最新刊期
- 摘要：Deep coal-rock gas has become an important target for increasing natural gas reserves and production in China. Field practice indicates that there is a clear relationship between the production rate of deep coal-rock gas in the Daning–Jixian area and the economically recoverable reserves (EUR) controlled by gas wells. However, existing stress-sensitivity relationships for coal rock fail to effectively capture this phenomenon, particularly the differentiated response of permeability to stress paths, i.e., different pressure-decline rates. In this study, the pore pressure variation process was simulated to investigate the influence of stress paths on permeability stress sensitivity, with a specific focus on the relationship between pore pressure decline rate and permeability during pressure depletion. The permeability evolution of coal-rock reservoirs under different stress conditions was systematically analyzed. Permeability experiments were conducted using a pulse-decay method for unconventional reservoir cores. By adjusting the average pressures of the upstream and downstream reference chambers, different pore pressure decline rates (stress paths) were simulated. Four core samples from the No. 8 coal seam of the Baode Mine were tested to examine permeability evolution and its irreversibility under different pressure-decline paths. The results show that, as pore pressure decreases, the matrix permeability of coal rock generally exhibits an exponential decline, characterized by a rapid decrease at the early stage followed by a slower decline at later stages. Normalized analysis indicates that permeability recovery during unloading is limited and fails to return to its initial value; moreover, the permeability reduction during unloading is smaller than that during loading, demonstrating a pronounced hysteresis effect. Regression analysis of pressure-decline rate versus permeability change rate reveals that, for every 1 MPa/d increase in pore pressure decline rate, the permeability stress-sensitivity degree increases by an average of 0.28%, indicating a differentiated stress-sensitive response of coal permeability under different loading rates. Field statistical observations further confirm the sensitivity of coal-rock permeability to the pore pressure decline rate.关键词：deep coal-rock gas;matrix permeability;stress sensitivity;pressure drop rate;plastic deformation8|0|0更新时间：2026-04-23
- 摘要：CO2-enhanced shale gas recovery (CO2-ESGR) is a promising carbon capture, utilization, and storage (CCUS) technology that simultaneously improves shale gas production and enables geological CO2 sequestration, contributing to carbon neutrality. The adsorption behaviors of CH4 and CO2 in shale are critical factors controlling the efficiency of CO₂-ESGR. In this study, experimental data on CH4-CO2 adsorption in shale samples from major shale-gas-rich regions in China were compiled to establish a comprehensive database. The effects of total organic carbon (TOC), clay content, specific surface area, temperature, pressure, and CO2 fraction on adsorption behavior were systematically considered. Several machine-learning models, including back-propagation neural network, K-nearest-neighbor regression, random forest regression, and support vector machine regression, were developed to predict CH4-CO2 adsorption capacities and to investigate competitive adsorption in mixed-gas systems. Model performance was evaluated by comparison with published data, experimental measurements, and Langmuir model predictions. The results indicate that the random forest regression model achieves the highest prediction accuracy and strong generalization ability. Within the pressure range of 0-15 MPa, the model yields an average absolute relative deviation of 1.57%-1.94% and an R2 value of 0.99 for both single-component and mixed-gas systems. These results demonstrate that the proposed machine-learning model can reliably predict CH4-CO2 adsorption and competitive adsorption behaviors in shale, providing theoretical support for CO2-ESGR applications.关键词：shale;CH4-CO2;adsorption;competitive adsorption;machine learning17|0|0更新时间：2026-04-23
- 摘要：Aquifer thermal energy storage technology is an emerging and viable multi-energy complementary solution, with its core principle being the storage of highly variable renewable energy sources (such as solar and wind energy) in underground aquifers in thermal form, enabling stable extraction and utilization when needed to achieve multi-energy complementary storage based on geothermal reservoirs. The thermal equilibrium distance is a key parameter for determining the well spacing in this system, representing the minimum distance required for the temperature fluctuation amplitude of injected fluids to reduce to an acceptable range while flowing through the aquifer under specific operating conditions. To reveal the influencing mechanisms of thermal equilibrium distance, a three-dimensional aquifer model incorporating thermo-hydraulic coupling was constructed. The study focused on analyzing the impact of operational parameters (injection temperature and injection rate), formation properties (permeability and porosity), and rock thermophysical properties (volumetric heat capacity and thermal conductivity) on thermal equilibrium distance. Multivariate linear regression analysis was employed to rank the sensitivity of each parameter and identify the primary influencing factors. The results indicate that thermal equilibrium distance is positively correlated with injection temperature, injection rate, permeability, and rock thermal conductivity, while negatively correlated with porosity and volumetric heat capacity. The three dominant factors influencing thermal equilibrium distance are permeability, injection rate, and injection temperature, with their sensitivity ranking as permeability > injection rate > injection temperature. Notably, operational parameters account for a relatively high proportion among the dominant factors, suggesting that optimizing injection-production strategies and wellfield layouts can effectively enhance the thermal storage efficiency and economic viability of the system. These findings provide quantitative basis for well placement and operational strategies in "geothermal+" multi-energy complementary systems, offering technical support for renewable energy utilization.关键词：aquifer energy storage;thermal equilibrium distance;multi energy complementary system;Tthermo-hydraulic coupling;sensitivity analysis12|0|0更新时间：2026-04-21
