Seismic facies mapping is an underutilized tool for getting extra geology in to your exploration, or development. It is a key component of palaeogeography mapping that help show different types and locations of seals and reservoirs. Both manual and automated facies mapping, on 2D and 3D seismic, when calibrated to local wells, can help de-risk crucial components of a play. In many areas today where deep water or new frontier exploration is undertaken, there is often little or no well control and seismic facies mapping, allied to analogues, may be your only tool for getting at the geology in your palaeogeography maps. This talk will apply geological models to, and discuss, the construction of manual seismic facies maps which are then used to guide automated facies map work. Manual facies mapping is undertaken once sequence boundaries have been mapped and named. Each different facies identified is given the name of upper and lower boundaries and the facies name and then the horizon is picked so that the facies extent is shown on a base map. Once completed, polygons encompass this facies. The final map uses all polygons constructed, along with well logs for that sequence. Automated facies maps start with RMS and maximum amplitude maps of the sequence, then possibly of proportional slices within the sequence and then we may construct waveform facies maps or spectral decomposition maps of the interval. All these maps are considered with the interval's isochron map and at least gamma log windows at wells, with appropriate geology transcribed to finally construct the palaeogeography map of the interval.

The early Permian Patchawarra Formation is one of the principal gas producing intervals of the South Australian Cooper Basin (Government of South Australia., 2022). The gross depositional environment (GDE) for this interval is reported to be dominantly fluvial plain (Strong et al., 2002 and Stephens et al., 2014). However, recent logging and interpretation of 296 m of the Patchawarra Formation from seven wells (Dullingari 39, Fly Lake 2, Halsam 1, Le Chiffre 1, Moomba 194, Pando 1 and Talaq 1), from the South Australian Cooper Basin, indicate the presence of significant lacustrine depositional environments, including shoreface, possible lacustrine turbidites and potential incised valleys, all of which may alter exploration and development strategies.

Some 1800 wildcat wells have been drilled in Australia since 1900 to test over 30 basins ranging in age from Proterozoic to Tertiary. In New Zealand some 400 wells have tested three basins from Cretaceous to Tertiary in age. Fewer than 100 wells have specifically targeted submarine fan sands. Total discovered recoverable oil and gas reserves in Australia and New Zealand are around 6700 million barrels of oil and 85 TCF of gas, and submarine fan reserves account for only 300 million barrels of oil and 13 TCF of gas. Most of these fans reserves are in Upper Jurassic synrift and Lower Cretaceous late synrift sediments in the Carnarvon Basin of Western Australia. The few New Zealand submarine fan reserves are in Tertiary post breakup sediments. The Carnarvon Basin of Western Australia contains five third-order depositional sequences, each with lowstand clastics developed. The Callovian Anchor sequence slope fan has good gas and oil shows in channel sands while the Kimmeridgian-Tithonian Dupuy sequences contain over 200 million barrels of oil in lowstand prograding complex grain flow slope deposits of the Wanaea-Cossack fields. The Anchor, Dingo, and Dupuy sequence fans are an underexplored play worthy of further exploration. The Neocomian Barrow Group consists of up to six thirdorder depositional sequences, at least three of which contain well developed clastics of probable deep water slope or basin floor fan origin. The Scarborough field of some 12 TCF, is reservoired in mass flow sands of the youngest basin floor fan, one of only two economically viable fans in either country. There is good potential for new stratigraphic trap discoveries in this section. The Carnarvon Basin Harriet group of small fields has over 50 million barrels of recoverable oil in massive grain flow sands of the Zeepard sequence basin floor fan, which could be more extensive than presently defined and still presents a prospective play. Exploration within the northern Browse Basin of northern Australia, an Upper Jurassic restricted rift system similar to the Carnarvon Basin, has discovered to date few submarine fans, but drilling has been predominantly confined to horst blocks with little basinal exploration taking place. A handful of wells which have penetrated basinal sequences have occasionally found massive Upper Jurassic stacked sand units, which may be of deep water origin, adjacent to Triassic horst blocks. Good shows exist in widespread Maastrichtian sands of the Puffin Formation, a succession of stacked basin floor fan complexes. The Upper Devonian Canning Basin of onshore Western Australia has good potential for lowstand clastics downdip from poorly productive carbonate complexes. A Frasnian slope fan levee complex has produced oil, and current exploration is testing seismically-defined basin floor fans downdip from the highstand carbonate complexes. The Bonaparte Basin offshore northern Australia contains seismically-defined Carboniferous basin floor (?) fans, updip from which Paleozoic oil has been recovered. These features are, as yet, undrilled. The Gippsland Basin contains 60% of Australia’s oil reserves-all in Latrobe Group fluvio-deltaic reservoirs, 50% of which are in subcrop traps set up by Eocene lowstand incisions with transgressive shale infill. Large amounts of these clastics have been removed so the potential for lowstand prograding complex shingled turbidites and slope/basin floor fans downdip exists, but the latter will be in modern deep water. Tertiary fans have been identified on seismic in the Dampier (Western Australia), Otway, and Duntroon basins (southern Australia) but not yet tested due to perceived problems of sourcing and migration of hydrocarbons. All of New Zealand’s submarine fan reserves (some 40 million barrels of oil) occur within Tertiary submarine fan complexes. The oldest fan, associated with the basal Oligocene lowstand, has some 3 million barrels of oil within the Tariki Sandstone in overthrust structures onshore. The Middle Miocene Moki ‘B’ fan complex contains some 35 million barrels of oil in the Moki offshore field while Upper Miocene Mt. Messenger fan contains 1 million barrels of oil. The oldest fan complex contains the Upper Eocene Tangaroa Sandstone but this unit is yet to yield commercial reserves. A new fan play currently being assessed, is for Pliocene Moki ‘C’ sands in a NE-SW fairway several hundred kilometers long in the northern Taranaki Basin. Shows have also been recorded in Miocene fan clastics in the East Coast and Westland Basins. Most New Zealand submarine fan reserves are small due to structural complexity and poor sand reservoir properties. Both countries are significantly underexplored for submarine fan reserves. Upper Jurassic, Lower Cretaceous, and Tertiary petroleum systems have been proved to be working and fans have been identified in at least four basins in Australia and New Zealand. There is still potential for finding these reserves by companies using an integrated strategy which combines biostratigraphic, seismic, geochemical, and log data together within a sequence framework.

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