Carbon Isotopic Composition Of Methane Research Articles

Influencing Factors and Model of Shallow Gas Enrichment in the Quaternary Sediments of the Qiongdongnan Basin, South China Sea

Investigating the primary influencing factors that regulate the enrichment of shallow gas not only deepens our understanding of the rules governing shallow gas enrichment in deep-ocean environments but also has the potential to enhance the success rate of locating shallow gas reservoirs. Recent drilling activities in the LS36 gas field located in the central Qiongdongnan Basin have revealed a substantial shallow gas reserve within the sediments of the Quaternary Ledong Formation, marking it as the first shallow gas reservoir discovered in the offshore region of China with confirmed natural gas geological reserves surpassing 100 billion cubic meters. However, the formation mechanism and influencing factors of shallow gas enrichment remain elusive due to the limited availability of 3D seismic and well data. This study employs seismic interpretation and digital simulation to decipher the dynamics of shallow gas accumulation and utilizes the carbon isotope composition of methane to ascertain the origin of the shallow gas. Our results show that the shallow gas is primarily concentrated within a large-scale submarine fan, covering a distribution region of up to 2800 km2, situated in the deep-sea plain. The δ13 C1 methane carbon isotope data ranges from −69.7‰ to −45.2‰ and all δ13 C2 values are above −28‰, suggesting that the shallow gas within the Ledong Formation is derived from a mix of biogenic gas produced in shallow strata and thermogenic gas generated in deeper source rocks. The results of gas sources, seismic profiles, and digital simulations suggest that thermogenic gas originating from the Lingshui and Beijiao sags was transported to the Quaternary submarine fan via a complex system that includes faults, gas chimneys, and channel sands. The mass-transported deposits (MTDs) in the upper reaches of the submarine fan have effectively acted as a seal, preventing the escape of shallow gas from the fan. Therefore, the factors contributing to the enrichment of shallow gas in the Qiongdongnan Basin include the presence of favorable submarine fan reservoirs, the availability of two distinct gas sources, the effective sealing of MTDs, and the presence of two efficient transport pathways. A conceptual model for the accumulation of shallow gas is developed, illuminating the complex formation–migration–accumulation process. This study underscores the importance of aligning multiple influencing factors in the process of shallow gas accumulation, and the suggested accumulation model may be pertinent to shallow gas exploration in other marginal sea basins.

Surface geochemistry as a key to understanding the petroleum system in regions of complex geology - Polish Outer Carpathians

The goal of the study is to investigate the relationships between soil gas composition and geological structures in a structurally complex area of the Carpathian fold and thrust belt. Surface geochemical surveys, aimed at determining the molecular and isotopic composition of soil gas samples, were carried out in the central part of the Polish Outer Carpathians in two major tectonic units, the Magura Unit and the Fore-Magura Group of units, which outcrop at the front of the former and within it as a tectonic window (the so-called Mszana Dolna Tectonic Window, MDTW). The tectonic structure of the area has numerous deformations, such as folds, thrusts, and strike-slip faults, that are accompanied by broad zones of mélange. In all 572 soil gas samples, the concentrations of light alkanes, gaseous alkenes as well as non-hydrocarbon (e.g. hydrogen) components were determined, and part of the samples were analysed to test the carbon isotope composition of methane and carbon dioxide.The results of the surface geochemical survey showed significant differences in the recorded microconcentrations of hydrocarbons within the tectonic units of the Outer Carpathians. Significantly higher concentrations of total alkanes C2-C5 were mainly recorded in the MDTW, although the distribution of total alkane values within the Window shows strong connections with the arrangement of strata and the strike of faults and thrusts. Generally, the sealing is insufficient within the MDTW to support the existence of conventional economically viable hydrocarbon accumulations. Our data confirms the sealing role of the Magura Unit in the Carpathian oil system. Therefore, hydrocarbon sources (i.e. potential hydrocarbon accumulations) may be expected within the Fore-Magura Group beneath the cover of the Magura Unit.Our results are also of key importance for the interpretation of surface geochemistry data in other oil and gas provinces with a complex geological structure.

