Journal of Natural Gas Geoscience最新文献

The classification system, effective reservoir control elements, and major enrichment and exploration modes of helium resources in China are analyzed based on the source of helium, carrier, geological background, and anatomy of typical helium-rich fields. Firstly, based on the special characteristics of helium and the correlation analysis of natural gas accumulation and reservoir formation, we analyzed and sorted out the helium resource and play type classification scheme and classification system in China from nine aspects, namely, the source of helium parental sources, helium type diversities, the storage and carrier types, the technically and economically recoverable characteristics of carrier gases, the carrier gas genesis, the main components of carrier gases, the matching combination of helium sources and reservoirs, background of prototype basin structure, and helium content, to lay the foundation for the subsequent targeted and detailed studies and evaluation programs in different categories. Secondly, the analysis points out the characteristics of helium resource types in the east, middle, and west of China in terms of longitudinal and transverse distribution, tectonic dynamics, geological and geochemical characteristics, and key conditions for the formation of helium deposits. Thirdly, from the perspective of the helium “generation-migration-accumulation” system and the controlling elements and effectiveness of helium-rich reservoir formation, we analyze the effective controlling elements of helium accumulation and the related problems that deserve attention in geological evaluation and point out the misunderstandings in helium reservoir formation and exploration evaluation. Last but not least, from the perspective of basin tectonic background, helium enrichment controlling mechanism and exploration direction, the exploration and evaluation direction and classification scheme for the four element combination zones of “original basin–structure–lithology–carrier gas” helium accumulation in China have been proposed, based on which, four types of basins and eight types of helium-rich zones in China have been sorted out. In these eight types of helium-rich zones, eight typical helium-rich field enrichment and exploration patterns, including the ancient uplift type of China's craton, fracture-fold variant of the craton margin, fracture-rise type of depression basin, slope bulge and uplift type of foreland basin, fracture-convex type of fracture basin, and U/Th-rich basement type of basin were analyzed, and the main controlling factors of the formation of different types of helium-rich deposits were analyzed, which will provide a reference for the subsequent exploration and discovery of similar helium-rich areas and exploration target evaluation.

The crude oils of the Sarvak reservoir were studied by integrated geochemical, inorganic and isotopic analyses to evaluate the origin, depositional conditions, geological age, thermal maturity of the source rocks and possible facies from which these oils were sourced. This study provides new insights into the Middle-Jurassic age source rock in the Azar Oilfield. This is the first geochemical study in Azar Oilfield where non-biomarker parameters and biomarker parameters were utilized to achieve the objectives. The n-alkane distribution pattern along with their standard ratios, including CPI (0.83–1.03), TAR (0.18–0.29) and isoprenoids (Pr/Ph, 0.52–0.65) as well as pristane/n-C₁₇ versus phytane/n-C₁₈ cross-plot indicate a marine source of the organic matter deposited in an anoxic condition. The sterane parameters such as C₂₇ and C₂₉ are characterized by the predominance of C₂₇ααα-20R steranes (41%–49%) and also depict the algal source of organic matter. The organic input and facies of the source units were also determined by terpanes C₂₉/C₃₀H, Ts/Tm, C₃₅/C₃₄-HH, and DBT/Phen. The relatively high ratio of C₂₉/C₃₀H along with the ratios of Ts/Tm (<0.5) and C₃₅/C₃₄ (>0.8) reflect the carbonate marine facies of the source rocks. Furthermore, the higher values of the homohopane index (>0.1) along with the low ratio of the gammacerane/C₃₀-H (0.06–0.22) as well as the high ratio of V/Ni (>1) further indicate anoxic environments. The dibenzothiophene/phenanthrene ratios of the oil samples (from 2.43 to 3.25) indicate the marine carbonates/marl zone. This genetic classification is also supported by stable carbon isotopic compositions (δ¹³C). Most of the maturity-related biomarkers and non-biomarker parameters such as CPI, steranes-C₂₉S/(S + R), ββ/(αα+ββ), moretane to hopane (M₂₉/C₃₀H), pentacyclic terpanes C₂₇Ts/(Ts + Tm), C₃₂-S/(S + R) hopanes, and methyl phenanthrene index agree that the analyzed oils have originated from mature source rocks. Ultimately, this study has demonstrated that analyses of biomarkers and their stable isotope compositions (δ¹³C and δ³⁴S) complemented with trace element data provide an excellent novel tool for better understanding the basic concepts in petroleum basins and for solving a wide range of problems during petroleum exploration.

