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IPA01-G-063

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION

Twenty-Eighth Annual Convention & Exhibition, October 2001

COALBED METHANE POTENTIAL OF INDONESIA: PRELIMINARY EVALUATION OF A NEW NATURAL GAS SOURCE

Scott H. Stevens* Kartono Sani**

ABSTRACT A study conducted by PT Caltex Pacific Indonesia and Advanced Resources International, Inc. evaluated the coalbed methane (CBM) potential of Indonesia, the first rigorous study of this emerging natural gas resource. Well and seismic data provided by Pertamina and the Directorate of Coal showed CBM potential in a number of onshore Indonesian basins. CBM has been overlooked in Indonesia because (a) Coal rank is low (sub-bituminous) at surface outcrop; and (b) Nearly all coal mining takes place near the surface, where CBM gas content is negligible. However, our analysis indicates that geologic conditions at CBM completion depths (1,000 to 4,000 ft) are much more favorable. Well log and seismic data define thick, flat-lying, laterally continuous coal units in broad structural troughs, often associated with strong gas kicks. Coal rank increases from lignite at the surface to more prospective bituminous rank at target depth. CO2 content is low. Since 1985, over 20 Tcf of CBM reserves have been booked in the USA. CBM currently accounts for 7% of total U.S. gas production. Exploration focus has shifted towards lower rank settings, such as the Powder River (Ro=0.3%) and Uinta (Ro=0.6%) basins. Indonesian coals are thicker, deeper and higher in rank compared with Powder River basin coal reservoirs and could be more productive. We estimate that Indonesia has 337 Tcf of potentially completable CBM resources in the South and Central Sumatra, Barito, Kutei and other coal basins. Based on USA experience, 10% of this resource – 30 Tcf – may occur in high-quality, gas-saturated, permeable “fairways,” where development may be economic. ___________________________________________________________ * Advanced Resources International, Inc. ** P.T. Caltex Pacific Indonesia

However, CBM development costs will likely be higher in Indonesia than in the U.S., at least initially, and fiscal incentives may be required to jump-start this new gas supply source. INTRODUCTION During the past two decades, new technology has been developed in the United States to produce methane from deep coal seams. Not to be confused with experimental underground coal gasification, coalbed methane (CBM) production utilizes largely conventional petroleum production technology and can be highly profitable in favorable geologic settings. From its beginnings in the 1970’s as a coal mine degasification technique, CBM production technology and the new CBM production industry have grown rapidly. Early development was encouraged by a production tax credit equivalent to about $1.00/Mcf. Initial development took place in the Warrior basin in Alabama and the San Juan basin in Colorado and New Mexico (Figure 1). After the Section 29 tax credit expired for new development at the end of 1992, commercial development expanded to four additional basins (the Raton basin in Colorado and New Mexico, the Powder River basin in Wyoming and Montana, the Central Appalachian basin in Virginia, and the Uinta basin in Utah). Today, CBM is a significant component of natural gas supply in the U.S., representing 7% of total gas production and 8% of gas reserves in 1999. CBM production totaled about 1.2 trillion cubic feet (Tcf), or 3.3 billion cubic feet per day (Bcfd) from over 10,000 wells (U.S. DOE, 2000). CBM production in the U.S. is nearly half of Indonesia’s current marketed natural gas production and two-thirds the energy equivalent of Indonesia’s current coal production (Figure 2).

