In recent years, Sinopec Shanghai Offshore Oil & Gas Company has continuously carried out exploration and development practices in the Xihu Sag of East China Sea Shelf Basin. In the face of high geological uncertainties caused by sparse wells and limited data offshore and engineering difficulties brought by constrained platform space and limited coverage, along with the significant challenges of high investment and high risk in offshore oil and gas development and exceptionally complex reservoir types in the Xihu Sag, multiple engineering technologies tailored to the characteristics of offshore development have been innovatively developed. The development technology for offshore low-permeability tight gas reservoirs has preliminarily achieved balanced production in strongly heterogeneous, low-permeability tight gas reservoirs. The integrated “rolling evaluation and development” technology for offshore scattered reserves has enabled the effective utilization and cost-effective development of scattered reserves in the East China Sea. The integrated and efficient “rolling evaluation and adjustment” technology for mature areas fully considers the three objectives of rolling exploration, evaluation, and adjustment, and achieves a comprehensive and multidimensional deployment, with implementation results far exceeding expectations. The full-lifecycle enhanced oil recovery technology for offshore water-bearing gas reservoirs effectively controls the water invasion rates in edge-bottom water gas reservoirs, and significantly extends the production lifespan of gas wells. The promotion and application of these technologies enables increased oil and gas reserves, production, and efficient development in the Xihu Sag of East China Sea Shelf Basin, providing a reference for the efficient development of offshore oil and gas fields both in China and abroad. For the efficient development of low-permeability tight reservoirs in the East China Sea, effective utilization of marginal and scattered reserves, and enhanced oil recovery in conventional edge-bottom water gas reservoirs, there are still challenges in theoretical innovation and technological breakthroughs. It is urgent to tackle key technical challenges such as efficient development technologies for low-permeability tight gas reservoirs, engineering technologies for long-distance reserve development around platforms, residual gas characterization in water-bearing gas reservoirs, and integrated utilization of multiple resources in the Xihu Sag, with the aim of continuously promoting the efficient and high-quality development of oil and gas resources in the Xihu Sag of East China Sea.

To address the unclear sedimentary microfacies types and sandbody distribution characteristics in the Baoshi Formation-lower member of Pinghu Formation (hereinafter referred to as lower Pinghu member) in the Pingbei area of the Baochu slope belt, Xihu Sag, East China Sea Shelf Basin, the study employed a comprehensive approach combining paleogeomorphology, biological traces, trace element analysis, well-seismic integration, and modern depositional analogs to analyze the sedimentary microfacies types, spatiotemporal evolution, and trap models. The research indicated that the Baoshi Formation-lower Pinghu member in the Pingbei area was in the intense rift period, with a paleo-geomorphologic pattern characterized by deep depressions and high uplifts, exerting a strong control on the sedimentary system. The Baoshi Formation was sourced from magmatic rocks in the northern Hupijiao uplift, while sediment supply from the Haijiao uplift in the western lower Pinghu member gradually increased, forming a dual-provenance system. Trace element analysis indicated that the deposition of the Pinghu and Baoshi Formations occurred under an arid and hot paleoclimate in a generally suboxic, marine-continental transitional environment. Four third-order sequences were developed in the Baoshi Formation-lower Pinghu member, representing a progressive marine transgression. Integrated analysis of core facies, logging facies, biofacies, and ichnofacies revealed that the Baoshi Formation-lower Pinghu member developed three sedimentary facies (tidal delta, tidal flat facies, and marine facies) and nine microfacies (subaqueous distributary channels, sheet sands, mouth bars, tidal channels, sand flats, mixed flats, mud flats, interdistributary bays, and bay mud). The extensively developed tidal flat facies was the dominant sedimentary facies type. Dendritic flood and ebb tidal deltas, tidal channels, and tidal sand bars developed near the slope depression belt. Five sand-controlling models were identified in the Baoshi Formation-lower Pinghu member: graben-horst type, uplift-fault slope type, multiple fault slope type, transfer zone type, and flexural slope break type. Five trap types were summarized: graben-horst structural traps, uplift-fault slope structural traps, multiple fault slope structural-lithological composite traps, transfer zone structural-lithological composite traps, and flexural slope break lithological traps. Within the inner slope zone, the Pinghu and Baoshi Formations developed large-scale sand bodies under bay environments, which were prone to lithologic pinch-out controlled by flexural slope breaks. Tidal and wave reworking produced clean fine sandstones with strong compaction resistance, forming favorable “sweet spot” reservoirs. Overall, the inner slope zone possesses excellent accumulation conditions. The research findings provide clear directions for future exploration.

The development of onshore low-permeability gas reservoirs has become relatively mature. In North America, efficient development has been achieved through technologies such as horizontal wells, hydraulic fracturing, and microseismic monitoring. In the Ordos Basin and Sichuan Basin in China, adaptive technical systems suitable for local geological conditions have been established through the introduction and re-innovation of technologies. However, the recoverable reserves per well generally remain low. In contrast, the development of offshore low-permeability gas reservoirs faces challenges such as high investment, limited platform space, multiple drilling constraints, and strict environmental requirements, leading to relatively slow progress. Offshore unconventional resources, especially low- and ultra-low-permeability natural gas, are gradually becoming important alternatives to conventional resources. In the Xihu Sag of the East China Sea, low-permeability gas reservoirs account for more than two thirds of the total resources. They are characterized by great burial depth, strong heterogeneity, and poor porosity and permeability conditions, making development challenging and requiring high economic efficiency. Since the development of low-permeability gas reservoirs in the Xihu Sag of the East China Sea began in 2006, significant breakthroughs have been made in the development of low-permeability gas reservoirs in the East China Sea over nearly 20 years of exploration. Through two stages of exploratory practice, a development model with "sweet spot prediction + efficient well types + reservoir protection" as the core has gradually been developed. A technical system tailored to the characteristics of low-permeability gas reservoirs in the Xihu Sag has been established, and the core driving force for transforming difficult-to-produce resources into economically viable production has been revealed. However, the large-scale development of these reservoirs in the East China Sea still faces three major scientific and technological challenges: deepening theoretical understanding, overcoming key technical barriers, and achieving cost-effective and efficient development. To address these issues, future research and development efforts should focus on the following three aspects: (1) strengthening fundamental research to deepen theoretical understanding and establish a high-success-rate system for geological reservoir evaluation and selection; (2) overcoming key technical barriers by developing more adaptable technologies and equipment systems for the development of low-permeability gas fields in offshore areas; and (3) improving development efficiency through establishing an integrated technical and management model that supports low-cost and efficient development of offshore low-permeability gas reservoirs, encompassing offshore engineering, drilling, gas production, transportation.