Geochemical Characteristics and Origin of Natural Gas in the Middle of Shuntuoguole Low Uplift, Tarim Basin: Evidence from Natural Gas Composition and Isotopes

Multiple types of reservoirs, including volatile oil reservoirs, condensate gas reservoirs, and dry gas reservoirs, have been discovered in ultra-deep layers buried at depths greater than 7500 m. Understanding the genetic types of natural gas is of utmost importance in evaluating oil and gas exploration potential. The cumulative proved reserves of the super deep layer in the Shuntuoguole low uplift area of the Tarim Basin exceed 1 × 108 t (oil equivalent). The origin, source, and accumulation characteristics of natural gas still remain a subject of controversy. By analyzing the composition and carbon isotope of natural gas, a detailed investigation was conducted to examine the unique geochemical and reservoir formation characteristics of the Ordovician ultra-deep natural gas within different fault zones in the middle region of the Shuntuoguole low uplift. It was determined that most of the natural gas in this area is displaying a characteristic of wet gas with a drying coefficient ranging from 0.41 to 0.99. The carbon isotope composition of methane in the gas reservoir shows relatively light values, ranging from −49.4‰ to −42‰. The carbon and hydrogen isotopes of the components are distributed in a positive order. The natural gas is oil type gas, which is derived from marine sapropelic organic matter and has a good correspondence with the lower Yuertusi formation. The maturity of natural gas in Shunbei No. 1 and No. 5 fault zones is about 1.0%, which is the associated gas of normal crude oil, while the maturity of No. 4 and No. 8 fault zones is higher than 1.0%, which is the mixture of kerogen pyrolysis gas and crude oil pyrolysis gas. The variations in the drying coefficient and carbon isotope composition of the natural gas provide evidence for the migration patterns within the Shuntuoguole low uplift central region. It indicates that the Shunbei No. 5 and No. 8 fault zones have likely migrated from south to north, while the No. 4 fault zone has migrated from the middle to both the north and south sides. These migration patterns are primarily controlled by high and steep strike-slip faults, which facilitate the vertical migration of natural gas along fault planes. Consequently, the gas accumulates in fractured and vuggy reservoirs within the Ordovician formation.

End-Member Mixing Model for Methane Carbon Isotope Fractionation During Shale Gas Desorption and Its Application.

Unlike conventional natural gas reservoirs, shale gas development involves systematic changes in methane carbon isotopes that cannot be effectively described by existing isotope fractionation models and mechanisms. Therefore, based on fundamental theories such as Rayleigh fractionation, mass transfer flow, and mass conservation, this study established isotopic fractionation equations for methane in adsorbed and free gas. By considering adsorbed and free gases as two end-members and using an isotope mixing model, a fractionation model for methane carbon isotopes during shale gas desorption was constructed. This model quantifies the isotopic fractionation effects during shale gas desorption and elucidates the mechanism of methane carbon isotope fractionation. Using on-site desorbed gas content and isotope data, parameter fitting and model calculations were conducted to characterize methane carbon isotope variations throughout the process of shale core field desorption. The results show a pattern of "initially negative and then turning positive," consistent with those of physical simulation experiments. It was clarified that differences in mixing the two end-members and isotopic fractionation play key roles in the variation of methane carbon isotopic composition in shale gas. By applying the methane carbon isotope fractionation model, the contribution of adsorbed gas during shale gas production was explored. It was found that in the early stage of development, the adsorbed gas in Well JY 1 was negligible. After nearly seven years of development, the contribution of adsorbed gas in the later stage has only reached nearly 15%, indicating that the production contribution of adsorbed gas is still less than 0.3 million cubic feet per day. The open flow of Well JY 6-2 is more conducive to the production of adsorbed gas, but the production capacity is still mainly contributed by free gas, indicating that the shale gas production capacity in the later stage in the Jiaoshiba gas field is still primarily dominated by free gas.

Measurement Uncertainty and Risk of False Compliance Assessment Applied to Carbon Isotopic Analyses in Natural Gas Exploratory Evaluation.

