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PEH:Coalbed Methane

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume VI – Emerging and Peripheral Technologies

H.R. Warner Jr., Editor

Chapter 6 – Coalbed Methane

By C. Jenkins, DeGolyer and MacNaughton, D. Freyder, Freyder Enterprises Inc., J. Smith, Great Plains Energy, and G. Starley, Devon Energy Corp.

Pgs. 249-296

ISBN 978-1-55563-122-2
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Development of the Coalbed Methane Industry

Although mines in the U.S. have been venting coal gas intentionally since the 19th century, the production and sale of methane from coalbed wellbores is a relatively recent development. Methane was produced from a few coal seam wells in Wyoming, Kansas, and West Virginia during the early part of the twentieth century; however, the first deliberate attempts to complete wells as coalbed-methane (CBM) producers did not occur until the early 1950s in the San Juan basin of New Mexico. These wells targeted the Fruitland coal seams, which previously were viewed as a high-pressure hazard overlying deeper conventional oil and gas targets. Gas production development from the Fruitland coal seams languished until the mid-1970s when an energy crisis in the U.S. encouraged feasibility studies and investment. In the late 1970s, several companies completed wells in the Fruitland coal seams and found high gas contents and production rates of several hundred Mscf/D.[1] At approximately the same time, several dozen CBM wells were drilled to degas coal seams adjacent to mines in Alabama's Black Warrior basin.

This early development work received a huge boost in 1980 when a U.S. federal tax credit was introduced for nonconventional fuel sources. This tax credit ignited a research and drilling boom throughout the 1980s, which resulted in approximately 5,500 U.S. CBM wells by 1992.[2] This expansion was facilitated by service companies and pipeline infrastructure that were already serving conventional gas wells. Although the tax credit for new wells expired in 1992, CBM development continued at a strong pace. Commercial projects involving hundreds of wells, such as those in the Uinta and Powder River basins of the western U.S., were developed in the 1990s without the benefit of these tax credits. In 2000, the U.S. CBM industry reported proven reserves of more than 10 Tscf for approximately 10,000 producing wells.[3]

As the CBM industry developed in the U.S., companies began to look worldwide for additional opportunities. This is a natural progression given that, as Table 6.1[4][5] shows, approximately only 16% of the world's coal resources are in the U.S. More than 300 exploration core holes and production test wells have been drilled in at least 15 different countries in search of development opportunities. To date, the only international commercial CBM production has come from two relatively small projects in the Bowen basin of Queensland, Australia. International development has been hampered by numerous factors including unfavorable reservoir conditions, governmental policies, the absence of gas infrastructure and markets, and the lack of a readily available hydrocarbon service industry. Nonetheless, exploration continues in several countries, spurred on by government incentives, advances in technology, and a greater demand for natural gas.

Characteristics of Successful CBM Projects

A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 6.2 summarizes the characteristics of several successful projects in the U.S. and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.

Comparison With Conventional Gas Reservoirs

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. Because of the low permeabilities, hydraulic fracture stimulation or cavity completions are required for efficient production.

Coal gas is generated in place and is sorbed physically to the coal. Because coal has a large amount of microporosity, the surface area available for sorption is huge. It is estimated that one kilogram of coal contains a surface area of more than 100,000 m2.[2] CBM reservoirs can hold two to three times as much gas as a sandstone reservoir at the same pressure. Initially, the cleats are filled with water and/or gas, creating pressure that keeps the sorbed gas bound to the coal. Producing wells lower the pressure in the cleats, causing gas to desorb from the coal matrix. Most CBM wells initially produce large volumes of water and small volumes of gas. Over time, the produced water volume decreases, and the gas rate increases. This is the opposite of conventional gas wells, which are characterized by high initial gas rates that decline with time.

Appraisal and Development Strategy

It is important to collect and interpret high-quality data early in the life of a CBM project to determine commerciality quickly and to generate a cost-effective development plan. Reservoir description work must be conducted to determine coal thickness, quality, lateral continuity, and structural position. Reservoir engineering analyses are needed to determine gas content, saturation conditions, sorption isotherm values, pressures, and permeabilities. Operations engineering must demonstrate that wells can be successfully drilled, completed, stimulated, and produced.

The first step in appraising a new area is to collect all relevant information from conventional wells, mining operations, mining core holes, geophysical surveys, geologic mapping, and remote sensing studies. These data should be compared with the characteristics of producing CBM reservoirs to estimate the range of possible gas rates and reserves. The collected data can be used to identify the prospective areas in a basin and determine appraisal well locations. Appraisal wells then can be drilled to core, log, test, and produce the coal seams. These wells determine if there is sufficient coal thickness, gas content, and permeability to justify a pilot project.

Pilot wells should be drilled in a closely spaced five- or nine-spot pattern that includes an isolated center well. The close spacing will quickly determine if dewatering is possible and if significant quantities of gas can be produced. The pilot project then can be expanded to ensure that gas can be produced economically at a development well spacing. A properly designed pilot well program should include the opportunity to test different completion, stimulation, and artificial lift methods. A detailed reservoir surveillance plan should be created to accumulate routine production, pressure, and fluid entry data over time. Numerical simulation studies should be conducted to integrate and reconcile all the collected data properly, determine the reservoir mechanisms, evaluate the appropriate development well spacing and pattern geometry, and forecast whether commercial rates will be achieved.

CBM Reservoir Fundamentals

What is Coal?

Coal is a chemically complex, combustible solid consisting of a mixture of altered plant remains. Organic matter constitutes more than 50% of coal by weight and more than 70% by volume. Coals are described and classified by differences in composition (type), purity (grade), and maturity (rank). Type refers to the variety of organic constituents. Coals are composed of macerals, which are analogous to minerals in rocks. The three main maceral groups are vitrinite, liptinite (exinite), and inertinite. Vitrinite macerals form the bright bands in hand samples of coals and originate from the woody and cellulose portions of plants. Liptinite-rich coals have a waxy texture and are the product of spores, resins, and algae. Inertinite-rich coals have a dull black luster and are composed of oxidized organic matter. These differences are the basis for classifying coal types by their appearance (such as bright-banded or dull-banded) or their composition (such as humic or sapropelic). Table 6.3 summarizes these coal industry terms and several others for convenient reference. Table 6.4 summarizes the characteristics and genesis of coals and their precursors.

Grade is a measure of the coal's purity and is based on the weight percentage of organic material as determined by chemical analyses. Impure coals are referred to as ash-rich or bony. Rank represents the level of compositional maturity attained during coalification. Changes in rank are caused by increases in temperature and pressure associated with deeper burial. Mature coals, such as bituminous and anthracite coals, form at depths of thousands of meters in a process that typically requires millions of years. As coals are buried more deeply, both their carbon content and their ability to reflect incident light (vitrinite reflectance) increase. The measurement of vitrinite reflectance is the most common means to assess coal rank.

Origin of CBM Reservoirs

Coal originates as an accumulation of organic matter in swamps and marshes commonly associated with fluvial systems, deltas, and marine shorelines. It is critical to submerge the accumulating organic matter quickly beneath the water table to prevent oxidation. This requires a combination of basin subsidence and a rising water table sufficient to match the accumulation rate. Organic matter accumulates at an average rate of approximately a millimeter per year and compacts by a factor of seven to 10 times as it is transformed into coal.

As organic matter is buried, it is first transformed into peat, which consists of loosely compacted masses of organic material containing more than 75% moisture. This transformation takes place mainly through the compaction and expulsion of interstitial water. Biochemical reactions associated with this process transform the organic matter into humic substances, which are the precursors of coal macerals. These reactions can also generate significant amounts of biogenic methane, which often is referred to as swamp gas. Continued compaction and dehydration transform peat into a low-quality coal called lignite, which contains 30 to 40% interstitial water.

With deeper burial, temperatures increase, and geochemical processes dominate physical processes. Lignite evolves into subbituminous coal by expelling H2O, CO, CO2, H2S, and NH3, leaving behind a structure enriched in carbon and hydrogen. At temperatures greater than approximately 220°F (104.4°C), carbon-carbon bonds begin to break, generating gas and liquid hydrocarbons that become trapped in the coals. As these bituminous coals are buried more deeply, their hydrocarbons are cracked into thermogenic methane and expelled as an order of magnitude more gas is generated than the coal is capable of storing. In a typical coal, the H/C atomic ratio decreases from 0.75 to 0.25 as coals mature from high-volatile bituminous to anthracite.

The generation and expulsion of hydrocarbons is accompanied by several profound changes in coal structure and composition.[6] Moisture content is reduced to just a few percent as water is expelled. Microporosity increases as the atomic structure of the coal changes, generating a huge surface area for sorbing methane. These changes also lower the bulk density from 1.5 g/cm3 in high-volatile bituminous coals to less than 1.3 g/cm3 in low-volatile bituminous coals. Coal strength decreases, making it easier for the coal to fracture as volatiles evolve and the coal shrinks. This creates closely spaced cleats, which enhance permeability.

At temperatures exceeding approximately 300°F, bituminous coals are changed to anthracite (> 92% carbon). Methane generation and expulsion decrease, and the bulk density increases from 1.3 g/cm3 to more than 1.8 g/cm3 as the coal structure becomes more compact. Methane contents in anthracites are typically quite high, but permeability is lower than bituminous coals because of cleat annealing. With further maturation, remaining volatiles are driven off and carbon structures coalesce, resulting in a dense coal with very high carbon content and a chemical composition similar to graphite.

To generate temperatures high enough to produce large quantities of hydrocarbons, coals must be buried deeply, typically to depths greater than 3000 m. Exceptions to this are coals transformed by local heat sources such as igneous intrusions. After sufficient burial and time to generate hydrocarbons, coals must be uplifted to shallower depths to be exploited commercially. At depths shallower than a few hundred meters, there is not enough pressure in the cleat system to hold economic quantities of sorbed gas in the coal. At depths greater than approximately 1200 m, permeabilities are generally too low to produce gas at economic rates.

Gas Content

Gas contents in coal seams vary widely and are a function of coal composition, burial and uplift history, and the addition of migrated thermal or biogenic gas. Both vitrinite- and liptinite-rich coals can generate large quantities of hydrocarbons, but inertinite-rich coals, which consist of oxidized organic material, generate very little gas. The highest gas contents are found in anthracite coals, although their permeabilities are often too low to achieve commercial gas rates. High-volatile A to low-volatile bituminous coals have lower gas contents than anthracites but higher permeabilities. These bituminous coals have been the primary target of CBM exploration, primarily because coals of this rank are CBM reservoirs in the San Juan and Black Warrior basins where the modern CBM industry began.

During the 1990s, CBM reservoirs in the Uinta basin of Utah (high-volatile B) and Powder River basin of Wyoming (subbituminous B) were developed successfully despite being of lower rank than San Juan or Black Warrior coals. In the Uinta basin, gas contents have been enhanced by biogenic and migrating thermogenic gases. In the Powder River basin, the coals have low gas contents but are very thick, laterally extensive, and located close to the surface, allowing wells to be drilled and completed cheaply. These two projects have caused the industry to broaden its perspective and include lower rank coals as commercially viable targets.

Most CBM reservoirs contain both thermogenic and biogenic methane. Thermogenic methane is generated on burial, whereas biogenic methane is formed by late-stage bacteria that are introduced through groundwater flow and convert longer-chain hydrocarbons to methane. This gas augments the existing thermogenic methane and may increase gas contents significantly. Conversely, groundwater flow can reduce gas content by dissolving gas from the coal. An example of this is found in the Ferron coals located south of the Drunkard's Wash CBM project in the Uinta basin of the western U.S. Groundwater is believed to have moved downward along the Joe's Valley fault system, entering the coal seams at depth and pushing the gas updip where it is expelled at the outcrop.[7]

Another mechanism for decreasing gas contents is the uplift and reburial of coal seams. For example, in the Hedong basin of China, Carboniferous coal seams are located beneath Plio-Pleistocene loess, which is up to several hundred meters deep. Before the deposition of this loess, the coal seams were closer to the surface and possibly were equilibrated to a lower pressure before reburial. As a result, the gas contents could be lower than expected, unless biogenic gas or migrated thermogenic gas augmented the existing gas fraction after reburial.

Coalbeds often contain gases other than methane, including carbon dioxide, ethane, hydrogen, and nitrogen. Coal has a greater affinity for carbon dioxide and ethane than for methane and may contain substantial quantities of these gases. Proper coal desorption and sorption isotherm work can quantify the amount of each species and generate a composite isotherm representative of the coal's sorption character. If carbon dioxide and ethane are present in the reservoir, it is likely that the produced gas will become enriched in these components as the reservoir is depleted.

Gas Saturation State

Fluid movement in a coal is controlled by diffusion in the coal matrix and by Darcy flow in the fracture (cleat) system. In most CBM reservoirs, the cleat system is filled with water at initial conditions, although, in some cases, the system also may contain some free gas. The reservoir pressure is decreased by producing water from the cleats. This causes gas to desorb from the coal matrix at the matrix/cleat interfaces, creating a methane concentration gradient across the coal matrix. Gas diffuses through the matrix and is released into the cleat system. When the gas saturation exceeds a critical value in the cleats, gas will flow to the wellbore.

The capacity of the coal matrix to store gas as a function of pressure is described by the Langmuir sorption isotherm. The gas content at a specified pressure is defined by Eq. 6.1, which is modified from Langmuir.[8] The Langmuir volume is the maximum volume of gas a coal can sorb onto its surface area. The Langmuir pressure is the pressure at which the storage capacity of a coal is equal to half the Langmuir volume.


where Cm = matrix gas concentration, scf/ft3; ρB = bulk density, g/cm3; VL = dry, ash-free Langmuir volume constant, scf/ton; pL = Langmuir pressure constant, psia; and p = pressure in the fracture system, psia.

In general, coal seam gas contents are less than the amount of gas a coal is capable of storing; therefore, the coals are undersaturated with gas. This phenomenon occurs because as the coals are uplifted, their temperature decreases allowing them to sorb more gas.[9] However, once the coals are uplifted above the hydrocarbon generation window, no additional gas can be generated in situ to keep the coals saturated. Gases from other sources must be introduced for the coals to remain saturated. These sources include migrated thermogenic gas from deeper in the basin or biogenic gas created by the breakdown of longer-chain hydrocarbons in the coal from the action of bacteria introduced by groundwater.

For coals that are 100% gas saturated, gas will be produced as soon as the pressure is decreased by producing water from the cleats. Gas rates will ramp up to a peak over several years and then decline. For undersaturated coals, gas will not be produced until the pressure in the cleats has been drawn down below the saturation pressure. Gas will be liberated more slowly, resulting in a longer period to achieve peak gas rates, as well as lower peak rates. There have been several cases in which companies have drilled numerous development wells based on early gas rates of a few hundred Mscf/D per well, believing that the rates would increase substantially with additional dewatering and well interference. Failure to recognize the undersaturated state of their coals and the impact of this condition left them with dozens of low-rate, marginally economic or uneconomic wells.

The parameters affecting the saturation state of the coal, such as coal rank, composition, and moisture content, may vary greatly within a CBM reservoir. To assess this variation, an isotherm should be obtained from each major coal seam. These isotherms can be used to determine the saturation state and estimate a recovery factor by comparing the expected gas content at an assumed abandonment pressure with the initial gas content at reservoir conditions. Fig. 6.1 shows a sorption isotherm curve that illustrates how a recovery factor is calculated. Numerical simulation can be used to estimate the impact of initial saturation conditions on production.

