Genesis Of Gas Research Articles

Differences in the Genesis and Sources of Hydrocarbon Gas Fluid from the Eastern and Western Kuqa Depression

The Kuqa Depression is rich in oil and gas resources and serves as a key production area in the Tarim Basin. However, controversy persists over the genesis of oil and gas in the various structural zones of the Kuqa Depression. This study employs natural gas composition analysis, gas carbon isotope analysis and gold pipe thermal simulation experiments, to comprehensively analyze the differences in the genesis and sources of hydrocarbon gas fluid from the eastern and western Kuqa Depression. The results show that the Kuqa Depression is dominated by alkane gas, with an average gas drying coefficient of 95.6, with nitrogen and carbon dioxide as the primary non-hydrocarbon gases. The average of δ13C1, δ13C2 and δ13C3 values in natural gas are −27.70‰, −20.43‰ and −21.75‰, respectively. Based on comprehensive natural gas geochemical maps, the CO2 in the natural gas from the Tudong and Dabei areas, as well as the KT-1 well of the Kuqa Depression, is thought to be of organic origin. Additionally, natural gas formation in the Tudong area is relatively simple, consisting entirely of thermally generated coal gas derived from the initial cracking of kerogen. The natural gas in the KT-1 well and the Dabei area are mixed gasses, formed by the initial cracking of kerogen from highly evolved lacustrine and coal-bearing source rocks, exhibiting characteristics resembling those of crude oil cracking gas. The methane (CH4) content of natural gas in the Dabei area is high and the carbon isotopes are unusually heavy. Considering the regional geological background, potential source rock characteristics and geochemical features may be related to the large-scale invasion of dry gas contributed by CH4 from highly evolved, underlying coal-bearing source rocks. Consequently, the CH4 content in the mixed gas is generally high (Ln (C1/C2) can reach up to 5.38), while the relative content of heavy components is low, though remains relatively unchanged. Thus, the map of the relative content of heavy components still reflects the characteristics of the original gas genesis (initial cracking of kerogen). Mixed-source gas was analyzed using thermal simulation experiments and natural gas composition ratio diagrams. The contributions of natural gas from deep, highly evolved coal-bearing source rocks in the KT-1 well and the Dabei area accounted for more than 90% and approximately 60%, respectively. This analysis provides theoretical guidance for natural gas exploration in the research area.

Oil and Gas Content of the South Caspian Basin

Abstract —We have compiled maps of areal isotope composition changes and constructed graphs of gas HC distribution depending on the stratigraphic age of the host rocks and graphs of isotope composition changes depending on the depth of sampling to study the hydrocarbon potential of the deep-seated oil and gas pools of the South Caspian Basin. The genesis of gas was studied using the techniques elaborated by M. Schoell and A. James. Two stages of hydrocarbon formation have been established by study of various kinds of gas manifestation. The first stage (Miocene–Eocene) began in the deposits underlying the Productive Series and continued up to the deposits of the latter. This stage was characterized by a frequent change in the directions of both downward and upward movements of gases. The second stage of hydrocarbon formation (Anthropogene–Pliocene) began in the deposits of the Productive Series and was characterized by a change in the regional geodynamic setting. Avalanche sedimentation and the predominance of downward movements over upward ones favored the accumulation of thick sediments at the time when the Productive Series formed. The sedimentation and tectonic processes (downwarping) in the deep-water zone of the basin led to harsh thermobaric conditions in the sedimentary strata. A detailed analysis of the results of gas survey in the deep-water zone of the South Caspian Basin has shown gas generation with a predominance of two components, methane and ethane. Study of the trends of temporal and areal hydrocarbon migration and of the areas of oil and gas generation makes it possible to reveal structures with evidence for large and giant hydrocarbon reserves. We have established that gas hydrocarbons in the bottom and upper-section sediments of the southern Caspian Sea are intimately related to the sources of hydrocarbons, their migration, and other processes running in the deep-seated sediments and in the upper section.

