Search Results (153)

The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article

Capturing CO₂ emitted by coal chemical enterprises and injecting it into oil reservoirs not only effectively improves the recovery rate and development efficiency of tight oil reservoirs in the Ordos Basin but also addresses the carbon emission problem constraining the development of the region. Since initiating field experiments in 2012, the Ordos Basin has become a significant base for CCUS (Carbon capture, Utilization, and Storage) technology application and demonstration in China. However, over the years, projects have primarily focused on enhancing the recovery rate of CO₂ flooding, while issues such as potential reservoir damage and its extent have received insufficient attention. This oversight hinder the long-term development and promotion of CO₂ flooding technology in the region. Experimental results were comprehensively analyzed using techniques including nuclear magnetic resonance (NMR), X-ray diffraction (XRD), scanning electron microscopy (SEM), inductively coupled plasma (ICP), and ion chromography (IG). The findings indicate that under current reservoir temperature and pressure conditions, significant asphaltene deposition and calcium carbonate precipitation do not occur during CO₂ flooding. The reservoir’s characteristics-high feldspar content, low carbon mineral content, and low clay mineral content determine that the primary mechanism affecting physical properties under CO₂ flooding in the Chang 4 + 5 tight sandstone reservoir is not, as traditional understand, carbon mineral dissolution or primary clay mineral expansion and migration. Instead, feldspar corrosion and secondary particles migration are the fundamental reasons for the changes in reservoir properties. As permeability increases, micro pore blockage decreases, and the damaging effect of CO₂ flooding on reservoir permeability diminishes. Permeability and micro pore structure are therefore significant factors determining the damage degree of CO₂ flooding inflicts on tight reservoirs. In addition, temperature and pressure have a significant impact on the extent of reservoir damage caused by CO₂ flooding in the study region. At a given reservoir temperature, increasing CO₂ injection pressure can mitigate reservoir damage. It is recommended to avoid conducting CO₂ flooding projects in reservoirs with severe pressure attenuation, low permeability, and narrow pore throats as much as possible to prevent serious damage to the reservoir. At the same time, the production pressure difference should be reasonably controlled during the production process to reduce the risk and degree of calcium carbonate precipitation near oil production wells. Full article

Tight gas is an unconventional resource abundantly found in low-porosity, low-permeability sandstone reservoirs. Production can be significantly reduced due to water production during the development process. Therefore, it is necessary to predict water production during the logging phase to formulate development strategies for tight gas wells. This study analyzes the water production mechanism in tight sandstone reservoirs and identifies that the core of water production evaluation in the Shihezi Formation of the Linxing block is to clarify the pore permeability structure of tight sandstone and the type of intra-layer water. The primary challenge lies in the accurate characterization of bound water saturation. By integrating logging data with core experiments, a bound water saturation evaluation model based on grain size diameter and pore structure index was established, achieving a calculation accuracy of 92% for the multi-parameter-fitted bound water saturation. Then, based on the high-precision bound water saturation, a gas–water ratio prediction model for the first month of production, considering water saturation, grain size diameter, and fluid type, was established, improving the prediction accuracy to 87.7%. The bound water saturation evaluation and water production evaluation models in this study can achieve effective water production prediction in the early stage of production, providing theoretical support for the scientific development of tight gas in the Linxing block. Full article

