are low to moderate. The Muara Enim Fm. coals tend to have fairly high vitrinite contents (averaging 73% in the south of the South Sumatra basin), which favors cleat development and JAF98172.DOC 90 Advanced Resources International, Inc. IEA Greenhouse Gas K&D Programme Worldwide COy-ECBUAssessment enhanced permeability. (On the other hand, the low-rank lignites commonly present at shallower depth in the two basins can be expected to show poorer cleat development.) No direct coal seam permeability measurements have been made, but we estimate that low to moderate levels of coal seam permeability (1-5 md) may be developed within high-graded areas. Exhibit 6-5-2: Indonesia Technical ECBM Recovery Potential • IBH^££lffifiHi Prospective Basin Area (km2) 30,000 32,000 Coal Resource (Gt) 590 680 Gas-In-Place (Gm3) 2,830 3,400 GIF Cone. (MnrVkm2) 95 106 Technically Recoverable CBM 570 340 (Gm3) Technically Recoverable 230 68 3 CO2 -ECBM (Gm ) CO2 Sequestration Potential (Mt) 850 250 6.5.3 Economic Analysis KALIMANTAN Development Cost (Ranking 1). Coalbed methane has not been developed in Kalimantan and facilities and services would need to be imported or locally developed. There are significant conventional oil & gas operations currently, particularly in eastern Kalimantan in the Kutei basin. However, this industry targets high-cost, deep onshore and offshore production, with little potential synergy with CBM operations. In addition, much of the prospective CBM area is located in swampy and/or undeveloped areas with poor surface infrastructure. The cost of building access roads and drilling locations in this part of Indonesia is often higher than actual well drilling costs. Finally, it is unlikely that existing natural gas gathering systems could be utilized for CBM development in the basin. Consequently, we anticipate that development costs for CBM in eastern Kalimantan will be quite high, approximately 2 to 3 times that of the San Juan basin. Coalbed Methane Market (Ranking: 2). Because local markets are extremely limited, most of the conventional natural gas produced in east Kalimantan is exported in the form of liquified natural gas (LNG). In the Kutei area, short connectors (<50 km) could feed CBM production into the pipeline which runs along the coast from Balikpapan about 200 km north to JAF98172.DOC 91 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment the Bontang LNG plant. However, CBM would have difficulty competing with probably lower cost conventional gas. Commercial CBM is probably more viable if targeted at local consumption in areas not supplied with natural gas. Limited potential markets exist in steam-raising or as a chemical feedstock in the industrial centers of Banjarmasin, Balikpapan and Samarinda, or for electricity generation at coal mines or other operations in remote regions. The Indonesian government has floated the idea of a pipeline connecting Java with the Kutei gas fields which could be routed through the Barito basin and which could open up a new market for CBM in this particularly prospective area of east Kalimantan. However, the realistic medium-term outlook for CBM markets in Kalimantan is discouraging. Carbon Dioxide Availability (Ranking: 1). In Kalimantan, emissions from coal/oil-fired power plants or other industries represent limited but accessible (<50 km) sources of mixed-phase gas containing CO2. Conventional natural gas reservoirs in this portion of Indonesia are low in carbon dioxide. SUMATRA Development Cost (Ranking: 3). Unlike Kalimantan, there exists considerable capability and infrastructure on Sumatra for potentially supporting typical CBM operations. For example, each year hundreds of shallow, inexpensive wells are drilled at Duri steamflood in Central Sumatra. These rigs and related hydraulic stimulation equipment could be adapted for CBM operations. Location and access costs are still likely to be high, though less than in Kalimantan. Overall, development costs for Sumatra are anticipated to be approximately 50% higher than in the San Juan basin. Coalbed Methane Market (Ranking: 4). The potential market for CBM in Sumatra is much more favorable than that of eastern Kalimantan. Overall, we rate the potential market as relatively good for a developing country, and adequate to support a sizeable COa-ECBM program. The principal near-term market for CBM produced from the South and Central Sumatra basins is Caltex Pacific Indonesia's Duri heavy-oil steamflood operation ~ the world's largest ~ located in north-central Sumatra (Map 6-5). Duri steamflood currently burns 67,000 barrels of oil per day (20% of its production) as fuel to generate steam for injection within enhanced-oil recovery operations. Near-term natural gas requirements at Duri, including expansion into new oil zones, is estimated at 12.7 Mm3/day (450 MMcf/day). The development of Gulf Indonesia's Corridor conventional gas field (140-280 Gm3, or 5-10 Tcf of reserves) in the South Sumatra basin is dedicated almost entirely to supplying Duri, but is expected to satisfy only about two JAF98172.DOC 92 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment thirds of energy requirements. CBM could be in a strong position to capitalize on the demand shortfall. A 540-km gas pipeline is under construction between Corridor and Duri and is on target for completion by late 1998. Coalbed methane developed in the two basins could feed into this pipeline via short connectors not exceeding about 75 km in length. The Corridor-Duri pipeline may be extended southward to Jakarta. A 280-km spur line is planned to supply a gas-fired power plant on the Indonesian island of Batam, a few kilometers from Singapore. Under review is the continuation of this pipeline to the vast, but as yet untapped, methane and CCb resources near Indonesia's Natuna Island in the South China Sea. Secondary markets for electricity generation or industrial use may exist in Palembang and other centers. An indication of the growing electricity demand in southern Sumatra is the planned construction by the year 2000 of a 200 MW gas-fired power plant. The facility is to be built in the Jambi region by Electricite de France and the Indonesian state electricity company, PLN. Carbon Dioxide Availability (Banking: 4). Natural gas from the Corridor field contains an average of approximately 30% carbon dioxide which could be made available for ECBM recovery operations. Construction of the gas processing plant is nearing completion and sales to the Duri steamflood operation are due to begin in mid-1998. Full-scale production will reach 8.5 Mm3/day (300 MMcf/day), of which 7.6 Mm3/day will, go to Duri and the balance to the power plant at Batam. Expansion at Corridor and the inclusion of adjacent fields is expected to double production by 2001. Based on these production rates, 3.6 MmVday (7.2 Mm3/day in 2001) of waste CChis expected to be vented to the atmosphere and could become available. Natuna has enormous gas reserves (6,290 Gm3, 222 Tcf) but partners Exxon, Mobil and Pertamina have delayed project development. To a large extent, this is because of the high cost of removing the 72% CC>2 content, which is currently planned to be re-injected The project economics could, however, be improved if the gas processing costs were reduced through the sale of C02to an ECBM recovery operation in Sumatra. Other, smaller, high-CCb natural gas fields are also present in Sumatra. In addition, emissions from coal/oil-fired power plants or other local industries represent limited but accessible (<120 km) sources of mixed-phase gas containing CO2. JAF98172.DOC 93 Advanced Resources International, Inc. IEA Greenhouse GasR&D Programme World-Wide COrECBM Assessment Exhibit 6-5-3: Indonesia Commercial ECBM Recovery Potential Gas Market LNG plant, limited local electricity Caltex's Duri heavy-oil steamflood generation and industrial use in north-central Sumatra 3 CO2 Availability Limited local natural gas or Corridor gas field (3.6 Mm /day) in industrial emissions south-central Sumatra, Natuna Island field in longer term 6.5.4 Coalbed Methane Exploration and Production Preliminary CBM resource evaluations of Indonesian coal basins have been conducted but no areas has yet been leased or field tested. JAF98172.DOC 94 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Progran Worldwide COfECBM Assessment 6.6 India 6.6.1 Summary A moderately good potential exists in India for CO2-ECBM recovery and carbon dioxide sequestration. Sizable CBM resources are reasonably well defined in the Damodar Valley coalfields and in the Cambay basin (Map 6-6). It is also likely that large CBM resources are also present in several other coalfields but their CBM potential has yet to be quantified. Recycling of vented industrial emissions, principally from coal-fired power plants, constitutes the primary source of carbon dioxide for ECBM recovery. CO2 sequestration for high-graded ECBM areas is estimated at approximately 80 Mt in the two areas described, while total sequestration potential is much greater. Exhibit 6-6-1 provides an overview of the potential for CO2-ECBM recovery in the Damodar Valley and the Cambay basin. Exhibit 6-6-1: India Resource and Commercial ECBM Recovery Potential wwMW$i& BHH^PS^H Recoverable ECBM (Gm3) 2.2 8* . 20 §1 COa Sequestration lllQ Potential (Mt) 8 74 0:0! _j Gas Market Good Good o< LUZ! *>1U CO2 Availability Good Good Leasing/Testing Active Active s| °§ Commercial Production None None (Mm3/yr) World Ranking (1-20) 10 5 Demand for methane hi India is strong whereas domestic reserves of conventional natural gas are very limited. A concerted effort is underway to alleviate this acute shortage, and the possible role of CBM has been recognized by government. The Damodar Valley and the Cambay basin are favorably located near industrial markets in the Delhi-Calcutta corridor and the Gujarat region, respectively JAF98172.DOC 95 Advanced Resources International, Inc. Pakistan ECBM Reserves CO2 Sequestration DAMODAR VALLEY 3 Mahanadi ECBM Reserves: 2.2 Gm CO2 Sequestration: 8 Mt IEA Greenhouse Gas R&D Programme CO. - ECBM Potential of India Natural Gas Pipeline C02-ECBM Basins Other Coal Basins Advanced Resources International, Inc. JAF00934.CDR 96 IEA Greenhouse Gas R&D Programme Worldwide COi-ECBMAssessment 6.6.2 Resource Analysis India ranks third in world coal production, after China and the United States. Coal mining and resources are concentrated in the Damodar Valley, the Sone-Mahanadi Valley and the Godavari Valley regions of east and central India. Each of these elongated coal-bearing regions comprises a number of separate coal basins developed along a common structural trend. These regions share similar geological histories and employ the same stratigraphic nomenclature. Of the three regions, the Damodar Valley holds the greatest prospects for CO2-ECBM recovery. It is the most studied and developed coal mining region in India; coal rank is substantially higher than in the other regions; the CBM potential has already been investigated; and it is the best situated for gas markets and CO2 availability. The other coal-bearing region selected for analysis, the Cambay basin in west India, offers opportunities for enhanced CBM production in a different (and probably more favorable) geological and geographical environment. This basin contains conventional natural gas deposits with developed gas-related infrastructure, and is located in the State of Gujarat, the principal industrial region of India. DAMODAR VALLEY Location and General. The Damodar Valley coalfields are contained in four main basins which together cover an area of 3,600 km2 in eastern India. These are the Raniganj basin in West Bengal state and the Jharia, Bokaro and North Karanpura basins in Bihar state (Map 6- 6). Both surface and underground mining take place. Located between Calcutta and Delhi, the Damodar Valley contains coal-related industries such as power generation and steel-making. Data control is good in the mining areas but poorer elsewhere, especially in the deeper parts of the basins. Coal Seam Geology (Ranking: 5). The principal coal-bearing sequences are the Permian-age Barakar and Raniganj formations, the latter being slightly younger and preserved only in the east. Thick coal seams are developed, several of which are in the 10-25 m range. Gross coal thickness averages 100 m. There is a tendency towards concentration of the seams and about 50 m can typically be completed. The average prospective coal depth is in the 850-900 m range. Ash and moisture contents average 20% and 5%, respectively. