最新刊期
卷 16 ， 期 3 ， 2026
- 摘要：To promote the large-scale and efficient exploitation of shallow shale gas, this study focuses on the complex structural area in the southeastern margin of the Sichuan Basin. The geological characteristics, challenges in efficient exploration and development, countermeasures, and exploration achievements of shallow shale gas were systematically reviewed and analyzed. Theoretical research and exploration practices showed that: (1) Shallow shale gas experienced stronger structural modification and exhibited three key geological characteristics: low formation pressure coefficient (between 0.80 and 1.05), high ratio of adsorbed gas (between 55% and 80%), and high stress difference coefficient (between 0.32 and 0.56). Three types of accumulation models were: shallow monocline type, reverse fault type, and out-of-basin anticline type. Efficient exploration and development faced four major challenges: sweet spot optimization, fast and efficient well completion, full-scale reservoir stimulation, and pressure reduction and drainage. (2) When the burial depth was between 500 and 2 000 m, near-saturated adsorption of shallow shale gas formed a “golden zone” for adsorbed gas enrichment. Reducing the flowing pressure to the sensitive desorption window (pressure between 1.5 and 2.5 MPa) could efficiently activate adsorbed gas desorption. (3) The main controlling factors for the enrichment of the shallow monocline type were formation attitude and burial depth. In response to the characteristics of gentle strata and good self-sealing property of shale, a super-long horizontal well production enhancement technology was developed, thereby increasing the well-controlled reserves and single-well production. In the Nanchuan slope area, the daily gas production of single-well tests ranged from 4.1×104 m3 to 22.1×104 m3, achieving overall proven reserves and efficient development. (4) The main controlling factors for the enrichment of the fault footwall type were fault activity stages and sealing capacity. Considering the characteristics of multi-stage fracture development and moderate in-situ stress, a fracturing technology of “multiple clusters in the middle section, restricted flow perforation, and increased flow rate” was developed to enhance the complexity of the artificial fracture network. In the Daozhen fault footwall area, the daily gas production of single-well tests ranged from 4.5×104 m3 to 13.0×104 m3, achieving a breakthrough in the commercial gas flow threshold for out-of-basin normal-pressure shale gas. (5) The main controlling factors for the enrichment of the out-of-basin anticline type were formation pressure and temperature. Considering the characteristics of high adsorbed gas ratio and weak post-fracturing self-flowing capacity, a “near-zero flowing pressure” production technology was developed to promote adsorbed gas desorption. In the Laochangping anticline type, the daily gas production of single-well tests increased from 0.7×104 m3 to 4.5×104 m3, achieving adsorbed gas desorption and self-flowing production. (6) Adhering to the concept of low-cost and high-quality development, breakthroughs were achieved in fast and efficient drilling and completion technologies centered on the “two-level structure, logging while drilling (LWD), and water-based drilling fluid.” These were integrated with efficient fracturing technologies primarily based on “increased flow rate and net pressure, high intensity and high sand ratio, and multi-stage composite temporary plugging,” resulting in significant production enhancement, cost reduction, and efficiency improvement. Through integrated geological engineering theoretical research and innovative practices, exploration breakthrough and efficient production of shallow out-of-basin shale gas in southeastern Chongqing were achieved, providing theoretical support and practical experience for the efficient development of shallow shale gas in complex structural areas.关键词：shallow shale gas;geology-engineering integration;exploration practices;Wufeng-Longmaxi formation;complex structural area;Southeastern Chongqing;Sichuan Basin165|106|0更新时间：2026-05-09
- 摘要：The Lintanchang area of the Sichuan Basin has experienced multiple stages of tectonic movements, resulting in a complex fault and fracture system. Drilling results show that the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation possesses favorable exploration and development potential. Clarifying the development patterns of faults and associated fractures in these strata is critical for subsequent exploration. In this study, faults in the Lintanchang area were classified into four levels (A, B, C, and D), with three dominant strike directions: NE-trending, near-EW-trending, and near-NS-trending. A-level faults were mainly distributed on the flanks of the anticline, whereas fewer faults developed at the plunging end of the anticline. Using three-dimensional seismic attribute fusion with the fracture development index (FDI), a quantitative study was performed on fault-related fractures in the Wufeng-Longmaxi Formation. The results showed that: (1) The width of fault-related fracture zones exhibited a significant positive correlation with fault displacement. The widths of A-level fracture zones ranged from 510 m to 660 m (average ~600 m), B-level from 160 m to 280 m (average ~220 m), C-level from 130 m to 200 m (average ~168 m), and D-level from 115 m to 170 m (average ~150 m), respectively. Fracture zones in the hanging wall were generally wider than those in the footwall, and fractures were most developed at fault intersections. Among faults of the same level, near-EW-trending faults exhibited the widest fracture zones, followed by near-NS-trending faults, whereas NE-trending faults showed the narrowest zones. (2) Fault-related fracture zones were closely associated with shale gas preservation conditions. Wells located within fracture zones had lower formation pressure coefficients and productivity, whereas wells far from fracture zones exhibited higher pressure coefficients and greater gas production. A significant positive correlation was observed between these two, indicating that fault-related fractures played an important role in controlling pressure maintenance and limiting gas escape. This study reveals the development patterns of faults and associated fractures in the Wufeng-Longmaxi Formation of the Lintanchang area, providing important reference for shale gas sweet-spot selection and well placement in the region.关键词：Lintanchang;Wufeng-Longmaxi formation;shale gas;Attribute Fusion;Fault-Related Fractures;exploration area selection135|273|0更新时间：2026-05-09
Specialist Forum
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Fracture stress sensitivity of saline lacustrine shale considering time effect and fluid properties AI导读
