Black Shale Source Rocks and Oil Generation in the Cambrian and Ordovician of the Central Appalachian Basin, USA

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.

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Small angle neutron scattering signature of oil generation in artificially and naturally matured hydrocarbon source rocks

Organic Geochemistry ◽

10.1016/s0146-6380(99)00128-x ◽

2000 ◽

Vol 31 (1) ◽

pp. 1-14 ◽

Cited By ~ 61

Author(s):

A.P. Radliński ◽

C.J. Boreham ◽

P. Lindner ◽

O. Randl ◽

G.D. Wignall ◽

...

Keyword(s):

Neutron Scattering ◽

Small Angle ◽

Small Angle Neutron Scattering ◽

Source Rocks ◽

Hydrocarbon Source Rocks ◽

Oil Generation

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Oil generation from coal source rocks: the influence of depositional conditions and stratigraphic age

Geological Survey of Denmark and Greenland Bulletin ◽

10.34194/geusb.v7.4822 ◽

2005 ◽

Vol 7 ◽

pp. 9-12 ◽

Cited By ~ 6

Author(s):

Henrik I. Petersen

Keyword(s):

North Sea ◽

Liquid Hydrocarbon ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Oil Generation ◽

Generation Capacity ◽

The Subject ◽

Coal Composition ◽

Gippsland Basin ◽

Australasian Region

Although it was for many years believed that coals could not act as source rocks for commercial oil accumulations, it is today generally accepted that coals can indeed generate and expel commercial quantities of oil. While hydrocarbon generation from coals is less well understood than for marine and lacustrine source rocks, liquid hydrocarbon generation from coals and coaly source rocks is now known from many parts of the world, especially in the Australasian region (MacGregor 1994; Todd et al. 1997). Most of the known large oil accumulations derived from coaly source rocks have been generated from Cenozoic coals, such as in the Gippsland Basin (Australia), the Taranaki Basin (New Zealand), and the Kutei Basin (Indonesia). Permian and Jurassic coal-sourced oils are known from, respectively, the Cooper Basin (Australia) and the Danish North Sea, but in general only minor quantities of oil appear to be related to coals of Permian and Jurassic age. In contrast, Carboniferous coals are only associated with gas, as demonstrated for example by the large gas deposits in the southern North Sea and The Netherlands. Overall, the oil generation capacity of coals seems to increase from the Carboniferous to the Cenozoic. This suggests a relationship to the evolution of more complex higher land plants through time, such that the highly diversified Cenozoic plant communities in particular have the potential to produce oil-prone coals. In addition to this overall vegetational factor, the depositional conditions of the precursor mires influenced the generation potential. The various aspects of oil generation from coals have been the focus of research at the Geological Survey of Denmark and Greenland (GEUS) for several years, and recently a worldwide database consisting of more than 500 coals has been the subject of a detailed study that aims to describe the oil window and the generation potential of coals as a function of coal composition and age.

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Compositional Characterization of Expelled and Residual Oils in the Source Rocks from Oil Generation–Expulsion Thermal Simulation Experiments

ACS Omega ◽

10.1021/acsomega.9b00260 ◽

2019 ◽

Vol 4 (5) ◽

pp. 8239-8248 ◽

Cited By ~ 2

Author(s):

Yahe Zhang ◽

Yifeng Wang ◽

Wei Ma ◽

Jincheng Lu ◽

Yuhong Liao ◽

...

Keyword(s):

Thermal Simulation ◽

Source Rocks ◽

Simulation Experiments ◽

Oil Generation ◽

Compositional Characterization

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Hydrocarbon generation and evolution of the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China

Interpretation ◽

10.1190/int-2018-0013.1 ◽

2018 ◽

Vol 6 (4) ◽

pp. SN11-SN21

Author(s):

Zhenkai Huang ◽

Maowen Li ◽

Quanyou Liu ◽

Xiaomin Xie ◽

Peng Liu ◽

...

Keyword(s):

Activation Energy ◽

Eastern China ◽

Source Rocks ◽

Bohai Bay ◽

Hydrocarbon Generation ◽

Bohai Bay Basin ◽

Jiyang Depression ◽

Generation Threshold ◽

Oil Generation ◽

Shahejie Formation

Systematic organic petrology and geochemistry analyses have been conducted in the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China. The results indicate that the main organic types of shale and nongypsum mudstone in the lower Es3 and upper Es4 member are I-II1 kerogen, and the predominant ([Formula: see text]) activation energy frequencies range from 57 to [Formula: see text]. The similar distribution characteristics in the two source rocks indicate that they have a similar hydrocarbon maturation process. An extensive pyrolysis analysis indicates that the source rocks of the upper Es4 member do not have an obvious double peak hydrocarbon generation model. Previous studies indicate that the hydrocarbon index peak at a depth of 2500–2700 m is affected by migrating hydrocarbon. Major differences are not observed in the hydrocarbon generation and evolution process of the shale and nongypsum mudstone. The primary oil generation threshold of the lower Es3 and upper Es4 members is approximately 3200 m, and the oil generation peak is approximately 3500 m. The activation energy distribution of the gypsum mudstone of the upper Es4 member is wider than that of the shale and nongypsum mudstone, and lower activation energies account for a larger proportion of the activation energies. The above factors may lead to a shallower oil generation threshold for gypsum mudstone compared with that for shale and nongypsum mudstone.

