For many years, the exploration of natural gas in the large structural belts of the northern Qaidam Basin has yielded unsatisfactory results, which may be related to the traditional interpretation of deep-seated paleo-anticlinal traps based on the dual-layer structural model. Through seismic data interpretation and structural analysis, it is concluded that the dominant structural style of this area is mainly of synsedimentary compressional strike-slip structures that developed in the late Himalayan period. Strongly deformed structures occur as a ruptured anticlines with faults extending to the surface, resulting in low-abundance traps of underfilled gas accumulations. In contrast, the gentle anticline of Chahan, which developed as a synsedimentary overlying anticline over uplifted fault blocks associated with deep compressional strike-slip movement, exhibits more favorable conditions for hydrocarbon accumulation. Because deformation related with strike-slip belt is primarily concentrated along fault zones, the intervening sags generally experience relatively weak deformation, which is conducive to the preservation of gas reservoirs and therefore represents favorable targets for gas exploration as long as there is a gas source rocks. The Pingdong Sag, located between the Altun, Jianshan, and Eboliang structural belts, experienced gentle deformation during the Cenozoic and exhibits relatively complete distribution of three Mesozoic–Cenozoic tectonic layers, containing all geologic elements of a gas system. The deep-buried Jurassic source rocks within the sag are characterized by larger thickness and stable distribution and are currently in the stage of gas generation, suggesting that major gas accumulation occurred during the late Himalayan period. The fault-block structures developed in the lower Cenozoic tectonic layer provided effective migration and accumulation system. The lower Youshashan Formation (N21) delta front sandstone bodies and overlying mudstone intervals form favorable reservoir-caprock assemblages, while the lacustrine mudstones and evaporites in the upper tectonic layers (N22, N23, Q) offer an effective regional sealing conditions for gas preservation. The analysis suggests that the Chahan anticline, located above the source-rock and developed contemporaneously with major gas-generation phase, has the potential to host a large gas field. Furthermore, subtle traps beneath the regional sealing strata, including low-amplitude anticlines, fault-block traps, lithological traps on tectonic setting, and fault–sandstone combination traps within the sub-sags of the Pingdong Sag, constitute favorable exploration targets for natural gas. This study also has reference significance for natural gas exploration in regions characterized by tectonic settings similar to those of the Qaidam Basin.
Optimal well spacing is crucial for maximizing single-well productivity and efficiently utilizing reserves, making it a core indicator for evaluating development effectiveness. Due to the influence of natural fractures and the production sequence, the annual well opening pressure and inter-well interference in the Weirong Gas Field have led to an intensifying year-on-year decline, which have seriously affected both production and construction outcomes. To reduce inter well interference and improve productivity and construction efficiency, this study analyzes the interference mechanisms between wells. The results show that the main causes of interference are natural fractures and older well energy depletion. Based on these insights, a numerical simulation method was used to quantitatively evaluate the impact of varying well spacing, degrees of fracture hit and cumulative gas production from older wells on the Estimated Ultimate Recovery (EUR) of new wells. Consequently, a targeted and differentiated well spacing optimization design method was developed. The results show that: (1) The smaller the well spacing and the higher the degree of fracture hit, the greater the decrease on the EUR of new wells, with impact degrees of 7.1%-15.1%; (2) The smaller the well spacing and the higher the cumulative gas production from older wells, the greater the negative impact on the EUR of new wells, ranging from 8.1% to 28.3%; (3) In areas with well-developed natural fractures, a recommended well spacing of 350-450 m is suggested based on the fracture hit degree; (4) Near older wells, where energy depletion is prominent, a well spacing of 400-500 m is recommended. Following the application of well spacing optimization, the average well opening pressure increased by 9.3 MPa, and the EUR improved by 22.8%, demonstrating a favorable application effect and providing reference for well pattern arrangement in similar shale gas reservoirs.
