Oil Cracking Gas Research Articles

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.

New insights into the role of system sealing capacity in shale evolution under conditions analogous to geology: Implications for organic matter evolution and petroleum generation

Closed and semi-closed pyrolysis of a lacustrine shale sample were conducted using the same instrument characterized by lithostatic pressure and limited reactive space in order to unravel the impacts of system sealing capacity on organic matter evolution and hydrocarbon generation in shales under conditions analogous to natural processes. The products and solid residues were subjected to chemical composition determination, gaseous carbon isotopic composition analysis, solvent extraction, and Rock-Eval pyrolysis. Higher organic matter transformation and oil retention contents were obtained at 300–500 °C in the closed pyrolysis system compared to those in the semi-closed system at the same temperature ranges. However, lower yields of hydrocarbons except for methane were obtained in the closed system at this temperature range, while the iso-/n-C4,5 as well as C1/C1-5 values were significantly higher in this system. Stronger recombined reactions between kerogen and hydrocarbons were proposed to occur at 300–500 °C during the closed pyrolysis process, leading to the consumption of oil and hydrocarbon gases. Ultimately, positive deviations of initially more negative δ13C2∼3 values were occurred in the closed system, resulting in similar δ13C2∼3 values from the two systems before secondary cracking of hydrocarbon gases commences, but the δ13C1 value from the closed system was overall more negative. Different water retention ratios and hydrocarbon expulsion efficiencies induced by system sealing capacity are the predominant factor controlling organic matter evolution and petroleum generation during the pyrolysis processes. This highlights that the different gas contents of the Cambrian and Silurian shales in South China may be associated with the differences in the system sealing capacities of shales, although the sedimentary environment of the studied sample is lacustrine, and the lower methane content of the Cambrian shale gas is probably ascribed to semi-closed system. Finally, a higher ratio of oil cracking gas may be an important signal for natural gas systems that have better exploration potential.

Phase fractionation and oil mixing as contributors to complex petroleum phase in deep strata: A case study from LG7 block in the Tarim Basin, China

Integrated geochemical analysis was conducted on oil and gas samples from the LG7 block, Tarim Basin, China, to investigate the causal mechanisms for the complex petroleum phase. Consistency in biomarker derived parameters suggest that heavy oil, black oil, and condensate, though vary in physical properties and phase state, share a genetic affinity and are all mature oil generated at peak oil window. However, mass loss and double-peaks pattern in n-paraffins of black oil and heavy oil, and much higher maturity of gas and some oil fractions (diamondoids) jointly suggest the oil samples in the study site have suffered secondary alteration process including phase fractionation and mixing. In combination with tectonic evolution analysis, the study site experienced severe uplift after primary oil accumulation and thus formed biodegraded heavy oil in local highs. Since Neogene, the introduction of oil-cracking gas from deeper strata charged early oil accumulations and caused phase fractionation, during which primary oil was fractionated into vaporized light oil and heavy oil residue. Vaporized light oil continued to migrate towards higher positions and were readily to either mix with other oil residue and heavy oil, or to be trapped to form secondary condensate in favorable reservoirs. Thus, the complex disordered distribution of heavy oil, black oil, and condensate is observed within a relatively small area. Our reconstruction of the petroleum accumulation and alteration process speculates future exploration endeavors to potential oil-cracking gas/condensate accumulations in the study area.

Geochemistry and accumulation of petroleum in deep lacustrine reservoirs: A case study of Dongying Depression, Bohai Bay Basin

Numerous volatile oil reservoirs and condensate gas reservoirs were discovered in the Member 4 of Shahejie Formation in the Paleogene system, northern Dongying Depression of Bohai Bay Basin, eastern China. Deep reservoirs were examined thoroughly, including biomarker, light hydrocarbon, and diamondoid in oil; composition and carbon isotope in natural gas; fluid inclusion; and thermal history. Based on diamondoid parameters, the equivalent vitrinite reflectance (EqVRo) of the crude oil ranges from 1.55% to 1.82%, indicating a state of high to over maturity, while the low absolute concentration of methyl diamantanes indicates that the oil is still in the early cracking stage. The deep gas is a mixture of kerogen degradation gas generated from hydrocarbon source rocks and oil cracking gas produced from the reservoirs. The EqVRo of gas is mostly between 0.8% and 1.3%, which is in a moderately mature state. The oil and gas are sourced from Member 4 of the Shahejie Formation, which was formed in a saline and reductive environment with a main input of I-II algal organic matter. The kerogen degradation gas was generated in the late sedimentary period of Member 2 of the Shahejie Formation, which was the first stage of petroleum charging. The early oil and gas reservoirs underwent noticeable evaporative fractionation due to the invasion of oil cracking gas after entering the late period of the Guantao Formation in the Neogene, resulting in the formation of the present volatile and condensate oil and gas reservoirs.

