Coal Measure Gas Research Articles

Numerical Simulation of the Coal Measure Gas Accumulation Process in Well Z-7 in Qinshui Basin

The process of coal measure gas accumulation is relatively complex, involving multiple physicochemical processes such as migration, adsorption, desorption, and seepage of multiphase fluids (e.g., methane and water) in coal measure strata. This process is constrained by multiple factors, including geological structure, reservoir physical properties, fluid pressure, and temperature. This study used Well Z-7 in the Qinshui Basin as the research object as well as numerical simulations to reveal the processes of methane generation, migration, accumulation, and dissipation in the geological history. The results indicate that the gas content of the reservoir was basically zero in the early stage (before 25 Ma), and the gas content peaks all appeared after the peak of hydrocarbon generation (after 208 Ma). During the peak gas generation stage, the gas content increased sharply in the early stages. In the later stage, because of the pressurization of the hydrocarbon generation, the caprock broke through and was lost, and the gas content decreased in a zigzag manner. The reservoirs in the middle and upper parts of the coal measure were easily charged, which was consistent with the upward trend of diffusion and dissipation and had a certain relationship with the cumulative breakout and seepage dissipation. The gas contents of coal, shale, and tight sandstone reservoirs were positively correlated with the mature hydrocarbon generation of organic matter in coal seams, with the differences between different reservoirs gradually narrowing over time.

Analysis of Rock Mechanical Characteristics and Establishment of an Evaluation System for Coal Measures in the Longtan Formation, Guizhou Province.

The mechanical properties of coal measure rocks and their evaluation significantly impact the process and efficacy of coal measure exploration and development. This study focuses on the Guizhou Longtan Formation coal measure. The mechanical and fracturing characteristics of coal measure rock samples are analyzed via well coring, geophysical logging, and indoor experiments. Additionally, predictive models for rock mechanical parameters are developed, and an evaluation system for the Longtan Formation coal measure rock mass is established. The findings are as follows: (1) Coal measure rocks in Guizhou's Longtan Formation exhibit a relatively low elastic modulus and tensile strength, but a substantial variation in compressive strength. The triaxial compressive strength, elastic modulus, and residual strength increase nonlinearly with increasing confining pressure. As the confining pressure increases, the failure mode of the mudstone and siltstone transitions from primarily splitting failure to shearing failure. (2) Strong correlations are calculated between logging parameters and rock mechanical parameters and are used to construct three regression prediction models, yielding an average prediction accuracy of approximately 85% for rock mechanical properties. (3) Considering the rock mechanical properties, rock mass structure and stratigraphic characteristics, and the occurrence environment related to the characteristics of rock mass affecting coal measure gas development, eight evaluation indices are selected. The analytic hierarchy process-entropy weighting method is used to determine the weights of the comprehensive evaluation indices, and a coal measure rock mass evaluation system is established by utilizing gray clustering analysis. The evaluation results categorize the mudstone group (mudstone and silty mudstone) as Classes III-IV, the fine sandstone group as Classes I and II, and the siltstone group (muddy siltstone and siltstone) as Classes II and III. A comparative analysis with fuzzy comprehensive evaluation results and extenics theory evaluation results demonstrated a high level of consistency. These findings benefit coal measure rock mechanics classification and quantitative research on rock mechanics properties, providing a solid foundation for efficient coal measure gas exploration and development.

Coal measure gas resources matter in China: Review, challenges, and perspective

Achieving the dual carbon goals of peaking by 2030 and neutrality by 2060 is significantly aided by the growth of coal measure gas research and development, especially for China to optimize its primary energy consumption. We critically review the distribution, geological characteristics, methods of liberation and then recovery by hydraulic fracturing of coal measure gas in China and present a roadmap to optimize this recovery. The gas-bearing system is the focus of this recovery, but this system is embedded within its sedimentary environment and modulated by tectonic and hydrogeological controls that affect gas exploration and recovery. However, to improve the development of coal measure gas in China, bottleneck problems remain to be solved, such as accurately predicting reservoir behavior in dessert regions, optimizing well patterns, and deploying optimal horizontal well trajectories. Additionally, the technology breakthroughs on deep co-production of coal measure gas, automatic fracturing and intelligent drainage are imminent. Basically, developing new techniques and conducting improved geological surveys are essential to ensure the sustainable supply of coal measure gas resource. Thus, this review presents a comprehensive introduction to coal measure gas resources in China, of utility to academic researchers and engineers in enhancing the understanding of the current situation and in projecting future development.