Coal Permeability

Coal permeability is controlled primarily by two fracture sets called face cleats and butt cleats. These sets are aligned at right angles to each other (orthogonal) and are perpendicular to bedding. Face cleats are continuous while butt cleats terminate into the face cleats. Face cleats often are aligned parallel to faults and fold axes, indicating that local stresses exert control on their development. Because of the dominance of face cleats over butt cleats, a 5-spot pilot well pattern will show early interference between the center well and the two offset wells aligned parallel to the face cleat direction. An elliptical drainage area will form around each well and overlap the drainage area of the adjacent well. This will cause a greater pressure drop in these three wells than observed in the two wells aligned in the butt cleat direction. Sec. 6.8.5 discusses this phenomenon in a five-well pilot in the Hedong Coal basin of China.

Cleats are believed to form during coalification by shrinkage caused by moisture loss and by compactional folding of brittle coal beds.[10] Cleat spacing ranges from approximately 2 cm in lignites to 0.08 cm in medium-volatile bituminous coals.[11] Cleats are more closely spaced in vitrain-rich and thinner-bedded coals. Coals with high ash (> 45%) and high inertinite (> 40%) contents tend to have very poorly developed cleats.[2] In-situ cleat aperture widths vary from approximately 0.0001 to 0.1 mm and can be filled by calcite, gypsum, or pyrite minerals.[10] In addition to cleats, it is common to find shear-related fractures (joints) dipping 45 to 60° to bedding. These typically are much more widely spaced than cleats but can enhance permeability.

Laboratory testing and field observations indicate that cleat permeability decreases during initial gas production because of coal swelling as the reservoir pressure decreases. If the cleat permeabilities are very low, this swelling can effectively close the cleats. Conversely, coals will shrink as the gas desorbs, increasing permeabilities and gas rates. This phenomenon has been observed in several San Juan basin CBM wells that have been producing gas for the last 10 years. In addition, like conventional oil and gas reservoirs, CBM reservoirs exhibit changes in relative permeability as fluid saturations change during production.

Well Behavior

CBM wells usually produce little or no gas initially and have moderate to high initial water rates. On a per well basis, water rates may range from a few barrels per day for low-permeability coals up to thousands of barrels per day for high-permeability coals. The wells may produce water for several months or years before producing significant volumes of gas. As the water is produced, the pressure near the wellbore is reduced, allowing gas to desorb from the coal matrix. When the gas saturation exceeds the critical value, the gas begins to flow to the wellbore. If the well pattern allows for adequate interference between wells and the coals are not connected to a strong aquifer, the water rates will decline over time to some minimum that will likely continue for the life of the well.

In general, gas rates will increase until a peak rate is achieved, although the reservoir behavior and the influence of offset wells may create a flat production profile or an early decline in gas rate. Ramp-up periods of 3 to 5 years or more are common and wells may produce near the peak rate for several years before gas rates begin to decline. It is possible, although not typical, to have high initial gas rates and relatively low water rates if the reservoir is fully gas saturated and not supported by a large, active aquifer.

Multiple wells are needed to develop a CBM reservoir. Well interference helps dewater the reservoir more quickly, and closely spaced wells achieve peak rates more quickly than widely spaced wells. Numerical simulation may be used to evaluate the effects of well spacing and well patterns on production rates and ultimate recoveries. CBM wells may have a long life compared with conventional gas wells. Numerical reservoir simulations for several basins indicate that typical CBM wells may produce 20 to 40 years at economical rates. These estimates are supported by current production trends in the San Juan basin.

Enhanced Recovery

Methane recovery can be enhanced in CBM reservoirs by the injection of CO2 or nitrogen. Coal prefers carbon dioxide, and it will release methane to sorb injected CO2. This significantly increases the amount of methane available for production, but also causes the coal to swell, reducing permeability with time. Nitrogen reduces the partial pressure of methane, causing it to desorb from the coal.[12] The injected gas reduces the partial pressure of methane more rapidly than the total pressure can be reduced by dewatering, resulting in accelerated production.[13] An additional benefit of nitrogen or CO2 injection is that the methane can be desorbed while maintaining higher reservoir pressures, resulting in added energy to drive the methane to the wellbore. Both injection processes have been tested over the past decade. The largest pilot projects are Burlington Resources' Allison pilot and BP's Tiffany Unit pilot, which are both located in the San Juan basin. While these pilots were primarily designed to enhance methane recovery, pilots that are more recent focus on the benefits of both CO2 sequestration and enhanced methane recovery.

Basin Assessment

Structural Geology

Several different types of basins present excellent exploration targets for CBM prospecting.[14] Foreland basins are flexural troughs that form in front of rising mountain belts. These basins, which include the Black Warrior and San Juan basins of the U.S., have provided more than 90% of the world's coal gas production to date. Cratonic basins such as the Williston basin, which straddles the U.S./Canadian border, are simple structural depressions that favor the deposition of widespread, continuous coal seams. Intermontane basins, which are common in the Appalachian Mountains of the eastern U.S., form within mountain belts and often are structurally complex, resulting in a more heterogeneous coal distribution.

Within these basins, near-surface coal gas reservoirs of bituminous to anthracite rank were at one time buried to depths of greater than 3000 m. At these depths, hydrocarbons were generated in situ, and the cleat structure of the coal was formed. The cleats were preserved by relatively gentle uplift of the basin and erosion of the overburden. This is an important consideration for prospecting, because intense folding and faulting can shear coal seams, destroying the cleat structure and related permeability. Not all CBM reservoirs have been buried deeply before uplift. In portions of the Piceance, San Juan, and Raton basins of the western U.S., anomalously high geothermal gradients created by tertiary igneous intrusions have created high-rank coals at relatively shallow depths.[15] In the Powder River basin, biogenic gas is produced commercially from subbituminous coals that are too immature to have been deeply buried.

Within a given basin, various structures tend to be associated with enhanced gas production. In the Powder River basin, folds with up to 75 m of structural relief were created by differential compaction. These folds are superimposed on the gently dipping flank of the basin and contain free gas.[16] In the Black Warrior basin, several rollover anticlines and synclines have been linked to higher gas rates.[14] Tensional stress along the axes of these structures results in cleats that are more open and have greater permeability. Also in the Black Warrior basin, field mapping and remote sensing techniques have been used to identify well-developed fracture systems associated with high-rate gas wells.[17] In the San Juan basin, a multicomponent 3D seismic survey showed that areas of high well productivity correspond to zones of extensional fractures and lower in-situ stress.[18] The relationship between higher rates and lower stress also has been established in the Black Warrior basin by correlating the results of 70 well-test measurements with production from more than 600 wells.[19]

From these studies, it is clear that the prospective basins are relatively undeformed with low in-situ tectonic stresses. Within a given basin, knowledge of all structures, especially the locations of faults and folds, is very useful for siting prospective well locations.

Depositional Setting

Coals are associated with a variety of depositional systems including alluvial fans, rivers, deltas, and coastlines. Coals originate as peat deposits consisting of organic matter preserved from oxidation by rapid submergence beneath the water table. Accumulation rates are highly variable and range up to approximately 2 mm/yr.[20] The thickest, purest coals form in raised peat bogs that are protected from inundation by floodwaters. In contrast, lower-lying fens, swamps, and marshes are vulnerable to flooding and erosion. This creates laterally discontinuous coals with higher ash contents and interbeds of sandstone and shale (splits).

The Powder River, Black Warrior, and San Juan basins are among the most studied coal basins in the world, and they contain a variety of coal depositional systems.[21] Coals of the Paleocene Fort Union formation in the Powder River basin were deposited in a meandering to anastamosing fluvial system. The coals are elongated parallel to depositional dip and typically are narrow lenticular bodies. Coals in the overlying Wasatch formation formed in front of alluvial fans and are thick, lenticular, and oriented transverse to depositional dip.

Coals in the Pennsylvanian Pottsville formation of the Black Warrior basin are also of fluvial origin, but their distribution is partially controlled by the structural setting.[22] Thicker, higher-quality coals were deposited on the elevated, upthrown sides of faults and were protected from fluvial inundation.[21] Thinner, more ash-rich coal bodies formed on the downthrown sides of the faults. In some of the upthrown blocks, fluvial systems carved paleovalleys that were later abandoned and filled with peat, forming dendritic coal bodies.

In the San Juan basin, coals of the Fruitland formation are associated with both delta-plain and back-barrier settings.[21] Back-barrier coal bodies are geographically continuous along depositional strike. Relative to back-barrier coals, deltaic coal bodies are oriented along depositional dip and typically are more discontinuous, numerous, and thicker. These differences exist because the deltaic coals are separated by distributary channels, whereas the back-barrier coals formed behind a laterally extensive shoreline.

Understanding the likely geometry, orientation, and distribution of prospective coal seams is an important element of successful appraisal and development programs. These insights are valuable for locating thicker and higher-quality coal bodies, predicting whether these will be connected at a given well spacing, and determining future appraisal or exploration well locations. However, the presence of thick, laterally extensive coal bodies does not guarantee connectivity among wells because individual bodies can be extremely heterogeneous. Conversely, in areas in which coal bodies are small, they may be stacked to form well-connected, areally extensive coal reservoirs. To understand these relationships in a new area, it is necessary to continuously core coal seams and the rocks interbedded with them in several wells and relate this information to logs, well tests, and depositional models. This strategy has the added benefit of identifying potential conventional gas reservoirs in sandstones and carbonates interbedded with the coal seams.


The hydrogeology of a CBM reservoir can strongly influence reservoir pressure and gas content. Regions of artesian overpressure may form, allowing coals to retain significantly more gas than at lower pressures. Although these regions will require more dewatering, the potential exists for very high gas rates if the coal seams are saturated with gas. Conversely, regions of underpressure may form if permeabilities are low and coals are poorly connected to recharge areas. Coals in these regions are likely to have lower gas contents and poorer well performance. Hydrogeologic studies can identify these different pressure regimes and intervening permeability barriers, which provide explanations for regional differences in reservoir behavior and offer predictive tools to identify areas with the potential for extraordinary gas production.

Because of their good permeability and lateral continuity, coal seams are excellent aquifers in most basins. The coals outcrop along the basin margins, where they are recharged and carry groundwater to the basin. As a result, produced waters are relatively fresh (< 10,000 g/m3) and can be discharged at the surface in some basins. Points of discharge (upward flow) in a basin coincide with major river valleys, no-flow boundaries, and topographically low outcrop belts.[23] For a given coal seam, pressure data from existing wells can be combined with outcrop and stream elevations to produce a potentiometric map. This map is a measure of the hydraulic head in the coal seam, and it quantifies the driving force behind groundwater movement. Groundwater flows down the hydraulic gradient, perpendicular to the contours of the map.

A potentiometric map of Fruitland formation coals in the San Juan basin shows high values of hydrostatic head along the northern rim of the basin resulting from recharge. Farther south, the contours become tightly spaced and aligned in a northwest/southeast direction, indicating a buildup of fluid pressure caused by resistance to flow. This resistance is interpreted as a decrease in coal permeability and/or thickness coincident with a structural hingeline.[24] The hingeline forms the southern boundary of a large area of artesian overpressure, high gas content, and high gas rates known as the San Juan fairway. The artesian overpressure makes it possible for the coals to retain a large gas volume, and several gas sources (thermogenic, biogenic, and migrated gas) have combined to saturate these seams with gas. This recognition has led to the development of a model for identifying areas with extraordinary coal gas production potential in coal basins.[9]

In addition to potentiometric maps, chemical analyses of produced waters can be used to determine flow patterns within coal seams. This is possible because groundwater evolves chemically along its flow path, causing changes in pH, Eh, and in the composition and concentration of ions and isotopes. For example, recharge along basin margins creates plumes of low chloride, fresh water that follow the most-permeable flow paths within a coal reservoir. These meteroric waters are depleted in certain isotopes of oxygen and hydrogen.[23] Other isotopes can indicate the presence of bacterial activity or provide an absolute age for the waters. Abrupt differences between these values can help identify reservoir compartments.

Data Sources

Openhole logs, mudlogs, mining data, drilling histories, and cores from conventional wells are valuable sources of data for determining the number, depth, thickness, and quality of coal seams in a frontier basin. Because of their low density, coals are identified most easily with openhole density logs. A combination of other log responses may be used to infer coals if density logs are not available. Mudlogs are useful for detecting coals through cuttings analysis and associated gas shows. Drilling histories should indicate an increase in rate of penetration through the coals, which are much softer than adjacent rocks. Gas kicks also may be noted, especially in high-pressure, gassy coal seams.

Cores are a critical source of information, but conventional wells typically cut cores only in sandstone or carbonate horizons. Descriptions of these intervals can provide insights into the depositional setting of associated coal horizons, while routine core analyses can indicate whether these intervals could be an important source of supplemental gas. If coal cores have been cut in conventional wells, they are unlikely to be described or analyzed in detail. However, if the cores have been placed in a storage facility, they can be described thoroughly and characteristics such as maceral composition and rank can be determined.

Well tests in conventional wells may provide indications as to the potential for coal gas production. Coals occasionally are included in a test interval and could be the source of any reported gas production. Because coals are damaged easily by conventional drilling muds, reports of produced gas from intervals that include coals may indicate the potential for much greater rates from an undamaged or stimulated coal completion.

Coal outcrops typically are found updip from CBM prospects and are often the site of extensive mining activity. Data from these mines can be very helpful in an initial assessment of CBM prospectivity. The amount of gas released can provide an indication as to whether the coals have high gas content. In some mines, horizontal and/or vertical boreholes are drilled ahead of mining operations to help reduce gas concentrations, and this gas may be captured and sold. Mining companies are keenly interested in coal quality and regularly collect information regarding ash content, coal composition, and maturity. As part of planning for future expansion, core holes are commonly drilled downdip from the mines. Core hole drilling histories may indicate gas kicks or report the flow of water and gas to the surface. Information from these core holes can be combined with data from the active mine to make maps of coal structure, thickness, and quality. A trip to an active mine may include the opportunity to obtain coal samples for analysis or examine an active coalface. This examination can yield important clues regarding cleat spacing, cleat orientation, variations in coal quality, and relationships with other lithologies.[25]

Geologic maps of the earth's surface exist for many coal basins. If the maps contain the coal outcrop belt, they can be used to determine the strike and dip of coal seams, identify faults or folds, and determine the relationship of coal horizons to underlying and overlying strata. Geophysical data also may exist, especially seismic data, which are very useful for estimating the depth and lateral extent of thick coal seams and recognizing faults that displace them. Remote sensing data, including aerial photos and satellite photos, can be used to delineate geomorphic patterns that may be controlled by the underlying structural geology. These patterns include linear features that may indicate faults, closely spaced linear features that could represent fracture zones, and annular drainage patterns that may indicate structural highs.[26]

Reservoir Evaluation

Core Analyses

Core analyses are a critical part of analyzing CBM reservoirs to determine gas saturations. Coal cores must be placed in desorption canisters and heated to reservoir temperature. As the coal desorbs, gases are captured, and both their volume and composition are determined. Desorption continues for up to several months until the rate at which gas is being liberated from the coal becomes very small. At this point, the canisters are opened, and the cores can be described. The cores then are crushed in a mill that captures any remaining gas (residual gas), and the milled coal is mixed thoroughly to form a representative sample. Portions of this sample are used for sorption isotherm measurements, proximate analysis, ultimate analysis, vitrinite reflectance, maceral analysis, and bulk density determination. Table 6.5 summarizes the various core analyses. An alternative to crushing the entire core is to first slab the core and crush one-half. The uncrushed half can be preserved for additional work including petrographic examination of the core and future coal analyses. The results of these core analyses are critical for both gas-in-place determinations[27] and estimates of gas rates and recovery factors.[28]

Log Analyses

Because gas is sorbed to the walls of the coal micropores, openhole logs cannot calculate useful matrix porosity or gas saturation values. Nonetheless, logs are still useful for determining the location and thickness of coal seams and estimating their quality. Because of their low density, coals are identified most easily from a density log. They also can be recognized by a combination of other log responses including high apparent neutron and sonic porosities, high resistivities, and low gamma ray values. Caliper logs also can be a useful coal indicator because coal intervals are often washed out by drilling operations. Mudlogging can detect coal seams through a combination of gas kicks, lithologic description, and changes in the rate of drilling penetration. Mudlogging is recommended especially for exploratory or appraisal wells, which may contain unexpected coal seams or other gas-bearing lithologies.

