Carbon isotope compositional development of hydrocarbon gases during closed system MSSV pyrolysis of heather and draupne formation source rocks

1998 ◽  
Vol 43 (S1) ◽  
pp. 37-37
Author(s):  
M. Erdmann ◽  
B. Cramer ◽  
B. Horsfield
Keyword(s):  
Carbon Isotope ◽  
Closed System ◽  
Source Rocks ◽  
Hydrocarbon Gases

scholarly journals Origin of the hydrate bound gases in the Juhugeng Sag, Muli Basin, Tibetan Plateau

2019 ◽  
Vol 7 (1) ◽  
pp. 43-57
Author(s):  
Shiming Liu ◽  
Furong Tan ◽  
Ting Huo ◽  
Shuheng Tang ◽  
Weixiao Zhao ◽  
...  
Keyword(s):  
Tibetan Plateau ◽  
Carbon Isotope ◽  
Gas Hydrates ◽  
Gas Hydrate ◽  
Middle Jurassic ◽  
Vitrinite Reflectance ◽  
Surface Mining ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Gases

AbstractThe Juhugeng Sag, located in northwest of the Muli Basin, Tibetan Plateau, has been investigated for coal and petroleum resources during the past several decades. There have been successful recoveries of gas hydrates during recent years from the Middle Jurassic Yaojie Formation that offer insight into the origin of the hydrocarbon gases from the complex sag feature. This study examines the organic geochemical and stable carbon isotopic characteristics of shale and coal samples from the Middle Jurassic Yaojie Formation of the Juhugeng Sag, as well as compares with carbon isotopes, gas amounts and components of hydrate-bound gas. A total of 19 samples from surface mining, including 12 samples of black shale and 7 samples of coal, were analysed using a micro-photometer, a gas chromatograph, Rock–Eval and isotope methods. All the shale samples contained 100% type I kerogen, and the random vitrinite reflectance values vary from 0.65% to 1.32% and achieve thermal pyrolysis phase. Isotope values of methane (δ13C ranging from − 52.6‰ to − 39.5‰ and δD ranging from − 285‰ to − 227‰) in the hydrate bound gases suggest that the methane originates mainly from thermogenic contributions. It is proposed that ethane from the gas hydrate is thermogenic-produced, and this conjecture is supported by the fact that most of the gas hydrate also contains more than 30% of thermogenic C2+ hydrocarbons and is similar to structure II hydrate. Carbon isotope data from the gas hydrates show a positive carbon isotope series (δ13C1 < δ13C2 < δ13C3), with ethane δ13C values being lighter than − 28.5‰, as high consistency with source rocks from the Jurassic period indicate thermal oil-prone gas. A model of the accumulation of gas hydrate is plotted. However, the gaseous sources of gas hydrates may be a subject for more research.

Generation and origin of natural gas in Lower Palaeozoic shales from southern Sweden

1969 ◽  
pp. 37-40
Author(s):  
Niels Hemmingsen Schovsbo ◽  
Arne Thorshøj Nielsen
Keyword(s):  
Source Rocks ◽  
Southern Sweden ◽  
Hydrocarbon Gases ◽  
Biogenic Gas ◽  
South Central ◽  
Alum Shale ◽  
Marine Source ◽  
Lower Palaeozoic ◽  
Background Gas ◽  
Origin Of Natural Gas

The Lower Palaeozoic succession in Scandinavia includes several excellent marine source rocks notably the Alum Shale, the Dicellograptus shale and the Rastrites Shale that have been targets for shale gas exploration since 2008. We here report on samples of these source rocks from cored shallow scientific wells in southern Sweden. The samples contain both free and sorbed hydrocarbon gases with concentrations significantly above the background gas level. The gases consist of a mixture of thermogenic and bacterially derived gas. The latter likely derives from both carbonate reduction and methyl fermentation processes. The presence of both thermogenic and biogenic gas in the Lower Palaeozoic shales is in agreement with results from past and present exploration activities; thermogenic gas is a target in deeply buried, gas-mature shales in southernmost Sweden, Denmark and northern Poland, whereas biogenic gas is a target in shallow, immature-marginally mature shales in south central Sweden. We here document that biogenic gas signatures are present also in gas-mature shallow buried shales in Skåne in southernmost Sweden.

