Search Results (55)

Deep coalbed methane (CBM) reservoirs are characterized by high hydrocarbon content and are considered an important strategic resource. Due to their inherently low permeability and porosity, horizontal well drilling is commonly employed to enhance production, with the length of the horizontal section playing a critical role in determining CBM output. However, during extended horizontal drilling, wellbore instability frequently occurs as a result of drilling fluid invasion into the coal formation, posing significant safety challenges. This instability is primarily caused by the physical intrusion of drilling fluids and their interactions with the coal seam, which alter the mechanical integrity of the formation. To address these challenges, interpenetrating and semi-interpenetrating network (IPN/s-IPN) hydrogels have gained attention due to their superior physicochemical properties. This material offers enhanced sealing and support performance across fracture widths ranging from micrometers to millimeters, making it especially suited for plugging applications in deep CBM reservoirs. A self-degradable interpenetrating double-network hydrogel particle plugging agent (SSG) was developed in this study, using polyacrylamide (PAM) as the primary network and an ionic polymer as the secondary network. The SSG demonstrated excellent thermal stability, remaining intact for at least 40 h in simulated formation water at 120 °C with a degradation rate as high as 90.8%, thereby minimizing potential damage to the reservoir. After thermal aging at 120 °C, the SSG maintained strong plugging performance and favorable viscoelastic properties. A drilling fluid containing 2% SSG achieved an invasion depth of only 2.85 cm in an 80–100 mesh sand bed. The linear viscoelastic region (LVR) ranged from 0.1% to 0.98%, and the elastic modulus reached 2100 Pa, indicating robust mechanical support and deformation resistance. Full article

The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article

Based on a detailed investigation of the geological setting of coalbed methane by previous work in the Xiangzhong Depression, Hunan Province, numerical simulation methods were used to simulate the geological storage of carbon dioxide and displacement gas production in this area. In this simulation, a 400 m × 400 m square well group was constructed for coalbed methane production, and a carbon dioxide injection well was arranged in the center of the well group. Injection storage and displacement gas production simulations were carried out under the conditions of original permeability and 1 mD permeability. At the initial permeability (0.01 mD), carbon dioxide is difficult to inject, and the production of displaced and non-displaced coalbed methane is low. During the 25-year injection process, the reservoir pressure only increased by 7 MPa, and it is difficult to reach the formation fracture pressure. When the permeability reaches 1 mD, the carbon dioxide injection displacement rate can reach 4000 m³/d; the cumulative production of displaced and non-displaced coalbed methane is 7.83 × 10⁶ m³ and 9.56 × 10⁵ m³, respectively, and the average daily production is 1430 m³/d and 175 m³/d. The displacement effect is significantly improved compared to the original permeability. In the later storage stage, the carbon dioxide injection rate can reach 8000 m³/d, reaching the formation rupture pressure after 3 years, and the cumulative carbon dioxide injection volume is 1.17 × 10⁷ m³. This research indicates that permeability has a great impact on carbon dioxide geological storage. During the carbon dioxide injection process, selecting areas with high permeability and choosing appropriate reservoir transformation measures to enhance permeability are key factors in increasing the amount of carbon dioxide injected into the area. Full article

This study systematically investigates the pore–fracture architecture of deep coal seams in the JiaTan (JT) block of the Ordos Basin using an integrated suite of advanced techniques, including nuclear magnetic resonance (NMR), high-pressure mercury intrusion, low-temperature nitrogen adsorption, low-pressure carbon dioxide adsorption, and micro-computed tomography (micro-CT). These complementary methods enable a quantitative assessment of pore structures spanning nano- to microscale dimensions. The results reveal a pore system overwhelmingly dominated by micropores—accounting for more than 98% of the total pore volume—which play a central role in coalbed methane (CBM) storage. Microfractures, although limited in volumetric proportion, markedly enhance permeability by forming critical flow pathways. Together, these features establish a dual-porosity system that governs methane transport and recovery in deep coal reservoirs. The multiscale characterization employed here proves essential for resolving reservoir heterogeneity and designing effective stimulation strategies. Notably, enhancing methane desorption in micropore-rich matrices and improving fracture connectivity are identified as key levers for optimizing deep CBM extraction. These insights offer a valuable foundation for the development of deep coalbed methane (DCBM) resources in the Ordos Basin and similar geological settings. Full article

