Search Results (35)

Deep coalbed methane (CBM) resources represent a significant opportunity for future exploration and development. The combination of horizontal well drilling and hydraulic fracturing technology has emerged as the most efficient method for extracting deep CBM. By optimizing the fracturing parameters for horizontal wells, we can improve the effectiveness of reservoir stimulation even further. In this paper, taking the deep coalbed methane in the Daniudi gas field in the Ordos Basin as the research object, using Numerical simulation software such as Petrel, comprehensively considering the field logging, logging data and laboratory experimental data of rock mechanical parameters, the three-dimensional geomechanical and stress field model of deep coalbed methane is established, and on this basis, the numerical simulation research on the fracture network expansion and construction parameter optimization of single well and well group is carried out. Through the qualitative evaluation of fracture network morphology, the change of in situ stress field, the quantitative evaluation of post-pressure conductivity and fracture volume, the section spacing, construction fluid volume, and construction displacement under the conditions of single well and well group were optimized. The results show that under the condition of a certain well spacing, the fracture propagation of the well group is affected by stress shadowing and channeling, and the fracture pattern is more complex, and the construction scale is smaller than that of a single well. These findings provide critical insights for improving the efficiency of deep CBM recovery. Full article

China holds substantial coalbed methane resources, yet low single-well productivity persists. While horizontal well cavity completion offers a permeability-enhancing solution through stress release, its effectiveness remains limited by the incomplete knowledge of stress redistribution and permeability evolution during stress release. To bridge this gap, a fully coupled hydromechanical 3D discrete element model (FLC3D) was developed to investigate stress redistribution and permeability evolution in deep coalbed methane reservoirs under varying cavity spacings and fluid pressures, and a novel sequential cavity completion technique integrated with hydraulic fracturing was proposed to amplify stress release zones and mitigate stress concentration effects. Key findings reveal that cavity-induced stress release zones predominantly develop proximal to the working face, exhibiting radial attenuation with increasing distance. Vertical stress concentrations at cavity termini reach peak intensities of 2.54 times initial stress levels, forming localized permeability barriers with 50–70% reduction. Stress release zones demonstrate permeability enhancement directly proportional to stress reduction magnitude, achieving a maximum permeability of 5.8 mD (483% increase from baseline). Prolonged drainage operations reduce stress release zone volumes by 17% while expanding stress concentration zones by 31%. The developed sequential cavity hydraulic fracturing technology demonstrates, through simulation, that strategically induced hydraulic fractures elevate fluid pressures in stress-concentrated regions, effectively neutralizing compressive stresses and restoring reservoir permeability. These findings provide actionable insights for optimizing stress release stimulation strategies in deep coalbed methane reservoirs, offering a viable pathway toward sustainable and efficient resource development. Full article

The development of deep coalbed methane (CBM) wells faces challenges such as significant reservoir depth, low permeability, and severe liquid loading in the wellbore. Traditional drainage and gas recovery techniques struggle to meet the dynamic production demands. This study, using the deep CBM wells at the Jishen 15A platform as an example, proposes a “cyclic gas lift–wellhead compression-vent gas recovery” composite synergy technology. By selecting a critical liquid-carrying model, innovating equipment design, and dynamically regulating pressure, this approach enables efficient production from low-pressure, low-permeability gas wells. This research conducts a comparative analysis of different critical liquid-carrying velocity models and selects the Belfroid model, modified for well inclination angle effects, as the primary model to guide the matching of tubing production and annular gas injection parameters. A mobile vent gas rapid recovery unit was developed, utilizing a three-stage/two stage pressurization dual-process switching technology to achieve sealed vent gas recovery while optimizing pipeline frictional losses. By combining cyclic gas lift with wellhead compression, a dynamic wellbore pressure equilibrium system was established. Field tests show that after 140 days of implementation, the platform’s daily gas production increased to 11.32 × 10⁴ m³, representing a 35.8% rise. The average bottom-hole flow pressure decreased by 38%, liquid accumulation was reduced by 72%, and cumulative gas production increased by 370 × 10⁴ m³. This technology effectively addresses gas–liquid imbalance and liquid loading issues in the middle and late stages of deep CBM well production, providing a technical solution for the efficient development of low-permeability CBM reservoirs. Full article