Pure coals are characterized by low values of density and photoelectric effect, whereas ash-rich coals have much higher values. Micrologs can provide a qualitative indication of coal permeability based on the degree of separation between the micronormal and microinverse curves. Caliper logs also may indicate permeability by detecting a thicker mudcake across permeable coals. Logs that are more sophisticated may be available in newer wells, such as geochemical, nuclear magnetic resonance, or borehole imaging logs. These may have to be reprocessed with an emphasis on quantifying the location and properties of coals. These imaging logs are useful for identifying large fractures and thin higher-resistivity shales interbedded with the coals, but these tools do not have sufficient resolution to identify cleats. If a complete log suite is available, sophisticated computer models may be applied to estimate multiple coal characteristics.[29]

Although logs are useful for identifying coal seams and estimating their gross character, coals typically are laminated at a much finer scale than can be resolved with logs. As a result, bright-banded coals with good cleating and high gas contents may be interbedded with ash-rich horizons, giving the appearance of a relatively homogeneous, poor-quality coal on the logs. This is similar to the thin-bedded-pay problem in clastic reservoirs and emphasizes the value of the use of coal cores for reservoir characterization. In addition, pure coals identified from logs may be composed of relatively gas-rich vitrinite macerals or gas-poor fusinite macerals. As a result, some low-density coals may be highly gas-productive while others may not.

Well Testing

Buildup tests, injection/falloff tests, and slug tests each have been used successfully to determine critical reservoir and completion parameters in CBM reservoirs. In a buildup test, a well that is producing at a constant rate is shut in, and the downhole pressure is measured as it builds up. In an injection/falloff test, a well that is injecting at a constant rate is shut in, and the downhole pressure is measured as it falls off. In a slug test, a pressure differential is introduced instantaneously across the sandface, and the pressure response is measured. This typically is done by rapidly changing the fluid level in the well.

Slug tests are relatively simple to run and are inexpensive compared with other types of well tests. However, slug tests can be used only in underpressured reservoirs and may not investigate a large reservoir volume. This is an important consideration because CBM reservoirs typically are very heterogeneous, requiring a large radius of investigation to characterize them adequately. Slug test results may be used to design other single or multiple well tests for determining additional reservoir parameters.

Conventional drillstem or buildup tests can be run in CBM wells, but, in many cases, the reservoir pressure will be too low to lift produced water to the surface. This limits the ability to obtain a large radius of investigation with these tests in low-permeability reservoirs. However, reliable test data and results can be obtained if the test is run long enough to reach infinite-acting radial flow. For example, drillstem tests conducted in low-permeability coal seams in the Ordos basin of China were followed by injection/falloff tests that provided similar results.

In an injection/falloff test, it is important to establish communication with all the coal layers before testing. This can be achieved by breaking down the perforations with a small ballout treatment followed by a spinner survey to confirm communication. After allowing the water level in the well to stabilize, injection should commence at a low, constant rate to avoid changing the wellbore stress. This rate should be below the formation-parting pressure to avoid long periods of linear flow that could mask the infinite-acting radial flow regime. The formation-parting pressure can be determined by a step-rate test before the injection falloff test. The maximum acceptable injection pressure should be less than 80% of the estimated parting pressure. After the injection period, the well is shut in and the bottomhole pressure is monitored for a period of time that is usually approximately twice the injection time. A downhole shut-in device may be used to minimize storage effects and reduce the test time. A downhole shut-in device is critical in underpressured reservoirs to avoid problems of falling liquid levels in the wellbore during the falloff period.

Injection/falloff tests are more expensive than slug tests and buildup tests, but they have at least three advantages. First, injection/falloff tests do not require reservoir flow; therefore, they can be run in underpressured as well as normal and overpressured reservoirs. It usually is easier to measure injection rates in an injection/falloff test than it is to estimate flow rates in a drillstem test when fluids are not produced to the surface. Second, injection/falloff tests usually are not affected by complications resulting from gas desorption because the reservoir pressure does not fall below the initial pressure during the test. The reservoir pressure will fall below the initial saturation pressure in the drawdown portion of a drillstem test and may result in gas desorption near the wellbore. Third, injection/falloff tests typically investigate larger reservoir volumes than slug tests or buildup tests, especially in underpressured reservoirs, which cannot flow fluids to the surface.

Well-test permeability is a critical parameter for estimating CBM production rates and ultimate recovery. Fig. 6.2 illustrates a plot of effective permeability vs. expected ultimate recovery. It is important to obtain good permeability estimates from well testing early in the life of each well, preferably before hydraulic fracture stimulation and production. If the well is not tested before fracture stimulation, it may be difficult to run a test long enough to reach infinite-acting radial flow and determine the average value of permeability. Once the permeability is known from a prefracture test, post-fracture tests can be used to determine fracture properties. Wells should be tested before production to avoid two-phase flow during the tests. Slug tests and injection/falloff tests performed before production are most likely to result in a single-phase flow of water. The data from these tests can be analyzed with conventional methods. Although it is easier to analyze data from tests with single-phase flow, it is often important to test wells with two-phase flow. Tests with two-phase flow may be required to track permeability changes over the life of a field because permeability can vary significantly as a function of pressure and gas desorption as a CBM reservoir is produced.

Effective permeability will change during the productive life of a CBM reservoir because of changes in relative permeability as fluid saturations change. Effective permeability also may vary because of changes in absolute permeability as the reservoir is produced. During early production, the coal matrix expands as pore pressure is reduced, resulting in a decrease in absolute permeability. With continued production, the matrix contracts as gas desorbs from the coal, resulting in an increase in absolute permeability. These changes can be tracked over time with pressure-transient testing. The absolute permeability can be calculated from a two-phase test with the use of relative permeability curves derived from simulation, analogous fields, or the published literature. The coal degasification pseudopressure function developed by Kamal and Six[30] can be used to analyze CBM well tests with two phases flowing. The method incorporates sorption isotherm and relative permeability relations. Mavor[28] describes an alternative method to analyze tests with two-phase flow.

Multiple well tests can be used to indicate the degree of communication between wells and to determine permeability anisotropy. Coals typically demonstrate greater permeability in the face cleat direction because these fractures are more continuous and have wider apertures than butt cleats. Directional permeability ratios as high as 17:1 have been reported because of this anisotropy. It is important to understand both the direction and magnitude of permeability anisotropy early in the project life because it can have a significant impact on the choice of well-pattern geometry and orientation and well spacing.

Commercial software or conventional pressure-transient equations can be used to design CBM tests properly. If the permeability range is unknown, the test can be designed for the lowest acceptable permeability that would result in a viable project, usually 1 to 5 md, depending on other factors such as coal thickness, gas content, and initial saturation state. Although coal has a dual porosity nature, most CBM tests can be analyzed with a homogeneous model because all the Darcy flow occurs within the cleat system. Conventional well-test analyses generally are preferred for analyzing data from CBM well tests because they are relatively straightforward. In some cases, however, reservoir and flow conditions do not follow the assumptions on which conventional well-test analysis methods are based. Numerical simulators are useful for history matching well-test data when conventional analyses are inadequate.

Pilot Projects

Multiwell pilots are a key element in appraising the potential of a CBM reservoir. A typical pilot consists of several closely spaced wells that are produced for a sufficient period to understand the potential of the reservoir and determine if it can be developed commercially. The key objectives of a pilot are to quantify variations in key reservoir parameters such as net thickness, gas content, gas saturation, and permeability; assess the ability to dewater the reservoir as indicated by decreasing water rates and reservoir pressures; determine gas productivity and the potential for commercial gas rates; test completion options such as hydraulic fracture stimulation, cavitation, and artificial-lift methods; and evaluate full-field development issues such as well spacing and pattern geometry.

Choosing the size of the pilot is a critical consideration. The pilot should be large enough to evaluate a representative part of the reservoir but small enough to achieve definitive results in a short period. Generally, pilot wells will need to produce for a minimum of 6 to 12 months at a well spacing of less than 40 acres. Numerical simulation should be used to optimize these values and predict the performance of the pilot on the basis of individual reservoir characteristics. A pattern containing an isolated center well, such as a five-spot, is preferable and can be implemented with a successful appraisal well as part of the pattern. Once the wells are drilled and completed, it is critical to collect high-quality surveillance data on a regular basis including individual-well water and gas rates, flowing bottomhole pressures, and shut-in bottomhole pressures.

A successful pilot will show increasing gas rates, decreasing water rates, and decreasing reservoir pressures with time. If the pilot gas rates are approaching an economic level, the pilot can be expanded to development-scale spacing. If the gas rates are increasing but clearly subeconomic, the pilot can be expanded at the current well spacing to a nine-spot or other configuration to minimize water influx and assess whether economic rates will be achievable. If water and gas rates are low, the initial pilot wells can be produced for a longer period, or the project can be terminated. Before making any decision, it is critical to reconcile pilot well performance with core, log, and well-test data, preferably through reservoir simulation. This work will ensure, for example, that a good CBM reservoir is not being abandoned because of poor well completions.

A staged piloting approach is the best way to minimize the time and cost of evaluating a CBM reservoir. In a frontier area, multiple pilots may be needed to prove up a large enough area to declare commerciality and obtain gas sales contracts. The number of appraisal wells that should be drilled and offset by additional wells to create pilots must be determined. If several widely spaced appraisal wells indicate similar reservoir properties, a single pilot may be sufficient to decision a large area. However, if properties vary dramatically, multiple pilots may be needed. A good approach is to drill the first pilot wells around the most prospective appraisal well. If this pilot is unable to produce gas at economic rates, then it becomes unlikely that additional pilots will be successful, leading to an early exit from the project. Alternatively, if the first pilot is successful, management will be enthusiastic about expansion and additional investment. Unfortunately, management often loses interest in a CBM prospect because of the multiyear time commitment, the money required to reach a decision point, and because the technical staff often does not have a clearly defined evaluation and exit strategy.

Numerical Simulation Studies

Because of their layered, fractured, and heterogeneous nature, CBM reservoirs are very complex. Reservoir properties can vary rapidly, and many variations are difficult to quantify. Some of these properties, such as porosity and gas saturation, must be determined from sources such as cores, analogous reservoirs, and correlations rather than from wireline logs. Other properties, such as compressibility and gas storage capacity, are difficult to measure in the lab and can range over several orders of magnitude. Additional complications include fluid contributions from noncoal layers and the likelihood of strong directional permeability trends.

The impacts of these reservoir complexities are best resolved with numerical reservoir simulation. The advantages of numerical simulation include the ability to integrate widely different data types such as reservoir, completion, and well performance data; help resolve data discrepancies and provide key insights into production mechanisms; incorporate unique components such as gas storage and diffusion mechanisms; understand and revise the geologic model including estimates of aquifer size and strength; evaluate development options such as well spacing, well pattern, and fracture design; and provide a reasonable basis for rate and reserve estimates. However, because of their complexity, rate and reserve forecasts for CBM reservoirs are generally less certain than the forecasts for conventional oil and gas reservoirs. Perhaps the most valuable use of CBM simulation is to evaluate the effects of variations in key parameters. Because of the difficulty in quantifying the areal and vertical variation of every CBM parameter, simulation can be used to test the impact of various parameter combinations on overall reservoir performance.

In addition to the usual data types required for numerical simulation, CBM simulation requires gas content values at initial reservoir conditions, sorption isotherms, the diffusion coefficient, and parameters to estimate changes in absolute permeability as a function of pore-pressure depletion and gas desorption. Because these properties may vary significantly, it is critical to have representative core and well-test data from each coal seam. To obtain a meaningful history match, high-quality surveillance data must be obtained from producing wells at regular time intervals. Water and gas production data can be obtained easily, and flowing bottomhole pressures can be estimated from fluid levels in a pumping well. Numerical simulation can be used to determine how often shut-in pressures should be obtained, and these often can be measured in conjunction with well work or other planned shut-in periods.

Gas-in-Place Determination

Gas in place in a CBM reservoir consists of free gas residing in the cleat system plus the gas that is sorbed onto the surface of the coal.



G = gas in place, Mscf, A = areal extent, acres, h = net coal thickness, ft, φcl = cleat porosity, fraction, Swi = initial water saturation fraction in the cleats, fraction, Bgi = initial gas formation volume factor, Mscf/ft3, Gc = gas content (dry ash-free basis), scf/ton, ρc = coal density (dry ash-free basis), lbm/ft3, fa = ash weight fraction, lbm ash/lbm coal, and fw = water weight fraction, lbm water/lbm coal.

Generally, coal thickness is estimated by counting those intervals with a bulk density of less than 1.75 g/cm3. Larger density cutoff values are sometimes used, but this requires that a lower average gas content be used as well. Coal density values can be determined from a density log or from core measurements.

Gas content values are obtained from coal core-desorption measurements corrected for lost gas and residual gas. Values of several hundred scf/ton are quite common, although values can range from less than 10 to more than 1,000 scf/ton in high-rank coals. The ash fraction is derived from proximate analysis of desorption-canister samples and ranges from a value of zero in pure coals to a value of one in mudstones. The water weight fraction is also obtained from proximate analysis and ranges from less than 0.05 in medium-volatile bituminous coals to more than 0.5 in subbituminous coals. Cleat porosities, which are difficult to measure, typically are assigned values ranging from 0.01 to 0.05. Initial water saturation in the cleats is generally assumed to be 1 unless the cleats contain free gas.

Determining accurate coalbed reservoir gas-in-place parameters is often a difficult, time-consuming process, and the resulting estimates must be revised many times as additional wells are drilled and more information becomes available. Because few wells are cored and coal recoveries generally will be less than 100%, the existing coal samples may not be representative of such a heterogeneous reservoir. Lost-gas corrections, especially if they are large, often yield erroneous gas content values. Density logs do not capture the fine-scale variability of coal seams and typically are only a rough approximation of the net coal thickness that is actually contributing gas. Several references exist to guide this work including a comprehensive publication by the Gas Research Institute (GRI).[27]

Reserves Determination

Estimates of remaining CBM reserves are commonly made throughout the life of a project. These estimates begin with qualitative values generated before drilling appraisal wells and extend to quantitative reserve numbers based on the production history of development wells. During the initial screening stage, parametric studies provide a means to relate values of key reservoir parameters generically to recovery factors.[31] As the first wells are drilled, data from analogous producing fields can be used to estimate the potential gas reserves of a new asset if their reservoir characteristics are similar.

