Commercial Coalbed Methane Research Articles

Mineral matter in the Pennsylvanian coal from the Yangquan Mining District, northeastern Qinshui Basin, China: Enrichment of critical elements and a Se-Mo-Pb-Hg assemblage

The Qinshui Basin, the largest reservoir of commercial coalbed methane in China, has attracted much attention and several studies have focused on the mineralogy and element geochemistry of coals in this basin. However, the sources of minerals and elements, particularly those of high-ash coals in the northeastern basin were yet unidentified. This study investigated mineralogy and geochemistry of the Pennsylvanian No. 8 Coal (including the roof strata and partings) from the Xinjing mine, northeastern Qinshui Basin, Shanxi Province, China. The Xinjing Coal is a low-ash, medium‑sulfur semi-anthracite. The minerals in the studied coals are mainly represented by kaolinite, illite, calcite, ankerite, siderite, dolomite, and pyrite. The Xinjing Coal is characterized by enriched Li, Zr, and Hg, and slightly enriched F, Ga, Ge, Se, Sr, Mo, Hf, and Pb. The diagrams of Al2O3-TiO2, Zr/TiO2-Nb/Y, as well as the REY (rare earth elements and Y) distribution patterns show that the sediment source region of the studied deposit is represented by the old granitoides, sedimentary rocks and bauxites of the Yinshan Upland located to the north of Qinshui Basin.In this study, three geological factors (sediment source regions, injections of hydrothermal fluids, and seawater) are identified as the dominant influences on geochemical and mineralogical compositions. Elevated concentrations of critical elements such as Li and Ga are dominantly derived from the sediment source region. Authigenic minerals including sulfides, quartz, carbonates, phosphates, and clausthalite, as well as the significant variations of Se-Mo-Pb-Hg assemblage across the coal seam, indicate that the Xinjing coal probably has been subjected to a multi-stage hydrothermal activities. Relatively high total sulfur contents (2.3% on average), framboidal pyrite, Sr/Ba (3.3) and Th/U values (2.2) suggest that seawater is another important geological factor affecting the Xinjing coal.

Exploration on microbial load and nutrient source in coal-bed methane produced water

ABSTRACT Coalbedmethane (CBM) is a significant unconventional natural gas source on earth and has been extracted commercially. Numerous environmental questions flank the commercial CBM expansion. This study examined to explore microbial population in produced water of CBM growth in Jharkhand, India. Additionally, the current study focused on understanding the water as an indigenous microbial habitat on biological facts and nutrient accessibility and utilization of produced water and microbes therein. The results suggest the existence of numerous microbial communities (bacteria, archaea, actinomycetes, and fungi) in water, which may add from coal deposit. The isolate was related to Methanobacterium sp., a methanogenic archaebacteria. The study proposed that laboratory-based supplements enhance native microbial growth. Ni, Zn, Cu, Mn, B, Fe, and Se are detected in produced water, and the overall data suggest that nutrients in water may encourage native microbial growth. Therefore, the described work expands our understanding on microbial life in deep-underground in context to geomicrobiology of that region. Furthermore, it offers insight into the utilization of produced water and the abundance of indigenous microbial assemblage may aid in the biotransformation of organic material. Future research is needed to examine the diversity of microbes in water and to identify cost-effective alternatives to chemically defined medium.

Multi-fractured horizontal well for improved coalbed methane production in eastern Ordos basin, China: Field observations and numerical simulations

Eastern margin of Ordos basin has been an active commercial coalbed methane (CBM) production area in China, where coal seams are typically characterized with thin layers, low permeability and high gas content. Hydraulically fractured vertical wells (HFVWs) are the primary means for recovery of CBM in this area, which however are usually subject to low gas production and unpromising economics. Although the multi-fractured horizontal well (MFHW) has proven as an effective solution for producing hydrocarbon resources from both tight and shale reservoirs, its applicability in efficient development of CBM reservoirs remains yet unclear.This paper presents a pilot field application of MFHW to improve CBM recovery in eastern Ordos basin. A horizontal well stimulated with 6 stages of hydraulic fractures was observed to significantly outperform HFVWs in terms of depressurization efficiency, gas production and ultimate recovery factor. Peak gas rate of the MFHW is more than five times higher than an HFVW. History matches of the MFHW and representative HFVWs were conducted to obtain key reservoir properties that are subsequently used for production predictions. Numerical simulation predicts that cumulative gas production for the MFHW is 3–15 times as that for each of the HFVWs during a production duration of 15 years. A total of 500 stochastic geological scenarios for the study area were simulated to analyze the effect of geological parameters on the superiority of an MFHW over a group of four HFVWs (which are at equivalent well construction outlays) in terms of cumulative gas production. A correlation was then developed using the alternating conditional expectation (ACE) regression method, resulting in a linear relationship between an indicator of the superiority with permeability and desorption pressure in a log-log coordinate system. This correlation can be potentially used as a criterion for fast determination of the optimal completion option in the target CBM seams. The regression results also show that the superiority of an MFHW over HFVWs is especially highlighted in thin coal seams with low permeability and low gas content. Finally, the effect of the size and spacing of stimulated area (SA) on MFHW producibility was analyzed, showing that increasing the spacing between SAs is an economically viable option when the budget for fracturing operations is limited.

