Search Results (164)

The G-function can obtain the formation ground stress information by identifying the fracture closure point after fracturing, but the main fracture closure period of the deep coal seam volume fracture network is long, and the on-site pump stop time is short, and only the branch fracture closure can be observed. In order to explore the relationship between the closure pressure of branch fractures and the horizontal in situ stress, taking the deep coal seam in Daning–Jixian area as the background, the numerical simulation of the pump-stopping pressure drop of a complex fracture network with different complexity and different approximation angles was carried out using a finite element method, and the relationship between the closure pressure corresponding to the fracture closure point and the in situ stress was explored. The results show that when the crack approximation angle is greater than 60°, it can be approximately considered that the closure pressure of the first crack closure point tends to the maximum horizontal in situ stress. Furthermore, the minimum horizontal in situ stress can be obtained by formula conversion. The above-outlined method is applied to the in situ stress prediction of the X well area in Daning–Jixian County. The calculation results are compared with the test fracturing results, and the relative difference is within 5%, which shows that it has good accuracy and feasibility. The research results can provide guidance for the optimization of deep coalbed methane scheme design. Full article

Coalbed methane (CBM) is a vital clean energy resource, yet its extraction efficiency is often hindered by rapid production decline and low production rates in medium-shallow reservoirs. This study investigates the potential of CO₂ huff-and-puff technology to enhance CBM recovery and achieve CO₂ storage in low-productivity wells. A comprehensive model, constructed based on the geological conditions of the Qinshui Basin, was developed. Numerical simulations revealed that CO₂ huff-and-puff significantly improves CH₄ production by displacing adsorbed CH₄ and maintaining reservoir pressure. Key findings indicate that higher CO₂ injection volumes yield substantial increases in both peak CH₄ production and cumulative production compared with conventional extraction. Optimal soaking times balance recovery efficiency and operational costs. Sensitivity analysis identified gas diffusion coefficients, initial permeability, and Langmuir volume constants as critical geological parameters influencing the performance. This study preliminarily demonstrates the feasibility of large-scale CO₂ huff-and-puff for enhancing production in low-productivity CBM wells and provides theoretical insights for revitalizing China’s underperforming CBM wells while advancing carbon neutrality goals, although further experimental validation is still required. Full article

Deep coalbed methane (DCBM) reservoirs often experience severe proppant flowback during large-scale hydraulic fracturing, which undermines fracture conductivity and limits long-term recovery. The critical flowback velocity (CFVP) is the key parameter controlling proppant pack instability and flowback. In this study, the instability and flowback behavior of proppant packs throughout the entire production process, from early water flowback to late gas-dominated stages, were systematically investigated. Proppant flowback under closure stress was simulated using a CFD–DEM approach to clarify the flowback process and mechanical mechanisms. Laboratory experiments on coal fracture surfaces under gas-liquid two-phase and gas-liquid-solid three-phase conditions were then conducted to quantify CFVP and its variation across different production stages. Finally, a semi-empirical CFVP predictive model was developed through dimensional analysis. Results show that proppant flowback proceeds through three distinct stages—no flowback, gradual flowback, and rapid flowback. Increasing fracture width reduces proppant pack stability and lowers CFVP but allows higher flow capacity, and within the typical gas and water production ranges of deep coalbed methane reservoirs, flowback is significantly reduced when the width exceeds about 8 mm. Closure stress enhances CFVP below 15 MPa but has little effect above this threshold, while higher stresses progressively stabilize the proppant pack and minimize flowback. Larger average proppant size raises CFVP and preserves conductivity, whereas higher gas–liquid ratios elevate CFVP and reduce flowback, with ratios above 40 sustaining consistently low flowback levels. These findings clarify the mechanisms and threshold conditions of proppant flowback, establish quantitative CFVP benchmarks, and deliver theoretical as well as experimental guidance for optimizing DCBM production. Full article