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Major CBM producers in the U.S. include Burlington Resources, BP, Phillips, Devon Energy, Marathon, Conoco, Texaco, as well as numerous smaller companies. Several coal companies, such as Jim Walters Resources and Consol, are also significant producers and rely on CBM recovery to reduce methane levels in their coal mine ventilation systems. Starting in the early 1990’s, CBM exploration accelerated outside the U.S. Significant CBM testing, including clustered multi-well pilots, has been conducted in Australia, China, Poland, Germany, and the Czech Republic (Stevens, 1999). India, South Africa, Zimbabwe, Russia, Kazakhstan, and many other countries have also experienced exploration, generally restricted to isolated wells (Kelafant and Stern, 1998). Major international CBM operators have included Amoco, Arco, BP, Enron, Texaco, Phillips, and Conoco. So far, results outside the U.S. have been mixed, due to complex geology and the high cost of operations. Indonesia has significant deep coal resources but has been almost completely overlooked by CBM operators. This may be because the coal mined in Indonesia is generally of low rank and is produced from surface mines. Not surprisingly, Indonesian strip mines report negligible methane contents. However, deep petroleum well data from throughout Indonesia indicate that: 1) coal rank increases rapidly with depth in many Indonesian basins; and 2) gas kicks are almost universally associated with thick coal seams in Indonesia below 1,000 ft depth. This evidence is indirect, requiring confirmation by in-situ gas content or permeability measurement. Recent CBM drilling in the U.S. has shifted to lower rank settings that more closely resemble Indonesian coal basins. During 1999, some 1,800 CBM wells were completed in the Powder River basin, with a further 100 new wells in the Uinta basin. Formerly, these basins had been considered too immature for successful CBM development. In light of these developments, Indonesian CBM resources appear much more prospective. PT Caltex Pacific Indonesia (Caltex) and Advanced Resources International, Inc. (ARI) recently completed a 4-year evaluation of the CBM potential of Indonesia. For this study, Pertamina provided extensive deep well and seismic data from throughout Indonesia. The Indonesian Directorate of Coal

provided coal borehole data, samples, and mine evaluations. The study synthesized diverse petroleum and coal industry well log, seismic, and laboratory data, generating the first comprehensive view of the CBM potential of Indonesia. Non-confidential aspects of this study are discussed in this article, which summarizes earlier presentations by Sani (2000) and Stevens and Soetoto (2000). CBM PRODUCTION MECHANISMS

Deep coal seams can store large volumes of methane on the surface of coal under pressure. Methane is produced by first pumping off large volumes of formation water to reduce reservoir pressure. As pressure declines, sorbed methane is released (desorbed) into the coal matrix (Figure 3). Methane then flows by diffusion to the cleat and fracture system of the coal, and finally via Darcy flow to a production wellbore.

The unique storage and release mechanisms of a CBM reservoir result in an unconventional gas and water production profile (Figure 4). Initially, water production is high while gas production rates are usually discouragingly low. However, as reservoir pressure declines, the ever-steepening slope of the sorption isotherm curve yields accelerating gas desorption. Simultaneously, higher gas saturation in the cleat system improves the relative permeability to gas in the two-phase (gas/water) flow regime. Consequently, CBM gas production often peaks as late as year 4 to 6, with slower decline in later years compared with conventional gas wells. Nearly all coal contains some methane, but commercial production requires two less common reservoir characteristics: high fracture/cleat permeability and gas saturation. Whereas most coals are relatively tight (k < 1.0 md) -- particularly in structurally complex, high-stress settings -- permeability in more favorable areas can range from 5 to 100 md (or higher). The second requirement for commercial CBM production is high gas saturation, where actual gas content approaches the theoretical storage capacity of the coal.

Because CBM reservoirs take months or years to dewater, identifying good quality production areas quickly can be challenging. The closest operational analogy for Indonesia may be thermal EOR operations in Central Sumatra, where multi-well

