Origin Of Natural Gas Research Articles

Geochemical characteristics and origin of natural gas from Wufeng-Longmaxi shales of the Fuling gas field, Sichuan Basin (China)

As the first giant shale gas field in China, the Fuling gas field has recently been regarded as one of the most important regions for natural gas exploration and production in the Sichuan Basin. However, the origin of natural gas from Upper Ordovician Wufeng and the bottom of Lower Silurian Longmaxi (WL) shales in the Fuling gas field is poorly understood to limit a comprehensive understanding of gas generation, accumulation and exploration.In this work, based on molecular and stable carbon isotopic composition of a total of 24 gas samples from five shale gas wells in the Fuling field, we analyzed the geochemical characteristics and gas origin, and discussed the cause for the geochemical anomalies (carbon isotopic reversals). Molecular composition results show that gases from the Fuling gas field are dry and mainly composed of methane (97.9–98.9%), with a very low level of ethane (C2H6), propane (C3H8) and non-hydrocarbon gases (mainly CO2 and N2). These dry gases are classified as oil-associated gas and mainly derived from secondary cracking. Due to the lack of gas samples across a maturation gradient from immature to late mature, the WL gases in the Fuling field show an unclear evolution trend between the δ13C2 and wetness values; however, all these samples are located in the isotopic reversal zone. Carbon isotopes of gaseous alkanes clearly display full isotopic reversals (δ13C1>δ13C2>δ13C3), which is indicative of a relatively high thermal maturity and consistent with the measured vitrinite reflectance and modeled values (~3.0% Ro). The observed complete carbon isotopic reversals in the WL gases are caused by a combination of several mechanisms, in which isotope exchange at high temperature is the primary controlling factor. Other secondary factors include Rayleigh-type fractionation of C2H6 and C3H8, secondary cracking and gas diffusion mixing of gases at different thermal maturity levels.

Geochemical characteristics and origin of natural gas in the Dongping–Niudong areas, Qaidam Basin, China

The geochemical characteristics, origin, and source of natural gas in the Dongping–Niudong areas are researched based on the information of components and the stable carbon isotopes of natural gas. The main component of hydrocarbon gas is methane, and C2+ possesses a relatively low content that ranges from 0.5% to 6.5%. The dryness coefficient of the Dongping area is more than 0.97, which categorizes as dry gas. The dryness coefficient of the Niudong area ranges from 90.3% to 98.1%, whilst having the characteristics of dry gas coexisting with wet gas. The δ13C1 dryness coefficient varies from −17.58‰ to −36.4‰, and δ13C2 is greater than −29‰. The gas of the Dongping 3 block has the characteristics of an abiogenic gas such as the reversed carbon isotope series. The combination of the relationship between the component of CO2 and δCCO213 and the background of development of hydrocarbon-generating sag, suggests that it is coal-derived gas. The RO and fluid inclusion studies show that the gas in Niudong area is mainly derived from Early Jurassic coal-measure source rocks of Kunteyi Sag, and there are two periods of hydrocarbon fillings. The first filling is mainly oil, and the second is mainly high mature gas; gas in Dongping area is mainly derived from Early Jurassic coal-measure source rocks of Pingdong–Yiliping Sag, and there are four periods of high-over mature gas fillings. The phenomenon of reversed carbon isotope series in Dongping area resulted from the multiple gas charging.

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.

