Search Results (1,081)

This study investigates the impact of fracture conductivity on hydraulically fractured wells in the Eagle Ford Shale using commercial simulation software. Motivated by recent findings on conductivity degradation and the proven reliability of sensitivity analyses in shale reservoirs, a 17-stage horizontal well was modeled to evaluate productivity optimization. The methodology involved holding fracture fluid volume constant while analyzing conductivity variations across both single-fracture and full-well models. Production simulations were validated against real-time field data. Results indicate that the simulation models accurately represent the reservoir, with single-fracture scenarios yielding similar cumulative production and full-well models showing only minor deviations. Ultimately, the observed differences do not justify a significant deviation from current completion techniques under the modeling assumptions considered, as infinite-acting flow remains the dominant regime due to the reservoir’s low permeability. Full article

Characterizing tight reservoirs is challenging due to the complex pore structure and strong heterogeneity at various scales. Current digital rock physics often struggles to reconcile high-resolution imaging with representative sample sizes, and 3D digital cores are frequently used primarily as visualization tools rather than predictive, computable platforms. Thus, a clear methodological gap persists: high-resolution models typically lack macroscopic geological features, while existing 3D digital models are seldom leveraged for quantitative, predictive analysis. This study, based on a full-diameter core sample of a single lithology (gray-black shale), aims to bridge this gap by developing an integrated workflow to construct a high-fidelity, computable 3D model that connects the micro–nano to the macroscopic scale. The core was scanned using high-resolution X-ray computed tomography (CT) at 0.4 μm resolution. The raw CT images were processed through a dedicated pipeline to mitigate artifacts and noise, followed by segmentation using Otsu’s algorithm and region-growing techniques in Avizo 9.0 to isolate minerals, pores, and the matrix. The segmented model was converted into an unstructured tetrahedral finite element mesh within ANSYS 2024 Workbench, with quality control (aspect ratio ≤ 3; skewness ≤ 0.4), enabling mechanical property assignment and simulation. The digital core model was rigorously validated against physical laboratory measurements, showing excellent agreement with relative errors below 5% for key properties, including porosity (4.52% vs. 4.615%), permeability (0.0186 mD vs. 0.0192 mD), and elastic modulus (38.2 GPa vs. 39.5 GPa). Pore network analysis quantified the poor connectivity of the tight reservoir, revealing an average coordination number of 2.8 and a pore throat radius distribution of 0.05–0.32 μm. The presented workflow successfully creates a quantitatively validated “digital twin” of a full-diameter core. It provides a tangible solution to the scale-representativeness trade-off and transitions digital core analysis from a visualization tool to a computable platform for predicting key reservoir properties, such as permeability and elastic modulus, through numerical simulation, offering a robust technical means for the accurate evaluation of tight reservoirs. Full article

Based on a nonlinear effective stress coefficient calculation method, this study investigates the nonlinear stress sensitivity of permeability in deep shale gas reservoirs through high-temperature, high-pressure experiments on matrix, unpropped fracture, and propped fracture samples. Furthermore, the influence of different effective stress models on production performance in deep shale gas wells was investigated using the PETREL integrated fracturing production simulation module. Results reveal significant nonlinearity in the effective stress behavior of all media, with matrix samples showing much stronger permeability stress sensitivity than fracture samples. Numerical simulations revealed that horizontal well productivity under the nonlinear effective stress model was lower than predictions from the net stress model, providing critical theoretical and technical foundations for the large-scale and efficient development of deep marine shale gas reservoirs in the Sichuan Basin and emphasizing the importance of accurate stress models for production performance forecasting. Full article

