Oil shale in the Sinopec exploration areas is abundant and serves as an important strategic reserve and supplementary energy source for the country. Accelerating the exploration and development of oil shale is crucial for improving China’s energy structure and ensuring national energy security. To achieve large-scale exploration and cost-effective development of oil shale, the technologies of in-situ exploitation field tests successfully conducted both domestically and internationally were reviewed and summarized. Based on this review, the characteristics of test areas, geological and engineering adaptability, and selection layer requirements were analyzed. It was concluded that field pilot tests of Shell’s electric heating method, Jilin Zhongcheng Company’s in-situ fracturing chemical retorting technology, and Jilin University’s local chemical reaction-based in-situ pyrolysis technology have been successfully carried out. However, the maturity and feasibility of two technologies in China need to be further studied and validated, and the adaptability of existing in-situ exploitation technologies to deep oil shale remains unverified. The technical characteristics, geological resource conditions, and exploitation engineering conditions of in-situ oil shale exploitation were reviewed and analyzed. Based on the key factors restricting in-situ exploitation of oil shale in China and the heating method, four geological parameters, six engineering parameters, and classification evaluation limits were determined. Additionally, the weights of each parameter were assigned according to the degree of constraints on in-situ exploitation and utilization of oil shale. A two-factor evaluation model of geological and engineering for identifying favorable areas for in-situ oil shale exploitation was then established, leading to the selection of 15 Class Ⅰ favorable areas in Sinopec exploration areas and adjacent areas. The effects of key factors, including roof and floor, fractures, and movable water, on the selected favorable areas were further analyzed. Through comprehensive evaluation, four target areas were selected: the Xunyi mining area on the southern margin of the Ordos Basin, the Shanghuangshan Street mining area on the southern edge of the northern piedmont of the Bogda Mountains, the Dianbai mining area in the Maoming Basin, and the Fushun mining area in the Fushun Basin.

Shale oil resources in the Subei Basin show significant potential. The second and fourth members of the Funing Formation (hereafter referred to as Funing Member 2 and Funing Member 4) are the main target layers for exploration. These layers are characterized by substantial thickness, wide distribution, high content of brittle minerals, well-developed laminated structure, and favorable organic matter types, with typical geological features, including low to medium total organic carbon (TOC), complex tectonics and lithology, and developed faults/fractures. Since 2011, Jiangsu Oilfield has strengthened basic research and exploration practices, leading to the establishment of the theory of differential enrichment of shale oil in complex fault blocks with low to medium TOC. Key technologies for exploration and development have been integrated and innovated, green and low-carbon development models have been explored, and significant breakthroughs have been achieved in shale oil exploration of Funing Member 2 and Funing Member 4 in the Gaoyou Sag. However, there are still many challenges, such as an unclear understanding of the patterns of shale oil enrichment and high yield, insufficient adaptability of engineering technologies, undefined technical policies for cost-effective development, and high development costs. Main approaches to achieving large-scale production and cost-effective development of shale oil include: deepening the fundamental research on the main controlling factors of shale oil enrichment and high yield, tackling main challenges and advancing key technologies, optimizing integrated organizational management and operation mechanisms, and maximizing the drilling success rate in high-quality reservoirs, the utilization rate of shale oil reserves, and the recovery efficiency to further reduce costs and improve efficiency.

The Subei Basin is characterized by a complex structure and well-developed faults. The shale in the second member of the Funing Formation has relatively low organic matter abundance, with a total organic carbon (TOC) generally below 1.5%. This shale exhibits diverse lithofacies types, complex pore structures, strong reservoir heterogeneity, and significant lateral variations in pressure coefficients. Using the shale oil reservoir in Block H of the second member of the Funing Formation in the Subei Basin as an example, this paper analyzed the characteristics of regional logging responses based on the results of rock physics experiments. By integrating conventional and specialized logging methods, a logging interpretation model was developed to evaluate the lithology, reservoir properties, oil content, mobility, and fracability of the shale oil reservoir. The model’s calculations aligned well with core analysis results. Building on this, sensitive parameters were optimized to establish evaluation and classification standards for the shale oil reservoirs in the block, and a comprehensive “sweet spot” evaluation of the reservoir was conducted. Exploration practices involving multiple wells have verified that this logging evaluation technology is regionally adaptable. It effectively classifies shale oil reservoir types, supports the optimal selection of “sweet spots”, and provides reliable technical support for the exploration and development of shale oil in the Subei Basin.

