Abstract The Green River and Hoback Basins of northwest Wyoming contain very large, regionally pervasive, basin-centered gas accumulations (BCGAs). Published estimates of the amount of in-place gas resources in the Green River Basin range from 91 to 5036 trillion cubic feet (tcf). The Hoback Basin, like the Green River Basin, contains a BCGA in Cretaceous rocks. In this chapter, we make a distinction between regionally pervasive BCGAs and BCGA sweet spots. The Pinedale field, located in the northern part of the Green River Basin, is one of the largest gas fields in America and is a sweet spot in this very large BCGA. By analogy with the Pinedale field, we have also identified a similar BCGA sweet spot in the Hoback Basin. BCGA sweet spots probably always have characteristics in common with conventional accumulations but are different in that they are always contiguous with the underlying more regional BCGA. In this way, they are inseparable from the more regionally pervasive BCGA. We conclude that the probability of forming sweet spots is highly dependent on the presence of faults and/or fractures that have served as conduits for hydrocarbons originating in regional BCGAs. Finally, we propose that the Paleocene “unnamed unit” overlying the Lance Formation be renamed the Wagon Wheel Formation.

Abstract Abnormal pressures, pressures above or below hydrostatic pressures, occur on all continents in a wide range of geological conditions. According to a survey of published literature on abnormal pressures, compaction disequilibrium and hydrocarbon generation are the two most commonly cited causes of abnormally high pressure in petroleum provinces. In young (Tertiary) deltaic sequences, compaction disequilibrium is the dominant cause of abnormal pressure. In older (pre-Tertiary) lithified rocks, hydrocarbon generation, aquathermal expansion, and tectonics are most often cited as the causes of abnormal pressure. The association of abnormal pressures with hydrocarbon accumulations is statistically significant. Within abnormally pressured reservoirs, empirical evidence indicates that the bulk of economically recoverable oil and gas occurs in reservoirs with pressure gradients less than 0.75 psi/ft (17.4 kPa/m) and there is very little production potential from reservoirs that exceed 0.85 psi/ft (19.6 kPa/m). Abnormally pressured rocks are also commonly associated with unconventional gas accumulations where the pressuring phase is gas of either a thermal or microbial origin. In underpressured, thermally mature rocks, the affected reservoirs have most often experienced a significant cooling history and probably evolved from an originally overpressured system.

Abstract Coal, “the black rock that burns,” is the subject of song, story, and legend. The earliest literature citation of coal (combustible bodies, some of which by inference must be coal) is credited to Aristotle in his treatise “Meteorology,” which may date near the middle of the fourth century B.C. Theophrastus, a student of Aristotle, at what is probably a slightly later date provides descriptions of different forms of coal based on their behavior in combustion, identifies areas of occurrence, and states that it was used by smiths (footnote by Hoover to Agricola, 1556). Though the Greek philosophers are responsible for the earliest known literature citations, China and perhaps other parts of eastern Asia are usually believed to have preceded the Mediterranean area in recognition of coal as a peculiar material with usable properties. Inouye (1913) states that although there is no authentic record of the history of the Fu-shun coal field in southern Manchuria, “it is said that the coal was used as fuel … for copper smelting in times as remote as 2,000 or even 3,000 years ago.” Fires through most of man’s history have been fed by “traditional fuels"—wood, straw, dung, and other plant materials. That coal could be of complementary usage is recorded in the remains of funeral pyres in Wales, dated about 3,000 years ago (Lindbergh and Proverse, 1977). However, the versatility of coal was not widely appreciated, and the discovery and use of charcoal satisfied most needs of primitive metal-working. By the end of the

