scholarly journals Solid bitumen in shales from the Middle to Upper Jurassic Sargelu and Naokelekan Formations of northernmost Iraq: implication for reservoir characterization

2021 ◽  
Vol 14 (9) ◽  
Author(s):  
Nagham Omar ◽  
Tom McCann ◽  
Ali I. Al-Juboury ◽  
Isabel Suárez-Ruiz
Keyword(s):  
Reservoir Characterization ◽  
Vitrinite Reflectance ◽  
Alkali Feldspar ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Petrographic Analysis ◽  
Second Phase ◽  
Carbon And Oxygen Isotopes ◽  
Solid Bitumen ◽  
Carbon And Oxygen Isotope

AbstractPetrographic, organic, and inorganic geochemical analysis of the solid bitumen and host shales from the Middle and Late Jurassic-age Sargelu and Naokelekan Formations of the Banik section, northernmost Iraq, was undertaken. The aim was to understand their derivation and preservation, as well as examine the carbon and oxygen isotopes, and paleoredox proxies under which the solid bitumen and host sediments were deposited. Petrographic analysis of both formations revealed the presence of solid bitumen high reflectance (first phase) and solid bitumen low reflectance (second phase). The equivalent vitrinite reflectance indicates that the solid bitumen of the two formations probably accumulated within the shale reservoirs following oil migration from source rocks located within the same formations. Mineralogical study (XRD and SEM - EDX) revealed that the shales hosting the solid bitumen also contain clay minerals (illite, rectorite, chlorite, montmorillonite, and kaolinite) as well as carbonate minerals, quartz, alkali feldspar, and pyrite. Carbon and oxygen isotope data along with paleoredox indicators suggest that both the solid bitumen sources and host shales in both formations formed within a shallow-marine setting, most probably under anoxic conditions where water circulation was restricted.

scholarly journals Biomarkers and C and S Isotopes of the Permian to Triassic Solid Bitumen and Its Potential Source Rocks in NE Sichuan Basin

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-14 ◽  
Author(s):  
Chunfang Cai ◽  
Chenlu Xu ◽  
Wenxiang He ◽  
Chunming Zhang ◽  
Hongxia Li
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Lower Triassic ◽  
Source Rocks ◽  
Upper Permian ◽  
Solid Bitumen ◽  
Lower Silurian ◽  
High Maturity ◽  
Gas Fields ◽  
Extractable Organic Matter

The potential parent source rocks except from Upper Permian Dalong Formation (P3d) for Upper Permian and Lower Triassic solid bitumen show high maturity to overmaturity with equivalent vitrinite reflectance (ERo) from 1.7% to 3.1% but have extractable organic matter likely not contaminated by younger source rocks. P3d source rocks were deposited under euxinic environments as indicated by the pyrite δ34S values as light as -34.5‰ and distribution of aryl isoprenoids, which were also detected from the Lower Silurian (S1l) source rock and the solid bitumen in the gas fields in the west not in the east. All the solid bitumen not altered by thermochemical sulfate reduction (TSR) has δ13C and δ34S values similar to part of the P3l kerogens and within the S1l kerogens. Thus, the eastern solid bitumen may have been derived from the P3l kerogens, and the western solid bitumen was likely to have precracking oils from P3l kerogens mixed with the S1l or P3d kerogens. This case-study tentatively shows that δ13C and δ34S values along with biomarkers have the potential to be used for the purpose of solid bitumen and source rock correlation in a rapidly buried basin, although further work should be done to confirm it.

MATURATION PATTERNS IN THE PERTH BASIN

1979 ◽  
Vol 19 (1) ◽  
pp. 94 ◽  
Author(s):  
A. J. Kantsler ◽  
A. C. Cook
Keyword(s):  
Vitrinite Reflectance ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Geothermal Gradients ◽  
The North ◽  
Reservoir Conditions ◽  
Igneous Activity ◽  
Hydrocarbon Deposits ◽  
Very High