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.

Insights into origins of the natural gas in the Lower Paleozoic of Ordos basin, China

Abstract Based on natural gas compositions, carbon isotope ratios, and geological analysis, the genesis and origin of gases in the Lower Paleozoic of Ordos basin are discussed. Due to differences in distribution and genesis, the gases in Lower Paleozoic were divided into five types, namely western margin gas, weathered crust gas, pre-salt gas, Ordovician deep gas, and Cambrian gas. The results show that the δ 13C1 and δ 13C2 of western margin gas range from −35.6 to −38.9‰ and from −27.2 to −35.9‰, respectively, indicating oil-type gas and mainly from the O1k and O2w marine source rocks. The δ 13C1 of weathered crust gas varies from −31.2 to −37.8‰, but δ 13C2 is mostly around −25.0‰, which indicates weathered crust gas originates from the Carboniferous–Permian coal-measure source rocks. In contrast, δ 13C1 and δ 13C2 in the pre-salt strata are mostly less than −30.0‰. Yet its distribution of Δ(δ 13C2–δ 13C1) is from −1.7 to 13.6‰, and C1/C2 + C3 is of 6.68–4372.50. These indicate that the pre-salt gas is mainly high-over mature oil cracking gas from the O1m marine source rock. The δ 13C1 of Ordovician deep gas is averaging −39.4‰, and δ 13C2 varies from −25.4 to −33.0‰, which imply coexistence of oil-type and coal-type gas. It is presumed that the C–P coal-type gas may migrate into and accumulate at Ordovician deep reservoirs through unconformity and fault. The δ 13C2 and Δ(δ 13C2–δ 13C1) of Cambrian gas are both the most negative, respectively, averaging −34.9‰ and averaging −3.2‰, indicating over-mature oil-type gas. Formation and evolution of the Qingyang paleo-uplift result in that the Cambrian gas mainly comes from the Cambrian or Ordovician marine source rocks in the southern basin.

Reservoir solid bitumen-source rock correlation using the trace and rare earth elements–implications for identifying the natural gas source of the Ediacaran-Lower Cambrian reservoirs, central Sichuan Basin

The hydrocarbon-source correlation in highly-mature and over-mature stages is a challenging task in natural gas exploration. The Ediacaran-Lower Cambrian natural gas in the central Sichuan Basin is typical oil-cracking gas. With a burial depth of more than 4650 m, the gas is now in the highly-mature to the over-mature stage (equivalent Ro>1.8%) with apparent alteration by thermochemical sulfate reduction (TSR), leading to difficulties for gas-source correlation. Conventional hydrocarbon-source correlation mainly relies on organic geochemical methods, taking media such as biomarkers and carbon isotope for correlation. However, in the highly-mature and over-mature stages, the characteristics of conventional biomarkers tend to be homogenised. Furthermore, the gas components and carbon isotope of natural gas are frequently altered by TSR in the deep burial stage. Thus, conventional organic geochemical methods are significantly restricted. This paper explored the source of highly-mature natural gas from the DY and LWM Formations in the central Sichuan Basin by studying the inorganic geochemical information (trace elements and rare earth elements) of the reservoir bitumen and potential source rocks. The results show that the depositional environment of the potential source rocks (the QZS and the D-3 source rocks) in the central Sichuan Basin were different. The redox-sensitive parameters (V/(V + Ni), Mo/Ni, δCe and Ce/Y) and the provenance-sensitive parameters (La/Co and La/Sc) of the source rocks have apparent differences, which can be used as the basis for gas-source correlation. The correlation results show that the LWM gas was derived from the QZS source rock, while the D-2 and D-4 gases were mainly derived from the QZS source rock, with a partial contribution of the D-3 source rock. During geologic evolution, the crude oil generated from the two sets of source rocks were thoroughly mixed in the paleo-oil reservoir of the D-4 Member. As a result, the characteristics of the D-3 source rock were obscured by the QZS. In contrast, the solid bitumen in the D-2 paleo-oil-reservoir recorded the contribution of the D-3 source rock. However, this contribution was limited within the range of 50 m adjacent to the D-3 Member by a more significant oil generation from the QZS source rock located in Deyang-Anyue Rift Trough. This study clarified the gas source differences between the D-2 Member, D-4 Member and LWM Formation, providing a new insight for in-depth study on the gas accumulation of the Ediacaran-Lower Cambrian in the central Sichuan Basin.