The concept of uncertainty in an isotopic analysis is not uniform in the scientific community worldwide and can compromise the risk of false compliance assessment applied to carbon isotopic analyses in natural gas exploratory evaluation. In this work, we demonstrated a way to calculate one of the main sources of this uncertainty, which is underestimated in most studies focusing on gas analysis: the δ13C calculation itself is primarily based on the raw analytical data. The carbon isotopic composition of methane, ethane, propane, and CO2 was measured. After a detailed mathematical treatment, the corresponding expanded uncertainties for each analyte were calculated. Next, for the systematic isotopic characterization of the two gas standards, we calculated the standard uncertainty, intermediary precision, combined standard uncertainty, and finally, the expanded uncertainty for methane, ethane, propane, and CO2. We have found an expanded uncertainty value of 1.8‰ for all compounds, except for propane, where a value of 1.6‰ was obtained. The expanded uncertainty values calculated with the approach shown in this study reveal that the error arising from the application of delta calculation algorithms cannot be neglected, and the obtained values are higher than 0.5‰, usually considered as the accepted uncertainty associated with the GC-IRMS analyses. Finally, based on the use of uncertainty information to evaluate the risk of false compliance, the lower and upper acceptance limits for the carbon isotopic analysis of methane in natural gas are calculated, considering the exploratory limits between -55‰ and -50‰: (i) for the underestimated current uncertainty of 0.5‰, the lower and upper acceptance limits, respectively, are -54.6‰ and -50.4‰; and (ii) for the proposed realistic uncertainty of 1.8‰, the lower and upper acceptance limits would be more restrictive; i.e., -53.5‰ and -51.5‰, respectively.

High temperature and solar radiation in the Red Sea enhance the dissolution of crude oil from surface films

The Red Sea is a hotspot of biodiversity susceptible to oil pollution. Besides, it is one of the warmest seas on the Earth with highly transparent waters. In this study, we estimated the oil dissolution rates under natural sunlight spectra and temperature conditions using coastal oil slicks collected after the 2019 Sabiti oil spill in the Red Sea. Optical analyses revealed the significant interactive effect of sunlight and temperature in enhancing the dissolution of oil into dissolved organic matter (DOM). The highest oil dissolution rate (38.68 g C m−3 d−1) was observed in full-spectrum sunlight. Oil dissolution significantly enhanced total organic carbon (TOC) and polycyclic aromatic hydrocarbons (PAHs) in seawater. High nucleic acid (HNA) bacteria, likely the oil degraders, proliferated from 30 to 70 – 90% after 4 days. The heavier stable carbon isotopic composition of methane (δ13C-CH4) and lighter stable carbon isotopic composition of carbon dioxide (δ13C-CO2) indicate the putative role of bacterial processes in the natural degradation of crude oil. The results indicated that the combined effect of temperature and solar radiation enhanced the biological and photochemical dissolution of oil on the Red Sea surface.

Tracing of natural gas migration by light hydrocarbons: A case study of the Dongsheng gas field in the Ordos Basin, NW China

Based on the analysis of light hydrocarbon compositions of natural gas and regional comparison in combination with the chemical components and carbon isotopic compositions of methane, the indication of geochemical characteristics of light hydrocarbons on the migration features, dissolution and escape of natural gas from the Dongsheng gas field in the Ordos Basin is revealed, and the effect of migration on specific light hydrocarbon indexes is further discussed. The study indicates that, natural gas from the Lower Shihezi Formation (P1x) in the Dongsheng gas field displays higher iso-C5−7 contents than n-C5−7 contents, and the C6−7 light hydrocarbons are composed of paraffins with extremely low aromatic contents (<0.4%), whereas the C7 light hydrocarbons are dominated by methylcyclohexane, suggesting the characteristics of coal-derived gas with the influence by secondary alterations such as dissolution. The natural gas from the Dongsheng gas field has experienced free-phase migration from south to north and different degrees of dissolution after charging, and the gas in the Shiguhao area to the north of the Borjianghaizi fault has experienced apparent diffusion loss after accumulation. Long-distance migration in free phase results in the decrease of the relative contents of the methylcyclohexane in C7 light hydrocarbons and the toluene/n-heptane ratio, as well as the increase of the n-heptane/methylcyclohexane ratio and heptane values. The dissolution causes the increase of isoheptane values of the light hydrocarbons, whereas the diffusion loss of natural gas in the Shiguhao area results in the increase of n-C5−7 contents compared to the iso-C5−7 contents.

