The origins of paraffinic oils collected from oilfields in the western Siberian Basin, Russia: implications from geochemical and physical characteristics

AbstractFour oil samples were collected from oilfields in the western Siberian Basin, and analyzed using conventional geochemical and physical methods. The results of this study were used to evaluate the oil samples, focusing on the characteristics of their source rocks, including the origin of organic matter input; redox depositional conditions and degree of thermal maturity of their probable source rock were studied. The obtained SARA results show that the examined oils are paraffinic oils owing to their high saturated hydrocarbon fraction values of greater than 70% volume. The observed API gravity values (23.55° to 32.57°) and low sulfur content of less than 0.25% wt indicate that the examined oils are sweet oils and were generated from source rock containing Type-II, with low sulfur content. The low sulfur content combined with the vanadium (V) and nickel (Ni) ratios indicates that the examined oils were scoured from a mixture of aquatic and terrestrial organic matter, depositing under generally suboxic environmental conditions. The n-alkane and isoprenoid distributions, with their ratios and parameters further suggest that the examined oil samples were generated from source rock containing a mixed organic matter input and deposited under suboxic to relatively oxic environmental conditions. Bulk compositions and distributions of n-alkane and isoprenoid indicate that the oil samples were generated from mature source rock.

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EVIDENCE FOR A NEW OIL FAMILY IN THE NANCAR TROUGH AREA, TIMOR SEA

The APPEA Journal ◽

10.1071/aj01021 ◽

2002 ◽

Vol 42 (1) ◽

pp. 387 ◽

Cited By ~ 3

Author(s):

S.C. George ◽

H. Volk ◽

T.E. Ruble ◽

M.P. Brincat

Keyword(s):

Organic Matter ◽

Fluid Inclusion ◽

Source Rock ◽

Bacterial Activity ◽

Source Rocks ◽

Drilling Mud ◽

Terrestrial Organic Matter ◽

High Contribution ◽

Timor Sea ◽

Oil Source

Geochemical evidence is presented for a previously unrecognised oil generative source rock in the Nancar Trough area. This source rock supplements the middle to late Jurassic source rocks, which have previously been shown to have generated most of the oils in the northern Bonaparte Basin and the Vulcan Sub-basin. Fluids with a strong contribution from this new source rock, defined here as the Nancar oil family, have an unusually high abundance of mid-chain substituted monomethylalkanes. In comparison, oils from the Vulcan Sub-basin contain mostly terminally substituted monomethylalkanes and the overall abundance is much lower. Oils from the Laminaria High and some from the northern Vulcan Sub-Basin show intermediate characteristics and may be co-sourced. Evidence from the analysis of fluid inclusion oils was important in establishing the presence of the new oil family because interference from drilling mud contaminants could be excluded. The detailed geochemistry of Ludmilla–1 fluid inclusion oil suggests the source rock for the Nancar oil family was deposited in a marine environment under sub-oxic conditions with limited sulphur content, a low contribution of terrestrial organic matter and a high contribution of organic matter from bacterial activity. Since monomethylalkanes are typical biomarkers of cyanobacteria, the source rock that gave rise to the new oil family may be rich in cyanobacterial organic matter. Further studies on sediment extracts are needed to establish an explicit oil-source rock correlation and to identify the stratigraphic location/palaeo-environment of the source rock. Such information will be valuable in determining the prospectivity of the large and relatively unexplored province draining the Nancar Trough kitchen.

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GEOCHEMICAL AND COMPOUND SPECIFIC CARBON ISOTOPIC CHARACTERISATION OF FLUID INCLUSION OILS FROM THE OFFSHORE PERTH BASIN,WESTERN AUSTRALIA: IMPLICATIONS FOR RECOGNISING EFFECTIVE OIL SOURCE ROCKS

The APPEA Journal ◽

10.1071/aj03008 ◽

2004 ◽

Vol 44 (1) ◽

pp. 223 ◽

Cited By ~ 4

Author(s):

H. Volk ◽

S.C. George ◽

C.J. Boreham ◽

R.H. Kempton

Keyword(s):

Organic Matter ◽

Fluid Inclusion ◽

Source Rock ◽

Early Cretaceous ◽

Source Rocks ◽

Molecular Evidence ◽

Terrestrial Organic Matter ◽

Carbon Isotopic ◽

Oil Source ◽

Coal Measures

The molecular composition of fluid inclusion (FI) oils from Leander Reef–1, Houtman–1 and Gage Roads–2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef–1 and Houtman–1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef–1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. The heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef–1 FI oil indicate, however, that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman–1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to sub-oxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman–1 FI oil δ13C CSI n-alkane data are similar to those acquired on the Walyering–2 oil. Possible lacustrine sources may exist in the Early Jurassic Eneabba Formation and are present in the Late Jurassic Yarragadee Formation. The low maturity Gage Roads–2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads–1, and was probably sourced from the Early Cretaceous Parmelia Formation.