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource is estimated to be 440 Gm3 (16 Tcf), with an average resource concentration of 470 Mm3/km2 (43 Bcf/mi2). This is a large resource with a very attractive concentration. JAF98172DOC 97 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBU Assessment The prospective surface area is estimated at 1,100 km2, of which 940 km2 is assumed to remain non-minable for several decades. The contained coal resource — the amount of coal that would be contacted during CBM production and hence available for COa sequestration — is calculated at 46 Gt. Coal rank is generally high- to medium-volatile bituminous. Vitrinite reflectance is in the 0.8-1.2% range and is highly favorable for CBM development. A small number of gas content measurements have been made. The moderately shallow and the deeper seams are expected to be gas-saturated with an average gas content of 10 m3/t. Methane is a hazard in some of the region's underground coal mines. Methane content is estimated to average 95% with local increases in near dolerite dikes and sills. Producibility (Ranking: 2). It is estimated that technically recoverable gas, or potential reserves, is of the order of 22 Gm3 (0.8 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using CCb flooding could raise this by 2.2 Gm3 (O.OSTcf) About 8 Mt of CC«2 could be permanently sequestered. The stress regime is relaxed to mildly compressive. Dips tend to be fairly low. Degree of fracturing is variable but zones of enhanced fracturing have been mapped. Cleating is fair to poorly developed. It is speculated that permeability at CBM depths would be in the range of 1 md. CAMBAY BASIN Location and General. The Cambay basin occupies an area of approximately 13,000 km2 in the west Indian state of Gujarat (Map 6-6). The region is densely populated and has a reasonably well developed oil and gas infrastructure as well as other industries. Overall data control is fair but very good in the areas of petroleum exploration. Coal Seam Geology (Ranking: 4). The Tertiary-age Kadi and Kalol. formations contain several seams in the 5-20 m range. Gross coal thickness averages 65 m, of which over 40 m is completable. Average prospective coal depth is relatively deep at around 1,300-1,400 m. Ash and moisture contents average 5% and 10%, respectively. Prospective Gas-In-Place (Ranking: 4). A large prospective gas-in-place resource is estimated at 1,000 Gm3 (35 Tcf), with an attractive average resource concentration of 250 Mm3/km2 (23 BcfTmi2). JAF98172.DOC 98 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COz-ECBM Assessment The prospective surface area is estimated to be 4,000 km2, all of which is likely to remain non-minable for many decades due to the depth of the coal. The contained coal resource available for CO2 sequestration is calculated at 190 Gt. The coal is described as lignite to sub-bituminous, with average gas content estimated to be 5-6 m3/t. The degree of saturation is not known. Methane content is expected to be 95% or more. Produdbility (Ranking: 3). Technically recoverable gas, or potential reserves, is estimated to be 100 Gm3 (3.5 Tcf) using conventional pressure-depletion techniques. Enhanced 3 gas recovery using C02 flooding could produce an additional 20 Gm (0.7 Tcf). About 74 Mt of CO2 could be permanently sequestered in this high-graded area. The Cambay basin is an active extensional rift system with well developed fracturing. Dips are generally low. Although the stress regime favors enhanced permeability, this is mitigated to a degree by the the depth of the coal. Limited permeability measurements to date are in the 0.5-2.5 md range. Exhibit 6-6-2: India Technical ECBM Recovery Potential |||||||||||I||]|||H^mWHA Prospective Basin Area (km2) 940 4,000 Coal Resource (Gt) 46 190 Gas-In-Place (Gm3) 440 1,000 GIF Cone. (MtrrVkm2) 470 250 Technically Recoverable 43 100 CBM (Gm3) Technically Recoverable 2.2 20 3 CO2 -ECBM (Gm ) CO2 Sequestration Potential 8 74 (Mt) JAF98172.DOC 99 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBUAssessment 6.6.3 Economic Analysis CBM development costs in India are likely to be higher than in the U.S. India does have a significant domestic onshore petroleum industry, with equipment and services that are at least fairly adequate for CBM operations. Actual well cost details are sketchy, but we estimate that long-term costs for a large-scale ECBM project in India would be approximately 25 to 50% above current San Juan basin costs. On the other hand, the outlook for gas demand and wellhead gas prices is highly favorable in India. In fact, India has some of the world's highest projected natural gas price forecasts, with some analysts predicting $0.11/m3 ($3.00/Mcf) at the wellhead. DAMODAR VALLEY Development Cost (Ranking: 2). The Damodar Valley is not a producing oil & gas center, so industry equipment and services would have to come from other parts of India. It is also one of India's poorest regions and local infrastructure is not well developed. Hydraulic stimulation capability in particular is inadequate. Overall, development costs are likely to be 50% higher than in the San Juan basin. Coalbed Methane Market (Ranking: 4). The CBM resources of the Damodar Valley are located in the industrial corridor between Delhi and Calcutta. CBM is not expected to be competitive with cheap coal for power generation or industrial steam raising but demand for other uses is strong and India's domestic production of conventional gas is very limited. The acute shortage of natural gas has prompted investigation of the expensive option of piping gas from either the Middle East or Central Asia. Several LNG projects are also slated. The Gas Authority of India Ltd. has conducted a study of the CBM resource potential in the Damodar Valley and is seeking financial assistance from the Asian Development Bank to conduct further investigations in this region. Carbon Dioxide Availability (Ranking: 4). Emissions from coal-fired power stations, located in or close to the coalfields, represent the main source of vented CO2 available for ECBM recovery in the Damodar Valley region. Relatively short lines (<30 km) would therefore be required to introduce CO2 into future CBM production areas. CAMBAY BASIN Development Cost (Ranking: 3). The Cambay basin is fortunate to be an existing petroleum production center, so that equipment and services for a potential ECBM project are relatively well developed. India's Oil and Natural Gas Corporation (ONGC) are very active in JAF98172.DOC 100 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COz-ECBMAssessment local oil and gas fields, such as Sobhasan and North Kadi. Gujarat province is also one of India's most highly developed, so infrastructure is also quite favorable. Suface topography is quite simple and site preparation costs should be minimal. Long-term development costs for ECBM are expected to be moderate, about 25% above current San Juan basin costs. Coalbed Methane Market (Ranking: 5). The markets for Cambay basin CBM would be mainly for power generation and synthesis gas in the industrial zones of Mumbai, Ahmadabad and other centers in this economically important region. The Cambay basin benefits from existing pipeline and other infrastructure associated with the conventional gas resources in the basin. Carbon Dioxide Availability (Ranking: 4). Industrial emissions offer a moderately abundant source of vented CO2 for ECBM recovery. By-product C02 may also be available from conventional gas fields in the basin, but actual supplies are as yet unknown. Exhibit 6-6-3: India Commercial ECBM Recovery Potential Gas Market Local industry Gujarat, Mumbai industrial regions CO2 Availability Coal-fired power Industrial emissions plant emissions 6.6.4 Coalbed Methane Exploration and Production CBM resource evaluations have been performed and test wells drilled in both the Damodar Valley coalfields and the Cambay basin. Exploration is currently active in the Damodar Valley. No production has been established in either region. Details of these testing programs are confidential, although gas content and at least low permeability levels have been confirmed. JAF98172.DOC 101 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COj-ECBM Assessment 6.7 Southern Africa 6.7.1 Summary Fair potential exists in several parts of southern Africa for CO2-ECBM recovery and carbon dioxide sequestration (Map 6-7). Attractive CBM resources are present especially in the Waterberg and Zambezi basins of South Africa and Zimbabwe, respectively. Recycling of vented industrial emissions, principally from coal-fired power plants, constitutes the primary source of carbon dioxide for ECBM recovery. CO2 sequestration potential in high-graded ECBM prospects is estimated at approximately 500 Mt in the three regions described. Exhibit 6-7-1 provides an overview of the potential for COa-ECBM recovery in the Main Karoo, Waterberg and Zambezi basins. Results of the resource analyses for these regions are: Exhibit 6-7-1: S. Africa Resource and Commercial ECBM Recovery Potential ^MSTO^^ If^ATER^EI^lif Recoverable ECBM (Gm3) 2.6 25 108 CO2 Sequestration Potential (Mt) 9.6 93 400 RESOURC E POTENTIA L <£ i Gas Market Good Moderate Moderate o< UJZ CO2 Availability Good Fair Poor OQ_ Leasing/Testing None None Active S^ s l Commercial Production None None None (MnrVyr) Overall Ranking (1-20) 20 17 14 Demand for methane in southern Africa is strongest in Gauteng Province (Johannesburg region) located just north of the Main Karoo coal basin. A modest gas pipeline infrastructure is in place and CBM could probably compete favorably with the limited quantities of expensive synthetic gas currently being supplied to industrial, commercial and residential consumers. Smaller, local markets also exist for CBM in the Waterberg and Zambezi basins. JAF98172.DOC 102 Advanced Resources International, Inc, vfpj$l^ 3'^;«?f»««^«»*S;j^;««K;:;;»5;i5;«;5;j ECBM Reserves: 108 Gm3 CO2 Sequestration: 400 Mt WATERBERG ECBM Reserves: 25 Gm3 CO2 Sequestration: 93 Mt ECBM CO2 Sequestration IPIR;^^ \%«ij^7^N^^^^mi^ii^^ IEA Greenhouse Gas R&D Programme CO, - ECBM Potential of Natural Gas Pipeline CO2-ECBM Basins Advanced Resources International, Inc. 103 JEA Greenhouse Gas R&D Programme Worldwide COz-ECBUAssessment 6.7.2 Resource Analysis Africa's coal resources are concentrated within three adjacent countries at the continent's southern tip: South Africa, Zimbabwe and Botswana. The coal deposits all belong to the Karoo basin depositional environment (Permian age) and share similar reservoir characteristics. South Africa is a major coal producer and ranks third in the world in exports, while the other two countries produce mainly for domestic consumption. Mining is divided between underground and surface methods. MAIN KAROO BASIN Location and General. The Main Karoo basin, as it is termed here, refers to the intensively mined sub-basins or coalfields centered in Mpumalanga Province (southeast Transvaal) and extending into the northern parts of Orange Free State and KwaZulu-Natal provinces (Map 6-7). The Main Karoo basin occupies the most industrialized region in southern Africa with well developed infrastructure. Data control is generally good due to extensive coal and other mineral exploration, and numerous coal exploration coreholes have been drilled. CBM testing, on the other hand, has been very limited to date. Coal Seam Geology (Ranking: 2). The coal-bearing sequence is the Permian-age Vryheid Formation, which usually contains only two minable coal seams. Gross and completable coal thickness averages only 3-4 m at an average prospective coal depth of 250-400 m. This is relatively thin, comparable to the marginally economic Warrior basin of the U.S. Ash and moisture contents average 30% and 5%, respectively. Prospective Gas-In-Place (Ranking: 2). The prospective gas-in-place resource is estimated to be 125 Gm3 (4.4 Tcf), but with an unfavorably low average resource concentration of only 21 Mm3/km2 (1.9 Bcf/mi2). The prospective surface area is estimated at 6,750 km2, of which 6,000 km2 is assumed to remain non-minable for several decades. The contained coal resource ~ the amount of coal that would be contacted during CBM production and hence available for CO2 sequestration » is calculated at 15 Gt. Coal rank is generally high-volatile bituminous which is favorable for CBM development. Vitrinite reflectance is in the 0.5-1.0% range. Average gas content is around 7-10 m3/t, based on rank and a number of measurements. Methane content is estimated to average 95% with local increases in CO2 near dolerite dikes and sills. JAF98172.DOC 104 Advanced Resources International. Inc. ISA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Producibility (Ranking: 3). It is estimated that technically recoverable gas, or potential reserves, is of. the order of 13 Gm3 (0.5 Tcf) using conventional pressure-depletion techniques. 