Geochemical characteristics of pyrolysis gas from epimetamorphic rocks in the northern basement of Songliao Basin,Northeast China

The Xushen gas field, located in the north of Songliao Basin, is a potential giant gas area for China in the future. Its proved reserves have exceeded 1000×10⁸ m³ by the end of 2005. But, the origin of natural gases from the deep strata is still in debating. Epimetamorphic rocks as a potential gas source are widely spreading in the northern basement of Songliao Basin. According to pyrolysis experiments for these rocks in the semi-confined system, gas production and geochemistry of alkane gases are discussed in this paper. The Carboniferous-Permian epimetamorphic rocks were heated from 300°C to 550°C, with temperature interval of 50°C. The gas production was quantified and measured for chemical and carbon isotopic compositions. Results show that δ ¹³C₁ is less than ?20‰, carbon isotope trend of alkane gas is δ ¹³C₁<δ ¹³C₂<δ ¹³C₃ or δ ¹³C₁<δ ¹³C₂>δ ¹³C₃, these features suggest that the gas would be coal-type gas at high-over maturity, not be inorganic gas with reversal trend of gaseous alkanes (δ ¹³C₁>δ ¹³C₂>δ ¹³C₃). These characteristics of carbon isotopes are similar with the natural gas from the basin basement, but disagree with gas from the Xingcheng reservoir. Thus, the mixing gases from the pyrolysis gas with coal-typed gases at high-over maturity or oil-typed gases do not cause the reversal trend of carbon isotopes. The gas generation intensity for epimetamorphic rocks is 3.0×10⁸–23.8×10⁸ m³/km², corresponding to R _o from 2.0% to 3.5% for organic matter.     

Geochemical characteristics and origin of gases from the Upper,Lower Paleozoic and the Mesozoic reservoirs in the Ordos Basin,China

The Ordos Basin, the second largest sedimentary basin in China, contains the broad distribution of natural gas types. So far, several giant gas fields have been discovered in the Upper and Lower Paleozoic in this basin, each having over 1000×10⁸m³ of proven gas reserves, and several gas pools have also been discovered in the Mesozoic. This paper collected the data of natural gases and elucidated the geochemical characteristics of gases from different reservoirs, and then discussed their origin. For hydrocarbons preserved in the Upper Paleozoic, the elevated δ ¹³C values of methane, ethane and propane indicate that the gases would be mainly coal-formed gases; the singular reversal in the stable carbon isotopes of gaseous alkanes suggests the mixed gases from humic sources with different maturity. In the Lower Paleozoic, the δ ¹³C₁ values are mostly similar with those in the Upper Paleozoic, but the δ ¹³C₂ and δ ¹³C₃ values are slightly lighter, suggesting that the gases would be mixing of coal-type gases as a main member and oil-type gases. There are multiple reversals in carbon isotopes for gaseous alkanes, especially abnormal reversal for methane and ethane (i.e. δ ¹³C₁>δ ¹³C₂), inferring that gases would be mixed between high-mature coal-formed gases and oil-type gases. In the Mesozoic, the δ ¹³C values for gaseous alkanes are enriched in ¹²C, indicating that the gases are mainly derived from sapropelic sources; the carbon isotopic reversal for propane and butane in the Mesozoic is caused by microbial oxidation and mixing of gases from sapropelic sources with different maturity. In contrast to the Upper Paleozoic gases, the Mesozoic gases are characterized by heavier carbon isotopes of iso-butane than normal butane, which may be caused by gases generated from different kerogen types. Finally, according to δ ¹³C₁-R ₀ relationship and extremely low total organic carbon contents, the Low Paleozoic gases would not be generated from the Ordovician source as a main gas source, bycontrast, the Upper Paleozoic source as a main gas source is contributed to the Lower Paleozoic gases.