Enrichment origin of critical elements (Li and rare earth elements) and a Mo-U-Se-Re assemblage in Pennsylvanian anthracite from the Jincheng Coalfield, southeastern Qinshui Basin, northern China

The Qinshui Basin is the largest reservoir of commercial coalbed methane in China. The No. 15 seam, one of the major coal seams for coalbed methane exploration in the Jincheng Coalfield, SE Qinshui Basin, has recently been found to be enriched in the critical element Li. This study further investigates the inorganic geochemistry of the No. 15 coal and associated rocks and reveals the enrichment origin of critical elements in these horizons. The Jincheng No. 15 coal is rich in Li, Mo, U, Se, Re, and rare earth elements and Y (REY). Concentrations of Mo, U, Se, and Re are higher in the two topmost coal benches, probably due to marine transgression in the early diagenetic stage after the peat had been established. The enrichment of Li and REY in a few lowermost coal benches is suggested to be derived from hydrothermal fluids that were related to magmatic activity (110–140 Ma) during the Yanshanian Orogeny (Late Jurassic-Early Cretaceous), or a Late Triassic-Early Jurassic abnormal thermal event occurring at 190–215 Ma. Light REY (La, Ce, Pr, and Nd) in the Jincheng No. 15 coal are predominantly associated with phosphate minerals. Heavier REY (Sm to Lu) show a mixed phosphate and organic affinity in the studied coal samples. Non-coal samples are characterized by light REY- and HREY-enrichment, which is probably inherited from the source material in the Trans North China Orogen.Trace elements in the coal can be highly enriched in the ash if the coal is combusted due to the low to medium ash yield of the coal. Critical elements, including Li, Ga, and REY, in the Jincheng No. 15 coal are considered as promising material for industrial recovery and have been previously under-estimated. On the other hand, environmentally sensitive elements including As, Hg, and Pb, while having concentrations within the normal range compared with average worldwide coals, can be highly enriched in the coal combustion residues if the coal is combusted, and thus careful consideration needs to be given to the utilisation of such coals.

In situ stress heterogeneity in a highly developed strike-slip fault zone and its effect on the distribution of tight gases: A 3D finite element simulation study

Abstract Strike-slip fault zones are an important type of structure formed during continental orogenic events. Exploring the influence of strike-slip faults on the distribution of natural gas by using the 3D finite element method (FEM) is a frontier in the field of geoscience. In this paper, the effects of strike-slip faults on the heterogeneity of in situ stress and reservoir quality were systematically studied in a shallow commercial coalbed methane reservoir in the Shanxi Formation in the southern Qinshui Basin. Systematic 3D FEM modeling and in situ stress evaluation of a highly developed strike-slip fault zone were conducted. The results indicate that the simulated in situ stress distributions of σH, σh and σv in the target layer present ranges of 10–55 MPa, 3–23 MPa and 5–30 MPa, respectively, which are consistent with acoustic emission and hydraulic fracturing measurements. Along the strike-slip faults, the distribution of horizontal in situ stress is mainly affected by the fault length and vertical throw. The stress magnitude differs greatly between the two sides of a given strike-slip fault, affecting the compaction degree and petrophysical properties of the gas-bearing reservoir on both sides of the fault. Along the strike of a given strike-slip fault, the minimum horizontal in situ stress exhibits distinct segmentation characteristics, which affect the distribution of wells with a higher and lower yields. For the 2 s-order faults (the Sitou and Houchengyao faults), wells with a higher gas production capacity are typically located on the northwestern side of the faults. In the middle and southern sections of the Sitou-Houchengyao strike-slip fault zone, both highly concentrated faults and large-scale opening faults (basement and surface faults) produce greater stress concentrations, and the gas production capacity of the gas wells in these areas is poor. When the main strike direction of the faults is consistent with the loading direction of the boundary stress, the stress concentration is relatively low; whereas, the stress concentration increases as the angle between the main fault strike and the loading direction increases. The shear stress of the target layer is characterized by clockwise rotation, which is an important control on the stress heterogeneity of the strike-slip faults in the study area.