Coalbed methane (CBM), a significant unconventional natural gas resource, holds a crucial position in China’s ongoing energy structure transformation. However, the inherent low permeability, high brittleness, and strong sensitivity of CBM reservoirs to drilling fluids often lead to severe formation damage during drilling operations, consequently impairing well productivity. To address these challenges, this study developed a novel low-damage, plugging, and anti-collapse water-based drilling fluid gel system (ACWD) specifically designed for coalbed methane drilling. Laboratory investigations demonstrate that the ACWD system exhibits superior overall performance. It exhibits stable rheological properties, with an initial API filtrate loss of 1.0 mL and a high-temperature, high-pressure (HTHP) filtrate loss of 4.4 mL after 16 h of hot rolling at 120 °C. It also demonstrates excellent static settling stability. The system effectively inhibits the hydration and swelling of clay and coal, significantly reducing the linear expansion of bentonite from 5.42 mm (in deionized water) to 1.05 mm, and achieving high shale rolling recovery rates (both exceeding 80%). Crucially, the ACWD system exhibits exceptional plugging performance, completely sealing simulated 400 µm fractures with zero filtrate loss at 5 MPa pressure. It also significantly reduces core damage, with an LS-C1 core damage rate of 7.73%, substantially lower than the 19.85% recorded for the control polymer system (LS-C2 core). Field application in the JX-1 well of the Ordos Basin further validated the system’s effectiveness in mitigating fluid loss, preventing wellbore instability, and enhancing drilling efficiency in complex coal formations. This study offers a promising, relatively environmentally friendly, and cost-effective drilling fluid solution for the safe and efficient development of coalbed methane resources. Full article

This study presents a comprehensive multifractal characterization of full-scale pore structures in middle- to high-rank coal reservoirs from the Western Guizhou–Eastern Yunnan Basin and establishes a permeability prediction model integrating fractal heterogeneity and pore throat parameters. Eight coal samples were analyzed using mercury intrusion porosimetry (MIP), low-pressure gas adsorption (N₂/CO₂), and multifractal theory to quantify multiscale pore heterogeneity and its implications for fluid transport. Results reveal weak correlations (R² < 0.39) between conventional petrophysical parameters (ash yield, volatile matter, porosity) and permeability, underscoring the inadequacy of bulk properties in predicting flow behavior. Full-scale pore characterization identified distinct pore architecture regimes: Laochang block coals exhibit microporous dominance (0.45–0.55 nm) with CO₂ adsorption capacities 78% higher than Tucheng samples, while Tucheng coals display enhanced seepage pore development (100–5000 nm), yielding 2.5× greater stage pore volumes. Multifractal analysis demonstrated significant heterogeneity (Δα = 0.98–1.82), with Laochang samples showing superior pore uniformity (D₁ = 0.86 vs. 0.82) but inferior connectivity (D₂ = 0.69 vs. 0.71). A novel permeability model was developed through multivariate regression, integrating the heterogeneity index (Δα) and effective pore throat diameter (D₁₀), achieving exceptional predictive accuracy. The strong negative correlation between Δα and permeability (R = −0.93) highlights how pore complexity governs flow resistance, while D₁₀’s positive influence (R = 0.72) emphasizes throat size control on fluid migration. This work provides a paradigm shift in coal reservoir evaluation, demonstrating that multiscale fractal heterogeneity, rather than conventional bulk properties, dictates permeability in anisotropic coal systems. The model offers critical insights for optimizing hydraulic fracturing and enhanced coalbed methane recovery in structurally heterogeneous basins. Full article

The acidification modification treatment of coal is a key technical means to improve the permeability of coal seams and enhance the efficiency of coalbed methane extraction. Yet, current acidic fracturing fluids are highly corrosive, corroding downhole pipelines and contaminating groundwater. By compounding environmentally friendly and non-polluting acidic fracturing fluids and combining fractal theory and the Frenkel–Halsey–Hill (FHH) model, this paper systematically investigates their effects on the pore structure, permeability, and mechanical properties of coal bodies. It was found that the complex acid treatment significantly reduced the surface fractal dimension D₁ and spatial fractal dimension D₂ of the coal samples and optimized pore connectivity, thus improving gas transport efficiency. Meanwhile, a static splitting test and digital image analysis showed that the fracture evolution pattern of the treated coal samples changed from a centralized strain extension of the original coal to a discrete distribution, peak stress and strain were significantly reduced, and permeability was significantly increased. These findings can offer dramatic support for the optimal optimization of acidic fracturing fluids. Full article