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GEOLOGY AND HYDROCARBON POTENTIAL OF THE SOUTHERN GEORGINA BASIN, AUSTRALIA

The APPEA Journal ◽

10.1071/aj00007 ◽

2001 ◽

Vol 41 (1) ◽

pp. 139 ◽

Cited By ~ 20

Author(s):

G.J. Ambrose ◽

P.D. Kruse ◽

P.E. Putnam

Keyword(s):

Early Carboniferous ◽

Source Rocks ◽

Peak Oil ◽

Middle Cambrian ◽

Late Cambrian ◽

Oil Generation ◽

World Class ◽

Lower Palaeozoic ◽

Southwestern Margin ◽

Intracratonic Basin

The Georgina Basin is an intracratonic basin on the central-northern Australian craton. Its southern portion includes a highly prospective Middle Cambrian petroleum system which remains largely unexplored. A plethora of stratigraphic names plagued previous exploration but the lithostratigraphy has now been rationalised using previously unpublished electric-log correlations and seismic and core data.Neoproterozoic and Lower Palaeozoic sedimentary rocks of the southern portion of the basin cover an area of 100,000 km2 and thicken into two main depocentres, the Toko and Dulcie Synclines. In and between these depocentres, a Middle Cambrian carbonate succession comprising Thorntonia Limestone and Arthur Creek Formation provides a prospective reservoir-source/seal couplet extending over 80,000 km2. The lower Arthur Creek Formation includes world class microbial source rocks recording total organic carbon (TOC) values of up to 16% and hydrocarbon yields up to 50 kg/tonne. This blanket source/seal unconformably overlies sheetlike, platform dolostone of the Thorntonia Limestone which provides the prime target reservoir. Intra- Arthur Creek high-permeability grainstone shoals are important secondary targets.In the Toko Syncline, Middle Cambrian source rocks entered the oil window during the Ordovician, corresponding to major sediment loading at this time. The gas window was reached prior to structuring associated with the Middle Devonian-Early Carboniferous Alice Springs Orogeny, and source rocks today lie in the dry gas window. In contrast, high-temperature basement granites have resulted in overmaturity of the Arthur Creek Formation in the Dulcie Syncline area. On platform areas adjacent to both these depocentres source rocks reached peak oil generation shortly after the Alice Springs Orogeny; numerous structural leads have been identified in these areas. In addition, an important stratigraphic play occurs in the Late Cambrian Arrinthrunga Formation (Hagen Member) on the southwestern margin of the basin. Key elements of the play are the pinchout of porous oil-stained, vuggy dolostone onto basement where top seal is provided by massive anhydrite while underlying Arthur Creek Formation shale provides a potential source.

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HYDROCARBON HABITAT OF THE COOPER/EROMANGA BASIN, AUSTRALIA

The APPEA Journal ◽

10.1071/aj82008 ◽

1983 ◽

Vol 23 (1) ◽

pp. 75 ◽

Cited By ~ 1

Author(s):

A. J. Kantsler ◽

T. J. C. Prudence ◽

A. C. Cook ◽

M. Zwigulis

Keyword(s):

Geothermal Gradient ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Oil Generation ◽

Late Tertiary ◽

Modelling Studies ◽

Permian Coal ◽

Intracratonic Basin ◽

Hydrocarbon Charge ◽

Eromanga Basin

The Cooper Basin is a complex intracratonic basin containing a Permian-Triassic succession which is uncomformably overlain by Jurassic-Cretaceous sediments of the Eromanga Basin. Abundant inertinite-rich humic source rocks in the Permian coal measures sequence have sourced some 3TCF recoverable gas and 300 million barrels recoverable natural gas liquids and oil found to date in Permian sandstones. Locally developed vitrinitic and exinite-rich humic source rocks in the Jurassic to Lower Cretaceous section have, together with Permian source rocks, contributed to a further 60 million barrels of recoverable oil found in fluvial Jurassic-Cretaceous sandstones.Maturity trends vary across the basin in response to a complex thermal history, resulting in a present-day geothermal gradient which ranges from 3.0°C/100 m to 6.0°C/100 m. Permian source rocks are generally mature to postmature for oil generation, and oil/condensate-prone and dry gas-prone kitchens exist in separate depositional troughs. Jurassic source rocks generally range from immature to mature but are postmature in the central Nappamerri Trough. The Nappamerri Trough is considered to have been the most prolific Jurassic oil kitchen because of the mature character of the crudes found in Jurassic reservoirs around its flanks.Outside the central Nappamerri Trough, maturation modelling studies show that most hydrocarbon generation followed rapid subsidence during the Cenomanian. Most syndepositional Permian structures are favourably located in time and space to receive this hydrocarbon charge. Late formed structures (Mid-Late Tertiary) are less favourably situated and are rarely filled to spill point.The high CO2 contents of the Permian gas (up to 50 percent) may be related to maturation of the humic Permian source rocks and thermal degradation of Permian crudes. However, the high δ13C of the CO2 (av. −6.9 percent) suggests some mixing with CO2 derived from thermal breakdown of carbonates within both the prospective sequence and economic basement.

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