Isotopic Reversal Research Articles

Investigation on the thermal maturity, organic matter sources and depositional environment of lacustrine source rocks in the Dongying Formation of the Bozhong Sag, Bohai Bay Basin, China

The unclear understanding of the source rock characteristics for the Paleogene Dongying Formation in the Bozhong Sag leads to the lack of cognition in oil and gas exploration. This research systematically evaluated the discrepancy in geochemical characteristics of source rock intervals in the Dongying Formation based on detailed analysis using Rock‐Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), maceral components, stable carbon isotopes and biomarker parameters. It discusses the organic matter sources, depositional environment, thermal maturity and hydrocarbon generation potential in the source rock intervals of the Dongying Formation. The organic matter abundance in the third member (E3d3) and lower sub‐member of the second member (E3d2L) of the Dongying Formation is higher, with an average TOC of 2.08% and 1.03%, respectively, indicating that these source rock intervals could have good and excellent quality. The source rocks of the Dongying Formation predominately contain exinite maceral group and type II1 and II2 kerogen. The thermal evolution is mainly in the low‐mature and mature stages. The organic matter sources in the Dongying Formation are mainly dominated by mixed origin (the carbon isotope reversal of aromatics also provides a potential explanation). However, the values of 1,2,5−/1,3,6‐trimethylnaphthalene, (1,2,5,6 + 1,2,3,5)‐tetramethylnaphthalene/tetramethylnaphthalenes, methyldibenzofuran/methylphenanthrene (MDBF/MP) and dibenzofuran/phenanthrene (DBF/PHEN) parameters in the E3d3 and some samples in E3d2L decipher relatively smaller values than other source rock intervals, proving the enhancement of the contribution of lower organisms. Moreover, the terrestrial input in the bottom‐up deposition process of the Dongying Formation gradually increases. The depositional environment reveals the Dongying Formation source rocks mainly developed freshwater sulphur‐poor lacustrine facies and shallow lake‐fluvial delta facies in an open clay‐rich sedimentary environment with poor water column stratification, belonging to the typical weak oxidation–reduction depositional conditions. The comprehensive geochemical evaluation concludes that the favourable supply of lower organisms and stable clay‐rich depositional environment in the E3d3 interval of the Dongying Formation are potential explanations for the formation of lacustrine source rocks with high organic matter abundance, intermediate thermal evolution and excellent hydrocarbon generation potential, providing a good foundation for the exploration and development prospects of hydrocarbons.

Chemical and Geological Properties of Shale Gas: In Situ Desorption of Lower Cambrian Niutitang Shale in the Micangshan Tectonic Zone of South Shaanxi, China.

Shale gas was recently found in the Lower Cambrian Niutitang Formation (LCNF) of the Micangshan tectonic zone of south Shaanxi (MTZSS), but not in commercial quantities. To determine the laws governing the generation, enrichment, and desorption of shale gases in overmatured shale strata in the LCNF of MTZSS, we carried out in situ desorption experiments on nine shale core samples and got 168 desorbed gas samples at different phases of desorption. Also measured were the chemical and carbon isotopic compositions of these desorbed gas samples and the geochemical parameters of the shale core samples. CH4 was the predominant hydrocarbon shale gas identified in the 82.06-98.48% range, suggesting that the gases were mainly dry. The nonhydrocarbon gases found were CO2 and H2. The CH4 content of the desorbed gas samples dropped continuously during desorption, lowering the dryness index to 98.48 and 92.26% of the first and last desorbed shale gas, respectively. The change in the gas ratio during shale gas desorption proved that the adsorbability of the LCNF to the various gases follows the trend H2 > CO2 > C2H6 > CH4 > He. Further, δ13C2H6 and δ13CH4 become heavier during desorption, showing isotopic fractionation arising from the desorption-diffusion coeffect. As the desorption temperature increases, the value of δ13CH4 increases because 12CH4 is more sensitive to temperature than 13CH4, so it is with the ethane. Similar to the LCNF shale gas in other areas of China, the desorbed shale gases are characteristic of carbon isotope reversal (CIR) (δ13CH4 > δ13C2H6). The cracking of the residual soluble organic matter at the high overmaturity stage mixed with the cracking of kerogen at the early stage of maturation, causing CIR. Furthermore, the desorbed gas content was proportionally and inversely related to the CIR degree and final dryness index of the desorbed gas, respectively. Moreover, the carbon isotope fractionation degree of CH4 and δ13C1 of the last desorbed gas correlated positively with the desorbed gas content and the desorbed time of the gas. In conclusion, the four parameters are effective parameters for identifying shale gas sweet spots.