3 Enhanced gas recovery using CO2 flooding could raise this by 2.6 Gm (0.09 Tcf). About 9.6 Mt of CO2 could be permanently sequestered in high-graded areas. The stress regime is normal and dips are sub-horizontal. The seams are fairly well fractured but cleating is poorly to moderately well developed. No permeability measurements are available but we estimate an average in the 1 md range based on the degree of fracturing, coal characteristics and the relatively shallow depth. WATERBERG BASIN Location and General. The Waterberg basin is one of a number of sub-basins belonging to the extensive Karoo sedimentary system. The basin lies in the Northwest Province (northwestern Transvaal) and extends westward into Botswana. The South African portion covers an area of approximately 3,500 km2 (Map 6-7) and hosts one open-cast coal mine. The region is primarily agricultural and thinly populated with a moderately well developed infrastructure. Overall data control is fair, but better in the areas of coal exploration. Coal Seam Geology (Ranking: 4). Coal is found in the Permian-age Grootegeluk and underlying Vryheid-equivalent formations. The former includes a 60-m thick zone of interbedded coal and carbonaceous shale, while the latter contains 4-5 seams up to 8 m thick concentrated in a 50-m interval. The combined gross coal thickness averages 35 m, of which about 30 m is completable. Average prospective coal depth is relatively shallow, approximately 400- 500 m. Ash and moisture contents average 25% and 5%, respectively. Prospective Gas-In-Place (Ranking: 3). The prospective gas-in-place resource is estimated at 315 Gm3 (11 Tcf), with an average resource concentration of 209 Mm3/km2 (19 Bcf7mi2). The prospective surface area is estimated to be 1,500 km2, all of which is likely to remain non-minable for many decades. The contained coal resource available for CO2 sequestration is calculated at 40 Gt. Coal rank is generally high-volatile bituminous which is favorable for CBM development. Average gas content estimated to be 8 m3/t based on rank (Ro=0.7-0.8%). The degree of saturation is not known. Methane content is expected to be around 95%. Producibility (Ranking: 4). Technically recoverable gas is estimated to be 63 Gm3 (2.2 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using CO2 JAF98172.DOC 105 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment 3 flooding could add an extra 25 Gm (0.9Tcf). About 93 Mt of CO2 could be permanently sequestered in high-graded areas. The Waterberg basin is interpreted to be under extensional stress with sub-horizontal dips and well developed fracturing. Cleating is poorly to moderately well developed. Based on the above data, the moderate depth and the fairly high vitrinite content, average permeability is speculated to be in the 1 to 5 md range. ZAMBEZI BASIN Location and General. The Zambezi basin is another of the Karoo sub-basins. It extends over a 80,000 km2 area of western Zimbabwe, northern Botswana and southeast Zambia (Map 6-7). Coal is mined underground at Hwange in Zimbabwe. The region is sparsely populated. Infrastructure is moderately to poorly developed in Zimbabwe and non-existent in Botswana. Data control is fair to poor. Coal Seam Geology (Ranking: 4). Coal occurs in the Bira and equivalent Permian-age formations. The multiple coal seams, each generally less than 2 m thick, are frequently concentrated over a relatively narrow stratigraphic interval. The gross coal thickness averages 25 m, of which 20 m is typically completable. Average prospective coal depth is in the 350-450 m range. Ash and moisture contents average 35% and 5%, respectively. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource is estimated at 1,350 Gm3 (48 Tcf), with an average resource concentration of 75 Mm3/km2 (6.9 Bcf/mi2). The prospective surface area is estimated to be 20,000 km2, of which 18,000 km2 is likely to remain non-minable for many decades. The contained coal resource available for COa sequestration is calculated at 285 Gt. The high-volatile bituminous coal rank is favorable for CBM development. Average measured gas content is about 5 m3/t. The degree of saturation is not known. Methane content is expected to be around 95%. Producibility (Ranking: 4). Technically recoverable gas is estimated to be 270 Gm3 (9.5 Tcf) using conventional pressure-depletion techniques. Enhanced gas recovery using COa 3 flooding could increase this by 108 Gm (3.8 Tcf). About 400 Mt of C02 could be permanently sequestered in high-graded areas. The stress regime is relaxed with sub-horizontal dips. Fracturing and cleat development are moderate. Previous work indicates are that permeability may average around 5 md. JAF98172.DOC 106 Advanced Resources International, Inc. SEA Greenhouse Gas R&D Programme Worldwide COi-ECBM Assessment Exhibit 6-7-2: Southern Africa Technical ECBM Recovery Potential MMSlBlEBi'ipfS Prospective Basin Area (km2) 6,000 1,500 18,000 Coal Resource (Gt) 15 40 285 Gas-In-Place (Gm3) 125 315 1,350 GIF Cone. (Mm3/km2) 21 209 75 Technically Recoverable 13 63 270 CBM (Gm3) Technically Recoverable 2.6 25 108 3 CO2 -ECBM (Gm ) COa Sequestration 9.6 93 400 Potential (Mt) 6.7.3 Economic Analysis Unlike most of the regions in this study, southern Africa lacks a significant indigenous oil & gas industry. Consequently, the services and equipment for CBM development must be imported, at least initially, and from very distant petroleum centers (such as the U.S. or Western Europe). Competition amongst suppliers is likely to be minimal, keeping costs high. Preliminary costs estimates for CBM operations are some of the world's highest, estimated at approximately double San Juan basin costs even for a large commercial project. On the other hand, the outlook for natural gas demand in southern Africa is bright. The conventional natural gas resource base is quite limited, and CBM could compete favorably with high-cost, synthetically produced gas. MAIN KAROO BASIN Development Cost (Ranking: 2). As discussed above, estimated at double San Juan basin project costs. Coalbed Methane Market (Ranking: 4). The CBM resources of the Main Karoo basin are located in the industrial and mining districts surrounding Johannesburg. South Africa lacks cheap and plentiful supplies of natural gas, although methane is produced from the Sasol facilities which convert coal to liquid fuels. Demand for industrial, commercial and residential use of gas is JAF98172.DOC 107 Advanced Resources International, Inc. IEA Greenhouse GasR&D Programme Worldwide COfECBUAssessment strong, and attractive prices can be expected. A modest gas pipeline network is already in place in this region. CBM is unlikely to be competitive with cheap coal for power generation. Consequently, wellhead natural gas prices are likely to be in the range of $0.07 to $0.11/m3 ($2.00 to $3.00/Mcf). Carbon Dioxide Availability (Ranking: 4). Emissions from coal-fired power stations and numerous other industrial plants, located close to the CBM resources, represent the primary source of vented CO2 available for ECBM recovery in the Main Karoo basin. Relatively short lines (<30 km) would therefore be required to introduce CO2into future CBM production areas. WATERBERG BASIN Development Cost (Ranking: 2). As discussed above, estimated at double San Juan basin project costs. CoalbedMethane Market (Ranking: 3). The markets for Waterberg basin CBM would be limited to local industrial consumption. Carbon Dioxide Availability (Ranking: 2). Emissions from one coal-fired power plant and operations at one coal mine offer a modest source of vented CO2 for ECBM recovery. ZAMBEZI BASIN Development Cost (Ranking: 2). As discussed above, estimated at double San Juan basin project costs. Coalbed Methane Market (Ranking: 3). Potential industrial markets for Zambezi basin CBM are located primarily in the Bulawayo area. Natural gas is not currently available in Zimbabwe but could be an attractive alternative energy source for power generation. JAF98172.DOC 108 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide CO>ECBM Assessment Carbon Dioxide Availability (Ranking: 1). Emissions from coal-fired power plants, located within 100 km of the CBM resource, could provide a limited source of vented CO2 for ECBM recovery. However, this is probably too distant and costly to be a feasible source of carbon dioxide. Exhibit 6-7-3: Southern Africa Commercial ECBM Recovery Potential Gas Market Ind., com. & res. in Local industry Industry in Bulawayo Johannesburg region area CO2 Availability Coal-fired power plant Limited coal-fired Limited coal-fired power and other industrial power plant emissions plant emissions emissions 6.7.4 Coalbed Methane Exploration and Production CBM resource evaluation and limited testing has been financed by the European Investment Bank in the Zimbabwean portion of the Zambezi basin. Coalbed methane leases are currently held by two companies in this region. However, negotiations are underway to lease and investigate CBM prospects in South Africa and Botswana and additional testing is anticipated during the next several years. JAF98172.DOC 109 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment 6.8 Russia and Ukraine 6.8.1 Summary The Kuznetsk basin in Russia has excellent potential for CO2-ECBM recovery. A second major coal-producing area, the Donetsk basin in "Ukraine, has some potential but is located in a complex structural setting that is probably not appropriate for ECBM (Map 6-8). Numerous other coal basins exist in Russia, but appear to have lower potential or are less well documented. Recycling of vented industrial emissions, principally from coal-fired power plants, constitutes a readily available source of carbon dioxide. Naturally occurring CO2 hi petroleum fields may also be available. CO2 sequestration potential for high-graded ECBM areas within these two coal basins is estimated at approximately 1,000 Mt. Exhibit 6-8-1 provides an overview of the potential for CO2-ECBM recovery in the Kuznetsk and Donetsk basins. Exhibit 6-8-1: Russia, Ukraine Resource and Commercial ECBM Recovery Potential (k$$$t$$$$& i! J!;jff|^i^i$&;/j '1 3 280 7 UJ_I Recoverable ECBM (Gm ) CO2 Sequestration 1,000 26 UJ<5 Potential (Mt) K.Q. Gas Market Good Good <_J O< LLJZZ CO Availability Good Good 2>UJ 2 Leasing/Testing None None ll < Commercial Production None None (Mm3/yr) (mine drainage: 170) Overall Ranking (1-20) 7 11 JAF98172.DOC 110 Advanced Resources International, Inc. E'^'tP?Jl'P-i&W5-.. -"v?!?:.!? * "'*'•;' '™™-" Tunguska !5B».!'L"??1.^^!^Sste™--BJ!"'SBgjJ South Yakutia ^^^™-g^>^^^^^^^^^^^^^^ " - ; 3 •Jry]i5lI alS ;l;»:»«":'^= ~ DONETSK ECBM Reserves: 7 Gm3 IEA Greenhouse Gas R&D Programme CO2 Sequestration: 26 Mt KUZNETSK ECBM Reserves: 280 Gm Map 6-8 CO2 Sequestration: 1000 Mt CO2 - ECBM Potential of Russia and Ukraine CO2-ECBM Basins Other Coal Basins Advanced Resources International, Inc. JAF00936.CDR IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment The Kuznetsk area suffers from a shortage of natural gas, while in the Donetsk there is a need to reduce imports of expensive Russian gas and find alternative sources. Many coal mines in both regions are unprofitable and there is great pressure to increase productivity and reduce costs. CBM could provide a means of generating income and reducing future development costs by degassing seams ahead of mining. These factors could encourage commercial production of CBM in these two basins, particularly in the Donbass where some of the technology and infrastructure are already in place for recpvering and utilizing methane from the mine workings. 