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Cambrian subsalt dolomite is an important strategic area for natural gas exploration in the Tarim Basin. The gypsum-salt rocks, argillaceous mudstone and argillaceous dolomite strata developed in large areas of the Middle Cambrian can be used as good caprocks. The sealing ability and favorable area distribution of the Middle Cambrian caprock in the Tarim Basin are studied through the lithofacies paleogeography and microscopic evaluation of the Middle Cambrian strata in this paper. Based on the 2D seismic interpretation covering the entire basin, combined with data from drilling, outcrops, well logging, core samples and thin sections, the sedimentary characteristics and lithofacies paleogeography of the Middle Cambrian were studied and then the thickness of the Middle Cambrian gypsum-salt rocks, gypsiferous mudstone and gypsiferous dolomite was analyzed in the Tarim Basin. Studies suggest that the Middle Cambrian is primarily characterized by the development of restricted-platform facies. In the Awati Depression, the northern part of the Tazhong Uplift, the southern part of the Manxi Low Uplift, and the central and northern parts of the Bachu Uplift, the thickness of the gypsum-salt rock strata is relatively large. Moreover, centered on the northern part of the Bachu Uplift, the thickness of the gypsum-salt rocks decreases irregularly towards the periphery, forming a circumferential distribution. To investigate the sealing ability of caprocks, 64 core samples from four wells were examined under a microscope, and physical parameters as well as breakthrough-pressure tests were conducted. By establishing correlations between various parameters, the sealing ability of different rock types in the Cambrian formation within the study area was quantitatively assessed. The research suggests that gypsum-salt rocks exhibit superior sealing ability compared to gypsiferous mudstone and gypsiferous dolomite, but factors such as faults and geological conditions of gypsum can influence the sealing performance of caprocks. According to both micro- and macro-scale evaluations of the Cambrian strata in the study area, along with constraints imposed by actual drilling exploration results, a comprehensive evaluation method for assessing caprock sealing ability has been established. The results suggest that the Awat Depression, the western and southern parts of the Manxi Low Uplift, the northern and western parts of the Tazhong Uplift, and the central part of the Tabei Uplift are favorable areas for the development of caprocks.

Wufeng Formation shale is an important source rock of unconventional hydrocarbons in the Lower Paleozoic shales of Sichuan Basin. However, the study on its provenance and paleoclimate is still relatively limited. In this study, mineralogical and geochemical data of the shales from the Upper Ordovician Wufeng Formation in southwestern China has been used to interpret the provenance and conditions of weathering and paleoclimate. The Wufeng shales have intermediate to high SiO 2 (57.72–82.38 wt. %, av. = 68.84 wt. %) and Al 2 O 3 (5.26–16.17 wt. %, av. = 10.62 wt. %), are rich in transition metal elements (i.e. V, Ni, Cu, Co and Cr) and Y as well as moderate depletion in Na 2 O and Sr, relative to the concentrations of the upper continental crust (UCC). In the chondrite-normalized (CN) rare earth elements (REE) distributions, these rocks display light REE (LREE) enrichment (La/Yb CN = 6.69–12.63, av. = 9.28), flat heavy REE (HREE) (Gd/Yb CN = 1.35–2.41, av. = 1.70), and clearly negative Eu anomalies (Eu an = 0.50–0.66, av. = 0.58), showing similar characteristics with the CN post-Archean Australian Average Shales (PAAS). Wufeng Formation shales are immature composition without evident recycling sediments, and they are originated from an intermediate-felsic igneous source composed of tonalite–trondhjemite–granodiorite (TTG), granitic and andesitic igneous rocks. The chemical weathering conditions of studied shales decreased from moderate to low in the provenance region, suggesting a gradual cooling trend of the climate at Late Ordovician Thus, this article will be helpful to discern the provenance and variations of chemical weathering conditions and paleoclimate of Wufeng Formation shales.

In addition to traditional gypsum salt rocks and shale rocks, many studies have confirmed that carbonate rocks also work as oil and gas seals. Breakthrough pressure is a characteristic parameter for the evaluation of the sealing ability of cap rocks. Different lithology types and lengths of carbonate rocks were subjected to breakthrough pressure measurement experiments at different temperatures, results showed that lithology, permeability and fracture development have obvious effects to rock characteristics. At the same temperature, sample length does not have a good correlation with breakthrough pressure, however, at different temperatures, the breakthrough pressure of most samples gradually decreases with the increase of temperature. Therefore, formation temperature has a non-negligible effect on the sealing ability of cap rocks. It is a key factor that needs to be considered for the evaluation of the sealing capacity of cap rocks. The carbonate rock with a high argillaceous content has better sealing capacity under high geothermal conditions.

