Since the 1950s, major breakthroughs have been made in the field of carbonate oil and gas exploration, and large reservoirs have been found in carbonate strata in many countries; however, the validity of highly evolved carbonate source rocks has been controversial. Because of the loss of organic carbon during acid-solution processing in conventional total organic carbon (TOC) determination, we decided to use a new method of reducing acid-solution losses in order to more effectively quantify acid-soluble organic matter in carbonate rock samples. Different levels of acid-soluble organic matter were present in different types of samples, and there was no positive correlation between the content of acid-soluble organic matter and conventionally measured TOC values. However, the thermal evolutionary maturity of samples with high acid-soluble organic matter content is relatively low, and the high hydrocarbon generation conversion rate of acid-soluble organic matter and conventional TOC in carbonate rocks is an important reason for the low residual TOC in highly evolved carbonate rocks. The new method is helpful in re-evaluating the abundance of organic matter in carbonate rocks and in providing evidence for studying hydrocarbon generation and the hydrocarbon capacity of carbonate source rocks.

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).

With the targets of petroleum exploration transferred to the deep and ancient strata, abundant oil and gas resources have been found in the Lower Paleozoic and older strata in central and western China. Due to complex evolutionary processes including multiple episodes of hydrocarbon accumulation and ubiquitously accompanied by secondary alterations, significant uncertainties were remained for the generation time and accumulation processes of these revealed petroleum. In this paper, relative pure Re and Os elements existing in the asphaltene fractions of Lower Cambrian solid bitumen collected from the Guangyuan area, western Sichuan Basin, SW China and another Middle–Lower Ordovician heavy oils in the Aiding area of the Tahe oilfield in the Tarim Basin, NW China were successfully obtained by the sample pre-treatments, and Re–Os isotopic analysis was subsequently carried out for the dating of these two petroleum. The Re–Os isotopic composition indicates a generation time of Guangyuan bitumen to locate between 572 Ma and 559 Ma, corresponding to the late Sinian period of Neoproterozoic era. By the means of Re–Os isochron ages, initial 187Os/188Os ratios, and carbon isotopic compositions, the Lower Cambrian bitumen is supposed to be originated from source rocks of the Doushantuo Formation in the Sinian strata and subsequently migrated into the reservoirs of Dengying Formation. These previously reserved petroleum had been transformed to present bitumen by the destruction of reservoirs caused by tectonic uplift. The Re–Os dating results of Middle–Lower Ordovician heavy oil of Tarim Basin supposed that it was formed between 450 Ma to 436 Ma, corresponding to the Late Ordovician–Early Silurian system, and the generated petroleum is likely to migrate into the Middle–Lower Ordovician karst reservoirs to form early oil reservoirs. With tectonic uplift, these oil reservoirs were degraded and reformed to be present heavy oil reservoirs.

With the targets of petroleum exploration transferred to the deep and ancient strata, abundant oil and gas resources have been found in Lower Paleozoic and older strata in central and western China. Due to complex evolutionary processes including multiple episodes of hydrocarbon accumulation and ubiquitously accompanied by secondary alterations, significant uncertainties remain concerning the generation time and accumulation processes of these revealed petroleum sources. In this paper, relative pure Re and Os elements existing in the asphaltene fractions of Lower Cambrian solid bitumen collected from the Guangyuan area, western Sichuan Basin, SW China and Middle–Lower Ordovician heavy oils in the Aiding area of the Tahe oilfield in the Tarim Basin, NW China were successfully obtained by sample pretreatments, and Re–Os isotopic analysis was subsequently carried out for the dating of these. The Re–Os isotopic composition indicates a generation time of Guangyuan bitumen to between 572 Ma and 559 Ma, corresponding to the late Sinian period of the Neoproterozoic era. By the means of Re–Os isochron aging, initial ¹⁸⁷Os/¹⁸⁸Os ratios, and carbon isotopic compositions, the Lower Cambrian bitumen is supposed to originate from source rocks of the Doushantuo Formation in the Sinian strata and subsequently migrated into the reservoirs of the Dengying Formation. This previously reserved petroleum was transformed into its present bitumen state by the destruction of reservoirs caused by tectonic uplift. The Re–Os dating results of Middle–Lower Ordovician heavy oil of Tarim Basin suggest that it was formed between 450 Ma to 436 Ma, corresponding to the Late Ordovician–Early Silurian system, and the generated petroleum likely migrate into the Middle–Lower Ordovician karst reservoirs to form early oil reservoirs. With tectonic uplift, these oil reservoirs were degraded and reformed to the heavy-oil reservoirs of today.