6.8.2 Resource Analysis Russia ranks fourth in world coal production and Ukraine is also a major producer. The most important mining regions — and the two that are described here — are the Kuznetsk basin in Russia and the Donetsk basin straddling the border between the two countries. Vast additional coalbed methane resources are contained in the Pechora, Lena, Tunguska, South Yakutia and other Russian basins. Based on current information, the latter appear to hold less promise for commercial CO2-ECBM recovery resulting from a combination of lack of CBM-specific data, poor market accessibility, limited sources of carbon dioxide and high development costs. KUZNETSK BASIN Location and General The nearly 30,000 km2 Kuznetsk basin (Kuzbass), located in south-central Russia, is that country's largest coal producing region (Exhibit (Map 6-8), predominantly from underground mines. Kemerovo and Novokuznetsk are centers for steel- making and other heavy industries. Infrastructure is generally well developed. Data control is good. Coal Seam Geology (Ranking: 4). The coal-bearing sequences are the Permo- Carboniferous Kolchuginsk and Balakhonsk formations containing multiple, dispersed coal seams frequently thicker than 2 m. Computable coal thickness averages 20 m out of a gross thickness of around 70 m. The average prospective coal depth is 1,000 m. Ash and moisture contents average 20% and 7%, respectively in high-graded areas. Prospective Gas-In- Place (Ranking: 5). The prospective gas-in-place resource is estimated to be 3,510 Gm3 (126 Tcf), with an average resource concentration of 219 Mm3/km2 (20 Bcf/mi2). This is a very large resource with a very attractive concentration. The prospective surface area is estimated at 20,000 km2, of which 16,000 km2 will probably be unaffected by mining activities in the medium to long term. The contained coal resource available for C02 sequestration is calculated to be 310 Gt. JAF98172.DOC 112 Advanced Resources International, Inc. ISA Greenhouse GasR&D Programme Worldwide COrECBM Assessment The coal rank is high-volatile bituminous. Gas content has been extensively monitored and averages 12 m3/t, which is likely to be at saturated levels. A methane content of at least 95% is estimated. Producibility (Ranking: 4). The technically recoverable gas is estimated at approximately 710 Gm3 (25 Tcf), using conventional pressure-depletion techniques, which could 3 be raised by 284 Gm (10 Tcf) with application of CO2-ECBM recovery. Based on these assumptions, about 1,000 Mt of CO2 could be permanently sequestered in high-graded areas. The stress regime is compressive with low to moderate dips up to 30 degrees. The coal is well cleated. No permeability data are available but values are estimated to be in the range of 1 to 5 md, with the potential for higher permeability. DONETSK BASIN Location and General. About three-quarters of the 60,000 km2 Donetsk basin (Donbass) lies in Ukraine, the rest in Russia (Map 6-8). It is the largest coal-producing center in the former Soviet Union region. Production is almost exclusively from deep mines. The Donbass is Ukraine's most industrialized area and infrastructure is well developed. Major cities include Donetsk, Makeevka and Lugansk. Data control for CBM evaluation is good. Coal Seam Geology (Ranking: 3). The main coal-bearing formations are the Carboniferous Moskovsk and Bashkirsk Fms. Multiple, dispersed seams make up about 60 m of gross coal thickness, with individual seams relatively thin at 0.5-2.0 m. Completable coal is estimated to be 15 m at an average depth of 900 m. Ash and moisture contents average 20% and a little under 7%, respectively. Prospective Gas-In-Place (Ranking: 4). The prospective gas-in-place resource in the Donetsk basin is estimated to be 1,390 Gm3 (49 Tcf), with an average resource concentration of 139 Mm3/km2 (13 Bcf/mi2). This is a very large and fairly concentrated resource. The prospective surface area is estimated at approximately 30,000 km2, of which around 10,000 km2 in the deeper portions of the basin is assumed to remain non-minable for several decades. The contained coal resource available for CO2 sequestration is calculated at 150 billion tons. Coal rank is predominantly bituminous. Since most mines are extremely gassy, methane levels are closely monitored. Gas contents across the coalfields average 10 m3/t but undersaturation is a frequent problem in this area of uplift and prior degassing. Methane content is around 95% with low C02 levels. JAF98172.DOC 113 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COi-ECBM Assessment Producibility (Ranking: 2). Despite the attractive CBM resource in the Donetsk basin, producibility of this resource is likely to be poor due to low permeability and fault compartmentalization. It is estimated that technically recoverable gas (potential reserves) is on the order of 70 Gm3 (2.5 Tcf) using conventional pressure-depletion techniques. Enhanced gas 3 recovery using CO2 flooding could provide a further 7 Gm (0.25 Tcf). About 26 Mt of CO2 could be permanently sequestered in high-graded areas. Low to moderate dips, which can exceed 35 degrees, attest to a compressive stress regime. Coal cleats are well developed, but mineralization is a frequent problem. No permeability measurements are publicly available, but we estimate an average of 1 md, possibly much less. Exhibit 6-8-2: Russia and Ukraine Technical ECBM Recovery Potential |fi|f|^I|?S|fl|t MASlWty Prospective Basin Area (kit?) 16,000 10,000 Coal Resource (Gt) 310 150 Gas-In-Place (Gm3) 3,500 1,390 GIF Cone. (Mm3/km2) 219 139 Technically Recoverable 710 70 CBM (Gm3) Technically Recoverable 280 7 3 CO2 -ECBM (Gm ) CC>2 Sequestration Potential (Mr) 1,000 26 6.8.3 Economic Analysis Although Russia has a mature oil and gas industry, there is currently no CBM production from virgin coal seams nor a service industry for an ECBM project to draw upon. Futhermore, the closest petroleum industry centers to the Kusnetsk coal field is several hundred kilometers distant and mobilization charges would be costly. Ukraine has a very limited domestic oil and gas industry, and ECBM development costs in the Donetsk basin are also expected to be fairly high. KUZNETSK BASEST Development Cost (Ranking: 3) Approximately 50% higher than San Juan basin costs for a large-scale project. JAF98172.DOC 114 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBMAssessment CoalbedMethane Market (Ranking: 4). Although coal dominates the energy mix, demand for natural gas is high, and the Tyumen gas fields 400 km to the north supply only one- third of the estimated 20 Mm3 consumed in the Kuzbass region. The metals industry is the largest gas consumer. Carbon Dioxide Availability (Ranking: 4). Given the large quantities of coal burned in the region, industrial emissions represent plentiful and suitably located sources of vented CO2 available for ECBM recovery. DONETSK BASM Development Cost (Ranking: 3). Approximately 50% higher than San Juan basin costs for a large-scale project. Coalbed Methane Market (Ranking: 4). Favorable market conditions exist for CBM in the Donbass. Having in the past had access to abundant, low-cost supplies of natural gas from Russia, Ukrainian industry is designed to rely heavily on gas for its energy needs. The country is now seeking to reduce its dependence on increasingly costly gas imports which it must purchase with scarce foreign currency, and there is a strong incentive to boost domestic gas production. Carbon Dioxide Availability (Ranking: 4). Anthropogenic CO2 emissions from within the heavily industrialized Donbass is available in close proximity to the CBM resources and would require limited construction of supply lines. Exhibit 6-8-3: Russia and Ukraine Commercial ECBM Recovery Potential Gas Market Metal and other industry Mixed industry CO2 Availability Coal-fired industrial emissions Coal-fired industrial emissions 6.8.4 Coalbed Methane Exploration and Production Gas drainage from Donbass coal mines, and utilization of recovered methane, is described above. The Ukrainian government has conducted several inconclusive CBM test programs (vertical wells) in the Donetsk basin. In addition, two new U.S.-ftmded CBM exploration programs are underway in the Donetsk basin: U.S.-based International Coalbed Methane Group, Inc. received a $600,000 grant from the U.S. Trade and Development Agency to conduct a feasibility study of a CBM project, while elsewhere in the basin U.S.-based Raven Ridge expects to receive approval soon for a CBM exploration and development lease. JAF98172.DOC 115 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COx-ECBM Assessment 6.9 Western and Central Europe 6.9.1 Summary Most (if not all) of the European coal basins are geologically poorly suited to coalbed methane development and initial production testing has been disappointing. The two European basins with at least modest potential for CO2-ECBM recovery are the Upper Silesian basin in Poland and the Czech Republic, and the Saar/Lorraine basin in Germany and France (Map 6-9). Recycling of vented industrial emissions in Europe constitutes a readily available and environmentally desirable source of carbon dioxide. Total CO2 sequestration potential in high- graded ECBM areas is estimated at approximately 17 Mt. Exhibit 6-9-1 provides an overview of the potential for CO2-ECBM recovery in the Upper Silesian and Saar basins. Exhibit 6-9-1: Europe Resource and Commercial ECBM Recovery Potential snissiffliBm ll*3Ri8&!!B}nH! Recoverable ECBM 2.0 2.5 p (Gm3) COz Sequestration 7.4 9.3 11 Potential (Mt) Gas Market Good Good 0< ^UJZ CO2 Availability Good Good 55 sj| Leasing/Testing Active Active Commercial Production None None ^ (MnrVyr) (Mine drainage: 200) (Some mine drainage) World Ranking (1-20) 16 17 A strong demand for natural gas exists in and around the Upper Silesian and Saar basins, driven both by environmental considerations and the declining contribution of domestic coal reserves towards the energy mix. Heavy reliance on expensive imported gas from potentially unreliable sources, and the need to curb high unemployment levels have been additional incentives to utilize domestic gas resources. JAF98172.DOC 116 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Map 6-9 CO2 - ECBM Potential of Western and Central Europe COvECBM Basins Advanced Resources International, Inc. SAAR/LORRAINE ECBM Reserves: 2.5 Gm S-'S^SySKJKiSJSSSSS^KSKiSiKxxSiS CO, Sequestration: 9 Mt UPPER SILESIAN ECBM Reserves: 8 Gm CO, Sequestration: 30 Mt JAF00937.CDR ISA Greenhouse Gas R&D Programme Worldwide COj-ECBM Assessment 6.9.2 Resource Analysis The two most prospective European coal basins for CO2-ECBM recovery are the Upper Silesian basin in Poland and the Czech Republic, and the Saar/Lorraine basin in Germany and France. However, the potential in these basins is probably very limited, since early CBM testing has encountered low permeability and very low production rates (typically 1 to 10 m3/day per well). An analysis of these basins is presented below. There are a number of other basins in Europe which contain coal of suitable rank and depth for coalbed methane development. However, several factors conspire to limit the CBM prospectivity of many of them. The overall size of the CBM resource hi many of the basins is small by international standards. Most coalfields are in regions with complex structural histories which result not only in steep dips and fault dislocation, but also in very low seam permeability and gas undersaturation. Finally, intensive though declining coal mining in many cases restricts the area effectively available for CBM development. Consequently, these other basins were screened out at an early stage and are not discussed in detail. UPPER SILESIAN BASIN Location and General. Over 80% of the 7,000 km2 Upper Silesian basin lies in southwest Poland and the remainder in northeast Czech Republic (Ostrava-Karvina Coalfield; Map 6-9). Poland is the world's seventh largest producer of hard coal, the majority of which is extracted from underground mines in the Upper Silesian basin. Krakow and Ostrava are the largest cities near the Polish and Czech coalfields, respectively. The region is heavily industrialized and infrastructure is well developed. Data control is considered very good, including a significant body of confidential CBM well test data. Coal Seam Geology (Ranking: 3). Numerous coal seams are dispersed through the Carboniferous Ruda and Zabrze Formations in Poland, and the broadly correlative Karvina and Ostrava Formations in the Czech Republic. Individual seams are generally less than a meter thick but can attain 5 m. Coal is a little better developed in Poland where gross thickness averages around 40 m and the average completable coal thickness is about llm. Prospective coal depth averages 1,100-1,200 m. The average ash and moisture contents are 15% and 2%, respectively. Prospective Gas-In-Place (Ranking: 2). The prospective gas-in-place resource across the Upper Silesian basin is estimated at 415 Gm3 (15 Tcf), with a reasonably attractive average resource concentration of 110 Mm3/km2 (10 Bcf/mi2). JAF98172.DOC 118 Advanced Resources International, Inc. ISA Greenhouse GasR&D Programme Worldwide COrECBM Assessment The prospective surface area is estimated at 5,000 km2, of which an estimated 3,750 km.;2 will probably remain unmined in the medium to long term. The contained coal resource available for C02 sequestration is calculated to be 44 Gt. The coal rank is mostly high-volatile A bituminous (R<, of 0.9-1.0%), although some anthracite is present in the Czech part. The average gas content is approximately 10 m3/t and is higher in Poland than in the Czech part of the basin. Some areas show moderate to severe gas undersaturation. A methane content of at least 95% is estimated. Producibility (Ranking: 2). The technically recoverable gas is estimated at approximately 20 Gm3 (0.7 Tcf), using conventional pressure-depletion techniques, which could 3 be raised by 2.0 Gm (0.1 Tcf)with application of CO2-ECBM recovery. About 7.4 Mt of CO2 could be permanently sequestered in high-graded areas. The stress regime is relaxed to compressive with low to moderate dips (5-25 degrees). The coal has a high vitrinite content and is well cleated. Limited data indicate permeabilities in the 1 md range, frequently less. SAAR BASIN Location and General. The Saar basin occupies an area of some 12,000 km2 almost, equally divided between western Germany and northeastern France (where it is termed the Lorraine basin; Map 6-9). Mining activity has declined dramatically during the last several years, particularly in France, in the face of cheaper imported coat. Data control for CBM evaluation is very good, including several CBM wells. Coal Seam Geology (Ranking: 3). The coal-bearing formations are the Carboniferous Westphalian C&D units in France and the Sulzbach Formation in Germany. Gross coal thickness is 40-45 m comprised of multiple seams generally less than 2 m thick. Completable coal thickness averages 14 m at an average depth of 1,000-1,200 m. Ash and moisture contents average 5% each. Prospective Gas-In-Place (Ranking: 2). The prospective gas-in-place resource is estimated to be almost 500 Gm3 (18 Tcf), with an average resource concentration of 121 Mm3/km2(llBcf/mi2). The prospective surface area is estimated at 5,100 km2, of which 4,100 km2 is assumed to remain unmined in the future. The contained coal resource available for CO2 sequestration is calculated at 69 Gt. 119 Advanced Resources International, Inc. JAF98172.DOC 1EA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment Coal rank is high-volatile bituminous with vitrinite reflectance in the 0.7-1.0% range. Measured gas contents average 8 m3/t which, given the coal rank, suggests significant undersaturation. Methane content is estimated at around 95%. Producibility (Ranking: 2). It is estimated that technically recoverable gas (potential reserves) is on the order of 25 Gm3 (0.9 Tcf) using conventional pressure-depletion techniques. 