Deep coal seams in the Junggar Basin, China, have demonstrated high gas yields due to enhanced pore structures resulting from hydraulic fracturing. However, raw coal samples inadequately represent these stimulated reservoirs, and acquiring fractured core samples post-stimulation is impractical. To address this, a novel and operable laboratory method has been developed to fabricate porosity-enhanced synthetic coal plugs that better simulate deep coalbed methane reservoirs. The fabrication process involves crushing lignite and separating it into three particle size fractions (<0.25 mm, 0.25–1 mm, and 1–2 mm), followed by mixing with a resin-based binder system (F51 phenolic epoxy resin, 650 polyamide, and tetrahydrofuran). These mixtures are molded into cylindrical plugs (⌀50 mm × 100 mm) and cured. This approach enables tailored control over pore development during briquette formation. Porosity and pore structure were comprehensively assessed using helium porosimetry, mercury intrusion porosimetry (MIP), and micro-computed tomography (micro-CT). MIP and micro-CT confirmed that the synthetic plugs exhibit significantly enhanced porosity compared to raw lignite, with pore sizes and volumes falling within the macropore range. Specifically, porosity reached up to 27.84%, averaging 20.73% and surpassing the typical range for conventional coal briquettes (1.89–18.96%). Additionally, the resin content was found to strongly influence porosity, with optimal levels between 6% and 10% by weight. Visualization improvements in micro-CT imaging were achieved through iodine addition, allowing for more accurate porosity estimations. This method offers a cost-effective and repeatable strategy for creating coal analogs with tunable porosity, providing valuable physical models for investigating flow behaviors in stimulated coal reservoirs. Full article

Deep coalbed methane (CBM) reservoirs have the characteristics of low permeability, low porosity, and low water saturation, which easily experience wellbore instability due to drilling fluid, severely affecting drilling safety. Based on the physical property analysis of coal samples, the wellbore instability mechanism of the deep CBM reservoir was investigated by multiple methods. It was found that the wellbore instability is mainly caused by drilling fluid intrusion and the interaction between drilling fluid and coal formation; the fracture pressure of coal after immersion decreased from 27.4 MPa to 25.0 MPa because of the imbibition of drilling fluid. A novel nano-plugging agent with a size of 460 nm was prepared that can cement coal particles to form disc-shaped briquettes with a tensile strength of 2.27 MPa. Based on that, an effective anti-collapse drilling fluid for deep coal rock reservoirs was constructed, the invasion depth of the optimized drilling fluid was only 6 mm. The CT result shows that the number of fractures and pores in coal rock significantly reduced after treatment with the wellbore-stabilizing drilling fluid; nano-plugging anti-collapse agent in drilling fluid can form a dense layer on the coal surface, and then the hydration swelling of clay in the wellbore region can be effectively suppressed. Finally, the drilling fluid in this work can achieve the purpose of sealing and wettability alternation to prevent the collapse of the wellbore in the deep coal reservoir. Full article

Deep coalbed methane (CBM) reservoirs hold substantial resource potential and play a crucial role in China’s unconventional natural gas development. However, the vertical propagation behavior of hydraulic fractures in deep CBM formations remains inadequately understood, posing challenges for optimizing fracturing parameters to control fracture height growth and enhance fracture development within the coal seam. To address this, this study establishes numerical simulation models to investigate hydraulic fracture propagation in directional wells, incorporating three typical lithological combinations representative of deep CBM reservoirs. Through these models, the influence mechanisms of bedding density, stress ratio, rock friction coefficient, and fracturing parameters on vertical fracture propagation and post-fracture productivity were systematically analyzed. The results reveal that the fracture propagation characteristics vary significantly with lithological combinations. Initially, hydraulic fractures penetrated adjacent formations near the wellbore while simultaneously generating branched fractures, leading to the formation of a complex fracture network. As propagation continues, branch fractures exhibited reduced width compared to the primary fracture. Well-developed bedding planes in the roof or floor, combined with lower stress ratios and friction coefficients, effectively constrained vertical fracture growth. Furthermore, optimizing fracturing fluid volume, reducing injection rate, and lowering proppant concentration promoted fracture development within the coal seam, thereby enhancing post-fracture well productivity. These findings provide a theoretical foundation for the optimization of hydraulic fracturing strategies in deep CBM reservoirs, contributing to more effective reservoir stimulation and resource recovery. Full article