The Dynamic Evolution Model of the Chemical and Carbon Isotopic Composition of C1-3 during the Hydrocarbon Generation Process.

A new approach is presented in this paper for the dynamic modeling of the chemical and isotopic evolution of C1-3 during the hydrocarbon generation process. Based on systematic data obtained from published papers for the pyrolysis of various hydrocarbon sources (type I kerogen/source rock, type II kerogen/source rock, type III kerogen/source rock, crude oil, and asphalt, etc.), the empirical evolution framework of the chemical and isotopic composition of C1-3 during the hydrocarbon generation process was built. Although the empirical framework was built only by fitting a large amount of pyrolysis data, the chemical and isotopic composition of C1-3 derived from the pyrolysis experiments all follow evolution laws, convincing us that it is applicable to the thermal evolution process of various hydrocarbon sources. Based on the simplified formula of the isotopic composition of mixed natural gas at different maturities (δ13Cmixed), δ13Cmixed = X×niA×δ13CiA+Y×niB×δ13CiBX×niA+Y×niB, it can be derived that the cumulative isotopic composition of alkane generated in a certain maturity interval can be expressed by the integral of the product of the instantaneous isotopic composition and instantaneous yield at a certain maturity point, and then divided by the cumulative yield of alkane generated in the corresponding maturity interval. Thus, the cumulative isotopic composition (A(X)), cumulative yield (B(X)), instantaneous isotope (C(X)), and instantaneous yield (D(x)) in the dynamic model, comply with the following formula during the maturity interval of (X0~X). A(X) = ∫X0XCX×DXdxB(X), where A(X) and B(X) can be obtained by the fitting of pyrolysis data, and D(x) can also be obtained from the derivation of B(X). The dynamic model was applied on the pyrolysis data of Pingliang Shale to illustrate the quantitative evolution of the cumulative yield, instantaneous yield, cumulative isotope, and instantaneous isotope of C1-3 with increasing maturity. The dynamic model can quantify the yield of methane, ethane, and propane, as well as δ13C1, δ13C2, and δ13C3, respectively, during the hydrocarbon generation process. This model is of great significance for evaluating the natural gas resources of hydrocarbon source rock of different maturities and for identifying the origin and evolutionary process of hydrocarbons by chemical and isotopic data. Moreover, this model provides an approach to study the dynamic evolution of the isotope series of C1-3 (including reversed isotopic series), which is promising for revealing the mechanism responsible for isotopic reversal when combined with post-generation studies.

Origin and process of carbon isotopic reversal of tight sandstone gas in the Shixi gas field, eastern margin of Ordos Basin

Stable carbon isotopic compositions of natural gas have long been employed to determine its origin, accumulation, and migration. A reversal of the natural gas carbon isotope sequence, i.e. δ13C1 > δ13C2 > δ13C3, was discovered in the tight sandstone gas (TSG) of the Shixi gas field at the eastern margin of the Ordos Basin. This paper presents a study to determine the causes of carbon isotopic reversal hence to better understand the gas accumulation in these tight sandstone reservoirs. The molecular composition and carbon isotopes on 81 wellhead gas samples were measured from the TSG reservoirs of the Pennsylvanian in the Shixi gas field. Results indicate that the molecular compositions of the Shixi gas field comprise methane ranging from 88.9 wt% to 98.9 wt%, ethane ranging from 0.49 wt% to 1.12 wt%, and minor propane with content <0.01 wt%. The non-hydrocarbons are mostly CO2 which is <1.2 wt% and the rare helium ranges from 0.02 wt% to 0.23 wt% with an average of 0.09 wt%. The CO2 was probably derived from the decomposition of carbonate sediments under a high temperature owing to the varied δ13CCO2. Hydrocarbon is considered predominantly from coal-derived humic source rocks and minor oil-type gas. The isotopes of CO2, helium and vitrinite reflectance of the source rocks, i.e. coal and carbonaceous mudstone, indicate that the study area is lacking conditions for the formation of biogenic gas. The carbon isotopic reversal with δ13C1>δ13C2>δ13C3 in the Shixi gas field was interpreted as a result of secondary cracking under a local high temperature >200 °C.

