Search Results (395)

The Chang 7 member of the Ordos Basin hosts abundant shale oil and gas resources and plays a vital role in the development of unconventional energy. This study investigates differences in damage evolution and underlying mechanisms between representative shale oil and shale gas reservoir cores from the Chang 7 member under fracturing fluid hydration. A combination of high-temperature expansion tests, nuclear magnetic resonance (NMR), and micro-computed tomography (Micro-CT) was used to systematically characterize macroscopic expansion behavior and microscopic pore structure evolution. Results indicate that shale gas cores undergo faster expansion and higher imbibition rates during hydration (reaching stability in 10 h vs. 23 h for shale oil cores), making them more vulnerable to water-lock damage, while shale oil cores exhibit slower hydration but more pronounced pore structure reconstruction. After 72 h of immersion in fracturing fluid, both core types experienced reduced pore volumes and structural reorganization; however, shale oil cores demonstrated greater capacity for pore reconstruction, with a newly formed pore volume fraction of 34.5% compared to 24.6% for shale gas cores. NMR and Micro-CT analyses reveal that hydration is not merely a destructive process but a dynamic “damage–reconstruction” evolution. Furthermore, the addition of clay stabilizers effectively mitigates water sensitivity and preserves pore structure, with 0.7% identified as the optimal concentration. The research results not only reveal the differential response law of fracturing fluid damage in the Chang 7 shale reservoir but also provide a theoretical basis and technical support for optimizing fracturing fluid systems and achieving differential production increases. Full article

The laminae of lacustrine shale in China have been systematically identified and characterized by a combination of core/slice observations, mineral compositions, geochemical analysis, pore structure characterization, and oil-bearing evaluation. The shale of the Chang 7 Member, Yanchang Formation, Ordos Basin was examined as an example in the study. Four types of laminae are developed in the Chang 7 Member, including felsic laminae (FQL), clay laminae (CLL), organic matter laminae (OML), and tuff laminae (TUL). The shale reservoirs exhibit significant heterogeneity. Of these, FQL and TUL have superior reservoir characteristics. The pore diameter of TUL is primarily composed of micrometer-sized secondary pores that are generated during the diagenesis process, while mesopore and macropore development are dominant in FQL. The main source laminae in the Chang 7 Member of the Ordos Basin are the OML and CLL, while the main reservoir laminae are the FQL and TUL. Some of the hydrocarbons produced by hydrocarbon generation are stored in the pore space inside the laminae, while the majority migrate to the inorganic pores of the adjacent FQL and TUL. It confirms that OML and CLL afford abundant shale oil, the combination of organic pores and inorganic pores in FQL and TUL serve as reservoir space, and the “clay generation-siliceous reservoir” shale oil enrichment model is established in the Chang 7 Member of Ordos Basin. 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

Reservoir architecture significantly influences fluid flow in ultra-low permeability reservoirs, yet this critical factor is frequently neglected in development strategies. This study investigates the Huang 57 block within the Jiyuan Oilfield of China’s Ordos Basin, where we conducted detailed analysis of well logging data, production history, and sedimentological characteristics. Our research established five diagnostic criteria for identifying architectural boundaries of subaqueous distributary channels, enabling classification of two fundamental architectural patterns—isolated and amalgamated—with four distinctive stacking styles. Analysis reveals that architectural heterogeneity exerts primary control over residual oil distribution, with concentrated accumulation occurring at poorly connected channel margins, interlayer barriers, and unswept zones. We verified these findings through horizontal well data and production performance analysis. The study presents a comprehensive framework for architectural characterization in low-permeability reservoirs and proposes specific development strategies, including strategic well conversion and optimized infill drilling, to enhance injection–production connectivity and improve recovery efficiency. These practical solutions offer valuable guidance for developing similar reservoirs worldwide. Full article