The shale lithofacies in the second member of the Funing Formation (hereafter referred to as Funing Formation Member 2) in the Gaoyou Sag of Subei Basin exhibits significant heterogeneity, with complex lamination types that are challenging to quantify using well logging, thus limiting the identification of favorable “sweet spots” for shale oil. Therefore, this study investigates the methods for quantitative characterization of shale lamination types and their development in Funing Formation Member 2 of Gaoyou Sag, by integrating data from core thin sections, whole rock diffraction, elemental logging, and well logging, based on the climatic and environmental evolution during different sedimentary stages. The results show that shale lamination types mainly include quartz-enriched, clay-enriched, calcite, and dolomite bands. Influenced by ancient climatic evolution, the proportions of different lamination types vary across intervals, and the vertical superposition and coupling of these lamination types lead to differential shale oil enrichment, with more developed laminations corresponding to higher oil enrichment. During the deposition of intervals Ⅴ-6 to Ⅴ-10, the sediments exhibit a high aridity index, low Sr/Cu ratio, significant variation in the Sr/Ba ratio, and high V/(V+Ni) ratio. These characteristics suggest a strongly reducing, semi-arid to arid saline water environment with fluctuating water depths and periodic variation in lake nutrients. Saline stratification and diagenesis facilitate the development of abundant bright calcite layers, fibrous calcite layers, and dolomite layers, providing favorable reservoir properties for shale oil. During the deposition of intervals Ⅴ-1 to Ⅴ-5, the Sr/Cu ratio increases significantly while the aridity index decreases. The overall environmental characteristics indicate a strongly reducing, arid saline water environment. The shale is predominantly composed of clay-rich to sandy-mixed lithology, with clay-enriched layers and clay-rich laminations as the dominant lamination types. Due to the influence of recrystallization degree, the proportion of bright calcite layers decreases while the proportion of mudstone-like calcite layers increases. During the deposition of intervals Ⅳ-5 to Ⅳ-8, the Sr/Cu ratio exhibits a periodic variation of “decrease followed by increase”, indicating a decrease in lake water salinity. The lithology primarily consists of clay-rich to sandy-mixed shale, with the development of clay-enriched layers, clay-rich laminations, bright calcite layers, fibrous calcite layers, and dolomite layers. These intervals demonstrate excellent reservoir properties and are regarded as high-quality sweet spot layers for shale oil. During the deposition of intervals Ⅳ1-Ⅳ4, the Sr/Cu ratio increases, indicating intensified arid conditions. The climate characteristics suggest a strongly reducing, arid saline environment. The recrystallization degree of calcite is higher, leading to the development of bright calcite, fibrous calcite, and dolomite layers. Additionally, the proportion of mudstone-like calcite layers increases, indicating a higher overall carbonate mineral content influenced by the depositional environment. During the deposition of the subinterval Ⅲ, the climate alternates between humid and arid conditions, with a higher degree of calcite crystallization and the development of bright calcite layers. Subintervals Ⅱ and Ⅰ exhibit a significant decrease in Fe/Mn and Sr/Ba ratios, indicating intensified humid conditions. Water depth increases, and the shale gradually transitions to blocky structure. The content of gray and muddy minerals decreases, limiting the development of gray and muddy laminations. The study further confirms a positive correlation between the degree of shale lamination development and shale oil enrichment. Based on the geological characteristics of the shale lamination distribution, further analysis was conducted using methods such as edge detection from electrical imaging well logging and shale deposition rate calculation. The study identified intervals Ⅳ-3 to Ⅳ-7 and Ⅴ-6 to Ⅴ-8 in Funing Formation Member 2 as having well-developed laminations and higher total organic carbon (TOC) compared to other intervals, marking them as vertical shale oil sweet spot layers. The image edge detection method using electrical imaging well logging offers high accuracy for shale bedding identification and is suitable for detailed geological evaluation of vertical shale oil sweet spot layers in different blocks. Furthermore, as the climate change during shale deposition becomes more frequent and the sedimentation rate varies more drastically, the vertical heterogeneity and lamination development of shale increase. Thus, sedimentation rate variations can serve as an indicator of shale lamination development. An analysis of stratigraphic cycles in the Huazhuang area's Funing Formation Member 2 revealed that natural gamma MTM spectrum analysis of well Huaye 7 identified eight dominant frequencies, corresponding to cycle thicknesses of 39.84, 11.76, 9.43, 4.20, 3.19, 2.32, 2.13, 1.82 m. The ratio of cycle thicknesses is 21.91:6.47:5.19:2.13:1.76:1.28:1.17:1.00, which is close to the theoretical cycle ratio of 21.32:6.58:5.26:2.74:2.00:1.21:1.16:1.00 for this period. Therefore, the shale deposition process of the Funing Formation Member 2 is controlled by the Milankovitch astronomical cycle. The optimal sedimentation rate for this interval was determined to be 10.8 cm/kyr. Using this optimal rate, the eCOCO statistical method was applied to track and analyze sedimentation rate variations in the Funing Formation Member 2. The results indicate significant differences in sedimentation rates among different sub-layers of the Funing Formation Member 2 due to the influence of periodic climatic fluctuations. Moreover, the degree of lamination development indicated by the sedimentation rate variation correlates well with the overall proportion of lamination development obtained from thin section analysis, and is consistent with the lamination development detected by imaging logging in different intervals. Consequently, this method can predict the spatial distribution of lamination development, providing guidance for three-dimensional shale oil exploration. In summary, this study provides insight on the lithological heterogeneity and quantitative logging characterization of the Funing Formation Member 2 in the Gaoyou Sag, Subei Basin. These findings contribute to the identification and evaluation of shale oil sweet spot layers, promoting shale oil exploration and development.

