Isotopic Compositions Of Natural Gases Research Articles

Determination of intermolecular and intramolecular isotopic compositions of low-abundance gaseous hydrocarbons using an online hydrocarbon gas concentration method

The stable isotopic composition of natural gas can be used to identify its origin and source. However, low concentrations of gaseous hydrocarbons in high-mature natural and shale gases hinder accurate determination of their compound- and position-specific isotopic compositions. In this study, an online C2+ hydrocarbon gas concentration system combined with gas chromatography–isotope ratio mass spectrometry (GC–IRMS) or gas chromatography–pyrolysis–gas chromatography–isotope ratio mass spectrometry (GC–Py–GC–IRMS) was developed to determine compound- and position-specific isotopic compositions of low-abundance gaseous hydrocarbons. The lower limit of the gas concentration required for isotope ratio determination using the online concentration system is 0.001% (0.003%) for compound-specific carbon (hydrogen) isotopes and 0.005% for position-specific carbon isotopes and is thus applicable to most natural gas samples. The online concentration technique does not cause significant isotopic fractionation effects, and the combination with GC–IRMS and GC–Py–GC–IRMS can accurately and precisely determine the compound-specific δ13C and δD values of low-content C2+ gaseous hydrocarbons and the position-specific δ13C values (δ13Ca, δ13Cb, and SP values) of propane in low-content propane samples, respectively. The application of our method to two natural gas samples from the Ordos and Sichuan basins further confirms that the online concentration method allows simple and rapid determination of the compound- and position-specific isotopic compositions of low-abundance gaseous hydrocarbons.

Methods and benefits of measuring non-hydrocarbon gases from surface casing vents

Surface casing vents divert natural gas migration along oil and gas boreholes to bypass groundwater, with the gas venting to the atmosphere. While this strategy is designed to protect groundwater, it constitutes a source of greenhouse gases to the atmosphere. In instances where gas leakage occurs, the characterization of the molecular and isotopic composition of natural gas emitted from surface casing vent flows can be used to assist in identifying the gas source. We compare concentration measurements of non-hydrocarbon gases (within natural gas) of samples analyzed by laboratory-based gas chromatography (N2, Ar, CO2 and O2) and magnetic sector noble gas mass spectrometry (He, Ar and Kr) with field measurements conducted using a field portable quadrupole mass spectrometer (miniRUEDI). The standard deviation of miniRUEDI concentration results was within plus/minus one standard deviation of samples measured using laboratory-based GC (N2, O2, Ar and He) and magnetic sector noble gas mass spectrometry (He, Ar). Additional laboratory-based determination of isotope ratios of methane and argon (δ13CCH4, δ2HCH4, and 40Ar/36Ar) enabled a comparison between information provided by the analysis of reactive gases compared with noble gas isotopes. Gases from different sources displayed quantifiable differences in δ13CCH4 and δ2HCH4, but these changes may or may not be distinguished if only one sampling event is conducted. By comparison, 40Ar/36Ar further enabled the differentiation of various gas sources. The objective of this paper is to discuss the advantages and trade-offs of the three different analysis methods considered, and the feasibility of their application in different environmental monitoring scenarios.

Carbon Dioxide and its Carbon Isotopic Composition of Natural Gas in the Sichuan Basin, SW China