Geological and hydrological controls on the accumulation of coalbed methane within the No. 3 coal seam of the southern Qinshui Basin

Since 2006, the Zhengzhuang (ZZ) block has been part of a commercial coalbed methane (CBM) production area in the southern Qinshui Basin, which has become one of the most productive CBM areas in China. However, hydrogeological study of the migration gas and groundwater of the ZZ block has not been systematically launched. This study focuses on geochemical analysis, including quality analysis and stable isotope analyses for the water from the CBM production wells, discusses the groundwater flow pathways and their influencing factors, and evaluates the geological and hydrological controls on gas accumulation in the study area. The results show that the produced waters produced with total dissolved solids (TDS) values of 152.8–5389.49mg/L are typically fresh water and brackish water. The water type is primarily bicarbonate and the dissolved ions are effectively devoid of sulfate, calcium and magnesium. With the low desulfurization coefficients of 0.24–5.63, the hydrochemical condition is conductive to CBM preservation. The predominant flow of groundwater originates from the southwestern source, which flows to the north basin center and then shifts to the east deep graben due to the drastic structural variation. Four hydrodynamic zones were distinguished through the differences in hydrodynamic conditions. In the southwest Zone I and the central Zone II, the gas contents are relatively low (13.17–24.53m3/t) despite the high thermal maturity (Ro,max=3.31%–3.97%). However, the stagnant Zone III in the north and the deep stagnant Zone IV in the southeast show comparatively high gas content (16.5–31.44m3/t). The complex geostructures act synergistically with the intense hydrodynamic activities for gas accumulation. Three CBM enrichment modes were distinguished: hydrodynamic trapping at structure lows with high hydrostatic pressure; conventional trap of impermeable boundary; and hydraulic flushing and gas loss through the fault. These investigations may serve for CBM exploration and development in the study area.

An Overview of CBM Resources in Lower Indus Basin, Sindh, Pakistan

Pakistan is energy deficient and underdeveloped country but it contains wide resources of low quality coal. The contemporaneous models for Coal Bed Methane (CBM) in low-rank coals have changed dramatically in recent years due to the growth of commercial CBM activity in the Powder River Basin (PRB). The CBM models are still evolving because the CBM evaluation concepts are on steep learning curve based on proven and tested commercial activities. Coal is an unusual lithology in that it is both an excellent source and reservoir rock. CBM resource has also been found in commercial quantities in the Cambay Basin of India. The CBM resource of Cambay Basin and Powder River Basin (PRB) are similar in age and rank to most of Pakistan’s coal. The success in the above mentioned basins provoked geoscientists in Pakistan to re-look into Sindh`s CBM resource. Thar coal is considered as the largest reserves of low ranking coal in Pakistan. Preliminary geological investigation was carried out; results show that low ranked coal seams of class Lignite B to High Volatile B bituminous coal exists in Sindh. The rank specified above is better in quality from Powder River Coal Deposits, so it warrants further evaluation to firm up further exploration and subsequent exploitation. Interactive wireline correlations between several wells have been carried out explicitly. Results show that isolated coal seams of Bara Member (Paleocene) and Sonari Member of Laki Formation (Eocene) exists a few kilometers in sub-surface. The thickness of coal seams is thickest in Thar area with better prospect for gas adsorption capacity. The dedicated CBM studies also reveal that the bituminous coal exists in Badin, Sonda, Thatta and Jherruck areas. Depositional Model of Thar coal deposit has been prepared using plate reconstruction.