Abstract Depositional environments of coal beds, despite the voluminous works on this topic, remain elusive and difficult to prove (Dapples and Hopkins, 1969; Ferm et al., 1979; Rahmani and Flores, 1984; Lyons and Alpern, 1989; McCabe and Parrish, 1992). Factors that control coal accumulation are as varied as the many disciplines (sedimentol- ogy, coal petrology, geochemistry, paleobotany, etc.) studying the origin of coal beds. For decades, approaches to coal-bed depositional environments have been dichoto- mous; that is, separate and independent analyses of the organic deposits and “accompanying” sediments. This uni- discipline-research approach has fragmented and confused efforts to understand this century-old problem (Schaler, 1885; Stevenson, 1910). However, attempts to bridge the interdisciplinary gap during the past few decades have produced new insights on the nature and origin of coals and associated sedimentary rocks (Raistrick and Marshall, 1939; Styan and Bustin, 1983; Pocknall and Flores, 1987; Stanton et al., 1989; McCabe, 1991; Diessel, 1992). The economic potential of coal-bed methane gas resource has renewed study of coal resources, coal rank, coal geochemistry, and physical properties of coals (Rightmire et al., 1984; Fassett, 1988; Coalbed Methane Symposium, 1989). Although coal beds often serve as source and reservoir rocks of methane gas, it has been found that adjoining sandstones can also serve as reservoir rocks (Rice and Flores, 1990; Flores et al., 1991; Law et al., 1991; Pashin et al., 1991). Thus, knowledge of the origin and properties of the sedimentary rocks lateral to, above, and below coal beds is vital to a successful

Abstract Beginning with its deposition on the earth’s surface, and continuing throughout its burial history, sedimentary organic matter undergoes progressive changes in composition and structure termed organic metamorphism , or when referring specifically to coal, coalification. In the broadest sense, coalification refers to the diagenetic alteration of all sedimentary organic matter (OM) during burial, including tiny organic particles dispersed in an inorganic matrix. From the standpoint of petrogenesis, however, coalification refers to the combined set of processes (physical, chemical, and biological) by which the sedimentary rock coal is formed (where “coal" refers to rocks comprised of at least 50% by weight and 70% by volume carbonaceous material: Schopf, 1956; Bates and Jackson, 1980; ASTM, 1991). The present paper describes the evolution of coal as a sedimentary rock, particularly as it bears on the generation and storage of hydrocarbons; but most of the discussion could be applied equally as well to dispersed OM. Nevertheless, coal, because it is so rich in organic constituents, has many unique physical and chemical properties that are measured by means of specialized tests, such as proximate analysis, calorific value, and Hardgrove Grindability Index (among many others). Coal can be systematically described and classified according to three compositional criteria: grade, type, and rank. Grade represents the relative proportion of organic vs. inorganic constituents; type represents the different classes or categories of organic constituents; and rank represents the level of physico-chemical alteration of coal composition and structure occurring during coalification. Grade and type are initially established in the sedimentary environment

Abstract As in any other sedimentary rock, the composition of coal is extremely heterogeneous. Coal is largely a macro- molecular organic rock, derived from the burial and compaction of peat deposited under various wetland conditions (Stach et al., 1982; Hatcher et al., 1983; Schobert, 1989; Teichmiiller, 1989). The nature of a peat mire is largely controlled by the nature of the water source (ground water versus rainfall) and supply of nutrients. The formation of peat is controlled by several complex parameters as depicted in Figure 1A. A peat mire can be classified as rheotrophic (recharge both from ground water and rainfall) or ombrotrophic (recharge solely from rainfall) (Moore, 1987; Calder et al., 1991). A minerotrophic peat is derived through recharge from mineral-rich ground water. The relative influence of ground water and rainfall (precipitation versus evaporation ratio) determines the various type of peat mire (swamp, fen, or bog) (Figure IB). Coal is composed mainly of organic material with inorganic material as a minor constituent. An inorganic (mineral matter) content of 30% in a coal is considered to be the boundary between coal and impure coal, otherwise known as coaly middlings (intermediate between shale and coal; Alpern, 1981). The major organic constituents of peat are floral components of vascular (forested or marsh vegetation) and nonvascular (aquatic vegetation) plants such as bark, wood, stems, roots, spores, pollen, cuticles, and grasses as well as algae which are associated with fungal, bacterial, and animal remains. The inorganic constituents include minerals or mineral-maceral associations and trace elements