Further discussion about the origin of natural gas in the Sinian of central Sichuan paleo-uplift, Sichuan Basin, China

The origin of Sinian natural gas in the paleo-uplift in the central Sichuan is controversial. The major geo-chemical evidence to prove the gas origin was studied again, and it indicates that: the relationship of the Cambrian and Sinian ethane carbon isotope and ethane content complies with the Rayleigh distillation model, hence, the differences in the δ13C2 was not due to the different parent materials. As for the Sinian methane, the δD1 abnormally decreases with the increase of the δ13C1. This can be caused by the isotopic exchange with the formation water at an extremely high maturation stage rather than the different water salinities of depositional environment of their source rocks. Meanwhile, for the Sinian bitumen, the alkyldibenzothiophene molecular ratios 4-/1-MDBT is higher in the southwest and lower in the northeast, showing the hydrocarbon laterally migrated from the aulacogen Cambrian Qiongzhusi shale. The C7 light hydrocarbon was dominated by methylcyclohexane and a lack of toluene, demonstrating that the gas is from oil cracking instead of carbonate source rock. Therefore, the point that there is significant contribution from the Sinian source rock lacks evidence at present, and the major contribution of the Sinian gas is from the aulacogen of the Cambrian shale.

The origin of gas in the Changxing–Feixianguan gas pools in the Longgang gas field in the Sichuan Basin, China

In this paper, the origin of natural gas in the formations of the Changxing–Feixianguan within the Longgang gas field was studied in detail using geochemical methods. The gas discovered has a very high dryness coefficient, yet low ethane and other less heavy hydrocarbons content. Apart from a small amount of N2 and CO2 gasses it generally contains H2S. In the field location, the Changxing–Feixianguan formations itself does not have a hydrocarbon generation potential. Nearing the edge of the Kaijiang-Liangping Trough, there developed the Dalong Formation. However, it also has a very low TOC content in the area of the Longgang gas field, and it cannot act as an effective source rock. The geochemistry of natural gas is much different from the gasses generated by the Silurian and Cambrian source rocks. Therefore, it is impossible that the gas in the Longgang gas field is from the Silurian and Cambrian source rocks. Gas reservoirs generally contain bitumen which is considered a product of crude oil cracking. The carbon isotope fractionation between the bitumen and methane is not distinct, and it indicates that the gas is not directly from oil cracking. The carbon of methane and ethane has isotopically less negative value, which is considered to be in a high-overmature coal-formed gas, mainly from the Longtan Formation coal measures. In comparison to the gas from high overmature stage obtained from the Xujiahe coal measure source rock in the Western Sichuan Depression. The methane in the Longgang gas field has abnormal less negative carbon isotopic value. It is due to the superposition of these two factors together: higher evolution of source rocks and mixing of gas degassing from the water. It is not caused by TSR that most researchers believed at present because the methane carbon isotopic values have no relationship with H2S content.

Sourcing methane and carbon dioxide emissions from a small city: Influence of natural gas leakage and combustion

Natural gas leakage and combustion are major sources of methane (CH4) and carbon dioxide (CO2), respectively; however, our understanding of emissions from cities is limited. We mapped distribution pipeline leakage using a mobile CH4 detection system, and continuously monitored atmospheric CO2 and CH4 concentrations and carbon isotopes (δ13C-CO2 and δ13C-CH4) for one-year above Ithaca, New York. Pipeline leakage rates were low (<0.39 leaks mile−1), likely due to the small extent of cast iron and bare steel within the distribution pipeline system (2.6%). Our atmospheric monitoring demonstrated that the isotopic composition of locally emitted CO2 approached the δ13C range of natural gas combustion in winter, correlating to natural gas power generation patterns at Cornell's Combined Heat and Power Plant located 600 m southeast of the monitoring site. Atmospheric CH4 plumes were primarily of natural gas origin, were observed intermittently throughout the year, and were most frequent in winter and spring. No correlations between the timing of atmospheric natural gas CH4 plumes and Cornell Plant gas use patterns could be drawn. However, elevated CH4 and CO2 concentrations were observed coincident with high winds from the southeast, and the plant is the only major emission source in that wind sector. Our results demonstrate pipeline leakage rates are low in cities with a low extent of leak prone pipe, and natural gas power facilities may be an important source of urban and suburban emissions.

