Kerogen-cracking Gas Research Articles

Genetic mechanism and exploration progress of global deep alkane gases and small molecule gases (H2, He)

From the perspective of global oil and gas exploration trends, deep to ultra-deep gas exploration has emerged as a focal point in the past decade, shaping the future landscape of fossil energy exploration. Specifically, China has undertaken oil and gas exploration ventures reaching depths of 10,000 m, drawing significant attention to the genesis of gas accumulation at such extreme depths. An analysis of crucial geological factors including basin formation, hydrocarbon generation, storage and accumulation reveals that kerogen cracking gas, crude oil cracking gas, and coal cracking gas served as vital gas sources for ultra-deep paraffin gas in highly over-mature oil-bearing basins, establishing a model for the formation, evolution, and accumulation of natural gas. With the continuous expansion of hydrocarbon genesis theory and the increasing global demand for clean energy, hydrogen, as an important link between inorganic and organic hydrocarbon generation theory, and as a promising clean energy, has gradually aroused extensive attention in the academic community. The genetic types of natural hydrogen are mainly generated from inorganic genetic mechanisms, including earth degassing, water-rock interaction, and water radiolysis. The lithology of the reservoir and the sealing property of the cap layer control the accumulation of natural hydrogen, with the salt-rock cap layer beneficial to the large-scale preservation of natural hydrogen reservoir. Helium, as a constituent resource of natural gas, represents the primary target for exploration among deep small molecule gases. Helium within natural gas reservoirs can be categorized into atmospheric, crust-source and mantle-source varieties based on their origins. Helium source rocks exhibit significant disparities in helium generation capacity attributed to variations in rock types, mineral compositions, and ages, resulting in a relatively complex mechanism governing helium reservoir release, migration and accumulation. Typically, helium-rich gas reservoirs lack optimal cap sealing performance, as excessive sealing inhibits the formation of pressure relief conduits, thereby impeding the supply of helium-rich fluid to the reservoir. Through an analysis of genetic types, formation and evolution models, and reservoir preservation mechanisms pertinent to deep alkane gases and small molecule gases, it is revealed that the large-scale pool-forming geologic units and giant hydrocarbon enrichment zones in ultra-deep strata are key and promising prospects for delivering successive discoveries, and the energy significance and development trend of natural hydrogen and helium in the future were pointed out, in order to provide references for promoting the transition from high carbon to low carbon and carbon-free energy in the energy field.

Evaluation of source rocks and prediction of oil and gas resources distribution in Baiyun Sag, Pearl River Mouth Basin, China

By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin, China, the development characteristics of hydrocarbon source rocks in the sag are clarified. Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type, scale, and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation. The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks, which are deposited in a slightly oxidizing environment. The source rocks are mainly composed of terrestrial higher plants, with algae making a certain contribution, and are oil and gas source rocks. Current geothermal field of the sag was reconstructed, in which the range of geothermal gradients is (3.5–5.2) °C/100 m, showing an overall increasing trend from northwest to southeast, with significant differences in geothermal gradients across different sub-sags. Baiyun Sag has undergone two distinct periods of extensional process, the Eocene and Miocene, since the Cenozoic era. These two periods of heating and warming events have been identified, accelerating the maturation and evolution of source rocks. The main body of ancient basal heat flow value reached its highest at 13.82 Ma. The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags. The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity, while the Eocene Enping Formation has reached the stage of maturity to high maturity. The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window. Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil, and has ability to generate kerogen cracking gas in the late stage. The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation. The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags, with an average of about 1 200×104 t/km2. Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3rd and 4th members of Wenchang Formation. Four favorable zones are selected for the division and evaluation of migration and aggregation units: No. ▪ Panyu 30 nose-shaped structural belt, No. ▪ Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt, No. ▪ gentle slope belt of Baiyun east sag, and No. ▪ Baiyun 1 low-uplift.

Phase change of the Ordovician hydrocarbon in the Tarim Basin: A case study from the Halahatang–Shunbei area

Abstract To clarify the genetic mechanism for phase change of the hydrocarbon in the ultra-deep reservoirs, a case study from the Ordovician hydrocarbon in the Halahatang–Shunbei area (HSA), Tarim Basin, NW China, was conducted. The results show that the Ordovician reservoirs in the HSA are characterized as multi-phase reservoirs with a lateral co-existence of condensates, volatile-oil reservoirs, normal oil reservoirs, and heavy oil reservoirs. From north to south, there are regular variations in the geochemical characteristics of the Ordovician hydrocarbon in different blocks of the HSA, showing an increasing trend in GOR, dryness coefficients, methane contents, methane carbon isotope values, and ethane carbon isotope values, while a decreasing trend in oil densities and wax contents. Because the same Cambrian–Lower Ordovician source for the Ordovician hydrocarbon is observed and the kerogen-cracking gas is dominated in the HSA, the regular variations of the hydrocarbon phases and geochemical characteristics can be interpreted as records of biodegradation and multistage oil–gas filling rather than controlled by the source rock organofacies, oil cracking, and gas invasion. The formation mechanism of the Ordovician multi-phase reservoirs in the HSA suggests that the deep strata of the Tarim Basin hold potential for the exploration of natural gas resources.