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.

Natural gas accumulation in the basin–mountain transition zone, northwestern Sichuan Basin, China

The basin–mountain transition zone is an important area for hydrocarbon exploration. To better understand the process and mechanism of hydrocarbon accumulation in this area, the middle Permian Qixia Formation at the piedmont of the Longmenshan Mountains, northwestern Sichuan Basin, China, was investigated. It is showed that natural gas in the Qixia Formation in the thrust belt (i.e., the Kuangshanliang and Hewanchang areas) was derived from lower Cambrian strata by oil cracking. The reservoirs are filled with amounts of bitumen, which reflects strong oil charging. However, the gas accumulation is not rich, which is due to the later destruction of hydrocarbon accumulations by the invasion of meteoric waters. In contrast, in the thrust front (i.e., the Shuangyushi area) and forebulge belt (i.e., the Jiulongshan area), the reservoirs contain few bitumens and large amounts of natural gas, which is indicative of good preservation for hydrocarbon accumulation. The natural gas was mainly derived from kerogen cracking in middle Permian source rocks, although it was mixed with a small amount of lower Cambrian-derived oil-cracking gases. The thrust front and forebulge belts occur in areas of lesser deformation, and thus are favorable for gas accumulation, due to the strata containing both sapropel- and humic-type source rocks and reservoirs. It is generalized that hydrocarbon resources in (ultra-)deep strata in the basin–mountain transition zone may be an important target for exploration worldwide.

The Fluid Evolution of Ancient Carbonate Reservoirs in Sichuan Basin and Its Implication for Shale Gas Exploration

Sichuan Basin is the only successful basin for shale gas exploration in China. In addition to the main shale in the Lower Silurian Longmaxi formation, the lower Cambrian Qiongzhusi shale is an important potential formation. However, it was once considered that shale gas is difficult to enrich because of its poor sealing conditions and hydrocarbon migration to adjacent reservoirs. With the increasing research on hydrocarbon generation and reservoir in shale of Qiongzhusi Formation in recent years, it has become an important exploration target in Sichuan Basin. The enrichment of oil and gas is closely related to fluid activities. Limited by the degree of exploration, there is little analysis of fluid activities in Qiongzhusi Formation, and there is little analysis of shale gas enrichment potential from the perspective of fluid. The hydrocarbon generated from Qiongzhusi shale in the rift could migrate laterally to the uplift area and form a reservoir in Dengying Formation. The fluid activities from source rock to reservoir are basically the same. Therefore, this paper reconstructed the history of hydrocarbon activities in Dengying reservoirs based on fluid inclusion analysis. Then the fluid activity process in Qiongzhusi shale was studied, and its enrichment conditions of shale gas was discussed. The results show that the hydrocarbon activities of Dengying Formation can be divided into three stages: 1) oil charging stage, 2) oil cracking gas generation stage and 3) gas reservoir adjustment stage. The first stage is under normal pressure, and the second and third stages developed overpressure with pressure coefficients of 1.3 and 1.2, respectively. High pressure coefficient is an important indicator of shale gas enrichment. Because the source rock of Qiongzhusi Formation has always been the main source rock of Dengying Formation, it can supply hydrocarbon to Dengying Formation only with overpressure in gas generation stage. Therefore, overpressure in the last two stages of gas generation indeed existed. As long as the sealing condition of shale itself is not particularly poor, shale gas “sweet points” would be formed. Therefore, the thick shale in Deyang-Anyue rift is the focus of shale gas exploration in Qiongzhusi Formation.