Influence of coal rock on tight sandstone reservoirs in coal seam roofs: A case study of the lower jurassic in the Taibei sag, Turpan-Hami Basin, China

After shale gas, coalbed methane and gas hydrate, coal measure gas has become an important new unconventional resource, for which exploration to depths of >3000 m are taking place in China. However, owing to unusual geological conditions and as yet inadequate exploration technology the current level of exploration is low. The acidic water medium in coal-bearing strata affects the diagenesis of adjacent tight sandstone reservoirs, thereby influencing reservoir quality. However, the current understanding of the impact mechanism of coal seams on neighboring tight reservoirs is insufficient, constraining the further exploration of coal measure gas. In order to reveal the influence of coal rock on a tight sandstone reservoir in its roof, we study the coal-bearing strata of the Xishanyao Formation in the Taibei Sag of the Turpan-Hami Basin using cast thin sections, physical property tests, XRD analysis, carbon and oxygen isotopes, high-pressure mercury intrusion and low-temperature N2 adsorption. The carbonate cement in the sandstone reservoir of the coal seam roof was formed by the decarboxylation of organic acid. The organic acid, containing CO2 generated by coal rock hydrocarbon generation, has modified the tight sandstone reservoir of the coal seam roof via dissolution. This has improved the physical properties and pore throat structure of the tight sandstone reservoir close to the coal-sandstone interface. The amount of improvement extends to about 2 m into the sandstone. During the upward transport of fluid, the pre-existing carbonate cement dissolves and then precipitates, which causes the CO2 generated by the organic acid decarboxylation to exchange carbon with the carbon isotopes in the pre-existing carbonate cement. Due to the slow upward diffusion rate and limited diffusion distance of the CO2-bearing fluids, the carbonate cement exhibits gradually heavier δ13CPDB values with increasing distance from the coal-sandstone interface.

Characteristics and Controlling Factors of Fluid Interlayer Crossflow through Fractures in Coal Measure Gas Reservoirs: Implication for Enhancing Production

Characteristics and Controlling Factors of Fluid Interlayer Crossflow through Fractures in Coal Measure Gas Reservoirs: Implication for Enhancing Production

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.

Comprehensive Evaluation of In Situ Stress in the Daning–Jixian Area and Its Control on the Distribution of Coal-Measure Gas

Comprehensive Evaluation of In Situ Stress in the Daning–Jixian Area and Its Control on the Distribution of Coal-Measure Gas

A Study on the Production Simulation of Coal–Shale Interbedded Coal Measure Superimposed Gas Reservoirs under Different Drainage Methods

To study the influence of different drainage methods on the production performance of coal measure gas wells, the interbedded reservoir composed of coal and shale in the Longtan Formation of the Dahebian block was used as the research object. Considering the influence of coal and shale matrix shrinkage, effective stress, and interlayer fluid flow on reservoir properties such as fluid migration behavior and permeability, a fluid–solid coupling mathematical model of coal measure superimposed gas reservoirs was established. Numerical simulations of coal measure gas production under different drainage and production modes were conducted to analyze the evolution of reservoir pressure, gas content in the matrix, permeability, and other characteristic parameters of the superimposed reservoir, as well as differences in interlayer flow. The results showed that, compared to single-layer drainage, cumulative gas production increased by 33% under multi-layer drainage. Both drainage methods involve interlayer energy and substance transfer. Due to the influence of permeability, porosity, and mechanical properties, significant differences exist in reservoir pressure distribution, preferential flow direction, gas content in the matrix, and permeability ratio between coal and shale reservoirs under different drainage and production modes. Multi-layer drainage effectively alleviates the influence of vertical reservoir pressure differences between reservoir layers, facilitates reservoir pressure transmission in shale reservoirs, enhances methane desorption in shale matrices, promotes matrix shrinkage, and induces the rebound of shale reservoir permeability, thus improving overall gas production.

Numerical simulation of hydraulic fracture extension patterns at the interface of coal-measure composite rock mass with Cohesive Zone Model

This study presents the development of a numerical computational model for hydraulic fracturing of coal-measure rock mass. The model is based on the B-K hybrid fracture energy criterion and is implemented using the extended finite element method (XFEM) and cohesive zone model (CZM) in the ABAQUS software. The study took into account the elastic-plastic damage properties of the coal-measure rock mass, as well as the combined effects of tensile and shear damage during the start and expansion of hydraulic fractures. The expansion trajectories and fracture morphology of hydraulic fractures at the interface of coal-measure rock mass under different lithological combinations (lithological strength differences) and ground stress conditions are revealed, and the main controlling factors affecting the expansion across the bedding are clarified. The study provides valuable insights into the management of hydraulic fracturing in the challenging context of hard roof coal mines, the stimulation of coal-measure gas co-production reservoirs, and the development of effective fracturing stimulation strategies for shale oil reservoirs interlayered with thin sandstone, and it can promote the development of industrial production technology for coal-measure gas and shale oil and gas resources, and is beneficial to increase the proportion of clean energy in China's energy consumption structure, and thus promoting a further reduction in the carbon emissions from energy consumption.