The first commercial coal bed methane project in Turkey - reservoir simulation and prefeasibility study for the Amasra coalfield

The first commercial coal bed methane project in Turkey - reservoir simulation and prefeasibility study for the Amasra coalfield

The first commercial coal bed methane project in Turkey - reservoir simulation and prefeasibility study for the Amasra coalfield

This study plans and models coalbed methane (CBM) recovery from the Amasra coalfield (the east and the west fields) in Zonguldak Basin, Turkey and compares the results from several operational development scenarios in order to identify the most effective development strategy. The reservoir was modelled using GEM, an advanced general equation-of-state compositional simulator. Vertical and multi-lateral CBM development plans were proposed and the cumulative gas production and gas production rates were estimated. Finally, a standard discounted cash flow analysis was performed. It was found that the vertical and multi-lateral CBM plans would yield positive NPV's - US$ 12,148,498 (IRR - 28.35%) and US$ 11,250,167 (IRR - 27.39%) respectively - only at the west field. Financial analysis showed that none of the alternatives are feasible at the east field. It can be concluded that the vertical CBM development plan with higher IRR (28.35%) would be the best alternative for the west field considering the technical difficulties in drilling operations and much higher capital investment in the multi-lateral CBM development plan. By this way emissions of 2.57 MMtCO2e would be avoided over a 20-year period based on the fact that the coal will be mined and the resulting methane will be liberated. [Received: January 6, 2015; Accepted: March 2, 2015]

Fault-sealing capability and its impact on coalbed methane distribution in the Zhengzhuang field, southern Qinshui Basin, North China

Fault-sealing capability has critical influence on coalbed methane (CBM) accumulation and preservation in coal-bearing basins. Although southern Qinshui Basin is the first commercial CBM production area in China, detailed investigation on faults evolution and its impact on gas accumulation has never been performed. In this paper, the generation time and the evolution process of the sealing capability of seven major faults in the Zhengzhuang field were evaluated by using well-logging data and 3D seismic tectonic interpretation. Results indicate that most normal faults in the Zhengzhuang field were created from Late Cretaceous to Paleogene and after the key stage of hydrocarbon-generation. Fault-sealing capability was evaluated through the vertical pressure on the faults' surface (VPFS), the shale gouge ratio (SGR) and the clay-smear potential (CSP), the values of which for Zhengzhuang field are −3.2 MPa to 16 MPa, 0.36 to 0.91, and 2–40 m, respectively. These values demonstrate that the fault-sealing is complex and variable when the faults present in different scales or different positions in the faulting system. In the Zhengzhuang field, almost all faults exhibit good lateral sealing capability (LSC) with high values of SGR (>0.6) and CSP (>15 m) during fault evolution. Therefore, the current gas contents are primarily related to the vertical sealing capability (VSC) but not to the LSC of the faults. The VSC of the fault varies with the different stages during the fault evolution. In the Late Cretaceous-Paleogene, a key stage for gas dissipation, almost all faults possess low VSC, which caused generally low gas content (<22.4 m3/t) near the faults. In contrast, the gas content that was not affected by faults is commonly >25 m3/t. In the Neogene-Quaternary, the VSC was variable for different faults. For the faults with low VSC, they would gradually lead to low gas content. The results showed that the VSC positively correlated with the current gas contents near the faults in the Zhengzhuang field, southern Qinshui Basin, North China.

Solute Concentrations Influence Microbial Methanogenesis in Coal-bearing Strata of the Cherokee Basin, USA.

Microorganisms have contributed significantly to subsurface energy resources by converting organic matter in hydrocarbon reservoirs into methane, the main component of natural gas. In this study, we consider environmental controls on microbial populations in coal-bearing strata of the Cherokee basin, an unconventional natural gas resource in southeast Kansas, USA. Pennsylvanian-age strata in the basin contain numerous thin (0.4–1.1 m) coalbeds with marginal thermal maturities (0.5–0.7% Ro) that are interbedded with shale and sandstone. We collected gas, water, and microbe samples from 16 commercial coalbed methane wells for geochemical and microbiological analysis. The water samples were Na–Cl type with total dissolved solids (TDS) content ranging from 34.9 to 91.3 g L−1. Gas dryness values [C1/(C2 + C3)] averaged 2640 and carbon and hydrogen isotope ratios of methane differed from those of carbon dioxide and water, respectively, by an average of 65 and 183‰. These values are thought to be consistent with gas that formed primarily by hydrogenotrophic methanogenesis. Results from cultivation assays and taxonomic analysis of 16S rRNA genes agree with the geochemical results. Cultivable methanogens were present in every sample tested, methanogen sequences dominate the archaeal community in each sample (avg 91%), and few archaeal sequences (avg 4.2%) were classified within Methanosarcinales, an order of methanogens known to contain methylotrophic methanogens. Although hydrogenotrophs appear dominant, geochemical and microbial analyses both indicate that the proportion of methane generated by acetoclastic methanogens increases with the solute content of formation water, a trend that is contrary to existing conceptual models. Consistent with this trend, beta diversity analyses show that archaeal diversity significantly correlates with formation water solute content. In contrast, bacterial diversity more strongly correlates with location than solute content, possibly as a result of spatial variation in the thermal maturity of the coalbeds.

