Search

The helium (He) contents of the Weiyuan and Anyue gas fields in the Sichuan Basin (China) differ significantly despite their similar helium‐nitrogen (N2) coupling characteristics, that is, the positive correlation between the N2 and He contents, and the negative correlation between the nitrogen/helium (N2/He) ratio and depth. To determine the factors influencing the differential enrichment of He resources and He–N2 coupling in the Weiyuan and Anyue gas fields, this study analysed the compositions of natural gases within the study area and established a computational model for evaluating the dissolution and exsolution amount of He and N2 in the pore water. The results indicated that: the uplift of the basement granite was crucial for the exsolution and enrichment of dissolved helium, and it was also the main reason for He–N2 coupling. The differential uplift that occurred in the Leshan–Longnvsi palaeo‐uplift during the Himalayan period further promoted the differential enrichment of He resources, thus also impacting the N2/He ratio in the study area. The distinct quantities of N2 and He exsolution during the uplift directly affected the negative correlation between the N2/He ratio and the depth. Within the same depth range of the uplift, the average and variations of the N2/He ratio in the crust‐derived helium‐rich natural gas reservoir were inversely proportional to the in situ molar partial pressure of He. The uplift of the crystalline basement is an important mechanism that causes the enrichment of helium resources and the coupling of helium‐nitrogen in the crust‐derived helium‐rich natural gas reservoir, which is of great significance for understanding the variation of N2/He ratio and exploration of He resources. [ABSTRACT FROM AUTHOR]

Based on the recent oil and gas discoveries and geological understandings on the ultra-deep strata of sedimentary basins, the formation and occurrence of hydrocarbons in the ultra-deep strata were investigated with respect to the processes of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation, and key issues in ultra-deep oil and gas exploration were discussed. The ultra-deep strata in China underwent two extensional-convergent cycles in the Meso-Neoproterozoic Era and the Early Paleozoic Era respectively, with the tectonic-sedimentary differentiation producing the spatially adjacent source-reservoir assemblages. There are diverse large-scale carbonate reservoirs such as mound-beach, dolomite, karst fracture-vug, fractured karst and faulted zone, as well as over-pressured clastic rock and fractured bedrock reservoirs. Hydrocarbons were accumulated in multiple stages, accompanied by adjusting and finalizing in the late stage. The distribution of hydrocarbons is controlled by high-energy beach zone, regional unconformity, paleo-high and large-scale fault zone. The ultra-deep strata endow oil and gas resources as 33% of the remaining total resources, suggesting an important successive domain for hydrocarbon development in China. 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. The geological conditions and enrichment zone prediction of ultra-deep oil and gas are key issues of petroleum geology. [ABSTRACT FROM AUTHOR]

Interactive depositional systems of marine carbonates and gypsum salt rocks are closely related to natural gas reservoirs. Despite continuous progress in the exploration of new areas of marine carbonate genesis within the Ordos Basin, the source and mechanism of "sub-salt" natural gas genesis remains controversial. In this study, we investigated natural gas genesis through geochemical analysis of Lower Paleozoic natural gas samples from the mid-eastern Ordos Basin, obtaining natural gas composition data and carbon/hydrogen isotope compositions. We found evident differences between the geochemical characteristics of "sub-salt" and "post-salt" natural gas; the methane carbon isotope signature of "sub-salt" natural gas was lighter overall than that of "post-salt" natural gas, while the ethane carbon isotope composition of the former was more widely distributed and partially lighter than that of the latter. Combining these data with the regional geological background and existing geochemical data, it is evident that Ordovician "post-salt" natural gas comprises a composite of Upper Paleozoic coal-type gas and Lower Paleozoic oil-type gas, with the oil-type gas accounting for the largest proportion. In contrast, the "sub-salt" natural gas was formed and preserved within the Ordovician marine carbonates or sourced from deeper and more ancient hydrocarbon source rocks. Geochemical anomalies, including light methane carbon isotopes and ethane carbon isotopes with coal-type gas characteristics, are closely related to the prevalence of thermochemical sulfate reduction during hydrocarbon formation and reservoir formation of natural gas in "sub-salt" strata. [ABSTRACT FROM AUTHOR]