A gasfield with reserves exceeding 100 billion cubic meters has been discovered in the Central Canyon on the southern slope of the Lingshui Sag in Qiongdongnan Basin. However, the northern slope shows poor oil and gas enrichment, with gas detected but no fields found. One of the key reasons is the absence of large-scale high-quality reservoirs encountered during drilling. To clarify the sedimentary evolution model and distribution patterns of high-quality sand bodies on the northern slope of the Lingshui Sag, this study integrated drilling, logging, mud logging, testing, and seismic data, using techniques such as thin section observation, grain size analysis, and physical property testing. Core facies, logging facies, and seismic facies analyses were carried out for the key strata to establish the sedimentary evolution model of Meishan Formation. Combined with reservoir microscopic characteristics and fault-sand matching, the oil-gas geological significance was clarified. The results showed that during the Meishan Formation period, sediment sources were provided by Hainan Island, and a shelf delta-submarine fan sedimentary system was developed. In the study area, the microfacies sand bodies of channels and channel-lobe complexes were relatively coarse and thick, with box-shaped or bell-shaped logging curves, and stratification and bioturbation were observed in the cores. Seismic data showed U-shaped or V-shaped low-frequency continuous parallel reflections, which served as the main exploration targets in the study area. The development of submarine fans and the differentiation of their internal sand bodies were mainly controlled by fluctuations in relative sea level, paleogeomorphic features, and the intensity of sediment supply. During the second member of the Meishan Formation (hereinafter referred to as Meishan 2) period, the relative sea level dropped, the sediment supply was abundant, and the relative accommodation space was relatively small, with A/S ≤ 1 (A representing relative accommodation space and S representing sediment supply). Sediments were transported over long distances to the continental slope, forming multiple phases of submarine fan progradation. Laterally, the development of submarine fans and the differences within their internal sand bodies were controlled by paleogeomorphology and distance from the sediment source, mainly developing in the proximal slope break zones and fault-controlled slope break zones formed by synsedimentary faults. The Meishan 2 reservoirs in the study area had porosity ranging from 8.40% to 26.24%, and permeability ranging from 0.05×10^-3 µm² to 26.49×10^-3 µm², mainly characterized by medium porosity and ultra-low to low permeability. High-quality reservoirs were controlled by late-stage reworking. Contour currents could wash, transport, and redeposit gravity flow sediments formed earlier, significantly improving reservoir physical properties. Under the general background of sand deficiency in the study area, the coupling between faults and sand bodies constrained the degree of oil and gas enrichment. Drilling results showed that oil and gas were highly active near the No.2 fault zone. The sand body enrichment zone of the No.2 fault zone was an important oil and gas target for future exploration.

The Xihu Sag of the East China Sea Shelf Basin is characterized by thick Cenozoic sediments. Extensive research has been conducted on the geological conditions and hydrocarbon accumulation of the Eocene, Oligocene, and Miocene strata, with limited studies on the Paleocene strata. Recent studies indicate that the Paleocene strata in the Xihu Sag have significant hydrocarbon generation potential and constitute an important source rock system, which plays a key role in oil and gas generation and accumulation in the Xihu Sag. To clarify the development characteristics of the Paleocene strata and their implications for oil and gas accumulation, this study analyzed data from well J-1 in the Yingcuixuan area, located in the northern slope segment of the Xihu Sag. Four lines of evidence supported that well J-1 has penetrated the Paleocene strata: ⑴ regional seismic correlation suggested that the deep layers of well J-1 exhibited medium-to-high frequency, medium-to-weak amplitude, and medium-to-low continuity reflections, with distinct stratigraphic folding. The strata below the T40 seismic reflection interface showed truncation features, which are typical seismic facies characteristics of the top of the Paleocene strata. ⑵ Lithological assemblage comparison revealed that the lower section of well J-1 contained marker layers of reddish-brown mudstone, indicating a Paleocene lake-delta depositional environment. ⑶ Palynological comparison showed that the Paleocene sporopollen characteristics in the study area were similar to those in the Changjiang Sag, both lacking marine foraminifera. ⑷ During the Paleocene, a large fault-depression structure formed, controlled by basement faults. The downthrow side of a fault provided favorable geological conditions for the formation of thick Paleocene strata. By analyzing the geochemical characteristics of the Paleocene source rocks in well J-1 and comparing them with geochemical indicators from other sags in the East China Sea Shelf Basin, it was concluded that the Paleocene strata in the Xihu Sag host medium-to-good source rocks with significant hydrocarbon generation potential. This study provides valuable guidance for oil and gas exploration deployment in the Xihu Sag. The findings suggest that the area near the depression in the Yingcuixuan area is favorable for large-scale oil and gas exploration due to the development of thick Paleocene source rocks (dark mudstone).