Due to factors such as low porosity and permeability, thin sand body thickness, and strong interlayer heterogeneity, the fluid flow in the tight reservoir (beach-bar sandstone reservoir) exhibits obvious nonlinear seepage characteristics. Considering the time-varying physical parameters of different types of sand bodies, a nonlinear seepage coefficient is derived based on permeability and capillary force, and a low-velocity nonlinear seepage model for beach bar sand reservoirs is established. Based on core displacement experiments of different types of sand bodies, the low-velocity nonlinear seepage coefficient was fitted and numerical simulation of low-velocity nonlinear seepage in beach-bar sandstone reservoirs was carried out. The research results show that the displacement pressure and flow rate of low-permeability tight reservoirs exhibit a significant nonlinear relationship. The lower the permeability and the smaller the displacement pressure, the more significant the nonlinear seepage characteristics. Compared to the bar sand reservoir, the water injection pressure in the tight reservoir of the beach sand is higher. In the nonlinear seepage model, the bottom hole pressure of the water injection well increases by 10.56% compared to the linear model, indicating that water injection is more difficult in the beach sand reservoir. Compared to matrix type beach sand reservoirs, natural fractures can effectively reduce the impact of fluid nonlinear seepage characteristics on the injection and production process of beach sand reservoirs. Based on the nonlinear seepage characteristics, the beach-bar sandstone reservoir can be divided into four flow zones during the injection production process, including linear seepage zone, nonlinear seepage zone, non-flow zone affected by pressure, and non-flow zone not affected by pressure. The research results can effectively guide the development of beach-bar sandstone reservoirs, reduce the impact of low-speed nonlinear seepage, and enhance oil recovery. Full article

The pore-throat structure of the extremely low-permeability sandstone reservoir in the Huachi area of the Ordos Basin is complex and highly heterogeneous. Currently, there are issues such as unclear understanding of the micro-pore-throat structural characteristics, primary controlling factors of reservoir quality, and classification boundaries of the reservoir in the study area, which seriously restricts the exploration and development effectiveness of the reservoir in this region. It is necessary to use a combination of various analytical techniques to comprehensively characterize the pore-throat structure and establish reservoir classification evaluation standards in order to better understand the reservoir. This study employs a suite of analytical and testing techniques, including cast thin sections (CTS), scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), as well as high-pressure mercury injection (HPMI) and constant-rate mercury injection (CRMI), and applies fractal theory for analysis. The research findings indicate that the extremely low-permeability sandstone reservoir of the Chang 3 section primarily consists of arkose and a minor amount of lithic arkose. The types of pore-throat are diverse, with intergranular pores, feldspar dissolution pores, and clay interstitial pores and microcracks being the most prevalent. The throat types are predominantly sheet-type, followed by pore shrinkage-type and tubular throats. The pore-throat network of low-permeability sandstone is primarily composed of nanopores (pore-throat radius r < 0.01 μm), micropores (0.01 < r < 0.1 μm), mesopores (0.1 < r < 1.0 μm), and macropores (r > 1.0 μm). The complexity of the reservoir pore-throat structure was quantitatively characterized by fractal theory. Nanopores do not exhibit ideal fractal characteristics. By splicing high-pressure mercury injection and constant-rate mercury injection at a pore-throat radius of 0.12 μm, a more detailed characterization of the full pore-throat size distribution can be achieved. The average fractal dimensions for micropores (Dh2), mesopores (Dc3), and macropores (Dc4) are 2.43, 2.75, and 2.95, respectively. This indicates that the larger the pore-throat size, the rougher the surface, and the more complex the structure. The degree of development and surface roughness of large pores significantly influence the heterogeneity and permeability of the reservoir in the study area. Dh2, Dc3, and Dc4 are primarily controlled by a combination of pore-throat structural parameters, sedimentary processes, and diagenetic processes. Underwater diversion channels and dissolution are key factors in the formation of effective storage space. Based on sedimentary processes, reservoir space types, pore-throat structural parameters, and the characteristics of mercury injection curves, the study area is divided into three categories. This classification provides a theoretical basis for predicting sweet spots in oil and gas exploration within the study area. Full article

