Non-conventional gas

Transcription

1 2.2 Non-conventional gas Introduction Definition The expression non-conventional gas, historically, has meant many different things to different governments, organizations, and public/private businesses. Early distinctions in the USA (mid-1970s) were based primarily on economics: sub-economic to marginally- economic gas resources were termed non-conventional or unconventional. The term non-conventional gas (and unconventional gas) began to gain widespread use in the late 1970s in the USA as a result of the US Government s Natural Gas Policy Act of 1978 and the Crude Oil Windfall Profits Tax Act of 1980, which provided tax incentives for businesses to encourage energy conservation and the production of alternative energy sources, including non-conventional gas (NPC, 1980). Recently, geologic distinctions have been suggested to identify non-conventional gas. In this categorization, conventional gas resources are buoyancy-driven deposits whereas non-conventional gas resources are not buoyancy-driven (Law and Curtis, 2002). These non-conventional resources are regionally pervasive and often independent of structural or stratigraphic traps. So, what exactly is non-conventional gas? Numerous reservoirs and gas deposits have been associated with the term non-conventional gas. These include: a) natural gas in coal, i.e., Coal Bed Methane (CBM), coal gas, coal seam gas, and Coal Bed Natural Gas (CBNG); b) natural gas in shale/mudstone, i.e., shale gas, gas shale, and Devonian shale gas (in the eastern USA); c) natural gas in low permeability clastic deposits (tight sand gas, tight sandstone gas, or tight gas); d) biogenic natural gas in conventional reservoirs; e) natural gas hydrate (methane hydrate); f ) natural gas in municipal solid waste (landfill gas, biogenic gas); g) natural gas in geo-pressured aquifers; h) natural gas in naturally fractured igneous and metamorphic rock; and i) natural gas in deep clastic or carbonate formations ( 6,000 m). Although all of these reservoirs or deposits may be identified as non-conventional gas, currently four primary reservoir types are the focus of the international natural gas exploration and production industry: coalbed methane, shale gas, tight gas, and gas hydrate. Tight gas has transitioned during the last 20 years to be considered a more traditional (albeit low permeability) conventional gas reservoir; and coalbed methane and shale gas are presented in detail below. Gas hydrate is the subject of the next chapter in this volume and therefore is not discussed in detail here. Historical development Serendipitous historical examples exist of commercial production from coal and gas shale reservoirs: shale gas production from a well drilled in 1821 in the Dunkirk Shale of western New York, USA (Broadhead, 1993), and coal gas production from the Pittsburgh coal in the Big Run Field of northern West Virginia, USA, in the early 1920s (Patchen et al., 1991). However, the large-scale, worldwide commercial development of gas-charged coal and shale reservoirs as sources of natural gas is a recent development in the world hydrocarbon industry. Prior to the mid-1970s, attempts had been made worldwide to recover the methane that is contained in coal. These were primarily conducted within a coal mining environment (underground) and focused on the removal of the methane from the coal to enhance mine safety and coal mining VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 57

2 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES productivity. Generally, these attempts employed the use of horizontal (or angled) boreholes that were drilled from within the mine workings into the mined coal seam or adjacent seams and strata. Beginning in the mid-1970s, research efforts in the USA began exploring the possibility of applying oilfield technology to the removal of gas from coal seams. The advantage of these new approaches, which consisted of drilling vertical wells from the surface into the coal seam(s), was that it permitted the removal of methane from the coal seam in advance of mining operations (using vertical, hydraulic fracture-stimulated wells). Initial attempts using these techniques at coal mines in the Warrior and Appalachian s, USA, and in virgin, un-mined areas of the San Juan, New Mexico, USA, were successful. Moreover, this success was twofold: not only was the methane readily recovered from the coal seam in advance of mining or in the gob areas, but also the recovery rates were high enough to be considered commercial. As a result, the first modern commercial production of methane from coal seams in the USA began. The first instance was in 1977 in the San Juan, New Mexico, USA (at Amoco Production Company s Cedar Hill Field in a virgin coal area not in conjunction with a mining operation). The second was in 1981 in the Black Warrior, Alabama, USA (at the USS Mining Company s Oak Grove Mine and at the Jim Walter Resource s No. 4 and No. 5 Mines). Thus, the commercial coalbed methane industry in the USA was initiated (Boyer and Qingzhao, 1998). Coalbed methane development and production have increased dramatically during the past two decades. Beginning from a few wells in the late 1970s, the industry grew slowly, such that by the mid-1980s less than 100 wells were commercially producing coalbed methane in the USA. However, during the late 1980s through 2004, the industry underwent a rapid expansion. By the end of 2004, over 23,000 wells were producing natural gas from coal seam reservoirs, with an annual production rate of approximately m 3 or a rate of approximately m 3 per day (Fig. 1). Shale gas production was initiated in the USA in 1821 near the town of Fredonia, New York. Peebles (1980) stated: The accidental ignition by small boys of a seepage of natural gas at the nearby Canadaway Creek brought home to the local townspeople the potential value of this burning spring. They drilled a well 27 feet (8 m) deep and piped the gas through small hollowed-out logs to several nearby houses for lighting. These primitive log pipes were later replaced by a three-quarter inch (1.9 cm) lead pipe made by William Hart, the local gunsmith. He ran the gas some 25 feet (7.5 m) into an inverted water-filled vat, called a gasometer and from there a line to Abel House, one of the local inns, where the gas was used for illumination. In December 1825 the Fredonia Censor reported: 60 22,000 annual CBM production (10 9 m 3 ) 50 gas production producing wells ,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 producing CBM wells Fig. 1. Growth in coalbed methane production and number of producing wells in the USA, 1981 to 2004 (Anderson et al., 2003). 58 ENCYCLOPAEDIA OF HYDROCARBONS

