Coal Gas Reservoirs Research Articles

Characterizing coal gas reservoirs: A multiparametric evaluation based on geological and geophysical methods

The gas content of coal seams is a key parameter to guide the development of coalbed methane (CBM). While most studies focused on geological features, geophysical methods provide a powerful tool for the analysis of the differential distribution of CBM. In this paper, we present a comprehensive model for the quantitative evaluation of gas content in coal seams based on the computation of multiple parameters including lithology coefficient, deformation coefficient, and ash content. Based on the results of industrial analysis and isothermal adsorption tests of 135 coal samples, logging data of 76 CBM wells, as well as 10 2D seismic lines, a geophysical evaluation method of lithology inversion, structural curvature calculation, and ash content identification was established. Our study reveals the differential distribution characteristics of gas content in coal seams under the coupling effect of the three parameters. The results from this method were applied in the southeastern margin area of the Ordos Basin where 5# coal seam with sandstone and mudstone is interbedded as the roof and floor, and the mudstone in the roof contributes more to the sealing ability of surrounding rock. For the 8# coal seam with stabilized limestone and thinly interbedded mudstones as the roof, the limestone contributes most to the sealing ability. The sealing ability of surrounding rock is poorer in the area with large sandstone content in the roof and floor of coal seams and large structural curvature. The lithological combination of the 5# coal seam is the most critical gas controlling factor, whereas deformation coefficient is found to be least significant. However, for the 8# coal seam with little change in the lithology of the roof, the effect of deformation coefficient on gas content increases, and the adsorption capacity is the most important factor influencing the differential distribution of CBM.

Opportunities and challenges for gas coproduction from coal measure gas reservoirs with coal‐shale‐tight sandstone layers: A review

AbstractThe extraction of coal measure gas has been shifted toward thin gas reservoirs due to the depletion of medium‐thick gas reservoirs. The coproduction of coalbed gas, shale gas, and tight sandstone gas (called a multisuperposed gas system) is a key low‐cost technology for the enhancement of natural gas production from thin gas reservoirs in coal measure. As an emerging engineering exploitation technology at its early stage of development, gas coproduction confronts various engineering challenges in hydraulic fracturing, bottom‐hole pressure regulation, well network arrangement, and extraction sequence. The current understanding of the opportunities and challenges in the gas coproduction from the multisuperposed gas system is not comprehensive enough. In this case, the previous achievements in the field of gas coproduction should be urgently reviewed to provide valuable guidance and recommendations for further development. This review first discusses the regional and spatial distribution characteristics and possible reservoir combinations of gas reservoirs in coal measure. Then, the basic properties of different reservoirs, engineering challenges, and interlayer interference are comparatively analyzed and discussed. The current simulation models for gas coproduction and potential future research directions are further explored. The results indicate that the coupling effects of reservoir heterogeneity, interwell interference, and geological structure for increasing coproduction prediction accuracy should be included in future simulation models for gas coproduction. Careful investigation is required to explore the mechanisms and their further quantifications on the effects of interlayer interference in gas coproduction. The fractal dimension as a scale can play an important role in the characterization of the gas and water transport in different reservoirs. The machine learning methods have tremendous potential to provide accurate and fast predictions for gas coproduction and interlayer interference.

Physical Characteristics and Controlling Factors of Coal Gas Reservoir in Pingdingshan No. 10 Coal Mine

