Genesis Of Natural Gas Research Articles

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.

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 > δ13C2, δ13C2 > δ13C3, δ13C3 > δ13C4, and δD2 > 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.

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 of source rocks and natural gas in Fudong area, Junggar Basin: implications for the genesis of natural gas

Geochemical characteristics of source rocks and natural gas in Fudong area, Junggar Basin: implications for the genesis of natural gas

Geochemical characteristics and genesis of natural gas in the Yan’an gas field, Ordos Basin, China

The Yan’an gas field in the Ordos Basin, China, was discovered in 2014 and contains reserves of up to 100billionm3. Its occurrence in the basin contradicts the distribution model of “gas in the north, oil in the south”. Upper Paleozoic natural gas in the Yan’an area is dominated by methane, with an average dryness coefficient (C1/C1–4, %) of 99.5% (δ13C1=−30.8 to −27.5‰), with minor amounts of CO2=3.8%, N2=0.5%, and ethane (δ13C2=−37.2 to −30.5‰) and traces of higher hydrocarbons. The gas is predominantly coal-derived originating from Carboniferous–Permian humic hydrocarbon source rocks and minor oil-type gas from sapropelic source rocks. The carbon isotope series includes reversals, with δ13C2<δ13C1 and rare δ13C3<δ13C2<δ13C1. The enriched δ13C1 value is a result of the extremely high thermal maturity, while the depleted δ13C2 value cannot be explained solely by the simple addition of oil-type gas. The complex carbon isotope reversals result from the combined effects of several secondary reactions under extremely high thermal maturity.

Oil and gas generation potential of different age sediments of the transcarpathian depression according to TOC content

Evolution of views on genesis of natural gases in the depths of Transcarpathian depression is given in the article. Besides another aspect that is mentioned is definition of potential source rocks of oil and gas within the depression by the analysis of the cores on TOC amount and oil and gas generation potential of Miocene thicknesses of sediments as well as preneogene basement

Petroleum Systems of the Hebaochang Gas Field in the Southern of Sichuan Basin, SW China

The Hebaochang gas field is located in the Upper Triassic Xujiahe terrestrial formation of southern Sichuan Basin in China, with at least 374 billion cubic feet (tcf) of proved gas reserves. Because of long-term compression, the reservoirs become mostly tight reservoir with low porosity, low permeability and strong heterogeneity. Furthermore, the contact between gas and water is so complex that there is no uniform gas-water interface. It is unclear for the distribution and physical properties of gas reservoirs and for matching relations between reservoir digenetic evolution and porosity, which hinder the exploration of Xujiahe formation. In this paper, petroleum system has been studied to investigate petroleum accumulation condition and pattern. The conclusions are as follows: (1) The rocks are mainly ash grey-debris-quartz sandstone, ash grey-debris-feldspar quartz sandstone and few feldspar-debris quartz sandstone. The reservoir spaces are mainly remainder intergranular pore and secondary dissolved pore, and it belongs to small pore-thin throat type; (2) Excellent hydrocarbon sources are mainly mudstones and shales from member 1st, member 3rd and member 5th in the Upper Triassic Xujiahe formation. The organic matters mainly consist of I and III types, which are in the late stage of mature to the earlier stage of high mature, so the potential of gas-generation is strong; (3) Reservoirs in member 2nd, member 4th and member 6th of Xujiahe formation produce gas and a little condensate. It is identified that gases mainly come from its coal hydrocarbon source rock and the genesis of natural gas is humus type; (4) Mudstone beds in Jurassic formation are considered as the direct seal for the gas accumulation in Upper Trassic, and the thick mudstones in member 1st, member 3rd and member 5th of Xujiahe formation also as an indirect cap rocks for the reservoir in member 2nd, member 4th and member 6th of Xujiahe formation; (5) Physical property of Xujiahe formation shows that reservoir is so tight that the resistance of natural gas secondary migration is strong, and the buoyancy force is so weak that the driving force of migration is mainly gas expansion. Accumulation pattern of Hebaochang gas field is “near-source gas accumulation-forming model.”

