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Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for CBM. A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. CBM reservoirs are layered and contain an orthogonal fracture set called cleats, which are perpendicular to bedding. Because the coal matrix has essentially no permeability, CBM can be produced economically only if there is sufficient fracture permeability. Relative to conventional gas reservoirs, coal seam permeabilities are generally low and may vary by three orders of magnitude in wells separated by distances of less than 500 m.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft.
The new surge in drilling for coalbed methane gas brought on by the attractive tax credits has increased the need for quantitative evaluation of coal formations. The potential resource base in the U.S. alone is on the order of 422 Tcf. Currently available petrophysical and fluid flow mechanistic models for gas reservoir petrophysical and fluid flow mechanistic models for gas reservoir analysis in traditional clastic or carbonate environments are notably inadequate for coal formation evaluation and well productivity assessment. Existing coal formation evaluation techniques rely on core measurements and certain basic log measurements such as "bulk" density. The evaluation program as such, is typically site specific and devoid of critical answers like recoverable reserves and well productivity assessment. Additions and improvements to the existing technology are needed to efficiently exploit the production of methane gas from coalbeds. production of methane gas from coalbeds. In this paper we present a methodology that integrates the existing technology with new measurements and techniques. Such a procedure can allow one to evaluate the coal formation specifically procedure can allow one to evaluate the coal formation specifically for identification, resource definition (thickness), gas content (reserves), recoverable reserves (permeability, porosity and reservoir pressure) and to plan for the de-watering process (reservoir performance). The methodology provides evaluation alternatives depending on the coal seam thickness and the type and concentration of the fracture system. The thin laminated coal seams found in basins like the Black Warrior and the Appalachian require a different evaluation suite of logs compared to those required for the relatively thick (greater than 2 ft) coal seams found in the San Juan and Piceance Basin. Also, the type and concentration of fractures within the cleat system dictate the capillary pressure pattern and thus may require specific transient pressure tests. The majority of coal basins found in the U.S., pressure tests. The majority of coal basins found in the U.S., Canada, U.K., Central Europe and Australia can be broadly categorized within the above aspects of seam thickness and fracture system distribution.
Coalbeds have long been known to contain natural gas in varying amounts. Due to safety considerations, coalbeds are degassified prior to mining so that the risk of explosion can be minimized. prior to mining so that the risk of explosion can be minimized. The energy shortage of the 1970s initiated exploitation of the coalbed methane as a viable source of energy. The recent tax incentive promulgated by the U.S. government has caused a miniboom in methane gas production from coal seams. The 1990 detailed geologic appraisal of the major coal basins in the U.S. by the Gas Research Institute (GRI) and ICF Resources Inc. suggests a total resource base of 422 Tcf. Fig. 1 illustrates the location of the various coalbed methane resources within the mainland U.S. Outside the U.S, Western Alberta, U.K., Central Europe and Australia also have large potential reserves. Considering the resource base and the increased drilling activity, it should not come as a surprise that almost 10 percent of all the wells drilled in the U.S. during 1990 have been drilled for coalbed methane gas. Also, most of the financial resources spent to-date by the operators have been just to drill the wells. A good number of the drilled wells are still awaiting evaluation and subsequent completion.
Basic information needed to efficiently exploit coalbed methane gas is not very different from that needed for production from traditional gas reservoirs. One must identify the presence of the gas; quantify the amount of gas in place; figure out how much of the gas in place can be recovered by primary production; decide on the need for enhanced recovery through hydraulic fracturing; dewatering and gas breakthrough time; and finally, determine the associated costs to recover the gas. The main difference in trying to answer these questions arises with the reservoir in question being so dramatically different than the conventional intergranular or intercrystalline reservoir. This difficulty requires an understanding of how methane gas is produced from coal formations and how it impacts wireline tool measurements and data requirements.
GAS PRODUCTION MECHANISM FROM COAL FORMATIONS
The coal formation not only serves as a reservoir for methane but also can serve as its own source rock and a haven for water accumulation. The mechanism through which gas and water are stored in and produced from coals is significantly different than storage and flow mechanism of conventional gas sand reservoirs.
Abstract The purpose of this paper is to provide a view on the South Sumatra basin CBM development potential. The basin ranks as one of Indonesia's most prospective coalbed methane (CBM) basins, but well testing is still in the earliest stages. In S. Sumatra basin there are three distinct identifiable sub-basin evolution periods. First, a period of horst-graben development controlled by major localized extensional faults that initiated the basin architecture. This episode was followed by rapid to moderate sedimentation controlled by normal faults resulting in deposition of Oligocene Talang Akar alluvial, fluvial and deltaic deposits. Secondly, a period of decreased fault activity along with regional subsidence coinciding with the deposition of the post-rifting Miocene Air Benekat and Muara Enim Formations. The third period is marked by regional uplift resulting in wide spread basin inversion over the entire region. Coal seams in the Muara Enim Formation are thickest and most numerous in the SW half of the South Sumatra basin representing key target for CBM development. This is the axial region of the basin where the subsidence has been most pronounced and the formation is thickest. While the coals are quite thick and laterally extensive in the broad synclines, most of the Miocene Muara Enim Formation has been eroded out along the anticlines. The Lematang Depression and the Central Palembang sub-basin are considered the most prospective CBM areas on the basis of coal thickness, depth, and gas kicks on mud logs. The Muara Enim formation comprises more than 3500 ft of paralic sandstones and mudstones, with thick intercalated coal seams. Typically some 10 to 15 individual coal seams are present. The coals are of sub-bituminous rank and characterized by low vitrinite (huminite) reflectance (VRr = 0.35 – 0.46%). These low rank coals are dominated by huminite (34.6 – 94.6 vol. %). Less abundant are liptinite (4.0 – 22.5 vol. %) and inertinite (0.2 – 43.9 vol. %). Minerals are found only in small amounts (0 – 5 vol. %); mostly as iron sulfide. Kaolinite occurs as cleat fillings at some places. The coals are characterized by high moisture content (4 – 21 %) and volatile matter content (> 40 wt.%, daf), and less than 80 wt. % (daf) carbon cotent. CO2 and CH4 sorption isotherms on six different coal samples were carried out at reservoir temperature. Given the uncertainty around the gas content measurements, the coals tend to suffer from some serious under saturation. The sorption capacities of the coals tend to decrease with increasing depth. This behavior can either be related to the increasing moisture content of the coal with depth or with the significant variation of the vitrinite content of the deeper seams. The high CO2 adsorption capacity and the low rank tend to make these coals ideal targets for CO2 sequestration.
Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.