HYDROCARBON GASES IN SEAFLOOR SEDIMENTS, OTWAY AND GIPPSLAND BASINS: IMPLICATIONS FOR PETROLEUM EXPLORATION

1989 ◽  
Vol 29 (1) ◽  
pp. 96 ◽  
Author(s):  
G.W. O'Brien ◽  
D.T. Heggie
Keyword(s):  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Gas Content ◽  
Hydrocarbon Gases ◽  
Near Surface ◽  
Wet Gas ◽  
Well Data ◽  
Seafloor Sediments ◽  
Gippsland Basin

During April- May 1988, the BMR research vessel Rig Seismic carried out a 21- day geochemical and sedimento- logical research program in the Otway (17 days) and Gippsland (4 days) Basins. The concentrations and molecular compositions of light hydrocarbon gases (C1- C4) were measured in sediments at 203 locations on the continental shelf and upper continental slope: the presence of thermogenic hydrocarbons was inferred from the molecular compositions of the gas mixtures. Thermogenic hydrocarbons were identified in near- surface sediments at 32 locations in the Otway Basin; 6 of these locations were on the Crayfish Platform, 7 were on the Mussel Platform and 17 were in the Voluta Trough. Thermogenic hydrocarbons were identified at 10 locations in the Gippsland Basin. Data from the Otway Basin indicated that total C1- C4 gas concentrations were higher in the Voluta Trough than on the basin margins, probably because intense faulting in the trough facilitates gas migration from deeply buried source rocks and/or reservoirs to the seafloor. However, anomalies were detected where the Tertiary sequence was thick and relatively unfaulted. The wet gas contents of the anomalies were highest on the basin margins, lower in the Voluta Trough and co- varied with the depth of burial of the basal Early Cretaceous sedimentary sequence. These data, when integrated with geohistory, thermal maturation modelling and well data, suggest that the areas with the best potential for liquid hydrocarbon entrapment and preservation are the Crayfish Platform and the inshore part of the Mussel Platform. In contrast, the Late Cretaceous Sherbrook Group and much of the Voluta Trough appear to be gas prone.Thermogenic anomalies in the Gippsland Basin were concentrated within and along the margins of the Central Deep where mature Latrobe Group source rocks are present. The wet gas content of these anomalies was variable, which is consistent with the spatial heterogeneity of hydrocarbon accumulations in the Gippsland Basin.

scholarly journals Geochemical Characteristics of Gas and Flowback Water in Lake Facies Shale: A Case Study From the Junggar Basin, China

2021 ◽  
Vol 9 ◽  
Author(s):  
Lin Zhang ◽  
Dan Liu ◽  
Yongjin Gao ◽  
Min Zhang
Keyword(s):  
Carbon Isotope ◽  
Shale Gas ◽  
Isotope Composition ◽  
Ordos Basin ◽  
Junggar Basin ◽  
Source Rocks ◽  
Flowback Water ◽  
Lucaogou Formation ◽  
The Difference

The chemical and isotopic compositions of the natural gas and the co-produced flowback water from the XJC 1 well in Junggar Basin, China, were analyzed to determine the origin of gases in the Permian Lucaogou Formation (P2l) and the Triassic Karamay Formation (T2k) in the Bogda Mountain periphery area of the Southern Junggar Basin. The value of carbon isotope composition of the P2l lacustrine shale gas in the Junggar Basin was between the shale gas in Chang 7 Formation of Triassic (T1y7) in the Ordos Basin and that in the Xu 5 Formation of Triassic (T3x5) in the Sichuan Basin. The difference in gas carbon isotope is primarily because the parent materials were different. A comparison between compositions in the flowback water reveals that the P2l water is of NaHCO3 type while the T2k water is of NaCl type, and the salinity of the latter is higher than the former, indicating a connection between P2l source rock and the T2k reservoir. In combination with the structural setting in the study area, the gas filling mode was proposed as follows: the gas generated from the lacustrine source rocks of the Permian Lucaogou Formation is stored in nearby lithological reservoirs from the Permian. Petroleum was also transported along the faults to the shallow layer of the Karamay Formation over long distances before it entered the Triassic reservoir.

