Faults and sand bodies are the main transport elements of hydrocarbon migration of the Dongying Formation in the East Slope of Chengdao. In order to explore the mechanism of hydrocarbon migration and accumulation under the control of fault-sand configuration transportation conditions, the types of fault-sand configuration of the Dongying Formation in the East Slope of Chengdao are first divided based on the precise interpretation of seismic data and RMS attribute analysis of sand body. The fault-sand configuration transport properties are quantitatively evaluated by using the relative transport index of the sandstone transport layer RT_i and fault lateral conductivity index F_LSI indices. The control effect of different types of fault-sand configuration on hydrocarbon migration and accumulation was then analyzed with the HMIE index and Trinity hydrocarbon migration numerical simulation. The results show that the fault-sand configuration in the East Slope of Chengdao can be divided into three types, forward configuration of fault-sand, reverse configuration of fault-sand and compounds of primary faults and secondary faults configuration of fault-sand according to the spatial superposition relationship between faults and sand bodies. The controlling effect of fault-sand configuration on hydrocarbon accumulation is mainly reflected in the following aspects: (1) Control the area of hydrocarbon migration and accumulation; the hydrocarbon migration and accumulation was controlled by transportation conductivity of fault-sand configuration when RT_i > 0.15, RT_i are positively associated with the degree of hydrocarbon accumulation on the slope region, hydrocarbons are easily sealed laterally to form reservoirs on the fault terrace zone when F_LSI≥0.45. (2) Control the dominant migration path of hydrocarbon; the types, the communicating effectiveness with the source rock and transport capacity of fault-sand configuration determine the dominant migration paths of hydrocarbon. The HMIE index and Trinity simulation analysis show that there are three dominant migration paths, namely, the depression area towards the fault belt of southern Shenghai 10, the depression area towards the fault belt of southern Shenghai 8, and the depression area belt towards the fault terrace area. (3) Control the distribution and accumulation of hydrocarbon; The forward configuration of fault-sand mainly plays the role of stepping hydrocarbon transport, the reverse configuration of fault-sand type can block hydrocarbon accumulation laterally, and the compounds of primary faults and secondary faults configuration of fault-sand plays the role of diverting hydrocarbon first and then enriching it. Different types of fault-sand configuration control the hydrocarbon accumulation pattern, which has the characteristics of “zonal control, vertical differentiation and multi-layer system enrichment”.

In recent years, extensive exploration and exploitation activities in tight sandstone gas reservoirs have highlighted the common phenomenon of water production, indicating complex gas-water contacts. Exploring gas layers while avoiding water layers has become critical to the efficient exploration and exploitation of tight sandstone gas reservoirs. This study presents comprehensive geological analyses of gas-water contacts in simple gentle tectonic zones (tight sandstone gas reservoirs in the Sulige and Daniudi areas in the Ordos Basin), a transition zone of simple gentle to complex uplift (Hangjin Banner in the Ordos Basin), and complex uplift zones (tight-gas reservoirs in the western Sichuan Basin). Combined with the core-scale and pore-scale physical simulations of gas-water contact in tight sandstone, we clarify the types and characteristics of gas-water contacts in tight-gas sandstone reservoirs, reveal the dominant factors controlling the formation and distribution of intricate gas-water contacts based on the sand bodies, cores, and pores, and establish corresponding gas-water distribution patterns. Key findings are as follows. In terms of sand body, there are primarily six types of gas-water contacts within, including (1) the simple type of gas layer without water layer; (2) the normal type with gas layer underlain by water layer; (3) the inverted type with gas layer overlaid by water layer; (4) the hybrid type with gas and water in the same layer; (5) the isolated type with water layer within a gas layer; and (6) the simple type of water layer without gas. The distribution range, style, and boundary of gas-water contacts are governed by hydrocarbon-generating intensity, reservoir heterogeneity, and a combination of source rock-reservoir pressure differences and tectonic activity, respectively. At core-scale, permeability coupled with charging dynamics of the tight sandstone governs the critical conditions for the formation and distribution of gas-water contacts. At pore-scale, the coupling of pore throat size and coordination number with charging pressure dictates the fluid occurrence and seepage characteristics, determining the critical conditions for the formation and distribution of gas-water contacts. Owing to the collective effects of dominant factors from sand body, core-scale, and pore scale and their differences, tight-gas reservoirs with different source rock-reservoir assemblages exhibit different gas-water distribution patterns.

