A review of oil geochemistry in the UK North Sea

by Akinniyi Akinwumiju

The geochemical characteristics of UK North Sea oils have been investigated over very many years with the oils mainly being typed to the Kimmeridge Clay source rock (dominated by oil-prone Type II marine kerogen; e.g. Cornford, 1998; Underhill, 1998; Gautier, 2005; Raji et al., 2015), except for the Beatrice oil from the Inner Moray Firth area which has been attributed to mixed sourcing from Devonian and Middle Jurassic lacustrine source rocks (Peters et al., 1989). This technical note briefly reviews the geochemistry of some UK North Sea oils using selected key parameters including gasoline, aromatic hydrocarbon, biomarker and stable carbon isotope compositions from recently acquired geochemical data for 76 legacy oils (IGI/GHGeochem, 2016/17).

The graph of toluene/nC7 versus nC7/MCH ratios (Fig. 1) suggests the bulk of the oils have not undergone any significant oil alteration processes including biodegradation, water washing and evaporative fractionation, whilst three oils (from Toni field (well 16/17-16) & well 16/12A-4) plot as fractionated oils (that is, residual liquids). Typically, these residual liquids are enriched in cyclohexanes & aromatics, and depleted in the light hydrocarbons and branched alkanes in particular as a result of evaporitic fractionation (i.e. gas stripping) of originally normal reservoired oils (Thompson, 1987). Some other oils show less obvious evidence of this process.

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Figure 1: Plot of the ratios of toluene/n-heptane versusn-heptane/methylcyclohexane for the UK oils (modified from Thompson, 1987).

Aromatic hydrocarbons are especially useful in determining the maturity of the source rock of an oil as they tend to carry a strong maturity signature since the difference in the compositions of these compounds are less influenced by organic matter inputs than the biomarkers, particularly steranes. Calculated vitrinite reflectance values from Methylphenanthrene Index (Fig. 2) indicate early to normal oil window maturity for most of the samples suggesting that the oils have been sourced from early to mid-oil mature source rock(s).

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Figure 2: Histogram of calculated vitrinite reflectance (from MPI1); the calibration is from Radke et al. (1986).

A cross-plot of the stable carbon isotopic composition of the saturated hydrocarbon fraction against the source environment-sensitive pristane/phytane ratio (two very common and low error parameters) indicates that the oils studied here mostly belong to a single (broadly) genetic oil family (Fig. 3). The bulk of the oils show a very good correlation to the extractable organic matter (EOM) from the available Upper Jurassic Kimmeridge Clay Formation (KCF) samples with possible contributions from the Middle to Upper Jurassic more terrestrial Heather Formation, although only two samples of this have EOM data (Fig. 3).

However, considering the apparently lower maturity (early oil window) indicated for some of the oils, particularly those from the central part of the UK North Sea (Fig. 2), it is possible that these oils have been expelled from localised kitchens in the area where the KCF source rock contains a significant proportion of Type lIS kerogen (e.g. Peters et al., 2005). Unlike a typical Type II marine kerogen, the weakly bonded Type IIS sulphur-rich kerogen (usually with organic sulphur content greater than 6 wt.% & atomic sulphur/carbon ratio equal or greater than 0.04) starts to generate oil at lower thermal exposure in the 410-415 Tmax range (Orr, 1986; Baskin & Peters, 1992; Peters et al., 2005) and becomes fully mature in the 420-445 Tmax (0.4-0.85%Roe) range.

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Figure 3: Cross-plot of pristane/phytane versus saturated hydrocarbon carbon isotope composition for (left) source rock extractable organic matter (EOM) and (right) UK North Sea oils. EOM data source: IGI’s Inner Moray Firth multiclient database.

Further geochemical data for these legacy oils are available in the updated IGI/GHGeochem’s (2017) multiclient UK North Sea oils analytical reports and database, details of which can be found on IGI’s website.



Baskin, D.K. and Peters, K.E. (1992) Early generation characteristics of a sulfur-rich Monterey kerogen. American Association of Petroleum Geologists Bulletin, 76, p. 1-13.

Cornford, C., 1998. Source rocks and hydrocarbons of the North Sea. In: Glennie, K.W. (ed.), Petroleum Geology of the North Sea (4th ed). Blackwell Science Ltd., London, p. 376-462.

Gautier, D.L., 2005. Kimmeridgean Shales Total Petroleum System of the North Sea Graben Province: U.S. Geological Survey Bulletin 2204-C, 24. Available online http://pubs.usgs.gov/bul/2204/c [accessed 15. July.2014].

Orr, W.L. (1986) Kerogen/asphaltene/sulfur relationships in sulfur-rich Monterey oils. Organic Geochemistry 10, p. 499—516.

Peters, K.E., Moldowan, J.M., Driscole, A.R. & Demaison, G.J. (1989) Origin of Beatrice oil by co-sourcing from Devonian and Middle Jurassic source rocks, Inner Moray Firth, United Kingdom. AAPG Bulletin 73(4), p. 454-471.

Peters, K. E., Walters C. C. and Moldowan, J. M. (2005) Biomarkers and Isotopes in the Environment and Human History. 2nd ed., Vol. 2, Cambridge: Cambridge University Press, 471 p.

Radke, M., Welte, D.H. & Willsch, H. (1986) Maturity parameters based on aromatic hydrocarbons: influence of the organic matter type. Organic Geochemistry 10, p. 51-63.

Raji, M., Grocke, D.R, Greenwell, H.C., Gluyas, J.G., Cornford, C., 2015.The effect of interbedding on shale reservoir properties. Marine and Petroleum Geology 67, p.154-169.

Underhill, J.R., (1998) Jurassic. In: Glennie, K.W. (ed.), Petroleum geology of the North Sea (4th ed.). Blackwell Science Ltd.,  p. 245–293.

Thompson, K.F.M. (1987)  Fractionated aromatic petroleums and the generation of gas-condensates. Organic Geochemistry 11, p. 573-590.


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