Search Results (57)

This study addresses the poorly understood fracture propagation mechanisms in continental shale oil reservoirs with multi-lithologic combinations, specifically those in the lower third member of the Shahejie Formation, Bonan Sag, which exhibit complex lithology, coexistence of bedding planes and natural fractures, and pronounced mechanical anisotropy. We conduct small scale true triaxial hydraulic fracturing physical simulation experiments using limestone mudstone, felsic–lime mixed shale, and their combined rock samples. We innovatively introduce the hydraulic fracture complexity coefficient (F_h), the bedding plane fracture complexity coefficient (F_l), and the comprehensive fracture complexity coefficient (F_T) to enable quantitative evaluation of fracture complexity. The results show that high-viscosity fracturing fluid promotes vertical propagation and improves proppant placement, but yields relatively simple fracture geometry. Low-viscosity fracturing fluid readily activates bedding plane fractures, yet limits fracture height; a combined viscosity strategy can synergistically optimize the overall fracturing performance. The “high–low–high” viscosity sequence achieves the highest comprehensive fracture complexity coefficient (F_T), simultaneously providing large fracture height, high complexity, and effective proppant transport. Although increasing the injection rate significantly reduces the breakdown pressure and increases fracture width, it contributes marginally to vertical fracture growth. For fracturing multi-lithologic shale oil reservoirs, the recommended technical strategy is a “high-low-high” viscosity sequence combined with a moderately increased injection rate” to maximize the stimulated reservoir volume and overall fracturing effectiveness. Full article

The Gulong shale oil reservoir is characterized by high clay content and strong heterogeneity, with substantial variations in mineral composition among different intervals. However, existing fracability evaluation methods for such continental shales remain inconsistent and often rely on oversimplified two-dimensional fracture descriptors, lacking a multi-parameter quantitative framework derived from three-dimensional fracture characterization. In this study, the Q1 and Q9 members of the Gulong shale oil were selected, and laboratory-scale hydraulic fracturing simulation experiments were conducted using supercritical carbon dioxide (SC-CO₂), liquid CO₂, and water as the fracturing media. Within a fractal-theory framework based on CT-derived three-dimensional reconstructions, a multi-scale evaluation index system was established by integrating fractal dimension, fracture density, and spatial connectivity. The experimental results demonstrate that fluid properties exert a decisive influence on rock failure behavior. Owing to its ultra-low viscosity and strong diffusivity, SC-CO₂ can significantly reduce formation breakdown pressure while effectively activating natural weak planes to generate a more complex fracture network. For the Q9 shale, the breakdown pressure under SC-CO₂ is reduced by 11.91% and 8.33% relative to water and liquid CO₂, respectively. Moreover, the fracture fractal dimension reaches 2.41 under SC-CO₂, which is markedly higher than the values obtained under liquid CO₂ (2.18) and water (2.12). Mineral composition and densely developed bedding are the key factors inducing fracture branching and deflection, whereas injection rate and an asymmetric stress field regulate the internal energy-release rate and stress path, thereby influencing fracture crossing capability and aperture evolution. Based on the experimental dataset, a fracture complexity index (FCI) evaluation model was developed: under SC-CO₂ fracturing, the FCI values are 8.92 for the Q9 member and 4.43 for the Q1 member, and the model predictions are in good agreement with physical observations. This work elucidates the failure mechanism of the Gulong shale under multi-field coupling and provides a theoretical basis for optimizing hydraulic fracturing and evaluating fracability in unconventional reservoirs through the proposed FCI-based assessment framework. Full article

In the Ordos Basin, one of the most important oil- and gas-bearing basins, the Triassic Yanchang Formation has formed important source rocks, but is also a typical representative of continental deep-water sedimentation. In the Huacheng area of the Upper Triassic Yanchang Formation, the deep-water gravity flow sedimentation characteristics of the lake-bottom fan are complex, and the spatial distribution pattern and stacking style of the sand bodies are of great significance for oil and gas resource exploration. Based on core observation, by combining well logging and analysis of signs of sedimentary facies, including petrologic features and primary sedimentary structures, the thick massive sand bodies of the Chang 6 Member belong to deep-water gravity flow deposits, and they develop in a semi-deep to deep lacustrine environment in the Huachi area, Ordos Basin. The primary sedimentary structures of deep-water gravity flows include massive bedding, graded bedding, sliding fractures, slumping deformation structures, turbidite sequences, and synsedimentary offsets. Two kinds of deep-water gravity flows of the channel system, namely sandy debris flows and turbidity currents, were identified in the sublacustrine fan. The sublacustrine provided accommodation space for the rapid unloading and accumulation of gravity flows. Deposited sandy debris flows are the most widely distributed in the sublacustrine fan. Three types of stacked sand bodies developed in the Chang 6 Member of the Huachi area, including multi-stacked thick-layered, sandstone–mudstone interbedded, and sand-thin and mud-thick types. The multi-stacked thick-layered sand bodies consist of multi-period massive sandstones, which are interpreted as sandy debris flow deposits. Sandstone–mudstone interbedded types exhibit diverse lithologies, including massive sandstone and deformed structural sandstone. In addition, the turbidity current is the primary factor controlling the stacked sand bodies. Sand-thin and mud-thick sand bodies consist primarily of laminated mudstone, massive mudstone, and flaser-bedded sandstone, and these deposits were formed by waning-stage turbidity currents and the rigid heads of sandy debris flows. Full article

