Search Results (626)

To address wellbore instability and the technical challenges associated with high-density water-based drilling fluid loss control in deep shale gas formations of the Sichuan-Chongqing region in China, a novel nano-micro sealant designated CLG-Seal was synthesized via molecular structural optimization. The molecular structure of newly developed CLG-Seal exhibits distinct core–shell structural characteristics. The inorganic nano-silica constitutes the rigid core of CLG-Seal, which guarantees its plugging performance. The hydrophobically associating polymer which is coated on the surface of nano-silica constructs the flexible shell of CLG-Seal, endowing the CLG-Seal with excellent gel-forming capacity, adhesion film-forming capacity, deformability and perfect dispersibility. Transmission electron microscopy and scanning electron microscopy were employed to characterize the morphology of the CLG-Seal nanomicron-scale plugging agent. The sealing performance and underlying mechanisms of CLG-Seal were subsequently evaluated via particle plugging apparatus tests, displacement experiments, and etched glass micromodel simulations. Field trials conducted in the third section of Well WY3-2-3HF validated the application effectiveness of this agent in drilling fluid systems. The results indicate that the nano-micro sealant CLG-Seal exhibits a median particle size of D₅₀ is 146 nm, which can be modulated by adjusting the synthesis conditions. The nano-micro sealant CLG-Seal significantly mitigates fluid loss in low-permeability microfractures and fissures. Notably, a concentration of merely 3% is sufficient to achieve optimal nano-micro plugging performance. The results of the mechanism study indicate that while the CLG-Seal particles are close to each other, the polymer chains with flexible long chain structure which are coated on the surface of nano-silica constructs tend to be intertwined, forming a cross-linked network structure of gel film, thereby increasing the interaction between nano-micron particles and forming an impermeable plugging film. In addition, due to the nanoscale effect, the CLG-Seal has a strong tendency to adsorb onto the surface of shale rock through hydrogen bonding with the shale matrix. The hydrophobically associating polymer with high elastic modulus and excellent mechanical properties can enhance the pressure-bearing capacity of the filter cake through elastic deformation. Therefore, these nano-micron particles can form a strong sealing film on the filter cake and at the micropores of shale rock, thereby creating a dense mud cake on the outside of the shale formation. Field trial results demonstrate that the incorporation of the nano-micro sealant CLG-Seal into the drilling fluid for the third section of Well WY3-2-3HF reduced the PPA fluid loss to 4.6 mL. This value represents a substantial reduction compared to adjacent wells and signifies a remarkable improvement over the drilling fluids previously employed in the Longmaxi Formation of this block. Furthermore, the treated drilling fluid exhibited a superior filtration control pressure capacity of 10.5 MPa. The operation was completed successfully without any lost circulation or wellbore instability, and achieved a drilling footage of 42 h with an average penetration rate of 7.81 m/h. The mud weight was reduced by approximately 0.08–0.10 g/cm³ compared to offset wells. These results confirm the excellent application efficiency of the newly developed CLG-Seal in field operations. Full article

Oil shale in situ conversion provides an important pathway for developing medium- to deep-buried, low-grade, and thin oil shale resources. Among the available approaches, the in situ conversion technology triggered by the topochemical reaction method, hereafter referred to as the TSA method, induces local oxidation reactions of pyrolysis residuals, fixed carbon, and reactive organic matter through preheating and oxygen-containing gas injection. The released in-formation heat then supports continued kerogen cracking and reaction-front propagation. This review summarizes the TSA method from a process-oriented perspective, linking reaction mechanisms, engineering controls, geochemical process identification, pilot tests, economic–environmental constraints, and scale-up evaluation. Existing studies indicate that the TSA method has formed a technical chain involving reaction initiation, heat/reaction-front propagation, oil and gas recovery, and process monitoring. Pilot tests provide evidence for operational feasibility, but not yet for full commercial feasibility. Thermal simulation results show that oil and gas generation and expulsion become significant above ~350 °C, and that 375–425 °C can be used as an important reference window for temperature control rather than a fixed optimum for all oil shale reservoirs. Geochemical indicators can provide complementary constraints for identifying reaction progress, especially when calibrated with produced oil and gas. Further development should focus on fracture-network control, heat-transfer enhancement, oxygen-supply regulation, multi-well coordination, equipment reliability, economic evaluation, groundwater protection, and CO₂ emission accounting. These issues are critical for advancing the TSA method toward larger-scale, low-carbon, and well-regulated application. Full article