The Ordovician ultra-deep carbonate reservoirs in the Tarim Basin are rich in oil and gas resources. However, due to the influence of multiple periods of tectonic activity, their distribution shows strong heterogeneity. In regions characterized by fault-controlled fractures and caves, traditional reservoir quality evaluation methods based on physical property parameters are subject to considerable uncertainty. In contrast, methods incorporating geomechanical parameters show notable advantages. In this study, geomechanical parameters—such as present-day in-situ stress, elastic modulus, and natural fracture density—were quantitatively characterized. A geological model of the carbonate fracture-cavity system was established, and a reservoir quality evaluation factor was defined and calculated to enable a quantitative evaluation of ultra-deep carbonate reservoir quality. The results indicate that: (1) In fault-controlled fracture-cavity ultra-deep carbonate reservoirs, the spatial distribution of geomechanical parameters has strong heterogeneity and significantly affected by fault structure. This distribution is segmented along the fault extension direction. Both the elastic modulus and natural fracture density indicate elevated values near fault zones, while present-day in-situ stresses are relatively lower in these areas. (2) Reservoir geomechanical parameters are strongly responsive to the structural and geological characteristics of fault-controlled fracture-cavity carbonate oil and gas reservoirs. The proposed evaluation methods are effective in evaluating reservoir quality and provide a valuable geological reference and support for the efficient exploration and profitable development of fault-controlled fracture-cavity ultra-deep carbonate reservoirs.
The Ordos Basin is the largest natural gas producing region in China. Recent discoveries of two helium-rich natural gas fields (Dongsheng and Qingyang) shows promising helium resource potential. Sulige Gas Field, the largest natural gas field in China, was analyzed to evaluate its helium resource potential. Comprehensive geochemical analyses were conducted, examining natural gas components, alkane gases, carbon isotopic signatures of carbon dioxide, helium concentrations, and helium isotopic ratios within the gas field. Preliminarily studies identified the geochemical characteristics of natural gas and helium in the Paleozoic strata of Sulige Gas Field, and explored the main controlling factors of helium reservoir formation. The results show that the composition of natural gas in the Upper Paleozoic is obviously different. Specifically, Upper Paleozoic natural gas exhibited typical wet gas at the mature stage and dry gas at the over-mature stage, while Lower Paleozoic natural gas is mainly dry gas with partial contribution of wet gas. The Upper Paleozoic is dominated by thermogenic natural gas, predominantly middle-late humic gas (coal-derived) originating from Carboniferous and Permian coal measure source rocks. In contrast, the Lower Paleozoic is dominated by late sapropelic dry gas and oil cracking gas. The helium concentrations in Paleozoic natural gas is higher than in conventional natural gas (0.03%), which belongs to middle helium gas, and the Upper Paleozoic is exceeding those of the Lower Paleozoic. The helium accumulation in the Sulige Gas Field is influenced by the ancient and modern structural location, the high helium generation intensity and relatively low hydrocarbon generation potential of helium source rocks (such as U–Th-rich basement granite and granite gneiss), the development of basement faults, and the complex gas–water relationship, which is favorable for the helium to dissolve out of the water and enter into the natural gas reservoirs.
Different helium source rocks exhibit varying characteristics, including differences in the content and occurrence states of precursor elements such as uranium (U) and thorium (Th). In sedimentary rocks, U and Th mainly exist in adsorbed and (or) complexed states of organic matter and clay minerals. The primary migration of helium generated in sediments is liable to occur due to the lack of mineral crystal restraint. Hence, source rocks and reservoir rocks in gas pools act as the primary effective helium source rocks in sediments. In contrast, other sedimentary rocks are less effective as helium sources due to the fact that high porosity results in prolonged helium saturation, thereby restraining the desolubilization and secondary migration of helium. In igneous rocks, isomorphous U and Th are mainly enriched in silicate and phosphate minerals. Temperature is the main controlling factor affecting their primary migration. Granite, characterized by low porosity and limited helium solubility, can experience large-scale release helium under conditions of tectonic uplift and abnormally high temperatures, acting as an effective helium source rock for helium-rich natural gases. Various forms of U and Th can exist in metamorphic rocks, which have higher porosity and higher soluble helium contents than granite, but this result in greater difficulty in helium release. Although the direct source rocks and reservoirs of natural gas reservoirs are effective helium source rocks, it is difficult to form He-rich natural gas due to the influence of hydrocarbon dilution. Sufficient He supply from basin basement or mantle-derived sources is a key condition for natural gas reservoirs to be rich in He.