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pilots on close spacing are used to evaluate expansion to full-scale flooding. The same strategy is used for CBM testing and development to limit risk and achieve an early go/no-go decision on full-field development. The Drunkards Wash CBM project in the Uinta Basin, Utah provides an excellent example of the early challenges facing CBM operators during initial development (Figure 5). The first three wells at this field averaged low gas rates of 30 to 50 Mcfd/well, with no dewatering (Phase I). The operator tried to farm out the prospect to over 100 companies, without success. After the operator added a dozen more wells during the second year of the pilot (Phase II), dewatering of the reservoir improved and gas production increased to a more acceptable 200 Mcfd/well. Today (Phase III), this project averages over 700 Mcfd/well and is the most successful CBM development outside the San Juan basin, with over 500 Bcf of reserve additions from 200 wells. “Management fatigue” with early, apparently negative results is a common challenge facing CBM development and will undoubtedly confront CBM operators in Indonesia. INDONESIAN CBM RESERVOIRS The coal geology of Indonesia has been relatively well documented, but no comprehensive analysis of CBM potential has been published. Early studies identified coal basins with CBM potential, including an initial highly preliminary resource estimate of 213 Tcf of gas in place (Nugroho and Arsegianto, 1993a and b; Suyartono and Ginting, 1995). Our study identified eleven major coal basins with CBM potential in onshore Indonesia (Figure 6). These basins may be grouped into two general tectonic settings: the relatively undeformed cratonic setting of east and south Kalimantan; and the active tectonic setting of Sumatra-Java (Table 1). Other onshore basins were initially considered but found to be too small or too remote from gas markets. Additional coal basins lay offshore. These were not evaluated due to high development costs (offshore CBM resources have not yet been developed due to the tight 40- to 320-acre well spacing required). Most basins were constrained by at least a dozen petroleum wells and numerous coal exploration boreholes; some also had seismic data.

Indonesian coal deposits are associated with the Eocene-Oligocene syn-rift and Late Miocene-Pliocene regressive sequences of the Tertiary basins (Koesoemadinata, 2000). The principal coal-bearing units are the Eocene Tanjung, Oligo-Miocene Talang Akar, and Mio-Pliocene Muara Enim Fm and their equivalents. Individual coal seams can be very thick (up to 100 ft) and laterally continuous for miles to tens of miles. Cumulative coal thickness reaches as much as 200 to 300 ft. “Completable” coal thickness, the proportion of coal that may be targeted by a multi-frac well completion, frequently exceeds 100 ft in the better areas. This is considerably thicker coal than in most U.S. CBM basins, including the Powder River basin. Many deep petroleum exploration wells in Indonesia encountered gas kicks while penetrating coal seams (Figure 7). Though an indirect indication that does not prove saturation, which must be confirmed by core retrieval and direct gas desorption, these gas kicks are positive indications that also were noted early on in the San Juan basin. Coal rank, as measured by vitrinite reflectance (Ro) or calorific content, generally increases with depth in Indonesia. The rank/depth increase is most rapid in back-arc settings with high heat flow, such as the Sumatra and Ombilin basins. In one extreme example, lignite and sub-bituminous coal at the surface (Ro=0.3%) increased to bituminous levels at CBM target depths of 3,000 ft (Figure 8). The only reliable measurement of coal seam gas content is direct desorption of core at the well site under controlled temperature conditions. The authors know of only a few such direct desorption measurements in Indonesia, which remain proprietary. As a proxy, we used the sorptive capacity of coal measured in the laboratory. Our measurements, and more detailed analysis by Saghafi and Hadiyanto (2000), indicate that Indonesian coal can sorb approximately 200 ft3/ton (6.25 m3/tonne) of methane at typical CBM reservoir pressures of 1,000 psia, depending on thermal maturity and maceral composition. Although such gas contents are not considered exceptional, coupled with extremely thick coal seams the gas-in-place resource concentration may be an attractive 20 Bcf/mi2. In-situ coal seam permeability, perhaps the most critical single reservoir property for commercial CBM

