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.

月球地质年代表将月球的地层按形成的时间顺序划分为不同的时代, 能够清晰地表达月球的整体演化历史. 在地基望远镜观测和阿波罗时代早期, 由于当时所用数据的空间覆盖度和分辨率有限, 所建立的月球地质年代划分存在部分缺陷. 在阿波罗时代结束以来的几十年里, 人类对月球进行了更广泛的研究, 拓展了对全月地质演化的认识和理解. 基于对月球动力学演化的综合性分析, 本文对当前的月球地质年代表进行了更新, 特别考虑了内动力地质作用和外动力地质作用在月球早期演化中所发挥的作用. 首先, 根据内动力和外动力在不同时期对月球改造的效应, 提出了三阶段月球动力学演化模型, 并建立了三个相应的"宙/宇"级别的年代及地层单元. 其次, 为了更清晰地反映月球的演化历史, 以南极-艾肯(SPA)盆地的形成为界线将前酒海纪划分为了岩浆洋纪和艾肯纪, 其中较年轻的艾肯纪是以SPA盆地的形成为起点. 本文识别了SPA盆地的溅射物地层, 即达斯建造, 其沉积在月球的原始月壳上, 是岩浆洋结束后保存下来的最古老的外动力成因地层. 更新的月球地质年代表系统综合了阿波罗时期以来月球探测和研究的成果, 构建了一个描述月球演化历史的系统框架, 能够更方便地开展月球地质研究, 对其他类地行星的地质演化研究也具有重要的参考意义.

The Hongche fault belt-Chepaizi uplift in the northwestern margin of Junggarbasin has many oil and gas reservoirs,and the physical and chemical properties and geochemical characteristics of crude oil are very complex,so the type and source of crude oil have long been controversial,which directly affects the decision of oil and gas exploration.Based on the summary of typical geochemical characteristics of crude oils and main oil source identification indexes in different ages of Junggar basin,this paper systematically analyzed and studied the geochemical characteristics and sources of the crude oils in Hongche fault belt and Chepaizi uplift,and divided the crude oils in this area into three types with single source and two types with mixed sources.Three types of single source crude oils are derived from the lacustrine source rocks of Permian,coal measure source rocks of the Middle and Lower Jurassic,lacustrine source rocks of the Paleogene Anjihaihe Formation.The two types of mixed crude oils are mixed from the biodegraded heavy oil derived from the Permian lacustrine source rocks,the normal crude oil derived from the Middle and Lower Jurassic coal measure source rocks,and the normal crude oil derived from the Paleogene lacustrine source rocks.The crude oil of the Carboniferous-Cretaceous oil reservoirs in the Hongche fault belt is mainly derived from the Permian lacustrine source rock,and the heavy oil in Chunfeng oilfield in the northeast of Chepaizi uplift is also derived from the Permian lacustrine source rock.Light crude oil in the Neogene Shawan Formation oil reservoir on the east side of Chepaizi Uplift and west side of Hongche fault belt is derived from Paleogene lacustrine source rocks.The heavy oil of the Cretaceous-Paleogene oil reservoirs in the Chunguang oilfield in the middle of Chepaizi uplift is the mixture of the Permian sourced heavy oil and the Jurassic sourced normal crude oil,and the heavy oil of Neogene Shawan Formation oil reservoir is the mixture of the Permian sourced heavy oil and the Neogene sourced normal crude oil.The light crude oil of the Carboniferous-Paleogene oil reservoir in the west of Chepaizi uplift is derived from the Middle-Lower Jurassic coal measure source rocks,while the light crude oil of the Neogene Shawan Formation oil reservoir is derived from the Paleogene lacustrine source rocks.This paper has important reference for the study of hydrocarbon accumulation and regional oil and gas exploration decision in the southern area of northwest margin of Junggar basin.