In the deep shale reservoirs of the southern Sichuan Basin, the development of fractures directly impacts the engineering construction and effective production of horizontal shale gas wells. Taking the shale cores in the Wufeng-Longmaxi Formation in the southern Sichuan Basin as a case study, rock physics experiments and numerical simulations were conducted to obtain the acoustic response characteristics of fractures at different scales, orientations, and fillings. The study analyzed the factors affecting the attenuation capability of acoustic waves on fractures and established a set of fracture identification and effectiveness evaluation methods for horizontal shale gas wells. The results showed that the amplitude attenuation of P-waves, S-waves, and Stoneley waves was influenced by both the fracture dip angle and fracture width, with attenuation capacity exponentially increasing with fracture width and decreasing with the dip angle. Stoneley waves were sensitive to fluid-filled fractures and could be used to identify and evaluate gas-bearing and water-bearing effective fractures. P-waves and dipole S-waves were sensitive to calcite-filled fractures, able to identify and evaluate ineffective calcite-filled fractures. The fracture identification results based on reflected wave imaging were consistent with the results obtained from imaging logging and core identification, verifying the reliability of the effectiveness evaluation method. The research findings were applied to the actual data from horizontal shale gas wells, thoroughly evaluating the fracture risk positions in horizontal shale gas wells and effectively ensuring the optimized and tailored design for fracturing segments.