Aiming to address whether coal-bed methane and shale gas can form helium-rich gas reservoirs, this paper employs geochemical research methods to analyze the content of uranium (U) and thorium (Th) in coal and shale, as well as the helium content in coal-bed and shale gas reservoirs. An objective evaluation of the helium-generating potential and helium-bearing properties of coal and shale is provided. It is observed that although the content of U and Th in coal and shale is significantly higher than in other rocks, resulting in relatively more helium production from radioactive decay, the large amount of natural gas generated by coal and shale exerts a serious dilution effect on helium, making it difficult for coal beds and shale to enrich helium. The organic carbon content of coal is much higher than that of shale, leading to a greater generation of natural gas from coal beds compared to shale. Consequently, the helium content of coal-bed gas is much lower than that of shale gas. The helium rich shale gas and coal bed gas found in a few areas are attributed to the helium supply from other rocks in the gas reservoir, which is mostly distributed on or near the old granite masses, or in the tectonic active zones. In addition to capturing some of the helium produced by the coal beds and shales themselves, helium from other rocks, particularly from ancient basement rocks, is also captured, though this is not common.

The Middle Permian Lucaogou Formation is the most significant source rock in the eastern Junggar Basin. Previous studies have confirmed its excellent hydrocarbon-generating potential in the Jimsar Sag. However, its potential in other areas of the eastern Junggar Basin remains uncertain. Based on total organic carbon and pyrolysis, organic petrology, hydrocarbon simulation experiments, basin simulation, and combined well-seismic coupling interpretation, this study systematically compares the hydrocarbon-generating potential of the Lucaogou source rock in the Jimsar Sag with other areas of the eastern Junggar Basin. It discusses the sedimentary environment of high-quality source rocks and depicts the distribution of practical source kitchens. The Lucaogou source rocks in the eastern Junggar Basin are oil-prone, dominated by type I–II kerogen, and generally classified as good to excellent source rocks. Nowadays, the area of the Lucaogou source rocks that have entered the main oil-generating window is approximately 11 × 10³ km². Except for the bulge area, the Lucaogou source rocks in the eastern Junggar Basin successively entered the hydrocarbon-generating threshold during the Jurassic and the main oil-generating window in the Cretaceous. The Lucaogou source rocks in the Jimsar Sag and other parts of the eastern Junggar Basin share similar biomarker fingerprints, characterized by relatively low ratios of Pr/Ph, Pr/n-C₁₇, Tm/C₃₀ hopane, C₁₉/C₂₀ tricyclic terpene, and C₂₄ tetracyclic terpene/C₂₆ tricyclic terpene, and high β-carotene content, gammacerane index, and Ts/Tm ratios. These characteristics reflect deposition in a strongly reducing brackish lacustrine environment with parental sources dominated by lower organisms such as algae and bacteria. Generally, the Lucaogou source rocks in the eastern Junggar Basin have an oil-generating intensity of more than 3 × 10⁶ t/km². Several oil-generating centers with an intensity of more than 5 × 10⁶ t/km² have developed in the front of the Bogda Mountain, Jimsar Sag, Dongdaohaizi Sag, Wucaiwan Sag, and Shazhang Fault Zone, covering a total area of approximately 12,500 km². These characteristics of the Lucaogou source rocks promise favorable potential for forming large and medium oil fields. The results further consolidated the oil and gas resources in the eastern Junggar Basin and provided valuable references for exploring future oil and gas fields.

Understanding the key timings related to petroleum evolution is crucial for optimizing exploration targets and assessing oil/gas resources, attract petroleum geologists’ attention worldwide. Recently, hydrocarbon (oil and bitumen) Re–Os isotope dating has been innovatively applied to constrain the timing related to oil/gas generation, however, the resulting Re–Os isochron ages can be complex and challenging to interpret. This study utilizes various geochemical and geochronological data from Sinian to Cambrian natural gas reservoirs in the Sichuan Basin to reconstruct the hydrocarbon evolution process and discuss the significance of different bitumen Re–Os dating results. The gas accumulation in the Sinian-Cambrian reservoirs experienced four stages of evolution: (1) initial oil generation during the Ordovician to Silurian periods, (2) secondary oil generation during the Triassic period, (3) gas generation through thermal cracking of liquid oil from the Jurassic to Cretaceous periods, and (4) gas reservoir redistribution since the late Cretaceous. The Re–Os dates (ca. 485 Ma) of low maturity and biodegraded bitumen from the western Sichuan Basin record the oil generation during the Ordovician before the Caledonian tectonic event. The Re–Os dates (ca.184–128 Ma) of highly mature bitumen associated with MVT Pb–Zn deposits in northern Sichuan Basin provide insights into both liquid oil-cracking and thermochemical sulfate reduction (TSR) processes. The complex Re–Os dates (ca.414 Ma, ca.154 Ma) of highly mature bitumen from the central Sichuan Basin may represent different periods related to either oil or gas generation. Future studies should explore the genetic type, maturity, thermal cracking, or TSR degrees of bitumen to better understand the significance of Re–Os dates.