Coalbed methane (CBM) wells with low production are widespread in China, and the influence of single-water-phase or -gas-phase seepage on CBM development was investigated. The influence of gas–water two-phase seepage on CBM development has rarely been studied. To study the controlling factors of gas–water two-phase seepage on CBM development, stress–strain relationship of coal reservoir, Darcy’s law of gas–water two-phases and the relationship between porosity and permeability were combined to establish a two-phase multi-physics coupling model. The feasibility and rationality of the established model was proven by comparing field CBM well data of Z29 in the ZhengZhuang Block and the simulation curve. Then, the coupling model was solved with COMSOL Multiphysics software (version 3.5), and the effect of Young’s modulus, initial permeability and the drainage system on the process of drainage was discussed. The results of numerical simulation show that the Young’s modulus of a reservoir has limited positive effects on CBM production. When the Young’s modulus of the reservoir increases by 80%, the gas production only increases by 10.71%. The initial permeability has a significant impact on CBM production. The reservoir with a permeability of 0.9 mD had the highest daily gas production of 2183 m³/d on the 162nd day, while the maximum daily gas production of the reservoir with a permeability of 0.1 mD was only 371 m³/d. In addition, a high pressure drop rate inevitably results in lower porosity and permeability, which limits the production of CBM. When the pressure drop reaches 0.1 MPa, the gas production drops sharply, with the daily gas production decreasing by more than 30%. Thus, a sudden change in bottom hole pressure should be avoided in the actual production scenario to extend the stable gas production stage. This simulation research quantifies the effects of Young’s modulus, initial permeability and the drainage system on CBM production, which could provide a basis for understanding CBM drainage and its controlling factor. Full article

The evaluation of the fracturing effect of coalbed methane (CBM) wells is crucial for the efficient development of CBM reservoirs. Currently, studies focusing on the evaluation of the hydraulic fracture stimulation effect of coal seams and the integrated analysis of “drilling-fracturing-monitoring” are relatively insufficient. Therefore, this paper takes three drainage and production wells in the coalbed methane block on the northwest wing of the Xiangxia anticline in the Bijie Experimental Zone of Guizhou Province as the research objects. In view of the complex geological characteristics of this area, such as multiple and thin coal seams, high gas content, and high stress and low permeability, the paper systematically summarizes the results of drilling and fracturing engineering practices of the three drainage and production wells in the area, including the application of key technologies such as a two-stage wellbore structure and the “bentonite slurry + low-solid-phase polymer drilling fluid” system to ensure wellbore stability, low-solid-phase polymer drilling fluid for wellbore protection, and staged temporary plugging fracturing. On this basis, a study on microseismic signal acquisition and tomographic energy inversion based on a ground dense array was carried out, achieving four-dimensional dynamic imaging and quantitative interpretation of the fracturing fractures. The results show that the fracturing fractures of the three drainage and production wells all extend along the direction of the maximum horizontal principal stress, with azimuths concentrated between 88° and 91°, which is highly consistent with the results of the in situ stress calculation from the previous drilling engineering. The overall heterogeneity of the reservoir leads to the asymmetric distribution of fractures, with the transformation intensity on the east side generally higher than that on the west side, and the maximum stress deformation influence radius reaching 150 m. The overall transformation effect of each well is good, with the effective transformation volume ratio of fracturing all exceeding 75%, and most of the target coal seams are covered by the fracture network, significantly improving the fracture connectivity. From the perspective of the transformed planar area per unit fluid volume, although there are numerical differences among the three wells, they are all within the effective transformation range. This study shows that microseismic fracture monitoring technology can provide a key basis for the optimization of fracturing technology and the evaluation of the production increase effect, and offers a solution to the problem of evaluating the hydraulic fracture stimulation effect of coal seams. Full article

Rotary Steerable System (RSS) enhances directional drilling efficiency by over 300% via dynamic bit adjustment during string rotation. This study aims to systematically address these bottlenecks, quantify technical boundaries, and propose actionable breakthrough paths for China’s RSS technology in shale gas development. To address China’s shale gas RSS bottlenecks, this study proposes a “Material-Algorithm-System” tri-level strategy centered on an innovative “Tri-loop System.” Key innovations include (1) silicon nitride–tungsten carbide composite coatings to enhance thermal resilience, tested to withstand 220 °C, reducing thermal failure risk by 40% compared to conventional materials; (2) downhole reinforcement learning optimization; (3) a “Tri-loop System” integrating downhole intelligent control, wellbore-surface bidirectional communication, and cloud monitoring, shortening downhole command response latency from over 5 s to less than 1 s. In practical shale gas development scenarios—such as the Sichuan Basin’s deep coalbed methane wells and Shengli Oilfield’s tight reservoirs—this tri-level strategy has proven effective: the high-frequency electromagnetic wave radar increased thin coal seam drilling encounter rate by 23%, while the piezoelectric ceramic micro-actuators reduced tool failure rate by 35% in 175–200 °C environments. This approach targets raising China’s shale gas RSS application rate to 60%, supporting sustainable oil and gas exploration. Full article