The physical properties of coal reservoirs are the main restrictions to exploration and development of Coalbed methane (CBM). The study of the physical characteristics of coal reservoirs and their controlling factors is of great significance to the safe and efficient development and utilization of CBM resources in the mining area. The Pingdingshan No. 10 coal mine was chosen for this study because of its better gas production effect at the test wells. The reservoir properties of the main coal seams of the No. 10 coal mine were tested and analyzed to comprehensively evaluate the reservoir properties, and the physical characteristics and controlling factors of the coal reservoir in Pingdingshan No. 10 coal mine were studied. The results indicate the following: (1) The gas content and methane purity of the No. 4 coal seam were significantly higher than the No. 2 seam, and therefore they have better development potential than the No. 2 seam. (2) The average adsorption time of the No. 2 coal seam was less than that of the No. 4 seam, making it easier to reach the peak production capacity of CBM wells in the short term, but was not conducive to long-term stable production of CBM. The Langmuir volume of the No. 2 coal seam samples was significantly greater than for the No. 4 coal seam; however, the No. 4 coal seam contains about three times the amount of gas in the No. 2 seam. (3) All three coal seams have high porosity, which was favorable for large amounts of CBM adsorption and storage. Micropores predominated; transitional pores were less frequent, and a few mesopores occurred; macropores were the least common. Samples from the No. 4 seam contained the highest proportion of micropores. (4) Organic pores were common in all the coal samples, with pore diameters not more than 30 µm, mainly concentrated between 50.5 and 1000 nm. Microfractures with apertures less than 70 nm were relatively frequent, mainly in the 50–65 nm range. A large number of the nanoscale microfractures were curved or jagged. (5) Fractures in the No. 2 and No. 4 coal seam samples with widths of 50 nm to 20 µm were more developed, and many were filled with kaolinite, quartz, and other minerals. (6) The samples contained mostly layered silicate minerals (kaolinite), with hard granular minerals (quartz) next, and a very small quantity of iron-type minerals, such as siderite and pyrite in dendritic form. The results of this study can provide a reference basis for the large-scale development and utilization of subsequent CBM wells.

Substantiation of Drilling Parameters for Undermined Drainage Boreholes for Increasing Methane Production from Unconventional Coal-Gas Collectors

Decarbonization of the mining industry on the basis of closing the energy generation, on the basis of cogeneration of coal mine methane, and on the internal consumption of the mine is a promising direction in ensuring sustainable development. Known problems of deep underground mining do not allow for realizing the potential of man-made gas reservoirs due to the deterioration of the conditions of development of reserves of georesources. The aim of the work was to improve recommendations for the substantiation of drilling parameters for undermined drainage boreholes for increasing methane production from unconventional coal-gas collectors. The authors’ approach innovation lies in the possibility of using the established patterns of better natural stability of undermined boreholes to optimize them as spatial orientation parameters in an existing drilling passport for the improvement of methane extraction productivity. For this purpose, smoothing (LOESS) of the experimental data of two similar types of wells was used; then deterministic interpolation methods in combination with a three-dimensional representation of the response function in “gnuplot” were used. As a result, it was found that the increase in the inclination angle from 40° to 60° leads to a significant transformation of the model of the studied process, accompanied by a decline in the dynamics of methane emission and a decrease in the distance of the productive work zone of this type of well from 13 to 5 m before the roof landing, which then is replaced by a sharp increase in the productive work zone up to 35 m ahead of the longwall face. This allows under specific conditions for recommending increasing the productivity of methane capex from technogenic disturbed coal-gas reservoir replacement of wells with a smaller angle of rise to the transition to a more frequent grid of clusters from wells #4.

Symbiotic Combination and Accumulation of Coal Measure Gas in the Daning–Jixian Block, Eastern Margin of Ordos Basin, China

Coal measure gas resources, including coalbed methane (CBM), shale gas, and tight gas are abundant in the Daning–Jixian Block. The complexity of the source–reservoir–cap relationship in the coal measure strata leads to unclear symbiotic characteristics and gas accumulation, which in turn, restrict the exploration and exploitation of the coal measure gas. In this study, the enrichment and accumulation of coal measure gas are discussed and summarized in detail. The results show that there are eight lithofacies and six reservoir combinations in the superposed strata of the coal measures in the study area. Controlled by the tidal flat-lagoon facies, the “sand-mud-coal” type mainly distributes in P1s2 and P1t, showing a good gas indication. Based on the variation of the total hydrocarbon content, key strata, and pressure coefficient of the coal measure gas reservoir, four superposed gas-bearing systems are identified in the vertical direction. According to the relationship between the gas-bearing system and gas reservoir, the enrichment of coal measure gas in the study area can be divided into three modes, including an intra-source enrichment mode, a near-source migration enrichment mode, and a far-source migration enrichment mode. The symbiotic accumulation of a coal measure gas model is further proposed, that is, an “Adjacent to co-source reservoir” type superimposed coalbed methane and shale gas reservoir model, a “Three gas symbiosis” superimposed reservoir model in the local gas-bearing system, and a “Co-source far reservoir” tight sandstone gas reservoir model. Clarifying the symbiotic relationship of coal measure gas reservoirs is beneficial to the exploration and further production of unconventional gas in the study area.