Vitrinite reflectance data from wells drilled in the Perth Basin show that major variations exist in the pattern of rank distribution within the basin. Generally, rank gradients are low and near linear, but some wells show curvature of the rank profile in the Early Jurassic and Triassic parts of their sections. Curvature of the rank profile is generally associated with a shallow depth to basement, but the presence of very high ranks in parts of the Permian section on the Beagle Ridge suggests that a Permian to Jurassic thermal event associated with local igneous activity or the initiation of rifting, or both, may also be a controlling factor. Low, linear rank gradients from parts of the basin such as the Bunbury Trough and the thick Upper Jurassic sections of some of the deeper sub-basins are taken to indicate that low geothermal gradients have operated since the Permian,in the former instance and certainly since the Jurassic in the latter. Such conditions imply slow generation of hydrocarbons.Higher geothermal gradients and rank gradients in parts of the basin as in the north Dandaragan Trough and Vlaming Sub-basin imply enhanced hydrocarbon generation, particularly as calculated palaeotemperatures indicate that the advent of higher geothermal gradients is likely to have been relatively recent. Potential source rocks occur throughout the basin and provided that suitable structural and reservoir conditions can be delineated, the prospects of discovering more commercial hydrocarbon deposits are high.

Reservoir geochemistry: Evaluation of thermal maturity from gasoline-range hydrocarbons

2015 ◽  
Vol 3 (3) ◽  
pp. SV1-SV7
Author(s):  
Gary H. Isaksen
Keyword(s):  
North Sea ◽  
Vitrinite Reflectance ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Calibration Data ◽  
Thermal Maturity ◽  
Volatile Oils ◽  
Marine Algal ◽  
The Uk ◽  
Maturity Parameters

Oils and condensates with high concentrations of gasoline-range hydrocarbons typically lack adequate quantities of [Formula: see text] biomarkers used for thermal maturity and organic facies evaluations. I attempted a calibration of rock-based thermal maturity parameters between gasoline-range molecular parameters and nonmolecular maturity parameters such as Rock-Eval Tmax, vitrinite reflectance, and downhole temperatures. This enables maturity evaluation of volatile oils and condensates whose biomarker concentrations are at low or trace levels. The rock-based calibration data were used to assess thermal maturity of nonvolatile oils, volatile oils, and condensates from the Central Graben area of the UK North Sea and includes samples from high-pressure (gradients [Formula: see text]) and high-temperature ([Formula: see text]) hydrocarbon systems. Source rocks for theses North Sea oils and condensates are the Upper Jurassic Kimmeridge Clay and Heather shales, with a predominance of marine, algal type II organic matter.

scholarly journals Regional hydrocarbon potential and thermal reconstruction of the Lower Jurassic to lowermost Cretaceous source rocks in the Danish Central Graben

2020 ◽  
Vol 68 ◽  
pp. 195-230
Author(s):  
Niels Hemmingsen Schovsbo ◽  
Louise Ponsaing ◽  
Anders Mathiesen ◽  
Jørgen A. Bojesen-Koefoed ◽  
Lars Kristensen ◽  
...  
Keyword(s):  
Source Rock ◽  
Middle Jurassic ◽  
Western Europe ◽  
Vitrinite Reflectance ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Salt Dome ◽  
Source Rocks ◽  
Statistical Parameters ◽  
Thermally Conductive

The Danish part of the Central Graben (DCG) is one of the petroliferous basins in the offshore region of north-western Europe. The source rock quality and maturity is here reviewed, based on 5556 Rock-Eval analyses and total organic carbon (TOC) measurements from 78 wells and 1175 vitrinite reflectance (VR) measurement from 55 wells, which makes this study the most comprehensive to date. The thermal maturity is evaluated through 1-D basin modelling of 46 wells. Statistical parameters describ-ing the distribution of TOC, hydrocarbon index (HI) and Tmax are presented for the Lower Jurassic marine Fjerritslev Formation, the Middle Jurassic terrestrial-paralic Bryne, Lulu, and Middle Graben Formations and the Upper Jurassic to lowermost Cretaceous marine Lola and Farsund Formations in six areas in the DCG. For the Farsund Formation the source-rock richness is presented for selected stratigraphic sequences. The upper part of the Farsund Formation is immature in the southern part of the Salt Dome Province, and late oil mature in and near the Tail End Graben and in the Søgne Basin. The lower part of the Farsund Formation is immature in local areas, yet post-mature in the Tail End Graben and in the Salt Dome Province. The Lower and Middle Jurassic shales are gas-prone in most of the DCG. The depth of the oil window, as defined by a VR of 0.6% Ro, ranges between 2200 and 4500 m. The variations are ascribed to heat flow differences in the DCG and can be modelled by a simple depth model, which includes the thickness of the Cretaceous to Palaeo-gene Chalk and Cromer Knoll Groups. According to the model, a thick Chalk Group offsets the oil window to deeper levels, which likely can be attributed to the thermal properties of the highly thermally conductive chalk compared to the underlying less thermally conductive clays. The DCG is an overpressured basin, and high-pressure, high-temperature conditions are expected to occur deeper than 3.8 km except for the Feda and Gertrud Grabens where such conditions, due to generally lower tem-peratures, are expected to occur deeper than around 4.7 km.

