Source rock potential of the Late Miocene Metochia formation of Gavdos Island, Greece

Rock-Eval method was used to analyze 53 samples from late Miocene Metochia Formation of Gavdos Island (south of Crete Island) in order to characterize the contained organic matter and to evaluate its potential as source rock. The samples were collected from Metochia Section which consists of about 100 m thick marlssapropels alternations. Organic matter analysis showed that the studied succession could be subdivided into two parts. The lower one, which is generally rich in organic matter and the upper one, which is poor. In the lower part the rich horizons in organic matter are characterized by Kerogen type II, III and IV, with low oxygen content, and with fair to very good potential for gas and/or oil hydrocarbon generation. Additionally, the studied samples are thermally immature. Taking into account that the studied area has never been buried in such a depth to reach conditions of maturation, as well as, that the studied section in Gavdos is connected with Messara basin located in the northeastern and, finally, that the main part of Gavdos basin, which is situated between Gavdos and Crete islands, has continuously encountered subsidence, we could conclude that sediments of Metochia Formation could act as source rocks but in the more deep central part of the Gavdos basin.

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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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Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Interpretation ◽

10.1190/int-2016-0114.1 ◽

2017 ◽

Vol 5 (2) ◽

pp. SF225-SF242 ◽

Cited By ~ 2

Author(s):

Xun Sun ◽

Quansheng Liang ◽

Chengfu Jiang ◽

Daniel Enriquez ◽

Tongwei Zhang ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Ordos Basin ◽

Depositional Environments ◽

Source Rocks ◽

Type I ◽

Hydrocarbon Generation ◽

Type Ii ◽

Thermal Maturity ◽

Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

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Hydrocarbon Generation Potential of Chia Gara Formation in Three Selected Wells, Northern Iraq

Open Geosciences ◽

10.1515/geo-2019-0007 ◽

2019 ◽

Vol 11 (1) ◽

pp. 77-88 ◽

Cited By ~ 1

Author(s):

Wrya J. Mamaseni ◽

Srood F Naqshabandi ◽

Falah Kh. Al-Jaboury

Keyword(s):

Organic Matter ◽

Hydrocarbon Generation ◽

Peak Oil ◽

Low Oxygen ◽

High Hydrogen ◽

Northern Iraq ◽

Average Value ◽

Kerogen Type ◽

Oil Generation ◽

Rock Eval

Abstract In this study collected samples of Chia Gara Formation in Atrush, Shaikhan and Sarsang oilfields are used to geochemical characteristics of organic matter in this formation. This determination was based on Rock-Eval pyrolysis and Biomarker analyses. The Chia Gara Formation can be considered as good to excellent source rock; it’s TOC content ranges from 1.14-8.5wt% with an average of 1.85%, 3.91%, and 6.94% in Atush-1, Mangesh-1 and Shaikhan-8 wells respectively. The samples of Chia Gara Formation contain kerogen type II. These properties are considered optimal for oil generation. The low oxygen index (OI) and pristane/phytane (Pr/Ph) ratios (Average 20.73, 0.61 respectively) and high hydrogen index (HI) (average 637.6) indicate that the formation was deposited under anoxic condition. According to regular sterane (C27%, C28%, C29%) and terpanes ratios (C29/C30, C31/C30 hopane), the formation was deposited in marine environment. The average value of the Carbon Preference Index (CPI) is one with Tmax values of more than 430 ºC; these indicate peak oil window for the selected samples. Overall, the 20S/(20S+20R), ββ/(ββ+αα)C29 steranes and 22R/(22R+22S)C32homohopane, with Ts/ (Ts+Tm), and moretane/ hopane ratios point to a mature organic matter and to the ability of the formation to generate oil.

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Preliminary investigation of the hydrocarbon generation potential from the post-rift Abbas shale Formation (Pliocene) in the Tihamah Basin, south-eastern Yemeni Red Sea

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-01045-6 ◽

2020 ◽

Author(s):

Mohammed Hail Hakimi ◽

Abbas F. Gharib ◽

Nor Syazwani Z. Abidin ◽

Madyan M. A. Yahya

Keyword(s):

Preliminary Investigation ◽

Source Rocks ◽

Mature Stage ◽

Preliminary Evaluation ◽

Hydrocarbon Generation ◽

Organic Facies ◽

Petroleum Generation ◽

Good Potential ◽

Facies Types ◽

Rock Eval

AbstractPliocene shales included in the post-rift Abbas Formation were recovered from an exploratory well (Kathib-01) in the Tihamah Basin and geochemically analyzed. A preliminary evaluation of the organic facies of the Abbas shales and their petroleum generation potential was conducted based on basic organic geochemical results. Most Abbas shale samples had total organic carbon (TOC) contents < 1% and a fair source potential, while the remaining samples, with TOC contents > 1%, had a relatively good potential. Overall, the Rock–Eval hydrogen index values of the shales analyzed were between 96 and 234 mg of hydrocarbon per gram of TOC (mg HC/g TOC), indicating two dominant organic facies: types III and II/III kerogen, which indicate the presence of mainly gas- and oil-prone source rocks. We conclude that the Pliocene Abbas shales in the Tihamah Basin are still in a very early-mature stage (with respect to the oil window) and, hence, have not generated petroleum yet.