Generation Potential and Characteristics of Kerogen Cracking Gas of Over-Mature Shale

To investigate the characteristics and generation potential of gas generated from over-mature shale, hydrous and anhydrous pyrolysis experiments were carried out on the Longmaxi Formation in the Anwen 1 well of the Sichuan Basin of China at temperatures of 400–598 °C and pressures of 50 Mpa, with (hydrous) and without (anhydrous) the addition of liquid water. The results show that in the presence of water, the total yield of carbon-containing gases (i.e., the sum of methane, ethane, and carbon dioxide) was increased by up to 1.8 times when compared to the total yield from the anhydrous pyrolysis experiments. The increased yield of carbon dioxide and methane accounted for 89% and 10.5% of the total increased yield of carbon-containing gases. This indicated that the participation of water could have promoted the release of carbon from over-mature shale, like we used in this study. The methane generated in the hydrous pyrolysis experiments was heavier, with a δ13C value of −21.27‰ (544 °C) compared to that generated in the anhydrous pyrolysis experiments, which showed a lighter δ13C of −33.70‰ (544 °C). It is noteworthy that the δ13C values of the methane from hydrous pyrolysis at >500 °C were even heavier than that of the kerogen from the over-mature shale, although the δ13C values of the methane show an overall increasing trend with increasing temperature both in hydrous and anhydrous pyrolysis. The carbon dioxide from hydrous pyrolysis was less enriched in 13C relative to that from anhydrous pyrolysis. Specifically, the δ 13C values of the carbon dioxide increased with the increasing temperature in anhydrous pyrolysis, whereas they remained nearly constant with increasing temperature in hydrous pyrolysis. The overall lighter δ13C values of the carbon dioxide generated in the hydrous pyrolysis experiments likely indicate that water tends to prompt the release of lighter carbon and/or suppress the release of heavier carbon from over-mature shale in the form of carbon dioxide, especially at higher temperatures, for example, of >510 °C.

Overpressure origin and evolution during burial in the shale gas plays of the Wufeng-Longmaxi formations of southern Sichuan basin

Identifying the origin, evolution and distribution of overpressure poses a significant challenge in shale gas reservoir, particularly in the deeper layers and zones of the Wufeng-Longmaxi Formations. To uncover the origin mechanism and reconstruct the evolution process of overpressure, samples are collected from the Wufeng-Longmaxi Formations in the southern Sichuan Basin. Subsequently, a combination of multi well-logging methods is employed to comprehensively identify the origin mechanism of overpressure. Additionally, forward numerical simulation and Laser Raman inversion validation are utilized to reconstruct the evolution process of overpressure during burial. Results show that: (1) Hydrocarbon generation pressurization is identified as the dominant origin mechanism of overpressure in the Wufeng-Longmaxi shale gas reservoir, employing a combination of well-logging methods, the revised Bowers method, and a velocity-density intersection chart. (2) The Wufeng-Longmaxi shale undergoes three main pressurization processes, including kerogen generation oil pressurization, crude oil cracking gas pressurization and kerogen cracking gas pressurization. Hydrocarbon generation pressurization correlates closely with factors such as organic matter abundance and type, original hydrogen index, kerogen mass fraction and transformation rate, oil cracking rate and retention coefficient. (3) The pressure coefficient of kerogen generation oil pressurization and gas cracking pressurization reaches 1.73 and 2.78, respectively. The contribution of crude oil cracking gas pressurization (75.6 MPa) is significantly greater than kerogen generation oil pressurization (37.8 MPa). (4) The density of methane inclusions (0.290–0.319 g/cm3) is corroborated through both Laser Raman spectroscopy and homogenization temperature analysis. The paleo pressure is recovered as 90.3–193.5 MPa, with a corresponding pressure coefficient spanning from 1.39 to 2.98. This study not only contributes to the advancement of the shale gas accumulation theory, but also provides valuable insights to guide the further exploration and development of marine shale gas within the intricate tectonic setting of the Sichuan Basin.