The Mahu Sag, a hydrocarbon-rich depression within the Junggar Basin, hosts significant petroleum resources. Here, the Permian Fengcheng Formation shale oil reservoirs have emerged as a primary exploration target. This study investigates fracture development within these alkaline lacustrine shales, a critical factor governing hydrocarbon migration and accumulation. Through integrated petrographic and geochemical analyses, we elucidate a multifactorial fracture formation mechanism driven by the interplay of alkaline minerals, stress, and fluids. Two distinct fracture types were identified: bedding-complex fracture veins (BCFVs) and Y-shaped high-angle fracture veins (Y-HFVs). Both fracture types result from alkaline fluid–rock interactions, which induce fracture opening along specific orientations, alter fracture angles, and control aperture width and final morphology. Alkaline mineral assemblages further influence fracture evolution via dissolution–precipitation cycles. Concurrently, these assemblages preserve hydrocarbons by inhibiting the thermal maturation of organic matter, as evidenced by variations in fluid inclusion fluorescence. The fracture networks act as crucial migration pathways, with the BCFV containing higher-maturity hydrocarbons (indicated by blue-green fluorescence) and the Y-HFV retaining less mature fluids (indicated by yellow-green fluorescence). This study presents the first systematic characterization of the multifactorial controls on fractures in alkaline lake environments, proposing a cooperative “alkaline minerals–stress–fluids” mechanism. These findings provide a new framework for understanding fracture development in alkaline lacustrine shales and offer valuable insights for shale oil exploration in analogous depositional settings. Full article

The fractured lacustrine carbonate oil reservoir in the Lower submember of Member 4 (Qian-4) of the Qianjiang Formation in the Zhongshi area, Jianghan Basin, represents an important target for hydrocarbon exploration and exhibits substantial exploration and development potential. To clarify the mechanisms by which fractures control reservoir effectiveness, this study integrates core description, thin-section petrography, petrophysical measurements, and geophysical interpretation to systematically characterize matrix properties and fracture development. Results show that the reservoir matrix is dominated by micritic carbonate rocks and grain-dominated carbonate rocks, and overall exhibits low-porosity and ultra-low-permeability characteristics, with an average porosity of 5.19% and permeability generally below 5 mD. Fractures are well developed within the matrix, mainly comprising non-tectonic bedding-parallel fractures and tectonic high-angle fractures. Fracture-related porosity averages 8.42%, and permeability can reach 10–100 mD or higher. The fracture attributes and their spatial distribution are the key controls on hydrocarbon enrichment and deliverability; the occurrence of different fracture types across lithologies and sublayers can significantly enhance reservoir flow capacity. Moreover, natural-fracture characteristics provide critical geological constraints for hydraulic fracturing design and implementation. These findings offer a theoretical basis for fine-scale exploration and development of fractured lacustrine carbonate reservoirs. Full article

This study systematically investigates the reaction characteristics of laminated shale oil reservoirs in the 7₃ sub-member of the Yanchang Formation, Heshui area, Ordos Basin, under exposure to CNI-I nanoviscous fracturing fluid. The reservoir matrix comprises 84.85% brittle minerals and 15.15% clay minerals. Fluid–rock interactions significantly dissolve calcite and dolomite, releasing Ca²⁺ and Mg²⁺ ions, while clay mineral reactions liberate substantial amounts of Na⁺. Post-reaction, fluid system stability is markedly reduced, elevating the risk of precipitate formation and pore-throat plugging. Exposure to fracturing fluid reduces the T₂ cutoff value of core samples from 3.29 ms to 1.72 ms, indicating a densification of the micro-pore-throat network and a decline in mobile fluid saturation, while fracture apertures exhibit widening. Based on empirical data, a discriminant criterion (R value) defined as the ratio of fracture aperture increment rate to pore-throat diameter reduction rate is established at 1.25, confirming that fracture propagation dominates over pore constriction. Dual-medium modeling yields a net permeability enhancement of 19.35%. Fluid–rock interactions induce overall degradation of rock mechanical properties with pronounced anisotropy: rock strength along the direction perpendicular to bedding declines by 37.546%, Young’s modulus decreases by 1.81%, and Poisson’s ratio increases by 0.02%—all significantly exceeding the degree of degradation parallel to bedding. This anisotropic mechanical degradation predisposes the near-wellbore region to shear slip and wall spalling, prompting the development of targeted engineering mitigation strategies. Full article