A series of marginal-sea basins and fault-depression basins were formed in eastern China under the background of subduction of the West Pacific plate. Different types of helium-rich natural gas reservoirs (He>1000 ppm, 1 ppm=1 µmol mol−1) have been found in these basins: helium-rich CO2 gas reservoirs, helium-rich N2 gas reservoirs, and helium-rich hydrocarbon gas reservoirs. Based on the analysis of gas geochemical data, the source and accumulation mechanism of helium in these helium-rich natural gas reservoirs were discussed. Helium-rich natural gas has relatively high 3He/4He ratios (0.88–4.91 Ra, average 2.82 Ra). The 3He/4He ratio characteristics of mantle xenoliths and mantle-derived CO2 gas reservoirs indicate that the helium in these helium-rich natural gas reservoirs is mainly mantle-derived (>70%). The original mantle volatile is mainly CO2 with a low helium concentration (He<200 ppm), and the enrichment of mantle-derived helium in the gas reservoir is mainly related to the dissolution and mineralization of CO2. During this process, the CO2/3He ratio decreases from 2×109 to approximately 2×106. As CO2 dissolves and mineralizes, the concentration of conservative gases (He and N2) increases in the remaining CO2 gas proportionally to the loss of CO2. Large amounts of carbonate minerals, such as dawsonite, which are relatively enriched in 13C, are found in CO2 reservoirs in eastern China. The relative enrichment of 12C in residual CO2 gas is important evidence of the dissolution and mineralization of CO2. The relative abundance of mantle-derived helium and N2 gas increases thousands of times during the dissolution and mineralization of CO2, which is the main accumulation mechanism of mantle-derived helium-rich CO2 gas reservoirs and helium-rich N2 gas reservoirs. Helium-rich gas from the mantle is mixed with alkane gas generated by organic matter in the sedimentary basin to form helium-rich hydrocarbon gas reservoirs. [ABSTRACT FROM AUTHOR]

Helium (He) is an important societal resource, yet its enrichment mechanism is unclear in the Bohai Bay Basin, despite the presence of He-rich (He > 0.1% v/v) gas. A comprehensive analysis of 112 sets of chemical and isotopic data from natural gases in the literature was conducted to further elucidate the source and accumulation mechanism of He in this basin. Natural gas is categorized into five groups based on CO 2 and N 2 abundances: N 2 gas (CO 2 +N 2 ≥ 95%, CO 2 < N 2), high-purity CO 2 gas (CO 2 +N 2 ≥ 95%, CO 2 > N 2), low-purity CO 2 gas (50 ≤ CO 2 +N 2 < 95%, CO 2 > N 2), low-purity HC gas (15 ≤ CO 2 +N 2 < 50%) and high-purity HC gas (CO 2 +N 2 < 15%). δ13C–CO 2 (−8.3 to −3.0‰) and 3He/4He (1.66–6.45 Ra, where Ra is the atmospheric 3He/4He) suggest a mantle origin of CO 2 in N 2 and CO 2 gases. The δ13C–CO 2 of N 2 gas (−8.3‰) is lighter than that of high-purity CO 2 gas (−6.2 to −3.4‰), indicating CO 2 dissolution and mineralization. A positive correlation between He and CH 4 content in the N 2 and high-purity CO 2 gases suggests water-derived CH 4 capture during CO 2 migration. Similarly, the positive correlation between He and N 2 content across all samples indicates water-derived N 2 capture during gas migration. A mixture of mantle and crust-derived He is indicated by 3He/4He ratio (0.06–6.45 Ra). Two distinct types of He-rich gas were identified: He-rich N 2 gas (3He/4He = 3.1–3.2 Ra) and He-rich HC gas (3He/4He = 0.36–0.48 Ra). He enrichment in N 2 gas is attributed to water-derived He capture and concurrent loss of CO 2 during mantle-derived CO 2 migration. He-rich HC gas formation results from He-rich N 2 gas dilution with hydrocarbons. The findings provide theoretical support for exploring He-rich natural gas in this basin and offer valuable insights into He enrichment mechanisms in comparable sedimentary basins globally. • He-rich gas includes N 2 gas and HC gas. • He enrichment in N 2 gas results from water-derived He capture and loss of CO 2 during mantle CO 2 migration. • He-rich HC gas formation results from He-rich N 2 gas dilution with hydrocarbons. [ABSTRACT FROM AUTHOR]