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production, has not been measured in Indonesia. The dominant permeability type in coal is cleat or fracture permeability, which can be several orders of magnitude higher than matrix permeability. Cleating generally is not well developed in Indonesian coal samples. However, this may be because coal samples used in this study came from low-rank surface mines and outcrops rather than sampled from CBM target depths. Vitrinite, the dominant maceral in Indonesian coals, is relatively brittle and should promote good cleat development in thermally mature settings. The tectonic setting is also important for permeability development; fracture permeability may have developed locally in areas undergoing tensional stress. High levels of carbon dioxide are naturally present in many conventional natural gas fields in Indonesia. For example, CO2 levels can exceed 30% within the Corridor PSC area of South Sumatra and over 70% at the Natuna D-Alpha field in the South China Sea. CO2 removal is costly and a significant consideration for CBM operations. Carbon dioxide levels tend to increase sharply with depth in Indonesia, particularly in Sumatra. Available data indicate that shallow CBM deposits in Indonesia (<3,000 ft) are likely to be low in CO2 (<5%). CBM could be blended with high-CO2 gas streams to reduce gas processing costs. Indeed, deep coal seams may even provide an economic disposal site for waste CO2. A novel enhanced recovery method, currently undergoing testing in the San Juan basin, involves injection of CO2 into coal reservoirs for enhanced CBM recovery and CO2 disposal (Stevens and Spector, 1998). ECBM could be used for disposing waste CO2 while recovering more methane from the coals in Indonesia. To estimate prospective coalbed methane resources in Indonesia, (generally a fraction of the total CBM resource in place) we used the following methodology: • Minimum depth of 1,000 feet below the surface,

to ensure adequate gas content. • Maximum depth of 5,000 feet, below which

permeability is likely to be too low. • Coal thickness was measured from petroleum

logs and coal mining data, confirmed by multiple independent logs (neutron/density, resistivity, gamma ray, wellbore caliper).

• Three hydraulic fracture treatments per well were assumed. Each frac was assumed to stimulate all coal within a 100-foot frac-height-growth interval.

• Gas content was inferred from coal rank and

sorption isotherm data. • Measured ash content data. • Standard volumetric gas-in-place equation. Our estimate of 337 Tcf of accessible CBM resources in Indonesia is significantly larger than the previous estimate of 213 Tcf (Nugroho and Arsegianto, 1993b), which furthermore was based on gross rather than completable thickness (Table 1). This is a vast resource, but only a small fraction will likely be recoverable. Commercial CBM production requires unusually favorable reservoir conditions (high permeability, high gas saturation, etc.). To date, only about 4% of total U.S. CBM resources has been produced or confirmed as proven reserves (8.3 Tcf of cumulative production plus 13.2 Tcf of remaining proved reserves, out of an estimated 560 Tcf of gas in place). As development continues in existing and new basins, this proportion is likely to grow to 10% or more of gas in place. Applying a 10% recovery factor to Indonesia yields a plausible CBM reserve potential on the order of 30 Tcf. PROSPECTIVE BASINS Based on our evaluation, the most prospective basins were identified and are briefly discussed below. It should be noted that CBM exploration results in the U.S. more often than not confound conventional wisdom, both positive and negative. Further study and testing of CBM resources in Indonesia will undoubtedly reveal similar surprises. With this caveat in mind, the most prospective basins, in alphabetical order, are considered to be: • Barito Basin: Thick, low-rank coal seams with

gas kicks occur in the Miocene Warukin and Eocene Tanjung Fm at prospective depths. The Barito basin is large (15,000 km2) and structurally simple, which in U.S. basins is conducive to permeability. Challenges include lack of petroleum infrastructure and poor surface access. Potentially completable CBM resources, based on only eight well logs, were estimated at 75 Tcf.

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• Jatibarang Basin: Although relatively small, deep, and structurally complex, Jatibarang is a producing oil field and is located close to the Jakarta gas market. Small, strategically located coal basins such as Jatibarang warrant further study for near-term development. Jatibarang may have 1 Tcf of completable CBM resource within a 500-km2 area.