Significant differences exist in the geological and production characteristics between normal-pressure shale gas reservoirs and high-pressure shale gas reservoirs. The current shale gas reserve calculation standards are primarily based on the initial investment in shale gas exploration and the production patterns of high-pressure shale gas. With breakthroughs in normal-pressure shale gas exploration in blocks such as Wulong and Daozhen in southeastern Chongqing, it is imperative to conduct targeted research on reserve calculation standards by considering the geological characteristics, technical and economic indicators, and production patterns of normal-pressure shale gas. Based on the break-even principle, this study analyzed the sensitivity of economic parameters to reserve calculation standards and developed a calculation model tailored to the characteristics of normal-pressure shale gas according to the production performance of atmospheric shale gas. Taking Wulong block as an example, the reserve calculation standards were estimated at different burial depths by incorporating technical parameters and economic factors such as investment, costs, and gas prices. The variation patterns in the calculation results were analyzed. It was suggested that the reserve calculation standards for single well in normal-pressure shale gas reservoirs ranged from 2.0×10⁴ m³/d to 5.5×10⁴ m³/d when the burial depth was 2 000 m to 7 000 m. The study of reserve calculation standards for normal-pressure shale gas provides valuable insights for revising relevant standards, facilitating the addition of proven reserves and large-scale production of normal-pressure shale gas outside the Sichuan Basin.

The Shunbei No. 4 fault zone is located in the central part of the Shuntuoguole Low Uplift. The reservoir type in this zone is a condensate gas reservoir controlled by fracture zones. This type of reservoir is rare both domestically and internationally. The phase characteristics of the condensate gas reservoir exhibit a clear north-south differentiation. In-depth research on the phase characteristics and the main controlling factors of this differentiation can provide valuable insights for the exploration and development of similar condensate gas reservoirs. This study employed various technical methods, including PVT (pressure-volume-temperature) high-pressure physical property experiments, organic geochemical analysis, and fluid inclusion analysis and testing. The results showed that the crude oil in the Shunbei No. 4 fault zone was characterized by a low freezing point, low sulfur content, and medium-to-high wax content. Within the zone, natural gas exhibited differential distribution in terms of methane molar fraction, gas-oil ratio, gas dryness coefficient, and CO₂ molar fraction. PVT experiments indicated that the reservoir was a condensate gas reservoir with a large difference between formation pressure and dew-point pressure, classifying it as an unsaturated reservoir. The critical temperature and pressure in the northern section were significantly higher than in the middle and southern sections, showing a decreasing trend from north to south. From the perspective of hydrocarbon source rocks and reservoir formation, the differential enrichment of condensate gas reservoirs in the Shunbei No. 4 fault zone is primarily controlled by multiple sources of hydrocarbon supply and multiple phases of reservoir formation.

The C-2 oilfield, located in the Bohai Bay Basin, is a fluvial-facies offshore oilfield primarily developed with horizontal wells. It is characterized by thin reservoir layers, vertically stacked multi-phase sandbodies, and rapid lateral facies transitions, leading to complex internal reservoir structures and connectivity. The combined effects of complex reservoir structures and well-seismic data make reservoir characterization challenging under sparse well patterns, hindering refined development. Conventional seismic inversion fails to meet the requirements for high-resolution prediction of thin reservoirs and detailed characterization of internal reservoir structures. To study the structural characteristics of braided river reservoirs in the oilfield, a stacking ensemble learning method based on seismic attributes was applied to predict the complex fluvial-facies reservoir structures. This approach significantly improved prediction accuracy compared to a single machine learning model. By integrating multi-dimensional information such as geology, geophysics, and reservoir dynamics, iterative optimization was conducted to further reduce the uncertainty in subsurface reservoir prediction and structural understanding. This enabled the precise characterization of the complex braided river reservoir structures in the study area, providing a basis for refined exploitation of remaining oil and potential sandbodies in the oilfield. The study demonstrates that the reservoir prediction method based on stacking ensemble learning not only enhances seismic vertical resolution, but also exhibits strong horizontal phase-control capabilities. The prediction results include sandbody stacking relationships and internal reservoir structures, making it more suitable for the prediction and fine characterization of continental fluvial sedimentary systems with rapid facies transitions and complex spatial architectural structures. This method can serve as a reference for the detailed characterization of fluvial-facies reservoir configurations during the middle and late development stages of offshore oilfields with sparse well patterns.