• The carbon isotope curve index (CICI) summarizes the isotope ratios of C 1 - C 3. • Carbon-isotope curves can be divided into Convex, Linear, Concave and Reversed. • In Normal-type gas, leakage and preferential propane biodegradation increase CICI. • In Normal-type gas, migration and mixing with microbial methane decrease CICI. The carbon isotope curve (δ13C n versus 1/n) is often used to evaluate the origin and secondary alteration of hydrocarbon gases, but the factors that influence the carbon isotope curve are not fully understood, limiting its practical application. We define a carbon isotope curve index (CICI) to quantitatively characterize the curve type. Four general curve types are defined: a Normal (δ13C 1 < δ13C 2 < δ13C 3) type and three Reversed types consisting of R 1 (δ13C 1 > δ13C 2 > δ13C 3), R 2 (δ13C 1 < δ13C 2 > δ13C 3), and R 3 (δ13C 1 > δ13C 2 < δ13C 3). CICI is defined as arctan (3Δ13C 3-2 /Δ13C 2-1) × 180/π for Normal and R 2 , –180 + arctan (3Δ13C 3-2 /Δ13C 2-1) × 180/π for R 1 , and 180 + arctan (3Δ13C 3-2 /Δ13C 2-1) × 180/π for R 3. CICI ranges from 0 to 90 for Normal, –180 to –90 for R 1 , –90 to 0 for R 2 , and 90 to 180 for R 3. Normal gases can be divided into three categories: Linear (CICI = 45), Convex (CICI 0 to < 45), and Concave (CICI > 45 to 90). The influence of kerogen type and maturity on CICI is investigated by comparing thermogenic gases generated from different kerogens in both sedimentary basins and pyrolysis experiments. Curves for low-maturity lacustrine and low-to-high-maturity coal gases are mainly Convex. In contrast, curves for high maturity to overmature marine gases are more Concave. The curve type of thermogenic gas changes from Convex to Concave with increasing maturity, and the mixing of gases generated from kerogen-cracking and oil-cracking results in the Concave type. The effect of post-generation alteration processes on CICI was elucidated using data from three field studies. In Normal-type gas, preferential biodegradation of propane and leakage increase CICI, while migration and mixing with microbial methane decrease CICI. Preferential biodegradation of propane and leakage are two other reasons for the Concave type. [ABSTRACT FROM AUTHOR]

A physical model was developed to quantify 4 He accumulation in gas reservoirs. Both radiogenic 4 He from external crustal flux and in situ 4 He production were calculated with this model. Considering the time-accumulation effect of 4 He, the formation time of a gas reservoir can be estimated. The proposed method was applied to Puguang gas reservoir in southwest China's Sichuan Basin, the formation time of which was estimated as 32.5 Ma, which corresponds to the Oligocene epoch and to the mid-Himalayan movement, and which is consistent with gas formation and accumulation history. This result indicates that the proposed model based on 4 He accumulation can be a useful tool for studying the formation time of gas reservoirs. [ABSTRACT FROM AUTHOR]

The mechanism of hydrogen sulfide (HS) generation plays a key role in the exploration and development of marine high-sulfur natural gas, of which the major targets are the composition and isotope characteristics of sulfur-containing compounds. Hydrocarbon source rocks, reservoir rocks, natural gases and water-soluble gases from Sichuan Basin have been analyzed with an online method for the content of HS and isotopic composition of different sulfur-containing compounds. The results of comparative analysis show that the sulfur-containing compounds in the source rocks are mainly formed by bacterial sulfate reduction (BSR), and the sulfur compounds in natural gas, water and reservoir are mainly formed by thermal sulfate reduction (TSR). Moreover, it has been shown that the isotopically reversion for methane and ethane in high sulfur content gas is caused by TSR. The sulfur isotopic composition of HS in natural gas is inherited from the gypsum or brine of the same or adjacent layer, indicating that the generation and accumulation of HS have the characteristics of either a self-generated source or a near-source. [ABSTRACT FROM AUTHOR]