РАСПРЕДЕЛЕНИЕ И ГЕНЕЗИС УГЛЕВОДОРОДНЫХ ГАЗОВ ДОННЫХ ОТЛОЖЕНИЙ ЛАПТЕВО-СИБИРОМОРСКОЙ ЗОНЫ ВОСТОЧНО-АРКТИЧЕСКОГО ШЕЛЬФА

Gases from bottom sediments of the Laptev–Siberian Sea zone contain methane (up to 8.3047 cm3/kg) and its homologues (down to and including pentane) totaling 0.0259 cm3/kg. The established values of the carbon isotope composition of methane (δ13С), the molecular weight of the hydrocarbon fraction, the weight concentrations of С1–С5 hydrocarbons and their ratios, the «wetness» and «transformation» coefficients of the hydrocarbons fraction, indicate the presence of various syngenetic and epigenetic gases in bottom sediments. Potential gas sources are modern sediments, peat, coal, gas and gas hydrate? deposits, solid bitumen, igneous rocks, and inferred oil and gas accumulations. It has been established that the distribution of hydrocarbon gases in sediments vertically and horizontally depends on the influence of a complex of geological factors – fold and fault tectonics, magmatism and seismic activity in the region, coal, oil and gas potential and bituminosity, organic saturation and lithological composition, hydrogeological, geocryological, and other conditions for accumulation of gases or their degassing.

Genesis and source of natural gas in Well Mitan-1 of Ordovician Majiagou Formation, middle-eastern Ordos Basin, China

The Well Mitan-1 has achieved a major breakthrough in the exploration of Ordovician subsalt natural gas in the mid-eastern Ordos Basin, demonstrating a high-yield industrial gas flow in fourth member of the Majiagou Formation of Ordovician (O1m4). Despite this success, there are ongoing disputes regarding the origin of the natural gas found in Well Mitan-1. Measured results show that the natural gas in Well Mitan-1 is mainly composed of alkane gas (95.18 %). The gas drying coefficient (C1/C1-5) is measured at 0.947, and the H2S content is 3.49 %, with a small amount of N2 and CO2 in the non-hydrocarbon gas. The carbon isotopic compositions of methane, ethane, and propane in the natural gas are −45.5 ‰, −26.4 ‰, and −24.3 ‰, respectively. Based on the regional geological background, the characteristics of potential source rocks and the geochemical characteristics of natural gas, it is considered that the natural gas in Well Mitan-1 is self-generated and self-accumulated oil-associated gas in Ordovician subsalt carbonate rocks. However, certain geochemical anomalies, such as the lighter methane carbon isotope value (δ13C1) and coal-type gas characteristics in ethane carbon isotope (δ13C2), raise questions. Further insights from thermal simulation experiments on hydrocarbon generation and the analysis of residual gas in rocks suggest a close relationship between the special geochemical characteristics of Well Mitan-1 and the presence of gypsum rocks. The ubiquitous gypsum rock serves a dual purpose: acting as an effective caprock, facilitating the retention of early-generated natural gas, and promoting the generation of heavy hydrocarbon gases (C2+) and H2S. The relatively low H2S content (less than 5 %) and higher C2+ content indicate that thermochemical sulfate reduction (TSR), if present, is not strong enough to significantly impact methane. The δ13C2 is identified as a potentially sensitive parameter for identifying TSR.

Self-Sourced Unconventional Tight Marlstone Reservoir Potential from Evaporative Lagoon of Triassic Leikoupo Formation in the Central Sichuan Basin

A breakthrough was made in tight marlstone reservoirs from an evaporative lagoon in the second sub-member of the third member of the Leikoupo Formation (Lei3-2) in the Central Sichuan Basin. The source rock characteristics, reservoir characteristics of the marlstone and geochemical parameters of the oil and natural gas were investigated to evaluate the unconventional hydrocarbon exploration potential of the tight marlstone from the evaporative lagoon. The results revealed that the source rocks were deposited in evaporative lagoon environments, and the average total organic carbon (TOC) content value for the samples was 0.75 wt%. The thermal maturity of the organic matter was relatively high, with a calculated vitrinite reflectance (Rc) of 1.7%. The characteristics of marlstones suggest that the potential source rocks had fair to good hydrocarbon generative potential. The condensate samples had low densities, low viscosities and high thermal maturity, with a Rc value of 1.7%. For the natural gas, the dry coefficient was around 0.90, and the carbon isotopic compositions of methane and ethane was −41.3‰ and −28.4‰, respectively. According to the carbon isotopic compositions, thermal maturity and geological background, the oil and natural gas from Lei3-2 are comparable with the marlstone of Lei3-2. Thus, the oil and natural gas is self-sourced and originates from the marlstone in the Lei3-2. Micropores and microfractures are often detected in the marlstone from Lei3-2, and a gypsum layer is conducive to the hydrocarbon preservation. These results suggest that the evaporative lagoon facies in Lei3-2 have large, self-sourced, unconventional, tight marlstone reservoir potential. This study also enhances the prospects for further oil and gas exploration of evaporative lagoon facies in other basins.