Carbon isotope evidence for shale gas preservation conditions and large methane release over million years: A case study of shale gas reservoirs of Wufeng and Longmaxi Formations in the Sichuan Basin

Although carbon isotope reversal and its reasons in shale gas reservoirs have been widely recognized, the application of the reversal is yet to be investigated. A study on high-maturity shale from Wufeng and Longmaxi Formations in the Sichuan Basin not only reveals the relationship between the degree of isotopes inversion and the production capacity (e.g., estimated ultimate recovery (EUR)) of the gas well but also indicates the preservation conditions of shale gas reservoirs. (1) Although there are differences in gas isotopes in different shale gas reservoirs, the isotope fractionation of shale gas is small during the production stage of gas wells, even when the wellbore pressure drops to zero. The main cause of the difference in carbon isotopes and their inversion degree can be the uplift time during the Yanshan period and the formation pressure relief degree of shale gas reservoirs in distinct structural positions. Thus, carbon isotope inversion is a good indicator of shale gas preservation condition and EUR of shale gas wells. (2) The degree of carbon isotope inversion correlates strongly with shale gas content and EUR. The calculation formula of shale-gas recoverable reserves was established using Δδ13C (δC1-δC2) and EUR. (3) The gas loss rate and total loss amount can be estimated using the dynamic reserves and isotopic difference values of gas wells in various shale gas fields, which also reflects the current methane loss, thereby demonstrating great potential for evaluating global methane loss in shales.

Carbon Isotope Reversal Gas Generated in the Hydrothermal Experiments Involving 1-MNa and MnCO3

Carbon Isotope Reversal Gas Generated in the Hydrothermal Experiments Involving 1-MNa and MnCO₃

Characteristics of In Situ Desorption Gas and their Relations to Shale Components: A Case Study of the Wufeng-Longmaxi Shales in Eastern Sichuan Basin, China

AbstractIn situ desorption gas measurement can be used to evaluate shale gas potential, sweet spot prediction, and production strategy optimization. However, gas contents and carbon isotope compositions of in situ desorption gas and the relationship to reservoir properties and shale compositions are not systematically studied from the actual production situation. In this study, 63 core shales of Wufeng-Longmaxi formation from the YY1 well in the eastern Sichuan Basin were subjected to TOC (total organic carbon), solid bitumen reflectance (Rb), maceral fractions of kerogen analysis, and X-ray diffraction (XRD) analysis to obtain shale compositions, and 10 selected samples were conducted on low-pressure N2/CO2 (N2/CO2GA), mercury injection capillary pressure (MICP), and field emission scanning electron microscopy (FE-SEM) tests to acquire reservoir properties. Meanwhile, 60 samples were also subjected to in situ desorption tests to obtain shale gas content, and 5 selected samples were used to investigate variations in shale gas compositions and carbon isotopes during the desorption process. Results indicated that transient rates of shale gas during desorption process are significantly controlled by desorption time and temperature. In terms of in situ desorption process, total gas is divided into desorbed gas and lost gas. Desorbed gas is mainly comprised of CH4, N2, CO2, and C2H6, with desorption priorities of N2 &amp;gt; CH4 &amp;gt; CO2 ≈ C2H6, which are consistent with their adsorption capacities. The δ13CH4 values tend to become heavier during desorption process, varying from -37.7‰ to -16.5‰, with a maximum increase amplitude of 18.8‰, whereas the change of δ13C2H6 value, from -38.2‰ to -34.8‰, is minor. Desorbed gas shows carbon isotope reversals, due to that preferential desorption of 12C-CH4 during desorption process results in δ13C value less negative in CH4. The tested desorbed gas, lost gas, and total gas ranged 0.088 to 1.63 cm3/g, 0.15 to 3.64 cm3/g, and 0.23 to 5.20 cm3/g, respectively. Shale gas content, i.e., desorbed gas and lost gas, is controlled primarily by TOC content and organic matter (OM)-hosted nanometer-size pores. Clay mineral content is negatively correlated with shale gas content, due to that, clay mineral pores are more easily compacted during burial and occupied by water molecules. Compared with shale gas reservoirs in North America, the studied shale reservoir has high brittle mineral content and permeability, which is considered to have great potential of shale gas resource and to be the next commercial development zone in south China.