Once coal cores have been cut and analyzed, the measured gas content and sorption isotherm data can be used to estimate a recovery factor and reserves. The gas content indicated by the isotherm at an assumed abandonment pressure is subtracted from the total gas content of the core at current reservoir pressure. This value, divided by the total gas content of the core, provides an estimated recovery factor (Fig. 6.1). This calculation assumes that the permeability and coal-seam continuity are sufficient to achieve the expected abandonment pressure in an economic time frame. This is a critical assumption because the shape of the sorption isotherm curves dictates that most of the gas is produced at low-pressure values. A more sophisticated tool for estimating reserves at this stage is numerical reservoir simulation, which can be used to determine whether the assumed abandonment pressure is realistic for the expected range of permeabilities.

Estimates of gas in place and the recovery factor may be improved after multiple wells have been completed with the use of a modified material-balance technique.[32] This approach requires substantial production and reservoir pressure data as well as estimates of gas saturation, effective porosity, formation compressibility, and water influx. The technique uses a conventional material-balance equation modified to account for gas desorption from the coal seams.

Decline-curve analysis can be used in the mid-to-late stages of the field's producing life. This method is dependent on production data and implicitly assumes decreasing gas production in its forecast. The increasing gas rates that characterize early CBM reservoir behavior preclude the application of decline-curve analysis during this period. However, if the reservoir data, completion type, and early production character of a new well are similar to a mature well in the area, then the profile from this mature well may be used to estimate the performance of the new well. Some operators use mature-well data to create a series of type curves for estimating the performance of new wells.

Drilling, Coring, and Completions


The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. These data include reservoir depths and pressures, drilling histories, and environmental considerations. Sources of this information include regulatory agencies, service companies, coal-mine operators, and the published literature. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel.

An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple. For example, water-based drilling fluids may be more damaging to the coals than air or gas drilling, but they are safer in the event of a gas kick, and the damage can be mitigated by fracture stimulation.

CBM wells range in depth from a few hundred meters to more than 3000 m. As a result, several rig types and sizes may be suitable for a given well plan. The most common rig type is the conventional rotary drilling rig, although modified water-well rigs commonly are used to drill shallow coal wells in locations such as the Powder River basin of Wyoming. Other rig types include top-drive rigs, mining rigs, and coiled-tubing drilling units. In some cases, a drilling rig is used to drill the well to the top of the target coal seams and set/cement casing. A modified completion rig is used to drill the target coals and complete the well while the drilling rig moves to the next well.

The selection of a rig, associated equipment, and drilling fluids is often guided by the completion method. For example, if a dynamic-cavity completion is planned, the rig should be equipped with a power swivel for rotating, reciprocating, and circulating during cleanouts. Auxiliary equipment for this completion will include air compressors and boosters, blowout preventers, a rotating head, and specially designed manifold and flowlines for production testing. In some instances, it is more efficient to select a drilling rig by starting with the desired completion method and designing backwards.

Reservoir pressure and coal characteristics help dictate whether the coal interval is drilled with mud, water, air, gas, or mist. Water-sensitive shales may require the use of gas or air to minimize swelling and sloughing. Slightly underbalanced drilling helps minimize coal formation damage. Horizontally drilled CBM wells are becoming more common and have been used successfully to produce CBM from several locations in the U.S., including the Arkoma basin of Oklahoma and the Appalachian basin of West Virginia. Multilateral wells also are used, especially in coal mining applications to degas coal seams economically ahead of mining.[33]


Coal cores can be obtained with several different techniques including conventional, wireline, and pressure coring. Conventional coring equipment is drillpipe conveyed, which can result in trip times of an hour or more. Because coal samples begin to desorb gas as they are lifted from the bottom of the well, long trip times can result in large volumes of lost gas. Desorbed gas volumes can be corrected for this effect, but the correction may not provide accurate gas content. As an alternative, many operators use wireline-coring equipment, which can bring samples to the surface in 15 to 20 minutes, significantly reducing lost-gas volumes.

A few operators use pressure coring, which traps the coal downhole in a sealed barrel, preventing any gas loss. This technique requires specialized equipment, which can be difficult to operate, and is approximately five times more expensive than conventional coring. The best applications for pressure coring are those cases in which there are large discrepancies between existing gas content data and well behavior. For example, pressure coring in some San Juan basin wells showed that gas contents were twice as high as those values obtained from conventionally cored wells.

To obtain representative gas content values, high core recoveries are imperative. Unfortunately, recoveries are often low because higher-quality coals tend to be highly cleated and friable, causing them to break up. In addition, many operators wait to core until they see a gas kick on the mud log or a change in the rate of penetration. Waiting until this point means that the top few feet of the coal seam will be missed, and if the coal seam is thin, it may be missed entirely.


Several different types of CBM completions have been developed to link the wellbore to the cleat system effectively. The most common completion type is to run casing, perforate, and hydraulically fracture the coal seams. Frac jobs in low-permeability coals require long, narrow, propped fractures, whereas short, wide, unpropped fractures are used in higher-permeability coals. If the permeability is high enough and the coals are relatively undamaged by drilling, a simple openhole completion may be sufficient. In a few areas, dynamic-cavity completions are used, resulting in gas rates that are substantially greater than fracture-stimulated wells. Fig. 6.3 compares fracture-stimulated and dynamic-cavity completion types.

It is important to stress that optimizing completion methods in a coal reservoir is likely to be a trial-and-error process. This process can be shortened by fully understanding the different completion types available, where they are most applicable, and by collecting sufficient reservoir data to select the best completion. Reviewing publications from the GRI, which has been involved in a wide range of CBM completion studies for many years, is a good place to start.

In developing a completion and stimulation procedure, it is useful to begin with a successful stimulation design and modify it to fit a specific coal reservoir. Service companies typically have access to generic designs and an in-house proprietary stimulation model. It is important to conduct this modeling before drilling the well because factors such as stimulation treating pressures, the number of fracture stages, and the expected production rate will have a direct bearing on components such as rig equipment, tubulars, and overall well cost.

Hydraulic Fracture Stimulation Hydraulic fracture stimulations in cased and perforated CBM wells are very similar to those in conventional reservoirs, and there are many advantages to this completion type. By casing the well, interbedded strata can be placed behind pipe. This is especially important if the strata include swelling shales or fractured lithologies that could contribute large volumes of water. By perforating coal seams individually, they can be tested to determine their pressure, permeability, and skin before the stimulation treatment.

The well then can be fractured in multiple stages, with treatments optimized for a particular coal seam or group of seams. To ensure the appropriate interval is treated, stages can be isolated with bridge plugs, frac baffles, sand plugs, or ball sealers. Limited-entry fracture stimulations may be appropriate if there are several coal zones distributed over a long interval. If there are thin, multiple coals, a modified coiled-tubing unit can be used to treat each coal seam successively, resulting in significant cost savings. During the stimulation, tracers often are added to the fracturing fluids to determine fracture height by running a subsequent gamma ray log. Subsequent well testing can help determine the conductivity of this fracture. During production, fluid-entry surveys can be used to quantify the contribution of individual coal seams.

The biggest disadvantage to fracture stimulation is that productivity is often lower than expected. Horizontal, vertical, or complex fractures may be generated, depending on the depth, seam thickness, and the distribution of in-situ stresses.[2][34][35] Induced fractures may be very tortuous, leading to high treatment pressures and early screenouts. Severe formation damage can be caused by coal fines or fracturing fluids. These fracturing fluids can be difficult to remove with gel breakers because of low formation temperatures. Most CBM hydraulic stimulations are performed conventionally through perforations in the casing, although openhole hydraulic stimulations have been tried in several basins. These stimulations typically yield unfavorable results because of poor downhole controls.[36]

CBM fracture-stimulation treatments typically are water based and fall into one of the following four categories: water (slickwater), gel, foam, or proppantless. In a water fracture-stimulation treatment, the base fluid is plain water or water with a high-molecular-weight polyacrylimide polymer added for friction reduction (slickwater). Water fracs are often a preferred treatment because they are less damaging to the coals than gel treatments and are commonly less expensive. Water fracs typically are pumped at high rates of 50 to 80 bbl/min to compensate for the low viscosity and poor sand-carrying capacity of the water. Typical treatments use 12/20- to 20/40-mesh sand with proppant loadings of 2,000 to 3,000 lbm/ft of net coal, ramping up from 1 lbm/gal to 4 to 6 lbm/gal at the end of a typical treatment. One of the main disadvantages of a water frac is the tendency for premature screenouts, which create short fracture half-lengths and result in poorer well performance.

Gelled water-based stimulation fluids use natural or synthetic polymers to provide viscosity and are categorized as linear or cross-linked gels. Their high viscosities result in large transport capacities, which allow bigger jobs to be pumped. Proppant sizes are commonly 12/20- to 20/40-mesh sand with proppant loadings of 5,000 to 10,000 lbm/ft of net coal. The key disadvantage to a gel-based fluid is the potential for serious formation damage caused by cleat blockage from unbroken gel, gel residues, and sorption-induced coal swelling.

Foam treatments are formed by dispersing a gas (usually nitrogen or carbon dioxide) within a water-based fluid. Foam stimulations are commonly used in coal reservoirs with low permeabilities and/or low pressures. When combined with gel systems, foams can provide high viscosities to carry proppant efficiently. An additional benefit of foam is its low hydrostatic pressure, which helps create rapid flowback of the fracturing fluids in low-pressure coals. Disadvantages of foam are the safety concerns of pumping an energized fluid, rapid proppant flowback, and the additional cost of the gas.

Proppantless stimulations generally use plain water as the base fluid, although gel and foam can be used. When water is used, the volumes and rates are similar to those of a slickwater design. Ball sealers are recommended to ensure effective zonal treatment. Proppantless stimulations are attractive because there is no proppant flowback, no residual-gel damage, and substantial cost savings. These stimulations are effective in locations such as the Powder River basin of Wyoming, where the objective is to connect the wellbore effectively to high-permeability coals. However, in lower-permeability coals such as the Black Warrior basin of Alabama, production rates indicate that proppantless stimulations are less effective than sand/water stimulations by a ratio of 2:1.[37]

Dynamic-Cavity Completions A cavity completion is defined as an openhole completion with an intentionally enlarged wellbore (cavity) in the target coal interval. This completion type was pioneered in the overpressured Fruitland Coal fairway of the San Juan basin, where cavity completions have produced gas and water at rates more than 10 times greater than those of nearby fracture-stimulated wells.[38][39] Cavity completions are believed to enhance permeability by creating self-propped tensile fractures and orthogonal shear failure zones. Additionally, the surging and cycling process increases permeability by removing formation damage and causing dilatancy.[37][38] Dynamic-cavity completions are created by intentionally causing a large pressure drop in the wellbore, resulting in the redistribution of stresses and subsequent coal failure.[33] Sonar probes run in cavitated wells indicate cavern diameters as large as 8 ft.2

Different cavitation techniques have evolved in response to different coal properties and various problems, including the inability to initiate coal failure, stuck pipe or tools, and cavity instability. At least five different types of cavitation are now used including drilling, natural, injection, mechanical, and jetting cavitation. Each of these operations usually are conducted multiple times over a given coal zone until an acceptable flowrate is obtained. The flow rate following each operation can be determined quickly with a pitot gauge to decide if another cavitation cycle is needed.

Drilling cavitation is performed by drilling through the coal zones in an underbalanced state. This creates a pressure drop across the formation face, causing the coal to shear or break off along near-wellbore cleat or fracture planes. High circulation rates with air, gas, or mist generally are used to clean the hole effectively.

Natural cavitation begins by drilling a targeted coal seam with air, gas, or mist. The bit is then lifted above the seam and the well is shut in. The well builds pressure naturally until a specific pressure is achieved. Buildup surface pressures should be recorded and a curve drawn of each buildup period. Once a pressure breakover point is observed, the well is rapidly opened at the surface with hydraulically operated valves. This causes a high-rate depressurization accompanied by a surge of water, gas, and coal rubble, which are produced up the well and through a flowline to the flare pit. The bit is then lowered to the bottom of the hole while rotating, reciprocating, and circulating. The wellbore is cleaned out and checked for fill, and the operation is repeated until adequate results are achieved. The next zone is then drilled, and the process is repeated. In some cases, all coal zones are drilled before the natural cavitation process is attempted.

Injection cavitation is similar to natural cavitation, except that the wellbore is pressured up from the surface and then surged. The process typically is repeated many times, often for several days or weeks depending on the results of each cycle. Several different fluids can be injected including gas, air, water, CO2, foam, or coal-comminuting solvents.[40][41][42] These are pumped through the drillstring into the formation until a predetermined pressure is reached, sometimes in excess of 1,500 psia. This induced pressure is then suddenly released at the surface by hydraulic valves, resulting in the flow of water, gas, and coal rubble to the surface while continuing to circulate the wellbore through the annulus with gas or air. Because of the large cavities that sometimes are created, a substantial amount of the larger coal pieces may not be circulated out of the wellbore. It is crucial to drill up and clean this fill so that the maximum production potential of the well can be determined.

Mechanical cavitation involves drilling the coal zones to total depth, and then a mechanical hole opener (underreamer) is used to enlarge the wellbore. This process also removes any near-wellbore formation damage. In some cases the noncoal zones above and below the coals are underreamed to relieve overburden stresses that could cause the coals to fail and slough into the wellbore. In some cases, natural or surging cavitation is performed after mechanical cavitation. Jetting cavitation uses hydraulic pressure to direct a jet of gas and water directly toward the coal face. This process may be performed to facilitate a cavity when other cavitation methods have failed. It has been used in several basins with mixed success. In the Piceance basin of the western U.S., jetting cavitation increased coal gas production from approximately 20 Mscf/D to more than 100 Mscf/D.[43]

Recavitations are performed when the original openhole or cavity completion exhibits poor production compared with offsetting cavitated wells. Additionally, a recavitation or cleanout is performed when the original cavity completion exhibits unexplainable production decline over time. The injection cavitation technique is typically used and the procedure is carried out with a modified completion or cavitation rig. The well is killed with water, and the production casing or liner, if there is one, is removed. The removal is sometimes difficult, resulting in a sidetrack or redrill of the original hole. The well is then recavitated until the flow rate is acceptable, the cavity is stable, and the amount of produced coal fines is minimal.

When a successful cavitation or recavitation operation is performed and the cavity is deemed stable, it is crucial that no additional pressure surges (increasing or decreasing) are applied to the well. When the well is ready for production, it should be opened slowly over a period of several hours to limit the surging of water and gas into the wellbore, thereby minimizing the movement of coal fines and the spalling of coal.

Production Operations and Facilities

Critical Aspects

Production operations in CBM wells are not significantly different from other gas wells except for one important distinction. Conventional wells typically begin production with high gas/water ratios (GWR) that decrease with time, whereas CBM wells start with low GWRs that increase with time. This distinction requires that equipment and facilities for water handling and disposal be built at the start of a project, which requires significant lead time and capital investment.

The initial operational goal of nearly all CBM wells is to depressure the reservoir by continuously producing water at a low flowing bottomhole pressure. This requires an artificial-lift system that can be modified as the gas rate increases and water volumes decrease. Smaller tubulars and pumps are typically required with time as the reservoir pressure decreases and water rates drop. Initially, produced gas may be flared, especially in frontier areas without access to gas transmission systems. If the gas is to be sold, analyses will be required and treatment facilities may be needed to meet pipeline specifications.

The acquisition of high-quality reservoir surveillance data is a key element of production operations. Initial reservoir pressure values from each well and subsequent reservoir pressures are critical for determining whether depressuring is occurring. These data can be captured with downhole gauges or by measuring static wellbore fluid levels. Similar data should be obtained under producing conditions to ensure that wells are being pumped off. Both static and flowing bottomhole pressures should be measured every few months in a new pilot project or field development.