Zonation of the active methane-cycling community in deep subsurface sediments of the Peru trench.

The production and anaerobic oxidation of methane (AOM) by microorganisms is widespread in organic-rich deep subseafloor sediments. Yet, the organisms that carry out these processes remain largely unknown. Here we identify members of the methane-cycling microbial community in deep subsurface, hydrate-containing sediments of the Peru Trench by targeting functional genes of the alpha subunit of methyl coenzyme M reductase (mcrA). The mcrA profile reveals a distinct community zonation that partially matches the zonation of methane oxidizing and -producing activity inferred from sulfate and methane concentrations and carbon-isotopic compositions of methane and dissolved inorganic carbon (DIC). McrA appears absent from sulfate-rich sediments that are devoid of methane, but mcrA sequences belonging to putatively methane-oxidizing ANME-1a-b occur from the zone of methane oxidation to several meters into the methanogenesis zone. A sister group of ANME-1a-b, referred to as ANME-1d, and members of putatively aceticlastic Methanothrix (formerly Methanosaeta) occur throughout the remaining methanogenesis zone. Analyses of 16S rRNA and mcrA-mRNA indicate that the methane-cycling community is alive throughout (rRNA to 230 mbsf) and active in at least parts of the sediment column (mRNA at 44 mbsf). Carbon-isotopic depletions of methane relative to DIC (-80 to -86‰) suggest mostly methane production by CO2 reduction and thus seem at odds with the widespread detection of ANME-1 and Methanothrix. We explain this apparent contradiction based on recent insights into the metabolisms of both ANME-1 and Methanothricaceae, which indicate the potential for methanogenetic growth by CO2 reduction in both groups.

Biogeochemical Activity of Methane-Related Microbial Communities in Bottom Sediments of Cold Seeps of the Laptev Sea

Bottom sediments at methane discharge sites of the Laptev Sea shelf were investigated. The rates of microbial methanogenesis and methane oxidation were measured, and the communities responsible for these processes were analyzed. Methane content in the sediments varied from 0.9 to 37 µmol CH4 dm-3. Methane carbon isotopic composition (δ13C-CH4) varied from -98.9 to -77.6‱, indicating its biogenic origin. The rates of hydrogenotrophic methanogenesis were low (0.4-5.0 nmol dm-3 day-1). Methane oxidation rates varied from 0.4 to 1.2 µmol dm-3 day-1 at the seep stations. Four lineages of anaerobic methanotrophic archaea (ANME) (1, 2a-2b, 2c, and 3) were found in the deeper sediments at the seep stations along with sulfate-reducing Desulfobacteriota. The ANME-2a-2b clade was predominant among ANME. Aerobic ammonium-oxidizing Crenarchaeota (family Nitrosopumilaceae) predominated in the upper sediments along with heterotrophic Actinobacteriota and Bacteroidota, and mehtanotrophs of the classes Alphaproteobacteria (Methyloceanibacter) and Gammaproteobacteria (families Methylophilaceae and Methylomonadaceae). Members of the genera Sulfurovum and Sulfurimonas occurred in the sediments of the seep stations. Mehtanotrophs of the classes Alphaproteobacteria (Methyloceanibacter) and Gammaproteobacteria (families Methylophilaceae and Methylomonadaceae) occurred in the sediments of all stations. The microbial community composition was similar to that of methane seep sediments from geographically remote areas of the global ocean.

Contribution of soluble organic matter to hydrocarbon generation in saline lacustrine source rocks: Evidence from thermal simulation experiments

Soluble organic matter generally exists in the source rocks of saline lacustrine basins. In this paper, we quantified the contribution of soluble organic matter to hydrocarbon generation based on thermal simulation experiments using a saline lacustrine source rock from the Qaidam Basin. Our results show that the yields of gaseous and liquid hydrocarbons in the thermal simulation products are greatly improved in the presence of soluble organic matter. As a comparison, the maximum yields of gaseous and liquid hydrocarbons in series C (without soluble organic matter) were 270 mg/gTOC and 329.78 mg/gTOC, respectively, while in series A (with soluble organic matter) they were 364 and 602.98 mg/gTOC, respectively. The proportion of isoprenoids and n-alkanes in the products also increased from approximately 3%–40%. Meanwhile, the presence of soluble organic matter reduced the temperature corresponding to the hydrocarbon generation peak from 375 to 250°C. Moreover, the presence of soluble organic matter also had a remarkable change on the stable carbon isotope composition of methane, resulting in more 12C enrichment with a range of 2.24‰–5.25‰. The combined evidence indicates that soluble organic matter can promote the formation of immature‒low maturity oil in source rocks.

