2016 Release Areas

Gippsland Basin

Release Area V17-1, offshore Victoria

Highlights

Bids close on Thursday 19 October 2017

Proven world class petroleum province with ready access to the growing southeast Australian energy market.
Adjacent to major producing oil and gas fields
Shallow water around 50 m deep
Release area fully covered by 3D seismic
Further guidance applies, refer to 2017 Special Notices.

The Gippsland Basin is recognised as one of Australia’s premier hydrocarbon provinces, having continually produced oil and gas for the southeast Australian energy market for over 50 years. From 1967-2015, the Gippsland Basin Joint Venture alone produced 54% of Australia’s crude oil and gas, comprising 4.7 Bbbls (~750 GL) of oil and 8 TCF (~200 km³) of gas (Jakeman, 2016). Several petroleum systems operate in the basin, with the largest oil and gas fields hosted by top-Latrobe Group (Eocene) shallow marine barrier sandstones, and additional discoveries made in intra-Latrobe (Upper Cretaceous-Paleocene) coastal plain and deltaic channel sandstones.

Release Area V17-1 consists of four graticular blocks located in shallow water (~50 m deep), 16 km southeast of Lakes Entrance, adjacent to numerous producing oil and gas fields including Snapper, Marlin, Turrum and Longtom (Figure 1). Most of the area is located on the Northern Terrace and reaches as far as the Central Deep basinward of the Rosedale Fault System. Rollover structures associated with the Rosedale Fault System have proved successful exploration targets at the nearby Moonfish, Sunfish and Sweetlips fields. North of the area, oil has been produced from the onshore Lakes Entrance Field, while gas is produced from the Admiral Formation of the Emperor Subgroup (Figure 2 and Figure 3) in the Longtom Field immediately adjacent to Release Area V17-1.

A detailed well log for the nearby Longtom 1 ST1 well is shown in Figure 3, indicating the gas bearing reservoir in the Turonian age Admiral Formation of the Emperor Subgroup. Figure 4 shows a cross section through this well and others on the Northern Terrace and Central Deep, in the vicinity of the Release Area. One well, Fur Seal 1, lies within V17-1 and two 3D seismic surveys: the Fields 3D MSS and 3D‑Geo Seismic Mega-volume surveys, cover the area (Figure 5). The major play types occurring in the Gippsland Basin are shown in Figure 6.

Petroleum systems elements

Gippsland Basin

Sources	Upper Cretaceous fluvial-deltaic Volador Formation (Halibut Subgroup) Upper Cretaceous marine Anemone Formation (Golden Beach Subgroup) Upper Cretaceous (T. lilliei zone) fluvial-deltaic Chimaera Formation (Golden Beach Subgroup) Upper Cretaceous lacustrine Kipper Shale (Emperor Subgroup) Lower Cretaceous non-marine Strzelecki Group
Reservoirs	Eocene greensands of the Gurnard Formation (Cobia Subgroup) Eocene marine barrier sandstones of the Burong Formation (Cobia Subgroup) Maastrichtian-Paleocene fluvial-deltaic Kingfish Formation (Halibut Subgroup) Campanian–Maastrichtian fluvial-deltaic Volador Formation (Halibut Subgroup) Santonian–Campanian fluvial-deltaic Chimaera Formation (Golden Beach Subgroup) Turonian fluvial and lacustrine Admiral Formation (Emperor Subgroup)
Seals	Regional seals Oligocene–Miocene marine carbonate Lakes Entrance and Swordfish formations (Seaspray Group) Intraformational seals Campanian volcanics Santonian–Campanian Anemone Formation (Golden Beach Subgroup) Turonian-Coniacian lacustrine Kipper Shale (Emperor Subgroup)
Traps	Structural traps (anticlinal closures) Combined structural/stratigraphic traps Stratigraphic pinch out plays A variety of fault related traps, including tilted fault blocks

Infrastructure and markets

The Release Area is situated near the major oil and gas fields of the Gippsland Basin. Hydrocarbon production in the basin remains strong, expanded by the A$4.4 billion investment to develop the Kipper-Tuna-Turrum project. The oil and gas resources are processed at the Longford facility, which includes three gas plants and one crude oil stabilisation plant, plus a gas conditioning plant currently in the final stages of start-up. Additionally, in East Gippsland, the Orbost gas plant is being upgraded to allow processing of hydrogen sulphide-rich gas from the Sole gas field, which will be made available through the new Sole Pipeline. Despite some decline due to long term production, the Gippsland Basin is still recognised as a world class petroleum province, continuing to make oil and gas available for the growing southeast Australian energy market.