     

Stable carbon and hydrogen isotopes of gases from the large tight gas fields in China

By the end of the year 2010,a total of 15 large tight gas fields have been found in China,located in the Ordos,Sichuan,and Tarim basins.The annual production and total reserves of these fields in 2010 were 222.5×108and 28657×108m3,respectively,accounting for 23.5%and 37.3%,respectively,of the total annual production and reserves of natural gases in China.They took a major part of all natural gas production and reserves in China.According to the analyses of 81 gas samples,the stable carbon and hydrogen isotopic compositions of tight gases in China have following characteristics:(1)Plots of 13C1-13C2-13C3,13C1-C1/C2+3and 13C1-13C2demonstrate the coal-derived origin of tight gases in China;(2)For the primary alkane gases,both carbon and hydrogen isotopic values increase with increasing molecular mass,i.e.,13C113C213C313C4and2H12H22H3;(3)The isotopic differences of 13C2-13C1,13C3-13C1,2H2-2H1and 2H3-2H1decrease with increasing Ro(%)and C1/C1–4;(4)There are seven causes for the carbon and hydrogen isotopic reversal,however,the carbon and hydrogen isotopic reversal of tight gases in China is caused mainly by multiple stages of gas charge and accumulation.     

Abiogenic hydrocarbons in commercial gases from the Songliao Basin, China

This paper discusses the kinetic fractionation, composition and distribution characteristics of carbon and hydrogen isotopes for various alkane gases formed in different environments, by different mecha- nisms and from different sources in nature. It is demonstrated that the biodegradation or thermode- gradation of complex high-molecule sedimentary organic material can form microbial gas or thermogenic gas. The δ 13C1 value ranges from -110‰ to -50‰ for microbial gases but from -50‰ to -35‰ (even heavier) f...     

Geochemical characteristics and origin of gases from the Upper,Lower Paleozoic and the Mesozoic reservoirs in the Ordos Basin,China

The Ordos Basin, the second largest sedimentary basin in China, contains the broad distribution of natural gas types. So far, several giant gas fields have been discovered in the Upper and Lower Paleozoic in this basin, each having over 1000×10⁸m³ of proven gas reserves, and several gas pools have also been discovered in the Mesozoic. This paper collected the data of natural gases and elucidated the geochemical characteristics of gases from different reservoirs, and then discussed their origin. For hydrocarbons preserved in the Upper Paleozoic, the elevated δ ¹³C values of methane, ethane and propane indicate that the gases would be mainly coal-formed gases; the singular reversal in the stable carbon isotopes of gaseous alkanes suggests the mixed gases from humic sources with different maturity. In the Lower Paleozoic, the δ ¹³C₁ values are mostly similar with those in the Upper Paleozoic, but the δ ¹³C₂ and δ ¹³C₃ values are slightly lighter, suggesting that the gases would be mixing of coal-type gases as a main member and oil-type gases. There are multiple reversals in carbon isotopes for gaseous alkanes, especially abnormal reversal for methane and ethane (i.e. δ ¹³C₁>δ ¹³C₂), inferring that gases would be mixed between high-mature coal-formed gases and oil-type gases. In the Mesozoic, the δ ¹³C values for gaseous alkanes are enriched in ¹²C, indicating that the gases are mainly derived from sapropelic sources; the carbon isotopic reversal for propane and butane in the Mesozoic is caused by microbial oxidation and mixing of gases from sapropelic sources with different maturity. In contrast to the Upper Paleozoic gases, the Mesozoic gases are characterized by heavier carbon isotopes of iso-butane than normal butane, which may be caused by gases generated from different kerogen types. Finally, according to δ ¹³C₁-R ₀ relationship and extremely low total organic carbon contents, the Low Paleozoic gases would not be generated from the Ordovician source as a main gas source, bycontrast, the Upper Paleozoic source as a main gas source is contributed to the Lower Paleozoic gases.     

Discrimination of abiogenic and biogenic alkane gases

We have combined the analytical data of the carbon isotope distribution pattern, R/Ra and CH4/3He values of abiogenic and biogenic (referring to the thermogenic and bacterial or microbial) alkane gases in China with those of alkane gases from USA, Russia, Germany, Australia and other countries. Four discrimination criteria are derived from this comparative study: 1) Carbon isotopic composition is generally greater than -30‰ for abiogenic methane and less than -30‰ for biogenic methane; 2) Abiogenic alkane gases have a carbon isotopic reversal trend (δ 13C1> δ 13C2> δ 13C3> δ 13C4) with δ 13C1>-30‰ in general; 3) Gases with R/Ra >0.5 and δ 13C11 δ 13C2>0 are of abiogenic origin; 4) Gases (meth- ane) with CH4/3He≤106 are of abiogenic origin, whereas gases with CH4/3He≥1011 are of biogenic origin.     