Geochemistry and origin of natural gas in the petroliferous Mahu sag, northwestern Junggar Basin, NW China: Carboniferous marine and Permian lacustrine gas systems

The Mahu sag, located in the northwestern Junggar Basin of NW China, is a renowned Carboniferous marine–Permian lacustrine hydrocarbon depocenter that in theory could host both oil and gas. However, as ongoing hydrocarbon exploration and production are focused solely on oil, few gas prospects have been discovered. In this paper, we discuss the possible occurrence of natural gas deposits, based on a comprehensive study of gas geochemistry, including gas composition, carbon isotopes and compositions of light hydrocarbons (C5–C7), and biomarkers in retrograde condensates, combined with geological information available for the study area. Our results indicate that three types of natural gas occur in the region: a sapropelic-type gas derived from the lower Permian Fengcheng Formation (P1f), a humic-type gas sourced from Carboniferous strata (C) and the overlying lower Permian Jiamuhe Formation (P1j), and a humic-type gas derived from the middle Permian Lower Wuerhe Formation (P2w). The P1f-sourced sapropelic-type gas accumulated during at least two distinct periods of time, yielding low maturity oil-associated gases and mature to high-maturity kerogen/oil-cracking gases. The Carboniferous and P1j-sourced humic-type gases are mainly high-maturity to over-mature kerogen/oil-cracking gases, without obvious geochemical evidence for a multi-stage accumulation. The P2w-sourced gas is a mature humic-type gas. Of these three types of gas, the former two have the potential to form significant gas deposits and constitute valid exploration targets, making the Mahu sag a prospective area for gas exploration. Favorable areas for gas occurrence include deep anticlines hosting both kerogen- and oil-cracking gases. The inferred exploration targets occur at significant depths, which is why little drilling has been undertaken in these areas and major gas discoveries have yet to be made.

Lower Paleozoic source rocks and natural gas origins in Ordos Basin, NW China

Abstract Based on the geochemical characteristics of Lower Paleozoic gases from 154 most recently drilled wells and their genetic type, in combination with the organic abundance evaluation of 733 core samples from the Lower Paleozoic, the origin of Lower Paleozoic gases in Ordos Basin was discussed. According to the carbon isotope data of paraffin gases in the gas samples and the geological background, the Lower Paleozoic gases are divided into three types and four sub-types: (1) the coal-derived gas generated from the Upper Paleozoic coaly source rock; (2) the oil-associated gas sourced from the Lower Paleozoic source rock, and (3) the mixing gas originated from the Upper Paleozoic coaly source rock and Paleozoic limestone, and the mixing gas can be divided into two sub-types, the mixing gas of positive carbon isotopic series and that of negative carbon isotopic series. From the TOC and organic maceral results of Lower Paleozoic source rock, the samples below salt have an average TOC of 0.3%, with 28.2% of them having TOC>0.4%, the kerogen type being sapropel type, showing great gas generating potential. The Lower Paleozoic gases are primarily coal-derived gas generated from the Upper Paleozoic coal, some oil-associated gas of self-source and self-reservoir can be found in pre-salt reservoirs in the central-eastern basin, where the developed source rock can serve as the source of some Lower Paleozoic gas.

Geochemical characteristics and genetic types of natural gas in the Changxing-Feixianguan Formations from the Yuanba Gas Field in the Sichuan Basin, China

The Yuanba Gas Field is a large gas field in the marine strata with the largest burial depth in China up to date. The studies performed on the mentioned gas field have achieved significant progress made possible by determining the characteristics of reef flat reservoirs in the marine strata and the main controlling factors of hydrocarbon accumulation. However, there is no consensus on the origin of natural gases stored in the reservoir in the Changxing-Feixianguan Formations in the Yuanba and its adjacent area. The study on geochemical characteristics indicates that natural gases in the reservoir in the Changxing-Feixianguan Formations in the Yuanba Gas Field are mainly composed of alkane gases which are dominated by methane with dryness coefficients generally higher than 0.995. The CO2 and H2S display an average content of 8.55% and 6.47%, respectively. The δ13C1 and δ13C2 values are from −31.2‰ to −27.9‰, and from −29.9‰ to −25.0‰, respectively, displaying the positive carbon isotopic series. The δ13CCO2 values are generally higher than −8‰, and the δD1 values are from −156‰ to −107‰. The identification of gas origin and gas–source correlation indicate that the natural gases reservoired in the Changxing-Feixianguan Formations in the Yuanba Gas Field have been altered by thermochemical sulfate reduction, and they are mainly composed of oil cracking gases derived from the secondary cracking of oil generated by the sapropelic-prone source rocks in the Permian Longtan Formation. The CO2 in the gas pools are mainly inorganic and were derived from the interaction between the acidic fluid and carbonate reservoirs.