Improvement of Intensive In-Seam Gas Drainage Technology at Kirova Mine in Kuznetsk Coal Basin

One of the ways to resolve the “green energy-economic development” dilemma, in which the coal industry is situated, is by the improvement of technologies and the integrated use of extracted resources, including methane gas as a clean energy source. Using the example of the Kirova mine, located in Kuznetsk coal basin—one of the ecologically unfavorable coal mining regions of Russia—this article discusses an integrated technology for the extraction of coalbed methane (ECBM), which makes it possible to reduce greenhouse gas (methane) emissions and improve the safety and intensity of coal mining. The Kirova mine, with its 3 Mt production in 2019, is one of the coal mining leaders in Russia. The available mining equipment has the potential to significantly increase the output; however, gas is a limiting factor to this. The customary approaches to coal seam degassing have already been petered out. The miners and mine science are facing a challenge to validate and test an alternative technology to ensure effective in-seam gas drainage prior to vigorous mining. This article gives an account of the improvement track record of the in-seam gas drainage technology used to pre-treat coal seams for intensive and safe extraction. This technology suggests, at the first stage, hydraulic loosening of the target coal seam through wells drilled from the surface (SSHL), then hydraulic fracturing (HF) of the coal seam through the boreholes drilled from underground development headings, followed by methane extraction from the high-permeability coal-gas reservoir created through standard in-seam gas drainage underground wells. Results are presented in this paper of field testing of the improved SSHL technique. Findings are presented on the effective parameters of the HF technology. Methodological recommendations are offered for selecting viable in-seam gas drainage technology.

Pore structure complexity and its significance to the petrophysical properties of coal measure gas reservoirs in Qinshui Basin, China

Pore structure complexity and its significance to the petrophysical properties of coal measure gas reservoirs in Qinshui Basin, China

Advanced microbial fuel cell for waste water treatment-a review.

Petroleum, coal, and natural gas reservoir were depleting continuously due to an increase in industrialization, which enforced study to identify alternative sources. The next option is the renewable resources which are most important for energy purpose coupled with environmental problem reduction. Microbial fuel cells (MFCs) have become a promising approach to generate cleaner and more sustainable electrical energy. The involvement of various disciplines had been contributing to enhancing the performance of the MFCs. This review covers the performance of MFC along with different wastewater as a substrate in terms of treatment efficiencies as well as for energy generation. Apart from this, effect of various parameters and use of different nanomaterials for performance of MFC were also studied. From the current study, it proves that the use of microbial fuel cell along with the use of nanomaterials could be the waste and energy-related problem-solving approach. MFC could be better in performances based on optimized process parameters for handling any wastewater from industrial process.

The experimental study on integrated hydraulic fracturing of coal measures gas reservoirs

Coal measures are rich in coalbed methane, shale gas and tight sandstone gas, and the three gases co-exploration has become a potentially promising technology in China. During the process of integrated hydraulic fracturing of three gas formations in coal measures, interlayer contradiction occurs due to the formation heterogeneity, which is the key to restricting the application of this technology. In this paper, an experimental device has been designed to study the influencing factors for integrated hydraulic fracturing in coal measure gas reservoir. The results of experimental test and theoretical analysis indicate that the formation permeability and breakdown pressure are the main factors affecting hydraulic fracturing process, and the formations with large difference in these two factors always induce an uneven distribution of fracturing fluid and poor effect of integrated hydraulic fracturing. High flow rate pumping injection rate is conducive to the even distribution of fracturing fluid in various formations. Meanwhile, the proper ball injection is used to limit fluid flowrate to ensure the fluid pressure in high permeability formation is higher than it in low permeability formation, fracturing fluid can flow to low permeability formation through perforation hole. In addition, interlayer crossflow occurs during the migration of fracturing fluid and causes fluid flow to low permeability formation, which is also conducive to the even fracturing. Therefore, high flow rate pumping injection, ball injection and interlayer crossflow control are effective measures for achieving the integrated hydraulic fracturing of coal measure gas reservoirs.

