There are three major stratigraphic targets that have proved successful in exploration for hydrocarbons, (1) Top Latrobe, (2) intra-Latrobe, and (3) pre-Latrobe. The largest fields and approximately 85% of the total discovered reserves are found in Latrobe Group reservoirs (Petroconsultants, 1996). Fields also occur in strata younger that the Top Latrobe such as Lakes Entrance Field (Ozmic and others, 1987).

The earliest offshore discoveries were in anticlines under the unconformity that defines Top Latrobe. These remain the largest fields discovered in the basin. The Top Latrobe unconformity was developed by a tectonic event 50 Ma (Duff and others, 1991). This unconformity eroded the Latrobe Group strata and anticlines involving the Latrobe Group (Duff and others, 1991; Gross, 1993). Reservoirs beneath the Top Latrobe unconformity vary from Late Cretaceous to Eocene in age (Gross, 1993). The fields immediately below the Top Latrobe are fed by hydrocarbons migrating from large areas of the basin and adjacent synclines (Rahmanian and others, 1990).

Intra-Latrobe fields contain hydrocarbons in Latrobe reservoirs that are not associated with the Top Latrobe unconformity (Clark and Thomas, 1988). These reservoirs are fed by local migration of hydrocarbons within fault blocks and reflect maturation of source rock in a smaller area (Rahmanian and others, 1990; Sloan, 1987).

Pre-Latrobe fields are located on the edges of the basin with reservoirs in the Golden Beach Group (Sloan and others, 1992).

Although Gippsland Basin oils have been attributed to the same source rock, there is considerable variation in chemical composition ranging from very waxy and paraffinic to light and condensate-like (Burns and others 1987; Moore and others, 1992). These differences are attributed to oil being generated at different maturities, low reservoir temperatures, and the presence of a fresh-water wedge that extends from the present shoreline east and south into the basin and to depths of as much as 2,400 m (Fig. 5) (Mebberson, 1989; Moore and others, 1992: Burns and others, 1987). Oils in traps at Top Latrobe are not chemically distinct from oils in traps within the Latrobe Group (Clark and Thomas, 1988). Gas generation from a deep overmature source was suggested by Burns and others (1987). Their analysis of six fields showed the carbon isotope composition of methane to range from –31.4 to –41.4 per mil.

Oil gravity ranges from 15.4° -64° API, and sulfur is less than 0.5% (Burns and others, 1987; Clark and Thomas, 1988; Petroconsultants, 1996). A trend of oil gravity increasing with maturity of the source rocks was shown by Burns and others (1987). Their work also suggested that in Wirrah Field (Fig. 5), accumulations at different reservoir levels were derived from source rocks at different maturities; reserves at 2,633 m and 2,046 m were interpreted as being from source rocks in the early mature stage, whereas reserves at 2,195 m were from source rocks at the peak mature stage.

Published analysis of one onshore field, one nearshore discovery and two offshore fields described the following ranges: methane 82.6-93.3%; ethane nil-6.8%; propane + nil-8.6%; nitrogen nil-18.68%; oxygen nil-.82%; CO₂ 0.01-2.0% (McPhee, 1976).

The only production or discovery deemed economic from the onshore portion of the Gippsland Basin is at Lakes Entrance. This field lies on the Northern Platform directly north of the Lake Wellington fault system that defines the southern edge of the platform (Fig. 3 and Fig. 5). The reservoir is the Oligocene Lakes Entrance Formation, which occurs in a stratigraphic trap and drape structure overlying paleo-topography (Ozimic and others, 1987). This is a marine sandstone described as poorly cemented, calcareous, glauconitic, and oolitic, with porosity as much as 36% and permeability averaging 10 millidarcy (mD). The field lies at a depth of approximately 385 m. Oil from this field is heavy, API 15.4° and tarry, and considered to be biodegraded and fresh water washed (Ozimic and others, 1987).

SOURCE ROCK
The results of analyses of oils and potential source rocks indicate that terrestrial source rocks--coals and lower coastal plain coaly shales--show excellent correlation with the produced oils of the Gippsland Basin (Moore and others, 1992; Philp, 1994). These strata in the Latrobe Group contain total organic carbon contents (TOC) as much as 70 wt% and hydrocarbon indicies (HI) as high as 400 mg hydrocarbon (HC)/g TOC and are considered to be the source rocks in the basin (Bradshaw and others, 1998; Rahmanian and others, 1990; Howes, 1997; MacGregor, 1994; Hocking, 1976; Fielding, 1992). Marine shales of this group are reported to have TOC values of 1-3 wt%. The average TOC of the Golden Beach Group is 2-3 wt% (Sloan and others, 1992). The dominantly aggradational setting described by Fielding (1992) during the Cretaceous to Paleocene period of Latrobe deposition may have favored deposition of coal and coaly shale source rocks. Furthermore, McCabe and Shanley (1992) described low-ash coals that are best developed landward of aggradational shorelines and discussed the development of raised peat mires that may have influenced aggradation. One oil sample showed an algal influence in a dominantly terrestrial character (Moore and others, 1992; Marshall, 1989).

The estimated 1,000-m-thick Kipper Shale did not correlate with any of the oils analyzed (Moore and others, 1992). This lacustrine shale measured at the Kipper well averages TOC 2-4 wt% and is characterized as gas-prone with S2 values below 2 milligrams/gram and HI below 100 mg hydrocarbon (HC)/g TOC (Sloan and others, 1992). Well intersections at Kipper, Tuna, Emperor, Sunfish and Sole encountered more than 700 m of lacustrine shale described as lean source rocks with HI of 80-200 mg hydrocarbon (HC)/g TOC (Moore and others, 1992). The poor source-rock quality of this lacustrine shale has been attributed to oxidation of organic matter due to seasonal turnover of the lake waters of this cold climate setting at lat 65° S (Partridge, 1996; Moore and others, 1992). This lacustrine shale could be a source for some gas in the Gippsland Basin (Moore and others, 1992).

Possible source rocks in the coaly section of the Strzelecki Group penetrated in onshore wells range from 0.21 to 26.83 wt% TOC, with vitrinite reflectance in oil (R_o) values of 0.35-1.04 % and HI values from 23-179 mg hydrocarbon (HC)/g TOC (Mehin and Bock, 1998).