Origin Of Natural Gas Research Articles

Geochemical characteristics and origin of crude oil and natural gas in different areas of Wenchang-A Sag, Pearl River Mouth Basin, South China Sea

Geochemical characteristics and origin of crude oil and natural gas in different areas of Wenchang-A Sag, Pearl River Mouth Basin, South China Sea

Characteristics and Origin of Natural Gas in Yongfeng Sub-Sag of Bogda Mountain Front Belt

By systematically analyzing the natural gas composition, carbon isotopes, and source rock characteristics in the Yongfeng sub-sag of the Bogda Mountain front belt, natural gas characteristics were determined, and the genetic types and sources of natural gas were investigated. The research results indicate that methane is the main component of natural gas in the Yongfeng sub-sag, with low levels of heavy hydrocarbons and a high drying coefficient. These characteristics make it dry gas, which refers to natural gas with a methane content of over 95%. The ethane carbon isotope δ13C2 of natural gas is −28.5‰ and belongs to oil type gas. The methane carbon isotope δ13C1 of natural gas is −58.6‰~−59.4‰, has a relatively depleted methane carbon isotope value, shows significant differences from the surrounding natural gas methane carbon isotope, and belongs to the category of biogenic gas. The Permian Lucaogou Formation is the main source rock in the study area, with good organic matter abundance. The microscopic components of kerogen are mainly composed of sapropelic formations and the organic matter type is I–II1. The source rock has a high maturity and has reached the mature stage, mainly consisting of oil and wet gas. The ethane carbon isotope of natural gas in the Yongfeng sub-sag shows as oil type gas, which is consistent with the kerogen type of the Lucaogou Formation source rocks, indicating that the natural gas mainly comes from the Lucaogou Formation source rocks. Based on comprehensive data and information on natural gas composition, carbon isotopes, and burial history of the source rocks, it is believed that some of the crude oil generated from the Lucaogou Formation in the early stage underwent biodegradation due to tectonic uplift, resulting in biogenic methane and the formation of crude oil biodegraded gas.

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.

Carbon isotope fractionation during methane transport through tight sedimentary rocks: Phenomena, mechanisms, characterization, and implications

The phenomenon of carbon isotopic fractionation, induced by the transport of methane in tight sedimentary rocks through processes primarily involving diffusion and adsorption/desorption, is ubiquitous in nature and plays a significant role in numerous geological and geochemical systems. Consequently, understanding the mechanisms of transport-induced carbon isotopic fractionation both theoretically and experimentally is of considerable scientific importance. However, previous experimental studies have observed carbon isotope fractionation phenomena that are entirely distinct, and even exhibit opposing characteristics. At present, there is a lack of a convincing mechanistic explanation and valid numerical model for this discrepancy. Here, we performed gas transport experiments under different gas pressures (1–5 MPa) and confining pressures (10–20 MPa). The results show that methane carbon isotope fractionation during natural gas transport through shale is controlled by its pore structure and evolves regularly with increasing effective stress. Compared with the carbon isotopic composition of the source gas, the initial effluent methane is predominantly depleted in 13C, but occasionally exhibits 13C enrichment. The carbon isotopic composition of effluent methane converges to that of the source gas as mass transport reaches a steady state. The evolution patterns of the isotope fractionation curve, transitioning from the initial non-steady state to the final steady state, can be categorized into five distinct types. The combined effect of multi-level transport channels offers the most compelling mechanistic explanation for the observed evolution patterns and their interconversion. Numerical simulation studies demonstrate that existing models, including the Rayleigh model, the diffusion model, and the coupled diffusion-adsorption/desorption model, are unable to describe the observed complex isotope fractionation behavior. In contrast, the multi-scale multi-mechanism coupled model developed herein, incorporating diffusion and adsorption/desorption across multi-level transport channels, effectively reproduces all the observed fractionation patterns and supports the mechanistic rationale for the combined effect. Finally, the potential carbon isotopic fractionation resulting from natural gas transport in/through porous media and its geological implications are discussed in several hypothetical scenarios combining numerical simulations. These findings highlight the limitations of carbon isotopic parameters for determining the origin and maturity of natural gas, and underscore their potential in identifying greenhouse gas leaks and tracing sources.