The generation mechanism of deep natural gas in Tabei uplift, Tarim Basin, Northwest China: insights from instantaneous and accumulative effects

The natural gas heavy carbon isotope and high dryness coefficients genesis in Tabei uplift, Tarim Basin has been highly controversial. To investigate the generation mechanisms of natural gas in the Tabei Uplift. Natural gas chemical composition, carbon isotopes were used to analyze the genesis of natural gas, source rock maturity, and basin modeling were conducted to reconstruct the natural gas generation process, and the influences of instantaneous and cumulative effects on natural gas properties was discussed. The results show that the dryness coefficients of natural gas range from 0.62 to 0.99 (average: 0.92), the methane contents range from 30.42% to 96.4% (average: 85.10%), ethane contents from 0.43% to 15.58% (average: 3.39%), propane contents from 0.11% to 11.43% (average: 1.78%), and the methane carbon isotopes range from −47.30‰ to −33.80‰ (average: −36.96‰), ethane carbon isotopes range from −39.60‰ to −33.20‰ (average: −35.57‰), propane carbon isotopes range from −36.90‰ to −28.50‰ (average: −35.49‰). Compared with the actual regional thermal evolution of the source rock (Ro% range from 1.4%∼1.7%), the natural gas exhibits excessively high dryness coefficients and heavy methane carbon isotope characteristics. The natural gas is primary cracking gas and sourced from marine type II kerogen. The dryness coefficient, methane carbon isotopes, and source rock maturity gradually increases from the west to the east. Instantaneous effects and leakage led to the dry gas and relative heavy methane carbon isotopes generated at a low maturity level. The current natural gas in the Ordovician reservoirs was all generated during the Himalayan orogeny. Long period pause of the gas generation between the two hydrocarbon generation phases is the main cause for the instantaneous effects.

Sources of natural gas in the Middle-Permian carbonate succession in the central-northern Sichuan Basin, Southwest China

Natural gas-source correlation is a challenging aspect of natural gas exploration in deep strata. The Middle-Permian carbonate succession in the Sichuan Basin, southwest China, particularly in the Maokou Formation, is a hotspot for natural gas exploration. However, determining the natural gas source in the Maokou Formation is challenging because of the high maturity and complexity of potential source rocks. In this study, we analyzed the genesis and sources of natural gas in the central-northern Sichuan Basin while considering the geological conditions and systematically utilizing the gas components, stable and rare-gas isotopes, and solid bitumen biomarkers. The results indicate that (1) the natural gas in the northern Sichuan Basin comprises a mixture originating from the source rocks of the Maokou and Wujiaping formations; (2) the Qiongzhusi Formation is the major source of natural gas in the north slope (and the Maokou Formation source rock could be used as an important supplement); (3) the natural gas in the Moxi-Longnvsi structure comprises a mixture originating from the source rocks of the Qiongzhusi and Maokou formations. From south to north and west to east, the major source rocks of the gas reservoirs changed from belonging to the Qiongzhusi Formation to the Maokou and Wujiaping formations. This study is the first to combine multiple geochemical methods and consider different geological settings to identify the gas source of a deep carbonate gas reservoir. Our study provides a reliable method for determining the natural gas-source correlation of gas reservoirs that contain highly mature and complex gas sources.

The Distribution and Genesis of Hydrocarbon Gases in the Bottom Sediments of the Laptev–Siberian Sea Zone of the East Arctic Shelf

The Distribution and Genesis of Hydrocarbon Gases in the Bottom Sediments of the Laptev–Siberian Sea Zone of the East Arctic Shelf

Genesis and accumulation mechanism of external gas in deep coal seams of the Baijiahai Uplift, Junggar Basin, China