A mathematical diffusion model of carbon isotopic reversals inside ultra-tight Longmaxi shale matrixes

Developing mathematical models for high Knudsen number (Kn) flow for isotopic gas fractionation in tight sedimentary rocks is still challenging. In this study, carbon isotopic reversals (δ13C1 > δ13C2) were found for four Longmaxi shale samples based on gas degassing experiments. Gas in shale with higher gas content exhibits larger reversal. Then, a mathematical model was developed to simulate the carbon isotopic reversals of methane and ethane. This model is based on these hypotheses: (i) diffusion flow is dominating during gas transport process; (ii) diffusion coefficients are nonlinear depending on concentration gradient. Our model not only shows a good agreement with isotopic reversals, but also well predicts gas production rates by selecting appropriate exponents m and m∗ of gas pressure gradient, where m is for 12C and m∗ is for 13C. Moreover, the (m−m∗) value has a positive correlation with fractionation level. (m1−m1∗) of methane are much higher than that of ethane. Finally, the predicted carbon isotopic reversal magnitude (δ13C1−δ13C2) exhibits a positive relationship with total gas content since gas in shale with higher gas content experiences a more extensive high Kn number diffusion flow. As a result, our model demonstrates an impressive agreement with the experimental carbon isotopic reversal data.

The genesis of gas condensates and light oilsin the lower paleozoic of Tarim Basin, NW China: The exploration implications for ultra-deep petroleum

Almost 8 × 108 tons marine condensate reserveshave been estimated to be present in the Paleozoic to Cenozoic reservoirs of the Tarim Basin. Thethermal maturity of condensate gases are estimated to be greater than 2.2%REo (vitrinite reflectance equivalent),which are higher than the calculated maturity of thecondensates <1.9%REo. Therefore, the formation of gas-condensates might include a mixture of later cracked gases with earlieroil accumulations. The mixture model indicates that the relative content of oil-cracking gases varies from 42% to 98% in condensate gases, and the mixing extent of kerogen and oil cracking gas with various maturities could also lead to the carbon isotope reversal of methane and ethane. The positive correlation between the gas-oil ratio (GOR) of gas condensates and the maturity of cracking gas shows that the cracking gas is much more enriched in the eastern Tabei uplift of the northern Tarim Basin thanthe Tazhong uplift ofcentral Tarim Basin. The relative abundance of the triaromatic dinosteranes in the condensates coincides with the feature of hydrocarbons derived from Cambrian source rocks Furthermore, based on the multi-stagethermal maturity of the Cambrian source rocks, the formation mechanism of secondary gas condensates has been demonstrated and reconstructed. Recent exploration discoveries in the ultra-deep Cambrian of the Tabei and Tazhong uplifts, involving ZS-1 and LT-1wells, confirmed the cracking gases were derived from the post-high mature Manjar Depression and that liquid hydrocarbons could be maintained in the ultra-deep of Tabei uplift. The findings are helpful toestimate the exploration potential of the deeper cracking gases in the high-temperature and high-pressurereservoirs of the Tarim Basin.

