Fracturing flooding is a new technology that combines traditional conventional water drive, chemical drive, and hydraulic fracturing technologies and injects water under proximity fracture pressure to increase the wave area. It is currently applied in onshore low-permeability oilfields with good results, but the research on the design method of fracturing flooding in offshore low-permeability reservoirs is still lacking. Numerical simulation studies of well fracturing flooding are needed to optimize the key parameters of fracturing flooding development. This study simulates the real-time fracture dynamic expansion process of micro-level fracture expansion for hydraulic fracturing, combines it with a numerical simulation of well pressure-driving, and finally optimizes the parameters of hydraulic flooding. By studying the fracture expansion law, this study determined that the total amount of injection volume had a large influence on both fracture half-length and inflow capacity; the larger the injection rate, the larger the fracture half-length, but the inflow capacity was basically unchanged. It was also found that multiple rounds of fracturing flooding had no effect on fracture morphology or length. In studying the key fracturing flooding parameters in oil wells, it was concluded that the higher the total injection amount, the higher the oil increase in fracturing flooding and the wider the wave area of pressure-driving. Moreover, the higher the displacement, the higher the pressure near the bottom of the well, but there was little difference in the spreading area; in addition, the longer the well shut-in time, the higher the early oil production. Finally, these results were combined with the fracture expansion mechanism model and A21 well model, and the analysis of fracturing flooding parameters based on the simulation results allowed for the following recommendations to be made: the total amount of fracturing flooding injection should be 15,000 m³, the injection rate should be 6 m³/min, the simmering time should be 3–7 days, and only one round of fracturing flooding is required. The mechanism of fracture expansion revealed in this paper can guide the design of fracturing flooding programs in the process of reservoir fracturing flooding development, which is of some significance to the development of the fracturing flooding of offshore reservoirs with low permeability.

The Hudson Oilfield’s Donghe sandstone reservoir has multiple independent oil–water systems. The complex oil–water relationship is mainly due to reservoir heterogeneity, especially the sealing and shielding effects of interlayers. This paper uses methods like well logging and test well data interpretation, seismic impedance inversion, and the simulation of oil and gas preferential migration paths. It analyzes and quantifies parameters related to sand layer oil content, physical properties, and the development degree of interbedded layers using small layers as units. Sandstone horizontal transportability has three types. Type I matches structural forms to form preferential migration paths. Type II transportability has enclosed sand bodies that obstruct oil and gas flow and change their migration paths. Unevenly distributed calcareous interbedded layers are the main controlling factor for vertical sand body transportability. Locally continuous cemented calcareous interbedded layers can form the base of a dome-shaped pinch-out lithologic trap in sandstone. The closure area of the trap is controlled by the pinch-out line of sandstone and the distribution of continuous interbedded layers together.

In this paper, the high-pressure physical property analysis of reservoir fluid PVT (pressure–volume–temperature) was studied to improve the accuracy and efficiency of reservoir fluid property prediction. Due to the limitations of traditional laboratory measurement and theoretical model prediction methods, the graph convolutional network (GCN) model was introduced in this paper, and the enhanced ChebNet model was used to analyze the complex relationship between the high pressure physical property parameters. The key parameters such as bubble point pressure, volume coefficient, and crude oil viscosity were accurately predicted by using Chebyshev polynomial approximation and the matrix product optimization ChebNet model, which was constructed to represent the high pressure physical property parameters and their relationships. The experimental results showed that compared with linear regression, linear discrimination, random forest, and ordinary ChebNet models, the enhanced ChebNet model introduced in this paper presented significant advantages in evaluation indicators, and the AUC value reached the optimal value. This paper provides a new perspective and method for reservoir fluid PVT high-pressure physical property analysis and explores a new possibility for the application of graph convolutional networks in oil and gas exploration and development.