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Hydrocarbon-Generating Potential of Eocene Source Rocks in the Abakaliki Fold Belt, Nigeria / Potencial za nastanek oglikovodikov v eocenskih izvornih kamninah nariva Abakaliki

Materials and Geoenvironment ◽

10.2478/rmzmag-2019-0014 ◽

2020 ◽

Vol 66 (4) ◽

pp. 223-233

Author(s):

O.A. Oluwajana ◽

A.O. Opatola ◽

O.B. Ogbe ◽

T.D. Johnson

Keyword(s):

Source Rock ◽

Oil And Gas ◽

Threshold Value ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Fold Belt ◽

Gaseous Hydrocarbon ◽

Geochemical Model ◽

The One ◽

Rock Eval

AbstractSubsurface information on source rock potential of the Eocene shale unit of the Abakaliki Fold Belt is limited and has not been widely discussed. The total organic carbon (TOC) content and results of rock-eval pyrolysis for nine shale samples, as well as the one-dimensional (1D) geochemical model, from an exploration well in the Abakaliki Fold Belt were used to evaluate the source rock potentials and timing of hydrocarbon generation of Lower Eocene source rocks. The TOC content values of all the samples exceeded the minimum threshold value of 0.5 wt.% required for potential source rocks. A pseudo-Van Krevelen plot for the shale samples indicated Type II–III organic matter capable of generating gaseous hydrocarbon at thermally mature subsurface levels. The 1D burial model suggests that the Eocene source rock is capable of generating oil and gas at the present time. The modelled transformation ratio trend indicates that a fair amount of hydrocarbon has been expelled from the source rocks. The results of this study indicate that the Eocene source units may have charged the overlying thin Eocene sand bodies of the Abakaliki Fold Belt.

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Depositional Setting and Enrichment Mechanism of Organic Matter of Lower Cretaceous Shale in Ri-Qing-Wei Basin in the Central Sulu Orogenic Belt

Frontiers in Earth Science ◽

10.3389/feart.2021.808916 ◽

2022 ◽

Vol 9 ◽

Author(s):

Tengfei Zhou ◽

Yaoqi Zhou ◽

Hanjie Zhao ◽

Manjie Li ◽

Hongyu Mu

Keyword(s):

Organic Matter ◽

Source Rock ◽

Early Stage ◽

Salt Water ◽

Sedimentary Environment ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Element Geochemistry ◽

High Positive Correlation ◽

Evolution Stage

A suite of source rock consists of mudstone and shale, with great thickness and continuous deposition was found in the well LK-1 in Lingshan island in Ri-Qing-Wei basin. In order to evaluate the hydrocarbon generation prospects of these source rock and find the mechanism of organic matter enrichment, shale samples were selected from the core for TOC (total organic carbon) and element geochemistry analysis. The results show that organic matter abundance of the source rocks are generally high with average TOC content of 1.26 wt%, suggesting they are good source rocks. The geochemical features show that the sedimentary environment is mostly anoxic brackish water to salt water environment with arid to semiarid climate condition. The enrichment mechanism of organic matter varied with the evolution of the basin, which was divided into three stages according to the sedimentary characteristics. In the initial-middle period of rifting evolution (stage 1 and early stage 2), paleoproductivity is the major factor of OM-enrichment reflecting by high positive correlation between the TOC contents and paleoproductivity proxies. While with the evolution of the rift basin, redox condition and terrigenous clastic input became more and more important until they became the major factor of OM enrichment in the middle stage of rift evolution (stage 2). In the later stage of rift evolution (latest stage 2 and stage 3), besides terrigenous clastic input, the effect of paleoclimate on OM-enrichment increased gradually from a minor factor to a major factor.

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KITCHENS, KETTLES AND CUPS OF HYDROCARBONS, VICTORIAN OTWAY BASIN

The APPEA Journal ◽

10.1071/aj96018 ◽

1997 ◽

Vol 37 (1) ◽

pp. 285

Author(s):

K. Mehin ◽

A.G. Link

Keyword(s):

Source Rock ◽

Early Cretaceous ◽

Bulk Composition ◽

Source Rocks ◽

Eastern Region ◽

Hydrocarbon Generation ◽

Good Source ◽

Oil Generation ◽

Close Proximity ◽

Rock Eval

Evaluation of Early Cretaceous source rocks within the onshore Victoria Otway Basin has revealed that thick, mature shales containing predominantly gas-prone and in local concentrations, oil-prone macerals exist northwest of Portland, in the Tyrendarra Embayment, and around the Port Campbell region.Current results of Rock-Eval, bulk composition, gas chromatography, and biomarker analyses, coupled with geohistory and hydrocarbon generation interpretations, indicate that at least three phases of oil generation and expulsion occurred within the basin. The earliest phase, which coincided with the maximum heatflow in the crust around 100 Ma, resulted in the charging of the existing stratigraphic/shoestring traps of the basin. The second and third phases occurred in the eastern end of the basin at around 85 and 60 Ma. There is also evidence to suggest that structural traps of the eastern areas were formed later, during Oligocene time, and that these traps are probably still receiving late-stage charges of hydrocarbons.Although the sparse well density in the basin has resulted in limited, non-uniforin sampling opportunities, several regions with good Early Cretaceous source rocks can be recognised. Some of these good source rock areas are in close proximity to the several known hydrocarbon shows and producing fields. These current studies, which also include a source rock risk analysis indicating source rock adequacy, show that locations for future exploration could include the Casterton-Portland-Mt Gambier western region, the Peterborough-Port Campbell eastern region, and the prospective close peripheries and offshore extensions of these regions.