Influence of horizontal control holes on fracture height containment in low permeability layered coal measure gas reservoirs

In view of the difficulty of fracture height containment during fracturing in low permeability layered or thin-layered coal measure gas reservoirs, this paper proposes a method of excavating horizontal control holes in the barriers to contain the fracture height. Considering the influence of excavating control hole on the ground stress at hydraulic fracture tips, a calculation model of hydraulic fracture height in layered strata is established. Taking the coal measures tight sandstone reservoir of Shihezi Formation in Linxing block as an example, the effect of horizontal control holes on fracture height was simulated, and the influence of various factors on the containment effect was studied. The results showed that: the excavation of horizontal control holes can effectively prevent the hydraulic fracture propagation in its height within a certain range (about 0-10r from the center of the hole, r is radius of the control hole) and reduce the penetration depth of the barrier. The greater the ground stress difference between reservoirs and barriers, the stronger the containment effect of the control holes on the fracture height. When the ground stress difference is greater than 2 MPa, the fracture height can be effectively controlled. The fracture toughness difference between reservoirs and barriers has little effect on the control holes' containment. The greater the control hole radius is, the stronger the containment effect on the fracture height is, and the greater the effective containment range will be. The optimal height of the control hole is within the stratum which the ground stress is larger, and near the interlayer interface. The research results can provide new ideas and theoretical support for fracture height containment in low permeability layered or thin layered coal measures stratum.

Contribution to Gas Production from Minor Coal Seams and Adjacent Shales: Numerical Modelling Results for the Mannville Coal Measures, South Central Alberta

The contribution to production of the gas stored within the coal and shale beds adjacent to the main coal seam in the Mannville Group, in which a lateral is drilled, was investigated through a series of numerical simulations. The results indicate that the added gas from the minor coal seams, with interbedded shales with no gas, results in 1.4 times (×) more produced gas and 3.0× more produced water after 25 years of production than when only the main Mannville coal seam is considered. Including gas in the shales results in 1.7× more produced gas and 2.5× more produced water after 25 years of production than when only the main coal seam is considered. The produced gas recovered from the shales exceeds the produced gas recovered from the coals after ~8.5 years, resulting in 2.1× more produced shale gas than coal gas after 25 years of production. Over half (56%) of the produced coal gas after 25 years of production is recovered from the main coal seam while a quarter (22%) is recovered from the L1 seam, which is the thickest and nearest minor coal seam to the horizontal wellbore located in the main seam. The results from the numerical simulations provide insights that are not intuitive or otherwise predictable in developing complex reservoirs. Although the results are specifically for the Mannville producing fairway, undoubtedly the production from minor coal seams and interbedded gas shales should be considered in other producing and potential coal gas reservoirs to identify higher producible reserves and optimize drilling and completions strategies.

Accumulation characteristics and exploration strategies of coal measure gas in China

Coal measure gas is broadly defined as all natural gas occurring in coal measure strata while narrowly defined as the coalbed methane (CBM) in coal beds and the natural gas in the adjacent tight sandstone reservoirs. In this paper, the accumulation characteristics and control factors of narrowly defined coal measure gas in China were analyzed from the aspects of source rock distribution, coal–sandstone combination type, sedimentary facies and closed system to improve CBM development benefit. And the following research results were obtained. First, there are various coal–sandstone combination relationships in coal measure strata of coal bearing basins in China. Second, the widely-distributed source rocks provide sufficient gas sources for the enrichment of coal measure gas. Third, sedimentary facies dominate the combination relationships of source–reservoir–caprock assemblages of coal measure gas, so the inborn material base of coal measure gas accumulation is formed. The sedimentary systems of fluvial facies and delta facies are the most favorable sedimentary facies for the paragenesis and accumulation of coal measure gas for their coal beds and sandstones are developed. Fourth, the closed system controls the whole process of generation, enrichment and accumulation of CBM (coal measure gas). Three types of coal measure gas reservoirs are identified: self-source and self-reservoir CBM reservoirs, paragenetic CBM–sandstone gas reservoirs, coal-derived sandstone gas reservoirs, among which the first type is currently the main target of CBM exploration and development. Finally, the next exploration direction of coal measure gas was pointed out as follows. First, the exploration and evaluation of coal measure gas shall be focused on the giant basins with abundant coal measure gas, such as Qinshui, Ordos, Junggar, Hailar and Jixi. Second, coal measure gas reservoirs shall be explored specifically based on different types. It is necessary to carry out CBM exploration in the self-source and self-reservoir CBM enriched zones in the shallow layers, integrated exploration of CBM and sandstone gas in the paragenetic CBM–sandstone gas reservoirs in the deep layers, and sandstone gas exploration in coal-derived sandstone gas reservoirs.