Geochemical characteristics and exploration significance of ultra-deep Sinian oil and gas from Well Tashen 5, Tarim Basin, NW China

The Well Tashen 5 (TS5), drilled and completed at a vertical depth of 9017 m in the Tabei Uplift of the Tarim Basin, NW China, is the deepest well in Asia. It has been producing both oil and gas from the Sinian at a depth of 8780–8840 m, also the deepest in Asia in terms of oil discovery. In this paper, the geochemical characteristics of Sinian oil and gas from the well were investigated and compared with those of Cambrian oil and gas discovered in the same basin. The oil samples, with Pr/Ph ratio of 0.78 and a whole oil carbon isotopic value of −31.6‰, have geochemical characteristics similar to those of Ordovician oils from the No. 1 fault in the North Shuntuoguole area (also named Shunbei area) and the Middle Cambrian oil from wells Zhongshen 1 (ZS1) and Zhongshen 5 (ZS5) of Tazhong Uplift. The maturity of light hydrocarbons, diamondoids and aromatic fractions all suggest an approximate maturity of 1.5%–1.7% Ro for the samples. The (4-+3-) methyldiamantane concentration of the samples is 113.5 μg/g, indicating intense cracking with a cracking degree of about 80%, which is consistent with the high bottom hole temperature (179 °C). The Sinian gas samples are dry with a dryness coefficient of 0.97. The gas is a mixture of kerogen-cracking gas and oil-cracking gas and has Ro values ranging between 1.5% and 1.7%, and methane carbon isotopic values of −41.6‰. Based on the equivalent vitrinite reflectance (Reqv = 1.51%–1.61%) and the thermal evolution of source rocks from the Cambrian Yu'ertusi Formation of the same well, it is proposed that the Sinian oil and gas be mainly sourced from the Cambrian Yu'ertusi Formation during the Himalayan period but probably also be joined by hydrocarbon of higher maturity that migrated from other source rocks in deeper formations. The discovery of Sinian oil and gas from Well TS5 suggests that the ancient ultra-deep strata in the northern Tarim Basin have the potential for finding volatile oil or condensate reservoirs.

Differential Enrichment Regulation and Genetic Analysis of Tight Sandstone Gas Reservoir

In the deep Paleogene of graben basins in eastern China, not only the tight sandstone oil and gas resources, but also the secondary hydrocarbon generation of source rocks are universal and worth studying. In order to elucidate the laws of oil and gas accumulations in tight sandstone with different phases and explore the diversity of its genetic mechanism, Shahejie Formation in Wendong area was taken as an example in this paper to carry out further research. Firstly, the differential enrichment rules of oil and gas reservoirs are clarified from the aspects of spatial distribution, phase type and fluid properties. Secondly, the reasons for differential accumulation of oil and gas reservoirs were analyzed from multiple perspectives by using a variety of methods, such as source rock thermal evolution simulation, fault activity evaluation and reservoir porosity evolution. A large number of researches have been carried out on hydrocarbon generation and expulsion process of source rocks, paleo-temperature and paleo-pressure changes, the connectivity of skeleton sand bodies, reservoir physical property and densification process, tectonic strength and so on. The results indicate that the deep tight sandstone reservoirs of the Paleogene in the Wendong area have a quasi-continuous distribution characteristic of "planar partition and longitudinal zoning". Secondary kerogen cracking gas, crude oil cracking gas, medium light crude oil, and primary kerogen cracking gas are distributed in a semi-circular manner, from the center of Qianliyuan Sag to Wendong graben and rollover anticline belt at the high structural position. In conclusion, the two periods of hydrocarbon generation and expulsion of source rocks lead to the discontinuity of hydrocarbon accumulation process. Paleo-temperature and paleo-pressure conditions control the phase types of hydrocarbon filling. The lateral connectivity and the difference of physical properties of the skeleton sand bodies limit the distribution range of oil and gas reservoirs. The temporal and spatial availability of faults during the critical accumulation period determines the differential enrichment of oil and gas. The temporal and spatial validity of faults during the critical accumulation period determines the extent of differential enrichment of oil and gas.

Geological Characteristics of Lower Paleozoic Shale Gas Accumulation in the Yuxi Region, Southern Sichuan Basin: In View of High-Density Methane Inclusions.

Twelve shale fracture veins and forty-nine fluid inclusion assemblages within the veins of 3800–4200 m in three wells located in different tectonic zones in the Yuxi Region, southern Sichuan Basin were selected in this study. The burial and thermal histories of single wells were reconstructed, and time–temperature–pressure of oil and gas filling were clarified using microscopy observation, Raman microprobe analyses, geochemical tests, and fluid inclusion microtemperature measurement. The shale fracture veins of the Wufeng-Longmaxi Formation in the Yuxi Region are mainly formed vertically and horizontally, where the vein-forming fluids are derived from endogenous fluids. A large number of methane inclusions, bituminous inclusions, and methane-bearing bituminous inclusions within the veins confirm the process of oil cracking gas and kerogen cracking gas. The homogeneous temperature (Th) of the aqueous inclusions contemporaneous with the bituminous inclusions ranges from 109.3 to 174.1 °C, which were trapped during 220 to 250 Ma. The homogeneous temperature of the aqueous inclusions contemporaneous with the methane inclusions ranges from 137.3 to 226.8 °C, which were trapped during 160 to 195 Ma and 51 to 56 Ma. The trapped pressure calculated by high-density methane inclusions (0.246–0.293 g/cm3) is between 82.9 and 140.1 MPa, with a pressure coefficient between 1.64 and 2.07. The formation pressure coefficient is nearly two, indicating that the current overpressure is inherited from the overpressure at the maximum burial depth. The earlier the fracture vein opening, the less the damage to the shale gas accumulation, and the more opening-closing phases, the lower the homogeneous temperature of the gas–liquid two-phase aqueous inclusions coeval with the high-density methane inclusions and the greater the degree of damage to the shale gas accumulation. The results provide a basis for further study on the genesis of overpressure and the migration of shale gas.