- 摘要：The development of low-rank coalbed methane in the Fukang Block of Xinjiang has entered a bottleneck stage, necessitating an urgent enhancement and acceleration of exploration and exploitation initiatives. However, the inefficient methane desorption process within the microscopic pores of low-rank coal, combined with poorly understood adsorption and desorption mechanisms, has resulted in challenges such as low initial production rates, short durations of stable production, and suboptimal development performance in newly commissioned coalbed methane wells. To address challenges such as low recovery rates and the difficulty in mobilizing adsorbed-phase methane, low-rank coal from the Fukang block was selected as the study subject. The coal’s pore size distribution, molecular formula (C100H108O16N3) and molecular structure were characterized using elemental analysis, Low-temperature N2 adsorption, XRD, FT-IR, and 13C-NMR, enabling the construction of a slit-shaped pore model. Adsorption behavior under varying slit widths, pressures, and temperatures was simulated via the grand canonical Monte Carlo (GCMC) method, and a non-isothermal Langmuir equation was fitted to describe methane adsorption in the Fukang coal. Subsequently, isothermal depressurization desorption processes were analyzed using molecular dynamics simulations based on adsorbed methane configurations in slit pores at 10 MPa and 308 K. Key findings include: (1) The dominant molecular architecture of Fukang low-rank coal consists of aliphatic chains linking aromatic rings (benzene/naphthalene), functionalized with carboxyl, hydroxyl, and pyrrole groups; (2) At slit widths below 2 nm, strong nano-confinement deepens the adsorption potential well, leading to a “single-peak” methane density distribution, with micropore filling as the primary storage mechanism; above 2 nm, the density profile transitions to a “double-peak” pattern accompanied by a non-adsorption zone, indicating a shift toward surface-dominated adsorption; (3) Under high-pressure conditions, elevated temperature reduces adsorption potential energy, thereby promoting methane desorption—this effect is more pronounced in pores >2 nm, where both micropore filling and surface adsorption co-dominate, the central region of the slit still exhibits adsorbed methane; (4) In narrow slit (1 nm), high desorption energy barriers and low diffusion coefficients (0.075 Å2/ps) lead to significant desorption hysteresis, whereas wider slit (3 nm) exhibit lower energy barriers and higher diffusivity (0.647 Å2/ps), eliminating hysteresis. In conclusion, reducing the adsorption/desorption energy barrier in low-rank coal micropores is crucial for enhancing methane desorption efficiency and diffusivity. A synergistic strategy combining depressurization, aperture expansion, and thermal stimulation—implemented through pre-injected CO₂ combined with self-heating fracturing fluids, followed by well-pattern thermal fluid displacement—represents a promising pathway for improving recovery rates in low-rank coalbed methane reservoirs in the Fukang block.关键词：Fukang block;low-rank coal;coalbed methane;adsorption and desorption;molecular simulation;micropore filling44|44|0更新时间：2026-04-10
- 摘要：CO2 foam can effectively reduce gas mobility and improve oil displacement system sweep efficiency, but the presence of oil phase will have a significant impact on the formation and stability of foam and the control of gas mobility in porous media. Therefore, it is very important to understand the interaction between foam and oil phase in porous media. This study systematically studied the effects of foam quality (fg) on its steady-state transport behavior, the effects of oil phase composition on foam strength, and the effects of foam generation mode (in-situ generated foam, pre-generated foam) on miscible flooding efficiency through supercritical CO2 foam steady-state flow experiments and core displacement experiments. The results show that the apparent viscosity of supercritical CO2 foam increases first and then decreases with the increase of foam quality. In the core with a permeability of approximately 28×10-3 μm2, the optimal foam quality is about 0.75, and the foam system shows the best mobility control ability. The oil phase composition significantly affects the foam strength. Compared with n-decane (C10), in the process of displacing hexadecane (C16), the apparent viscosity and pressure difference of foam are larger, the gas breakthrough time is lagging behind, the foam strength is larger, and the recovery rate is higher during displacement. In addition, the foam generation mode has an important influence on the efficiency of miscible flooding. Whether it is displacing C10 or C16, the recovery rate of in-situ generated foam is higher than that of pre-generated foam. The specific data show that the recovery rates of in-situ generated foam flooding C10 and C16 are 17.78% and 30.91%, respectively, while the recovery rates of pre-generated foam under the same conditions are 15.91% and 20.83%, respectively. This study clarifies the optimal foam injection quality and provides a direct basis for the optimization of field process parameters. At the same time, it clarifies the influence of oil phase composition and foam generation mode on CO2 foam performance and oil flooding efficiency, which lays a theoretical foundation for reservoir adaptability evaluation and injection process optimization.关键词：mobility control;oil phase composition;foam generation mode;supercritical CO2 foam;the steady-state transport characteristics;miscible flooding behavior63|33|0更新时间：2026-04-02
