Coalbed Methane: Scientific, Environmental and Economic Evaluation

Coal seam gas exploration has had a long history in Queensland. While most people think that coal seam gas exploration is a relatively new industry in Queensland, exploration started in May 1976 with the granting of Authorities to Prospect 226P, 231P and 233P to Houston Oil & Minerals of Australia Inc. Since then over 200 wells have been drilled and nearly $200,000,000 has been spent exploring for and appraising coal seam gas. All this effort has resulted in the development of three areas for coal seam gas production; the Moura Mine, the Dawson Valley Project and Fairview with many more possible.

This paper is a modification of a paper published in the Queensland Government Mining Journal (January, 1998, p.30–34) and also draws extensively on the Government position paper ‘A new coal seam gas regime for Queensland’ published by the Department of Mines and Energy in November 1997. The assistance of Steven Scott in providing information for the overview section (including Figures 1&2) is also acknowledged.

The Fairview coal seam gasfield is located in central eastern Queensland, approximately 30km northeast of the town of Injune which is approximately 475km northwest of Brisbane (Figure 1). Fairview was discovered in August 1994 with the drilling of TPC Fairview 1. Since August 1994, 18 more wells have been drilled for a total of 14,455.93m with an average depth of 803.1m. The gasfield is covered by three granted Petroleum Leases (PLs) 90, 91 and 92 with eastern and southern extensions covered by two PL applications (PL 99 and 100). The five PLs and the surrounding Authority to Prospect (ATP) 526P are owned and operated by Tri-Star Petroleum Company.

This paper presents drilling, completion and stimulation costs for Australia and New Zealand coalbed methane (CBM) wells and compares them with reference international costs from the USA, Canada and China to deduce the local “premium factor” faced by the fledgling Australian and New Zealand CBM industry. CBM exploration and development economics in the Queensland fiscal environment are then analysed with a 100-well designed and costed prototype model. It is concluded that CBM economics are sub-marginal and costs must come down to make the industry attractive to potential investors. As well, investment tax credits and royalty “holidays” are investigated in the context of government policy. They are recommended as efficient fiscal tools to “kick start” a vibrant CBM industry, thereby achieving economies of scale and favourable social return.

The exploration of coalbed methane resources is underway in many countries throughout the world. The ability to accurately predict and/or estimate expected production from a prospective coalbed methane play is imperative for evaluating the potential for economic success of proposed developmental projects. However, to accurately predict coalbed methane production requires the use of a reservoir simulator and generally requires knowledge of numerous reservoir properties. It is usually difficult to reliably predict key reservoir properties based on the datasets which are available for exploratory-type coalbed projects. We have found that a probabilistic approach is useful for estimating the expected range of producibility for a prospective coalbed methane area, and for quantifying the risk associated with finding commercial production in prospective areas. The probabilistic approach provides a forecast of the expected distribution of reserves that would be expected to be realized from large-scale development of a particular area.This paper describes a probabilistic approach for evaluating prospective coalbed methane projects which combines (1) coalbed methane reservoir simulation to predict coalbed weIl production, and (2) Monte Carlo simulation analysis to determine the distribution of expected reserves for a prospective area. This methodology allows us to predict, in a probabilistic manner, the expected average productivity and distribution of reserves for a prospective coalbed methane project. This paper explains in detail the approach used and presents a case study to show how this method is applied to a developmental coalbed methane project. The methodology presented in this paper can be applied to any new or emerging coalbed methane development project to assist in quantification of the economic viability of the project. It also provides a basis for risking investments in prospectivecoalbed methane projects.

A basin-scale coalbed methane producibility and exploration model has been developed on the basis of research performed in the San Juan, Sand Wash, Greater Green Rivers, and Piceance Basins of the Rocky Mountain Foreland and reconnaissance studies of several other producing and prospective coal basins in the United States and worldwide. The producibility model indicates that depositional setting and coal distribution, coal rank, gas content, permeability, hydrodynamics, and tectonic/structural setting are controls critical to coalbed methane production. However, knowledge of a basin’s geologic and hydrologic characteristics will not facilitate conclusions about coalbed methane producibility because it is the interplay among geologic and hydrologic controls on production and their spatial relation that govern producibility. High producibility requires that the geologic and hydrologic controls be synergistically combined. That synergism is absent in the marginally producing, hydrocarbon-overpressured Piceance Basin. As predicted from the coalbed methane producibility model, significant coalbed methane production (greater than 1 MMcf/d [28 Mm3/d]) may be precluded in many parts of the hydrocarbon-overpressured Piceance Basin by the absence of coalbed reservoir continuity, high permeability, and dynamic groundwater flow. The best potential for coalbed methane production may lie in conventional and compartmentalized traps basinward of where outcrop and subsurface coals are in good reservoir and hydraulic communication and/or in areas of vertical flow potential and fracture-enhanced permeability. In the low-permeability, hydrocarbon-overpressured Piceance Basin, exploration and development of migrated conventionally and hydrodynamically trapped gases, in-situ-generated secondary biogenic gases, and solution gases will be required to achieve high coalbed methane production.

