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.