To address the critical challenges of wellbore instability in deep coal seam drilling operations, this investigation developed an innovative organic–inorganic composite nanosealing agent (NS) through chemical modification of nano-silica. Advanced characterization techniques including Fourier Transform Infrared Spectroscopy, laser particle size analysis, and Scanning Electron Microscopy revealed that the optimized NS possessed a uniform particle distribution (mean diameter 86 nm) and enhanced surface hydrophobicity, effectively mitigating particle agglomeration. Systematic experimental evaluation demonstrated the material’s multifunctional performance: the NS-enriched drilling fluid achieved an 88.7% reduction in sand bed invasion depth and 76.4% decrease in filtrate loss at optimal concentration. Notably, comparative inhibition tests showed the NS outperformed conventional KCl and KPAM inhibitors, achieving 91.2% shale rolling recovery rate and 65.3% lower swelling rate than deionized water baseline. Core flooding experiments further confirmed superior sealing capability, with 2% NS addition attaining 88% sealing efficiency for low-permeability cores (0.5 mD) and establishing a 10 MPa breakthrough pressure threshold. Field implementation in the SSM1 well at Shenmu Huineng Liangshui Coal Mine validated the technical efficacy, the NS-enhanced drilling fluid system achieved 86.7% coal seam encounter rate with zero wellbore collapse incidents, while core recovery rate improved by 32.6% to 90.4% compared to conventional systems. This research breakthrough provides a scientific foundation for developing next-generation intelligent drilling fluids, demonstrating significant potential for ensuring drilling safety and enhancing gas recovery efficiency in deep coalbed methane reservoirs. Full article

This paper proposed a fracture propagation model of water-based fracturing based on seepage–stress–damage coupling, which was employed to analyse the effects of different water-based fracturing fluid properties and rock parameters on the propagation behaviour of reservoir fractures in low-permeability reservoirs. Concurrently, molecular dynamics theory and mechanical analysis of reservoir fractures were employed to elucidate the microscopic mechanism of water-based fracturing on fracture propagation. The results showed that the apparent viscosity of water-based fracturing fluid primarily contributed to elevated fracture internal pressures through the seepage reduction in water-based fracturing fluid at the coal fracture surface. A substantial impact on the minimum fracturing pressure of coal fractures that rapidly pierce the coal rock and an increasing crack extension was notably presented by the low filtration and high viscosity of water-based fracturing fluids. Furthermore, the reservoir pressure and the crack turning angle were not conducive to the effective expansion of coal seam fractures, whereas the reservoir temperature exhibited a positive proportional relationship with deep coal seam fractures. Full article

Hydraulic fracturing can significantly enhance coalbed methane production, with in-situ stress playing a crucial role in this process. Our study focuses on calculating in-situ stress in the deep 8+9# coal seam in the north-central Zijinshan block. Leveraging data from acoustic logging and hydraulic fracturing tests, we developed a stress prediction model tailored to the area’s geology. We analyzed stress’s impact on fracturing behavior and the origins of mechanical anisotropy in deep coal reservoirs using μ-CT imaging. Our results show that the Anderson-modified model, accounting for transverse isotropy, offers greater accuracy and applicability than traditional models. The study area exhibits a normal faulting stress regime with significant stress contrasts and maximum horizontal principal stress aligned with the east-west geological stress direction. After hydraulic fracturing, fractures form a complex fracture system resembling elongated ellipses in the coal reservoir, primarily extending in the vertical direction. To control fracture height and prevent penetration through the roof and floor, regulatory measures are essential. μ-CT analysis revealed the distribution of primary fractures, pores, and minerals in the coal, contributing to mechanical anisotropy. This research advances CBM development in the Zijinshan block and similar regions by refining stress prediction and fracturing propagation methods. Full article

To clarify the micropore structure and fractal characteristics of the Danning–Jixian block on the eastern margin of the Ordos Basin, this study focuses on the deep coal rock of the Benxi Formation in that area. On the basis of an analysis of coal quality and physical properties, qualitative and quantitative studies of pore structures with different pore diameters were conducted via techniques such as field emission scanning electron microscopy (FE-SEM), low-pressure CO₂ adsorption (LP-CO₂A), low-temperature N₂ adsorption (LT-N₂A), and high-pressure mercury intrusion (HPMI). By applying fractal theory and integrating the results from the LP-CO₂A, LT-N₂A, and HPMI experiments, the fractal dimensions of pores with different diameters were obtained to characterize the complexity and heterogeneity of the pore structures of the coal samples. The results indicate that the deep coal reservoirs in the Danning–Jixian block have abundant nanometer-scale organic matter gas pores, tissue pores, and a small number of intergranular pores, showing strong heterogeneity influenced by the microscopic components and forms of distribution of organic matter. The pore structure of the Benxi Formation exhibits significant cross-scale effects and strong heterogeneity and is predominantly composed of micropores that account for more than 90% of the total pore volume; the pore structure is affected mainly by the degree of coalification, the vitrinite group, and the ash yield. Fractal analysis reveals that the heterogeneity of macropores is greater than that of mesopores and micropores. This may be attributed to the smaller pore sizes and concentrated distributions of micropores, which are less influenced by diagenesis, resulting in simpler pore structures with lower fractal dimensions. In contrast, mesopores and macropores, with larger diameters and broader distributions, exhibit diverse origins and are more affected by diagenesis, reflecting strong heterogeneity. The abundant storage space and strong self-similarity of micropores in deep coal facilitate the occurrence, flow, and extraction of deep coalbed methane. Full article