The development and utilization of unconventional shale oil and gas have enhanced the resilience of global energy security. Hydraulic fracturing is the primary method for enhancing unconventional shale oil and gas extraction. Previous studies have predominantly employed homogenized geomechanical models to simulate fracture propagation in rock masses. However, bedding planes and inhomogeneous mineral distributions introduce mechanical anisotropy in shale, rendering conventional homogenized models insufficient for accurately representing hydraulic fracturing in real reservoirs. For this, millimeter-scale indentation testing was employed to systematically quantify the depth-dependent distribution of mechanical parameters across varying bedding orientations, using fragmented shale samples obtained from the Qingshankou Formation of the Songliao Basin, northern China. Then, hydraulic fracturing simulations were performed using the mechanical properties derived from the indentation tests. The key findings include: (1) The elastic modulus of the Qingshankou Formation shale reservoir exhibits significant anisotropic properties in both the depth and bedding orientations. The elastic modulus measured parallel to bedding (10.23–65.08 GPa) is 28% higher than that measured perpendicular to bedding (9.60–47.24 GPa) due to shale bedding anisotropy. The mineralogical composition predominantly governs the depth-dependent anisotropy, with an elevated brittle mineral content increasing the elastic modulus and a higher clay content reducing it. (2) The simulation results reveal that the depth-dependent anisotropy of elastic modulus induces asymmetric hydraulic fracture propagation, with the fractures preferentially extending along the orientations exhibiting a higher elastic modulus. This behavior arises due to the enhanced brittleness and reduced deformation resistance of high-modulus rocks, facilitating fracture advancement. The study offers critical insights for hydraulic fracturing design and operational implementation in bedded shale reservoirs. Full article

The Yingxiongling structural zone in the Qaidam Basin is a critical yet challenging target for shale oil exploration due to strong reservoir heterogeneity and complex sedimentary cycles. This study employs an integrated methodology combining laboratory rock mechanical tests, field fracturing diagnostics, and tracer data to evaluate the fracturing performance of dominant lithofacies. Results indicate that: (1) Laminated dolomitic limestone exhibits higher mechanical strength and requires elevated fracturing pressure compared to laminated shale, but contains inferior hydrocarbon content. In contrast, laminated shale develops more uniform and complex fracture networks post-fracturing. (2) A lower microseismic b-value in laminated dolomitic limestone suggests shear-dominated failure along bedding planes, enhancing micro-fracture development. (3) Pressure decline analysis and microseismic monitoring confirm that laminated shale facilitates higher fracture network complexity. In conclusion, laminated shale is identified as the preferred lithofacies in the Yingxiongling area, as it possesses a superior potential for generating complex fracture networks that meet the technical requirements for effective volume stimulation. Full article

The paper examines the experimental performance of air–rock bed, oil only, and oil–rock bed systems for storing heat suitable for cooking applications. The air–rock bed system is charged using hot air from a compressed air tank, while the oil–rock bed system employs a resistive heating element to heat a small volume of oil, which then circulates naturally. The charging process for the oil systems was controlled by adjusting funnel heights, and temperature measurements were taken using thermocouples connected to a data logger. Both systems can store thermal energy ranging from 4.5 kWh to 8 kWh and achieve temperatures between 150 °C and 300 °C, depending on supply temperatures. The simpler oil–rock bed allows for the direct boiling of water using the high temperature produced, and tests indicated comparable boiling times between systems. The findings suggest that these heat storage systems could enhance the advancement and integration of solar cookers, enabling more flexible cooking options. Full article

