Search Results (415)

The deep marine shale of the Wufeng–Longmaxi (WF–LMX) Formation in the Sichuan Basin is characterized by laterally continuous thickness, high porosity, and significant gas content, making it a representative shale reservoir with considerable resource potential. This study investigates the heterogeneity of pore structures and their controlling factors using shale samples from three representative wells, based on low-temperature nitrogen adsorption and mercury intrusion data. The reservoir can be classified into three main lithofacies: mixed siliceous shale (MSS), clay-rich siliceous shale (CSS), and siliceous clay mixed shale (SMS). The results show that siliceous shales (MSS and CSS) exhibit higher total organic carbon and quartz contents, with more developed pore systems. Among them, the CSS exhibits the highest specific surface area and the largest mesopore and macropore volumes, indicating a greater development of larger pores and superior reservoir quality. All three shale facies exhibit clear single and multifractal characteristics. The average D₁ and D₂ values (fractal dimensions from nitrogen adsorption at P/P₀ < 0.45 and >0.45, respectively) are higher than D_Hg, (fractal dimension from mercury intrusion), indicating greater pore-surface roughness than internal pore structure complexity and stronger heterogeneity in larger pores. The D(q)–q spectrum shows a left-wide/right-narrow pattern, whereas the α–f(α) spectrum exhibits the opposite trend. The branch-width ratios S_kd and S_ka (indices of pore-size distribution complexity and heterogeneity) are both <0.1, suggesting that heterogeneity is more pronounced in low-probability regions. Fractal and multifractal analyses reveal significant pore structure heterogeneity across different lithofacies, with CSS showing relatively more homogeneous pore structures, whereas MSS exhibits stronger heterogeneity and poorer connectivity. The heterogeneity of shale reservoirs is primarily controlled by pore development, especially micropores and mesopores, and is strongly influenced by total organic carbon and quartz content. Full article

The upper Permian Dalong Formation in western Hubei Province is a crucial strategic successor for shale gas development in South China. However, the geological controls on reservoir pore development, particularly the influence of organic–inorganic interactions on the pore system, remain poorly understood. This restricts the precise optimization of shale gas exploration targets in this formation. To investigate the pore development characteristics and main controlling factors of the Dalong Formation shale reservoirs, this study takes the DFS from the Shuanghe section in western Hubei as the research object. X-ray diffraction (XRD), argon-ion polishing-scanning electron microscopy (SEM), and N₂/CO₂ gas adsorption–desorption technologies were integrated to achieve qualitative characterization and quantitative assessment of the pore network, with analyses of pore size distribution. The results show that the pores of the DFSs are dominated by interparticle pores and organic matter pores, and the pore structures of organic-rich and organic-lean shales exhibit significant differentiation characteristics. The quartz in the DFSs are mainly of diagenetic origin, and authigenic quartz cementation blocks primary intergranular pores, exerting a significant negative effect on pore development. In contrast, the smectite-to-illite transformation promotes the development of interlayer micropores, leading to a good positive correlation between clay mineral content and micropore volume, as well as specific surface area. Organic matter abundance is the core controlling factor for the construction of micro–nano pore networks. This study clarifies the dominant mechanisms of pore development driven by organic–inorganic interactions in the DFS. Authigenic diagenetic quartz impedes pore development, while smectite-to-illite transformation promotes micropore formation. Organic matter abundance is the dominant control on the micro-nanopore system. This study lays a critical geological theoretical foundation for the exploration evaluation and target selection of shale gas in the Dalong Formation. Full article

Conventional Diagnostic Fracture Injection Tests (DFITs) are widely used for formation pressure estimation, but in practice, they frequently require days, weeks, or even months of extended shut-in periods, a challenge particularly pronounced when large injection volumes are coupled with ultra-low formation permeability. While recent studies have proposed various modified DFIT approaches to reduce testing time, direct physical validation confirming the reliability of the derived formation pressure estimates remains scarce in the literature. This study applies a low-rate/volume injection mini-frac approach that integrates flow regime identification and Horner analysis. Two complementary field cases are presented: a standard DFIT in a shale reservoir to validate the baseline methodology, and a low-volume mini-frac in a tight granite formation to demonstrate rapid estimation. Results show that low-volume injections exhibit a flow regime evolution identical to standard DFITs, yet this approach is expected to accelerate the transition to the pseudo-radial flow regime. To verify the reliability of formation pressure estimates derived from such methods, the formation pressure estimated in the low-rate/volume injection mini-frac case was benchmarked against a decade of continuous downhole fluid pressure monitoring data from the same well, yielding a relative error of less than 5%. The findings suggest that employing a lower injection rate and volume can improve formation pressure testing efficiency, with potential applications in unconventional hydrocarbon development and deep geo-energy engineering. Full article