Geochemical characteristics and origins of natural gases in the eastern Cote d’Ivoire Basin, West Africa

Geochemical characteristics and origins of natural gases in the eastern Cote d’Ivoire Basin, West Africa

Geochemical Characteristics and Origin of Sinian-Cambrian Natural Gas in Penglai Gas Area, Sichuan Basin

Geochemical Characteristics and Origin of Sinian-Cambrian Natural Gas in Penglai Gas Area, Sichuan Basin

Tracing Oils and Gas Accumulation in Complex Petroleum Systems Based on Biomarkers, Light Hydrocarbons, and Diamondoids from Concomitant Crude Oils: A Case Study in the Shawan Sag of the Junggar Basin, NW China.

The Shawan Sag is one of the most promising blocks in the western Junggar Basin for natural gas and oil exploration. To date, the research and exploration degree here is still low, and there is limited understanding of the origin and migration of natural gas and oils, which seriously restricts future exploration and development. At least three oil charging episodes and one gas charging episode could be confirmed in the reservoirs on the western slope of the Shawan Sag based on the analysis of concentrations and ratios of hopanes and steranes, diamondoids, and light hydrocarbons. The first and second charging oils originated from the peak and late oil generation window stages of Lower Permian Fengcheng Formation (P1f) source rocks, respectively. The third charging oil originated from the late oil generation window stage of source rocks of the Middle Permian lower Wuerhe Formation (P2w). Combining the carbon isotopic compositions and the gas composition, the fourth charging gas was derived from the postmature source rocks of Carboniferous(C) and Lower Permian Jiamuhe Formation (P1j) and the high-postmature source rock of Lower Permian Fengcheng Formation (P1f). The preservation conditions of nature gas in the Mesozoic (T-K) cap rocks in the Shawan Sag, as indicated by methyladamantanes (MAs)/methyldiamantanes (MDs) ratio, are better than those in the Mahu Sag. In this study, the methyladamantane maturity parameters of oils in the reservoirs were proposed to evaluate the maturity and further determine the migration direction of late-charging natural gas. The results suggest that late postmatured natural gases were charged from the southern part to the northwest of the Shawan Sag. Therefore, the southeastern direction of Well SP1 is a favorable area for natural gas exploration in the Shawan Sag. Meanwhile the northern part of the sag is favorable for the exploration of high-mature oil generated from source rocks within the Middle Permian Lower Wuerhe Formation.

A Review on Natural Gas Origin and Composition

Natural gas is obtained naturally. It is a hydrocarbon mixture. Natural gas is clean fossil fuel. It is safe when transported. Methane is main constituent of natural gas. It may also contain higher order hydrocarbons, carbon dioxide, helium, hydrogen sulphide and noble gases. World is facing problem of environmental pollution. To combat menace of pollution alternative sources of energy should be used. Natural gas is the cleanest fuel. Demand of natural gas all over the world is increasing.

Pyrolysis experiments of model compounds to explore carbon isotope fractionation in propane from natural gas