The Santan Deep Depression in the Xihu Sag of East China Sea Basin has favorable conditions for oil and gas accumulation, and multiple gasfields such as Y, Q, and G have been discovered, indicating abundant oil and gas resources. The key factor for accumulation and enrichment in this area is the reservoir. However, the study area experienced early deep burial, resulting in overall poor reservoir physical properties and unclear distribution of sweet spot reservoirs, which constrains the exploration process of oil and gas in the middle and deep formations. To identify large-scale high-quality reservoir zones, based on data such as thin section observation, X-ray diffraction, and physical properties, two conclusions were drawn through comparison of sedimentation, microscopic pore structures, and differences in diagenetic evolution of reservoirs in the southern, central, and northern parts of the Santan Deep Depression: (1) In terms of reservoir characteristics and diagenesis, the study area mainly consisted of low-porosity and low-permeability, ultra-low-porosity and ultra-low-permeability, and tight reservoirs, with reservoir evolution at the middle diagenetic stage B. Secondary dissolution pores were the main type of reservoir space, and chlorite film and dissolution were constructive diagenesis processes. (2) In terms of differences in reservoir physical properties, influenced by provenance, diagenesis, and geothermal gradient variations, the burial depths of the top boundaries of tight reservoirs between the southern and northern parts of the Santan Deep Depression differed. The top boundary of tight reservoirs in the southern part was buried at 4 000 m, corresponding to a temperature of 140 ℃. In the central and northern parts, the top boundary was at 4 700 m, with a corresponding temperature of 160 ℃. Compared with the Huagang Formation, Pinghu Formation reservoirs experienced stronger carbonate cementation, weaker compaction, and stronger dissolution. More high-quality reservoirs were developed in conventional reservoir units, and more effective reservoirs were developed in tight reservoirs controlled by the overpressure-induced diagenetic inhibition effects within the source. Based on the above understanding, a high-quality reservoir development model controlled by “coarse-grained facies, main channel sand bodies, and internal source overpressure” was proposed, providing important guidance for exploring large-scale oil and gas reservoirs in the middle and deep formations of the Santan Deep Depression in the Xihu Sag.

The lower member of the Pinghu Formation (hereinafter referred to as the lower Pinghu member) in the well block W of the Xihu Sag is an important oil and gas-bearing system. An accurate characterization of its sedimentary evolution patterns and reservoir distribution is critical for guiding future exploration and development. Based on core, drilling, and geophysical data, this study analyzed the sedimentary microfacies, evolution processes, and dominant controlling factors of the lower Pinghu member. The results showed that the lower Pinghu member (sand groups P12~P9) could be divided into third-order sequences, mainly comprising deltaic and tidal flat deposits influenced by tidal processes. The P12 sand group, deposited during a lowstand system tract with relatively low sea level, was primarily composed of deltaic deposits, issueed by tidal deposits. During deposition of the P11 and P10 sand groups in the transgressive system tract, sediment supply weakened and delta development was curtailed. Thus, tidal flat environments became dominant in the study area. The P9 sand group, deposited during the highstand system tract, experienced increased sediment supply, tidal flat deposition reduction, and delta progradation towards the basin. Analysis of the sedimentary evolution process clarified that sediment supply, sea level fluctuations, and the paleogeomorphology controlled the microfacies migration and evolution in the well block W. Firstly, paleogeomorphology directly controlled the depositional accommodation and determined the spatial distribution of sedimentation. Secondly, abundant sediment supply and relatively lower sea level promoted deltaic development, leading to the formation of distributary channel and mouth bar sand bodies. On the contrary, the reduction of sediment supply and rising relative sea level restricted deltaic propagation while enhancing tidal power, resulting in the development of tidal flats, tidal channels, and tidal sand bars. In the study area, the relative intensity of deltaic and tidal processes was controlled by changes in relative sea level and sediment supply. During deposition of the P12 and P9 sand groups, sufficient sediment supply and relatively low sea levels favored delta development. On the contrary, during marine transgression stage corresponding to the P11-P10 sand groups, the sediment supply weakened and the relative sea levels rose. Under such conditions, deltaic deposits were vulnerable to damage, which favored the development of tidal sediments. However, the development of deltaic and tidal flat deposits in response to changes in relative sea level and sediment supply was also controlled by paleogeomorphology. During deposition of the P12 sand group, the presence of a nose-shaped paleo-uplift in the central part of the study area limited eastward progradation of the western delta. This resulted in differences in sedimentary facies types between the east and west sides of the nose-shaped paleo-uplift during deposition of the P12 sand group. The western fault trough zone was dominated by deltaic deposits, while the eastern fault step zone was dominated by tidal deposits. During deposition of the P11-P9 sand groups, the influence of the nose-shaped paleo-uplift weakened, and the sedimentary facies types in the study area were relatively uniform (P11-P10 was mainly dominated by tidal flat deposits; P9 was mainly dominated by deltaic deposits). This study offers insights into the spatiotemporal distribution characteristics of favorable reservoirs in the study area and adjacent zones. In the western fault trough zone of the P12 sand group and in the P9 sand group, deltaic sand bodies such as channels, mouth bars, and sheet sands are the favorable sand body types, and their exploration and development should be primarily guided by the deltaic depositional model. In eastern fault step zone of the P12 sand group and in the P11-P10 sand groups, the dominant sand bodies are tidal sand bars or tidal channels extending seaward and parallel to the shoreline, and their exploration and development should follow the tidal depositional model.