3 NON-CONVENTIONAL GAS 25 35,000 annual shale gas production (10 9 m 3 ) gas production producing wells 30,000 25,000 20,000 15,000 10,000 5,000 producing shale gas wells Fig. 2. Growth in shale gas production and number of producing wells in the USA, 1979 to 2004 (Curtis, 2002). We witnessed last evening burning of 66 beautiful gas lights and 150 lights could be supplied by this gasometer. There is now sufficient gas to supply another one [gasometer] as large. Fredonia s gas supply was acclaimed as: unparalleled on the face of the globe. This first practical use of natural gas in 1821 was only five years after the birth of the manufactured gas industry in the United States, which most commentators agree was marked by the founding of the Gas Light Company of Baltimore (Maryland) in Development of these Devonian-age organic shale formations spread throughout this region of the eastern USA during the remainder of the 19 th and beginning of the 20 th century. In 1921 the discovery well for the Big Sandy Field was drilled into the Devonian Ohio Shale in eastern Kentucky, USA, producing up to m 3 per day. By the mid-1930s this field was recognized as the largest gas accumulation in the USA (Ley, 1935). USA government- and industry-sponsored geological, geochemical, and petroleum engineering studies in shale gas were initiated in the mid-1970s and continued through the early 1990s. Results of this work led to the further expansion of the shale gas industry into the Devonian Antrim Shale of the Michigan (Michigan, USA), which became commercially productive in the late 1980s. Subsequent to this, commercial development of the Cretaceous Lewis Shale of the San Juan and the Mississippian Barnett Shale of the Fort Worth (Texas, USA) was initiated in the 1990s (Curtis, 2002). The number of shale gas wells and the annual production in the USA has increased annually, but has recently seen a more rapid growth (Fig. 2) due to the production success of the Barnett Shale, currently one of the most prolific gas reservoirs in the USA. Current production is approximately m 3 per day with over 3,700 producing wells. Since 1981, the total gas produced from the field is estimated at almost m 3. In 2004 alone, the Barnett Shale produced over m 3 making it the largest gas field in the state of Texas, USA (Frantz et al., 2005). World resources Many researchers have evaluated the coalbed methane potential of most of the major coal-bearing regions and countries of the world (Kuuskraa et al., 1992). Boyer (1994) presented a summary of this work, which is shown in Table 1. As seen in this table, the overall size of the natural gas resource that is contained in the coal deposits of the world is significant: m 3 to m 3. Accordingly, coalbed methane represents a major new international source of natural gas. While initial interest has focused on the major coal-bearing countries, many countries have small but significant quantities of coalbed methane. Individual plays in small basins, particularly those close to markets for the gas, may VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 59

4 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES Table 1. Summary estimates of world coalbed methane resources (Boyer, 1998) Country/Region Coalbed methane resource, m 3 (trillion ft 3 ) China (1,060-1,240) Russia (600-4,000) United States ( ) Australia ( ) Canada (200-2,700) Germany 2.8 (100) Poland 2.8 (100) United Kingdom 1.7 (60) Ukraine 1.7 (60) Kazakhstan 1.1 (40) India 0.8 (30) Southern Africa 0.8 (30) Other 0.8 (30) Total (2,953-9,304) provide commercially attractive opportunities for operators (Boyer et al., 1992). Conversely, the world s shale gas resources are not as well understood. Estimates of the shale gas resources in the five producing basins in the USA (Table 2) range from m 3 to m 3. Significantly more gas is estimated to occur within the 12 other identified gas shale formations in the USA (Hill and Nelson, 2000), but no estimate of the volume has been made to date. A 2002 estimate of the shale gas resources of the western Canada sedimentary basin by Faraj indicated greater than m 3 of gas in place (Faraj et al., 2002). An initial assessment of the shale gas potential of the United Kingdom (Selley, 2005) identified potential reservoirs, but no volumetric estimates were provided. To date, no detailed estimate of the shale gas resource in the shale formations throughout the world has been made Reservoir fundamentals Overview Unlike conventional reservoirs, coal and shale are the source, trap, and reservoir for natural gas. Methane (and other gases-heavier hydrocarbons, carbon dioxide, water, nitrogen, and others) is generated in-situ from the transformation of organic matter, and exists as both free gas in the micropores and sorbed gas on the reservoir surface. The matrix permeability of coal and shale reservoirs is extremely low; because of this, secondary natural fracture permeability is required for commercial production. Coal gas reservoirs contain an orthogonal fracture set called cleats that are perpendicular to bedding and provide the primary conduit for fluid flow. In gas shale reservoirs, tectonic fracture sets provide this conduit. Gas flows from the matrix to the fractures by a combination of diffusion and Darcy flow. Production profiles for coal and shale gas wells usually differ from those of conventional reservoirs. In a typical coal gas reservoir, the cleats are initially filled with water that must be produced to lower the pressure in the cleat system. This causes gas to desorb at the coal matrix-cleat interfaces, creating a methane concentration gradient across the coal matrix. Thus, gas diffuses through the matrix and is released into the cleat system. Over time, the produced water volume decreases (due to relative permeability effects) and the gas rate increases. However, in some isolated cases, coal reservoirs are dry and require no dewatering. As production matures, shrinkage of the coal matrix can increase the absolute permeability of a coal gas reservoir several-fold and accelerate gas production. In gas shale reservoirs, which typically contain a larger free gas component than coal reservoirs, methane and water are usually produced simultaneously. As reservoir pressure decreases, gas begins to desorb from the organics in the matrix to supplement production of the free matrix gas and reduce the gas production decline rate. Table 2. Summary estimates of shale gas resources in historically productive plays in the USA (Curtis, 2002) Shale formation Shale gas resource, m 3 (trillion ft 3 ) Appalachian Ohio Shale ( ) Michigan Antrim Shale (35-76) Illinois New Albany Shale (86-160) Fort Worth Barnett Shale (54-202) San Juan Lewis Shale 2.7 (97) Total ( ) 60 ENCYCLOPAEDIA OF HYDROCARBONS

