2016 Release Areas

Cape Wickham Sub-basin

Release Area T17-1, offshore Tasmania

Highlights

Bids close 19 October 2017

Cretaceous–Cenozoic intracratonic rift basin containing proven hydrocarbon reserves
Situated in shallow water (<83 m) close to southeast Australian gas markets and production infrastructure
Release area surrounding the Yolla Field production lease and adjacent to retention leases associated with the White Ibis, Bass, Trefoil and Rockhopper accumulations
Fault block, anticlinal closure and onlap plays occurring on the up-dip flanks of proven hydrocarbon kitchens
Release Area partly covered by recent 3D seismic surveys
Further guidance available, refer to 2017 Special Notices

Release Area T17-1 is located in the western Bass Basin, covering much of the central Cape Wickham Sub-basin (Figure 1). The Release Area surrounds the producing Yolla Field (BassGas Project), is traversed by the BassGas pipeline, and is adjacent to known accumulations at White Ibis, Bass, Trefoil and Rockhopper. The northwestern and eastern parts of the Release Area are partly covered by recently acquired 3D and 2D seismic surveys (Figure 2).

The Cretaceous–Cenozoic Bass Basin is a northwest-trending, intracratonic rift basin that underlies the Bass Strait between northern Tasmania and southern Victoria. The Bass Basin is separated from the Otway and Sorell basins to the west by the King Island High, and from the Gippsland Basin to the northeast by Flinders Island and the Bassian Rise. The Bass Basin is divided into the Cape Wickham Sub-basin in the west and the Durroon Sub-basin in the east (Blevin et al, 2005). The Cape Wickham Sub-basin is a proven hydrocarbon province, hosting several gas discoveries and a producing gas and condensate field (Yolla).

The Cape Wickham Sub-basin consists of a series of large northwest- to north-northwest-trending Cretaceous–Cenozoic half graben informally named the Cormorant, White Ibis, Yolla, Dondu and Pelican troughs (Lennon et al, 1999; Blevin et al, 2003, 2005; Cummings et al, 2004). Rift bounding faults generally dip to the southwest to west-southwest. Fault throws in the sub-basin are in the order of 3–5 km, with the total sedimentary succession (syn-rift and post-rift) reaching a thickness of 8–10 km in the main depocentres.

The evolution of the Cape Wickham Sub-basin was dominated by three distinct rift phases (Figure 3). The first, in the Barremian–earliest Cenomanian, was coeval with extension in the adjacent Otway Basin and resulted in deposition of the non-marine Otway Megasequence (Blevin, 2003b). A second phase of extension affected the basin during the Turonian–Campanian, driven by Tasman Basin rifting to the east. Half graben initiated in the previous rifting phase continued to develop and expand, forming a system of linked fluvio-lacustrine depocentres (Blevin et al, 2005). A third phase of extension affected the Cape Wickham Sub-basin in the Campanian–early Eocene (Bass rift phase) (Smit, 1988; Blevin, 2003b; Blevin and Cathro, 2008). This phase of extension focused particularly on structures within the Pelican, Yolla and Cormorant troughs, and resulted in episodic reactivation of existing Lower Cretaceous half-graben structures from the Campanian until the early Eocene. In the Cape Wickham Sub-basin, the oldest sediments penetrated by drilling are Campanian–Maastrichtian (Bass Rift Phase; Figure 4, Figure 5).

Until the late Eocene, deposition of non-marine sediments in the Bass Basin was controlled by internal drainage systems that migrated from the uplifted flanks of the basin into the developing half-graben structures. Following the cessation of rift-related activity in the latest early Eocene, accommodation was controlled by normal post-rift subsidence and eustatic fluctuations. Widespread marine flooding of the basin occurred from west to east in the late middle Eocene, although indications of periodic marine incursions are recorded as early as the Paleocene.

Multiple periods of post-rift tectonic reactivation, including several episodes of Cenozoic inversion, affected the Bass Basin. The events formed large scale anticlines within the syn- and post-rift successions, with several of these structures targeted by exploration drilling (e.g., Cormorant 1). The Cape Wickham Sub-basin has been affected by multiple periods of volcanic activity during the syn- and post-rift phases of basin evolution resulting in the widespread emplacement of intrusive (sills and dykes) and extrusive rocks (volcanic mounds and flows; Figure 4).