Hydrocarbon accumulation characteristics and model of deep-seated glutenite on steep slope zone of fault basin: a case study of the E2s4 Member in Yanjia area, Dongying Sag

Deep-seated oil and gas have become the focus of hydrocarbon exploration at home and abroad. Strengthening the research on the deep-seated hydrocarbon accumulation is the key to efficient exploration of oil and gas. Based on the analysis of light component and organic matter types of crude oil, the results show that there are two sets of source rocks in the E2s42 sub-member in Yanjia area, which are self-derived reservoirs. The reservoir types of the deep-seated glutenite in E2s4 member are mainly lithologic and lithologic-tectonic reservoirs. The distribution sequence is characterized by oil reservoirs in the high part of the structure, oil cracking gas reservoirs in the deep part, and condensate oil and gas reservoirs in the middle part. Further analysis shows that there are three layer pressure zones: overpressure zones (PCOE >1.4), the pressure transition zone (1.1 <PCOE<1.4) and the normal pressure zone (0.9 <PCOE<1.1), and the part near the upper fan area is dominated by the crude oil from the E2s42 sub-member, the middle fan area is dominated by the mixed source oil, and the lower fan area is dominated by the crude oil from the E2s41 sub-member. Compared with the characteristics of hydrocarbon migration and accumulation in middle and shallow strata, hydrocarbon accumulation in deep-seated glutenite is more controlled by hydrocarbon migration power and reservoir physical property. The secondary pore development zones are the key reservoir spaces for hydrocarbon in deep layer. On the basis of the above analyses, the hydrocarbon accumulation model of “source-reservoir-pressure” is constructed, which further reveals the hydrocarbon differential enrichment law of deep-seated glutenite, and guides the efficient exploration of oil and gas in Yanjia area, Dongying Sag.

Differential hydrocarbon enrichment in deep Paleogene tight sandstones of the Dongpu Depression in Eastern China

To clarify the characteristics and enrichment rules of Paleogene tight sandstone reservoirs inside the rifted-basin of Eastern China, the third member of Shahejie Formation (abbreviated as Es3) in Wendong area of Dongpu Depression is selected as the research object. It not only clarified the geochemical characteristics of oil and natural gas in the Es3 of Wendong area through testing and analysis of crude oil biomarkers, natural gas components and carbon isotopes, etc.; but also compared and explained the types and geneses of oil and gas reservoirs in slope zone and sub-sag zone by matching relationship between the porosity evolution of tight reservoirs and the charging process of hydrocarbons. Significant differences have been found between the properties and the enrichment rules of hydrocarbon reservoirs in different structural areas in Wendong area. The study shows that the Paleogene hydrocarbon resources are quasi-continuous distribution in Wendong area. The late kerogen pyrolysis gas, light crude oil, medium crude oil, oil-cracked gas and the early kerogen pyrolysis gas are distributed in a semicircle successively, from the center of sub-sag zone to the uplift belt, that is the result of two discontinuous hydrocarbon charging. Among them, the slope zone is dominated by early conventional filling of oil-gas mixture (at the late deposition period of Dongying Formation, about 31–27 Ma ago), while the reservoirs are gradually densified in the late stage without large-scale hydrocarbon charging (since the deposition stage of Minghuazhen Formation, about 6–0 Ma). In contrast, the sub-sag zone is lack of oil reservoirs, but a lot of late kerogen pyrolysis gas reservoirs are enriched, and the reservoir densification and hydrocarbon filling occur in both early and late stages.

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.

Coevolutionary Dynamics of Organic-Inorganic Interactions, Hydrocarbon Generation, and Shale Gas Reservoir Preservation: A Case Study from the Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations, Fuling Shale Gas Field, Eastern Sichuan Basin