5 NON-CONVENTIONAL GAS Both coal gas and gas shale reservoirs are continuous gas accumulations. These are reservoir systems where gas-bearing strata are not density-stratified, do not contain a gas-water contact, and persist over a very large geographical area. The challenge in these accumulations is to identify the most prospective (potentially productive) areas and to efficiently appraise and develop them. A useful first step in this process is to compare the characteristics of prospective areas to those of existing commercial projects for coal gas and gas shale reservoirs (Tables 3, and 4; see again Table 2). Successful projects have many similarities, including concentrated gas resources, sufficient gas rates, and access to technologies and markets. Coal as a reservoir Coal composition Coal is a chemically complex, combustible solid consisting of a mixture of altered plant remains. Organic matter comprises more than Table 3. Summary reservoir and production characteristics of four coalbed methane fields in the USA San Juan Uinta Black Warrior Powder River Target play Fairway Drunkard s Wash Cedar Cove Recluse/Rawhide Butte Area (km 2 ) 1, Wells ,000 Gas production rate (m 3 /d/well) 70,800 15,000 4,000 4,000 Reserves (10 6 m 3 /well) Coal seam age Cretaceous Cretaceous Carboniferous Paleocene Coal formation Fruitland Ferron Pottsville Fort Union Coal thickness (m) Number of seams Stratigraphic interval thickness (m) Gas content (m 3 /t) Permeability (md) Pressure gradient (MPa/100m) Producing depth (m) 880-1, , Completed zones Well cost (10 3 $) Coal rank High volatile A-medium volatile bituminous High volatile B bituminous Medium-low volatile bituminous Sub-bituminous B Gas saturation state Saturated Saturated Undersaturated to saturated Saturated Completion type Cavitated Hydraulic fracture Hydraulic fracture Water infusion Well spacing (km 2 ) VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 61

6 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES Table 4. Summary reservoir and production characteristics of five shale gas basins in the USA (Curtis, 2002) Shale Formation Antrim Ohio New Albany Barnett Lewis Michigan Appalachian Illinois Fort Worth San Juan Depth (m) , ,500 2,000-2, ,800 Gross thickness (m) Net thickness (m) Bottom-hole temperature (ºC) Total organic carbon (%) Vitrinite reflectance (% R o ) Total porosity (%) Gas-filled porosity (%) Water-filled porosity (%) Permeability thickness (md m) 0.3-1, n/a Gas content (m 3 /t) Adsorbed gas (%) Reservoir pressure (MPa) Pressure gradient (MPa/100m) Well costs (10 3 $) Completion costs (10 3 $) Water production (m 3 /d) Gas production rate (m 3 /d/well) 1,100-14, , ,400 2,800-28,300 2,800-5,600 Well spacing (km 2 ) Recovery factor (%) Gas in place (10 6 m 3 /km 2 ) Reserves (10 6 m 3 /well) % of coal by weight and more than 70% by volume (Schopf, 1956). Coals are described and classified by differences in composition (type), maturity (rank), and purity (grade). Coal type is based on the kinds of altered vegetative material (macerals) that form the coal. The two primary types of coal are humic (most coals) and sapropelic (rare). Coal type is important because each maceral type generates different volumes of gas during maturation. Each maceral type also adsorbs (stores) different quantities of methane, has different diffusion characteristics, and impacts natural fracture (cleat) development within the coal (Mukhopadhyay and Hatcher, 1993). The primary method for determining coal type is by microscopic examination of coal samples. Coal rank is a measure of the maturity of the organic material within the coal, which is the result of heat (due to geothermal gradient or igneous intrusions) and pressure (due to tectonic and overburden forces) (Stach et al., 1975). A comparison of coal rank versus coal classification and measurement systems is provided in Table ENCYCLOPAEDIA OF HYDROCARBONS

7 NON-CONVENTIONAL GAS Coal rank is an important measurement for the evaluation of coalbed methane reservoirs because gas generation in coal is highly correlated with increasing coal rank. In addition, gas storage in coal, gas diffusivity in coal, gas composition, and natural fracture development in coal are also strongly correlated to coal rank. Coal rank is most often measured by thermal destruction (proximate analysis), vitrinite reflectance, or heat content (calorific value). A final classification for coal is the coal purity or grade. Grade is a measure of the quantity and type of non-organic material in the coal. Coal grade includes evaluation of primary minerals, secondary minerals, and moisture. Measurement of coal grade can be accomplished by proximate analysis, petrographic analysis (microscopic identification of minerals), ash composition analysis (elemental oxide composition of ash from proximate analysis), and equilibrium moisture analysis. Coal grade is important because non-coal material dilutes the concentration of organics in the coal (gas is stored only in the organic fraction). Non-coal material also affects the amount of natural fracturing in the coal. Geometric aspects of coal reservoirs In evaluation of coal reservoirs, the first issue that must be considered is the geometric aspects of the reservoir. The parameters relating to the geometry of the reservoir, which are important for this evaluation, include thickness of the coal seams (individual and cumulative), number of coal seams, depth(s) of the coal seam(s), thickness of the stratigraphic interval containing the coal seams, and aerial extent of the coal seams (discontinuities/no-flow boundaries). The geometry of the reservoir refers to the three dimensional shape through which fluids (gas and water) flow. The geometry of the reservoir impacts drilling, completion, and production methodologies relating to development of coalbed methane projects. Coal is most often formed as part of a typical clastic depositional sequence. Coal originates as an accumulation of organic matter in swamps and marshes commonly associated with fluvial systems, deltas, and marine shorelines. It is critical that the accumulating organic matter is quickly submerged beneath the water table to prevent oxidation. This requires a combination of basin accommodation and a rising water table sufficient to match the accumulation rate. Organic matter accumulates at rates ranging from 20 to 200 cm per 1,000 years (Flores, 1993). The depositional environment impacts the degree of coal continuity. It is important to determine if the reservoir is continuous (relatively infinite boundaries) or if there are flow boundaries caused by faulting, Table 5. Comparison of coal rank designation and measured coal property (Levine, 1993; ASTM, 2005) Coal rank (USA classification) Vitrinite reflectance, % R o Volatile matter (dry, ash-free), wt % Calorific value, Btu/lb Peat Lignite ,300-8,300 Sub-bituminous C ,300-9,500 Sub-bituminous B ,500-10,500 Sub-bituminous A ,500-11,500 High volatile bituminous C ,500-13,000 High volatile bituminous B ,000-14,000 High volatile bituminous A ,000 Medium volatile bituminous Low volatile bituminous Semi-anthracite Anthracite Meta-anthracite VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 63