Multi-stage fracturing of shale gas is currently the core technology for achieving the economic development of shale gas. However, during post-fracturing production, issues such as fracture closure, proppant backflow, and fracturing fluid loss can inevitably occur, causing damage to the reservoir. To investigate the backflow performance of shale gas fracturing, this study establishes a high-precision fluid–solid coupled geomechanical model based on actual data from Changning shale gas wells and performs history matching. The history matching results indicate that neglecting factors such as geomechanics and capillary pressure leads to overly smooth curves, poor convergence, and results inconsistent with the actual production trends. A comprehensive model incorporating gas adsorption, geomechanics, capillary pressure, and secondary fractures provides the best fit. After validating the model’s accuracy, the effects of proppant concentration, proppant injection method, fracture parameters, well spacing, and fracturing design on fracturing backflow were analyzed. The study shows that proppant concentration, distribution pattern, fracture geometry, and well spacing are key factors influencing the effectiveness of shale gas fracturing stimulation. An optimal proppant concentration exists, as excessively high concentrations accelerate fracture closure and reduce production gains. Proppants should be primarily distributed near the wellbore to ensure high production and sufficient backflow. Fracture spacing and half-length should be optimized to balance production increase and fracturing fluid retention. Among the vertically non-uniform fracture distributions, staggered patterns offer the highest production potential, while uniform distributions yield the best backflow performance. In the Changning shale gas region, a well spacing of 300 m is recommended, and zipper fracturing can improve backflow efficiency. Full article

The Ordos Basin hosts abundant lacustrine shale oil resources. Adequately retained hydrocarbons in source rocks, together with favorable mobility, are prerequisites for large-scale shale oil exploitation. Therefore, the quantitative characterization of retained hydrocarbon content and mobility is a core research focus in shale oil exploration and development. This study investigates Chang 7 shale with varying lithofacies and geochemical characteristics. Stepwise pyrolysis and pyrolysis gas chromatography–mass spectrometry (GC–MS) were applied to analyze retained hydrocarbons in different occurrence states, their compositions, and biomarkers. In addition, nuclear magnetic resonance (NMR) combined with CO₂ flooding experiments was conducted, and the collected products under different displacement pressures were analyzed using GC–MS. The aim was to quantitatively examine the variations in expelled oil volume, compositional differences during migration, and occurrence features of shale oil within reservoir micro-pores. The results show the following: (1) Organic-rich shale is characterized by higher proportions of light and medium hydrocarbons, lower heavy fractions, and elevated aromatic hydrocarbon content. In contrast, low-organic-carbon mudstone or siltstone contains more medium and heavy hydrocarbons, with lower light and aromatic fractions. The C13−/C14+ ratio increases with total organic carbon (TOC). (2) In black shale, oil displacement is mainly contributed by mesopores. At low pressures, oil expulsion is difficult and dominated by heavy hydrocarbons. When pressure reaches a threshold, the capillary-bound oil in micropores is released, increasing production and improving oil quality. Muddy siltstone shows higher displacement efficiency than black shale, with contributions from pores of all sizes. At low pressures, its expelled oil volume is larger and lighter than that of black shale. With increasing pressure, the oil yield rises significantly, and medium–large pores produce heavier fractions compared with micropores, likely because light hydrocarbons preferentially enter micropores and are less prone to dissipation. (3) The main controlling factors for shale oil enrichment include retained hydrocarbon content, mobile hydrocarbon fraction, fluidity, and engineering-related parameters. Thick shale layers with high organic matter abundance, high proportions of light–medium hydrocarbons, and favorable porosity–permeability conditions, as well as interbedded siltstone, are enriched in mobile hydrocarbons. Full article