Coal seams are typically self-sourced reservoirs. However, in certain special cases, the coal seams also contain large amounts of external gas from other source rocks. Successful development strategies in relation to Jurassic coalbed methane (CBM) in recent years have confirmed the presence of large amounts of external gas within the coal seams of the Baijiahai Uplift, Junggar Basin, China, which has important exploration and development prospects. However, the genesis and source of Jurassic CBM in the area remain unclear, limiting our understanding of its formation and accumulation as well as the planning of further development strategies. Based on a comprehensive analysis of the geochemical characteristics of Jurassic CBM, combined with research on the burial and thermal evolution history of the Jurassic coal seams, this study discusses the production curves of typical wells as well as regional tectonic styles, genesis, source, and accumulation of Jurassic CBM in the Baijiahai Uplift. Depending on the genesis, Jurassic CBM in the study area is divided mainly into coal-type (humic-type) gas, oil-type (sapropelic-type) gas, and mixtures of them, all of which are thermogenic gases of medium to high maturity. There are two main sources of Jurassic CBM in the Baijiahai Uplift. On the one hand, it comes from the vertical migration of gas generated by Permian and Carboniferous source rocks in the Baijiahai Uplift directly. On the other hand, it comes from the regional lateral migration from the Dongdaohaizi and Fukang Sags. Gas generated by source rocks in the Dongdaohaizi and Fukang Sags is driven by pressure, migrates towards the Baijiahai Uplift through sandstone channels, and accumulates in the Jurassic coal seams through faults. Compared with common self-sourced coal seams, enrichment of the coal seams with large amounts of external gases requires two necessary conditions: (1) Other layers of gas-generating source rocks are present at levels deeper than those of the coal seams, constituting additional gas sources for the coal seams, and (2) an open fault system is developed regionally, providing pathways for gas from other layers to enter the coal seams.

Discovery and inspiration of large- and medium-sized glutenite-rich oil and gas fields in the eastern South China Sea: An example from Paleogene Enping Formation in Huizhou 26 subsag, Pearl River Mouth Basin

Based on the practice of oil and gas exploration in the Huizhou Sag of the Pearl River Mouth Basin, the geochemical indexes of source rocks were measured, the reservoir development morphology was restored, the rocks and minerals were characterized microscopically, the measured trap sealing indexes were compared, the biomarker compounds of crude oil were extracted, the genesis of condensate gas was identified, and the reservoir-forming conditions were examined. On this basis, the Paleogene Enping Formation in the Huizhou 26 subsag was systematically analyzed for the potential of oil and gas resources, the development characteristics of large-scale high-quality conglomerate reservoirs, the trapping effectiveness of faults, the hydrocarbon migration and accumulation model, and the formation conditions and exploration targets of large- and medium-sized glutenite-rich oil and gas fields. The research results were obtained in four aspects. First, the Paleogene Wenchang Formation in the Huizhou 26 subsag develops extensive and thick high-quality source rocks of semi-deep to deep lacustrine subfacies, which have typical hydrocarbon expulsion characteristics of “great oil generation in the early stage and huge gas expulsion in the late stage”, providing a sufficient material basis for hydrocarbon accumulation in the Enping Formation. Second, under the joint control of the steep slope zone and transition zone of the fault within the sag, the large-scale near-source glutenite reservoirs are highly heterogeneous, with the development scale dominated hierarchically by three factors (favorable facies zone, particle component, and microfracture). The (subaqueous) distributary channels near the fault system, with equal grains, a low mud content (<5%), and a high content of feldspar composition, are conducive to the development of sweet spot reservoirs. Third, the strike-slip pressurization trap covered by stable lake flooding mudstone is a necessary condition for oil and gas preservation, and the NE and nearly EW faults obliquely to the principal stress have the best control on traps. Fourth, the spatiotemporal configuration of high-quality source rocks, fault transport/sealing, and glutenite reservoirs controls the degree of hydrocarbon enrichment. From top to bottom, three hydrocarbon accumulation units, i.e. low-fill zone, transition zone, and high-fill zone, are recognized. The main area of the channel in the nearly pressurized source-connecting fault zone is favorable for large-scale hydrocarbon enrichment. The research results suggest a new direction for the exploration of large-scale glutenite-rich reservoirs in the Enping Formation of the Pearl River Mouth Basin, and present a major breakthrough in oil and gas exploration.