Shale gas deposits are self-sourced, self-accumulating, and self-preserving in the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation of the Fuling Shale Gas Field in the eastern Sichuan Basin. They were both seemingly mixed by secondary oil cracking and kerogen cracking gases during the high maturation window. The reservoir space primarily consists of mineral pores and organic matter (OM) pores, and the shale gas was mainly trapped by a high-pressure system. In this study, the Fuling O3w-S1l Shale Gas Field in the eastern Sichuan Basin was used as a case study to discuss the coevolutionary process and organic-inorganic interactions of hydrocarbon generation, accumulation, and preservation. The results indicate that the processes and mechanisms of organic-inorganic interactions and coevolution of hydrocarbon generation and reservoir preservation are quite different among the shale graptolite zones (GZ) with respect to hydrocarbon generation, types and characteristics of shale gas reservoirs, seal characteristics, and their spatiotemporal relations. In the WF2-LM4 GZ, the favorable OM, biogenic authigenic quartz and organic-inorganic interactions are highly coupled, leading to the high level of coevolution demonstrated within the field, as well as to the favorable conditions for shale gas accumulation. Conversely, the overlying LM5-LM8 GZ seemingly exhibits early densification and late charge and has a reverse mode of reservoir development (i.e., low degree of coevolution). These two coevolutionary processes were conducive to the development of a high degree of spatiotemporal matching between the reservoir (i.e., WF2-LM4 GZ) and the seal (i.e., LM5-LM8 GZ). This is due to underlying differences in their coevolutionary histories. The synthetic work presented here on the coevolutionary processes and mechanisms of formation for organic-inorganic interactions and hydrocarbon generation and reservoir preservation reveals insights into the driving mechanisms of shale gas enrichment, providing a basis for effectively predicting favorable enrichment intervals for shale gas worldwide.

Genesis and accumulation process of deep natural gas in the Altun foreland on the northern margin of the Qaidam Basin

Deep natural gas in the northern margin of the Qaidam Basin is characterized by low exploration degree and large resource potential, but the genesis of deep gas reservoirs is complex. In particular, Jurassic source rocks do not develop in west of Altun foreland. The mechanism of deep accumulation is unknown, which restricts the exploration of deep gas reservoirs. Using gas components, isotopes and other data, combined with the geological characteristics of the Altun foreland, this study analyzes the genesis and source of deep gas in this area, and establishes the accumulation procesess of the deep gas reservoirs. Analysis shows that the gas in the Altun foreland is dominated by coal-type gas with the characteristics of oil cracking gas in deep reservoirs. The Jurassic source rocks in the Qaidam Basin are mainly lacustrine mudstones, with black mudstones and oil shale developed, which have the material basis for forming large oil reservoirs. The deep reservoir has experienced the process of long-term deep burial and high-temperature cracking, and has the conditions to form oil cracked gas. Accumulation in deep bedrock gas reservoirs is characterized by early oil filling, later high-temperature cracking into gas, and late adjustment. Reservoirs formed in early stage can be deeply cracked into gas reservoir under high temperature in the process of deep burial. The ancient uplifts along the basin margin and large anticline traps in the late tectonic zone are favorable exploration areas for deep gas. The exploration area for natural gas in the Qaidam Basin has been expanded by the discovery of deep oil cracking gas in the Altun foreland, which has crucial significance for guiding and intensifying deep gas exploration in the Qaidam Basin.

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.

Analysis of tight oil and gas charging characteristics by the carbon isotope on-site detection technology: A case study of the northern slope of the Minfeng Subsag in the Bohai Bay Basin

Studying hydrocarbon charging is quite important for searching exploration targets and confirming well locations. In this paper, the north slope of the Minfeng sub-sag in the Bohai Bay Basin was taken as an example. The Wells Yanxie 233, Yongxie 932 and Yan 22 were selected for on-site carbon isotope detection. Then, based on sufficient carbon isotope data which were acquired on the drilling site using the brand-new carbon isotopic measuring instrument, the carbon isotope data and composition data of natural gas produced in this area were compared. And combined with the evolution of source rocks, the geochemical characteristics of crude oil, the depositional environment of reservoirs and the physical properties, single-well charging characteristics and regional charging area of natural gas were analyzed. Finally, the feasibility of on-site carbon isotope detection method to discriminate hydrocarbon charging was discussed. And the following research results were obtained. First, deep hydrocarbon charging happened in the Purely Purely Lower Sha 4 Member in Well Yanxie 233, and its natural gas is the mixture of the oil cracking gas of deep layers and the thermal cracking gas of autochthonous source rocks. Second, the natural gas in the third and fourth Members of Shahejie Formation in Well Yongxie 932 is the thermal cracking gas of autochthonous source rocks, but deep gas charging occurred in particular hole sections. Third, the carbon isotope of associated gas in Well block Yan 22 is high in the central area and low in both sides and high in the south and low in the north, which is accordant with the distribution characteristics of reservoir physical properties, indicating that the charging of high-maturity natural gas is under the control of reservoir physical properties. Fourth, the oil in Well block Yan 22 is the product of autochthonous source rocks in the mature stage while the natural gas is the autochthonous oil-associated gas combined with the charging of deep high-maturity product. It is concluded that there is a high-maturity hydrocarbon charging area in the northwest of the northern slope of the Minfeng sub-sag, and it is a favorable hydrocarbon exploration target. What's more, the on-site carbon isotope rapid detection technology can provide a large number of continuous three-dimensional carbon isotope data, and it can be used to quickly analyze the characteristics of hydrocarbon charging and determine the source and origin of hydrocarbon, so as to provide reference for hydrocarbon development deployment.