Investigating the mechanisms that determine the bulk and position-specific carbon isotopic distributions of propane in natural gas will help elucidate its formation and evolution. We used octadecane and squalane as model compounds that give simple precursors for gas production in gold-tube isothermal pyrolysis experiments to study the variations in intermolecular and intramolecular distributions of isotopes in the generated gaseous hydrocarbons. The δ13C values of the products and inverses of their carbon numbers (1/n where n = C1–C5) showed a negative linear relationship versus maturity, indicating that they formed by homolytic cleavage of C–C bonds and that the precursors showed homogeneous distributions of carbon isotopes. However, the significant difference in the kinetic isotopic effects (KIEs) of the gas generated by cracking of two model compounds under the same experimental conditions is not readily explained by single homolytic bond cleavage. The results indicate that besides the KIE of C–C bond cleavage, the bulk and position-specific carbon isotopic compositions of propane are related to the chemical and isotopic structures of the precursors and the propane transformation ratio. Based on the sites of C–C bond cleavage, two isotopic fractionation patterns (i.e., normal propyl and isopropyl models) may explain the bulk and position-specific carbon isotopic distributions of the generated propane. According to the propyl model, propane originates from (normal) propyl structures (CH3CH2CH2*) in the precursor via C–C bond cleavage at a terminal site of a propyl group, while the isopropyl model involves propane derived from isopropyl structures (CH3CH*CH3) in the precursor, with C–C bond cleavage at the central site. Simulations show that these distributions for propane cracked from octadecane closely follow the propyl model, whereas propane generated from squalane showed mixed contributions from both models, and its bulk and position-specific carbon isotopic distributions depend on the proportions of propyl and isopropyl structures in the precursors. Variations of propane’s position-specific carbon isotopic distributions during the main stage of propane generation indicate that free radical reactions are the main pathway for thermogenic propane formation, resulting in similar KIEs for propane terminal and central carbons. Therefore, the position-specific carbon isotopic distribution of propane can provide evidence of its formation mechanism and shows potential for revealing the origin and evolution of natural gas.

Deciphering the origin and secondary alteration of deep natural gas in the Tarim basin through paired methane clumped isotopes

The Tarim Basin is one of the most complex, ancient, and petroliferous deep craton basins in the world. Multiple sets of source rocks, stages of tectonism, and episodes of hydrocarbon generation and accumulation complicate the formation and evolutionary processes of hydrocarbons in the basin, especially for the deeply buried petroleum system at >6000 m depth. Paired clumped isotopes (Δ13CH3D and Δ12CH2D2) allow the investigation of methane isotopic bond ordering, elucidating the methane generation mechanism and its post-generation processes, which can complement studies of the molecular and conventional stable isotopic compositions of gas hydrocarbons in constraining the origin and source of natural gas. This study focused on methane clumped isotopes, and chemical and conventional stable isotopic compositions of natural gas samples from four typical oil and gas regions of the Tarim Basin. Results indicate that these gases are thermogenic gases with relatively high stable isotopic δ values (i.e., −46.1‰ < δ13C–CH4 < −25.9‰, −184‰ < δD-CH4 < −140‰). Most exhibit equilibrium methane clumped isotope signatures at temperatures of 128–257 °C, consistent with the main oil-window to gas-window region. The clumped isotope apparent temperature of equilibrated methane was used to determine its formation temperature, which was applied for gas–source correlations and thermal maturity assessments of the natural gases based on the results of previous basin modeling. The clumped isotope compositions of two gas samples from the Keshen area of the basin are characterized by significant deficits in Δ12CH2D2 values but with similar Δ13CH3D values to those of other equilibrated gases there, indicating the possibility of methane bond re-ordering at high temperatures (>300 °C) exceeding the methane “closure temperature”. Non-equilibrium gases in the Tabei area yielded a plausible Δ13CH3D apparent temperature (<160 °C) with a pronounced deficit in Δ12CH2D2 values, possibly owing to irreversible chemical kinetic processes in thermal cracking of organic matter at early thermal maturity (Ro < 1.5‰) or mixing between thermogenic gases generated at two distinct temperatures (i.e., ∼200 °C and ∼120 °C). Equilibrium clumped isotope signatures also rule out the possible effects of secondary alteration on natural gases in the Hetianhe area that were previously considered in conventional isotope studies. Such findings demonstrate that methane clumped isotopes provide independent and effective indicators of gas–source correlations in deep basins while also elucidating secondary processes that are often under- or over-estimated in conventional stable isotope studies.