The noble gases He and Ar are trace components in natural gas. Although their genesis is significantly different from that of hydrocarbon gases, they can provide key information on the accumulation and preservation of natural gas. In this paper, the relative and absolute abundances of He and Ar in lower Paleozoic shale gas samples from different areas of southern China were systematically analyzed, and the relationships between the concentrations of noble gases and the accumulation and expulsion of shale gas were evaluated. The evolution of He and Ar concentrations in shale gas system can be divided into three phases: the early accumulation stage, the hydrocarbon dilution stage and the preservation and enrichment stage. The generation of a large amounts of methane in the shale leads to the lowest relative concentrations of He and Ar in the hydrocarbon dilution stage. After that, the tectonic uplift causes the partial loss of the shale gas, and methane is no longer generated, but He and Ar are still produced. The concentrations of He and Ar present in shale gas are mainly controlled by the conditions of the preservation and enrichment stage. Tectonic uplift is the main reason for the loss of shale gas, and later uplift often results in higher gas content, which also leads to relatively low concentrations of He and Ar. The absolute abundance of residual Ar atm and the He/Ar ratio of a shale gas can indirectly reflect the preservation conditions of that shale gas. • No evidence was found of external sources of He or Ar in the shale gas systems. • The relative abundances of He and Ar can reflect the accumulation and expulsion process of the shale gas. • The He/Ar ratio is related to the time available for diffusion and the sealing capabilities of the shale system. [ABSTRACT FROM AUTHOR]

The hydrogen isotope composition of methane is an important parameter in natural gas research and provides complementary information to that provided by carbon isotopes. The stable hydrogen isotope ratios of 313 natural gas samples from six of China’s sedimentary basins are used to evaluate the factors that influence the stable hydrogen isotopic composition of methane. An important factor is the δD of organic matter in hydrocarbon source rocks, which is influenced by the sedimentary environment and type of organic matter. Natural gases generated from sapropelic organic matter have relatively less negative δ D CH 4 , while natural gases generated from humic organic matter have relatively more negative δ D CH 4 . The other factor is thermal maturity. Increased thermal maturity leads to δ D CH 4 becoming less negative and there exists a two stage linear relationship between the δ D CH 4 and the logarithm of the vitrinite reflectance ( R o) value for natural gases generated from type III kerogen. The third factor is the environmental conditions of the aqueous medium in the original depositional environment and after sedimentation. Elemental hydrogen from water participates in biochemical processes as organisms grow and is exchanged during the sedimentation and diagenesis of organic matter as well as maturity process of kerogen to generate gases. The influence of the aqueous medium on δ D CH 4 after formation of natural gases can be ignored. Among these factors, the aqueous medium is the key constraining factor. The δ D CH 4 in natural gases can be combined with the use of stable carbon isotopic composition to identify the origins of natural gases and to aid gas-source correlations. [ABSTRACT FROM AUTHOR]

Two mudstone samples in low-maturity from the E 2 s 3 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 E 2 s source rocks in Langgu Sag attained the peak yield of nearly 350 mg/g TOC at about 0.9% of Ro for C 6+ compounds due to thermal cracking occurrence of them if Ro higher than 0.9%, and C 6-14 compounds would reach the maximum yield at about 1.3% of Ro owed to C 14+ 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 E 2 s 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 E 2 s 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 E 2 s 4 source rocks, because the Ro of E 2 s 3 source rock is mainly lower than 1.1% but it reaches about 1.8% for E 2 s 4 source rock at present. The natural gases in shallow reservoirs experienced different degrees of bacterial degradation and formed methane-dominated gas reservoirs, consequently, the C 1 /C 1-5 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. • Hydrocarbon potentials of the E 2 s source rocks in Langgu Sag were studied by gold tube pyrolysis. • The E 2 s source rocks attained the peak oil yield at about 0.9% of Ro and gas is dominated by primary gases at Ro <1.3%. • The E 2 s intervals in Langgu Sag can be effective gas source rocks at Ro >0.8% based on the standard of 20 ml/g TOC. • Natural gases in Langgu Sag are dominated by primary gases generated at Ro <1.3% but some experienced bacterial degradation. [ABSTRACT FROM AUTHOR]