Abstract The literature that describes natural fractures (cleats) in coal can be divided into two areas of activity, including an older mining industry viewpoint and a much newer petroleum industry viewpoint. Cleats in coal have been of interest to the coal mining community for more than 100 years. Knowledge of cleat geometry is important in designing coal mines for maximum extraction efficiency and for safety considerations. One of the earliest references on cleats in coal from the mining perspective is by Mammatt (1834, cited in Kendall and Briggs, 1933), who noted the uniform strike of cleats in coal fields of the United Kingdom. Since that time a large number of papers on cleats have been published. Because of the relatively recent interest in commercial production of coal gas resources, many contemporary research efforts have been directed toward the development of a better understanding of factors that influence the production of gas from coal reservoirs. Among the more important of these factors is the cleat system. The importance of cleat development stems from the fact that the principal natural fracture permeability pathways for the flow of gas and water are through the cleat systems. Cleat permeability is often the reservoir characteristic that has the greatest influence on the economic success or failure of coal gas exploration and development programs (Dhir et al., 1991a, b). A better understanding of cleat genesis is therefore useful for reasons besides academic interest, which include the following: (1) One can better assess why certain coal gas plays

Abstract Coal is, by definition, a rock containing a greater proportion of preserved organic matter than mineral matter. As such, it more than clearly satisfies the empirical observation that an effective petroleum source rock has an initial organic matter content greater than 1 to 1.5% (Bissada, 1982). The vast majority of petroleum source rocks that are known to have led to commercial petroleum pools have total organic carbon contents above this threshold. Although there is consensus within the geochemical and petroleum geological community that coal can source gas and condensate, there are opposite viewpoints on whether coal can (Brooks and Smith, 1969; Smyth, 1979, 1983; Thomas, 1982; Durand and Paratte, 1983; Verheyen et al., 1984; Shanmugan, 1985; Khorasani, 1987; Horsfield et al., 1988; Bjoroy et al., 1988; Lu and Kaplan 1990; Boreham and Powell, 1991; Hunt, 1991; Noble et al., 1991; Powell and Boreham, 1991) or cannot (Rigby and Smith, 1982; Katz et al., 1990) be a source for liquid petroleum. Certainly, the casual observation that ultimate reserves of world oil are diachronous with ultimate reserves of coal cannot be used as an argument against coal as a source rock for oil (Hunt, 1991). The proponents for coal not being a source for reser- voirable oil argue that although coals can have a high potential to generate significant petroleum (oil and gas), any liquids generated would effectively be retained within the coal matrix because of the microporosity present in coal (van Krevelen, 1961). Only at higher maturities where there is significant

Abstract Coal, which contains more than 50% by weight and 70% by volume of carbonaceous material including inherent moisture (Bates and Jackson, 1987), has been and remains the most abundant energy source in the world. Reserves are estimated to be in the range of several trillion tons (Landis, this volume). Thus coal potentially represents a much larger energy resource than that estimated for crude oil and natural gas. In addition to minable reserves, coal has been and is being studied as a source of hydrocarbons, in particular natural gas. The presence of methane-rich gas in coal has long been recognized because of explosions that have occurred during underground mining. Not only is the gas a hazard, but coal mining contributes to the increasing amount of atmospheric methane, which is a potent greenhouse gas (Boyer et al., 1990). In addition, coal is the source of hydrocarbons that have accumulated in adjacent reservoirs in many basins. Only recently has gas in coal beds been recognized as a large untapped energy resource with the coal serving as both the source and reservoir rock. After burial, plant material is progressively converted to coal by the process of coalification (Levine, this volume). Figure 1 shows the rank sequence from peat to anthracite and common properties for measuring it. The alteration is controlled by biochemical processes during peat formation and by temperature and pressure during diagenesis and metamorphism. In addition to temperature and pressure, which are usually dependent on depth of burial, the conversion is determined by