摘要：In the process of shale oil and gas development, the fracture network formed by large-scale hydraulic fracturing leads to significant stress sensitivity in the reservoir. The salinity, ion composition, and loading time of fluids may complicate the stress-sensitive behavior of the reservoir, thereby affecting the stimulation performance and the stable production of oil and gas wells. Taking the saline lacustrine shale from the upper part of the fourth member to the lower part of the third member of the Shahejie Formation (Paleogene) in block N, Bohai Bay Basin as the research object, stress sensitivity experiments on fractured shale samples were conducted. The influence mechanism of the coupling of three factors—effective stress, fluid salinity, and loading time—on permeability was systematically analyzed. The results showed that fracture permeability exhibited a two-stage decrease with increasing effective stress, and the rate of decrease gradually slowed down. In the stress range of 3-25 MPa, the permeability decreased rapidly, and the influence of fluid salinity was significant. The permeability of formation water was higher than that of sub-formation water and distilled water. During loading from 5 MPa to 15 MPa, the increases in turbidity and electrical conductivity of the outlet of distilled water were both greater than those of sub-formation water. Moreover, at effective stresses of 10 MPa and 15 MPa, the permeability of distilled water was higher than that of sub-formation water. In the stress range of >25-40 MPa, the rate of permeability decrease slowed down, and the permeabilities of the three fluids tended to converge. Under constant effective stress, the rate of permeability change gradually decreased with prolonged loading time. Additionally, the influence of loading time on permeability diminished as the effective stress increased. Fluid selection for well injection should consider the time-dependent permeability behavior under effective stress. Under low-stress conditions, it is recommended to use high-salinity flowback fluids to prepare injection fluids to reduce stress sensitivity. Under high-stress conditions, it is suggested to use high-strength proppants to prevent fracture closure and to reasonably utilize the salt-dissolving and fracture-enlarging effect of low-salinity fluids to improve seepage channels, thereby ensuring the long-term effectiveness of fracturing stimulation. This study provides an important theoretical basis and practical guidance for the efficient development of lacustrine shale reservoirs and the optimization of fluids for well injection.关键词：shale;stress sensitivity;time effect;fluid salinity;reservoir damage111|139|0更新时间：2026-05-09 - 摘要：The organic-rich deep shale gas reservoirs of the Longmaxi Formation in the Dazu area of western Chongqing exhibit pronounced heterogeneity, which constrains the efficient exploration and development of the Longmaxi Formation shale gas in this region. Three-dimensional seismic data were used to reconstruct the paleogeomorphic pattern of the Early Silurian Longmaxi period in the Dazu area. Combined with lithological and mineralogical data, organic and inorganic geochemical data, well logging-seismic data, and reservoir characterization results, the sedimentary environment, material composition, and reservoir heterogeneity of the Longmaxi Formation under different paleogeomorphic units were investigated, and their genetic mechanisms were explored. The results indicated that: (1) The paleogeomorphology during the deposition of the Longmaxi Formation in the study area showed a step-like pattern, with higher elevations in the north and lower in the south. From north to south, shelf highlands, shelf slopes, and shelf depressions were developed sequentially, and the redox conditions and paleosalinity of the sedimentary water body gradually increased southward. (2) The material composition of shale reservoirs showed a clear co-variation relationship with the secondary paleogeomorphic units. The biogenic quartz content and total organic carbon (TOC) content increased southward, while the clay mineral and terrigenous clastic contents decreased southward. High productivity and good preservation conditions in the shelf depressions favored organic matter enrichment, and diagenetic processes such as feldspar alteration controlled the spatial distribution of mineral composition. (3) The spatial variations in mineral composition and organic matter content further controlled the reservoir characteristics. The porosity of the continental shelf slope was the highest, dominated by intercrystalline pores and organic pores. The porosity of the continental shelf highlands was the second highest, primarily consisting of intergranular and intragranular pores. The porosity of the continental shelf depression was the lowest, which was associated with the small size of organic pores and the filling of intergranular pores by biogenic quartz. (4) Constrained by quantitative inversion and measured data, the thickness of type I shale gas reservoirs gradually increased from the continental shelf highlands to the continental shelf depressions, showing a significant genetic connection with the changes in the sedimentary environment. The differences in sedimentary environment controlled by paleogeomorphology are the fundamental cause of the strong heterogeneity of shale gas reservoirs. The research findings can provide a basis for the efficient exploration and development of heterogeneous shale gas reservoirs.关键词：Dazu Block;Longmaxi Formation;deep shale gas;reservoir heterogeneity;reservoir genesis;paleogeomorphic pattern156|104|0更新时间：2026-05-09
- 摘要：The Wulalike Formation developed in the southwest margin of the Ordos Basin is an important shale gas exploration and development horizon in northern China, characterized by general gas occurrence and local enrichment. Exploring the influencing factors of the development of high-quality source rocks in the Wulalike Formation has important guiding significance for current oil and gas exploration. This study focused on the Wulalike Formation shale from the Shixiagu cross-section in the northern part and the Yindongguanzhuang cross-section in the southern part of the western margin of the basin. A systematic investigation was conducted on the geochemical characteristics of source rocks, the composition of hydrocarbon-generating organisms, and the evolution of the paleoceanic environment to establish the sedimentary model of the Wulalike Formation and identify the influencing factors of the development of high-quality source rocks. The results showed that: (1) The source rocks were primarily developed at the bottom of the Wulalike Formation, with overall low total organic carbon (TOC) content. The thermal maturity ranged from mature to highly mature, and the overall hydrocarbon generation potential was relatively low. (2) The biotic assemblage of the Wulalike Formation included planktonic algae, graptolites, benthic algae, algal sporangia, and radiolarians. Further study confirmed that the hydrocarbon-generating organisms in the source rock intervals were mainly planktic algae bodies and their degraded fragments, with lower contents of graptolites and benthic algae fragments. (3) Trace element geochemical indicators showed that the Wulalike Formation shale was deposited in an anoxic water environment, but the paleoproductivity level was overall low. The sedimentary water body in the northern part of the western margin was anoxic and stagnant, while the sedimentary water body depth in the southern part of the western margin was shallower, with a weaker degree of anoxia. Comprehensive analysis indicates that the organic matter enrichment in the Wulalike Formation shale is influenced by both paleo-marine productivity and the redox conditions of the water body. The overall low paleo-marine productivity level is the primary reason for the low organic matter abundance in the source rocks, while the local redox environment plays a more significant role in regulating the preservation efficiency of organic matter.关键词：Ordos Basin;Wulalike Formation;shale;hydrocarbon-generating organisms;source rock143|146|0更新时间：2026-05-09