Microbially enhanced coalbed methane (MECoM) imitates and enhances the natural process of secondary biogenic gas generation in coal beds that occurs in coal basins worldwide. MECoM involves the introduction of anaerobic bacterial consortia, which consists of hydrolyzers, acetogens and methanogens, and/or nutrients into coalbed methane wells. Coalbed methane production may increase through generation of additional methane, removal of pore-plugging coal waxes, and permeability enhancement as cleat-aperture size increases during biogasification. The amount of coal gas potentially generated by MECoM is large. If only one-hundredth of 1% (1/10,000) of U.S. (lower 48) coal resources were converted into methane using MECoM, gas resources would increase by 23 Tcf, or approximately 16% of current lower 48 nonassociated reserves. However, coal surface area and biogasification reaction rates in the subsurface may potentially limit gas generation, indicating that permeability enhancement may be the most significant benefit of MECoM. Additional research, including microbial sampling of deeply buried bituminous coals to identify genetically unique bacterial consortia, is required to fully evaluate MECoM and determine if the process will improve coalbed methane producibility. Successful implementation of MECoM requires an integrated approach towards understanding the geologic, hydrologic, organic and inorganic geochemistry, microbiological, and engineering factors that may limit MECoM in the subsurface. If economically feasible, MECoM can generate methane in coal beds that currently have limited coalbed methane potential, and thereby provide cheap, environmentally clean energy for many parts of the world.

Coalbed methane exploration in the Western Canada Sedimentary Basin has focused mainly on the foothills and mountain regions of Alberta and British Columbia because of the numerous thick coal seams of suitable rank for thermogenic gas generation. Cumulative coal thicknesses in excess of 50 m and gas contents ranging from 12 to 22 cc/g yield in situ resources estimates of more than 1.2 x109 m3 (42x109 Bcf) per sq. km. These regions are structurally complex and present unique challenges in defining and exploring for the optimum CBM exploration target.In order to delineate potential reservoir traps, it is necessary to understand the style of deformation and the main structural features where permeability enhancement may occur. The axial regions of anticlines and synclines appear to have the greatest potential. Here, a tensional rather than compressional stress regime exists and the natural fracture system of the coal, (cleating) could be enhanced, resulting in better reservoir permeability. In anticlines the coal gas is trapped in the crest of the structure, where “free” or easily desorbed gas lies in the enhanced natural fracture system, above what would be traditionally defined as the gas/water contact. In synclinal structures, the overpressuring of the reservoir from the adjacent structural limbs may lead to enhanced gas storage within the open fracture system.In addition to structural complexity, topography and local hydrogeology influence the depth of the reservoir and subsequent reservoir pressure and gas retention within the coal seam(s). Gas desorption experiments completed in the Mist Mountain Formation of southeast British Columbia have demonstrated that in most cases, coals must lie below the regional water table, or be a sufficient distance from subcrop, to ensure that the adsorbed methane is retained within the seam. In synclinal structures, the dipping limbs can provide the hydrological recharge and hydrostatic head to allow overpressured reservoir conditions to exist in the axis of the fold. The regional migration of gas downdip via the coal seam aquifer can also result in the formation of biogenic methane that may enhance the resource potential.

Since 1994, North China Petroleum Bureau has cooperated with Lowell Petroleum N.L to exploit coalbed methane in the Liulin Permit which is 218 square kilometers in area. The Permit is structurally situated in the southern limb of the Lishi structural nose which is in the middle of the eastern margin of Ordos Basin. Main coal seams are Numbers 4 and 5 of the Shanxi Formation, Lower Permian and Number 8 of the Taiyuan Formation, Upper Carboniferous.Three wells have been completed and operations of coring, gas content determination, geophysical logging and well testing have been performed. The exploration results have proved that Seam 4, 5 and 8 are the main potential seams of the Permit. In the eastern part of the Permit, three target seams have similar thickness of 3 m to 5 m, and the formation pressure is relatively low. In the west part of the Permit, Seam 8 is dominant among all seams with thickness of 8–10 m, and the formation pressure is 1.2 Mpa higher than normal pressure. The gas content of the Permit is high and varies from 10 to 15 m3/ton. Well testing and reservoir simulation of Seam 8 yield a rather high permeability, which is comparable to one of the main production seams in the San Juan Basin. On the whole, the reservoir characters of the Permit show that Liulin Permit possesses high producibility.Based on exploration results, coalbed methane resources of Liulin Permit was calculated and the value is 24.26 billion m3.

Through centuries coalbed methane (CBM) was only treated as a hazard for coal mining operations. Fortunately, this point of view has changed and now the methane is also perceived as a valuable source of energy, if captured and utilized, or as an impedence for the Earth’s climate, if released to the atmosphere. These three faces of CBM force mining engineers, geologists and environmental officers to assess the amounts of methane captured in coal, available for recovery and capable for venting to the air. But anybody who wants to make any reliable assessment of CBM resources or describe rules the amount of gas release from coal depends on needs to take into account a lot of gassy characteristics of coal.