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Generation potential, distribution area and maturity of the Barents-Kara Sea source rocks

Georesursy ◽

10.18599/grs.2021.2.1 ◽

2021 ◽

Vol 23 (2) ◽

pp. 6-25

Author(s):

Antonina V. Stoupakova ◽

Maria A. Bolshakova ◽

Anna A. Suslova ◽

Alina V. Mordasova ◽

Konstantin O. Osipov ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Middle Triassic ◽

Barents Sea ◽

Kara Sea ◽

Source Rocks ◽

Distribution Area ◽

Lower Permian ◽

Terrestrial Organic Matter ◽

Marine Organic Matter

Identification of the source rock potential and distribution area is the most important stage of the basin analysis and oil, and gas reserves assessment. Based on analysis of the large geochemical and geological data base of the Petroleum geology department of the Lomonosov Moscow State University and integration of different-scale information (pyrolysis results and regional palaeogeographic maps), generation potential, distribution area and maturity of the main source rock intervals of the Barents-Kara Sea shelf are reconstructed. These source rocks wide distribute on the Barents-Kara Sea shelf and are characterized by lateral variability of generation potential and type of organic matter depending on paleogeography. During regional transgressions in Late Devonian, Early Permian, Middle Triassic and Late Jurassic, deposited source rocks with marine organic matter and excellent generation potential. However in the regression periods, during the short-term transgressions, formed Lower Carboniferous, Upper Permian, Induan, Olenekian and Late Triassic source rocks with mixed and terrestrial organic matter and good potential. Upper Devonian shales contain up to 20.6% (average – 3%) of marine organic matter, have an excellent potential and is predicted on the Eastern-Barents megabasin. Upper Devonian source rocks are in the oil window on the steps, platforms and monoclines, while are overmature in the basins. Lower Permian shale-carbonate source rock is enriched with marine organic matter (up to 4%, average – 1.4%) and has a good end excellent potential. Lower Permian source rocks distribute over the entire Barents shelf and also in the North-Kara basin (Akhmatov Fm). These rocks enter the gas window in the Barents Sea shelf, the oil window on the highs and platforms and are immature in the North-Kara basin. Middle Triassic shales contain up to 11.2% of organic matter, there is a significant lateral variability of the features: an excellent generation potential and marine organic matter on the western Barents Sea and poor potential and terrestrial organic matter in the eastern Barents Sea. Middle Triassic source rocks are in the oil window; in the depocenters it generates gas. Upper Jurassic black shales are enriched with marine and mixed organic matter (up to 27,9%, average – 7.3%) and have an excellent potential. On the most Barents-Kara Sea shelf, Upper Jurassic source rock are immature, but are in the oil window in the South-Kara basin and in the deepest parts of the Barents Sea shelf.

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SEDIMENTARY AND GEOCHEMICAL EVIDENCE FOR TERRESTRIAL ORGANIC MATTER INPUT DRIVING ANOXIA EVENTS FOUND IN LATE DEVONIAN BLACK-GRAY SHALE TRANSITIONS, APPALACHIAN BASIN, NORTH-CENTRAL OHIO

10.1130/abs/2020am-357585 ◽

2020 ◽

Author(s):

Caroline A. Dunkel ◽

◽

James E. Evans

Keyword(s):

Organic Matter ◽

Appalachian Basin ◽

Late Devonian ◽

Terrestrial Organic Matter ◽

North Central ◽

Geochemical Evidence ◽

Organic Matter Input

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Effective source rock selection and oil–source correlation in the Western Slope of the northern Songliao Basin, China

Petroleum Science ◽

10.1007/s12182-021-00554-1 ◽

2021 ◽

Vol 18 (2) ◽

pp. 398-415

Author(s):

He Bi ◽

Peng Li ◽

Yun Jiang ◽

Jing-Jing Fan ◽

Xiao-Yue Chen

Keyword(s):

Organic Matter ◽

Source Rock ◽

Thermal Evolution ◽

Songliao Basin ◽

Source Rocks ◽

Crude Oils ◽

Western Slope ◽

Geochemical Parameters ◽

Group I ◽

Oil Source

AbstractThis study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

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Investigation of the qualities of some promising oils of the Absheron oil and gas region

World of OIL Products the Oil Companies Bulletin ◽

10.32758/2071-5951-2021-0-2-22-26 ◽

2021 ◽

Vol 02 ◽

pp. 22-26

Author(s):

Yu.A. Abdulayeva ◽

◽

N.H. Alekperova ◽

S.B. Logmanova ◽

N.F. Kafarova ◽

...