The Sichuan Basin, covering an area of 180 × 103 km2, has the following advantages in natural gas geology: The sedimentary rocks are 6,000–12,000 m thick with high maturity of source rocks, and nine sets of primary gas source rocks are developed in the basin with a gas–oil ratio of 80:1, and thus it is a gas basin. The remaining recoverable reserves of conventional and unconventional natural gas are up to 13.6404 × 1012 m3. Multiple gas-bearing systems are developed with 25 conventional and tight oil and gas producing layers and 135 discovered gas fields, and the total proved geological reserves and cumulative production of natural gas by the end of 2019 were 5.7966 × 1012 m3 and 648.8 × 109 m3, respectively. The CO2 components and the correlation with relevant parameters for 243 samples from 22 gas fields indicate that CO2 in the Sichuan Basin display the following two characteristics: (1) Relatively low CO2 content of 0.02%–22.90% with an average of 2.96%, which guaranteed the commerciality of natural gas exploration and production; (2) cratonic CO2, which is characterized by low CO2 contents (<5%) and low R/Ra ratios (<0.24). According to the δ13CCO2 values and the relationship with R/Ra, δ13C1, CO2 contents, and wetness coefficient (W) for 263 gas samples, the δ13CCO2 values display three characteristics: (1) The highest δ13CCO2 value (10.4‰) in China is found in the Fuling shale gas field, which extends the interval values from previous −39‰–7‰ to −39‰–10.4‰. (2) The δ13CCO2 values can be applied to identify the CO2 origin of natural gas in the Sichuan Basin: type A, organic origin from thermal decomposition of organic matter, with an average δ13CCO2 value of −12.8‰ and average wetness coefficient of 7.8% for 44 samples; type B, organic origin from thermal cracking of organic matter, with an average δ13CCO2 value of −15.7‰ and average wetness coefficient of 1.30% for 34 samples; type C, inorganic origin from thermal decomposition or organic acid dissolution of carbonate rocks or minerals, with an average δ13CCO2 value of −1.8‰ and average wetness coefficient of 0.85% for 175 samples. (3) δ13CCO2>δ13CCH4. This is a common characteristic shared by all geological age (from Z2dn to J2s) gas reservoirs and various gas types (coal-derived gas, oil-associated gas, and shale gas).

Origins and deep petroleum dynamic accumulation in the southwest part of the Bozhong depression, Bohai Bay Basin: Insights from geochemical and geological evidences

Latest exploration practices revealed appreciable petroleum resources in the deep pre-Cenozoic reservoirs in the southwest area of the Bozhong depression; however, the origins and accumulation mechanisms of deep hydrocarbons remain not fully understood. Here, an integrated study of the geochemical characteristics of overlying source rocks, maturity evaluation of petroleum, and origin of natural gas was conducted to characterize the dynamic petroleum accumulation and illustrate the main factors influencing the differential phases of petroleum distribution in the research area. The third member of the Dongying Formation (Ed3) mudstone in the research area displays high organic richness and is characterized by oil-prone organic matter, indicating high petroleum potential. The oils contained in the CFD18 and BZ13 buried-hill traps were mainly derived from the Ed3 and Shahejie Formation (Es) source rocks, respectively, with natural gas of kerogen cracking origin. Buried-hill oil from the BZ13 field displays a high thermal maturity than that of the CFD18 oils, which was evidenced by maturity parameters of saturated and aromatic hydrocarbons and concentrations of stigmastane. Nevertheless, maturity index of diamondoids and carbon isotopic composition of natural gas indicate the possible presence of mixing of higher mature Es fluids for the CFD18 field. This research underlines the contribution of the overlapped effective source rocks to the buried-hill traps. The causes of multiple petroleum phases in the deep reservoirs in the research area are mainly linked to dynamic petroleum accumulation rather than source rock type and oil secondary cracking. Although faults are present to act as vertical migration conduits due to late-stage activation with high intensity, abundant petroleum supply due to near-source charge and favorable constitution relationship of source rock and reservoir rock provide crucial conditions for deep petroleum accumulation in a tectonic activation zone.