Origins of natural gas and the main controlling factors of gas accumulation in the Middle Ordovician assemblages in Jingxi area, Ordos Basin

During the progressive exploration of the Jingbian Gas Field in the Ordos Basin, multiple gas-bearing regions have been discovered in the dolomite reservoirs in the Middle Ordovician assemblages of Lower Paleozoic in Jingxi area, but these gas-bearing regions and intervals are significantly different in terms of gas enrichment degrees. So far, however, the reasons for the difference have not been figured out. In this paper, the origin and source of natural gas in the Middle Ordovician assemblages in Jingxi area was investigated on the basis of geochemical data (e.g. natural gas composition and carbon isotope), and then the main factors controlling the gas accumulation were analyzed. It is shown that the natural gas in the Middle Ordovician assemblages in the Middle Ordovician assemblages in Jingxi area is similar to that in the Upper Ordovician assemblages and Upper Paleozoic reservoir in terms of genesis and sources, and they are mainly the Upper Paleozoic coaliferous gas with some oil-derived gas. Under the influence of hydrocarbon generation center of coal source rocks and the source–rock–reservoir contact relationship, the proportion of coaliferous gas increases areally from the north to the south and vertically from Ma55 sub-member of the Lower Ordovician Majiagou Fm. It is concluded that the natural gas enrichment degree is controlled by the gas charging capacity at the hydrocarbon-supplying windows. Second, the vertical migration and distribution of natural gas is dominated by the differences of Ma55−Ma510 transport pathways. And third, the lateral migration direction of natural gas and the range of gas accumulation are controlled by the superimposition relationship between structures and reservoirs.

Geochemistry and origin of natural gas in the eastern Junggar Basin, NW China

The eastern Junggar Basin in NW China is an important region for natural gas exploration with the giant Kelameili Gas Field having been discovered. However, the origin of gas in the region is unclear, which limits the understanding of gas formation and accumulation, as well as the planning of exploration strategies. Here, we address the origin of gas in this region through a comprehensive investigation of gas geochemistry in the context of geological setting, including gas chemical compositions, carbon isotopes and light hydrocarbons and biomarkers of retrograde condensates. Results show that four main types of natural gases were identified: (1) highly mature to post-mature humic-type gas sourced from Carboniferous rocks with Type III kerogen, (2) mature to highly mature humic-type gas sourced from Permian rocks with Type III kerogen, (3) mature to highly mature sapropelic-type gas sourced from Permian rocks with Type I–II kerogen, and (4) microbial gas sourced from Permian rocks with Type II–III kerogen. These gases vary significantly in geochemistry, and thus can be easily identified. The distribution of the gases follows the “source-controlled” principle in that it is controlled by the distribution and maturity of hydrocarbon source rocks. As such, the gases sourced from the Carboniferous and Permian rocks are the most viable exploration targets, with the areas in and surrounding the hydrocarbon-generation centers being favorable for exploration. These results also provide guidance to natural gas exploration and research in other basins with similar geological settings.