- 摘要：Saline lacustrine basin shale oil, as an important type of continental shale oil and gas resources, undergoes hydrocarbon generation processes regulated by multiple factors including sedimentation and diagenesis, exhibiting significant complexity and heterogeneity. Based on a systematic investigation of geological characteristics of shales from typical saline lacustrine basins in China, combined with the application results of experimental techniques such as closed-system MSSV (Microscale Sealed Vessel pyrolysis), semi-open-system hot-press simulation, and organic sulfur analysis, this study comprehensively explores the genetic mechanism of differential hydrocarbon generation in shales from Chinese saline lacustrine basins. The results indicate that saline lacustrine basin shales feature diverse lithofacies and organic facies with strong heterogeneity, and the main source rock sequences generally possess medium-to-high organic matter abundance, kerogen predominantly of Type Ⅰ-Ⅱ₂, and a thermal evolution degree ranging from 0.7% to 1.3% Ro. The hydrocarbon generation process of some typical shales presents distinct "double-peak oil generation" differentiation characteristics: shales in sulfate-type lacustrine basins exhibit a "low-mature oil-mature oil" double peak, while those in alkaline carbonate-type lacustrine basins are characterized by a "mature oil-high-mature oil" double peak. Organic sulfur reduces the hydrocarbon generation activation energy of kerogen through forming low-bond-energy C-S structures, thereby advancing the hydrocarbon generation threshold. Salt minerals, clay minerals, volcanic minerals, and alkaline minerals regulate the hydrocarbon generation pathways and product composition through organic-inorganic interactions such as catalytic reactions, hydrogen supply, and saponification reactions. Through the innovation of experimental techniques and the deepening of genetic mechanisms, dynamic simulation of hydrocarbon generation from microscopic compounds to macroscopic geological processes has been realized, providing key technical support for hydrocarbon generation kinetic modeling, resource potential evaluation, and "sweet spot" interval prediction of saline lacustrine basin shales. This study is of great significance for improving the theory of continental shale hydrocarbon generation and guiding the efficient exploration and development of continental shale oil and gas..关键词：shale oil;hydrocarbon generation mechanism;experimental techniques;organic sulfur;organic-inorganic interactions62|138|0更新时间：2026-03-31
- 摘要：The second section of the Xujiahe Formation in western Sichuan has abundant natural gas resources in the deep tight sandstone, but the low exploration rate, low utilization rate, and difficulty in upgrading of reserves have always been challenges for exploration and development in the region. The unclear distribution pattern and genesis of gas and water in both horizontal and vertical directions have hindered further understanding of gas reservoirs and drilling deployment research. To solve the dilemma of gas reservoir evaluation brought about by the complex distribution of gas and water, and effectively promote exploration and development deployment, based on actual drilling, logging, testing data and natural gas and core analysis and laboratory data, this study analyzed the characteristics of natural gas enrichment and production under different combinations of geological elements from macro and micro scales, plane and vertical dimensions, and the original state of gas reservoirs and actual drilling conditions. The differences in gas and water occurrence and electrical response in different depths of fracture development were sorted out, and the principles and methods for identifying gas and water in tight fractured reservoirs under wellbore conditions were summarized. Research has shown that: ①Macroscopically, the spatiotemporal coupling of the hydrocarbon source reservoir transport system controls the vertical and horizontal distribution of gas and water, with the scale and formation period of faults being key factors affecting gas and water distribution; ②At the micro level, small-scale fractures and microcracks control the filling behavior of natural gas. High maturity gas is difficult to achieve long-distance vertical and horizontal migration in matrix reservoirs. The depth range of fracture development has significantly higher gas saturation and natural gas maturity compared to adjacent matrix segments; ③Under actual drilling conditions, the deep invasion of mud filtrate significantly reduces the identification of gas and water layer resistivity in the fracture development depth range, which is an ideal target area for gas bearing identification. The new method, which uses gas logging C1/C2 as the key means and characterizes the rhythmic changes of natural gas maturity in different fracture development stages, effectively improves the gas water identification ability of tight reservoirs; ④The results of single well gas water identification show that in early fault controlled areas, the height of gas columns is usually less than 100m and the planar distribution radius of fault transmission conductors is small, while in late fault controlled areas, the height of gas columns and the planar distribution radius of fault transmission conductors are usually larger and related to the size of the fault. Under the guidance of the fluid identification methods and gas water distribution laws mentioned above, drilling deployment was carried out, and general principles for designing drilling trajectories and selecting test layers for target layers were established. Multiple new drilling wells achieved good oil and gas results, which strongly supported the high-quality exploration and development of deep tight sandstone in the second section of the Xujiahe Formation in western Sichuan.关键词：gas water distribution;transporting gas reservoir;cracks;gas maturity level;Western Sichuan Depression;second section of Xujiahe Formation29|95|0更新时间：2026-03-31
- 摘要：The potential of deep shale gas resources in the Sichuan Basin is huge, but due to its deep burial depth, the pressure-holding coring technology is difficult and costly. Therefore, how to accurately recover and evaluate the in-situ gas content through numerical simulation or experimental methods has become a key issue in the industry. Based on Nuclear Magnetic Resonance (NMR) isothermal adsorption data, this study employs adsorption potential theory to derive adsorption curves at various temperatures and establishes a prediction model for adsorbed gas under variable temperature and pressure conditions. Additionally, a free gas prediction model is developed using NMR free gas data and the equation of state. These models enable the analysis of adsorbed and free gas, as well as the prediction of in-situ gas content in the study area. Experimental results reveal comparable in-situ gas content between siliceous shales (6.2 cm³/g) and mixed siliceous shales (5.9 cm³/g), with statistically insignificant differences. Notably distinct gas phase partitioning is observed across lithologies, with free gas consistently predominating over adsorbed gas at ratios of 3:7 in siliceous shales and 4:6 in mixed siliceous shales, which reveals the differential control of lithology on the distribution of occurrence state. This difference in phase distribution is mainly related to clay mineral content and water saturation. In the deep high-pressure environment, although free gas is dominant, clay minerals play a key ' lock gas ' role, and water saturation is the ' short board ' of free gas enrichment. By changing the temperature and pressure gradient on the basis of the model, the temperature and pressure response characteristics of shale gas occurrence are revealed: the adsorbed methane has the conversion of the main controlling factors of temperature and pressure in the deep and shallow parts, and the favorable geological conditions for its occurrence are high pressure and low temperature conditions; free methane is mainly controlled by pressure, and the high pressure environment of deep shale in the study area is conducive to the occurrence of free methane.关键词：Sichuan Basin;Longmaxi Formation shale;adsorption potential theory;adsorption gas prediction model;free gas prediction model32|46|0更新时间：2026-03-30