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Geochemical Trends Reflecting Hydrocarbon Generation, Migration and Accumulation in Unconventional Reservoirs Based on Pyrolysis Data (on the Example of the Bazhenov Formation)

Geosciences ◽

10.3390/geosciences11080307 ◽

2021 ◽

Vol 11 (8) ◽

pp. 307

Author(s):

Mikhail Spasennykh ◽

Polina Maglevannaia ◽

Elena Kozlova ◽

Timur Bulatov ◽

Evgeniya Leushina ◽

...

Keyword(s):

Organic Matter ◽

Source Rocks ◽

Unconventional Reservoirs ◽

Geochemical Evolution ◽

Hydrocarbon Generation ◽

Generation Process ◽

Marine Sedimentation ◽

Before And After ◽

Standard Set ◽

Rock Eval

The current study is devoted to the determination and interpretation of geochemical trends reflecting hydrocarbon generation, migration and accumulation in unconventional reservoirs; the study is performed on the Bazhenov shale rock formation (Western Siberia, Russia). Results are based on more than 3000 Rock-Eval analyses of the samples from 34 wells drilled in the central part of the West Siberian petroleum basin, which is characterized by common marine sedimentation environments. Pyrolysis studies were carried out before and after the extraction of rocks by organic solvent. As a result, we have improved the accuracy of kerogen content and maturity determination and complemented the standard set of pyrolysis parameters with the content of heavy fraction of hydrocarbons. The data obtained for the wells from areas of different organic matter maturity was summarized in the form of cross-plots and diagrams reflecting geochemical evolution of the source rocks from the beginning to the end of the oil window. Interpretation of the obtained results revealed quantitative trends in the changes of generation potential, amount, and composition of generated hydrocarbons in rocks at different stages of oil generation process. The analysis of geochemical trends allowed us to improve approaches for the productivity evaluation of the formation and study the effect of organic matter maturity on distribution of productive intervals of different types.

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Petroleum Geochemistry of the Loperot-1 Well in Lokichar Basin, Kenya

10.2118/afrc-2557372-ms ◽

2016 ◽

Cited By ~ 1

Author(s):

David M. Katithi ◽

David O. Opar

Keyword(s):

Organic Matter ◽

Source Rock ◽

Shale Gas ◽

Source Rocks ◽

Geochemical Data ◽

Mature Stage ◽

Type I ◽

Hydrocarbon Generation ◽

Gas Generation ◽

Gas Targets

ABSTRACT The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% – 3.18% (average 2.4%), HI of 87 – 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.

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Hydrocarbon Potential of the Late Permian and the Late Triassic Source Rocks from the Qamdo (Changdu) Basin, Eastern Tibet and Its Linkage with the Sea Level Change

Frontiers in Earth Science ◽

10.3389/feart.2021.778025 ◽

2021 ◽

Vol 9 ◽

Author(s):

Zhaolin Qi ◽

Yalin Li ◽

Chengshan Wang

Keyword(s):

Organic Matter ◽

Source Rock ◽

Upper Triassic ◽

Source Rocks ◽

Late Triassic ◽

Upper Permian ◽

Late Permian ◽

Petroleum Potential ◽

Eastern Tibet ◽

Rock Eval

The Qamdo Basin in eastern Tibet has significant petroleum potential and previous studies indicate that the basin contains thick potential source rocks of the Late Permian and the Late Triassic ages. In this paper, the petroleum potential of samples from measured the Upper Permian and Upper Triassic outcrop sections was evaluated on the basis of sedimentological, organic petrographic and geochemical analyses. Initial evaluations of total organic carbon contents indicated that shale samples from the Upper Permian Tuoba Formation and the Upper Triassic Adula and Duogala Formations have major source rock potential, while carbonate rocks from the Upper Triassic Bolila Formation are comparatively lean in organic matter More detailed analyses of OM-rich shale samples from the Tuoba, Adula and Duogala Formations included Rock-eval, elemental analyses, gas chromatography and organic petrography. Maceral compositions and plots of atomic O/C versus H/C indicate that the organic matter present in the samples is primarily Type II with a mixed source. Analyses of acyclic isoprenoid biomarkers indicate the organic matter was deposited under reducing and sub-to anoxic conditions. Based on the high vitrinite reflectance (Ro>1.3%) and Rock-eval data, the samples are classified as highly to over-mature, suggesting that the Tuoba, Adula and Duogaila Formation shales may generate thermogenic gas. Source rock intervals in the three formations are interpreted to have been deposited in marginal-marine environment during transgressions and under a warm and moist climatic condition.

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