Geochemistry, origin and accumulation of natural gases in the deepwater area of the Qiongdongnan Basin, South China Sea

The Qiongdongnan Basin, South China Sea has received huge thickness (>12 km) of Tertiary-Quaternary sediments in the deepwater area to which great attention has been paid due to the recent discoveries of the SS22-1 and the SS17-2 commercial gas fields in the Pliocene-Upper Miocene submarine canyon system with water depth over 1300 m. In this study, the geochemistry, origin and accumulation models of these gases were investigated. The results reveal that the gases are predominated by hydrocarbon gases (98%–99% by volume), with the ratio of C1/C1-5 ranging from 0.92 to 0.94, and they are characterized by relatively heavy δ13C1 (−36.8‰ to −39.4‰) and δDCH4 values (−144‰ to −147‰), similar to the thermogenic gases discovered in the shallow water area of the basin. The C5-7 light hydrocarbons associated with these gases are dominated by isoparaffins (35%–65%), implying an origin from higher plants. For the associated condensates, carbon isotopic compositions and high abundance of oleanane and presence of bicadinanes show close affinity with those from the YC13-1 gas field in the shallow water area. All these geochemical characteristics correlate well with those found in the shales of the Oligocene Yacheng Formation in the Qiongdongnan Basin. The Yacheng Formation in the deepwater area has TOC values in the range of 0.4–21% and contains type IIb–III gas-prone kerogens, indicating an excellent gas source rock. The kinetic modeling results show that the δ13C1 values of the gas generated from the Yacheng source rock since 3 or 4 Ma are well matched with those of the reservoir gases, indicating that the gas pool is young and likely formed after 4 Ma. The geologic and geochemical data show that the mud diapirs and faults provide the main pathways for the upward migration of gases from the deep gas kitchen into the shallow, normally pressured reservoirs, and that the deep overpressure is the key driving force for the vertical and lateral migration of gas. This gas migration pattern implies that the South Low Uplift and the No.2 Fault zone near the deepwater area are also favorable for gas accumulation because they are located in the pathway of gas migration, and therefore more attention should be paid to them in the future.

Features and origin of natural gas in the Sinian–Cambrian of central Sichuan paleo-uplift, Sichuan Basin, SW China

Abstract Based on the new drilling data and field outcrop data of the Gaoshiti–Moxi area, the geochemical characteristics of the Sinian-Cambrian natural gas are studied and analyzed, including gas composition, isotope, light hydrocarbon, kerogen carbon isotope and reservoir bitumen biomarkers etc. The results show that: (1) The natural gases of the Sinian Dengying Formation and Cambrian Longwangmiao Formation, mainly composed of hydrocarbon gas, are typical dry gas. However, the natural gas of the Dengying Formation is characterized by higher dry coefficient, lower content of hydrocarbon gas and higher content of non-hydrocarbon gas. The main differences in non-hydrocarbon gases are the contents of N 2 , CO 2 , H 2 S and He, the small composition differences between the natural gas of Dengying Formation and that of Longwangmiao Formation are mainly caused by maturity differences of source rocks and H 2 S generated by reaction between sulfide mineral and hydrocarbons. (2) There are obvious differences in δ 13 C 2 between the natural gases in Dengying Formation and Longwangmiao Formation, showing different parent materials of them. (3) There are large differences in δ 2 H between the natural gases of Dengying Formation and Longwangmiao Formation, showing the different water salinities of their source rock depositional environment. (4) The average kerogen carbon isotope values of the Lower Cambrian shale, Dengying Formation mudstone, Doushantuo Formation mudstone and Dengying Formation carbonates are −32.8‰, −31.9‰, −30.7‰ and −27.8‰ respectively. (5) The ratio of 4-methyl dibenzothiophene to 1-methyl dibenzothiophene of Dengying Formation bitumen is between that of Qiongzhusi Formation and Dengying Formation source rocks. It is believed that the Sinian-Cambrian natural gas in the Gaoshiti-Moxi area is mainly oil cracking gas, the Sinian natural gases come from the Sinian and Cambrian source rocks, and the Cambrian natural gases mainly come from Cambrian source rock.

