Search Results (1,083)

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

As the retrieval of unconventional oil and gas resources extends to the deep and ultra-deep domains, the issue of cement sheath failure in shale oil wellbores seriously endangers wellbore safety, making it imperative to uncover the relevant damage mechanism and develop effective assessment approaches. In response to the limitations of conventional finite element methods in representing mesoscopic damage, in this study, we determined the mesoscopic parameters of cement paste via laboratory calibrations; constructed a 3D casing–cement sheath–formation composite model using the discrete element method; addressed the restriction of the continuum assumption; and numerically simulated the microcrack initiation, propagation, and interface debonding behaviors of cement paste from a mesomechanical viewpoint. The model’s reliability was validated using a full-scale cement sheath sealing integrity assessment apparatus, while the influences of fracturing location, stage count, and internal casing pressure on cement sheath damage were analyzed systematically. Our findings indicate that the DEM model can precisely capture the dynamic evolution features of microcracks under cyclic loading, and the results agree well with the results of the cement sheath sealing integrity evaluation. During the first internal casing pressure loading phase, the microcracks generated account for 84% of the total microcracks formed during the entire loading process. The primary interface (casing–cement sheath interface) is fully debonded after the second internal pressure loading, demonstrating that the initial stage of cyclic internal casing pressure exerts a decisive impact on cement sheath integrity. The cement sheath in the horizontal well section is subjected to high internal casing pressure and high formation stress, resulting in more frequent microcrack coalescence and a rapid rise in the interface debonding rate, whereas the damage progression in the vertical well section is relatively slow. 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

Natural fractures in marine shales are crucial storage spaces and migration pathways for oil and gas, making the study of their formation mechanisms and distribution patterns essential for hydrocarbon exploration and development. This review systematically evaluates the progress in natural fracture studies, transitioning from qualitative to quantitative approaches, with a focus on the genetic mechanisms, distribution patterns, and methodological advancements of fracture types. The review finds that: (1) Integrated “geological-geophysical-dynamic” analyses significantly improve the prediction accuracy of tectonic fracture networks compared to traditional stress-field models. Bedding-parallel fracture development is primarily controlled by the interplay between diagenetic evolution and in situ stress, with their critical opening conditions now being quantifiable; (2) Crucially, the application of micro-scale in situ techniques (e.g., Laser Ablation Inductively Coupled PlasmaMass Spectrometer, laser C-O isotope analysis, carbonate U-Pb dating) has successfully decoded the geochemical signatures and absolute timing of fracture fillings, revealing multiple episodes of fluid activity directly tied to hydrocarbon migration. (3) The combined application of multiple techniques holds promise for deepening the understanding of the coupling mechanisms between fractures. The combined application of these techniques provides a robust framework for deciphering the coupling mechanisms between fracture dynamic evolution and hydrocarbon migration, offering critical insights for future exploration. 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

This paper presents a comprehensive study on the feasibility and implications of a CO₂ injection simulation in the Syderiai deep saline aquifer of Lithuania, focusing on leakage, geo-mechanical aspects, and geo-chemical aspects. The Syderiai aquifer, characterized by its sandstone formation covered by shaly rocks, is considered a potential site for CO₂ geological storage in Lithuania. Using 3D mechanistic models developed in T-navigator software, we conducted extensive simulations to analyze CO₂ storage behavior and associated impacts. The leakage study examines various scenarios to assess the impact of fracture permeability, layer-wise heterogeneity, and fracture position on CO₂ injection and leakage volumes. Results indicate that while fracture permeability influences CO₂ migration dynamics, its impact on both free and dissolved CO₂ leakage volumes is minimal, highlighting that leakage behavior is more dependent on the presence of fractures than their permeability. Geo-mechanical analysis reveals the effects of CO₂ injection on the bulk modulus and shear modulus of sandstone and shale formations, highlighting changes in compaction and cementation. The geo-chemical study was performed using TOUGHREACT software V4.13-OMP to investigate the distribution of pH, porosity change, and free CO₂ over 1000-years following 10-year CO₂ injection. Results demonstrate the acidifying effect of CO₂ injection and its implications for the caprock–reservoir interface over time. The findings offer valuable perspectives on the feasibility and consequences of CO₂ geological storage in the Syderiai deep saline aquifer, highlighting the importance of incorporating leakage, geo-mechanical aspects, and geo-chemical aspects for implementing efficient CO₂ storage. Full article