Comprehensive nitrogen biogeochemical cycle has been reconstructed for representative lacustrine organic-rich sedimentary rock in China, namely the Triassic Yanchang Formation (YF, 199-230 Ma) in Ordos and the Cretaceous Qingshankou Formation (QF, 86-92 Ma) in Songliao basins, by evaluating the organic and inorganic nitrogen isotopic compositions rather than only organic or bulk nitrogen iso-topic compositions. The results indicate that the nitrogen isotope values of bulk rock (615Nbulk) in the non-metamorphic stage are significantly different from that of kerogen, which challenge the conceptual framework of sedimentary nitrogen isotope interpretation. The 615Nbulk from the YF and QF were lower than their respective the nitrogen isotope values of kerogen (615Nker), with offsets up to-5.1%0, which have the inverse relationship for the metamorphosed rock. Thermal evolution did not significantly mod-ify the 615N of bulk rock and kerogen. The 615N of sediments from the YF (615Nbulk, 1.6%0-5.6%0) were lower than that of rock from the QF (615Nbulk, 10.2%0-15.3%0). The nitrogen isotope values of silicate incorporated nitrogen (615Nsil) were slightly lower than those of the 615Nker in the YF and obviously lower for the QF. The fact that different nitrogen cycles occur in the YF and QF due to the different depositional redox conditions leads to different isotopic results. The YF water environment dominated by oxic condi-tions is not conducive to the occurrence of denitrification and anammox, and no abundant N2 loss leads to the relatively light 615Nbulk. In the stratified water for the QF, redox transition zone promotes denitrifica-tion and anammox, resulting in the heavy 615Nbulk of rock and promotes the DNRA, resulting in heavy 615Nker and low 615Nsil.(c) 2022 China University of Geosciences (Beijing) and Peking University. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/ licenses/by-nc-nd/4.0/).

Shale gas wastewater (SGW) disposal is a major challenge in the areas in central China due to its increasing volume associated with intensification of shale gas exploration and its high levels of contaminants. In the Fuling shale gas field of Sichuan Basin, a small amount of SGW originated from the flowback and produced water (FPW) is treated and then discharged to a local stream. This study investigated the inorganic water geochemistry and Sr isotopic composition of the FPW in Fuling shale gas field, the SGW effluent that is generated in the treatment facility, and the quality of a local river after the disposal of treated SGW. The data generated in this study reveals that FPW generate after several years of shale gas operation maintain the original geochemical fingerprints detected in early stages of FPW generation, and consistent with the FPW composition detected in other shale gas fields in Sichuan Basin. We show that reuse of saline FPW for hydraulic fracturing can generate an inverse salinity trend, where the salinity of FPW decreases with time, reflecting the increase of the contribution of formation water with lower salinity. The treatment of the FPW results in ~40 % reduction of the salts by dilution with freshwater and selective (80-90 %) removal of some of the inorganic contaminants. The original geochemical fingerprints of the FPW from Fuling shale gas field was not modified during FPW treatment, reinforcing the applicability of these tracers for detecting SGW in the environment. Discharge of treated SGW effluent to a local river causes a major 200-fold dilution and reduction of all contaminants levels below drinking water and ecological standards. Overall, this study emphasizes the importance of water quality monitoring of treated SGW and the overall measures needed to protect public health and the environment in areas of shale gas development.

