T. B.  Abay1*, D. A. Karlsen1 and S. E. Ohm2

1 Department of Geosciences, University of Oslo, PO Box 1047 Blindern, N-0316 Oslo, Norway.

2 ConocoPhillips Norge, PO Box 220, N-4098 Tananger, Norway.

*corresponding author, email:

The Embla field, located in the Greater Ekofisk area (Norwegian North Sea), produces oil from Palaeozoic reservoir rocks comprising moderately to well sorted micaceous sandstones and silty mudstones. The reservoir is divided into ‘‘upper’’ and ‘‘lower’’ sandstones by a mudstone/siltstone succession, and is overlain by the Jurassic Tyne Group. Below are Palaeozoic mudstones and fractured rhyolites. Bitumen coatings on sand grains and in the fractured rhyolites have been recorded at Embla, and the bitumen may modify the dynamic response of the reservoir during production.

In this paper, the organic geochemistry of core extracts and DST oil from well 2-7/26S were analysed by Iatroscan TLC-FID, GC-FID and GC-MS in order to investigate heterogeneities in petroleum composition, thermal maturity and biodegradation between the lower and upper sandstones and the fractured rhyolites, and to investigate the trap filling history.

The geochemical data suggest that the reservoir at Embla has received two pulses of oil. The first oil pulse represents a palaeo-filling event which is interpreted to have charged the reservoir around the end of the Triassic. This oil was biodegraded in the reservoir which must therefore have been uplifted to depths of less than ca. 2km (equivalent to ca. 70ºC). Because of later burial, the reservoir is at a depth of more than 4km at the present day. This palaeo-oil is compositionally different to most North Sea oils, and may be derived from a source rock containing Type II kerogen. The second more recent oil pulse, comprising “Ekofisk” type oil, started to refill the Embla structure when the Kimmeridge-equivalent Mandal Formation became thermally mature around the end of the Cretaceous. This second oil migrated along the Skrubbe Fault.

Extracts from the upper and lower sandstones are medium to highly mature and show different biomarker and aromatic maturity signatures. The bitumen from the lower sandstone is more mature as indicated by ratios of diasteranes/(diasteranes + regular steranes), 20S/(20S + 20R) steranes, and calculated vitrinite reflectances. Bitumen from rhyolite samples shows the lowest maturity. This suggests that the oil trapped in the fractured rhyolites represents the early oil pulse which did not undergo in-reservoir cracking or biodegradation after its emplacement

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