8 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES Fig. 3. Correlations of the upper Cretaceous Calico and A-sequence coals (Straight Cliffs Formation, Kaiparowits Plateau, Utah, USA), showing impact of coal deposition on coal seam continuity and stratigraphy (Hettinger, 2000). B southwest ng den ng den Calico and A-sequences ng den ng den ng den northeast B' measured ng res ng res ng res section 1,000 feet (c. 300 m) braided river coastal plain coal zone 14 miles (c. 26 km) coal bed shoreface offshore 100 feet (c. 30 m) geophysical logs: density (den), resistivity (res), natural gamma (ng) drill hole pinchouts, discontinuities, etc. (Fig. 3). The inclusion of non-coal material within the coal reservoir also has a significant impact on the performance of coal seam reservoirs, so it is important to understand the depositional environment and the potential for non-coal minerals to be part of the reservoir. 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, i.e. humification and gelification (Stach et al., 1975), associated with this process transform the organic matter into precursors of coal macerals. These reactions can also generate significant amounts of biogenic methane and carbon dioxide. Continued compaction and dehydration transform peat into a low-quality coal (lignite or brown coal) that normally contains 30 to 40% interstitial water (Levine, 1993). With deeper burial, temperatures increase and geochemical processes dominate physical processes. Lignite evolves into sub-bituminous coal by expelling water, carbon monoxide, carbon dioxide, hydrogen sulphide, and ammonia, leaving behind a structure enriched in carbon and hydrogen. At temperatures above about 104 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. While some of the methane remains in the coal, a significant volume is expelled from the coal, as an order-of-magnitude more gas is generated than the coal is capable of storing (Fig. 4). In a typical coal, the H/C atomic Fig. 4. Gas generation as a function of coal rank (Anderson et al., 2003). increasing gas volume thermally-derived methane biogenic methane nitrogen carbon dioxide volatile matter driven off lignite sub-bituminous bituminous anthracite graphite increasing coal rank 64 ENCYCLOPAEDIA OF HYDROCARBONS

9 NON-CONVENTIONAL GAS 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 (Levine, 1993). Moisture content is reduced to just a few percent as water is expelled. Micro-porosity increases as the atomic structure of the coal changes, generating a huge surface area for adsorbing methane. These changes also lower the bulk density from 1.5 g/cm 3 in high-volatile bituminous coals to less than 1.2 g/cm 3 in low-volatile bituminous coals. Coal strength decreases, making it easier for the coal to fracture as hydrocarbons evolve and the coal shrinks. This creates closely spaced cleats that enhance permeability (Close, 1993). At temperatures exceeding about 300 C, bituminous coals are altered to anthracite ( 92% carbon). Methane generation and expulsion decreases and the bulk density increases from 1.3 g/cm 3 to more than 1.8 g/cm 3 as the coal structure becomes more compact. Methane contents in anthracites are typically quite high but permeability is often lower than bituminous coals due to cleat annealing. With further maturation, remaining hydrocarbons are driven off and carbon structures coalesce, resulting in a dense coal with a very high carbon content and a chemical composition similar to graphite (Levine, 1993). In order to generate high enough temperatures to produce large quantities of hydrocarbons, coals must be deeply buried, typically to depths of greater than 3,000 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 commercially exploited. At depths shallower than 100 m, there is usually not enough pressure in the cleat system to hold economic quantities of adsorbed gas in the coal. At depths greater than about 1,200 m, natural fracture permeability is generally too low to produce gas at economic rates. Coal seams are typically multi-layered reservoirs. The thickness of individual coal seams may vary widely (from a few centimetres to tens of metres). Also, the number of coal seams within the stratigraphic interval target may vary widely, from a few seams to more than 100 seams (Fig. 5). Stratigraphic sequence thickness also varies, ranging from tens of metres to hundreds of metres. In addition to depositional setting, post-depositional structural effects may deform the coal seam and impact reservoir conditions. Of significant importance are the three-dimensional reservoir orientation, reservoir continuity, and internal reservoir structure. These events may have either a positive or negative effect on the coal reservoir. Faulting and folding events may cause shearing (structural damage) to the coal reservoir and reduce permeability. However, faulting may system Permian Pennsylvanian series Lower Permian Upper Pennsylvanian group Dunkard (part) Monongahela Conemaugh (part) sandstone limestone shale and siltstone thickness (in feet) generalized lithologies shale siltstone claystone Fig. 5. Generalized stratigraphic column of the Upper Pennsylvanian Monongahela Group showing seven major coal beds within a 100 m thick stratigraphic section (Tewalt et al., 2001). selected units Waynesburg coal bed Little Waynesburg coal bed Uniontown coal bed Benwood limestone (informal) Sewickley coal bed Fishpot coal bed Redstone coal bed Pittsburgh sandstone (informal) Pittsburgh coal bed coal coal or coal and shale VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 65