Shale oil and gas resources mainly exist in the pore and fracture system. Quantitative characterization of pore development characteristics and gas-bearing properties is crucial for shale reservoir evaluation. The pore development of shale reservoir exhibits strong complexity and heterogeneity, and research on pore development characteristics of coal measure shale lags behind that of marine shale reservoir. Hence, it is urgent to investigate the pore heterogeneity characteristics of coal-bearing shale and its influence on gas bearing properties. Therefore, the coal-bearing Cretaceous Nenjiang shales from the Songyuan area of the Songliao Basin were selected as the research object in this study. Through total organic carbon (TOC) analysis, X-ray diffraction experiments, porosity analysis, nitrogen adsorption–desorption experiments, and methane isothermal adsorption experiments, the characteristics of pore structure, heterogeneity, and gas bearing properties of coal-bearing shale were analyzed. The influence of rock and mineral components on pore structure and heterogeneity characteristics, the relationship between pore structure characteristics and fractal characteristics, and the effects of pore structure and heterogeneity on gas bearing properties were also discussed. The results show that: (1) The organic matter abundance of the shale in the Nenjiang Formation does not change significantly (the average TOC content is 2.38%). Ink bottle-shaped pores are mostly developed, and the Nenjiang shale is rich in clay minerals (average content 55.6%), with slit-shaped pores mostly developed. The pore surface of shale exhibits obvious fractal characteristics, with average fractal dimensions D₁ and D₂ of 2.54 and 2.74, respectively, indicating that the internal structure is more complex than the surface structure. (2) The enrichment of organic carbon increases the specific surface area by affecting the development of micropores and pores, consequently increasing the fractal dimension of pores. Similarly, the development of clay minerals increases the number of mesopores and macropores, thereby increasing the fractal dimension of pores. (3) Small pores develop larger specific surface areas, which increases the complexity and heterogeneity of the pore structure. This promotes remarkable fractal characteristics, expands the adsorption sites, and improves the adsorption capacity. This work will provide a scientific theoretical basis for the comprehensive evaluation of coal-bearing shale reservoirs and research on shale gas reservoir formation theory.

This study aims to address the problem of porosity preservation in the Mangahewa Formation of five main hydrocarbon fields covering onshore and offshore of the Taranaki Basin. An integrated reservoir characterization of the Middle to Late Eocene Mangahewa Formation is achieved through petrophysical evaluation, sedimentological and petrographical descriptions, and well log analysis methods. Petrophysical parameters (porosity and permeability) were acquired from the available core analysis and using mathematical equations to obtain other petrophysical matrices such as normalized porosity index (NPI) and reservoir quality index (RQI). Factors that affected Mangahewa reservoir were studied through thin-section microscopy and well-log analysis helped to measure the reservoir and hydrocarbon potentiality in the Mangahewa Formation. The Mangahewa Formation is dominated by sandstone and a range of marginal to shallow marine facies with varying hydraulic flow units (HFU). The Mangahewa Formation has a high positive correlation in porosity-permeability relationship and has a maximum of 4.67 μm RQI and 20.08 μm FZI (Well Kapuni-14) which reflect potential reservoir. The Mangahewa Formation observed from Wells Kapuni-14, Maui-A1G, McKee-16A, and Mokau-1 are dominated with 59.6%, 56.4%, 79.3%, and 68% of macro- and megapores, respectively. The presence of authigenic clay and calcite cement has greatly reduced the reservoir quality; however, primary and secondary pores are still observed within the Mangahewa sands. Moreover, well log analysis was carried out on four wells in Taranaki Basin, to run a qualitative and quantitative analysis of the Mangahewa reservoir. Eight potential reservoir zones were examined, revealing that the Mangahewa Formation has a very low shale volume of less than 6%, good effective porosity ranging between 11.0% and 13.3%, up to 36.2% of average water saturation and maximum of 69.8% average hydrocarbon saturation. In conclusion, from this comprehensive study, it can be deduced that the Mangahewa Formation possesses fair to good reservoir quality and hydrocarbon potentiality.