A billion-ton mega shale oil field has been discovered in the Jimsar Sag, located in the Eastern Uplift of Junggar Basin, which reveals the good hydrocarbon-generating potential of the source rocks in the Middle Permian Lucaogou Formation. This paper systematically evaluates the hydrocarbon-generating potential and formation environment of the Lucaogou source rocks in the Gucheng Sag, which is adjacent to the Jimsar Sag, and draws the distribution range of the source kitchen, and compares them with those of the Lucaogou source rocks in the Jimsar Sag. The results show that the kerogen type of Lucaogou source rocks in the Gucheng Sag is mainly of type II/III-III, dominated by good-excellent source rocks, and the type and abundance are slightly inferior to those in the Jimusar Sag. In the Middle and Late Jurassic, the Lucaogou source rocks in the Gucheng Sag entered the hydrocarbon-generating threshold, and now, the area entering the main oil-generating window reaches 212 km2. Although both of them are lacustrine deposits, the Lucaogou source rocks in the Gucheng Sag have slightly higher Pr/Ph, Ts/(Ts + Tm), C19/C21 tricyclic terpane, C24 tetracyclic terpane/C26 tricyclic terpane ratios, and somewhat lower C28 regular sterane content than the Jimsar Sag, suggesting that Lucaogou source rocks were deposited in an oxidizing-reducing transitional environment of a specific salinity in the Gucheng Sag. There was a certain amount of terrestrial higher plant input in addition to the contribution of algal and microbial biota in the Lucaogou source rocks in the Gucheng Sag.The Lucaogou source rocks have developed four centers with a thickness greater than 160 m in the Gucheng Sag, covering a total area of about 420 km2. In the southern part of the sag, three hydrocarbon-generating centers with an oil-generating intensity greater than 2000 x 103 t/km2 have developed, covering a total area of 130 km2. The research results further strengthen the resource base of the Middle Permian petroleum system in the Junggar Basin and lay the foundation for the next step of petroleum exploration in the Gucheng Sag. (c) 2025 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Different types of natural gas exhibit distinct carbon and hydrogen isotopic compositions, making these isotopic compositions crucial indicators for identifying gas origins. With ongoing advancements in natural gas exploration technology and the increasing volume of exploration data, our understanding of natural gas origins and sources continues to deepen, and how to update and verify the existing data to ensure the applicability of gas genetic diagrams has become crucial. This study comprehensively analyzes the stable carbon and hydrogen isotope characteristics of different genetic types of natural gases in Sichuan, Tarim, Ordos, Turpan-Hami, Songliao, Northern Jiangsu, Sanshui, Qaidam, and Bohai Bay basins in China, together with abiotic gases from the Lost City of the Middle Atlantic Ridge, and the genetic diagrams related to commonly used carbon and hydrogen isotopes are evaluated. The study yields the following four conclusions: (1) The carbon isotopic values of methane (δ13C1), ethane (δ13C2), propane (δ13C3) and butane (δ13C4) of natural gases from China are from −89.4‰ to −11.4‰ (average of −36.6‰), −66.0‰ to −17.5‰ (average of −29.4‰), −49.5‰ to −13.2‰ (average of −27.3‰), −38.5‰ to −16.0‰ (average of −25.6‰), respectively. (2) The hydrogen isotopic values of methane (δD1), ethane (δD2) and propane (δD3) of natural gases from China range from −287‰ to −111‰ (average of −177‰), −249‰ to −94‰ (average of −158‰), and −237‰ to −75‰ (average of −146‰), respectively. (3) The carbon and hydrogen isotopic distribution patterns among methane and its homologues of natural gases in China are mainly in positive order (δ13C1<δ13C2<δ13C3<δ13C4, δD1<δD2<δD3). In most natural gas samples, the fractionation amplitude between methane and ethane is greater than that between ethane and propane (Δ(δ13C2−δ13C1) > Δ(δ13C3−δ13C2), Δ(δD2−δD1) > Δ(δD3−δD2)). (4) The δ13C1–δ13C2–δ13C3, the δ13C1–δD1, δ13C1–C1/C2+3, Δ(δ13C2−δ13C1)–Δ(δ13C3−δ13C2) and Δ(δD2−δD1)–Δ(δD3−δD2) diagrams, can be used to identify the gas origin in many different cases, and the combined application between different charts can enhance the identification effect.