Velocity spectrum picking is a crucial step in seismic data processing. Traditional velocity spectrum picking methods usually require manual intervention, which is time-consuming, labor-intensive, and prone to error. Therefore, an intelligent velocity spectrum picking method based on the YOLOv8 (You Only Look Once v8) neural network was proposed. This method transforms velocity spectrum data analysis into an image recognition task, therefore achieving automated and intelligent velocity spectrum picking. The core of this method is to convert velocity spectrum data into images, which are then input into the constructed YOLOv8 neural network model. The feature extraction network in the model learns the spatial information of energy clusters in the velocity spectrum images, and the feature fusion network fuses the extracted multi-scale features of energy clusters from shallow, intermediate, and deep layers to capture the energy cluster features in the images more comprehensively. The detection head of the model allows for refined predictions of energy cluster targets, obtaining pixel points corresponding to different picking positions in the velocity spectrum images. Then, the pixel points are converted to finally obtain the time-velocity pairs. For the exploration area GY of the Sinopec Jiangsu oilfield with developed igneous rocks and strong multiple interference, a dataset containing 1 200 velocity spectrum images was constructed. By optimizing training parameters, both the model accuracy and recall reached about 90%. The intelligent velocity spectrum picking technology based on the YOLOv8 neural network showed over 94% consistency with manually picked velocity curves in high-coverage areas, more than 90% consistency in areas above 3 500 ms, and about 92% consistency in areas with igneous rocks and fault development. Compared with traditional convolutional neural network (CNN) methods, the intelligent velocity spectrum picking technology based on the YOLOv8 neural network obtains more picking points with higher positional accuracy, and the processing time of a single velocity spectrum is only 10 ms, showing significant efficiency improvement. This technology provides an efficient and accurate intelligent solution for seismic data processing, demonstrating promising application and promotion value.

The Mahu oilfield, located in the northwestern part of the Junggar Basin in Xinjiang, is one of the largest conglomerate oilfields in the world, with reserves exceeding 1 billion tons. However, poor reservoir properties and strong heterogeneity present significant challenges to the efficient development of oil and gas resources. The key to efficient oil and gas development lies in accurately identifying reservoirs with industrial production value, those with higher productivity and relatively lower development costs. To address the complexity of oil and gas reservoir evaluation in the Mahu Sag of the Junggar Basin, this study proposed an oil and gas reservoir value (OGRV) prediction model based on ensemble learning. The study began with an in-depth analysis of the geological characteristics and exploration status of the Mahu Sag. Then, an ensemble model integrating random forest (RF), long short-term memory (LSTM), and convolutional neural network (CNN) was constructed to improve the accuracy and generalization ability of reservoir evaluation. During implementation, key feature parameters were extracted through systematic preprocessing and feature engineering. With expert knowledge, additional augmented features such as hydrocarbon humidity ratio, hydrocarbon balance ratio, and hydrocarbon characteristic ratio were incorporated. In addition, the sliding window technique was introduced to track the trend of features with depth variations, and the category information of similar wells was used as prior knowledge to enhance the model’s prediction performance. By leveraging the strengths of different models, a precise and robust reservoir evaluation algorithm was developed. It effectively identified reservoirs with industrial value in the Mahu Sag. The model yielded an F1-score of 0.847 0, accuracy of 0.772 5, and area under the receiver operating characteristic (ROC) curve (AUC) of 0.781 0. The study also investigated model interpretability in depth to help geoscientists better understand the model’s decision-making mechanisms and support more informed decision-making in oil and gas exploration and development.

The BZ condensate gas reservoir in the Bohai Sea, China, is a rare fractured buried hill condensate gas reservoir with high saturation and high content of condensate oil. The reservoir features high temperature, high pressure, ultra-low porosity, and ultra-low permeability. Due to the small difference between the fluid dew point and the pressure in the gas reservoir, it is prone to condensate oil precipitation, causing contamination in the near-wellbore zone. In the early development stage, the BZ gas reservoir pilot area was produced using natural energy. When the reservoir pressure drops below the dew point, retrograde condensation intensifies, leading to a rapid increase in the gas-oil ratio and an accelerated decline in production. Therefore, there is an urgent need for the evaluation of retrograde condensation damage and effective remediation methods. Core depletion experiments were conducted under high-temperature and high-pressure conditions using compound condensate gas to simulate retrograde condensate oil contamination. Gas-phase permeability was tested at different depletion pressure points to evaluate the degree of retrograde condensate contamination. Additionally, gas injection experiments were carried out to investigate the mechanisms of damage mitigation. Experimental results showed that as the reservoir pressure decreased, the amount of retrograde condensate in the core increased, and the effective gas-phase permeability decreased significantly. Ultimately, the resulting retrograde condensate damage to the reservoir reached 65.8% to 70.2%. Gas injection could reduce the viscosity of condensate oil, increase the volume expansion coefficient of reservoir fluids, and induce re-vaporization of retrograde condensate oil. This process reduced the amount and saturation of retrograde condensate liquid, relieved retrograde condensate blockage, and improved the effective gas-phase permeability of reservoir cores. The permeability recovery rates for N₂, associated gas, and CO₂ were 48.1%, 78.6%, and 81.7%, respectively. The final recovery rates for condensate oil reached 43.7%, 66.8%, and 69.2%, respectively. The research results provide technical support for gas injection development in the pilot zone of the BZ buried hill condensate gas reservoir. This approach effectively mitigates production decline and achieves good results, offering important guidance for the efficient large-scale gas injection development in the future.