The Eocene Pinghu Formation in the Xihu Depression, East China Sea Shelf Basin, is a key coal-bearing unit for offshore China’s petroleum exploration. However, the mechanisms of coal accumulation controlled by astronomical cycles and the stacking patterns of coal seams remain underexplored. Recent studies using wavelet analysis have highlighted the need for further investigation into the role of Milankovitch cycles in coal formation. This study uses natural gamma-ray logging data from Well K and applies cyclic stratigraphy to investigate how astronomical orbital cycles control coal seam development, identifying the link between cyclic stratigraphy and coal accumulation, and the distribution patterns of coal seams across different cycle levels. The top of the Pinghu Formation was used as the astronomical anchor, and tuning was conducted from top to base following a “cycle identification–anchor tying–astronomical tuning” workflow. The resulting astronomical timescale indicates a depositional duration of 8.17 Ma. COCO/eCOCO analyses with 5000 Monte Carlo simulations (sedimentation-rate range: 7–11 cm/kyr; step: 0.1 cm/kyr) yield a mean sedimentation rate of 9 cm/kyr. Coal accumulation is influenced by Milankovitch cycles. High eccentricity periods correspond to warmer climates that promote coal development, while low eccentricity phases synchronize with optimal climatic conditions for coal formation. Based on these findings, this study proposes a coal seam development model for the Pinghu Formation in Area A of the Xihu Depression, offering insights for cyclic stratigraphy and coal accumulation research in similar basins and supporting sustainable development of coal-bearing strata in the East China Sea Basin.

A comprehensive study on the distribution characteristics and exploitation strategies of remaining oil was carried out in the Ordovician ultra-deep fault-controlled fractured–vuggy carbonate reservoir within the Shunbei No. 1 strike–slip fault zone. This research addresses challenges such as severe watered-out and gas channeling encountered during multi-stage development, marking a shift toward a development phase focused on residual oil recovery. By integrating seismic attributes, drilling, logging, and production performance data—and building upon previous methodologies of “hierarchical constraint and genetic modeling”—a three-dimensional geological model was constructed with a five-tiered architecture: strike–slip fault affected zone, fault-controlled unit, cave-like structure, cluster fillings, and fracture zone. Numerical simulations were subsequently performed based on this model. The results demonstrate that the distribution of remaining oil is dominantly controlled by the coupling between key geological factors—including fault kinematics, reservoir architecture formed by karst evolution, and fracture–vug connectivity—and the injection–production well pattern. Three major categories with five sub-types of residual oil distribution patterns were identified: (1) local low permeability, weak hydrodynamics; (2) shielded connectivity pathways; and (3) Well Pattern-Dependent. Accordingly, two types of potential-tapping measures are proposed: improve well control through optimized well placement and sidetrack drilling and reservoir flow field modification via adjusted injection–production parameters and sealing of high-permeability channels. Techniques such as gas (nitrogen) huff-and-puff, gravity-assisted segregation, and injection–production pattern restructuring are recommended to improve reserve control and sweep efficiency, thereby increasing ultimate recovery. This study provides valuable guidance for the efficient development of similar ultra-deep fractured–vuggy carbonate reservoirs.

Calcareous interbeds are widely developed in marine clastic sequences, where laterally continuous, tight calcareous interbeds act as critical controls on the formation of lithologic traps and the distribution of oil. However, the genetic mechanisms and development models of these interbeds, particularly under deep-burial conditions subject to complex fluid interactions, remain poorly understood. Using the Donghe Sandstone in the Hade Oilfield (Tarim Basin) as a case study, this paper investigates the genetic evolution of calcareous interbeds via an integrated approach combining core observation, thin-section petrography, scanning electron microscopy (SEM), stable isotope analysis, fluid inclusion microthermometry, and heavy fraction analysis. The results indicate that: (1) The carbonate cements within the interbeds are compositionally complex, dominated by calcite but characterized by a diagnostic assemblage of anhydrite, ferroan calcite, and ankerite. (2) During the depositional to shallow burial stages, seawater evaporation and meteoric freshwater influx led to the supersaturation of calcium-rich pore waters near the surface. This facilitated the precipitation of early cement assemblages, which are predominantly of freshwater origin and consist mainly of non-ferroan calcite nodules, dolomite, and anhydrite. (3) During the deep burial stage, the injection of high-salinity brines and organic acid decarboxylation triggered Thermochemical Sulfate Reduction (TSR). This process caused the extensive consumption of the pre-existing anhydrite and the formation of authigenic pyrite, followed by the tight occlusion of remaining porosity through the precipitation of late-stage ferroan calcite and ankerite. (4) In the broad slope setting, these tight calcareous interbeds constitute effective flow barriers, resulting in a stepped distribution of the oil–water contact. Within the reservoir compartments segmented by these interbeds, crude oil maturity exhibits a distinct inversion (i.e., higher maturity below the interbeds and lower maturity above), confirming the critical sealing capacity of the interbeds during hydrocarbon accumulation. Ultimately, this study establishes a genetic model coupling calcareous interbed development with deep-burial fluid alteration, providing new geological insights for predicting subtle traps in marine sandstone reservoirs.