10 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES also cause fracturing swarms within the reservoir, which will enhance permeability. Natural fractures in coal Natural fractures (cleat) provide the primary flow paths within the coal reservoir; therefore, successful production wells must establish connection with this natural fracture system. Cleats generally occur at right angles and are perpendicular to bedding (Fig. 6). The primary fracture direction is normally referred to as the face cleat and the secondary fracture direction is normally referred to as the butt cleat. The primary difference between the face and butt cleats is the continuity of the fracture system, with the face cleats tending to be more continuous than the butt cleats. The origin of cleating in coal is most often linked to the coalification process, where the processes of dehydration and devolatilization of the organic material occur in the confined, stressed depositional/burial system. Cleating in coal may range in spacing from 1-2 mm to several centimetres. Cleating in coal is generally related to coal rank (higher rank gives close spacing), vitrinite content (higher vitrinite content results in close spacing), mineral matter content (high mineral matter content implies wide spacing), and tectonic activity of the reservoir. In-situ cleat aperture widths vary from about mm to 0.1 mm and can sometimes be filled by calcite, gypsum, or pyrite minerals (Close, 1993). It should be noted that, in addition to the primary fractures or cleats, coals may also have secondary natural fractures caused by tectonic activity and post-cleating structural events. The identification and measurement of cleating in coals is accomplished either by direct measurement using coal samples (outcrop or core samples) or by measurement of the coal seam flow characteristics (pressure transient testing). Laboratory testing and field observations indicate that cleat permeability decreases during initial gas production due to cleat aperture closing as a function of reduced reservoir pressure (stress dependent permeability). Conversely, the cleat apertures may widen due to the coal matrix shrinking as the gas diffuses and flows out of the coal matrix, increasing permeability and gas rates. This phenomenon has been observed in several wells in the San Juan, USA, that have been producing gas for over ten years (Palmer and Mansoori, 1998). Also, like conventional oil and gas reservoirs, coalbed methane reservoirs exhibit changes in relative permeability as fluid saturations change during production. butt cleat Fig. 6. Orthogonal cleat (plan view) developed in the Waynesburg coal, Northern Appalachian, Greene County, Pennsylvania, USA (courtesy of the Author). 10 cm face cleat Gas content of coal Gas generation in coal occurs as a result of the thermal maturation process (see again Fig. 4). Gas is generated in coals from the sub-bituminous through anthracite coal ranks. Much more gas is generated in the coalification process than can be stored in the coal (up to 8-10 times). The composition of the generated gas is primarily methane, but includes carbon dioxide, nitrogen, and higher-end hydrocarbons. Heavier hydrocarbons are relatively uncommon, due to a lack of hydrogen (when compared to carbon) in the coal. Gas from lower ranked coals often has a higher carbon dioxide component; also, igneous intrusions through the coal reservoir can lead to higher carbon dioxide concentrations. In addition to gas generated during thermal maturation, biogenic activity may also contribute to gas in coals. Originally, biogenic activity was thought to end at the end of the peat cycle. However, more recent evidence suggests that microbial activity may also occur at later stages and in higher rank coals. This activity is thought to exist in and near outcrop areas (about 8 km from crop line), where fresh water may actively recharge into the coal reservoir (Rice, 1993). The ability of coal to store gas is dependent upon coal rank (thermal maturity), moisture, and ash content in the coal, the maceral makeup of the coal, and the geologic history of the coal reservoir. Because in-situ gas content is affected by these numerous parametres, the actual gas content in any particular coal reservoir can only be determined by direct measurement. This is generally accomplished by measuring the quantity 66 ENCYCLOPAEDIA OF HYDROCARBONS

11 NON-CONVENTIONAL GAS Fig. 7. Sorptive capacity of coal as described by the Langmuir isotherm for various coal rank (Anderson et al., 2003). adsorbed gas content (sft 3 /t; dry, ash-free) 1,200 1, anthracite medium volatile bituminous high volatile bituminous A high volatile bituminous B ,000 pressure (psia) of gas desorbed from coal core or cutting samples from coalbed methane wells. This method provides a direct measurement of the volume of gas contained in the coal at in-situ reservoir conditions. Gas storage in coal While gas content measurements determine the quantity of gas contained in the coal at reservoir conditions, it is also important for reservoir evaluation purposes to understand how gas is stored in the coal. The capacity of the coal matrix to store gas as a function of pressure is described by the Langmuir sorption isotherm (Fig. 7). This storage mechanism gives coal reservoirs their unique characteristic: the ability to store large volumes of gas at relatively low reservoir pressure. The sorption process is physical, involving weak intermolecular attraction due to van der Waals forces (Yee et al., 1993). Large volumes of gas can be stored because the internal surface area of the micro-porosity in coal is very large, ranging from less than 50 to over 275 m 2 /g of coal (Crosdale et al., 1998). Comparing the gas sorptive capacity of coal to that of conventional sandstone (Fig. 8), it can be seen that at a relatively low reservoir pressure (6.9 MPa), coal can store 4 to 6 times the volume of gas stored in a medium porosity sandstone. The maximum sorbed gas content of coal at a specified pressure is defined by the following equation, modified from Langmuir (1916): C g (V L P)/(P L + P) where C g is the matrix gas concentration (m 3 /t), V L is the Langmuir volume (m 3 /t), P L is the Langmuir pressure (MPa), P is the reservoir pressure in fracture system (MPa). The Langmuir volume is the theoretical maximum volume of gas a coal can adsorb onto its surface area at infinite pressure. This would represent a continuous monolayer of methane molecules over the entire internal surface of the coal. The Langmuir pressure is the pressure at Fig. 8. Comparison of the volume of gas stored in coal as sorbed gas versus that stored in a conventional sandstone reservoir at various sandstone porosity (Anderson et al., 2003). gas content (sft 3 /t; coal equivalent) coal coal isotherm 8% porosity to gas 6% porosity to gas 4% porosity to gas sandstones ,000 1,500 2,000 2,500 3,000 3,500 4,000 4, 500 pore pressure (psia) VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 67

