Clarification of the cause of overpressure is of great significance for the study of hydrocarbon generation, migration and accumulation processes under an overpressure environment, and the prediction of predrilling pressure. The cause of overpressure in Xihu Depression is still controversial. This study, based on mudstone compaction research and organic matter correction of logging data, ascertained the causes of overpressure in the Pinghu tectonic zone, Xihu Depression. A modified discrimination method for overpressure genesis was used and the overpressure–hydrocarbon distribution relationship was explored. The results show the following: (1) Vertically, overpressure is located in the lower section of the Pinghu Formation, with a pressure coefficient of 1.1–1.7 and a pressure relief feature. On the plane, the pressure coefficient in the Pingzhong area exceeds that in the Pingbei area. (2) The main causes of abnormal high pressure in the research area are undercompaction and fluid expansion. The fluid expansion mechanisms include overpressure transmission and hydrocarbon charging within the reservoir as well as hydrocarbon generation pressurisation and overpressure transmission within the source rock. (3) In the surge section of kaolinite, under fluid pressure, kaolin migrates toward the low-pressure areas, decreasing the porosity in low-pressure areas and preserving pores in high-pressure areas. The evolution of fluid pressure can be divided into two stages: pressurisation; and both pressurisation and pressure relief. Pressurisation and pressure relief drive hydrocarbon charging, but hydrocarbons are more enriched in overpressure layers.

Under the conditions of many faults, sandbodies, and hydrocarbon sources on the slopes of faulted basins where structural traps are scarce, only a few sandbodies are capable of forming hydrocarbon pools, while most sandbodies act as aquifers. This situation presents a challenge for predicting favorable hydrocarbon accumulation areas and understanding controlling factors. The Pinghu Formation reservoirs in the Baoyunting nose structure of the Xihu Sag in the East China Sea exemplify this characteristic. Among the 19 small-scale oil and gas reservoirs discovered in this area, 10 are faulted sandbody composite traps and 9 are lithological traps, while the majority of the remaining sand layers, especially the thick layers, act as aquifers, resulting in significantly lower accumulation probabilities compared to the adjacent northern and southern areas. We analyzed the relationship between the sandstone thickness and the amplitude through the 1-D forward modeling of wells and dissected the 3-D seismic event to obtain the planar distribution of a single sandbody. Further comprehensive research on fault sealing and kinetic reservoir formation processes suggests that the gas pool formation in this area is closely related to fault sealing and lateral oil and gas transport. A small fault-to-caprock ratio is beneficial for the sealing of mudstone caprocks, while a large fault-to-sand thickness ratio is beneficial for the lateral sealing of faults and the formation of fault–sand composite pools. The tidal microfacies sandbody has a small scale, poor lateral transport ability, and a low probability of gas reservoir formation. The barrier and delta front sandbodies have a large scale, good lateral transport, and a high probability of reservoir formation. Based on the above methods, favorable pool formation traps were identified in the area, and high-yield gas wells were drilled.

In recent years, understanding the distribution of oil and water in tight sandstones has been a challenge in the exploration and development of the Chang 8¹ Member in the Longdong area of the Ordos Basin. The spatial pattern of the oil/water contacts pattern varies widely over a distance of 160 km from south to north. The origin of these patterns is unknown. The present-day oil-water distribution in the reservoirs reflects the superimposed effects of hydrocarbon migration and accumulation. An integrated analysis of the characteristics of the present-day oil-water distribution in the Chang8¹ Member revealed that the a typical water-oil relationships are primarily located in the northeastern oil migration zone, and nearly normal water-oil relationships are located in the southwestern oil accumulation zone. Large-scale oil accumulation occurred at the end of the Early Cretaceous in response to strong fluid dynamics. The oil migrated from northeast to southwest in the slightly oil-wet carrier beds, and nearly normal water-oil relationships and larger accumulations formed in the Xifeng and Heshui oilfields in the southwest. The fluid dynamics subsequently weakened, and reservoir heterogeneity dominated, causing the oil to be trapped more easily in the tight reservoirs in the deeper parts of the northeastern oil migration zone. A typical oil-water distributions, such as inverted oil-water distributions, gradational oil-water interfaces, and low-abundance oil reservoirs, developed in such locations as the Huachi oilfield. Strong reservoir heterogeneity existed in both stages, but the fluid dynamics were significantly different, which controlled the distribution of oil and water in the tight reservoirs.