Coalbed-methane (CBM) extraction involves complex processes such as desorption, diffusion, and seepage, significantly increasing the difficulty of numerical simulation. To enable efficient CBM development, this study establishes an integrated simulation workflow for CBM, encompassing geological modeling, geomechanical modeling, hydraulic fracture simulation, and production dynamic simulation. Specifically, the unconventional fracture model (UFM), integrated within the Petrel commercial software, is applied for fracture simulation, with an unstructured grid constructing the CBM production model. Subsequently, based on the case study of well pad A in the Daning–Jixian block, the effects of well spacing and hydraulic fractures on gas production were analyzed. The results indicate that the significant stress difference between the coal seam and the top/bottom strata constrains fracture height, with simulated hydraulic fractures ranging from 169.79 to 215.84 m in length, 8.91 to 10.45 m in height, and 121.92 to 248.71 mD·m in conductivity. Due to the low matrix permeability, pressure drop and desorption primarily occur in the stimulated reservoir volume (SRV) region. The calibrated model predicts a 10-year cumulative gas production of 616 × 10⁴ m³ for the well group, with a recovery rate of 10.17%, indicating significant potential for enhancing recovery rates. Maximum cumulative gas production occurs when well spacing slightly exceeds fracture length. Beyond 200 mD·m, fracture conductivity has diminishing returns on production. Fracture length increases from 100 to 250 m show near-linear growth in production, but further increases yield smaller gains. These findings provide valuable insights for evaluating development performance and exploiting remaining gas resources for CBM. Full article

Coalbed methane (CBM) reservoirs in southwestern China are characterized by thick, multi-layered coal sequences partitioned into several independent pressure systems by impermeable strata. Commingled production from multiple coal seams in such multi-superposed CBM systems often suffers from severe inter-layer interference, leading to suboptimal gas recovery. To address this challenge, we developed a systematic four-step optimization workflow integrating geological data screening, pressure compartmentalization analysis, and numerical reservoir simulation. The workflow identifies the key “main” coal seams and evaluates various co-production layer combinations to maximize gas recovery while minimizing negative interference. We applied this method to a CBM well (LC-C2) in the Western Guizhou–Eastern Yunnan region, which penetrates three discrete CBM pressure systems. In the case study, single-layer simulations first revealed that one seam (No. 7 + 8) contributed over 30% of the total gas potential, with a few other seams (e.g., No. 18, 13, 4, 16) providing moderate contributions and many seams yielding negligible gas. Guided by these results, we simulated five commingling scenarios of increasing complexity. The optimal scenario was to co-produce the seams from the two higher-pressure systems (a total of six seams) while excluding the low-pressure shallow seams. This optimal six-seam configuration achieved a 10-year cumulative gas production of approximately 2.53 × 10⁶ m³ (about 700 m³/day average)—roughly 75% higher than producing the main seam alone, and even about 15% greater than a scenario involving all available seams. In contrast, including all three pressure systems (ten seams) led to interference effects where the high-pressure seams dominated flow and the low-pressure seams contributed little, resulting in lower overall recovery. The findings demonstrate that more is not always better in multi-seam CBM production. By intelligently selecting a moderate number of compatible seams for co-production, the reservoir’s gas can be extracted more efficiently. The proposed quantitative optimization approach provides a practical tool for designing multi-seam CBM wells and can be broadly applied to similar geologically compartmentalized reservoirs. Full article