Tools available for methane recovery from mines belonging to C.E.H. Petroşani

Mine gas is present both in coals and in the surrounding rocks and basically consists of methane (some-times almost 100%) mixed with carbon dioxide (up to 5%) with nitrogen (a few percent) and traces of carbon monoxide. The genesis of mine gas can be related to the biochemical transformation of vegetation during the carbonization process. The degassing of coal bed has been established as an active method of reducing methane emissions due to the need to ensure the exploitation of the bed with high productivity and in safe conditions. The methane gas existing in the coal bed is captured through various types of drilling executed for this purpose, being directed through a system of pipes to the surface to the central degassing station from where it can be taken and directed for use for a specific purpose. From an economic point of view, it has been proven that methane recovery from coal mines is again a profitable activity for both the mining company and a possible investor. The volume of methane from the coal deposits in Jiu Valley is very large and can provide large quantities for the recovery of this gas. At the same time, there was already a market for this product in Jiu Valley made up of industrial and individual consumers.

Geochemical characteristics and genesis of the Ordovician sub-salt natural gas in the Ordos Basin, China

A significant amount of natural gas resources has been discovered in the Ordovician reservoirs under a thick layer of gypsum-salt strata as a result of ongoing research into deep natural gas in China’s Ordos Basin, however, the genetic type and source of the Ordovician sub-salt natural gas remain contentious. These limits understanding how the geochemical properties of the natural gas in Ordos Basin have evolved and how to best guide future exploration and development. Based on the components, carbon and hydrogen isotopic ratios of natural gas from the latest exploration wells, combined with the geological background, this study systematically analyzed the genetic types and sources of sub-salt natural gas of the central and eastern Ordos Basin. The results show that the Ordovician natural gas is mainly composed of hydrocarbon gases with low content of heavy hydrocarbons and dryness (CCH4/CCH4+) above 0.95, belonging to typical dry gas. Non-hydrocarbon gases mainly include N2 and CO2, and some natural gas samples contained H2S. The Ordovician sub-salt natural gas is primarily a self-generating and self-preserving oil-cracking gas with relatively high maturity (Ro ranging from 1.5% to 2.1%) mixed with coal-derived gas generated from upper-Paleozoic coal with relatively low maturity (Ro ranging from 1.1% to 1.5%). Due to the dual-source hydrocarbon supply, the Ordovician sub-salt reservoirs provide favorable gas accumulation conditions and development prospects. This study offers a reasonable explanation for the anomalous geochemical characteristics of the Ordovician sub-salt reservoirs in the Ordos Basin, and also may serve as a guide for future exploration of natural gas in the carbonate gypsum-salt sedimentary system in other basins.

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.

Origin, Migration, and Characterization of Gas in the Xinglongtai Area, Liaohe Subbasin (Northeast China): Insight from Geochemical Evidence and Basin Modeling

Buried hill zones in the rift basins have a significant impact on the enrichment of natural gas resources, and this is of great significance for exploration and development. This study aims to unravel the origins, migration, and dynamic accumulation process of natural gas in the Xinglongtai structural belt, Liaohe Subbasin. A comprehensive geological and geochemical analysis was performed on source rocks and natural gas samples from various geological structures within the Xinglongtai structural belt. Moreover, basin modeling techniques were employed to trace the genesis and migration of natural gas, offering an in-depth understanding of the dynamic process of accumulation. We identified the Fourth Mbr (Es4) and Third Mbr (Es3) of the Shahejie Fm as the main source rocks in the Qingshui and Chenjia Sags. The Es4, primarily Shallow Lacustrine Mudstones, contributed mainly type II organic matter, while the Es3, consisting of Nearshore Subaqueous Fan and Deep Lacustrine Mudstones, contributed mainly type III and type II organic matter, respectively. Two distinct hydrocarbon accumulation systems were observed, one inside and one outside the buried hills. The system outside the buried hill is governed by a complex fault system within the lacustrine basin, resulting in dual-source directions, dual-source rock types, two migration phases, and late-stage accumulation. In contrast, the system within the buried hill primarily involves reservoirs nested in the basement, exhibiting dual-source directions, dual-source rock types, a single migration phase, and early-stage charging. The understanding of this interplay, alongside dynamic simulation of generation, migration, and accumulation, can provide valuable insights for predicting natural gas distribution and accumulation patterns in terrestrial faulted lacustrine basins. This knowledge can guide more effective exploration and development strategies for natural gas.