The traditional geological view holds that overpressure resists mechanical compaction during sedimentary burial, keeping effective stress approximately constant and thereby passively preserving porosity and permeability in deep reservoirs. However, this assumption has relied predominantly on theoretical inference and struggles to explain a widespread geomechanical paradox: in many overpressured formations, the magnitude of permeability enhancement significantly outpaces the degree of porosity preservation. To decode this paradox, we conducted a fundamental proof-of-concept study utilizing high-pressure percolation coupled with in situ micro-CT and fractal analysis to dynamically simulate the effects of overpressure on porous sandstone under constant mean effective stress. The results reveal a counterintuitive phenomenon: while the global porosity remained fundamentally stable, the absolute permeability demonstrated a significant ~8% enhancement. Microstructural analysis indicates that this enhancement is driven by localized hydraulic wedging and the reactivation of sub-resolution throats acting as topological bridges. This active topological optimization physically and mathematically manifests as: (1) the massive reconnection of macroscopic isolated pores; (2) an enhanced space-filling capacity of the flow network, evidenced by an increased coordination number and 3D pore space fractal dimension (D_f); and (3) the structural straightening of fluid pathways, rigorously quantified by a reduction in flow tortuosity and tortuosity fractal dimension (D_T). These findings, derived from a single well-characterized sandstone sample, demonstrate that overpressure-driven permeability enhancement is a physically plausible mechanism in tight sandstones. This discovery offers a candidate physical explanation for the anomalously high permeability observed in certain deep overpressured reservoirs. However, the generalizability of these results to reservoirs with differing porosities, mineralogies, and diagenetic histories remains to be evaluated through multi-sample studies.

Accurate prediction of overpressure in deep reservoirs is critical for hydrocarbon ex-ploration and development. Conventional approaches, such as interpolation of sin-gle-well pressure data and seismic inversion, often produce considerable errors and uncertainty when predicting overpressure in undrilled or inter-well areas, potentially leading to misinterpretation of reservoir pressure-field distributions. To address these limitations, this study proposes a novel approach that integrates identification of overpressure origins with quantitative analysis of the geological factors controlling overpressure magnitude. Multiple regression analysis enabled accurate prediction of overpressure in undrilled areas, with relative errors of less than 5% compared with measured pressures. Based on the conventional classification of normal and overpressure systems in the Bozhong area, three pressure-system types were identified: (1) paleo-overpressure converted to present-day normal pressure, (2) paleo-normal pressure retained as present-day normal pressure, and (3) paleo-overpressure preserved as present-day overpressure. The first type, character-ized by present-day pressure coefficients of 1.0–1.1, occurs predominantly near first- and second-order faults and is attributed to vertical fault opening and subsequent pressure release. The second type occurs mainly on structural slope highs and is asso-ciated with slow sedimentation rates and the absence of high-quality source rocks. The third type, with pressure coefficients ranging from 1.2 to 2.0, is primarily distributed in slope lows and depressions. It exhibits complex origins involving individual mecha-nisms, including undercompaction, hydrocarbon generation, pressure transfer, and tectonic compression, as well as coupled mechanisms, particularly undercompaction combined with hydrocarbon generation. This complex pressure system is controlled by several geological factors, including burial depth, sedimentation rate, vitrinite reflec-tance (Ro), total organic carbon content, fault throw, fault dip angle, and distance from faults.

Predicting present-day pore pressure and 3D in situ stress in ultra-deep fold-thrust belts is severely hindered by the inadequacies of traditional 1D vertical compaction models, which fail to account for massive lateral tectonic compression and continuous elastoplastic yielding. To overcome this, a 3D poro-elastoplastic analytical framework is developed based on the Modified Cam-Clay model to decode the irreversible “geomechanical memory” of deeply buried argillaceous rocks. Applied to the highly compressed Kelasu Thrust Belt, this method links volumetric strain with mean and deviatoric stresses in stress-invariant space to reconstruct the maximum paleo-pore pressure and 3D paleo-stress tensor during the Coulomb Failure Period (CFP). The quantitative decoupling reveals an extreme state of geopressure prior to macroscopic faulting (pore pressure ratio α = 0.85–0.89). Crucially, the mean stress surge is identified as the dominant driver, generating ~91% of the excess overpressure. Consequently, horizontal tectonic compression accounts for 80–90% of the total overpressure anomaly, fundamentally overturning the classical assumption that vertical undercompaction (10–20%) is the primary mechanism. Furthermore, it is demonstrated that during subsequent tectonic uplift, the heavily compacted, salt-capped mudstones follow an undrained unloading path; the reduction in lithostatic burden is almost entirely offset by fluid depressurization, maintaining a constant effective stress state. This physically decoupled framework provides a rigorous basis for optimizing pre-drill safe mud-weight windows, designing hydraulic fracturing in highly deviatoric stress regimes, and assessing caprock integrity for deep geo-energy storage.