Resistivity is a key parameter in shale reservoir characterization. Diverse micro-pore types and complex conduction mechanisms in shale result in poor accuracy when applying existed conductivity models. Establishing a high-precision conductivity response model requires comprehensive consideration of the pore structure and clay-bound water conduction. The primary novelty of this work lies in replacing macroscopic empirical fitting parameters with a mechanistic, multi-dimensional fractal framework. We develop a novel conductivity response characterization model that explicitly couples multi-dimensional fractal pore structure theory with clay-bound water conduction. Experimental data verification demonstrates the new model’s superior characterization accuracy. Results indicate three distinct zones in the shale conductivity-pore water conductivity relationship: a nonlinear zone, a transition zone, and a linear zone. A higher cation exchange rate on clay surfaces leads to an increase in the nonlinear characteristics of the conductivity for both the shale and the pore water in low-salinity regions. An increase in the values of the conduction path fractal dimension, pore morphology fractal dimension, and pore fractal dimension all contribute to reduced shale conductivity. While sharing clay-induced conductivity terms with conventional dual-water and shale volume models, the new model offers advantages in operational simplicity and parameter accessibility. This research provides a physically rigorous and highly accessible approach for conductivity-based reservoir parameter calculation, offering new technical perspectives for complex shale oil/gas evaluation. Full article

Reservoir characterization of the Abu Roash “G” (AR/G) Member in the Karama Field, Abu Gharadig Basin, Western Desert of Egypt, is complicated by structural deformation, facies variability, and lithologic heterogeneity, which introduce uncertainties in reservoir evaluation and hydrocarbon estimation. This study aims to provide a comprehensive reservoir assessment through an integrated three-dimensional (3D) static modeling workflow. Well-log data from four wells were combined with the interpretation of seventeen seismic lines to construct structural, stratigraphic, and petrophysical models of the AR/G reservoir. The results indicate that reservoir thickness ranges from 9 to 14 ft and is structurally controlled by nine normal faults forming a horst–graben configuration that significantly influences compartmentalization and hydrocarbon distribution. Petrophysical modeling reveals favorable reservoir quality, with effective porosity ranging from 14% to 20%, an average shale volume of approximately 19%, and hydrocarbon saturation averaging 56%. Two prospective zones were identified, with estimated original oil in place (OOIP) of 10.76 MMSTB and 3.23 MMSTB, respectively, representing recoverable volumes within structurally defined closures rather than the entire field volume. The model also explains the relatively poor performance of Karama-5 and Karama-11 wells due to their peripheral structural positions outside the main closures and their higher water saturation (44–53%). These findings demonstrate that integrated structural and petrophysical modeling improves reservoir understanding and helps identify optimal drilling targets in structurally complex reservoirs of the Abu Gharadig Basin and comparable North African settings. Although the estimated volumes correspond to relatively small accumulations, they are considered economically viable within mature basins such as the Abu Gharadig Basin, where existing infrastructure and optimized development strategies enable efficient exploitation of marginal reserves. Full article

Shale gas, as an unconventional resource, requires hydraulic fracturing to create complex fracture networks due to its low porosity and permeability. However, the presence of interlayers significantly affects fracture propagation, leading to highly complex fracture morphologies. This study focuses on the interbedded shale of the WJP Formation in southern China. A three-dimensional block discrete element method (BDEM) was employed to establish a hydraulic fracture propagation model, systematically investigating the effects of geological parameters (stress difference, interlayer thickness), engineering parameters pumping rate, fluid volume, viscosity), and perforation parameters (cluster number, cluster spacing, perforation location) on fracture network morphology. The results indicate that: (1) Among geological parameters, interlayer thickness is the key factor inhibiting vertical fracture propagation. Due to the influence of interlayers, an increase in stress difference promotes fracture length but suppresses fracture height and stimulated reservoir volume (SRV); (2) For engineering parameters, there exists a “threshold effect” for pumping rate and fluid volume, with 16 m³/min and 2000 m³ identified as the critical thresholds for interlayer breakthrough. Low viscosity (1 mPa·s) is conducive to forming complex fracture networks, while high viscosity extends fracture length but reduces SRV; (3) Regarding perforation parameters, the optimal stimulation effect is achieved with 6–7 clusters, a cluster spacing of 10 m, and perforation locations in the center of the main shale layer (19.85–21.6 m); (4) By introducing grey relational analysis, the degree of correlation between various influencing factors and the response to interlayer breakthrough is systematically evaluated based on the breakthrough conditions under different factors. Thin interlayers or low stress differences can reduce the critical pumping rate, whereas thick interlayers (≥3 m) become the primary constraint, making breakthrough difficult even at high pumping rates. Reliable interlayer breakthrough requires the simultaneous satisfaction of Δσ ≤ 16 MPa, h < 1 m, and Q ≥ 16 m³/min. The reliability of the model was verified by comparing numerical simulation results with field microseismic data. This study reveals the extension laws of complex fracture networks in interbedded shale, providing a theoretical basis for fracturing design and development optimization. Full article