• Kutei Basin: Similarly thick, low-rank coal

occurs in the Miocene Prangat, Kamboja, and Loa Kulu Formations. Structure is moderately complex, with large-amplitude folds probably caused by gravitational sliding (extension) rather than compressional folding. Service company and pipeline access are superior to the Barito basin. Completable CBM resources were estimated at 50 Tcf within a 10,000-km2 area.

• Ombilin Basin: Located in the central Sumatran

highlands, the Ombilin basin contains some of the highest coal rank in Indonesia, reaching bituminous levels at target depth. Two exploratory wells encountered thick coal seams in the Eocene Sawahlunto and Oligocene Sawahtambang Fms. Elevated CO2 levels may be a problem in this intra-montane rift basin.

• Central Sumatra: Low- to moderate-rank coals

occur in the Korinci Fm, but are generally deep (>6,000 ft). Potential gas markets include thermal enhanced oil recovery operations at Duri field as well as Singapore. Completable CBM resources could be as much as 50 Tcf within a 15,000-km2 area.

• South Sumatra Basin: Key targets include thick

low-rank coals within the Mio-Pliocene Muara Enim and Oligo-Miocene Talang Akar Fms. However, structure is more complex than in east Kalimantan and permeability is a significant risk. The Corridor-Duri gas pipeline currently transports 310 MMcfd of deeper conventional production, while PGN is planning a new line southeast to Java. Completable CBM resources were estimated at 120 Tcf within a 15,000-km2 area, constrained by numerous wells and seismic lines.

ANALOGS WITH PRODUCING CBM BASINS Early CBM producing areas in the U.S., such as the Warrior and San Juan basins, were inevitably used as exploration analogs for subsequent areas. Yet, these analogs hindered as much as helped subsequent exploration. Each of the six productive CBM basins in the U.S. is geologically and operationally unique. Some had been written off for years as non-prospective by “expert” opinion (including the author’s!). There is no identical U.S. analog to any coal basin in Indonesia. However, the Powder River basin of Wyoming and Montana may be the closest in terms of coal age, thickness, and rank. Figure 9 shows intensive recent CBM development along a small portion of the eastern margin of this vast low-rank basin, showing some of the over 1,800 new production wells drilled in 1999 alone. The better areas in Indonesia resemble or even exceed the Powder River basin in coal thickness, but are deeper, at higher pressure and thermally more mature. Gas content may be several times higher than in the Powder River. Permeability, however, is likely to be lower. The Eocene Ardley coal of the Western Canadian Sedimentary basin, currently being tested for CBM, may also be a good geologic analog. Unlike the Powder River, CBM operations in Indonesia will almost certainly require hydraulic stimulation. Development costs in jungle or swamp will be high, closer to San Juan basin fairway costs ($600,000/well, equipped) than to Powder River basin costs ($75,000/well). However, given shallow drilling depths and low CO2 content, finding and development costs in the better areas may still be attractive. We conclude that the CBM potential of Indonesia is vast and highly prospective. ACKNOWLEDGMENTS The authors thank Pertamina, the Directorate of Coal, and PT Caltex Pacific Indonesia for support of and permission to publish this study. Particular recognition is due to Sutarno of Migas, Wahyudi Soetoto and Nelly Ekayanti of Pertamina; Mike Campbell, John Hebberger, Ichwan Murdianto, Peter Sommer, and Bard Strong of Caltex; and Denis Spector of ARI.

