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Abstract Indonesia has thick, low-rank coal deposits that are prospective for coalbed methane (CBM) development but remain untested. Conventional oil and gas wells that drill through these coal seams experience gas kicks and blow outs, good CBM indicators. We analyzed petroleum and coal mining data to perform a comprehensive assessment of Indonesia’s CBM resources. We identified 12.7 trillion m3 (450 Tcf) of prospective CBM resources within eleven onshore coal basins. Full-cycle development costs in high-graded areas are estimated at $0.70/Mcf. These potential CBM reservoirs could be tested at low cost using coreholes or production “wells of opportunity.” Introduction Coalbed methane (CBM), which is methane desorbed and produced from deep coal seams, has become a significant source of natural gas supply in the USA. From humble beginnings in the 1980’s, CBM production has steadily grown to the current 127 million m3/day (4.5 Bcfd), nearly 10% of total USA natural gas production. CBM reserves at the end of 2002 stood at 18.5 Tcf. Cumulative reserve additions, including past production, total nearly 30 Tcf. Much of this reserve is low-cost natural gas with all-in supply costs of under $1.00/Mcf. Outside the USA, CBM is undergoing initial commercial development in Australia and Canada, while exploration is underway in China, India, South Africa and several other coal-rich countries.

Indonesia has extensive coal deposits distributed in eleven

onshore coal basins (Figure 1), yet has not yet experienced significant CBM testing [1]. There has been a perception by CBM operators that Indonesia’s coal deposits are too shallow and too low rank to be prospective. After all, Indonesia’s coal mining sector produces primarily lignite or sub-bituminous

coal from open-pit mines that have no significant methane control issues.

However, this perception is changing due to several

factors: a) The success of low-rank CBM development in the Powder River Basin, Wyoming, USA, where gas production is more than 28 million m3/day (1.0 Bcfd) and increasing rapidly; b) improved understanding that the shallow coal seams mined at the surface in Indonesia dip basinward and become gas charged at CBM target depths (100-1,500 m) over broad areas; and c) strong and nearly ubiquitous gas kicks that are recorded on petroleum well mud logs as these deep coal seams are penetrated, sometimes causing hole stability problems, and indicating that the coals have adsorbed large quantities of methane.

This study was supported by the Asian Development Bank

and Indonesia’s Department of Energy and Mineral Resources (MIGAS). It builds on earlier data compilation efforts supported by PT Caltex Pacific Indonesia and Pertamina [2,3] and laboratory work performed by the Indonesian Ministry of Energy and Mineral Resources [4]. A separate component of the project, not discussed here, involved assisting MIGAS in formulating regulations for commercial CBM investment and development. Data Control Extensive surface and subsurface data are available in Indonesia for basic CBM parameters such as coal thickness, depth, rank and other coal properties. We assembled a GIS data base of these coal properties acquired from coal exploration coreholes, deep petroleum exploration well logs, measured coal outcrop sections, and laboratory data such as vitrinite reflectance and volatile matter analyses. Recently, adsorption isotherms have been run on a handful of coal samples, which remain confidential. Other data on CBM-specific reservoir properties remain scarce or non-existent. Coal seam permeability has not yet been tested in situ using well testing. No CBM production wells have been tested to date, nor has hydraulic fracturing of coal seams been attempted. Despite this paucity of data, it is still possible to make rough estimates of in-place CBM resource distribution and potential producibility. Basin characteristics are summarized in Table 1.