Abstract Coal and coaly organic matter dispersed in shales have long been recognized as sources of hydrocarbon gas and CO 2 but have only recently been shown to be capable of generating and expelling economic quantities of liquid products in a number of basins worldwide (e.g., Brooks and Smith, 1969; Combaz and DeMatharel, 1978; Shibaoka et al., 1978; Durand and Paratte, 1983; Noble et al., 1991; Shanmugan, 1985; Thompson et al., 1985; Khorasani, 1987; Huang Difan et al., 1991). The composition of hydrocarbons that can be extracted with solvents or can be generated by experimental heating varies widely for coals of different ages and from different regions of the world. Factors affecting the hydrocarbon composition include the kerogen composition of the coal and conditions of heating, under either natural or experimental conditions. An understanding of the composition and geochemical characteristics unique (if any) to oils derived from coaly organic matter is important to characterization of oils where the source rock is unknown or uncertain. The ability to characterize an oil as being from a coal source can provide direction in further exploration efforts by helping to elucidate the generation and migration history of the oil accumulation. Moreover, our understanding of the ability of coals and coaly organic matter to generate and expel oil depends not only on assessment of various coals by geochemical means, but also on studies of oil accumulations that have been generated and expelled from coal or coaly organic matter. The purpose of the present paper is to review

Abstract One feature that makes coal different from conventional gas reservoirs is the manner in which the gas is stored. In conventional reservoirs, the gas exists in a free state in the pores of the reservoir rock; and its behavior can be described by the real gas law. In contrast, nearly all of the gas in coal exists in a condensed, near liquid-like state because of physical sorption. These differences bring up two important questions. How do you describe the behavior of the sorbed gas, and how do you determine the sorbed gas content? Much literature has been written concerning these two subjects, and the following discussion reviews and summarizes the results and presents the current answers to these questions. First, the behavior of the sorbed gas is described, in terms of the physical sorption process and a sorption isotherm. The changes in gas content with pressure, temperature, mineral matter, moisture, rank, petrology, different pure gases, and multicomponent sorption are discussed. Techniques for measuring isotherms are also presented. Second, methods for determining the gas content are described in terms of direct methods that actually measure the amount of gas present and indirect methods in which the gas content is inferred from the sorption isotherm.

Abstract Primary migration in source rocks follows petroleum (= oil and gas) generation, which in turn is a function of rank and kerogen composition (Hunt, 1979; Tissot and Welte, 1984). Whether petroleum generation in coals is an economically important process was controversially discussed in the past (e.g., Katz et al., 1991; Durand and Paratte, 1983; Hunt, 1979,1991). Six groups of observations strongly support the assumption that great masses of petroleum are generated in coals: Liptinites constitute generally between 5 and 20% of humic coals. These petrographic constituents (macerals) are known to be hydrogen-rich (van Krevelen, 1961) and act as source of petroleum. In many conventional petroleum source rocks, liptinites also constitute between 5 and 20% of the rock (by volume), but are surrounded by a mineral groundmass rather than by an organic, mainly vitrinitic groundmass. It should be noted, however, that liptinites in coals are derived from other precursors (e.g., spores, pollen, resins, cuticles) than are liptinites in clastic and carbonate source rocks and will generate different products upon maturation (Given, 1984). Upon artificial maturation (pyrolysis), most coals generate significant quantities of petroleum compounds. The gas/oil ratio and the ratio of aromatic over n-alkyl moieties are often greater in coal pyrolysates than in kerogen pyrolysates derived from marine or lacustrine source rocks (Larter and Senftle, 1985; Horsfield, 1989; Katz et al., 1991; Powell et al., 1991). An example of a pyrolysate from a pure, hand-picked vitrinite from a Carboniferous coal seam is shown in Figure 1. Aromatic hydrocarbons

Abstract It is estimated that coalbeds in the United States contain as much as 11.3 trillion m 3 (400 trillion ft 3 ) of in-place gas (Kuuskraa and Brandenburg, 1989). This volume of gas represents a source of clean-burning fuel; however, methane emissions into underground coal mines present a serious hazard to coal miners. Since the first documented major U.S. coal mine explosion in Virginia in 1839, several thousand fatalities have been recorded as a result of explosions where methane was a contributing factor (Skow et al., 1980). Ventilation has been the primary means of controlling methane in coal mines for many years. However, as mines began operating in deeper and gassier coalbeds, supplemental means of methane control became of interest to mine operators. The shift to mining gassier coalbeds is quite evident in Figure 1, which charts the methane emissions from coal mine ventilation systems from 1971 to 1988. The volume of methane and the number of operating mines remained stable through the early to middle 1970s (Irani et al., 1972, 1974), but as of the 1980 and 1985 surveys (Grau and LaScola, 1984; Grau, 1987), methane emissions increased substantially, while the number of operating mines declined. The decline of methane emissions in 1988 is at least partially attributed to the increased use of methane drainage technology, especially in the Black Warrior basin of Alabama. Methane emissions from Alabama coal mines decreased 17%, from 2.3 x 10 6 m 3 /d (82.4 MMcfd) to 1.9 x 10 6 m 3 /d (68.4 MMcfd) between 1985 and 1988 (Trevits et al., 1991)