A Comparison of the Geochemical Characteristics of Ultra-Deep Natural Gas in the Kuqa Foreland and Marine Craton Areas in the Tarim Basin, China

This research analyzed the composition and hydrocarbon isotope geochemical characteristics of ultra-deep natural gas (buried deeper than 6000 m) in more than 130 wells in the Tarim Basin. Characteristics of the ultra-deep natural gas components in the Tarim Basin are as follows: natural gas in the Kuqa sandstone reservoir is developed as dry gas, with a high methane content (an average of 95.53%) and a low ethane content (an average of only 1.39%). The ultra-deep gas of the marine craton carbonate reservoirs in the North Tarim-Central Tarim-East Tarim area is developed as wet gas. It is mainly composed of methane ranging from 56.1% to 98.8%, with an average content of 76.36% and also contains a small amount of ethane amounting to 6.74%. CO2 and H2S contents of ultra-deep condensate gas in the Central Tarim area are high, with maximum values of 24.2% and 23.1%, respectively. Isotopic characteristics are as follows: δ13C1 values of Kuqa natural gas are distributed between −36‰ and −25.3‰, with an average of −28.2‰, δ13C2 values are distributed between −26.2‰ and −13.8‰, with an average of −18.3‰. Most gas samples in Kuqa area are developed with the reversal of carbon isotopic series as δ13C2 > δ13C3, and the δ13CCO2 values are distributed between −19.5‰ and −10.3‰. The δ13C1 values of ultra-deep gas in marine craton carbonate rocks are distributed between −54.4‰ and −33.3‰, with an average of −42.6‰. δ13C2 values are distributed between −41.1‰ and −29.4‰, with an average of −33.8‰, and δ13CCO2 values are distributed between −28.2‰–0.6‰. According to the identification chart, it can be seen that the ultra-deep gas in the sandstone reservoir of the Kuqa foreland is mainly coal-derived gas in the high over-mature stage, and the reversal of carbon isotopic series may be caused by the mixing of natural gas of the same type and different sources. The natural gas in carbonate reservoirs of marine craton is mainly oil-type gas with complex sources, including both kerogen cracking gas and oil cracking gas. CO2 can be formed by organic and inorganic genesis. Inorganic CO2 is most likely to be generated by the dissolution of carbonate rocks under acid formation water.

Natural gas origin of Langgu Sag in Jizhong Depression, Bohai Bay Basin: Insight from hydrous pyrolysis experiments of gold tube

Two mudstone samples in low-maturity from the E2s3 source rock interval were used to hydrous pyrolysis experiments of gold tube with isothermal heating in order to better understand natural gas origins of Langgu Sag. The results displayed that the E2s source rocks in Langgu Sag attained the peak yield of nearly 350 mg/g TOC at about 0.9% of Ro for C6+ compounds due to thermal cracking occurrence of them if Ro higher than 0.9%, and C6-14 compounds would reach the maximum yield at about 1.3% of Ro owed to C14+ compounds preferentially cracking to them. Hydrocarbon gases were dominated by kerogen cracking gases at Ro lower than about 1.3% (referred to oil associated gases) and higher than about 1.8% (interpreted to residual kerogen cracking gases) but by secondary gases (belonged to early-generated liquid hydrocarbon cracking gases) if Ro at about 1.3%–1.8% for E2s source rocks. Furthermore, the yield of kerogen cracking gases would reach 90–100 ml/g TOC at 1.3% of Ro, far greater than 20 ml/g TOC as the lower limit standard of an effective gas source rock, even the kerogen cracking gas yield could reach 20 ml/g TOC if Ro at about 0.8%, therefore, as long as the E2s source rocks in Langgu Sag reach mature level, they can become effective gas source rocks.Considering their calculated Ro mainly distributing between 1.0% and 1.3% except Ordovician buried-hill reservoirs of the D2 oil-gas field, the proved natural gases in Langgu Sag mainly originated from kerogen cracking gases at Ro lower than 1.3%. And the gases from Ordovician buried-hill reservoirs of the D2 oil-gas field, with calculated Ro ranging about 1.3%–1.6%, essentially derived from residual liquid hydrocarbon cracking gases of the E2s4 source rocks, because the Ro of E2s3 source rock is mainly lower than 1.1% but it reaches about 1.8% for E2s4 source rock at present. The natural gases in shallow reservoirs experienced different degrees of bacterial degradation and formed methane-dominated gas reservoirs, consequently, the C1/C1-5 values displayed a range of 0.96–0.99 for bacterial degradation gas reservoirs and of 0.67–0.89 for natural gas reservoirs without bacterial reworking.