Products from various temperatures and heating rates of vitrinite and extractable bitumen from coals of different rank were studied by pyrolysis gas chromatography — mass spectrometry (py-gc-ms) and flash pyrolysis, and compared to ‘naturally’ matured Bowen basin coals. Generation temperatures and quantities of hydrocarbon species from vitrinite and bitumen were shown to be dependant on initial rank of the coal as well, as H/C of vitrinite. A significant amount of bitumen formation characterises rapid heating of vitrinite as established by py-gc-ms, as well as microscopy of residues. Similarly significant bitumen input is noted for Bowen Basin coals, supporting maturation by rapid heating. Using flash pyrolysis, bitumen has been confirmed to be a major source of methane. The light oil during pyrolysis is readily expelled from the coal leaving behind bitumen in vitrinite micro-cleats and char (inertinite) cavities. The ratio of solvent extractable to non-extractable bitumen may be used as indicator of methane generation in these coals.Comparison of open system pyrolysis with confined pyrolysis under varied pressure showed accelaration of organic maturation at presures up to 250 bar, and retardation at higher pressure. Very low pressure of 2–3 bar showed peak bitumen generation at the same tempertaure as in open system. On the other hand, light oil and methane peaked at higher temperature with significantly higher yields that in open system due to bitumen cracking.TEM observations of vitrinite and inertinite (chars) in the coals studied, as well as their residues from pyrolysis experiments highlight differences in microporosity between the two macerals. Microporosity in chars explains diffusion of hydrocarbons through char walls as well as storage of bitumen and gases within the large internal volume of closely spaced micro and nano-pores.The conversion of vitrinite to char has been followed experimentally by heating vitrinite from 300 to 800 degrees C.The gradual development of mosaic texture was recorded by TEM in residues from a range of temperatures. A 3- dimensional reconstruction of mosaic textures facilitates understanding of processes associated with hydrocarbon adsorption and diffusion.

Extensive studies have been carried out on the genetic chemical reaction of coals by many famous researchers. Some of the previous studies are as follows: H. Potonei[1] initiated the study of coalification. F. Fischer, et. al.[2] supported the origin of lignin theory. F. Bergins[3], Erasmus[4] and R. V. Wheeler, et. al.[5] supported the cellulose theory. Tropsch[6], Berl and Schmit[7], Horn and Sustsmann[8] and Fuch and Horn[9] developed the systematic investigation on artificial coalification. Berl and Schmidt[10] experiments on coalification were checked and confirmed by Schuhmacher and Van Krevelen[11]. Two researches on this topic were studied in our country. W. Funasaka and C. Yokokawa[12] discussed the relationship between the genetic origin of coal and its chemical properties at atmospheric conditions by artificial coalification experiments. T. Yamazaki and R. Abe[13] reported the experimental results of the gas evolutions from raw coal during the artificial coalification process following the procedure presented by C. Yakakawa.

Undersaturation of coal with respect to gas is a major economic risk in the coal bed gas exploration. This communication addresses the following questions: (1) How much thermogenic gas is formed from coals at different levels of maturity? (2)What is the minimum rank at which a given coal has generated sufficient thermogenic gas to be saturated at reservoir pressure and temperature conditions? (3) What is the effect of uplift on sorption equilibria? (4) What is the role of biogenic gas for coal bed gas saturation? and (5) what is the magnitude of the diffusive gas loss? Results and conclusions of this work do not include coals which are within a conventional gas reservoir. Kinetic compositional modeling results, calibrated with coal-specific data, show that the vitrinite reflectance (R_o) level at which a coal has generated sufficient thermogenic gas to be saturated at reservoir pressure-temperature (PT) conditions varies from less than 0.60% to more than 1.4%. The coals rich in linear aliphatic polymers (LAP) become saturated by self-generated thermogenic gas at reflectance levels below 0.75%. The self-generated gas from coals which are dominated by “humic” aromatic polymers (HAP) does not reach the saturation sorption level, below a vitrinite reflectance of around 0.9–1.2%. The vitrinite-rich coals of Jurassic, Cretaceous and Tertiary age are more likely to have an appreciable contribution from LAP material, than are the coals of Palaeozoic age. Coals which are dominated by semi-inertinites may not become saturated by self-generated gas even at very high ranks (R_o>1.4%). The importance of biogenic gas for saturating a severely undersatu-rated coal is questionable. Very strong biogenic signature is observed in strongly undersaturated coals, which have lost significant amounts of thermogenic gas. Evaluation of sorption (ad- & ab-sorption) and desorption experiments and modeling results indicates that coal can sorb larger quantities of gas in deep basin positions, and those which have generated enough gas to do so, will des-orb gas during uplift. A critical factor which can lead to undersaturation, of an initially saturated coal bed, is diffusive gas loss. The effect of diffusive losses can be significant and should be accounted for in the risk assessment.