This study investigates the heterogeneity of pore structures in lacustrine shale gas reservoirs, with a specific focus on shales from the Lower Cretaceous Shahezi Formation in the Lishu Fault Sag of the Songliao Basin. By integrating multi-scale characterization techniques—including high-pressure mercury intrusion, N₂/CO₂ adsorption, and nuclear magnetic resonance (NMR)—we examined the pore networks across five identified lithofacies: organic-rich clayey shale, organic-rich mixed shale, organic-rich siliceous shale, organic clayey shale, and organic mixed shale. The results indicate that mesopores (2–50 nm) constitute the dominant fraction of pore volume (31.7%–56.6%), followed by micropores (<2 nm) and macropores (>10 μm). Notable lithofacies-dependent variations were observed: organic-rich clayey shale exhibits abundant organic pores, clay interlayer pores, and intragranular dissolution pores with favorable connectivity; organic-rich siliceous shale is mainly dominated by inorganic pores with limited organic porosity; mixed shales are characterized by clay mineral contraction fractures and intergranular pores. The key controlling factors are mineral composition and organic matter abundance: clay content shows a positive correlation with pore volume and surface area in organic-rich clayey shale, but a negative correlation in organic mixed shale. Brittle minerals (quartz and feldspar) generally reduce porosity through compaction. Total organic carbon (TOC) displays a weak positive correlation with mesopore volume, while thermal maturity (Ro = 1.2%–1.73%) exerts influences that vary by lithofacies. In contrast to marine shales—which are dominated by high-maturity (Ro > 2.0%) organic pores and quartz-supported frameworks—terrestrial shales primarily rely on inorganic pores derived from clay minerals (e.g., illite). This study clarifies the relationships among lithofacies, pore structure, and controlling factors, thereby providing a basis for evaluating the gas potential of terrestrial shales. Full article

Deep shale gas reservoirs in the southern Sichuan Basin (Weiyuan area) exhibit strong heterogeneity and complex pore-fracture networks. Traditional reservoir evaluation methods struggle to accurately capture their microscale pore characteristics and fracability, thereby restricting efficient development and precise sweet spot prediction. Therefore, integrating digital core technology with geological analysis is essential to systematically quantify key reservoir parameters, including microscale pore structure, mineral composition, and brittleness characteristics. To clarify the controlling factors of high-quality deep shale gas reservoirs in the Weiyuan area and assess their exploration and development potential, we performed digital core analysis at micron to nanometer scales. Three-dimensional digital core models of representative deep shale gas wells were constructed. Integrating mineral composition, geochemical characteristics, and pore space features, we discuss the geological conditions for deep shale gas accumulation and the fracability of horizontal wells, and we delineate favorable shale reservoir zones. The results show that digital core technology enables quantitative and visual characterization of each sublayer of the Longmaxi Formation shale reservoir, including mineral types, laminae types, pore-throat structures, and organic matter distribution. From the Long 11-1 sublayer to the Long 11-4 sublayer, the pore-throat radius, total pore volume, total throat volume, connected pore-throat percentage, and coordination number all gradually decrease. In the eastern Weiyuan area, the siliceous components in deep shale gas reservoirs at the base of the Longmaxi Formation are primarily of both biogenic and terrigenous origin. Due to local variations in the sedimentary environment, terrigenous input contributes significantly to the total siliceous content in this region. Although the Long 11-1 sublayer of the Longmaxi Formation is lithologically classified as mud shale, its particle size and mineral composition more closely resemble those of clayey siltstone or argillaceous sandstone, suggesting considerable potential for reservoir space development. Typical wells in the eastern Weiyuan area exhibit distinct lithological characteristics, including coarser grain sizes, stronger hydrodynamic conditions during deposition, and abundant terrigenous clastic supply. The rigid framework formed by silt- to sand-sized particles effectively mitigates compaction, thereby facilitating the preservation of intergranular pores and microfractures. High organic matter abundance, appropriate thermal maturity, and a considerable thickness of high-quality shale ensured sufficient hydrocarbon supply. The main types of natural fractures are intergranular and grain-edge fractures formed by differences in sedimentary grain size, and bedding-parallel fractures generated by hydrocarbon generation overpressure. Based on reservoir mineral composition, pore characteristics, areal porosity, and pore size distribution identified via digital core analysis, the bottom 0–3 m of the Long 11-1 sublayer is determined to be the optimal target interval. By delineating the microscopic characteristics of the shale reservoir and predicting rock mechanical parameters, a fracability evaluation index was established from digital core simulations. This guides the selection of target layers in deep shale gas reservoirs and optimizes hydraulic fracturing design. Full article