The geochemical characteristics of the Paleozoic natural gas in the southern part of the Ordos Basin shows significant differences from those in the northern part. These differences lead to the increase in dryness coefficient and a heavier carbon isotope composition of methane attributed to the increase in organic matter maturity of the source rocks. Additionally, the Upper Paleozoic natural gas in the southern basin contains a higher carbon dioxide (CO2) gas content, and exhibits a common phenomenon of methane and ethane carbon isotope composition inversions. This paper employs gas geochemistry as the principal analytical method to systematically compare the north-south differences in the Paleozoic natural gas composition and to explore its origin and source. The findings indicate that the Upper Paleozoic natural gas in the southern basin mainly composed of highly over-mature coal-type gas. However, certain gas geochemical indicators suggest the presence of lower paleomarine hydrocarbon sources in specific areas. The observed inversion of methane and ethane carbon isotope composition in the Upper Paleozoic natural gas in the southern basin is attributed to the mixing of different types of natural gas. Specifically, the varying degrees of mixing with the Lower Paleozoic oil-type gas—characterized by a higher ethane content and lighter ethane carbon isotope values—are identified as the primary cause of the inversion of carbon isotopes. Furthermore, geochemical indicators of natural gas in the lower Paleozoic in the southern basin strongly reflect typical marine hydrocarbon source characteristics. While these gases predominantly originate from marine source rocks, a minor contribution from the Upper Paleozoic coal-type gas cannot be entirely ruled out.
The Chinese offshore area holds vast reserves of deepwater and shallow gas hydrates. However, due to the geological looseness of deepwater and shallow layers, the absence of tight sealing layers, and the high heterogeneity of gas hydrate reservoirs, identifying the occurrence state of gas hydrates remains challenging, greatly impeding the accurate prediction of gas hydrate saturation. Based on the acoustic-electric response characteristics of deepwater and shallow gas hydrates, this study employs the intersection method of resistivity and longitudinal wave velocity diagrams to identify the occurrence state of gas hydrates. The pore volume of gas hydrate reservoirs is calculated using a density formula corrected for mud content. Gas hydrate saturation in the YL target area of the Qiongdongnan (QDN) Basin is predicted using three methods: the mud-corrected resistivity method, the equivalent medium method, and the joint inversion method, finding the minimum combined error of acoustic and electric data. The results indicate that the predicted values using the joint inversion method in the YL target area of the QDN Basin are closest to the measured values obtained from the chloride ion concentration method, with prediction errors ranging from 0.09 % to 14.89 % and an average error of 6.85 %. These findings suggest that selecting an appropriate acoustic-electric joint inversion saturation calculation model, based on the determination of hydrate occurrence states, can significantly improve the accuracy of hydrate saturation prediction. This approach provides a realiable method for calculating hydrate saturation in the deepwater and shallow sediments. (c) 2025 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