Critical risks

It is likely that the oil and gas fields on the Northern Terrace (and the onshore Lakes Entrance oil field) result from hydrocarbons migrating north from sources within the Central Deep. Thus, with the presence of the Rosedale Fault System within the area, the main risks are inadequate cross-fault seals and possible migration shadows. For example, a lack of fault-seal closure is cited as a possible reason for well failure at Gilbert 1A and Cuttlefish 1 (Amity Oil NL, 1999; Bass Strait Oil Company Ltd., 2006), while inadequate sealing units prevented accumulations at Gannet 1 and Fur Seal 1 (Jessop et al, 1970; Apache Energy, 2008). Additionally, Fur Seal 1 may be in a migration shadow north of the Sunfish-Remora fault. The timing of structuring relative to migration may also be of concern in some areas, with the presence of a gas show but no oil at Cuttlefish 1 attributed to late final structuring after oil generation and migration. However, the presence of an oil leg at the Sweetlips and Emperor fields and at Sperm Whale 1, indicates that oil migration pathways are present across this part of the Northern Terrace.

Well control

Sunfish oil and gas field

Sunfish 1 (1974) and Sunfish 2 (1983) were drilled by Esso Australia in an anticlinal structure, compressional against an east-west trending right lateral shear system on the edge of the Central Deep, bordering the Northern Terrace. Sunfish 1 penetrated an intra-Latrobe Paleocene and Cretaceous section, identifying five separate hydrocarbon zones. Net pay totalled 221 ft (67.3 m) of net condensate-rich gas and 55 ft (17.8 m) of net oil, with the most significant oil zone comprising 34 ft (10.4 m) of net oil pay in the T lilliei spore-pollen zone (Chimaera Formation) trapped beneath highly weathered volcanics. The sand porosity throughout the Latrobe Group was good, ranging from over 25% in L balmei zone sediments (Paleocene) to an average of 17 % for the Upper Cretaceous oil zones (Criss and Brooks, 1974). Because of the complexity and number of separate hydrocarbon systems, Sunfish 2 was drilled to help accurately define recoverable reserves. It was drilled into the east-northeast plunging Sunfish Nose truncated by the Marlin Channel, and penetrated 3.3 m of net oil sand at the top of the Latrobe Group and 3 m of stratigraphically trapped net gas at the base of the L balmei zone (Kingfish Formation). The appraisal well demonstrated that the hydrocarbon zones penetrated in Sunfish 1 were less extensive than originally thought, and the Sunfish structure not as broad as originally proposed (Esso Australia Limited, 1984).

Sperm Whale 1 (1981)

Sperm Whale 1 (1981) was drilled by Lasmo Energy Australia, penetrating an asymmetric anticline, formed by arching in to a major east-west, reverse fault, upthrown to the south. The well penetrated the Latrobe and Strzelecki groups, and reached a TD of 1417 mMDRT in the Lower Cretaceous. Movable hydrocarbons were identified within the upper section of the Latrobe Group (Kingfish Formation) and the well flowed dry gas at rates of up to 5.4 MMcf/d (0.15 MMm³/d) during a drill stem test over the interval 819‑826 m. Degraded oil was recovered during the repeat formation tester programme from a thin oil leg over the interval 831.5‑833.5 m, indicating the presence of an oil migration pathway on the Northern Terrace. Sperm Whale 1 was plugged and abandoned as a gas well (Hudbay Oil [Australia] Ltd., 1982a).

Patricia-Baleen gas field

The Patricia-Baleen Gas field lies to the east of Release Area V17-1, between the Rosedale and Lake Wellington faults. Lasmo Energy Australia drilled the first two discovery wells of the field, Baleen 1 (1982) and Patricia 1 (1988). Baleen 1 was drilled to test a structure formed by arching into a major east-west, high angle reverse fault, with closure mapped at two horizons designated Top Latrobe and Top Strzelecki. Drill stem tests proved movable hydrocarbons in two zones: dry gas flowed at 1.8 MMcf/d (0.05 MMm³/d) over 700-706 m and 6.3 MMcf/d (0.18 MMm³/d) over 662-670 m. Formation permeabilities were calculated to be 56 md and 747 md, respectively (Hudbay Oil [Australia] Ltd, 1982b) . Patricia 1 tested the extent of the gas encountered in Baleen 1, in a structural culmination 2.5 km to the south-southeast. The well encountered a 50 m gas column reservoired in the Gurnard (44 m) and Barracouta (6 m) formations, and flowed gas through casing up to 2.6 MMcf/d (0.07 MMm³/d) from the Barracouta Formation and 24.1 MMcf/d (0.68 MMm³/d) from the Gurnard Formation (Lasmo Energy Australia Ltd, 1987). OMV Australia went on to drill Baleen 2 (1999), Patricia 2 (2003) and Baleen 3 ST1 (2003). Baleen 2 was drilled structurally down-dip of Baleen 1 and confirmed the southwest extension of the accumulation, with a 16.2 m gross gas column (OMV Australia, 2001). Patricia 2 and Baleen 3 ST1 were crestal horizontal gas development wells for commercial production (OMV Australia, 2003a; 2003b). The Patricia-Baleen field produced over 28 Bcf (793 MMm3) of sales gas from 2003 to 2008, under operation by Santos (APPEA, 2016).