Production logging tools also should be run to determine which coal seams are contributing; however, these tools typically are limited to either flowing wells or those with a downhole assembly that can accommodate the tools under pumping conditions &lsqb;such as an electrical-submersible pump (ESP) with a Y-tool&rsqb;. Accurate gas and oil rates are extremely important and should be measured frequently. In most projects, the production rates from new wells are measured daily to capture fluctuations in early production.

Water Production and Artificial Lift

Initial water rates in a CBM well are a function of the average coal permeability and aquifer strength. Because permeability often varies by more than three orders of magnitude within the same field, produced-water rates will vary by this magnitude as well. For example, in the Black Warrior basin of Alabama, initial production rates for 420 wells ranged from 17 to 1,175 BWPD, averaging 103 BWPD.[44] Initial water rates may be unusually high if the coals are overpressured because of coal recharge along the basin margin. Initial water rates may be unusually low if the productive area has been depressured by nearby mining operations or previous well production. Water rates should peak within the first few years and decline thereafter, unless the aquifer is extremely strong or the number/spacing of producing wells is insufficient to depressure the reservoir.

Nearly all CBM wells require artificial lift at some point to accelerate dewatering and reduce reservoir pressure. The most common artificial-lift types include ESPs, progressive-cavity pumps (PCPs), beam pumps, and gas lift. The method and criteria for selecting lift equipment is similar to other wells and is governed primarily by the expected production rate. However, because many CBM wells are drilled in frontier areas where there is little coalbed-well experience and a limited maintenance infrastructure, it is often best to choose the lift system that is simplest to operate and least troublesome.

ESPs are ideal for pumping volumes in excess of l,000 BWPD from coal wells, but these pumps require reliable electricity and can be damaged by coal solids (fines), which are common in the early productive life of a well. PCPs are popular in many CBM projects because they can produce 100 to 1,000 BWPD, handle coal fines effectively, and require little maintenance. The versatile beam pump handles low-to-medium water volumes of 5 to 500 BWPD and requires little maintenance. Gas lift is the least expensive lift system to operate. It requires no electrical power and handles low water rates of 5 to 50 BWPD. Gas lift, however, requires specific well pressure tolerances to work effectively. The bottom line is that no matter which artificial-lift system is used, it is crucial to minimize downtime and keep the well pumped off.

Water Disposal

Water disposal is one of the most important considerations in a CBM development. It can be very costly to build water-handling facilities, drill disposal wells, and comply with numerous environmental regulations. In marginally economic projects, water-disposal costs can be the deciding factor as to whether the project moves forward. It is important to remember that water production in CBM wells is viewed as an early, relatively short-term problem that must be overcome to produce gas economically.

To decide which disposal method is most applicable, a complete chemical analysis of a representative water sample is needed and anticipated water rates must be determined. There are three common techniques used for disposing of produced water in the CBM industry. Subsurface injection requires that a well be drilled or an existing well be worked over to accept produced fluids into an approved disposal zone. Because CBM reservoirs are shallow, most disposal wells must be drilled to deeper horizons, resulting in disposal wells costing more than development wells. The second disposal method, surface evaporation, uses active evaporation ponds and a spray/mist system to evaporate the produced water. The third technique, stream discharge, requires an elaborate treating and monitoring system to ensure that chlorides, total dissolved solids, and other impurities are lowered to acceptable levels.


Production facilities for CBM wells must be capable of handling produced water, coal fines, and low-pressure gas. Accurate forecasts of early water production are necessary to size separators, flowlines, transfer pumps, and storage facilities. Separators can remove most of the produced water from the flow stream, but heated separators or dehydration units are needed to extract the remaining water. Filters may be required to remove coal fines produced with the water to keep valves and equipment functioning properly. If scale-forming minerals are present in the water, chemical treatment may be needed to protect steel tubulars and surface equipment. If the water is to be disposed of off site, trucks or additional pipelines will be required for water transport. If water-disposal wells are used, injection wellhead assemblies and flow control equipment will be needed.

Produced coal gas rarely contains any H2S but may contain other impurities. For example, produced gas from the Oak Grove field in the Black Warrior basin contains 3.4% N2, while gas from the Piceance basin contains 6.4% CO2.[2] If these concentrations are more than pipeline specifications, the impurity levels will have to be reduced with amine scrubbing, molecular sieve dehydration/treatment, and/or cryogenic processing.

After the produced water is separated from the gas stream and the impurities in the gas have been removed, the coal gas is piped to a compressor. This compressor may be installed at the wellsite if the produced gas volume is sufficient, or centralized compression can be used to handle several wells and reduce costs. The volume of gas being compressed will dictate the ultimate size of the compression unit. The amount of compression required will vary depending on trunk- or transmission-line specifications. Some pipeline companies will accept low-pressure gas in the 50- to 150-psi range, while others require compression of up to 900 psi. After the gas is compressed to a sufficient line pressure, it typically requires a final dehydration before delivery.

Economic and Commercial Considerations

Compared With Conventional Gas Projects

The commercial success of any gas project depends on a number of critical factors including gas production rates, capital requirements, operating costs, gas markets, and economies of scale.[31] In conventional gas projects, gas rates are known from well tests before development, and capital costs for water processing and disposal typically are deferred until later in reservoir life. High-value gas contracts can be established at project startup with reasonable certainty that a specified plateau rate can be maintained for many years.

In contrast, CBM reservoirs initially produce little or no gas and require a large initial capital commitment for well drilling, stimulation, and water handling. Because it may be several years before commercial gas rates are achieved, if at all, it can be difficult to obtain long-term gas contracts or financing. As a result, CBM projects require more work to fully quantify and manage the risks involved. Technical risk can be reduced through reservoir data analysis, pilot projects, and staged reservoir development. Commercial risks can be reduced by the use of decision analysis, fiscal incentives, and creative project financing.

Assessing Economic Viability

Appraising and developing CBM resources require a series of decisions and associated investments over an extended period. These projects are ideal candidates for applying decision analysis or real-option evaluation methods to plan and guide the process.[45][46][47] Both methods can be used to create a decision pathway for evaluating a prospect and characterizing its value at each decision point. As part of the decision analysis process, profitability measures including net present value, internal rate of return, investment efficiency, and payout should be calculated.[48][49] Net present value, which is determined by discounted cash flow analysis, is the most appropriate method to assess the value returned by a CBM project. Investment efficiency is commonly used as a secondary ranking tool to allocate capital among projects in a capital-constrained environment.[49] In CBM projects, the use of payout as a financial performance indicator is generally misleading because of the nature of the cash flow streams; consequently, it should not be used as a primary decision criterion.[2]

Fiscal Incentives

A variety of tax exemptions, tax deductions, tax credits, capital assistance programs, and price subsidies have been developed to encourage CBM development and coal-mine methane recovery projects.[50][51][52] The U.S. CBM industry was brought to maturity by the Federal Sec. 29 tax credit, which was designed to promote the development of unconventional fuels. Fig. 6.4 shows that although the subsidy expired at the end of 1992, drilling and completion activity continued, resulting in nearly 6,000 CBM wells by 1994 and substantially increased gas production.

Other countries have developed similar incentives.[50] Poland provided a 10-year corporate tax exemption through the late 1990s to encourage oil, gas, and coal-mine methane prospecting. China passed a law in 1998 exempting CBM producers from royalties and land occupation fees for production of up to 70 Bscf annually. Some countries provide tax deductions to CBM projects because they are considered to provide a clean alternative to burning coal or oil.

International Issues in CBM Development Projects

While the U.S. domestic CBM industry developed and matured from 1975 to 2000, international CBM development has languished because of a variety of technical and commercial issues. While many of the commercial issues are common to both conventional and unconventional gas development, there are a number of issues specific to CBM development.

Regulatory and Payment Issues Because the international CBM industry is relatively immature, there are numerous hurdles in negotiating and implementing production-sharing contracts (PSCs) and technical service agreements.[53] These hurdles are less daunting in more-developed countries, which tend to have efficient legal and regulatory systems that provide protection and legal recourse. In contrast, developing countries and transitional economies tend to have less-dependable, incomplete, or dysfunctional systems, creating numerous problems.

In some countries, there is overlap and rivalry between various licensing and regulatory agencies, creating considerable confusion. In some cases, provincial governments have signed contracts with foreign companies to develop a CBM project before national laws were established defining jurisdiction. When national laws were enacted, these took precedence over provincial laws, negating the ownership rights of the foreign companies without eliminating their work commitments. These cases show that it is imperative for a company to understand which government agencies have legal authority to negotiate and regulate agreements.

By their nature, CBM resources tend to be located onshore and generally in land-locked areas. This is not a serious problem in developed, free-market economies with deregulated natural gas markets. However, in developing countries, the operating firm may be faced with selling gas into a limited domestic market and may receive payments in a currency that is not fully convertible. Under these circumstances, a foreign firm should consider creative payment alternatives such as trading gas for crude-oil equivalent for export sales or using local currency for operations but taking net profits in a convertible currency for repatriation. Foreign firms also should maintain expertise in project financing and risk hedging for these ventures.[54][55][56][57]

Production-Sharing Contracts Most international CBM PSCs evolved from petroleum PSCs.[53] In general, CBM PSCs contain commonly accepted principles and requirements with regard to royalties, severance taxes, and income taxes. Some contracts require an additional profit split (X-factor) with the government after payment of all expenses, royalties, fees, and taxes. Additionally, some PSCs limit the maximum annual rate of return that a foreign enterprise can earn on gas production. In essentially all PSCs, the foreign company takes on the majority of, if not all, financial risk during exploration and appraisal. Many countries limit the ownership share of production that the foreign company can hold, ensuring that the company remains a minority owner. Most contracts in developing countries also require that operatorship revert to a national company or government-owned enterprise at a specified future date.

Many PSCs also contain performance requirements that the foreign operator must meet. These may require mandatory training of nationals and/or a fixed percentage of jobs reserved exclusively for national employees. Some contracts have local content clauses in which a fixed percentage of materials, labor, and services must be provided by national sources rather than obtained through global markets. PSCs also may contain back-in clauses, which allow a domestic company to take an ownership interest in a CBM reservoir after it is demonstrated to be commercial. Most PSCs in developing countries do not provide specific terms regarding pricing and marketing of produced gas. The contracts contain vague language and assurances that the operator has the freedom to market produced gas in domestic natural gas markets, which, in most developing countries, are fragile, fragmented, or nonexistent. This lack of clarity generally leads to lengthy gas sales negotiations once commerciality is declared and extends the time frame before the gas reserves can be monetized.

Access to Gas Markets In the U.S., development of the CBM industry was facilitated by access to a fully integrated gas pipeline system into which early low-volume gas production could be sold and the existence of deregulated natural gas markets to purchase the available gas. Other countries with fully developed market economies (Canada, Australia, and western European countries) also possess highly developed gas pipeline systems and liberalized (if not fully deregulated) natural gas markets. Some economically developed countries have not liberalized their natural gas markets (Japan, Korea) as a matter of national energy policy or national security priorities.[58][59]

Developing countries typically do not have an extensive pipeline infrastructure to transport gas or a spot market to purchase produced gas. In addition, many countries will not allow foreign firms to invest in infrastructure projects, thus limiting their ability to transport produced gas to a domestic marketplace. Operators usually are forced to flare produced gas from early appraisal and pilot wells, although some of this gas may be used as lease fuel. As reserves are being proved up, long-term sales contracts can be pursued with domestic purchasers. Potential market segments for natural gas include (given in order of value to the supplier) power generation, chemical and industrial feedstock, compressed natural gas for vehicles, town gas for residential and commercial heating, and feedstock for manufacturing fertilizer.

Access to Operational Support Services Growth of the CBM industry in the U.S. relied heavily on technologies and operational practices developed by a competitive oil and gas service industry. Outside the U.S., these services generally are concentrated in basins containing large conventional oil and gas fields. Because many CBM projects are in frontier areas, there may be no locally available field services or materials, resulting in high mobilization costs. Alternatively, oilfield services may be provided by a single state-owned enterprise, making it difficult to negotiate favorable prices and performance guarantees. In some cases, there may be little familiarity with standard CBM operational practices, resulting in learning through trial-and-error. Maintaining high-quality, consistent services in this environment is generally quite challenging.

Environmental Considerations Most developing nations, including China, the former Soviet Union, and eastern European countries, are heavily dependent on coal combustion for energy. In these countries, converting from coal to natural gas will result in significant environmental benefits from reductions in greenhouse gases, coal-mine methane emissions, and air pollutants including NOx, SOx, and particulate matter. CBM can be a viable substitute for coal in many of these countries and has the added benefit of improving mine safety by producing the gas before mining the coal seams.

Over the past decade, several international conferences have focused on stabilizing greenhouse gas concentrations in the atmosphere, and many countries have signed documents committing themselves to this goal.[60] Methods to achieve stabilized levels are still under discussion but may include emissions taxes, external offsets, and tradable permits.[50][61][62] Tradable permits appear to be the most popular of these alternatives and would require that participating countries be issued permits to emit carbon dioxide at a specified level. To exceed these levels, a given country would have to purchase or lease permits from other countries with excess capacity.[50] Environmental programs such as these could substantially increase the value of CBM projects that reduce coal combustion, reduce mine emissions, or sequester CO2 through injection of this gas into coal reservoirs. Such a program could result in additional incentives for international energy companies to participate in CBM projects. This concept is likely to grow in importance as global concerns over environmentally sustainable economic activity continue to grow.[63][64]

Project Financing and International Capital Resources

Obtaining capital to fund CBM projects can be a substantial hurdle. Historically, oil and gas companies have funded development projects from operating cash flow when sufficient cash is available and the project risk is low. However, CBM projects possess a number of financing, regulatory, and risk components that make project financing and international capital resources attractive alternatives.[56][65]

Project Financing There are five principal features of a CBM project funded and structured with project financing. First, the project is established as a separate company and operates under a concession obtained from the host country government. This structure protects the assets of the equity investors, allows creditors to evaluate the risks of a singular project, and guarantees that cash flows from the project can be recognized and used to service project debt.

Second, the project manager, or sponsor, provides a major portion of the project equity, thus linking the provision of finance to project management throughout its life. Third, the project entity enters into comprehensive, long-term contracts with suppliers and customers. Take-or-pay contracts typically are used to guarantee revenues, and long-term supplier contracts are established to control costs. The resulting predictability of net cash inflows to long-term contracts eliminates much of the project's business risk, which allows heavy debt financing without creating financial distress.

Fourth, the project company operates with a high debt-to-equity ratio, and lenders have only limited recourse to the equity holders or to the government in the event of default. Fifth, the project contains a partnership and management structure that aligns the appropriate expertise of a partner with appropriate risks and rewards. For example, the lead equity partner in the project must have expertise in managing finance, currency, and political risk, while the operator needs to hold an equity interest in the project to ensure its performance.

International Capital Resources Domestic capital can be very difficult to obtain for project financing in developing nations and economies in transition. Reasons for this include the limited information available to capital owners regarding the scope and potential of available projects, the large scale of investment needed to finance a project, and the perception that the political and commercial risks are too great. Because of these issues, resource development projects in these countries commonly are funded through broad joint ventures between private sector corporations, governmental units, and international lending institutions. These institutions provide access to capital through grants, low-interest loans, loan guarantees, and venture capital.[51][56][66]

Mulilateral institutions, such as the World Bank, are funded by contributions from member countries.[66] The World Bank finances numerous environmental and energy infrastructure projects in developing countries. Regional multilateral banks play a role similar to that of the World Bank. Coalbed and coal-mine methane projects have been funded in China by the Asian Development Bank and the Asia Pacific Economic Cooperation. The European Commission has funded projects in Poland. The European Bank for Reconstruction and Development and the African Development Bank could fund projects in their client countries. Another source of assistance is the United Nations Development Program, which manages technical assistance projects under the Global Environmental Facility. This entity provides resources needed to demonstrate technologies, develop training programs, and provide technical assistance in creating public policy in countries focused on encouraging environmentally favorable projects and practices.

