Search Results (628)

With the increasing exploration and development of deep shale gas resources, water-based fracturing fluids face multiple challenges, including high-temperature resistance, salt tolerance, and efficient proppant transport. In this study, a zwitterionic polymer (polyAMASV) is synthesized via aqueous two-phase dispersion polymerization, using acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), acrylic acid (AA), stearyl methacrylate (SMA), and 4-vinylpyridine propylsulfobetaine (4-VPPS) as monomers. The introduction of hydrophobic alkyl chains effectively adjusts the viscoelasticity of the emulsion, while the incorporation of zwitterionic units provides salt tolerance through their intrinsic anti-polyelectrolyte effect. As a result, the solutions of such copolymers exhibit stable apparent viscosity in both NaCl and CaCl₂ solutions and under high temperatures. Meanwhile, polyAMASV outperforms conventional samples across various saline environments, reducing proppant settling rates by approximately 20%. Moreover, the solutions exhibit rapid gel-breaking and low residue characteristics, ensuring effective reservoir protection. These results highlight the promising potential of polyAMASV for deep shale gas fracturing applications. Full article

The Chang 7 member of the Ordos Basin hosts abundant shale oil and gas resources and plays a vital role in the development of unconventional energy. This study investigates differences in damage evolution and underlying mechanisms between representative shale oil and shale gas reservoir cores from the Chang 7 member under fracturing fluid hydration. A combination of high-temperature expansion tests, nuclear magnetic resonance (NMR), and micro-computed tomography (Micro-CT) was used to systematically characterize macroscopic expansion behavior and microscopic pore structure evolution. Results indicate that shale gas cores undergo faster expansion and higher imbibition rates during hydration (reaching stability in 10 h vs. 23 h for shale oil cores), making them more vulnerable to water-lock damage, while shale oil cores exhibit slower hydration but more pronounced pore structure reconstruction. After 72 h of immersion in fracturing fluid, both core types experienced reduced pore volumes and structural reorganization; however, shale oil cores demonstrated greater capacity for pore reconstruction, with a newly formed pore volume fraction of 34.5% compared to 24.6% for shale gas cores. NMR and Micro-CT analyses reveal that hydration is not merely a destructive process but a dynamic “damage–reconstruction” evolution. Furthermore, the addition of clay stabilizers effectively mitigates water sensitivity and preserves pore structure, with 0.7% identified as the optimal concentration. The research results not only reveal the differential response law of fracturing fluid damage in the Chang 7 shale reservoir but also provide a theoretical basis and technical support for optimizing fracturing fluid systems and achieving differential production increases. Full article

Fault slips induced by hydraulic fracturing are the primary mechanism of casing de-formation during deep shale gas development in Sichuan’s Luzhou Block, where de-formation rates reach 51% and severely compromise productivity. To address a critical gap in existing research on quantitative risk assessment systems, we developed a probabilistic model integrating pore pressure evolution dynamics with Monte Carlo simulations to quantify slip risks. The model incorporates key operational parameters (pumping pressure, rate, and duration) and geological factors (fault friction coefficient, strike/dip angles, and horizontal stress difference) validated through field data, showing >90% slip probability in 60% of deformed well intervals. The results demonstrate that prolonged high-intensity fracturing increases slip probability by 32% under 80–100 MPa pressure surges. Meanwhile, an increase in the friction coefficient from 0.40 to 0.80 reduces slip probability by 6.4% through elevated critical pore pressure. Fault geometry exhibits coupling effects: the risk of low-dip faults reaches its peak when strike parallels the maximum horizontal stress, whereas high-dip faults show a bimodal high-risk distribution at strike angles of 60–120°; here, the horizontal stress difference is directly proportional to the slip probability. We propose optimizing fracturing parameters, controlling operation duration, and avoiding high-risk fault geometries as mitigation strategies, providing a scientific foundation for enhancing the safety and efficiency of shale gas development. Full article