Geology and hydrocarbon accumulations in the deepwater of the northwestern South China Sea—with focus on natural gas

The deepwater of the northwestern South China Sea is located in the central to southern parts of the Qiongdongnan Basin (QDN Basin), which is a key site for hydrocarbon exploration in recent years. In this study, the authors did a comprehensive analysis of gravity-magnetic data, extensive 3D seismic survey, cores and cuttings, paleontology and geochemical indexes, proposed the mechanism of natural gas origin, identified different oil and gas systems, and established the model of hydrocarbon accumulations in the deep-water region. Our basin tectonic simulation indicates that the evolution of QDN Basin was controlled by multiple-phased tectonic movements, such as Indochina-Eurasian Plate collision, Tibetan Uplift, Red River faulting and the expansion of the South China Sea which is characterized by Paleogene rifting, Neogene depression, and Eocene intensive faulting and lacustrine deposits. The drilling results show that this region is dominated by marineterrestrial transitional and neritic-bathyal facies from the early Oligocene. The Yacheng Formation of the early Oligocene is rich in organic matter and a main gas-source rock. According to the geological-geochemical data from the latest drilling wells, Lingshui, Baodao, Changchang Sags have good hydrocarbon-generating potentials, where two plays from the Paleogene and Neogene reservoirs were developed. Those reservoirs occur in central canyon structural-lithologic trap zone, Changchang marginal trap zone and southern fault terrace of Baodao Sag. Among them, the central canyon trap zone has a great potential for exploration because the various reservoirforming elements are well developed, i.e., good coal-measure source rocks, sufficient reservoirs from the Neogene turbidity sandstone and submarine fan, faults connecting source rock and reservoirs, effective vertical migration, late stage aggregation and favorable structural–lithological composite trapping. These study results provide an important scientific basis for hydrocarbon exploration in this region, evidenced by the recent discovery of the significant commercial LS-A gas field in the central canyon of the Lingshui Sag.

Origin of natural gases in the Permo-Triassic reservoirs of the Coastal Fars and Iranian sector of the Persian Gulf

The Coastal Fars and the Iranian part of the Persian Gulf are one of the largest natural gas provinces in Iran. More than 90 percent of the natural gases in these areas are found in Dalan (Upper Permian) and Kangan (Lower Triassic) carbonate rocks. In order to determine the origin of the natural gas in Iranian sector of Persian Gulf and Coastal Fars area, we collated 23 gas samples (7 samples from Kangan Fm. 12 samples from Upper Dalan and 4 samples from Lower Dalan) from 12 gas fields in the study area and analyzed chemical and isotopic composition. Based on molecular composition and isotope data, gas samples in the study area have the thermogenic origin. In the lower part of Dalan Formation, evidence of secondary process like thermochemical reduction of sulfate (TSR) is seen. The main part of hydrocarbon gases was generated during secondary cracking of paleo-oil in these reservoirs. Based on this study, lower Silurian organic-rich shales (Sarchahan Formation) with the 1–1.8 vitrinite reflectance, is the main source for the natural gas of southern Iran.

Fracturing and Natural Gas in Groundwater: Is There a Connection?