The Wufeng–Longmaxi (WF–LMX) shale gas reservoirs at depths > 3500 m in the Lu203–Yang101 well block, southern Sichuan Basin, possess great exploration potential, but their reservoir characteristics and high-production mechanisms remain unclear. In this study, we employed multi-scale analyses—including core geochemistry, X-ray diffraction (XRD), scanning electron microscopy (SEM), low-pressure N₂ adsorption, and nuclear magnetic resonance (NMR)—to characterize the macro- and micro-scale characteristics of these deep shales. By comparing with shallower shales in adjacent areas, we investigated differences in pore structure between deep and shallow shales and the main controlling factors for high gas-well productivity. The results show that the Long 11 sub-member shales are rich in organic matter, with total organic carbon (TOC) content decreasing upward. The mineral composition is dominated by quartz (averaging ~51%), which slightly decreases upward, while clay content increases upward. Porosity ranges from 1% to 7%; the Long11-1-3 sublayers average 4–6%, locally >6%. Gas content correlates closely with TOC and porosity, highest in the Long11-1 sublayer (6–10 m³/t) and decreasing upward, and the central part of the study area has higher gas content than adjacent areas. The micro-pore structure exhibits pronounced stratigraphic differences: the WF Formation top and Long11-1 and Long11-3 sublayers are dominated by connected round or bubble-like organic pores (50–100 nm), whereas the Long11-2 and Long11-4 sublayers contain mainly smaller isolated organic pores (5–50 nm). Compared to shallow shales nearby, the deep shales have a slightly lower proportion of organic pores, smaller pore sizes with more isolated pores, inorganic pores of mainly intraparticle types, and more developed microfractures, confirming that greater burial depth leads to a more complex pore structure. Type I high-quality reservoirs are primarily distributed from the top of the WF Formation to the Long11-3 sublayer, with a thickness of 15.6–38.5 m and a continuous thickness of 13–23 m. The Lu206–Yang101 area has the thickest high-quality reservoir, with a cumulative thickness of Type I + II exceeding 60 m. Shale gas-well high productivity is jointly controlled by multiple factors: an oxygen-depleted, stagnant deep-shelf environment, with deposited organic-rich, biogenic siliceous shales providing the material basis for high yields; abnormally high pore-fluid pressure with preserved abundant large organic pores and increased free gas content; and effective multi-stage massive fracturing connecting a greater reservoir volume, which is the key to achieving high gas-well production. This study provides a scientific basis for evaluating deep marine shale gas reservoirs in southern Sichuan and understanding the enrichment patterns for high productivity. Full article

Shale oil is primarily hosted within nanopores, where its flow behavior exhibits significant deviations from classical Darcy flow. The combined influences of nanoscale confinement and interfacial interactions represent key scientific challenges that hinder efficient shale oil recovery. The results show that under 25 °C and 1 MPa, the displacement distances of shale oil within 12 s in 100, 200, and 300 nm channels were 2.88, 5.67, and 11.01 mm, respectively. As pore size decreases, flow capacity drops sharply, and the displacement–time relationship evolves from quasi-linear to strongly nonlinear, indicating pronounced nanoscale non-Darcy behavior. By incorporating an equivalent resistance coefficient into the plate-channel flow model, the experimental data were accurately fitted, enabling quantitative evaluation of the additional flow resistance induced by nanoconfinement and interfacial adsorption. The equivalent resistance coefficient increases markedly with decreasing pore size but decreases progressively with increasing temperature and driving pressure. Increasing temperature and pressure partially mitigates nanoconfinement effects. In 200 nm channels, the equivalent resistance coefficient decreases from 1.87 to 1.20 as temperature rises from 25 to 80 °C, while in 100 nm channels it decreases from 2.43 to 1.65 as driving pressure increases from 1 to 6 MPa. Nevertheless, even under high-temperature and high-pressure conditions, shale-oil flow does not fully recover to ideal Darcy behavior. This work establishes a nanofluidic-based prediction and evaluation framework for shale oil flow, offering theoretical guidance and experimental reference for unconventional reservoir development and the optimization of enhanced oil recovery strategies. Full article