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Indonesia: Coalbed Methane Indicators and Basin Evaluation Scott H. Stevens, Advanced Resources International, Inc., SPE Hadiyanto, Indonesian Ministry of Energy and Mineral Resources, Directorate General of Geology and Mineral Resources

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CBM Geology Thick, economically important coal deposits occur in Indonesia, formed in Tertiary back-arc rift basins that developed throughout Southeast Asia [5]. The islands of Sumatra and Borneo (Kalimantan province) account for the vast majority of Indonesia’s coal and CBM potential. Coal deposits of two primary ages occur, providing varied coalbed methane reservoir settings. The younger (Miocene) coals, such as the Muara Enim Formation and equivalents, appear to be the more prospective. Although relatively low in rank, they are extremely thick. Coal typically comprises 10 to 20% of total formation thickness. A total of 20 to 30 individual coal seams are present, in stratigraphically concentrated groups presenting attractive completion targets with over 30 m of net coal, in places considerably more. The Miocene coal is low in rank (lignite to sub-bituminous with Ro of 0.3 to 0.5%), and relatively shallow (outcrop to 1,000 m). High in moisture (around 10%), these coal deposits are extremely low in ash content (<5%). Overall, Indonesia’s Miocene coal deposits are thicker, deeper, and somewhat higher in rank than CBM reservoirs in the Powder River basin.

Older coal deposits occur in the Eocene Tanjung Formation and its equivalents, which contain thin to moderately thick (1-10 m net) coal deposits. Typically, they are buried much deeper than the Miocene coals (1,000 to 2,000 m) and thus have been subjected to greater thermal alteration, attaining low to moderate rank (sub-bituminous to bituminous). Poorly characterized, these Eocene deposits appear to present less attractive CBM targets, due to their thinner and deeper coals, but may be locally prospective. CBM Reservoir Properties Apart from coal depth, thickness, rank, quality, and maceral composition, coal reservoir properties are still poorly characterized in Indonesia. The coal-bearing sequences are much shallower than the conventional oil and gas targets and thus rarely cored or tested. Adsorption Isotherms. Methane adsorption isotherms were determined for about one dozen low-rank coal samples (lignite to sub-bituminous) from Sumatra and Kalimantan. These isotherms were measured at constant 27oC temperature and equilibrium moisture conditions. Sorptive capacity varied widely with rank, reaching as much as 15 m3/t (480 ft3/ton) on a dry, ash-free basis for high-volatile C rank coal (Ro = 0.69%) at a pressure of 1200 psi, which is equivalent to a typical CBM target depth of about 850 m under a hydrostatic pressure gradient (Figure 2). More typically, sub-bituminous rank coal (Ro = 0.41% to 0.46%) can adsorb 4.7 to 8.1 m3/t (150 to 260 ft3/ton) of methane at 1200-psi pressure.

It should be noted that most coal samples that have been analyzed for sorptive capacity were obtained from shallow outcrops or coal mines; coals at CBM-target depth are higher in rank, lower in moisture, and likely to have significantly higher sorptive capacity. On the other hand, reservoir temperature can be high at target depth (70°C), which would tend to reduce methane adsorption capacity. To better approximate actual CBM target conditions, rather than outcrop conditions, we estimated a synthetic sorption isotherm for sub-

bituminous coal at slightly elevated rank (Ro = 0.50%), shown as the heavy line on Figure 2. Gas Content. Gas kicks frequently occur while drilling through the shallow coals, indicating at least partial methane saturation. A limited number of gas content desorption measurements have taken place but remain confidential. Permeability. Not yet tested in situ, coal seam permeability is estimated to be low to moderate in Indonesian basins. Cleat development at shallow outcrop and coal mine locations generally is poor. However, the coal is typically high in vitrinite maceral content (>90%), with low inertinite and liptinite contents (<10%), which could promote cleat development in deeper, more thermally mature coals. Most of the coal basins in Indonesia are tectonically extensional, experiencing only local compression or transpressional forces; this setting suggests possible low horizontal stress and favorable permeability. High-Graded CBM Basin Characteristics We ranked Indonesia’s CBM basins based on geology, inferred reservoir quality, proximity to gas markets, drilling infrastructure, and other factors. The following summarizes the CBM characteristics of the top-ranked coal basins. South Sumatra Basin. This large (100,000 km2) coal- and petroleum-producing basin is a NW-SE trending half graben containing coals of Eocene and Miocene age (Figure 3). The basin is asymmetric, with the thickest sediments formed in the west-central region, while sediments thin towards the east as they pinch out against the Sunda landmass. The basin is sub-divided into a series of fault-controlled depressions separated by basement-cored structural highs. These depressions – notably the Jambi, Central Palembang, and South Palembang/Lematang sub-basins – contain the thickest coals, located at optimal CBM target depth. Consequently, the depressions represent the most CBM-prospective portions of the South Sumatra basin. In contrast, the structural highs (or anticlinoria) generally have thin and shallow coals that are less prospective. This contradicts the geometry of the conventional oil and gas deposits, which are concentrated in the structural highs; thus, data control in the troughs is not as complete as on the highs.