Lacustrine hydrocarbon source rocks with high quantity and quality of organic matter (OM) are developed within the third member of the Eocene Shahejie formation (Es3) in the Qikou Sag of the Huanghua Depression, Bohai Bay Basin, Eastern China. However, the paleolake environments associated with deposition of these rocks remain relatively undescribed, restricting our understanding of the biogeochemical processes which contributed to the development of excellent source rocks and inhibiting efforts for exploration of lacustrine hydrocarbon deposits. In this study, 18 core samples from the Es3 interval of Well Gangshen 4 in Qikou Sag were subject to a detailed analysis of bulk OM, biomarkers, molecular carbon isotopes, trace elements, and phosphorus (P) to investigate the environment and ecosystem of the ancient lake in which the rocks were deposited. High values of gammacerane index (av. 0.35) recorded in the samples reveals the oxic-anoxic stratification in the water column that persisted for the majority of the year due to the hot climate and great depth of the lake during this period. Meanwhile 13C-depleted hopanes (lower than −63.2‰) indicate an input of OM from chemoautotrophic and methanotrophic bacteria, supported by the production of CO2 and CH4 due to the anaerobic respiration of OM in the hypolimnion or sediments. The abundances of total organic carbon (TOC) relative to total P (TOC/P, mole ratio, av. 289.9) indicates the preferential release of P from sediments in an anoxic environment. However, the low (<2.0) Ni/Co and V/Cr ratios and moderate (av. 1.48) pristane/phytane (Pr/Ph) ratios suggest periodic oxidation of the hypolimnion, which may be a result of replenishment of oxygen during the short-term mixing of the water column driven by seasonal cooling and wind disturbance. Excess P was introduced into the epilimnion via mixing, which initiated high algal productivity after further stratification of the water column. Algal OM produced in this early stratification phase was crucial for the formation of excellent source rocks. The large variation of δ13C in TOC, n-alkanes, and isoprenoids reflects changes in CO2 concentrations or carbon isotopes in the photic zone, which may be attributable to increased inputs of terrestrial OM in response to a changing climate.

Natural gases from the Taiyang (shallow), Jiaoshiba (middle), and Weirong (deep) shale gas fields in the southern Sichuan Basin were analyzed for molecular and stable carbon isotopic compositions to investigate the geochemical characteristics and gas origins. All the gases belong to shale gas from the Upper Ordovician–Lower Silurian shale and are dominated by methane with gas wetness generally less than 0.83%. The δ13C1 values are −28.5‰, −30.3‰, and −35.2‰ in Taiyang, Jiaoshiba, and Weirong shale gas fields, respectively. The extremely high thermal maturity is the controlling factor for the enrichment of 13C in methane, with a minor contribution from the heavy carbon isotope of the organic matter in the Ordovician Wufeng Formation. Fischer–Tropsch-type synthesis of hydrocarbon gas from CO2 and H2 contributes to the increase of wet gas, which results in the offset from the δ13C1∼wetness linear trend in the Taiyang and Jiaoshiba gas fields. Methane, ethane, and propane in the Taiyang shale gas field have increasing δ13C values with increasing burial depth, which is mainly caused by diffusive migration. All gases are characterized by a complete carbon isotopic reversal trend (δ13C1 > δ13C2 > δ13C3), and it is mainly caused by the reversible free-radical reactions with the conversion from alkane to alkyl groups, with some contribution from the Fischer–Tropsch-type synthesis. The results of this study will improve our understanding of the geochemical characteristics of shale gases from different burial depths and have important implications for future shale gas exploration in the deep and shallow layers.

Lipid biomarker parameters and molecular carbon isotope compositions of n-alkanes were used as tracers to determine geochemical behavior of aliphatic hydrocarbons during their migration from two sequences of source rock-type mudstones (4050.8-4062.2 and 4067.4-4073 m depth, respectively) to the interbedded reservoir sandstones (4062.6-4066.3 m depth) in the Qikou Sag, Bohai Bay Basin, eastern China. Abnormally high values of the production index (0.69-0.90) and total extract/total organic carbon (TOC) ratios (0.53-1.21) in the sandstone samples indicated that the hydrocarbons in the sandstones were not produced in situ but migrated from the adjoining mudstones. A comparison of values in lipid biomarker parameters (oleanane index, gammacerane index, C23 tricyclic terpane/C30 alpha beta-hopane, and C29/C27 alpha alpha alpha 20R sterane ratios) in the sandstone with the mudstone samples indicated steroids and hopanoids in the upper section of the sandstone layer (4062.6-4065.2 m depth) were transported from the overlying mudstones, while those in the lower sandstone layer (4066.3 m depth) were transported from the underlying mudstones. Molecular carbon isotope data suggest that all n-alkanes in the upper section of the sandstone layer were transported from the overlying mudstones. However, in the lower sandstone layer, most of the C15-C17 n-alkanes were transported from the overlying mudstones, while the C18-C31 n-alkanes were transported mainly from the underlying mudstones. These combined results suggest the short-chain n-alkanes (C18) and steroids/hopanoids may have been expelled in a separate oil phase.

