This study analyzes the geochemical characteristics of natural gas composition, carbon isotope, and light hydrocarbon in the eastern belt around the Penyijingxi sag of the Junggar Basin. The result shows the that natural gas content is dominated by alkane gas, with low contents of heavy hydrocarbon and non-hydrocarbon components. The overall carbon isotopic composition of the alkanes shows a trend as δ¹³methane (C₁) < δ¹³ethane (C₂) < δ¹³propane (C₃) < δ¹³butane (C₄), and all δ¹³C₁ values are <−30‰, which are typical of gases of organic origin. The natural gas is mainly coal-derived gas from the Lower Urho formation, mixed with a small amount of oil-associated gas from the Fengcheng formation. The vertical migration of natural gas resulted in the mixing of oil-associated gas and coal-derived gas and the mixing of alkane gas at different stages of the same origin, which should be the origin of carbon isotope inversion. The diffusion migration of carboniferous oil and gas reservoirs has led to differences in gas geochemical characteristics among gas wells. These migration characteristics of natural gas may indicate that the shallow layers are a favorable stratum for the next step of oil and gas exploration in the eastern belt around the Penyijingxi sag.

Clarifying the phase evolution history of hydrocarbon fluids helps formulate exploration and development strategies. The discovery of the Xinguang Gas Field marks a significant breakthrough in the Western Junggar Basin. However, the phase evolution history of this gas field remains unclear, which hinders the formulation of subsequent exploration strategies. This study employs a comprehensive approach, combining organic geochemistry, fluid inclusions, basin modeling, and PVT testing and simulation, to investigate the characteristics and phase behavior of deep-seated hydrocarbon fluids in this gas field. It also examines the charging history, compositional evolution, and temperature and pressure histories of the reservoir, thereby clarifying the phase transition process of hydrocarbon fluids in the Xinguang Gas Field. This study finds that the deep-seated reservoir fluids in the Jiamuhe Formation (Fm.) of the Xinguang Gas Field exhibit low densities of 0.77 to 0.83 g/cm³, high gas-to-oil ratios (GORs) of 1014.41 to 13,054.77 m³/m³, high methane contents of 91.16% to 92.74%, and retrograde condensation characteristics. Additionally, the reservoir temperature and pressure exceed the critical point and the saturation pressure at reservoir temperature, indicating a supercritical condensate gas phase. The present condensate gas in the Xinguang Gas Field is a mixed hydrocarbon from two charging events. Initially, during the Middle–Late Triassic period, both Block 1 and the Xinguang Gas Field were charged with mature oil. Later, from the Late Cretaceous to Early Neogene periods, a secondary charging of highly mature oil and gas occurred in the Xinguang Gas Field, while the reservoir in Block 1 remained largely unchanged. In the co-evolution of reservoir fluid composition, temperature, and pressure, the phase transitions of the hydrocarbon fluids in the Xinguang Gas Field passed through several stages, including liquid black oil (231.9–80.3 Ma), liquid volatile oil (80.3–79.1 Ma), vapor–liquid two-phase volatile oil (79.1–78.3 Ma), vapor–liquid two-phase condensate gas (78.3–69.1 Ma), and supercritical condensate gas (69.1 Ma–present).

The Junggar basin is sandwiched between the Siberian plate, the Kazakhstan plate and the Tarim plate, and is an important part of the Central Asian orogenic belt. Based on the comprehensive analysis of the characteristics of the natural gas composition，carbon isotope, light hydrocarbons and source rocks in the eastern belt around Penyijingxi Sag, Junggar Basin, i.e., our studied area, the genesis and origins of natural gas in this area are discussed. The natural gases in the eastern belt around Penyijingxi Sag, are dominated by alkane gases, and have relatively low contents of heavy hydrocarbons and non-hydrocarbons. Methane is dominant in alkane gas, with volume fraction varies from 70.36% to 93.34%. In non-hydrocarbon gas, the volume fraction of nitrogen varies from 0.69% to 11.95%, and the volume fraction of carbon dioxide varies from 0 to 1.49%. The values of δ13methane(C1), δ13ethane(C2), δ13propane(C3) and δ13butane(C4) of natural gas are in the ranges from −45.57‰ to −31.19‰, −31.69‰ to −24.66‰, −28.76‰ to −23.56‰, −27.96‰ to −23.64‰, respectively. The overall carbon isotopic composition of the alkanes shows a trend as δ13C1 < δ13C2 < δ13C3 < δ13C4, and all δ13C1 values are ≤ -30‰, which are typical of gases of organic origin. The methane and ethane isotopic compositions and the characteristics of light hydrocarbons show that the natural gases in the studied area are dominated by coal-type gas and contain a small amount of oil-type gas. Specifically, the coal-type gas is from the mature to highly mature source rocks of the Lower Urho Formation, and the oil-type gas is from the mature to highly mature source rocks of the Fengcheng Formation. Analysis of gas migration parameters show that, while there was no significant lateral migration of natural gas in the studied area, natural gases once migrated vertically and resulted in the mixing of oil- and coal-type gases as well as the mixing of alkane gases of the same genetic type formed at different stages, which should be the cause of observed reversed carbon isotopic series. The diffusion and migration of carboniferous oil and gas after reservoir formation have led to differences in gas geochemical characteristics among gas wells in this area, which may provide important information for oil and gas exploration in the central Junggar Basin.Keywords: Junggar Basin; geochemistry; natural gas genesis; carbon isotopes; light hydrocarbons