Deep tight sandstone reservoirs are characterized by low porosity and permeability, complex pore structure, and strong heterogeneity. Conducting research on the heterogeneity characteristics of reservoirs could lay a foundation for evaluating their effectiveness and accurately identifying advantageous reservoirs, which is of great significance for searching for “sweet spot” oil and gas reservoirs in tight reservoirs. In this study, the deep tight sandstone reservoir in the Dibei area, northern Kuqa depression, Tarim Basin, China, is taken as the research object. Firstly, statistical methods are used to calculate the coefficient of variation (CV) and coefficient of heterogeneity (TK) of core permeability, and the heterogeneity within the reservoir is evaluated by analyzing the variations in the reservoir permeability. Then, based on fractal theory, the fractal and multifractal parameters of the GR and acoustic logs are calculated using the box dimension, correlation dimension, and the wavelet leader methods. The results show that the heterogeneity revealed by the box dimension, correlation dimension, and multifractal singular spectrum calculated based on well logs is consistent and in good agreement with the parameters calculated based on core permeability. The heterogeneity of gas layers is comparatively weaker, while that of dry layers is stronger. In addition, the fractal parameters of GR and the acoustic logs of three wells with the oil test in the study area were analyzed, and the relationship between reservoir heterogeneity and production was determined: As reservoir heterogeneity decreases, production increases. Therefore, reservoir heterogeneity can be used as an indicator of production; specifically, reservoirs with weak heterogeneity have high production. Full article

The shale oil reservoirs in the Liang Gaoshan area of the Sichuan Basin exhibit extremely low porosity and permeability, as well as significant heterogeneity. Consequently, hydraulic fracturing of horizontal wells is critical for achieving effective production enhancement. Early diagnostic monitoring revealed substantial variations in fracture propagation. Some hydraulic fractures extended beyond the target layer into adjacent river sandstone, leading to increased fracturing costs and reduced reserve utilization rates. To address these challenges, temporary plugging fracturing (TPF) was implemented to optimize fluid distribution among fracture clusters. However, previous TPF operations in this basin relied heavily on empirical methods, resulting in a relatively low sealing success rate of approximately 70%. This study proposes a fracture propagation model that incorporates stress interference dynamics induced by temporary plugging fracturing agents. Additionally, through laboratory experiments, a high-pressure (30.2 MPa) degradable temporary-plugging agent was selected for use in horizontal well fracturing. Key process parameters, including the insertion timing, dosage, and distribution strategy of the temporary-plugging agent, were optimized using a numerical simulation system. The results indicate that injecting 50% of the fracturing fluid followed by the simultaneous deployment of 12 temporary blocking nodes ensures uniform fracture cluster extension while maximizing the reconstruction volume. Furthermore, deploying all temporary blocking nodes at once reduces the fracturing operation time by approximately 20%. These findings were validated via field applications at Well NC1. Microseismic monitoring during fracturing confirmed the accuracy of the research outcomes presented in this paper. After temporary plugging, the extension uniformity of each fracture cluster significantly improved, with the stimulated reservoir volume (SRV) of a single section reaching 530,000 cubic meters. These results provide a foundation for optimizing horizontal well fracturing in Liang Gaoshan shale oil reservoirs within the Sichuan Basin, facilitating efficient and economical fracturing operations. Full article

Clay content is a critical geological parameter influencing the pore structure, compaction sensitivity, and flow capacity of sandstone reservoirs. In this study, representative Tertiary sandstones from a major sedimentary basin in western China were selected, covering natural and synthetic core samples with clay contents ranging from 20% to 70%. Utilizing a self-developed apparatus capable of both static and dynamic compaction experiments, we systematically performed staged static loading and gas–water two-phase displacement tests. This enabled us to obtain comprehensive datasets on porosity, permeability, pressure response, and two-phase flow characteristics under various clay content, confining pressure, and gas drive rate conditions. Results demonstrate that high clay content leads to pronounced pore structure compaction and substantially greater permeability reductions compared to low-clay reservoirs, indicating heightened stress sensitivity. The synergy between gas drive rate and confining pressure regulates intralayer water production efficiency: initially, increased gas drive enhances mobile water production, but efficiency drops sharply at late stages due to pore contraction and increased bound water. As confining pressure increases, the mixed-flow region for two-phase flow shrinks, with water permeability decreasing sharply and gas permeability increasing, revealing the dynamic fluid transport and productivity decline mechanisms controlled by effective stress. The research deepens understanding of compaction–flow mechanisms in clay-rich sandstones, offering bases for evaluating reservoir stress sensitivity and supporting efficient, sustainable gas reservoir development, which increasingly helps offset global energy shortages. Full article