The Chang 7 shale oil reservoirs of the Yanchang Formation in the Heishui Area of the Ordos Basin display typical tight sandstone characteristics, marked by complex microscopic pore structures and limited flow capacity, which severely constrain efficient development. Using a suite of laboratory techniques—including nuclear magnetic resonance, mercury intrusion porosimetry, oil–water relative permeability, spontaneous imbibition experiments, scanning electron microscopy, and thin section analysis—this study systematically characterizes representative tight sandstone samples and examines the microscopic distribution of remaining oil, flow behavior, and their controlling factors. Results indicate that residual oil is mainly stored in nanoscale micropores, whereas movable fluids are predominantly concentrated in medium to large pores. The bimodal or trimodal T₂ spectra reflect the presence of multiscale pore–fracture systems. Spontaneous imbibition and relative permeability experiments reveal low displacement efficiency (average 41.07%), with flow behavior controlled by capillary forces and imbibition rates exhibiting a three-stage pattern. The primary factors influencing movable fluid distribution include mineral composition (quartz, feldspar, lithic fragments), pore–throat structure (pore size, sorting, displacement pressure), physical properties (porosity, permeability), and heterogeneity (fractal dimension). High quartz and illite contents enhance effective flow pathways, whereas lithic fragments and swelling clay minerals significantly impede fluid migration. Overall, this study clarifies the coupled “lithology–pore–flow” control mechanism, providing a theoretical foundation and practical guidance for the fine characterization and efficient development of tight oil reservoirs. The findings can directly guide the optimization of hydraulic fracturing and enhanced oil recovery strategies by identifying high-mobility zones and key mineralogical constraints, enabling targeted stimulation and improved recovery in the Chang 7 and analogous tight reservoirs. Full article

The shale oil reservoir is characterized by ultra-low porosity and permeability and multi-scale strong heterogeneity. During the sampling process of downhole cores, the rocks can easily be affected by drilling fluid contamination, mechanical stress damage, and other factors, altering the original distribution of oil–water and the characteristics of pore structures. Oil removal and oil saturation are critical steps in core pre-treatment, yet the mechanism of its impact on cores has not been systematically studied. This research focuses on oil removal in six cores from the Jimsar shale oil reservoir with different oil saturations. The necessity and effectiveness of the oil removal saturation and its impact on the microstructure of the cores were systematically evaluated by employing nuclear magnetic resonance (NMR), CT scanning, and permeability testing methods. The results indicate that there are significant differences in fluid composition, pore structure, and wettability among downhole cores, making oil removal saturation treatment a necessary prerequisite for subsequent experiments. High-temperature and high-pressure oil removal shows significant effectiveness, with an average core weight reduction of 2.46% and average reduction in T₂ peak area of 73.75%. The efficacy of oil saturation is influenced by the initial pore-throat distribution in the cores. The oil removal process significantly alters petrophysical parameters, with an average increase in porosity of 3.21 times and permeability rising by an average of 2.16 times, although individual variations exist. Microstructural analysis demonstrates that the oil removal process preferentially removes crude oil from larger pores, while residual oil is mainly distributed in smaller pores, indicated by a left shift in T₂ peak values. Meanwhile, high-temperature and high-pressure conditions induce microfracture development, promoting the migration of crude oil into smaller pores. This research reveals the complex impact mechanism of the oil removal saturation process on shale cores, providing a theoretical basis for accurately evaluating shale reservoir characteristics and optimizing experimental design. Full article

With unconventional oil–gas reservoir exploration and oil and gas theory development, more and more importance is attached to the wellbore integrity. The casing deformation and damage is an integral part of the wellbore integrity theory. In the shale gas block in southwestern China, the casing deformation is grave because of the nonuniform stress of the reservoir, posing a significant influence on the productivity and economic efficiency of the shale gas development. In order to clarify the causes and mechanisms of the casing deformation caused by the nonuniform stress, the author of this paper has established the mechanical properties mathematical model of the casing under the nonuniform load as well as the casing–cement ring–stratum assembly numerical model based on the data of in situ multi-arm well logger and reservoir geological characteristics. Such models are established to study the response pattern of the casing under the nonuniform creep ground stress of the shale gas reservoir. The study herein serves as a reference for the optimization of casing design and target-specific exploration technology adjustments and lays the foundation for promoting the cost-effective development of shale gas reservoirs. Full article