To investigate the influence of shale oil with different oil saturation on imbibition recovery rate, shale samples from the Jiangling sag in the Jianghan Basin were taken as the research object. Imbibition experiments were conducted to examine the variation of core imbibition curves at oil saturation of 20%, 30%, 40%, and 50% under conditions of similar and increasing permeability. Nuclear magnetic resonance (NMR) technology was used to analyze the changes in oil-phase signals within the core pores before and after imbibition. Additionally, the imbibition volume and oil displacement volume during the imbibition process were compared. The results showed that under similar permeability conditions, cores with higher oil saturation exhibited higher imbibition recovery rates. In contrast, cores with higher oil saturation had slower imbibition rates at the initial stage of imbibition and required a longer time to reach imbibition equilibrium. When permeability gradually increased, cores with higher oil saturation achieved higher imbibition recovery rates. In this case, cores with higher oil saturation also exhibited faster imbibition rates in the early stages compared to those with lower oil saturation. The hydration and expansion of shale resulted in the imbibition volume exceeding the oil displacement volume during the imbibition process. Moreover, the difference between these two volumes increased with higher oil saturation. The findings of this study provide a theoretical basis for improving shale oil recovery.

To address the issue of interwell interference caused by adjacent well fracturing and development adjustments in shale gas reservoirs, existing dynamic evaluation methods for well groups based on single wells or those ignoring fracture network connectivity are inadequate. A well test analysis model for shale gas well groups, incorporating the connectivity of fracturing network, was developed based on a variable conductivity fracture model. By discretizing the fracture network, the model equation of multi-stage fracturing well groups was transformed into linear equations and the bottom-hole pressure solution of well groups was obtained. The bottom-hole pressure solution of the well groups was compared and validated using the finite volume numerical method. Typical characteristic curve diagrams of bottom-hole pressure, both with and without connected fractures, were established. Application examples of four wells on two platforms in the Fuling shale gas field were provided. The results showed that: ① Production wells had bilinear flow (1/4 stage), linear flow (1/2 stage), unsteady crossflow, and boundary quasi-steady flow stages, while non-production wells rarely had bilinear or linear flow stages. ②Under both connected and unconnected fractures, the bottom-hole pressure solution of the well group calculated by the finite volume numerical method was entirely consistent with that calculated by the method proposed in this paper. ③ The interpretation and evaluation results of measured data from four wells on two platforms in the Fuling shale gas field were consistent with field observations, verifying the reliability and practicality of the proposed method. The findings provide technical support for calculating shale gas reservoir parameters and fracturing parameters, and evaluating interwell connectivity.

In the later stage of water injection development, the rapid increase in water content significantly degrades the development performance of water drive reservoirs. The non-uniform distribution and viscosity enhancement of polymer particle dispersed systems effectively reduce the water phase flow capacity that occupies the flow space of large pores, thereby mitigating inefficient and ineffective water circulation. Currently, studies on polymer particle dispersed phase for oil displacement are primarily based on laboratory simulations, focusing on the migration behavior of polymer particles. However, limited research has been conducted on the oil-water flow dynamics and relative permeability curves during the oil displacement process of polymer particle dispersed phase. This study first analyzed the non-uniform distribution of polymer particles in porous media and introduced the red blood cell dendritic volume fraction distribution theory from biological fluid dynamics. A viscosity characterization method was established, considering the effects of the polymer particle phase separation mechanism. Subsequently, a relative permeability model of polymer particle dispersed phase for oil displacement was developed based on fractal and percolation theories. The accuracy of the model was validated through comparisons with laboratory core displacement experiments, and the effects of various factors on the relative permeability of polymer particle dispersed phase for oil displacement were analyzed. This research holds significant value for assessing the development performance of polymer particle dispersed phase for oil displacement.

