PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS

Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.

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COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

The APPEA Journal ◽

10.1071/aj02006 ◽

2003 ◽

Vol 43 (1) ◽

pp. 117 ◽

Cited By ~ 18

Author(s):

C.J. Boreham ◽

J.E. Blevin ◽

A.P. Radlinski ◽

K.R. Trigg

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Middle Eocene ◽

Vitrinite Reflectance ◽

Mineral Resources ◽

Sedimentary Basins ◽

Source Rocks ◽

Gas Generation ◽

Australian Context ◽

Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

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Source Rocks’ Potentiality of the Sargelu Formation (Middle Jurassic) in the Taq Taq Oilfield, Kurdistan Region, Iraq

Iraqi Geological Journal ◽

10.46717/igj.54.2e.5ms-2021-11-21 ◽

2021 ◽

Vol 54 (2E) ◽

pp. 59-85

Author(s):

Dler Baban

Keyword(s):

Organic Matter ◽

Source Rock ◽

Source Rocks ◽

Petrographic Analysis ◽

Gas Generation ◽

Organic Matters ◽

Rock Samples ◽

Generation Zone ◽

Oil Generation ◽

Palynological Study

Thirty rock samples were selected from the well Tq-1 that penetrated the Jurassic beds in the Taq Taq Oilfield to be studied the source rock potentiality of the Sargelu Formation. The formation is characterized by three types of microfacies, namely, foraminiferal packstone, grainstone microfacies, fossiliferous packstone microfacies, and foraminiferal wackestone which were deposited in an environment extending from middle to outer carbonate ramp. An average of 3.03 wt.% of total organic carbon was obtained from a Rock Eval pyrolysis analysis carried out on 24 selected rock samples. The petrographic analysis for such organic matters revealed that they are of kerogen types III and IV and they are currently in a post-mature state. Pyrolysis parameters showed that limited generation potential was remained for these sources to expel generated hydrocarbons. The palynological study showed that Amorphous Organic Matter forms the highest percentage of organic matter components with more than 70%, followed by phytoclasts with 10 – 25 % and palynomorphs of less than 10%. The organic matters within the Sargelu Formation are deposited at the distal part of the basin under suboxic to anoxic condition. The color of the organic matter components, examined under transmitted light, showed Thermal Alteration Index values between 3+ and 4-. Such values may indicate that these organic matters are thermally at the end of the liquid oil generation zone and beginning of condensate-wet gas generation zone. The thermal maturity of the Sargelu Formation depending on the calculated VRo% revealed that the formation in the studied oilfield is currently at the peak of the oil generation zone. The Sargelu Formation in the studied field is considered as an effective source rock, as it has already generated and expelled hydrocarbons.

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Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study

GeoArabia ◽

10.2113/geoarabia090441 ◽

2004 ◽

Vol 9 (4) ◽

pp. 41-72 ◽

Cited By ~ 4

Author(s):

Janet K. Pitman ◽

Douglas Steinshouer ◽

Michael D. Lewan

Keyword(s):

Late Cretaceous ◽

Oil And Gas ◽

Source Rocks ◽

Peak Oil ◽

Fold Belt ◽

Hydrous Pyrolysis ◽

Oil Generation ◽

Petroleum Generation ◽

And Migration ◽

Migration Pathways

ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.

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NEW LIGHT ON THE ORIGIN OF COOPER BASIN OIL

The APPEA Journal ◽

10.1071/aj87023 ◽

1988 ◽

Vol 28 (1) ◽

pp. 303 ◽

Cited By ~ 3

Author(s):

G.H.Taylor G.H.Taylor ◽

Susie Y. Liu ◽

Michelle Smyth

Keyword(s):