Accurately determining hydraulic fracture parameters is crucial for guiding the design of fracturing treatments and predicting single-well production. Currently, existing production-data-based fracture parameter inversion methods struggle to obtain fracture parameters for individual fracturing stages. To address this, leveraging the ensemble Kalman filter (EnKF) algorithm, an automatic inversion method for fracture parameters of each stage in tight gas reservoirs based on gas production profile testing was developed. To balance simulation accuracy and inversion efficiency, a reservoir production numerical simulation model based on embedded discrete fractures was established using the MATLAB reservoir simulation toolbox (MRST). Subsequently, the production of each fracture stage was simulated, and the EnKF was employed to iteratively update the fracture half-length and permeability for each stage, achieving automatic inversion of fracture parameters in tight gas reservoirs based on the gas production profile. Finally, the reliability of this method was validated through a designed case study, and it was applied to invert the fracture half-length and permeability of a field horizontal well. The research results indicated that: (1) when fracture orientation and spacing were fixed, increasing both fracture length and permeability enhanced tight gas production, but their impact on fracture production varied over time. Fracture permeability significantly influenced gas production in the first three months, while fracture half-length had a greater effect on production during the middle and late stages. (2) EnKF, as a sequential data assimilation method, captured the influence of fracture half-length and permeability on production at different stages. In the designed production profile fitting case, the relative errors of inverted fracture half-length and permeability were below 6.30% and 0.88%, respectively. (3) Based on the gas production profile of an actual horizontal well in a tight gas reservoir, EnKF could simultaneously invert the fracture half-length and permeability for each stage, with the relative error of the inverted fracture half-length below 8% compared to microseismic monitoring results. This method provides valuable guidance and reference for diagnosing hydraulic fractures in tight gas reservoirs.

Imbibition plays a crucial role in waterflood development and the soaking stage after fracturing in tight oil reservoirs, serving as an effective method to enhance oil recovery. To investigate the effects of complex pore structures and rock-fluid interactions on imbibition mechanisms in tight reservoirs, this study combined nuclear magnetic resonance (NMR) technology with pore-scale imbibition numerical simulation techniques, conducting imbibition experiments and pore-scale imbibition numerical simulations on tight cores with different pore-throat characteristics. In the imbibition experiments, NMR T₂ spectra (transverse relaxation time) at different times were monitored in real time, which revealed the dynamic influencing patterns of pore structure on imbibition efficiency. In the pore-scale imbibition numerical simulations, realistic pore-scale physical models of tight sandstone were constructed based on thin sections, and the pore-scale imbibition process of tight sandstone was simulated by solving the Navier-Stokes equations combined with the phase field method. Based on the mutual verification of experimental and simulation results, the effects of contact angle, crude oil viscosity, and reservoir physical properties on imbibition efficiency were analyzed in detail. The results showed that the pore-scale imbibition numerical simulation results were in good agreement with the experimental data. The complexity of the pore structures significantly affected the oil displacement characteristics of imbibition, showing a relatively fast imbibition rate that gradually decreased with the extension of imbibition time. The aqueous phase preferentially entered smaller pores and then displaced the oil phase in larger pores. The smaller the contact angle resulting from rock-fluid interaction (i.e., the stronger the hydrophilicity of the rock), the greater the oil-water displacement driving force in the imbibition process and the higher the imbibition efficiency. In addition, a lower oil-water viscosity ratio and lower core permeability both generated stronger imbibition driving force. The research findings deepen the understanding of imbibition mechanisms in tight oil reservoirs at the microscopic level and provide theoretical foundation and experimental support for improving the development efficiency of tight oil reservoirs.

Gas reservoir X is a block-fractured edge-water gas reservoir controlled by anticline structures. Due to edge-water invasion, rapid water breakthrough severely reduced recovery efficiency, highlighting the urgent need for theoretical and methodological guidance for reservoir development. To address this, based on a systematic analysis of the influence patterns of key parameters on recovery rate, a recovery prediction model for fractured water-driven gas reservoirs was established. This model provides a scientific basis for the dynamic optimization of development schemes. Using basic geological and production data, a single-well mechanistic model was constructed with the embedded discrete fracture model (EDFM). Through single-factor sensitivity analysis, the influence patterns of water body multiple, gas production rate, matrix permeability, and permeability anisotropy were revealed. Recovery rate exhibited a negative correlation with water body multiple. As the water body multiple increased, the water-gas ratio of gas wells rose significantly faster, and the stable production time was greatly shortened. Gas production rate had a pronounced impact on the stable production time of the reservoir. An optimal gas production rate threshold existed that maximized the recovery rate. Matrix permeability was positively correlated with recovery rate. Lower matrix permeability led to lower recovery rate. The faster the increase in water-gas ratio, the shorter the stable production time. When permeability anisotropy was too low, poor seepage capacity resulted in a reduced recovery rate. An increased ratio accelerated water invasion, further decreasing the recovery rate. Based on these findings, 125 sets of cross-experimental schemes were designed, and basic data were obtained through numerical simulations. A recovery rate prediction model for fractured water-driven gas reservoirs was established. To improve the prediction accuracy of the model, the original data were discretized, and a decision tree algorithm was used. After parameter optimization, the prediction accuracy of the model reached 96%. The model was validated using actual dynamic data from two production wells in the gas reservoir X. The prediction results were compared with those from the Blasingame production decline analysis method. The results showed high consistency between model predictions and actual production data, indicating high reliability and practicality of the model. This provides an efficient and precise technical method for recovery rate prediction in fractured water-driven gas reservoirs.

