Upper Jurassic–lowermost Cretaceous marine shale source rocks (Farsund Formation), North Sea: Kerogen composition and quality and the adverse effect of oil-based mud contamination on organic geochemical analyses

Petersen, Henrik I.; Hertle, M.; Sulsbrück, H.

doi:10.1016/j.coal.2017.02.006

Cited by 30 publications

(19 citation statements)

References 16 publications

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“…Currently, the most successful shale gas development is mainly in marine facies shales, such as the Longmaxi formation shale in South China [8,21,30,34], the Marcellus shale [8,21,30,34,36,37], and the Barnett shale in the US [38]. The organic matter type of marine shales is type I or type II [39][40][41]. Additionally, research on shale gas reservoirs has mainly focused on organic shale with type I or type II kerogen [42][43][44].…”

Section: Introductionmentioning

confidence: 99%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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This study focuses on the nanostructure of shale samples with type III kerogen and its effect on methane adsorption capacity. The composition, pore size distribution, and methane adsorption capacities of 12 shale samples were analyzed by using the high-pressure mercury injection experiment, low-temperature N2/CO2 adsorption experiments, and the isothermal methane adsorption experiment. The results show that the total organic carbon (TOC) content of the 12 shale samples ranges from 0.70% to ~35.84%. In shales with type III kerogen, clay minerals and organic matter tend to be deposited simultaneously. When the TOC content is higher than 10%, the clay minerals in these shale samples contribute more than 70% of the total inorganic matter. The CO2 adsorption experimental results show that micropores in shales with type III kerogen are mainly formed in organic matter. However, mesopores and macropores are significantly affected by the contents of clay minerals and quartz. The methane isothermal capacity experimental results show that the Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples is between 0.78 cm3/g and 9.26 cm3/g. Moreover, methane is mainly adsorbed in micropores and developed in organic matter, whereas the influence of mesopores and macropores on the methane adsorption capacity of shale with type III kerogen is small. At different stages, the influencing factors of methane adsorption capacity are different. When the TOC content is <1.4% or >4.5%, the methane adsorption capacity is positively correlated with the TOC content. When the TOC content is in the range of 1.4–4.5%, clay minerals have obviously positive effects on the methane adsorption capacity.

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Section: Introductionmentioning

confidence: 99%

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

et al. 2020

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“…The liquid potential is much less than the worldclass marine shales of the Upper Jurassic -lowermost Cretaceous Farsund Formation, but identifies the coal-bearing Bryne/Lulu strata as the most important secondary source rock in the Danish Central Graben. As an example, the total UEP of the about 850 m thick shale section of the Farsund Formation in the Jude-1 well located in the central part of the Danish Central Graben is ~142 MM boe/km 2 , and the UEO and UEG are ~78 MM boe/km 2 and ~63 MM boe/km 2 respectively (Petersen et al, 2017).…”

Section: Source Rock Qualitymentioning

confidence: 99%

“…The primary source rocks in the North Sea are the Upper Jurassic -lowermost Cretaceous marine shales of the Farsund, Mandal and Kimmeridge Clay Formations and equivalents (Damtoft et al, 1992;Cornford, 1998;Ineson et al, 2003;Justwan et al, 2005;Petersen et al, 2010Petersen et al, , 2016Petersen et al, , 2017. In the Danish Central Graben, these world-class source rocks have charged the major chalk fields which account for the vast majority of the daily production of approximately 150,000 brl of oil and 3.9 billion Sm 3 (c. 71,000 brl oil-equivalent) of gas (Danish Energy Agency, 2016).…”

Section: Introductionmentioning

confidence: 99%

A Review of the Coaly Source Rocks and Generated Petroleums in the Danish North Sea: An Underexplored Middle Jurassic Petroleum System?

Petersen

Hertle

2018

Journal of Petroleum Geology

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This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up...

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“…The principal source rocks throughout the entire North Sea region are the Upper Jurassic -lowermost Cretaceous (lower Upper Kimmeridgian -Ryazanian) marine shales which in the Danish Central Graben are constituted by the Farsund Formation ( Fig. 3) (see Thomsen et al (1983), Damtoft et al (1992), , Petersen et al (2013Petersen et al ( , 2017). The Farsund Formation is equivalent to the Kimmeridge Clay and Mandal Formations in the UK and Norwegian Central Grabens and the South Viking Graben (Cornford, 1994(Cornford, , 1998Justwan et al, 2006;Ohm et al, 2006).…”

Section: Ringkøbing -Fyn High Mid North Sea Highmentioning

confidence: 99%

Temporal and Spatial Distribution of Original Source Rock Potential in Upper Jurassic – Lowermost Cretaceous Marine Shales, Danish Central Graben, North Sea

Petersen¹,

Hertle

2020

Journal of Petroleum Geology

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The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.

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Upper Jurassic–lowermost Cretaceous marine shale source rocks (Farsund Formation), North Sea: Kerogen composition and quality and the adverse effect of oil-based mud contamination on organic geochemical analyses

Cited by 30 publications

References 16 publications

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

A Review of the Coaly Source Rocks and Generated Petroleums in the Danish North Sea: An Underexplored Middle Jurassic Petroleum System?

Temporal and Spatial Distribution of Original Source Rock Potential in Upper Jurassic – Lowermost Cretaceous Marine Shales, Danish Central Graben, North Sea

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