Coal seams of the Sydney Basin contain large volumes of gas, mainly methane (CH₄) and carbon dioxide (CO₂) with subordinate amounts of heavier hydrocarbons (C₂₊). The desorbable gas content of the Sydney Basin coals ranges up to about 20 m3/t, and its abundance is mainly related to depth and geological structure.Gas isotope data indicate that most of the hydrocarbons presently occurring within the coal measures sequence was generated during coalification between the Permian and Late Cretaceous or as a result of post-Cretaceous bacterial activity, or both. Most of the CO₂ was introduced into the sequence in association with intermittent igneous activity between the Triassic and the Tertiary.In the Sydney Basin coals, the CH₄ content of the gas ranges up to 100% whereas the C₂₊ ranges up to 12% (by volume). A systematic variation in the various hydrocarbon components with depth is evident in most parts of the basin. Hydrocarbons, at depths shallower than about 600 m and close to the basin margins are essentially dry (depleted C₂₊). At greater depth, however, the quantity of C₂₊ in the gas increases regularly with depth up to 12% at about 1200 m. Carbon isotope data for the southern part of the basin show that CH₄ becomes isotopically light towards shallower parts and close to the margins of the basin.Two different hypotheses are proposed to explain these variations in gas composition. One hypothesis emphasises the role of gas fractionation during migration due to variations in molecular diffusivity and solubility of the components. In this context, lighter and more rapidly diffusing components such as CH, can migrate readily to shallower depths and as a result the CH₄/C₂₊ ratio is expected to increase towards the upper part of the sequence.However, in the Sydney Basin, such preferential migration cannot totally account for the abrupt scarcity of C„ at depths less than about 600 m. The lack of C₂₊ gases at < 500 m indicates that they may have been eliminated by a process which is confined to shallow depths. At these depths CH, is isotopically light (δ13C values range generally between –75‰ and –50‰ PDB) signifying a strong biogenic influence. Worldwide experience shows that biogenically formed gases are generally dry. Therefore, both the molecular and carbon isotope compositions indicate that in the Sydney Basin the lack of C₂₊ at shallow depths is probably due to bacterial alteration of the gases.

Coal seam gases collected from Bowen Basin cores have moderately negative methane carbon isotope compositions (−51 ± 9 per mil) which overlap the published range for Australian coal seam methane of −60 ± 11 per mil. No systematic relationship between coal rank and methane δ13C value is apparent. A thermogenic origin for methane has been assigned when its carbon isotope composition is heavier than −60 per mil, although biogenic methane generated in closed systems may have similar δ13C values from −60 to −40 per mil depending on the methanogenic pathway and the carbon isotope composition of the source. Subordinate inputs from biogenic methane could account for some of the isotopic variability of the desorbed methane; however, a good correlation between desorbed methane volumes and bitumen/pyrobitumen content suggests that much of the methane sorbed in the coal was produced by secondary cracking of bitumen.Bowen Basin methane δ13C values are typically some 20 to 30 per mil lighter than vitrinite and inertinite δ13C values. Carbon isotope compositions of vitrinites and inertinites in sub-bituminous coals become less negative with increasing rank as a result of the preferential loss of the lighter isotope of carbon during maturation. Vitrinite reflectance and maceral carbon isotope compositions often display an anomolous trend for coals in the high to medium volatile bituminous rank as a result of the presence of adsorbed isotopically light methane Thus, a sharp distinction in isotope systematics distinguishes coals that are within peak oil generation from those that are at or below the threshold of oil generation. Bitumen may show equal or higher concentrations within inertinite cell cavities as in vitrinite cleats and affect carbon isotope compositions of vitrinites and inertinites.Compositional data for desorbed coal seam gases from the Bowen Basin show that ethane and the other wet gases are a minor component. On the other hand, high concentrations of wet gases are produced during pyrolysis of coals. This discrepancy between the proportion of wet-gas components produced during pyrolysis and that observed in many naturally matured coals may be the result of preferential migration of wet gas components. Alternatively, the wet gas components may be thermally cracked to methane at higher maturation levels or diluted by additional methane produced by secondary cracking of bitumen.Previous vitrinite reflectance and clay mineral diagenesis studies indicate that thermal maturation of the Late Permian coals in the central and northern Bowen Basin occurred largely as a result of a short-lived hydrothermal event in the Late Triassic rather than during maximum burial in the Middle Triassic as previously thought. Textural relationships at a variety of scales and the observation that coals in proximity to Cretaceous intrusions are highly mineralised with carbonates and sulfides suggest several periods of hydrothermal activity. It is concluded, therefore, that thermal maturation of coal in the Bowen Basin to form oil and gas was caused predominantly by transient thermal and fluid flow events in the Mesozoic. High temperatures associated with transient hydrothermal events and the potential for secondary cracking of bitumen may provide an explanation for anomolous gas compositions and isotope systematics.

It is remarkable that the origins of the coal-associated gases in the Sydney and Bowen Basins should have been so generally and consistently misunderstood. These gases occur at depths to some 600 m, vary widely in composition and most commonly occur as mixtures of very dry methane with carbon dioxide in all proportions. The origins of these gases remain in doubt, although a thermal maturation mechanism was initially agreed. Up-lifting and erosion have resulted in the loss of the bulk of this early-formed wet thermogenic gas. It has been almost completely displaced by very dry methane and now remains as traces in seam-enclosing sandstones and in the deepest coal measures. A biogenic origin, largely via carbon dioxide reduction, is often assigned to gases of this type. However in these Basins higher temperatures associated with hydrothermal activity, and anomalies in the behaviour of carbon dioxide, appear likely to curtail biogenic activity and suggest alternative gas sources.