3 Enhanced gas recovery using CO2 flooding could add 2.5 Gm (0.1 Tcf). About 9.3 Mt of CO2 could be permanently sequestered in high-graded areas. The stress regime is relaxed to compressive and formation dips are moderate to steep. Although the coal is well cleated, seam permeabilities are nonetheless low and frequently less than Imd. Exhibit 6-9-2: Europe Technical ECBM Recovery Potential Msnffi§i!^r'ri,M Prospective Basin Area (km2) 3,750 4,100 Coal Resource (Gt) 44 69 Gas-In-Place (Gm3) 415 496 GIF Cone. (Mm3/km2) 110 121 Technically Recoverable 20 25 CBM (Gm3) Technically Recoverable 2.0 2.5 3 CO2 -ECBM (Gm ) CO2 Sequestration Potential (Mt) 7.4 9.3 6.9.3 Economic Analysis Development costs for ECBM in Western Europe are expected to be high, due to the small onshore oil & gas industry (compared with offshore), strict environmental restrictions on development, and high labor rates. Costs in Central Europe are expected to be somewhat lower, although equipment and services are outdated (but improving). UPPER SILESIAN BASIN Development Cost (Ranking: 4). Poland and the Czech Republic have functioning oil & gas industries, with newly privatized service companies operating with some degree of JAF98172.DOC 120 Advanced Resources International, Inc. JEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment competition. Coalbed methane E&P testing to date has raised capabilities in this new resource, but overall costs for a large-scale ECBM project are still expected to be about 25% higher than San Juan basin levels. Coalbed Methane Market (Ranking: 4). There is a growing demand for gas in the Upper Silesian basin region and elsewhere in Poland and the Czech Republic. Coal remains the primary energy source but production is steadily declining as reserves become exhausted and pollution control measures demand cleaner burning fuels. Closure of coke plants has drastically reduced the availability of polluting coke-oven gas which was formerly supplied at a rate of 3.5 GmVyear to Polish households and industry. Poland imports about 60 percent of its natural gas requirements from Russia. Not only has the price of this gas risen sharply, but the source is perceived as unreliable and there is every incentive to promote domestic gas production, including CBM. Both Poland and the Czech Republic benefit from a well developed gas distribution system which would greatly facilitate the marketability of CBM. Carbon Dioxide Availability (Ranking: 4). Large volumes of vented CO2 are generated by industries in close proximity to the CBM resource of the Upper Silesian basin, and this could be harnessed for ECBM recovery. SAAR BASIN Development Cost (Ranking: 2). Long-term development and operational costs for an ECBM project in this region are estimated to be 50% to 100% above San Juan basin levels, based on actual CBM testing costs to date. Obtaining approval for drilling programs from local governmental authorities is costly and time consuming. Coalbed Methane Market (Ranking: 4). It is expected that coalbed methane would readily be able to tap into the existing markets for natural gas in the Saar/Lorraine basin region where gas pipeline and other infrastructure is highly developed. There are also a number of factors which could promote CBM development. Public opinion and stringent environmental regulations favor cleaner burning fuels, such as natural gas, over coal. At the same time, contraction of the coal mining industry has caused severe unemployment levels which could be tempered by utilizing the CBM resource of the coalfields. Furthermore, much of the gas consumed by German and French households and industry is imported at relatively high cost from potentially unreliable sources such as Russia and Algeria, providing additional encouragement to domestic gas production. Carbon Dioxide Availability (Ranking: 4). Plentiful anthropogenic CO2 emissions from Saar basin industries could be tapped for C02-ECBM recovery. Natural reservoir C02 supplies are very limited. JAF98172.DOC 121 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment Exhibit 6-9-3: Europe Commercial ECBM Recovery Potential Gas Market Commercial reticulation, Commercial reticulation, industry industry CO2 Availability Coal-fired industrial Industrial emissions emissions 6.9.4 Coalbed Methane Exploration and Production During the past 8 years, approximately 50 CBM wells have been drilled and tested in the Upper Silesian basin. Operators have included Amoco and Pol-Tex Methane hi Poland and DPB and GPO in the Czech Republic. Testing has shown undersaturated reservoir conditions, low permeability, and generally low gas production rates. Conoco and other operators have drilled test wells in the Saar/Lorraine basin, with reportedly poor results. There is also some recovery and utilization of gas drained from coal mines in both basins. In the United Kingdom, Evergreen Resources UK Ltd. has drilled three CBM wells in the North Wales coalfield with a maximum stabilized production rate of only 1,700 m3/d (60 Mcfd). Recently, exploration drilling has been conducted in the South Wales coalfield (where the highest average gas contents in the U.K. — 13 m3/t - have been measured, and also in southern Scotland, but no testing results are yet available. Elsewhere in Europe, published reports to date indicate limited exploration and testing activity (but no results) in Belgium, Hungary and Spain. JAF98172.DOC 122 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment 6.10 Ranking of World COr-ECBM Coal Basins The overall potential of a coal deposit to support an economically viable CO2-ECBM recovery operation depends on an optimal combination of four factors: 1) CBM Producibility. Given the in-place CBM resource and the coal seam permeability, what is the size and per-well recovery rate of the technically recoverable CBM reserve? 2) Carbon Dioxide Availability. What is the nature, concentration and supply rate of the CO2 source, and how conveniently is it located to the CBM resource? 3) Development Cost. How do location, CO2 systems and other factors affect the capital and operating costs? 4) Markets. Are there existing or potential markets for CBM at the minimum gas price necessary for a profitable operation? These and related factors were discussed in detail in Section 5 and were assigned a score from 1 to 5 (lowest to highest) for each CBM resource area. The individual scores are collated in Exhibit 6-10-1 to produce an overall score and ranking which measures the relative CO2-ECBM potential of the world's most prospective coal deposits. Basins with equal overall scores were ranked according to their ECBM producibility (a measure of the rate of CBM production/CO2 sequestration) and then according to their development cost. The rankings show that, with a score of 29/30, the San Juan basin in the United States has by far the greatest CO2-ECBM potential. This was to be expected since the San Juan already possesses a combination of technical and economic advantages that makes it the most prolific producer of CBM by the conventional pressure-depletion method. In addition to this, the availability of carbon dioxide is good. The San Juan basin, all other things being equal, would be the best choice for near-term future research into CO2-ECBM recovery. Scoring somewhat lower is a cluster of seven coal basins: Uinta, USA (24); Bowen, Australia (24); Raton, USA (23); Cambay, India (23); Sydney, Australia (22); Kuznetsk, Russia (21); and Sumatra, Indonesia (21). Outside of the San Juan basin, these probably hold the greatest near-term potential for CO2-ECBM recovery projects. Ranking, as presented here, should not be the sole arbiter of ECBM potential. It must be emphasized that the resource evaluations are averages based on a basin-wide or regional analysis and that each basin will contain high grade zones, or prospects, that would be the actual focus of any CBM development efforts. It is possible, therefore, that a relatively low ranked basin could contain a prospect with equal or even better potential than a prospect in a higher ranked basin. i o 3 Advanced Resources International, Inc. JAF98172.DOC -1-" Exhibit 6-10-1: Ranking of World's Most Prospective Coal Deposits for CO2-ECBM Recovery Potential 4 ; <*»s T- -v;\V^ Y%'-- ,& ^""iUV~;^< "ftfetifeL , R^UJHS* , > i?J$08M , ; Berefegfoeoi £a? Sales , ^C%" ;= ,'J&te$£ti; ^ ' "" ', , ~. \-.%\v •.'"'' \ -. ""*" ""• v. •.cisiB^Jta/feegW " ItesemS. % Cdncenfeeatiort fedudfcljilfr - ' >€esfcr -- Markef Amiability &s«ikaig , San Juan U.S.A. 5 5 5 5 4 5 29 1 Uinta U.S.A. 2 3 5 5 4 5 24 2 Bowen Australia 5 4 4 4 4 3 24 3 Raton U.S.A. 2 3 . 4 5 4 5 23 4 Cambay India 3 5 3 4 5 3 23 5 Sydney Australia 4 4 3 3 4 4 22 6 Kuznetsk Russia 2 3 4 4 4 4 21 7 to Sumatra Indonesia 4 3 3 3 4 4 21 8 Western Canada Canada 4 2 3 4 3 3 19 9 Damodar Valley India 2 3 2 4 4 4 19 10 Donetsk Ukraine/Russia 1 5 2 3 4 4 19 11 NE China China 2 4 2 3 4 4 19 12 Ordos China 4 3 4 3 2 2 18 13 Clarence-Moreton Australia 3 3 4 3 3 2 18 14 Kalimantan Indonesia 5 3 4 2 3 1 18 15 Upper Silesian Poland/Czech 1 3 2 4 4 4 18 16 Saar Germany/France 1 3 2 4 4 4 18 17 Waterberg S.A./Botswana 2 4 4 2 3 2 17 18 Zambezi Zimbabwe/Bots. 5 3 4 1 2 1 16 19 Main Karoo South Africa 1 1 2 2 4 4 14 20 ISA Greenhouse Gas R&D Programme Worldwide COf ECBU Assessment Section 7: Preliminary Estimate of the Worldwide CO2 Sequestration Potential in Deep Coals 7.1 Conclusions Preliminary analysis of the CO2 sequestration potential for enhanced coalbed methane (ECBM) recovery projects indicates that approximately 140 Gt of CO2 could be sequestered in worldwide coal basins at total capital and operating costs of less than $100/t An estimated 60 Gt of CO2 could be sequestered at costs of under $50/t, which is the range of costs for many competing sequestration options, as well as the initial level of Norway's CO2 emissions tax. In the most favorable coal basins, an estimated 5 to 15 Gt of CO2 may be sequested within profitable ECBM operations, generating profits of up to $20/t of sequestered CO2. The economics of worldwide CO2 sequestration using ECBM are summarized in Exhibit 7-1 and presented in greater detail within the individual country summary tables that immediately follow. 