Implication of Alkane Carbon and Hydrogen Isotopes for Genesis and Accumulation of Over-Mature Shale Gas: A Case Study of Longmaxi Formation Shale Gas in Upper Yangtze Area

To clarify the implication of alkane carbon and hydrogen isotopes for the genesis and accumulation of over-mature shale gas, we carried out a comparative study on Longmaxi shale gases from eight blocks in the Upper Yangtze area. The results show that the δ13CCH4, δ13CC2H6, and δ13CC3H8 of Longmaxi shale gas are all positively correlated with Ro. According to the distribution model of δ13C with thermal maturity, the Longmaxi shale gas lies in the reversal stage. Shale gas is a mixture of the kerogen cracking gas and secondary cracking gas, and the mixing ratio of the two cracking gas can be estimated by isotopic fractionation experiments of thermogenic gas. The proportion of secondary cracking gas in the shale gas of the Longmaxi Formation ranges from 33 to 72%. The increase of secondary cracking gas with lower δ13C would reduce the carbon isotope of the shale gas. The δ13CC2H6 and δ13CC3H8 have acute sensitivity to the occurrence of secondary cracking gas, hence they can be used as potential indicators of shale gas content. The decline of gas generation capacity, the reduction of micropores, and the destruction of tectonic movement are the considerable factors leading to the decrease of gas content in high-maturity shale.

Geochemistry and origins of natural gas in the Hong-Che fault zone of the Junggar Basin, NW China

The uplift zone adjacent to the sag is the dominant direction of natural gas migration and accumulation, and the multi-layer source rocks developed in the sag have laid a material foundation for natural gas accumulation. However, owing to the deep burial and high drilling cost of the sag, drilling the source rocks in the sag is challenging, which severely restricts the fine gas-source correlation study of natural gas in the uplift zone. The Hong-Che fault zone is adjacent to the Shawan sag, the natural gas is of various types, and the origin and source of natural gas are unclear. The referential contrast research methods on multi-source and multi-period natural gas are absent, which hinders their subsequent exploration and development. In view of these problems, we analysed the pyrolysis gas of source rocks, along with its composition, including the light hydrocarbon and the carbon isotope of natural gas. The experimental results show that: (1) There are significant differences in the carbon isotopes of ethane in pyrolysis gas from different source rocks, which is one of the research bases of natural gas source analyses. (2) The natural gas in the region is mainly present as kerogen cracking gas. (3) The natural gas in the study area is divided into five types. Type-Ⅰ and type-Ⅱ gases derived from the humic source rocks of the Carboniferous stratum and the Jiamuhe Formation, respectively. Type-Ⅲgas was sourced from the sapropelic source rocks of the Fengcheng Formation. Type-Ⅳ gas was originated from mixed source rocks of the Wuerhe Formation. Type-Ⅴ gas was derived from the mixing of multiple sets of source rocks. (4) The south section of the Hong-Che fault zone has high gas production, and is a favourable exploration target for humic pure gas reservoirs. The slope area near the Shawan sag has better preservation conditions and is a favourable target area for subsequent natural gas exploration activities. These results lay the theoretical foundation for the evaluation and identification of the origins of multi-source and multi-period natural gas in complex areas.

Genesis and sources of natural gas in fold-and-thrust belt: The Middle Permian in the NW Sichuan Basin

