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1 Department of Geology, University of Oslo, PO Box 1047 Blindern, N-0316 Oslo, Norway
2 Norwegian Petroleum Directorate, PO Box 600, N-4001 Stavanger, Norway
3 Brekke Chemometrical, Leirstad 27, 6800 Førde, Norway
4 Rogaland Research - RF, PO Box 2503, Ullandhaug, N-4004 Stavanger, Norway
5 Present Address: ElfAquitaine Norge a/s, PO Box 168, N-4001 Stavanger, Norway
Thirty-three oil/condensate samples, representing most of the known petroleum accumulations in the Haltenbanken region, were analysed by a comprehensive geochemical scheme to determine possible genetic relationships. The organic geochemistry of the samples is comparatively invariate if one excludes the characteristics attributed to maturity differences and phase-induced fractionation. On this basis, in a gross sense, the C10+ fractions of most of the petroleum samples are suggested to be derived from the Spekk Formation. However, the ratio of pristane to phytane and the stable carbon isotope composition of the petroleums proved useful to differentiate this picture. The database was subjectively divided into three main genetic groups which show dependence on the geographical location of the fields.
Group 1, comprising the samples from Njord, Smørbukk Sør well 6506/12-5, Tyrihans N, Tyrihans S, Trestakk and the 6506/12-3 DST 6 sample above the Smørbukk Sør main reservoir, is clearly differentiated from Group 2, comprising samples from Midgard, 6407/2-2 DST 1 and from Alve 6507/3-1 DST 3. Group 3, comprising samples from Draugen, Heidrun, Mikkel plus the Smørbukk Sør petroleum 6506/12-3 DST 1, forms an intermediate population between Groups 1 and 2. In general, Group 2 is confined to the easterly, more proximal part of the basin, while Group 1 fields have drainage areas in distal, more deeply buried regions of the basin. Available data on the geochemistry of the two major source rocks in the region, the Spekk Formation and the deeper Åre Formation, lead us to conclude that the C15+ fractions of the Group 1 petroleums are derived predominantly from a distal marine anoxic facies of the Spekk Formation. Group 2 forms the other end member, supposedly sou rced mainly from more terrestrially influenced proximal marine (partly dysaerobic?) isotopically heavier shales of the Spekk Formation. Group 3 contains characteristics of both source-rock facies. We see no evidence in biomarker distributions of the current database for significant contributions to the heavy ends of the reservoired petroleums from Åre coals. However, we cannot, based on our limited source-rock database, exclude contributions in some localities from Åre Formation shales. Furthermore, we have no evidence to exclude contributions to the light hydrocarbon range from the Åre Formation, e.g. condensate/gas contributions. We feel that the Spekk Formation varies significantly in geochemistry, both laterally and vertically, i.e. according to Walters law, and that this formation is less homogeneous with respect to geochemistry and the depositional and early diagenetic environment than commonly described. The metal composition of the petroleums generally substantiates these interp retations on laterally varying dysaerobic/anoxic conditions of the Spekk Formation, even if it proved difficult in cases to compare metal distributions in petroleums with drastically different gas/oil ratios.
Because most fields, despite overall similarities, contain petroleum with specific singular minor characteristics, we suggest that, with the exception of the Draugen and Midgard Fields, lateral migration has been predominantly short- to medium-range with respect to intra-field distances. A core extract from well 6609/11-1 (Helgeland basin) deserves special attention, as our data suggest that this core at 2561 m contains a zone of terrestrially derived oil, possibly lacushine, most likely sourced from a Triassic or Palaeozoic formation.
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