Scholars have primarily focused on statistical analysis of exploration practices and simple physical simulation experiments when investigating the relationship between stratigraphic dip and hydrocarbon resources during the hydrocarbon accumulation period. However, there is a notable lack of research on the theoretical relationship between stratigraphic dip and hydrocarbon resources during this critical period. This study addresses this gap by exploring the principle of minimum energy dissipation rate governing oil and gas migration. Through this principle, the existence of a stratigraphic dip window for hydrocarbon migration and accumulation system is strictly proved during the hydrocarbon accumulation period. It is established that when the stratigraphic dip window coincides with the hydrocarbon accumulation period, the effective driving power for hydrocarbon migration is at its weakest, resulting in the lowest energy dissipation rate within the hydrocarbon system. Consequently, the hydrocarbon migration and accumulation yields the highest efficiency, leading to the greatest reserves of hydrocarbon resources. This study resolves the puzzle of why the amount of hydrocarbon resources in 44 natural gas-effective zones and 49 oil-effective zones, that have been put into commercial development in China, as reported by Hou et al. (2021), exhibit the statistical characteristic of “downward parabola of opening” in their average stratigraphic dip during the main hydrocarbon accumulation period. Furthermore, it explains the influence of the stratigraphic dip size during the hydrocarbon accumulation period on oil-gas reservoir formation. Moreover, the theory is used to investigate the evolutionary changes in the stratigraphic dip window of tight gas reservoirs in the Upper Paleozoic strata of the Ordos Basin. The study traces the transition of Upper Paleozoic high-pressure tight paleo-gas reservoirs, where the sum of net buoyancy gradient, excess pressure gradient, and discharge pressure gradient serve as the effective driving force of hydrocarbon migration, to modern low-pressure tight gas reservoirs, where the sum of net buoyancy gradient and discharge pressure gradient prevail. Correspondingly, during the hydrocarbon accumulation period, the stratigraphic dip window of the high-pressure tight paleo-gas reservoirs is relatively small (0.2°–0.3°), gradually evolving into the comparatively larger stratigraphic dip window (0.35°–0.45°) characteristic of the current low-pressure tight gas reservoirs.

Taking the deep-ultra deep glutenite reservoirs in the Upper Wuerhe Formation of Permian in Fukang Sag and Dongdaohaizi Sag as the research object and representative of the eastern Junggar Basin, its characteristics and main controlling factors are analyzed using various methods, including core analysis, thin section examination, and scanning electron microscope observation. High-pressure mercury injection and logging imaging were also employed to reveal the reservoir that Fukang and Dongdaohaizi sags harbor deep-ultra deep glutenite reservoirs, with Fukang Sag being a typical low porosity to ultra-low permeability reservoir, while Dongdaohaizi Sag is a low porosity to low permeability reservoir. Reservoir space types vary between the two sags, with Fukang Sag characterized by microfractures and corrosion pores, while a large number of corrosion pores with fewer fractures existing in Dongdaohaizi Sag. Both compaction and cementation exhibit a strong destructive effect on the reservoirs in the eastern Junggar Basin. However, the compaction effect in Fukang Sag is very strong, and the dissolution effect is weak. The large number of fractures generated by overpressure becomes an effective channel for ultra-deep oil and gas migration. The cracks in the Dongdaohaizi Sag are underdeveloped, and a large number of intra-particle corrosion pores generated by the dissolution of feldspar and turbidite improve reservoir properties. In addition, its rich turbidite also plays a compressive and pore retention role. There are two types of reservoir models developed in the Upper Wuerhe Formation of Permian in the eastern Junggar Basin: the deep fracture model represented by the Fukang Sag and the solution pore model rich in turbidite in Dongdaohaizi Sag. These models create favorable conditions for oil and gas accumulation in the deep-ultra deep reservoirs in the depression area.

The evaluation of potential helium source rocks’ effectiveness is a core issue in the field of helium resource exploration and development. However, previous studies predominantly rely on uranium (U) and thorium (T) contents and the age of the rock for evaluating the effectiveness of potential helium source rocks, which fails to fully characterize the key factors affecting their effectiveness. Therefore, this paper takes four typical potential helium source rocks—granite, mud shale, gneisses, and bauxite, as the research object. Through the establishment of a calculation model for accumulated dissolved helium in pore water, combined with gas reservoir examples, a quantitative analysis of dissolved helium accumulation and exsolution in the pores of each potential helium source rock is carried out. This analysis aims to discuss and summarize the effectiveness of each potential helium source rock and the evaluation method for identifying effective helium source rocks. It is believed that: (1) The exsolution of dissolved helium accumulated in the pores of potential helium source rocks into free helium on a large scale under suitable conditions is the key prerequisite for identifying their effectiveness; (2) In addition to the content of U and Th elements, parameters such as large volume, suitable porosity, and water saturation, the good matching relationship of “sedimentary and burial history, gas accumulation history and tectonic evolution history”, and relatively specific helium generation ability are also the key parameters for judging the effectiveness of potential helium source rocks; (3) By establishing the calculation method of dissolved helium enrichment efficiency (η_He), it is concluded that under similar conditions, free helium enrichment is most easily achieved in granite, followed by mud shale and bauxite, while gneiss poses the greatest difficulty.