Geochemistry and origins of hydrogen-containing natural gases in deep Songliao Basin, China: Insights from continental scientific drilling

The different reservoirs in deep Songliao Basin have non-homogeneous lithologies and include multiple layers with a high content of hydrogen gas. The gas composition and stable isotope characteristics vary significantly, but the origin analysis of different gas types has previously been weak. Based on the geochemical parameters of gas samples from different depths and the analysis of geological settings, this research covers the diverse origins of natural gas in different strata. The gas components are mainly methane with a small amount of C2+, and non-hydrocarbon gases, including nitrogen (N2), hydrogen (H2), carbon dioxide (CO2), and helium (He). At greater depth, the carbon isotope of methane becomes heavier, and the hydrogen isotope points to a lacustrine sedimentary environment. With increasing depth, the origins of N2 and CO2 change gradually from a mixture of organic and inorganic to inorganic. The origins of hydrogen gas are complex and include organic sources, water radiolysis, water-rock (Fe2+-containing minerals) reactions, and mantle-derived. The shales of Denglouku and Shahezi Formations, as source rocks, provide the premise for generation and occurrence of organic gas. Furthermore, the deep faults and fluid activities in Basement Formation control the generation and migration of mantle-derived gas. The discovery of a high content of H2 in study area not only reveals the organic and inorganic association of natural-gas generation, but also provides a scientific basis for the exploration of deep hydrogen-rich gas.

The geochemical differences and origin of multilayered natural gases in marine strata, the northwestern Sichuan Basin, China

The gas-source correlation of highly mature natural gas in marine strata has always been a contentious issue due to the complexities of the petroleum systems, which involve multiple source-reservoir-cap assemblages. To shed light on this matter, a study was conducted using data from five typical gas fields and two hot exploration blocks in the northwestern Sichuan Basin. Thirty-seven samples from marine strata were collected, and their natural gas molecular compositions and stable carbon isotopes were examined to investigate the gas genetic types and origins. Based on detailed gas geochemistry information, combined with source rocks and reservoir characteristics, hydrocarbon accumulation history, and tectonic evolution, the formation of natural gas was studied. The results suggest that the natural gases in the area are dominated by hydrocarbon gases with extremely high dryness coefficients and a trace of CO2 and N2. These natural gases can be separated into three groups based on the development of structures and different source rocks, according to the identification of the gas-source correlation. The presence of oil cracking gas in natural gas increases with the amount of fracture development in the gas-bearing area and the amount of input from sapropelic organic matter in the Qiongzhusi Formation (Fm). Conversely, the contribution from mixing sapropelic-humic organic matter in the Middle-Upper Permian increases noticeably. The different geochemical characteristics of natural gas in the northwestern Sichuan Basin are the result of three-factor coupling, involving different source rocks, diversified fracture evolution, and various secondary alterations (thermochemical sulfate reduction alteration, thermal maturity effect, and mixing of gas). The development of fracture determines the contribution proportion of different source rocks, while secondary alteration further transforms the geochemical characteristics of natural gas.

Tracking the origin of Ordovician natural gas in the Ordos basin using volatile sulfur compounds

Molecular and compound specific isotope analysis of volatile organic sulfur compounds (VOSC), alkanes and CO2 in natural gases from the Ordovician Majiagou Formation of the Daniudi field (Ordos basin, China) was performed. The analysis of VOSC demonstrated abundant thiols, sulfides and thiophenes in several samples while others had low concentrations of sulfides only. Molecular analysis of main alkanes and non-hydrocarbons showed the samples vary by the nitrogen and H2S concentrations. Thiols in the gas were at isotopic equilibrium with H2S bearing isotopic signature similar to that of Ordovician anhydrites within the reservoirs, hence the source of H2S was likely thermochemical sulfate reduction (TSR) of these anhydrites. In contrast, gas samples that lacked thiols also lacked H2S. Since all gases came from the same formation and similar thermal regime, the lack of thiols and H2S indicates that the occurrence of TSR in the field was limited, likely by contact between hydrocarbons to the anhydrites. The isotopic signature (δ34S) of thiophenes in the gas samples suggests the source of the gas is unlikely to be Carboniferous or Permian coals which were previously suggested as the source rocks for the gas. The δ13C and δ2H of alkanes further supports this suggestion as it demonstrates Carboniferous and Permian gases are unlikely to undergo TSR and generate the gas present in the Ordovician reservoirs. Instead, the δ13C and δ2H of alkanes hint that the gas source is shale rather than coal.This study demonstrates the applicability of compound specific sulfur isotope analysis of VOSC in identification of H2S sources, performing gas-source rock correlation and acting as a complementary proxy in case where routine analysis of hydrocarbons (δ13C and δ2H) is insufficient for identification of the gas source.