Experimental and numerical simulation studies on the imbibition front of different rocks in coal-measure gas composite reservoir

Spontaneous imbibition (SI) is an important mechanism during the development of coal-measure gas composite reservoirs. However, due to the highly heterogeneity of composite reservoirs, there are differences in the imbibition laws of different lithological reservoirs. In this study, a numerical simulation model of the imbibition mass (IM) and imbibition front (IF) of the composite reservoir was established, and the influencing factors of the SI as well as the change law of the IF of the composite reservoir were studied. The experimental results showed that the IM is mainly controlled by porosity and the influence of wettability is significantly weaker than that of porosity. The time to imbibition mass inflection point (Ti) ranged from 20 to 45 h, IM ranged from 0.2314 to 0.5430 g. The inflection point of the IF occurs at 0.5 Ti, ranged from 1.32 to 2.21 cm, and the displacement increment of the IF shows the characteristic of first becoming larger and then slowly decreasing. Before the inflection point, the displacement curve of the IF is in the form of a power function, and the displacement increment gradually decreases from more than 110% to less than 40%; after the inflection point, the displacement curve of the IF is close to a straight line, and the displacement increment does not change much. The variation of the direction of action of the capillary force and the capillary diameter resulted in a displacement of the IF in the decelerating development phase that was approximately 2 times greater than in the slow stabilisation phase for all samples, and this quantitative relationship was generalizable across all samples. Results show that our model provides a powerful tool to revealing water-gas flow behaviors and for modeling two-phase flow in coal-measure gas reservoirs.

Fluid seepage mechanism and permeability prediction model of multi-seam interbed coal measures

The successful development of coal measure gas (CMG) in the Surat Basin in Australia shows that the geological conditions of thin-interbed CMG development may be more favorable, but the above understanding is still in the geological law summary level. This study combines numerical simulation and physical simulation experiments to study the core geological problems of CMG in the geological control of the permeability of a multi-thin coal seam composite reservoir (MTCCR). The results show that in the initial stage of stress loading, the permeability advantage of the coal-mudstone/sandstone composite reservoir is reflected in the bedding permeability. Based on this phenomenon, the concept of “cross-layer seepage effect of fluid in MTCCR” is proposed for the first time, which is analyzed as the result of the permeation effect of adjacent rock fluids in the composite reservoir under the action of pressure difference. The numerical simulation shows that the permeability increase of the MTCCR depends on the increase in the fracture, and the coupling effect of the fracture and pore changes the fluid pressure field and seepage mode around the fracture. From the experimental perspective, the above understanding confirms the results of previous conclusions on the geological law of high permeability of MTCCR, and explains the geological phenomenon of high permeability of MTCCR from the seepage mechanism. Based on numerical and physical simulation experiment, a sedimentation-tectonics controlled permeability prediction model was constructed. The seepage mechanism and the permeability prediction model established of MTCCR in this study can provide theoretical support and quantitative basis for the selection of high permeability zones and evaluation of high permeability sections in the exploration and development process of thin interbed CMG.

Study on fracture characteristics in coal and shale for coal-measure gas reservoir based on 3D CT reconstruction and fractal features

Study on fracture characteristics in coal and shale for coal-measure gas reservoir based on 3D CT reconstruction and fractal features

Editorial: Exploration, exploitation, and utilization of coal-measure gas into the future: Volume II

Editorial: Exploration, exploitation, and utilization of coal-measure gas into the future: Volume II

Reservoir characteristics of marine–continental transitional shale and gas-bearing mechanism:Understanding based on comparison with marine shale reservoir