The natural fracture system plays a key role in the formation of hydrocarbon reservoirs in the carbonate buried hill of the Nanpu Sag in the Bohai Bay Basin, affecting the distribution of high-quality reservoirs and the migration and accumulation of hydrocarbons. Using data from outcrops, cores, thin sections, and image logs, a quantitative analysis was conducted on the development patterns of fractures both in vertical and horizontal directions, and the main controlling factors for fracture development were identified. On this basis, numerical simulation techniques were applied to quantitatively predict the development patterns of fractures in the carbonate reservoirs of the ancient buried hills in Nanpu Sag. Four types of fractures were identified in the study area: structural fractures, diagenetic fractures, weathering fractures, and dissolution fractures, with structural fractures being the most predominant. The fractures show a low degree of filling, with 59% being effective, indicating good fracture effectiveness. The linear density of structural fractures ranges from 3 to 10 m-1, with an average of 5.6 m-1. The height of structural fractures is generally less than 30 cm, mainly distributed between 5 and 20 cm. The microscopic fracture areal density ranges from 25 to 50 cm/cm2, with an average of 32.3 cm/cm2, and the porosity of micro-fractures ranges from 0.24% to 0.69%, averaging at 0.55%. These micro-fractures provide essential storage space in tight reservoirs and enhance pore connectivity, facilitating hydrocarbon migration and accumulation. Three primary fracture groups were identified in the study area: nearly E-W trending fractures, NE-SW trending fractures, and NW-SE trending fractures, with the first two groups being the most developed. The degree of fracture development in the study area is mainly affected by lithology, rock mechanical layers, and faults. Fractures are most abundant in dolomite and dolomitic limestone, but less developed in mudstone. Different rock mechanical interfaces affect the geometry, scale, and intensity of fracture development. Stratigraphy-bound fractures are generally vertical and terminate at rock mechanical interfaces, while throughgoing fractures usually span multiple mechanical layers and are controlled by more extensive mechanical interfaces. Faults are important factor in fracture heterogeneity, with fracture intensity being highest near fault cores, especially at fault tips, overlaps, intersections, and the hinges of fault-associated folds. The number of fractures decreases as the distance from the fault zone increases. (c) 2024 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
In the process of energy structure adjustment,as an unconventional natural gas resources,the development and utilization of coalbed methane(CBM)has gradually attracted attention,since CBM is an important unconventional natural gas resources.The large amount of water produced by the exploitation of coalbed methane has therefore raised concerns about water pollution and other related environmental issues.Qinshui Basin is an important area for the development of CBM in China.This study analyzed samples from 6 blocks in the Qinshui Basin to trace the source and evolution of trace elements in CBM co-produced water,and provided geochemical data support for the follow-up treatments.The main trace element compositions of the water samples in Qinshui Basin include Li,B,F,Mn,Fe,Sr,and Ba.Particularly,F and Mn levels exceed the Chinese drinking water health standards by 7 times and 1.4 times,respectively,corresponding to groundwater quality standards of Class Ⅴ and Class Ⅲ-Ⅳ.The long-term accumulation of elements due to CBM exploitation poses a serious threat to the surrounding environment and human health.Magmatic activities bring a large amount of F to the coal seam in Qinshui Basin.The local water environment,riched in HCO3-,promotes the dissolution of fluoride-containing minerals.The situation of Mn exceeding the standard was the most serious in Yushe and Zhengzhuang.The dissolution of manganese siderite is the main control factor for high concentration of dissolved Mn in coal seam water,and with the increase of buried depth of coal seams and the decrease of pH value,Mn is gradually enriched in CBM co-produced water.The phenomenon of F and Mn exceeding the standard exists widely in coal seam water in China.It is necessary to take appropriate treatment measures for F and Mn before discharging CBM co-produced water.