- 摘要：The G Oilfield in the Ordos Basin has entered the middle to late stages of development and is confronted with the challenge of production decline due to depleted reservoir energy. Fracturing stimulation combined with water injection for energy replenishment is a commonly used production enhancement strategy. However, parameter mismatch in fracturing-induced energy storage within this oilfield often leads to water channeling and premature water breakthrough in adjacent wells, severely constraining development effectiveness. To address this issue, this study focuses on the integrated optimization of fracturing-induced energy storage parameters for the G Oilfield. Firstly, a geological model of a representative well group was established using the CMG numerical simulation software, and the mechanism of water injection for energy storage was thoroughly analyzed. Subsequently, the single-factor analysis method was employed to systematically identify key control parameters significantly impacting the 1 000-day cumulative oil production, including fracture-length ratio, fracture conductivity, injection intensity, daily injection volume, and well soaking time. Following this, the Response Surface Methodology was applied to construct a high-precision predictive model between these key parameters and the 1 000-day cumulative oil production. The reliability of the model was verified through residual analysis and numerical simulation validation. Finally, the Comprehensive Learning Particle Swarm Optimization algorithm was introduced to perform iterative optimization of the identified key parameters, with the objective of maximizing cumulative oil production. The application of this integrated optimization strategy significantly enhanced the development outcomes. The optimized scheme increased the 1000-day cumulative oil production by 5.98% compared to the simulation results under parameters optimized solely by the Response Surface Methodology. The study successfully determined the optimal parameter combination suitable for fracturing-induced energy storage in the G Oilfield. The results demonstrate that the integrated optimization method, combining single-factor analysis, Response Surface Methodology, and the intelligent optimization algorithm, effectively resolved the inefficient production problem caused by parameter mismatch in fracturing-induced energy storage, significantly improving crude oil production. The integrated optimization strategy proposed in this study provides a systematic and feasible technical solution for addressing common issues in low-pressure coefficient reservoirs, such as insufficient natural productivity and difficulties in enhancing development. It holds significant application value for the Ordos Basin and similar reservoirs.关键词：CLPSO;Energy Replenishment;fracturing;Process Parameter Optimization;RSM29|12|0更新时间：2026-03-27
- 摘要：To reveal the influence of water on the CO2-ECBM (CO2-replacement of CH4) effect in deep coal seams, using Fuchang deep coal as the research object, experiments such as 13C nuclear magnetic resonance spectroscopy (13C-NMR) and X-ray photoelectron spectroscopy (XPS) were conducted. A coal matrix model was constructed using molecular simulation software, and the microscopic mechanism of water’s effect on the CO2-ECBM process in deep coal seams was studied using molecular simulation methods. The results show that after the coal matrix adsorbs gas, it undergoes significant expansion, and the pore volume significantly decreases. When saturated with adsorbed CH4, the coal matrix porosity decreases by 72.2% compared to the initial value; when the molar fraction ratio of CO2 to CH4 (
- 摘要：Ultra-deep pore-fracture-fault complex condensate gas reservoirs exhibit highly heterogeneous fluid flow behaviors. During production, the fracture system often experiences locally reduced pressure, leading to retrograde condensation, while the matrix pressure and overall reservoir pressure remain above the dew-point pressure. This discrepancy makes it difficult for traditional gas reservoir engineering methods—typically based on average reservoir pressure—to accurately identify the onset and extent of local retrograde condensation. To address this issue, this study investigates the Bozi condensate gas reservoir located in the Kuqa Depression of the northern Tarim Basin. The flow mechanism and pressure response characteristics of the pore-fracture-fault triple-medium system are systematically analyzed. Based on the variation patterns of wellhead oil pressure, the production process is divided into three distinct stages: a steady-decline period, an unstable-fluctuation period, and an accelerated-decline period. Abnormal fluctuations in the gas-oil ratio (GOR) are interpreted as early indicators of phase change. By examining GOR variations across different pressure intervals, this work characterizes the dynamic evolution of complex medium gas reservoirs at various production stages. A hybrid predictive framework is proposed that integrates the Long Short-Term Memory (LSTM) network and the Temporal Convolutional Network (TCN), whose hyperparameters are globally optimized using the Pelican Optimization Algorithm (POA). A weighted fusion strategy is employed to construct the POA-LSTM-TCN combined model, enabling stage-wise fitting and prediction of GOR. The results demonstrate that the optimized POA-LSTM and POA-TCN models achieve mean absolute percentage errors (MAPE) of 3.71% and 7.73%, respectively, whereas the POA-LSTM-TCN hybrid model achieves a significantly lower MAPE of 2.40%, outperforming the single models by 1.31% and 5.33%. Numerical simulation further verifies that the traditional gas reservoir engineering approach based on average pressure fails to effectively capture retrograde condensation occurring within fractures. In contrast, the POA-LSTM-TCN model not only provides high-accuracy and efficient GOR prediction but also identifies retrograde condensation when deviations exceed the prdefined threshold. Therefore, this study overcomes the limitations of conventional engineering methods in detecting local retrograde condensation and establishes an early-warning approach based on anomaly recognition. The findings hold substantial theoretical and practical significance for production dynamics analysis, retrograde condensation mechanism identification, and development optimization of complex condensate gas reservoirs.关键词：Tarim Basin;Bozi Gas Reservoir;complex media;condensate gas reservoir;gas-oil ratio;anti-condensate;neural network32|81|0更新时间：2026-03-24