7.2 Methodology The primary focus of this study, summarized in Section 6, has been on coal basins where reservoir and market conditions appear to be most favorable for ECBM. In these high-graded settings, ECBM and CO2 sequestration operations have a reasonable chance of being economically viable on a stand-alone basis, based on the current (admittedly very preliminary) understanding of exploration testing results and the geologic controls on CBM production, as well as on the current state of technology development as demonstrated by the Allison Unit pilot. However, in our experience, such unusually favorable settings probably represent only about 2 to 5% of the worldwide coal resource base. Should restrictions be placed on future CO2 emissions, resulting in substantial taxes on emissions or subsidies on sequestration, a large additional sequestration potential would be available within other less favorable coal basins as well as in the geologically inferior portions of the high-graded basins. In these settings, C02 may be sequestered in unprofitable but still moderately low-cost operations. It would be prudent to focus on the low-cost portion of this sequestration potential. Unless subsidies/taxes are extremely high, successful CO2 sequestration will still require generally favorable geologic and market conditions. This section discusses our preliminary analysis of the economics of CO2 sequestration within coal basins that span the broad spectrum of resource and market quality. We performed this analysis in six stages. JAF98172DOC 125 Advanced Resources International, Inc. Exhibit 7-1 CO2 Sequestration Using ECBM for Major Worldwide Coal Basins (Current Technology) | NS ($50.00) - $0.50/McfCO2Cost $0.00 -•*- FreeCO2 22 Gt/yr j '6.6 Gt/yr Annual Energy Emissions Power Emissions), $50.00 i A' ' ' In' '—i—L r i i i I i I I I I i I i I I I i i I i I I I I I I r I 0 20 40 60 80 100 120 140 160 180 CO2 Sequestered (Gt) June S. 1998 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COi-ECBMAssessment Stage 1: Characterize Coal Resources by Basin. For the major coal basins, we characterized the resource into three types, based on our assessment of their geologic prospectiveness for ECBM. These resource types are defined as: (A) Potentially Profitable Resources: Coal resources that are predicted to be favorable for ECBM based on geologic conditions and/or early CBM testing results, and that may be expected to support potentially commercial ECBM operations. (Generally 2% to 5% of total coal resources in most basins.) (B) Technically Recoverable Resources: Coal resources that are less favorable but still may be expected to support ECBM projects with some degree of subsidy. Where possible, expert assessments of the technically recoverable resource base were used. For basins where public assessments are not available, we relied on proprietary information and our judgment in each area. (Typically 10% to 50% of total coal resources in each basin.) (C) Low-Quality Resources: Much of the coal resource base occurs in geologic settings characterized by adverse reservoir conditions, such as thin coal, low permeability, and undersaturation. COa sequestration in these relatively unfavorable settings is likely to be costly. (This resource category typically accounts for 50% or more of the total coal resource base in each basin.) Stage 2: Develop Average CBM Gas Production Profiles. Based on our analysis of geologic resource quality and producibility (summarized in Section 6), we selected likely average gas production profiles for base case (pre-CO2 injection). These production curves were based on average production in three U.S. CBM basins: 1) San Juan/Uinta/Raton Basin Profile: This is a relatively favorable methane production profile typical of western U.S. CBM basins with total per-well gas reserves of about 3.28 Bcf/well (93'million nrVwell). 2) Warrior/Appalachian/Powder River Basin Profile: This is a more marginal gas production profile typical of eastern U.S. CBM basins with modest per-well methane reserves of about 0.28 Bcfi'well (8 million mVwell), although development costs related to this production profile are favorably low. 3) Piceance/Greater Green River Basin Profile: This profile represents frontier CBM basins, with high development costs and low-moderate per-well methane reserves of about 1.0 Bcf7well (28 million m3/well). JAF98172.DOC 127 Advanced Resources International, Inc. JE4 Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Stage 3: Determine Enhancement Factor: Based on the variable enhancement achieved at the Allison Unit pilot, we speculated that different geologic settings will have different enhancement factors for methane production due to C02 injection. We assumed enhancement factors of 75%, 50%, and 25% from resource types A, B, and C, respectively. There is little empirical basis for these values currently, but it is reasonable to assume that the efficiency of ECBM will be less in poor geologic settings, due to reservoir heterogeneity. Stage 4: Develop Basin-Specific Costs. Based on the costs presented in Section 6, the development and operating costs for methane production and CO2 injection wells were estimated for each basin as a multiple of established San Juan and Warrior Basin costs. Stage 5: Determine Minimum Economic Gas Price (MEGP). For each resource type in each coal basin, the minimum netback wellhead gas price was determined using cash-flow analysis. This is the effective natural gas sales price that would enable the CO2-ECBM project to just break even, based on typical private-sector discount rates of 11.5%. (Note that governmental discount rates tend to be lower, which would reduce our estimated costs of CO2 sequestration.) Step 6: Compare MEGP -with Market Gas Prices. For each basin, the MEGP was compared with actual current and likely future long-term natural gas prices. If natural gas prices are higher than the MEGP, then the project is likely to be profitable. For example, the high-quality portion of the Cambay basin in western India is estimated to achieve profit margins of $8.09/tonne of CO2 sequestered. Conversely, high-cost projects in basins with poor gas market outlook and low wellhead gas prices are not expected to be profitable. The difference between the MEGP and actual wellhead price was used to determine net CO2 sequestration costs, which was then converted to a $/t basis. Potentially profitable and low-cost C02 sequestration areas should be given priority in future R&D and demonstration pilots. Step 7: Perform Sensitivity Analysis to CO2 Supply Costs. The base case assumed that CO2 supply costs at the injection well are $0.50/Mcf ($0.018/m3), based on actual costs at the Allison Unit pilot. An additional sensitivity was performed assuming "free" CO2 supplies. This could occur if taxes on emissions encourage CO2 emission sources to effectively cover the supply costs (processing, transportation, compression) for injection in ECBM projects. It should be noted that under this scenario, the CO2 supply cost would not actually be free when viewed from the overall societal point of view. We performed the analysis outlined above for each of 66 individual basin settings, with individual cash-flow analyses run for each setting (constructed similar to Exhibit 4-2 but not provided in this report). These results are summarized in Exhibit 7-1, and by individual country and individual coal basin for most major worldwide coal basins on the tables that follow. JAF98172.DOC 128 Advanced Resources International, Inc. CO2 Sequestration Using CO2-Enhanced Coalbed Methane Recovery USA Coal Basins Cost-Sequestration Economic Analysis Min EC Netback Price Profit/(Loss) Profit/(Loss) ($/Mcf CH4) Long-Term ($/Mcf CH4) ($/t C02) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential Country Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 5 3 Category Type No. ($0.01 8/m3) No. ($/Mcf) ($0.01 8/m*) ($0.01 8/m3) (x28.310'm (x28.310'm USA San Juan San Juan A 1 $1.64 $0.55 4 $2.00 $0.36 $1.45 $3.35 $13.49 13.0 26.0 1.4 Type B 2 $2.21 $1.12 5 $2.00 ($0.21) $0.88 ($1.95) $8.18 18.0 36.0 1.9 C 3 $5.20 $4.10 6 $2.00 ($3.20) ($2.10) ($29.76) ($19.53) 29.0 58.0 3.1 Uinta A 1 $1.64 $0.55 4 $1.75 $0.11 $1.20 $1.02 $11.16 2.2 4.4 0.2 B 2 $2.21 $1.12 5 $1.75 ($0.46) $0.63 ($4.28) $5.86 3.0 6.0 0.3 C 3 $5.20 $4.10 6 $1.75 ($3.45) ($2.35) ($32.09) ($21.86) 4.8 9.6 0.5 Raton A 1 $1.64 $0.55 4 $1.75 $0.11 $1.20 $1.02 $11.16 0.8 1.6 0.1 B 2 $2.21 $1.12 5 $1.75 ($0.46) $0.63 ($4.28) $5.86 2.0 4.0 0.2 C 3 $5.20 $4.10 6 $1.75 ($3.45) ($2.35) ($32.09) ($21.86) 7.4 14.8 0.8 Warrior Warrior A $2.25 0 0 0.0 Type B 8 $4.27 $3.18 11 $2.25 ($2.02) ($0.93) ($18.79) ($8.65) 2.3 4.6 0.2 C 9 $10.65 $9.55 12 $2.25 ($8.40) ($7.30) ($78.12) ($67.89) 17.5 35 1.9 N&C Appalachian A $2.50 0 0 0.0 B 8 $4.27 $3.18 11 $2.50 ($1.77) ($0.68) ($16.46) ($6.32) 14.6 29.2 1.6 C 9 $10.65 $9.55 12 $2.50 ($8.15) ($7.05) ($75.80) ($65.57) 51.4 102.8 . 5.5 Powder River A $1.75 0 0 0.0 B 8 $4.27 $3.18 11 $1.75 ($2.52) ($1.43) ($23.44) ($13.30) 5.1 10.2 0.5 C 9 $10.65 $9.55 12 $1.75 ($8.90) ($7.80) ($82.77) ($72.54) 24.9 49.8 2.7 Frontier Piceance A $1.75 0 0 0.0 B 14 $2.80 $1.71 17 $1.75 ($1.05) $0.04 ($9.77) $0.37 7.5 15 0.8 C 15 $10.03 $8.95 18 $1.75 ($8.28) ($7.20) ($77.00) ($66.96) 76.5 153 8.2 Greater Green R. A $1.75 0 0 0.0 B 14 $2.80 $1.71 17 $1.75 ($1.05) $0.04 ($9.77) $0.37 3.9 7.8 0.4 C 15 $10.03 $8.95 18 $1.75 ($8.28) ($7.20) ($77.00) ($66.96) 44.1 88.2 4.7 Total 328 656 35 June 4, 1998 Advanced Resources International, Inc. CO2 Sequestration Using C02-Enhanced Coalbed Methane Recovery Australian Coal Basins Cost-Sequestration Economic Analysis Min EC Netback Price t Profit/(Loss) Profit/(Loss) ($/Mcf CH4) Long-Ter ($/McfCH4) ($/tC02) ECBM C02 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential ount Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 3 3 8 3 Category Type No. ($0.01 8/m No. ($/Mcf) ($0.018/m ) ($0.018/m ) (X28.3 10 m ) (X28.3 10°m3) Aus Bowen Bowen A 19 $2.33 $1.25 22 $2.00 ($0.33) $0.75 ($3.07) $6.98 8.3 16.6 0.9 Type B 20 $2.80 $1.71 23 $2.00 ($0.80) $0.29 ($7.44) $2.70 21.0 42.0 2.3 C 21 $14.46 $13.38 •24 $2.00 ($12.46) ($11.38) ($115.88) ($105.83) 74.7 149.4 8.0 Sydney A 19 $2.33 $1.25 22 $3.00 $0.67 $1.75 $6.23 $16.28 1.4 2.8 0.2 B 20 $2.80 $1.71 23 $3.00 $0.20 $1.29 $1.86 $12.00 7.2 14.4 0.8 C 21 $14.46 $13.38 24 $3.00 ($11.46) ($10.38) ($106.58) ($96.53) 63.4 126.8 6.8 Clarence/ A 19 $2.33 $1.25 22 $2.50 $0.17 $1.25 $1.58 $11.63 2.5 5.0 0.3 Moreton B 20 $2.80 $1.71 23 $2.50 ($0.30) $0.79 ($2.79) $7.35 6.2 12.4 0.7 C 21 $14.46 $13.38 24 $2.50 ($11.96) ($10.88) ($111.23) ($101.18) 22.3 44.6 2.4 Low-Rank Gunnedah A $2.00 0 0 0.0 Type B 8 $9.00 $7.90 11 $2.00 ($7.00) ($5.90) ($65.10) ($54.87) 3.0 6.08 0.3 C 9 $13.40 $12.33 12 $2.00 ($11.40) ($10.33) ($106.02) ($96.07) 27.4 54.72 2.9 Galilee A $1.50 0 0 0.0 B 8 $9.00 $7.90 11 $1.50 ($7.50) ($6.40) ($69.75) ($59.52) 2 4 0.2 C 9 $13.40 $12.33 12 $1.50 ($11.90) ($10.83) ($110.67) ($100.72) ' 38 76 4.1 Total 277 555 30 June 9. 1998 Advanced Resources International, Inc. C02 Sequestration Using CO2-Enhanced Coalbed Methane Recovery Canadian Coal Basins Cost-Sequestration Economic Analysis Min EC Netback Price Profit/(Loss) Profit/(Loss) ($/Mcf CH4) _ong-Ter ($/Mcf CH4) ($/t C02) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resource Potential ountr Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 3 3 9 3 Category Type No. ($0.018/m ) No. ($/Mcf) ($0.018/m ) ($0.018/m ) {x28.3 10 m ) (X28.3 109m3) Canad Plains W Canada A 2 $2.21 $1.12 5 $1.00 ($1.21) ($0.12) ($11.25) ($1.12) 1.6 3.2 0.2 B 14 $2.80 $1.71 17 $1.00 ($1.80) ($0.71) ($16.74) ($6.60) 8.0 16 0.9 C 15 $10.03 $8.95 18 $1.00 ($9.03) ($7.95) ($83.98) ($73.94) 69.4 139 7.5 Atlantic Cumberland A $2.50 0 0 0.0 Type and others B 8 $4.27 $3.18 11 $2.50 ($1.77) ($0.68) ($16.46) ($6.32) 3.0 6.1 0.3 C g $10.65 $9.55 12 $2.50 ($8.15) ($7.05) ($75.80) ($65.57) 27.4 54.7 2.9 Total 109 219 12 June 8.1998 Advanced Resources International, Inc. C02 Sequestration Using C02-Enhanced Coalbed Methane Recovery Chinese Coal Basins Cost-Sequestration Economic Analysis Min EC Netback Price ProfW(Loss) ProfW(Loss) ($/Mcf CH4) Long-Ter ($/McfCH4) ($/t C02) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential ounti Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 s 3 3 Category Type No. ($0.018/m ) No. ($/Mcf) ($0.0l8/m ) ($o.oi8/m ) (X28.3 10'm ) (X28.3 10'm1) China Ordos Ordos A 2 $1.92 $0.83 5 $1.50 ($0.42) $0.67 ($3.91) $6.23 6.4 12.8 0.7 B 14 $3.53 $2.44 17 $1.50 ($2.03) ($0.94) ($18.88) ($8.74) 16.0 32.0 1.7 C 15 $7.85 $6.75 18 $1.50 ($6.35) ($5.25) ($59.06) ($48.83) 55.6 111.2 6.0 NE Chin Various A $3.00 0.2 0.4 0.0 Type B 8 $5.86 $4.77 11 $3.00 ($2.86) ($1.77) ($26.60) ($16.46) 1.9 3.8 0.2 C 9 $15.50 $14.35 12 $3.00 ($12.50) ($11.35) ($116.25) ($105.56) 37.9 75.8 4.1 Total 118 236 13 June 8f 1998 Advanced Resources International, Inc. CO2 Sequestration Using CO2-Enhanced Coalbed Methane Recovery Indonesian Coal Basins Cost-Sequestration Economic Analysis IV in EC Netback Pric:e Profit/{Loss) Profitf(Loss) ($/McfCH4) Long-Ter ($/Mcf CH4) ($/t CO2) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ C02 Costs @ C02 Costs Resources Potential Country Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 3 s 3 Category Type No. ($0.01 8/tn ) No. ($/Mcf) ($0.018/m ) (50.01 8/m3) (X28.3 10 m ) (X28.3 10"m3) Indonesi Sumatra S&C Sum A 1 $2.02 $0.95 4 $1.75 ($0.27) $0.80 ($2.51) $7.44 3.5 7.0 0.4 B 2 $3.11 $2.02 5 $1.75 ($1.36) ($0.27) ($12.65) ($2.51) 17 34 1.8 C 3 $6.75 $5.67 6 $1.75 ($5.00) ($3.92) ($46.50) ($36.46) 100 200 10.8 Kalimantan Various A 1 $2.34 $1.26 4 $0.75 ($1.59) ($0.51) ($14.79) ($4.74) 12 24 1.3 B 2 $3.78 $2.69 5 $0.75 ($3.03) ($1.94) ($28.18) ($18.04) 29 58 3.1 C 3 $8.65 $7.55 6 $0.75 ($7.90) ($6.80) ($73.47) ($63.24) 60 120 6.5 Total . 222 443 24 JuneS, 1998 Advanced Resources International, Inc. CO2 Sequestration Using CO2-Enhanced Coalbed Methane Recovery Indian Coal Basins Cost-Sequestration Economic Analysis Itlin EC Netback Pric:e Profit/(Loss) Profit/(Loss) ($/Mcf CH4) Long-Ter ($/Mcf CH4) ($/t C02) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential Countr Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) Category Type No. ($0.018/m3) No. ($/Mcf) ($0.018/m3) ($0.018/m3) {X28.3 10flm3) (X28.3 109m3) India Tertiary Cambay A 2 $2.13 $1.04 5 $3.00 $0.87 $1.96 $8.09 $18.23 0.7 1.4 0.1 B 14 $3.22 $2.14 17 $3.00 ($0.22) $0.86 ($2.05) $8.00 3.5 7 0.4 C 15 $12.27 $11.15 18 $3.00 ($9.27) ($8.15) ($86.21) ($75.80) 31 62 3.3 Gondwana Damodar A $2.50 0.1 0.16 0.0 B 8 $5.08 $3.98 11 $2.50 ($2.58) ($1.48) ($23.99) ($13.76) 0.8 1.6 0.1 C 9 $8.72 $7.64 12 $2.50 ($6.22) ($5.14) ($57.85) ($47.80) 15 30.2 1.6 Total 51 102 5 June 8. 