Determination of carbon isotopic composition of individual light hydrocarbons evolved from pyrolysis of source rocks by using GC-IRMS

The carbon isotopic composition of individual light hydrocarbons generated from source rocks that had been pyrolysed in vacuum glass tube were determined by using the GC-IRMS techniques. The results indicate that abundant CO2 in the pyrolysates has a remarkable effect on the determination of CH4δ13C. Running cryogenically with an initial temperature of −40°C can effectively eliminate the effect. In addition, it conduces to measuring the δ13C of C2+ hydrocarbons by increasing the injection volume and/or absorbing CO2 with the solution of sodium hydroxide. The above measures will help to get the carbon isotopic composition of C1–C7 components, which is of great significance for gas/source rock correlation and for study on the genesis of natural gas.

99/03639 Genesis of natural gas of eastern Changde gas field in northern Songliao basin: Hou, Q. et al. Shiyou Kantan Yu Kaifa, 1988, 25, (4), 17–19. (In Chinese)

99/03639 Genesis of natural gas of eastern Changde gas field in northern Songliao basin: Hou, Q. et al. Shiyou Kantan Yu Kaifa, 1988, 25, (4), 17–19. (In Chinese)

Reconsideration of Methane Isotope Signature As a Criterion for the Genesis of Natural Gas: Influence of Migration on Isotopic Signatures

Experiments were performed in the purpose of studying the isotopic consequences of the diffusional transport of hydrocarbon gases through sediment rocks. Linked to a numerical model, these gas diffusion experiments through a shale porous plug allowed us to correlate porosity and diffusivity of the migration medium. Significant isotopic fractionations (carbon and hydrogen) of methane, and ethane at a lesser degree were observed. This is in contradiction with the actual dogma of isotope geochemistry of natural gases which claims that no fractionation occurs during gas migration. The genetic characterization of natural gases by using the isotopic signature of methane appears as an ambiguous method.

深部火山岩中の天然ガスの成因に関する地球化学的考察

Chemical and isotopic analyses were applied to characterize genesis of natural gases commercially produced in north-east Japan, so called “Green Tuff” region. Concentrations of He and N2, isotopic ratios of 3He/4He and 4He/20Ne, δ13C values of CH4 showed positive correlations with stratigraphy of gas reservoirs. Especially isotopic values of He included in the deepest gases from volcaniclastic rocks in Nanatani and Nishikurosawa Formations were almost equivalent to those of volcanic fumaroles in the Japanese Islands, suggesting high contribution of mantle materials.On the other hand the genetic diagram of hydrocarbon compositions versus δ13C values of methane attributed hydrocarbon compounds exactly to pyrolysis products of organic matters in sedimentary rocks regardless of their reservoir rock types.No more than 1% of methane seems to be derived from upper mantle, whose contribution may be estimated by comparing CH4/3He values of Green Tuff gases with those of hydrothermal fluids according to studies of EPR.

Natural gases in mercury deposits of Donbass and Northwestern Caucasus

A short review of information on the composition and genesis of natural gases in the Northwestern Caucasus and Donbass mercury deposits is presented. These differences in gas composition, as well as the distinct predominance of carbon dioxide and hydrogen in hydrothermally altered rocks, may be used for predicting gas-bearing capacity of deposits and for mercury prospecting in new areas. (JMT)

Geochemical Studies on the Genesis of Natural Gas

天然ガス鉱床の生因を地球化学的に究明するために,現世の堆積物中のメタンガス発生の機構および第四紀天然ガス鉱床の研究を行なった。メタンが有機物の分解によって生成されるかぎり,メタン以外の分解生成物も考慮に入れる必要がある。すなわち炭酸ガス,炭酸塩,窒素ガスおよびアンモニアを考慮した。また,ガス成分に関しては,地上で遊離するガス(casing head gag)も,ガス水比により,溶在ガスに加え合わせ,各成分は水1l中の量として示す。このようにして,雨水および湖水に始まり,堆積物中の間隙水を経て第四紀天然ガス鉱床へとガス鉱床が進化して行くものとして考察した。その結果,有機物の分解生成物の全炭素と全窒素の比から,この両者の相対分解速度は,窒素に関して初期の段階に極大値を示し,メタン濃縮の段階になると減少する。そして,終りに分解生成物の炭素と窒素の比は有機物のその比に近くなり鉱床が成立する。また,生成径路は[CH4],[CO2+HCO3-+CO22-]および[N2+NH4+]の三角座標を用いて明らかにすることができた。すなわちメタン濃縮の前段階として炭酸の濃縮が見いだされた。