The prediction and distribution of reservoir porosity and permeability are of paramount importance for the exploration and development of regional oil and gas resources. In order to optimize the prediction methods of porosity and permeability and better guide gas field development, it is necessary to identify the most effective approaches. Therefore, based on the extreme gradient boosting (XGBoost) algorithm, laboratory test data of the porosity and permeability of cores from the southern margin of the Ordos Basin were selected as the target labels, conventional logging curves were used as the input feature variables, and the mean absolute error (MAE) and the coefficient of determination (R²) were used as the evaluation indicators. Following the selection of the optimal feature variables and optimization of the hyper-parameters, an XGBoost porosity and permeability prediction model was established. Subsequently, the innovative application of homogeneous clustering (K-means) data preprocessing was applied to enhance the XGBoost model’s performance. The results show that logarithmically preprocessed (LOG(PERM)) target labels enhanced the performance of the XGBoost permeability prediction model, with an increase of 0.26 in its test set R². Furthermore, the application of K-means improved the performance of the XGBoost prediction model, with an increase of 0.15 in the R² of the model and a decrease of 0.017 in the MAE. Finally, the POR_0/POR_1 grouped porosity model was selected as the final predictive model for porosity in the study area, and the Arctan(PERM)_0/Arctan(PER0M)_1 grouped model was selected as the final predictive model for permeability, which has better prediction accuracy than logging curves. The combination of K-means and the XGBoost modeling method provides a new approach and reference for the efficient and relatively accurate evaluation of porosity and permeability in the study area.

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.

This study employed high-resolution CT scanning and Avizo software algorithms to analyze the microscopic pore structure of the clastic rock reservoir in the Yingcheng Formation, Block D, southeastern Songliao Basin, China, and its impact on fluid flow, constructing a high-precision three-dimensional digital rock model. The optimal representative elementary volume (REV) was identified as 400 × 400 × 400 voxels. Using this as a basis, the ″maximum ball″ algorithm extracted the pore network model, allowing for quantitative characterization of its topological features and PNM-based single-phase flow simulations. Furthermore, two-phase flow simulations of CO₂ displacing CH₄ were performed via the AVIZO-FLUENT interactive coupling technology. Results show that the reservoir exhibits significant heterogeneity, with pore radii mainly between 2 and 7 μm and throat radii from 0.5 to 3 μm, reflecting a typical ″large pore, small throat″ characteristic. Throat lengths are primarily between 10 and 25 μm, while the coordination number is mainly within 1–4. Permeability correlates positively with pore-throat radius and throat length but negatively with tortuosity and fractal dimension. Single-phase flow simulations indicate that pore structure complexity significantly affects seepage behavior. The numerically simulated permeability deviates from experimental measurements by no more than 12.5%, confirming the reliability of the simulation approach. Two-phase flow simulations show that the CO₂ displacement is significantly affected by pore structure complexity and heterogeneity, progressing through three stages: uniform front advancement, fingering development, and residual gas retention. Residual CH₄ mainly accumulates at pore edges and corners, with final CO₂ and residual CH₄ saturations stabilizing at 94.74 and 5.26%, respectively. Integrating digital rock technology with multiscale flow simulations, this study refines the characterization of complex reservoir pore structures and elucidates their control over fluid migration. These findings provide a scientific basis for optimizing CO₂ geological storage and enhancing gas reservoir recovery while also supporting development strategies for low-permeability reservoirs.