Origin of condensate oil and natural gas in Bozhong 19-6 gas field, Bohai Bay Basin

The discovery of the Bozhong 19-6 gas field has opened a new frontier for deep gas exploration in the Bohai Bay Basin, with a great potential for further gas exploration. However, poor understanding of oil and gas origin has been limiting the exploration progress in this area. To clarify the origin of condensate oil and gas in Bozhong 19-6 gas field, this study adequately utilized the organic geochemical analysis data to investigate the composition and geochemical characteristics of condensate oil and natural gas, and analyzed the relationship between condensate oil and the three sets of source rocks in the nearby sub-sags. Results show that the lighter components dominate the condensate oil, with a forward type predominance. The parent material of crude oil was primarily deposited in a shallow, clay-rich, low-salinity, weakly reducing aquatic environment. The condensate and natural gas have similar parent source characteristics and maturity, with Ro ranging from 1.4% to 1.6%. Both are products of high maturity stage, indicating that they are hydrocarbon compounds produced by the same group of source rocks in the same stage. Oil-sources correlation shows that condensate oil and gas mainly originate from the source rocks of the third member of Shahejie Formation in the nearby subsags of the Bozhong 19-6 structural belt.

Geochemistry and origin of natural gas in the arctic area of West Siberia

Results obtained in the studies of gas composition in the hydrocarbon pools of the Jurassic–Cretaceous sediments in the Arctic regions of West Siberia are reported. The specific features of gas composition in hydrocarbon pools are shown. The main features of the vertical and lateral gas zoning in the Aptian–Albian–Cenomanian, Berriasian–Hauterivian and Jurassic oil and gas bearing complexes are revealed. Generalization of the data on the geochemistry of hydrocarbon gases (the features of component composition, the isotope composition of methane), along with the published data of the geological and geochemical investigation of the Arctic regions of West Siberia, allows us to consider the highly mature Triassic–Middle Jurassic coaly matter as the source of the dry hydrocarbon gases of the Lower and Middle Jurassic complex. Either the Triassic–Middle Jurassic sediments or the Upper Jurassic beds, enriched with the aquatic organic matter, could be involved in the formation of Upper Jurassic and Lower Cretaceous pools. The low-maturity terrestrial (carbonaceous) organic matter of the Cretaceous sediments generated the major amount of light-isotope gases in the Aptian–Albian–Cenomanian sediments. In addition, the source of those gases could be methane formed during oil biodegradation.

Geocatalytically generated methane from low-maturity coal and shale source rocks at low temperatures (80–120 °C) over 52 months