Petroleum systems elements

Cape Wickham Sub-basin

Sources	Lower Paleogene (particularly Paleocene to lower Eocene) coals and interbedded shales of the Bass Megasequence and Aroo Sequence (middle and upper Eastern View Formation [EVF]) Lower Cretaceous coals and shales of the Otway Megasequence (Eumeralla Formation equivalent)
Reservoirs	Campanian–Maastrichtian, Paleocene and lower Eocene fluvio-deltaic to marginal marine sandstones of the Bass Megasequence and Aroo Sequence (middle and upper EVF)
Seals	Intraformational seals Lacustrine and interdistributary–floodplain shales within the Upper Cretaceous–Eocene Bass Megasequence and Aroo Sequence Regional seal Siltstones and calcilutites of the marginal to shallow marine Flinders Sequence (Demons Bluff Formation)
Traps	rotated fault blocks and overlying drape closure located up-dip from deep half graben reactivation structures such as Eocene, Miocene and younger inversion anticlines crestal collapse fault blocks anticlinal closures associated with the intrusion of volcanic rocks

Infrastructure and markets

The Bass Basin is an established gas and condensate producing province that services the southeastern Australian energy market. Release Area T17-1 surrounds the Yolla Field, which commenced production in 2006. The Bass Gas pipeline takes gas and liquids from Yolla to a processing facility in onshore Victoria at Lang Lang, 70 km south of Melbourne. The greater Melbourne region is one of Australia’s largest domestic gas markets and is supported by major petroleum refineries.

Critical risks

The main exploration risks in the Cape Wickham Sub-basin relate to variations in reservoir quality, the influence of extrusive volcanics and hydrothermal fluids, seal and trap integrity, and migration and charge.

Concerns regarding reservoir quality include the reduction in porosity and permeability due to extensive diagenesis within deeper sandstone units (such as at Rockhopper 1; Hall, 2012), and the lateral extent of good reservoir characteristics as a result of mineralogical and textural immaturity, depositional facies changes in fluvio-lacustrine and marginal marine sediments, or diagenesis (Brooks et al, 2005). Volcanic and related intrusive rocks are widespread in the Cape Wickham Sub-basin (Figure 4). Lemon (2003) noted that in areas of elevated heat flow associated with magmatic activity, diagenetic effects occur at shallower depths. The injection of fluids associated with hydrothermal vents may also have affected reservoir quality in some areas.

Trap integrity and/or fault seal breach, inadequate closure, and variations in seal quality leading to inadequate seal are also considered to be exploration risks in the Cape Wickham Sub-basin; all have been cited as reasons for failure (no hydrocarbons or non-economic accumulations) of wells in the sub-basin, including Cormorant 1 and Bass 3 (Trigg et al, 2003).

The interbedded and discontinuous nature of facies within the Bass and Aroo sequences, diagenesis and the effects of hydrothermal fluids on reservoirs, and magmatic rocks within the succession mean that migration pathways in the basin can be tortuous or limited. The presence of dykes as a barrier to migration was cited as the probable cause of failure for the recent Craigow 1 well, which was drilled in the Cormorant Trough, an area of proven hydrocarbon charge (Tap Oil, 2011).

In some areas of the sub-basin, hydrocarbon charge is a key risk. A lack of commercial success in the Pelican Trough in the southern part of the Release Area, despite good hydrocarbon shows in the Pelican wells, has been attributed to a lack of or inadequate charge (Beach Energy, 2010). Two recent wells drilled in the area—Spikey Beach 1 and Peejay 1—were both unsuccessful.

Well control

Cormorant 1 (1970)

Cormorant 1 was drilled by Esso Exploration and Production in 1970 to test Eocene sandstones of the upper Eastern View Formation (EVF) in a large NW–SE trending anticlinal closure that formed in the Miocene. The well intersected the primary target, reaching a TD of 3001 mRT in Eocene strata. Significant oil, gas and condensate shows were encountered. The first oil show from the Bass Basin was recovered from a thin sand at 1499–1501 m, and four sandstones located deeper in the Eocene section of the EVF were interpreted to contain gas and condensate. Porosity values within reservoir sands were good (averaging 20%), however permeability data for the well is limited. The lack of an economic accumulation at Cormorant 1 was attributed to ineffective seal (Esso, 1973) and late development of the trapping structure.