China is rich in shale gas resources, which are mainly distributed in densely populated southern marine carbonate areas. The geological and surface conditions are complex, the ecological environment is fragile, and water resources are scarce or unevenly distributed. Therefore, large-scale fracturing mining has high pressure of water resources utilization and serious risk of water environment pollution. In this paper, the geochemical characteristics of traditional and non-traditional stable isotopes such as hydrogen, oxygen, boron, lithium, strontium in shale gas hydraulic fracturing flowback/produced water (FP water) were comprehensively analyzed. The results show that, the hydrogen and oxygen isotopic composition of the FP water in Sichuan Basin, China has similar evolution trend with the produced water of conventional wells from Cambrian, Permian and Triassic Xujiahe, Jialingjiang and Leikoupo formations, but different from that of the Sinian conventional produced water. It indicates that the FP water in Sichuan Basin is a mixture of fracturing injected fluid and formation brine retained in Silurian shale. The saline end member is close to the formation water of Cambrian, but with higher δ11B values. The FP water in Sichuan Basin has δ11B values close to that of the Marcellus FP water, and both are derived from the evaporated seawater. The δ11B values of FP water in Sichuan Basin have overlap with that of the conventional produced water from different strata, so it can not be precisely distinguished. However, the δ11B and B/Cl values of the FP water in Sichuan Basin can be clearly distinguished from the river and the FP water from non-marine facies shale in Qaidam Basin. The FP water in Sichuan Basin has slightly higher δ7Li values than that of the Marcellus FP water, but has overlap with that of the Yangtze River. The average value of 87Sr/86Sr of FP water is 0.7197 in Weiyuan and 0.7193 in Changning, which is much higher than that of the produced water from conventional wells in different formations. This is because the Silurian shale is affected by terrestrial siliceous sediments and the underlying Sr-rich fluids. As a result, 87Sr/86Sr values measured in the Silurian strata in southern Sichuan Basin are high, which makes 87Sr/86Sr values become an effective index to distinguish shale gas fracturing FP water from conventional gas well produced water and shallow groundwater in Sichuan Basin.

Oilfield water contains valuable information on the origin, migration, and geochemical evolution of fluids in sedimentary basins. Jiuquan Basin is one of the richest oil basins in China and holds large potential for future tight oil exploration. We use a wide range of geochemical and isotopic tracers to evaluate the origin and reconstruct the migration of oilfield water across Jiuquan Basin, including major (Ca, Mg, Na, K, NH4, Cl, SO4, Br, HCO3) and minor (B, Li, Ba, Sr, Rb) elements, water isotopes (δ18O, δ2H), the isotopes of carbon (δ13C-DIC), boron, (δ11B), and strontium (87Sr/86Sr). We show that the oilfield water was co-generated with the original hydrocarbons in the deep Qingxi sub-basin in the western part of the basin, and were derived from blending of two distinctive sources (1) deep-source brine that originated from relicts of evaporated seawater; and (2) geothermal water that underwent intensive water-rock interactions with the Lower Cretaceous Xiagou Formation, characterized by high DIC, Li+ , B, and SO4 concentrations and distinctive δ18O, δ13C-DIC, and 87Sr/86Sr, which are consistent with the composition of the source rocks of Xiagou Formation. The distinctive geothermal signature was detected in the Yaerxia oilfield water in the eastern side of the Qingxi sub-basin, suggesting eastward co-migration of the geothermal water and crude oil to the shallow geological trap. Further eastward migration of the saline formation water into less saline environment in the central (Laojunmiao) and eastern (Shiyougou) fields caused base-exchange reactions, adsorption, and sulfate reduction that resulted in a progressive reduction in the overall salinity, Na+, NH4+, Li+, B, SO42−, and 87Sr/86Sr, coupled with increasing Ca2+, Mg2+, Sr2+, and δ11B. Later dilution of Laojunmiao oil field caused B desorption, oxidation of organic matter, and secondary methanogenesis. The integration of multiple geochemical tracers provides systematic geochemical criteria's for reconstructing the origin and evolution of the oilfield water in Jiuquan Basin and the ability to distinguish between the original composition and secondary modification of the geochemistry of the oilfield water.