Preliminary study on the origin identification of natural gas by the parameters of light hydrocarbon

The light hydrocarbon composition of 209 natural gas samples and individual light hydrocarbon carbon isotopes of 53 natural gas samples from typical humic-sourced gas and sapropelic-sourced gas in the four basins of China have been determined and analyzed. Some identification parameters for humic-sourced gas and sapropelic-sourced gas are proposed or corrected. The differences of compound-specific δ ¹³C value of individual light hydrocarbon between humic-sourced gas and sapropelic-sourced gas have been founded. The humic-sourced gas has the distribution of δ ¹³C_benzene> ?24‰, δ ¹³C_toluene >?23‰, δ ¹³C_cyclohexane > ?24‰ and δ ¹³C_{methyl cyclohexane}> ?24‰, while the sapropelic-sourced gas has the distribution of δ ¹³C_benzene <?24‰, δ ¹³C_toluene< ?24‰, δ ¹³C_cyclohexane< ?24‰ and δ ¹³C_{methyl cyclohexane}< ?24‰. Among the components of C₇ light hydrocarbon compound, such as normal heptane (nC₇), methyl cyclohexane (MCH) and dimethyl cyclopentane (ΣDMCP), etc, relative contents of nC₇ and MCH are influenced mainly by the source organic matter type of natural gas. Therefore, it is suggested that the gas with relative content of nC₇ of more than 30% and relative content of MCH of less than 70% is sapropelic-sourced gas, while gas with relative content of nC₇ of less than 35% and relative content of MCH of more than 50% is humic-sourced gas. Among components of C_5–7 aliphatics, the gas with relative content of C_5–7 normal alkane of more than 30% is sapropelic-sourced gas, while the gas with relative content of C_5–7 normal alkane of less than 30% is humic-sourced gas. These paremeters have been suggested to identify humic-sourced gas and sapropelic-sourced gas.     

Classification and origin of natural gases from Lishui Sag,the East China Sea Basin

Natural gases discovered up to now in Lishui Sag, the East China Sea Basin, differ greatly in gaseous compositions, of which hydrocarbon gases amount to 2%–94% while non-hydrocarbon gases are dominated by CO₂. Their hydrocarbon gases, without exception, contain less than 90% of methane and over 10% of C₂ ⁺ heavier hydrocarbons, indicating a wet gas. Carbon isotopic analyses on these hydrocarbon gases showed that δ ¹³C₁, δ ¹³C₂ and δ ¹³C₃ are basically lighter than −44‰, −29‰ and −26‰, respectively. The difference in carbon isotopic values between methane and ethane is great, suggesting a biogenic oil-type gas produced by the mixed organic matter at peak generation. δ ¹³ \( C_{CO_2 } \) values of nonhydrocarbon gases are all heavier than −10‰, indicating a typical abiogenic gas. The simulation experiment on hydrocarbon generation of organic matter in a closed gold-tube system showed that the proportion of methane in natural gases produced by terrigenous organic matter in the Lingfeng Formation marine deposit is obviously higher than that in natural gases derived from the aquatic and terrigenous mixed organic matter in the Yueguifeng Formation lacustrine deposit, consequently the proportion of heavier hydrocarbons of the former is remarkably lower than that of the latter. Moreover, δ ¹³C₁ values of natural gases produced by terrigenous organic matter in the Lingfeng Formation marine deposit are about 5‰ heavier than those of natural gases derived from the aquatic and terrigenous mixed organic matter in the Yueguifeng Formation lacustrine deposit while δ ¹³C₂ and δ ¹³C₃ values of the former are over 9‰ heavier than those of the latter. Currently the LS36-1 oil-gas pool is the only commercial oil-gas reservoir in Lishui Sag, where carbon isotopic compositions of various hydrocarbon components differ greatly from those of natural gases produced by the Lingfeng Formation organic matter but are very similar to those of natural gases derived from the Yueguifeng Formation organic matter, therefore, natural gases in the LS36-1 oil-gas pool are mainly derived from the Yueguifeng Formation lacustrine source rock rather than the Lingfeng Formation marine or Mingyuefeng Formation coal-measures source rocks.