Compositional variations and carbon isotope reversal in coal and shale gas reservoirs of the Bowen and Beetaloo basins, Australia

Abstract Stable isotope composition of gas is widely used in hydrocarbon exploration to determine the composition and thermal maturity of source rocks. Many isotope classification systems used for gas to source rock correlation and thermal maturity determination are primarily based on empirical observations made in conventional reservoirs and the kinetic isotope effects observed during pyrolysis experiments performed on source rocks. However, such relationships may not be readily applicable to onshore unconventional reservoirs due to the strong molecular and isotope fractionation that occur during extensive gas expulsion associated with basin uplift and depressurization. Degassing studies of freshly recovered core samples can provide useful insight into the behaviour of gas molecules in unconventional reservoirs during basin uplift. The analyses of Australian coal and marine shale samples demonstrate that during desorption both molecular and isotopic compositions of gas change at variable rates. Gas initially desorbed from the samples is mostly CH 4 , whereas later desorbed gas becomes increasingly enriched in C 2 H 6 and higher hydrocarbons. Hydrocarbon molecules also fractionate according to their isotopic composition, where the early released gas is enriched in 12 C causing the remaining gas in the reservoir to be enriched in the heavier 13 C isotope. During the release of gas from the Bowen Basin coals the C isotope ratio of CH 4 ( δ 13 C 1 ) changes by up to 21‰ (VPDB), whereas that for C 2 H 6 ( δ 13 C 2 ) and C 3 H 8 ( δ 13 C 3 ) changes by <6‰. Similar changes in the isotope composition can be seen during the release of gas from marine source rocks of the Beetaloo Sub-basin. In a fully gas-mature middle Velkerri shale sample, δ 13 C 1 changes by up to 28‰ and δ 13 C 2 by up to 3‰ with no appreciable change occurring in δ 13 C 3 . The extent of molecular fractionation during gas flow through carbonaceous rocks is primarily related to the adsorption–desorption properties of organic matter and diffusivity through the overall rock matrix. Using the current dataset, the magnitude of the contributions exerted by the desorption and diffusion processes cannot be readily distinguished. However, both Bowen Basin coals and Beetaloo Sub-basin shale show similar fractionation effects during gas flow, where the heavier alkane molecules, including those containing more 13 C, desorb and move slowly compared with the lighter components, in particular CH 4 . Different rates of isotope fractionation between hydrocarbon molecules during gas flow cause the shape of compound-specific-isotope (CSI) curve to change with time. Early released gas is characterized by a normal CSI trend where the short-chain hydrocarbons are isotopically lighter compared with the longer-chain hydrocarbons. Because CH 4 and C 2 H 6 molecules enriched in 12 C desorb and diffuse more readily than the heavier hydrocarbons (including those enriched 13 C), the gas remaining in the coal and shale samples after extensive desorption shows a reversed CSI trend where CH 4 and C 2 H 6 are isotopically heavier compared with the longer chain hydrocarbons. Reversed isotope trends may also develop over geological time, particularly where the source rock is fully gas-mature and has expelled hydrocarbons due to prolonged degassing. As seen in the Beetaloo Sub-basin, the CSI trend in the dry-gas-mature Velkerri shale is reversed, possibly due to the loss of a large proportion of originally generated CH 4 during post-Cambrian basin uplift.

A combined stimulation technology for coalbed methane wells: Part 1. Theory and technology

As there are numerous coalbed methane (CBM) wells with low or zero gas production after traditional hydraulic fracturing in China, new technologies are needed for both the secondary stimulation of these wells and new wells’ stimulation. Based on the results of laboratory tests and theoretical analysis, this paper, the first of a two-part series, demonstrates the theory of a new combined stimulation technology for CBM wells. Firstly, gas contents in the coal seam, neighbouring shale and sandstone were measured and calculated. Then, the geomechanic, mineral composition and permeability of the tight sandstone were tested. Based on these tests and calculations, a combined stimulation technology is demonstrated. This new technology is to expand gas production from coal seams to coal measures; to expand the stimulation object from unitary coal seams to coal measures; and to change the stimulation method from the conventional hydraulic fracturing to fracture network stimulation. Results show that: (1) in addition to CBM, significant amounts of shale gas and tight sandstone gas can serve as complements of CBM; (2) the highest fracability formation is tight sandstone, followed by mudstone and coal. It is concluded that this combined stimulation technology can be demonstrated as conducting combined fracture network stimulation for coal measure gas reservoirs through multilayer and multi-cluster perforation, quadruplex hydraulic fracturing and other auxiliary technologies, e.g., ball-injection temporary plugging and limited entry fracturing. In part 2, the application of this combined stimulation technology to a CBM well in the Sunan Syncline is described.