Kinetic data from the literature were used to predict formation rates and product yields of oil and gas at typical low-temperature conditions of coal maturation. The data indicate that gas formation rates from hydrocarbon thermolysis reactions are several orders of magnitude too low to have generated known reserves of coalbed gas. By contrast, acid-mineral-catalyzed cracking, transition-metalcatalyzed hydrogenolysis of liquid hydrocarbons, and transition-metal-catalyzed CO₂ hydrogenation form gas at sufficiently high rates in geologic time and at geologic conditions to account for formation of enormous reserves of coal-bed gas. Rates of gas production in these reactions are 5 to 10 orders of magnitude higher than those predicted from thermolysis. The gaseous product compositions for metal-catalyzed hydrogenolysis of hydrocarbon liquids and for CO₂ hydrogenation are nearly the same as those of natural gases, while those from thermal and catalytic cracking are vastly different. From chemical analysis of a pair of gas-producing and non-gas-producing coals it was found that significant, comparable amounts of iron are present. The available data are consistent with a model involving thermal and catalytic cracking of kerogen to oil followed by iron-metal-catalyzed hydrogenolysis of oil to natural gas; in CO₂-containing coal gases, natural gas may also be formed by iron-catalyzed CO₂ hydrogenation.

Five years and more of experience gained during coalbed methane exploration in Australia has pointed to the important role that the in-situ stress state has on coal seam permeability, and hence gas/water producability. Similar understanding is also emerging from other parts of the world. The aim of this contribution is to elaborate the context in which stress appears to influence coal seam permeability in Australia, and to investigate some of the mechanisms controlling the in-situ stress state in Australian coal basins. The paper, while generic, draws particularly on experience gained during exploration of the Glouscester Basin by Pacific Power.

Natural fractures provide most of the interconnected macroporosity in coal. Therefore, understanding the characteristics of these fractures and the associated mechanisms of formation is essential for effective coalbed methane exploration and field management. Natural fractures in coal can be divided into two general types: cleat and shear structures. Cleat has been studied for more than a century, yet the mechanisms of cleat formation remain poorly understood (see reviews by Close, 1993; Laubach et al.,1998). An important aspect of cleating is that systematic fracturing of coal is takes place in concert with devolatization and concomitant shrinkage of the coal matrix during thermal maturation (Ammosov and Eremin, 1960). Coal, furthermore, is a mechanically weak rock type that is subject to bedding-plane shear between more competent beds like shale, sandstone, and limestone. Yet, the significance of shear structures in coal has only begun to attract scientific interest (Hathaway and Gayer, 1996; Pashin, 1998).

Scanning electron microscopy (SEM), small angle neutron scattering (SANS) and small angle X-ray scattering (SAXS) were used to analyse pore space for a series of Bowen Basin coals ranked in the range VR=0.7% toVR =3.1%. The linear pore size range assessed in the small angle scattering (SAS) experiments was 1.3 nm to 200nm. Using fractal analysis of the SAS data we showed that for the lower rank coals (VR less than 1%) the pore-coal interface is rough in the entire pore size range. For coals with VR larger than 1%, the interface becomes smooth on scales larger than 100 nm, but remains rough at smaller scales. The degree of roughness is decreasing with increasing coal rank and for anthracites the interface becomes smooth in the entire scale range.These findings are quantified by the calculated values of the specific area of the internal pore-coal interface. Owing to the fractal character of the pore space for sizes above 10 nm, the specific surface area was obtained by an appropriate scaling procedure and depends on the size of measuring yardstick. For the particular case of coals used in this study, when measured with the 5 A (0.5 nm, atomic size) yardstick the specific area decreases from about 200 m2/g for low rank coals to 3 m2/g for anthracites. The corresponding sorption capacity for methane at saturation is calculated to decrease from about 40 mg/g to 0.5 mg/g of coal. For a 60 Å (large molecule size) yardstick these limits are 20 m2/g and 3 m2/g, respectively.Apart from the fractal micro-architecture at scales above 100 Å, an additional microstructural feature of the characteristic smallest dimension of 20Å was observed. This feature develops in coals as their maturity increases. As a consequence, for mature coals the specific internal surface area may be significantly larger than that calculated solely from fractal scaling.SEM observations were performed on fragments of samples previously analysed by SAS. Samples were cleaved in the direction perpendicular to the bedding plane and internal surfaces of relatively large pores (of the order of 1µm across) opening to the exposed surface were observed at magnifications from x500 to x500000. For low rank coals, structural features down to the size of 5 nm were observed. The wide size range of the observed structural detail is consistent with the notion of fractal microstructure of coals, as determined using small angle scattering techniques.

The coalbed methane potential of the Jurassic-Cretaceous Mist Mountain Formation was investigated to determine if shearing and oxidation of coal could account for the low volumes of methane encountered in the formation The coal is of suitable rank and composition to host significant coalbed methane reserves, yet tests to date indicate lower than the expected volumes of methane are present.Adsorption isotherms indicate that Mist Mountain Formation has good to excellent reservoir capacity (Langmuir volumes 13 to 30 cc/g daf bases). Shearing does not significantly affect the methane adsorption capacity of the coal; any effect shearing may have on adsorption capacity is overshadowed by the effect of variation in maceral content and oxidation. Adsorption tends to increase with increasing vitrinite content, irrespective of whether or not the coal is sheared. Oxidation results in decreased methane adsorption capacity in the Mist Mountain Formation coals. However, the decreased volume of methane adsorbed due to oxidation alone is unlikely to result in the sub-economic volumes of methane that desorb from the coal.It appears that shearing and oxidation have facilitated leakage of methane resulting in under saturation: both shearing and oxidation enhance the permeability of coal and therefore have facilitated the diffusion and pressure dependent flow of methane from the coal to groundwater.