     

Natural gas geochemistry and its origins in Kuqa depression

According to gas compositional and carbon isotopic measurement of 114 gas samples from the Kuqa depression, accumulation of the natural gases in the depression is dominated by hydrocarbon gases, with high gas dryness (C₁/C_1–4) at the middle and northern parts of the depression and low one towards east and west sides and southern part. The carbon isotopes of methane and its homologues are relatively enriched in ¹³C, and the distributive range of δ ¹³C₁, δ ¹³C₂ and δ ¹³C₃ is ?32‰–?36‰, ?22‰–?24‰ and ?20‰–?22‰, respectively. In general, the carbon isotopes of gaseous alkanes become less negative with the increase of carbon numbers. The δ ¹³ \(C_{CO_2 } \) value is less than ?10‰ in the Kuqa depression, indicating its organogenic origin. The distributive range of ³He/⁴He ratio is within n × 10^?8 and a decrease in ³He/⁴He ratio from north to south in the depression is observed. Based on the geochemical parameters of natural gas above, natural gas in the Kuqa depression is of characteristics of coal-type gas origin. The possible reasons for the partial reversal of stable carbon isotopes of gaseous alkanes involve the mixing of gases from one common source rock with different thermal maturity or from two separated source rock intervals of similar kerogen type, multistages accumulation of natural gas under high-temperature and over-pressure conditions, and sufficiency and diffusion of natural gas.     

Classification and origin of natural gases from Lishui Sag,the East China Sea Basin

Natural gases discovered up to now in Lishui Sag, the East China Sea Basin, differ greatly in gaseous compositions, of which hydrocarbon gases amount to 2%–94% while non-hydrocarbon gases are dominated by CO₂. Their hydrocarbon gases, without exception, contain less than 90% of methane and over 10% of C₂ ⁺ heavier hydrocarbons, indicating a wet gas. Carbon isotopic analyses on these hydrocarbon gases showed that δ ¹³C₁, δ ¹³C₂ and δ ¹³C₃ are basically lighter than ?44‰, ?29‰ and ?26‰, respectively. The difference in carbon isotopic values between methane and ethane is great, suggesting a biogenic oil-type gas produced by the mixed organic matter at peak generation. δ ¹³ \(C_{CO_2 } \) values of nonhydrocarbon gases are all heavier than ?10‰, indicating a typical abiogenic gas. The simulation experiment on hydrocarbon generation of organic matter in a closed gold-tube system showed that the proportion of methane in natural gases produced by terrigenous organic matter in the Lingfeng Formation marine deposit is obviously higher than that in natural gases derived from the aquatic and terrigenous mixed organic matter in the Yueguifeng Formation lacustrine deposit, consequently the proportion of heavier hydrocarbons of the former is remarkably lower than that of the latter. Moreover, δ ¹³C₁ values of natural gases produced by terrigenous organic matter in the Lingfeng Formation marine deposit are about 5‰ heavier than those of natural gases derived from the aquatic and terrigenous mixed organic matter in the Yueguifeng Formation lacustrine deposit while δ ¹³C₂ and δ ¹³C₃ values of the former are over 9‰ heavier than those of the latter. Currently the LS36-1 oil-gas pool is the only commercial oil-gas reservoir in Lishui Sag, where carbon isotopic compositions of various hydrocarbon components differ greatly from those of natural gases produced by the Lingfeng Formation organic matter but are very similar to those of natural gases derived from the Yueguifeng Formation organic matter, therefore, natural gases in the LS36-1 oil-gas pool are mainly derived from the Yueguifeng Formation lacustrine source rock rather than the Lingfeng Formation marine or Mingyuefeng Formation coal-measures source rocks.     