In this paper, factors controlling natural gas accumulation in the southern margin of Junggar Basin were mainly discussed by a comparison with natural gas generation and accumulation in the Kuqa Depression of Tarim Basin. The southern margin of Junggar Basin and the Kuqa Depression of Tarim Basin are located on the north and south sides of the Tianshan Mountains respectively, and they share the similar sedimentary stratigraphy and tectonic evolution history. In recent several decades, many large gas fields have been found in the Kuqa Depression of Tarim Basin, but no great breakthrough in the southern margin of Junggar Basin. Our results suggest that natural gas in the southern margin of Junggar Basin is mainly thermogenic wet gas, and can be divided into three types as coal-derived gas, mixed gas and oil-associated gas, of which the former two types are dominated. The Jurassic coal measures are the main source rocks of natural gas, and the main gas generation time from this set of source rocks matched well with the formation time of the anticline structures, resulting in favorable conditions for natural gas accumulation. In the western part of the southern margin in the Junggar Basin, the Permian lacustrine and the Upper Triassic lacustrine-swamp source rocks could be important sources of natural gas, and the main gas generation time also matched well with the formation time of traps. Compared with the Kuqa Depression of Tarim Basin, natural gas sources are better in the southern margin of Junggar Basin, and the geologic conditions are favorable for the formation of large oil and gas fields in the southern margin of Junggar Basin. The deep Permian-Jurassic-Cretaceous petroleum system is the most favorable petroleum system for natural gas exploration in the southern margin of Junggar Basin. The western part and the central part of the southern margin in the Junggar Basin could be the first targets for the discovery of the Jurassic coal-derived oil and gas reservoirs. The shallow Cretaceous-Neogene petroleum system is the second target for natural gas exploration.

The identification of the origin and source of natural gas is always a difficult and hot issue. Hereinto, the maturity identification is one of the most important scientific problems. Many empirical equations have been established to decipher the relationship between the maturity of gas source rocks and the carbon isotopic composition of natural gas. However, these equations proposed often fail to identify the maturity of the source rocks correctly, which in turn prevents the identification of genetic types and source rocks of the natural gas because the petroliferous sedimentary basins in China are complex and diverse, with multiple sets of source rocks and different thermal history. In this paper, the oil-associated gas from the Permian lacustrine source rocks and the coal-derived gas from the Jurassic source rocks in Junggar and Turpan-Hami basins have been investigated to decipher the relationship between the maturity (vitrinite reflectance) of gas source rocks and the carbon isotopic composition of methane. The equations established are δ13C1=25lgRo−42.5 for oil-associated gas, and δ13C1=25lgRo−37.5 for coal-derived gas. These new equations are suitable for the maturity identification of source rocks in most petroliferous basins, and favorable for the identification of the genetic type and source of natural gas, which is very important to improve the geological theory of natural gas.