The depletion process of a gas-condensate reservoir is characterized by significant condensation phenomenon. Existing material balance methods often fail to establish a linear relationship between pressure drop and cumulative production, resulting in considerable errors in dynamic reserve evaluations. Therefore, it is crucial to study material balance methods tailored for complex multiphase flow gas reservoirs. Based on the fluid flow poromechanics of gas-condensate reservoirs, a new method for calculating dynamic reserves in gas-condensate reservoirs was established by introducing two-phase pseudo-pressure parameter and applying flowing material balance theory. In the multiphase flowing material balance method, a clear linear relationship was observed between the normalized production rate and normalized cumulative production. The analysis results showed that when the production did not reach the pseudo-steady state, the calculated dynamic reserve results would be biased. By analyzing the differences in saturation behavior across various flow regimes, a calculation method for the two-phase pseudo-pressure parameter was developed. The modified production indication curve could improve the accuracy of dynamic reserve calculations for condensate gas reservoirs. The method was applied to wells in a gas-condensate reservoir. Compared with conventional methods and the Blasingame chart fitting method, the proposed approach yielded more accurate dynamic reserve evaluations. The results demonstrate that the proposed calculation method enhances the accuracy of dynamic reserve evaluations for gas-condensate reservoirs and supports timely adjustments to development plans in the field.

In fault block G76 of the Jidong Oilfield, issues such as increased injection pressure and difficulty in water injection have arisen during the waterflooding development process. To analyze the variation in reservoir properties during water injection, high multiple waterflooding experiments were conducted on cores using two-dimensional nuclear magnetic resonance (NMR) technology. Laser particle size analysis was performed on the target reservoir cores to obtain particle size distribution, and X-ray diffraction (XRD) analysis was conducted to determine mineral content proportions. High multiple waterflooding experiments based on NMR technology were carried out to analyze reservoir property variations. The results showed that core 5-1 and core 6-1 consisted of medium sand-bearing silty fine sandstone and silt-bearing medium sandy fine sandstone, respectively, with high contents of fine sand, silt, and clay minerals. The relative permeability of the water phase and NMR porosity initially increased with cumulative water injection to a high value and then declined. In the NMR T₂ spectrum, the right endpoint values and the curves corresponding to medium and large pores shifted left as water injection increased. In the two-dimensional spectra, the free water signal intensity increased with cumulative water injection. As the injected water transitioned from bound water to a cumulative injection of 500 PV, the bound water signal continuously increased. When the cumulative injection is beyond 500 and up to 1 000 PV, the bound water signal of core 5-1 continued to strengthen, while that of core 6-1 weakened. The study suggests that, in the early stages of water injection, weak hydration of clay minerals occurs. In the later stages, due to water flushing, fine silt particles and clay minerals in the cement may detach and migrate to pore throats, causing blockage and damage to the pore throat structure, thereby reducing water phase permeability. The findings reveal the reasons for injection difficulty and increased pressure during waterflooding in medium-low permeability oil reservoirs and provide guidance for mitigating contamination and improving the effectiveness of waterflooding development.

To investigate the variation of production decline rate at different water cut stages during oilfield development, this study explored the relationship between decline rate, water cut rise rate, and water cut based on relative permeability curves. The relationship between decline rate and water cut under injection-production balance conditions was established, followed by computational analyses on a thick oil reservoir Z and a multi-layer oil reservoir S. The results showed that, under ideal injection-production balance conditions, the decline rate at a certain water cut stage was jointly influenced by liquid production rate and irreducible water saturation. The decline rate exhibited a parabolic trend with increasing water cut and was proportional to the liquid production rate. For a given reservoir under known conditions, the magnitude of the production decline rate was primarily determined by the liquid production rate and could be controlled by adjusting parameters such as well spacing density and the ratio of injection to production wells, which affected the liquid production rate. By establishing the relationship between decline rate and water cut, factors influencing production decline are clarified, providing a basis for strategies to mitigate production decline.