Gas extraction is an important means to reduce coalbed gas and ensure safe coal production. Injecting N₂/CO₂ into a coalbed can enhance coal seam gas extraction, but problems with N₂/CO₂ sources underground have prevented the wide application of this technology in coal mines. The air contains a large amount of N₂, but only a few studies have investigated the injection of air into coalbeds to facilitate gas extraction. In this study, a thermal–hydraulic–solid coupling model for air-enhanced coalbed gas extraction (Air-ECGE) was established. Additionally, the impact of air injection on coalbed methane extraction was simulated, and field experiments were conducted on air injection to enhance gas extraction. The results showed that injecting high-pressure air into a coalbed can effectively facilitate gas desorption and gas migration within the coalbed, greatly improving the efficiency of gas extraction in the coalbed. In addition, owing to the large pressure gradient that can lead to fast coalbed gas seepage, the gas production rate of the extraction borehole is directly proportional to the gas injection pressure. Further, the spacing of the boreholes limits the influence range of the gas injection: the larger the spacing, the larger the influence range, and the higher the gas extraction rate of the extraction borehole. After injecting air into the coalbed of the Liuzhuang coal mine, the extraction flow rate and concentration of gas from the extraction boreholes both increased significantly. A certain delay effect was also observed in the gas injection effect, and the gas extraction flow rate only decreased after a period of time after the gas injection had stopped. Full article

The Zhengzhuang Block in the Qinshui Basin is one of the important coalbed methane (CBM) development areas in China. As high-quality CBM resources become depleted, remaining reserves exhibit complex geological characteristics requiring advanced development strategies. In this study, a multidisciplinary workflow integrating 3D geological modeling (94.85 km² seismic data, 973 wells), geomechanical stress analysis, and production simulation was developed to optimize development of the Permian No. 3 coal seam. Structural architecture and reservoir heterogeneity were characterized through Petrel-based modeling, while finite-element analysis identified stress anisotropy with favorable stimulation zones concentrated in southwestern sectors. Computer Modeling Group (CMG) simulations of a 27-well group revealed a rapid initial pressure decline followed by a stabilization phase. A weighted multi-criteria evaluation framework classified resources into three tiers: type I (southwestern sector: 28–33.5 m³/t residual gas content, 0.8–1.0 mD permeability, 8–12% porosity), type II (northern/central: 20–26 m³/t residual gas content, 0.5–0.6 mD permeability, 5–8% porosity), and type III (<20 m³/t residual gas content, <0.4 mD permeability, <4% porosity). The integrated methodology provides a technical foundation for optimizing well patterns, enhancing hydraulic fracturing efficacy, and improving residual gas recovery in heterogeneous CBM reservoirs. 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

Low permeability has always limited the efficient extraction of coalbed methane (CBM) in China. To investigate the permeability enhancement effect of supercritical CO₂ on coal seams, experiments were conducted using a self-developed supercritical CO₂ immersion system and a single-component gas (CO₂ and CH₄) seepage experimental apparatus, considering different immersion times and injection pressures. The gas seepage characteristics of CO₂ and CH₄ in coal seams were studied under various conditions. Additionally, nuclear magnetic resonance (NMR) was used to obtain the porosity components of the coal samples at different immersion times. The changes in permeability before and after the experiment were compared to analyze the permeability enhancement effect of supercritical CO₂ on the coal samples. The results show that the original porosity of the coal sample was 2.06%. After 5, 10, 15, and 20 days of immersion, the porosity of the coal samples increased by 2.78%, 3.26%, 3.22%, and 2.86%, respectively. After immersion in supercritical CO₂, the porosity exhibited a trend of initially increasing and then decreasing. During the single-component gas seepage experiment following supercritical CO₂ immersion, the outlet flow rates of both CO₂ and CH₄ reached their maximum on the 10th day of immersion. Compared with the 0-day immersion, the outlet flow rates of CO₂ and CH₄ increased by 4.49 times and 3.23 times, respectively. After immersion, the CH₄ permeability within the coal sample was stronger than that of CO₂. Full article