Ultra-deep Permian coal gas reservoirs of the Cooper Basin: insights from new studies

There is a vast, untapped gas resource in deep coal seams of the Cooper Basin, where extensive legacy gas infrastructure facilitates efficient access to markets. Proof-of-concept for the 5 million acre (20 000km2) Cooper Basin Deep Coal Gas (CBDCG) Play was demonstrated by Santos Limited in 2007 during the rise of shale gas. Commercial viability on a full-cycle, standalone basis is yet to be proven. If commercial reservoirs in nanoDarcy matrix permeability shale can be manufactured by engineers, why not in deep, dry, low-vitrinite, poorly cleated coal seams having comparable matrix permeability but higher gas content? Apart from gas being stored in a source rock reservoir format, there is little similarity to other unconventional plays. Without an analogue, development of an optimal reservoir stimulation technology must be undertaken from first principles, using deep coal-specific geotechnical and engineering assumptions. Results to date suggest that stimulation techniques for other unconventional reservoirs are unlikely to be transferable. A paradigm shift in extraction technology may be required, comparable to that devised for shale reservoirs. Recent collaborative studies between the South Australian Department of State Development, Geological Survey of Queensland and Geoscience Australia provide new insight into the hydrocarbon generative capacity of Cooper Basin coal seams. Sophisticated regional modelling relies upon a limited coal-specific raw dataset involving ~90 (5%) of the total 1900 wells penetrating Permian coal. Complex environmental overprints affecting resource concentration and gas flow capacity are not considered. Detailed resource estimation and the detection of anomalies such as sweet spots requires the incorporation of direct measurement. To increase granularity, the authors are conducting an independent, basin-wide review of underutilised open file data, not yet used for unconventional reservoir purposes. Reservoir parameters are quantified for seams thicker than 10feet (3m), primarily using mudlogs and electric logs. To date, ~3750 reservoir intersections are characterised in ~1000 wells. Some parameters relate to resource, others to extraction. A gas storage proxy is generated, not compromised by desorption lost gas corrections. A 2016 United States Geological Survey resource assessment, based on Geoscience Australia studies, suggests that the Play remains a world-class opportunity, despite being technology-stranded for the past 10years. Progress has been made in achieving small but incrementally economic flow rates from add-on hydraulic fracture stimulation treatments inside conventional gas fields. Nevertheless, a geology/technology impasse precludes full-cycle, standalone commercial production. A review of open file data and cross-industry literature suggests that the root cause is the inability of current techniques to generate the massive fracture network surface area essential for high gas flow. Coal ductility and high initial reservoir confining stress are interpreted to be responsible. Ultra-deep coal reservoirs, like shale reservoirs, must be artificially created by a large-scale stimulation event. Although coal seams fail the reservoir ‘brittleness test’ for shale reservoir stimulation practices, the authors conclude from recent studies that pervasive, mostly cemented or closed coal fabric planes of weakness may instead be reactivated on a large scale, to create a shale reservoir-like stimulated reservoir volume (SRV), by mechanisms which harness the reservoir stress reduction capacity of desorption-induced coal matrix shrinkage.