Organic Matter ◽

Light Microscope ◽

Oil And Gas ◽

Close Association ◽

Source Rocks ◽

Transmission Electron ◽

Oil Generation ◽

Terrestrial Sediments ◽

Major Producer ◽

Cooper Basin

The Cooper Basin in central Australia is a major producer of gas and oil. It is generally accepted that the organic matter in the Permian terrestrial sediments of the Basin was the source of the oil and gas. However, both the coals and the dispersed organic matter (DOM) are rich in inertinite and both inertinite itself and inertinite-rich organic matter have been widely discounted as a possible source for oil.Recent co-ordinated transmission electron microscope and light microscope work on the inertiniterich coals of the Cooper Basin has shown that up to several per cent of some coal samples are composed of microscopic and sub-microscopic alginite. This includes material that had previously been identified with the light microscope alone as degraded sporinite, liptodetrinite or resinite, as well as algal-derived matter, which is too fine to observe with light microscopy. Much of this material of algal origin was selectively degraded at about the time of its deposition, and this degradation appears likely to have had the effect of further enhancing its potential to yield hydrocarbons. Thus, such material should be ranked among the richest potential sources of hydrocarbons when appropriate diagenetic conditions have been attained. Since inertinite and this kind of alginite occur in particularly close association, the presence of inertinite-rich coals and DOM within potential source rocks should be regarded as a highly favourable rather than an unfavourable, indication (as in the past).The quantity of alginite in the very large volumes of inertinite-rich coal in the Basin is more than adequate to account for the oil accumulations. In the Cooper Basin the coals, rather than the DOM, had the better potential for oil generation.

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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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Oil And Gas Generation History Based On Burial History Reconstruction And Thermal Maturity Modeling Of Petroleum Systems In Northern Iraq

Journal of Petroleum Research and Studies ◽

10.52716/jprs.v10i4.370 ◽

2020 ◽

Vol 10 (4) ◽

pp. 95-120

Author(s):

Rzger Abdulkarim Abdula

Keyword(s):

Source Rock ◽

Late Cretaceous ◽

Oil And Gas ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Thermal Maturity ◽

Burial History ◽

Gas Generation ◽

Northern Iraq ◽

Oil Generation

Burial history, thermal maturity, and timing of hydrocarbon generation were modeled for five key source-rock horizons at five locations in Northern Iraq. Constructed burial-history locations from east to west in the region are: Taq Taq-1; Qara Chugh-2; Zab-1; Guwair-2; and Shaikhan-2 wells. Generally, the thermal maturity status of the burial history sites based on increasing thermal maturity is Shaikhan-2 < Zab-1 < Guwair-2 < Qara Chugh-2 < Taq Taq-1. In well Qara Chugh-2, oil generation from Type-IIS kerogen in Geli Khana Formation started in the Late Cretaceous. Gas generation occurred at Qara Chugh-2 from Geli Khana Formation in the Late Miocene. The Kurra Chine Formation entered oil generation window at Guwair-2 and Shaikhan-2 at 64 Ma and 46 Ma, respectively. At Zab-1, the Baluti Formation started to generate gas at 120 Ma. The Butmah /Sarki reached peak oil generation at 45 Ma at Taq Taq-1. The main source rock in the area, Sargelu Formation started to generate oil at 47, 51, 33, 28, and 28 Ma at Taq Taq-1, Guwair-2, Shaikhan-2, Qara Chugh-2, and Zab-1, respectively. The results of the models demonstrated that peak petroleum generation from the Jurassic oil- and gas-prone source rocks in the most profound parts of the studied area occurred from Late Cretaceous to Middle Oligocene. At all localities, the Sargelu Formation is still within the oil window apart from Taq Taq-1 and Qara Chugh-2 where it is in the oil cracking and gas generation phase.

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Analysis of Fault Characteristics and Reservoir Forming Control in Middle Fault Depression Belt in Hailer-Tamtsag Basin

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.616-618.174 ◽

2012 ◽

Vol 616-618 ◽

pp. 174-184

Author(s):

Yong He Sun ◽

Lin Kang ◽

Feng Xiang Yang ◽

Xue Song Li

Keyword(s):