12 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES which the storage capacity of a coal is equal to 1/2 the Langmuir volume. Coal sorption isotherms are determined by laboratory testing of crushed coal samples, with moisture content and temperature closely controlled. The sorption isotherm test results in the relationship between pressure and adsorbed gas content in the reservoir at static temperature and moisture conditions. In some reservoir settings, coal seam gas contents are less than the amount of gas a coal is capable of storing. The coals are therefore considered undersaturated with gas. 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 increase 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 reduced below the saturation pressure, resulting in a longer period to achieve peak gas rates. Gas transport mechanisms in coal Coals are fractured reservoirs, including a matrix and a fracture system. The matrix system is the low permeability organic portion of the reservoir and provides the primary storage for gas. The fracture system in the reservoir is low porosity, relatively high permeability, and provides the primary storage for produced water within the reservoir. The major mechanisms which control gas and water flow in the reservoir include diffusion in the coal matrix, desorption of gas from the coal matrix into the fracture system, and Darcy flow within the coal fracture system (Fig. 9). The major storage mechanisms within coal include adsorption of gas within the matrix system (the major gas source for coals) and free porosity, which occurs primarily in the fracture system. Adsorption in the matrix is the primary storage mechanism for gas, and the fracture (cleat) porosity is the major source of storage of water in the reservoir. The Langmuir isotherm equation describes the volume of gas stored in the coal matrix system as a function of reservoir pressure. The porosity of the fracture systems within the coals is generally low, ranging from less than 0.5% to 2-4%. As already said, fluid transport mechanisms in coal include diffusion of gas in the coal matrix, desorption of gas from the matrix to fractures, and Darcy flow within the fracture system. Gas moves through the coal matrix via a molecular diffusion process as described by Fick s law (Zuber, 1996). This process is a concentration gradient driven process, which occurs because the gas cleat methane gas water coal matrix reduce methane partial pressure in cleat. reduce cleat pressure by producing water. methane desorbs from matrix and diffuses to cleat. methane and water flow to wellbore nitrogen gas carbon dioxide gas Fig. 9. Gas flow mechanisms in coal (Puri and Yee, 1990; Dallegge and Barker, 2000). wellbore, master cleat, or fault concentration within the matrix is lower at the matrix-cleat boundary than within the centre of the matrix elements. Darcy s law generally describes flow within the coal fracture system. The relative permeability concept is used to describe simultaneous flow of gas and water within the fracture system as a function of saturation. Coalbed methane production characteristics and dewatering cycle Coalbeds are complex reservoirs, normally containing both gas and water in the fracture system and gas sorbed on the coal surface in the coal matrix system. Because of the complex reservoir mechanisms that control gas and water flow in coals, production from coalbed methane wells tends to have complex characteristics related to these mechanisms. Fig. 10 shows a typical production profile (for gas and water) in a coalbed methane well. Coalbed methane water production is normally characterized by a declining trend. The gas production cycle for coalbed methane wells often consists of a trend of inclining initial production, reaching at a peak at some point, and then a declining production trend. This profile is normally exhibited by coalbed methane wells (within a pattern of producing wells) that are bounded in some manner, either by interference due to offset producing wells, or by natural boundaries within the reservoirs, such as faulting. The inclining trend in gas production exhibited by coalbed methane wells is related to the changing relative permeability to gas within the 68 ENCYCLOPAEDIA OF HYDROCARBONS

13 NON-CONVENTIONAL GAS production rate stage I stage II well dewatered Fig. 10. Typical water-saturated coalbed methane well performance profile (Anderson et al., 2003). stage III water gas production time reservoir. In many coal seams the natural fracture system is initially saturated with water. As water is produced from the natural fracture system, the reservoir pressure is reduced and gas desorbs from the coal and diffuses to the fracture system. As the gas saturation in the fracture system in the reservoir steadily increases, the relative permeability to gas in the reservoir increases. This causes the inclining gas production trend. Conversely, as the water saturation in the fracture system declines, the water production declines. Once the relative permeability to gas within the reservoir stabilizes (the reservoir is said to be dewatered at this point in time), the gas production peaks and begins to decline. In coal reservoirs which are dry (no mobile water is in the fracture systems), a continuous declining trend in gas production is observed since the desorption rate is decreasing throughout the drainage area. Because the gas production of coal reservoirs is dependent upon the dewatering of the reservoir and the ability to increase gas relative permeability in the reservoir, the characteristic production profile of any given coalbed methane well is dependent upon those factors that affect the ability of a pattern of wells to dewater the reservoir. These factors include well spacing, reservoir permeability, porosity of the fracture system, initial gas and water saturations within the reservoir, and the quantity of adsorbed gas. Variability in well production Examination of production from coalbed methane producing fields indicates that there is a high degree of variability in well production from well to well within producing patterns. This variability is not attributed to large variations in well spacing or gas in place in the coal reservoir. The primary contributing factor to production variability seems to be variations in reservoir permeability. These variations are due to heterogeneities in the natural fracture system within the reservoir (number of cleats and natural fractures and their aperture width). Permeability in coals has also been shown to be highly stress-sensitive. Field studies conducted in the Black Warrior, USA, have indicated that variations in reservoir stress can lead to order of magnitude changes in permeability from area to area within producing fields (Sparks et al., 1993). Examination of numerous producing wells across extensively developed coalbed methane plays indicates that order of magnitude variations in well performance is typical. Fig. 11 shows the cumulative gas production from 23 producing coalbed methane wells in a field in the Black Warrior, USA. All of the wells were drilled and completed nearly identically, and there were only slight well-to-well variations in coal thickness, gas content, and other reservoir parameters. The wells were also drilled on the same small spacing: 304 m between wells on a square grid. Hence, only variation in reservoir permeability can explain the large variation in well production across this field. Extensive studies of coalbed methane production data from highly developed coalbed methane plays have also indicated that a high degree of variability exists across producing plays, and for smaller areas (down to field scale) within these producing plays. The variations in production within the San Juan, Black Warrior, and Central Appalachian s are shown in Fig. 12, which is a probability distribution cumulative gas production (Msft 3 ) 175, , , ,000 75,000 50,000 25, time (months) Fig. 11. Local well performance variations in a group of 23 similar wells in the Black Warrior, USA, due to local changes in natural fracture permeability (Anderson et al, 2003). VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 69