The seventh member of the Yanchang Formation (Chang 7 member) in the Ordos Basin is a typical interlayered shale oil reservoir in China. A national shale oil development demonstration base has been established in the Longdong area. Spontaneous imbibition and oil displacement are observed throughout the entire process from hydraulic fracturing to crude oil production, exerting a significant impact on shale oil output. Therefore, clarifying the characteristics of spontaneous imbibition and oil displacement of fracturing fluid in pores of different sizes and their controlling factors is crucial for enhancing shale oil recovery in Chang 7. This study took the interlayered shale oil reservoirs of Chang 7 in the Ordos Basin as a case study. A series of experiments was conducted, including porosity-permeability measurements, X-ray diffraction (XRD) analysis, contact angle determination, and nuclear magnetic resonance (NMR)-based spontaneous imbibition and oil displacement experiments with fracturing fluid. These analyses characterized the spontaneous imbibition and oil displacement behavior of fracturing fluid in pores of different sizes across different reservoir types and revealed their key controlling factors from the perspectives of reservoir physical properties, mineral composition, and wettability. The results showed that: (1) based on pore-type proportions obtained from NMR fractal analysis, the samples were classified into TypeⅠand TypeⅡreservoirs. In TypeⅠreservoirs, macropores made up an average of 85.1%, and in TypeⅡreservoirs, mesopores made up an average of 79.0%. (2) TypeⅠreservoirs exhibited higher reservoir quality factors and quartz content than TypeⅡreservoirs, while containing less clay minerals. Their contact angles ranged from 77.3° to 103.7°, indicating the development of both hydrophilic and lipophilic reservoirs. In contrast, TypeⅡreservoir samples had contact angles between 53.2° and 63.1°, showing strong hydrophilicity. (3) The average spontaneous imbibition and oil displacement ratio in TypeⅠreservoirs was 17.27%, primarily contributed by macropores (74.1% on average), with mesopores accounting for 25.5%. In TypeⅡ reservoirs, the average ratio was 40.74%, primarily attributed to mesopores (85.2% on average). A comprehensive analysis of all influencing factors indicated that mineral composition was the fundamental factor influencing the ratio of spontaneous imbibition and oil displacement, followed by pore type, wettability, and petrophysical properties.

Horizontal well drilling has become an important method for oil companies to enhance single-well production in tight and unconventional oil and gas reservoirs. However, due to the complex spatial relationship between the wellbore trajectory of horizontal wells and the formation layers, traditional vertical well analysis methods cannot be effectively applied. Accurately describing the spatial combination relationship between the wellbore trajectory, the target layer, and the surrounding rock is a primary task in horizontal well logging interpretation. To address this issue, the mainstream approach is to construct an initial stratigraphic model based on a pilot well and then adjust the model segment by segment using forward modeling constraints from logging data. However, this process is time-consuming and requires numerous repetitive forward modeling calculations for different wells in the same area. Therefore, in the processing and interpretation of horizontal well logging data, developing a reasonable well-formation model is essential. This model enables an accurate description of the spatial relationship between the wellbore and the formation interfaces, including the distance between the wellbore position and formation interfaces and the angle between the wellbore axis and the formation normal direction. At the same time, logging data analysis methods based on machine learning and artificial intelligence (AI) technologies have been applied to various aspects of logging data interpretation by training intelligent models. With the support of AI technologies, it is expected to overcome the bottlenecks of traditional methods. To this end, the study proposed an automated horizontal well logging interpretation method based on multi-model integration and deep neural networks. First, a theoretical model was constructed incorporating different wellbore trajectories and formation combination relationships, and a logging response sample library was generated. Then, machine learning models such as eXtreme Gradient Boosting (XGBoost), Light Gradient Boosting Machine (LightGBM), and Categorical Boosting (CatBoost) were integrated, and their prediction results were further fused using a multi-layer perceptron (MLP). Finally, intelligent automatic recognition of the geometric relationship between the well trajectory and the surrounding rock was carried out using actual logging data. Case analysis showed that this method accurately captured the complex logging response characteristics of horizontal wells while significantly improving interpretation speed and accuracy. The proposed method meets the demand for rapid analysis of multiple wells in similar geological environments and provides an efficient, intelligent approach to horizontal well logging interpretation.

For tight sandstone reservoirs experiencing production decline after a period of development, refracturing is a feasible solution to reactivate existing fractures, initiate new fractures, and ultimately enhance production. Refracturing requires consideration of not only operational parameters such as slurry rate, fluid volume, and sand volume, but also whether to adopt fracture reactivation along original fractures or infill perforation completion techniques. Traditional evaluation methods for fracturing operations based on microseismic monitoring results mainly assess fracture dimensions and stimulated reservoir volume by measuring the geometric distribution of microseismic event point clouds. However, these methods cannot quantitatively evaluate the complexity of fracture networks under different operational parameters and the development and extent of new fractures generated by refracturing under different completion techniques. Therefore, a method was proposed to evaluate refracturing effectiveness using continuous fracture networks and apparent stress attribute maps constructed from microseismic events. This method utilized the spatiotemporal distribution characteristics of microseismic events (including temporal sequence and spatial distribution), and connected event points using defined geometric connection criteria (such as the shortest path principle) to build hydraulic fracture networks. The branch index attribute of the continuous fracture networks was used to quantitatively analyze the complexity of the hydraulic fracture networks. The apparent stress attribute values were calculated based on the energy, seismic moment, and shear modulus of the microseismic events. Lower apparent stress values indicated reactivation of existing fractures during refracturing, while higher values indicated that refracturing generated a large number of new fractures in the reservoir. This pattern could be used to evaluate the development of new fractures created by refracturing. The proposed method was applied to evaluate the refracturing effectiveness of a horizontal well in a tight sandstone reservoir in the Huaqing oilfield. The results showed that when refracturing was performed with higher slurry rates and larger fluid volumes than the initial frac (slurry rate ≤ 3 m³/min and fluid volume per stage ranging from 200~350 m³ for initial fracturing, while slurry rate ranging from 6~8 m³/min and fluid volume per stage ranging from 1 850~2 300 m³ for refracturing), the application of original fracture reactivation technology in horizontal wells of tight sandstone reservoirs enabled the formation of more new fractures and more complex hydraulic fracture networks compared to infill perforation.