Due to the diverse origins of shale reservoirs, the coal measure shales of the Wuxiang block, Qinshui Basin typically exhibit fractal pore structures, which significantly influence shale gas occurrence and migration. Clarifying the fractal nature of pore structures is significant for the efficient development and utilization of shale gas. In this study, mercury intrusion porosimetry and liquid nitrogen adsorption experiments were conducted to develop a method that integrates pore compressibility correction and nitrogen adsorption for pore structure characterization. On this basis, this study analyzed the fractal characteristics of coal measure shale pore structures across multiple scales. The results reveal that coal measure shale pores exhibit a three-stage fractal pattern, consisting of three regions with pore diameters >65 nm (seepage pores), 6–65 nm (transition pores), and <6 nm (micropores). Samples with fractal dimensions of seepage pores ($D_{\mathrm{a}}$) exceeding 2.9 and transition pores ($D_1$) exceeding 2.5 tend to have larger specific surface areas and more complex pore structures; this is indicated by the increased surface roughness of large-scale pores, which hinders gas seepage. Samples with lower fractal dimension of micropores ($D_2$)—in the range of 2.2–2.8—exhibit higher micropore development, larger specific surface area, and simpler pore structures, as demonstrated by a greater number of micropores and a more uniform pore distribution, which promotes gas adsorption. Full article

The estimated ultimate recovery (EUR) is an important parameter for forecasting oil and gas production and informing decisions regarding field development strategies. In this study, we combined site-specific geologic, completion, and operational parameters with the predictive capabilities of machine learning (ML) models to predict EURs of the wells for the Eagle Ford Marl Continuous Oil Assessment Unit. We developed an extensive dataset of wells that have produced from the lower and upper Eagle Ford Shale intervals and reduced the model complexity using principal component analysis. We tested the ML models and estimated the sensitivities of ML-predicted EURs to changes in the values of different input variables. The results of applying the optimized ML model to the Eagle Ford suggest that the approach developed in this study could be promising. The ML estimates of the EURs fit the DCA-based values with an R² ~ 0.9 and a mean absolute error of ~36 × 10³ bbl. In the lower Eagle Ford Shale, the EUR estimates were found to be most sensitive to changes in porosity, net thickness of the interval, clay volume, and the API gravity of the oil; and that in the upper Eagle Ford Shale they were most sensitive to changes in the total organic carbon and water saturation, which suggests that it could be important to consider these parameters in assessing these intervals or close analogs. Full article

Hydraulic fracturing is currently the main technical means to form complex fracture systems in shale gas development. To explore the influence of fracture dip, fracture length and fracture filling degree on the propagation of hydraulic fractures under complex fracture conditions, this paper establishes a 20 cm × 20 cm two-dimensional numerical model by inserting global cohesive elements and conducting triaxial hydraulic fracturing experiments to verify the model. The results show that the fracture filling degree plays a major role in the fracture pressure and the propagation of hydraulic fractures, while the fracture dip plays a minor role. The experimental results are consistent with the model results in terms of the law, but due to the existence of other natural fractures in the test block, the fracture pressure is smaller than that of this model. This model can provide some theoretical basis and technical support for situations where there are complex natural fractures in hydraulic fracturing. Full article

Horizontal wells in shale formations, such as those in the South Pars gas field (Iran) and the Bakken shale (Canada/USA), are essential for production from ultralow-permeability reservoirs but remain limited by poor hole cleaning, high torque, and unstable fluid transport. This study integrates real-time field data from South Pars with Drillbench simulations in the Bakken to develop practical strategies for improving drilling efficiency. A water-based mud system (9–10.2 ppg, 29–35 cP) supplemented with 2 wt.% sulphonated asphalt was applied to mitigate shale hydration, enhance cuttings transport, and preserve near-wellbore injectivity. Field implementation in South Pars demonstrated that adjusting drillstring rotation to 90 RPM and circulation rates to 1100 GPM reduced torque by ~70% (24 to 7 klbf·ft) and increased the rate of penetration (ROP) by ~25% (8 to 10 m/h) across a 230 m interval. Simulations in the Bakken confirmed these improvements, showing consistent torque and pressure trends, with cuttings transport efficiency above 95%. Inducing controlled synchronous whirl further improved sweep efficiency by ~15% and stabilized annular velocities at 0.7 m/s. Overall, these optimizations enhanced drilling efficiency by up to 25%, reduced operational risks, and created better well conditions for field development and EOR applications. The results provide clear, transferable guidelines for designing and drilling shale wells that balance immediate operational gains with long-term reservoir recovery. 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