14 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES Fig. 12. Probability distribution of actual five-year cumulative production from coalbed methane wells in the San Juan, Black Warrior, and Central Appalachian basins, USA (Weida et al., 2005). five-year cumulative gas production (Msft 3 ) 10,000,000 1,000, ,000 San Juan Black Warrior Central Appalachian 10, probability (%) of actual five-year cumulative production. This high degree of variability within the coal reservoirs has significant implications for evaluating prospective coalbed methane areas (Weida et al., 2005). Shale as a reservoir Shale composition Shale is the most commonly occurring type of sedimentary rock, being typically deposited on river floodplains and on the bottoms of lakes, lagoons, and oceans. It is formed by the consolidation of fine-grained detrital rock fragments or mineral particles, and typically contains 50% silt, 35% clay, and 15% chemical or authigenic materials. Silt and clay are differentiated from one another on the basis of their particle diameters. Silt consists of rock or mineral particles having diameters between 1/256 and 1/16 mm whereas clay consists of rock or mineral particles having a diameter less than 1/256 mm. Shale has a finely laminated, fissile structure, and readily breaks into thin, parallel layers. Mudstone is compositionally similar to shale, but lacks a finely laminated or fissile structure and commonly disintegrates upon exposure to water (Bates and Jackson, 1980). The color of shale ranges from green and gray to black, depending on the organic matter content. The higher the organic matter content, the darker the color of the shale. Black shale (high organic content) is a common source rock for natural gas and crude oil (Hill and Nelson, 2000). Producing gas shale reservoirs in the USA demonstrate a wide range in depositional history and composition. The Antrim, Ohio, and New Albany Shale of the eastern and central USA are all part of an extensive, organic-rich shale depositional system of middle to upper Devonian age (Curtis, 2002). However, while the deposition of these silica-rich shale formations was time-equivalent, the compositional characteristics of these three formations differ. As shown in Table 4, the Antrim Shale is characterized by high organic content (up to 24%) whereas the organic content of the Ohio Shale rarely exceeds 5%. Variations in anoxic conditions within sub-basins of this depositional system probably accounted for the variation in preserved organic mass. Similar variations in organic content (as represented typically by Type II or Type III kerogen) are observed in the Barnett (4-8%) and Lewis ( %) gas shale reservoirs. Shale gas generation and storage Gas in shale gas systems is of thermogenic or biogenic origin. Thermogenic gas is derived from the transformation of the kerogen via thermal maturation, typical of conventional petroleum systems. Jarvie et al. (2001) identified 13 other formations (Ordovician to Pennsylvanian in age) that were sourced from the oil generated in the Barnett Shale of the western Fort Worth, Texas, USA. Subsequent cracking of this oil may have contributed to the gas currently in place (and produced) from this shale. Similar thermogenic gas generation occurred in all of the other productive USA gas shale systems (Antrim, Ohio, New Albany, and Lewis Shale). However, in the case of the Antrim Shale it appears that the thermogenic gas has largely migrated from the system. In this shale reservoir, the gas currently in place is probably only tens of thousands of years old, having been produced as recent biogenic gas (Martini et al., 1998). Methanogenic bacteria, carried into the organic shale via post-pleistocene aquifer recharge, 70 ENCYCLOPAEDIA OF HYDROCARBONS

15 NON-CONVENTIONAL GAS generated gas by consuming the kerogen in the Antrim Shale around the margin of the Michigan. In this area of the basin, produced gas is a mixture of recent biogenic and geologically older thermogenic gas. Storage of gas in shale gas systems is somewhat similar to that encountered in coal, discussed previously. Gas is stored on the kerogen as sorbed gas (described by the Langmuir isotherm), within the intergranular porosity as free gas, within the natural fracture system as free gas, and within the kerogen (and bitumen, in thermally more mature shale) as dissolved gas. Trapping mechanisms are subtle, with gas saturations generally covering large areas (Roen, 1993). Originally, based on production results from the Ohio and Antrim Shale reservoirs, it was postulated that most of the gas in shale reservoirs was sorbed gas. This gas mimics the storage mechanism described for coal, and sorption isotherms of the organic component in shale gas reservoirs are routinely measured. However, recent studies have shown that the proportion of gas stored in shale by the two dominant methods, sorbed versus free gas, can vary significantly with reservoir conditions. The Antrim Shale of the Michigan, USA, is a shallow, cool reservoir (24 C) with high organic content (see again Table 4). Comparison of the volume of sorbed gas versus free gas in the reservoir (at a reservoir pressure of 400 psia, or 2.8 MPa) shows that 74% of the gas is sorbed onto the organics while 26% is free gas in the intergranular and fracture porosity (Fig. 13). By comparison, the Barnett Shale of the Fort Worth, USA, is a deep, higher temperature/higher pressure reservoir with relatively low total organic content. At reservoir conditions (4,000 psia, or 27.6 MPa, and 90 C) 63% is free gas while 37% is sorbed (Fig. 14). As exploration and development of gas shale reservoirs occur throughout the world, a similar range in reservoir types is expected, ranging from sorbed-gas dominant reservoirs to free-gas dominant reservoirs. Gas transport mechanisms in shale Similar to coal in many respects, the mechanisms of gas transport and flow in gas shale reservoirs is controlled by factors other than just conventional Darcy flow. A dual porosity system exists in most productive gas shale reservoirs: primary microporosity in the shale matrix coupled with a secondary natural fracture porosity. Natural fractures, formed either due to tectonic forces or during hydrocarbon generation, vary in spacing from one metre to several metres and are often present in an orthogonal pattern perpendicular to bedding, with a dominant and subordinate set (Fig. 15). Matrix porosity is low, generally ranging from 1-10%; fracture porosity is very low, less than 1% (Zuber et al, 1994a; Frantz et al., 2005; Curtis, 2002). The fracture porosity may be filled with mobile water, up to 100% in some areas of the Antrim gas shale play area; other gas shale areas (e.g. Barnett Shale) have little or no mobile water associated with the fracture porosity. Matrix permeability is extremely low, ranging from to 10 8 md. Gas flow through this low permeability shale matrix has been compared to the diffusion of gas through coal matrix. Fracture permeability varies widely, from 5 md in the shallow Antrim Shale to md in the Barnett and Lewis Shale. Flow in shale gas reservoirs is, therefore, a combination of desorption of gas from the gas content (sft 3 ) total gas sorbed gas free gas pressure (psia) gas content (sft 3 ) total gas free gas sorbed gas ,000 2,000 3,000 4,000 5,000 pressure (psia) Fig. 13. Comparison of sorbed and free gas in the Antrim Shale, Michigan, Michigan, USA (Zuber et al., 1994a). Fig. 14. Comparison of sorbed and free gas in the Barnett Shale, Fort Worth, Texas, USA (Frantz et al., 2005). VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 71