- 摘要：Since 2020, exploration of continental shale oil in the second member of the Paleogene Funing Formation (hereinafter referred to as Funing 2 member) in the Qintong Sag, Subei Basin, has continuously yielded discoveries, with proven geological reserves for sub-member Ⅰ exceeding 4 000×104 t for the first time. To systematically reveal the occurrence characteristics and controlling factors of shale oil in sub-member Ⅰ of the Funing 2 member in this sag, analysis techniques such as thin-section observation, scanning electron microscopy, X-ray diffraction, multi-temperature stage rock pyrolysis, low-temperature N2 adsorption, and two-dimensional nuclear magnetic resonance were employed to conduct in-depth research on the mineral composition, pore development characteristics, and pore fluid occurrence state of the shale reservoir. The results indicated that sub-member Ⅰ of the Funing 2 member developed mixed shale, felsic shale, and carbonate shale. The micro-nano scale storage spaces included organic pores, intercrystalline pores, intergranular pores, dissolution pores, clay mineral interlayer fractures, and grain-edge fractures, with clay mineral intercrystalline pores and intergranular pores being the main occurrence sites for shale oil. Shale oil mainly occurred in a free state (accounting for 67%-97%, with an average of 88%). Based on 2D NMR data, the lower limit of oil-bearing pore size was determined to be 5.38 nm, and the lower limit of movable oil pore size was 26.88 nm. The study revealed that organic matter abundance was the core prerequisite for controlling shale oil occurrence, as it determined both the scale of oil generation and dominated the occurrence of adsorbed oil. Mineral composition and occurrence patterns controlled the occurrence of free oil by determining pore types and development scale. When the contents of felsic minerals, clay minerals, and carbonate minerals were in the range of 30%-60%, 20%-40%, and below 30%, respectively, and the ratio of felsic mineral to clay mineral was between 1 and 2, the conditions for free oil occurrence were optimal. The results reveal that intervals with mixed shale and felsic shale, characterized by relatively high organic matter abundance and low carbonate mineral content, have favorable conditions for shale oil occurrence and should be prioritized as the next focus areas for shale oil exploration in the Funing 2 member.关键词：Qintong Sag;second member of Funing Formation;shale oil;occurrence characteristics;controlling factors144|292|0更新时间：2026-05-09
- 摘要：Natural fractures are important reservoir spaces and seepage channels in continental shale reservoirs of the Bonan Subsag, Jiyang Depression. The development characteristics and genetic mechanisms of these fractures directly affect the productivity of single wells. Seismic interpretation, core and thin section observation, scanning electron microscopy, and X-ray diffraction (XRD) analysis were employed to investigate the structural styles, development characteristics of natural fractures, main controlling factors, and the influence of effective fractures on single-well productivity in the lower submember of the third member of the Shahejie Formation in the Bonan Subsag. The results showed that natural fractures in the lower submember of the third member of the Shahejie Formation were classified by genesis into tectonic fractures, diagenetic fractures, and hydrocarbon-generating overpressure fractures. Tectonic fractures were further subdivided based on geological origin into shear fractures, tensile fractures, and bedding-slip fractures. The dominant type of natural fractures was the vertical shear fractures (75°-90°). Overall, the fracture extension lengths were relatively short (5-10 cm), and tensile fractures exhibited slightly larger apertures (0.5-1.0 mm). The fracture fillings were mainly calcite and asphalt, with a high proportion of shear fractures remaining unfilled. The main controlling factors of natural fracture formation included distance from faults, structural combination style, carbonate mineral content, organic matter content, and lithofacies combination types. Natural fractures were more developed near faults, on the fault hanging wall, and in fault-block structural combination styles. Carbonate mineral and organic matter contents were positively correlated with the degree of natural fracture development. Natural fractures were relatively well developed in carbonate-rich shale facies and felsic shale facies. Unfilled and partially filled high-angle shear fractures and tensile fractures were the effective fracture types that contributed most to shale oil productivity, followed by unfilled bedding-slip fractures. This study helps deepen the understanding of the formation mechanisms of natural fractures in eastern continental shale oil, providing an important basis for the exploration and development of fractured shale oil reservoirs in the Bonan Subsag and the entire Jiyang Depression.关键词：Bonan Subsag;lower submember of third member of Shahejie Formation;continental shale;natural fracture;main controlling factors88|463|0更新时间：2026-05-09
- 摘要：The second member of the Paleogene Funing Formation in the Gaoyou Sag, Subei Basin, is one of the key strata for shale oil exploration. Shale reservoir characteristics are important factors influencing oil and gas accumulation, seepage, and migration. To investigate the reservoir characteristics, methods including core observation, X-ray diffraction mineral analysis, N₂ adsorption, scanning electron microscopy, and nuclear magnetic resonance were utilized to study the “four properties” (oil-bearing potential, storage capacity, mobility, and fracturability) of different lithofacies, characterize the reservoir features, and analyze their influencing factors. The results indicated that eight main lithofacies types (Type 1 to Type 8) and four lamination types (felsic lamination, argillaceous lamination, carbonate lamination, and mixed lamination) developed in the study area. The dominant lithofacies were medium-carbon laminated felsic-argillaceous mixed shale, medium-carbon laminated felsic-carbonate mixed shale, and medium-carbon laminated carbonate rock, which were mainly developed in the middle-lower part of sub-member III, sub-member IV, and the middle-lower parts of sub-member V. The storage spaces included pores and fractures. The pores were mainly intergranular (interparticle) pores, while the fractures were mainly tectonic shear fractures, tension-shear fractures, and non-tectonic bedding fractures. The shale reservoirs were influenced by mineral composition, lamination development, and fracture effectiveness. Specifically, intergranular pores in carbonate minerals were relatively small. Higher contents of felsic and argillaceous minerals led to more developed pores and a larger proportion of meso- and macropores. Furthermore, the more uniform the mineral composition of the shale, the better the pore connectivity. Laminated shale exhibited better porosity and permeability, oil-bearing potential, and mobility than other structural types of shale. Unfilled large tectonic shear fractures, bedding fractures, bedding calcite veins, and intralaminar tension-shear fractures constituted effective storage spaces. After fracturing, these could connect pores, forming a complex pore-fracture system. These findings provide support for the evaluation and "sweet spot" selection of shale oil reservoirs in the second member of the Funing Formation, Gaoyou Sag, Subei Basin.关键词：Subei Basin;Gaoyou Sag;second member of Funing Formation;shale oil;storage space;influencing factors100|205|0更新时间：2026-05-09