As the residual products of severe chemical weathering, bauxite deposits serve both as essential economic Al-Fe resources and geochemical archives that reveal information about the parent rocks’ composition, paleoenvironments and paleoclimates, and the tectonic settings responsible for their genesis. The well-developed Early Paleocene bauxite deposits of the Salt Range, Pakistan, provide an opportunity for deciphering their ore genesis and parental affinities. The deposits occur as lenticular bodies and are typically composed of three consecutive stratigraphic facies from base to top: (1) massive dark-red facies (L-1), (2) composite conglomeratic–pisolitic facies (L-2), and (3) Kaolinite-rich clayey facies (L-3). Results from optical microscopy, X-ray powder diffraction (XRPD), and scanning electron microscopy with Energy-Dispersive X-Ray Spectroscopy (SEM-EDS) reveal that facies L-1 contains kaolinite, hematite, and goethite as major minerals, with minor amounts of muscovite, quartz, anatase, and rutile. In contrast, facies L-2 primarily consists of kaolinite, boehmite, hematite, gibbsite, goethite, alunite/natroalunite, and zaherite, with anatase, rutile, and quartz as minor constituents. L-3 is dominated by kaolinite, quartz, and anatase, while hematite and goethite exist in minor concentrations. Geochemical analysis reveals elevated concentrations of ${\mathrm{Al}}_2$${\mathrm{O}}_3$, ${\mathrm{Fe}}_2$${\mathrm{O}}_3$, ${\mathrm{SiO}}_2$, and ${\mathrm{TiO}}_2$. Trace elements, including Th, U, Ga, Y, Zr, Nb, Hf, V, and Cr, exhibit a positive trend across all sections when normalized to Upper Continental Crust (UCC) values. Field observations and analytical data suggest a polygenetic origin of these deposits. L-1 suggests in situ lateritization of some sort of precursor materials, with enrichment in stable and ultra-stable heavy minerals such as zircon, tourmaline, rutile, and monazite. This facies is mineralogically mature with bauxitic components, but lacks the typical bauxitic textures. In contrast, L-2 is texturally and mineralogically mature, characterized by various-sized pisoids and ooids within a microgranular-to-microclastic matrix. The L-3 mineralogy and texture suggest that the conditions were still favorable for bauxite formation. However, the ongoing tectonic activities and wet–dry climate cycles post-depositionally disrupted the bauxitization process. The accumulation of highly stable detrital minerals, such as zircon, rutile, tourmaline, and monazite, indicates prolonged weathering and multiple cycles of sedimentary reworking. These deposits have parental affinity with acidic-to-intermediate/-argillaceous rocks, resulting from the weathering of sediments derived from UCC sources, including cratonic sandstone and shale. Full article

