The Kingfish field, currently Australia's largest producing oil field, lies 48 miles offshore southeastern Victoria in 250 ft of water. The field occurs within a large, essentially, east-west trending topographic high on the Latrobe unconformity surface sealed by fine grained clastics of the Upper Eocene Gurnard and Oligocene Lakes Entrance Formations. The reservoir itself is formed by Lower Eocene sediments of interdeltaic origin.The discovery well, Kingfish 1, was spudded on 6 April 1967. This well indicated the severity of a suspected seismic velocity gradient, a function of high velocity channel deposits in Miocene sediments overlying the crest of the Latrobe unconformity surface. Additional seismic coverage and two outpost wells provided sufficient structural and stratigraphic control to define a commercial oil field having a maximum of 270 ft of vertical relief over an area of some 28 sq mi at the oil-water contact of 7,566 ft subsea.Following completion of the 42 well development drilling program for the A and B platforms the Kingfish oil field was put on stream on 21 April 1971. Proved and probable reserves have been initially estimated at 1,060 MM STB. The field has flowed oil at rates in excess of 180,000 STB/D for a cumulative production to the end of 1972 of 83 MM STB.

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Dolomite cement had been recognised within fluvio-deltaic facies sandstones of the Gippsland Basin Marlin field N-1 (Eocene) gas reservoir in the initial wildcat and two stepout wells. Although initially thought to be insignificant, the additional control provided by development drilling indicated that the degree and extent of dolomite cementation within the reservoir sandstones could be wide-ranging enough significantly to reduce reserves and influence reservoir performance. A study to define the area and degree of dolomite cementation within the reservoir showed that the distribution pattern within the 5 major sandstone units fell into 3 distinct groups. Whereas the 3 stratigraphically oldest (N-1.5, N-1.4 and N-1.3) units were only dolomitized within the northeastern portion of the field area, the N-1.2 unit was dolomite cemented field-wide. The youngest (N-1.1) unit, which unconformably overlies the truncated N-1.2 unit, is devoid of significant dolomite influence.Dolomitization of the N-1 sandstone units is interpreted to have occurred during a phase of estuarine-restricted marine shale deposition which followed the truncation of the N-1.2 sandstone unit. Although these estuarine dolomitic shales are absent by erosion at Marlin, they are present in the adjacent Tuna field area. Distribution of the dolomite cement within the reservoir sandstones was controlled by the subcrop pattern of the sandstone units during the deposition of the estuarine sediments.Petrological and x-ray diffraction information strongly suggest primary dolomite cementation, and not dolomitization of some pre-existing carbonate cement. The petrological, core analysis and geological information was integrated with the interpretation of wireline porosity logs to obtain reservoir unit average porosities and calculate reserves.The currently estimated initial N-1 reservoir dry gas reserves are 2.72 TSCF. If the reservoir sandstones were not dolomite cemented, reserves would be 3.15 TSCF, that is 14% greater.