Search Results (229)

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

The development of deep coalbed methane (buried depth > 2000 m) in the Yan’an block of Ordos Basin is limited by low permeability, the pore structure of the coal reservoir, and the gas–water occurrence relationship. It is urgent to clarify the key control mechanism of pore structure on gas migration. In this study, based on high-pressure mercury intrusion (pore size > 50 nm), low-temperature N₂/CO₂ adsorption (0.38–50 nm), low-field nuclear magnetic resonance technology, fractal theory and Pearson correlation coefficient analysis, quantitative characterization of multi-scale pore–fluid system was carried out. The results show that the multi-scale pore network in the study area jointly regulates the occurrence and migration process of deep coalbed methane in Yan’an through the ternary hierarchical gas control mechanism of ‘micropore adsorption dominant, mesopore diffusion connection and macroporous seepage bottleneck’. The fractal dimensions of micropores and seepage are between 2.17–2.29 and 2.46–2.58, respectively. The shape of micropores is relatively regular, the complexity of micropore structure is low, and the confined space is mainly slit-like or ink bottle-like. The pore-throat network structure is relatively homogeneous, the difference in pore throat size is reduced, and the seepage pore shape is simple. The bimodal structure of low-field nuclear magnetic resonance shows that the bound fluid is related to the development of micropores, and the fluid mobility mainly depends on the seepage pores. Pearson’s correlation coefficient showed that the specific surface area of micropores was strongly positively correlated with methane adsorption capacity, and the nanoscale pore-size dominated gas occurrence through van der Waals force physical adsorption. The specific surface area of mesopores is significantly positively correlated with the tortuosity. The roughness and branch structure of the inner surface of the channel lead to the extension of the migration path and the inhibition of methane diffusion efficiency. Seepage porosity is linearly correlated with gas permeability, and the scale of connected seepage pores dominates the seepage capacity of reservoirs. This study reveals the pore structure and ternary grading synergistic gas control mechanism of deep coal reservoirs in the Yan’an Block, which provides a theoretical basis for the development of deep coalbed methane. Full article

In comparison to shallow coal seams, deep coal seams exhibit characteristics of high temperature, pressure, and in-situ stress, leading to significant differences in reservoir properties that constrain the effective development of deep coalbed methane (CBM). This study takes the Carboniferous deep 8# coal seam in the Yulin area of Ordos basin as the research subject. Based on the test results from core drilling wells, a comprehensive analysis of the characteristics and variation patterns of coal reservoir properties and a comparative analysis of the exploration and development potential of deep CBM are conducted, aiming to provide guidance for the development of deep CBM in the Ordos basin. The research results indicate that the coal seams are primarily composed of primary structure coal, with semi-bright to bright being the dominant macroscopic coal types. The maximum vitrinite reflectance (R_o,max) ranges between 1.99% and 2.24%, the organic is type III, and the high Vitrinite content provides a substantial material basis for the generation of CBM. Longitudinally, influenced by sedimentary environment and plant types, the lower part of the coal seam exhibits higher Vitrinite content and fixed carbon (FC_ad). The pore morphology is mainly characterized by wedge-shaped/parallel plate-shaped pores and open ventilation pores, with good connectivity, which is favorable for the storage and output of CBM. Micropores (<2 nm) have the highest volume proportion, showing an increasing trend with burial depth, and due to interlayer sliding and capillary condensation, the pore size (<2 nm) distribution follows an N shape. The full-scale pore heterogeneity (fractal dimension) gradually increases with increasing buried depth. Macroscopic fractures are mostly found in bright coal bands, while microscopic fractures are more developed in Vitrinite, showing a positive correlation between fracture density and Vitrinite content. The porosity and permeability conditions of reservoirs are comparable to the Daning–Jixian block, mostly constituting oversaturated gas reservoirs with a critical depth of 2400–2600 m and a high proportion of free gas, exhibiting promising development prospects, and the middle and upper coal seams are favorable intervals. In terms of resource conditions, preservation conditions, and reservoir alterability, the development potential of CBM from the Carboniferous deep 8# coal seam is comparable to the Linxing block but inferior to the Daning–Jixian block and Baijiahai uplift. Full article