Oil And Gas ◽

Source Rocks ◽

Fault System ◽

Type I ◽

Weathering Crust ◽

Gas Migration ◽

Block Boundary ◽

System Type ◽

Fracture Damage ◽

Buried Hill

In order to reveal in middle fault depression belt of Hailer-Tamtsag Basin buried hill oil and gas migration and accumulation characteristics, we summarize controlling effect of fault on oil and gas migration and accumulation of buried hill, which by analysing genetic mechanism of buried hills based on fault systems formation and evolution. Research shows that three types of fault system in Hailer-Tamtsag Basin: early stretched fault system(Type I), early stretched middle tensile shearing fault system(Type I-II), early stretched middle tensile shearing reverse late fault system(Type I-II-III). Type I-II and I-II-III are stretching by NW tensional stress in Nantun group ,which afford tectonic framework for syngenesis buried hill and epigenetic buried hill. Type I make buried hills complicated .It is also favorable to ancient geomorphological buried hill in the fault less affected zones. Although they formed cracks dense zone easier, Type I-II and I-II-III fault system damage the reservoir which is not conducive to " hydrocarbon-supplying window " formation; Type I fault system have less promotion on the development of the buried hill reservoir, while it is conducive to hydrocarbon accumulation as the block boundary in buried hill hydrocarbon. Fault formed source rocks two kinds for hydrocarbon mode: unidirectional and bidirectional, which formed two reservoir-forming pattern: Unidirectional transportation hydrocarbon of weathering crust or hydrocarbon of fracture damage zones and bidirectional transportation hydrocarbon of weathering crust or hydrocarbon of fracture damage zones.

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Petrography and Organic Geochemistry Characterizations of Lower Paleozoic Organic-Rich Shale in the Northwestern Upper Yangtze Plate: Niutitang Formation and Longmaxi Formation, Dabashan Foreland Belt

Minerals ◽

10.3390/min8100439 ◽

2018 ◽

Vol 8 (10) ◽

pp. 439 ◽

Cited By ~ 1

Author(s):

Delu Li ◽

Rongxi Li ◽

Di Zhao ◽

Feng Xu

Keyword(s):

Gas Chromatography ◽

Organic Matter ◽

Organic Geochemistry ◽

Source Rocks ◽

Gas Chromatography Mass Spectrometry ◽

Mature Stage ◽

Type I ◽

Lower Paleozoic ◽

Longmaxi Formation ◽

Niutitang Formation

Measurements of total organic carbon, Rock-Eval pyrolysis, X-ray diffraction, scanning electron microscope, maceral examination, gas chromatography, and gas chromatography-mass spectrometry were conducted on the organic-rich shale of Lower Paleozoic Niutitang Formation and Longmaxi Formation in Dabashan foreland belt to discuss the organic matter characteristic, organic matter origin, redox condition, and salinity. The results indicate that the Niutiang Formation and Longmaxi Formation organic-rich shale are good and very good source rocks with Type I kerogen. Both of the shales have reached mature stage for generating gas. Biomarker analyses indicate that the organic matter origin of Niutitang Formation and Longmaxi Formation organic-rich shale are all derived from the lower bacteria and algae, and the organic matter are all suffered different biodegradation degrees. During Niutitang Formation and Longmaxi Formation period, the redox conditions are both anoxic with no stratification and the sedimentary water is normal marine water.

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Study on the distribution of extractable organic matter in pores of lacustrine shale: An example of Zhangjiatan Shale from the Upper Triassic Yanchang Formation, Ordos Basin, China

Interpretation ◽

10.1190/int-2016-0124.1 ◽

2017 ◽

Vol 5 (2) ◽

pp. SF109-SF126 ◽

Cited By ~ 7

Author(s):

Yuxi Yu ◽

Xiaorong Luo ◽

Ming Cheng ◽

Yuhong Lei ◽

Xiangzeng Wang ◽

...

Keyword(s):

Organic Matter ◽

Oil And Gas ◽

Storage Capacity ◽

Ordos Basin ◽

Organic Content ◽

Capacity Control ◽

Yanchang Formation ◽

Geochemical Characterization ◽

Extractable Organic Matter

Shale oil and gas have been discovered in the lacustrine Zhangjiatan Shale in the southern Ordos Basin, China. To study the distribution of extractable organic matter (EOM) in the Zhangjiatan Shale ([Formula: see text] ranges from 1.25% to 1.28%), geochemical characterization of core samples of different lithologies, scanning electron microscope observations, low-pressure [Formula: see text] and [Formula: see text] adsorption, and helium pycnometry were conducted. The content and saturation of the EOM in the pores were quantitatively characterized. The results show that the distribution of the EOM in the shale interval is heterogeneous. In general, the shale layers have a higher EOM content and saturation than siltstone layers. The total organic content and the original storage capacity control the EOM content in the shale layers. For the siltstone layers, the EOM content is mainly determined by the original storage capacity. On average, 75% of the EOM occurs in the mesopores, followed by 14% in the macropores, and 11% in the micropores. The EOM saturation in the pores decreases with the increase in pore diameter. The distribution of EOM in the shale pores is closely related to the pore type. Micropores and mesopores developed in the kerogens and pyrobitumens and the clay-mineral pores coated with organic matter are most favorable for EOM retention and charging.

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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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