With the continuous increase in exploration efforts in new zones and new strata, significant breakthroughs have been made in the natural gas exploration of the O1m56 to O1m4 formations in the Ordos Basin. Thus, the origin and exploration potential of subsalt natural gas have attracted much attention and urgently need to be addressed. On the basis of certain geochemical characteristics, genetic types, and sources of natural gas, a comprehensive study on the sedimentary environment, organic geochemical characteristics, and spatial distribution scale of source rocks are conducted in this paper by using geological and geochemical methods. The study shows that: (1) The Ordovician subsalt natural gas is mainly "pyrolysis dry gas," among which the 513C1 of Ordovician subsalt low sulfur (sulfur-free) natural gas is lighter, with an average value of -39.6%; the 513C2 ranges more largely from -35.6%to -25.8%. In contrast, both 513C1 and 513C2 values are heavier in high-sulfur natural gas, revealing that different Thermochemical Sulfate Reduction (TSR) reaction stages have different degrees of influence on natural gas components and carbon isotope composition. (2) Subsalt natural gas is classified as "oil-type gas," which is self-generated and self-accumulated, whose source rocks are mainly Ordovician subsalt marine deposits. (3) Three types of marine source rocks are developed in Ordovician subsalt, including black argillaceous rock, dark argillaceous dolomite (dolomitic mudstone), and dark micrite (bioclastic) limestone. In addition to micrite limestone, these rocks were mainly formed in a confined lagoon sedimentary environment with high salinity and anoxia. Sedimentary water was significantly stratified and the environment was highly reduced. The organic matter content of the source rocks is relatively high, with an average TOC value of 0.45%. The hydrocarbon-generating parent materials are mainly composed of bacteria and algae, and the organic matter evolution reaches highover maturity stage. The total gas generation amount of the marine source rocks in Ordovician subsalt is approximately 43.8 x 1012 m3, which can provide hydrocarbons and accumulate for the subsalt favorable reservoir facies located far from Upper Paleozoic gas sources. (c) 2024 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Shale gas migration is a critical geological process in the enrichment of shale gas deposits. Computational fluid dynamics (CFD) methods were employed to investigate this migration process. Utilizing CFD principles, an abstract physical model incorporating stratum dip angles and physical properties was developed. The control variable method was utilized to ascertain the impact of these factors on gas migration. By employing a typical shale gas reservoir profile from the Changning area as the case study, mathematical equations were formulated to describe the evolution of ancient pressures and gas contents under real geological conditions. These equations served as initial conditions for simulating the macroscopic dynamic evolution of the shale gas reservoir through fluid dynamics techniques. The findings indicate that the stratum dip angle dictates the normal stress on bedding planes and the gas pressure gradient along these planes. A larger dip angle corresponds to lesser compaction on the stratum surface, resulting in a steeper pressure gradient and improved gas migration efficiency. Gas predominantly migrates through channels with superior physical properties, and the larger the disparity between these channels and the surrounding rock, the more pronounced the influence on hydrocarbon migration. In the Changning anticline, shale gas migration is predominantly governed by strata uplift, which reduces vertical diffusion and encourages lateral migration from lower to higher regions within the reservoir. In Tiangongtang, on the other hand, early-phase normal fault activity during the last tectonic stage led to significant seepage losses. Although subsequent reverse faulting mitigated these losses, the overall gas content in the reservoir remains relatively low.
Helium is a globally scarce strategic resource that is relevant to national economies and the development of high-tech industries, and China primarily depends on imported helium for its industrial applications. Therefore, there is an urgent demand for clarifying helium formation and enrichment patterns, searching for helium-rich fields, and realizing China's helium resource inventory and development potential. This article analyzes the reservoir characteristics and accumulation conditions of typical helium-rich fields in China, and clarifying the origin and source of helium as well as the main controlling factors of helium enrichment. It was recognized that helium in natural gas in China mainly comes from crustal sources. Relatively shallow buried ancient U–Th-rich granite basement or intrusion, large and stable ancient uplift or submarine formed in the early period, good overburden of huge thick paste-salt rock or mudstone cover, and channels connecting the basement and reservoir, were the main controlling factors of helium enrichment. Four types of helium-rich gas reservoirs, namely helium-rich conventional gas, helium-rich shale gas, helium-rich non-hydrocarbon gas, and helium-rich water-soluble gas, have been modeled and predicted to be helium-rich favorable exploration areas. Based on this analysis, the prospect of helium resource development in China has been analyzed. It was proposed that the exploration of helium-rich fields and the comprehensive development and utilization of medium- and low-abundance helium resources are important ways to increase the domestic helium production in China in the future.