Most industrialized nations also provide assistance to developing countries through bilateral international aid and energy, environmental, and trade agencies, which may include coalbed or coalmine methane projects.[66] In the U.S., the U.S. Agency for Intl. Development supports efforts to achieve sustainable economic and social progress in developing countries and economies in transition. Aid also may be available to help nations meet obligations to limit greenhouse gas emissions through the U.N. Initiative on Joint Implementation, which is a pilot program to execute an article of the U.N. Framework Convention on Climate Change. Various countries also support trade agencies to provide financing for companies and projects. U.S. government trade agencies include the Overseas Private Investment Corp., the Trade and Development Agency, the Export-Import Bank, and the Small Business Admin.

Unconventional private financing of projects also may be available through a number of venture capital firms.[65][66] These companies invest in projects with moderate risk balanced by high potential returns. Some firms specialize in oil and gas investments, alternative energy projects, or have a regional focus. Significant growth has occurred recently in financing projects that lead to reductions in greenhouse gas emissions. Electric utilities, other major energy producers, and consumers have been driving this market. A few companies are specializing in brokering greenhouse gas emissions credits, and this market has grown substantially since the conclusion of the Kyoto accords in 1997.

Case Studies

San Juan Basin

The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Fig. 6.5), 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.[67]

Development History 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.

Coal Characteristics 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.[67] 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 (Fig. 6.5) 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,[8] 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+.[68] 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.[9] 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.[69] The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area. The nonfairway coals were buried less deeply than those in the fairway, resulting in lower-rank coals (high-volatile B bituminous) and gas contents of less than 200 scf/ton. The nonfairway coals also have higher ash contents, resulting in poorer cleating and permeabilities of generally less than 10 md.

Between the fairway and nonfairway areas of the basin is a transition zone one to two miles wide[70] that coincides with a slight change in dip, which is referred to as a structural hingeline.[71] Along this hingeline, a combination of faulting, stratigraphic thinning, and diminished coal quality appear to separate the higher-pressure, better-quality coals in the prolific fairway area from the rest of the basin.[72]

Drilling and Completions During the late 1970s and early 1980s, wells in the San Juan basin were completed as cased holes and hydraulically fractured. Skins were often high in these completions because of formation damage from drilling, cementing, or fracturing fluids. In early 1986, Meridian Oil began a pilot project in the San Juan 30–6 area that pioneered the openhole-cavity completion technique.[69] Resulting gas rates often exceeded 1 MMscf/D per well with some wells achieving 10 MMscf/D. It is estimated that 80% of the completions in the fairway area are cavity completions and that their average rate is four times that of hydraulically fractured wells.[72]

Analysis of the data from several hundred San Juan basin wells shows that the most successful cavity completions are those in coal seams with minimum in-situ stress values of 2,080 psia, ash contents of less than 70%, ranks of high-volatile A bituminous or greater, depths of 2,000 to 3,600 ft, and bottomhole pressures of at least 1,370 psia.[73] These characteristics are common in the fairway area, but, in areas where coal properties are less favorable, cavity completions have been largely unsuccessful.

In the nonfairway area, gas rates are much lower, but wells can still be economically drilled and produced. Initial gas rates are highly variable and range from less than 100 to more than 700 Mscf/D.[49] The biggest factor in obtaining economic gas rates appears to be permeability, with some wells producing more than 300 Mscf/D for more than 5 years when permeability exceeds 10 md.

Various completions are used in the nonfairway areas including cased-hole hydraulic fracturing, acid breakdowns, or unstimulated techniques. Initially, these completions are likely to result in more formation damage than cavity completions. However, matrix shrinkage and a decrease in horizontal stresses with production result in a higher absolute permeability, which offsets this initial damage.[74] Maintaining very low flowing bottomhole pressures is critical in nonfairway wells because of low reservoir pressures.[69] Gas compression is essential for economic success, often because pipeline pressures are greater than reservoir pressures.

Well Performance The San Juan basin produces more than 2.5 Bscf/D from more than 3,500 wells. Good wells in the fairway area typically reach a peak rate of 6,000 Mscf/D with an ultimate recovery of 15 Bscf. Permeabilities in these wells exceed 10 md, and the well spacing is typically 320 acres. Abandonment pressures in the fairway are projected to be less than 100 psia, resulting in recovery factors of greater than 70%. In contrast, wells in the nonfairway areas produce at peak rates of only a few hundred Mscf/D. Permeabilities are typically 1 to 5 md, which requires more closely spaced wells and results in lower recovery factors because of higher abandonment pressures.

An average well in the San Juan basin produces at an initial rate of 100 to 400 Mscf/D and 40 to 400 BWPD.[9] Production typically doubles within 2 to 4 years in fairway wells, while flat initial production profiles are more characteristic of nonfairway wells. Decline rates are highly variable, ranging from less than 5% to more than 20% per year. Most fairway wells experienced a "negative decline" for the first several years as gas rates increased, making it difficult to predict peak rates and decline rates thereafter.

Black Warrior Basin

The Black Warrior basin is located in Alabama and Mississippi in the southeastern U.S. (Fig. 6.6). The basin contains approximately 20 Tscf of gas resources and 2,700 producing wells in 18,000 sq miles.

Development History Drilling activity began in the 1970s when boreholes were drilled into mining faces and the collapsed roofs of active coal mines to degas them.[75] In 1981, the first pipeline sale of coalbed gas was made from 21 wells associated with the Oak Grove mine. At approximately the same time, companies began drilling coal gas wells not associated with mining operations. U.S. federal tax credits and a reduced state severance tax encouraged this development throughout the 1980s. Development was assisted by an infrastructure of service companies and an accessible pipeline grid already in place.

Coal Characteristics Coal gas in the Black Warrior basin is produced from thin, multiple seams ranging from 1 to 8 ft thick with a typical aggregate thickness of 15 to 25 ft. The seams are distributed over long intervals of 400 to 1,400 ft and produce from depths of 400 to 4,500 ft. The coals are part of the Lower Pennsylvanian Pottsville formation and consist of four groups: Cobb, Pratt, Mary Lee, and Black Creek. The coal rank is high-volatile A to medium-volatile bituminous. The seams generally have a low ash and low sulfur content.

Gas contents vary widely from 250 to 650 scf/ton, and it is quite common for the coals to be undersaturated with gas.[76] The average methane content is approximately 96% with small amounts of carbon dioxide and nitrogen. A few wells in the southern part of the basin have produced small amounts of oil along with the coal gas. Permeabilities range from less than 1 to 25 md.

The highly variable nature of gas productivity in the Black Warrior coals is influenced greatly by depositional systems and structural geology. The depositional system includes channel and sheet sandstones that periodically interrupted peat deposition, truncating coal seams laterally and compartmentalizing the coal reservoirs. Structural features include faults that create individual compartments, folds that contain fracture systems that enhance permeability along fold axes, and areas of high reservoir stress resulting in lower cleat permeabilities. In some areas, a positive correlation exists between well productivity and the location of wells within mapped fracture systems.[17] In other areas, higher permeabilities can be correlated to lower in-situ stress values.[19]

Drilling and Completions Nearly all wells are cased, perforated, and fracture stimulated to achieve economic production rates. Water fracs are useful in the shallow, higher-permeability coals (Pratt group) in which the objective is to connect the well effectively to the fracture system.[77] For the deeper, lower-permeability coals, more-viscous fluids (cross-linked gels and nitrogen foam) with greater transport capacity are needed. Typically, 90,000 to 180,000 gal of fluid and 125,000 to 150,000 lbm of sand are used. It is critical to understand the stress profile, rock properties, and preferred fracture growth directions to design and execute fracture stimulation properly in these coal seams.

Nearly all coal gas wells in the Black Warrior basin are produced with rod pumps. Gas compressor stations typically handle gas from 30 to 70 wells, compressing the gas to a pipeline pressure of 400 to 700 psia. Approximately 95% of the produced water is discharged into streams. Operators pump the water into storage ponds where it is treated before release.

Well Performance A histogram of gas production data from 1,140 vertical CBM wells in Alabama form a log-normal distribution.[78] The data show that most wells reach their peak production within 4 years. The wells achieve a mean peak gas rate of 107 Mscf/D with values ranging from 35 to 324 Mscf/D within one standard deviation of the mean. These values attest to the wide range of CBM well performance and the difficulty in predicting rates and reserves for possible new well locations.

One of the key producing properties in the Black Warrior basin is the Cedar Cove field (Fig. 6.6). It contains 517 producing wells and produces approximately 20% of the total coal gas from the basin.[79] The average well in this field is drilled on an 80-acre spacing and reaches a peak gas rate of 150 Mscf/D in 600 days. The well remains at this rate for approximately 4.5 years before declining. Approximately one-third of the wells peak at less than 100 Mscf/D, one-third peak in the 100 to 300 Mscf/D range, and the other one-third peak at more than 300 Mscf/D. Projected average gas reserves are 820 MMscf per well over a 30-year project life.

Drunkard's Wash(Uinta Basin)

The Drunkard's Wash unit is located along the western edge of the Uinta basin in Utah (Fig. 6.7). Drunkard's Wash is the most productive of several CBM leases discovered in a coal trend 6 to 10 miles wide and 20 to 60 miles long.[7]

Development History In 1988, Texaco was the first to test the potential of this area with two cored wells. The cores showed high gas contents, and the wells produced at rates of up to 230 Mscf/D and 500 BWPD.[80] Because of a shift to international exploration opportunities, Texaco farmed out 92,000 acres of Drunkard's Wash to River Gas Corp. in 1991.

River Gas cored a well on this acreage followed by a producer that tested more than 2 MMscf/D.[81] By mid-1992, three producers were connected to an existing gas pipeline. By the end of 1992, 10 additional development wells were drilled and completed.[82] Subsequent development increased the number of wells to more than 400. The expansion strategy consisted of stepping out from the central group of producing wells with core holes to confirm the existence of good reservoir properties and then expanding the development outward.

Coal Characteristics The Drunkard's Wash unit produces gas from coals associated with the Cretaceous Ferron Sandstone member of the Mancos shale. The sandstone and associated coals are part of a fluvially dominated delta. The average coal thickness is 24 ft, and the coals occur in 3 to 6 seams at depths of 1,200 to 3,400 ft.[80] Although some coal seams split and coalesce over short distances, many are continuous and correlatable from well to well. Tonsteins are common and serve as excellent time-stratigraphic markers for geologic correlation.

The coals dip to the west at approximately 2 degrees, or 200 ft/mile. Superimposed on this dip is a southwest-plunging nose near the center of the unit. Reverse faults with up to 150 ft of throw are aligned parallel to this nose.[80] Repeated sections are common where wells intersect faults, and production data suggest that these faults may compartmentalize the coal seams. Well testing and production indicate excellent permeabilities of 5 to 20 md.[80] Because of artesian conditions, the coal seams are slightly overpressured relative to a freshwater gradient of 0.43 psi/ft.[7]

The coals produce dry gas with methane concentrations of 95.8 to 98.3%.[80] CO2 concentrations range from 0.7 to 2.5%, and N2 concentrations range from 0.42 to 0.82%. The gas specific gravity is 0.57, and the dry Btu content is 987 to 1,000 Btu/ft3. The average in-situ gas content is 425 scf/ton, and the average ash content is 14.6% based on a 1.75-g/cm3 density cutoff. This average gas content value is considered high given that the rank of the coal is high-volatile B bituminous. Isotopic studies suggest that the coals have been enriched by thermogenic gas that has migrated updip from higher-rank coals buried deeper in the basin and late-stage biogenic gas.[7] Interbedded sandstone layers are thought to contribute 10 to 15% of the gas production. Interbedded carbonaceous shales, which have bulk densities of greater than 1.75 g/cm3 and contain significant quantities of methane, are also likely contributors of gas to the wellbores.[83]

Drilling and Completions Wells are air drilled to minimize formation damage with 7.875-in.-diameter bits.[80] Approximately 5% of the wells are cored with a diamond-bit, wireline-retrievable tool that cuts a 2.5-in. core. This system minimizes lost gas and results in core recoveries of 80% or greater. Wells are logged with density/neutron, gamma ray, caliper, and resistivity tools. High-resolution processing of the bulk density logs increases vertical resolution to 0.5 ft, helping to identify the coalbeds.

Wells are completed with cemented 5.5-in.-diameter casing that is perforated and hydraulically fractured in two to three separate treatments. One well was stimulated with a cavity-completion technique, but the results were less than expected; therefore, this technique has not been subsequently used.[82] A typical fracture treatment consists of 56,000 lbm of 12/20 sand and 27,000 lbm of 20/40 sand.[80] The sand is carried in approximately 40,000 gal of water containing a 30-lbm/1,000 gal cross-linked gel. Significant variations in fracture gradient have been observed with values ranging from 0.6 to 1.4 psi/ft.[84] For each well, the drilling and equipment costs are approximately U.S. $200,000, and the fracture-stimulation cost is approximately U.S. $100,000.

In most cases, wells are completed with tubing and rods and produced with a pumping unit.[80] Several high-volume wells are produced with PCPs. In approximately half the wells, gas is produced up the annulus between the tubing and casing while water is produced through the tubing. In the other wells, water and gas are produced up the tubing and separated at the surface. After producing for 6 months to a year, some of the pumping wells produced at high enough gas rates that the pumps were removed. Downhole problems include scaling, coal-fines migration, and gel damage from the fracture stimulation. In 1997, a series of cleanout and flush jobs was conducted to correct these problems, and gas production increased by approximately 20% per well.

Well Performance The Drunkard's Wash unit includes approximately 350 wells that currently produce an average of 616 Mscf/D and 175 BWPD per well.[83] Cumulative field production exceeds 210 Bscf with estimated reserves for individual wells ranging from 1.5 to 4 Bscf. This translates into a minimum field recovery of 1 to 2 Tscf.[7] The current well spacing of 160 acres appears to be sufficient on the basis of a pressure monitor well showing a significant reduction in interwell pressure.[80]

Wells typically reach their peak gas rate within 3 to 5 years and remain at this peak for a year or so. Afterwards, the wells decline at approximately 10% per year. In February 1995, after approximately 2 years of production, the wells were shut in for a month to install gas compression. When the wells were returned to production, it took 5 months to return to preshut-in gas rates. This emphasizes the need for constant production in CBM wells to dewater the reservoir and desorb the gas progressively.

A central gas compressor facility increases the gas pressure from 10 psia to more than 500 psia, reducing wellhead pressure and maximizing gas rates.[80] Produced water is injected into seven water-disposal wells in the Jurassic Navajo sandstone at 5,200 to 6,000 ft or is pumped into an 11-acre evaporation pond.[80] Water-disposal costs are approximately U.S. $0.07/bbl.

Powder River Basin

The Powder River basin of Wyoming (Fig. 6.8) has been the recent focus of intense development activity targeting thick, shallow, subbituminous coals with low gas content. Operators drilled more than 4,200 wells in 2001, and estimates call for up to 60,000 new wells by 2011. With more than 1 trillion tons of coal available and gas resources exceeding 7 Tscf,[85] there are plenty of remaining CBM opportunities.