Coal seams in South Sumatra show remarkable lateral continuity. For example, the Mangus Seam in southern South Sumatra basin has been correlated over a distance of 140 km surrounding the Bukit Asam coal mine, while other seams are traceable for over 50 km. Not all coal seams will be “completeable” in CBM production wells. Based on three hydraulic stimulations per well completion, and assuming 30-m vertical height growth, we estimate that average completeable coal thickness in South Sumatra will be approximately 40 m. This represents one of the thickest and laterally most extensive CBM targets in the world, aerially larger and thicker than the coal packages typically completed in the Powder River basin.

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Coal rank is relatively low in South Sumatra, primarily lignite to sub-bituminous grade. Rank data most commonly cited in the literature was obtained from surface outcrops and shallow mines, where the vitrinite reflectance (Ro) is only about 0.3%. However, coal rank increases gradually with depth in South Sumatra, which is a back-arc tectonic setting with high heat flow. For example, coal rank in the Bungin No. 1 petroleum well increased gradually to about 0.5% Ro at CBM target depths of 600 m (Figure 4). The vitrinite reflectance of South Sumatra basin coal targets is significantly higher than those in the Powder River basin, where Ro averages only 0.3%.

Gas content has not yet been measured in South Sumatra using standard direct desorption methods from core. However, many petroleum wells in this basin experienced gas kicks while drilling through deep coal seams. Figure 5 shows a typical petroleum exploration well in the basin exhibiting gas kicks, even from shallow (200 m deep) coal seams. This indicates that at least some methane has sorbed onto the coal, although it does not necessarily prove gas saturation. Sorption isotherms performed on Muara Enim coals indicate potential gas contents of around 7 m3/t (225 scf/ton; dry, ash-free basis), assuming saturated conditions and a normal hydrostatic pressure gradient. The composition of gas adsorbed in these coal reservoirs is unknown. CO2 is a common constituent of deep conventional gas fields in South Sumatra, reaching levels of 30% or higher in the Corridor Block. However, shallow formations generally contain much lower CO2 contents, reflecting the deep volcanic source likely for CO2 in South Sumatra. We anticipate that CBM targets in South Sumatra will have low CO2 (<5%).

Reservoir pressure gradients were estimated from 30 well tests conducted in conventional formations the South Sumatra basin. The pressure/depth gradient averages at or slightly above hydrostatic levels, approximately 0.45 psi/foot. Deeper horizons below 1,500 m can reach gradients of over 0.5 psi/foot. Temperature is somewhat elevated due to the high geothermal gradient in this back-arc tectonic setting. We estimate typical reservoir temperature of 68°C at target depth (600 m). Coal seam permeability and stress have not yet been tested in-situ.

CBM resources in South Sumatra were estimated volumetrically based on coal thickness and sorption isotherm data. We mapped and high-graded an 18,800 km2 area (19% of the basin) that appears to be the most prospective area, containing thick coals at target depths of 150 to 1,500 m. We used the following reservoir parameters to compute prospective gas in place. Depth-prospective area = 18,800 km2 (4.7 MM ac) Completeable coal thickness = 36.6 m (120 ft) Ash Content = 10% Moisture Content = 7.5% Coal Density = 1,800 tons/acre-ft CO2 Content = 3% CH4 Content = 7.0 m3/t (223 scf/ton)

Using standard volumetric computation, Gas in Place (GIP) = {120 ft x (1 – 0.1 ash) x (1 – 0.075 moisture) x 1,800 ton/ac-ft x (1 – 0.03 CO2) x 223 scf/ton x 4,704,000 acres}