水力压裂技术是页岩气开发的核心技术之一,大规模水力压裂技术可能会带来大量压裂返排液,而压裂返排液存在污染地下水和地表水等风险.综合对比分析四川盆地威远页岩气开发区压裂返排液与盆地内不同层系地层水地球化学特征,结果表明:威远页岩气返排液具有高矿化度、高含金属离子的特点,但与地层水相比,返排液中钠(7334 mg/L,n=63)、钙(297 mg/L,n=62)、锶(73.07 mg/L,n=64)、镁(32.1 mg/L,n=42)、钡(153.12 mg/L,n=64)、锰(1.83 mg/L,n=35)、锂(17.53 mg/L,n=64)、溴(72 mg/L,n=70)、氯(12578 mg/L,n=70)等含量基本上都是低于地层水,但硼含量(38.2 mg/L,n=64)与二叠系和三叠系地层水相近,低于震旦系和寒武系地层水.返排液B/Cl值、Li/Cl值和Na/Cl值基本都高于地层水,但Ca/Cl值和Br/Cl值则低于地层水.返排液、压裂注入液、寒武系地层水的溴氯含量具有很好的线性相关性(R2=0.9673),表明威远页岩气开发区返排液为压裂注入液与滞留在志留系页岩中的地层水的混合产物,且该地层卤水与寒武系相近.由于白云岩化作用,地层水具有富钙贫镁的特征,因此,返排液也具有富钙贫镁的特征.与生活饮用水卫生标准(GB 5749-2006)相比,返排液钠、氯、硼、钡、锰、铁、铊、SO42-等含量以及矿化度远高于前者,对环境具有潜在影响,不宜直接排放.威远返排液的处理主要采用循环利用方法,如果在循环利用之前能够根据返排液主微量元素的化学组成进行针对性前期处理,则可降低返排液复杂成分可能对页岩气产量与开采难度的影响,从而大大提高该方法的可行性.页岩气压裂返排液与常规地层水元素化学组成的差异性及其潜在环境风险的研究,为压裂返排液的处理与污染防控提供了重要的科学依据.

Organic-rich mudrocks that served as sources for the prolific unconventional system of the Bakken Formation display pronounced heterogeneity in composition and expulsion behavior. The dominant mudrocks of the Bakken Formation (tarls) contain few biogenic allochems and have a diagenetic history dominated by compaction. Mudrocks that at deposition contained relatively more siliceous biogenic debris display microquartz cement that reduced porosity and enhanced rock stiffness. Against a background of strong expulsion at the formation scale, the ratio of methane to iso-butane (C1/iC4) in gas extracted from these organic-rich mudrocks reveals a wide range of expulsion efficiency. C1/iC4 in crushed rock gas is strongly controlled by maturity, with lower maturity samples displaying a range of iso-butane content, but little methane. At higher maturity a strong negative correlation between methane and iso-butane is interpreted in terms of expulsion efficiency, with higher proportional amounts of iso-butane corresponding to greater oil expulsion. The majority of mudrocks in the Upper and Lower Bakken Formation source rocks display strong expulsion efficiency, although a minority of samples display relatively high oil retention. A key control on the degree of petroleum expulsion in the Upper and Lower members that have served as sources for the Middle Bakken reservoir is the extent of cementation by authigenic microquartz. The grain assemblages in the organic-rich mudrocks are mixed, but are mostly dominated by grains of extrabasinal derivation (tarls). At the time of deposition only a minority of the mudrocks contained a substantial component of grains of intrabasinal derivation, notably radiolarians, which reacted to form authigenic microquartz. The higher-maturity mudrocks cemented by microquartz display relatively high retention of generated hydrocarbons whereas the associated tarls show a wide range of expulsion behavior. The contrast in expulsion state displayed across Bakken Formation mudrocks suggests that compaction, where not inhibited by cementation, persists into the oil window and acts together with overpressuring as a driver of hydrocarbon expulsion. Where cemented early in the diagenetic history, mudrocks cease to compact and are able to retain more of their generated oil. These results for the Bakken Formation have implications for unconventional systems more generally. The cementation status of mudrocks may be one of the key factors for predicting expulsion efficiency and for determining the efficacy of organic-rich mudrocks as hydrocarbon sources (where compaction-dominated) versus reservoirs (where cemented early in the burial history).