Generation and geochemical signatures of natural gas from solid bitumen: Implications from closed and stepwise semi-open pyrolysis experiments

Solid bitumen has been acknowledged as an important source of overmature shale gas. However, the gas generation potential, chemical signatures and carbon isotopic compositions of natural gas derived from solid bitumen in an overmature hydrocarbon system are not well-understood with respect to various geological conditions. In this study, a relatively low-maturity solid bitumen from Cambrian reservoirs in the northwest Sichuan Basin was pyrolyzed in both closed and stepwise, semi-open systems. In the closed system, methane generated in the overmature thermal stage is dominated by the secondary cracking of wet gas and cumulative methane carbon isotopic values that are 4.4‰–14.8‰ lighter than the carbon isotope composition of the original solid bitumen. In semi-open systems, the gas is predominantly generated from residual solid bitumen and has wetness (i.e., C2–C5/C1–C5 by volume) values of generally less than 1%. At the same thermal maturity levels, the carbon isotope composition of methane in various semi-open systems is 4.4‰–10.0‰ heavier than those in the closed system and may also be isotopically heavier than the carbon isotope value of the original solid bitumen. The present study also illustrates that the calculated gas yields and methane carbon isotopes within a certain thermal maturity range in the closed system cannot be compared with those from residual solid bitumen as measured in the corresponding semi-open systems. This highlights the need to conduct specific semi-open pyrolysis experiments to investigate the late gas generation potential and geochemical signatures of natural gas from solid bitumen when the geological system is not a closed system. By comparing the above-mentioned results with the geochemical characteristics of Wufeng-Longmaxi shale gas from the Changning and Jiaoshiba gas fields of the Sichuan Basin, southwest China, it is suggested that the shale gas examined in this study is most likely generated in semi-open systems rather than in a closed system. In other words, the early-generated gas has been expelled from the shales, leaving the late-generated gas from residual solid bitumen and/or kerogen as the main gas source in the present hydrocarbon system.

Carbon isotopic composition of methane and its origin in natural gas from the Petišovci-Dolina oil and gas field (Pannonian Basin System, NE Slovenia) – a preliminary study

The carbon isotopic composition of methane (δ13CCH4) in natural gas from the Petišovci-Dolina oil and gas field (NE Slovenia) was measured for the first time in August and September 2021. The gas samples from different depths were taken from three wells: Dolina-deep (Pg-6) from the depth interval 3102–3104 m, Petišovci-deep (Pg-5) from the depth interval 2772–2795 m, and Petišovci-shallow (D-5) from the depth interval 1212–1250 m. According to the available composition dataset of gas, available from the Petrol Geo d.o.o. documentation, the “deep” gases sampled from the Pg-6 and Pg-5 wells consist of 85 % methane (C1), 11 % hydrocarbons heavier than methane (C2–C6) and 4 % CO2. The “shallow” gas from well D-5 contains more than 89 % methane, up to 11 % C2–C6 gases, while the CO2 content is negligible. The “deep« gas from the Pg-6 and Pg-5 wells has δ13CCH4 -36.7 ‰ and -36.6 ‰, respectively, while the “shallow” gas from the D-5 well has the δ13CCH4 of -38.6 ‰. The methane from the “shallow” gas is slightly enriched in the lighter 12C isotope. δ13CCH4 in the range from -38.6 to -36.6 ‰ clearly indicates the thermogenic origin of methane formed during the catagenesis phase of gas formation.

The 13C-depleted methane in terrigenous shale gas: A case study in the Triassic Yanchang Formation, Ordos Basin