Based on the pyrolysis products for the Jurassic low-mature coal under programmed temperature, and chemical and carbon isotopic compositions of natural gas from the Kuqa Depression, the genetic origin of natural gas was determined, and then a gas filling model was established, in combination with the geological background of the Kuqa Depression. The active energy of CH4, C2H6 and C3H8 was gotten after the data of pyrolysis gas products under different heating rates (2°C/h and 20°C/h) were fitted by the Gas Oil Ratio (GOR) Isotope Model soft. When the frequency factor (Af) was chosen as 1×1014, the active energy of CH4, C2H6 and C3H8 was 58 kcal/mol, 57 kcal/mol and 54 kcal/mol, respectively. The distributive ranges of the δ13C1, δ13C2 and δ13C3 values for the pyrolysis gas products are -35.9‰ to -30.7‰, -26.2‰ to -21.3‰ and -26.4‰ to -22.7‰, respectively. All of the natural gases from the Kuqa Depression are dominated by hydrocarbon gases, with the high gas dryness (C1/C1-4) at the middle and northern parts of the depression and the low values at both east and west sides and the southern part. The carbon isotopes of methane and its homologs as a typical coal-type gas are enriched in 13C, and the distributive range of the δ13C1, δ13C2 and, δ13C3 value is -32‰ to -38‰, -22‰ to -24‰ and -20‰ to -22‰, respectively, with the carbon isotopes of gaseous alkanes being less negative with the carbon number. With the ethane being enriched in 13C the increasing tendency of the geological reserve of natural gas in the Kuqa Depression is observed. This observed change is consistent with the results of pyrolysate gas yield of coal as a potential gas source in the Kuqa Depression, suggesting natural gas was thermally derived from the humic organic matters and the carbon isotopes of gaseous alkanes would coarsely predict the geological reserve of gas in the Kuqa Depression. Through the simulation of kinetic processes of gas generation for the Jurassic coal in the Kuqa Depression, the gas in the Kela 2 gas field would get the threshold of gas expulsion after 27 Ma, be expelled out of source rocks as 'pulse action', and then filled in the gas reservoir. The peak gas-filling history took place during the past 2 Ma. [ABSTRACT FROM AUTHOR]

In this study, frontal chromatography experiments have been conducted with hydrocarbon gases (methane and ethane) on selected stationary phases (quartz, 3 Å, 5 Å and 13X molecular sieves, activated carbon, coal and shale) to study compositional and carbon isotope fractionation during adsorption process. The results show that the diffusion process cannot leads to obvious isotopic fractionation larger than ∼1.5 per mil in a relatively short distance. However, carbon isotope fractionation varies in different adsorption matrix. Gas molecules transporting in a relatively short distance can cause the isotopically light molecules weakly enriched in the front part of the alkane gases flows. The pore size distribution acts as the leading factor influencing the isotopic fractionation during hydrocarbon gases adsorption. In adsorption matrix with relatively low pore radius (i.e., activated carbon, 5 Å molecular sieve and coal), the isotopically light molecules can occupy the adsorption site preferentially and almost cannot be replaced due to the strong adsorption force. Hence, isotopically heavy molecules flow out of the system preferentially. To contrast, in adsorption matrix with relatively high pore radius (i.e., 13X molecular sieve and shale), the isotopically light molecules can occupy the adsorption site and desorb preferentially. Hence, isotopically light molecules flow out of the system preferentially after repeated adsorption and desorption. In addition, physical selectivity on isotopologues of gaseous alkanes by pore network also can occur in natural shale gas system. The Niutitang shale mainly is contributed by micropore. Whereas, Wufeng-Longmaxi shale mainly is contributed by mesopore. In general, initial adsorbed gases (residual gases) in natural shale samples from Niutitang shale were of more negative isotopic compositon in CH 4 and C 2 H 6 compared to Wufeng-Longmaxi shale. • Frontal chromatography experiments have been conducted with to study compositional and carbon isotope fractionation. • Gas molecules transporting in a short distance can cause the isotopically light molecules weakly enriched in the front of the gases flows. • The pore size distribution acts as the leading factor influencing the isotopic fractionation during hydrocarbon gases adsorption. [ABSTRACT FROM AUTHOR]