CONCEPT ABOUT ABIIOGENIC THEORY OF OIL GENESIS

The article considers alternative arguments, that contradict the accepted the organic hypothesis of oil origin, which must be taken into account at carrying out of oil and gas prospecting works. These conclusions must be used in the exploratory oil and gas well engineering in nonconventional reservoir types. The substantiation of the inorganic genesis of oil and gas, the assumption about the current age of hydrocarbon formation is proposed. The oil of many modern deposits undergoes dynamic processes, exchanges matter, information, while in the reservoir. This is proven by the chemistry of hydrocarbon molecules, characteristic only of oil, and their increased content in the surround-ing geological environment. A brief strategy of prospecting and exploration of commercial hydrocarbon reserves is outlined. The basic geological conditions for the potential belonging of the structure to the oil trap have been established. The well-known drilling data of an oil field dedicated to the Krasnoleninsky arch of the West Siberian oil and gas province are presented. The prospecting and exploration of oil reservoir is considered as the removal of two uncertainties: dynamic and static. The prospecting for oil involves the removal of dynamic uncertainty, which is a derivative of oil discrete reproduction and the formation of an accumulation. Its result is difficult to reliably identify. Geo chemical characteristics and prerequisites are no less important markers for prospecting and exploration.

Chemical and Isotopic Features of a High pCO2 Natural Mineral Water from Essentuki Field (Caucasian Mineral Water Region, Russia)

This article presents the new data on the chemical and gas composition, the content of stable isotopes of oxygen, hydrogen, carbon, and sulfur in natural mineral waters of the Essentuki field. A detailed study of the geological and hydrogeological features of the water circulation area, its major chemical composition, the content of organic matter in water, temperature conditions and δ18OSMOW, δDSMOW, δ13CDIC, δ18ODIC, δ34SVCDT, δ13CCO2, δ13CCH4, δ15N values made it possible to specify the genesis of water, gas, and solute components of the Essentuki CO2-rich mineral water field. The stable isotopes values (δ18OSMOW and δDSMOW) in the water phase ranges from −13.75 to −9.69‰ and from −101.08 to −74.34‰, respectively. They correspond to GMWL, which indicates their predominantly infiltration genesis. The values of δ13CDIC in mineral waters of the Essentuki field vary widely from −14.43 to +8.59‰ and indicate their mixed genesis. δ15N gas values in mineral waters of the Essentuki field vary quite widely from −2.31 to 2.50‰ indicating a different source of this gas. Obtained data prove that all mineral waters in the Essentuki field are infiltration waters, and the heterogeneous component composition of waters circulating in different aquifers reflects the lithological composition of water-bearing strata, the rate of openness/closure of faults and the intensity of reactions in the «water-rock-gas-organic matter» system.

New insight into abiotic or biotic gas in deep reservoirs of the CL-I gas field in Songliao Basin (China) by light hydrocarbons associated with natural gas

Abiotic synthesis through carbon dioxide (CO2) reduction may provide the prebiotic organic compounds needed for the emergence of life, whereas petroleum geologists pay more attention to whether abiotic gas generated by purely chemical reactions plays a prominent role in the formation of industrial gas pools like biotic gas. The Cretaceous reservoir associated with volcanic rocks of the Songliao Basin in northeastern China is suspected of possessing abiotic gas due to some abnormal geochemical characteristics, such as abundant 13C-enriched CO2, 13C-enriched CH4, 13C-depleted C2H6, and an isotopic trend of decreasing 13C content with growing carbon number. To understand further the genesis of deep natural gas, we examined the molecular and isotopic compositions of C1–C4 alkanes, CO2, and light hydrocarbons (LHs) of equal number (four) of gas samples collected from the Yingcheng (K1yc) volcanic and Denglouku (K1d) clastic reservoirs in the Changling (CL-I) gas field. Compared with the products of abiotic polymerization composed of 13C-depleted straight-chain alkanes, various 13C-enriched LH isomers that are highly compatible with the molecular and isotopic compositions of coal-derived thermogenic gas are confirmed in our samples, such as 2-methylhexane (2-MH), 2,3-dimethylpentane (2,3-DMP), cyclohexane (CH), methylcyclohexane (MCH), and other branched-chain alkanes or cycloalkanes. The striking invariable K1 ratio and resemblance of isotopic curves of LHs further indicate that the natural gas in different reservoirs is derived from underlying homologous source rocks, regardless of the variation of CO2 content (K1yc > 15% and K1d < 1%). Combining geological conditions, we propose that C1–C4 and LHs that have no inherent correlation with the concentration of CO2, which is predominantly derived from mantle degassing, are generated from the thermal decomposition of 13C-enriched type III organic matter during burial and diagenesis rather than sourced from mantle degassing, abiotic polymerization, or mixing of thermogenic gas. In addition, we also suggest that the geochemical anomalies consisting of 13C-enriched methane and 13C-depleted ethane are the products of the chemical mechanisms controlled by high temperature, and mantle-derived non-hydrocarbon gas (e.g., CO2 and He) are simply added to thermogenic gas.

