C. I. Macaulay1,5, D. Beckett2, K. Braithwaite3, D. Bliefnick3 and B. Philps4

1Isotope Geosciences Unit, Scottish Universities Research and Reactor Centre, East Kilbride G75 0QF.

2BG International, 100 Thames Valley Park Drive, Reading, Berkshire RG6 1PT.

3BG Technology, Gas Research and Technology Centre, Ashby Road, Loughborough, Leicestershire LE11 3GR.

4Royal School of Mines, Imperial College, London SW7 2BP.

5 Corresponding author: email

Present address: Department of Geology and Geophysics, University of Edinburgh, Grant Institute, West Mains Road, Edinburgh EH9 3JW.

The hydrocarbon reservoir of the Hasdrubal field (offshore Tunisia) lies within the Eocene El Garia Formation. This formation was deposited on a shallow north- to NE-facing ramp in the Early Eocene and is composed of a belt of nummulitic wackestones-grainstones. The nummulitic facies occupies a range of depositional environments from outer to mid ramp. In addition to Hasdrubal, several other producing oil- and gasfields have been discovered in the variably dolomitised El Garia Formation offshore Tunisia.

Cores from three Hasdrubal wells were examined. Reservoir quality shows a limited relationship to primary depositional fabric and has been influenced significantly by compaction and later diagenesis. The highest permeabilities are typically developed within a dolomitised zone which occurs near the middle of the reservoir interval across the entire field, and which may follow a primary wackestone lithofabric (typically 20-30% bulk volume dolomite, with porosities of 15-22% and permeabilities of 1-30mD). Fractures, particularly in zones surrounding faults, have resulted in enhanced permeabilities.

Combined results of isotope (?18O -5.0 to -7.3‰PDB) and fluid inclusion (Th 80-90C) analyses of dolomites from this dolomitised zone indicate that matrix dolomites are burial diagenesis cements. Dolomitisation of the reservoir was a "closed system" event and was not the result of major fluid flow or mixing. Magnesium ions for dolomitisation were derived from the transformation of high-Mg to low-Mg calcite in nummulite tests within the reservoir facies.

Our analyses indicate that calcite cements were precipitated at temperatures of up to almost 150C in primary and secondary pores and in variably-sealed fractures. Fracture lining and filling cements show a range of ?18O values, which suggests that the fractures acted as fluid conduits over a range of temperatures during burial diagenesis. Fracture densities measured in core increase rapidly close to seismically-resolvable faults in the reservoir facies. Fracturing probably resulted in the leakage of hydrocarbons through the Compact Micrite Formation seal which overlies the accumulation, as well as facilitating the ingress of hot fluids from stratigraphically deeper levels in the basin.

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