- 摘要：In recent years, high-yield oil and gas flows have been obtained from buried hill reservoirs in the Bohai Sea and South China Sea, but no breakthroughs have been made in the East China Sea. Based on core observations, thin-section analysis, X-ray diffraction, elemental analysis, and zircon U-Pb dating, the characteristics of the buried hill and fracture-filling mechanisms in the middle slope zone of the Xihu Sag in the East China Sea were analyzed. The results showed that: (1) the basement rock of the buried hill consists of granite, with a zircon U-Pb age of about 113 Ma, indicating its formation was completed in the Early Cretaceous. (2) Fractures were the main reservoir space in the study area. Drilling results confirmed that the basement rock of buried hill was affected by three stages of fault activity from the Eocene to the Oligocene, resulting in high-angle structural fractures. Diagenetic minerals were broken and cut by dense networks of fractures, forming clastic structures dominated by closed fractures. (3) The shallow fractures were mainly filled with calcite, with the filling primarily derived from authigenic carbonate minerals precipitated within marine sediments. In contrast, deep fractures developed a quartz-calcite-pyrite combination. The carbonate filling components were characterized by high 87Sr/86Sr ratios, strong carbon and oxygen isotope fractionation, right-skewed rare earth element patterns, and significant positive Eu anomalies, indicating that the filling minerals originated mainly from high-temperature fluid upwelling from the mantle. These processes were associated with the two episodes of magmatic activity during the Paleocene-Eocene and Oligocene-Miocene. This study clarifies the genetic mechanisms of filled fractures and predicts zones of effective fracture development, providing a basis for future oil and gas exploration and deployment.关键词：paleo-buried hill;filled fracture;calcite;Xihu Sag;East China Sea70|52|0更新时间：2026-05-09
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A deep learning-based seismic frequency extension method using generalized regression neural network AI导读
摘要：To meet the urgent demand for high-resolution seismic data in the exploration of structural-lithological oil and gas reservoirs in the Subei Basin, and to address the limitations of traditional deconvolution and frequency-domain transformation methods such as insufficient utilization of well information and poor adaptability to nonlinear characteristics, this study proposed a deep learning-based intelligent seismic frequency extension method using generalized regression neural network (GRNN). By integrating well-seismic joint technology, a deep learning framework centered on GRNN was constructed to fully utilize logging data to synthesize high-frequency seismic labels and realize the intelligent extension of the seismic frequency band. The GRNN network, based on the Parzen window probability density estimation theory, adopted a four-layer topology consisting of input layer, pattern layer, summation layer, and output layer. It had advantages including non-parametric modeling, local feature adaptive approximation, and noise robustness, which effectively solved problems such as non-stationarity of seismic signals and high-dimensional noise interference. In the YA high-density 3D survey area of the Subei exploration area, high-frequency seismic traces were synthesized from well data to train the network for frequency extension processing. The results showed that the effective frequency range was extended from 7-43 Hz to 6-56 Hz. The thin sand body boundaries were delineated more clearly, and the well-seismic matching was good, with a correlation of synthetic records of 82%. Additionally, this study explored the effects of different training set sizes and different selection methods of training traces on the prediction results. It was found that selecting seismic traces that could control the entire seismic profile as training data yielded better frequency extension results. The deep learning-based frequency extension method has been applied to multiple blocks in the Subei Basin, yielding favorable results that verified its effectiveness and applicability. The research findings provide high-resolution data support for the fine characterization of complex lithological oil and gas reservoirs and promote the intelligent development of seismic frequency extension technology.关键词：Subei Basin;generalized regression neural network;deep learning;frequency extension;logging information80|174|0更新时间：2026-05-09
Oil and Gas Exploration
- 摘要：China’s normal-pressure shale gas resources are widely distributed and hold significant potential, serving as one of the important replacement areas for future reserve growth and production enhancement. Well LY1 in the Wulong block, located in the fold belt outside the Sichuan Basin, is a typical normal-pressure shale gas well. It has been in continuous production for nearly 10 years, with a cumulative gas production exceeding 40 000 × 104 m3. It is currently the normal-pressure shale gas well with the highest cumulative production outside the basin, highlighting the promising exploration and development prospects of normal-pressure shale gas. Based on drilling, logging, seismic, laboratory analysis, and fracturing test data from the Wulong area, this study systematically analyzed the geological characteristics of the normal-pressure shale gas reservoir, clarified its production dynamics and flow mechanisms at different development stages, and deepened the understanding of the main controlling factors of the enrichment and high productivity of normal-pressure shale gas. The results showed that: (1) The thickness of high-quality shale in the Wufeng-Longmaxi Formation in the normal-pressure area of Wulong was approximately 32 m. Although slightly thinner than that in the overpressured area inside the basin, it still provided a favorable material foundation. The reservoir exhibited favorable physical properties, with well-developed organic matter pores (pore diameters ranging from 2 to 50 nm) and more developed microfractures than those inside the basin. Influenced by multi-stage tectonic movements, reservoir preservation conditions were relatively poor. As a result, shale gas occurred mainly in an adsorbed state, and the total gas content was lower than that in the overpressured area inside the basin. The shale demonstrated a high brittleness index, and its mechanical properties were generally favorable for subsequent fracturing stimulation. (2) Preservation conditions were the prerequisite for normal-pressure shale gas enrichment. The in-situ stress field was the critical determinant for its high productivity. The complexity of the fracture network was the key to determining the variations in single-well production. (3) The production of normal-pressure shale gas wells underwent three stages: controlled pressure flow in the initial stage, enhanced drainage in the middle stage, and artificial lifting in the late stage. This process exhibited typical characteristics, including a long drainage period, high flowback rate, low gas-liquid ratio, strong stable production capacity under low pressure, and a gentle production decline. The research findings provide important theoretical value and practical guidance for deepening the understanding of normal-pressure shale gas accumulation mechanisms, optimizing development technologies and strategies, and promoting the expansion of China’s shale gas resources into normal-pressure areas.关键词：Southeastern Chongqing;Wulong block;Wufeng-Longmaxi formation;normal-pressure shale gas;geological characteristics;production patterns123|298|0更新时间：2026-05-09