1998 Advanced Resources International, Inc. CO2 Sequestration Using C02-Enhanced Coalbed Methane Recovery Southern African Coal Basins Cost-Sequestration Economic Analysis IV in EC Netback Pric e Profit/(Loss) Profit/(Loss) ($/Mcf CH4) _ong-Ter ($/Mcf CH4) ($/t C02) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential Country Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 3 3 9 3 Category Type No. ($0.01 8/m ) No. ($/Mcf) ($0.018/m ) ($0.018/m ) (X28.3 109m3) (X28.3 10 m ) S Africa Gondwana Karoo A $2.50 1.0 2.0 0.1 B 8 $7.45 $6.36 11 $2.50 ($4.95) ($3.86) ($46.04) ($35.90) 2.7 5 0.3 ' C 9 $20.18 $19.10 12 $2.50 ($17.68) ($16.60) ($164.42) ($154.38) 12 23 1.3 Zimbabw Gondwana Zambez A $1.50 3.8 7.6 0.4 B 2 $4.74 $3.66 5 $1.50 ($3.24) ($2.16) ($30.13) ($20.09) 9.5 19 1.0 C 3 $12.06 $10.98 6 $1.50 ($10.56) ($9.48) ($98.21) ($88.16) 35 69.4 3.7 Total 63 127 7 June 8,1998 . Advanced Resources International, Inc. C02 Sequestration Using C02-Enhanced Coalbed Methane Recovery Russia/Ukraine Coal Basins Cost-Sequestration Economic Analysis IWin EC Netback Price Profit/(Loss) Profit/(Loss) ($/Mcf CH4) Long-Ter ($/Mcf CH4) ($/t CO2) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential Country Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 Category Type No. ($0.018/m3) No. ($/Mcf) ($0.018/m3) ($0.018/m ) (X28.3 108m3) (X28.3 10V) Russia Kuznetsk Kuznetsk A 1 $1.87 $0.79 4 $2.50 $0.63 $1.71 $5.86 $15.90 10.0 20.0 1.1 B 2 $2.77 $1.68 5 $2.50 ($0.27) $0.82 ($2.51) $7.63 25.0 50 2.7 C 3 $5.81 $4.72 6 $2.50 ($3.31) ($2.22) ($30.78) ($20.65) 91 182 9.8 Ukraine Donetsk Donetsk A $2.00 0.3 0.5 0.0 B 8 $5.86 $4.77 11 $2.00 ($3.86) ($2.77) ($35.90) ($25.76) 2.5 5 0.3 C 9 $15.40 $14.35 12 $2.00 ($13.40) ($12.35) ($124.62) ($114.86) 46 92.4 5.0 Total 175 350 19 Note: Other potential ECBM basins such as Pechora, Lena, Tungusk, South Yakutia, Karaganda, and others not assessed due to sparse data. June 9, 1998 Advanced Resources International, Inc. C02 Sequestration Using C02-Enhanced Coalbed Methane Recovery W&C European Coal Basins Cost-Sequestration Economic Analysis Min EC Netback Pri<;e Profit/(Loss) Profit/(Loss) ($/Mcf CH4) _ong-Ter ($/McfCH4) ($/t C02) ECBM CO2 Sequestration CBM Cash @ CO2 Costs Cash Netback @ CO2 Costs @ CO2 Costs Resources Potential Country Basin Basin Resource Flow $0.50/Mcf Free Flow CH4 Price $0.50/Mcf Free $0.50/Mcf Free (Tcf) (Tcf) (Gt) 3 3 3 3 Category Type No. ($0.01 8/m ) No. ($/Mcf) ($0.018/m ) ($0.018/m ) (X28.3 10"m3) (X28.3 10°m ) Poland/ U Silesian U Silesian A $2.50 0.1 0.2 0.0 Czech B 8 $5.08 $3.98 11 $2.50 ($2.58) ($1.48) ($23.99) ($13.76) 0.7 1 0.1 C 9 $8.72 $7.64 12 $2.50 ($6.22) ($5.14) ($57.85) ($47.80) 14 28 1.5 France/ Saar Saar A $3.00 0.1 0.2 0.0 Germany B 8 $5.08 $3.98 11 $3.00 ($2.08) ($0.98) ($19.34) ($9.11) 0.9 1.8 0.1 C 9 $8.72 $7.64 12 $3.00 ($5.72) ($4.64) ($53.20) ($43.15) 17 34 1.8 Total 33 66 4 Note: Other potential ECBM basins in Europe were not assessed due to small resource size and poor CBM testing results to date. June 10, 1998 Advanced Resources. International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COt-ECBM Assessment Section 8: Conclusions and Recommendations for Future Work 8.1 Conclusions • Long-term testing at a ground-breaking pilot CO2-ECBM production field in the San Juan basin, U.S.A., indicates that carbon dioxide can be injected (and sequestered) in deep coal seams to boost recovery of in-place methane by about 75%. • Costs estimates indicate that a typical San Juan basin C02-ECBM project would be economic at a current wellhead price of $0.07/m3 ($2.00/Mcf). Projects outside the U.S. could require gas prices of $0.11/m3 ($3.00/Mcf) or more, depending on such considerations as infrastructural development and the existence of oil and gas industry services. • Key geological/reservoir conditions for successful ECBM include: thick, gas- saturated coal seams buried at suitable depth (300 to 1,500 m); simple structural setting with minimal folding and faulting; and adequate in-situ coal seam permeability (>5 md). • Readily available supplies of low-cost CO2 are essential, whether derived from natural reservoirs or captured from anthropogenic sources such as power plant flue gas. • The presence of efficient, long-term markets, the existence of pipeline infrastructure and favorable wellhead prices are all crucial to the economics of CO2-ECBM projects. • The San Juan basin, southwest U.S.A., is the top-ranked CO2-ECBM coal deposit, both in terms of commercial viability and capacity to sequester carbon dioxide. Other highly prospective coal basins are: Uinta and Raton (U.S.A.); Bowen and Sydney (Australia); Cambay (India); Kuznetsk (Russia); and Sumatra (Indonesia). • Worldwide CO2 sequestration potential in deep coal seams is estimated to be more than 150 Gt — based on the twenty coal basins estimated, to have the best potential for commercial CO2-ECBM recovery. Of this total, perhaps 60 Gt of CO2 may be sequestered at costs of under $50/t. JAF98172.DOC 129 Advanced Resources International, Inc. TEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment 8.2 Recommendations This preliminary study has hopefully helped to frame some of the key technical and economic issues affecting application of CO2-ECBM technology. However, considerable future work is needed in a number of areas where understanding is still limited: 1. Reservoir Study: The Burlington Resources Allison Unit pilot needs to be evaluated in further depth. A reservoir study involving rigorous history matching using a 3-phase reservoir simulator that models gas and water production, bottom- hole pressures, well completion and stimulation effectiveness, and other operational factors could provide a more precise understanding of the effectiveness of sequestration and enhanced recovery. 2. Detailed Basin Evaluations: The top half-dozen most prospective potential ECBM basins need to be examined in greater detail to confirm and quantify the CO2-ECBM application potential. Such detailed evaluations could address resource, producibility, market and other factors. 3. Match CO; with ECBM Resources: Better understanding of the worldwide availability of natural and anthropogenic C02 sources is needed, particularly the location and supply costs of C02 relative to prospective ECBM resources. The cost of collecting, processing, transporting, and injecting industrial CO2 needs particular study. 4. COi-ECBM Pilot: The Allison Unit pilot offers encouraging initial results, but is not an ideal test project due to proprietary considerations and because of varied well completion strategies and an inconsistent operational history. A new CO2- ECBM test pilot, preferably located in a well-characterized basin such as the San Juan, could, if well designed, answer crucial questions about this technology and offer a test bed for technology refinement. The GRI coal site in the San Juan basin served just such a role for the emerging CBM industry during the early 1990s. 5. Tradeable CO? Emissions Credits: The emergence of a trading system for CO2 emissions credits could dramatically improve the economics of CO2-ECBM projects by lowering C02 supply costs. The impact of such a system on ECBM economics and investment is recommended, perhaps examining the CBM production tax credit as a case study. JAF98172DOC 130 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COfECBM Assessment Bibliography The body of published literature on worldwide coalbed methane tends to be very general in nature, and lacks important testing results which are deemed commercially sensitive. Consequently, some of the material presented in this report, particularly in Section 6.0 dealing with the technical assessment of worldwide CBM resources, is derived from ARI's proprietary in- house database acquired through many years of coalbed methane evaluation and well testing. In such instances, therefore, no sources are or can be cited. By contrast, a vast and accessible literature exists on most of the world's coal deposits, from which some general background information can be obtained pertaining to the CBM potential of these deposits. Because of the great number involved, no attempt has been made to provide an exhaustive list of such references. Instead, a selected bibliography is given below which includes some of the more useful and CBM-specific published references. Section 1; Introduction BEA Greenhouse Gas R&D Programme, Annual Report, 1996. Section 3; Enhanced Coalbed Methane Recovery/General Arri, L.E., Yee, D., Morgan, W.D., and Jeansonne, M.W., Modeling coalbed methane production •with binary gas sorption, Society of Petroleum Engineers, SPE 24363, 1992. Chaback, J.J., Morgan, D., and Yee, D., Sorption irregularities and mixture compositional behavior during enhanced coal bed methane recovery processes, Society of Petroleum Engineers, SPE 35622, 1996. Gas Research Institute, A Guide to Coalbed Methane Reservoir Engineering, Chicago, Illinois, • 1996. Gunter, W.D., Gentzis, T., Rottenfusser, B.A., and Richardson, R.J.H., Deep coalbed methane in Alberta, Canada: a fuel resource -with the potential of zero greenhouse gas emissions, Proceedings of the Third International Conference on Carbon Dioxide Removal, Cambridge, MA, U.S.A., 9-11 September 1996. International Energy Agency, Oil, Gas & Coal Supply Outlook, 1995. Pun, R. and Yee, D., Enhanced coalbed methane recovery, Society of Petroleum Engineers, SPE 20732,1990. JAF98172.DOC 131 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBU Assessment Seidle, J.P., Sigdestad, C.A., Raterman, K.T., and Negahban, S., Characterization of enhanced coalbed methane recovery injection wells, Society of Petroleum Engineers, SPE 38861, 1997. Stevens, S. H., Kuuskraa, J.A., and Schraufhagel, RA, Technology spurs growth of U.S. coalbed methane, Oil and Gas Journal, January 1,1996. Stevenson, M.D. and Pinczewski, M.V., Economic evaluation of nitrogen injection for coalseam gas recovery, Society of Petroleum Engineers, SPE 26199, 1993. Section 5; Ranking of CBM Basin Parameters United States Energy Information Administration, Emissions of Greenhouse Gases in the United States 1987-1992, DOE/EIA-0573, November 1994. Section 6; CQyECBM Coal Basins Australia Australian Gas Association, Gas - Australia's Clean Growth Energy, Gas Industry Development Strategy 1995-2000, November 1995. Australian Gas Association, Gas Statistics Australia 1996. Brown, K., Casey, D.A., Enever, J.R., Facer, R.A., and Wright, K., New South Wales Coal Seam Methane Potential, New South Wales Department of Mineral Resources, Petroleum Bulletin 2, March 1996. Harrington, H.J. et al., Permian Coals of Eastern Australia, Bureau of Mineral Resources, Bulletin 231, 1989. Koenig, R.A., Booking, M.A., Forster, 1, Eriever, J.R., and Casey, D.A., Experience -with -well testing and in-situ stress measurements in the Sydney Basin for evaluation of coalbed methane prospectivity, Coalbed Methane Symposium, Townsville, November 19-21, p. 75-95, 1992. Mallett, C.W. and Russell, NJ, 1992, The thermal history of the Bowen-Gunnedah-Sydney basins. Symposium on Coalbed Methane Research and Development in Australia, James Cook University of North Queensland, Townsville, 19-21 November 1992. Matheson, S.G., 1993, Coal geology and resources of the Moreton basin, Queensland, Queensland Minerals and Energy Review Series. JAF98172.DOC 132 Advanced Resources International, Inc. ISA Greenhouse Gas R&D Programme Worldwide COz-ECBM Assessment Stewart, R. and Alder, D., eds., New South Wales Petroleum Potential, New South Wales Department of Mineral Resources, Coal and Petroleum Bulletin 1, April 1995. Canada Canadian Gas Potential Committee, 1997, Natural Gas Potential in Canada. Dawson, P.M., 1995, Coalbed methane: a comparison between Canada and the United States. Geological Survey of Canada Bulletin 489. Gunter, W.D., Gentzis, T., Rottenfusser, B.A., and Richardson, R.J.H., Deep coalbed methane in Alberta, Canada: a fuel resource with the potential of zero greenhouse gas emissions, Proceedings of the Third International Conference on Carbon Dioxide Removal, Cambridge, MA, U.S.A., 9-11 September 1996. International Coal Seam Gas Report, Cairn Point Publishing, Inc., 1997. Sinclair, KG. and Cranstone, J.R., Canadian coalbed methane: the birth of an industry, International Coalbed Methane Symposium Proceedings, May 12-17, 1997, p. 115-120. China Chen, M., Introductory Statement, Proceedings of the International Mining Tech '96 Symposium, Xian, China, p. ix-xii, 1996. Dai, J.X., Song, Y., Dai, C.S., and Wang, D.R., Geochemistry and accumulation of carbon dioxide gases in China, American Association of Petroleum Geologists Bulletin, v. 80, p. 1615-1626,1996. Zhang, I, Wang, Z., Liang, X., Wu, S., Liu, C., Shen, I, Yang, Y., Analyses of Chinese coalbed methane exploration and development, Proceedings of the International Mining Tech '96 Symposium, Xian, China, p. 238-243, 1996. Zhang, X. and Zhang, X., Distribution and development strategy for coalbed methane resources in China, United Nations International Conference on Coal Bed Methane Development and Utilization, Beijing, October 17-21, 1996, p. 19-24. JAF98172.DOC 133 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COr-ECBM Assessment Western and Central Europe Gairaud, H., Coalbed methane resources in France and current exploration/production work. 3rd Annual European CBM Forum, Producing Coalbed Methane - A Reality in Europe? Conference proceedings, London, March 28, 1996. Knox, L.M. and Hadro, J., Coalbed methane in Upper Silesia, Poland - A comprehensive, integrated study, International Coalbed Methane Symposium Proceedings, May 12-17, 1997, p. 127-135. Rice, D.D., 1993, Origin of Upper Carboniferous coalbed gases, Lower and Upper Silesian coal basins, Poland. Proceedings of the 1993 International Coalbed Methane Symposium, The University of Alabama/Tuscaloosa, May 17-21, 1993. Ryska, J. and Hemza, P., 1997, Coalbed methane development in virgin coal seams in the Czech part of Upper Silesian coal basin, Czech Republic. 