Sandstone reservoirs exhibit strong heterogeneity and complex microscopic pore structures, presenting challenges for quantitative characterization. This study investigates the Chang 8 tight sandstone reservoir in the Jiyuan, Ordos Basin through analyses of its physical properties, high-pressure mercury injection (HPMI), casting thin sections (CTS), and scanning electron microscopy (SEM). Deep learning techniques were employed to extract the geometric parameters of the pores from the SEM images. Fractal geometry was applied for the combined quantitative characterization of pore parameters and fractal dimensions of the tight sandstone. This study also analyzed the correlations between the fractal dimensions, sample properties, pore structure, geometric parameters, and mineral content. The results indicate that the HPMI-derived fractal dimension (D_MIP) reflects pore connectivity and permeability. D_MIP gradually increases from Type I to Type III reservoirs, indicating deteriorating pore connectivity and increasing reservoir heterogeneity. The average fractal dimensions of the small and large pore-throats are 2.16 and 2.52, respectively, indicating greater complexity in the large pore-throat structures. The SEM-derived fractal dimension (D_SEM) reflects the diversity of pore shapes and the complexity of the micro-scale geometries. As the reservoir quality decreases, the pore structure becomes more complex, and the pore morphology exhibits increased irregularity. D_MIP and D_SEM values range from 2.21 to 2.49 and 1.01 to 1.28, respectively, providing a comprehensive quantitative characterization of multiple pore structure characteristics. The fractal dimension shows negative correlations with permeability, porosity, median radius, maximum mercury intrusion saturation, mercury withdrawal efficiency, and sorting factor, while showing a positive correlation with median and displacement pressures. Among these factors, the correlations with the maximum mercury intrusion saturation and sorting factor are the strongest (R² > 0.8). Additionally, the fractal dimension is negatively correlated with pore circularity and major axis length, but positively correlated with pore perimeter, aspect ratio, and solidity. A higher proportion of circular pores and fewer irregular or long-strip pores correspond to lower fractal dimensions. Furthermore, mineral composition influences the fractal dimension, showing negative correlations with feldspar, quartz, and chlorite concentrations, and a positive correlation with carbonate content. This study provides new perspectives for the quantitative characterization of pore structures in tight sandstone reservoirs, enhances the understanding of low-permeability formation reservoir performance, and establishes a theoretical foundation for reservoir evaluation and exploration development in the study area. Full article

The tight sandstone gas reservoirs in the LX area of the Ordos Basin are characterized by low porosity, poor permeability, and strong heterogeneity, which significantly complicate fluid type identification. Conventional methods based on petrophysical logging and core analysis have shown limited effectiveness in this region, often resulting in low accuracy of fluid identification. To improve the precision of fluid property identification in such complex tight gas reservoirs, this study proposes a hybrid deep learning model named ResViTNet, which integrates ResNet (residual neural network) with ViT (vision transformer). The proposed method transforms multi-dimensional logging data into thermal maps and utilizes a sliding window sampling strategy combined with data augmentation techniques to generate high-dimensional image inputs. This enables automatic classification of different reservoir fluid types, including water zones, gas zones, and gas–water coexisting zones. Application of the method to a logging dataset from 80 wells in the LX block demonstrates a fluid identification accuracy of 97.4%, outperforming conventional statistical methods and standalone machine learning algorithms. The ResViTNet model exhibits strong robustness and generalization capability, providing technical support for fluid identification and productivity evaluation in the exploration and development of tight gas reservoirs. Full article