Research on sequence stratigraphy, hydrogeological units and commingled drainage associated with coalbed methane production: a case study in Zhuzang syncline of Guizhou province, China

Exploitation of coalbed methane (CBM) involves groundwater extraction to depressurize coal reservoirs. This can involve groundwater extraction from multiple coal seams (commingled drainage). Interlayer interferences, caused by heterogeneity of hydrodynamic fields of the different coal gas reservoirs, can restrain CBM production. Understanding of the hydrogeological characteristics of each reservoir, inseparable from characteristics of the sequence stratigraphic framework, is critical for CBM exploration. Analysis of Zhuzang syncline in Guizhou province, China, found gas- and water-blocking strata near the maximum flooding surface in the upper part of each third-order stratigraphic sequence; thus, the hydrogeological units were divided vertically (SQ4, SQ3, SQ2 and SQ1) by the boundaries of the third-order sequence. The commingled-drainage CBM wells were analyzed by numerical simulation and Extenics theory, on the basis of characteristics of the hydrogeological units. Gas content, reservoir pressure and hydrodynamic parameters were found to vary between the hydrogeological units. The interlayer interference was not obvious where there was commingled drainage within single hydrogeological units with similar hydrodynamic force; this was validated by observing the consistent pressure decrease within each reservoir using historical matching. Since the source of drainage water varied from stratum SQ3 to SQ4 (containing lower hydrodynamic force compared to SQ3), it was obvious that groundwater extraction from SQ4 was restrained by SQ3, by showing obvious interlayer interference and restrained CBM production during commingled drainage across the different hydrogeological units. Reservoirs within each single hydrogeological unit tend to obtain higher CBM yield, thus take priority for commingled drainage.

An improved void-resistance model for abandoned coal mine gas reservoirs

Previous studies have shown that the gas pressure behaviour of some abandoned coal mines may be described with the aid of a simple conceptual model, the so called void-resistance model. In this study, an improved void-resistance model has been developed and validated using previously collected data. Two model parameters, i.e. an apparent source/sink pressure and a time constant, which control the gas pressure behaviour during recharge and under certain gas production conditions, are defined. It has been shown that the two parameters can be determined via linear regression through analysing the historical abandoned mine gas pressure data during recharge. The void-resistance model developed has been successfully applied to analyse the historical pressure data recorded at two abandoned coal mines in Europe.

Changes in gas storage and transport properties of coal as a result of enhanced microbial methane generation

This study was aimed at identifying the changes in coal storage and transport properties affecting gas production from coal-gas reservoirs, when treated with microbial consortia to generate/enhance production of methane. The work expanded on the technology of bio-conversion, first proposed in order to imitate the natural/microbial process of biogenic gasification leading to recharging coalbed methane reservoirs or, setting up natural gas reservoirs in non-producing coalbeds or, to coal waste, typically in the form of fines/ultra-fines. The pressure parameter was considered critical since, with continued production of methane, the produced gas would first diffuse into the coal matrix and get adsorbed with increasing pressure. During production, the pressure would decrease and the process would be reversed, gas diffusing out of the coal matrix and arriving at the cleat system.The experimental work tested the variation in the sorption and diffusion properties of treated coal, post continued bio-conversion since these are the first two physical phenomena in CBM production. During the first phase, single component sorption–diffusion experiments were carried out using methane and CO2 on virgin coals retrieved from the Illinois basin. Coals were then treated with nutrient amended microbial consortia for different periods. Gas production was monitored over thirty and sixty day periods of treatment after which, sorption–diffusion experiments were repeated on treated coals, thus establishing a trend over the sixty-day period. The sorption data was characterized using the Langmuir model. The variation trend in the value of diffusion coefficient, D, was also established as a function of pore pressure.The results indicated an increase in the sorption capacity of coal as a result of continued bioconversion. This was attributed to increased pore surface area due to microbial actions resulting in changes in the pore size or, creation of new pores. It was further shown that the rate of diffusion increased, especially for methane, which exhibited rates higher than that for CO2. These findings clearly support improved gas storage capacity with continued bio-conversion as well as significantly enhanced diffusion rates. As a continuation of this effort, change in permeability, the second gas transport phenomenon in coal-gas production, is currently being evaluated.

Formation of Methane Clathrate Hydrates in Coal Moisture: Implications for Coalbed Methane Resources and Reservoir Pressures