In-situ cracking of oil into gas in reservoirs identified by fluid inclusion analysis: Theoretical model and case study

Natural gas formed by cracking of crude oil occurs in many basins globally. One of the key questions about such gas is whether it was produced in-situ—by cracking of crude oil in the reservoir itself—or whether it was generated elsewhere and accumulated in the reservoir subsequently. Fluid inclusions trapped in minerals can provide direct evidence regarding the genesis of natural gas, because these inclusions represent samples of the fluid present at the time of trapping, and/or resulting from subsequent modification of the trapped fluid. Here, we outline some theoretical aspects of the processes of cracking, trapping of fluid inclusions, and potential post-entrapment modifications, that lead to a model for identifying evidence for in-situ cracking of crude oil in reservoirs based on fluid inclusion assemblages (FIAs). This model divides the crude oil cracking process into three main stages, and considers the predicted evolution of fluids and possibility of forming FIAs. In the initial step, before cracking, only liquid oil and aqueous fluid are present in a reservoir, and two endmember types of inclusions may be formed. If cracking of crude oil occurs in the reservoir after these inclusions were trapped, then in-situ cracking of oil within the inclusions gives rise to systematic changes that can be interpreted through the lens of progressive thermal maturation, and hence provide direct evidence for cracking in the reservoir. In the second step, during cracking, the reservoir may host up to four fluid phases (residual oil, aqueous fluid, natural gas, and solid bitumen), and in theory as many as fourteen types fluid inclusions can be trapped; hence, complex FIAs comprising multiple fluid inclusion types can be considered evidence for trapping during in-situ cracking of crude oil in the reservoir. In the third and final step, after complete cracking, liquid oil has been exhausted and only natural gas, solid bitumen and aqueous fluid remain in the reservoir; at this stage, up to six fluid inclusion types can be trapped, which can be indicative of cracking. We applied this model to study the genesis of natural gas in the Sinian Dengying Formation reservoir of the Anyue Gas Field in the Sichuan Basin, southwest China. Six types of hydrocarbon-bearing primary fluid inclusions were observed in fluorite crystals formed during hydrocarbon accumulation. Notably, one type of inclusion showed consistent volumetric phase ratios of solid bitumen plus gas, suggesting that these inclusions originally captured crude oil, which subsequently underwent in-situ cracking in a closed system (within the inclusions) to generate fixed proportions of gas and solid bitumen. These FIAs are consistent with our model and suggest that the fluid inclusions trapped in fluorite can record the in-situ cracking of crude oil in the reservoir, and can therefore be used as direct evidence for the genesis of natural gas.