Organic carbon isotope gradient and ocean stratification across the late Ediacaran-Early Cambrian Yangtze Platform

Organic carbon isotope(δ13Corg) data from two well-preserved sections across a shallow-to-deep water transect of the late Ediacaran-Early Cambrian Yangtze Platform in South China show significant temporal and spatial variations. In the shallow-water Jiulongwan-Jijiapo section, δ13Corg values of the late Ediacaran Dengying Formation range from -29‰ to -24‰. In the deep-water Longbizui section, δ13Corg values from time-equivalent strata of the Dengying Formation are mostly between –35‰ and -32‰. These new data, in combination with δ13Corg data reported from other sections in South China, reveal a 6‰–8‰ shallow-to-deep water δ13Corg gradient. High δ13Corg values(-30‰) occur mostly in shallow-water carbonate rocks, whereas low δ13Corg values(-32‰) dominate the deep-water black shale and chert. The large temporal and spatial δ13Corg variations imply limited buffering effect from a large dissolved organic carbon(DOC) reservoir that was inferred to have existed in Ediacaran-Early Cambrian oceans. Instead, δ13Corg variations between platform and basin sections are more likely caused by differential microbial biomass contribution to total organic matter. High δ13Corg values(-30‰) documented from shallow-water carbonates are within the range of typical Phanerozoic δ13Corg data and may record the isotope signature of organic matter from primary(photosynthetic) production. In contrast, low δ13Corg values(-32‰) from deep-water sections may have resulted from higher chemoautotrophic or methanotrophic biomass contribution to bulk organic matter in anoxic environments. The δ13Corg data provide indirect evidence for ocean stratification and episodic chemocline fluctuations in the Ediacaran-Early Cambrian Yangtze Platform.     

Natural gas leakage of Mizhi gas reservoir in Ordos Basin,recorded by natural gas fluid inclusion

Abundant natural gas inclusions were found in calcite veins filled in fractures of Central Fault Belt across the centre of Ordos Basin. Time of the calcite veins and characteristics of natural gas fluid inclusion were investigated by means of dating of thermolum luminescence (TL) and analyzing stable isotope of fluid inclusion. Results show that natural gas inclusion formed at 130–140°C with salinity of 5.5 wt%–6.0 wt% NaCl. It indicates that natural gas inclusion is a kind of thermal hydrocarbon fluid formed within the basin. Method of opening inclusion by heating was used to analyze composition of fluid inclusion online, of which the maximal hydrocarbon gas content of fluid inclusion contained in veins is 2.4219 m³/t rock and the maximal C₁/ΣC _i ratio is 91%. Laser Raman spectroscopy (LRS) was used to analyze chemistry of individual fluid inclusion in which the maximal hydrocarbon gas content is 91.6% compared with little inorganic composition. Isotope analysis results of calcite veins show that they were deposited in fresh water, in which the δ ¹³C_PDB of calcite veins is from −5.75‰ to 15.23‰ and δ ¹⁸O_SMOW of calcite veins is from 21.33‰ to 21.67‰. Isotope results show that δ ¹³C_{1 PDB} of natural gas fluid inclusion is from −21.36‰ to −29.06‰ and δD_SMOW of that is from −70.89‰ to −111.03‰. It indicates that the gas of fluid inclusion formed from coal source rocks and it is the same as that of natural gas of Mizhi gas reservoir. Results of TL dating show that time of calcite vein is (32.4±3.42)×10⁴ a, which is thought to be formation time of gas inclusion. It indicated that natural gas inclusion contained in calcite veins recorded natural gas leakage from Mizhi gas reservoir through the Central Fault Belt due to Himalayan tectonic movement.

     