16 HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES primary fracture wells typically have low production rates but may produce for over 40 years (Boswell, 1996). Finally, Type 3 production reflects the reservoir response observed in the deep, high-pressure Barnett Shale of the Fort Worth (northeastern Texas, USA). Production from these shale reservoirs is dominated by flow from the micro-porosity system, with sorbed gas contributing less than 10% of the total gas produced (Frantz et al., 2005) secondary fracture Fig. 15. Natural fractures in the New Albany Shale, Illinois, Indiana, USA (courtesy of the Author). organics; Darcy flow (and/or diffusion) of free gas through the low permeability, microporous shale matrix to the natural fracture system; and Darcy flow of gas and water (usually) through the natural fracture system. Shale gas production characteristics Production of gas from shale gas reservoirs varies significantly from play to play and within specific plays (as is the case for coalbed methane production). Three types of production have been identified: Type 1 co-production of gas and water in sorption-dominated reservoirs; Type 2 production of gas in sorbed gas-dominated reservoirs; and Type 3 production of gas in free-gas dominated reservoirs. Type 1 production is reflected in the production performance of wells in the Antrim Shale of the Michigan (Michigan, USA) and the New Albany Shale of the Illinois (Illinois, Indiana, and Kentucky, USA). General production performance is similar to that observed in water-saturated coalbed methane wells, in that the gas production follows a trend of inclining initial production, reaching a peak at some point, and then a declining production trend, while water production is normally characterized by a declining trend (Zuber et al., 1994a). Type 2 production, characterized by the Ohio Shale of the Appalachian (especially in the area comprising southern West Virginia, western Virginia, and eastern Kentucky, USA), initially produces free gas associated with the natural fracture system and the micro-porosity. With the pressure reduction associated with the free gas production, the sorbed gas desorbs and becomes a source of free gas to the system. These Drilling, completion, and production Until recently, most drilling activity was confined to vertical wells targeting the relatively shallow coal reservoirs 150 to 1,000 m deep, and the more moderate depth shale reservoirs 1,000 to over 2,500 m deep. Shallow coal gas wells are commonly drilled using under-balanced rotary-percussion drilling methods (Hollub and Schafer, 1992). This technique allows for rapid drilling rates (up to 15 m/h) and minimal damage to the natural fractures in the coal reservoir. Alternatively, conventional rotary drilling with light-weight mud systems (balanced to under-balanced) are used when higher reservoir pressures, excessive water flows, and wellbore stability problems are expected. Similarly, shallower shale gas wells (for example, those in the upper Devonian Ohio Shale in the Big Sandy Field of eastern Kentucky, USA) are also drilled using under-balanced rotary-percussion drilling methods, while the deeper Barnett Shale wells in the Fort Worth, northeastern Texas, USA, rely upon both rotary-percussion and conventional rotary with light mud systems. With recent improvement in downhole technology and the associated reduction in costs, horizontal drilling is becoming an attractive alternative in certain reservoir settings to vertical wells in both coal and gas shale reservoirs. The first large-scale application of horizontal wells in coal occurred in the mid-1990s in the Hartshorne coal of the Arkoma in Oklahoma, USA (Rutter, 2002). In this setting, a single horizontal wellbore is typically drilled. Subsequent to the success of these wells, a multi-lateral technique was developed for mine degasification and natural gas production at the Pinnacle Mine in the Central Appalachian, West Virginia, USA (von Schoenfeldt et al., 2004). As shown in Fig. 16, a vertical well is initially drilled. Subsequent to this, a horizontal well is drilled to intersect the vertical well, and from this primary horizontal section, 72 ENCYCLOPAEDIA OF HYDROCARBONS

17 NON-CONVENTIONAL GAS multiple laterals are drilled in a pinnate pattern. The horizontal laterals are typically completed openhole, thus exposing the extensive, naturally fractured coal to the entire wellbore. However, wellbore stability and artificial lift (dewatering) problems have been reported, which must be considered in the application of this technology to other coal areas. Reported recovery of these multi-lateral wells is 80-90% of the original gas in place within 24 to 48 months, which leads to significant economic benefits. Similar to the application in coal, the use of horizontal drilling methods in gas shale reservoirs (especially in the Barnett Shale) is rapidly expanding (Frantz et al., 2005). Beginning in 2003, a rapid change from vertical to horizontal wells in the Barnett Shale occurred, such that 60% of all new wells drilled into this shale formation are now horizontal. Unlike the horizontal wells in coal, these wells are typically cased, cemented, and hydraulically fractured, because the natural fracture system of this shale is poorly developed. The most common form of completion in coal and shale gas wells has been perforated casedhole with single- or multi-stage hydraulic fractures. Fracturing coal reservoirs effectively has been a subject of much debate for the last three decades. In the highly fractured, low modulus coal, complex fractures are often created (especially in the nearwellbore region) that lead to shorter half-lengths and high treating pressures over 22.6 kpa/m gradients (Palmer et al., 1993). Fluid inefficiencies due to leak-off into the fracture system, damage due to swelling of the coal in the presence of certain gel systems, and out-of-zone growth due to the relative thinness of the zones are only part of the complexities involved in fracturing coal seams. Although generalities may be dangerous, the industry is trending towards less damaging fluid systems and greater reliance on nitrified systems. The recent and rapid development of the coal reservoirs in the Powder River of Wyoming and Montana has led to the development of an alternative to the traditional hydraulic fracturing operation. The most widespread completion practice (in over 10,000 wells currently producing) has been the application of a non-damaging openhole completion followed by water infusion ( 0.8 m 3 /min) to help open the coal cleats and flush coal fines (DOE/NETL, 2003). Similarly, the fast development of the dry, shallow Horseshoe Canyon coals of the Alberta Plains region in Canada has led to an alternative stimulation technique. Because no water is produced from wells drilled into this coal formation, operators have been successful using nitrogen-only (no proppant) fracturing treatments (Gatens, 2004). Shale gas wells almost universally rely upon hydraulic fracturing to connect the natural fractures (less well developed than in coal) to the wellbore. Although a number of horizontal openhole wells have been attempted in the New Albany Shale of the Illinois, most horizontal shale gas wells are now completed using multiple stage treatments pumped along the length of the horizontal section. To reduce the effect of cement damage on the natural fracture system, innovative openhole and non-cemented casedhole approaches have been Fig. 16. Horizontal, multi-lateral pinnate wells for the production of coalbed methane (von Schoenfeldt et al., 2004). small coal seams coal bed small coal seams coal bed CDX drill site VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY 73