Geochemical characteristics and genetic mechanism of the high-N2 shale gas reservoir in the Longmaxi Formation, Dianqianbei Area, China

As an important pilot target for shale gas exploration and development in China, the Longmaxi Formation shale in the Dianqianbei Area is characterized by high content of nitrogen, which severely increases exploration risk. Accordingly, this study explores the genesis of shale gas reservoir and the mechanism of nitrogen enrichment through investigating shale gas compositions, isotope features, and geochemical characteristics of associated gases. The high-nitrogen shale gas reservoir in the Longmaxi Formation is demonstrated to be a typical dry gas reservoir. Specifically, the alkane carbon isotope reversal is ascribed to the secondary cracking of crude oil and the Rayleigh fractionation induced by the basalt mantle plume. Such a thermogenic oil-type gas reservoir is composed of both oil-cracking gas and kerogen-cracking gas. The normally high nitrogen content (18.05%–40.92%) is attributed to organic matter cracking and thermal ammoniation in the high-maturity stage. Specifically, the high heat flow effect of the Emeishan mantle plume exacerbates the thermal cracking of organic matter in the Longmaxi Formation shale, accompanied by nitrogen generation. In comparison, the abnormally high nitrogen content (86.79%–98.54%) is ascribed to the communication between the atmosphere and deep underground fluids by deep faults, which results in hydrocarbon loss and nitrogen intrusion, acting as the key factor for deconstruction of the primary shale gas reservoir. Results of this study not only enrich research on genetic mechanism of high-maturity N2 shale gas reservoirs, but also provide theoretical guidance for subsequent gas reservoir resource evaluation and well-drilling deployment in this area.

Tracing the sources and evolution processes of shale gas by coupling stable (C, H) and noble gas isotopic compositions: Cases from Weiyuan and Changning in Sichuan Basin, China

The source and thermal evolution history of organic matter for the Longmaxi shale are still debated. This study analyzed the molecular and stable carbon isotopic compositions of hydrocarbons (CH4, C2H6, and C3H8) and CO2 as well as the stable hydrogen isotopic compositions of methane, ethane, and noble gases (He, Ne, Ar, Kr, and Xe). Shale gases in the WY and CN areas show an extremely-low-wetness with CH4 concentrations range from 93.41% to 99.01%. Non-hydrocarbon gases are mainly N2 (0.22%–2.81%) and CO2 (0.03%–1.35%). H2S have not been detected. Different δ13C1 and δ13C2 values in WY and CN shale gases (WY: −37.3‰ to −35.0‰ and −40.3‰ to −38.3‰, CN: −29.8‰ to −26.3‰ and −35.3‰ to −32.7‰) and various carbon isotope-composition distribution patterns (δ13C1>δ13C2<δ13C3 and δ13C1>δ13C2>δ13C3) of hydrocarbons indicate a complex evolution process. WY shale gases include more oil-cracking gas than CN shale gases, suggesting WY shale gases more like come from Type I-II organic matter. In shale gas systems, methane content and δ13C1 ratios vary with the degree of thermal evolution, so the origin of shale gas cannot be determined using carbon isotope data alone. The wide range of δ13CCO2 values (−8.9‰ to −0.8‰) and N2/40Ar ratios (20.8–165.1) suggests multiple origins of the gases. Emeishan mantle plume provides the source of heat for some thermo-genic gas. Noble gas isotopic compositions (3He/4He: 0.001Ra to 0.019Ra) indicate air and crustal origins with no significant contribution from the mantle. 40Ar/36Ar ratios (1194.3–4604.5) are consistent with the age of Longmaxi strata calculated by accumulative effect of Ar isotope. The shale gas humidity, carbon isotope ratios, and the carbon isotope-composition distribution patterns may contain information indicating the shale gas sweet spot.