Petrography and geochemistry of the Middle– Upper Jurassic Banik section, northernmost Iraq – Implications for palaeoredox, evaporitic and diagenetic conditions

2020 ◽  
Vol 297 (2) ◽  
pp. 125-152
Author(s):  
Nagham Omar ◽  
Tom McCann ◽  
Ali I. Al-Juboury ◽  
Sven Oliver Franz
Keyword(s):  
Clay Minerals ◽  
Marine Environment ◽  
Alkali Feldspar ◽  
Upper Jurassic ◽  
Tectonic Activity ◽  
Petrographic Analysis ◽  
Geochemical Analysis ◽  
Shallow Marine ◽  
Shallow Lagoon ◽  
Lagoon Environment

Lithological, petrographic, and geochemical analysis of the Middle to Upper Jurassic succession (i.e.Sargelu and Naokelekan formations) from northernmost Iraq were undertaken with the aim of providing an updated discussion for their sedimentary and diagenetic histories, as well as examining the evaporation proxies and palaeoredox conditions under which these two formations were deposited. Lithologically, the Sargelu Formation comprises massive dolomites, interbedded with shales, rare cherts and one single limestone bed, whilst the Naokelekan Formation consists of shales overlain by limestones and one single dolomite bed. Petrographic analysis of both formations revealed the presence of rare ostracods, bioclastic fragments as well as calcispheres. Five main microfacies were recognized, including bioclastic wackestone, mudstone, dolorudite, dolarenite and dolo micrite microfacies. The shales comprise clay minerals assemblages (illite/muscovite and kaolinite) with some quartz, alkali feldspar and rare pyrite. The Sargelu Formation was probably deposited in a shallow marine environment. In contrast, the Naokelekan Formation is hypothesized to be deposited in a restricted shallow lagoon environment. Palaeoredox indicators suggest that both formations were accumulated under anoxic conditions, most probably in silled basins where water circulation was restricted. Tectonic activity thus resulted in basin compartmentalization across the region, which also explains the marked differences which are often observed.

Oil to Source Rock Correlation Using Biomarker Data Through Pattern Matching and Fingerprinting Analysis in “Kitkat” Field, Jabung Block, South Sumatra Basin

2020 ◽  
Author(s):  
S., R. Muthasyabiha
Keyword(s):  
Pattern Matching ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Maturity Level ◽  
Fingerprinting Analysis ◽  
Kerogen Type ◽  
Oil Characteristics ◽  
Biomarker Data

Geochemical analysis is necessary to enable the optimization of hydrocarbon exploration. In this research, it is used to determine the oil characteristics and the type of source rock candidates that produces hydrocarbon in the “KITKAT” Field and also to understand the quality, quantity and maturity of proven source rocks. The evaluation of source rock was obtained from Rock-Eval Pyrolysis (REP) to determine the hydrocarbon type and analysis of the value of Total Organic Carbon (TOC) was performed to know the quantity of its organic content. Analysis of Tmax value and Vitrinite Reflectance (Ro) was also performed to know the maturity level of the source rock samples. Then the oil characteristics such as the depositional environment of source rock candidate and where the oil sample develops were obtained from pattern matching and fingerprinting analysis of Biomarker data GC/GCMS. Moreover, these data are used to know the correlation of oil to source rock. The result of source rock evaluation shows that the Talangakar Formation (TAF) has all these parameters as a source rock. Organic material from Upper Talangakar Formation (UTAF) comes from kerogen type II/III that is capable of producing oil and gas (Espitalie, 1985) and Lower Talangakar Formation (LTAF) comes from kerogen type III that is capable of producing gas. All intervals of TAF have a quantity value from very good–excellent considerable from the amount of TOC > 1% (Peters and Cassa, 1994). Source rock maturity level (Ro > 0.6) in UTAF is mature–late mature and LTAF is late mature–over mature (Peters and Cassa, 1994). Source rock from UTAF has deposited in the transition environment, and source rock from LTAF has deposited in the terrestrial environment. The correlation of oil to source rock shows that oil sample is positively correlated with the UTAF.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