A numerical model for simulating single-phase gas flow in anisotropic coal

Numerical simulation has become an important approach for investigating coalbed methane (CBM) recovery. This demand has enabled the development of numerical simulators and each simulator has its own features. This paper first modifies the mathematical model of single-phase gas flow in coal by incorporating the anisotropic permeability model presented in our previous work. A numerical model is then developed based on this modified mathematical model by using the finite difference method. The numerical model is solved by using the Gauss-Seidel iteration method. A simulator is developed with the C++ programing language to solve the iteration equation. The numerical model is validated with a set of published experimental data and a set of published production data modeled by commercial CBM simulators. The results show that the numerical model developed in this paper agrees well with both data sets. A series of numerical simulation is conducted to evaluated the effects of permeability anisotropy on dry CBM production by using the numerical model developed in this paper. The results show that if the equivalent permeability is equal to the isotropic permeability, the permeability anisotropy has few effects on gas rate but impacts the distributions of pore pressure and gas content significantly. These results may be meaningful for dry CBM production with multiple vertical wells.

A progress report on Indonesian coal bed methane development

This article examines the progress made towards achieving material commercial coal bed methane (CBM) production in Indonesia during the period since the publication in 2010 of ‘Coal Bed Methane Development in Indonesia: Golden Opportunity or Impossible Dream?’ (2010 Paper; P Godfrey, Tan Ee and T Hewitt, ‘Coal Bed Methane Development in Indonesia: Golden Opportunity or Impossible Dream?’ (2010) 28(2) JERL 233–64) by the Journal of Energy and Natural Resources Law. Although blessed by favourable geology, and despite some quite extensive exploration activities, Indonesia has not yet seen CBM become a significant contributor to its energy supply mix. This is the case both in relation to domestic gas demand and in terms of contribution to spare capacity in liquefied natural gas export facilities. The Government of Indonesia has continued to use the production sharing contract (PSC) as the centrepiece of its regulation of the CBM sector. Except for the issue of a newish regulation on bidding for unconventional gas acreage, the regulatory regime pertaining to CBM exploration and production (E&P) has remained basically unchanged since 2010. Generally speaking, bureaucratic inertia at central and local levels of Government continues to be an unfortunate characteristic of the administration of the sector. However, at the same time, a lack of suitable specialized drilling equipment together with a lack of commitment by some CBM operators has also played a significant part in disappointing progress overall.

Evaluation of coalbed methane potential of different reservoirs in western Guizhou and eastern Yunnan, China

The coal and coalbed methane (CBM) resources are abundant in western Guizhou and eastern Yunnan, South China. However, commercial CBM production in this region has not been achieved. Reservoir properties are the prerequisites in determining the possibility of CBM exploration and its development potential. Thus, to help to select the most favorable block and to prioritize CBM development in the study area, a comprehensive program of experimental work has been carried out to study the physical properties of coal reservoirs in different blocks. Experimental results show that the properties of coal reservoir change significantly with respect to coal rank, and the coal rank in the study area is very uneven, with the vitrinite reflectance (Ro) of coal samples ranging from 0.68% to 3.31%. In detail, low rank coals have well developed seepage pores but undeveloped adsorption pores, resulting in the low adsorption capacity and high porosity and permeability. With burial depth increase, the metamorphic degree and compaction degree of coals grow accordingly, as a result pores and fractures are gradually closed under stress, leading to a sharp reduction of porosity and permeability in medium rank coals. However, most of the high rank coals in the study area have experienced a large number of tectonic thermal events, which not only increased the metamorphism degree and adsorption capacity, but also improved the porosity and permeability of the coal reservoirs. Based on experimental results, the CBM potentials of coal reservoirs in different blocks in the study area were evaluated using multi-objective and multi-level fuzzy optimization model, and the most prospective zones for CBM production were suggested.