Effect of Methane Cracking on Carbon Isotope Reversal and the Production of Over-Mature Shale Gas

The geochemical statistics indicate that the wetness (C2~C5/C1~C5) of over-mature shale gas with carbon isotope reversal is less than 1.8%. The magnitude of carbon isotope reversal (δ13C1–δ13C2) increases with decreasing wetness within a wetness range of 0.9~1.8% and then decreases at wetness &lt;0.9%. The experimental result demonstrates that CH4 polymerization proceeding to CH4 substantial cracking is an important factor involved in isotope reversal of over-mature shale gas. Moreover, δ13C1–δ13C2 decreases with an increase in experimental temperature prior to CH4 substantial cracking. The values of δ13C1 and δ13C2 tend to equalize during CH4 substantial cracking. The δ13C1–δ13C2 of mud gas investigated at different depths during shale gas drilling in the Sichuan Basin increases initially, then decreases with further increase in the depth, and finally tends to zero, with only a trace hydrocarbon gas being detectable. Thus, the approximately equal value between δ13C1 and δ13C2 for over-mature shale gas and very low wetness could potentially serve as useful criteria to screen CH4 substantial cracking. Two geochemical indices to indicate CH4 substantial cracking in a geological setting are proposed according to the variation production data with the geochemistry of over-mature shale gas in the Sichuan Basin, China.

Geochemical Characteristics and Origin of Shale Gases From Sichuan Basin, China

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

Carbon-hydrogen isotopic systematics of gases generated in semi-closed hydrous pyrolysis of type I source rock with the presence of formation water: Implications for gas isotope partitioning under supercritical conditions

Hydrocarbon gas is a significant type of clean energy, and understanding its carbon-hydrogen (C–H) isotopic behaviour during hydrocarbon generation is essential for determining the gas genesis. Hydrous pyrolysis is an artificial method to simulate natural gas generation process with the presence of water. Formation water is a type of ubiquitous saline water in oilfields, whereas not commonly utilized in hydrous pyrolysis. To determine the influence of formation water on C–H isotopic systematics of hydrocarbon gas (methane, ethane and propane), two series of semi-closed hydrous pyrolysis experiments were conducted in 275–550 °C for the type I Green River Shale source rock using distilled water and formation water. Hydrocarbon gases generated in two series of experiments have similar δ13C ratios yet slightly different δD ratios at individual temperatures, which is likely attributed to the water-organic interaction as formation water has a different δD ratio compared to distilled water. The δ13C and δD ratios of gas increase with the rising of thermal maturity level, and exhibit quadratic correlations with vitrinite reflectance (VR) values in both series of experiments. The presence of supercritical water in hydrous pyrolysis does not significantly affect the gas C–H isotopic partitioning behaviour because gases collected below and above the critical temperature (374.2 °C) display consistent δ13C (δD)-VR patterns. Partial C–H isotopic reversals (δ13C2>δ13C3, δD2>δD3 or δD1>δD2) are observed during the pre-oil to oil generation peak and gas generation stages, which are likely mainly affected by gas mixing as evidenced by rigorous correlations between δ13Cn (δDn) ratios and reciprocals of the gas proportion (1/Cn).

Assessing source and maturity of oils in the Mahu sag, Junggar Basin: Molecular concentrations, compositions and carbon isotopes

Molecular parameters are both facies and maturity dependent. Source and maturity assessment remains a difficult task for oils which were derived from multiple source rocks at a wide range of maturities from the early to late oil generation window. In this paper, a new approach was presented to assess oil source on the basis of molecular facies parameters under maturity constraint using crossplots of one source parameter versus one maturity parameter. Concentrations of ΣC29 steranes and C30 hopane were tentatively used as maturity indicators. Quantitative GC, GC-MS and GC-IRMS analyses were performed on 52 oils from the southern and central Mahu sag of northwestern Junggar Basin, NW China. The 52 oils are first classified into three groups, i.e., groups I, II and III which were derived from source beds within the Lower Permian Fengcheng Formation (P1f), Middle Permian Lower Wuerhe Formation (P2w) and both, respectively on the basis of carbon isotopes of individual n-alkanes in combination with reservoir geological settings. These three oil groups, in particular groups I and II from different sources were further distinguished sufficiently using crossplots of ratios of pristane (Pr)/n-C17 and phytane (Ph)/n-C18, β-carotane/n-C21 and concentrations of n-alkanes, Pr, Ph, β-carotane, Ts, C29 Ts, C30 diahopane, C20, C21 and C23 tricyclic terpanes versus concentrations of ΣC29 steranes and C30 hopane, respectively. Variation trends of isotopic reversal index (RI) and δ13C value of n-C25, the lowest among those of n-alkanes (n-C12–34), with decreasing concentrations of ΣC29 steranes and C30 hopane demonstrate that carbon isotopes of n-alkanes were unlikely influenced significantly by oil maturities within oil generation window. Concentration of n-alkanes increases while concentrations of Pr, Ph, crotanes, terpanes and steranes generally decrease with decreasing concentrations of ΣC29 steranes and C30 hopane. Application of this approach provides numerous choices and opportunities to distinguish oil groups which were derived from different sources in combination with isotopic data and reservoir geological settings.