Permeability is affected by nanopores and pore structure, and anisotropic permeability is the result of shale lamination, orientation, and stratification of minerals. To understand the reasons for permeability anisotropy, the pore networks of over-mature shale has been studied. The mineral compositions, petrophysical properties, and pore structures of the Lower Cambrian Niutitang Formation shales were analyzed using subcritical gas adsorption, field-emission scanning electron microscopic, and X-ray micro-computed tomographic methods. Quartz, clay minerals, and carbonate are the dominant minerals in the shales. The bedding-parallel and bedding-perpendicular permeabilities are 1.25–46.21 × 10⁻² and 1.38–6.62 × 10⁻² mD, respectively. The anisotropy of permeability, which is the ratio between the bedding-parallel and bedding-perpendicular permeability, is 0.21–26.87. The micropore and Barrett–Joyner–Halenda pore volumes are 0.54–3.62 and 0.05–0.69 mL/100 g, respectively. The bedding-parallel permeability is correlated positively with the micropore and Barrett–Joyner–Halenda pore volumes. Thin-section observations indicate the shales exhibit a bedding-parallel alignment of phyllosilicate minerals and planar deformation bands. The scanning electron microscopy shows deformation of the lamination and parallel alignment of the clay minerals due to compaction or differential compaction over coarser-grained quartz grains. The scanning electron microscopy images and subcritical gas adsorption data indicate that the pore fracture system is parallel to bedding and formed after diagenesis. Furthermore, X-ray micro-computed tomographic analysis shows that the micro-fractures are also preferentially oriented, parallel to bedding. Full article

The Ordos Basin hosts significant shale gas resources in China, yet its marine-continental transitional sedimentary setting causes intense reservoir heterogeneity that severely hinders accurate sweet spot identification in the Permian Shanxi Formation. This study aims to reveal the synergistic controls of lithofacies, mineralogy, and organic matter on shale gas sweet spot formation in the southern Yishan Slope of the eastern Ordos Basin. A multi-dimensional characterization approach was adopted, integrating drilling/logging data and systematic core analyses including X-ray diffraction (XRD), organic geochemical testing, porosity/permeability measurement, and on-site gas content desorption, to quantify reservoir heterogeneity across lithofacies, mineralogy, organic geochemistry, and petrophysical properties. The results show that three lithofacies associations are identified in the target interval: mud-wrapped sand, sand-mud interbedding, and sand-wrapped mud, among which sand-mud interbedding and mud-wrapped sand associations exhibit higher total organic carbon (TOC) contents and strong inter/intra-well heterogeneity. The organic matter in the reservoir is dominated by Type III kerogen, with TOC values ranging from 0.04% to 12.15%, and the Shan 2 Member shows significantly higher average TOC (2.55%) than the Shan 1 Member (1.36%). The reservoir is characterized by ultra-low porosity (average of 0.77%) and low permeability (average of 0.26 × 10⁻³ μm²), with mesopores and macropores contributing over 99% of the total pore volume and showing a significant positive correlation with gas content. Quartz (average of 34.86%) and clay minerals present strong vertical heterogeneity, with the Shan 2 Member being more heterogeneous than the Shan 1 Member due to differences in sedimentary environment evolution. A TOC threshold of 1.5% is determined for sweet spot identification in the study area, and shale gas sweet spots are synergistically controlled by high TOC abundance, moderate brittle mineral content, and 0.1–3 m thick sandy interbeds. This study enriches the theoretical understanding of marine-continental transitional shale reservoirs and provides a scientific basis for sweet spot prediction and development optimization in similar heterogeneous shale gas systems worldwide. Full article