Relative permeability of CBM reservoirs: Controls on curve shape

Abstract Relative permeability to gas and water for 2-phase flow coalbed methane (CBM) reservoirs has long been known to exhibit a strong control on (gas and water) production profile characteristics. Despite its important control on both primary and enhanced recovery of CBM for coal seams that have not been fully dewatered, relative permeability in coal has received little attention in the literature in the past decade. There are few published laboratory-derived curves; these studies and their resulting data represent a small subset of the commercial CBM reservoirs and do not allow for a systematic investigation of the physical controls on relative permeability curve shape. Other methods for estimation of relative permeability curves include derivation from simulation history-matching, and production data analysis. Both of these methods will yield pseudo-relative permeability curves whose shapes could be affected by several dynamic CBM reservoir and operating characteristics. The purpose of the current work is to perform a systematic investigation of the controls on CBM relative permeability curve shape, including non-static fracture permeability and porosity, multi-layer effects and transient flow. To derive the relative permeability curves, effective permeability to gas and water are obtained from flow equations, flow rates and pressure data. Simulated cases are analyzed so that derived and input curves may be compared allowing for investigation of CBM reservoir properties on curve shape. One set of relative permeability curves that were input into the simulator were obtained from pore-scale modeling. Field cases from two basins are also examined and controls on derived relative permeability curve shape inferred. The results of this work should be useful for future CBM development and greenhouse gas sequestration studies, and it is hoped that it will spark additional research of this critical CBM flow property.

CBM and CO2-ECBM related sorption processes in coal: A review

Abstract This article reviews the state of research on sorption of gases (CO2, CH4) and water on coal for primary recovery of coalbed methane (CBM), secondary recovery by an enhancement with carbon dioxide injection (CO2-ECBM), and for permanent storage of CO2 in coal seams. Especially in the last decade a large amount of data has been published characterizing coals from various coal basins world-wide for their gas sorption capacity. This research was either related to commercial CBM production or to the usage of coal seams as a permanent sink for anthropogenic CO2 emissions. Presently, producing methane from coal beds is an attractive option and operations are under way or planned in many coal basins around the globe. Gas-in-place determinations using canister desorption tests and CH4 isotherms are performed routinely and have provided large datasets for correlating gas transport and sorption properties with coal characteristic parameters. Publicly funded research projects have produced large datasets on the interaction of CO2 with coals. The determination of sorption isotherms, sorption capacities and rates has meanwhile become a standard approach. In this study we discuss and compare the manometric, volumetric and gravimetric methods for recording sorption isotherms and provide an uncertainty analysis. Using published datasets and theoretical considerations, water sorption is discussed in detail as an important mechanisms controlling gas sorption on coal. Most sorption isotherms are still recorded for dry coals, which usually do not represent in-seam conditions, and water present in the coal has a significant control on CBM gas contents and CO2 storage potential. This section is followed by considerations of the interdependence of sorption capacity and coal properties like coal rank, maceral composition or ash content. For assessment of the most suitable coal rank for CO2 storage data on the CO2/CH4 sorption ratio data have been collected and compared with coal rank. Finally, we discuss sorption rates and gas diffusion in the coal matrix as well as the different unipore or bidisperse models used for describing these processes. This review does not include information on low-pressure sorption measurements (BET approach) to characterize pore sizes or pore volume since this would be a review of its own. We also do not consider sorption of gas mixtures since the data base is still limited and measurement techniques are associated with large uncertainties.

Coalbed methane resources and reservoir characteristics from the Alberta Plains, Canada