The Central Depression of the Junggar Basin relies heavily on Permian lacustrine mudstone for deep-seated hydrocarbon sealing. This research investigated how the fluorescence parameters of caprock samples responded to the leakage of palaeo-oil zones based on measurements from SEM, Rock-Eval, and X-ray diffraction analysis. First, two sets of control experiments were conducted to establish the proper grain-size range of 100–140 mesh for testing caprock samples in the research area using quantitative fluorescence technology. Subsequently, based on the examination of the rock pyrolysis parameters and the fluorescence parameters against TOC values, the conjecture was formed that the quantitative fluorescence technology test results were mostly unaffected by the primary hydrocarbons. Lastly, four fluorescence parameters were used to assess seal integrity: quantitative grain fluorescence intensity of the extract (QGF E intensity, the meaning of QGF is the same in this study), QGF spectral peaks (QGF λmax), the ratio of QGF intensity to fluorescence intensity at 300 nm on the QGF spectrum (QGF index), and total scanning fluorescence spectral ratio R₁ (TSF R₁). The Permian caprock can effectively seal hydrocarbons as evidenced by the decrease of QGF E intensity and QGF index values with depth. When hydraulic fracturing causes caprock failure, it can lead to complete leakage of hydrocarbons from the palaeo-oil zones. As the depth becomes shallower, the QGF E intensity value increases, the QGF index value decreases. Due to the differences in the migration pathways of hydrocarbons in the caprock, those leaked from the Permian palaeo-oil zone into the well PD1 caprock are mainly condensate and light–normal crude oil, while the hydrocarbons from the Carboniferous palaeo-oil zone into the well MS1 caprock consist predominantly of light–normal crude oil and medium–heavy crude oil.

The northern part of the the Junggar Basin is the Siberian plate, and the western part is the Kazakhstan plate, which is an important part of the Central Asian orogenic belt. This study discusses how fluorescence parameters inside the mudstone caprocks of the Mobei Bugle and Mosuowan Bugle respond to the leakage of palaeo-oil zones. It is based on X-ray diffraction analysis, TOC testing, physical property testing, rock pyrolysis experiments, and image observation. First, using quantitative fluorescence technology, it was established that the appropriate particle size range for the study area mudstone is between 100 and 140 mesh by examining the QGF E intensity and sample loss rate of the control group. Then, the influence of retained primary hydrocarbons inside the mudstone on the test results of quantitative fluorescence technology is speculated to be relatively weak based on an analysis of the correlation between TOC value and total hydrocarbon value, TOC value and fluorescence parameters. The QGF index of the 5265-5302m reservoir in PD1 well ranges from 3.9 to 87.2, with an average of 16.18; the QGF index of the 7034-7195m reservoir in MS1 well ranges from 2.2 to 57.5, with an average of 11.6. The reservoirs of the PD1 and MS1 wells contain palaeo-oil zones, based on the QGF index classification criteria. Both image observation and micro resistivity imaging logging analysis demonstrate that the caprock's physical properties in the PD1 well are inferior to those in the MS1 well. The pore types of the PD1 well caprock are filled dissolution pores and residual intergranular pores, whereas the pore types of the MS1 well caprock are dissolution pores and microcracks. There is a discrepancy of approximately 9 times between the development density of fractures in the MS1 well caprock (0.989 pieces/m) and the PD1 well caprock (0.114 pieces/m). The palaeo-oil zone can be effectively sealed due to the poor physical properties of the PD1 well caprock. The oil testing conclusion of the reservoir is oil-water layer, with a daily oil production of 8.52t. Therefore, as the depth decreases, the QGF E intensity value decreases, and the QGF λmax and TSF R1 values reflect higher hydrocarbon maturity. The MS1 well caprock has good physical properties and cannot effectively seal the palaeo-oil zone. The oil testing conclusion of the reservoir is water layer, with a daily oil production of 4.4t. As the depth decreases, the QGF E intensity value increases, and the QGF λmax and TSF R1 values reflect lower hydrocarbon maturity. Comprehensive analysis suggests that the fluorescence parameters inside the caprock exhibit characteristics related to the degree and form of palaeo-oil zone leakage.Keywords: Quantitative fluorescence technology, Fluorescence parameters, Mudstone caprock, Palaeo-oil zones