Oil and gas generation and expulsion from Golden Beach and lower Latrobe source intervals in the central eastern portion of the Gippsland Basin occurred in Late Cretaceous and Early Paleocene time due to higher heatflow and subsidence of this area prior to formation of trapping structures in Late Eocene to Middle Miocene time (Fig. 4) (Moore and others, 1992; Keall and Smith, 1996). Subsequent to Miocene trap formation, oil has been generated from younger Latrobe source intervals, accounting for the predominance of oil fields in this region (Moore and others, 1992). Gas has been the dominant hydrocarbon generated since trap formation in the area north of Barracouta field, which explains the predominance of gas fields in the north and western portions of the basin (Moore and others, 1992). 

Vertical migration of 2 km or more occurs in the central portions of the Gippsland Basin, and significant lateral migration is cited for accumulation on the Northern Platform (Fig. 4) (Clark and Thomas, 1988). Discovery trends that locate most oil in the middle of the basin and most gas toward the margins are explained by the migration paths and the state of maturity of the immediately adjacent synclinal ‘kitchen’ (Moore and others, 1992) and the timing of compressional trap formation (Keall and Smith, 1996). Oil fields found on the margins of the basin are thought to tap only oil-mature source rocks within the migration area (Moore and others, 1992). Hydrocarbons from the deepest parts of the basin were expelled during an early phase of generation in the Paleocene, but the main phase of generation has been in the last 20 m. y. (Fig. 6) (Keall and Smith, 1996). Structures in the northwest were not available for early oil migration so these structures have trapped mostly mature gas (Keall and Smith, 1996). Source rocks in the southwestern portions of the basin are still in the oil window (Mebberson, 1989; Rahmanian and others, 1990; Keall and Smith, 1996).

There may have been some contribution of hydrocarbons from Strzelecki Group source rocks to the Latrobe petroleum system. Hydrocarbon generation and expulsion modeling from onshore wells in the Seaspray Depression and on the Northern Strzelecki Terrace near Lake Wellington indicate that there was one widespread expulsion event in this area at 115-95 Ma and a second event detected in some wells between 80 and 40 Ma with one area possibly continuing to the present (Mehin and Bock, 1998).

OVERBURDEN ROCK
Marine sediments of the Lower Oligocene through Miocene Seaspray Group overlie and form a regional seal for the entire offshore and most of the onshore area, with the notable exception of the Latrobe Valley Trough where nonmarine conditions were prevalent and deposition of thick coals continued (Fig. 2 and Fig. 4A). This group represents a widespread marine transgression initiated in Oligocene time and reaching maximum in Early to Middle Miocene time, followed by regression beginning in Late Miocene to Early Pliocene time. It is characterized by marine shales, marls, limestones, calcareous claystones, siltstones, and sandstones more than 1,800 m thick, with successive periods of submarine channeling and channel fill (Mehin and Bock, 1998). 

The Seaspray Group is divided into three formations: Lakes Entrance, Gippsland Limestone, and Jemmy’s Point/Tambo River (Fig. 2) (Mehin and Bock, 1998). The regional seal for the majority of oil and gas fields of the offshore area is the Lakes Entrance Formation (Mehin and Bock, 1998), which consists of sandstone, marl, and limestone deposited unconformably on the Latrobe Group. Marls and calcarenite of the Gippsland Limestone Formation represent the maximum marine highstand in the Miocene, and are as thick as 800 m in the offshore area (Mehin and Bock, 1998). The Miocene to lower Pliocene Jemmy’s Point Formation consists of marls, limestone, and shoreline sandstones of the late highstand (Mehin and Bock, 1998).

Onshore, the upper Pliocene Sale Group is nonmarine sandstones and claystones (Mehin and Bock, 1998).