Paleogene lacustrine shale is a key source rock for large oil reserves in China and a major target for shale oil exploration. However, differences in the chemical characteristics of felsic and carbonate shales during burial and thermal evolution remain poorly understood. This study evaluates hydrocarbon generation and expulsion efficiency in these shale types using pyrolysis experiments on lower Paleocene Kongdian Formation samples (Type I) from the Eastern China Sedimentary Basin. Results show that felsic shale has higher hydrocarbon generation capacity than carbonate shale. During pyrolysis, carbonate shale retained ~119 mg/g more oil but expelled 184 mg/g less than felsic shale. Felsic shale reached peak oil generation and retention faster but with lower retention efficiency. The larger volume of residual hydrocarbons in felsic shale facilitated earlier expulsion onset, higher yields of gaseous hydrocarbons, and superior gas expulsion efficiency. While both shales exhibited similar thermal evolution trends for hydrocarbon gases, methane proportions and gas-oil ratios (GOR) differed significantly. Carbon loss was comparable during the oil window, but felsic shale lost more carbon overall. At higher temperatures, n-alkanes in residual oil decreased sharply, with lighter oil retained at advanced maturity, increasing GOR and reducing heavy hydrocarbons. These findings demonstrate the effective hydrocarbon potential of medium-high TOC felsic and carbonate shales. Full article

Herein, we present a systematic investigation of plant fossils from the Yingzuilazi Formation in Baishan City, Jilin Province, China. The Baishan flora comprises 27 genera and 46 species. They are predominantly autochthonous or parautochthonous, based on their floral composition and taphonomic attributes. An analysis of paleoecological characteristics of the fossil plant assemblages, combined with the habitat preferences of analogous modern communities, allowed us to reconstruct the Early Cretaceous plant communities in the Baishan Basin: a riparian–wetland community, lowland community, montane slope community, and montane highland community. The floral composition, a statistical analysis of foliar physiognomy, and the palynofloral characteristics indicated a warm and humid temperate climate during the deposition of the Yingzuilazi Formation. A genus-level comparison with the Yixian Formation flora of western Liaoning revealed high compositional similarity, which confirms the Baishan flora as the easternmost distribution of the Jehol Biota in China. This study provides new fossil evidence for understanding Early Cretaceous floristic provincialism and paleoenvironmental reconstruction in East Asia. It offers geological references that can predict vegetation responses to a greenhouse climate. Additionally, Sphenopsida and Filicopsida may serve as potential indicators that may identify favorable terrestrial shale oil and gas reservoirs from the Early Cretaceous. Full article

The shale oil reservoirs of Member 7 of the Triassic Yanchang Formation in the Longdong Area of the Ordos Basin have attracted widespread attention due to their unique geological characteristics and enormous development potential. As the core factor controlling reservoir storage capacity and hydrocarbon flow efficiency, the precise characterization and quantitative analysis of pore structure are the prerequisite and key for reservoir evaluation and development plan optimization. All samples selected in this study were collected from the shale of Member 7 of the Triassic Yanchang Formation and were classified into two categories: medium-organic-rich shales (total organic carbon, TOC: 2–6%; TOC refers to the total organic carbon content in rocks, indicating organic matter abundance; unit: %) and high-organic-rich shales (TOC: >6%). The mineral composition and organic geochemical parameters of the shale were determined via X-ray diffraction (XRD) and Rock-Eval pyrolysis experiments, respectively. Meanwhile, pore structure characteristics were analyzed by combining low-temperature nitrogen adsorption–desorption experiments before and after extraction, and multifractal analysis was used to systematically investigate the differences in pore heterogeneity of shale and their influencing factors. The results show that the specific surface area (SSA) and total pore volume (TPV) of shale increased after extraction, while the change in average pore diameter (APD) varied. Multifractal analysis indicates that the micropores of shale both before and after extraction exhibit significant multifractal characteristics; after extraction, pore connectivity is improved, but the changes in pore heterogeneity are inconsistent. The pore connectivity of shale first increases and then decreases with the increase in TOC content and pyrolysis parameter S₂ content. The better the pore connectivity of shale, the lower the content of light-component saturated hydrocarbons and the relatively higher the content of heavy-component resins in the extractable organic matter (EOM). Brittle minerals can provide a rigid framework to inhibit compaction and are prone to forming natural microfractures under tectonic stress, thereby promoting pore connectivity. In contrast, clay minerals, due to their plasticity, are prone to deformation and filling pore throats during compaction, thus reducing pore connectivity. This study provides a theoretical basis for the evaluation and development of shale reservoirs in the Longdong Area. Full article