During the prospecting extraction of methane from coal seams in Ostrava district by the method of hydraulic fracturing in many cases it has been observed that the gas releasing does not follow the assumed pattern of continuous flow with gradually decreasing intensity as it is known from the degassing of drilling cores by canister test. On the contrary, after a short initial outburst, the gas stream quickly decreases to a minimum. Due to the fact that in the pumped water a high sludge content was present, it was assumed that the sludge formed during the disintegration of the coal seam by the shock wave of pressurized water may restrict the gas release owing to clogging of transport pores by very fine particles. The overpressure of water towards gas present in coal introduces these particles into the orifices of transport pores, blocking them partially and thus reducing the gas escape.

The Ostrava-Karvina part (OKR) of the Upper Silesian coal basin is the most important hard coal basin in the Czech Republic. This basin extends over an area of 1,600 km2. The Carboniferous basin fill contains 255 seams with a net coal thickness of 150 m. In the north-western part of the basin, the coal seam gas contains methane and carbon dioxide. But in the remaining part it contains only methane. The gas content in the coal is estimated between 4.4 to 20 m3/t. The seams of the western and south collieries are prone to outbursts of coal and gas.In the active mines, a system of methane drainage is operating to ensure mine safety. Other safety measures are taken in the mines which exploit the seams susceptible to outbursts of coal and gas to predict and to prevent their occurrence.Some of the collieries are already closed or being closed. Coal mines closure does not mean that methane liberation into the underground abandoned areas would be stopped. After closure water level in the mines would rise. During this stage some mine gas may leak uncontrollably to the surface via old mine shafts and natural migration channels. This migration is greatly influenced by rapid drops in atmospheric pressure. A risk of explosion or fire would occur in the basements of buildings or industrial plants in the densely populated city of Ostrava. A complete system of gas extraction, gas monitoring and safety measures in the buildings is being built to prevent the gas emissions to the atmosphere and to ensure the inhabitants safety.

In order to prevent methane emission from underground coal mines into the atmosphere, various technologies are required.In this paper, prediction methods of methane emission from the longwall panel and methane drainage methods are specifically described.

A two-dimensional computer program (HYDROMAT) for modeling the maturation of coal in sedimentary basins affected by hydrothermal circulation has been constructed. The program considers the effect of fluid flow on the thermal regime through time. The program contains: 1) a geodynamic module to simulate compaction, erosion, deposition, and tectonic uplift and subsidence of the sediments, 2) a fluid flow and thermal module to solve the coupled fluid flow and heat transfer equations, and 3) a chemical kinetic module to simulate the maturation of organic matter. The effect of magmatic intrusions during the evolution of a basin is considered. Coordinates fixed to the strata (Lagrangian coordinates) are used to follow the evolution of the coal generating units. The kinetic module uses the distribution of activation energies for parallel Arrhenius-type first order rate expressions to calculate the extent of chemical transformations over the thermal history of the basin. The program has been used to assess the effect of advective and/or convective fluid circulation on the generation of hydrocarbons. Our initial results suggest that for basins affected by high heat flow and fluid circulation, HYDROMAT can reproduce better the maturation of organic matter than conventional conductive models.

We model the hydrothermal maturation of hydrocarbons in the Bowen Basin of Australia with the program HYDROMAT (Lopez et al., these proceedings). HYDROMAT is used to determine the vitrinite reflectance and the generation of bulk hydrocarbons, hydrocarbons with one to four carbons, and hydrocarbons with five carbons or more during the evolution of the Bowen Basin. The uplift, subsidence, erosion, deposition, fluid flow and heat transfer, and thermal history of the Bowen Basin are reconstructed in order to model the maturation history of the hydrocarbon producing sediments. The effect of high temperature Cretaceous intrusions on the Bowen Basin is also modeled. We focus on the German Creek and Pleiades coal seams and find good agreement between our results and actual data for vitrinite reflectance. Our results support previous experimental studies, which suggested that hydrothermal fluid circulation and high temperature sills and dikes created the high ranking coals and methane gas deposits found in the Bowen Basin. According to our modeling results the regional Triassic high heat flow event was responsible for generating the largest fraction of the total hydrocarbons produced during the entire history of the Bowen Basin. This is consistent with the coexistence of bitumen and minerals of hydrothermal alteration in the Bowen Basin sediments.

This paper presents the results of modelling the formation of petroleum in the framework of rapid hydrodynamic processes in sedimentary basins. The study is motivated by the observation that many Pb-Zn deposits occur within hydrocarbon prone sedimentary basins, and that expulsion of hot basinal brines, over a geologically short period, may contribute significantly to the generation of hydrocarbons. Modelling of the generation of bitumen by hydrous pyrolysis shows that peak generation can occur after approximately 1000 years at a temperature of 200 °C. Hydrothermal modelling of advective heat transfer in a shaly formation above a hot porous layer, that permits (relatively) rapid fluid flow, was carried out. The results of this modelling indicated that with advective flow velocities in the vicinity of 0.315 m/yr (which is a reasonable value within the petrophysical constraints of the model) can significantly alter the temperature at a distance of some 200 m above the hot layer after 1000 years. It is concluded that a source bed approximately 200 m above such a hot layer, and buried 3 km deep within a basin, can attain 200 °C, and thus peak generation, in the vicinity of 1000 years.