The deep coal seams in the southern Sichuan region contain abundant coalbed methane resources. Determining the characteristics and distribution patterns of coal structures in this study area, and analyzing their impact on pore and fracture structures within coal reservoirs, holds substantial theoretical and practical significance for advancing coal structure characterization methods and the efficient development of deep coalbed methane resources. This paper quantitatively characterizes coal structures through coal core observations utilizing the Geological Strength Index (GSI) and integrates logging responses from different coal structures to develop a quantitative coal structure characterization model based on logging curves. This model predicts the spatial distribution of coal structures, while nitrogen adsorption data are used to analyze the development of pores and fractures in different coal structures, providing a quantitative theoretical basis for accurately characterizing deep coal seam features. Results indicate that density, gamma, acoustic, and caliper logging are particularly sensitive to coal structure variations and that performing multiple linear regression on logging data significantly enhances the accuracy of coal structure identification. According to the model proposed in this paper, primary-fragmented structures dominate the main coal seams in the study area, followed by fragmented structures. Micropores and small pores predominantly contribute to the volume and specific surface area of the coal samples, with both pore volume and specific surface area increasing alongside the degree of coal fragmentation. Additionally, the fragmentation of coal structures generates more micropores, enhancing pore volume and suggesting that tectonic coal has a greater adsorption capacity. This study combines theoretical analysis with experimental findings to construct a coal structure characterization model for deep coal seams, refining the limitations of logging techniques in accurately representing deep coal structures. This research provides theoretical and practical value for coal seam drilling, fracturing, and reservoir evaluation in the southern Sichuan region. Full article

Deep coalbed methane (CBM) demonstrates significant production potential, and a fervent exploration and development boom is currently underway in China. The permeability of coal reservoirs is heavily influenced by pore–fracture structure heterogeneity. Some researches have been conducted on deep coals’ pore–fracture structure; however, these studies mostly consider coal as a homogeneous material, neglecting the heterogeneity of the macrolithotypes within the coal. In this study, 33 deep coals with burial depths of more than 2000 m were obtained from the Daning-Jixian block of the Ordos Basin, covering all macrolithotypes: bright coal (BC), semi-bright coal (SBC), semi-dull coal (SDC), and dull coal (DC). These samples were subjected to three sets of NMR tests in dry, fully saturated, and irreducible water conditions, with the pore–fracture structure characteristics being analyzed. The results demonstrate that the sampled deep coals’ pore–fracture structure is highly heterogeneous, with transitional pores being dominant, followed by mesopores, “macropores and fractures”, and micropores. The NMR T_2C ranges from 0.61 to 2.44 ms, with an average of 1.19 ms; a higher T_2C value indicates more developed micropores. The ranges for producible water porosity (φ_pr) and producible water saturation (S_pr) are 0.31–7.24% (avg. 2.42%) and 6.97–71.47% (avg. 31.06%), respectively. Both of them exhibit a high positive correlation with the total volumes of “macropores and fractures” and mesopores. Compared to SDC and DC, the BC and SBC, especially the former, overall contain more “macropores and fractures” and mesopores, fewer transitional pores and micropores, and higher φ_pr and S_pr. These findings suggest that regions with abundant BC and SBC should be prioritized during deep CBM exploration and production due to the inherently superior permeability and gas extraction potential of BC and SBC, and these coals are likely to require less intensive stimulation to achieve higher recovery rates and could provide more sustainable gas production over time. Full article