Breakthroughs have been made for the natural gas exploration of the Middle Devonian and the Middle Permian formations in the Sichuan Basin in recent years. Nevertheless, its natural gas source is still not clear, which then affects the next exploration deployment decision. A comprehensive study is conducted on the geochemical characteristics of the Middle Devonian and the Middle Permian natural gas, the biomarkers of reservoir bitumen, and the source rocks. The results show that these natural gases are secondary cracking dry gas that includes more than 86% of methane content, a small amount of ethane, propane, and a non-hydrocarbon gas (e.g., nitrogen, carbon dioxide, and hydrogen sulfide). The natural gas maturity varies slightly in different regions. The carbon and hydrogen isotope values of natural gas are as follows: δ13C1 ranges from −35.7‰ to −27.3‰, δ13C2 ranges from −38.7‰ to −26.6‰, δ13C3 ranges from −37‰ to −26.5‰, δ2HCH4 ranges from −141‰ to −138‰, and δ2HC2H6 ranges from −164‰ to −112‰. The isotope values indicate that the genetic type of natural gas is the sapropelic type and the mixture type is dominated by sapropelic type. The difference between natural gas values of δ13C1, δ13C2, and δ2HCH4 in different regions is related to the contribution ratio of source rocks from different ages. The gases of the Middle Devonian and the Middle Permian of the Shuangyushi structure in Northwestern Sichuan, the Middle Permian of Southwestern Sichuan, and the Middle Permian of Paleo-uplift in Central Sichuan are mainly derived from the Cambrian Qiongzhusi Formation and the Middle-Lower Permian source rocks. The Middle-Upper Permian natural gases of the volcanic reservoir in Southwestern Sichuan is mainly from the Qiongzhusi source rock. The Middle Permian natural gases of the Hewanchang structure in Northwestern Sichuan, Eastern Sichuan, and Southern Sichuan are mainly derived from the Silurian Longmaxi source rock. The research results have important guiding significance for developing exploration and deployment solutions for natural gas of the Middle Devonian and the Middle Permian formation in the Sichuan Basin.

The dolomitization of carbonate rocks has always been a hot topic in the study of the dolomite reservoir. In this study, the genesis of Cambrian dolomite in the Bachu area, Tarim Basin, was assessed through petrographic examinations, isotope compositions (C, O, and Sr), trace and rare earth elements, and fluid inclusion microthermometry. Microscopic analysis revealed three types of dolomites: very fine-crystalline, nonplanar dolomite (D1); fine-crystalline, nonplanar to planar-s dolomite (D2); and medium- to coarse-crystalline, planar-e to planar-s dolomite (D3). D1 dolomite exhibits well-preserved original sedimentary features, such as algal laminae, stromatolite, and evaporite streak, and is characterized by the 87Sr/86Sr value and δ18O value in equilibrium with the coeval seawater, its high Sr and Na content, and its low Mn content. This indicates that D1 dolomite is primarily a penecontemporaneous dolomite in tidal flat or lagoon environments, and its dolomitizing fluid is mainly evaporated mesosaline to penesaline seawater. D2 dolomite shows ghosts of precursor particles; features δ13C values in equilibrium with the coeval seawater, high 87Sr/86Sr values, low Sr content, and positive Eu anomaly; and is widely distributed close to stylolite. This illustrates that D2 dolomite was principally formed by seepage–reflux dolomitization, and is closely related to hydrothermal activity and pressure dissolution. D3 dolomite displays a crystal texture with a cloudy core and compositional zoning, and the original sedimentary fabrics cannot be identified. It has similar δ13C values and REE patterns to the calcite precipitated from coeval seawater, high 87Sr/86Sr values, low Sr contents and high Mn/Sr ratios, which suggests that D3 dolomite is chiefly related to the recrystallization of the precursor dolomite during the deep burial stage, and the deep circular brine provides Mg ions through the fluid–rock reaction. This study shows that the Cambrian dolomite in the Bachu area is mainly formed in the coeval seawater environment during the penecontemporaneous and shallow burial stages, and has extensively suffered from recrystallization and burial diagenesis due to long-term deep burial, which was further strengthened in the fracture-enriched area.

