Because of the lack of gas supply from source rocks and gas loss, inefficient tight-gas fields represent a high share of all gas reservoirs in China. These gas fields are characterized by low abundance and large gas reserves. Here, the He 8 tight-gas reservoirs in the western region of the Sulige gas field are used as an example to characterize gas distribution under conditions of less efficient charging. Results show the following characteristics. First, the sandstone densification process has a relatively large impact on the charging of gas. Litharenite was already subjected to densification at the time of large-scale gas charging, and this was not conducive to gas charging. On the contrary, for sublitharenite, although strong compaction has already occurred during gas generation, quartz overgrowth that leads to further densification of the gas reservoirs occurs simultaneously with large-scale gas charging. This facilitates gas charging and is characterized by concomitant densification and reservoir formation. Second, structure traps can control the accumulation of gas to a certain extent. In particular, when physical properties of sandstones within the structure traps are appropriate, gas saturation during gas charging can be increased by approximately 7%. Third, less efficient charging is the main cause of the complex gas and water distribution in the He 8 gas reservoirs. The strong heterogeneity of the reservoirs and the decline in the gas reservoir pressure caused by tectonic uplift in the Yanshan period further exacerbate the complexity of gas and water distribution. These factors ultimately caused the He 8 gas reservoirs to become a multireservoir gas field with several gas–water interfaces. The He 8 gas reservoirs are neither conventional gas nor continuous gas reservoirs. Rather, they are quasi-continuous gas reservoirs, and the accumulation of gas is controlled by both the top surface of sandstone and the physical properties of the reservoirs. Traps and high-quality reservoirs within the regional traps are beneficial for the gas accumulation.

A better understanding of the controls on reservoir quality has become essential in the petroleum exploration in recent years. Determining the original composition of the sediment framework is important not only for paleogeographic reconstructions, but it is also vital for predicting the nature of physical and chemical diagenesis of the potential reservoirs. Depositional setting and diagenesis are important factors in controlling the type and quality of most siliciclastic reservoirs. We studied the Upper Triassic Chang 8 and 6 members, where the relationship between sediment provenance and diagenesis was examined. The study attempts to clarify sediment provenance and post-depositional diagenetic microscopic analysis of grain and heavy mineral types, and measurements of the palaeocurrent direction of the Yanchang Formation sediments in the outcrops in order to determine the provenance of the studied sediments. Furthermore, the relationship between framework grains, pore types and diagenesis of the sediments was analyzed by thin section petrographic characterization using a polarizing microscope.system was used to investigate the habits and textural relationships of diagenetic minerals. On the basis of of diagenesis which may be expected in sandstones. In the Chang 8 and 6 members, the formation of chlorite rims and laumontite cement was observed where volcanic rock fragments constitute a large part of the framework grains. Furthermore, high biotite content provides abundant iron and magnesium and enables the formation of chlorite rims due to biotite hydrolysis. In addition, ductile deformation of biotite leads to strong mechanical compaction of the sediments. Conversely, high feldspar content diminishes the degree of mechanical compaction, however the dissolution of feldspar minerals in sandstones is commonly observed. Apart from feldspars, quartz and other rigid framework grains highly control the degree of mechanical compaction during the initial stage of burial (0-2 km).

The carbonates in the Middle Ordovician Ma 5 5 submember of the Majiagou Formation in the northern Ordos Basin are partially to completely dolomitized. Two types of replacive dolomite are distinguished: (1) type 1 dolomite, which is primarily characterized by microcrystalline (\30 lm), euhedral to subhedral dolomite crystals, and is generally laminated and associated with gypsumbearing microcrystalline dolomite, and (2) type 2 dolomite, which is composed primarily of finely crystalline (30-100 lm), regular crystal plane, euhedral to subhedral dolomite. The type 2 dolomite crystals are truncated by stylolites, indicating that the type 2 dolomite most likely predated or developed simultaneously with the formation of the stylolites. Stratigraphic, petrographic, and geochemical data indicate that the type 1 dolomite formed from near-surface, low-temperature, and slightly evaporated seawater and that the dolomitizing fluids may have been driven by density differences and elevation-related hydraulic head. The absence of massive depositional evaporites in the dolomitized intervals indicates that dolomitization was driven by the reflux of slightly evaporated seawater. The d 18 O values (-7.5 to -6.1 %) of type 1 dolomite are slightly lower than those of seawaterderived dolomite, suggesting that the dolomite may be related to the recrystallization of dolomite at higher temperatures during burial. The type 2 dolomite has lower d 18 O values (-8.5 to -6.7 %) and Sr 2? concentration and slightly higher Na ? , Fe 2? , and Mn 2? concentrations and 87 Sr/ 86 Sr ratios (0.709188-0.709485) than type 1 dolomite, suggesting that the type 2 dolomite precipitated from modified seawater and dolomitic fluids in pore water and that it developed at slightly higher temperatures as a result of shallow burial.

The exploration of deeply buried hydrocarbon is still a challenge for the petroleum geology. The Shunbei area is a newly discovered oil fields, located in the center of the Tarim Basin. The oil is mainly yielded from the Middle–Lower Ordovician carbonate reservoirs with depth > 7000  m in the Shunbei No. 1 and No. 5 fault zones. Calcite cements filled in vugs (v-calcite) and fractures (f-calcite) are identified in limestones and dolostones of the carbonate reservoirs. F-calcites in the Shunbei No. 1 fault zone trap secondary inclusions in trails, which comprise liquid-dominated biphase aqueous inclusions, liquid-dominated biphase oil inclusions, and/or oil-bearing triphase inclusions. F-calcite and v-calcite in the No. 5 fault zone trap secondary inclusions in trails, which consist of liquid-only monophase aqueous inclusions, liquid-dominated biphase aqueous inclusions, liquid-dominated biphase oil inclusions, liquid-only monophase oil inclusions, and/or oil-bearing triphase inclusions. The ranges of the homogenization temperature ( T h ) and ice-melting temperature ( T m − ice ) in the Shunbei No. 1 fault zone are, respectively, 130–150°C and -2.1–-1.5°C. The coexistence of liquid-only and liquid-dominated aqueous inclusions in the Shunbei No. 5 fault zone indicates that the aqueous inclusions are trapped at low temperatures. The aqueous inclusions in the Shunbei No. 5 fault zone show a range from -0.4 to -0.2°C in T m − ice which is very close to the meteoric fluid. In the context of the burial-thermal history and the Cambrian source rock evolution, the charging process of hydrocarbon in the Shunbei No. 1 and No. 5 fault zones corresponds to the Silurian and Middle Ordovician, respectively. Results of fluid inclusions indicate a tightly coupling relationship between the hydrocarbon charging process and fault system evolution in the Shunbei area. This study reveals the application of fluid inclusion under the systemically petrographic constraints to decipher the charging history of hydrocarbon, especially for the deeply buried reservoirs.