The relationships between the pore structure and a single fractal or specific region have been widely reported. However, the intrinsic relationship between multifractal parameters and physical properties have remained uncertain. In this study, micro-computed tomography scanning technology and high-pressure mercury injection technologies were applied to determine the pore structures of tight sandstone at different scales. Subsequently, the multifractal theory was applied to quantitatively evaluate the multiscale pore structure heterogeneity. An evident linear relationship exists between $logX\left(q,\epsilon \right)$ and $\mathit{log}\left(\epsilon \right)$, indicating the pore structure of tight sandstones exhibits significant multifractal characteristics. Multifractal parameters, including $∆\left(\alpha \right), ∆D, D_{min}-D_0,\mathrm{a}\mathrm{n}\mathrm{d}{ D}_0-D_{max}$, can serve as sensitive indicators to assess the multiscale pore structure heterogeneity. In particular, the relative development degree of large-scale pores (>10 μm) can be reflected by $D_{min}-D_{0 }$, which has strong heterogeneity. The heterogeneity of the multiscale structure is closely linked to the mineral components of tight sandstone reservoirs, and the heterogeneity of small-scale pores (1–10 μm) is stronger by clay mineral enrichment. Furthermore, the part of the pore structure corresponding to the combination of pore size range of 10 to 20 μm and throat size range of 20 to 40 μm in a low probability measure area may dominate the permeability of tight sandstone. The findings enhance the understanding of pore structure heterogeneity and broaden the application of multifractal theory. Full article

Studies of hydrocarbon migration and enhanced oil recovery focus on the effects of reservoir heterogeneity on subsurface fluid flow and distribution. Differential diagenesis in clastic rock reservoirs is an important factor of internal-reservoir heterogeneity and its relationship to hydrocarbon charges is a key scientific issue for understanding hydrocarbon accumulation mechanisms in tight-sandstone reservoirs. This paper focuses on the ninth member of the Upper Triassic Yanchang Formation (Chang 9), located in the central and western Ordos Basin, China. The aims of the paper are to examine the differential diagenesis of sandstone reservoirs and to illustrate the process of organic/inorganic fluid–rock interaction using an integrated method of petrography, UV fluorescence spectra, fluid inclusion, and basin modeling analyses. The Chang 9 reservoir comprises four sandstone types: mechanically compacted sandstone, calcite-cemented sandstone, water-bearing sandstone, and oil-bearing sandstone. These four types of sandstone experience contrasting diagenetic evolutions. During early diagenesis, mechanically compacted sandstone and calcite-cemented sandstone undergo strong deformation and cementation, respectively. The water-bearing and oil-bearing sandstones experience similar diagenetic evolutions, but significantly different from those two tight sandstones in fluid activity and diagenesis magnitude. Three types of porous bitumen were identified in the oil-bearing sandstone, whereas no bitumen was identified in the water-bearing sandstone. According to the contact relationship between bitumen, cements, and dissolution pores, the related diagenesis sequence of the oil-bearing sandstones of Chang 9 was reconstructed. Three phases of fluid flow occurred in turn, with hydrocarbon charging in the process, but no hydrocarbon charging occurred in the water-bearing sandstones. The research findings, in terms of organic and/or inorganic fluid–rock interaction, can be used as a reference for the differential diagenesis and process of fluid–rock interaction in low-permeability sandstone reservoirs with a highly heterogeneous internal reservoir framework. Furthermore, this study could help in understanding the internal heterogeneity characteristics of a fluvial sandstone reservoir and its relationship with hydrocarbon charging. Full article