= 5.2 x 1012 m3 (183 Tcf)

Note that this represents prospective CBM resources that could be completed using a standard 3-frac per well completion strategy. Additional CBM resources exist in thinner isolated coal seams and in coals that are deeper or shallower than assumed by our screening parameters. Central Sumatra Basin. The 80,000-km2 Central Sumatra basin contains thick coals in the Miocene-Pliocene Upper Petani (or Korinci) Formation. Other coal-bearing units include the Early Miocene Sihapas Formation and the Eocene-Oligocene Lower Pematang Formation, but these tend to be much too deep for CBM development. Net coal thickness reaches 30 m in places, of which 15 m may be completeable in a 3-frac CBM well. Coal rank is lignite to sub-bituminous with estimated gas contents of 4.5 m3/t (145 scf/ton) at target depths of 750 m. Just as in South Sumatra, the structural depressions contain the thickest coal deposits, yet are seldom drilled and lack data control. Much of the coal resource is deeper than 1,500 m and may have low permeability. Central Sumatra is the site of Duri steamflood, a heavy oil field which consumes about 11 million m3/day of natural gas (400 MMcfd). We estimate completeable CBM resources at 1.0 x 1012 m3 (34 Tcf), based on prospective areas of 13,350 km2, 15 m completeable coal thickness, coal density of 1,800 tons per acre foot, 10% ash content, gas content of 4.5 m3/t (145 scf/ton), and 2% CO2. Barito Basin. Although not a significant oil and gas producer, the Barito basin contains gas-charged coal seams totaling up to 150 m thick, and at optimal depth over large areas. However, gas markets and operational logistics are inferior to those in South Sumatra. The Barito basin extends over 60,000 km2 in southeastern Kalimantan, of which the southern 15,000 km2 appears most prospective, particularly near the regional capital of Banjarmasin. Sediments are folded and faulted along the eastern basin margin near the Meratus Mountains, but are gently dipping and minimally faulted over 90% of the basin area west of this front. The Miocene Warukin Formation contains thick (30 to 150 m) coals of sub-bituminous rank. The Eocene Tanjung Formation contains thinner (15 m) bituminous rank coals, but is generally too deep to be prospective for CBM development.

We estimate completeable CBM resources of 2.9 x 1012 m3 (102 Tcf) within a 16,000-km2 high-graded area of the south-central Barito basin. This area is characterized by 30 m of completeable coal thickness, depth of approximately 800 m, vitrinite reflectance of 0.45%, gas content estimated at 4.7 m3/t (150 scf/ton), and low ash and CO2 contents. Figure 6 shows strong gas kicks associated with thick coal seams in a typical Barito basin petroleum exploration well, indicating the tremendous potential of this basin for CBM development.

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Kutei Basin. Located in eastern Kalimantan, the 100,000-km2 Kutei basin is a major oil and gas producing province. Like the Barito basin, the Kutei basin has thick (up to 50 m), gas-charged coal seams at optimal depth over large areas. But it also has considerable bituminous coal deposits, with some of the highest ranks in Indonesia. Gas markets and operational logistics are more established. Folding and faulting is more prevalent, with numerous tight anticlines separating broader, flat synclines. The primary CBM targets are the Lower Miocene Kamboja and the Mid-Miocene Prangat Formations of the Balikpapan Group, which has up to 50 m of net coal dispersed amongst 10 coal seams, some of which are traceable over distances of 20 km. The Loa Kulu Formation at the top of the Lower Miocene Bebulu Group has high-volatile C bituminous rank coal but is much thinner (3 m). Bituminous coals occur in the Eocene Tanjung Group, but are thinner and too deep for CBM development in most of the basin.