Shale pore volume is a critical parameter for reservoir evaluation. Accurate and rapid determination of this parameter is essential for identifying sweet spots and performing reliable reserve estimations. Currently, laboratory experiments remain the standard for determining pore volume; however, these methods are typically time-consuming, costly, and labor-intensive. To complement traditional experimental approaches, we developed a Gaussian Process Regression (GPR) model to estimate shale pore volume based on mineralogical compositions. The model is specifically tailored for the Longmaxi shale, utilizing six input features: the contents of Total Organic Carbon (TOC), clay, quartz, feldspar, carbonate, and pyrite. The GPR model achieved a mean absolute percentage error (MAPE) of 9.97% on the testing dataset, while it yielded an MAPE of 17.66% when applied to an additional independent validation set. Finally, a sensitivity analysis using the Shapley additive explanations was conducted to elucidate the influence of mineralogical constituents on shale pore volume. Full article

In this study, shale samples with diverse lithofacies from the Lower Silurian Longmaxi Formation in the Fuling Field were investigated to evaluate the variations in pore characteristics and methane adsorption capacity (MAC) of different shale lithofacies. A set of experiments were performed, such as total organic carbon (TOC) content, X-ray diffraction (XRD), field emission–scanning electron microscopy (FE-SEM), low-pressure gas (CO₂/N₂) adsorption, and high-pressure methane adsorption. Combined with TOC content and mineral composition, three types of shale lithofacies were identified, including organic-rich (OR) argillaceous-rich siliceous (S-3) shale lithofacies, organic-moderate (OM) argillaceous/siliceous mixed (M-2) shale lithofacies, and organic-lean (OL) siliceous-rich argillaceous (CM-1) shale lithofacies. Through detailed comparative analyses, we found that OR S-3 shales possess the maximum TOC content, the most developed heterogeneous organic micro-mesopores, the largest pore volume (PV), and the highest pore surface area (PSA); consequently, they display the strongest MAC. Conversely, OL CM-1 shales have the lowest TOC content and the highest clay content, and thus the smallest PSA and the poorest methane adsorption performance. In conclusion, considering the excellent gas storage potential, sustained shale gas production, and brittle response to hydraulic fracturing, OR S-3 shales are superior to shale gas exploration and exploitation compared with OM M-2 and OL CM-1 shales. Full article

Low-maturity shale is a prime target for in situ conversion (ICP), yet heating window selection remains largely empirical because pore evolution and hydrocarbon generation are rarely quantified in tandem. Nenjiang Formation shale from the Songliao Basin (TOC = 8.91%; R_o,max = 0.54%) was subjected to closed-system pyrolysis at 300–500 °C (20 °C h⁻¹; 72 h per step). Released oil and gas and residual chloroform-extractable bitumen (“A”) were quantified, and pore evolution was characterized using 2D low-field NMR, SEM, micro-CT, and low-pressure N₂ adsorption. Fractal dimensions (D_s and D_p) were derived from Frenkel–Halsey–Hill (FHH) fitting. Oil yield and bitumen “A” increased sharply above 350 °C and peaked at 375 °C, whereas gas generation accelerated above 400 °C and continued to increase to 500 °C. NMR indicates a temperature-dependent shift in retained hydrocarbons toward weaker confinement and higher mobility, with enhanced expulsion/mobility signals near 375 °C. At 375 °C, BJH pore volume and average pore diameter reached maxima (0.0675 cm³ g⁻¹ and 15.36 nm), while D_s and D_p reached minima (2.343 and 2.444). The coincidence of peak oil expulsion with minimum fractal complexity suggests that FHH-based fractal indices provide a quantitative metric for comparing ICP heating windows in low-maturity shale. Full article