Natural gas of radiolytic origin: An overlooked component of shale gas

Natural gas is an important fossil energy source that has historically been produced from conventional hydrocarbon reservoirs. It has been interpreted to be of microbial, thermogenic, or, in specific contexts, abiotic origin. Since the beginning of the 21st century, natural gas has been increasingly produced from unconventional hydrocarbon reservoirs including organic-rich shales. Here, we show, based on a careful interpretation of natural gas samples from numerous unconventional hydrocarbon reservoirs and results from recent irradiation experiments, that there is a previously overlooked source of natural gas that is generated by radiolysis of organic matter in shales. We demonstrate that radiolytic gas containing methane, ethane, and propane constitutes a significant end-member that can account for >25% of natural gas mixtures in major shale gas plays worldwide that have high organic matter and uranium contents. The consideration of radiolytic gas in natural gas mixtures provides alternative explanations for so-called carbon isotope reversals and suggests revised interpretations of some natural gas origins. We submit that considering natural gas of radiolytic origin as an additional component in uranium-bearing shale gas formations will lead to a more accurate determination of the origins of natural gas.

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.

Combination of Methyl from Methane Early Cracking: A Possible Mechanism for Carbon Isotopic Reversal of Overmature Natural Gas

In this study, a methane (CH4) cracking experiment in the temperature range of 425–800°C is presented. The experimental result shows that there are some alkane and alkene generation during CH4 cracking, in addition to hydrogen (H2). Moreover, the hydrocarbon gas displays carbon isotopic reversal ( δ 13 C 1 &gt; δ 13 C 2 ) below 700°C, while solid carbon appears on the inner wall of the gold tube above 700°C. The variation in experimental products (including gas and solid carbon) with increasing temperature suggests that CH4 does not crack into carbon and H2 directly during its cracking, but first cracks into methyl (CH3⋅) and proton (H+) groups. CH3⋅ shares depleted 13C for preferential bond cleavage in 12C–H rather than 13C–H. CH3⋅ combination leads to depletion of 13C in heavy gas and further causes the carbon isotopic reversal ( δ 13 C 1 &gt; δ 13 C 2 ) of hydrocarbon gas. Geological analysis of the experimental data indicates that the amount of heavy gas formed by the combination of CH3⋅ from CH4 early cracking and with depleted 13C is so little that can be masked by the bulk heavy gas from organic matter (OM) and with enriched 13C at R o &lt; 2.5 % . Thus, natural gas shows normal isotope distribution ( δ 13 C 1 &lt; δ 13 C 2 ) in this maturity stage. CH3⋅ combination (or CH4 polymerization) intensifies on exhaustion gas generation from OM in the maturity range of R o &gt; 2.5 % . Therefore, the carbon isotopic reversal of natural gas appears at the overmature stage. CH4 polymerization is a possible mechanism for carbon isotopic reversal of overmature natural gas. The experimental results indicate that although CH4 might have start cracking at R o &gt; 2.5 % , but it cracks substantially above 6.0% R o in actual geological settings.