1997 International Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama USA, May 12-16, 1997. Schloenbach, M., Coalbed methane resources in Germany's Saar basin and current activities, 3rd Annual European CBM Forum, Producing Coalbed Methane - A Reality in Europe? Conference proceedings, London, March 28, 1996. United States Environmental Protection Agency, Assessment of the Potential for Economic Development and Utilization of Coalbed Methane in Poland. EPA/400/1-91/032, August 1991. India Geological Survey of India, 1987, Coal Resources of Bihar. Bulletin Series A, No. 45, Vol. IV, Parti. Ministry of Petroleum & Natural Gas, Government of India, Coalbed Methane in India. Rao, K.L.N., Resource assessment of coal beds in the northern Cambay Basin, Gujarat, India, International Coalbed Methane Symposium Proceedings, May 12-17, 1997, p. 383-395. Indonesia Koesoemadinata, R.P., Hardjono, Usna, I. and Sumdirdja, H., 1978, Tertiary coal basins of Indonesia, in Sano, S., ed., Contribution to Knowledge of Tectonics and Mineral Resources in East Asia: United Nations ESCAP, CCOP Technical Bulletin, v. 12, p. 43- 84. JAF98172.DOC 134 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Nugroho, W. and Arsegianto, Economics of coalbed methane field development: a case study of Jatibarangfield, Society of Petroleum Engineers, SPE25311, 1993. Robertson Research (Australia) Pty. Ltd., Coal Resources of Indonesia, Vol. 1 (Report), 1980. Soehandojo, 1989, Coal exploration and exploitation review in Indonesia, Journal of the Association of Indonesian Geologists, vol. 12, no. 1, p. 279-325. van de Weerd, A. A. and Armin, R.A., 1992, Origin and evolution of the Tertiary hydrocarbon- bearing basins in Kalimantan (Borneo), Indonesia. AAPG Bulletin, v. 76, no. 11, pp. 1778-1803. Russia and Ukraine United States Environmental Protection Agency, Reducing Methane Emissions from Coal Mines in Russia and Ukraine: the Potential for CoalbedMethane Development. EPA 430-K- 94-003, April 1994. United States Environmental Protection Agency, Reducing Methane Emissions from Coal Mines in Russia: A Handbook for Expanding Coalbed Methane Recovery and Use in the Kuznetsk Coal Basin. EPA 430-D-95-001, September 1996. Marshall, J.S., Pilcher, R.C. and Bibler, C.J., 1995, Opportunities for the development and utilization of coalbed methane in three coal basins in Russia and Ukraine. Intergas '95, The University of Alabama, Tuscaloosa, Alabama USA, May 15-19, 1995. Pudak, V.V., 1995, Degassing of methane bearing geologic structures in the Donbass coal basin by the Donetsk Coal Association. Intergas '95, The University of Alabama, Tuscaloosa, Alabama USA, May 15-19, 1995. Saprykin, V.L., Boxerman, Y.A., Karp, IN. and Pyatnichko, A.I., 1995, Technical and economic feasibility of coalbed methane production and utilization in the Ukraine. Intergas '95, The University of Alabama, Tuscaloosa, Alabama USA, May 15-19, 1995. Tailakov, O.V., Polevshikov, G.Y., Abramoy, I.L., Panchisheva, T.A., Sinelnikova, A.V., and Zolotykh, S.S., Potential and utilization trends of coalbed methane recovery in Kuznetsk coal basin of Russia, International Coalbed Methane Symposium Proceedings, May 12- 17, 1997, p. 157-167. JAF98172.DOC 135 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COrECBM Assessment Southern Africa National Energy Council of South Africa, Coalbed Methane Potential for South Africa. Final Report - Phase 1, May 1991. National Energy Council of South Africa, Waterberg Coalfield: Geology of the Grootegeluk Coal Mine. United States Gas Research Institute, Quarterly Review of Methane from Coal Seams Technology, Vol. 11. No. 1, August 1993. International Coal Seam Gas Report, Cairn Point Publishing, Inc., 1997. Kelso, B.S., Wicks, D.E., and Kuuskra, V.A., 1988, A geologic assessment of natural gas from coal seams in the Fruitlandformation, San Juan basin, Topical Report (September 1986- September 1987), Gas Research Institute. Lamarre, R.A. and Burns, T.D., 1997, Drunkard's Wash unit: coalbed methane production from Perron coals in east-central Utah. Innovative Applications of Petroleum Technology Guidebook 1997, Rocky Mountain Association of Geologists. Stevens, S. H., Kuuskraa, J.A., and Schraufhagel, R.A, Technology spurs growth of U.S. coalbed methane, Oil and Gas Journal, January 1,1996. Stevens, S.H., Lombardi, T.E., Kelso, B.S., and Coates, J.M., A Geologic Assessment of Natural Gas From the Coal Seams in the Raton and Vermejo Formations, Raton Basin, Topical Report, GRI92/0345, June 1992. Tabet, D.E., Hucka, B.P., and Sommer, S.N., Coalbed methane resource potential of Perron Sandstone coals, Utah Geological Survey Open-File Report 329, November 1995. Tyler, R., Kaiser, W.R., Scott, A.R., and Hamilton, D.S., 1995, Coalbed gas potential of the Greater Green River basin, southwest Wyoming and northwestern Colorado, in Intergas '95, International Unconventional Gas Symposium, Proceedings - Tuscaloosa, Alabama, May 14-20, 1995. 1995 National Assessment of United States Oil and Gas Resources - Results, Methodology, and Supporting Data, Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds., U.S. Geological Survey Digital Data Series DDS-30 Release 2,1996. JAF98172.DOC 136 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide COfECBMAssessment APPENDIX A: Patents for Enhanced Coalbed Methane Recovery JAF98172.DOC 137 Advanced Resources International, Inc. IEA Greenhouse GasR&D Programme Worldwide COfECBM Assessment Patents for Enhanced Coalbed Methane Recovery A search of U.S. and international computer databases indicates four patents describing different techniques for CO2-ECBM recovery. All the patents are based on the principle that CO2 adsorbs more strongly onto the coal matrix than does methane, with the result that injected CO2 will preferentially be adsorbed (and remain sequestered in the seam) at the expense of coalbed methane, which becomes desorbed and can be recovered as free gas. The patents all also involve introducing carbon dioxide into the coal seam via one or more injection wells and collecting methane through one or more recovery wells, along with the non-adsorbed portion of the injected gas. The amounts of CO2 sequestered and methane released depend on a great many factors which must be determined empirically, and the relative merits of the different patented methods cannot be determined here. The patents are outlined below. 1. Method for Recovering Methane from a Solid Carbonaceous SuGterranean Formation. Patent No.: US 5,566,756 Patent Date: October 22, 1996 Inventors: Chaback, JJ. et al. Assignee: Amoco Corp. Method and Claims: A gas, which can include CO2-rich industrial flue gas or pure carbon dioxide, is introduced into a coal seam. (Other noxious constituents of some flue gases that will preferentially replace methane include hydrogen sulfide, sulfur dioxide and nitrogen dioxide.) Because of permeability heterogeneities, there may be a tendency for the injected gas to streak, that is to preferentially follow certain pathways between the injection and recovery wells. The result is that part of the coal is not contacted. To minimize this effect, the method makes use of intermittent injection of water. The water selectively fills the higher permeability regions so that, once gas injection is resumed, the gas is redirected into regions of lower permeability. Thus, the desorbing gas is made to contact a larger volume of coal. An example shows that after one year of methane production using the standard pressure depletion method (removal of connate water), it can take an additional 3-5 years of the gas-injection process before methane production tails off and CO2 content in the recovery well begins to equal CO2 injected. 2. Coal Bed Methane Recovery. Patent No.: US 5,402,847 Patent Date: April 4, 1995 Inventors: Wilson, D.R. et al. Assignee: Conoco Inc. Method and Claims: The method is suited for operation after a period of methane production by pressure depletion when some of the water removal wells can be converted to gas injection wells. In this method, the CO2 is contained in exhaust gases generated by a dedicated diesel or other internal combustion engine. (This particular aspect of the patent defeats the purpose of the study but industrial flue gas could perhaps be substituted as a CO2 source.) The gas is injected at a JAF98172.DOC 138 Advanced Resources International, Inc. IEA Greenhouse Gas R&D Programme Worldwide CO2-ECBM Assessment temperature of at least 350° F and a pressure of at least 2,000 psi. The high temperature vaporizes the formation water, which otherwise would impede the flow of the injection gas, and the water vapor and remaining liquid water are expelled by the injection gas. Dehydration causes the shrinkage of the coal and enlargement of cleats and creation of new interstices, leading to an increase in coalbed permeability, especially near the injection well. The high temperature also minimizes adsorption of CO2 near the injection well which would cause the coal to swell and lose permeability. Permeability around the injection well can be further enhanced by cyclically varying the injection gas temperature, the expansion and contraction causing new fractures or enlarging existing ones. 3. Method of Recovery of Natural Gases from Underground Coal Formations. Patent No.: US 5,332,036 Patent Date: July 26, 1994 Inventors: Shirley, A.I. et al. Assignee: The BOC Group, Inc. Method and Claims: As a first step, carbon dioxide, ideally liquefied, or a gaseous mixture preferably containing at least 75% CO2, is injected into a coal seam to cause desorption of methane. This is followed by injection of a weakly adsorbable propellant gas, such as nitrogen (preferably), argon, helium or air, which forces the CO2 plus the desorbed methane ahead of it through the coal seam towards the recovery well. The CO2 acts as a buffer between the methane and the propellant gas, allowing methane to be recovered along with any remaining C02 until the propellant gas breaks through at the recovery well. At this point gas recovery is ceased in order not to dilute the methane with propellant. Any CO2 recovered with the methane can easily be separated out (and reinjected) because of the large difference in the boiling points of these two gases, whereas nitrogen or other propellant gases are more difficult to strip from methane. 4. Method for Removing Methane from Coal. Patent No.: US 4,043,395 Patent Date: August 23,1977 Inventors: Every, R.L. et al. Assignee: Conoco, Inc. Method and Claims: This method employs a pulsed injection and recovery procedure. A carbon dioxide-containing fluid, which can include industrial flue gas, is injected into a coal seam. Injection is then ceased for a period typically of several hours, after which the recovery well is opened and the desorbed methane and residual injection gas are produced. The process is repeated until methane recovery falls below an acceptable level. The advantage of the pulsed method over continuous injection is that it attenuates the streaking effect where flow is concentrated along the higher permeability pathways between the injection and recovery wells. The shut-in period allows the CO2 to contact more of the coal by permeating more evenly through the seam, thus increasing the amount of methane desorbed. In laboratory experiments, it is shown that, for a like operating period, substantially more methane is displaced using the pulsed method than with either continuous injection or extended shut-in periods. JAF98172.DOC 139 Advanced Resources International, Inc.