Water within coal reservoirs exerts dual effects on methane adsorption–desorption by competing for adsorption sites and reducing permeability. The bound water effect, caused by coal wettability, significantly constrains coalbed methane (CBM) production, rendering investigations into coal wettability crucial for efficient CBM development. Compared with other geological formations, coals are characterized by a highly developed microporous structure, making the CO₂ sequestration mechanism in coal seams closely linked to the microscale interactions among gas, water, and coal matrixes. However, the intrinsic mechanisms remain poorly understood. In this study, molecular dynamics simulations are employed to investigate the wettability behaviors of CO₂, CH₄, and water on different coal matrix surfaces under varying temperature and pressure conditions, for coal macromolecules representative of four coal ranks. The study reveals the evolution of water wettability in response to CO₂ and CH₄ injection, identifies wettability differences among coal ranks, and analyzes the microscopic mechanisms governing wettability. The results show the following: (1) The contact angle increases with gas pressure, and the variation in wettability is more pronounced in CO₂ environments than in CH₄. As pressure increases, the number of hydrogen bonds decreases, while the peak gas density of CH₄ and CO₂ increases, leading to larger contact angles. (2) Simulations under different temperatures for the four coal ranks indicate that temperature has minimal influence on low-rank Hegu coal, whereas for higher-rank coals, gas adsorption on the coal surface increases, resulting in reduced wettability. Interfacial tension analysis further suggests that higher temperatures reduce water surface tension, cause dispersion of water molecules, and consequently improve wettability. Understanding the wettability variations among different coal ranks under variable pressure–temperature conditions provides a fundamental model and theoretical basis for investigating deep coal seam gas–water interactions and CO₂ geological sequestration mechanisms. These findings have significant implications for the advancement of CO₂-ECBM technology. Full article

The mechanism of low- to middle-rank coal seam gas accumulation in the Baode block on the eastern edge of the Ordos Basin is well understood. However, exploration efforts in the Shizuishan area on the western edge started later, and the current understanding of enrichment and accumulation rules is unclear. It is important to systematically study enrichment and accumulation, which guide the precise exploration and development of coal seam gas resources in the western wing of the basin. The coal seam collected from the Shizuishan area of Ningxia was taken as the target. Based on drilling, logging, seismic, and CBM (coalbed methane) test data, geological conditions were studied, and factors and reservoir formation modes of CBM enrichment were summarized. The results are as follows. The principal coal-bearing seams in the study area are coal seams No. 2 and No. 3 of the Shanxi Formation and No. 5 and No. 6 of the Taiyuan Formation, with thicknesses exceeding 10 m in the southwest and generally stable thickness across the region, providing favorable conditions for CBM enrichment. Spatial variations in burial depth show stability in the east and south, but notable fluctuations are observed near fault F1 in the west and north. These burial depth patterns are closely linked to coal rank, which increases with depth. Although the southeastern region exhibits a lower coal rank than the northwest, its variation is minimal, reflecting a more uniform thermal evolution. Lithologically, the roof of coal seam No. 6 is mainly composed of dense sandstone in the central and southern areas, indicating a strong sealing capacity conducive to gas preservation. This study employs a system that fuses multi-source geological data for analysis, integrating multi-dimensional data such as drilling, logging, seismic, and CBM testing data. It systematically reveals the gas control mechanism of “tectonic–sedimentary–fluid” trinity coupling in low-gentle slope structural belts, providing a new research paradigm for coalbed methane exploration in complex structural areas. It creatively proposes a three-type CBM accumulation model that includes the following: ① a steep flank tectonic fault escape type (tectonics-dominated); ② an axial tectonic hydrodynamic sealing type (water–tectonics composite); and ③ a gentle flank lithology–hydrodynamic sealing type (lithology–water synergy). This classification system breaks through the traditional binary framework, systematically explaining the spatiotemporal matching relationships of the accumulated elements in different structural positions and establishing quantitative criteria for target area selection. It systematically reveals the key controlling roles of low-gentle slope structural belts and slope belts in coalbed methane enrichment, innovatively proposing a new gentle slope accumulation model defined as “slope control storage, low-structure gas reservoir”. These integrated results highlight the mutual control of structural, thermal, and lithological factors on CBM enrichment and provide critical guidance for future exploration in the Ningxia Autonomous Region. 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