Abstract: In order to probe into the role of water in the process of natural gas generation, lignite from the Shenshan coal field of the Ordos Basin, China, was selected for pyrolytic simulation experiments under hydrous and anhydrous conditions for the purpose of comparison. The results showed that water was involved in the chemical reactions that took place during gas generation, and enhanced the productivity of CO2 and H2. Moreover, the involvement of water led to an increase in the productivity of hydrocarbons in a certain degree, especially methane at high temperatures. The δD values of CH4 become linearly heavier with increasing productivity of methane as observed in the two series of experiments, and the δD values of CH4 in the hydrous experiments are about 35‰ lighter than those obtained in the anhydrous experiments in the case of the same productivity of CH4. The fact that the δ 13C values of CO2 have become lighter in the hydrous experiments is strong evidence for the involvement of water in the chemical reactions during gas generation. Such trend of variations appears to have been caused by the conversion of methylene carbon to carboxyl carbon by water/alkene interaction in hydrous condition. [Copyright &y& Elsevier]

Natural gases of shallow reservoirs with the carbon isotopic compositions of methane ranging from -50‰ to -60‰ (PDB) were considered as mixed gases of biogenic and thermogenic origins previously and some of them were considered as low-mature (or low temperature thermogenic) gases lately. In this paper natural gases with the carbon isotopic compositions of methane in the above range were identified using the molecular and stable carbon isotopic compositions of methane, ethane and propane. The mixed gases of biogenic and mature thermogenic origins display the characteristics of δ 13C1 ranging from -50‰ to -60‰, δ 13C2 > -35‰, Δ values (δ 13C3 - δ 13C3) < 5‰ and C1/ΣC2+ ratios < 40. Immature to low-mature gases display the characteristics of δ 13C1 ranging from - 50‰ to - 60‰, δ 13C1 < -40‰, Δ values (δ 13C3 - δ 13C3) > 7‰, and C1/ΣC2+ ratios >60. [ABSTRACT FROM AUTHOR]

Helium is an important, scarce, and strategic resource that is critical to national security and advanced technology development. Although helium originates from mantle degassing and the radioactive decay of uranium (U) and thorium (Th) in minerals, commercial helium resources are primarily derived from natural gas reservoirs with He concentrations higher than 1000 ppm. The gas geochemistry characteristics of 920 natural gas samples from nine petroliferous basins in China were used to classify and discuss the enrichment mechanisms of helium. Helium-bearing natural gas reservoirs can be divided into the following three types: basement source-migration-rich accumulation, self-generating and self-preserving, and crust–mantle complex types. The basement source-migration-rich accumulation, which is the most common type of proven helium-rich natural gas reservoir, occurs primarily in inherited anticlines and dome traps located on basement uplifts. Ancient shale systems demonstrate the potential to form helium-rich shale gas that belongs to the self-generating and self-preserving type. Crust–mantle complex helium-rich natural gas reservoirs develop in petroliferous basins in active magmatic–tectonic areas. The origins of helium and hydrocarbon gas are different, but the entrainment of helium during hydrocarbon gas accumulation is a key factor influencing the formation of helium-rich natural gas reservoirs. The nitrogen concentration in helium-rich gas samples is often extremely high, indicating that the nitrogen and the helium are derived from the same source rock or both are extracted from water by migrating gas. • Helium-rich gas includes basement source-migration-rich accumulation, self-generating and self-preserving, and crust–mantle complex types. • Exsoluion gathering of underground dissolved helium is the key mechanism of helium enrichment. • High-quality matching between helium and natural gas is crucial for the helium-rich gas accumulation. [ABSTRACT FROM AUTHOR]