Transitional shale gas layers are widely distributed in China, but no significant exploration breakthrough has been made so far. This paper investigates and analyzes the characteristics and gas-bearing mechanisms of transitional shale gas reservoirs in detail, aiming to clarify the shale gas accumulation mechanism of transitional shale and provide theoretical support for the selection of favorable intervals. The transitional shale gas layer is characterized by a thin single-layer thickness, rapid lithological change, low brittle mineral content, and poor kerogen type. The lack of organic matter (OM) sponge pore development process from the oil-generation stage results in limited numbers of OM nanometer-scale pores. Shale pore space is dominated by pores and fractures related to clay minerals. The measured gas content is well consistent with the theoretically calculated gas content for marine organic-rich shales. However, the actual measured gas content is far lower than the theoretically calculated gas content for the transitional shale gas reservoir. The main mechanisms are summarized to be (1) the high hydrocarbon expulsion efficiency of the “sandwich” space structure of the sandstone–shale–coal association, which gives rise to most natural gas migrating into nearby sandstone, and (2) high water saturation resulting in insufficient storage space for free gas in the shale reservoir. Unlike marine shale gas, natural gas in the transitional shale reservoir is primarily dominated by adsorbed gas in kerogen, and free gas is relatively low. The favorable lithofacies types are organic-rich siliceous/calcareous shales. Multiple layers of siderite-bearing shales/siderites are developed vertically and continuously distributed horizontally in transitional strata, particularly in flat-lagoon facies. It is easy to form a “micro-trap” to store gas in siderite-bearing shale, and siderite-bearing shale has strong sealing properties due to low porosity, low permeability and high breakthrough pressure. This property can form overpressure and trap shale gas inside the shale, providing a new research perspective for the optimization of vertical favorable intervals, as well as exploration breakthrough in transitional shale gas. Further research should strengthen the systematic sedimentological study of transitional facies, reveal shale gas occurrence state and dynamic transformation, and optimize favorable interval evaluation systems to clarify the feasibility of coal-measure gas commingled production.

Experimental Investigation of Reservoir Fluid Interlayer Crossflow Through Fracture During the Drainage Stage of Coal Measure Gas Well

Experimental Investigation of Reservoir Fluid Interlayer Crossflow Through Fracture During the Drainage Stage of Coal Measure Gas Well

Geological characteristics and exploration potential of the coal measure gas from Shan 2 of the Shanxi formation in the eastern Ordos Basin

“Coal measure gas,” excluding tight (low-permeability) sandstone gas, refers in this study to the self-sourcing unconventional natural gas stored in coal, shale, and fine siltstone. It is characterized by various types of occurrences and reservoirs, a distinct cyclic succession of coal measure strata, widely distributed mosaic hydrocarbon accumulations, three types of coal measure gas accumulations, and configurations of vertically multiple-stacked gas-bearing reservoirs. Coal measure gas from Shan 2 can be divided—according to the grain size of sandstone, configurations of sandstone–coal–mudstone association, thickness, and layers—into four types: thick massive sandstone–coal–mudstone (type I), fine siltstone–coal–mudstone (type II), thin sandstone–mudstone–sandstone (type III), and coal–mudstone (type IV). Comprehensive evaluation suggests that the coal measure gas in the Suide-Mizhi area of the southern Ordos Basin presents an important and favorable accumulation option, characterized by coalbed methane, shale gas, and tight gas stored in sandstone–mudstone–coal strata. Therefore, it is essential to conduct full future assessments for the coal beds, shale, and tight gas controlling exploration for the “vertical gas-bearing zone” by three-dimensional exploration.

An Analytical and Numerical Analysis for Hydraulic Fracture Propagation through Reservoir Interface in Coal-Measure Superimposed Reservoirs

Hydraulic fracturing technology can be used to jointly exploit unconventional natural gas such as coalbed methane and tight sandstone gas in coal-measure superimposed reservoirs for the enhancement of natural gas production. Hydraulic fracturing usually induces mixed fractures of I and II modes, but existing studies have not considered the influence of reservoir lithology on the stress intensity factor of I/II mixed fractures in coal-measure superimposed reservoirs. This paper develops an analytical stress model and a seepage-mechanical-damage numerical model for the vertical propagation of I/II mixed fractures in coal-measure superimposed reservoirs. The variation of stress intensity factor of I/II mixed fractures is analyzed when the fractures are close to the interface of different lithologic reservoirs and the effects of elastic modulus difference, stress state, fracturing fluid viscosity, shear and tensile failure modes on the vertical propagation of hydraulic fractures are investigated. Finally, the ratio of elastic modulus of adjacent reservoirs is proposed as an evaluation index for the fracture propagation through reservoir interface. These investigations revealed that hydraulic fracture propagation through the reservoir interface is a process of multi-physical interactions and is mainly controlled by the injection pressure and the elastic modulus ratio of adjacent reservoirs. A critical line is formed in the coordinates of elastic modulus ratio and injection pressure. A fracture can propagate through the reservoir interface when the combination of injection pressure and the elastic modulus ratio is in the breakthrough zone. These results can provide theoretical support for the site selection of horizontal wells in coal-measure gas exploitation.