CO₂ geological sequestration in shale is a promising method to mitigate global warming caused by greenhouse gas emissions as well as to enhance the gas recovery to some degree, which effectively addresses the problems related to energy demand and climate change. With the data from the New Albany Shale in the Illinois Basin in the United States, the CMG-GEM simulator is applied to establish a numerical model to evaluate the feasibility of CO₂ sequestration in shale gas reservoirs with potential enhanced gas recovery (EGR). To represent the matrix, natural fractures, and hydraulic fractures in shale gas reservoirs, a multicontinua porous medium model will be developed. Darcys and Forchheimers models and desorption-adsorption models with a mixing rule will be incorporated into the multicontinua numerical model to depict the three-stage flow mechanism, including convective gas flow mainly in fractures, dispersive gas transport in macropores, and CH₄-CO₂ competitive sorption phenomenon in micropores. With the established shale reservoir model, different CO₂ injection schemes (continuous injection vs. pulse injection) for CO₂ sequestration in shale gas reservoirs are investigated. Meanwhile, a sensitivity analysis of the reservoir permeability between the hydraulic fractures of production and injection wells is conducted to quantify its influence on reservoir performance. The permeability multipliers are 10, 100, and 1,000 for the sensitivity study. The results indicate that CO₂ can be effectively sequestered in shale reservoirs. But the EGR of both injection schemes does not perform well as expected. In the field application, it is necessary to take the efficiency of supplemental energy utilization, the CO₂ sequestration ratio, and the effect of injected CO₂ on the purity of produced methane into consideration to design an optimal execution plan. The case with a permeability multiplier of 1,000 meets the demand for both CO₂ sequestration and EGR, which indicates that a moderate secondary stimulation zone needs to be formed between the primary hydraulic fractures of injection and production wells to facilitate the efficient energy transfer between interwell as well as to prevent CO₂ from channeling. To meet the demand for CO₂ sequestration in shale gas reservoirs with EGR, advanced and effective fracking is essential.

The study aims to investigate the rock mechanical properties of the Chang 7 member tight oil reservoir in the Longdong region of the Ordos Basin, China, with the goal of enhancing the efficiency of oilfield development. Despite numerous contributions in the field of rock mechanics, challenges persist in reconciling experimental results with actual geological conditions and achieving comprehensive understanding of rock mechanical properties in tight oil reservoirs. To address this, a variety of experimental methods were employed to systematically assess the mechanical properties of the target reservoir. Rock density was measured using volumetric methods, tensile strength was evaluated through the Brazilian test, uniaxial and triaxial compression tests were conducted to assess rock mechanics properties, and dynamic elastic modulus and Poisson’s ratio were obtained via sonic velocity measurements. Furthermore, differential strain analysis and imaging log analysis were employed to determine the magnitude and direction of geostress. The results revealed that fine-grained sandstone exhibited higher rock density and relatively higher tensile strength, while muddy siltstone exhibited comparatively lower values in these aspects. Analysis of the influence of confining pressure on rock mechanics properties demonstrated a strong positive correlation between compressive strength and Young’s modulus with confining pressure, while Poisson’s ratio exhibited more irregular variations. Additionally, a mathematical relationship between dynamic and static rock mechanical parameters was established. Lastly, based on the characteristics of geostress, reliable foundations for optimizing hydraulic fracturing and wellbore layout were provided. This study has enriched and complemented the investigation of rock mechanical properties in tight reservoirs, offering vital parameters and theoretical support for the development of tight oil reservoirs. This bears significant importance in enhancing petroleum extraction efficiency and optimizing engineering design.

Renewable geothermal utilization is a significant approach for residential heating with two principal modes, direct geothermal district heating systems (DGDHSs) and indirect geothermal district heating systems (IGDHSs). The key principle of geothermal development design is to prevent premature thermal breakthrough, which could result in low efficiency of geothermal heating systems. In this paper, a new approach considering building heating demand, geothermal water resource protection, and optimal economic benefits is presented systematically. The results simulated by OGS software show that well spacing, reinjection temperature, and production rate are the most significant parameters affecting thermal breakthrough in geothermal reservoirs. In addition, production rate and reinjection temperature have a huge effect on the payback period of investment. Comparing IGDHS to DGDHS, the investment in construction of geothermal wells and the annual water consumption decrease by up to 10% and 50%, respectively. Additionally, electricity costs increase by 5% to 30%. The indirect geothermal district heating system with a well spacing of 300 m, a production rate of 100 m3/h, and a reinjection temperature of 301.15 K is much better for this case, both technically and economically. The systematic calculation approach can be reasonably applied to other regions with geothermal energy utilization.