Geochemical characteristics and genesis of natural gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin

Abstract In recent years, the geochemical characteristics, genesis and sources of natural gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin have received extensive attention, but their genesis and sources are still controversial. In this study, taking the natural gas from the Xujiahe Formation in the Sichuan Basin as an example, the source and genesis of the natural gas have been systematically analyzed. The results show that the natural gas of the Xujiahe Formation in the Sichuan Basin is dominated by methane, followed by a small amount of CO2 and N2; only the southern Sichuan area contains a small amount of H2S, which comes from the supply of the underlying carbonate source rocks. Except for the western Sichuan Basin, the drying coefficient of the natural gas is generally less than 0.95 (wet gas). Furthermore, the composition of the natural gas is mainly controlled by the maturity of source rocks. The carbon isotope of ethane in natural gas ranges from −33.9 to −21.5‰, and the hydrogen isotope of methane ranges from −188‰ to −151‰. The carbon and hydrogen isotope values are higher in the western Sichuan Basin than in the central, northeastern and southern Sichuan Basin. The identification of the origin of natural gas and the comparison of gas sources show that the natural gas in the Xujiahe Formation is mainly coal-derived gas from its own coal-measure source rocks; the natural gas in the northern part of the southern Sichuan Basin is oil-derived gas originating from the Changxing Formation and the Silurian marine source rocks; however, the natural gas in the northeastern Sichuan Basin is a mixture of coal-derived and oil-derived gases. In addition, the carbon and hydrogen isotopes in some natural gas samples from the Xujiahe Formation have inversions of δ13C1 &gt; δ13C2, δ13C2 &gt; δ13C3, δ13C3 &gt; δ13C4, and δD2 &gt; δD3, and the magnitude of the inversions is small. It is considered to be caused by the mixing of gases from the same source, as well as the mixing of coal-derived and oil-derived gases.

Sedimentary Environments of Cambrian–Ordovician Source Rocks and Ultra‐deep Petroleum Accumulation in the Tarim Basin

AbstractThe Tarim Basin is the only petroliferous basin enriched with marine oil and gas in China. It is presently also the deepest basin for petroleum exploration and development in the world. There are two main sets of marine Source Rocks (SRs) in the Tarim Basin, namely the high over‐mature Cambrian–Lower Ordovician (∊ –O1) and the moderately mature Middle–Upper Ordovician (O2–3). The characteristic biomarkers of SRs and oils indicate that the main origin of the marine petroleum is a mixed source of ∊ –O1 and O2–3 SRs. With increasing burial, the hydrocarbon contribution of the ∊ –O1 SRs gradually increases. Accompanied by the superposition of multi‐stage hydrocarbon‐generation of the SRs and various secondary alteration processes, the emergence and abnormal enrichment of terpenoids, thiophene and trimethylaryl isoprenoid in deep reservoirs indicate a complex genesis of various deep oils and gases. Through the analysis of the biofacies and sedimentary environments of the ∊ –O1 and O2–3 SRs, it is shown that the lower Paleozoic high‐quality SRs in the Tarim Basin were mainly deposited in a passive continental margin and the gentle slope of the platform, deep‐water shelf and slope facies, which has exhibited a good response to the local tectonic‐sedimentary environment. The slope of the paleo‐uplift is the mutual area for the development of carbonate reservoirs and the deposition of marine SRs, which would be favorable for the accumulation of petroleum. Due to the characteristics of low ground temperature, the latest rapid and deep burial does not cause massive oil‐cracking in the paleo‐uplift and slope area. Therefore, it is speculated that the marine reservoirs in the slope of the Tabei Uplift are likely to be a favorable area for deep petroleum exploration, while the oil‐cracking gas would be a potential reserve around the west margin of the Manjiaer Depression. Hydrocarbons were generated from various unit SRs, mainly migrating along the lateral unconformities or reservoirs and the vertical faults. They eventually brought up three major types of exploration fields: middle and lower Cambrian salt‐related assemblages, dolomite inner reservoirs and Middle and Lower Ordovician oil‐bearing karst, which would become the most favorable target of marine ultra‐deep exploration in the Tarim Basin.