- 摘要：During the construction of salt cavern hydrogen storage, the debrining process—where brine is displaced by gas injection—directly determines the effective storage capacity and operational safety of the cavern. To mitigate the cost and safety risks of using hydrogen (H2) as the displacement medium and to establish a stable cushion gas system during cavern development, methane (CH₄), nitrogen (N₂), and carbon dioxide (CO₂) were selected as alternative cushion gases. This study investigates their flow behavior during debrining and their subsequent impact on hydrogen storage performance. A three-dimensional salt cavern model was developed using the CMG-GEM numerical simulator, based on geological data from the Dunham salt site in the U.S. Key operational parameters—including debrining rate, gas injection pressure, and cushion gas type—were systematically evaluated using indicators such as gas breakthrough time, cumulative gas injection, effective hydrogen storage capacity, and cushion gas proportion. The simulation results indicate that the debrining rate is the dominant factor controlling gas breakthrough and usable storage volume. Increasing the debrining rate from 40 m³/h to 80 m³/h advances gas breakthrough by approximately 34% and reduces effective hydrogen storage capacity by about 9%. Concurrently, the gas–water interface transitions from a uniformly flat decline to a coning pattern along the wellbore axis. Raising the injection pressure from 22 MPa to 25 MPa increases cumulative gas injection by roughly 13.6%, but has a limited effect on the timing of gas breakthrough. Among the cushion gases tested, CO₂ exhibits the earliest gas breakthrough during debrining due to its higher solubility and lower interfacial tension, resulting in the highest cushion gas proportion (~45%). CH₄ yields the largest effective hydrogen storage capacity, while N₂ offers the lowest cushion gas proportion (~37%) and more favorable H2 purity. Cavern geometry also significantly influences gas breakthrough behavior, cumulative injection, and effective capacity; however, under the same debrining rate, the trends across different cavern shapes remain consistent, with relatively minor variations in cushion gas proportion. These findings suggest that selecting an appropriate cushion gas and controlling the debrining rate during cavern construction can effectively delay gas breakthrough, enhance usable H2 storage capacity, and improve operational safety. This study provides a scientific basis for the process design of salt cavern hydrogen storage facilities.关键词：Salt cavern hydrogen storage;Debrining;Cushion gas;numerical simulation;gas channeling37|126|0更新时间：2026-03-23
- 摘要：Against the background of an accelerating global energy transition, the development of unconventional oil and gas resources has become an important strategic direction for ensuring energy security. To address the challenges caused by the increasing development intensity of unconventional oil and gas fields in China, such as deteriorating geological conditions, high development difficulty, low exploration rate, fast production decline, limited reduction in single well investment, and decreasing ultimate recovery and internal rate of return, promoting the geology-engineering integrated management in unconventional oil and gas exploration and development is crucial for achieving cost reduction, efficiency improvement, and overall coordination, and holds significant strategic importance. Using theoretical research achievement, the study proposed the concept, connotation, and characteristics of the geology-engineering integrated management for exploration and development. It systematically reviewed the challenges and current situation faced by unconventional oil and gas development, and revealed the drawbacks of isolated operation among the three major fields of exploration, development and engineering. A conceptual model of geology-engineering integrated management for unconventional oil and gas exploration and development was established, identifying and explaining seven elements, including storage-production conversion, program design, engineering support, platform construction, theoretical support, validation and correction, and geological iteration. Its specific implementation pathways were explored from multiple dimensions. Research results showed that the integrated management of unconventional oil and gas exploitation could be promoted alongside the implementation of full lifecycle management, top-level design of an integrated organizational structure, optimization and reengineering of operational processes, and development and construction of a data platform. This approach can achieve large-scale production, accelerate the conversion of unconventional oil and gas reserves into production. It not only provides a new management methodology for efficient unconventional oil and gas development but also offers insights for improving the quality and efficiency of traditional oil and gas field development management, and contribute to the high-quality development of modern oil and gas fields.关键词：unconventional oil and gas;integrated management;exploration and development;conceptual model;implementation pathway125|369|0更新时间：2026-03-16