CBM development in the Powder River basin has been slow because of uncertainties regarding coal reservoir characteristics and concerns that CBM wells could never be produced economically.[86] Early drilling was spurred by U.S. federal tax credits in the late 1980s and early 90s. The first wells were either drilled into deep coal seams because of their higher gas content or drilled into coal seams contained in structural highs (compactional folds) to produce free gas from the cleat system and minimize water production. One of the first commercial projects was in the Rawhide Butte area north of Gillette, Wyoming (Fig. 6.8), where approximately 90 wells were drilled and produced to remove coal gas adjacent to several large surface mines.[87]

From 1992 to 1994, Rawhide Butte was followed by development projects in the Marquiss and Macsy areas, south of Gillette, which demonstrated economic gas rates and that the coals could be dewatered. These projects pioneered several technological advances in the basin including the use of variable-speed pumps, hydraulic fracturing, and openhole completions through the coal intervals. Over the last few years, exploration has expanded from the Gillette area to the west side of the basin and northward to the Wyoming/Montana state line. Gas pipeline infrastructure is expanding with several projects underway to increase capacity. The average finding cost has been approximately U.S. $0.25/Mscf, which compares favorably with conventional onshore costs ranging from U.S. $0.15 to $0.50/Mscf.[88]

Coal Characteristics The producing coals of the Powder River basin are contained within the Tongue River member of the Paleocene Fort Union formation. The coals occur in 2 to 24 seams that individually range up to 100 ft thick with a total coal thickness of up to 300 ft.[85] The thickest seams can be correlated regionally, whereas the thinner seams merge and split locally. Typical productive depths are 250 to 1,000 ft. Compared with other U.S. basins, Powder River basin coals are immature with low gas contents and high permeabilities. Gas contents vary from 23 to 70 scf/ton,[85] and permeabilities range from 10 md to more than a Darcy. Well performance in some parts of the basin indicates that the gas content must be considerably higher than the sorbed gas content.[88] Potential sources of this additional gas include free gas, dissolved gas, gas that has migrated into the coals from other sources, or gas produced from adjacent shales.

The produced coal gas composition is approximately 90% methane, 8% carbon dioxide, and 2% nitrogen. The methane is isotopically light, indicating a biogenic origin. The coals have low ash (5%), low sulfur (0.35%), and high moisture (25 to 30%) content. Coal macerals consist of 70 to 90% vitrinite, suggesting a high capacity for gas storage. Limited comparisons of coal isotherms to gas content values indicate that the coals are saturated with gas at depth. The coals are immature, ranging from lignite to subbituminous in rank as indicated by vitrinite reflectance values of 0.28 to 0.45%. Their immaturity also results in large cleat spacings of 3 to 5 in. Pressure surveys indicate that the coals are underpressured relative to a freshwater gradient, with pressure gradients ranging from 0.26 to 0.29 psi/ft.[16]

Drilling and Completions Wells typically are completed in a single coal seam, with a twin well used if multiple seams are present. The minimum completion thickness is approximately 30 ft of coal with well depths ranging from 300 to 1,500 ft. A 9.625-in.-diameter hole is drilled into the top of the coal, and a 7-in.-diameter casing is run and cemented. A 6.25-in.-diameter pilot hole is then drilled through the target coal seam with air, air/mist, or water to minimize formation damage. This hole is underreamed to 10 to 12 in. and cleaned out.[89] Wells are placed on production with a completion rig to run tubing and an ESP. The drilling and completion process takes just a few days.

Water is produced up the tubing, and gas is produced up the tubing/casing annulus at bottomhole pressures of 15 to 250 psia. Backpressure helps keep the cleats open and the permeability high. Production typically continues for approximately 2 months to clean up the near-wellbore region before hydraulic fracturing. The purpose of the frac job is to connect the wellbore effectively to the coal cleat system. A typical job consists of pumping 500 bbl of water at 30 to 40 bbl/min at a surface injection pressure of 130 psia.[89] Drilling, completion, and facility costs range from U.S. $65,000 to $95,000[85] per well.

Well Performance Initial gas rates range from less than 100 Mscf/D to more than 1 MMscf/D with 0 to 700 BWPD. Wells ramp up over several years to peak rates of approximately 150 Mscf/D and 50 BWPD. The average well life is projected to be 12 to 15 years with an average estimated ultimate recovery of 300 MMscf per well at an 80-acre well spacing.[85] In 1998, the 625 active wells each produced an average of 140 Mscf/D and 325 BWPD[88] with a cumulative production of approximately 28 Bscf.

Interference between wells is common, especially at well spacings of 40 acres or less, resulting in faster dewatering and quicker gas response. This response is particularly dramatic in wells adjacent to mining areas in which groundwater levels are suppressed by up to tens of meters within a few kilometers of the mines. Produced water is very fresh and can be discharged into streams and livestock ponds, reducing disposal costs and improving project economics. As of 1999, approximately 10,000 acre-ft of water was being produced annually from CBM wells in the basin.

Hedong Coal Basin

The People's Republic of China contains an estimated 1,567 billion tons of coal,[4] which is the third-largest coal resource of any country in the world. By the early 1990s, it was recognized that these coals contain CBM resources estimated at 500 to 1,000 Tscf of gas in place.[90] To test the potential of these resources, several CBM projects have been initiated. One of these projects is in the Hedong coal basin, which is located along the eastern flank of the Ordos basin approximately 400 miles southwest of Beijing (Fig. 6.9).

Development History Coal is mined extensively from a north/south trending outcrop belt along the eastern edge of the Hedong coal basin. Downdip from the mines, several hundred core holes were drilled in the 1950s and 1960s demonstrating the existence of thick, gassy coals over a very large area. Analysis of this data indicates that within the Hedong coal basin, coal gas in place could exceed 10 Tscf.

In 1992, Enron signed an agreement with the Chinese government to assess the CBM potential of the Hedong coal basin. In early 1993, Enron drilled two core holes, which showed favorable coal thickness and gas content. That same year, the Hedong Prospect was chosen as the best CBM prospect in China on the basis of analysis of eight prospective areas.[91] This led to the establishment of the Liulin pilot project, a 3-year cooperative venture between the Chinese government and the United Nations, to demonstrate the CBM potential of the Hedong area. This project consisted of a seven-well pilot that averaged 35 to 106 Mscf/D per well with a peak of 247 Mscf/D in one well.[25]

Coinciding with the Liulin pilot, Enron drilled seven appraisal wells from late 1993 to 1995 to evaluate the Hedong prospect. Several of these were completed, and some produced at water rates of 315 to 1,195 BWPD, indicating good reservoir permeability. ARCO purchased Enron's interest in mid-1997 and signed PSCs with China United Coalbed Methane in mid-1998 to appraise a 2,000 sq mile area. Texaco joined the project shortly thereafter, and by mid-2001, 26 wells had been drilled including a five-well pilot and a nine-well pilot. The purpose of the pilots is to determine if the coals can be dewatered, if increasing gas rates will accompany this dewatering, and to determine how to optimize the completion and lifting techniques. The biggest challenges facing the project are the demonstration of commercial gas rates, the confirmation of sufficient reserves for commercial development, and access to potentially large gas markets located hundreds of kilometers away.

Coal Characteristics Coal seams in the Hedong coal basin are part of the Upper Carboniferous Taiyuan and Lower Permian Shanxi formations. Each well contains up to 10 coal seams distributed over an interval 490 to 660 ft thick.[26] Cumulative coal thickness varies from approximately 25 to 65 ft, with individual seams ranging up to approximately 16 ft in thickness. The coal seams dip gently westward at 5 to 10 degrees with a superimposed anticlinal nose and graben suggesting a tensional stress regime that may contribute to higher permeabilities. The coals extend from the outcrop to the deepest part of the Ordos basin, but only those coals at depths of 1,000 to 4,000 ft have been targeted for their CBM potential. Drilling in the area indicates that seams shallower than approximately 1,000 ft do not have high enough pressures to retain commercial quantities of gas, while seams deeper than approximately 4,000 ft do not have sufficient permeabilities to produce at commercial rates.

Two wells have been cored continuously from above the shallowest coal seam to below the deepest seam. The core descriptions show that the Taiyuan formation consists of thick (0.1 to 4.5 m), vitrinite-rich (45 to 57%), and high-sulfur (1.2 to 4.8%) coals. These coals are interbedded with fractured carbonates, but well tests indicate that the carbonate permeabilities are low. Coals of the overlying Shanxi formation are thinner (0.1 to 1.75 m), contain less vitrinite (31 to 55%), and have a lower sulfur content (0.4 to 0.6%). The Shanxi coals are thinner because of the erosive effect of fluvial and distributary channels. These coals contain less vitrinite and more ash because of the addition of material deposited from channel floodwaters. The sulfur content is lower because of the greater distance from the sea. Ash content ranges from 5 to 25% and is dominated by dispersed and layered clays. Petrographic analysis shows that the inertinite content of the Hedong coals is relatively high (30 to 60%) and cleat spacing effectively doubles as the inertinite content doubles, implying lower permeabilities in more inertinite-rich coals.

The coal rank for the Hedong area increases southward from high-volatile A bituminous to semianthracite coal. Gas contents range from less than 150 to more than 500 scf/ton, reflecting variations in coal rank, composition, depth, and degree of saturation. Residual gas is low, ranging from approximately 12.8 to 32.0 scf/ton. Desorption of the coal core samples shows that the gas composition is approximately 96% methane, 3% nitrogen, and 1% carbon dioxide. Comparisons of the desorbed gas volumes with isotherms indicate that the coals are saturated to significantly undersaturated with gas. The undersaturation may result from the uplift and erosion of overburden strata, followed by reburial of the coals under Quaternary and recent loess.

Pilot and appraisal wells drilled in the central part of the Hedong coal basin are normally pressured, but three downdip wells show a conspicuous departure from this trend. SG-1 and SG-2 are overpressured, and SH-2 is underpressured. These observations imply hydraulic connectivity among the central wells and hydraulic isolation from the downdip wells because of reduced permeability, faulting, facies changes, or thinning of the coals. The potentiometric surface for one of thickest coal seams, Seam 8, is above ground level along the Qiushui River, resulting in artesian flow. Mining core holes along the river report up to several hundred barrels per day of water production and gas burning with a flame up to 1 m in height. Based on this strong upward flow potential and a coal thickness of 65 ft, this area was selected for the first five-well pilot.

Drillstem tests and injection/falloffs have been conducted in nearly every well and show a very wide range of calculated permeability values. For example, in the five closely spaced San Jiao pilot wells, permeabilities for the thickest coal seam (Seam 8) range from 7 to 450 md. In addition, pressure data obtained after several months of production show a greater pressure decline in those wells aligned parallel to the face cleats (east/west direction) than perpendicular to them (north/south direction). This confirms the existence of directional permeability in the face cleat direction, creating elliptically shaped drainage areas and causing interference between wells.

Drilling and Completions The Hedong wells are drilled with low-fluid-loss, water-based bentonite muds. Coring is conducted with wireline-retrievable equipment resulting in trip times of less than 20 minutes, which minimizes the lost-gas volumes. Wells are logged with a combination of gamma ray, spontaneous potential, resistivity, neutron, and density tools. The casing program typically includes a 9.625-in.-diameter surface casing and a 7-in.-diameter completion string. The coals are perforated selectively from the bottom to the top to conduct injection falloff tests in each seam. Openhole cavity completions were attempted in some of the early wells with mixed results. Some wells failed to cavitate, while in others, the flow of coal could not be stopped as the cavity grew up beyond the casing shoe and caused the well to fail. The coal seams are moderately to highly stressed, with fracture gradients ranging from 0.7 to 1.3 psi/ft.

Depending on the well-test results, the seams are completed in several different ways. In coal seams with permeabilities of less than approximately 10 md, gel-based fluids are used to prop a narrow fracture with a long half-length. These fracs typically include 115,000 lbm of sand, 1,300 bbl of 2% KCl water, and a 40-lbm linear hydroxyethyl cellulose polymer gel followed by an ammonium persulfate breaker. In higher-permeability seams (>10 md), a slickwater (KCl) fracture stimulation is conducted to connect the wellbore effectively with the coals. These jobs typically include 2,390 bbl of 2% KCl fluid and 86,000 lbm of sand. An iridium tracer (Ir192) is commonly used so that a post-frac gamma ray log can be run to discern the fracture height. If the permeability is very high (> 100 md), no fracture stimulation is used.

The cost to drill and case a Hedong well is approximately U.S. $100,000. Fracture stimulations cost approximately U.S. $120,000 per well, which includes two frac stages (one for the upper seams and one for the lower seams). An additional U.S. $30,000 per well is spent for tubing, a flowline, a pump, and a separator. Different types of artificial lift have been used including rod pumps on lower-rate wells and ESPs or PCPs on higher rate wells. Water is produced up the tubing, and gas is produced up the annulus. A small backpressure of 50 to 100 ft of fluid is maintained over the pump. The produced gas is flared, and the produced water is used for irrigation.

Well Performance CBM well performance in the Hedong coal basin has been highly variable. Widely spaced appraisal wells drilled and completed by Enron in the mid-1990s showed performance ranging from virtually no water production to hundreds of barrels of water per day. Four appraisal wells drilled in the southern part of the Hedong prospect during 1997–98 had low well-test permeabilities of < 1 to 6 md, with each well producing approximately 20 Mscf/D and 20 BWPD. In 1999, five wells were completed in the San Jiao pilot at a well spacing of 30 acres. After approximately 18 months of production, rates for these five wells ranged from 25 to 50 Mscf/D and 50 to 900 BWPD, with higher rates corresponding to higher well-test permeabilities. In 2000, a second five-well pilot was established at Qikou. Rates for these wells were similar to those of the San Jiao pilot.

Although the permeabilities in several of the pilot wells were very encouraging, the gas content, gas saturations, and isotherm character of the coals were all less favorable than expected. Most significantly, the average coal seam gas saturations ranged from approximately 37 to 56%. Numerical simulation studies indicate that values below approximately 75% result in gas rates that are an order of magnitude lower than those for fully saturated coal seams. Early gas rates of 50 Mscf/D for the pilot are consistent with significantly undersaturated coals. After 2 years of production and an expansion of the San Jiao pilot from five to nine wells, the pilot wells are still producing gas at similar rates, even though the produced-water volumes and reservoir pressures have declined.

To determine if these producing characteristics are regional in extent, a second five-well pilot has recently been completed to the south of the first pilot in an area where the coal quality appears to be better. Individual wells here have peaked at rates as high as 250 Mscf/D.

Upper Silesian Coal Basin

The Upper Silesian coal basin occupies an area of approximately 2,860 sq miles along the border between Poland and the Czech Republic (Fig. 6.10). Gas resource estimates for the basin vary widely, ranging from 7 to 46 Tscf.[92] The Polish coal industry has collected a significant amount of data from active mines and 150 core holes over the last several decades to evaluate the deep coal mining potential of the area. These data are critical for characterizing coal seam distribution, understanding basic properties of the coals, and formulating a CBM evaluation strategy.

Development History In 1993, Amoco received one of the first CBM concessions in the basin, covering an area of approximately 121,000 acres.[92] As part of the concession agreement, Amoco agreed to drill 15 wells and production test at least eight of them within the first 3 years. The objectives of these wells were to evaluate gas saturations and permeabilities of the coal seams and to identify intervals that could be used for produced-water disposal. In 1997, Texaco was awarded a concession to the west of Amoco's acreage after agreeing to drill eight wells in an 18-month initial exploration phase.[93] With gas saturation and permeability data from previous CBM wells in the area, Texaco sited and drilled a five-well pilot on a 40-acre pattern. This enabled them to evaluate the CBM potential of the area quickly and decide their future activities.