Abstract The technology of drilling coalbed methane reservoirs has evolved significantly since the first coal wells were drilled in the 1950s. Approximately 6000 coalbed methane wells have been drilled in the United States (Oil and Gas Journal, May 20, 1991). The majority of the drilling activity has occurred in the San Juan basin, Colorado and New Mexico, and in the Black Warrior basin, Alabama (Table 1). Coalbed methane is also being developed outside the United States, in Canada, Mexico, Australia, and Europe (Nikols and Rottenfusser, 1991; Decker et al., 1991). Coal has a number of unique properties that must be considered during planning, drilling, completing, and producing a coalbed methane well. Variety in these unique reservoir and geologic characteristics has resulted in a corresponding diversity in the problems and practices of drilling coalbed methane wells. To a large extent, these are related to the different conditions existing for shallow coals in the eastern U.S. basins and the deeper coal seams in the west. Typically, eastern basin wells are easier to drill and encounter fewer problems than the deeper and sometimes overpressured western basin wells (Petroleum Frontiers, 1986). Generally, the primary drilling problems encountered when drilling coalbed methane wells in the United States are: (1) excessive water flows, (2) gas kicks caused by overpressured coal seams, (3) wellbore stability/coal sloughing, and (4) formation damage. Coal reservoirs are not homogeneous and within the same area can have different reservoir and geologic characteristics. In addition, the reservoir is typically not a single coal seam

Abstract Valuable geologic information can be obtained by utilizing wireline conveyed measurements. Generally referred to as “logs," these readings probably derive their name from the general term meaning a “record" of a series of events. In the context used here, the term log refers to a particular measurement in a well that is recorded as a function of well depth. It often refers to a measurement of one or more physical properties as a function of well depth. From these physical properties, the rock properties are inferred. Results are not limited to rock property measurements, though. Examples of other types of logs are fluid flow, cement quality, casing corrosion, etc. Having defined the term log , why the term wireline? This is to differentiate between logs made from instruments lowered into the well on a cable, and logs made in the oil field by noncable means such as mud logs (drilling mud characteristics), drilling time logs (bit penetration rates), etc. The term cable, as used in the foregoing comment, should be clarified. Cables, in their most familiar form, are strong, flexible "ropes" made of spiraled metal strands. "Wireline" denotes a special form of metal stranded cable that contains electrical conductors on the inside (core). These conductors generally serve dual purposes: to power the downhole instrument (tool) and to convey the tool signal back to the surface for display on the log. The "wireline" cable causes some difficult obstacles for the logging service company. Because of the small diameter conductors, line resistance tends

Abstract Coalbed methane wells require stimulation, or special completion techniques, to effectively connect the wellbore to the reservoir. A variety of completions and stimulations have been tried, and these are summarized through the end of 1991 as follows (with emphasis on San Juan and Black Warrior basins): Openhole cavity . This has worked best in the "fairway" zone of the San Juan basin where reservoir pressure and permeability are high. The wells can be prolific producers, up to 10 million cubic feet of gas per day (MMCFGD). The cavitation technique is discussed. The physical mechanisms involved in the completion are examined and used to try to understand why cavity completions outperform gel fracture stimulations in gas production in the fairway. Gel fracture treatments . These stimulations are conducted through casing perforations in coal seams. High fracture conductivities are achieved by using 12/20 mesh sand to concentrations of 10 ppg. Although gel damage to the coal formation is evident, moderate productivity increases have been achieved. Water fracture treatments . Because of gel damage to the formation, fracturing treatments have been conducted using water as fracture fluid, plus 12/20 sand to concentrations of a few ppg. In some parts of both basins gas production is greater than offset wells with gel fracture treatments, and the water fractures are cheaper by half. Sandless water fracture treatments . In the Black Warrior basin, water fracture treatments have been performed without sand, using ball sealers to open up more seams. Although their gas production may not