Yolla gas and condensate field (1985-present)

Yolla 1 was drilled in 1985 by Amoco Australia Petroleum Company as a crestal test of the EVF within a four-way dip and fault-closed structure. The well terminated at a TD of 3347 mRT in igneous rocks within the Paleocene middle (“Intra”) EVF section. Yolla 1 successfully encountered commercial hydrocarbon accumulations with approximately 30 m of net gas pay over a 278 m interval (2718–2996 mRT) in the middle EVF (Lennon et al, 1999). Gas pay was interpreted in 5 separate zones within this section (Brooks et al, 2006). In addition, the well penetrated a gross hydrocarbon column of 31 m (wet gas cap of 20.4 m overlying a 10.6 m oil leg) in the upper EVF. A drill-stem test from middle EVF sands over the interval 2809.1-2824.6 mRT flowed gas and condensate at rates of up to 425 Mcm/day and 92 kL/day respectively (15.1 MMscfd and 580 bcpd) (Brooks et al, 2006). The well was suspended for possible future re-entry.

The stacked hydrocarbon accumulations within the EVF at Yolla 1 are sealed by relatively thick and laterally continuous intraformational shales deposited in a lacustrine environment (Lennon et al, 1999). The success of Yolla 1 was attributed to the structure being well placed with respect to hydrocarbon charge, with the structure draining an extensive Paleocene source kitchen that extends into both the Cormorant and Yolla troughs (Lennon et al, 1999).

Work on commercialising the Yolla field has continued since its discovery (Brooks et al, 2006), with the drilling of a further five wells by Premier Oil (Yolla 2 appraisal well) and Origin Energy Resources (Yolla 3, 4, 5 and 6 production wells). The BassGas project (a joint venture between Origin Energy and AWE Petroleum, and later partners) was formed to develop the Yolla field. The production platform was installed in 2004, a pipeline to Victoria was constructed, and first gas was produced in 2006.

In June 2016, Origin Energy reported that net proven and probable (2P) reserves for the Yolla field were 50 PJe, down from 90 PJe in June 2015 (Origin Energy, 2015, 2016); this equates to a gross 2P for the field of 117 PJe in 2016, down from 211 PJe in 2015, based on Origin’s 42.5% share in BassGas. This downgrade followed 12 months production to June 2016 of 18.25 PJ of gas, 611 500 bbl (97.2 Mcm) of condensate and 54,700 t of LPG (AWE, 2015a, 2015b, 2016a, 2016b), and revisions based on the results of Yolla 5 and Yolla 6 (Origin Energy, 2016).

Pelican 5 (1985)

Pelican 5 (Figure 5) was drilled in 1985–1986 by Amoco Australia to test the production potential of the lower Eocene sands (M. diversus spore/pollen zone) of the middle EVF, which had good shows of gas and condensate at Pelican 1, 2 and 4, but had not been tested for production. The secondary objective was to investigate Upper Cretaceous to Paleocene sands that were thought to be in a structurally favourable position. Pelican 5 is located on the same large anticlinal structure that was found to be valid at Pelican 1, 2 and 4. Pelican 5 achieved its drilling objectives, reaching a total depth of 4267 m in Campanian–Maastrichtian rocks. Numerous hydrocarbon shows were noted while drilling through the EVF. Gas was produced during two tests, and wireline log evaluation indicated the presence of moveable hydrocarbons at various levels within the interval 2750–4050 m (Amoco, 1987). Hydrocarbons were found in limited quantities, with the low permeability of EVF reservoirs preventing the accumulation of economic quantities of hydrocarbons. Potential source rocks for both oil and gas were found in mature Paleocene and Eocene coals, to over-mature exinite-rich Cretaceous shales (Trigg et al, 2003).