We estimate completeable CBM resources of 1.4 x 1012 m3 (51 Tcf) within a 15,600-km2 high-graded area of the eastern Kutei basin. This area is characterized by 21 m of completeable coal thickness, depth of approximately 900 m, vitrinite reflectance of 0.5%, gas content estimated at around 6.1 m3/t (195 scf/ton), and low ash and CO2 contents. Berau Basin. Located just north of the Kutei basin in eastern Kalimantan, the smaller 10,000-km2 Berau basin is a major coal-producing area but only a minor producer of oil and gas. Miocene coal seams in the Latih Formation total up to 150 m thick, some 6-9% of total formation thickness. The Eocene Sujau Formation also contains thinner coals. Rank is sub-bituminous to high-volatile bituminous. Structure is simple, with few folds and faults. Gas markets are limited. We estimate 0.2 x 1012 m3 (8 Tcf) of completeable CBM resources within a 780-km2 high-graded area of the southern Berau basin. This area is characterized by 30 m of completeable coal thickness, average target depth of approximately 700 m, vitrinite reflectance of 0.45%, gas content estimated at around 4.5 m3/t (144 scf/ton), and low ash and CO2 contents. North Tarakan Basin. Located in northeastern Kalimantan, the 45,000-km2 North Tarakan basin includes the Tidung and Tarakan sub-basins. The basin currently has limited oil and gas production onshore. CBM targets include the Miocene Meliat and Tabul Formations, which contain 50-80 m of sub-bituminous to bituminous coal. Thick lignite with limited CBM potential also occurs in the Pliocene-Pleistocene Tarakan and Bunyu Formations. The Tabul Formation has an estimated 15 m of completeable coal thickness, including individual seams up to 6 m thick. We estimate 0.5 x 1012 m3 (18 Tcf) of completeable CBM resources within a 7,000-km2 high-graded area of the eastern North Tarakan basin. This area is characterized by 15 m of completeable coal thickness, average target depth of approximately 700 m, vitrinite reflectance of 0.45%, gas content estimated at around 4.5 m3/t (144 scf/ton), and low ash and CO2 contents. Other Basins. Indonesia has other coal basins with CBM potential, but they appear less prospective than the South Sumatra, Central Sumatra, Barito, Kutei, Berau, and North

Tarakan basins. The Ombilin basin in Sumatra has high-grade bituminous coal mined in deep, gas-prone underground coal mines. However, prospective area is limited (50 km2), and petroleum wells there have tested high CO2 levels of 40-70%. The Jatibarang basin in north Java is located close to Jakarta, but coals are extremely deep (>2,000 m) and may have low permeability. The Bengkulu basin in southwestern Sumatra is productive for coal but too structurally complex for CBM development. Nevertheless, experience in the USA has shown repeatedly that unpopular CBM basins can be made productive with improved geologic understanding and well completion technology. Drilling and Completion Strategies Indonesian CBM targets will present numerous operational challenges. Fortunately, the country’s petroleum service sector already has experience with mature oil field operations and enhanced oil recovery, which in many ways resembles CBM operations. Mature oil fields, such as Duri with the world’s largest steamflood, contain thousands of closely spaced wells developed on swamp lands. Water production in these fields is extremely high, yet technically and environmentally manageable. Hydraulic fracturing is commonly used in the oil fields, as are shallow drilling rigs with wireline core retrieval. All in all, Indonesia’s service sector is better equipped than most other coal-rich countries were for initial CBM development.

The main CBM operational challenges in Indonesia are likely to be surface access and high water production. Given the coal reservoir geometry (generally few, extremely thick coal seams), conventional vertical wells are likely to be most effective in Indonesia. Powder River basin wells do not require stimulation due to the unusually high coal seam permeability (100 – 1,000 mD). However, we anticipate that Indonesia coal seam permeability will be considerably lower (1 to 10 mD), based on poor cleat development in low-rank coals, and thus production wells will require hydraulic stimulation. Generally, one to three fracs per well would be expected to stimulate most of the coal package.