To investigate pore characteristics and the factors controlling lacustrine shales, geochemical, mineralogical and petrophysical experiments were performed on 23 shale samples from the Qingshankou Formation of the Songliao Basin, China. A comparison of mercury injection capillary pressure (MICP) and low-temperature N-2 adsorption pore-size distribution showed that MICP has a higher pore-size distribution (PSD) line in its overlapping pore diameter range, which may be elevated by the higher pressure of MICP. Therefore, in the overlapping range, low-temperature N-2 adsorption data were preferred in pore characterization. Negative correlations were observed between pore volumes and TOC content, indicating organic matter pores are not well-developed in the studied samples. This may be related to their low grade of maturity and type I kerogens. There existed negative relationships between pore volumes and S-1, which illustrated that liquid hydrocarbons occupied some pore space. Micropore volume had a better correlation with S-1 than mesopore and macropore volumes, which suggests that liquid hydrocarbons preferentially occur in micropores. No obvious relationships between pore volumes and quartz or feldspar were observed, while pore volumes increased with the increasing clay mineral content. These relationships indicate that intraparticle pores in clay minerals represent the principal pore type.

In order to have a better understanding of the geochemical characteristics of gases from deep depths, gases from the clastic sandstone reservoirs in the Dabei and Keshen gas fields in the Kuqa depression, Tarim Basin, and gases from the marine carbonate reservoirs (Ordovician and Cambrian) in the craton area of Tarim Basin and Sichuan Basin (Yuanba, Longgang, Puguang gas fields) are investigated based on the molecular composition, stable carbon and hydrogen isotopes. Deep gas, either from the clastic sandstone reservoirs or from the marine carbonate reservoirs, is dominated by alkane gas. Gases from Kuqa depression and Sichuan Basin are dry gas, with high gas dryness coefficient, 0.976 and 0.999, respectively. Deep gas from the craton area in Tarim Basin includes both dry and wet gases. N 2 and CO 2 are the common non-hydrocarbon components in the deep gas. Gases from the continental sandstone reservoirs have no H 2 S, while gases from the marine carbonate reservoirs often have H 2 S. The relatively high δ 13 C 2 value in the Kuqa depression indicates the gas was generated from humic type III kerogen, while the relatively low δ 13 C 2 value in the craton area of Tarim Basin indicates most of the gas was generated from the marine sapropelic organic matter. Deep gas in Sichuan Basin, which has medium δ 13 C 2 value, was generated from both humic type III and sapropelic type II organic matter. Carbon isotopic anomaly such as partial carbon isotopic reversal or relatively heavy carbon isotope is common in the deep gas, which is caused by secondary alteration. Gases from the Dabei gas field have a mean δ 2 H 1 value of –156‰, while gases from the craton area of Tarim Basin, and Yuanba and Puguang gas fields in Sichuan Basin have relatively heavier δ 2 H 1 value, i.e., average at −130 and −122‰, respectively. The abnormally heavier δ 2 H 1 value in Dabei gas field is due to the high thermal maturity and possible saline depositional environment of the source rocks. This study performed a comprehensive comparison of the geochemical characteristics of the deep gases with different origins, which may provide a hint for future exploration of deep gas in the world.

天然气成因与来源判识始终是天然气勘探与研究的难点与热点问题,国内外许多学者提出了多个应用天然气碳同位素组成判识气源岩成熟度的经验公式.但是,随着油气勘探程度的提高,以往经验公式在判识新发现天然气源岩成熟度时常出现明显偏差,需要对这些经验公式进行必要的修正.准噶尔盆地西北缘二叠系湖相烃源岩有机质生成的天然气属于典型油型气,准噶尔盆地南缘和吐哈盆地侏罗系煤系有机质生成的天然气属于典型煤成气.本文按照经典的有机质热演化生烃模式,在准噶尔盆地和吐哈盆地典型油型气与煤成气区域烃源岩热演化生烃地质条件的限定下,根据大量天然气实测碳同位素组成资料,构建了油型气和煤成气甲烷碳同位素组成与烃源岩有机质镜质体反射率之间的关系公式,其中,油型气δ 13 C 1 =25lgR o -42.5、煤成气δ 13 C 1 =25lgR o -37.5.这些新公式适用于绝大多数以连续埋藏热演化生烃为主的含油气盆地有机热成因天然气源岩成熟度判识,对天然气勘探具有较高的实用价值,对完善和发展天然气地质理论具有重要的科学意义.