White Ibis 1 (1998)

White Ibis 1 was drilled in 1998 by Premier Oil Australasia and partners on a prominent fault-bounded basement high on the southwestern margin of the Yolla Trough. The well was drilled to evaluate the Upper Cretaceous–Paleocene section of the EVF in a structurally optimal location up-dip of the gas discovery at Bass 3 (Lennon et al, 1999). The well intersected the full EVF section and reached a total depth of 2220 mRT in Paleozoic basement rocks. The structure was found to be valid, with fault-dependent closure at the middle EVF level and four-way dip closure at the top EVF. The well encountered three short hydrocarbon columns, sealed by intraformational shales within the objective section of the EVF; the thickest gas column covered a gross interval of 23 m (Lennon et al, 1999). Lennon et al (1999) suggested that the occurrence of a series of stacked reservoirs was the result of inadequate fault seal. Lennon et al (1999) proposed that formation pressure and sample data from the upper reservoir (2001.5–2023 m) could indicate the presence of an oil leg underlying a liquids-rich gas column; the lower two reservoirs (2044-2053 m and 2128-2140 m) are considered to contain dry gas only. The well was not tested and was suspended as a sub-commercial gas discovery (Premier Oil, 1998). Probabilistic calculations suggest a mean resource of 85 Bcf (2.4 Bcm) gas-in-place (Lennon et al, 1999).

Trefoil 1 (2004)

Trefoil 1 was drilled by Origin Energy Resources Limited and joint venture partners in 2004 to test the Cretaceous–Paleocene and Eocene EVF sandstone reservoirs that are hydrocarbon-bearing at the nearby Yolla Field and White Ibis 1 discovery (Brooks et al, 2005). The well penetrated the target EVF section and reached TD at 3545 mRT in igneous rocks within Campanian–Maastrichtian strata. The well intersected approximately 50 m of net gas pay over several zones in good quality sandstone reservoirs within the EVF. Multiple gas and condensate columns were discovered in the lower Paleocene and Cretaceous sands. MDT pressures showed that the middle EVF in the well consists of several different over-pressured and isolated layers. Production tests were carried out over two separate zones in the Cretaceous–lower Paleocene section, from 3040–3047 m and 3141–3150 m, flowing gas at 9.5 MMscf/d (268.4 Mcm/d) and 14.4 MMscf/d (406.8 Mcm/d) respectively (Brooks et al, 2005). Preliminary estimates for in-place resources for the field are 200–300 Bcf of gas (5.6–8.5 MMcm) and 14–21 MMbbls (2.2–3.4 MMcm) of associated liquids (AWE, 2004). The well was confirmed as a wildcat gas-condensate discovery.

Rockhopper 1 (2009)

Rockhopper 1 was drilled by Origin Energy Resources in 2009–2010 to test the crest of a fault-dependant three-way dip closure anticline within the middle EVF (Hall, 2012). The well was expected to intersect 50–100 m of gross gas pay, based on the results of Trefoil 1 and re-interpretation of the results of Aroo 1, which is located on the same structure. The well reached a total depth of 3522 mRT in Cretaceous volcanics. Rockhopper 1 (and its side-tracked appraisal well Rockhopper 1 ST1, which was drilled to determine fluid contacts and reservoir quality extent) intersected up to 28 separate hydrocarbon bearing intervals within Paleocene and Cretaceous sandstones of the EVF, with a total net hydrocarbon pay of 28.9 m. Hydrocarbons were sampled from seven sandstone units using the MDT tool; gas condensate was sampled from five and oil from two. Petrological analyses showed considerable variations in reservoir quality; although sandstones at the top of the reservoir section have been only mildly affected by diagenesis, deeper sandstones have been severely affected (Hall, 2012). The accumulations at Rockhopper 1 were interpreted to have been sourced from mature source rocks in the Yolla Trough to the east, and the Cormorant Trough to the north (Hall, 2012).