Sweetlips 1 and 1 ST1 (1989)

The Sweetlips 1 well was drilled by Esso Australia to test for hydrocarbons at the top the “Coarse Clastics” (Kingfish Formation), with stacked intra-Latrobe sandstones forming the secondary target. The Sweetlips Field is part of a larger structural feature incorporating Emperor 1, consisting of a multi-crested highside rollover. A 55 m gross hydrocarbon column was intersected in the “Coarse Clastics”, interpreted as a 51 m gas column with 4 m of oil on rock. The repeat formation tester data was not conclusive as to the exact depth of the oil-water contact, so the well was sidetracked 15 m downdip, to more accurately define the oil column. The well was plugged and abandoned after the sidetrack confirmed the initial interpretation and the 4 m oil column was non-commercial (Esso Australia Ltd., 1990).

Longtom gas field

Longtom 1 ST1 (1995), drilled by BHP Petroleum Pty Ltd (BHP) in 56 m of water, reached a total depth of 2445 mRT and tested a downthrown fault block (BHP Petroleum, 1995). The well encountered over 40 m of net gas pay (inferred from wireline logs) in three zones at intra-Latrobe/Emperor Subgroup level. Post-drill analysis showed the well had tested a valid structure, however reservoir properties were much poorer than predicted—gas sands were thin and log-derived porosities ranged between 7% and 11%. Longtom 2 ST1 and Longtom 3 ST1/H were drilled by Apache Energy Ltd. in 2004 and Nexus Energy Ltd.in 2006, respectively. Good reservoirs were discovered in Longtom 2 ST1, which encountered a 259.3 m gross gas column within the Admiral Formation (Apache Energy, 2006). A flow rate in excess of 80 MMscf/d (2.3 MMm3/d) from Longtom 3 ST1/H confirmed the commercial viability of the field (Nexus Energy Ltd., 2009).

Moby 1 (2004)

Bass Strait Oil Company Ltd spudded Moby 1 (2004) 5 km east of the Patricia-Baleen gas field, to test a seismic amplitude anomaly identified on the Baleen 3D survey. The anomaly was interpreted to represent gas within the Gurnard Formation, a prediction borne out by log evaluation, analysis of the RCI pressure, and sampling data and core analysis, which confirmed the likely presence of a 21 m gross gas column. The well successfully confirmed the presence of suitable Gurnard Formation reservoir, which the previous wells in the same structure, Flathead 1 and Whale 1, failed to encounter. Percussion sidewall core samples provided a measured average porosity of 36.7% and a measured average permeability of 549 md (although these figures must be treated with care as percussion coring tends to be destructive in nature). Geochemical biomarker analyses characterise hydrocarbon extracts from Gurnard Formation sidewall cores as biodegraded and mature, sourced from strongly terrestrial organic matter, possibly with some resin input. Being on the flanks of a structural closure on which the two earlier wells also recorded anomalous hydrocarbon occurrences, this data supports the suggestion that Moby 1 is located on a migration pathway from a proven hydrocarbon kitchen to the south and southeast within the deeper parts of the Central Deep. Moby 1 was plugged and abandoned as a new field gas discovery in October 2004 (Bass Straight Oil Company Ltd, 2005).

Fur Seal 1 (2005)

Fur Seal 1 (2005) was drilled by Apache Energy Ltd. to test a combined stratigraphic/structural trap in an elongate, east-west oriented, four-way dip closure structure, with the southern flank formed by the southerly dip of the Intra-Latrobe Group, and the northern flank formed by the base of the Marlin Channel truncating the southward dipping Intra-Latrobe Group. The well reached a total depth of 2610 mMDRT, terminating in the Strzelecki Group. The Primary objective was the Kingfish Formation, intersected 43.3 m higher than predicted. The secondary objective was the Volador Formation, which was intersected 1.5 m higher than predicted. Poor to fair inferred porosity was noted in each of these formations and no hydrocarbon shows were observed before the well was plugged and abandoned as a dry hole in November 2005. Apache Energy Ltd (2008) attribute the lateral seal against the southern flank of the Marlin Channel as the most likely reason for failure, although the lack of any shows or residual pay may point to Fur Seal 1 being in a migration shadow north of the Moonfish-Remora fault.