Keyword(s):

Sulfur Content ◽

Oil And Gas ◽

Viscosity Index ◽

Hydrocarbon Composition ◽

High Viscosity ◽

Group I ◽

Oil Fractions ◽

Low Sulfur Content ◽

Selective Refining ◽

Low Sulfur

The article presents the characteristics of characteristic oils of the Apsheron oil and gas region, as well as the hydrocarbon composition of light and oil fractions. Oils of the Apsheron oil and gas region in terms of light fractions, sulfur content, and density are comparable to marketing grades of oils. The standards for prices are: graded crude oil WTI, Light Sweet, Brent, and Russian oils Sokol, Urals, Siberian Light are approaching them. We have studied in detail the yields and hydrocarbon composition of light and oil fractions of oils from the Apsheron oil and gas region. To obtain oils with a high viscosity index, studies were carried out to change the structure of oil fractions using hydrogen using the example of oil fractions of Azeri oil. Due to the significant content of aromatic hydrocarbons, schemes for the processing of oil fractions have been developed, including selective purification of distillates, dewaxing (except for Guneshli oil), as well as hydrocatalytic treatment in a severe mode in the presence of industrial Russian catalysts. As a result, it was possible to obtain API group I oils, according to the viscosity classification corresponding to SAE 20 and SAE 30. Thus, a study of the qualities and hydrocarbon composition of oils from the Absheron oil and gas region showed that these oils are characterized by a high content of light fractions, low density, and low sulfur content. According to these indicators, these oils correspond to the marker oils. In order to obtain base oils with a viscosity index of ≥90 and an aromatic hydrocarbon content of ≥10, a traditional refining method was used: selective refining, dewaxing, and severe hydrotreating.

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Source rock characterization of mesozoic to cenozoic organic matter rich marls and shales of the Eratosthenes Seamount, Eastern Mediterranean Sea

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2018036 ◽

2018 ◽

Vol 73 ◽

pp. 49 ◽

Cited By ~ 8

Author(s):

Sebastian Grohmann ◽

Susanne W. Fietz ◽

Ralf Littke ◽

Samer Bou Daher ◽

Maria Fernanda Romero-Sarmiento ◽

...

Keyword(s):

Organic Matter ◽

Mediterranean Sea ◽

Source Rock ◽

Eastern Mediterranean ◽

Source Rocks ◽

Eastern Mediterranean Sea ◽

Potential Source Rock ◽

Levant Basin ◽

Rock Characterization ◽

Rock Eval

Several significant hydrocarbon accumulations were discovered over the past decade in the Levant Basin, Eastern Mediterranean Sea. Onshore studies have investigated potential source rock intervals to the east and south of the Levant Basin, whereas its offshore western margin is still relatively underexplored. Only a few cores were recovered from four boreholes offshore southern Cyprus by the Ocean Drilling Program (ODP) during the drilling campaign Leg 160 in 1995. These wells transect the Eratosthenes Seamount, a drowned bathymetric high, and recovered a thick sequence of both pre- and post-Messinian sedimentary rocks, containing mainly marine marls and shales. In this study, 122 core samples of Late Cretaceous to Messinian age were analyzed in order to identify organic-matter-rich intervals and to determine their depositional environment as well as their source rock potential and thermal maturity. Both Total Organic and Inorganic Carbon (TOC, TIC) analyses as well as Rock-Eval pyrolysis were firstly performed for the complete set of samples whereas Total Sulfur (TS) analysis was only carried out on samples containing significant amount of organic matter (>0.3 wt.% TOC). Based on the Rock-Eval results, eight samples were selected for organic petrographic investigations and twelve samples for analysis of major aliphatic hydrocarbon compounds. The organic content is highly variable in the analyzed samples (0–9.3 wt.%). TS/TOC as well as several biomarker ratios (e.g. Pr/Ph < 2) indicate a deposition under dysoxic conditions for the organic matter-rich sections, which were probably reached during sporadically active upwelling periods. Results prove potential oil prone Type II kerogen source rock intervals of fair to very good quality being present in Turonian to Coniacian (average: TOC = 0.93 wt.%, HI = 319 mg HC/g TOC) and in Bartonian to Priabonian (average: TOC = 4.8 wt.%, HI = 469 mg HC/g TOC) intervals. A precise determination of the actual source rock thickness is prevented by low core recovery rates for the respective intervals. All analyzed samples are immature to early mature. However, the presence of deeper buried, thermally mature source rocks and hydrocarbon migration is indicated by the observation of solid bitumen impregnation in one Upper Cretaceous and in one Lower Eocene sample.

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