The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan-Dishuiquan Sag, the Wucaiwan Sag-Dajing area, and the Dongdao Haizi Sag-Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900-4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and (c) 2024 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Typical condensate reservoirs have been developed in the No.4 fault zone of the Shunbei area in the Tarim Basin. However, exploration expansion is restricted due to the unclear genetic mechanisms and main controlling factors of condensate accumulation. Through a comprehensive analysis of organic geochemical characteristics and the regional geological background, the genetic mechanisms and main controlling factors of condensate accumulation in the No.4 fault zone of the Shunbei area have been identified, and the following understandings are mainly obtained: (1) the condensate oil and gas reservoirs in the No.4 fault zone of the Shunbei area are mainly primary condensate reservoirs, and their formation is mainly affected by differential maturation of organic matter, multi-phase accumulation, and secondary alteration; (2) the overall secondary effects on the condensate oil and gas reservoirs in the Shunbei No.4 fault zone are relatively weak, however, the secondary effect experienced by the middle and southern sections is relatively stronger compared to the northern section; these secondary processes include oil cracking, gas invasion, and thermochemical sulfate reduction (TSR); and (3) the enrichment degree of condensate oil and gas reservoirs in the northern section of the Shunbei No.4 fault zone is significantly higher than in the middle and southern sections; the enrichment and high production of condensate oil and gas are mainly controlled by transport conditions and reservoir scale. Stronger fault activity, better transport conditions, larger reservoir size, and thinner gypsum-salt rock layers facilitate the upward migration of oil and gas along strike-slip faults, leading to higher production and enrichment of condensate.
Through the analysis of natural gas composition, carbon and hydrogen isotopes of alkane gases, reservoir bitumen, source rock conditions, and source-reservoir combinations, this study clarifies the differences in gas sources and the origins of natural gas in the Permian Changxing Formation-Triassic Feixianguan Formation on both sides of the Kaijiang-Liangping Trough. Additionally, it identifies favorable exploration directions for coal-formed gas generated by the Longtan Formation in the Sichuan Basin. The following understanding was obtained: (1) The natural gas in the Changxing-Feixianguan formations mainly composed of alkane gas, typical of dry gas. (2) The carbon isotope values of methane and ethane in the Changxing-Feixianguan formations on the east side of the trough are lower than those on the west side. Specifically, the ethane carbon isotope value in the Longgang Gas Field on the west side is higher than that in the Yuanba Gas Field, while the methane hydrogen isotope value is lower in the Longgang Gas Field compared to the Yuanba Gas Field. (3) The natural gas in the Dongyuezhai, Puguang, and Yuanba gas fields predominantly originates from sapropelic organic matter of the Wujiaping Formation, with kerogen types II1-I; in contrast, the Longgang Gas Field contains a mixture of coal-formed gas and oil-type gas, with a slightly higher content of coal-formed gas, originating from mixed organic matter of the Wujiaping Formation, with kerogen type II1-II2. (4) Multiple types of gas, such as coal rock gas, tight sandstone gas, and shale gas, can be formed within the Longtan Formation. The Suining-Luzhou and Langzhong-Guang'an-Fuling areas are identified as favorable zones for the exploration of coal rock gas and marine-continental transitional shale gas, respectively. Additionally, the reef and shoal development areas of the Changxing Formation in the Suining-Hechuan and Guang'an-Nanchong regions are also favorable exploration areas for coal-formed gas. (c) 2024 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
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 x 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 beta-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 x 106 t/km2. Several oil-generating centers with an intensity of more than 5 x 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. (c) 2024 Northwest Institute of Eco-Environment and Resources, Chinese Academy of Sciences AND Research Institute of Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KEAI Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
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.