The Permian Xiashihezi Formation in the Ordos Basin is a typical tight sandstone gas reservoir, which is characterized by low porosity and strong heterogeneity. Diagenesis plays a crucial role in controlling reservoir quality. However, the multiple phases and types of diagenetic processes throughout geological history make the compaction mechanisms highly complex. This study employed a high-temperature and high-pressure diagenesis simulation system to conduct geological simulation experiments. Typical reservoir samples from the 2nd Member of the Permian Xiashihezi Formation were selected for these simulations. The experiments replicated the diagenetic evolution of the reservoirs under various temperature, pressure, and fluid conditions, successfully reproducing the diagenetic sequences. The diagenetic sequence included early-stage porosity reduction through compaction, early carbonate cementation, quartz overgrowth, chlorite rim formation, feldspar dissolution, and late-stage illite and quartz cementation. Mechanical compaction is the primary factor reducing reservoir porosity, exhibiting a distinct four-stage porosity reduction pattern: (1) continuous burial stage (>4000 m); (2) stagnation stage of burial (3900 m–4100 m); (3) the secondary continuous burial stage (>5000 m); (4) tectonic uplift stage (3600 m). The experiments confirmed that the formation of various authigenic minerals is strictly controlled by temperature, pressure, and fluid chemistry. Chlorite rims formed in an alkaline environment enriched with Fe²⁺ and Mg²⁺ (simulated temperatures of 280–295 °C), effectively inhibiting quartz overgrowth. Illite appeared at higher temperatures (>300 °C) in platy or fibrous forms. Feldspar dissolution was noticeable upon injection of acidic fluids (simulated organic acids), providing material for authigenic quartz and kaolinite. The key mineral composition significantly impacts reservoir diagenesis. The dissolution released Mg²⁺ and Fe²⁺ ions, crucial for forming early chlorite rims in the overlying sandstones, confirming the importance of inter-strata interactions in “source-facies coupling.” Through physical simulation methods, this study deepened the understanding of the diagenetic evolution and compaction mechanisms of tight sandstones. This provides significant experimental evidence and theoretical support for predicting “sweet spot” reservoirs in the area. Full article

To overcome wellbore instability problems in deep coalbed gas reservoirs in the Ordos Basin, drilling fluid additives were evaluated and a drilling fluid system was designed. According to the SEM and CT analysis results, there were not only face and butt cleats in the coal rock but also bedding and layered fractures. Potassium chloride (KCl) and Potassium formate (HCOOK) drilling fluid systems were formulated. The recovery rate of shale and coal rock cuttings reached 99%, and the linear swelling rates for coal rock in both types of drilling fluid were less than 0.18%. Measured with a servo-controlled compression frame at a loading rate of 1 mm/min, the uniaxial compression strength of coal rock was 11.74 MPa, and it was 9.13 MPa and 10.35 MPa after immersion in KCl and HCOOK drilling fluid, respectively. This indicates that both systems have good inhibition properties. The invasion depth in packed sand was 15.5 mm for KCl drilling fluid and 8 mm for HCOOK drilling fluid, demonstrating good sealing performance by the systems. Compared to KCl drilling fluid, the HCOOK system exhibited better inhibition and sealing performance. After the removal of the 10 mm deep invasion section of drilling fluid, the permeability of the coal rock recovered by more than 90%, and the drilling fluid caused minimum damage to the reservoir. The optimized drilling fluid exhibits excellent sealing and inhibition capabilities, making it highly effective in addressing wellbore stability challenges in carbonaceous mudstone formations at 4000 m in depth in the deep coalbed methane reservoirs of the Ordos Basin. 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

In recent years, controlling the integrity of shallow-buried natural gas pipelines within surface subsidence zones caused by high-intensity underground longwall mining in the Daniudi Gas Field of China’s Ordos Basin has emerged as a critical challenge impacting both mine planning and the safe, efficient co-exploitation of coal and deep natural gas resources. This study included field measurements and an analysis of surface subsidence data from high-intensity longwall mining operations at the Xiaobaodang No. 2 Coal Mine, revealing characteristic ground movement patterns under intensive extraction conditions. The subsidence basin was systematically divided into pipeline hazard zones using three key deformation indicators: horizontal strain, tilt, and curvature. Through ABAQUS-based 3D numerical modeling of coupled pipeline–coal seam mining systems, this research elucidated the spatiotemporal evolution of pipeline Von Mises stress under varying mining parameters, including working face advance rates, mining thicknesses, and pipeline orientation angles relative to the advance direction. The simulations further uncovered non-synchronous deformation behavior between the pipeline and its surrounding sand and soil, identifying two distinct evolutionary phases and three characteristic response patterns. Based on these findings, targeted pipeline integrity preservation measures were developed, with numerical validation demonstrating that maintaining advance rates below 10 m/d, restricting mining heights to under 2.5 m within the 260 m pre-mining influence zone, and where geotechnically feasible, the maximum stress of the pipeline laid perpendicular to the propulsion direction (90°) can be controlled below 480 MPa, and the separation amount between the pipe and the sand and soil can be controlled below 8.69 mm, which can effectively reduce the interference caused by mining. These results provide significant engineering guidance for optimizing longwall mining parameters while ensuring the structural integrity of shallow-buried pipelines in high-intensity extraction environments. 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