- 摘要：The horizontal well technology has become a key method for the efficient economic development of unconventional resources such as shale oil and gas. The drilling performance largely depends on the degree of matching between the bottom hole assembly (BHA) and the geomechanical properties of the shale formation. However, existing studies do not fully clarify the synergistic effects between the geomechanical properties, the BHA structural parameters, and the drilling process parameters, making it difficult to achieve precise and efficient trajectory control in actual drilling operations.In this study, based on geological data and drilling information from a typical shale block in the Junggar Basin of Xinjiang, a numerical simulation method is developed that integrates geomechanical properties, BHA structural mechanics, and drilling dynamics. The study focuses on analyzing the comprehensive impacts of parameters such as the number and distribution of stabilizers, the depth of stabilizer rib penetration into the formation, as well as drilling parameters such as weight on bit (WOB) and rotary speed on the steering capability of the bottom hole assembly. The aim is to reveal the dynamic coupling mechanisms between these parameters and to seek the optimal matching solution. The study found that, compared to drilling parameters such as WOB and rotary speed, which can be adjusted in real-time during drilling, the structural configuration of stabilizers—especially the number of stabilizers, the spacing between stabilizers and the drill bit, and the effective penetration depth of stabilizer ribs into the shale formation—has a more significant impact on the steering capability. Based on this mechanism, the study proposes a structural optimization strategy focusing on “increased stabilizer placement near the bit, precise spacing control, and optimized penetration depth.” Simulations and case comparisons show that this method can significantly improve the steering performance and drilling efficiency of the bottom hole assembly. The findings provide theoretical support and key technological assistance for the refined design of bottom hole assemblies in shale oil and gas horizontal wells.关键词：horizontal well;shale oil;shale gas;geological model;bottom hole assembly;numerical simulation;geology-engineering integration50|78|0更新时间：2026-02-27
- 摘要：In view of the difficulties in the geological engineering dessert of coal-rock gas development in Jiaxian block of Ordos Basin, such as unclear fine evaluation, difficult fine control of drilling trajectory of long horizontal section horizontal well, small space for liquid control, efficiency improvement and cost reduction in large-scale fracturing transformation, and inaccurate control of efficient and economical drainage, the development concept of geological engineering integration is adhered to. Through the application practice of development pilot test, the key technology of integrated and efficient development of coal-rock gas with dessert evaluation, optimal and fast drilling, fracturing transformation and efficient drainage is formed. Based on the integrated dessert evaluation technology, a three-factor and 12-item evaluation index system of geological engineering economy in the development dessert area is established. Based on the mud logging data while drilling, the identification standard of black gold target is established to support the development of selected areas and the deployment and implementation of horizontal wells. By optimizing the wellbore structure, optimizing the high-efficiency speed-up tools, and adopting the integrated guidance technology of seismic geology and engineering, the optimal and fast drilling of large well cluster horizontal wells in factory is realized, and the drilling rate of coal rock is guaranteed to be more than 98 %. The integrated fracturing technology system of geological engineering with ‘high displacement + moderate scale + complex fracture network + multi-scale support’ as the core is formed, and the ultra-low pre-liquid controlled hydraulic fracturing technology and few cluster long fracture fracturing technology are explored, which further improves the pertinence and economy of coal rock gas fracturing transformation. A full-cycle integrated drainage technology system of ‘initial oil control pressure self-flowing, medium-term auxiliary bubble drainage + gas lift, and later artificial lifting’ has been formed to improve the drainage and gas recovery efficiency of coal-rock gas wells. Practice shows that the integrated and efficient development technology of coal, rock and gas has realized the deep integration of geological engineering, formed the closed-loop optimization of the whole development cycle, reduced the development cost and realized the scale benefit development of coal, rock and gas while ensuring the drilling effect and production effect of single well.关键词：Coal-rock gas;geology-engineering integration;sweet spot evaluation;Optimized drilling;volume fracturing;Drainage schedule46|3|0更新时间：2026-02-11
- 摘要：During the multi-stage volumetric fracturing of shale gas horizontal wells, the problem of casing deformation severely restricts the efficient development of shale gas. Specifically, the casing deformation rate in major blocks of the Sichuan Basin in China exceeds 20%; among 43 drilled wells in the Baima Block of the Fuling Shale Gas Field, 11 have suffered casing damage (with a casing deformation rate of 26%); and the casing deformation rate in the Duvernay Shale Gas Field in North America reaches 47%. This issue often leads to the failure of bridge plug setting. This study aims to develop a cementing technology based on nitrogen-injected foam cement slurry, which enhances the deformation capacity of the cement sheath to alleviate the effect of formation shear slip on the casing, thereby effectively preventing and controlling casing deformation induced by fracturing. A three-dimensional mechanical model of "sliding fracture-cement sheath-casing" (including key parameters of the casing, cement sheath, and formation rock) was established using FLAC3D, and the relationship between the elastic modulus of the cement sheath and casing deformation was analyzed via numerical simulation. Mechanical property tests of foamed cement stone were conducted, and the results showed that the maximum compressive deformation capacity of foamed cement stone reaches 54%, far exceeding the 3%-5% of conventional cement stone; moreover, its elastic modulus can be adjusted by controlling the nitrogen injection amount. Combined with downhole working conditions (such as the certainty of casing deformation risk locations and lost circulation risk), four casing deformation prevention and control cementing processes were designed, namely the full horizontal section integrated type, interval type, targeted type, and full wellbore variable density type. Field tests were subsequently carried out in the Baima Block of the Fuling Shale Gas Field. The