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The West Barents Sea Basin in the Arctic is one of the most promising petroleum basins in the world. With the latest data from the IHS database, this study investigated the petroleum geology of the basin, documented the distribution characteristics of petroleum resources, systematically analyzed the petroleum systems and plays, evaluated the resource potential, and predicted the favorable exploration fairways in the West Barents Sea Basin. The results show that regionally, discovered oil and gas accumulations are mainly distributed in the southwest area of the basin; stratigraphically, oil and gas reserves are mainly confined to the Jurassic and Triassic reservoirs, which host 72.6% and 15.5% of the total proved and probable reserves, respectively. The basin has two known petroleum systems: the Jurassic/Triassic composite petroleum system and the Permian/Carboniferous composite petroleum system. The resource evaluation by the Monte Carlo statistical methodology indicates that the means of undiscovered resources in the West Barents Sea Basin are 487.4×106 t of oil, 1375.6×109 m3 of gas, and 84.6×106 t of condensate, amounting to 1681.9×106 t, of which the gas accounts for 66.0%. Based on the results of resource evaluation and comprehensive analysis of petroleum geology, two favorable exploration fairways were selected: the favorable exploration zone of the Jurassic play and the favorable exploration zone of the Triassic play in the southern area of the basin.

Western Hunan province and its surrounding areas are significant targets for shale gas exploration and development in southern China, where the black shale of the lower Cambrian Niutitang Formation and Wunitang Formation is extensively distributed. Geochemical analysis was conducted on the lower Cambrian black shale from a new exploration well of XAD1 located at the southeast margin of the Yangtze paraplatform, followed by a discussion on gas-bearing properties using molecular dynamics simulation. The geochemical characteristics indicate that the black shale in well XAD1 was primarily deposited in a strongly reducing marine environment, with organic matter predominantly composed of type I kerogen derived from algae. Currently, it has reached a stage of high to over maturity with limited potential for liquid hydrocarbon generation. The recovery of the original hydrocarbon generation potential shows that they are excellent source rocks and have completed the main hydrocarbon generation evolution. Despite the favorable conditions for shale gas formation observed in well XAD1, the low measured gas content within the Niutitang Formation suggests that other geological factors may have contributed to a substantial loss of shale gas. Gas adsorption simulation reveals that the maximum methane adsorption capacity (15.77 m3/t) was achieved by Niutitang shale during the late Silurian period when there was an abundant source of natural gas without any influence from CO2, H2O or other molecules. However, due to a lack of natural gas replenishment and subsequent tectonic uplift and subsidence causing variations in temperature and pressure, the methane adsorption capacity gradually decreased (to 6.56 m3/t). Furthermore, water occurrence within the shale reservoir further reduced the methane adsorption capacity (below 2 m3/t), while tectonic activities exacerbated the loss of shale gas potential within this study area. The findings indicate that the dynamic alteration of gas-bearing properties in shale reservoirs due to tectonic movements is a crucial factor influencing the success rate of shale gas exploration in the study area, provided that there are sufficient gas resources and superior reservoir conditions. [ABSTRACT FROM AUTHOR]