•A predominance of C28 steranes was found in lacustrine source rocks.•δ13C of the C28 ααα 20R sterane was as low as −37‰, similar to that of a C27 20R triaromatic steroid.•C28 steranes were produced by algae blooming in a mixed water column.•Other steranes derived from algae growing in a stratified water column.

Resources of coal-derived gas in the deep strata are found abundant in China. Recent advances in petroleum geochemistry suggest water may contribute hydrogen and oxygen to the formation of hydrocarbons and oxygenated alteration production. However, the role of water during gas generation has been in debate due to conflicting research results. In this study, a Jurassic coal sample from the Kuqa depression, Tarim Basin, China was artificially matured by nonhydrous pyrolysis and hydrous pyrolysis at isothermal (330 °C, 350 °C, 370 °C for 72h) and non-isothermal (440 °C, 470 °C and 500 °C at heating rate of 2 °C/h) temperatures. Both isothermal and non-isothermal experiments generated more methane but less C3-5 hydrocarbon gases and CO2 non-hydrocarbon gas in the nonhydrous system relative to hydrous conditions. In the isothermal experiment, the nonhydrous pyrolysis generated at most 24% more methane relative to the hydrous pyrolysis, but the hydrous pyrolysis generated 5%∼87% more C3-5 hydrocarbon gas and at most 28% more CO2 relative to the nonhydrous pyrolysis. In the non-isothermal experiment, the nonhydrous pyrolysis generated 25%∼94% more methane relative to the hydrous pyrolysis, but the hydrous pyrolysis generated at most 2.56 times more C3-5 hydrocarbon gas and 1.04 times more CO2 relative to the nonhydrous pyrolysis. In general, the compositional variation trend of hydrocarbon and non-hydrocarbon gases is similar between the isothermal and non-isothermal experiments. This indicates that contribution from the supercritical water in the non-isothermal pyrolysis is not essential. With the presence of water, the secondary cracking of C3-5 alkanes in the hydrous experiments was significantly suppressed, as shown by the relatively higher yield of C3-5 alkanes in the hydrous systems. The availability of exogenous hydrogen from water in the hydrous pyrolysis inhibits the carbon-carbon bond cross linking, thus the reaction pathway of hydrocarbon generation is dominated by the thermal cracking of carbon-carbon bonds. The significant increase in CO2 in the hydrous pyrolysis indicates water is not only the source for exogenous hydrogen but also the source for the excess oxygen accounted for the formation of CO2. The overall geochemical implication of these experimental results is that it is important to consider the role of water in the hydrocarbon generation, especially in the deep strata where both geological and geochemical conditions are complex.

In this study, we report new analyses of stable nitrogen isotopic compositions (delta N-15) of the black mudstones from the Chang-7 Member of the Upper Triassic Yanchang Formation in the Ordos Basin, China, to examine the possible linkage of such isotopic compositions with the depositional environment. These mudstones were deposited mainly under suboxic bottom water column conditions. The core descriptions and trace element concentrations differ between samples obtained from the Chang-7(3) and Chang-7(1,2) members, situated at the bottom and top of the Chang-7 Member, respectively, such that the depositional condition of the former implies a more reduced water regime. The bulk rock nitrogen isotope (delta N-15(bulk)) values of the samples obtained from the Chang-7(3) Member are higher than those of the Chang-7(1,2) Member. No significant differences were identified in the organic carbon isotopes (delta C-13(org)), total organic carbon (TOC), or total nitrogen (TN) values between the two units. The results of delta N-15(bulk) cross-plotting with the TOC, TN, and carbon to nitrogen atomic ratio (C/N) show an absence of significant modification of the primary nitrogen isotopic compositions from post-depositional processes. Given the depositional history of these units, we suggest that the sedimentary redox environment can have a significant influence on delta N-15(bulk). Denitrification, which occurs mainly in suboxic conditions, plays an important role in such an environment, resulting in N-15 enrichment during the original deposition. Thus, owing to its sensitivity to sedimentary redox environments, the delta N-15(bulk) index can be an effective tool for evaluating depositional redox conditions, particularly for further subdivision of suboxic environments.