Polyacrylamide (PAM) is a commonly used straight-chain organic polymer with good shear resistance, flocculation, dispersibility, and drag-reducing effect. It is mainly used in soil improvement, medicine, petrochemical industry, and environmental protection. By 2030, fossil fuels and renewable energy are projected to remain the primary energy sources (67.8×10¹⁶ J in total, with fossil fuels accounting for 78% of the total energy consumption). Over the past 40 years, polymer flooding technology has been applied in marginal oil fields and has proven effective in many cases. Most polymer flooding projects have employed partially hydrolyzed PAM and petroleum sulfonates. However, PAM can naturally degrade into aromatic amide monomers, which are highly toxic to humans. The purification methods of PAM-containing wastewater mainly include physical methods (flocculation, thermal degradation, mechanical shear degradation, and membrane separation), biological methods, and chemical methods. Among them, iron/carbon (Fe/C) micro-electrolysis, one of the widely used water treatment technologies in advanced oxidation processes, has been demonstrated as an efficient and low-cost method to treat various types of wastewaters and contaminated soils, including dye wastewater, organic wastewater, arsenic-containing, and fluoride-containing wastewater. Using ultraviolet (UV)-activated Fe/C micro-electrolysis, the study determined the chemical oxygen demand (COD) removal rates of PAM solution under different pH values, reaction times, K₂S₂O₈ concentrations, and UV powers. The experimental results showed that the COD removal rate under 365 nm UV irradiation was higher than that under 395 nm and 405 nm. Based on the measurements of the COD removal rate and the mass of iron oxide precipitates, the K₂S₂O₈ dosage fluctuation range was determined to be 1 mmol/L. The central composite design (CCD) approach-based response surface methodology (RSM) analysis showed that pH, reaction time, K₂S₂O₈ concentration, and UV power had significant effects on COD removal rate. The regression model yielded a coefficient of determination (R₂) of 0.778 9, indicating good agreement between the model and experimental results. The optimal conditions for PAM solution degradation were identified as pH 3.01, a reaction time of 3 h, a K₂S₂O₈ concentration of 1.4 mmol/L, and a UV power of 30 W. Under these conditions, the COD removal rate reached 90.2%, achieving effective removal of PAM.

The Yinggehai Basin is a key area for natural gas exploration in the western South China Sea. In recent years, commercially viable gas formations and abundant high-temperature formation water have been discovered in the Huangliu Formation of the X gasfield, indicating promising prospects for hydrothermal geothermal resource development. However, geothermal resource evaluation for this system are still lacking. Taking the X gasfield in the Yinggehai Basin as a case study, a heterogeneous 3D geothermal reservoir geological model was constructed by integrating drilling, logging, core, and seismic data. Key properties such as porosity, permeability, temperature, and water saturation were modeled and assigned in a gridded format. During the model construction, multiple stochastic simulations and seismic attribute constraints were introduced to enhance the rationality and accuracy of the spatial distribution of geological parameters. Based on this model, the volumetric method was applied to evaluate the geothermal resource potential of the Huangliu Formation, and the main geothermal resource-rich zones were identified. The results showed that the reservoir temperatures in the Huangliu Formation ranged from 167.0 ℃ to 197.6 ℃, with an average of 186.5 ℃, indicating favorable conditions for high-temperature geothermal development. The total geothermal resource was estimated to be 3.84×10¹⁶ kJ, equivalent to 1 310.5×10⁶ t of standard coal, with fine sandstone serving as the main reservoir lithology. Assuming a recovery coefficient of 8%, the recoverable resource was approximately 0.31×10¹⁶ kJ, equivalent to standard coal of 104.8×10⁶ t. The spatial distribution of resources revealed two major geothermal-rich zones, both located in the sand bodies of deepwater turbidite channels of the Huangliu Formation. These zones were characterized by high temperatures, favorable physical properties, and well-developed fine sandstone, making them preferred areas for future development. Meanwhile, water saturation model analysis indicated high water content in both the eastern and western parts of the Huangliu Formation, suggesting the presence of isolated water bodies that could serve as potential development areas. The research results provide clearer insights into the distribution characteristics and development potential of geothermal resources in the Yinggehai Basin and offer important guidance for promoting the integrated development of offshore gas fields and geothermal energy in China.

Hunan Province has relatively scarce primary energy resources. As an alternative energy source, geothermal energy is significant for optimizing the energy structure and promoting sustainable development. Historically, geothermal exploration in Hunan Province has primarily focused on uplifted mountain-type hydrothermal resources, with insufficient attention on hydrothermal resources in sedimentary basins. In recent years, Changsha Basin has demonstrated promising geothermal resource potential. However, its geological characteristics, formation mechanisms, and reserve scale remain inadequately understood. Based on previous research findings and drilling data, this study systematically analyzed key geological elements of the geothermal system in the Changsha Basin, including heat source, reservoir, caprock, and conduit. A geothermal genesis model was constructed. Furthermore, Monte Carlo simulation was used to conduct a quantitative evaluation of the geothermal resource potential. The results indicated that the primary heat source for the medium-deep geothermal resources in the Changsha Basin was mantle-derived conductive heat, resulting from mantle material uplift under an extensional tectonic regime. The geothermal reservoir mainly consisted of Upper Paleozoic carbonate rocks, with a relatively closed groundwater environment and prolonged water-rock interaction. The thickness of the caprock and the structural configuration of the basin interior influenced the geothermal field distribution. Regional faults and the development of pores and fractures provided good thermal conduction pathways. The average geothermal resource in the Changsha Basin was 9.85×10⁸ GJ, equivalent to 0.34×10⁸ t of standard coal, which could meet the heating demand for approximately 176.68×10⁸ m² of building area. Overall, the geothermal resources in this region are economically viable for development, with good social, economic, and environmental benefits. These findings can provide a reference for the exploration and development of medium-deep geothermal resources in the Changsha Basin, as well as for the evaluation of sedimentary basin-type geothermal resources in Hunan Province.