The methane carbon isotopic composition (δ13C1) of some shale gas, and of some conventional gas in shale gas regions, is more depleted in 13CH4 than can be predicted from vitrinite reflectance (Ro) using the δ13C1-Ro equation. This is also often the case for coal bed methane. There is currently no convincing explanation for this phenomenon primarily because wellhead gas or core desorption cannot represent the original, in-situ state of the shale gas, owing to problems of desorption fractionation, lost gas, and residual gas. In this paper, we focus on shale gas in the Yanchang Formation of the Ordos Basin. To avoid the above-mentioned problems and obtain the shale gas in-situ, two shale samples, obtained from pressure coring, were used for parallel experiments. The gas desorption experiment was carried out under normal temperature and heating conditions, the core residual gas was obtained by crushing, and the components and carbon isotopic composition of desorption gas and residual gas were analyzed. The δ13C1 values for the two shale (Ro = 1.2%) desorption gas samples were −50.7‰ and −50.8‰, about 10‰ lighter than the value of −40.6‰ predicted by the empirical δ13C1-Ro formula. The δ13C1 values for the small amount of core residual gas in the two samples were −47.0‰ and −47.6‰, indicating that δ13C1 of Yanchang Formation in-situ shale gas is about 10‰ lighter than the δ13C1-Ro empirical formula predicts. This difference may be related to gas adsorption onto organic matter and clay minerals in shale. The negative δ13C1 is due to the retention of pre-biogas and early thermogenic gas. Dynamic adsorption experiments with activated carbon and a 5 Å molecular sieve show that early methane molecules preferentially occupy adsorption sites with relatively low pore radii and are likely to be replaced by late methane molecules, due to the high adsorption energy. The pore size distribution characteristics of shale in the Yanchang Formation are generally consistent with this pattern. In general, the δ13C1 of shale gas is related to adsorption, and the degree to which it is negative is related to the adsorption intensity and pore structure of the source rock.

Hydrocarbon gas seepage along the Gydratny Fault (Lake Baikal)

The Gydratny Fault, extending in SW-NE over 60 km, is situated in the central basin of Lake Baikal. This fault governs a distribution of hydrocarbon gas discharge zones on the lake bottom, many of them are hydrate-bearing. During the Class@Baikal-2019 expedition gas samples were obtained from bottom sediments along the fault zone, molecular and isotopic properties of the gases were studied. It is concluded that the fault zone is permeable for hydrocarbons and serves as an important fluid flow conduit from deep sources to the surface. The most intensive gas seepage was determined along the central and north-eastern segments of the fault zone where it is associated with the MSU hydrate-bearing structure and the Novosibirsk and Ukhan mud volcanoes. Within these structures the highest concentrations of methane and C2+ components were detected, the heaviest isotopic composition of methane carbon (–57‰ VPDB) were identified and near-surface gas hydrate accumulations were observed. The south-western segment of the fault is characterized by the lowest concentrations of gases in sediments with light carbon isotopic composition of methane (–76‰ VPDB).A dominant gas migration mechanism (advection or diffusion) in the upper part of the basin sedimentary section conditions the registered concentrations of methane and its homologues in sediments and their carbon isotopic composition. Diffusion and dispersion of migrated thermogenic gases and significant portion of microbial methane in seeping gases are characteristic for the areas where the fault is buried under relatively thick modern sediments. Focused gas migration followed by its focused discharge are specific for the areas where the fault propagates to the lake floor and is well-expressed in a bottom relief. Two models of hydrocarbon gases migration to the surface explaining the observed gas-geochemical characteristics of bottom sediments are described and discussed. Obtained results can help in enhancing interpretation of data of gas geochemical prospecting for offshore oil and gas.

Molecular and isotopic compositions of hydrocarbon gases generated from anomalously 13C-enriched sapropelic sedimentary organic matter in lacustrine basins

For lacustrine basins, the enrichment of 13C in sedimentary organic matter is closely related to the growth of plankton biological productivity. Consequently, there are many cases where the sapropelic organic matter is more 13C-enriched than the humic organic matter. However, the geochemical characteristics of the pyrolysis products produced by 13C-enriched lacustrine sapropelic organic matter are less discussed. Herein, two lacustrine sapropelic kerogen samples with remarkably different carbon isotopic ratios (–23.2‰ and –28.4‰) and a coal sample (–25.6‰) were performed by a closed and dry pyrolysis system at temperatures ranging from 300 °C to 600 °C. The results indicated that the carbon isotopic compositions of hydrocarbon gas products were significantly affected by the initial carbon isotopic composition of their sources. At similar simulated temperatures, the carbon isotopic compositions of methane generated from the 13C-enriched sapropelic sample and the coal sample were more consistent. However, owing to the difference in their gas-generation mechanism, the natural gas generated from the coal sample had a more 13C-enriched isotopic composition of ethane (δ13C2) and a higher dryness, particularly at higher maturity levels. The hydrogen isotopic composition of methane (δ2HC1) was markedly enriched in deuterium as the thermal maturity increased and may have been independent of the genetic type and salinity. Therefore, we used the “Dryness vs. δ2HC1” and “δ13C2 vs. δ2HC1” diagrams to confirm the genetic type of natural gas in lacustrine basins.