Evaluation of gas-in-place content and gas-adsorbed ratio using carbon isotope fractionation model: A case study from Longmaxi shales in Sichuan Basin, China

Gas-in-place (GIP) content and gas-adsorbed ratio are crucial parameters for resource potential assessment, sweet spot prediction, and production strategy optimization. Various methods have been proposed from different perspectives to evaluate these parameters; however, none have been widely accepted. The carbon isotope fractionation (CIF) model provides a powerful tool for clarifying the mechanism of isotopic fractionation during natural gas transport and evaluating key parameters of unconventional gas resources. In this study, five shale samples from the Longmaxi Formation in the Jiaoshiba area, Sichuan Basin, China, were subjected to canister degassing experiments to investigate degassing behaviors and their variations in the isotopic compositions of methane (δ13C1), ethane (δ13C2), and carbon dioxide (δ13CCO2). The results showed that the degassing volume (rate) and isotopic fractionation amplitude (slope) of methane positively correlate with the TOC content after controlling the lost time. The released ethane was more enriched in 12C than methane and did not fractionate during degassing, resulting in an increased isotope reversal. The δ13CCO2 exhibited complex fractionation features corresponding to later stages (stages III and IV) in the general pattern. Furthermore, we evaluated the GIP content, gas-adsorbed ratio, and in-situ Langmuir parameters (VL and PL) using the CIF model. The calculated GIP content ranges from 3.48 cm3/g to 7.29 cm3/g with an average of 5.32 cm3/g, and the gas-adsorbed ratio is between 13.87% ~ 43.75% (average 30.79%). The optimized VL and PL show an excellent correlation with TOC content, demonstrating the great advantage of the CIF model in evaluating Langmuir parameters. Compared with the CIF model, the traditional USBM method underestimated shale gas resources in the Jiaoshiba area by 2% ~ 22%, with an average of 11.5%.

Carbon and hydrogen isotope fractionation during aerobic oxidation of short-chain alkanes in experimental incubations of vent fluids

Aerobic oxidation of short-chain alkanes was observed in gas samples from the Lutao intertidal hydrothermal vents in Taiwan, during storage at 20 °C for up to 29 months without adding bacterial strains and replenishing substrates. The carbon isotope fractionation factors (εC) of methane (C1), ethane (C2), and propane (C3), were calculated using the Rayleigh fractionation equation to be −37.1 ± 7.5‰, −14.8 ± 4.8‰, and −4.7 ± 5.2‰, respectively. The hydrogen isotope fractionation factor (εH) of methane was determined to be −281 ± 187‰. DNA sequencing of the 16S rRNA gene in the vent fluids suggests that aerobic oxidation is dominated by methanotrophs of the genera Methylomicrobium and Methylophaga, which use the ribulose monophosphate pathway (RuMP). The degrees of isotope fractionation (εC and εH values) herein are larger than previously reported values, possibly due to the limited O2 supply and low abundance of aerobic methane-oxidizing bacteria in the experiments. Since the fractionation factor of methane is higher than those of ethane and propane, the aerobic oxidation of thermogenic or microbial alkanes could produce a carbon isotope reversal, which is frequently noted as a trait of abiotic hydrocarbons. This work demonstrates that in addition to anaerobic microbial oxidation, aerobic oxidation with a low cell density can also produce significant isotope fractionation of alkanes in geological closed/semi-closed environments and open flow reaction systems that are characterized by moderate temperatures and a limited supply of substrates and O2; these environments include cold seeps, mud volcanoes, and low-temperature hydrothermal plumes/aquifers/reservoirs.