- 摘要：The Dingshan block in the Qijiang shale gas field has abundant shale gas resources and great potential for production increase. However, due to the combined influence of geological factors such as complex structures, faults, and in-situ stress, gas well productivity varies significantly. The favorable production and construction units are not yet clear, and the design of targeted development technical policies is difficult, posing significant challenges for achieving overall efficient development. Through detailed reservoir characterization, seven geological factors were selected, including structure, fractures, burial depth, formation dip angle, gas content, formation pressure coefficient, and in-situ stress, to establish zoning evaluation criteria. On this basis, combined with the analysis of the main controlling factors of productivity and zone-specific investment-benefit calculations, zone 2 and zone 3 were identified as favorable areas for production and construction. An integrated technology of geological modeling, fracturing simulation, and numerical simulation centered on “natural fracture + hydraulic fracture” coupled propagation simulation was adopted to simulate the horizontal and vertical propagation patterns of hydraulic fracturing fractures under different stimulation scales. An embedded discrete fracture model (EDFM) was constructed, and numerical simulation models of EDFM were established for different zones. Through the integrated technical-economic evaluation, well pattern deployment schemes with different target window positions, horizontal well orientations, well spacings, and horizontal section lengths were designed, and differentiated development technical policies for different zones were optimized and formulated. The results showed that under the current development conditions, economic and effective development could be achieved in zone 2 and zone 3. The reasonable horizontal well traverse layers were the 12th to 32nd sublayers, with a horizontal section length of 1 900-2 100 m, an angle between the horizontal well and the maximum horizontal principal stress of 60°-85°, and a well spacing of 300-350m. Well spacing could be appropriately increased by 50-100 m in fracture-developed areas and near existing wells. The research findings provide technical support for the formulation of production and construction plans for zone 2 and zone 3 in the Dingshan block, and offer a feasible technical approach and method for efficient shale gas development under complex geological conditions.关键词：complex structural area;favorable area evaluation;integrated geological modeling-fracturing simulation-numerical simulation;technical-economic integration;differentiated development technical policy88|118|0更新时间：2026-05-09
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A new inversion method for water holdup of gas-water two-phase slug flow in inclined shale gas wells AI导读
摘要：Slug flow is a common flow pattern of the distribution of gas-water two-phase media in inclined shale gas wells. Monitoring the dynamics of gas-water two-phase flow under slug flow conditions, accurately inverting the distribution of gas-water media in slug flow patterns, and precisely calculating the gas-water phase holdup in wells are key foundations for guiding the accurate quantitative evaluation of production performance in shale gas wells. Based on the physical simulation experiments of gas-water two-phase flow in a laboratory well with an inclination angle of 60°, air and tap water were used as simulation fluids, with the total flow rates of 50, 100, 200, 300, 400, and 500 m3/d, and inlet water contents of 0, 10%, 20%, 80%, 90%, and 100%, respectively. Based on the capacitance array tool (CAT) for monitoring the gas-water fluid dynamics in the well, and combined with the dynamic characteristics of gas-water slug flow in inclined wells and the CAT response patterns, the identification method for the distribution of slug flow media was clarified. Consequently, a characterization model for gas-water slug flow in inclined wells was established. A new method was proposed for water holdup calculation. For the liquid slug segment, the radial midpoint projection partition area weight method was used for calculation. For the gas slug segment, it was calculated using the Gaussian radial interpolation-ellipse fitting method. Finally, based on the structure of a complete slug unit, the average water holdup of the slug unit was calculated through weighted averaging. The proposed method for calculating water holdup in slug flow was compared with existing methods, specifically regarding the characteristics of gas slug segment media distribution obtained by different inversion methods. The results showed that the relative errors of the weighted average method, the radial equal-area weight method, the radial projection midpoint area weight method, and the proposed method were all generally within 20%. Specifically, the relative error of the weighted average method ranged from -3.14% to 14.10%. For the radial equal-area weight method, it ranged from -1.77% to 16.68%. For the radial projection midpoint area weight method, it ranged from -8.57% to 10.41%, with an average relative error of 4.55%. For the proposed method, it ranged from -8.10% to 9.43%, with an average relative error of 3.99%. By combining the processing and application of monitoring data from the multiple array production suite (MAPS) in actual shale gas wells in the Sichuan Basin, it was proved that the water holdup calculation model established in this study could accurately characterize the dynamics of gas-water two-phase flow in inclined shale gas wells, effectively supporting the evaluation of their production performance.关键词：shale gas well;Gas-water two-phase;Slug flow;media distribution inversion;Water holdup80|151|0更新时间：2026-05-09 - 摘要：During shale hydraulic fracturing, strain evolution exacerbates physical damage, leading to differentiated permeability changes across reservoir regions. Variations in mineral composition and microstructural heterogeneity in shale contribute to creep characteristics, leading to time-dependent reservoir deformation and reduced fracture conductivity. Previous creep experiments on shale cores mainly focus on their mechanical properties, with few studies investigating how creep effects influence permeability evolution. Although some international researchers have examined the relationship between shale permeability and time through experiments, comprehensive studies on cores with different flow capabilities and characteristics remain lacking. In this study, the reservoir near the wellbore was divided into three zones: propped fracture zone, unpropped fracture zone, and matrix zone. Using actual downhole shale cores, the reservoir characteristics of each zone were identified. A testing device and methodology for coupling creep effects and permeability were established. By analyzing the time-dependent evolution of core physical parameters, the mechanisms and variation patterns of permeability damage induced by creep effects in shale propped fractures, unpropped fractures, and the matrix were investigated. The results showed that the permeability of propped fracture cores, unpropped fracture cores, and matrix cores all exhibited an exponential decay with increasing effective stress duration, characterized by an initial rapid decline followed by a gradual slowdown. The permeability decay rate increased with effective stress, with the fastest decline in unpropped fracture cores, followed by propped fracture cores, and the slowest in matrix cores. Specifically, under an effective stress of 25 MPa for 108 h, the permeability of matrix, propped fracture and unpropped fracture cores decreased to 44.07%, 4.21%, and 1.55% of their initial values, respectively. Under 45 MPa for the same duration, the corresponding values decreased to 9.28%, 3.81%, and 1.02%. The homogeneous pore structure (with highly uniform pore size, shape, and distribution) enabled the external effective stress to be evenly distributed throughout the core. Under low-stress conditions, this uniformity prevented pore collapse or fracture propagation due to local stress concentration. Consequently, the permeability attenuation in matrix cores was relatively minor under low effective stress conditions. Based on physical simulation, this study effectively reveals and clarifies the influence mechanisms of creep effects on permeability in different shale reservoir zones under varying stress conditions.关键词：shale gas;effective stress;permeability dynamic evolution;creep effect;fracture zoning45|17|0更新时间：2026-05-09