Site selection evaluation is a crucial step in the research of hydrogen storage in saline aquifers. Geometric characteristics of the reservoir are one of the key factors determining the site selection evaluation. However, for the anticlinal saline aquifers with effective trap capacity, the coupled effects of reservoir curvature, thickness, and well configuration on hydrogen storage efficiency remain unclear. Thus, based on the Ordos Basin, various 3D computational models with different curvatures, thicknesses, and well configurations are designed to conduct the simulation analysis. The results show that (1) the greater the curvature, the stronger the trap effect. Hydrogen recovery rises first and then declines, reaching a peak of 79.58% at 170° and dropping to 55.17% at 90°. (2) Increasing thickness suppresses lateral hydrogen migration. The maximum gas saturations in the caprock are 0.12, 0.08, and 0.05 for thicknesses of 100%, 200%, and 300%, respectively, indicating that greater thickness reduces gas diffusion into the caprock. (3) The coupling effect between curvature and thickness affects the recovery rate. Thin reservoirs are suitable for small curvatures, while thick reservoirs are more suitable for high curvatures. (4) Top hydrogen injection significantly reduces the sensitivity of the recovery rate to curvature and thickness. When the curvature is between 180° and 100°, lowering recovery differences across thicknesses are lowered from 16.20% under bottom injection to 2.51% under top injection. These results provide support for the site selection and design of hydrogen storage in saline aquifers. Full article

A polyurethane slurry was developed to simultaneously enhance the strength and permeability of geological formations, differing from the conventional fracture grouting used for soft-soil reinforcement. Injected via splitting grouting, the slurry cures to form high-strength, highly permeable channels that increase reservoir permeability while improving mechanical stability (dual-enhanced stimulation). To quantify its diffusion behavior and guide field application, we built a splitting-grouting model using the finite–discrete element method (FDEM), parameterized with the reservoir properties of coalbed methane (CBM) formations in the Ordos Basin and the slurry’s measured rheology and filtration characteristics. Considering the stratified structures within coal rock formed by geological deposition, this study utilizes Python code interacting with Abaqus to divide the coal seam into coal rock and natural bedding. We analyzed the effects of engineering parameters, geological factors, and bedding characteristics on slurry–vein propagation patterns, the stimulation extent, and fracturing pressure. The findings reveal that increasing the grouting rate from 1.2 to 3.6 m³/min enlarges the stimulated volume and the maximum fracture width and raises the fracturing pressure from 26.28 to 31.44 MPa. A lower slurry viscosity of 100 mPa·s promotes the propagation of slurry veins, making it easier to develop multiple veins. The bedding-to-coal rock strength ratio controls crossing versus layer-parallel growth: at 0.3, veins more readily penetrate bedding planes, whereas at 0.1 they preferentially spread along them. Raising the lateral pressure coefficient from 0.6 to 0.8 increases the likelihood of the slurry expanding along the beddings. Natural bedding structures guide directional flow; a higher bedding density (225 lines per 10,000 m³) yields greater directional deflection and a more intricate fracture network. As the angle of bedding increases from 10° to 60°, the slurry veins are more susceptible to directional changes. Throughout the grouting process, the slurry veins can undergo varying degrees of directional alteration. Under the studied conditions, both fracturing and compaction grouting modes are present, with fracturing grouting dominating in the initial stages, while compaction grouting becomes more prominent later on. These results provide quantitative guidance for designing dual-enhanced stimulation to jointly improve permeability and mechanical stability. Full article

Deep coalbed methane development faces technical challenges, such as high in situ stress and low permeability. The dynamic evolution of fractures after hydraulic fracturing and the flowback mechanism are crucial for optimizing productivity. This paper focuses on the inversion of post-fracturing fracture volume parameters and dynamic analysis of the flowback in deep coalbed methane wells, with 89 vertical wells in the eastern margin of the Ordos Basin as the research objects, conducting systematic studies. Firstly, through the analysis of the double-logarithmic curve of normalized pressure and material balance time, the quantitative inversion of the volume of propped fractures and unpropped secondary fractures was realized. Using Pearson correlation coefficients to screen characteristic parameters, four machine learning models (Ridge Regression, Decision Tree, Random Forest, and AdaBoost) were constructed for fracture volume inversion prediction. The results show that the Random Forest model performed the best, with a test set R² of 0.86 and good generalization performance, so it was selected as the final prediction model. With the help of the SHAP model to analyze the influence of each characteristic parameter, it was found that the total fluid volume into the well, proppant intensity, minimum horizontal in situ stress, and elastic modulus were the main driving factors, all of which had threshold effects and exerted non-linear influences on fracture volume. The interaction of multiple parameters was explored by the Partial Dependence Plot (PDP) method, revealing the synergistic mechanism of geological and engineering parameters. For example, a high elastic modulus can enhance the promoting effect of fluid volume into the well and proppant intensity. There is a critical threshold of 2600 m³ in the interaction between the total fluid volume into the well and the minimum horizontal in situ stress. These findings provide a theoretical basis and technical support for optimizing fracturing operation parameters and efficient development of deep coalbed methane. Full article