Beyond the Headlines Editor’s note: Professionals in the oil and gas industry often receive questions about how industry operations affect public health, the environment, and the communities in which they operate. Of particular concern today is the impact of hydraulic fracturing on the environment. In this column, JPT invites energy experts to put those questions and concerns about industry operations into perspective. Additional information about the oil and gas industry, how it affects society, and how to explain industry operations and practices to the general public is available on SPE’s Energy4me website. Anyone who has watched films such as Gasland and Promised Land is aware of the alleged dire consequences to groundwater resources from the petroleum industry’s decades-old practice of hydraulic fracturing of tight formations to release hydrocarbons. Gasland (a “documentary”) and Promised Land (a movie starring Matt Damon) purport to expose such threats, which are highlighted in the form of natural gas discharging from groundwater or flares from the kitchen faucets of landowners whose water wells are located near fields with recently fractured wells. Such representations are intended to create the impression that fracturing opens pathways from deeply buried strata for the migration of natural gas, brine, and drilling fluids to shallow formations that are sources of groundwater for cities and rural areas where fracturing is a common method for oil and gas extraction. The print and broadcast media are complicit in the matter, as both have piled on to fan the sentiment of Americans against this method of developing much needed natural gas resources. A consequence of antifracturing films and reporting is confusion among the public and attempts by environmentalists to ban fracturing. Origins of Natural Gas Natural gas is derived from different sources. Most of what we think of as natural gas is produced within the deep subsurface under high- temperature and high-pressure conditions (thermogenic gas). A much smaller component is derived from the production of gas in the shallow subsurface under lowtemperature and low-pressure environments (biogenic gas, that is, coal beds, swampy environments, and landfills). Geochemists can differentiate between thermogenic and biogenic gases by looking at their carbon compositions (as illustrated by gas chromatographs) and their carbon and hydrogen isotope signatures. This column focuses on the role of gas chromatography as a differentiator of biogenic and thermogenic gases. Carbon and hydrogen isotope ratios will be the subject of another column. Gas Chromatography Because of the different environments in which natural gases are generated, thermogenic gases and biogenic gases can be expected to have distinct compositions. All hydrocarbons are carbonbased compounds with the number of carbon atoms of the components ranging from one to as many as 30 (C1 to C30). For our purposes, we are interested only in those components with one to six (C1 to C6) carbon atoms, which are methane through hexane, respectively. Biogenic gases are primarily methane (C1) and very little ethane (C2) and, in some cases, propane (C3), with methane usually accounting for 99% or more of total gas. Thermogenic gas consists of measurable components of fractions heavier than methane (that is, C2 through C6 gases). The difference between thermogenic and biogenic gases is illustrated in Fig. 1, which shows the composition of the gas samples collected from the groundwater of the Wilcox aquifer and produced-gas samples from nearby fractured wells that were thought to have been the source of natural gas in the aquifer, approximately 10 miles north of Shreveport (Caddo Parish), Louisiana. The figure shows the percentage (by mass) of each hydrocarbon and nonhydrocarbon gases detected in the samples.

Hydrogen isotope characteristics of thermogenic methane in Chinese sedimentary basins

The hydrogen isotope composition of methane is an important parameter in natural gas research and provides complementary information to that provided by carbon isotopes. The stable hydrogen isotope ratios of 313 natural gas samples from six of China’s sedimentary basins are used to evaluate the factors that influence the stable hydrogen isotopic composition of methane. An important factor is the δD of organic matter in hydrocarbon source rocks, which is influenced by the sedimentary environment and type of organic matter. Natural gases generated from sapropelic organic matter have relatively less negative δDCH4, while natural gases generated from humic organic matter have relatively more negative δDCH4. The other factor is thermal maturity. Increased thermal maturity leads to δDCH4 becoming less negative and there exists a two stage linear relationship between the δDCH4 and the logarithm of the vitrinite reflectance (Ro) value for natural gases generated from type III kerogen. The third factor is the environmental conditions of the aqueous medium in the original depositional environment and after sedimentation. Elemental hydrogen from water participates in biochemical processes as organisms grow and is exchanged during the sedimentation and diagenesis of organic matter as well as maturity process of kerogen to generate gases. The influence of the aqueous medium on δDCH4 after formation of natural gases can be ignored. Among these factors, the aqueous medium is the key constraining factor. The δDCH4 in natural gases can be combined with the use of stable carbon isotopic composition to identify the origins of natural gases and to aid gas-source correlations.