New Zealand coals range in age from Cretaceous to Miocene and represent a wide variety of mire floral communities. Chemical and petrographic analysis demonstrate considerable variability in coal properties, and particularly vitrinite chemistry. Although some chemical variability can be attributed to environmental controls such as mire drainage and marine influence, other trends correspond with age, climate and floral assemblage.Mire flora is primarily reconstructed using palynological analysis. Cretaceous and Eocene coals are dominated by gymnosperm and angiosperm pollen respectively. Paleocene sequences exhibit large fluctuations in mire flora and provide ideal sample sets for investigation of potential floral controls on petroleum source potential.Proximate analysis, specific energy, sulphur, palynology and Rock-Eval data presented for 36 coals demonstrate a general increase in petroleum source potential with increasing angiosperm palynomorph dominance. Notable exceptions are coals from immediately beneath the Cretaceous/Tertiary boundary at Greymouth Coalfield, which have moderate to high Rock-Eval yield despite very low angiosperm palynomorph abundance.Pyrolysis-gcros of 3 Paleocene and 2 Cretaceous samples shows generally good oil generative potential, particularly for perhydrous coals. Stepwise pyrolysis-GCMS and bulk kinetic parameters indicate that angiosperm derived coals may generate oil at slightly lower temperatures than gymnosperm derived coals. This difference in generation temperatures is small, however there is evidence that current kinetic models do not account for rank variation in the immature analogues used to predict generation histories. Consequently, actual generation temperatures may be significantly underestimated, and the difference in generation temperatures for gymnosperm vs angiosperm derived coals may be more significant, than current models suggest.

Three-dimensional modelling of vitrinite reflectance has been used to enhance the understanding of lateral and vertical rank variations in the Permian coals of the Gunnedah Basin, New South Wales, Australia. The level of organic maturity of the coals has been investigated using both petrographic (vitrinite reflectance and fluorescence) and chemical methods (proximate and ultimate analyses, and electron microprobe data). The coal is of high-volatile bituminous rank, with a mean maximum vitrinite reflectance of between 0.56 and 1.1%. In addition to maturation-induced trends, a significant influence of depositional environment has been identified on vitrinite reflectance and other coal rank indicators in different parts of the sequence.Lower than normal vitrinite reflectance is developed in several parts of the Permian sequence, where marine strata overlie the coal-bearing interval or where lower delta plain facies are present. The coals in these intervals have a perhydrous character, increased fluorescence intensity and contain framboidal pyrite, that combine to make them distinctive in petrographic studies. When plotted against depth all vitrinite reflectance values in these parts of the sequence are shifted to the lower side of the more “normal” depth/reflectance regression line. Such anomalies can be recognised at equivalent horizons over wide areas, suggesting basin-wide marine flooding events. If not allowed for in some sections rank, as expressed by vitrinite reflectance or volatile matter content, would appear to decrease instead of increase with depth.Coals in other parts of the section have anomalously high vitrinite reflectance values, and contain hydrogen-poor material described elsewhere as ‘pseudovitrinite’. Data from such coals plot to the right of the regression line in vitrinite reflectance profiles.Chemical and petrographic studies show that the different vitrinite types follow separate coalification tracks, and hence both high and low-value anomalies need to be taken into account when interpreting maturation patterns. The depositional controls and the rank trends both have implications to maturation studies, and to prospectivity mapping for coalbed methane and petroleum generation.

Many coals, in particular coals of Mesozoic and Cenozoic age, generate significant quantities of “oil” constituents. At the same time few commercial oil deposits can be demonstrated to have originated from coal derived fluids. In this paper we examine mass loss and volumetric changes of coals during petroleum generation. We do not find evidence for the view that coals do not expel fluids before secondary cracking have eliminated the oil potential. Mass balance and sorption data indicate that coal constituents have lower retention capacity than e g, classic oil source rocks. It is concluded that there must be a direct link between the generation/desorption of petroleum and the deformation of the coal. A continuum physics approach is applied to evaluate possible coal rheologies and the compaction behavior, given the state and forces which acts on the coal during petroleum generation. The coal during generation must behave in a fluid like manner. The diffusive micro scale transport of petroleum molecules in the coal matrix causes the coal to deform with a viscous rheology. The desorption of petroleum from the coal matrix instantaneously creates a mechanically unstable state, and a related fluid potential gradient in the petroleum will drive the petroleum out of the coal together with related compaction of the coal. The expulsion will be particularly efficient in normally pressured sedimentary sections, where petroleum is expelled nearly symmetrically in both directions. In sections with hard overpressure prior to generation/expulsion, there will be a stronger tendency for upward expulsion. The main driving force for expulsion is independent of the volume expansion of the organic matter. The deficiency of oil deposits from coals, must be related to factors other than the expulsion efficiency.

This paper using sedimentology, organic petrology and geochemistry studies the oil-related, Early and Middle Jurassic terrestrial coal measures, Junggar and Turpan-Hami Basins, NW China, shows that: (1) the oil generated in the main generating stage is earlier and generates from fluorescent desmocollinite (desmocollinite B), bituminite, cutinite and suberinite; (2) the oil-generating models of some individual macerals and oil expulsion experiment of vitrain sample are given; (3) the new organic petrological oil-source correlation techniques using laser-induced fluorescence, CLSM (Confocal Laser Scanning Microscope) and TEM (Transmission Electron Microscope) parameters for oil-source correlation are expressed and (4) the sedimentary organic facies will be founded by sedimentary, organic petrological and organic geochemical parameters, of which the running water swamp/marsh facies is best concerned with coal measures related oil.