Geocatalytic methanogenesis has been proposed to contribute to methane generation from low-maturity coal and shale source rocks. This study contributes further evidence for geocatalytic methanogenesis from low-maturity source rocks based on long-term experiments lasting up to 52 months. Samples from the Upper Devonian New Albany Shale (Ro 0.54 %) and Springfield Coal No. 2 (Pennsylvanian; Ro 0.54 %) were heated in glass tubes at 80, 100, and 120 °C for 52 months. Sample aliquots from the Upper Cretaceous Second White Specks Formation (Ro 0.42 %) were heated in gold tubes at 80 and 100 °C for 42 months at elevated hydrostatic pressures of 100 to 300 MPa. The product gases — methane (CH4) and carbon dioxide (CO2) — were collected and quantified, and gas yields were corrected for leakage from imperfectly closed pores in samples during heating. The results show that longer heating produced more CH4. The average CH4 yields from New Albany Shale and Springfield Coal No. 2 are 0.47 and 3.0 μmol CH4 per gram of total organic carbon (TOC) over 52 months of heating. Elevated hydrostatic pressure caused lower CH4 yields from the Second White Specks Formation (3.82 to 1.20 μmol g−1 TOC), suggesting that pressure can retard methanogenesis. Maceral type critically controls the methanogenesis potential of low-maturity coal and shale source rocks. Results of this study provide important insights to the origin of natural gas in low-maturity sedimentary basins.

Natural gas characteristics and gas-source comparisons of the Lower Triassic Feixianguan Formation, Eastern Sichuan Basin, China

There is great controversy regarding the origin and source of natural gas in the Lower Triassic Feixianguan Formation in the Eastern Sichuan Basin. This seriously restricts the study of natural gas dynamics in the Feixianguan Formation and thus hampers natural gas exploration in the region, so further study is urgently required. Using experimental tests of natural gas composition, stable isotopes, and noble gas isotopes with gas chromatography (GC) and mass spectrometry (MS) studies of source rock and reservoir asphalt saturated hydrocarbons, the natural gas geochemical characteristics, the genetic identification and a gas-source comparison of the Feixianguan Formation were studied. Then, constrained by the thermal history, the histories of gas generation and expulsion were restored by basin simulation technology. Finally, a gas accumulation model was established for the Feixianguan Formation. The results showed that (1) the H2S-rich and H2S-poor gas reservoirs of the Feixianguan Formation are distributed on the east and west sides of the Kaijiang-Liangping trough in the Eastern Sichuan Basin, respectively. The carbon and hydrogen isotope compositions of the natural gas in the gas reservoirs are generally heavy and have typical characteristics of high-maturity dry gas reservoirs. (2) The natural gas of the Feixianguan Formation is organic thermogenic gas, which is mainly oil-type gas generated by the secondary cracking of crude oil. The gas-generating parent material is mainly type II kerogen. (3) The natural gas of the Feixianguan Formation in the Eastern Sichuan Basin was mainly generated by argillaceous source rocks of the Upper Permian Longtan Formation. (4) Natural gas accumulation occurred as follows: the paleo-structure heights were filled with crude oil in the Early Jurassic, and paleo-oil reservoirs were formed in the Feixianguan Formation; during the Middle-Late Jurassic, the paleo-oil reservoirs were cracked when the reservoir temperatures rose above 160 °C, and paleo-gas reservoirs were formed. Since the end of the Late Jurassic, the paleo-gas reservoirs have been adjusted and reformed to form the present-day natural gas reservoirs. These results provide a basis for studying natural gas accumulation dynamics of the Feixianguan Formation in the Eastern Sichuan Basin.

Natural gas characteristics and gas-source comparisons of the lower triassic Jialingjiang formation, Eastern Sichuan basin