A GC-SSIM-CRDS system: Coupling a gas chromatograph with a Cavity Ring-Down Spectrometer for onboard Twofold analysis of molecular and isotopic compositions of natural gases during ocean-going research expeditions

Carbon dioxide (CO2) and methane (CH4) are two climate-sensitive components of gases migrating within sediments and emitted into the water column on continental margins. They are involved in several key biogeochemical processes entering into the global carbon cycle. In order to perform onboard measurements of both the molecular and stable carbon isotope ratios (δ13C) of CH4 and CO2 of natural gases during oceanic cruises, we have developed a novel approach coupling gas chromatography (GC) with cavity ring-down spectroscopy (CRDS). The coupled devices are connected to a small sample isotope module (SSIM) to form a system called GC-SSIM-CRDS. Small volumes of natural gas samples (<1 mL) are injected into the GC using a headspace autosampler or a gas-tight syringe to separate the chemical components using a Shincarbon ST packed column and for molecular quantification by thermal conductivity detection (TCD). Subsequently, CO2 from the sample is trapped in a 7 mL loop at 32 °C before being transferred to the CRDS analyzer for sequential determination of the stable carbon isotope ratios of CH4 and CO2 in 24 min. The loop is an open column (without stationary phase). This approach does not require the use of adsorbents or cooling for the trapping step. Optimization of the separation step prior to analysis was focused on the influence of two key separation factors 1) the flow of the carrier gas and 2) the temperature of the oven. Our analytical system and the measurement protocol were validated on samples collected from gas seeps in the Sea of Marmara (Turkey). Our results show that the GC-SSIM-CRDS system provides a reliable determination of the molecular identification of CH4 and CO2 in complex natural gases, followed by the stable carbon isotope ratios of methane and carbon dioxide.

New equation to decipher the relationship between carbon isotopic composition of methane and maturity of gas source rocks

The identification of the origin and source of natural gas is always a difficult and hot issue. Hereinto, the maturity identification is one of the most important scientific problems. Many empirical equations have been established to decipher the relationship between the maturity of gas source rocks and the carbon isotopic composition of natural gas. However, these equations proposed often fail to identify the maturity of the source rocks correctly, which in turn prevents the identification of genetic types and source rocks of the natural gas because the petroliferous sedimentary basins in China are complex and diverse, with multiple sets of source rocks and different thermal history. In this paper, the oil-associated gas from the Permian lacustrine source rocks and the coal-derived gas from the Jurassic source rocks in Junggar and Turpan-Hami basins have been investigated to decipher the relationship between the maturity (vitrinite reflectance) of gas source rocks and the carbon isotopic composition of methane. The equations established are δ13C1=25lgRo−42.5 for oil-associated gas, and δ13C1=25lgRo−37.5 for coal-derived gas. These new equations are suitable for the maturity identification of source rocks in most petroliferous basins, and favorable for the identification of the genetic type and source of natural gas, which is very important to improve the geological theory of natural gas.

Genetic types of natural gas and gas-source correlation in different strata of the Yuanba gas field, Sichuan Basin, SW China

The chemical compositions and stable carbon and hydrogen isotopic compositions of natural gases in different strata of the Yuanba gas field in the Sichuan Basin were analyzed to investigate their genetic types and source. Natural gases from the Permian Changxing and Triassic Feixianguan formations have dryness coefficients higher than 0.995 and contain H2S in most gas samples, having a positive correlation between the H2S and CO2 contents. The identification of gas origin and gas-source correlation from this study indicate that natural gas in the Ziliujing Formation and most gas samples from the Xujiahe Formation are coal-type gas produced from primary cracking of kerogen, and they are self-sourced reservoirs in relatively independent systems. The natural gases in the 1st and 2nd members of the Xujiahe Formation were mixed with minor amounts of oil-type gas from argillaceous carbonate rocks in the Leikoupo Formation. In addition to the self-accumulated oil-type gas in the Leikoupo Formation, natural gas mainly came from the overlying or lateral source rocks in the Xujiahe Formation. The H2S-bearing natural gases in the Changxing and Feixianguan formations were produced by the cracking of crude oil from source rocks in the underlying Wujiaping Formation, with partial contributions from certain local source rocks in the Permian Dalong Formation. The H2S-bearing natural gas has undergone the thermochemical sulfate reduction (TSR) which were dominated by heavy hydrocarbons. The high δ13C values of CO2 in these gas reservoirs mainly result from the interaction between acidic fluids and carbonate rocks in the reservoirs.