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REFERENCES Kelafant, J. and Stern, M., 1998. Coalbed Methane Could Cut India’s Energy Deficit. Oil and Gas Journal, May 25, p. 42-46. Koesoemadinata, R.P., 2000. Tectono-Stratigraphic Framework of Tertiary Coal Deposits of Indonesia. Proceedings Southeast Asian Coal Geology Conference, Bandung, Indonesia, 19-20 June. Nugroho, W., and Arsegianto, 1993a. Economics of Coalbed Methane Field Development: a Case Study of Jatibarang Field. Society of Petroleum Engineers, SPE 25311. Nugroho, W., and Arsegianto, 1993b. Future Prospect of Coalbed Methane in Indonesia. Proceedings of the 1993 International Coalbed Methane Symposium, University of Alabama, Tuscaloosa, May 17-21, p. 721-726. Saghafi, A., and Hadiyanto, 2000. Methane Storage Properties of Indonesian Tertiary Coals. Proceedings Southeast Asian Coal Geology Conference, Bandung, Indonesia, 19-20 June. Sani, Kartono, 2000. Coalbed Methane as Potential Alternative Energy Resources in Indonesia. Conference on Coal for Energy Security in Asean Region, Jakarta, Indonesia, December 6-7, 2000.

Stevens, S.H., and Soetoto, W., 2000. The Coalbed Methane Potential of Indonesia: Analogies with U.S. CBM Basins. Proceedings Southeast Asian Coal Geology Conference, extended abstract, Bandung, Indonesia, 19-20 June. Stevens, S.H., and Spector, D., 1998. Enhanced Coalbed Methane Recovery Using CO2 Injection: Worldwide Resource and CO2 Sequestration Potential. Society of Petroleum Engineers, SPE 48881. Stevens, S.H., 1999. China Coalbed Methane Reaches Turning Point. Oil and Gas Journal, January 25, p. 101-106. Stevens, S.H., 2000. Coalbed Methane in Indonesia: An Overlooked Resource. American Association of Petroleum Geologists, 2000 International Conference & Exhibition, Bali, Indonesia, October 15-18. Suyartono and Ginting, N., 1995. The Possibility of Coalbed Methane Recovery in Indonesia. United Nations International Conference on Coal Bed Methane Development and Utilization, Beijing, China, 17-21 October, p. 187-194. U.S. DOE (United States Department of Energy), 2000. U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report, Washington, D.C.

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TABLE 1

ESTIMATED CBM RESOURCES IN INDONESIA

Province Basin Prospective

Area (km2) CBM Resources

(Tcf) Kalimantan Barito

Berau Kutei North Tarakan

Pasir/Asem Asem

15,000 2,000 10,000 6,500

1,000

75 10 50 20

3 Sumatra Central Sumatra

South Sumatra Bengkulu

Ombilin

15,000 20,000 3,000

130

50 120 5

1 Java Jatibarang 500 1 Sulawesi Sengkang 1,000 2 Total 74,000 337

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FIGURE 1 - Out of 400 - 600 Tcf of CBM resources in place, 20.5 Tcf of reserves have been booked in six basins.

Western Washington

24 Tcf

Wind River 2 Tcf

Greater Green River

84 Tcf

Uinta 10 Tcf

Piceance 84 Tcf San Juan

Fruitland Coal = 50 Tcf Menefee Coal = 34 Tcf

Raton 11 Tcf

Arkoma 4 Tcf

Warrior 20 Tcf

Central Appalachia

5 Tcf

Northern Appalachian

61 Tcf

Illinois 21 Tcf

Established CBM Basin Emerging CBM Basin Frontier CBM Basin Reserve Additions (Tcf)

Forest City

Cherokee

15

Powder River 30 Tcf

0.6

151.9

1.6

0.8

0.5

FIGURE 2 - Comparison of coal, gas and CBM production.

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Desorption From Internal

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FIGURE 4 - Unique production characteristics of CBM result in production peaking around year 5 following low but inclining initial gas.

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JAF01835.CDR

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Phase I: Initial 3 Wells Look Poor

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FIGURE 5 - Early CBM testing results can be misleading (Uinta Basin).

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FIGURE 8 - Coal rank in Indonesia, while low at surface, can be optimal for CBM development at prospect depth.

FIGURE 7 - Many petroleum exploration wells in Indonesia show gas kicks associated with thick coal seams.

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FIGURE 9 - CBM development in the east-central Powder River Basin, USA, showing surface coal mines, direction of mining, and hundreds of CBM production wells.