2019 ◽  
Vol 56 (4) ◽  
pp. 365-396
Author(s):  
Debra Higley ◽  
Catherine Enomoto
Keyword(s):  
New York ◽  
Vitrinite Reflectance ◽  
Structural Complexity ◽  
Appalachian Basin ◽  
Source Rocks ◽  
Burial History ◽  
Gas Generation ◽  
Deep Basin ◽  
Utica Shale ◽  
Wet Gas

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland

1998 ◽  
pp. 43-54 ◽  
Author(s):  
Lars Stemmerik ◽  
Gregers Dam ◽  
Nanna Noe-Nygaard ◽  
Stefan Piasecki ◽  
Finn Surlyk
Keyword(s):  
Sequence Stratigraphy ◽  
Middle Jurassic ◽  
Sedimentary Basins ◽  
Upper Jurassic ◽  
Oil Field ◽  
Source Rocks ◽  
Upper Permian ◽  
Shallow Marine ◽  
East Greenland ◽  
Reservoir Rocks

NOTE: This article was published in a former series of GEUS Bulletin. Please use the original series name when citing this article, for example: Stemmerik, L., Dam, G., Noe-Nygaard, N., Piasecki, S., & Surlyk, F. (1998). Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland. Geology of Greenland Survey Bulletin, 180, 43-54. https://doi.org/10.34194/ggub.v180.5085 _______________ Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8317
Author(s):  
Qiang Cao ◽  
Jiaren Ye ◽  
Yongchao Lu ◽  
Yang Tian ◽  
Jinshui Liu ◽  
...  
Keyword(s):  
Carbon Isotopes ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Heating Time ◽  
Source Rocks ◽  
Evolution Process ◽  
Carbon Isotopic ◽  
Hydrous Pyrolysis ◽  
Increasing Temperature

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R2) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen0(original) + bitumen0(original)→kerogenr (residual kerogen) + expelled oil (generated) + bitumenn+r (generated + residual) + C2+(generated + residual) + CH4(generated). Among these, bitumen, expelled oil, and C2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ13C1 < 13C2-5 < δ13Cexpelled oil < δ13Cbitumen < δ13Ckerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

Finnmark Platform Composite Tectono-Sedimentary Element, Barents Sea

2021 ◽  
pp. M57-2020-20
Author(s):  
E. Henriksen ◽  
D. Ktenas ◽  
J. K. Nielsen
Keyword(s):  
High Frequency ◽  
Oil And Gas ◽  
Barents Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Basement Rocks ◽  
Sea Bottom ◽  
Middle Carboniferous ◽  
Uralian Orogen ◽  
Glacial Periods

AbstractThe Finnmark Platform Composite Tectono-Sedimentary Element (CTSE), located in the southern Barents Sea, is a northward-dipping monoclinal structural unit. It covers most of the southern Norwegian Barents Sea where it borders the Norwegian Mainland. Except for the different age of basement, the CTSE extends eastwards into the Kola Monocline on the Russian part of the Barents Sea.The general water depth varies between 200-350 m, and the sea bottom is influenced by Plio-Pleistocene glaciations. A high frequency of scour marks and deposition of moraine materials exists on the platform areas. Successively older strata sub-crop below the Upper Regional Unconformity (URU, which was) formed by several glacial periods.Basement rocks of Neoproterozoic age are heavily affected by the Caledonian Orogeny, and previously by the Timanide tectonic compression in the easternmost part of the Finnmark Platform CTSE.Depth to crystalline basement varies considerably and is estimated to be from 4-5 to 10 km. Following the Caledonian orogenesis, the Finnmark Platform was affected by Lower to Middle Carboniferous rifting, sediment input from the Uralian Orogen in the east, the Upper Jurassic / Lower Cretaceous rift phase and the Late Plio-Pleistocene isostatic uplift.A total of 8 exploration wells drilled different targets on the platform. Two minor discoveries have been made proving presence of both oil and gas and potential sandstone reservoirs of good quality identified in the Visean, Induan, Anisian and Carnian intervals. In addition, thick sequences of Perm-Carboniferous carbonates and spiculitic chert are proven in the eastern Platform area. The deep reservoirs are believed to be charged from Paleozoic sources. A western extension of the Domanik source rocks well documented in the Timan-Pechora Basin may exist towards the eastern part of the Finnmark Platform. In the westernmost part, charge from juxtaposed down-faulted basins may be possible.

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