- 摘要：During the rolling development of shale gas reservoirs, fracturing of new wells can easily cause inter-well interference with neighboring wells, severely affecting the development performance of both existing and new wells. However, there is currently a lack of quantitative, accurate, and effective risk evaluation and prediction methods for inter-well interference, making it difficult to effectively avoid gas wells highly susceptible to inter-well interference when formulating infill drilling plans. Therefore, a shale gas inter-well interference risk evaluation model was established based on machine learning methods, enabling quantitative evaluation of inter-well interference risk and effectively helping shale gas wells achieve their maximum production capacity. First, the main controlling factors that had the greatest impact on inter-well interference were identified, and a data processing method that could effectively improve data quality was established to construct the modeling dataset. Then, the inter-well interference risk level evaluation model was established by combining K-Means clustering algorithm and Spearman correlation analysis method to qualitatively evaluate the inter-well interference degree for affected gas wells. Finally, the inter-well interference risk level prediction model was established based on the results of the risk evaluation model and combined with the K-nearest neighbors (KNN) algorithm, achieving quantitative prediction of inter-well interference risk for new wells or wells that had not yet experienced interference. Additionally, the influence degree of each factor on inter-well interference was quantified based on the model's calculation results. The results indicated that in the X shale gas reservoir, the proportions of wells corresponding to low, relatively low, medium, relatively high, and high levels of inter-well interference were 27.48%, 30.39%, 20.59%, 16.67%, and 4.90%, respectively. The accuracy of the inter-well interference risk prediction model was 90.48%. The daily gas production of parent well before interference had the greatest impact on shale gas inter-well interference. Compared with the traditional data processing methods, the data processing method proposed in the study can improve the model accuracy by 14.29%, providing a reliable method for the quantitative prediction of inter-well interference risk in shale gas wells.关键词：shale gas;inter-well interference;risk evaluation and prediction;machine learning;K-Means clustering algorithm;KNN classification algorithm103|197|0更新时间：2026-05-09
- 摘要：The third sand group of the first member of the Shahezi Formation in block J is an ultra-low porosity and ultra-low permeability reservoir. While large-scale fracturing stimulation has been applied to enhance single-well productivity, the stimulated wells vary significantly in both initial and cumulative production and show weak correlation with reservoir physical properties and stimulation scale. The main controlling factors of productivity remain unclear, making the economic and effective development of the gas reservoir challenging. The development of the gas reservoir was divided into four stages to analyze the influencing factors of productivity. At the current stage, the main controlling factors of gas well productivity were stress sensitivity, water lock, and variable threshold pressure gradient. By integrating these three factors, a productivity prediction model for fractured horizontal wells was established. The model was solved using the Newton-Raphson method, and the prediction parameters, process, and results were visualized through MATLAB programming. Finally, the model was validated using actual production data from the gasfield, and a sensitivity analysis was conducted. The results showed that in a fractured horizontal well, not all fractures exhibited the same production rate and pressure. Instead, they gradually decreased from the well ends towards the middle, while fractures at symmetrical positions had identical production rates and pressures. Additionally, the pressure, permeability, and threshold pressure gradient varied with both location and time. Considering the combined effects of these factors, the new productivity equation predicted a reasonable production rate of 4.03×10⁴ m³/d, with a relative error of -0.55% compared to the actual initial production of the gas well. Gas well productivity was positively correlated with effective reservoir thickness, permeability, number of fractured stages, fracture half-length, and fracture conductivity. The quality of reservoir physical properties plays a decisive role in gas well productivity. Furthermore, reasonable fracturing parameters are beneficial for improving gas well productivity. Accurately predicting the productivity of fractured horizontal wells is an important basis for parameter optimization in development plans and design, providing important guidance for reasonable production allocation during the development process.关键词：ultra-low permeability gas reservoir;productivity prediction;Newton-Raphson method;water lock;variable threshold pressure gradient;stress sensitivity93|282|0更新时间：2026-05-09
- 摘要：Distributed temperature sensing (DTS) technology is widely applied in intelligent monitoring of production dynamics in oil and gas wells. To address the challenges in quantitatively analyzing oil-water two-phase flow profile in horizontal wells, a temperature profile prediction model applicable to oil-water two-phase flow in horizontal wells was constructed, comprehensively considering multiple micro-thermal effects, including the Joule-Thomson effect. Simulation and sensitivity analyses of the temperature profile of a reservoir horizontal well were conducted. Meanwhile, the particle swarm optimization (PSO) algorithm was used to establish a DTS data inversion model, innovatively enabling the inversion of multi-dimensional unknown downhole parameters based on a single DTS data source, thereby achieving a quantitative interpretation of the oil-water two-phase flow production profile in horizontal wells. The results showed that: (1) The main influencing factors of the temperature profile in oil-water two-phase horizontal wells, ranked by impact degree from high to low, were single-well production (Q)> permeability (k)> water cut (FW)> wellbore radius (Rw)> crude oil density (ρo)> damage zone radius (Rd)> reservoir thermal conductivity (Kt). (2) Single-well production, permeability, and water cut were the key dominant factors affecting the temperature profile. When inverting measured DTS data, formation permeability could be prioritized as the core target parameter for inversion, and secondary factors could be set as fixed values or assigned reasonable ranges to simplify the problem. (3) By using the PSO inversion model to invert the DTS temperature data of the field well, the production positions of the two-phase fluids could be accurately identified. The interpreted liquid production profile obtained from inversion showed high consistency with field production logging tool (PLT) test results, with a mean absolute error of the average liquid production per section of less than 10%, fully verifying the reliability of the PSO inversion model. Future research can focus on enhancing the model’s depiction of complex flows and expand toword multiphase flow application.关键词：production profile;inversion method;distributed temperature sensing;particle swarm optimization algorithm;two-phase flow in horizontal well;sensitivity analysis65|49|0更新时间：2026-05-09