Understanding the mechanical responses of layered rock masses at both macro and micro scales, particularly under diverse confining pressures and bedding directions, is crucial for evaluating their stability and optimizing resource extraction. This study employs PFC2D numerical models, calibrated with laboratory data from Xinjiang Barkol oil shale, to investigate how confining pressure and bedding direction control the mechanical properties of layered rock masses during biaxial compression. The results demonstrate distinct failure modes, shifting from splitting in Per bedding (beddings perpendicular to the loading direction) to shear-tension and shear-slip failures in inclined bedding. A U-shaped distribution of compressive strength across bedding directions is observed, with strength increasing under higher confining pressure. A novel microfracture connection algorithm is proposed to quantify microfracture parameters, such as quantity, length, and angle, shedding light on the complex microfracture evolution mechanisms. Fewer persistent microfractures in Par (i.e., beddings are parallel to the loading direction) and Per beddings explain their higher compressive strength compared to inclined bedding. Additionally, microfracture length evolution demonstrates a shift from brittle to ductile macro-failure as bedding direction changes. Microfractures primarily develop parallel to the loading direction, while confining pressure slightly affects microfracture characteristics. These findings establish a new framework for predicting the behavior of layered rock masses under complex loading, providing theoretical insights and practical guidance for engineering applications. Full article

Bedding-parallel fractures represent a crucial flow-path network in shale oil reservoirs, yet their timing of opening and driving mechanisms remain subjects of long-standing debate. This study investigates the origin and opening mechanisms of bedding-parallel fractures within the Paleogene Funing shale oil reservoir of the Huazhuang area, Subei Basin, eastern China. A combination of petrography, fluid-inclusion analysis, PVTx paleo-pressure modeling, hydrocarbon generation history modeling, and reflectance measurements was employed. The results reveal the presence of abundant oil inclusions and bitumen within the bedding-parallel veins, indicating that the initiation of fracture was essentially synchronous with the oil emplacement. The studied Funing shale, with vitrinite reflectance values of 0.85% to 1.04%, is mature, identifying it as an effective oil-prone source rock. Thermal maturity of bitumen is comparable to that of the host shale, suggesting a local oil source. Homogenization temperatures (T_h) of coeval aqueous inclusions record fracture opening temperatures of approximately 100–150 °C, consistent with oil-window conditions. By integrating T_h data with burial history modeling, the timing of fracture formation and coeval oil injection is constrained to the peak period of local hydrocarbon generation, rather than the Oligocene Sanduo tectonic event. This indicates that fracture opening was primarily associated with hydrocarbon generation rather than tectonic compression. Petroleum-inclusion thermodynamic modeling demonstrates that the bedding-parallel fracture opening occurred under moderate to strong overpressure conditions, with calculated paleo-pressure coefficients of ~1.35–2.36. This finding provides direct paleo-pressure evidence supporting the mechanism of bedding-parallel fracture opening driven by fluid overpressure created during oil generation. These oil-bearing, overpressured fluids facilitated the initial opening and subsequent propagation of fractures along the bedding planes of shales. Concurrently, the precipitation of the calcite veins may have been triggered by pressure drop associated with the expulsion of some coexisting aqueous fluids. This study provides evidence addressing the debated mechanisms of bedding-parallel fracture opening in organic-rich shales, highlighting the critical role of oil generation-induced overpressure. Full article

The study presents the results of investigations into various types of anhydrous pyrolysis aimed at determining the kinetic parameters of hydrocarbon generation processes from source rocks. Surface outcrop samples from the Silesian, Dukla, and Skole units, characterized by a low level of thermal maturity, were used as experimental material. The samples predominantly represented the Menilite Beds from the aforementioned three units, but also included Istebna, Lgota, Verovice, and Spas beds, which exhibit significantly lower parameters that describe generation properties. The anhydrous pyrolysis experiments provided information on the rate of organic matter decomposition (TG/DSC), the degree of conversion (Rock-Eval), the quality of the obtained products (Py/GC), and the isotopic composition of the gaseous products (Py/GC/IRMS). Chromatographic analyses confirmed the oil-prone nature of kerogen contained in the Menilites from the Dukla Unit (Tylawa area), the Silesian Unit (Iwonicz fold), and the Skole Unit, revealing an equal share of all hydrocarbon fractions: C₁–C₉, C₁₀–C₁₅, and C₁₅₊. Through the integration of pyrolytic studies conducted on potential source rocks in the polish Outer Carpathians, a new type of information was obtained regarding the rate of organic matter decomposition, as well as the fractional and isotopic composition of the pyrolysis products. The set of obtained results was used to estimate the activation energy and characterize the potential source levels. The innovative aspect of this approach involved the isotopic characterization of gaseous products generated during thermal degradation of the source rocks. These data were subsequently used to establish genetic correlations with natural gases accumulated in hydrocarbon reservoirs of the Carpathian region. It has been demonstrated that pyrolysis using PY-GC-IRMS can yield results comparable to those obtained through generation in natural geological conditions. Full article