Offshore heavy oil resources are abundant, driving a strong demand for thermal recovery development. Over years of practice, steam stimulation has been successfully applied to thin layer heavy oil, edge and bottom water heavy oil, and extra heavy oil. Accurately understanding the flow characteristics and development patterns of steam stimulation in offshore heavy oil reservoirs with large well spacing is essential for designing, adjusting, optimizing, and enhancing production and efficiency in thermal recovery development plans. Precise evaluation of thermal recovery effectiveness and development status is also critical. The study focuses on the quantitative characterization of the actual thermal field distribution and the steam override phenomenon in the thermal fluid zone, aiming to accurately depict changes in the heating radius. It summarizes the patterns and development experiences related to production decline, validity period, production pressure difference, and associated gas in offshore steam stimulation with large well spacing. From this analysis, three decline stages and average decline rates of offshore steam stimulation are identified. Based on these findings, the study proposes a development strategy for large well spacing steam stimulation in offshore heavy oil reservoirs, using reservoir numerical simulation methods for prediction. The study recommends horizontal wells for steam injection, especially in edge water reservoirs, with well placement over 150 to 200 meters from the oil-containing boundary. High steam dryness and large-cycle injection rates are suggested to enhance formation heat utilization efficiency. It is also found that offshore large well spacing thermal recovery has an average effective period of 329 days, with a first-cycle average monthly decline rate of 13.5%. The optimal production pressure difference for wells ranges from 3.5 to 5.0 MPa. The results offer valuable insights for scaling up offshore heavy oil thermal recovery development.

The Yanchang Formation in the Ordos Basin has deposited a set of mudshales and fine-grained sandy rocks, rich in shale oil resources, with an estimated resource potential exceeding billions of tons. However, shale oil reservoirs exhibit poor mobility, shallow burial depths, the development of bedding, fractures, and faults in horizontal sections, and unknown fracture propagation patterns, making volumetric fracturing challenging. To address this, cement-encased cores of full-diameter tight sandstone-mudstone and shale from the sublayer in the seventh member of the Yanchang Formation (Chang 7) were used in actual triaxial hydraulic fracturing physical model experiments. These experiments revealed hydraulic fracture morphologies and the fracture propagation mechanism under weak stress fields in shale oil reservoirs. The experiments found that shale oil reservoirs had tight layered structures and weak bonding between rock grains, causing fracturing fluid to easily infiltrate along bedding planes. When the difference between vertical stress and minimum horizontal principal stress was less than 2 MPa, hydraulic fractures predominantly formed horizontal fractures, with the fluid primarily infiltrating along bedding planes or horizontal natural fractures. When this stress difference increased to 7 MPa, vertical cross-layer fractures appeared, forming localized steps that eventually became captured by weakly bonded bedding planes, propagating horizontally along the layers. For fracturing operations, regions with a larger difference between vertical stress and minimum horizontal principal stress, such as wellheads at hilltops, are preferred. This facilitates vertical fracture propagation, improves volumetric fracturing effectiveness in reservoirs, enhances shale oil production, and increases economic benefits.

Under the influence of fracture shear slippage and wall roughness, the fluid flow channels within the fractures are uneven, making the transport and placement patterns of proppant carried by fracturing fluids more complex. Using core samples from the Longmaxi Formation, rock fracture surfaces were obtained through splitting, and rough fracture plates were created using techniques such as stretching, stacking, and carving to construct an experimental setup for proppant transport in single-sided rough fractures. Semi-quantitative tests of sand dam morphology and quantitative tests of solid-liquid two-phase flow were conducted. Experiments on proppant transport were carried out under conditions of varying roughness, discharge, viscosity, and particle size within the uneven flow channels of rough fractures. Additionally, particle image velocimetry (PIV) / particle tracking velocimetry (PTV) tests were performed in the fracture near-wellbore area under different roughness conditions. Results showed that the flow channels in rough fractures were uneven, and the proppant placement morphology exhibited an irregular concave-like structure, influenced by dominant channels. When fluids and proppants flowed near large protrusions, their original movement direction was altered towards dominant channels. The movement direction of the proppants was also affected by the accumulated sand dam morphology. Discharge was the key factor in reducing the influence of dominant channels, where decreasing discharge could effectively plug these channels. Under varying viscosity and particle size conditions, the influence of dominant channels persisted, with viscosity and particle size mainly affecting the transport distance and accumulation pattern of the proppants. Increased viscosity or reduced particle size led to greater proppant transport distances and layered sand dam accumulation.