- 摘要：During the ultra-high water cut development stage, the remaining oil in the reservoir is scattered, and the adaptability of the existing injection-production well pattern to the oil-water distribution system gradually decreases, resulting in poor development performance. To solve this problem, a well pattern reconstruction method combining existing wells and new wells was proposed, which specifically included five steps. (1) Based on reservoir physical properties and the heterogeneity characteristics of oil-water distribution, the reservoir was divided into multiple irregular injection-production units using cluster analysis. (2) For each irregular injection-production unit, the production wells were deployed at the center of the remaining oil reserves, and a quantitative calculation method for the reserve center was established. (3) Using the grid search algorithm, with the maximization of recoverable remaining oil reserves controlled by the injection-production unit as the optimization objective, the candidate well locations for injection wells in each irregular injection-production unit were determined. Taking the minimum inter-well distance as the constraint, the injection well deployment scheme for the entire reservoir was finally determined through gradual thinning optimization of injection wells. (4) Considering the overall cost of well pattern reconstruction, an evaluation system for the matching degree between the ideal reconstructed well pattern and the existing well pattern was established. Existing wells with high matching degree were directly utilized, partially matching existing wells were sidetracked and modified, and a small number of new wells were additionally deployed to construct a new type of efficient reconstructed well pattern system. (5) The fluid production of each unit was allocated based on the proportion of remaining oil reserves controlled by each irregular injection-production unit, and the water injection rate of each injection well was allocated based on the core principle of injection-production balance. The method was applied to the Nanguan 3-4 reservoir in the western area of Gudao. Numerical simulation results showed that compared with the original well pattern under the same cumulative injection-production volume, the comprehensive water cut of the reservoir after reconstruction decreased by 0.94%, and the recovery efficiency increased by 4.87%. The study shows that the well pattern reconstruction method is scientific and feasible, providing theoretical support and technical reference for well pattern adjustment in ultra-high water cut reservoirs.关键词：ultra-high water cut reservoir;well pattern reconstruction;cluster analysis;irregular injection-production unit;recovery efficiency73|109|0更新时间：2026-05-09
Oil and Gas Development
- 摘要：CO2 flooding is an important component of carbon capture, utilization, and storage (CCUS), effectively improving crude oil recovery and CO2 storage rates. However, conventional liquid CO2 transportation and injection technologies face problems such as strong geographical limitations, long transportation distances, and difficulties in source-sink matching, especially in remote oilfields, leading to rising transportation costs and reduced flooding efficiency. Therefore, it is urgent to develop new low-cost CO2 transportation and injection technologies. By systematically studying the fundamental principles and process characteristics of dry ice (solid CO2) sublimation, a dry ice sublimation gas phase injection process was developed, centered on “dry ice transportation, sublimation reaction, heating and temperature regulation, compression and pressurization, and injection system”. Additionally, technical and economic feasibility evaluations were conducted, and a field test was carried out in well H1P2, Hongzhuang Oilfield, Qintong Sag, Subei Basin. The research results showed that the dry ice sublimation gas phase injection technology could realize efficient conversion of dry ice to gas-phase CO2 at temperatures below 35 ℃. The pressure was increased from 0.1 MPa to the injection pressure through multi-stage compression, and then it was injected into oil wells for huff and puff to enhance oil production, demonstrating technical feasibility. The economic break-even transportation distance for traditional liquid CO2 injection and dry ice sublimation gas phase injection technology was 636.82 km. Compared with liquid CO2 injection technology, an average of 20 kWh of energy consumption per ton of dry ice injected could be saved, resulting in good economic benefits. Well H1P2 sublimated a total of 60 t of dry ice, cumulatively injecting 30 456 m3 of gas-phase CO2. The comprehensive water cut decreased from 95% to 78%, and the daily oil production increased from 0.60 t to a maximum of 3.08 t, achieving efficient utilization and geological storage of CO2. The dry ice sublimation gas phase injection technology fundamentally addresses the limitations of liquid CO2, such as restricted transportation distance, poor regional adaptability, and high difficulty in source-sink matching. Next, by controlling the sublimation rate, optimizing energy utilization, and improving economic efficiency, the application scope of CCUS technology can be expanded, and the large-scale deployment and application of CCUS technology can be further realized, thereby providing important support for achieving the goal of carbon neutrality and green low-carbon development.关键词：dry ice sublimation;gas phase injection;CO2 flooding;process technology;phase transition theory82|117|0更新时间：2026-05-09
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Risk level prediction model for casing deformation and frac-hit in deep shale gas horizontal wells AI导读
摘要：During hydraulic fracturing of deep shale gas in the Sichuan Basin, fracturing stages near fault and fracture zones are mostly treated with conservative control measures to reduce the risks of casing deformation and frac-hit, but this frequently leads to a significant decline in production. To effectively control these risks while maximizing the estimated ultimate recovery (EUR) of a single well, accurate risk identification and prediction are urgently required. Based on monitoring and fracturing construction data, the risks of casing deformation and frac-hit in 2 156 fracturing stages in the Y well area, southern Sichuan, were systematically classified and calibrated for risk levels. Key geological characteristics—fault fracture zones, microscopic natural weak planes, rock mechanical properties, and in-situ stress—were statistically analyzed. Statistical analysis was further employed to reveal the influence patterns of different geological parameters on risks, and, for the first time, a particle swarm optimization–backpropagation neural network was introduced to construct prediction models for casing deformation and frac-hit risks, with geological parameters as inputs and risk levels as outputs. The results indicated that casing deformation and frac-hit risks were primarily controlled by the distribution of fault fracture zones, whereas microscopic natural weak planes, rock mechanical properties, and in-situ stress significantly influenced risks by altering hydraulic fracture propagation directions and local stress distribution. Validated with 80% of the data as the training set and 20% as the test set, the prediction model achieved accuracies exceeding 83% for both casing deformation and frac-hit risks, demonstrating good fitting performance and generalization capability. Based on the prediction results, engineering control measures were developed, forming an integrated method of “pre-fracturing risk prediction—fracturing design optimization”. Field application results showed that this method effectively mitigated the risks of casing deformation and frac-hit, while significantly increasing the EUR per kilometer of a single well, achieving both risk control and production enhancement. The findings provide a new method for risk prediction in deep shale gas fracturing and offer a reference for optimizing fracturing design.关键词：deep shale gas;casing deformation;frac-hit;risk level prediction model;particle swarm optimization-backpropagation neural network;engineering control measures77|74|0更新时间：2026-05-09 -
Study on asymmetric propagation mechanisms of multi-cluster hydraulic fractures in shale reservoirs AI导读