Fold-and-thrust belts are important locations for oil and gas exploration, but due to the complex sources, migration, and charging histories the exploration risk is extremely high. The Longmenshan belt in the NW Sichuan Basin offers an excellent opportunity to study the genesis and sources of natural gas in fold-and-thrust belt. We synthesize existing geochemical data from ∼1100 samples from various strata in the Sichuan Basin. Among them, the bitumen biomarkers and the natural gas molecular compositions and stable carbon isotopes in the Middle Permian of different structural belts were analyzed to investigate the gas genetic types and sources. Then, they were compared with natural gas from other strata in the Sichuan Basin. Results indicate that the Middle Permian natural gases in the NW Sichuan Basin are dominated by hydrocarbon gases, with a small amount of CO2 and N2. The identification of the gas origin and gas-source correlation indicate that there are significant differences between the Middle Permian natural gas in different structural belts of the Longmenshan belt. The natural gas in the thrust nappe belt is mainly oil-cracking gas from the Qiongzhusi Formation (Fm) source rock, and the natural gas in the thrust front belt shows obvious mixed-source characteristics, with both kerogen-cracking gas of the Permian source rocks and oil-cracking gas from the Qiongzhusi Fm source rock. However, the natural gas in the unfaulted belt mainly comes from the kerogen-cracking gas in the Permian source rocks. Overall, from the thrust nappe belt to the thrust front belt, and then to a belt that is largely unfaulted, the contribution of deep source rocks controlled by fault migration channels decreases with gradually weakening deformation. This study will help to better understand the petroleum system in the fold-and-thrust belt and optimize the future exploration strategy.

Geochemical characteristics, origin and carbon isotope reversal of the presalt natural gas in the Lower Paleozoic Ordovician carbonates, Ordos Basin, China

The origin and potential source of the presalt natural gas in the Lower Paleozoic Ordovician carbonates within the Ordos Basin, China, is heavily debated, and the causes of carbon isotope reversal are currently unclear. This study analyzes the source and origin of the presalt natural gas and determines the reasons for carbon isotope reversal. The results show that the nonhydrocarbons contain CO2, H2S, and N2 and some gas samples have high H2S contents of 9.02%–23.58%. The dryness coefficient (C1/C1+) of 91.06%–99.99% (ave. 98.34%) suggests that the presalt gas is mainly a dry gas with some wet gas and that it originates from a high-to over-mature source. However, the results show that the presalt natural gas is primarily a wet-gas-cracking gas, rather than a kerogen-cracking gas, with a certain amount of coal-type gas mixing and it mainly originated from oil-prone marine carbonate source rocks rather than the Permian–Carboniferous coal measures. The gas has different types of carbon isotope reversal patterns, and the δ13C2 values become negative at Roequ > 1.5%. The mixing between the oil-cracking and wet-gas-cracking gas at Roequ > 1.5% results in carbon isotope reversal (δ13C1 > δ13C2), rather than Rayleigh and migration fractionation. The occurrence of thermochemical sulfate reduction (TSR) is supported by the high abundance of H2S in the presalt gas, reservoir bitumen in dissolved pores, secondary calcite with negative δ13Ccarbonate of −21.1‰ to −9.7‰, and diagenetic cubic pyrite. It is evident that the heavy δ13C2 values (greater than −28‰) and the carbon isotope reversal of δ13C2 > δ13C3 of the presalt natural gas at Roequ < 1.5% are related to TSR. This study also establishes a new model of the carbon isotope reversal of the natural gas, which is primarily controlled by its thermal maturity and TSR. Six carbon isotope patterns can be well explained and are supported by real gas samples from the presalt strata, and two types of carbon isotope reversal are predicted.

Geochemical characteristics and resource potential of shale gas in Sichuan Basin, China

Shale gas is a green, low-carbon and clean unconventional natural gas energy. China is rich in shale gas resources. Accelerating shale gas exploration and development is of great practical significance to improve China's energy structure and achieve the goal of “2030 carbon peak and 2060 carbon neutralization”. The Ordovician Wufeng Formation to Silurian Longmaxi Formation in Sichuan Basin is the key strata for shale gas exploration and development in China. Based on the experimental analysis of shale gas in Wufeng Formation to Longmaxi Formation in Weiyuan, Changning, Zhaotong, Fuling and Weirong areas of Sichuan Basin, this paper systematically analyzes the geochemical characteristics of shale gas in Wufeng Formation to Longmaxi Formation, discusses the genesis of shale gas, the causes of hydrocarbon isotope inversion and the source of shale gas, and looks forward to the exploration prospects of shale gas resources in the basin. It has important guiding significances for shale gas exploration and development in Sichuan Basin and even in China. The results show that: (1) The shale gas of Wufeng-Longmaxi Formations is a typical dry gas, and the hydrocarbon isotopes are distributed in negative sequence. The carbon isotopes of alkane gas in Changning, Zhaotong and Fuling areas are heavier and have a higher degree of thermal evolution than those in Weiyuan and Weirong areas, and the rare gas is of crustal origin. (2) Shale gas of Wufeng-Longmaxi Formations is a thermogenic oil-typed gas at high-over mature stage, which is mainly the mixture of crude oil cracking gas and kerogen cracking gas. The hydrocarbon isotope inversion of alkane gas is mainly caused by the mixing of crude oil cracking gas and kerogen cracking gas at high-over mature stage, the exchange between formation water and methane at high evolution stage and so on. (3) The carbon isotopic values of methane in shale gas of Wufeng-Longmaxi Formations match the carbon isotopic values of kerogen in mudstones of Longmaxi Formation of Lower Silurian, which conforms to the law of carbon isotopic fractionation δ13Ckerogen>δ13Coil>δ13Calkane gas. (4) The total amount of marine, marine continental transitional and continental facies shale gas resources in Sichuan Basin is about 41.5 × 1012 m3, with broad exploration prospects in resource potential.