Low-mature gases and typical low-mature gas fields in China

No natural gas pool of industrial importance could be formed at the low-evolution stage of organic matter. In the 1980s, on the basis of the development in exploration practice, the hypotheses of bio-thermo-catalytic transitional zone gases and early thermogenic gases were proposed. The lower-limit Ro values for the formation and accumulation of natural gases of industrial importance have been expanded to 0.3%―0.4%. In the light of the two-stage model established on the basis of carbon isotope fractionation in coal-type natural gases, the upper-limit Ro values have been set at 0.8%―1.0%. In terms of the geological practice in the low-mature gas zones and China's main coal-type gas fields, it is feasible and proper to set the upper-limit Ro value of low-mature gases at 0.8%. Supper-large gas fields such as the Urengoy gas field in western Siberian Basin should belong to low-mature gas fields, of which the natural gas reserves account for more than 20% of the global proven reserves, providing strong evidence for the significance of such a type of resources. The proven natural gas reserves in the Turpan-Hami Basin of China have almost reached 1000 × 108 m3. The main source rocks in this area are the Jurassic Xishanyao Formation, which occurs as a suite of coal series strata. The corresponding thermal evolution indices (Ro ) are mainly within the range of about 0.4%―0.8%, the δ 13C1 values of methane vary between-44‰ and-39‰ (correspondingly Ro =0.6%―0.8%), and those of ethane are within the range of-29‰―-26‰, indicating that natural gases in the Turpan-Hami Basin should be designated to coal-type low-mature gases. The light hydrocarbon evolution indices of natural gases also fall within the area of low evolution while the precursor type of light hydrocarbons also shows the characteristics of the coal-type. The geological background, carbon isotopic composition and light hydrocarbon index all provide strong evidence suggesting that the proven natural gases in the Turpan-Hami Basin are low-mature gases. In China a gas field with the gas reserves reaching 300 ×108 m3 can be defined as a large gas field, and thus the proven low-mature gases in the Turpan-Hami Basin are equivalent to the reserves of three large gas fields. Its existence is of great significance in research on and exploration of low-mature gases in China.     

Distribution and significance of C~_(40) alkanes in the extracts of Cretaceous source rocks from the Songliao Basin

Source rock extracts and crude oils from the Songliao Basin were analyzed by high-temperature gas chromatography (HTGC), gas chromatography-mass spectrometry (HTGC-MS) and gas chromatography-isotope ratio-mass spectrometry (GC-IRMS), for high molecular-weight alkanes. The distributions of n-alkanes in the Nenjiang Formation extracts are in the C14―C63 range; a bimodal distribution occurs in the C-21 and C21―40 regions. The C30―C37 n-alkanes are accompanied by C29―C35 hopanes, whereas the high molecular-weight C45―C47 n-alkanes co-occur with abundant isoalkanes, alkylcyclohexanes and alkylcyclopentanes. The high δ 13C values of the n-alkanes and the microscopic maceral compositions indicate a highly diversified organic source input for the Nenjiang Formation source rocks, ranging from aquatic plants, blue alge-bacteria, to land plant material. In contrast, n-alkanes in the rock extracts of the Qingshankou Formation are characterized by a single modal distribution, with relatively low abundances of C29―C35 hopanes, but high molecular-weight isoalkanes, alkylcyclohexanes and alkylcyclopentanes. The relatively low δ 13C values of C22―C44 n-alkanes and organic material compositions indicate that the source rocks in the Qingshankou Formation contain dominantly type I algal organic matter. The relative abundance of C 40 compounds in source rocks changes little at low maturity stage, but decreases drastically at higher maturity levels, with a concurrent reduction in the odd/even carbon predominance. In crude oils, in contrast, the relative abundance of C 40 compounds appears to relate closely with the oil source and oil viscosity.     