Origin and migration model of natural gas in L gas field, eastern slope of Yinggehai Sag, China

Abstract Based on the chemical and stable carbon isotopic composition of natural gas and light hydrocarbons, along with regional geological data, the genetic type, origin and migration of natural gases in the L lithologic gas field, the eastern slope of Yinggehai Sag were investigated. The results show that these gases have a considerable variation in chemical composition, with 33.6%–91.5% hydrocarbon, 0.5%–62.2% CO2, and dryness coefficients ranging from 0.94 to 0.99. The alkane gases are characterized by δ13C1 values of –40.71‰––27.40‰, δ13C2 values of –27.27‰––20.26‰, and the isoparaffin contents accounting for 55%–73% of the total C5–C7 light hydrocarbons. These data indicate that the natural gases belong to the coal-type gas and are mainly derived from the Miocene terrigenous organic-rich source rocks. When the CO2 contents are greater than 10%, the δ13CCO2 values are –9.04‰ to – 0.95‰ and the associated helium has a 3He/4He value of 7.78×10–8, suggesting that the CO2 here is crustal origin and inorganic and mainly sourced from the thermal decomposition of calcareous mudstone and carbonate in deep strata. The gas migrated in three ways, i.e., migration of gas from the Miocene source rock to the reservoirs nearby; vertical migration of highly mature gas from deeper Meishan and Sanya Formations source rock through concealed faults; and lateral migration along permeable sandbodies. The relatively large pressure difference between the “source” and “reservoir” is the key driving force for the vertical and lateral migration of gas. Short-distance migration and effective “source – reservoir” match control the gas distribution.

Pyrolytic Gaseous Hydrocarbon Generation and the Kinetics of Carbon Isotope Fractionation in Representative Model Compounds With Different Chemical Structures

AbstractFive model compounds with representative chemical structures were selected for use in simulation experiments of pyrolytic gas production. The gas production and isotopic fractionation characteristics were observed and analyzed. Then, the factors affecting carbon isotope fractionation during natural gas generation were discussed, and a fractionation model was established and calibrated. We concluded that the final hydrocarbon gas (C1–5) yield of octadecane, octadecylamine, octadecanoic acid, decahydronaphthalene, and 9‐phenylanthracene decreased in turn with the effective hydrogen content. Compared with linear alkanes or alkyl compounds, cycloalkanes have higher thermal stability and generate gas later. The variation in the carbon isotopic composition of natural gas is primarily controlled by the following three factors: (a) the thermal evolution of organic matter results in a gradually heavier isotopic composition for the main gas production stage. (b) Gas inherits the isotopic composition of its parent material, and this effect is evident when the chemical structure and gas generation mechanism between parent materials are similar. (c) The structure of organic matter determines the reaction mechanism of gas generation, which has a significant influence on the range and trend of carbon isotope fractionation in the process of methane generation. An improved chemical kinetic model can accurately characterize carbon isotope fractionation during gas generation.

Influence of retained bitumen in oil-prone shales on the chemical and carbon isotopic compositions of natural gases: Implications from pyrolysis experiments

Abstract Retained bitumen in oil-prone source rocks has a significant impact on late gas generation but such influence is still poorly quantified because it is quite difficult to restore the bitumen content retained in a mature source rock. In this study, a suite of artificially-matured samples were prepared from a moderate maturity shale sample to represent shales with different amount of retained bitumen. These samples were then pyrolyzed in sealed gold tubes to investigate how the amount of retained bitumen affects the changes in chemical and carbon isotopic compositions of generated gases, and the uncertainty of the evaluation of gas maturity and source identification. The results indicate that the decrease in yields of hydrocarbon gases is proportional to the reduction of retained bitumen content, however, a progressive enrichment in heavier carbon isotope (13C) of gaseous hydrocarbons occurs while less amount of bitumen is retained in shales. This experimental observation partly explains the heterogeneity of methane carbon isotopes for shale gases that have identical thermal maturity levels. Although the amount of retained bitumen can significantly change the carbon isotopic ratios of individual gas (δ13C1, δ13C2, and δ13C3), the difference in carbon isotopic composition between gaseous components such as ethane and methane (δ13C2 ‒δ13C1) or propane and ethane (δ13C3 ‒δ13C2) are not significantly affected, and therefore these differential values can be potentially used as maturity indicators for overmature natural gases exhibiting no carbon isotopic reversals. Geochemical and carbon isotopic diagrams that are widely used for the identification of oil- and kerogen-cracking gases are also found to be affected by the retained bitumen content. These results illustrate that it is necessary to take into account the retained bitumen content of shales when thermal maturity and genetic origin of natural gases derived from oil-prone source rocks are being evaluated.