Alberta has vast coal resources that may be a potential source of coalbed methane (CBM). Exploration and research are currently underway in the province to quantify gas potential, identify key geological factors that maximize CBM potential, and identify the ‘most favourable’ areas for CBM production potential. There are four main coal zones within the Plains and Foothills of Alberta. The Ardley Coal Zone of the Plains is undergoing CBM exploration and production piloting. Much of this effort is within the west-central Pembina area. Horseshoe Canyon Formation coals of south-central Alberta were initially thought to have gas concentrations too low to be economic CBM producers. It is these coals, however, that host Alberta's first commercial CBM production project. Although similar in both geographic distribution and coal quality to Horseshoe Canyon coals, not much is known regarding the gas potential of underlying coals of the Belly River Group. The deeper Mannville coals have some of the highest gas concentrations of Alberta coals; however, they are also relatively deep and have lower permeability than the overlying Belly River, Horseshoe Canyon and Ardley coals. Maximum gas-in-place for the Plains and Foothills has been estimated to be greater than 500 trillion cubic feet (1.42 * 1013 m3). Although this number is very large, little is known as to how much of this huge resource is actually producible. A key challenge to producibility in Alberta has been the generally low permeability of coals with the highest gas concentrations (Mannville coals), and the moderate to low gas concentrations of higher permeability coals (Horseshoe Canyon and Ardley coals). Regionally, coal distribution and average gas-in-place concentrations are calculated for the Alberta Plains. Identifying and explaining local areas with favourable CBM production characteristics within the regional setting is necessary to establish economic CBM plays within Alberta. There are currently several pilots and numerous exploration efforts underway in the province to demonstrate production potential. This study integrates existing data with new data collected from key areas that show favourable CBM potential. There is great opportunity for CBM development in Alberta. Local areas have enhanced characteristics favourable to production. Ongoing geological investigations are needed to identify characteristics that will serve as an exploration tool for future CBM discoveries.

The abnormal pressure regime of the Pennsylvanian No. 8 coalbed methane reservoir in Liulin–Wupu District, Eastern Ordos Basin, China

Coalbed methane reservoir pressure is an important parameter used to assess the producibility of coalbed methane wells. Practices indicate that high production of coalbed methane well is partly related closely to abnormally high pressure. Permo-Carboniferous coalbed methane resources are very abundant in the Liulin–Wupu District, Eastern Ordos Basin, which has been the highlight of coalbed methane exploration in China in recent years. In this district, the abnormally high pressure is present locally in the Pennsylvanian No. 8 coalbed methane reservoir (the Taiyuan Formation). Based on the distribution of the abnormally high pressure, burial history, hydrocarbon generation, hydrodynamics, and sealing regimes, the authors suggest that the abnormal coalbed methane reservoir pressure is related closely to local hydrodynamic trapping. The gas generated during the qualification is preserved, owing to the confinement of lower permeable roof and floor rock layers, and water trapping in the updip direction (like the “fairway” in San Juan Basin). As a result of pressure reconstruction event, the abnormally high pressure is formed during the uplifting stage. The current coalbed methane wells with high production are always located in abnormally high pressure areas. Therefore, the areas with abnormally high pressure in Liulin–Wupu District can be the preferred areas for commercial coalbed methane development.

99/00242 Coalbed methane: From hazard to resource

This article reviews the state of research on sorption of gases (CO2, CH4) and water on coal for primary recovery of coalbed methane (CBM), secondary recovery by an enhancement with carbon dioxide injection (CO2-ECBM), and for permanent storage of CO2 in coal seams.Especially in the last decade a large amount of data has been published characterizing coals from various coal basins world-wide for their gas sorption capacity. This research was either related to commercial CBM production or to the usage of coal seams as a permanent sink for anthropogenic CO2 emissions. Presently, producing methane from coal beds is an attractive option and operations are under way or planned in many coal basins around the globe. Gas-in-place determinations using canister desorption tests and CH4 isotherms are performed routinely and have provided large datasets for correlating gas transport and sorption properties with coal characteristic parameters.Publicly funded research projects have produced large datasets on the interaction of CO2 with coals. The determination of sorption isotherms, sorption capacities and rates has meanwhile become a standard approach.In this study we discuss and compare the manometric, volumetric and gravimetric methods for recording sorption isotherms and provide an uncertainty analysis. Using published datasets and theoretical considerations, water sorption is discussed in detail as an important mechanisms controlling gas sorption on coal. Most sorption isotherms are still recorded for dry coals, which usually do not represent in-seam conditions, and water present in the coal has a significant control on CBM gas contents and CO2 storage potential. This section is followed by considerations of the interdependence of sorption capacity and coal properties like coal rank, maceral composition or ash content. For assessment of the most suitable coal rank for CO2 storage data on the CO2/CH4 sorption ratio data have been collected and compared with coal rank.Finally, we discuss sorption rates and gas diffusion in the coal matrix as well as the different unipore or bidisperse models used for describing these processes.This review does not include information on low-pressure sorption measurements (BET approach) to characterize pore sizes or pore volume since this would be a review of its own. We also do not consider sorption of gas mixtures since the data base is still limited and measurement techniques are associated with large uncertainties.