In coal mining areas, the emission of coal bed methane into the atmosphere via mine shafts is a well known phenomenon. Only a few data exist about the coal bed methane release through the lithosphere/atmosphere-interface in a coal-bearing basin. Here four testfields within the german Ruhr basin are presented (Fig. 1) which differ geologically and in mining intensity. Methane fluxes across the surface of these testfields were measured and a possible correlation between mining intensity and coal bed methane emissions at the surface is discussed, as well as the consumption potential of methane oxidizing bacteria in soils.

For the purpose of methane extraction the pressure and volume parameters of methane contained in a coal seam are usually evaluated using its high-pressure isotherm determined under laboratory conditions. Volumes interpolated on the adsorption branch of methane isotherm measured on the evacuated exploited coal is in many cases not identical with the real gas content in the seam at the same pressures. Practical arguments for this statement are results of the canister test, where the volume of the released gas is frequently more or less lower than the volume read from the adsorption isotherm. Assuming that the canister test at lossless sampling includes the total real quantity of gas contained in the coal seam, the cause of such a difference is to be looked for in the interpretation of the sorption isotherm. Although several sources quote that — during the sorption of methane on coal — the desorption branch coincides with the adsorption one [1–3], while the reversibility occurs only exceptionally [4], it cannot be precluded, that the actual methane content in coal lies rather on the desorption branch of the sorption isotherm.

The grades of coalbed gas reserves and resources extents are mainly determined at the exploration stage and by a wildcat area. According to the numbers of development wells, the number of assessment parameters of reserves and resources extents, China’s coalbed gas could be classified into two kinds of resources extents and four types of geological reserves. Based on incomplete statistics, the total coalbed gas resources buried shallower than 2000m is about 326366×108 m3, within which the resources buried between 1000–2000m is about 215666×108 m3 and the resources shallower than 1000m is about 110700× 108 m3.

The theory presented in this paper is a synthesis of the observeable geology of petroleum occurrences and new information on the ability of microfauna to generate petroleum from methane. Three paradigms of petroleum generation, anhydride theory, conventional diagenesis, and cosmic or inner earth abiogenesis, are compared as to their relevant geology.The author calls attention to the well-known fact that methane effuses from earth’s interior and to varying degrees pervades all crustal terranes, crystalline, volcanic, and sedimentary. He points out that the energy from this methane can be utilized by hyperthermophyllic bacteria and archaea, which obtain it by stripping away its hydrogen. Dehydrogenated methane molecules can be defined as anhydrides, and their recombinations as petroleum. Anhydrides of this origin are biologically-derived through dehydrogenation of methane, and thus, are products of biogenesis by living, microbial organisms rather than biogenesis of fossil biomass (kerogen). Treating coal as the “terminal anhydride” classifies coalification also as a process of biogenesis by living organisms.Petroleum in anhydride theory may thus be generated either in association with source rocks or in their absence. Coal may result from the coalification of peat by addition of externally-derived carbon, or it may be deposited in veins as asphaltite absent any peat. Oil in igneous host rocks and asphaltite in non-sedimentary terranes attest to the validity of anhydride theory.Anhydride theory is a paradigm shift that portends serious implications for petroleum discovery and recoverability from terranes thought heretofore to be barren. It also implies the possibility for rejuvenation of producing or depleted resources, and thus challenges industry to note reservoir conditions suggesting rejuvenation, which may be occurring in a producing oil field or may be in progress in a previously depleted reserve.

China is a large country on coalbed methane resources. The total volume of CBM resources in China is about 30~35 × 1010m3.[1] So she has greatness development potential of coalbed methane in China. The developments of CBM in China go through three major stages. This paper presents the history of Chinese development coal seams gas, including in-mine gas drainage in the mining areas, Gob well drainage and vertical well development.The development program of coal seams gas in China can be divided into three distinct stages — non-industrialized development stage, an early exploration stage and a more recent experimental stage.

The permeability of coalbed is not only controlled by geological conditions, but it is also influenced by later production process (Zhang xinmin, 1991), especially the influence of producing pressure on the permeability of coal bed near wellbore is very significant. It has less reported about the study of the influence of production status on the permeability in literature for coalbed well. For the producing well, the producing pressure drop should be properly controlled during drainage in order to prevent coal fine from moving which can decrease coal permeability. That is extremely important for the success of experimental well and the evaluation of the previous experiment process in the key stage of exploration and development of coalbed methane. The correlation between the producing pressure drop and the permeability of coalbed have been established by using the experimental technology, the results of this paper may play an instructing role for coalbed methane production. Here are major elements of this study: (1)Pore structure features and its influence on permeability of coal has been studied.(2)The permeability at different confining pressure has been measured and the influence of confining pressure on coal permeability has been studied.(3)The influence of upstream pressures on coal permeability has been studied; the range of wellhead pressure correspondence to the biggest permeability has been gotten.