TRAP TYPES
Compression from Eocene through Early Miocene time resulted in anticlines and fault traps (Fig. 2, Fig. 3, Fig. 4, and Fig. 6) (Mebberson, 1989; Moore and others, 1992; Ozimic and others, 1987). Most of the large accumulations occur immediately below the Top Latrobe unconformity in anticlines eroded and then sealed by the overlying regional Seaspray Group. The traps were in place in the Kingfish Field area at approximately 28 Ma (Late Oligocene) and in the Barracouta Field area at approximately 22 Ma (Early Miocene) (Mebberson, 1989). At Marlin Field, erosional topography creates a larger closure than the anticline alone (McPhee, 1976). Additional traps within the Latrobe Group are fault traps sealed by the fault or juxtaposed shales (Clark and Thomas 1988). However, favorable juxtaposition is difficult in this fluvial, alluvial, and shoreline sandstone dominated group. Intra-Latrobe Group traps in the Barracouta Field area were in place at approximately 34 Ma (Early Oligocene) (Mebberson, 1989).

Successful fault traps within the Golden Beach Group are formed by lacustrine sandstones juxtaposed against thick lacustrine shale sections. The Kipper discovery appears to be an inverted structure containing hydrocarbons at several levels: Top Latrobe, intra-Latrobe Group and Golden Beach Group (Sloan and others, 1992). The Golden Beach accumulation is sealed by a basalt flow and faulted against shale (Sloan and others, 1992).

RESERVOIR ROCK
The Latrobe Group sandstones are the primary reservoirs of the Gippsland Basin (Petroconsultants, 1996; McKerron and others, 1998; Thornton and others, 1980) with diagenesis an important factor in reservoir quality. Widespread dolomite cement, grain and cement solution secondary porosity development, illite, kaolinite and chlorite cement, and quartz overgrowths are all factors either occluding porosity or enhancing porosity. Dolomite cement occurs as pore filling and grain replacement and makes up as much as 30% of the total rock volume (Bodard and others, 1984). This widespread and variable cementation is the major cause of porosity reduction in the Latrobe Group.

Secondary porosity accounts for most of the reservoir porosity, principally as dissolution of dolomite cement that is possibly associated with hydrocarbon emplacement (Bodard and others, 1984). Dissolution of clay matrix is also a mechanism important in developing secondary porosity in the group (Bodard and others, 1984), as is dissolution of feldspars and rock fragments. Porosity may then be occluded by authigenic kaolinite growth, chlorite filling, quartz cementation and overgrowths, and compaction (Bodard and others, 1984). Porosity versus depth plots for Latrobe Group sandstone reservoirs of the Basker Manta area, suggest a severe decline in porosity approaching 4 km burial depth indicating a possible maximum depth of target reservoirs (Clark and Thomas, 1988).

SEAL ROCK
Regionally extensive marine shales and marls of the Seaspray Group provide excellent seals for most of the fields in the area (Fig. 2, Fig. 4, and Fig. 6). Shales within the Latrobe Group provide seals for intra-Latrobe Group fields and a basalt flow provides the seal for at least one accumulation.

UNDISCOVERED PETROLEUM BY ASSESSMENT UNIT
Deeper, more marginal, and onshore prospects, as well as a shift to exploration for gas, may be the best targets of opportunity for future development of the petroleum resources in the Gippsland Basin Province (Megallaa, 1997; Mudge and Curry, 1992; Stainforth, 1984; Mehin and Bock, 1998; Collins, 1997; Collins and Megallaa, 1997). Producing horizons below the unconformity at the top of the Latrobe Group have been the most explored targets and that play is in its mature stage. Intra-Latrobe plays have become more attractive targets but there are variabilities of trap and migration to consider. Faults, for example, have been shown to act as seals in this basin, however, because of the nature of fluvial and shoreline sedimentary patterns, it is probably a rare circumstance to have a shale thick enough and in the right faulted position to act as a seal. Lateral facies changes also add a stratigraphic component to fault and rollover traps within the group and migration paths from the source areas may not encounter trapping structures.

Exploration targets down to the base of the Golden Beach Group, as well as within the Strzelecki Group, need to be considered around the margins of the basin. Possible source rocks of the Strzelecki Group are not well known from the subsurface but abundant thin coals are present in outcrop. These coals are projected to be thicker and more numerous in the subsurface. Although the source-rock quality of these coals is good and maturation and expulsion of hydrocarbons has been predicted (Mehin and Bock, 1998), there are uncertainties with regard to the timing of trap formation, continued integrity of traps, and the quality of potential Strzelecki Group reservoir rocks.