To elucidate the gas adsorption characteristics of medium-rank coal, this study collected samples from fresh mining faces in the Qinshui Basin. A series of experiments were conducted, including low-temperature carbon dioxide adsorption, low-temperature liquid nitrogen adsorption, mercury intrusion, and methane isothermal adsorption experiments, which clarify the pore structure characteristics of medium-rank coals, reveal the gas adsorption behavior in medium-rank coal, and identify the control mechanism. The results demonstrate that the modified Dubinin–Radushkevich (D-R) isothermal adsorption model accurately describes the gas adsorption in medium-rank coal, with fitting errors remaining below 1%. Comprehensive pore structure analysis reveals that the coal pore volume consists primarily of absorption pores (<2 nm), transitional pores (10–100 nm), and seepage pores (>100 nm), while the specific surface area is predominantly contributed by absorption pores (<2 nm). At low pressures, gas molecules form monolayer adsorption on absorption pore (<2 nm) and adsorption pore (2–10 nm) surfaces. With increasing pressure, multilayer adsorption dominates. As pore filling approaches the maximum capacity, the adsorption rate decreases progressively until reaching an equilibrium, at which point the adsorption capacity attains its saturation limit. The adsorption data of the gas in medium-rank coal can be explained by the improved D-R isothermal adsorption model. The priority of gas filling in pores is different, and the absorption pore is normally better than the adsorption pore. The results provide a new idea and understanding for the further study of the coalbed gas adsorption mechanism. Full article

The extensive use of coal in the steel metallurgy sector has resulted in significant greenhouse gas emissions. Hydrogen-rich gases have been introduced to partially replace coal in the blast furnace reduction process to mitigate this issue. This research explores using abundant coalbed methane (CBM) resources near steel plants for metallurgical applications. Addressing the challenge of determining optimal process parameters in hydrogen-rich blast furnace smelting, this project first develops an energy and mass balance model for the hydrogen-rich blast furnace, providing a foundation for process analysis. Using this model, the substitution ratio and oxygen enrichment rate of the blast furnace are calculated under varying preheating temperatures of coalbed methane. Additionally, this study assesses carbon dioxide emission patterns based on the elemental balance principle, emphasizing the potential of coalbed methane to reduce carbon emissions and support low-carbon metallurgical development. 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

During the drainage process of coalbed methane (CBM) horizontal wells, wellbore fluctuations exert a significant influence on gas–liquid–solid three-phase flow behavior and coal particle migration. This study investigates the effects of wellbore inclination, gas–liquid flow rates, and coal particle sizes on migration characteristics through laboratory-scale experiments, based on an initial analysis of coal particle physical properties. A critical velocity model accounting for wellbore fluctuations is developed and refined. The migration states of coal particles under various operational conditions are examined, and the corresponding critical velocities and movement patterns are analyzed. The results show that coal particle migration is predominantly governed by the liquid phase, while the presence of particles has limited impact on the overall gas–liquid flow regime. Under different wellbore inclinations, the critical velocity increases with particle size; however, the influence of inclination is more pronounced than that of particle size. Coal particle entrainment follows three distinct stages: hopping, rolling, and suspension. The velocity during the rolling stage is identified as the critical velocity. At steeper inclination angles, particles are more easily entrained by the flow, and the associated critical velocity is higher. Based on the fitted experimental data, the model is revised to improve its predictive capability for coal particle transport in CBM wells. Finally, the model is validated using field data from a CBM well in the Ordos Basin. The results confirm the model’s ability to predict coal particle accumulation trends within the wellbore. This study provides new insights into coal particle migration mechanisms under fluctuating wellbore conditions, offering both experimental and theoretical support for understanding gas–liquid–solid flow behavior. It also presents technical guidance for optimizing drainage performance, controlling particle deposition, and formulating wellbore cleaning strategies. 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

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