Wettability plays a critical role in dictating the fluid percolation within low-permeability sandstone reservoirs. However, the wettability evolutionary mechanisms remain ambiguous given the frequent changes in the fluid properties and mineral types and compositions in these reservoirs throughout diagenesis. This opacity severely hampers the research on the mechanisms of hydrocarbon accumulation in the reservoirs. This study centers on the upper submember of the 4th member of the Paleogene Shahejie Formation in the Dongying Sag, Bohai Bay Basin. Based on the analysis of geological data, we undertake a systematical analysis of diagenesis’s controlling effects on the wettability of lowpermeability sandstone reservoirs through observation of casting thin sections and the X-ray diffraction analysis of mineral compositions, Amott wettability tests using nuclear magnetic resonance (NMR) equipment, and experiments of contact angles in a solid-oil-water system, both under high temperature and pressure. The results highlight distinct major pore types across various diagenetic states attributable to complex diagenesis. Specifically, the early diagenetic stages A and B evidenced the major pore types of residual pores by compaction and both intragranular pores from feldspar dissolution and intergranular pores from carbonate dissolution, respectively, while middle diagenetic stages A1, A2, and B witnessed the presence of dissolution pores at quartz edge, both intragranular pores from feldspar dissolution and intergranular pores from carbonate dissolution, and fractures, respectively as major pore types. As diagenesis advanced, residual pores by compaction, dissolution pores at quartz edge, and intragranular pores from feldspar dissolution grew increasingly hydrophilic. Furthermore, intergranular pores from calcite dissolution trended toward lipophilicity, while intergranular pores from dolomite dissolution evolved from water wetting to intermediate wetting. The overall wettability of the low-permeability sandstone reservoirs is governed by the major pore types and their surface wettability throughout the diagenetic timeline. The wettability of low-permeability sandstone reservoirs was dominated by water wettability across all the diagenetic stages, showcasing strong hydrophilicity, weak hydrophilicity, hydrophilicity, intermediate wetting, and hydrophilicity sequentially. Finally, a wettability evolution model of sandstone reservoirs under the action of diagenesis is established, which will guide the prediction of sweet spots in low-permeability sandstone reservoirs.

In recent years, breakthroughs have been achieved in hydrocarbon exploration efforts in the ultra-deep marine carbonate rocks of strike-slip fault systems in the northern Tarim Basin. However, the Fuman oilfield in the basin exhibits pronounced differences in hydrocarbon distribution and enrichment, with the mechanisms driving the differential hydrocarbon accumulation in ultra-deep reservoirs governed by strike-slip faults remaining unclear. In this study, we investigate the geometric structures and evolution of strike-slip faults in the Fuman area, as well as their role in hydrocarbon migration and accumulation. By analyzing the hydrocarbon accumulation and enrichment mechanisms, we identify the dominant factors controlling hydrocarbon accumulation in ultra-deep carbonate reservoirs in the area. The results indicate that the strike-slip faults in the study area experienced a dynamic evolutionary process consisting of the early extension or weak compression, the middle-stage transpression, extension, or translation slip, and the late-stage stabilization, successive development, or tenso-shear inversion. The F_I5 and F_I17 fault zones underwent alternating compression, shear, and tensile stresses, resulting in significant evolutionary differences across their various parts. In contrast, the F_I7 and F_Il6 fault zones were primarily subjected to shear and tensile stresses, leading to relatively simple evolutionary processes. The faults with differential evolutionary processes exhibit distinct geometric structures, resulting in varying configurations of their connection to source rocks, hydrocarbon transport capacities, and reservoir properties. Consequently, three hydrocarbon charging models are formed: vertical charging as represented by F_I5 and F_I16, lateral migration for adjustment by F_I7, and a combination of the former two patterns by F_I17. The hydrocarbon charging process is governed by the differential evolution of fault zones. The late-stage strong activity of faults in the eastern part of the Fuman area, combined with the charging and accumulation of substantial highly mature pyrolysis gas during the Himalayan movement, results in the formation of a hydrocarbon distribution pattern characterized by “oil in the west and gas in the east”. Furthermore, the evolutionary differences across various parts of the fault zones cause more complex changes in hydrocarbon properties. For reservoirs dominated by vertical hydrocarbon charging, the degree of hydrocarbon enrichment is determined by the coupling of the connection to source rocks, hydrocarbon transport capacities, and reservoir properties of fault zones. Meanwhile, the hydrocarbon properties of the reservoirs are governed by the various hydrocarbon charging stages. For reservoirs dominated by lateral hydrocarbon migration, the degree of hydrocarbon enrichment and hydrocarbon property changes are controlled by their properties and the extent of lateral connections within.