Search Results (2,998)

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

This study developed a bio-based fluid loss reducer based on itaconic acid-grafted corn starch (IACS) for water-based drilling fluid systems. The product was synthesized through free radical graft copolymerization and characterized by FTIR, TGA, and SEM. In bentonite-based mud systems, IACS demonstrated excellent filtration control performance significantly superior to that of conventional fluid loss reducers such as PAM, CMC, and PAC. IACS exhibited outstanding temperature resistance, salt tolerance, and calcium contamination resistance. Particle size analysis revealed that IACS effectively dispersed bentonite particles to the nanoscale at elevated temperatures, preventing thermal aggregation. Mechanistic studies indicated that carboxyl groups introduced by the grafting reaction endowed IACS with strong adsorption capacity and hydration ability, forming a dense polymer network layer on clay particle surfaces. Environmental evaluation confirmed that IACS possessed moderate biodegradability and extremely low toxicity, meeting green drilling fluid additive requirements. This study provides new insights for developing high-performance, environmentally friendly fluid loss reducers. 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

This study produces high-purity nano-silica from corn straw ash (biomass power plants) using an alkaline fusion-derived sodium silicate solution. CO₂ replaces traditional acids in the carbonation reaction, enabling high extraction yield (93.11%). The process addresses the gap in directly utilizing combustion ash for such high-purity silica. Key optimal conditions identified were 5 M aq. HCl concentration, NaOH fusion reagent, 1:1.2 mixing ratio, 3 M aq. NaOH solvent, and 12 h ripening. The resulting nano-silica achieved 92.73% purity, 10–50 nm particle size, 270 × 10⁻⁵ m³/kg dibutyl phthalate (DBP) absorption, 55.9916 m²/g specific surface area, 6.38% loss on drying (LOD), and 6.69% loss on ignition (LOI). These properties meet national standards for premium, loosely structured nano-silica. This method provides an economical and effective silicon source, reducing costs and offering economic-environmental benefits. Full article

Lost circulation in oil-based drilling fluids (OBDFs) remains difficult to mitigate because particulate lost circulation materials depend on bridging/packing and gel systems for aqueous media often lack OBDF compatibility and controllable in situ sealing. A dual-precursor oil–water biphasic metal–organic supramolecular gel enables rapid in situ sealing in OBDF loss zones. The optimized formulation uses an oil-phase to aqueous gelling-solution volume ratio of 10:3, with 2.0 wt% Span 85, 12.5 wt% TXP-4, and 5.0 wt% NaAlO₂. Apparent-viscosity measurements and ATR–FTIR analysis were used to evaluate the effects of temperature, time, pH, and shear on MOSG gelation. Furthermore, the structural characteristics and performances of MOSGs were systematically investigated by combining microstructural characterization, thermogravimetric analysis, rheological tests, simulated fracture-plugging experiments, and anti-shear evaluations. The results indicate that elevated temperatures (30–70 °C) and mildly alkaline conditions in the aqueous gelling solution (pH ≈ 8.10–8.30) promote P–O–Al coordination and strengthen hydrogen bonding, thereby facilitating the formation of a three-dimensional network. In contrast, strong shear disrupts the nascent network and delays gelation. The optimized MOSGs rapidly exhibit pronounced viscoelasticity and thermal resistance (~193 °C); under high shear (380 rpm), the viscosity retention exceeds 60% and the viscosity recovery exceeds 70%. In plugging tests, MOSG forms a dense sealing layer, achieving a pressure-bearing gradient of 2.27 MPa/m in simulated permeable formations and markedly improving the fracture pressure-bearing capacity in simulated fractured formations. Full article

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

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

Cracking occurred in the surface coating of a screw rotor during shale gas well operations. To determine whether the coating cracks could contribute to the failure of the 42CrMo substrate, the microstructure and morphology of surface cracks and local corrosion pits were examined and analyzed using a metallographic microscope, an SEM, and an EDS. To investigate the cross-sectional morphology and elemental distribution of corrosion pits, EDS mapping was performed. The composition of the corrosion products was characterized using Raman spectroscopy and XPS. In addition, four-point bend stress corrosion tests were conducted on screw rotor specimens under simulated service conditions. The results indicate that the P and S contents in the screw rotor substrate exceeded the specified limits, whereas its tensile and impact strengths satisfied the standard requirements. The microstructure consisted of tempered sorbite and ferrite, along with a small amount of sulfide inclusions. The corrosion products on the fracture surface were primarily identified as FeOOH, Fe₃O₄, and Cr(OH)₃. All specimens failed during the four-point bend tests. The chlorine (Cl) content in the corroded regions reached up to 8.05%. These findings demonstrate that the crack resistance of the 42CrMo screw rotor was markedly reduced under the simulated service conditions of 130 °C in a saturated, oxygenated 25% CaCl₂ solution. The study concludes that stress concentration induced by sulfide inclusions in the screw rotor, together with the combined effects of chloride ions, dissolved oxygen, and applied load, promotes the initiation and propagation of stress corrosion cracking. Therefore, it is recommended to strictly control the chemical composition and inclusion content of the screw rotor material and to reduce the oxygen content of the drilling fluid, thereby mitigating the risk of corrosion-induced cracking of the rotor. Full article

To address the issues of cities being overwhelmed by the waste and energy crisis, the pyrolysis of municipal solid waste (MSW), oil shale (OS) and their blends was investigated using a thermogravimetric simultaneous thermal analyzer in this study. The experimental research was conducted to investigate the thermal behavior and kinetic parameters of the different blending ratios of MSW and OS, to better utilize these intractable resources, observing whether there is a synergistic effect and trying to find the optimal process conditions. The Ozawa–Flynn–Wall method and the Kissinger–Akahira–Sunose method were used to calculate the activation energy at four different heating rates. The existence of interactions between MSW and OS was confirmed by comparing the experimental thermogravimetric and derivative thermogravimetric curves with the calculated ones. The findings of the thermogravimetric analysis, the calculation of theoretical and experimental curves, and kinetic analysis confirmed the interaction between the components and that the optimal blending ratio is 30% MSW and 70% OS. The optimality results in a relatively smaller activation energy (Eave = 115 kJ/mol), better comprehensive pyrolysis characteristics, and a more beneficial mutual effect. Full article

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

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

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

Water-based drilling fluids (WBDFs) are widely used due to their economic and environmental advantages; however, shale hydration remains a major limitation. This study evaluates Fe₂O₃, CuO, ZnO, and MgO nanocrystalline metal oxides synthesized via co-precipitation as inorganic shale inhibitors for WBDFs. Comprehensive characterization confirmed phase-pure nanocrystalline oxides (17–38 nm) with high thermal stability. Performance tests revealed that MgO-based WBDF exhibited the lowest plastic viscosity (17 cP), the highest pH (≈10.0), and the strongest shale inhibition (6.1% swelling), while Fe₂O₃ provided superior filtration control (6.0 mL). CuO showed balanced rheology, whereas ZnO displayed comparatively weaker inhibition. Compared with commercial inhibitors (Amine NF and Glycol), MgO- and Fe₂O₃-based systems achieved comparable or improved performance with enhanced thermal and environmental robustness. These results demonstrate the potential of nanocrystalline metal oxides as sustainable additives for improving WBDF performance under high-pressure, high-temperature (HPHT) conditions. Full article

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