The Linnan Sag is one of the main oil-producing units in the Huimin Depression, Eastern China, and the pore pressure gradients obtained from drill stem tests (DSTs) range from 9.0 to 16.0 MPa/km. Uncertainty about the origin and distribution of abnormally high pressures in the Linnan Sag has led to different interpretations of hydrocarbon accumulation and resource assessments, and it interferes with safe drilling. In the Linnan Sag, mudstone compaction curves are substantially affected by several non-compaction factors, and the normal trend of the compaction curve is difficult to determine. The determination of the origin and distribution of overpressure in the Linnan Sag is a challenge. In this study, the factors that may affect mudstone compaction—such as the shale volume, higher calcareous, and organic matter content—were carefully examined and processed. The pressures in the mudstones were estimated by the corrected mudstone compaction curves, which were compiled from acoustic, density, and neutron logs, and calibrated using DST and mud weight data. The log response–vertical effective stress and acoustic velocity-density crossplots were used to identify the mechanisms that generate overpressure. The comprehensive compaction curve shows that the mudstones in the overpressured layer exhibit clear disequilibrium compaction characteristics. The logging response crossplots demonstrate that those overpressured points were consistent with the loading curve. The findings suggest that, the fundamental mechanism resulting in overpressures is the disequilibrium compaction of thick Paleocene mudstones. Hydrocarbon generation and vertical transfer of overpressure may be the main unloading mechanisms, which corresponds to the overpressure points that deviate from the loading curves. Since organic matter cracking may occur in formations at depths greater than 4000 m (Ro > 1.0%), the contribution of hydrocarbon generation to overpressuring is expected to be limited. The transfer of overpressure through opening faults is therefore considered to be the main cause of higher overpressure in local sandstones. The overpressures in the mudstones are characterized by a gradual decrease from the center to the margin in the Linnan Sag. The pressure in the isolated sand bodies are generally similar to that in the surrounding mudstones, whereas it can be lower or higher when the overpressure in the sand bodies are vertically transferred by faults to other pressure systems. The results of this analysis provide an indication of the magnitude, mechanism, and distribution of overpressure in the Linnan Sag. This insight can be used to guide further exploration of the Linnan Sag and similar geological basins.

The Lower Jurassic Ahe Formation is an important exploration target for deep clastic reservoirs in the eastern Kuqa Depression. The Ahe Formation sandstones show heterogeneous porosity and permeability petrophysical properties. These properties have been poorly understood, limiting forecast of petroleum accumulations and making it difficult to develop the reservoirs. Based on cores, thin sections, SEM, and fluid inclusions, this study examined sandstone composition and texture and diagenetic heterogeneity at the core scale. The aim was to understand the influence of variations in detrital composition and texture on diagenetic and reservoir quality evolution. The Ahe Formation sandstones are dominantly fine- to coarse-grained litharenites, with minor feldspathic litharenites. In fining-up sand beds, detrital grain size determines the degree of mechanical compaction and, consequently, the abundance of porosity through ductile grains and muddy matrix. Local complete calcite cementation is a noticeable exception to this general trend. Three sandstone petrofacies have been defined based on texture and framework composition, detrital matrix, diagenesis, and pore types: (1) ductile-lean sandstone, (2) ductile-rich sandstone, and (3) tightly calcite-cemented sandstone. Different petrofacies experienced contrasting diagenetic and porosity evolution pathways. Ductile-lean sandstones underwent lower degree of compaction relative to ductile-rich sandstones during the eodiagenesis stage, and extensive grain dissolution occurred. The petrofacies remained relatively porous and permeable before early oil arrival. With continued burial, the porosity and permeability in the sandstones were further reduced by cementation. The petrofacies still had moderate porosity and permeability and were substantially charged when late petroleum migrated into the reservoirs. Thus, ductile-lean sandstones constitute effective reservoir rocks in deep reservoirs. By translating petrofacies to signatures of well logs, the effective properties of the reservoir rocks can be forecasted at the well scale.

The current study examines the methane gas hydrate stability zone (GHSZ) in the Shenhu area in the northern South China Sea (SCS) as an example to calculate the thickness of the GHSZ and reconstruct its evolution since 8.2 Ma. Two mechanisms for typical double BSRs in the Shenhu area are shown, and the relationship between the evolving thickness of the GHSZ and the dynamic accumulation of NGHs at typical stations in the Shenhu area is clarified. The results show that the thickness of the GHSZ varies over time with overall thickening in the Shenhu area. The current thickness of the GHSZ is between 160.98 and 267.94 m. Two mechanisms of double BSRs in the Shenhu area are summarized: the double BSRs pattern based on changes in formation temperature, pressure and other conditions and the double BSRs pattern based on differences in gas source and composition. The formation process and occurrence characteristics of double BSRs and hydrate at site SH-W07-2016 in the Shenhu area are also closely related to the changes in thickness of the GHSZ. In addition, the age when gas source first enters the GHSZ has a considerable influence on the dynamic accumulation process of hydrate. Since the formation of hydrate above the BSR at site SH-W07-2016, the GHSZ has experienced up to two periods of thickening and two periods of thinning at this site. With the changes in the thickness of the GHSZ, up to two stages of hydrate formation and at most two stages of hydrate decomposition have occurred. This paper is of great value for understanding the formation of multiple bottom-simulating reflectors (BSRs) as well as the migration, accumulation and dissipation of natural gas hydrate (NGH) during the dynamic accumulation process.

It is of great significance to study the spatial-temporal variations of the thickness of the gas hydrate stability zone (GHSZ) to understand the decomposition, migration, accumulation and dissipation of gas hydrate, the corresponding relationship between bottom-simulating reflectors (BSRs) and gas hydrate, and the distribution of heterogeneous gas hydrate. We selected the Dongsha region in the South China Sea (SCS) as the research object to calculate the spatial-temporal variation of the GHSZ since 10 Ma, analyzed the main factors affecting the thickness of the GHSZ, discussed the dynamic accumulation processes of gas hydrate, and proposed an accumulation model of gas hydrate in the Dongsha region. The results show that the thicknesses of the GHSZ in the study area were between 0 m and 100 m from 10 to 5.11 Ma, and the relatively higher bottom water temperature (BWT) was the key factor leading to the thinner thickness of the GHSZ during this period. From 5.11-0 Ma, the thickness of the GHSZ gradually increased but showed several fluctuations in thickness due to changes in the geothermal gradient, seawater depth, BWT, and other factors. The decrease in the BWT was the main factor leading to GHSZ thickening from 5.11 to 0 Ma. The thicknesses of the GHSZ are between 110 m and 415 m at present. The present spatial distribution features show the following characteristics. The GHSZ in the deep canyon area is relatively thick, with thicknesses generally between 225 m and 415 m, while the GHSZ in other areas is relatively thin, with thicknesses between 110 m and 225 m. Based on the characteristics of the GHSZ, two hydrate accumulation models are proposed: a double-BSRs model due to thinning of the GHSZ and a multilayer hydrate model due to thickness changes of the GHSZ, with single or multiple BSRs.