Identification of marine natural gases with different origin sources

Kinetic experiments of gas generation for typical samples of marine gas precursors including low-maturity kerogen, residual kerogen and oil as well as dispersed liquid hydrocarbon (DLH) in source rocks were performed by closed system, and the evolution trends of molecular and isotopic compositions of natural gases from different precursors against the maturity (R ₀%) at laboratory conditions were analyzed. Several diagrams of gas origin were calibrated by using the experimental data. A diagram based on the ratio of normal and isomerous butane and pentane (i/nC₄ ? i/nC₅) was proposed and used to identify the origins of the typical marine natural gases in the Sichuan Basin and the Tarim Basin, China. And the maturities of natural gases were estimated by using the statistical relationships between the gaseous molecular carbon isotopic data and maturities (δ¹³C-R ₀%) with different origins. The results indicate that the molecular and isotopic compositions of simulated gases from different precursors are different from each other. For example, the dryness index of the oil-cracking gas is the lowest; the dryness indices of gases from DLH and kerogen in closed system are almost the same; and the dryness index of gases from residual kerogen is extremely high, indicating that the kerogen gases are very dry; the contents of non-hydrocarbon gases in kerogen-cracking gases are far higher than those in oil-cracking and DLH-cracking gases. The molecular carbon isotopes of oil-cracking gases are the lightest, those of kerogen in closed system and GLH-cracking gases are the second lightest, and those of cracking gases from residual kerogen are the heaviest. The calibration results indicate that the diagrams of In(C₁/C₂)-In(C₂/C₃) and δ^{4 3}C₂-δ^{4 3}C₃-In(C₂/C₃) can discriminate primary and secondary cracking gases, but cannot be used to identify gas origin sources, while the diagram of i/nC₄ ? i/nC₅ can differentiate the gases from different precursors. The application results of these diagrams show that gas mixtures extensively exist in China, which involved the gases from multiple precursors and those from different maturity stages. For example, marine gases in the Sichuan Basin involve the mixture of oil-cracking gases and high-over-maturated kerogen gases, while those in the Tarim Basin involve not only the mixture of gases from multiple precursors, but also those from different maturity gases and post-reservoir alternations such as oxidized degradation and gas intrusion processes.     

Hydrogen isotope composition of natural gases from the Tarim Basin and its indication of depositional environments of the source rocks

By measuring carbon and hydrogen isotope compositions for C1, C2 and C3 of 74 gas samples, natural gases from the Tarim Basin can be divided into six groups on the basis of their origins: (1) coal-type gas derived from coal measures; (2) coal-type gas generated from the T-J lacustrine mudstones; (3) oil-type gas derived from the Cambrian and low Ordovician marine source rocks; (4) oil-type gas from the source rocks deposited in the marine-transitional facies; (5) mixing gas between gas derived from the Carboniferous transitional source rocks and the Mesozoic humic gas, and (6) mixing gases of thermal genetic gas and little deep gas in the Southwest depression of the Tarim Basin. The δ D values of methane in natural gases originating from different type kerogens are affected by both palaeo-environments of the source rock formation (kerogen types) and thermal maturity, with sedimentary environment (kerogen type) as the main controlling factor. Under the similar thermal maturity, the hydrogen isotope composition of methane is more enriched in deuterium in marine environments than lacustrine one. With the increase of thermal maturity and the increase of carbon atomic numbers of gaseous alkanes, the hydrogen isotopes become enriched in deuterium. The δ D values of ethane and propane (δ D2, δ D3) are controlled mainly by thermal maturity and to a lesser degree by sedimentary environment of the source rock formation. The partial reversal of hydrogen isotopes for gaseous alkanes would be related to the microbial oxidation, mixing of sapropelic and humic gases and / or mixing of gases from similar kerogen sources with various thermal maturities. In the oil-type gas, the sulfate reduction reaction would result in the reversed order of δ D1 and δ D2 (e.g. δ D1>δ D2).     

Carbon and hydrogen isotopic characteristics of natural gases from the Luliang and Baoshan basins in Yunnan Province, China

The Luliang and Baoshan basins are two small ba- sins in Yunnan Province. In the recent ten years or so, there have been found a number of natural gas pools of commercial importance in the two basins. Although the gas pools are small in size, the natural …     

Natural gas leakage of Mizhi gas reservoir in Ordos Basin,recorded by natural gas fluid inclusion