Accurate assessment of coalbed methane (CBM) content is essential for characterizing subsurface reservoir distribution, guiding well placement, and estimating reserves. Current methods for determining coal seam gas content mainly rely on direct laboratory measurements of core samples or indirect interpretations derived from well log data. However, conventional coring is costly, while log-based approaches often depend on linear empirical formulas and are restricted to near-wellbore regions. In practice, the relationships between elastic properties and gas content are highly complex and nonlinear, leading conventional linear models to produce substantial prediction errors and inadequate performance. This study introduces a novel method for predicting gas content in deep coal seams using a Conditional Generative Adversarial Network (CGAN). First, elastic parameters are obtained through pre-stack inversion. Next, sensitivity analysis and attribute optimization are applied to identify elastic attributes that are most sensitive to gas content. A CGAN is then employed to learn the nonlinear mapping between multiple fluid-sensitive seismic attributes and gas content distribution. By integrating multiple constraints to refine the discriminator and guide generator training, the model achieves accurate gas content prediction directly from seismic data. Applied to a real dataset from a CBM block in the Ordos Basin, China, the proposed CGAN-based method produces predictions that align closely with measured gas content trends at well locations. Validation at blind wells shows an average prediction error of 1.6 m³/t, with 83% of samples exhibiting errors less than 3 m³/t. This research presents an effective and innovative deep learning approach for predicting coalbed methane content. Full article

Fracture systems critically govern coal seam permeability, influencing hydrocarbon migration pathways and well placement strategies. We established a predictive framework for fracture characterization in thin-interbedded coal reservoirs by integrating seismic response analysis with multi-domain validation. Utilizing borehole log statistics and staggered-grid wave equation modeling, we first decode azimuthal amplitude anisotropy patterns in fractured coal seams under varying lithological contexts. Key findings reveal that (1) isotropic thick surrounding rocks yield distinct fracture symmetry axis alignment (ellipse long-axis orientation shifts with layer velocity), while (2) anisotropic thin-interbedded host strata amplify azimuthal anisotropy ratios at mid–far offsets but induce prediction ambiguity under comparable fracture intensities. By applying azimuthally partitioned OVT data with optimized mid–long offset stacking, our amplitude ellipse fitting method demonstrates unique fracture solutions validated against structural, logging, and production data. This workflow resolves the multi-solution challenges in thin-layered systems, enabling precise fracture parameter prediction to optimize coalbed methane development in geologically complex basins. Full article

This study addresses the issue of coordinated development of coal, oil, and gas resources in the Yulin-Shenmu Coalfield. Taking the 132,201 working face of the Xiaobaodang No. 1 Coal Mine as a case study, the study combines FLAC^3D numerical simulation with on-site monitoring to analyze the impact of mining activities on the stability of gas well casings. Simulation results indicate that mining activities cause stress redistribution in the surrounding rock, with a maximum shear stress of 5.8 MPa, which is far below the shear strength of the casing. The maximum horizontal displacement of the wellbore is only 23 mm, with uniform overall deformation and no shear failure. On-site monitoring showed that the airtightness was intact, and the wellbore diameter test did not detect any destructive damage such as deformation or cracks. Concurrently, fiber optic strain monitoring of the inner and outer casings aligns with simulation results, confirming no significant instability caused by mining activities. The conclusion is that mining activities have a negligible impact on the stability of the gas well casing-concrete composite structure. The dual casing-cement ring structure effectively coordinates deformation to ensure safety. This finding provides a reliable technical basis for the coordinated exploitation of coal, oil and gas resources at the Xiaobaodang No. 1 Coal Mine and similar mines. Full article

The accurate prediction of single-well production performance necessitates considering the multiple factors influencing the dynamic changes in coal seam permeability during deep coalbed methane (CBM) extraction. This study focuses on Block D of the Ordos Basin. The Langmuir monolayer adsorption model was selected to describe gas adsorption behavior, and a productivity prediction model for deep CBM was developed by coupling multiple dynamic effects, including stress sensitivity, matrix shrinkage, gas slippage, and coal fines production and blockage. The results indicate that the stress sensitivity coefficients of artificial fracture networks and cleat fractures are key factors affecting the accuracy of CBM productivity predictions. Under accurate stress sensitivity coefficients, the predicted daily gas production rates of the productivity model for single wells showed errors ranging from 1.89% to 14.22%, with a mean error of 8.15%, while the predicted daily water production rates had errors between 0.35% and 17.66%, with a mean error of 8.68%. This demonstrates that the established productivity prediction model for deep CBM aligns with field observations. The findings can provide valuable references for production performance analysis and development planning for deep CBM wells. Full article