In recent years, the exploration of the Baibei Sag, located in the west of the Erlian Basin, has remained relatively underdeveloped. The Lower Cretaceous of the Baibei Sag hosts multiple tight sandstone reservoirs; however, research on the macro- and micro-characteristics, as well as the controlling factors of these reservoirs, is relatively limited. This study selected 105 Lower Cretaceous sandstone samples from the Baibei Sag for core observation, casting thin sections, scanning electron microscopy, X-ray diffraction, and high-pressure mercury intrusion analysis. The reservoir’s physical properties, pore throat structure, and diagenesis process were studied. The results indicate that the reservoir lithology is mainly composed of feldspar lithic sandstone, with an average composition of 44.3% lithic, 34.6% quartz, and 21.2% feldspar. The clay minerals in the interstitial material are primarily illite (69.3%) and illite–smectite mixed layers (12.7%), with smaller amounts of chlorite (10.9%) and kaolinite (7.2%), while smectite content is very low. The physical property analysis results indicate that the average effective porosity of the Tengger Formation sandstone is 3.3%. The average permeability is 0.01 × 10⁻³ μm². The average effective porosity of the Aershan Formation sandstone is 0.86%, and the average permeability is 0.05 × 10⁻³ μm². The Tengger Formation and Aershan Formation are both tight sandstone reservoirs. The analysis of pore throat structure shows that the reservoir space is mainly composed of dissolution pores. Three types of pore throat structures were identified, and corresponding pore models were established. Based on burial history and organic matter evolution characteristics, this study establishes a diagenetic evolution sequence of the Lower Cretaceous sandstone reservoir. Analysis suggests that the pore throat structure of different reservoir types is mainly controlled by material composition. In the process of diagenetic evolution, the Tengger Formation and Aershan Formation are in the Middle diagenetic stage A. Compaction and cementation are the main reasons for low porosity, while the dissolution improves reservoir performance. The intergranular and intragranular dissolution pores formed by dissolution are the main storage spaces of the reservoir. The early tectonic fractures are filled with calcite, and the residual small-scale fractures play a role in improving permeability. Full article

Reservoir evaluation is essential in oil and gas exploration, influencing development decisions. Traditional classification methods are often limited by small sample sizes and low accuracy, restricting their effectiveness. To address this, we propose an intelligent classification method, GA-XGBoost, which integrates Genetic Algorithm (GA) optimization with Extreme Gradient Boosting (XGBoost) to enhance the classification accuracy in small-sample scenarios. The lithological, physical, and lithofacies characteristics of tight sandstone reservoirs are analyzed, and key evaluation parameters—including the mineral composition, porosity, permeability, oil saturation, and logging data (GR, SP, CAL, DEN, AC, LLS)—are selected. After data normalization, the GA-XGBoost model is developed and compared with SVM, XGBoost, and AdaBoost models. The experimental results demonstrate that GA-XGBoost achieves an 88.8% classification precision, outperforming traditional algorithms in both efficiency and accuracy. This study advances experiments on and the standardization of intelligent reservoir evaluations, providing a more reliable classification approach for tight sandstone reservoirs. Additionally, it contributes to the integration of geological exploration and computational intelligence, offering new insights into the application of machine learning in geosciences. Full article

The eighth member of the Permian Shihezi Formation is one of the main tight sandstone gas layers in the Longdong Area of Ordos Basin, and the source rocks are dark mudstones and shales located in the Shanxi Formation and Taiyuan Formation of the Permian. The tight muddy sandstone at the top provides shielding conditions and constitutes traps. The lithology is mainly lithic quartz sandstone, followed by lithic sandstone. The reservoir space is mainly dissolved pores, inter crystalline pores, intergranular pores and so on. Clay minerals are the main interstitial materials, and chlorite has the highest content in it, a product of alkaline, moderate- to high-temperature, reducing conditions, effectively inhibited quartz cementation and enhanced secondary porosity development during mesodiagenesis. The average porosity of the reservoir is about 4.01%, and the average permeability is about 0.5 × 10⁻³ μm³, which is a typical low porosity and ultra-low permeability tight reservoir. The thickness of the sandstone reservoir in the study area is from 5 m to more than 25 m, mainly in the NE direction. The sand bodies are distributed in lenses on the plane. Full article