Shale oil reservoirs exhibit ultralow permeability and complex pore structures, which result in non-Darcy low-velocity flow and cause permeability to be stress-sensitive. Moreover, two-phase flow of oil and gas frequently occurs during the depletion of shale oil reservoirs. Consequently, investigating the rate-transient behavior of shale oil wells necessitates comprehensive consideration of multiphase flow, threshold pressure gradients, and stress sensitivity. Although numerous analytical models exist for rate-transient analysis of multistage fractured horizontal wells, none of them simultaneously incorporate these critical factors. In this study, we extend the classical five-region model to incorporate multiphase flow, threshold pressure gradients, and stress sensitivity. The proposed model is solved using Pedrosa’s transformation, perturbation theory, the Laplace transform, and the Stehfest numerical inversion method. A systematic analysis of the influence of various parameters on the oil production rate and cumulative oil production is conducted, and a field case study is presented to validate the applicability and effectiveness of the model. It is found that the permeability modulus of the main fracture, the half-length of the main fracture, and the threshold pressure gradient of the unstimulated reservoir have a significant influence on cumulative oil production spanning 20 years. With a 100% relative input error, these parameters result in prediction errors of 23.77%, 16.65%, and 17.78%, respectively. In contrast, the threshold pressure gradient of the main fracture and the threshold pressure gradient of the stimulated reservoir have a negligible impact; under the same level of input error (100%), they cause only 0.36% and 0.48% prediction errors in the 20-year cumulative oil production period, respectively. This research provides an efficient and reliable framework for analyzing production data and forecasting shale oil well performance. Full article

To enhance production efficiency, shale gas development often employs tighter well spacing and aggressive fracturing strategies. However, these approaches can result in well interference, where overlapping fracture networks between adjacent wells adversely affect gas production. This study introduces a comprehensive evaluation method for assessing fracture interference, with a specific focus on the role of Repeatedly Stimulated Volume (RSV). By integrating fracture network analysis with fracturing fluid migration modeling, we propose a combined static and dynamic risk assessment framework. The results demonstrate that RSV is a critical indicator of fracture interference—larger RSV values signify greater fracture overlap and intensified fluid migration between wells. Key engineering parameters influencing RSV are identified, including well spacing, fluid volume, and fracture design. Supported by real-time monitoring techniques such as microseismic events and pressure data, our dynamic assessment approach enables proactive management of interference risks. This work offers practical insights for optimizing shale gas development, allowing for improved production efficiency while mitigating interference-related drawbacks. Full article