The complex fracture networks, multiphase flow behavior, and nonlinear flow mechanisms induced by hydraulic fracturing in horizontal wells of shale oil reservoirs pose significant challenges to production evaluation. In this study, a semi-empirical productivity evaluation method for multiphase shale oil systems is developed by integrating production dynamics with flow mechanisms. Three-phase productivity equations for oil, gas, and water are established, explicitly incorporating the underlying flow mechanisms. A nonlinear flow index is introduced to characterize both the stress sensitivity of fractures and the threshold pressure gradient in the matrix. Key unknown parameters, including oil saturation, water cut, stimulated reservoir volume, and nonlinear coefficients, are determined through history matching of production data. The impacts of geological properties, fracturing parameters, operating conditions, and nonlinear flow parameters on oil–gas productivity are systematically investigated using the proposed multiphase semi-empirical model. The model is validated against production data from fractured horizontal wells in a field case, demonstrating its accuracy and applicability. Furthermore, the model enables reliable production forecasting based on the derived productivity relationships. The proposed approach provides a practical and efficient tool for rapid post-fracturing productivity evaluation in shale oil reservoirs. Full article

Multi-cluster perforation staged fracturing in horizontal wells has become an important means of completion stimulation for unconventional oil and gas reservoirs. However, the non-uniform propagation of multi-cluster hydraulic fractures remains one of the key challenges restricting efficient reservoir stimulation. In this study, based on the finite element method and considering factors such as frictional pressure drop along the wellbore for power-law fluid, perforation friction, and stress interference, a fracture propagation model with dynamic multi-stage flow distribution coupling formation, perforation, and wellbore flow was constructed. The effects of non-uniform perforation schemes, total number of perforations, and perforation non-uniformity coefficient on multi-cluster fracture propagation behavior were systematically investigated, and the characteristics of dynamic flow distribution were clarified. The results show that the order of fluid intake uniformity among different perforation schemes is as follows: spindle-shaped perforation, uniform perforation, and Tapered perforation. Reducing the number of perforations and decreasing the perforation non-uniformity coefficient can improve the uniformity of fracture propagation to a certain extent. The findings of this study can provide a theoretical basis and practical reference for efficient fracturing stimulation of shale oil in the Cangdong Sag. Full article

Aiming at the problems of insufficiently tight sealing of all-metal dissolvable frac plugs and the poor fracturing effect in the extraction of shale gas, the effects of structural parameters on the performance of metal dissolvable ball seat sealing rings was analyzed using numerical simulation and an experimental method. The key structural factors affecting performance were identified. The problem of stress concentration at the contact position between the sealing ring and the slip of the existing structure was discovered. To solve the above problems, a combination structure sealing ring was designed. Then the performance comparison analysis of the two structures and optimal structural parameters were carried out. Under the same sealing force, the combination structure sealing ring can be smoothly sealed, and the stress distribution of the upper sealing ring is uniform. This indicates that the performance of the combination structure sealing ring is superior, and the optimal cone angle and thickness obtained are 9° and 17 mm, respectively. Based on the optimized structural parameters, experiments were conducted. After being pressurized at room temperature to 51 MPa and stabilized for 15 min, the pressure gradually decreased to 47.4 MPa, indicating a secondary setting. After unloading, the lower end face of the dissolvable ball seat has no liquid leakage. Under high temperature, a pressure of 51 Mpa was applied; the pressure inside the wellbore remained basically unchanged. During the process of applying pressures of 60 MPa and 70 MPa, there was also a decrease in pressure, indicating the presence of secondary sealing. The above results indicate that the optimized combined metal sealing ring has strict sealing and good pressure-bearing performance. At the same time, the reliability of the simulation results was verified. The designed sealing ring was applied to the shale gas horizontal well deployed in Changning block, China. The application results show that when the displacement remains unchanged, the casing pressure increases from 51 MPa to 60 MPa, and continues to maintain the displacement. The pressure did not fall back to 51 MPa, proving that the formation pressure is released. The successful on-site application once again verifies the safe and reliable performance of the all-metal sealing ring. Full article