Geochemical Comparison of the Deep Gases From the Sichuan and Tarim Basins, China

In order to have a better understanding of the geochemical characteristics of gases from deep depths, gases from the clastic sandstone reservoirs in the Dabei and Keshen gas fields in the Kuqa depression, Tarim Basin, and gases from the marine carbonate reservoirs (Ordovician and Cambrian) in the craton area of Tarim Basin and Sichuan Basin (Yuanba, Longgang, Puguang gas fields) are investigated based on the molecular composition, stable carbon and hydrogen isotopes. Deep gas, either from the clastic sandstone reservoirs or from the marine carbonate reservoirs, is dominated by alkane gas. Gases from Kuqa depression and Sichuan Basin are dry gas, with high gas dryness coefficient, 0.976 and 0.999, respectively. Deep gas from the craton area in Tarim Basin includes both dry and wet gases. N2 and CO2 are the common non-hydrocarbon components in the deep gas. Gases from the continental sandstone reservoirs have no H2S, while gases from the marine carbonate reservoirs often have H2S. The relatively high δ13C2 value in the Kuqa depression indicates the gas was generated from humic type III kerogen, while the relatively low δ13C2 value in the craton area of Tarim Basin indicates most of the gas was generated from the marine sapropelic organic matter. Deep gas in Sichuan Basin, which has medium δ13C2 value, was generated from both humic type III and sapropelic type II organic matter. Carbon isotopic anomaly such as partial carbon isotopic reversal or relatively heavy carbon isotope is common in the deep gas, which is caused by secondary alteration. Gases from the Dabei gas field have a mean δ2H1 value of –156‰, while gases from the craton area of Tarim Basin, and Yuanba and Puguang gas fields in Sichuan Basin have relatively heavier δ2H1 value, i.e., average at −130 and −122‰, respectively. The abnormally heavier δ2H1 value in Dabei gas field is due to the high thermal maturity and possible saline depositional environment of the source rocks. This study performed a comprehensive comparison of the geochemical characteristics of the deep gases with different origins, which may provide a hint for future exploration of deep gas in the world.

Hydrogen and hydrocarbons associated with the Neoarchean Frog's Leg Gold Camp, Yilgarn Craton, Western Australia

High concentrations of hydrogen (H2) and methane (CH4) have been detected in shallow open-hole exploration wells surrounding the Neoarchean Frog's Leg gold camp in the Eastern Goldfields Superterrane, Yilgarn Craton, Western Australia. After corrections for modern air contaminants and excess nitrogen (N2) the Boomer deposit gases contain: 19.9–68.7 mol% H2; 28.7–76.9 mol% CH4; 0.47–1.6 mol% heavier hydrocarbons (C2–C5), which follow an Anderson-Schulz-Flory distribution; 0.11–3.3 mol% carbon dioxide (CO2); and 0.69–1.87 mol% helium (He). The isotopic composition of the gas components was further investigated: helium has 3He/4He ratios of 1.82–3.33 × 10−8 (from 0.013 to 0.024 RA, where RA is the atmospheric value) indicating a purely crustal origin; H2 has δ2H between −781.3‰ and − 759.5‰; and CH4 has δ13C between −20.3‰ and − 2.42‰ and δ2H between −382.5‰ and − 342.2‰. The C2–C5 gaseous hydrocarbons are commonly depleted in 13C (up to 22.75‰ for ethane) and enriched in 2H (up to 117.3‰ for iso-butane) compared to methane, while a carbon isotope reversal is observed between methane and ethane. The molecular and isotopic characteristics of the gas are consistent with 1) H2 generation controlled by radiolytic reactions within basic and felsic igneous rocks and by redox reactions including serpentinization in mafic-ultramafic lithologies, and 2) methane and C2+ gaseous hydrocarbons produced by interaction of H2 with a single carbon source (mainly CO2) most likely in Fischer-Tropsch type reactions. Using the H2–CH4 hydrogen isotopic fractionations as a geothermometer, isotopic equilibrium temperatures are calculated between 42 °C and 57 °C, which based on the modern geotherm represents a depth of ~1.4–2.7 km, corresponding to the Gleesons Basalt beneath the Frog's Leg gold camp. The free gases sampled from exploration wells in the Boomer deposit, Frog's Leg gold camp represent the first positive identification of abiogenic natural gas in Australia, with gas compositions similar to abiogenic gases previously reported from overseas Archean cratons. Interestingly, CH4-rich gases preserved in fluid inclusions associated with some of the region's lode gold deposits have distinctly different isotopic characteristics, suggesting that methane production has occurred by different pathways over a period from the Neoarchean to present day in the Yilgarn Craton.