摘要：In studies of multi-cluster hydraulic fracture propagation patterns, traditional research has emphasized inter-cluster competitive and unbalanced propagation caused by stress shadowing effects. However, theoretical analysis and field monitoring reveal that unbalanced propagation should also include the concept of spatial asymmetry, especially as fracturing processes evolve toward dense-cluster spacing and extreme limited-entry perforation techniques. The spatially asymmetric propagation of hydraulic fractures significantly affects the identification of effective stimulated volume, assessment of inter-well interference, and optimization of extreme limited-entry perforation techniques. Taking the Lianggaoshan Formation shale oil in the Fuxing block as an example, this study established an asymmetric propagation model for multi-cluster fractures in horizontal wells with dense-cluster spacing using a three-dimensional discrete lattice simulation method. The model precisely characterized the spatial evolution of hydraulic fractures , analyzed sensitivity factors influencing symmetry, and proposed optimization strategies. The results showed that: (1) Stress shadowing between fractures led to asymmetric propagation and complementary morphologies. As cluster density increased, asymmetric propagation became more pronounced, primarily in middle clusters, consistent with microseismic monitoring results. (2) As the pad fluid changed from low viscosity to gelled fluid, the asymmetry index showed a decreasing trend, and the equilibrium index showed a significant increasing trend. Increasing pad fluid viscosity enhanced fracture initiation and propagation uniformity while reducing asymmetry to some extent. However, severe fracture deflection occurred and complexity increased, limiting fracture length and requiring further scale enhancement. (3) Limited-entry perforation significantly improved initiation uniformity but exacerbated asymmetry, with severe deflection in middle-cluster fractures, particularly when cluster spacing was ≤6 m. However, when cluster spacing was ≥8 m, limited-entry perforation not only enhanced initiation uniformity but also effectively reduced the asymmetry of hydraulic fractures. In subsequent operations, based on full consideration of symmetry and uniformity, cluster spacing, fluid viscosity, and injection rate should be reasonably configured, supplemented by temporary plugging and limited-entry perforation techniques, to improve the stimulated volume of the hydraulic fracture network. This study provides a novel perspective on asymmetric fracture propagation for optimizing multi-cluster fracturing and perforation design in unconventional reservoirs.关键词：shale;hydraulic fracturing;asymmetric propagation;three-dimensional discrete lattice method;stress shadow;Lianggaoshan Formation101|66|0更新时间：2026-05-09 - 摘要：In recent years, volume fracturing has become a method for shale oil production enhancement. The effectiveness of proppant support during the fracturing process directly affects the post-fracturing results. The shale oil reservoir in the second member of the Funing Formation (hereinafter referred to as the Fu-2 member) in the Huazhuang block, Subei Basin exhibits significant vertical heterogeneity and poses challenges for sand addition, which in turn hampers proppant migration and affects stimulation effectiveness. To address these issues, physical model experiments were conducted to clarify fracture types, widths at different levels, and corresponding proppant particle sizes. The feasibility of using quartz sand to replace ceramic proppant was explored through laboratory proppant conductivity experiments. On this basis, the optimization of sand laying procedure was carried out to reduce the construction difficulty and improve stimulation performance. The results of the physical model experiments showed that the shale oil reservoirs in the Fu-2 member of the Huazhuang block comprised three types: main fractures, first-level bedding fractures, and second-level bedding fractures. The corresponding fracture widths were 4.375, 1.285, and 0.625 mm, respectively. 100-200 mesh and 70-140 mesh proppants could enter the main fractures, first-level bedding fractures, and second-level bedding fractures, while 40-70 mesh proppants could only enter the main fractures and first-level bedding fractures. Laboratory conductivity experiments indicated that the conductivity of quartz sand could be improved by increasing the sand mass concentration, thereby replacing ceramic proppant to achieve proppant cost reduction. The results of sand laying procedure optimization showed that adopting the strategy of "first settling and bridging + subsequent long-distance migration + tail high conductivity near the wellbore", and implementing a construction mode of high flow rate, variable viscosity, and high sand-to-liquid ratio—using 40-70 mesh quartz sand for bridging and tailing with a sand laying ratio of 40-70 mesh quartz sand to ceramic proppant of 2∶1—was beneficial for improving fracture proppant profile morphology and enhancing fracture conductivity. This method was applied in the field at well HY7H, successfully completing 32 stages with stable operation pressure. Continuous sand addition in medium-to-long slugs was achieved, increasing the sand addition intensity of this well to 4.7 t/m, with a post-fracturing peak daily oil production of 52.3 t and a current cumulative oil production of 1.3×104 t.关键词：shale oil;fracture;proppant;conductivity;sand laying procedure63|181|0更新时间：2026-05-09
- 摘要：During operation, subsea pipelines are affected by the internal medium, resulting in corrosion defects of varying degrees on the inner surface, which reduce the pressure-bearing capacity and may lead to pipeline rupture or even leakage. Analysis of subsea pipeline corrosion failure cases has shown that point corrosion is more common than uniform corrosion. However, current corrosion assessment standards and specifications mainly target uniformly corroded subsea pipelines of medium to low strength, and a comprehensive evaluation system for point corrosion has not yet been established. A corrosion pipeline model was established using nonlinear finite element analysis, and the results were compared with those from blasting experiments. The comparison indicated that this method produced more stable results with less variation in error than those based on standard specifications. A subsea pipeline made of X60 steel in the East China Sea was selected as the research object, and single and double point corrosion pipeline models were established using Abaqus software. The failure modes and processes under internal pressure were analyzed, along with the effects of parameters such as corrosion depth, corrosion diameter, and double point corrosion axial spacing on the residual strength of the pipeline. The calculation results showed that pipelines with point corrosion failed as a whole, with the inner layer nodes at the corrosion site showing the fastest stress variation and yielding first. The equivalent stress at these inner layer nodes was significantly higher than that at the middle and outer layer nodes. Corrosion depth and diameter jointly affected the residual strength of point corrosion pipelines. As these two factors increased, the failure pressure of double point corrosion pipelines gradually decreased, with increasingly pronounced changes. In addition, the failure pressure of double point corrosion pipelines was positively correlated with axial spacing, with a significant impact on failure pressure when the spacing was small. As the spacing increased, the failure pressure of the pipeline gradually stabilized. The research results can provide guidance for accurate evaluation of the residual strength of corroded subsea pipelines in the East China Sea, and lay a theoretical foundation for corrosion protection and safety assessment of pipelines in this region.关键词：subsea pipeline;point corrosion;failure pressure;residual strength;nonlinear finite element analysis69|38|0更新时间：2026-05-09
Engineering Techniques
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