Genetic types and origins of natural gases from eastern Fukang Sub-depression of the Junggar Basin, NW China: Implication for low-mature coal-derived gases

Although the Fukang Sub-depression is the largest hydrocarbon generation depression in the Junggar Basin and promises favorable potential for oil and gas exploration, only several small–medium oil/gas accumulations have been discovered so far. After analyzing the molecular and stable carbon isotopic compositions of natural gases and its associated low molecular weight hydrocarbons (LMWHs) from eastern Fukang Sub-depression, their genetic types and origins are discussed in this study. Natural gases are wet gases with an average dryness coefficient of 0.84. Stable carbon isotopes of methane and ethane are well correlated with the thermal evolution trend of coal-derived gases. The C5–7 LMWHs are enriched in methyl cyclohexane but they lack n-alkanes, indicating a predominance of higher plant input. Gases have maturities ranging 0.76%–0.93%Ro and are well consistent with their low n-heptane (H) and iso-heptane (I) contents. The geochemical characteristics of natural gases from eastern Fukang Sub-depression are quite similar with those from the Turpan–Hami Basin. Their gases are considered to be low-mature gases derived from the Lower–Middle Jurassic coal measures. In contrast, they show remarkable differences with those from the Wucaiwan gas field; they are considered to have high-mature gases derived from the Carboniferous coal measures.

Carbon isotopic composition and genetic types of natural gas in the Sichuan Basin, China

The origin and genetic types of natural gas in the Sichuan Basin are still disputed. To classify the origin and genetic types in different areas, the paper analyzes the carbon isotopic composition of gases and geologic features in the Sichuan Basin. The results showed that the gas sourced from terrestrial layers is typically characterized by terrestrial origin and was mainly accumulated nearby to form reservoir. The carbon isotopic composition of gas showed a normal combination sequence distribution, suggesting that natural gas in continental strata is not affected by secondary alteration or that this deformation is very weak. The gas source is singular, and only gas from the southern and northern Sichuan Basin shows the characteristic of mixed sources. However, marine gas presents the characteristics of an oil-formed gas. The carbon isotopic composition of natural gas in the western and central part of the basin mostly distributes in a normal combination sequence, and few of them showed an inversion, indicating that the gas perhaps had not experienced secondary alteration. The carbon isotopic composition of marine-origin gas in the southern, northern and eastern Sichuan Basin displays a completely different distribution pattern, which is probably caused by different mixing ratio of gas with multi-source and multi-period.

Processes involved in the origin and accumulation of hydrocarbon gases in the Yuanba gas field, Sichuan Basin, southwest China