Shale oil and gas reservoirs are characterized by low porosity and low permeability. The development of ultra-long horizontal wells can significantly increase reservoir contact area and enhance single-well production. Shale formations exhibit distinct bedding structures, high formation pressure, high rock hardness, and strong anisotropy. These characteristics result in poor drillability, slow drilling rates, and high costs when drilling horizontally, severely restricting efficient development. Therefore, accurately predicting the drillability of shale gas wells has become a major challenge. Currently, most scholars rely on a single parameter to predict drillability, which overlooks the coupled effects of multiple factors and reduces prediction accuracy. To address this issue, this study employs drillability experiments, mineral composition analysis, positional analysis, and acoustic transit-time tests to evaluate the effects of mineral composition, acoustic transit time, bottom-hole confining pressure, and formation drilling angle on the drillability of horizontal well reservoirs, innovatively integrating multiple parameters to construct a nonlinear model and introducing three intelligent optimization algorithms (PSO, AOA-GA, and EBPSO) for the first time to improve prediction accuracy, thus breaking through the limitations of traditional single-parameter prediction. Based on these findings, a nonlinear regression prediction model integrating multiple parameters is developed and validated using field data. To further enhance prediction accuracy, the model is optimized using three intelligent optimization algorithms: PSO, AOA-GA, and EBPSO. The results indicate that the EBPSO algorithm performs the best, followed by AOA-GA, while the PSO algorithm shows the lowest performance. Furthermore, the model is applied to predict the drillability of Well D4, and the results exhibit a high degree of agreement with actual measurements, confirming the model’s effectiveness. The findings support optimization of drilling parameters and bit selection in shale oil and gas reservoirs, thereby improving drilling efficiency and mechanical penetration rates. Full article

The characteristics and evolution of fibrous calcite veins in organic-rich shales have gained significant attention due to the recent advancements in shale oil and gas exploration. However, the fibrous calcite veins in the Upper Permian Dalong Formation remain lacking in awareness. To investigate the formation and significance of bedding-parallel fibrous calcite veins in the Dalong Formation, we conducted an extensive study utilizing petrography, geochemistry, isotopic analysis, and fluid inclusion studies on outcrops of the Dalong Formation in South China. Our findings reveal that fibrous calcite veins predominantly develop in the middle section of the Dalong Formation, specifically within the transitional interval between siliceous and calcareous shales, characterized by symmetric, antitaxial fibrous calcite veins. The δ¹³C values of these veins exhibit a broad range (−4.53‰ to +3.39‰) and display a decreasing trend in the directions of fiber growth from the central part, indicating an increased contribution of organic carbon to the calcite veins. Additionally, a consistent increase in trace element concentrations from the central part toward the fiber growth directions suggests a singular fluid source in a relatively closed environment, while other samples exhibit no distinct pattern, possibly due to the mixing of fluids from multiple layers resulting from repeated opening and closing of bedding-parallel fractures in the shales. The notable difference in δEu between the fibers on either side of the median zone indicates that previously formed veins acted as barriers, impeding the mixing of fluids, with the variation in δEu reflecting the differing sedimentary properties of the surrounding rocks. The in situ U-Pb dating of fibrous calcite veins yields an absolute age of 211 ± 23 Ma, signifying formation during the Late Triassic, which correlates with a shale maturity of 1.0‰ to 1.25‰. This integrated study suggests that the geochemical records of fibrous calcite veins document the processes related to overpressure generation and the opening and healing of bedding-parallel fractures within the Dalong Formation. Full article

The paper presents the geochemical characteristics of 26 selected oil seeps, more than half of which are remnants of old oil wells. The samples were collected from three tectonic units: the Magura, Silesian, and Skole units in the Polish part of the Carpathians. The analyzed seeps are mainly located on outcrops of Inoceramian beds within the Magura nappe, the Krosno Beds and Transition Beds in the Silesian nappe, as well as the Menilite Beds of the Skole unit. The study primarily focused on genetic characteristics, which were used to correlate the seeps with the oils from the deposits of these tectonic units and to assess the degree of secondary alterations. All hydrocarbon seeps were analyzed in terms of their location on surface cross-sections, and attempts were made to assign them features based on the classification proposed in 1952, which takes into account the tectonic characteristics of the regions where the seeps were identified. In the general genetic characterization, these seeps did not show significant differences, suggesting a similar source of supply as the crude oils. Among the analyzed seeps, three genetic groups were distinguished. For correlation purposes, information from published materials on crude oils and their genetic characteristics was used. Of the five classification types described in the literature, only two could be assigned to those occurring in the Carpathians. Considering the tectonic structure and the location of the seeps (based on surface cross-sections), it has been determined that most of the analyzed seeps are the result of migration along faults connecting source rocks or, less frequently, deformed deep accumulations with the surface. Full article