Development risk could be reduced by testing coal targets

in conventional oil and gas wells or by implementing a program of low-cost, expendable coreholes to test coal seam gas content, permeability and other reservoir properties. If well testing is promising, this should be followed by a 5-well pilot to evaluate producibility of the resource [6]. Indonesia’s mining sector employs wireline rigs that could drill test CBM coreholes quickly and cheaply. In some areas, such as South Sumatra, operators routinely drill through shallow CBM targets en route to deeper conventional reservoirs. These coals often are unstable and considered a drilling hazard; similar blowouts in deep coals led to the discovery of the highly productive (20 Tcf) San Juan basin CBM deposit in the USA. By adding a few extra days of rig time, coal seams encountered in conventional wells could be cored, desorbed to measure gas content, and tested to measure permeability using DST or injection/falloff methods.

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CBM prospective areas in Indonesia are often swampy and remote, requiring construction of roads and drilling sites for potentially thousands of CBM wells. Construction costs and environmental impacts could be mitigated by the application of horizontal drilling, a new technology that has been used for over 500 CBM well completions in the USA to date [7]. Our scoping reservoir simulation indicates that the low-rank, high-porosity coals in Indonesia could produce over 5,000 barrels/day per well during early-stage dewatering operations and thus would need to be equipped with high-capacity beam pumps. Fortunately, the produced water is likely to be low in dissolved solids, so that minimal treatment could allow discharge in Indonesia’s numerous high-capacity rivers and streams. Alternatively, produced water could be reinjected into waterflooded oil fields.

Conclusions

1. We estimate that Indonesia has approximately 450 Tcf of prosective coalbed methane resources, contained in onshore coal basins screened for depth (500 to 4,500 m) and assuming a three-frac-per-well completion strategy. Given ultimate reserve/resource conversion rates of 10% or more in the USA, and assuming adequate investment, Indonesia may eventually achieve CBM reserves of 50 Tcf, equivalent to about one-third of current conventional gas reserves.

2. The South Sumatra basin appears most prospective

for CBM development: the Miocene Muara Enim Fm at contains up to 100 m of sub-bituminous (Ro=0.4-0.5%), high-vitrinite (>90%) coal with extremely low ash (<10%) at target depths of 300-1,000 m. CBM resources in South Sumatra are estimated at 5.2 trillion m3 (183 Tcf), with resource concentrations of up to 0.7 billion m3/km2 (60 Bcf/mi2). As a petroleum producing basin, South Sumatra also has favorable data control, reservoir quality, drilling services, surface access, and gas markets. Compared with the prolific Powder River basin CBM play in the USA, which currently produces 28 million m3/day (1 Bcfd), CBM resources in South Sumatra are thicker, deeper, and higher in rank. Full-cycle development costs could be in the range of $0.50 to $1.00/Mcf.

3. The Barito (102 Tcf) and Kutei (80 Tcf) basins in

Kalimantan also are prospective, but situated further from markets. The Central Sumatra basin has an estimated 53 Tcf resource but coal seams are mainly deeper and thinner. The Berau and North Tarakan basins also have favorable reservoir properties but less data control. Other basins are much less prospective: the Ombilin basin is small and has high CO2 content; the Bengkulu basin is structurally complex; the Jatibarang basin is extremely deep; and the South Sulawesi basin has thin coals.

4. Indonesia’s significant CBM potential could be tested

at low cost using in-country mining rigs to drill expendable coreholes for measuring coal seam gas

content and permeability. This could be followed by a 5-well production pilot to evaluate producibility.

Acknowledgments The authors wish to thank MIGAS, the Asian Development Bank, PT Caltex Pacific Indonesia, and other groups for data and support provided in conducting this study.

Nomenclature Ac acres (0.00405 km2) Bcf billion (109) cubic feet Bcf/mi2 billion cubic feet per square mile Bwpd barrels of water per day C centigrade cbm coalbed methane ft foot km kilometer m meter mD millidarcy of permeability m3/t cubic meters per metric tonne mi mile Mcf thousand (103) cubic feet MMcf million (106) cubic feet psi pounds per square inch Ro vitrinite reflectance scf/ton standard cubic feet per short ton Tcf trillion (1012) cubic feet References 1. Nugroho, W. and Arsegianto: “Future Prospect of Coalbed

Methane in Indonesia.” Proceedings of the 1993 International Coalbed Methane Symposium, University of Alabama, Tuscaloosa, Alabama, USA, 17-21 May, 1993, p. 721-726.