Natural gases in the superimposed Sichuan Basin commonly experienced a history of remigration in marine carbonate reservoirs since the late Cretaceous. The reservoir in the Changxing Formation (P2c) in the Yuanba gas field in the Sichuan Basin is characterized by a great burial depth of 6200–7000 m and a high temperature about 165 °C. The gas dryness is 99.73–99.99%, and δ13C values of methane and ethane are −31.0 to −28.9‰ and −29.9 to −25.6‰, respectively. The chemical and isotopic compositions of natural gases, abundant reservoir solid bitumen, and high reservoir temperature (maximum to 240 °C) indicate that the P2c gases are of sapropelic origin and are derived from oil cracking. The paleo-oil layers, recognized by solid bitumen distribution, were mainly developed in high position traps when the paleo-oil accumulated during the early Jurassic. Reconstructed structural evolution shows the northwest was uplifted sharply and southern part dipped gently to the north in the gas field after oil cracking. Fluid potential analyses based on changes in the structural configuration imply that gas should re-migrate mainly to the northwest. The observations that paleo-oil-water contacts are mainly above the present day gas-water contacts in the northwest traps, and are below present day gas-water contacts in the middle and eastern traps also confirm the gas remigration trend. Currently, high gas production wells are mainly located in northwest traps and in high positions in the middle and eastern traps. Systematic analyses on early paleo-oil accumulation and late gas remigration processes can reduce the economic risks associated with natural gas exploration in the northeastern Sichuan Basin.

Molecular and isotopic compositions and origin of natural gases from Cambrian and Carboniferous-Lower Permian reservoirs of the onshore Polish Baltic region

Natural gases from Middle Cambrian and Carboniferous-Lower Permian reservoirs of the onshore Polish Baltic region were studied for their molecular and stable isotope compositions. The following gas species were analysed: 12,13C in CH4, C2H6, C3H8, n-C4H10, i-C4H10 and CO2, 1,2H in CH4, 14,15N in N2, and stable isotopes of all noble gases. Due to significantly different geological settings and genetic types of source rocks of Eastern and Western Pomerania, the molecular and isotopic compositions of natural gases of these two regions exhibit distinct differences. Hydrocarbon gases associated with oil accumulated in the Middle Cambrian reservoir of Eastern Pomerania were generated during low-temperature thermogenic processes from a single source rock containing Type-II kerogen at one phase of petroleum generation. Non-associated hydrocarbon gases accumulated in the Carboniferous (Mississippian and Pennsylvanian)-Lower Permian (Rotliegend) reservoirs of Western Pomerania originated during at least two phases of gas generation by thermogenic processes from mainly Type-III kerogen and a small component of mixed Type-III/II kerogen. Noble gases are in general heavily enriched in radiogenic and nucleogenic isotopes such as 4He, 40Ar and 21Ne accumulated in the reservoirs. Weak contributions of mantle-derived He and Ne are observed. Radiogenic 4He/40Ar ratios are higher than the average production rate ratio of about 5 for radiogenic 4He/40Ar in crustal materials, which might have been caused by a selective supply of 4He that is lighter than 40Ar from crustal rocks, or (U + Th)/K ratio might be higher than the average in crustal block. Carbon dioxide from gases of both the Western and Eastern Pomerania were mainly generated during thermogenic processes of transformation of organic matter, although gases of Western Pomerania can contain an endogenic component. Molecular nitrogen from the Eastern Pomeranian natural gases was mainly generated during low-temperature thermal transformation of organic matter and derived from NH3 and NH4 of crustal fluid, whereas molecular nitrogen from Western Pomeranian natural gases contains a significant component from the destruction of organic matter at a higher maturity level which may have been caused by a high heat flux from the volcanic activity during late Pennsylvanian–early Rotliegend ages, and has a bigger component release from NH4-rich illites.

Origin and Filling Model of Natural Gas in Jiannan Gas Field, Sichuan Basin, China

The chemical and stable isotopic compositions of natural gases from Jiannan Gas Field, Sichuan Basin, China, were investigated to elucidate the origin of the gas and to reconstruct the reservoir filling history. The natural gases in Jiannan Gas Field are dominated by CH4 with low amounts of non-hydrocarbon (e.g. CO2, H2S and N2) components. The stable carbon isotope compositions of methane and its homologues vary widely, with an isotope trend of δ13C1≥ δ13C2&lt; δ13C3. Structural restoration and burial history reconstruction indicated contrasting gas-filling histories for the gas reservoirs. Natural gas in the Carboniferous reservoirs was sourced from oil and gas cracking and thermal decomposition of kerogen in the lower Silurian shale and sealed by Lower Permian shale. Natural gas in the Upper Permian reservoir was derived primarily from Upper Permian mudstone with a minor contribution from Lower Silurian shale. The sulfur-bearing gas was probably sourced from Permian marine source rocks and migrated into the Lower Triassic reservoirs along unconformities and faults. Long-distance vertial migration may have caused the loss of H2S.