Accurately simulating immiscible counter-current flow is crucial for applications from geological ${\mathrm{CO}}_2$ storage to shale gas production, yet it remains a major challenge for conventional pore network models (PNMs), which are unable to handle the numerical instability of opposing flows. To address this critical gap, we developed a novel dynamic PNM that incorporates a ‘transition state’ algorithm. This method successfully eliminates the spurious meniscus oscillations that hinder traditional models, enabling robust simulation of the complete counter-current process. Using this model, we quantify the profound impact of pore structure on flow efficiency. Our results demonstrate that increasing the pore size distribution uniformity (Weibull shape factor k from 0.5 to 3.0) extends the persistence of continuous air outflow pathways by more than six-fold (from 359 to over 2300 simulation steps). This leads to a quantifiable increase in the initial fluid exchange rate by nearly 10 times (from ${10}^{-11}$ to ${10}^{-10}$${\mathrm{m}}^3$/s) and a reduction in final residual air saturation by 53% (from 0.91 to 0.43). This work provides a tool for predicting and optimizing counter-current flow efficiency in subsurface engineering applications. Full article

The deep shale gas reservoirs of the southern Sichuan Basin exhibit high temperatures, high pressure, large stress differentials, and complex natural fracture systems. Since 2019, hydraulic fracturing technology in this region has evolved through four stages: exploratory fracturing, intensive limited-volume fracturing, tight spacing with controlled fluid and proppants, and balanced fracturing that combines long-section temporary plugging with short-section intensive cutting. Despite these advances, production remains suboptimal due to inefficient reserve utilization, a lack of quantitative methods for residual gas evaluation, and unclear identification of the remaining reserves. To address these challenges, we developed an integrated workflow combining dynamic production analysis, geomechanical modeling, and numerical simulation to evaluate representative fracturing techniques. Fracture propagation in the well group was modeled in the in-house hydraulic fracture simulator, ZFRAC, to assess fracture geometry, while production history and geological data were used to build calibrated reservoir simulation models. This enabled quantitative assessment of effective fracture parameters, reserve utilization, and residual gas distribution. The results show significant intra-stage heterogeneity driven by stress interference, effective fracture half-lengths of 60–105 m, and a cut-off ratio (proportion of effective fracture half-length to wetted fracture half-length) of 60–93%. Reserve utilization peaked at 60% for intensive limited-volume fracturing, while the efficacy of long-section temporary plugging was limited. These findings offer critical insights for optimizing infill strategies and enhancing sustainable shale gas development in southern Sichuan. Full article

Hydraulic fracturing technology serves as the primary method for efficiently developing deep shale resources. During hydraulic fracturing, the thermal stress caused by the injection of fracturing fluid, which has low temperature, has a significant effect on the propagation of multiple hydraulic fractures in deep shale reservoirs. Due to the unclear mechanisms governing multi-fracture propagation in deep shale reservoirs, this study proposed a hydraulic fracturing model for multi-fracture propagation based on the principles of linear elastic fracture mechanics. The model was employed to investigate how formation properties and operational parameters influenced the expansion of multiple hydraulic fractures. The findings revealed that thermal stress fracturing caused by low-temperature fluid injection significantly affected the rock breakdown pressure and fracture initiation timing. Specifically, when the reservoir temperature exceeded 180 °C, the breakdown pressure decreased substantially, and the fracture initiation occurred much earlier. Moreover, an increase in rock thermal conductivity further reduced both the breakdown pressure and the propagation pressure, alleviating the “stress shadow” effect on intermediate fractures and promoting more uniform fracture growth. Furthermore, when the reservoir temperature surpassed 180 °C and the thermal conductivity exceeded 1.3 W/(m K), the influence of horizontal stress difference and cluster spacing on multi-fracture propagation diminished sharply—by more than 40%. This condition facilitated tight containment of the deep shale reservoir and significantly expanded the stimulated reservoir volume. These findings not only enriched and refined the theoretical understanding of hydraulic fracturing in deep shale reservoirs but also provided a valuable reference for optimizing fracturing parameters in the development of deep oil and gas reservoirs. Full article