This study is a systematical investigation of the fundamental geological conditions for shale gas in the Wufeng–Longmaxi formations in western Hubei, China, using drilling core data, with Well Xiandi-2 serving as the key well for core observation and experimental testing, integrated with outcrop profiles and regional provincial-level shale gas block data. The analysis encompasses petrology, organic geochemistry, mineral composition, physical properties, pore types, and gas content. Through a comprehensive comparison with established shale gas production fields in the Sichuan Basin, the shale gas resource potential of the study area is evaluated, and favorable zones for shale gas exploration are delineated. The results indicate that the study area contains a continuous organic-rich shale interval with a 18.84 m net thickness, 2.3% average total organic carbon, 65–89% brittle mineral content, 2.36% average porosity, and thermal maturity within the gas window. Systematic comparison with the Jiaoshiba and Changning fields confirms comparable geological attributes, including organic matter abundance, reservoir porosity, and brittle mineralogy. Given this comparability, areas with burial depths shallower than 1500 m on the northwestern margin of the Xuefeng Uplift are interpreted to retain moderate shale gas resource potential. Three favorable zones are delineated as priority targets: the synclines on both sides of the Longtan normal fault and the Lianghekou Syncline. These findings provide practical exploration value: the identified favorable zones offer immediate drilling targets, the analytical workflow is transferable to other structurally complex blocks on the basin margin, and the potential of shallow-buried sequences expands exploration beyond the core Sichuan Basin into previously overlooked transitional zones. Full article

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

Considerable debate remains regarding the mechanisms responsible for the reduction in organic matter (OM) pores in post-mature shales. To address this issue, complementary techniques including scanning electron microscopy (SEM), total organic carbon (TOC) analysis, and helium porosity measurement were employed to characterize the microstructure and porosity of post-mature shales from the Qiongzhusi Formation in the southwestern Upper Yangtze region, China. The results show that OM pores in these shales are poorly developed and exhibit highly irregular morphologies. Notably, the degree of OM pore development is negatively correlated with TOC. Interestingly, in samples with TOC < 2.5 wt.%, well-preserved spongy migrated OM is still observable under SEM. The average porosity of Qiongzhusi mudstones is 1.8%; siltstone samples with TOC < 2 wt.% yield an average porosity of 3.5%, whereas samples with TOC > 4 wt.% have an average porosity of only 1.9%. These findings do not support the hypothesis that graphitization causes the significant destruction of OM pores in post-mature shales. Instead, we propose that compaction has been the dominant factor controlling OM pore destruction. Accordingly, we introduce a “depth window” for the development of high-quality shale gas reservoirs: Beyond a certain maximum paleoburial depth, compaction leads to extensive OM pore destruction and a marked decline in reservoir quality. This study advances our understanding of pore evolution in post-mature shales and provides practical guidance for shale gas exploration. Full article

Gas-lift reverse circulation drilling technology is one of the typical “bottom-hole negative pressure” drilling technologies. This technology can significantly reduce wellbore circulation pressure loss, alleviate the bottom-hole pressure holding effect, and effectively lower the probability of lost circulation. The core theory underlying this technology is multiphase flow in the wellbore. Based on gas–liquid two-phase flow theory, this paper develops a method for calculating bottom-hole pressure during gas-lift reverse circulation. The effects of key operational parameters on bottom-hole pressure were analyzed. The results show that bottom-hole pressure decreases as gas injection rate increases and as the gas injection point deepens. Moreover, the deeper the gas injection point, the greater the pressure reduction. Compared with the results from gas-lift reverse circulation drilling design and monitoring software applied to a shale gas well in southern Sichuan, the two sets of data differ by approximately 3%. The proposed calculation method can predict bottom-hole pressure under gas-lift reverse circulation conditions, overcoming the low accuracy of empirical formulas traditionally used in such operations. This has significant implications for advancing gas-lift reverse circulation technology in oil and gas well drilling. Full article

Addressing the challenges of high-dimensional redundancy, noise interference, and parameter missing in the net present value prediction of shale gas wells, an intelligent prediction model PCA-DFNN integrating Principal Component Analysis and Deep Feedforward Neural Network is proposed. Based on actual data from 48 shale gas wells, Principal Component Analysis is first performed on 19 input features to reduce dimensionality, extracting 9 core principal components, which achieve a cumulative variance contribution rate of 88.05%. Subsequently, a deep neural network model is constructed for comparative modeling. The results indicate that the PCA-DFNN model achieves a coefficient of determination on the independent test set that improves from 0.6439 in the original model to 0.6882, an increase of 0.0443, or approximately 6.9%, with faster training convergence and superior generalization ability. The research confirms that the proposed method can effectively eliminate feature redundancy, filter noise, and circumvent the uncertainty of missing value imputation, providing a more reliable technical tool for the early economic evaluation of shale gas. Full article