Diagenesis is one of the most predominant factors controlling reservoir quality in the deeply buried siliciclastic sandstones of the third member in the Eocene Shahejie Formation (Es3), in the Raoyang Sag, the Bohai Bay Basin. In this study, thin section, cathodoluminescence (CL), scanning electron microscope (SEM), X-ray diffraction (XRD), Raman spectrum, carbon and oxygen isotopes, and fluid inclusion analyses are used to restructure paragenetic sequences and detect origins of carbonate cements recorded in this deeply buried member. Based on petrographic analyses, the Es3 sandstones are identified as lithic arkoses and feldspathic litharenites at present, but derived from original arkoses and lithic arkoses, respectively. Geohistorically, the Es3 sandstones have undergone two diagenetic episodes of eogenesis and mesogenesis. Events observed during eogenesis include chemical compaction, leaching of feldspar, development of chlorite coating and kaolinite, precipitation of the first generation of quartz overgrowth (QogI), dissolution of feldspar, and precipitation of calcite and nonferroan dolomite cement. Mesogenetic alterations include chemical compaction, precipitation of kaolinite aggregate and the second generation of quartz overgrowth (QogII), precipitation of ankerite, development of I/S and illite, and formation of pyrite. Carbon and oxygen isotopic data show that calcite cements are characterized by 13C ( δ 13 C PDB ranging from -0.7‰ to 1.0‰ with an average of 0.1‰) and 18O ( δ 18 O SMOW varying from 12.3‰ to 19.0‰ with an average of 16.2‰); these stable isotopic data combined with Z value (from 114.69 to 122.18) indicate skeletal debris ( δ 13 C PDB ranging from -1.2‰ to -1.1‰ with an average of -1.15‰; δ 18 O SMOW varying from 23.0‰ to 23.2‰ with an average of 23.1‰) and ooids in adjacent carbonate beds involved in meteoric water and seawater from outside jointly served as the carbon sources. For nonferroan dolomite, the δ 13 C PDB value of -4.1‰ is a little bit negative than the calcite, and the δ 18 O SMOW of 14.3‰ is coincident with the calcite, which suggest the nonferroan dolomites come from the diagenetic fluids with a similar oxygen isotopic composition to that of the calcite but modified by the external acidic δ 13C-depleted water. However, the ankerites are actually rich in 12C ( δ 13 C PDB ranging from -10.0‰ to -1.2‰, mean = − 4.3 ‰) and 16O ( δ 18 O SMOW varying from 10.1‰ to 19.4‰, mean = 14.9 ‰), when combined with the distribution of cutting down along the direction pointing to sand-body center from the margin and microthermometric temperature (Th's) data mainly varying between 115.2°C and 135.5°C with an average of 96.0°C, indicating the main origination from the Es3 source rocks with effective feldspar buffer action for the acidic fluids in the margins of the Es3 sandstones. In addition, the necessary elements for ankerite such as Fe2+, Ca2+, and Mg2+ ions also come from organic matter and clay minerals during thermal maturation of the Es3 source rocks. The study provides insights into diagenetic processes and origination of carbonate cements in the Es3 sandstones; it will facilitate the cognition of predictive models of deeply buried sandstone reservoirs to some extent, which can reduce the risks involved in oil and gas exploration and development. [ABSTRACT FROM AUTHOR]

Unconventional tight oil reservoirs have recently emerged as a significant source of oil worldwide, and juxtaposed to organic‐rich source rocks, tight mixed siliciclastic–carbonate sedimentary reservoirs are widely found. In China, such reservoirs are mainly found in saline lacustrine basins. In this paper, we conduct a systematic study on advantageous source–reservoir combinations (SRCs) in the Cretaceous Xiagou Formation in the Qingxi Sag of the Jiuquan Basin, a tight saline lacustrine and mixed siliciclastic–carbonate sedimentary oil reservoir. Mixed sediments result in multiple SRCs as follows: self‐contained SRC, thick interbedded‐type SRC, thin interbedded‐type SRC, and down generated‐up stored SRC. Geochemical characteristics of organic matter in the Cretaceous Xiagou Formation are established on the basis of Rock‐Eval pyrolysis and total organic carbon (TOC) and vitrinite reflectance analyses. TOC (0.5–4.12%, av. 1.62%) and S2 (0.36–26.63 mg/g, av. 5.62 mg/g) indicate a good hydrocarbon generative potential. The organic matters contain predominantly Type II kerogen with minor contributions from Type I kerogen. The samples analysed have vitrinite reflectance in the range of 0.65–1.0%Ro, and pyrolysis Tmax in the range of 430–450 °C indicate that the source rocks are early mature to mature and within the main stage of oil generation. The tight oil resources are divided into 4 classifications according to TOC versus S1 diagram, and dolomitic mudstone in lower K1g3 and K1g1 is primarily considered to be potentially generative and productive. Reservoir characterization such as porosity, permeability, and pore‐size distribution derived from nuclear magnetic resonance indicates that nano‐meter‐sized pores dominate pore size distribution, regardless of the lithology. Fractures contribute to the creation of relatively higher productivity reservoirs. The statistics of oil testing results shows that the daily oil productions increased basically from the down generated‐up stored SRCs to thin interbedded‐type SRCs to thick interbedded‐type SRCs to self‐contained SRCs. The movable oil saturations derived from nuclear magnetic resonance have the same changes as daily oil production. The self‐contained SRCs and the thick interbedded‐type SRCs are identified as advantageous SRCs that are important for tight oil prediction. [ABSTRACT FROM AUTHOR]