Coalbed methane (CBM) resources hold broad development prospects in China, with deep CBM reservoirs increasingly becoming a focal point for exploration. However, compared to shallow CBM, the factors influencing the productivity of deep CBM are more complex and less studied. This study integrates statistical methods—grey correlation analysis and principal component analysis—with the machine learning approach of random forests, and further employs a fuzzy mathematics-based comprehensive evaluation method to propose a systematic evaluation framework for identifying key controlling factors of productivity. Using field data from the No. 8+9 coal seam in the eastern margin of the Ordos Basin, the results indicate that the primary geological factors affecting cumulative gas production are gas content and coal seam thickness, while the key engineering factors are proppant intensity and proppant volume. These findings align with practical field experience and provide a rational basis for the design of fracturing strategies in deep CBM reservoirs. Full article

As critical components in continental shale systems, the composition and evolution of clay minerals are fundamental to their diagenetic processes and petrophysical properties. The Chang-7 shales in the Ordos Basin exhibit abundant clay mineral content, offering a valuable case study for clay mineral research under moderate diagenetic conditions. This study employed XRD analysis to determine the whole-rock mineralogy, clay mineral composition, and the evolution characteristics of illite-smectite mixed-layer minerals (I/S). Comprehensive clay mineral datasets compiled from 13 newly analyzed wells and existing literature revealed distinct lateral distribution patterns. Total Organic Carbon (TOC) analysis and vitrinite reflectance (R_o) measurements provided systematic quantification of organic matter abundance and thermal maturation parameters in the studied samples. The results reveal that the Chang-7 shale exhibits a characteristic clay mineral assemblage, with I/S (average 44.2%) predominating over illite (34.7%), followed by chlorite (15.6%) and limited kaolinite (5.4%). Frequent volcanic activities provided substantial precursor materials for smectite formation, which actively participated in subsequent illitization processes, while chlorite and kaolinite distributions were predominantly controlled by provenance inputs and sedimentary facies, respectively. Inconsistencies exist between diagenetic stages inferred from I/S mixed-layer ratios and R_o values, particularly in low-maturity samples exhibiting accelerated illitization. The observed negative correlation between TOC content and mixed-layer ratios in Well YY1 and YSC Section samples demonstrates the catalytic role of organic matter in facilitating smectite-to-illite transformation. These results systematically clarify the coupled effects of sedimentary-diagenetic processes, offering new insights into the mutual interactions between inorganic and organic phases during illitization under natural geological conditions. The findings advance the understanding of Chang-7 shale oil and gas systems and offer practical guidance for future exploration. Full article

This study focuses on the tight sandstone reservoirs of the He 8 Member (Lower Permian Shihezi Formation) in the western Sulige area, Ordos Basin. Multiple analytical methods were integrated, including core observation, thin-section analysis, X-ray diffraction (XRD), and rock mechanics experiments, to systematically evaluate the reservoir’s petrology, pore microstructure, physical properties, and fracture formation mechanisms. Results indicate that the reservoir is primarily composed of quartz arenite (78%), characterized by low porosity (avg. 5.5%) and permeability (avg. 0.15 mD). The pore system comprises dissolution pores, lithic dissolution pores, intergranular pores, and intercrystalline pores. Depositional microfacies significantly influence reservoir quality. Subaqueous distributary channel sands exhibit the best properties (porosity > 5%), followed by mouth bar deposits. The reservoir experienced intense compaction and siliceous cementation, which considerably reduced primary porosity. In contrast, dissolution and tectonic fracturing processes significantly enhanced reservoir quality. Rock mechanics tests reveal that highly heterogeneous rocks are more prone to fracturing under differential stress (σ₁–σ₃). These fractures considerably improve the flow capacity of tight reservoirs. Full article