Origin of Marine Sour Natural Gas and Gas-Filling Model in the Puguang Giant Gas Field, Sichuan Basin, China

Taking the geology and tectonic evolution characteristics of the Sichuan Basin into account, the chemical and stable isotopic compositions of natural gas, and biomarker compounds in the reservoir bitumen in the Puguang giant gas field, are investigated to identify the genetic type of marine sour natural gas, take the gas-source correlation, and set up the gas-filling model of the Puguang giant gas field in the Sichuan Basin. The alkane gases in the field are dominated by methane, ranging from 22.06% to 99.64% with an average value of 76.52%, and the low content of heavy hydrocarbon gases are dominantly ethane and little propane. The H2S contents occur among the marine carbonate gas reservoirs, ranging from 0 to 62.17%, wherein the H2S contents in the Upper Permian Changxing Formation and Lower Triassic Feixianguan Formation range from 6.9% to 34.72% (average value=15.27%) and from 0% to 62.17% (average value= 13.4%), respectively, indicating that both are H2S-enriched reservoirs. The chemical and carbon isotopic compositions of marine natural gases show that the alkane gas in the Puguang giant gas field is dominantly oil-cracking gas at high maturity stage, and the biomarker characteristics of reservoir bitumen indicate that the major source rocks are the Upper Permian Longtan Formation sapropelic matters. Moreover, various levels of thermochemical sulfate reduction (TSR) were present in the process of oil-gas transformation, not only increasing the content of non-hydrocarbon gas components (CO2 and H2S) and decreasing the content of heavy hydrocarbon gases, but also causing the reversal of carbon isotope compositions of methane and ethane and the heavier carbon isotope of methane. The recovery of structural configurations over geological time investigates that the gas-filling history of Puguang giant gas field can be divided into three stages: formation of paleo-oil accumulation from the middle-late Indosinian period to the early Yanshanian period, thermal cracking of paleo-oil and TSR alteration from the early to the middle Yanshanian period, and adjustment of gas accumulation from the late Yanshanian to the early Himalayan period. The gypsum of the Lower Triassic Jianglingjiang Formation and the Middle Triassic Leikoupo Formation plays the most important role as effective seal to the gas preservation in different periods.

Natural gas constituent and carbon isotopic composition in petroliferous basins, China

There are abundant gas resources in petroliferous basins of China. Large to midsize gas fields are found in Eastern, central and Western of China. However, origin, constituents and isotopic composition of natural gas in different gas fields are varied distinctly, and some present strong chemical secondary alteration and show variation both in age and space. Based on the systematic analysis of constituents and carbon isotope of a large number of gas samples, combined with the geological characteristics, this paper classifies the origins of the gases, explores the gas isotope characteristics and evolutionary regulation with the variation time and space, and further discusses the distinctive geochemistry of the gases in China. These gases are dominated by dry gas, its methane carbon isotope values range from −10‰ to −70‰, ethane from −16‰ to −52‰, propane from −13‰ to −43‰, and butane from −18‰ to −34‰. The carbon isotopes of most gases show the characteristics of humic-derived gas and crude oil cracked gas. In addition, large primary biogenic gas fields have been discovered in the Qaidam basin; inorganic-derived alkane gases have been discovered in deep of the Songliao Basin. Half of these gas fields are characterized by the alkane carbon isotope reversal in different degrees. Research indicates there are several reasons can result in carbon isotope reversal. Firstly, gas charge of different genetic types or different source in one gas reservoir may cause carbon isotope reversal. Besides, high-over mature evolution of gas can also lead to the carbon isotopic reversal of alkanes. Thirdly, secondary alteration of hydrocarbons may also result in abnormal distribution of carbon isotope, isotope transforms to unusual light and heavy.