The development of geologic theories and exploration findings of natural gas in China supplement each other. Since the 11th Five-Year Plan in 2006–2010, geologic theories of natural gas in China has achieved notable advancement in many aspects, of which, are mainly reflected in the following seven aspects. Among them, there are two research progresses in the basic geological theory enumerated as follows. (1) The formation mechanisms of three types of natural gas that have been studied broadly including highly evolved coal-based source rocks, crude oil pyrolysis gas, and biogas. The cracked gas mode of coal-based source rocks, whole process hydrocarbon-generating mode of humus-type organic matter, and continuous biogas generation mode have been thoroughly advanced. (2) The theory of genetic identification between crude oil pyrolysis gas and kerogen pyrolysis gas, aggregated crude oil pyrolysis gas and dispersed crude oil pyrolysis gas, organic and inorganic gases, coal-type gas and oil origin gas, has been enriched extensively. There are five theoretical advances in the field of hydrocarbon accumulation in large gas fields: (1) the theory of hydrocarbon accumulation in ancient carbonate rock, “five paleo-structures control accumulation”, has been proposed innovatively; (2) the accumulation theory of tight sandstone gas in craton basins, foreland basins, and rift basins have been well-established; (3) the accumulation mode of “three-micro conveying, near-source enrichment, and sustained preservation” for ultra-deep and weak deformation zones has been established; (4) the accumulation theory of volcanic gas reserves in rift basins with basic elements of hydrocarbon generation troughs has been established and improved; (5) lastly, the accumulation theory of offshore high-temperature, overpressure, and deepwater gas were methodically deepened. The development of geologic theories of natural gas has promoted many new exploration discoveries. The accumulation theory in ancient carbonate reservoirs paved the way for the exploration of Anyue gas field in the Sichuan Basin, the largest single reserve in China. The new understanding of tight sandstone gas accumulation in the foreland thrust belt helped the first gas field discovery in the size 1 × 1012 m3 in an ultra-deep layer in the Kuqa Depression. The accumulation theory of ultra-deep reef reservoirs has guided the exploration of Yuanba gas field, the deepest-buried reef gas field in China. The theory of offshore hydrocarbon accumulation has led to remarkable discoveries in the South China Sea. Some of the said discoveries are the Dongfang 13-2 gas field, the largest gas field in China located in self-supported areas, and the Lingshui 17-2 gas field, which is a hundred billion cubic meters in size and is located in the deepwater exploration field. Keywords: Natural gas, Basic geological theory, Mechanism of gas generation, Accumulation of large gas fields, New exploration findings

Great progress has been made in the exploration of tight sandstone gas resources in Kuqa depression. Great progress has been made in Dibei structural belt, which proves the previously unproven favorable area for tight sandstone gas. The physical properties, controlling factors, and characteristics of tight sandstone from the Ahe (J1a) Formation in the Dibei gas reservoir are analyzed. The results show that the tight sandstone of the J1a Formation is mainly feldspar lithic sandstone, with low porosity (average 9.1%) and low permeability (average 0.09 mD). Compaction (average compaction rate 61.9%) reduces porosity more than cementation (average cementation rate 14.3%). Secondary dissolution pores (average thin section porosity is 3.4%) dominate. The homogenization temperature has two peaks; the first peak is 85–110 °C, and the other peak is 115–140 °C, indicating that oil and gas experienced two filling stages at 12 Ma and 4.5 Ma, respectively. Eodiagenesis, A substage of mesogenetic diagenesis, and B substage of mesogenetic diagenesis happened in the area. Tight sandstone is developed in the B substage of mesogenetic diagenesis. The main controlling factors of diagenesis are: strong dissolution and structural pore increase; oil and gas charging and overpressure. The reservoir forming mode of the Dibei gas reservoir is: crude oil filling in the Late Neogene (12 Ma); reservoir densification in the late deposition of Kangcun Formation (7 Ma), mature natural gas filling in the early deposition of Kuqa Formation (4.5 Ma), and gas reservoir formed after transformation and adjustment in the deposition period of Quaternary (2 Ma). According to this model, it is predicted that the favorable area of the Dibei gas reservoir is in the southeast of the Yinan 2 well. This study provides guidance for the study of tight sandstone gas in other areas of the Kuqa Depression.

It is the consensus that sapropelic matter generated oil initially, subsequently, the oil cracked into gas in the process of hydrocarbon generation evolution; however, there exist a dispute considering how much gas is generated directly by kerogen as well as how to identify it. The experimental samples are low mature sapropelic shale from the Xiamaling Formation in North China; the experimental devices are high-temperature and high pressured golden tube system and normal autoclave thermal simulation; gas generation simulation experiments of original kerogen, residual kerogen and oil from the same shale are developed. It is concluded that: (1) the gas generated from kerogen directly accounts for about 20% after the oil generation peak period. The main gas generating stage is from 422 °C to 566 °C (RO = 1.3%–2.5%), and the amount produces 85.5%. (2) The value of ln (C1/C2) and ln (C2/C3) increase with the growth of evolution degree for both kerogen cracking gas and oil cracking gas. However, at over-mature period, the value of ln (C2/C3) increases for the kerogen cracking gas while the value for oil cracking gas remains constant, and the value of ln (C1/C2) at low heating rate is greater than that at a high heating rate. (3) The new oil cracking gas discrimination chart is established whilst taking into considering the evolution degree. The gas from the Sinian and Cambrian in the Sichuan Basin is oil cracking gas from the preceding understanding. The research results revealed that it’s not kerogen cracking gas but oil cracking gas that is the main target at high evolution degree wherein the sapropelic matter developed, and these can provide important evidence in the determination of the whole process of hydrocarbon generation evolution locus curve of organic matter.