The acidification modification of coal seams is a significant technical measure for transforming coalbed methane reservoirs and enhancing the permeability of coal seams, thereby improving the extractability of coalbed methane. However, the acids currently used in fracturing fluids are predominantly inorganic acids, which are highly corrosive and can contaminate groundwater reservoirs. In contrast, organic acids are not only significantly less corrosive than inorganic acids but also readily bind with the coal matrix. Some organic acids even exhibit complexing and flocculating effects, thus avoiding groundwater contamination. This study focuses on the 1/3 coking coal from the Guqiao Coal Mine of Huainan Mining Group Co., Ltd., in China. It systematically investigates the fractal characteristics and chemical structure of coal samples before and after pore modification using four organic acids (acetic acid, glycolic acid, oxalic acid, and citric acid) and compares their effects with those of hydrochloric acid solutions at the same concentration. Following treatment with organic acids, the coal samples exhibit an increase in surface fractal dimension, a reduction in spatial fractal dimension, a decline in micropore volume proportion, and a rise in the proportions of transitional and mesopore volumes, and the structure of the hydroxyl group and oxygen-containing functional group decreased. This indicates that treating coal samples with organic acids enhances their pore structure and chemical structure. A comparative analysis reveals that hydrochloric acid is more effective than acetic acid in modifying coal pores, while oxalic acid and citric acid outperform hydrochloric acid, and citric acid shows the best results. The findings provide essential theoretical support for organic acidification modification technology in coalbed methane reservoirs and hydraulic fracturing techniques for coalbed methane extraction. Full article

Coalbed methane (CBM), a highly efficient and clean energy source with substantial reserves, holds significant development potential. Permeability is a crucial factor in CBM recovery in underground coal mines. Hydraulic fracturing technology causes water to enter the coal reservoir, which will change mechanical properties, affecting permeability changes and gas depletion trends. This study combines theoretical analysis with numerical simulation techniques to create a coupling model for fluid flow and reservoir deformation. The numerical model is established by referring to the geological conditions of the Wangpo coal mine, Shanxi province. Specifically, the impact of water immersion-induced softening and changes in the anisotropic mechanical properties on the directional permeability and gas flow rate is examined through parametric analysis. The dominant role in controlling the evolution of permeability varies depending on the orientation. Horizontal deformation primarily affects vertical permeability, which is subsequently influenced by the gas adsorption effect. In contrast, horizontal permeability is mainly determined by vertical deformation. Water immersion-induced softening significantly reduces the permeability and gas flow rate. Young’s modulus, which is dependent on water saturation, alters the permeability trend under water-rich conditions. Vertical permeability evolution is more sensitive to water-induced softening and changes in the anisotropic mechanical properties. When S_w0 is 0.7, the vertical permeability decreases by 60%, while the horizontal permeability decreases by 43%. Ultimately, the vertical permeability ratio stabilizes between 0.9 and 1.0, while the horizontal permeability ratio stabilizes in the range of 0.6 to 0.7. The influence of permeability on gas production characteristics is dependent on the water saturation conditions. In water-scarce conditions, variations in the fracture permeability greatly influence production flow rates. Conversely, in water-rich conditions, a higher permeability facilitates a quicker return to original levels and also enhances gas production flow rates. The research findings from this study provide important insights for fully understanding the mechanical properties of coal and ensuring the sustainable production of CBM. Full article

Permeability variations during coalbed methane (CBM) production remain a critical research focus. However, existing studies have primarily concentrated on nearly horizontal reservoirs, with limited in-depth analyses of the dynamic evolution of permeability in steeply inclined coal reservoirs (SICRs) (>45°). This study examined the dynamic permeability characteristics across different reservoir dip angles, comparing variations in the up-dip (UD) and down-dip (DD) directions of SICRs and investigating their controlling mechanisms. The results indicate an asymmetry in permeability changes between UDs and DDs, with UDs generally exhibiting a greater amplitude of variation. The reservoir dip angle exerts a more pronounced influence on DD permeability changes, primarily through its effects on effective stress (ES) and matrix shrinkage (MS). Specifically, a reduction in the negative impact of ES in the UD enhances the overall reservoir permeability, whereas a reduction in the positive effect of MS in the DD leads to a more significant permeability decline. The comparatively smaller increase in DD permeability contributes to distinct evolutionary trends in the permeability between UDs and DDs. These dynamic permeability changes in SICRs have a more substantial impact on CBM production, particularly in low-strength and low-rank coal reservoirs. The findings of this study provide valuable insights for optimizing CBM production strategies in SICRs. 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