Abstract: The Ordos basin, the second largest natural gas producing basin in China, is one of the most tectonically stable sedimentary basins favorable to natural gas generation and preservation. The origin and potential source of the Jingbian gas field, one of the five giant gas fields in the basin containing the Ordovician paleo-weathering crust as reservoir strata, remains unclear. The question is whether gas is generated from Carboniferous–Permian coal measures or Ordovician carbonates. This study provides abundant gas geochemical evidence which clarifies its origin and source. Among 82 natural gas samples collected from the Ordovician paleo-weathering crust in the Jingbian gas field, C1–C4 gaseous hydrocarbons are dominant with low amounts of non-hydrocarbons (CO2, H2S and N2). The content of C1–C4 ranges from 79.26 to 99.93% with a gas dryness (C1/C1−4) of 0.981–0.999, suggesting that natural gases are dry and possibly originate from a high to over-mature source. The carbon isotopic compositions of methane and its homologues in natural gases from the Ordovician paleo-weathering crust vary widely, with δ13C1, δ13C2 and δ13C3 values of −38.9‰ to −29.1‰, −37.5‰ to −22.2‰ and −30.0 to −20.9‰, respectively. The δ13C2 and δ13C3 values in the Jingbian gas field are much more negative than those of typical coal-type gas in Sulige, Wushenqi, Yulin, Daniudi, and Kela2 gas fields. The carbon isotopic signature suggests that the natural gas in the Ordovician paleo-weathering crust in the Jingbian gas field most likely originates from Ordovician carbonates containing sapropelic organic matter. The measured δD values of methane range from −177 to −155‰ and support our hypothesis of the natural gases originating from marine sapropelic organic matter. The thermal maturity of the natural gases in the Ordovician paleo-weathering crust is at a high- to over-mature stage, suggesting that the gases originated from secondary cracking of oil and gas at high temperature and pressure. Thermochemical sulfate reduction (TSR) might partially play a role in the alteration of gas dryness and δ13C1 in those areas where gypsum is present as an effective cap rock. Mixing of high- to over-mature secondary cracking gas from the Ordovician source and coal-type gas from Carboniferous–Permian coal in the Jingbian gas field is minor. [Copyright &y& Elsevier]

An intramolecular isotopic study was conducted on natural gases from the Turpan-Hami Basin of China. The set of natural gases exhibits larger δ13C values of the terminal position compared with those at the central position of propane, with Δ C-T (δ13C central -δ13C terminal) values ranging from −3.8‰ to −0.7‰. During the thermal cracking of kerogen, the primary kinetic isotope effect is on the terminal carbon position to generate n -propyl radicals and on the central carbon position to produce i -propyl radicals. Therefore, distinct reaction pathways significantly influence the position-specific carbon isotope distribution in thermogenic propane. In the early stage of maturation, propane is preferentially generated from the i -propyl radicals by capturing hydrogen atoms owing to the lower dissociation energies of i -propyl radicals cleavage from kerogen compared with those of n -propyl radicals, resulting in larger δ13C values in the terminal position compared with those at the central position of generated propane. The position-specific 13C isotope composition of propane could provide new insights into revealing the generation mechanism of natural gas in the geological period at the atomic level. • Propane with early maturation exhibits larger δ13C values in the terminal position than those at the central position. • Propane can be preferentially generated from the i -propyl radical reaction at the early maturation stage. • Decompositions of the branched aliphatic chains structure contribute to the low-mature gas generation in the Turpan-Hami Basin. [ABSTRACT FROM AUTHOR]

This work systematically studied the significant geochemical heterogeneity of natural gases inside and outside the buried hills of the Xinglongtai area, West Sag, Liaohe Depression, Bohai Bay Basin. The gases inside the buried hills are thermogenic, whereas those outside the buried hills are dominated by secondary microbial gases, with a biodegraded thermogenic gas contribution. The humic- and sapropelic-type gases are primarily derived from the Es 3 and Es 4 source rocks, respectively. The gases inside the buried hills are primarily derived from the Es 3 source rocks, and decreasing δ13C 1 and C 1 /C 1-5 ratio towards the northeast are a result of the decreasing maturity of the adjacent Es 3 source rocks. The different geochemical characteristics of the gases outside the buried hills results from the relative contribution of secondary microbial and thermogenic gases, the maturity and organic type of the thermogenic gas, and biodegradation. In the Xinglongtai area, secondary microbial gas is an important shallow Paleogene exploration target, and the natural gas inside the buried hills is primarily enriched near the Es 3 source rocks. The findings and methods of this work are significant for studies on the origin and accumulation of natural gas inside and outside the buried hills in other petroliferous sags of the Bohai Bay Basin. Considering the geological and geochemical significance of the spatial geochemical heterogeneity of natural gas is essential for researching the origin and accumulation mechanism of gas and oil in complex exploration areas with multiple source rocks. • Sapropelic- and humic-type gases are from Es 4 and Es 3 source rocks, respectively. • Decreasing δ13C 1 and C 1 /C 1-5 inside buried hills results from varied maturities. • iC 4 /C 2 , 13C 1 and 13C 2 reveal mixing of secondary microbial and thermogenic gas. [ABSTRACT FROM AUTHOR]