Gas storage facilities are crucial for ensuring national energy security and stabilizing supply during peak-demand periods. However, during operation, gas storage facilities are prone to risks such as fault reactivation and local caprock breakthrough, potentially leading to gas leakage. Therefore, it is necessary to analyze their mechanical integrity. To clarify the stress variation patterns of the gas storage X and enhance the upper limit of the operational pressure and overall storage efficiency, this study integrated geological, seismic, logging, production, and laboratory data to establish one-dimensional and three-dimensional geomechanical models of the gas storage X. Based on production history matching and cyclic gas injection and production patterns, a four-dimensional dynamic geomechanical model was established. The stress variation patterns and mechanical integrity of the caprock, reservoir, base support layer, and faults during the injection and production process were analyzed. The injection-production plans were optimized by considering deliverability and mechanical integrity. The results showed that: (1) The Longtan Formation caprock of the gas storage X was characterized by a relatively low Young’s modulus, high Poisson’s ratio, and weak mechanical strength. The more argillaceous the lithology, the lower the modulus and the smaller the horizontal stress. (2) The initial in-situ stress state of the caprock corresponded to a strike-slip faulting regime, while the reservoir corresponded to a reverse faulting stress regime. (3) During the injection-production process of the gas storage X, the caprock and base support layer experienced minimal stress variation and posed low failure risk. (4) The pore pressure of the reservoir changed significantly, and the pressure variation was greater than stress changes. (5) During the injection-production process, the risk of matrix failure in the reservoir was low, but the failure risk increased in the main injection-production area after gas injection. There was a slip risk when the bottom hole pressure exceeded the original gas reservoir pressure by about 3 MPa. (6) Under the condition of ensuring the mechanical integrity of the gas storage X, the optimized injection-production plan yielded an approximately 34% increase in cumulative gas injection compared to pre-optimization. The results provide theoretical and methodological support for in-situ stress analysis and mechanical integrity evaluation of the gas storage X.

Helium is a crucial strategic resource with very limited reserves, but its enrichment and dilution mechanisms in gas reservoirs remain unclear. Noble gas isotopes play an important role in characterizing the interactions between gas and groundwater. In this study, noble gas compositions and isotopic signatures of coalbed methane (CBM) from the third coal seam in the southern Qinshui Basin were analyzed to determine the isotope composition characteristics of noble gas and to establish a helium reservoir formation model. Gas samples were collected from 13 CBM production wells. The results showed that the helium (He) content in CBM was generally one order of magnitude higher than in the atmosphere. The ³He/⁴He ratios were 0.002 9-0.021 8 R_a, with a very low mantle source contribution (0-0.31%). The ²⁰Ne/²²Ne ratios (10.09-10.43) and ²¹Ne/²²Ne ratios (0.029 6-0.031 9) were slightly higher than those in the atmosphere, reflecting an excess of ²¹Ne relative to the atmosphere. The ⁴⁰Ar/³⁶Ar ratios (295.23-779.44) were overall higher than the atmospheric values, suggesting a significant influence of crustal ⁴⁰Ar accumulation over time. The isotopic signatures of krypton (Kr) and xenon (Xe) were similar to those of the atmosphere. Quantitative calculations of helium production revealed an external ⁴He flux into the self-generating and self-preserving CBM system. The linear relationship between ⁴He and ²⁰Ne indicated that helium dissolved in groundwater before degassing into the gas reservoir, while methane desorbed from coal seams diluted helium (as well as neon and argon) in the groundwater-associated gases. Therefore, gas reservoirs with lower grades were more likely to accumulate helium. Helium was mainly distributed in areas with effective helium source rocks, ancient groundwater systems, efficient migration channels, and appropriate hydrocarbon generation intensity, providing a theoretical basis for exploring helium resources in CBM. Rayleigh fractionation, dilution modelling, and gas production quantification showed that the water output per well during gas production was 8.03×10³-1.63×10⁶ m³. CBM exploration affected only the local water around each well, offering a basis for optimizing well spacing design.

Helium has characteristics such as a low boiling point, high thermal conductivity, and strong inertness. It plays a key role in fields such as low-temperature superconductivity, protective gas, refrigeration, medical treatment, and electronics, and is referred to as the “golden gas” and “rare earth of gas”. In order to analyze the helium characteristics and resource potential of Wufeng-Longmaxi Formation in southern Sichuan province, helium resources of Wufeng-Longmaxi Formation in Changning area of southern Sichuan Province were studied based on rare gas isotope test and trace element test. The results showed that: (1) the uranium (U) and thorium (Th) contents in the shales of the Wufeng-Longmaxi Formation in the Changning area were relatively high, with the highest mass fractions reaching 6.57×10^-5 and 2.96×10^-5 respectively, indicating a strong potential for helium generation. The helium isotope ratio (R/R_a ≈ 0.01) and the ⁴He/²⁰Ne ratio of the samples indicated that they had typical crustal helium characteristics. The concentrations of U, Th, and potassium (K) in the front and back limbs of the anticline structure were similar, but the content of radiogenic argon (⁴⁰Ar_rad) in the back limb was significantly higher than that in the front limb. Considering the difference between the theoretical and measured values of ⁴He/⁴⁰Ar, it was inferred that deep crustal helium had a mixing effect on the primary helium in the shale, forming a crustal helium mixture of near-source and far-source components. (2) There were two main sources of helium in the shale of Wufeng-Longmaxi Formation in Changning area: one was the helium continuously generated by the shale itself since its deposition, and the other was the helium gas that migrated into the Wufeng-Longmaxi Formation with the subsurface fluid through material exchange. (3) Calculations showed that the cumulative amount of helium produced during the natural evolution of the Wufeng-Longmaxi Formation shale in the Changning area was about 4.76×10⁸ m³. The helium resource of Wufeng-Longmaxi Formation in the Changning area was at least 2.86×10⁸ m³ based on the calculation of reservoir helium concentration. The findings of this study provide important guidance for further research on the potential, enrichment mechanisms, and distribution patterns of shale helium resources in the Sichuan Basin, as well as for achieving large-scale helium production and improving helium supply capacity.