Abstract Coalbed methane has been produced in commercial quantities in the United States since 1981 and has attracted worldwide attention as a potential source of cost-competitive gas. Coal is different from other gas reservoirs in three primary ways: (1) gas is stored in the adsorbed state on the surface of the coal; (2) before gas can be produced in significant quantities, the average reservoir pressure must be reduced; and (3) water is usually present in the reservoir and is normally co-produced with the gas. These unique reservoir characteristics require low wellhead pressure (to maximize gas desorption), separation of gas and water at the surface, compression of gas to delivery pressure, and procedures to handle and dispose of produced water. Standard oil and gas production practices must be tailored to the unique characteristics of coalbed methane reservoirs to facilitate commercial production. This chapter documents commercial production, briefly describes coalbed methane production mechanisms, and defines the type of equipment used to produce this reservoir. Methods and equipment include typical surface facility layout and well design, types of dewatering pumps, gas and water separators, gathering lines, flow measurement options, gas treating and compression, and water handling procedures. Methods of initiating production from a well, typical workover procedures, and suggestions for optimizing gas production are also discussed. The majority of the information in this chapter is based on production experience in the Black Warrior basin of Alabama and the San Juan basin of Colorado and New Mexico. However, the techniques can be adapted to fit

Abstract The reservoir engineering aspects of classical coalbed methane production involve the physics of desorption, diffusion, and two-phase Darcy flow of gas and water. Generally speaking, early-time flow rates are controlled by the flow capacity of the coalbed and its ability to produce water since the coal cleats (natural fractures) are 100% water saturated at initial conditions. As a result, initial gas flow rates will be zero or very low. Once gas saturation in the cleats begins to increase, gas flow rates will peak and will then be controlled by the gas desorption rate. The micropore surface area upon which the gas is adsorbed is large, on the order of 1 million square feet per pound of coal. The generally accepted theory of gas storage in coal is that the gas is adsorbed in a monolayer on the micropore surfaces and the amount adsorbed is dependent upon the coal rank, temperature, and pressure. The coalbed reservoir is both the source of gas generation and the vessel in which the gas is stored. At similar depths and pressures, coal beds contain from 2 to 4 times the amount of gas contained in a conventional gas reservoir. The purpose of this paper is to discuss the interrelationships among various reservoir parameters (absolute permeability, relative permeability, porosity, compressibility, and gas content) and how they affect the production of gas from coalbed reservoirs. Difficulties and/or discrepancies in the measurement of some reservoir parameters will also be discussed. An example of how well spacing and the

Abstract Coalbed methane development and production in the United States have increased dramatically during the past few years. From a base of a few dozen wells in the mid- 1980s, nearly 6000 wells were producing methane from coal seams by 1992; another 2000 wells have been drilled but are awaiting completion or connection to a gathering system. By the end of 1992, production of coalbed methane had reached 1.5 billion cubic feet (Bcf) (42 million cubic meters [MMm 3 ]) per day with proved reserves of about 12 trillion cubic feet (Tcf) (340 billion cubic meters [Bm 3 ]). Assuming continued growth, coalbed methane could supply 2.5 Bcf (71 MMm 3 ) per day of pipeline-quality natural gas in 1995 and provide 3.6 Bcf (102 MMm 3 ) per day, or 1.5 Tcf (42 Bm 3 ) per year, by the turn of the century, as shown in Figure 1 (Kuuskraa, 1992). Reaching these targets, however, will require firming of the U.S. gas market and continuing advances in gas extraction technology. Elsewhere, coalbed methane field pilot projects are being started in Australia, Canada, China, Great Britain, and Spain. In other countries, such as Hungary, India, Poland, Russia and Zimbabwe, firms are conducting initial feasibility studies and gathering data to establish the coalbed methane potential in these areas. While the resource potential in these countries is substantial and in some cases, such as China, may dwarf the resource potential of conventional natural gas, the economic feasibility of producing gas from these coals has yet to be established. With this high level of