NOPIMS Data

Data relating to the Release Areas can be accessed through the National Offshore Petroleum Information Management System (NOPIMS), an online data discovery and delivery system for all Australian offshore petroleum wells and seismic surveys, at http://www.ga.gov.au/nopims

Marine and Environmental Information

Release Area V17-1 characteristics

Release Area V17-1 is located on the Twofold Shelf which is approximately 65 km in width, in water depths of approximately 50 m. The coastline lies 15 km to the north, with the closest town being Lakes Entrance.
Offshore shelf sediments are dominated by calcium carbonate (CaCO) with predominantly medium to fine sand (Jones and Davies, 1983). Very fine sand is restricted to immediately offshore Lakes Entrance, and to deeper water (~75-100 m) near the heads of the major canyons (Jones and Davies, 1983).

Commonwealth marine reserves

Release Area V17-1 is located 135 km north west of Beagle Commonwealth Marine Reserve (CMR) and 140 km west of East Gippsland CMR.

Victorian marine national parks

Release Area V17-1 is located 81 km northwest of Ninety Mile Beach Marine National Park (MNP), 40 km southwest of Beware Reef Marine Sanctuary and 85 km west-southwest of Point Hicks MNP.

Key ecological features

There are two Key Ecological Features of note. These include the upwelling east of Eden, which overlaps V17-1, and the Big Horseshoe Canyon which is 83 km east of V17-1 (National Conservation Values Atlas, 2016).

Biologically important areas

Release Area V17-1 overlaps, or is close to the following biologically important areas (National Conservation Values Atlas, 2017). The Area:

Overlaps with the foraging area for seabirds including the Shy, Indian Yellow-nose, Black-browed, Buller’s, Campbell, Wandering and Common albatrosses. The Common Diving Petrel breed in the area from July through to December. The Antipodean Albatross and the White-faced Storm Petrel foraging area is to the east
Overlaps with the known Southern Right Whale coastal waters migration and resting area. This generally occurs between May and November, although some whales stay year-round.
Overlaps with the White Shark known distribution area and breeding nursery area, in autumn, winter and spring.

The Atlas of Living Australia provides further information on animals and plants recorded from the release area, including Threatened or Listed Species.

Heritage

The wreck of the Anne and Mary, a Barquentine wrecked in 1887, is located in the area, at the following coordinates: 37.9333S, 148.31667E.

The Gunaikurnai Traditional Owner Land Management Agreement and Gunaikurnai Native Title Agreement recognise that the Gunaikurni hold native title over much of Gippsland, including 200 m of sea country offshore.

Information resources

National Conservation Values Atlas: http://www.environment.gov.au/webgis-framework/apps/ncva/ncva.jsf

Atlas of Living Australia: http://www.ala.org.au/

Geoscience Australia Marine Sediments: http://dbforms.ga.gov.au/pls/www/npm.mars.search

Fisheries

Geoscience Australia products

Regional geology and seismic

Gippsland Basin Infill 2D Marine Seismic Survey – GA352: Acquisition and Processing Reports. Geoscience Australia Record 2016/25 by Mitchell et al. 2016.
Gippsland Basin Infill 2D Marine Seismic Survey, (GA-0352) – High Resolution Bathymetry Grids. Dataset by Spinoccia, 2015
Single and Multibeam Bathymetry grids of the Gippsland Basin - 100 and 50m resolution - 2013. Dataset by Spinoccia, 201.
Australian Southern Margin Synthesis, Project GA707. Client report to Geoscience Australia by FrOG Tech Pty Ltd., 2009.
Regional Structure of the Gippsland Basin: Interpretation and Mapping of a Deep Seismic Data Set. Australian Geological Survey Organisation Record 1993/13 by Colwell et al, 1993.
A regional review of the offshore Gippsland Basin. Report 297. Bureau of Mineral Resources, Geology and Geophysics report by Maung and Nicholas 1990.

Stratigraphy

Gippsland Basin Biozonation and Stratigraphy. Chart 40 by Partridge et al, 2015.

Petroleum systems and accumulations

The Oils of Eastern Australia. Report by Summons et al, 2002
South-eastern Australia Surface Geochemistry II: Light Hydrocarbon Geochemistry in Bottom-waters of the Gippsland Basin, Eastern Otway Basin, Torquay Sub-Basin and the Durroon Sub-Basin. Volumes 1 and 2. Australian Geological Survey Organisation Record 1992/54 by Bishop et al 1992
Southeast Gippsland Basin Hydrocarbon Prospectivity Package. Bureau of Mineral Resources Record 1991/09 by Stephenson et al, 1991
Australian Petroleum Accumulations Report. Gippsland Basin, Victoria. Report by Ozimic et al, 1987

Search for these and other Geoscience Australia reports and products at www.ga.gov.au/search

Contact Geoscience Australia's Client Services for more information or to order these reports or products, phone 61 (0)2 6249 9966, email clientservices@ga.gov.au

References

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