Horizontal well multi-stage fracturing is the primary technology for deep shale gas development, but dense multi-cluster fractures are prone to non-uniform initiation and propagation, requiring real-time monitoring and interpretation techniques to adjust fracturing parameters. Although high-frequency water hammer pressure-monitoring technology shows diagnostic potential, the correlation mechanism between pressure response characteristics and multi-cluster fracture morphology remains unclear. This study utilized outcrop rock samples from the Longmaxi Formation shale to construct a long-injection-tube pipeline system and a 1 kHz high-frequency pressure acquisition system. Through a true triaxial fracturing simulation test system, it systematically investigated the effects of flow rate (50–180 mL/min) and fracturing fluid viscosity (3–15 mPa·s) on water hammer signal characteristics and fracture morphology. The results reveal that when the flow rate rose from 50 mL/min to 180 mL/min, the initiation efficiency of transverse fractures significantly improved, artificial fractures more easily broke through bedding plane limitations, and fracture height propagation became more complete. When the fracturing fluid viscosity increased from 3–5 mPa·s to 12–15 mPa·s, fracture height propagation and initiation efficiency significantly improved, but fewer bedding plane fractures were activated. The geometric complexity of fractures positively correlated with the water hammer decay rate. This research demonstrates a link between water hammer signal features and downhole fracture morphology, giving a theoretical basis for field fracturing diagnostics. Full article

As a significant energy source enabling the global energy transition, efficient shale gas development is critical for diversifying supplies and reducing carbon emissions. Zipper fracturing widely enhances the stimulated reservoir volume (SRV) by generating complex fracture networks of shale reservoirs. However, recent trends of reduced well spacing and increased injection intensity have significantly intensified interwell interference, particularly fracture-driven interactions (FDIs), leading to early production decline and well integrity issues. This study develops a fully coupled hydro–mechanical–damage (HMD) numerical model incorporating an explicit discrete fracture network (DFN), opening and closure of fractures, and an aperture–permeability relationship to capture the nonlinear mechanical behavior of natural fractures and their role in FDIs. After model validation, sensitivity analyses are conducted. Results show that when the horizontal differential stress exceeds 12 MPa, fractures tend to propagate as single dominant planes due to stress concentration, increasing the risks of FDIs and reducing effective SRV. Increasing well spacing from 60 m to 110 m delays or eliminates FDIs while significantly improving reservoir stimulation. Fracture approach angle governs the interaction mechanisms between hydraulic and natural fractures, influencing the deflection and branching behavior of primary fractures. Injection rate exerts a dual influence on fracture extension and FDI risk, requiring an optimized balance between stimulation efficiency and interference control. This work enriches the multi-physics coupling theory of FDIs during fracturing processes, for better understanding the fracturing design and optimization in shale gas production. Full article

With the progressive depletion of conventional oil and gas resources and the increasing demand for alternative energy, organic-rich sedimentary rock—oil shale—has attracted widespread attention as a key unconventional hydrocarbon resource. Pyrolysis is the essential process for converting the organic matter in oil shale into recoverable hydrocarbons, and a detailed understanding of its behavior is crucial for improving development efficiency. This review systematically summarizes the research progress on the pyrolysis characteristics of oil shale under laboratory conditions. It focuses on the applications of thermogravimetric analysis (TGA) and differential scanning calorimetry (DSC) in identifying pyrolysis stages, extracting kinetic parameters, and analyzing thermal effects; the role of coupled spectroscopic techniques (e.g., TG-FTIR, TG-MS) in elucidating the evolution of gaseous products; and the effects of key parameters such as pyrolysis temperature, heating rate, particle size, and reaction atmosphere on product distribution and yield. Furthermore, the mechanisms and effects of three distinct heating strategies—conventional heating, microwave heating, and autothermic pyrolysis—are compared, and the influence of inherent minerals and external catalysts on reaction pathways is discussed. Despite significant advances, challenges remain in quantitatively describing reaction mechanisms, accurately predicting product yields, and generalizing kinetic models. Future research should integrate multiscale experiments, in situ characterization, and molecular simulations to construct pyrolysis mechanism models tailored to various oil shale types, thereby providing theoretical support for the development of efficient and environmentally friendly oil shale conversion technologies. Full article