scholarly journals Organic and Inorganic Carbon Isotope in Cenozoic Source Rocks of the Qaidam Basin (China)

2020 ◽  
Author(s):  
Shixin Zhou ◽  
Ji Li ◽  
Kefei Cheng ◽  
Cheng Zhang ◽  
Zexiang Sun ◽  
...  
Keyword(s):  
Carbon Isotope ◽  
Inorganic Carbon ◽  
Qaidam Basin ◽  
Source Rocks ◽  
Organic And Inorganic Carbon

scholarly journals Biomarker Ratios and Stablecarbon Isotopes to Describe Crude Oils Characteristics in the Murzuq Basin (Libya)

2019 ◽  
pp. 1-12
Author(s):  
S. Aboglila ◽  
A. Abdulgader ◽  
A. Albaghdady ◽  
O. Hlal ◽  
E. Farifr
Keyword(s):  
Mass Spectrometry ◽  
Carbon Isotope ◽  
Isotope Ratio ◽  
Stable Carbon Isotope ◽  
Source Rocks ◽  
Bacterial Degradation ◽  
Gas Chromatography Mass Spectrometry ◽  
Crude Oils ◽  
Stable Carbon ◽  
Lower Palaeozoic

This present paper includes a detailed evaluation of specific biomarkers together with stable carbon isotope (δ13C) by gas chromatography-mass spectrometry (GC–MS) and Gas Chromatograph–Isotope Ratio Mass Spectrometry (GC–IR–MS). Eight crude oil samples were collected from the A, B, H (east) and H (west) Fields, located in the Murzuq Basin, Libya. Stable Carbon isotope data (δ13C) together with biomarker ratios data of individual hydrocarbons, n-alkanes, isoprenoids, terpenes, hopanes, steranes and aromatic have been determined in crude oils to delineate their bacterial degradation, source facies, organic matter precursors, depositional conditions and a variation of maturation. Based on source-specific parameters including n-C19 alkane, % C27S, %C28S, %C29S, %C23TT, %C30αβ, %rC28, DBT/P, CPI, Pr/Ph, Ts/Tm, dh 30/h 30, 1 MN, 2 MN,         26-27 DMN, 15 DMN, 236 TMN, 146-135 TMN, 125 TMN, 136 TMN ratios and δ13C‰ of saturates and aromatics fractions. Such oils showed non-biodegradation, n-C19 peak proved oils generated from a Lower Palaeozoic source rocks as emphasizedvian-C19 peak, the dominance of C29steranes over C27 and C28 with light Carbon isotope ratio (δ13C‰) values. The abundances of isosterane C29, C27, C28.Tricyclohexaprenol and bacteriohopane polyols and aminopolyols, recommended as mixture bioprecursors of tricyclic terpenes and hopanes, furthermore regular sterane ratio gives values characteristic of Lower Palaeozoic marine source rocks and holding green algae and most likely a quantity of contribution from acritarchs. Carbon preference indices (CPIs)>0.9 pointed to an anoxic deposition, dibenzothiophene to phenanthrene (DBT/Prange 0.49 - 0.58) recommend a siliciclastic source rather than carbonate and/or evaporate saline deposition. The ratios of CPIs, pristane/n-C17 and phytane/n-C18, n-alkanes (C16 to C22) against (C23 to C33), Ts/Tm, C30diahopane/C30hopane, methylnaphthalene, dimethyl naphthalene and trimethyl naphthalene indicated that the oils analysed are mature except the B Field oil being slightly less mature than the A, H (east) and  H (west) Fields oils.

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