Abundant natural gas inclusions were found in calcite veins filled in fractures of Central Fault Belt across the centre of Ordos Basin. Time of the calcite veins and characteristics of natural gas fluid inclusion were investigated by means of dating of thermolum luminescence (TL) and analyzing stable isotope of fluid inclusion. Results show that natural gas inclusion formed at 130–140°C with salinity of 5.5 wt%–6.0 wt% NaCl. It indicates that natural gas inclusion is a kind of thermal hydrocarbon fluid formed within the basin. Method of opening inclusion by heating was used to analyze composition of fluid inclusion online, of which the maximal hydrocarbon gas content of fluid inclusion contained in veins is 2.4219 m³/t rock and the maximal C₁/ΣC _i ratio is 91%. Laser Raman spectroscopy (LRS) was used to analyze chemistry of individual fluid inclusion in which the maximal hydrocarbon gas content is 91.6% compared with little inorganic composition. Isotope analysis results of calcite veins show that they were deposited in fresh water, in which the δ ¹³C_PDB of calcite veins is from ?5.75‰ to 15.23‰ and δ ¹⁸O_SMOW of calcite veins is from 21.33‰ to 21.67‰. Isotope results show that δ ¹³C_{1 PDB} of natural gas fluid inclusion is from ?21.36‰ to ?29.06‰ and δD_SMOW of that is from ?70.89‰ to ?111.03‰. It indicates that the gas of fluid inclusion formed from coal source rocks and it is the same as that of natural gas of Mizhi gas reservoir. Results of TL dating show that time of calcite vein is (32.4±3.42)×10⁴ a, which is thought to be formation time of gas inclusion. It indicated that natural gas inclusion contained in calcite veins recorded natural gas leakage from Mizhi gas reservoir through the Central Fault Belt due to Himalayan tectonic movement.     

Genetic features of gas-condensate reservoirs in the Kekeya Field,southwest depression in the Tarim Basin,China

Oils, condensates and natural gases in the Kekeya Field, southeast depression of the Tarim Basin were studied for their geochemical characteristics. According to the distribution analysis of the C₂/C₃ values with C₁/C₂ values, C₂/C₃ values with C₁/C₃ values, as well as C₂/C₃ values with dryness index, there are two different types of natural gases in the studied field, which are spatially regularly distributed. One is the oil cracking gas, located on shallow reservoirs over X ²₅ reservoir, namely Upper oil legs; the other is kerogen cracking gas, located on X ²₇ reservoirs, X₈ reservoirs and E₂ k reservoirs, namely Lower oil legs. In addition, the distribution patterns of molar concentration of oils and condensates with different carbon numbers of the n-alkanes in the Kekeya Field indicate that the crude oils have experienced several kinds of secondary alterations, which were closely related to the charging of gaseous hydrocarbons after petroleum accumulation. These results indicate that, based on the research of δ ¹³C values of individual hydrocarbons, heptane values and isoheptane values of light hydrocarbons and aromatic maturity parameters for oils, condensates and natural gases, oils and gases were charged at different geological time in the Kekeya Field.

     

Characteristics and accumulation mechanisms of the Dongfang 13-1 high temperature and overpressured gas field in the Yinggehai Basin,the South China Sea

The Dongfang 13-1 is located in the diapiric structure belt of the Yinggehai Basin. The formation pressure of its main gas reservoir in the Miocene Huangliu Formation is up to 54.6 MPa(pressure coefficient=1.91) and the temperature is as high as 143°C(geothermal gradient 4.36°C/100 m), indicating that it is a typical high-temperature and overpressured gas reservoir. The natural gas is interpreted to be coal-type gas derived from the Miocene mature source rocks containing type II2-III kerogens as evidenced by high dryness index of up to 0.98 and heavy carbon isotopes, i.e., the δ13C1 ranging from -30.76‰ to -37.52‰ and δ13C2 ranging from -25.02‰ to -25.62‰. The high temperature and overpressured Miocene petroleum system is related mainly to diapir in the Yinggehai Basin and contains more pore water in the overpressured reservoirs due to undercompaction process. The experimental and calculated results show that the solubility of natural gas in formation water is as high as 10.5 m3/m3 under the temperature and pressure conditions of the Sanya Formation, indicating that at least part of the gas may migrate in the form of water-soluble phase. Meanwhile, the abundant gas source in the Basin makes it possible for the rapid saturation of natural gas in formation water and exsolution of soluble gas. Therefore, the main elements controlling formation of the Dongfang 13-1 gas pool include that(1) the diapir activities and accompanying changes in temperature and pressure accelerate the water-soluble gas exsolution and release a lot of free gas;(2) submarine fan fine sandstone in the Huangliu Formation provides good gas-water segregation and accumulation space; and(3) the overlying overpressured mud rocks act as effective caps. The accumulation mechanism reveals that the high temperatural and high pressure structure belt near the diapir structures has a good potential for large and medium-sized gas field exploration.