Currently, the formation and evolution processes of overpressure in the Upper Paleozoic tight sandstones of the Ordos Basin are not clearly understood. Taking the Shan 1 Member of the Shanxi Formation in the Yanchang area, southeastern Ordos Basin, as an example, we adopted a numerical simulation method considering pressurization effects (e.g., hydrocarbon generation and disequilibrium compaction) to quantitatively reconstruct the paleo-overpressure evolution history of target sandstone and shale layers before the end of the Early Cretaceous. We calculated two types of formation pressure changes since the Late Cretaceous tectonic uplift: the pressure reduction induced by pore rebound, temperature decrease and pressure release from potential brittle fracturing of overpressured shales, and the pressure increase in tight sandstones caused by overpressure transmission, thus clarifying the abnormal pressure evolution process of the Upper Paleozoic Shanxi Formation tight sandstones in the study area. The results show that at the end of the Early Cretaceous, the formation pressures of the target shale and sandstone layers in the study area reached their peaks, with the formation pressure coefficients of shale and sandstone being 1.41–1.59 and 1.10, respectively. During tectonic uplift since the early Late Cretaceous, temperature decrease and brittle fracture-induced pressure release caused significant declines in shale formation pressure, by 12.95–17.75 MPa and 20.00–25.24 MPa, respectively, resulting in the current shale formation pressure coefficients of 1.00–1.06. In this stage, temperature decrease and pore rebound caused sandstone formation pressure to decrease by 12.07–13.85 MPa and 16.93–17.41 MPa, respectively. Meanwhile, the overpressure transfer from two phases of hydrocarbon charging during the Late Triassic–Early Cretaceous and pressure release from shale brittle fracture during the Late Cretaceous tectonic uplift induced an increase in adjacent sandstone formation pressure, with a total pressure increase of 7.32–8.58 MPa. The combined effects of these three factors have led to the evolution of the target sandstone layer from abnormally high pressure in the late Early Cretaceous to the current abnormally low pressure. This study contributes to a deeper understanding of the formation process of underpressured gas reservoir in the Upper Paleozoic of the Ordos Basin. Full article

The ZN Oilfield shale reservoir is characterized by thin sand–shale interbeds, strong lateral and vertical heterogeneity, poor porosity–permeability, low formation pressure coefficient, and low brittleness, which together limit fracture propagation and suppress production after conventional hydraulic fracturing. To overcome these constraints, we propose an intensive-stage, closely spaced volumetric fracturing technology that couples energy-replenishment pressurization with differentiated parameter design. Numerical simulations were used to quantify how injected fluid volume affects the post-fracturing formation pressure coefficient and estimated ultimate recovery (EUR), and to determine economically optimal energy-replenishment scales. Guided by a “dual sweet spot” evaluation (geological + engineering), field designs reduced stage spacing from 80–100 m to 30–50 m and cluster spacing from 10–20 m to 6–10 m, and increased proppant and fluid intensities to ~5.0 t/m and 22.0 m³/m, respectively. Field monitoring and production data show average fracture half-length increased to 193 m, and average initial oil production per well rose from 8.8 t/d to 12.9 t/d (≈46% increase). These results demonstrate that the proposed approach effectively enlarges fracture-controlled reservoir volume, enhances formation energy, and substantially improves single-well performance in low-pressure shale oil systems. Full article

Shale pores and throats are key factors controlling the enrichment and development efficiency of shale oil and gas. However, the characteristics and formation mechanisms of shale pores and throats remain unclear. Taking the Permian continental shales in the Mahu Sag of the Junggar Basin as an example, this paper studies the formation mechanisms of pores and throats in shales of different lithofacies through a series of experiments, such as high-pressure mercury injection and scanning electron microscopy. The results show that the Permian continental shales in the Junggar Basin are mainly composed of five lithofacies: rich siliceous shale (RSS), calcareous–siliceous shale (CSS), argillaceous–siliceous shale (ASS), siliceous–calcareous shale (SCS), and mixed-composition shale (MCS). The pores in shale are dominated by intergranular and intragranular pores. The intergranular pores are mainly primary pores and secondary dissolution pores. The primary pores are mainly slit-like and polygonal, with diameters between 40 and 1000 nm. The secondary dissolution pores formed by dissolution are irregular with serrated edges, and their diameters range from 0.1 to 10 μm. The throats are mainly pore-constriction throats and knot-like throats, with few vessel-like throats, overall exhibiting characteristics of nanometer-scale width. The mineral composition has a significant influence on the development of pores and throats. Siliceous minerals promote the development of macropores, and carbonate minerals promote the development of mesopores. Clay minerals inhibit pore development. Diagenesis regulates the development of pores and throats through mechanical compaction, cementation, and dissolution. Compaction leads to a reduction in porosity, and cementation has varying effects on the preservation of pores and throats. Dissolution is the main factor for increased pores and throats. These findings provide a lithofacies-based geological framework for evaluating effective porosity, seepage capacity, and shale oil development potential in continental shale reservoirs. Full article