A novel isotopic approach to distinguish primary microbial and thermogenic gases in shallow subsurface environments

The stable carbon isotopic compositions of methane and ethane have been used for several decades to characterize petroleum gas in the subsurface. However, difficulties have frequently remained in determining the exact origin of natural gas samples derived from microbial activity, thermal degradation of organic matter (e.g. thermogenic gas), and mixtures of both components. To further refine this approach, we represent the carbon isotope difference between methane and ethane, or Δ13CC1–C2, plotted versus the individual δ13C values of methane and ethane as a new graphical tool for a refined assessment of natural gas origins and their mixtures. In addition, a new mathematical notation using the δ13C values of methane and ethane is also proposed for discrimination of the origin of natural gas samples. This parameter has been termed isotope factor O(C1/C2) and is defined as the ratio [(δ13CC1*1000)/(δ13CC2)3]. When this factor is represented against the δ13C values of methane and ethane, an improved distinction between primary microbial and thermogenic gases is achieved. Our study does not propose mechanisms for microbial generation of ethane, but the data suggest that the isotopic composition of ethane should be taken into account for the characterization of the origin of natural gas samples from shallow subsurface environments. For primary microbial and thermogenic gases with similar δ13C values of methane, the primary microbial gas will be characterized by lower O(C1/C2) values (<1.5) compared to the thermogenic gas (>2), and will have a Δ13CC1–C2 value 10–20‰ more positive than that of thermogenic gas. Gas mixtures have intermediate O(C1/C2) and Δ13CC1–C2 values and are graphically identifiable using the here presented classification tools. The effectiveness of the new graphical tools is demonstrated using natural gas samples from Canadian groundwater wells, low-permeability petroleum reservoirs (including coalbed methane plays) in Canada and the USA, Quaternary primary microbial gas accumulations in China, and secondary microbial gases from Northern Africa and China.

Methanogenesis in the Eocene Tharad lignite deposits of Sanchor Sub-Basin, Gujarat, India: Insights from gas molecular ratio and stable carbon isotopic compositions

The present study investigates the molecular ratio and stable carbon isotopic compositions of gas samples from the Lower to Middle Eocene lignite deposits of the Lower to Middle Tharad Formation in the Sanchor Sub-Basin, Gujarat, India, which were understudied, hitherto. The stable carbon isotopic composition of methane (−69.30 to −57.20‰ in BK-5 and from −67.40 to −64.50‰ in BK-7 well) may imply the generation of primary microbial gas through the hydrogenotrophic methanogenesis, which was mixed with the early mature thermogenic gas, and this is a novel finding from this study area. The relation between the gas molecular ratio [methane/(ethane + propane)] and the stable carbon isotopic composition of methane confirms the mixing trend (~90–~40%) of the primary microbial methane with the early mature thermogenic gas sourced from hydrogen-rich macerals either in situ or at a higher depth that subsequently migrated upwards. Further, the studied gas samples comprise a large amount of carbon dioxide (16.95–32.32 vol.% and from 18.91 to 28.60 vol.% in BK-5 and BK-7 wells, respectively). The relation between the carbon dioxide content and its stable carbon isotopic composition (−21.30 to −11.80‰ and from −11.20 to −9.40‰ in BK-5 and BK-7 wells, respectively) may suggest the origin of carbon dioxide from volcanic degassing from the Deccan Trap basaltic magma as well as from coalification through decarboxylation and decarbonylation reactions. So, the mixed origins of carbon dioxide (inorganic + organic) and methane (primary microbial and early mature thermogenic) would have influenced the carbon isotopic difference between carbon dioxide and methane as well as the isotopic discrimination factor, which is also reported for the first time from this investigation. Finally, the relation between the gas molecular ratio and the carbon isotopic difference between carbon dioxide and methane compliments the gas mixing effects. Hence, the novelty of this investigation lies in elucidating the influences of the early mature thermogenic gas on the gas molecular and stable carbon isotopic signatures of primary microbial gas originated through the hydrogenotrophic pathway as depicted by the gas molecular ratio and stable carbon isotopic compositions of methane and carbon dioxide.