Shale gas reservoirs are characterized by high compactness and significant heterogeneity, with naturally low production that necessitates hydraulic fracturing technology for enhanced productivity to achieve industrial gas flow. The key to evaluating the effectiveness of fracturing operations and optimizing process parameters lies in obtaining accurate fracture network parameters. Traditional fracture monitoring techniques, such as microseismic monitoring, are costly and cannot achieve full coverage monitoring of well areas. Numerical simulation prediction models require a large number of engineering geological parameters, leading to poor prediction effects for geological data that are incomplete or missing well sections. There is an urgent need for a new method that is economically efficient in obtaining fracture network parameters. To address this, a shale gas reservoir fracture network inversion method based on deep learning was proposed. The core of this method is to quantitatively analyze the fracturing curve characteristic parameters based on the site fracturing curve data, using strongly correlated indicators of fracture network parameters as inputs and microseismic monitoring fracture network parameters (including length, width, height, and volume) as target outputs. A back-propagation (BP) neural network inversion model was established to achieve accurate inversion of fracture network parameters. The model was trained and optimized using 450 fracturing curve segments from shale gas wells in western Chongqing, with the average relative error of fracture network parameter inversion results in the test set being below 15%, which verified the feasibility of this new method for inversion of shale gas reservoir fracture networks.

Against the backdrop of continuously advancing big data technology, digitization and intelligent production management of oil and gas fields have become an inevitable trend. Shale gas wells face challenges such as liquid accumulation, sand production, and high stress sensitivity, necessitating the consideration of numerous factors during production adjustment. Traditional methods, which require extensive manual labor and exhibit low efficiency in production adjustment warnings, fail to consider multiple factors for optimal adjustment. To address this issue, considering the typical lifecycle characteristics of shale gas wells, the study divided the lifecycle into three stages: liquid unloading and gas transportation, stable production and pressure reduction, and fixed pressure and production reduction. Specific production adjustment rules tailored to different lifecycle stages were defined and six types of production adjustment indicators were proposed, including pressure drop method in stable production period, gas production per unit pressure drop method, critical sand-carrying flow rate method, critical liquid-carrying flow rate method, empirical chart method, and intermittent well-switching method. Based on these production adjustment rules and indicators, combined with field experience, an intelligent production adjustment early warning model for shale gas wells using fuzzy logic control was established. Implemented in Python, this model allows for real-time calculation of all production adjustment indicators and the fuzzy logic control algorithm as the well production dynamics change. This method has been applied in over a hundred wells in the Weirong shale gas field, reducing early warning times for production adjustments to just 30 seconds, compared to the traditional methods that require at least 5 days. The timely early warning of production adjustment needs has achieved good application results. In the future, combining remote control of oil nozzles or choke valves to adjust the production regime can provide technical support for intelligent oil and gas fields.

For offshore oil and gas jacket platforms with detected structural cracks, a methodology for structural integrity evaluation and maintenance cycle strategy formulation was developed based on engineering critical assessment (ECA) techniques. A case study was conducted on a specific jacket platform. The Morison equation was used for hydrodynamic analysis of the target platform to estimate the ultimate load of joints prone to failure. Hotspot stress assessment was performed on these joints using the finite element analysis method and linear extrapolation. Crack propagation behavior at critical joints was simulated using Paris' law, and the stress intensity factor at the crack tip was determined. Cracks were assessed using failure assessment diagrams (FAD), and the critical crack sizes were provided. Based on the relationship between critical crack depth and crack propagation, a reference maintenance cycle was proposed. The results showed that the joints connecting horizontal braces and risers of the jacket structure were prone to fatigue damage. Failure assessment indicated that failure in the crack depth direction was primarily dominated by collapse, while failure in the crack length direction may involve both collapse and fracture. For the analyzed platform, it was recommended to consider a critical crack depth of 5.3 mm and a critical crack half-width of 9.8 mm. If cracks ranging from 0.5 to 2.0 mm were detected, maintenance was recommended within 13.2 to 5.2 h. This methodology can be extended to similar offshore oil and gas platforms with detected cracks in adjacent sea areas.