During the development of multiple wells of shale gas, coproduction under varying pressures induces interference. High-pressure wells impose backpressure on low-pressure wells, thereby restricting overall reservoir productivity. Accurate interference characterization is critical for efficient development. This study examines 42 gathering platforms within the Changning 201 Block. A three-tier surface gathering network hydraulic model (‘Platform-Gathering Station-Central Station’) was established. The model calculates key node pressures in the pipeline system following the integration of new wells. Unlike conventional interference studies that primarily focus on the reservoir scale and overlook the critical role of the surface gathering pipeline network as a propagation pathway for interference, this paper, for the first time, extends interference analysis from the “reservoir–wellbore” system to the full surface pressure system encompassing “wellhead-platform-gas gathering station-central station”. A transferable three-stage engineering decision-making workflow of “diagnosis-comparison-coordination” is proposed. This evaluates the extent to which the production of new wells at different development stages interferes with the pressure and productivity of existing gas wells, and enables a quantitative assessment of the influence of pressure-boosting technology on well deliverability and auxiliary measures. This research confirms that the model presents calculation errors of less than 3%. The commissioning of seven new wells with a combined capacity of 531,000 m³/d resulted in a total output increase of 626,900 m³/d at the central processing station; Platform CN-30 gas well deliverability decreased by 20.7%; the implementation of appropriate pressure-boosting technology was effective, enabling an average deliverability increase of 1.27 × 10⁴ m³/d per well, releasing the potential deliverability of the well. 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

Spontaneous potential (SP) logging remains a widely used method in well geophysics. However, its interpretation is often limited by simplified physical models and correction charts that do not fully account for the processes governing SP generation, particularly in shaly and heterogeneous formations. In this study, we develop a finite element-based algorithm for modeling SP responses in complex near-wellbore environments, with the aim of providing a more physically consistent framework for interpretation. The proposed algorithm is based on the numerical solution of the Poisson equation with electrochemical source terms, incorporating the cation transport number to describe diffusion–adsorption processes and allowing for smooth variations in formation resistivity, fluid properties, and shale content. The numerical implementation is validated against published analytical solutions, correction charts, and previous numerical studies, showing good agreement in both the shape and amplitude of modeled SP responses across a range of geological scenarios, including thin beds and invasion zones. Application to real data from a Southeast Asia gas field demonstrates that the approach provides reliable estimates of formation water salinity and the cation transport number, with results consistent with independent estimates. The proposed method offers a flexible tool for SP response modeling and may complement existing interpretation techniques, particularly when working with heterogeneous formations and limited legacy datasets. Full article

Inter-well interference in multi-well pad development is a critical factor influencing the recovery efficiency of shale gas reservoirs. This study presents a comprehensive semi-analytical model to characterize the transient pressure behavior and interference mechanisms of multi-well multi-stage fractured horizontal wells (MFHWs). Utilizing point source functions and the principle of superposition, the model accounts for complex shale gas transport mechanisms, including gas desorption, diffusion, and real-gas compressibility via pseudo-pressure transformation. The proposed model is validated against the industrial standard numerical simulator KAPPA-Saphir, showing an excellent match across most flow regimes, with a maximum relative error of 3.2% and an average relative error of less than 1% across the entire production period. The results identify five distinct flow stages: fracture linear flow, fracture radial flow, compound linear flow, compound radial flow, and boundary-dominated flow. Sensitivity analysis reveals that decreasing the inter-well spacing significantly shortens the fracture radial flow duration, while longitudinal staggering of wellbore centers effectively mitigates early-time interference and promotes more uniform reservoir drainage. Furthermore, it is observed that in multi-well systems, inner wells suffer from more severe energy competition and faster pressure depletion than peripheral wells. Based on these findings, it is proposed that the inter-well spacing should exceed four times the fracture half-length, and a staggered fracture arrangement (the relative positions in the x-direction of the fractures between the wells are not the same) should be prioritized. This work provides a robust theoretical framework and practical guidelines for optimizing well spacing and infill drilling strategies in shale gas reservoirs. Full article