Coal Characteristics Coal seams of the Upper Silesian basin are of Carboniferous age and range from 980 to more than 7,200 ft in depth. The average total coal thickness exceeds 160 ft, with the thickest coal seams ranging up to 80 ft thick.[92] The basin is structurally complex with three major normal faults dividing both the Amoco and Texaco concessions. Throws on these faults range from 500 to more than 3,300 ft. Smaller normal faults, with throws of tens of meters, are very common and compartmentalize the reservoirs into dozens of blocks averaging 4,600 ft across.[93]

On the basis of an analysis of more than 1,640 ft of coal, Amoco's work showed highly variable gas contents and gas saturations.[92] Gas contents from 700 canister samples ranged from nearly 0 to approximately 365 scf/ton. On the basis of 32 isotherms, the saturation state of the coals ranged from 100% saturated in some of the deeper seams to significantly undersaturated. Gas analyses indicated an average composition of 91% methane, 4% C2+, 3% CO2 , and 2% N2 . Thirty well-test permeabilities showed values ranging from less than 0.1 md to more than 50 md.

Texaco's work also showed significant variations in gas content and saturation state.[93] The coals are slightly undersaturated just beneath the Miocene/Carboniferous unconformity and become increasingly undersaturated with depth. This trend reverses at depths of greater than 1,970 ft, where the coal gas contents increase to 160 to 320 scf/ton and the coals become moderately undersaturated (35 to 80% gas saturated). Coal seams in this interval were completed in the five-well pilot. The variations in gas saturation are the result of a complex succession of burial, uplift, degassing, reburial, and resaturation. The residual gas content of coal samples from the pilot's center well averaged 32% of total gas. This is a high value, which is consistent with the low diffusion rates measured by Amoco.

Texaco's work also showed that coal rank increases with depth, ranging from high-volatile B bituminous in shallow coals to low-volatile bituminous in the deepest coals.[93] Coal rank increases much faster below a depth of approximately 3,300 ft, coinciding with the appearance of higher gas contents. This inflection point may be useful for delineating the location of high gas content coals in other parts of the basin. Produced gas from Texaco's pilot wells consisted of approximately 91% methane, 4% ethane and heavier hydrocarbons, 2% nitrogen, and 3% carbon dioxide. Analysis of 25 openhole injection/falloff tests in the five-well pilot area showed absolute permeabilities of approximately 3 md at a depth of 3,600 ft, decreasing to 1.5 md at 4,600 ft.

Drilling and Completions Texaco fulfilled its eight-well commitment in 6 months by drilling three exploration and five pilot wells.[93] Two of the exploration wells were drilled to the west and north of the pilot to assess the CBM potential of these areas. A third exploration well was drilled to assess the water-disposal capacity of Tertiary sandstones and conglomerates. The pilot wells were drilled as straight holes with water-based muds. The pilot's center well was cored continuously through the target interval with wireline-retrievable tools to a depth of 4,950 ft. Core recovery was approximately 95% and trip times averaged less than 15 minutes, minimizing the amount of lost gas. The five pilot wells were each completed in approximately 30 ft of coal at depths from 3,660 to 4,580 ft.

The casing program included 13.375-in.-diameter surface casing to 165 ft, 9.625-in.-diameter intermediate casing to 1,310 ft, and 7-in.-diameter production casing to total depth. Wells were perforated and hydraulically fractured in three stages with 45,000 gal of cross-linked gel and 150,000 lbm of sand proppant per stage. Breakdown pressures varied from 4,500 to 6,000 psia, and injection rates ranged from 25 to 50 bbl/min. The stimulations were highly successful with no screenouts or significant flowback problems. Following the frac jobs, the wells were placed on pump and produced for 6 months.

Well Performance Texaco's five-well pilot attained an early production peak of less than 150 Mscf/D with declining production thereafter.[93] Numerical simulation work indicates that this performance is consistent with relatively low gas contents, moderate undersaturation, and low permeabilities. The relatively steep decline in production suggests a reduction in the effectiveness of the stimulation or completion as the result of plugging, the loss of proppant, or other factors. Alternatively, depressuring the near-wellbore region may have caused swelling of the coal matrix because of gas expansion, reducing the absolute permeability. This can profoundly affect production rates, especially in reservoirs with low initial permeabilities. Because of well performance and simulation work results, Texaco relinquished rights to the Polish concession in late 1998.

Bowen Basin

Australia contains estimated total coal resources of more than 450 billion tons. 5 Most coals are of Permian age with the largest deposits found in the Bowen/Gunnedah/Sydney basin system in eastern Australia. These basins have been the focus of numerous exploration and appraisal projects since the mid-1970s. The level of activity has increased significantly in the past few years, resulting in modest commercial production from three fields in the Bowen and Sydney basins.[94] Exploration has expanded to other basins, including the Surat basin, where wells are being drilled to assess the Middle Jurassic Walloon coals.[95]

Development History The Bowen basin (Fig. 6.11) has long been recognized as a potential CBM giant with an estimated resource base of at least 178 Tscf.[96] As far back as 1976, wells were drilled adjacent to existing mines to produce coal gas. In 1987, an eight-well pilot was initiated in the Broadmeadow gas field of the Northern Bowen basin, resulting in low-rate gas production.[97] This was followed by more than 120 production wells and core holes over the next 10 years in an attempt to establish commercial production. This goal was achieved in February of 1998 with the first sale of gas from the Comet Ridge field. A second field, the Scotia field, began selling gas in 2002. The Bowen basin has also become a prime target for CO2 sequestration projects. A recent international study identified the Dawson River site, in the southern Bowen basin, as the best location for a CO2 -enhanced CBM project among 11 sites evaluated.[94]

Coal Characteristics Coal seams in the Bowen basin exhibit a wide range of coal quality and rank characteristics. Lower Permian coals include the Bandanna and Reids Dome Beds, which are productive in the Comet Ridge field. The coals are high-volatile bituminous A and B with low ash contents.[98] They have a cumulative thickness of 50 to 100 ft at a depth of 2,500 to 3,000 ft. The gross production interval is up to 1,000 ft thick and contains 5 to 15 coal seams. Gas contents range from 200 to 400 scf/ton.

Upper Permian coals include the Middle Goonyella coal seam in the Broadmeadow project, the Rangal coals at the Dawson River site, and the Baralaba coal measures in the Scotia field. The Middle Goonyella seam is a medium- to low-volatile bituminous coal that averages 16.2 ft in thickness and occurs at an average depth of 1,640 ft.[97] The average gas content is 458 ft3 /ton on a dry ash-free basis, and the coals appear to be saturated with gas on the basis of the isotherm. Permeabilities range from 0.2 to 1.5 md on the basis of slug and injection/falloff tests.

The Upper Permian Rangal coals at Dawson River are contained in eight seams, 5.6 to 14.4 ft thick at depths of 1,312 to 2,133 ft.[99] The total coal thickness is approximately 75 ft. The coals are well cleated and of high-volatile bituminous rank with ash contents of less than 10%. Gas content values range from 195 to 440 scf/ton, and the seams are normally pressured to slightly underpressured. Well-test permeabilities range from 2.4 to 19.1 md.

The Baralaba coal measures in the Scotia field are lateral equivalents of the Rangal coals. Wells in the Scotia field produce from depths of approximately 2,950 ft, and the coal seams are contained in a conventional four-way dip closure. As a result, the cleat porosity is gas filled, and no dewatering of the coals is required.

Drilling and Completions At Broadmeadow, Wells 1 through 4 were completed with a 5.5-in.-diameter production casing set above the Middle Goonyella coal seam and a 4.5-in.-diameter open hole through the coal.[97] The wells were then fracture stimulated with 141,000 to 168,000 gal of fresh water and 88,000 to 110,000 lbm of 25/52 mesh Townsville sand. High fracture gradients of 0.96 to 1.33 psi/ft in these wells suggest horizontal or T-shaped fracture geometries. Wells 5 through 8 and Well 10 were completed with slotted 5.5-in.-diameter production casing across the coal seam. Wells 6, 8, and 10 were fracture stimulated in a manner similar to the first four wells, while Well 5 was fractured with linear gel and Well 7 was unstimulated. Because the thinking was that horizontal fractures were being generated, water-based fluids were chosen over gel-based fluids in most of the wells to provide greater penetration.[97]

In a 1992 research project at Dawson River, two field trials of the cavity completion technique were conducted. One of these resulted in a partial success, which increased the gas rate 4 to 5 times relative to the initial unstimulated completion.[99] Because of this work and the great success of the openhole cavity technique in the San Juan basin, this completion type is currently being used in the Comet Ridge CBM project.

Well Performance In the Broadmeadow pilot project, Well 3 peaked at 98 Mscf/D and 20 BWPD and Well 8 peaked at 50 Mscf/D and 40 BWPD within one year of their completion. Although formation damage and production problems may have contributed to these low rates, it is doubtful that commercial gas rates could ever be attained given the consistently low permeabilities of less than 1.5 md measured in four wells.

In contrast, the Comet Ridge CBM project attained commercial status in 1998. The project contains approximately 9,600 producing acres in the Fairview field. This field is located in the southern part of authority-to-prospect (ATP) 526, an exploration lease that includes approximately 1,088,000 acres in Queensland. As of 31 December 2000, there were 26 producing wells at Comet Ridge.[100] Sixteen wells were producing gas into a pipeline system, while production from the other 10 wells was being flared at the wellhead during the dewatering process. An additional 10 wells were awaiting completion and/or connection to a gathering system. Production began in February 1998, and approximately 5.5 Bscf had been produced as of 31 December 2000. As of this date, the producing gas rate was approximately 6 MMscf/D with plans to increase this to 10 to 15 MMscf/D. A 20-well drilling program is underway, with the sixth well finished in July 2001. Proven reserves for Comet Ridge are estimated at 430 Bscf. The majority interest owner, Tipperary Oil and Gas Australia, is appraising an additional 1.5 million acres adjacent to Comet Ridge.

Successful appraisal of the Scotia field in the Denison Trough area of the Bowen basin (ATP 378-P in eastern Queensland) has resulted in a declaration of commerciality.[101] Santos Ltd. has agreed to provide up to 9.5 × 108 Btus of gas for power generation over a 10 to 15 year period commencing in 2002. The latest wells, Scotia 11 through 13, were drilled during the second quarter of 2001 and were fractured hydraulically late in the year. Development costs for the project are estimated at U.S. $15 million, with $11 million of this committed to field infrastructure and a gas processing plant. Santos also has been granted additional exploration acreage immediately north of Scotia field and is evaluating its potential.

Future Trends in CBM Development

The vast majority of CBM activity between 1975 and 2000 has been concentrated in the United States, where numerous basins have been developed commercially. This trend will continue in the near future as activity accelerates in the Raton, Arkoma, Powder River, and Appalachian basins, among others. Frontier areas in North America, including Alaska and Canada, have been the focus of considerable activity in recent years and are likely to generate a number of commercial projects.

In other parts of the world, CBM growth has been slow and is likely to remain so. In the late 1980s and 1990s, there was great optimism that prolific CBM basins similar to the San Juan basin could be found all over the world. To search for these, more than 300 appraisal wells were drilled in at least 15 different countries, resulting in only a few small commercial projects in the Bowen basin of Australia.

The primary reason for these international failures has been poor reservoir characteristics. It is now clear that a number of critical elements must be favorable to produce CBM at commercial rates. These elements include coal thickness, gas content, gas saturation, sorption isotherm characteristics, permeability, porosity, and aquifer strength. Given this large number of variables, it is not surprising that two or more of these are unfavorable in most CBM prospects, resulting in subeconomic or marginally economic gas rates.

International development also has been hampered by governmental policies, the absence of gas infrastructure and markets, and inadequate hydrocarbon service industries. Over the next 20 years, there are likely to be dramatic, positive changes in each of these areas. International trade and banking organizations will help upgrade and liberalize foreign markets for investment, while various nations are likely to provide incentives that encourage further exploration and production. Model contracts and terms will become more standardized, which will streamline negotiation and approval processes. Technology transfer and foreign investment will improve the hydrocarbon service industries, making them more efficient and effective. However, there will still be problems caused by political instability, bureaucracy, market volatility, increased regulation, and other forces.

Only companies with strong technical and commercial skills are likely to be successful in pursuing international CBM opportunities. Most opportunities will be characterized by incomplete technical information of poor quality, which will require experienced technical staff to identify key data that indicate whether a project has good or poor potential. The technical and operations staff also must have the ability to generate and execute effective work programs that minimize the time and money required to evaluate a project. Successful companies will be characterized by world-class expertise in specific disciplines including reservoir characterization, reservoir engineering, and operations technologies. Table 6.6 reviews the areas of focus for CBM research and development. Research over the next decade will focus on these key areas and provide additional tools for understanding and exploiting CBM resources.

In addition to strong technical skills, the most successful companies will apply their financial expertise to quantify the uncertainties associated with each CBM project. These uncertainties are best understood through risk analyses, which help determine whether the best course of action is to purchase, appraise, develop, or divest an asset. Risk analyses integrate the technical evaluation, the country-specific financial model, and the company's strategy to determine the value of a project relative to others in the corporate portfolio. This leads to better decision making and financial results. Companies also will benefit greatly from creative financing and marketing solutions. For example, to attract a high-value gas market, a company may couple a conventional and a CBM gas project. The conventional gas project will supply gas on the front end, while the CBM project will replace the conventional gas in later years, ensuring a long, stable gas-rate plateau.

Environmental issues undoubtedly will exert a greater influence over the CBM industry in the next 25 years. Some of these issues will be problems for the industry, such as surface disturbances from drilling and development, the depletion of coalbed aquifers previously used as a residential or commercial water source, and the updip migration and seepage of methane from outcrops because of coalbed dewatering. Other environmental issues will present opportunities, such as the need to replace coal combustion, sequester CO 2 , or capture methane that would have escaped during mining activities. For example, the need to reduce CO 2 emissions from a large coal-fired power plant can be achieved by injecting the CO 2 into an adjacent coalfield for enhanced gas recovery.[102] (Sec. 6.2.7 discusses enhanced gas recovery.) Incentives associated with these opportunities will help foster expansion of the CBM industry.

The CBM industry is still relatively immature, and much remains to be learned. The Powder River basin, which contains low-gas-content, immature coals that were thought to be uneconomical a decade ago, is a good example of the changes occurring within the CBM industry. Many of the industry's advances will depend on rapidly evolving drilling, stimulation, and enhanced recovery technologies.[103] Combining these technologies with investment incentives, favorable regulatory policies, and other projects, such as conventional or CO2 sequestration, is critical for developing new CBM resources.


A = areal extent, L2, acres
Bgi = initial gas formation volume factor, Mscf/ft3
Cm = matrix gas concentration, scf/ft3
fa = ash weight fraction, m, lbm ash/lbm coal
fw = water weight fraction, m, lbm water/lbm coal
G = gas in place, L3, Mscf
Gc = gas content (dry ash-free basis), scf/ton
h = net coal thickness, L, ft
p = pressure in fracture system, m/Lt2, psia
pL = Langmuir pressure constant, m/Lt2, psia
Swi = initial water saturation fraction in the cleats, fraction
VL = dry, ash-free Langmuir volume constant, scf/ton
ρB = bulk density, m/L3, g/cm3
ρc = coal density (dry ash-free basis), m/L3, lbm/ft3
φcl = cleat porosity, fraction


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