Adsorption, X-ray diffraction, and nuclear magnetic resonance analysis of subbituminous to high-volatile bituminous coal at in situ moisture content, low temperatures, and moderate pressures demonstrate that a significant proportion of the inherent moisture (nonmobile water) is available to form methane clathrate hydrates. These results have implications for coal gas resources and reservoir pressures in current areas of permafrost and the much larger regions that were glaciated during the Pleistocene. Methane adsorption tests indicate the clathrates form comparatively rapidly in coal micro- and mesopores from an immobile water phase, at lower pressures than those formed in macroporous materials. At successively higher experimental pressures, hydrates nucleate and grow rapidly on the scale of minutes to hours, until an “apparent” equilibrium pressure is reached. The onset of hydrate formation at 0 °C is at about 3.25 MPa for a Tarn coal with 33% moisture and at slightly higher pressures for the other coals with lower inherent moisture. The amount of gas consumed in hydrate formation, in excess of that attributed to sorption, is 11.6 cm3/g coal for the Tarn coal (Alaska) with 33% moisture, 8.15 cm3/g coal for a Dietz coal (Wyoming) with 22% moisture, and 1.85 cm3/g coal for a Texas coal with about 8% moisture. On a volume of gas (STP) per volume of water basis at 8 MPa, the Tarn and Dietz coal have similar values (35 and 37 cm3/cm3), whereas the Texas coal is measureably less (24 cm3/cm3). At 8 MPa and 0 °C, about 20% of the inherent moisture has participated in hydrate formation for the Tarn and Deitz coals and 13% for the Texas coal. If hydrate formation strips methane from the sorbed state, the proportion of water contributing to hydrate calculates was over 100% for the Texas coal, which suggests that methane is mainly forming from free gas. The methane hydrates analyzed by X-ray diffraction and nuclear magnetic resonance (NMR) spectroscopy are cubic (Pm3n̅ space group) and have small and large cage sI structures. NMR and PXRD spectra indicates that the small cages are about 90% occupied, while the large cages are completely full, yielding a stoichiometry of ca. CH4·6H2O, which is consistent with other natural hydrates. There is some evidence that some methane gas remains trapped in the smallest pores, whereas the hydrates occupy large pores, which may be due to the suppression of hydrate formation by high capillary pressures. The formation of methane hydrates, particularly in low-rank coals, markedly increases the capacity of the coal to store gas. Depending on the coal moisture content and coal rank, methane storage capacity in gas hydrates is up to 2 orders of magnitude greater than the gas storage capacity of the coal by sorption alone. Since low-rank coals invariably have high moisture content, if the strata lie with the hydrate stability zone, significant gas storage in hydrates is anticipated, if gas is available. At the low temperature required for hydrate formation, however, self-sourced methane from methanogenesis or thermal alteration is not anticipated. Successive formation and dissociation of methane hydrates during glacial and interglacial times in the Pleistocene can be anticipated to have impacted shallow gas reservoirs, including coals, to depth up to about 800 m, depending on the surface temperature and geothermal gradient. It is speculated that during the Pleistocene free and sorbed coal gas was scavenged during the formation of hydrates, and this process may explain the low gas content of some high-latitude coals. Similarly, lower than anticipated pore pressure and lack of free water in the Horseshoe Canyon coals in western Canada may be the result of dissociation of hydrates forming overpressures, which potentially could hydraulically fracture the coal and flush the coal of free water. Subsequent dissipation of the gas pressure would lead to the current low reservoir pressure.

A semi-analytical mathematical model for transient pressure behavior of multiple fractured vertical well in coal reservoirs incorporating with diffusion, adsorption, and stress-sensitivity

Vertically fractured wells have been widely used in coal gas reservoirs. Investigating transient pressure behaviors (TPB) of these wells is a considerably significant task for fracturing evaluation as well as productivity prediction. Although some studies have been done in this area, most of them focus on two-wing fractured wells. Both micro-seismic fracture imaging and samples testing strongly showed that multiple fractures can develop during hydraulic fracturing in naturally fractured reservoirs like coal seam. However, little work has been done to study the TPB of multiple fractured vertical wells (MFVW) in coal reservoirs.In this paper, to study this problem thoroughly, a well testing model of MFVW at a constant production rate was established with consideration of multiple mechanisms including diffusion, adsorption, and stress-sensitivity effect. Applying line source function, superposition principle, Pedrosa's substation, Gauss elimination, and Stehfest numerical inversion, the transient pressure solution of the mathematical model was solved. Based on this solution, model validation was conducted by selecting a case in literature. In addition, the influences of some critical parameters on TPB were studied, containing fracture length, fracture conductivity, fracture number, fracture length asymmetry, fracture conductivity asymmetry, and fracture angle asymmetry.This work provides important references for some reservoir engineers in performance forecast and completion design of MFVW in coal gas reservoirs.