Development of new method of δ13C measurement for trace hydrocarbons in natural gas using solid phase micro-extraction coupled to gas chromatography isotope ratio mass spectrometry

Compound specific isotope analysis (CSIA) of normal-level hydrocarbons (C1–C4) in natural gas is often successfully used in natural gas origin identification and classification, but little progress so far has been made for trace level hydrocarbons (C5–C14) in natural gas. In this study, we developed a method for rapid analysis of carbon isotopic ratios for trace hydrocarbons in natural gas samples. This method can be described as a combined approach characterized by solid phase micro-extraction (SPME) technique coupled to gas chromatography isotope ratio mass spectrometry (GC/IRMS). In this study, the CAR–PDMS fiber was chosen as the SPME adsorptive material after comparative experiments with other four fibers, and the parameters, including equilibration time, extraction temperature and desorption time, for efficient extraction of trace hydrocarbons were systematically optimized. The results showed the carbon isotopic fractionation was not observed as a function of equilibration time and extraction temperature. And the δ13C signatures determined by SPME-GC/IRMS were in good agreement with the known δ13C values of C5–C14 measured by GC–IRMS, and the accuracy is generally within ±0.5‰. Five natural gas samples were analyzed using this method, and the δ13C values for C5–C14 components were obtained with satisfied repeatability. The SPME-GC/IRMS approach fitted with CAR–PDMS fiber is well suited for the preconcentration of trace hydrocarbons and provides so far the most reliable carbon isotopic analysis for trace compounds in natural gas.

The Research of Origin of Deep Natural Gas of Qianbei Sub-Sag in the South of Songliao Basin

This paper analyses the origins of deep natural gas in Qianbei Subsag using a variety of analytical data such as the natural gas components, the isotope and the light hydrocarbon analysis combining with the development characteristics of hydrocarbon source rocks. The study results show as the following: The abundance of organic matter from hydrocarbon source rocks in Qianbei Subsag is high and dominated by humus type. Part of good hydrocarbon source rocks of Type II1 and Type II2 are developed in Yingcheng Formation and these are the major gas source rocks that is in the stage of postmaturity in evolution degree. The natural gas component is dominated by methane and non-hydrocarbon gas content is low. The isotope values of ethane are lighter and methane and ethane have an obvious phenomenon of carbon isotopic reversal. Parent material types of methane and ethane are from different sources. The sources of methane are biased to humic parent material while the sources of ethane are biased to sapropelic parent material.

Geochemical characteristics and origin of Sinian-Lower Paleozoic natural gas in the Sichuan Basin

The composition and isotopic values of natural gas in the Sinian Dengying Fm, Cambrian Qiongzhusi Fm, Longwangmiao Fm and Xixiangchi Fm in the Sichuan Basin exhibit different features in different tectonic position, causing controversy over its origin and sources. The geochemical features of the natural gases in this area were compared based on previous research results and large amounts of drilling data of new exploration wells. The results show: (1) The natural gas is typical dry gas on the whole, with hydrocarbon gas in dominance, and a methane content of 74.85%–97.35%, mostly 83.0%–96.0%; due to different clay contents in source rocks, the difference in non-hydrocarbon gas mainly lies in N2 and He content, with gas in Weiyuan and Ziyang areas having high contents of N2 and He, while gas in Gaoshiti and Moxi areas having low N2 and He. (2) Natural gases in different regions differ greatly in carbon isotope value (δ13C1 and δ13C2). The δ13C1 of natural gas in Cambrian system of Ziyang area is the lightest, from −38.0‰ to −35.5‰, and that in other regions is from −33.9‰ to −32.0‰, indicating different capture stages of natural gases. For example, gas captured in early stage is relatively light in carbon isotope; the carbon isotope value (δ13C2) of gas from Sinian and Cambrian system in Weiyuan is from −36.5‰ to −32.7‰; that from the Longwangmiao Fm in Gaoshiti and Moxi is from −33.6‰ to −31.8‰, but that in the Dengying Fm in Gaoshiti-Moxi area is from −29.1‰ to −26.8‰, quite different from the above natural gases, which mainly shows the differences in kerogen types. (3) Light hydrocarbons of C6–C7 mainly consist of cyclanes and isomerization alkanes, which is the feature of oil cracking gas.