The Geryon, Orthrus, Maenad and Urania Gas Fields are located in permit WA-267-P in approximately 1,200 m of water, and between 35 km northwest and 70 km north of the Gorgon Gas Field in the offshore Carnarvon Basin of Western Australia. Five wells were drilled in these fields between August 1999 and February 2001 as part of a six-well, three-year obligatory drilling program. The primary objectives were late Triassic sandstones of the upper Mungaroo Formation. The Geryon and Urania Fields are three-way footwall structures, while the Orthrus and Maenad Fields comprise four-way horst structures where progressively older units subcrop against the Callovian Unconformity. All objective reservoirs were amplitude associated and had strong AVO signatures, which was instrumental in the high exploration success rate and excellent exploration prediction of OGIP from seismic data.This paper will briefly discuss the description of late Triassic and early Jurassic reservoirs and the transition of the AA sand of the Mungaroo Formation from fluvial to marginal marine facies in the Greater Gorgon Area, the recent drilling results of the Triassic Prospects in WA-267-P, and the geophysical attributes of the AA sand Mungaroo Formation reservoirs.The WA-267-P Triassic Gas Fields are estimated to contain approximately 210 billion m3 (7.4 TCF) recoverable sales gas. The close proximity of these Triassic gas fields to each other, the clean gas composition and size of resource base suggests these fields are excellent candidates for a future gas development in Western Australia.
The Jansz gas field is located in permit WA-268-P, 70 km northwest of the Gorgon gas field in the Carnarvon Basin. The Jansz–1 discovery well was drilled in April 2000 and intersected 29 m of net gas pay in an Oxfordian age shallow marine sandstone reservoir. The well drilled a stratigraphic trap on the western limb of the Kangaroo Syncline.The Io–1 well was drilled in January 2001 in the adjacent permit WA-267-P (18 km from Jansz–1) and intersected the same Oxfordian sandstone reservoir penetrated by Jansz–1, with a total of 44 m of net gas pay. The Tithonian and the Upper Triassic Brigadier Sandstone gas reservoirs at Geryon–1 (1999) and Callirhoe–1 (2001) in WA-267-P are in pressure communication with the Oxfordian gas reservoir at Jansz–1 and Io–1. Consequently, the three different age reservoirs comprise a single gas pool, with a common gas/water contact.The Jansz gas field has been delineated by four wells and 2D seismic. The gas sandstones have a prominent amplitude versus offset response, which defines the field limits. The Jansz gas field is confirmed by drilling to be an areally extensive (2,000 km2) gas accumulation with a gross column height of 400 m and an estimated 20 TCF (566 G.m3) recoverable sales gas, which represents 40% of the discovered gas resources in the deepwater Carnarvon Basin. The size of the Jansz gas field and its remoteness from existing pipeline gas markets suggests that an export LNG project will be the basis for its development.
The Esso-Hematite Mackerel oilfield is located approximately 70 kilometres offshore in the Gippsland Basin, south-eastern Australia. It is one of a number of fields in this basin in which the reservoir occurs beneath an unconformity at the top of the Latrobe Group which is of Paleocene-Eocene age. The trap has been formed within a topographic erosional feature, sealed by calcareous shales and mudstones of the Oligocene Lakes Entrance Formation. This paper covers two topics. The first is the history of, and problems related to, the definition of the irregularly eroded Latrobe surface. In particular, the use of migrated seismic data to particular, the use of migrated seismic data to define the Top of Latrobe is discussed. The second topic of the paper is the use of seismic stratigraphy to help plan the development of the field. Progradational seismic character in the Latrobe reservoir section is observed on the seismic data at Mackerel. Seismic stratigraphic work was integrated with the results from the four exploration wells to build a model of the reservoir section prior to field development. This model was then used to help plan the development well program. Finally, the results of development drilling to date are discussed and an evaluation made of the predevelopment geophysical and geological interpretation. predevelopment geophysical and geological interpretation Introduction The Esso-Hematite Mackerel oilfield is located approximately 70 kilometres offshore in the Gippsland Basin, south-eastern Australia (Figure 1). It is one of a number of fields in this basin in which the reservoir occurs at an unconformity at the top of the Latrobe Group which is of Paleocene-Eocene age. The Mackerel "structure" is not a structural closure in the strict sense but rather a combination of a number of elements. Dip to the south east is the result of the Latrobe paleoslope with its strike running along the south-eastern extremities of the Mackerel and Kingfish fields. The Latrobe section progrades from the north-west to the southeast. Dip progrades from the north-west to the southeast. Dip to the north-east and north-west is provided by erosion of the Marlin channel and by a feeder channel to the Marlin channel respectively. Finally closure to the south-west is the result of structural dip. The trap is sealed by calcareous shales and mudstones of the Oligocene Lakes Entrance Formation. THE DEFINITION The Mackerel feature was first mapped from seismic data in 1966 as a nose extending to the north-east from the Kingfish structure. It was first mapped as a closed feature after the 1967 seismic survey. The Mackerel-1 location was chosen to be on or near the crest of a large single northeast to south-west trending anticlinal closure (figure 2). Possible reserves were estimated to be up to 700 MMB. Possible reserves were estimated to be up to 700 MMB. In 1969, Mackerel-1 was drilled, intersecting the top of Latrobe within 0.5m of prediction. However, the results of Mackerel-1 were very disappointing, as the well intersected a gross oil column of only 18.5 metres reducing the estimated reserves to 30 MMB. In the following years, interpretation of new seismic data indicated that the Mackerel-1 discovery well had missed the crest of the structure and had drilled into a local erosional channel on what was now interpreted to be an irregular topographic surface, and reserve estimates for the field were upgraded to 140 MMB. In 1971, further seismic was shot over Mackerel. The structure (figure 3) was interpreted to consist of two crestal areas, the larger just to the south-west of Mackerel-1 and the smaller to the north, on the downside of a northwest-southeast trending fault.
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