Geological characteristics and gas-bearing evaluation of coal-measure gas reservoirs in the Huanghebei coalfield

Bystudying the source reservoir geochemical characteristics, reservoir cap physical properties, gas-bearing characteristics and reservoir-forming types of the coal-measure gas (CMG) accumulation system, the potential of CMG resources in the Huanghebei Coalfield was determined, and the sedimentary reservoir control mechanism was analyzed, which is of great significance for the orderly development of CMG reservoirs. CMG in the Huanghebei Coalfield mainly includes abundant shale gas (SG; 2100.45 × 108 m3), coalbed methane (CBM; 137.89 × 108 m3) and a small amount of tight sandstone gas, limestone gas and magmatic rock gas. CMG rocks mainly include shale and coal seams of the marine–terrestrial transitional facies Taiyuan Formation and continental facies Shanxi Formation, providing a favorable material basis for CMG enrichment. The coal seams are largely mature to highly mature, with satisfactory hydrocarbon generation potential and reservoir connectivity. They are low-porosity, low-permeability, underpressurized and undersaturated reservoirs. The shale organic matter is primarily Type II, with a moderate organic matter abundance. The material is at the middle-to high-maturity stage, provides a suitable hydrocarbon generation potential, belongs to low-porosity and low-permeability reservoirs, and exhibits favorable fracturing properties. There are several stable and independent gas-bearing systems among the coal measures. The CMG accumulation combination types are mostly self-sourced gas reservoirs and self-sourced+other-source near-source gas reservoirs, followed by other-source gas reservoirs. CBM and SG play the role of vertical regulation and horizontal regulation, respectively.

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.

Exploration and development in the Zhaotong national shale gas demonstration area: Progress and prospects

The Zhaotong national shale gas demonstration area in Yunnan (hereinafter referred to as demonstration area) is China's third largest national shale gas production base after Changning–Weiyuan in Sichuan and Fuling in Chongqing. And after more than ten years of deep and careful cultivation, a series of important achievements have been obtained in the exploration and development. From the perspective of exploration and development history, theory and technology, this paper systematically summarizes the exploration discovery process and productivity construction progress of shale gas in the demonstration area, expounds the geological exploration theories and key technologies of mountain shale gas, and predicts their development prospect and direction. And the following research results are obtained. First, the exploration and development in the demonstration area has gone through five development stages, and so far, three major productivity construction zones have been formed, including Huangjinba and Zijinba middle–deep shale gas zones and Taiyang shallow shale gas zone, with cumulative proved geological reserves more than 3100 × 108 m3 and cumulative gas production more than 72 × 108 m3. It has been constructed into the third largest green shale gas demonstration base in China. Second, the “multi-field coordination and multi-element coupling” mountain shale gas enrichment, accumulation and occurrence theory of “sedimentary background controlling source rock and reservoir, reworking intensity controlling preservation, and three-dimensional sealing controlling enrichment” is put forward innovatively, and the “three-dimensional sealing system” accumulation model of extrabasinal shallow shale gas is established. Third, a series of zone selection and evaluation technologies for mountain shale gas in strongly reworked complex structural areas have been developed, and the concept of geology–engineering integration has first been adopted to create transparent shale gas reservoirs and cultivate high-yield wells. A major exploration breakthrough has been achieved from marginal basin medium deep shale gas layers to extrabasin ultra shallow to medium shallow ones, and domestic first large-scale monoblock shallow shale gas field with reserves over 2570 × 108 m3 has been discovered. Fourth, a landmark technological achievement and efficient development model with geology–engineering integration and shale geomechanical evaluation as the core has been formed, which leads the clean, green and efficient exploration and development of mountain shale gas. In conclusion, it is necessary to implement the exploration strategic idea of “two outgoing” in the demonstration area, i.e., “walking out of the stable area of the basin and marching into the complex structure areas in the Dianqianbei Depression” and “walking out of the Wufeng–Longmaxi Formation and exploring other layers for breakthrough”. What's more, it is recommended to carry out the double-layer stereoscopic horizontal well pattern deployment of “Leping Formation CBM (coal measure gas) + Longmaxi Formation shale gas” appropriately in a large scale, so as to establish a new integrated development model for the three-dimensional efficient development of mountain shale gas and CBM.