2. Stevens, S.H., Sani, K., and Sutarno, H.: “Indonesia’s 337 Tcf CBM Resource a Low-Cost Alternative to Gas, LNG.” Oil & Gas Journal, October 22, 2001, p. 40-45.

3. Stevens, S.H. and Sani, K., “Coalbed Methane Potential of Indonesia: Preliminary Evaluation of a New Natural Gas Source.” Proceedings, Indonesian Petroleum Association, Twenty-Eighth Annual Convention & Exhibition, February 26-28, 2002.

4. Saghafi, A. and Hadiyanto, “Methane Storage Properties of Indonesian Tertiary Coals.” Proceedings of the Southeast Asian Coal Geology Conference, Bandung, Indonesia, 19-20 June, 2000, p. 121-124.

5. Friederich, M.C., Liu, G., Langford, R., Nas, C., and Ratanasthien, B.: “Coal in Tertiary Rift Systems in Southeast Asia.” Proceedings of the Southeast Asian Coal Geology Conference, Bandung, Indonesia, 19-20 June, 2000, p. 33-43.

6. McCants, C.Y., Spafford, S., and Stevens, S.H., “Five-Spot Production Pilot on Tight Spacing: Rapid Evaluation of a Coalbed Methane Block in the Upper Silesian Basin, Poland.” Proceedings of the 2001 International Coalbed Methane Symposium, University of Alabama, Tuscaloosa, Alabama, USA, 14-18 May, 2001, p. 193-204.

7. von Schoenfeldt, H., Zupanik, J., Wight, D., and Stevens, S.H., “Unconventional Drilling Methods for Unconventional Reservoirs In the US and Overseas.” Proceedings of the 2004 International Coalbed Methane Symposium, University of Alabama, Tuscaloosa, Alabama, USA, 3-7 May, 2004.

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Basin Province Target Completeable Coal Avg High- CBM ResourcesForm- Coal Rank Depth Graded Complet- Concen-ation Thickness Area able tration

(m) (Ro%) (m) (km2) (Tcf) (Bcf/mi2)1 S. Sumatra Sumatra M.Enim 37 0.47 762 7,350 183.0 24.92 Barito Kalimantan Warukin 28 0.45 915 6,330 101.6 16.03 Kutei Kalimantan Prangat 21 0.50 915 6,100 80.4 13.24 C. Sumatra Sumatra Petani 15 0.40 762 5,150 52.5 10.25 N. Tarakan Kalimantan Tabul 15 0.45 701 2,734 17.5 6.46 Berau Kalimantan Latih 24 0.45 671 780 8.4 10.87 Ombilin Sumatra Sawaht 24 0.80 762 47 0.5 10.78 Pasir/Asem Kalimantan Warukin 15 0.45 701 385 3.0 7.99 NW Java Java T. Akar 6 0.70 1524 100 0.8 7.610 Sulawesi Sulawesi Toraja 6 0.55 610 500 2.0 4.011 Bengkulu Sumatra Lemau 12 0.40 610 772 3.6 4.7

Total 30,248 453.3 15.0

Table 1 : Summary of Typical CBM Reservoir Properties of Indonesian Coal Basins

Figure 1 : Location of Indonesian Coal Basins with CBM Potential

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Figure 2 : Adsorption Isotherms Measured on Indonesian Coal Samples of Varying Rank

Figure 3 : Map of South Sumatra Basin Showing High-Graded CBM Area

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Figure 4 : Depth Vs. Coal Rank in the Bungin No. 1 Petroleum Exploration Well, South Sumatra Basin, Indonesia

Figure 5 (Left) : South Sumatra Basin - Coal Section Showing Gas Kicks

Figure 6 (Right) : Barito Basin – Coal Section Showing Gas Kicks