The geochemical characteristics and origin of Ordovician ultra-deep natural gas in the North Shuntuoguole area, Tarim Basin, NW China

Ultra-deep Ordovician in Shuntuoguole area, Tarim Basin, NW China, has complex oil & gas phases, in which light oil, volatile oil, condensate and dry gas phases coexisting. The study compares the geochemical characteristics and origin of Ordovician ultra-deep natural gas in the North Shuntuoguole (SB) area to that of gas in the Shuntuo (ST), South Shuntuoguole (SN), Gulong (GL), and Gucheng (GC) areas using natural gas composition, carbon isotope and hydrogen isotope data and light hydrocarbon data. The Ordovician ultra-deep natural gas in the SB area is wet gas, with dryness indexes ranging from 0.52 to 0.88 and minimal H2S content. The carbon isotopes of natural gas are relatively low, with δ13C1 and δ13C2 values ranging from −49.6‰ to −44.7‰ and −39.3‰ to −32.7‰, respectively. All the natural gas shows positive carbon and hydrogen isotope series. The n-alkane and iso-alkane dominate the C5–C7 light hydrocarbon, with the methylcyclohexane index of light hydrocarbon lower than 35%. All of the Ordovician natural gas in the Shuntuogule area is oil-type gas. The Ordovician natural gas in the SB area is dominated by kerogen cracking gas, with a small fraction of wet gas from the early stages of oil cracking, whereas, all of the gas in the ST, SN, GL and GC areas comes from oil cracking. The Cambrian source rocks led directly to both types of cracking gases. The distribution of two types of cracking gas in the Shuntuogule area is correlated with the maximum paleogeothermal temperature and (or) present temperature of the Ordovician. The maximum paleogeothermal temperature and present Ordovician temperature in the SB area are 170–180 °C and 150–160 °C, respectively, which are lower than those in ST and SN areas, and have not yet achieved the temperature of large amount oil cracking. As a result, light oil and volatile oil phases were preserved in the SB area, which was dominated by kerogen cracking gas, whereas reservoir phases varied from condensate to dry gas phases, and natural gas is oil-cracking gas, from ST to SN to GL to GC areas, due to large scale oil cracking caused by high present temperature and (or) paleo-geothermal temperature of the Ordovician.

Gas composition and carbon isotopic variation during shale gas desorption: Implication from the Ordovician Wufeng Formation - Silurian Longmaxi Formation in west Hubei, China

This paper focuses on the gas composition and carbon isotopic variation during gas desorption from the shale in Ordovician Wufeng Formation-Silurian Longmaxi Formation. The results show that the desorbed shale gases are predominately comprised of methane (content: 98.36–98.76%) and thus are typical dry gas. As the desorption proceeded, the content of methane gradually decreased, and the drying coefficient (C1/C1-5) of the desorbed shale gases also gradually decreased. The drying coefficient decreased from 98.58 to 99.04% (98.81% on average) of the initial desorbed samples to 88.72–96.78% (94.15% on average) of the final desorbed samples. Based on the variation patterns of gas component ratios during the shale gas desorption, the order of the shale's absorption capacity for different gas components is determined as CO2 > H2 > C3H8 > C2H6 > CH4 > He. The drying coefficient of the shale gas is negatively correlated with the total shale gas content due to the different adsorption capability of shale for gaseous hydrocarbons. The δ13C values tended to become heavier during desorption in general. The δ13C1 values of the initial desorbed samples were the lowest, ranging from −30.71‰ to −25.63‰. In detail, the δ13C values of methane increased by 5.41–25.93‰, while those of ethane increased within a relatively smaller range. The carbon isotopic fractionation is mainly ascribed to diffusion and adsorption/desorption. Moreover, the carbon isotopic fractionation degree of methane was correlated with the shale gas content during the field desorption, suggesting that the carbon isotopic fractionation degree of methane is a potential tool for the identification and selection of favorable sweet spots of shale gas. In addition, the shale gas from Wufeng-Longmaxi Formation in west Hubei consists of highly mature oil-cracking gas and kerogen-cracking gas. All of the desorbed shale gas is characterized by isotopic reversal and the extent of the isotopic reversal increased as desorption continued. This is primarily caused by the mixing of the gas from thermal degradation of kerogen with the gas from residual oil cracking and wet gas as well as the diffusion of the shale gas. The carbon isotope reversal of methane and ethane is not directly related to shale gas content.