Fourteen gases and their associated oils were collected at the surface from production wells in the Shahejie Formation, Dongying Formation, and Archean in six zones around the Qingshui Sub-sag of the Liaohe Depression, Bohai Bay Basin. The molecular compositions and carbon and hydrogen isotopic compositions of natural gas were measured. The origin, migration, accumulation, and secondary alteration of natural gas were studied based on the lateral and vertical comparison of natural gas geochemical characteristics. The natural gases include humic-type (δ13C 2 > −29.0‰, δ13C 1 > −43.0‰), sapropelic-type (δ13C 2 < −29.0‰, δ13C 1 > −43.0‰), and secondary microbial (δ13C 1 of −48.5‰, C 1 /(C 2 +C 3) of 46.3, δ13CO 2 of −1.5‰) gases. The humic-type and sapropelic-type gases were derived from the source rocks in the third and fourth members of the Shahejie Formation, respectively. The humic-type gases dominate. The biodegradation level of natural gas in the study area varies, and biodegraded gases are characterized by high Δ13C(C 3 –C 2), low C 3 /C 2 , and low C 3 /iC 4 and are associated with biodegraded oils. The vertical migration of natural gas in the west and east of the Qingshui Sub-sag is limited. There are good additional exploration prospects for humic-type gas, derived from high-maturity source rocks of the third member of the Shahejie Formation in the deep layers (depth >4.5 km) of the Qingshui Sub-sag. Secondary microbial gas is a potential exploration target in the shallow layers (depth <2.5 km). • Humic-type gas is from the source rock of the 3rd member of Shahejie Formation. • Sapropelic-type gas is from the source rock of the 4th member of Shahejie Formation. • Biodegraded gas: 13C-rich propane, depletion of propane and n-butane. • Secondary microbial gas: 13C-rich carbon dioxide and 13C-depleted methane. • Natural gas mainly accumulates near the source rock. [ABSTRACT FROM AUTHOR]

Adsorption and desorption processes of shale gas possess particular characteristics compared to conventional natural gas. Previous studies conducted desorption experiments on fresh core samples to investigate the isotope and chemical fractionations during the desorption process. However, complete chemical and isotope fractionations cannot be obtained due to the loss of gases during the coring process. In this study, we utilized a modified experimental apparatus based on the fixed adsorption bed to conduct systematic desorption experiments in confined systems with different proportions of free and adsorbed gases. The results show that different adsorption capacities and non-synchronous desorption for alkane gas components are leading factors influencing chemical fractionation during the desorption process. Meanwhile, C 1 /C 2 and C 1 /(C 1 +C 2) vary with different proportions of adsorbed gases in the same adsorption matrix. Generally, isotope fractionation between the adsorbed and free phases during desorption follows the Rayleigh fractionation model. The linear correlations between proportions of adsorbed CH 4 and isotope fractionation factors can be applied to predict the proportions of adsorbed gases. Calculations show that on average 55% of hydrocarbon gases exist at adsorbed state in shale gas from Yanchang Formation of Ordos Basin. • A modified experimental apparatus was firstly applied to study the chemical and isotope fractionations during desorption. • Isotope fractionation between the adsorbed and free phases during desorption follows the Rayleigh fractionation model. • Established mathematical model can be applied to predict the proportion of adsorbed gas in shale. [ABSTRACT FROM AUTHOR]