Economic and technological factors necessitate the use of alternative fuels during oil shale combustion, a process that generates substantial amounts of solid waste with varying ash compositions. This study evaluates the potential of two such waste materials: (i) fly ash derived from the combustion of oil shale (a fine particulate residue from burning crushed shale rock, sometimes combined with biomass), and (ii) short carbon fibres recovered from the pyrolysis (a process of decomposing materials at high temperatures in the absence of oxygen) of waste wind turbine blades. Oil shale ash from two different sources was investigated as a partial cement replacement, while recycled short carbon fibres (rCFs) were incorporated to enhance the functional properties of mortar composites. Results showed that carbonate-rich ash promoted the formation of higher amounts of monocarboaluminate (a crystalline hydration product in cement chemistry), leading to a refined pore structure and increased volumes of reaction products—primarily calcium silicate hydrates (C–S–H, critical compounds for cement strength). The findings indicate that the mineralogical composition of the modified binder (the mixture that holds solid particles together in mortar), rather than the fibre content, is the dominant factor in achieving a dense microstructure. This, in turn, enhances resistance to water ingress and improves mechanical performance under long-term hydration and freeze–thaw exposure. Life cycle assessment (LCA, a method to evaluate environmental impacts across a product’s lifespan) further demonstrated that combining complex binders with rCFs can significantly reduce the environmental impacts of cement production, particularly in terms of global warming potential (−4225 kg CO₂ eq), terrestrial ecotoxicity (−1651 kg 1,4-DCB), human non-carcinogenic toxicity (−2280 kg 1,4-DCB), and fossil resource scarcity (−422 kg oil eq). Overall, the integrative use of OSA and rCF presents a sustainable alternative to conventional cement, aligning with principles of waste recovery and reuse, while providing a foundation for the development of next-generation binder systems. Full article

The primary strata of western Taiwan are Cenozoic sedimentary rocks. Characterized by low cementation and high porosity, these rocks exhibit a pronounced wetting–softening effect. Long-term exposure to warm, humid tropical and subtropical climates significantly degrades their engineering geological properties due to weathering. This study, based on a sandstone-shale interbedded highway slope in central Taiwan that has repeatedly collapsed, investigated the slope’s failure mechanism using remote-sensing image interpretation of previous landslides, surface geological surveys, kinematic analysis, photogrammetric mapping, laboratory artificial weathering experiments, and Distinct Element Method (DEM) simulations. The study revealed that the fundamental cause of collapse on this type of oblique-slope interbedded sandstone-shale is the sliding and toppling of sandstone blocks, driven by weathering and erosion of the shale. Based on artificial weathering experiments, the strength loss rate of the shale in the Kuantaoshan Sandstone Member of the Kueichulin Formation after weathering is 6.6 times that of the sandstone. The estimated collapse area from the two-dimensional Distinct Element Method analysis is consistent with the actual value from the photogrammetric model. This type of landslide caused by rock weathering always forms stepped surface where sandstone overhangs above shale. A shale erosion amount of 0.78–0.91 of the spacing of the joint approximately parallel to the slope surface was found to be the critical erosion before collapse and can serve as the early warning indicator. Full article