Effect of organic maturity on shale gas genesis and pores development: A case study on marine shale in the upper Yangtze region, South China

Abstract The marine shale in southern China has undergone complex tectonic evolution with a high thermal evolution degree. Excessive thermal evolution brings certain risks to shale gas exploration and development. With the advancement of experimental methods, the evolution process of shale reservoirs can be better understood from the micro-nanoscale. This work takes the Ordovician-Silurian Wufeng and the first member of Longmaxi Formation in the Sichuan Basin and Lower Cambrian Niutitang Formation in Outer Margin of the Sichuan Basin to study the impact of maturity upon the genesis of shale gas and development features of the reservoir. A series of geochemical research methods, including TOC, gas component and gas isotope, were adopted to study the impact of different thermal evolution stages of organic matter upon the genesis of shale gas. The nanoscale micro-imaging technique, such as FIB-SEM and FIB-HIM, was used to analyze the development of OM-hosted pores. As shown from the results, when R o = 1.2–3.5%, the marine shale gas is dominated by methane and other hydrocarbon gases, since the mixture of cracking gas from liquid hydrocarbons and kerogen-cracking gas cause the carbon isotope reversal. Besides, the pyrobitumen pores characterized by the strong connectivity and storage capacity were primarily developed. When R o &gt; 3.5%, the organic matter is at the graphitization stage. The shale gas is mainly composed of nitrogen at this stage. The nitrogen is originated from the atmosphere and the thermal evolution process, and the OM-hosted pores (pyrobitumen and kerogen pores) characterized by the bad connectivity and storage capacity are developed. Finally, the main component of shale gas, the genesis of shale gas and the pattern of OM-hosted pores under different thermal evolution stages of organic matter are summarized, which provide technical support for the exploration and development of shale gas.

Factors Affecting Shale Gas Chemistry and Stable Isotope and Noble Gas Isotope Composition and Distribution: A Case Study of Lower Silurian Longmaxi Shale Gas, Sichuan Basin

The Weiyuan (WY) and Changning (CN) fields are the largest shale gas fields in the Sichuan Basin. Though the shale gases in both fields are sourced from the Longmaxi Formation, this study found notable differences between them in molecular composition, carbon isotopic composition, and noble gas abundance and isotopic composition. CO2 (av. 0.52%) and N2 (av. 0.94%) were higher in Weiyuan than in Changning by an average of 0.45% and 0.70%, respectively. The δ13C1 (−26.9% to −29.7%) and δ13C2 (−32.0% to −34.9%) ratios in the Changning shale gases were about 8% and 6% heavier than those in Weiyuan, respectively. Both shale gases had similar 3He/4He ratios but different 40Ar/36Ar ratios. These geochemical differences indicated complex geological conditions and shed light on the evolution of the Lonmaxi shale gas in the Sichuan Basin. In this study, we highlight the possible impacts on the geochemical characteristics of gas due to tectonic activity, thermal evolution, and migration. By combining previous gas geochemical data and the geological background of these natural gas fields, we concluded that four factors account for the differences in the Longmaxi Formation shale gas in the Sichuan Basin: a) A different ratio of oil cracking gas and kerogen cracking gas mixed in the closed system at the high over-mature stage. b) The Longmaxi shales in WY and CN have had differential geothermal histories, especially in terms of the effects from the Emeishan Large Igneous Province (LIP), which have led to the discrepancy in evolution of the shales in the two areas. c) The heterogeneity of the Lower Silurian Longmaxi shales is another important factor, according to the noble gas data. d) Although shale gas is generated in closed systems, natural gas loss throughout geological history cannot be avoided, which also accounts for gas geochemical differences. This research offers some useful information regarding the theory of shale gas generation and evolution.

P.771 Deciphering pharmacological mechanism of neurotrophic activity of steroidal chlorohydrin by proteomic, immunocytochemical and computational approach

Wufeng-Longmaxi Formations shale gas is a new exploration field in Wuxi area, Sichuan Basin, China. Some geological parameters related to shale gas evaluation of the new exploration wells in Wuxi area have been studied, including shale reservoir, gas-bearing, geochemical and paleontological characteristics. The study suggests that the original shale gas generation conditions of the area were good, but later this area went through serious and multi-phase tectonic damage. The major evidences include that: the δ13C2 value of shale gas is obviously higher than that in areas with the same maturity, indicating the shale gas is mainly late kerogen cracking gas and high hydrocarbon expulsion efficiency; the porosity of shale in Wuxi area is very low because of strong tectonic movements and lack of retained oil in the shale; some shale cores near faults even show very weak metamorphic characteristics with intense cleavage, and the epidermis of graptolite fossils was pyrolyzed. The comprehensive study shows shale gas in Wuxi area has prospective resources, but the possibility to get scale commercial production in recent time is very low.