Effect of structural features of sedimentary cover on gas composition of permafrost table in northern West Siberia

Here, we analyzed geochemical indices of gases from core samples of permafrost table and evaluated data acquired from electric survey at the field of the Nadym-Pursk petroleum-bearing region. The Nadym-Pursk region is located in the northern West Siberia that is presently the major object of raw hydrocarbon (HC) exploration. The geologic exploration practice has demonstrated that the seismic survey efficiency is notably influenced by heterogeneous rocks of permafrost table, especially within permafrost distribution zones. The exploration efficiency for oil and gas can be enhanced using data from surface geochemical surveys that rely on vertical HC migration from deposits. The adequate interpretation of both seismic and geochemical survey data requires insights on the structure of permafrost table and on processes occurring therein. This study aimed to explore if geologic structural features of the territory affect the composition of gases dispersed in the permafrost table and identify the role of non-geological factors. The gas compositional features of the permafrost table were associated with HC migration channels, frost mounds, and probable gas hydrates within the permafrost distribution zone. The distribution of deep (He and H2) and catagenic (light methane homologues) gases stems from tectonic activity. This conclusion was made from the isotopic assay of samples from several holes, from the correlation between methane and homologues, from the presence of migration channels as per electric survey data, and essentially from the presence of deep gases. The enhanced content of methane is due to its active migration from both diagenetic zone (biogenic methane) and Cenomanian gas pay zones, which along with the respective geotemperature regime of subpermafrost strata is a favorable factor for gas hydrate generation. The natural connections between data from frost mounds point to their distinct genesis: the compositional genesis of gases is influenced by deep degassing and gas accumulation from diagenetic zones.

Study of the gas sources of the Ordovician gas reservoir in the Central-Eastern Ordos Basin

The source of the natural gas in the Lower Paleozoic Ordovician strata in the Ordos Basin, China is a controversial issue. In the present study, the genesis and distribution characteristics of the Ordovician natural gas were qualitatively investigated based on the composition of the natural gas and the hydrocarbon isotopic composition. Then, the kinetics of the carbon isotope were analyzed to determine the proportions of the gas in the Ordovician gas reservoir contributed from the Carboniferous-Permian and Ordovician strata. The results show the following. Compared to the Upper Paleozoic natural gas, the Ordovician natural gas has a large dryness coefficient. In core areas where gypsum-salt rocks are developed, the gypsum-salt rocks completely isolate the gas sources. The weathering crust of the reservoir in the fifth member of the Majiagou Formation (Ma51+2) originates primarily from the Upper Paleozoic coal-measure source rocks, while the Ma55 and the pre-salt natural gas are mainly derived from the Ordovician source rocks. In the areas where the gypsum-salt rocks are relatively well-developed, the gypsum-salt rocks isolate the gas source to some extent, the pre-salt gas reservoir is mainly derived from the Lower Paleozoic source rocks, and this contribution gradually increases with increasing depth. In the areas where the gypsum-salt rocks are not developed, the proportion of the contribution of the Upper and Lower Paleozoic source rocks to the gas source of the Ordovician gas reservoir is mainly controlled by the volume of gas generated and the other accumulation conditions, and it does not reflect the isolation effect of the gypsum-salt rocks on the gas source. The Ordovician natural gas accumulation models in the central-eastern Ordos Basin can be divided into four types according to the differences in the gas sources.

The role of deep faults in the structure formation of the TCFD, the distribution of hydrocarbon accumulations, and thermomineral sources

The work purpose was to assess the prospects of oil and gas potential of the western part of the Tersko-Caspian trough (TCT) concerning the development of deep-sunk areas in the light of modern ideas about the deep-seated formation of hydrocarbons. The main tasks are to analyze the ideas about the formation mechanism of the tectonic structure and formation of hydrocarbon accumulations; to study the relationships between the formation processes, migration, and the areal distribution of hydrocarbon accumulations; to determine the main prerequisites for the deep genesis of oil and gas. The scientific novelty lies in a comprehensive approach to the study of the formation processes of hydrocarbons, migration, the formation of traps, and patterns of placement of hydrocarbon accumulations. The article describes the mechanisms of formation of the Tersk and Sunzha composite anticline as the main zones of oil and gas accumulation. It is suggested that the formation of high-amplitude anticline folds in the upper cretaceous deposits resulted from the vertical migration of high-pressure fluids along deep faults with the breakthrough of their upper horizons of the sedimentary cover into the late-orogenic folding stages. The main prerequisites for the deep genesis of oil and gas are listed as pronounced uneven distribution of hydrocarbon accumulations, AHFP, hydrochemical anomalies, etc.