research results indicate that when the elastic modulus of the cement sheath decreases from 10 GPa to 0.5 GPa, the casing shear deformation is reduced by 80%; when it decreases to 0.01 GPa, the impact of 35 mm formation slip on the casing is negligible. The maximum compressive deformation capacity of foamed cement stone is 54%, much higher than the 3%-5% of conventional cement stone, and its elastic modulus can be regulated by the nitrogen injection amount. For the 6 test wells, the excellent rate of cementing quality logging all exceeded 90%, and the excellent rate of the horizontal section in some wells exceeded 96%. No casing deformation occurred after fracturing, which is in sharp contrast to the 26% casing deformation rate of wells cemented with conventional cement slurry in the same block. Well Jiaoye X5HF has been in normal production for 1 year after fracturing, with a daily gas production of 4.6×10⁴ m³ and no annular pressure. In conclusion, the nitrogen-injected foam cement slurry cementing technology significantly reduces the impact of formation shear slip on the casing through the buffering effect of the flexible cement sheath. The four processes are suitable for different working conditions, solving the problem that conventional technologies struggle to balance sealing performance and deformation buffering. It provides an innovative solution for casing deformation prevention and control in shale gas wells under complex geological conditions, with broad application prospects. However, when the formation slip amount exceeds 45 mm, it is necessary to combine measures such as increasing the casing wall thickness for joint prevention and mitigation.关键词：shale gas;fracturing;casing deformation;foam cement slurry;prevention and mitigation80|211|0更新时间：2026-02-03
- 摘要：Shale oil reservoirs generally exhibit strong heterogeneity, and the in-situ stress field, rock mechanical properties, and lithological non-uniformity around the target zone are significant. These factors lead to large variations in initiation pressure at different perforation clusters along a horizontal well, resulting in unbalanced fracture initiation and propagation among clusters within a fracturing stage. This significantly restricts both the stimulated reservoir volume (SRV) and the overall stimulation efficiency. To address these issues, this study first optimized the depth positions of perforation clusters within each fractured well stage by minimizing the differences in initiation pressure among the perforation clusters. Subsequently, the stress interference effects between multiple clusters of fractures were considered to calculate the non-uniform stress field during the reservoir fracturing process. A multi-cluster hydraulic fracture propagation model for shale oil was then developed, culminating in a method for regulating the uniform propagation of multi-cluster fractures. Using horizontal shale oil well NC1 as a case, we first performed an optimization of the non-uniform perforation cluster layout with the objective of minimizing the differences in initiation pressure among the perforation clusters. A comparative analysis of fracture propagation before and after the optimization of the perforation clusters was conducted, and the effectiveness of fracture control post-optimization was evaluated. The results indicated that after optimizing the perforation clusters, the average initiation pressure difference across the entire well stage decreased from 7.04 MPa to 1.03 MPa. The average fracture length variation coefficient across all stages reduced from 0.22 to 0.09, with a decrease in the fracture length variation coefficient in each stage, and all cluster fractures in each stage initiated. The standard deviation of the inflow rates for each cluster of fractures in well NC1, derived from high-frequency pressure wave deconvolution, was found to be less than 10, indicating a relatively uniform distribution of inflow rates among the clusters. The regulation of hydraulic fracture initiation and propagation was significantly effective. This research provides a theoretical framework for enhancing the effectiveness of perforation cluster fracturing in horizontal shale oil wells and for regulating the uniform propagation of fractures among clusters, offering valuable guidance for the design of multi-cluster perforations in field applications.关键词：shale oil;Initiation pressure;Non-uniform perforation cluster;Fracture length variation coefficient;Uniform fracture propagation89|144|0更新时间：2026-01-27
- 摘要：In order to solve the key problems of low prediction accuracy of natural fractures and lack of theoretical support for artificial fracturing design in the development of tight oil reservoirs in Huaqing Oilfield, Ordos Basin, a multidisciplinary fusion of fracture network characterization and fracturing calculation method was adopted. Based on imaging logging data, core data, and rock mechanics experimental data of 452 wells, a multivariate coupling model of "logging response geostress field fracture parameters" was constructed, and a natural fracture identification standard considering quantitative indicators such as resistivity reduction>30% and acoustic time difference increase>10% was established. By using sequential Gaussian simulation and Oda algorithm, the three-dimensional fracture network reconstruction in the study area was achieved (with a NE60°~90° orientation accounting for 66.7%, a length of 5 m to 95 m, and a permeability of 0~18×10-3 μm2), and the model validation agreement reached nearly 90%. In terms of characterizing the geostress field, the modified Eaton method was used to invert the horizontal principal stress difference of 4~8 MPa (σ H_=NE75 °). Based on the study of natural fractures and geostress fields, a fracturing fracture length prediction system was developed by integrating the PKN/P3D model and XGBoost algorithm. The key innovations include: combining the classic fracturing model PKN/P3D model, while considering the difficulty of obtaining some parameters in the PKN/P3D model on site, the fracturing fractures calculated using the mature commercial software Kinetix for some wells in this study area were used as machine learning samples to obtain fracturing calculations for all wells and adjacent well areas in the study area. On site applications have shown that the prediction results have an average error of only 7.2% compared to microseismic monitoring data. Using research results to guide the B195-100X well to increase production by 42% after repeated fracturing. This study has developed an integrated technical pathway for "fracture identification geostress characterization fracture length prediction fracturing optimization" in tight oil reservoirs suitable for areas without seismic data, providing replicable theoretical methods and technical paradigms for efficient development of tight oil reservoirs in the Ordos Basin and similar geological conditions.关键词：tight oil reservoir;high inclination;natural fracture distribution;pressure fracture;machine learning;geostress75|422|0更新时间：2025-12-29