Origin of marine sour natural gas and gas-filling model for the Wolonghe Gas Field, Sichuan Basin, China

The chemical and isotopic composition of natural gases from the Wolonghe Gas Field, Sichuan Basin, Southwest China, was investigated to assess the potential gas sources and reconstruct the gas-filling history of the reservoirs. All natural gases in this field are dominated by gaseous hydrocarbons (C1–C3) with varied amounts of non-hydrocarbon components (CO2, H2S and N2). The H2S content varies with reservoir intervals. It ranges from zero to 1.84% with an average of 0.37% in the Carboniferous reservoir, from 0.05% to 0.76% with an average of 0.30% in the Permian reservoir, and from 1.09% to 18.83% with an average of 5.39% in the Lower Triassic reservoir. The gas dryness coefficient (C1/C1–3) ranges from 0.97 to 1.0 with an average of 0.99. The carbon isotopic compositions of methane and its homologues in the Wolonghe Gas Field vary widely, with δ13C1⩾δ13C2<δ13C3 in the Carboniferous and Permian gas reservoirs, and δ13C1<δ13C2<δ13C3 in the Lower Triassic Jialingjiang Formation gas reservoirs. The δD1 values range from −140‰ to −100‰, with an average of −124.5‰. The δ34SH2S values in the field extend from 5.7‰ to 31.0‰, with δ34SH2S values in the Lower Triassic Jialingjiang Formation reservoirs being much higher than those in the Carboniferous and Permian reservoirs. The sour natural gases in the field originated from cracking of oil and were sourced from the marine sapropelic organic matter at high maturity levels. The natural gases underwent alteration by thermochemical sulfate reduction (TSR). Although the limited extent TSR occurred in the Carboniferous and Permian gas reservoirs, the TSR alteration is likely to have caused the high gas dryness and the 13C enrichment of CH4. The present low content of H2S in the Carboniferous and Permian gases would be related to the loss of H2S dissolved in water under the reconstruction of these gas reservoirs. In contrast, the high H2S in the Jialingjiang Formation gases is determined by both the favorable TSR conditions in the Lower Triassic reservoirs and the favorable preservation conditions provided by the Lower-Middle Triassic gypsum.The Wolonghe natural gas system is characterized by multi-pay zones, multi-source supply and multi-type layers. The gas generated from Silurian source rocks migrated into the Carboniferous reservoir through faults and fractures and was trapped beneath the Permian Liangshan Formation shale, whereas the natural gas in the Permian and Lower Triassic Jialingjiang Formation was generated and preserved in its own formations with the overlying gypsum acting as a cap rock.

Water Role and Its Influence on Hydrogen Isotopic Composition of Natural Gas during Gas Generation

Abstract:In order to discuss the role and influence of water during the generation of natural gas, the participation mechanism of water during the evolution of organic matter and its influences were summarized. In addition, we carried out an anhydrous cracking experiment of oil extracted from the Feixianguan Formation source rock in a closed system, which led to the establishment of the kinetic models for describing carbon and hydrogen isotopic fractionation during gas generation from organic matter. The models were calibrated and then applied to the northeastern Sichuan Basin. By combining a series of gas generation experiments from octadecane pyrolysis without water or with distilled water in varying mass proportions, several results were proved: (1) the hydrogen isotopic composition of natural gas becomes lighter with the participation of formation water; (2) we can quantitatively study the hydrogen isotopic fractionation with the kinetic model for describing carbon isotopic fractionation; (3) more abundant and reliable geological information can be obtained through the combined application of carbon and hydrogen isotopic indices.

Water Role and Its Influence on Hydrogen Isotopic Composition of Natural Gas during Gas Generation

Water Role and Its Influence on Hydrogen Isotopic Composition of Natural Gas during Gas Generation