There are abundant natural gas resources in the Lower Triassic Jialingjiang Formation in the Eastern Sichuan Basin (ESB). Important progress has been made in the study of reservoir characteristics and sedimentary facies of marine reef-beach facies in the Jialingjiang Formation. However, there are still differences in the understanding of its natural gas origin and gas source rocks, which greatly restricts the understanding of the reservoir forming process and formation mechanism of the gas reservoirs, so further study is urgently needed. Based on experimental tests of natural gas composition, stable isotopes, and noble gas isotopes with gas chromatography (GC) and mass spectrometry (MS) studies of source rocks and reservoir asphalt saturated hydrocarbons, the natural gas geochemical characteristics, genetic identification and gas-source comparison of the Jialingjiang Formation were studied. The results showed that (1) the natural gas of the Jialingjiang Formation was mainly hydrocarbon gas, and methane was dominant. The average drying coefficient was 99.266%, which is typical of high maturity dry gas reservoirs. The δ13C1, δ13C2 and δ13C3 values ranged from −36.00‰ to 24.80‰, −37.80‰–27.60‰ and −39.20‰–23.20‰, respectively. The δD1, δD2 and δD3 values were between −164.00‰ and −124.00‰, −162.00‰ and −111.00‰ and −173.21‰ and −71.00‰, respectively. (2) The natural gas has a crustal source origin, which was mainly oil-type thermogenic gas generated by secondary cracking of crude oil. The gas-generating parent material is mainly partial sapropelic kerogen and was in the sedimentary environment of salt to brackish water. (3) The natural gas was mainly generated by argillaceous source rocks of the Upper Permian Longtan Formation. (4) The natural gas accumulation in the Jialingjiang Formation has experienced three stages, including paleo-oil reservoir, paleo-gas reservoir and current gas reservoir. The results provide a basis for the exploration decision-making of natural gas in the Jialingjiang Formation in the ESB.

Origin of natural gas within the deep-sea uncompacted sediments of the Shenhu area, northern South China Sea: Geochemical and methanogenic cultivation results

Large amounts of natural gas are dispersed at low concentrations or have accumulated to form highly saturated gas hydrates within uncompacted deep-sea (water depth usually >500 m) sediments worldwide. However, studies on their origin and microbial genetic mechanism are scarce. Using the gas hydrate prolific region of the Shenhu area in the northern South China Sea as our study area, we systematically investigated the genetic types and generation pathways of the natural gas in those sediments based on gas geochemical and anaerobic methanogenic cultivation results. Our results indicated that natural gas within the uncompacted deep-sea sediments in the Shenhu area is dominated by microbial methane (>95%) with a minor amount of biodegraded hydrocarbon (ethane to propane) (<1%). The microbial methane within the highly saturated gas hydrate reservoir was produced by hydrogenotrophic methanogens in the deeper buried optical methanogenic zone (25 °C < in-situ temperature <85 °C), rather than in the in-situ gas hydrate layer. However, the primary microbial gas generative potential of the upper part of the methanogenic zone (28–300 mbsf) in the Shenhu area is relatively poor because of insufficient methanogenic substrates. These findings suggest a strong vertical heterogeneity of methanogenesis potential in the methanogenic zone in the Shenhu area, which may be a common phenomenon in the worldwide marine sediment environments, especially in the regions with relatively low organic matter richness.

Hydrogen blending in the Italian scenario: Effects on a real distribution network considering natural gas origin

Blending hydrogen into the natural gas network can help decarbonize the energy sector by supporting the penetration of renewables. Italy is an importer of natural gas whose composition and properties depend on its origin. Previous literature simulates gas networks using a set of hydrogen molar fractions regardless of the natural gas composition variability. Instead, this paper defines the maximum mixable percentage of hydrogen as a function of the gas composition underlining the importance of not adopting a single hydrogen limit. Furthermore, the paper investigates whether guaranteeing gas quality also guarantees compliance with fluid dynamic constraints on a real network. The test case consists of seven gases imported in Italy in 2019 and an urban distribution network, meshed and consisting of more than 2000 elements with medium and several low-pressure levels. A steady-state simulation of the network is performed using each of the seven gases for a winter day in the case of pure natural gas and natural gas blended with hydrogen. The results show that the highest hydrogen molar fraction mixable in these gases can range between 5.3% and 14.8% and considering the lowest percentage can reduce the decarbonization potential of the network by 1463 kg of CO2,eq. The simulations show that fluid-dynamic standards are not always met in the low-pressure networks and safety limits on pressure and velocity are exceeded at peak demand. The results also lead the authors to suggest that a modulation of pressure setpoints as a function of gas composition should be investigated.