The characteristics of shale oil reservoirs, such as low porosity, ultra-low permeability, and complex pore structure, are key factors affecting effective pore space and fluid migration. This study focuses on medium-to-high maturity mud shale in the Qing-1 Member of the Qingshankou Formation in the Gulong Sag. Using methods such as XRD, organic geochemical testing, and multi-scale pore characterization (FE-SEM, low-temperature CO₂–N₂ adsorption, high-pressure mercury intrusion, and CT scanning), the lithofacies and pore structure were comprehensively characterized, and their controlling factors were analyzed. The results indicate: (1) The mineral composition is dominated by felsic and clay minerals. Based on a three-level classification standard of “mineral composition–sedimentary structure–organic matter abundance”, seven subfacies were identified, with the dominant lithofacies being Felsic–Clayey Mixed Shale and Felsic-bearing Clay Shale. (2) The reservoir space consists of inorganic pores, organic pores, microfractures, and a small amount of other auxiliary pores, exhibiting “bimodal” pore size characteristics. Micro–mesopores dominate adsorption, while macropores/microfractures control free oil seepage; mesopores contribute the most to pore volume. (3) In terms of oil-bearing potential, Felsic–Clayey Mixed Shale shows prominent movable oil potential (average OSI: 133.08 mg/g; S₁ > 2 mg/g, OSI > 100 mg/g). (4) CT-based 3D stick-and-ball models indicate that Felsic–Clayey Mixed Shale has the best connectivity (connectivity rate: 30.63%), with throat radii mostly ranging from 1–15 μm and pore radii from 2–20 μm. (5) Pore development is synergistically controlled by total organic carbon (TOC, with an optimal range of approximately 1–2.5%), clay/felsic mineral ratio, and bedding/structural fractures. The formation of the pore system is the result of dynamic coupling of organic–inorganic interactions during diagenetic evolution: intergranular pores of clay minerals and microfractures jointly contribute to specific surface area and pore volume, while bedding fractures connect nanopore clusters to enhance seepage capacity. This study improves the integrated understanding of dominant lithofacies, pore structure, and oil-bearing potential in the Qing-1 Member of the Gulong Sag, providing a basis for sweet spot evaluation and development optimization. Full article

The development of shale gas reservoirs relies on complex fracture networks created via multistage hydraulic fracturing, yet most existing models still use oversimplified fracture geometries and therefore cannot fully capture the coupled effects of multiscale fracture topology on flow and production. To address this gap, in this study, we combine fractal geometry with the Embedded Discrete Fracture Model (EDFM) to analyze the production dynamics of hydraulically fractured horizontal wells in shale gas reservoirs. A tree-like fractal fracture network is first generated using a stochastic fractal growth algorithm, where the iteration number, branching number, scale factor, and deviation angle control the self-similar hierarchical structure and spatial distribution of fractures. The resulting fracture network is then embedded into an EDFM-based, fully implicit finite-volume simulator with Non-Neighboring Connections (NNCs) to represent multiscale fracture–matrix flow. A synthetic shale gas reservoir model, constructed using representative geological and engineering parameters and calibrated against field production data, is used for all numerical experiments. The results show that increasing the initial water saturation from 0.20 to 0.35 leads to a 26.4% reduction in cumulative gas production due to enhanced water trapping. Optimizing hydraulic fracture spacing to 200 m increases cumulative production by 3.71% compared with a 100 m spacing, while longer fracture half-lengths significantly improve both early-time and stabilized gas rates. Increasing the fractal iteration number from 1 to 3 yields a 36.4% increase in cumulative production and markedly enlarges the pressure disturbance region. The proposed fractal–EDFM framework provides a synthetic yet field-calibrated tool for quantifying the impact of fracture complexity and design parameters on shale gas well productivity and for guiding fracture network optimization. Full article