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 Environment

Release Area T17-1 characteristics

Release Area T17-1 is approximately 230 km in width and is located in Bass Strait in water depths of approximately 50–80 m. The area lies 33 km north of Tasmania’s northern coastline and 42 km south of Wilsons Promontory, Victoria. There are three islands located to the west; Three Hummock Island (36 km west), Robbins Island (50 km west) and Hunter Island (47 km west). The closest industrial ports are Devonport and Burnie.
Offshore Bass Basin and shelf sediments typically comprise over 90% calcium carbonate (Passlow et al, 2004). Mud dominates (>70%) of the seafloor substrate throughout the eastern parts of the basin, while sand dominates (up to 89%) in the north western region.
Hazards: tidal sand waves have been mapped in shallower water, 16 km west (updrift) of the Release Areas (Malikides et al, 1988, 1989). Some turbidite activity has also been forecast in the central to eastern parts of the Release Areas (Li et al, 2007). Maximum significant wave heights (MSWH) approaching the western coast of Tasmania are some of the largest in Australia (<9 m); however, Bass Strait is partly protected from these larger swells and MSWH over the western sill is 5–6 m and reduces to 4–6 m across the Release Area (Li et al, 2007).

Commonwealth marine reserves

Release Area T17-1 is located 8.6 km east of Boags Commonwealth Marine Reserve (CMR) and 26 km southwest of the Beagle CMR.

There are no Tasmanian state marine reserves near the area.

Key ecological features

There are no key ecological features in the area (Department of Environment and Energy, 2017).

Biologically important areas

Release Area T17-1 overlaps, or is close to, the following biologically important areas (Department of Environment and Energy, 2017).

Overlaps with the foraging area for seabirds including the Shy, Indian Yellow-nose, Black-browed, Buller’s, Campbell and Wandering albatrosses. The Common Diving Petrel, Little Penguin, Short-tailed Shearwater and White-faced Storm Petrel breed and forage in the area. The Black-faced Cormorant foraging area extends 13 km from islands and the Tasmanian coast.
Lies north of known Southern Right Whale connecting habitat in shallow coastal waters. This generally occurs between May and November, although some whales stay year round.
Overlaps a known Pygmy Blue Whale foraging area through the Bass Strait migratory corridor.
Overlaps with the White Shark known distribution area and breeding nursery area, in autumn, winter and spring.

Table 1 Breeding periods (b) for key seabirds whose foraging areas are adjacent or overlapping to the Release Area.

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sept

Oct

Nov

Dec

Common Diving Petrel

Little Penguin

Short-tailed Shearwater

The Atlas of Living Australia (http://www.ala.org.au) provides further information on animals and plants recorded from the release area, including Threatened or Listed Species.

Heritage

There are a number of shipwrecks located coastward of the area.

There are currently no native title claims in Tasmania.

References and Information Resources

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

Boags Commonwealth Marine Reserve https://www.environment.gov.au/topics/marine/marine-reserves/south-east/boags

Beagle Commonwealth Marine Reserve https://www.environment.gov.au/topics/marine/marine-reserves/south-east/beagle

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

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

Fisheries http://www.afma.gov.au/fisheries/ and http://agriculture.vic.gov.au/fisheries/commercial-fishing

Shipwrecks http://www.environment.gov.au/heritage/historic-shipwrecks

Geoscience Australia products

Regional geology and seismic

Australian southern margin synthesis, Project GA707. A report to Geoscience Australia by Blevin and Cathro, 2008
Petroleum geology of the Bass Basin: interpretation report. Geoscience Australia Record by Blevin, 2003
An audit of petroleum exploration wells in the Bass Basin: 1965–1999. Geoscience Australia Record by Trigg et al, 2003
Bass Basin basic data compilation. Geoscience Australia Record by Blevin et al, 2003
Regional potential field interpretation report, Bass Basin. Geoscience Australia Report by Teasdale et al, 2003

Stratigraphy

Review and compilation of open file micropalaeontology and palynology data from offshore Tasmania. Geoscience Australia Record by Partridge et al, 2003
Bass Basin biozonation and stratigraphy chart, 1998, Chart 17. Australian Geological Survey Organisation Chart by Shafik et al, 1998

Petroleum systems and accumulations

The Oils of Eastern Australia. Geoscience 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. Vols 1 and 2. Australian Geological Survey Organisation Record by Bishop et al, 1992
Australian Petroleum Accumulations Report 2: Bass Basin, Tasmania and Victoria. Bureau of Mineral Resources Report by Ozimic et al, 1987
Petroleum potential of the Bass Basin. AGSO Journal of Australian Geology & Geophysics article by Nicholas et al, 1981

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

Contact Geoscience Australia Client Services for more information: phone +61 (0)2 6249 9966, email clientservices@ga.gov.au

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