- 摘要：Based on core observations and seismic data, this paper explores the genesis of salt rocks in the Dongpu Depression, in response to the debate over deep water and shallow water salt formation in thick salt rocks. Research shows that thickness of the gypsum salt rock in the third section of the Sha River is about 1 000 meters. The thick layer of salt rock is composed of two types of evaporite rock sequences vertically stacked, with a single sequence thickness of 5.7-18.0 m and a single layer salt rock thickness of 1.0-12.0 m. Due to the influence of arid climate, multi-tectonic deep-sags, and lake level fluctuations, the distribution of salt rocks has the characteristics of mult-periods and multi-centers, the "bull's-eye"-shaped salt dome core centered on the Xinwei-12 well area was located within the Liutun Sag during the early Es3x period; the sedimentation center of Liutun Sag is consistent with that of its structural subsidence, which belonging to the coincidence matching relationship. In most cases, there is a spatial matching relationship between the center of salt rock and the center of structural subsidence or sedimentation. The center of salt rock does not represent deep or shallow water. Research suggests that the central uplift of the Lower Sha3 and even earlier Upper Sha4 periods in the Dongpu Depression belongs to underwater uplift and shallow water sedimentation, without forming a sedimentary center; there were both deep-water salt formation and shallow-water salt formation, coexisting in the same basin. It is Innovatively proposed that a complex salt formation model of deep-basin and deep-water, shallow-platform and shallow-water in the Dongpu Depression, This breaks the previous understanding of the single shallow-water and single deep-water salt rock genesis, solves the spatiotemporal matching between salt rocks and deep-water facies, therefore provides a basis for avoiding salt (for drilling and completion projects and finding deep water in shale oil exploration.关键词：Thick and massive salt rocks;distribution rule;Deep-basin and deep-water;Shallow-platform shallow-water;Dongpu depression135|198|0更新时间：2025-12-25
- 摘要：In recent years, research in China's coalbed methane (CBM) field has focused on the development of deep and coal rock gas. However, China's shallow and medium-depth CBM resources are abundant and have a high degree of reserve confirmation. Currently, the main challenge is the difficulty in effectively mobilizing the large amount of adsorbed gas. If the remaining adsorbed gas can be effectively utilized, the production capacity of shallow and medium-depth CBM can be significantly increased. To clarify the development direction of surface well construction technology for enhancing recovery in shallow CBM, this study conducts an in-depth discussion based on the "in-situ desorption - matrix diffusion - cleat seepage - fracture conductivity" chain mass transfer model. It reviews the definition and connotation of shallow CBM recovery rate, where matrix diffusion, as the key link connecting microscopic desorption and macroscopic seepage, is identified as the core bottleneck restricting the overall recovery rate. Further, the influencing factors are systematically classified into two categories: the main seepage control factors affecting the pressure drop sweep efficiency, such as fracture conductivity, well pattern layout, and pressure drop transmission speed; and the main diffusion control factors affecting desorption efficiency, including matrix block size, gas diffusion coefficient, water saturation, temperature and pressure conditions. On this basis, the current mainstream enhanced recovery technologies, such as well pattern optimization, gas injection displacement (CO2, N2 flooding), negative pressure extraction, desorption agent injection, physical field energy enhancement (acoustic wave, microwave, electric field), microbial stimulation, and hydraulic fracturing, are systematically reviewed, analyzing their applicable conditions, field application effects, and failure mechanisms. The study finds that although these technologies can increase production under certain conditions, they generally have the common limitations of "difficult matrix access, easy energy dissipation, and limited production increase", that is, external energy is difficult to effectively act on the matrix interior, the pressure drop sweep range is limited, the increase in desorption efficiency is insufficient, and the production increase effect rapidly decreases over time, making sustainable development difficult to achieve. The study emphasizes that for shallow CBM development, the speed of mobilizing recoverable reserves (i.e., the kinetic process) is more practically significant than their absolute value (thermodynamic state). Rapid and efficient mobilization of adsorbed gas within the matrix is the key to increasing production and recovery. Therefore, surface well construction technology for enhancing recovery should focus on three aspects: increasing matrix mass transfer power, reducing matrix block size, and enhancing the gas phase flow capacity of the matrix. Among them, reducing matrix block size is currently the easiest direction to break through, while increasing matrix mass transfer power has limited influence, and enhancing the gas phase flow capacity of the matrix requires long-term research and development to achieve breakthroughs.关键词：Shallow coalbed methane;Ground well construction;Enhanced recovery;controlling factors;Technical limitations;development direction73|443|0更新时间：2025-12-25
- Postal code：210019
- Tel：025-66201780 Email：66scjs@vip.sina.com
- Technical support is provided by Beijing Founder electronics co., LTD 苏ICP备2025204824号-1
苏公网安备32010502011276号 - It is recommended to read the content of this site in Chrome&IE9+. Please switch to extreme mode in browser 360.
- Cookies We use cookies to help provide and enhance our service and tailor content. By continuing, you agree to the use of cookies.
- Total Visits：79133 Visits Today：419
0