Coalbed Methane (CBM) accounts for about 5% of China’s domestic gas supply, which has been regarded as one of the most promising energies for alleviating the energy supply–demand imbalance. Deep CBM reservoirs have the characteristics of low permeability, low porosity, and low water saturation, which easily experience reservoir damage during the drilling process, further affecting the gas productivity. Based on the analysis of coal mineral composition, pore structure distribution, and the surface micromorphology change in coal surface before and after hydration, a possible mechanism for CBM formation damage was revealed. It was found that the damage caused by drilling fluid intrusion can be divided into three stages: stripping, migration, and plugging. Based on the water-sensitive, acid-sensitive, and stress-sensitive evaluation tests, a novel anti-waterblocking agent with both wettability alteration and surface tension reduction was developed; then a reservoir protection drilling fluid for deep coal formation in Daning-Jixian block was constructed; then the reservoir protection performance of drilling fluid was evaluated. The results show that as the concentration of the anti-waterblocking agent FSS increases from 0% to 1%, the surface tension of the water phase is significantly reduced from 72.15 mN/m to 26.58 mN/m, while the maximum contact angle of water on the surface reaches 117°. This enhancement in wettability leads to an improvement in the permeability recovery rate from 56.6% to 80.0%, indicating a substantial reduction in waterblocking effects and better fluid mobility within the reservoir. These findings highlight the efficacy of FSS in mitigating formation damage and optimizing gas production in coalbed methane reservoirs. The drilling fluid has good wettability alteration, inhibition, and sealing performance, which is of great significance for protecting gas well productivity. Full article

Deep coalbed methane (CBM) resources are abundant in China, and in the last few years, the country’s search for and extraction of CBM have intensified, progressively moving from shallow to deep strata and from high-rank coal to medium- and low-rank coal. On the other hand, little is known about the gas content features of deep coal reservoirs in the eastern Junggar Basin, especially with regard to the gas content and the factors that affect it. Based on data from CBM drilling, logging, and seismic surveys, this study focuses on the gas content of Baijiahai Uplift’s primary Jurassic coal seams through experiments on the microscopic components of coal, industrial analysis, isothermal adsorption, low-temperature CO₂, low-temperature N₂, and high-pressure mercury injection. A systematic investigation of the controlling factors, including the depth, thickness, and quality of the coal seam and pore structure; tectonics; and lithology and thickness of the roof, was conducted. The results indicate that the Xishanyao Formation in the Baijiahai Uplift usually has a larger gas content than that in the Badaowan Formation, with the Xishanyao Formation showing that free gas and adsorbed gas coexist, while the Badaowan Formation primarily consists of adsorbed gas. The coal seams in the Baijiahai Uplift are generally deep and thick, and the coal samples from the Xishanyao and Badawan formations have a high vitrinite content, which contributes to their strong gas generation capacity. Additionally, low moisture and ash contents enhance the adsorption capacity of the coal seams, facilitating the storage of CBM. The pore-specific surface area of the coal samples is primarily provided by micropores, which is beneficial for CBM adsorption. Furthermore, a fault connecting the Carboniferous and Permian systems (C-P) developed in the northeastern part of the Baijiahai Uplift allows gas to migrate into the Xishanyao and Badaowan formations, resulting in a higher gas content in the coal seams. The roof lithology is predominantly mudstone with significant thickness, effectively reducing the dissipation of coalbed methane and promoting its accumulation. Full article

The development of deep coalbed methane has become an important way to obtain natural gas in China. The development of deep CBM mainly depends on horizontal well technology. The different orientations of horizontal wells will have an important impact on the productivity of coalbed methane wells. The angle grid geological model of coalbed methane reservoirs with different inclination angles is established, and the deployment orientation of horizontal wells is changed to study the optimal deployment orientation of deep-saturated coalbed methane reservoirs. When CBM horizontal wells in deep saturated CBM reservoirs are deployed upward along the dip, well-controlled reserves, peak daily gas production, and cumulative gas production increase as the dip decreases. When deploying down the dip, with the increase in dip angle, the well-controlled reserves increase, and the peak daily gas production and cumulative gas production first increase and then decrease. In the low-dip reservoir, the development effect of horizontal wells deployed in different directions is better than that in the up-dip direction. In the high-dip reservoir, the development effect of horizontal wells deployed along the strike is better than that in the up-dip and down-dip directions. The development effect of horizontal wells is controlled by both well-controlled reserves and reservoir pressure drop. Because this method is targeted at different geological conditions, it can be used to guide the horizontal well optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs. Full article