To enhance the structural safety of casings in coalbed methane (CBM) wells, this study develops a finite element model of the casing-cement sheath-formation assembly using ABAQUS software (ABAQUS 6.14). The model systematically investigates the influence of cement sheath defect thickness, defect angle, and internal pressure on the casing stress distribution. The results reveal that the cement sheath defects significantly elevate the casing stress, particularly when the defect is located at the first cementing interface. Casing stress increases most sharply when the defect angle lies between 20° and 60°. Beyond 60°, the stress on the outer wall approaches the yield strength of the casing material. Furthermore, rising internal pressure intensifies stress concentration. When internal pressure exceeds 60 MPa, the outer wall becomes the most likely location for failure initiation. Optimizing the elastic modulus of the cement sheath and employing heavy-wall casing grades such as TP125V can effectively mitigate the casing stress and enhance wellbore integrity. These findings offer both theoretical insights and practical guidance for optimizing cementing design and hydraulic fracturing operations in CBM wells. Full article

Understanding coalbed methane (CBM) enrichment patterns is essential for optimizing production capacity. This study evaluates the CBM reservoir-forming characteristics and exploration potential of the Longtan Formation in the Santang Syncline, Zhijin area, to systematically reveal CBM enrichment and high-production patterns. The investigation integrates regional geology, logging, well testing, laboratory analyses, and drainage production data. Results indicate that coal seam vitrinite reflectance (R_o,max) ranges from 3.20% to 3.60%, with metamorphic grade increasing with burial depth. Coal lithotypes consist predominantly of semi-bright coal, with subordinate semi-bright to semi-dull coal and minor semi-dull coal. Coal seam roofs comprise gray-black mudstone and calcareous mudstone, locally developing limestone, while floors consist of bauxitic mudstone. Pore structure analysis reveals greater complexity in coal seams 6 and 14, whereas seams 7 and 16 display simpler structures. Coal seams 5-3 and 6 demonstrate the weakest adsorption capacity and lowest theoretical gas saturation, while other seams exceed 55% gas saturation. Langmuir volume (V_L) increases with burial depth, reaching maximum values in coal seam 30. Langmuir pressure (P_L) follows a low–high–low trend, with lower values at both ends and higher values in the middle section. Measured gas content is highest in the middle section, moderate in the lower section, and lowest in the upper section. Reservoir condition assessment indicates favorable conditions in coal seams 14, 16, and 21, relatively favorable conditions in seam 7, and unfavorable conditions in seams 6, 30, 32, and 35. Among the three coal groups penetrated, the middle coal group exhibits the most favorable reservoir conditions, followed by the upper and lower groups. Full article

Deep coalbed methane (CBM) resources possess significant potential. However, their development is challenged by geological characteristics such as high in situ stress and low permeability. Furthermore, existing production strategies often prove inadequate. In order to achieve long-term stable production of deep coalbed methane reservoirs and increase their final recoverable reserves, it is urgent to construct a scientific and reasonable drainage system. This study focuses on the deep CBM reservoir in the Daning-Jixian Block of the Ordos Basin. First, a thermal–hydraulic–mechanical (THM) multi-physics coupling mathematical model was constructed and validated against historical well production data. Then, the model was used to forecast production. Finally, key control measures for enhancing well productivity were identified through production strategy adjustment. The results indicate that controlling the bottom-hole flowing pressure drop rate at 1.5 times the current pressure drop rate accelerates the early-stage pressure drop, enabling gas wells to reach the peak gas production earlier. The optimized pressure drop rates for each stage are as follows: 0.15 MPa/d during the dewatering stage, 0.057 MPa/d during the gas production rise stage, 0.035 MPa/d during the stable production stage, and 0.01 MPa/d during the production decline stage. This strategy increases peak daily gas production by 15.90% and cumulative production by 3.68%. It also avoids excessive pressure drop, which can cause premature production decline during the stable phase. Consequently, the approach maximizes production over the entire life cycle of the well. Mechanistically, the 1.5× flowing pressure drop offers multiple advantages. Firstly, it significantly shortens the dewatering and production ramp-up periods. This acceleration promotes efficient gas desorption, increasing the desorbed gas volume by 1.9%, and enhances diffusion, yielding a 39.2% higher peak diffusion rate, all while preserving reservoir properties. Additionally, this strategy synergistically optimizes the water saturation and temperature fields, which mitigates the water-blocking effect. Furthermore, by enhancing coal matrix shrinkage, it rebounds permeability to 88.9%, thus avoiding stress-induced damage from aggressive extraction. Full article