The Otway Basin is a Jurassic - Late Cretaceous basin.
The Otway Basin comprises one of a series of Jurassic to Cretaceous basins with a Tertiary cover (Gambier Basin) that occur along the southern coast of Australia.
|Age||Jurassic - Late Cretaceous|
|Onshore area in South Australia||9650 km2 (3730 sq. miles)|
|Onshore Exploration Well Density||1 well per 121 km2 (1 well per 47 sq. miles)|
|Onshore success ratio||0.125|
|Offshore area in South Australia ||50 000 km2 (19 300 sq. miles).|
|Offshore exploration well Density ||1 well per 5,000 km2 (1 well per 1,930 sq. miles)|
|Offshore success ratio ||No discoveries|
|Depth to target zone||100-4000+ m|
|Hydrocarbon shows||Onshore commercial gas from Pretty Hill Formation and Windermere Sandstone Member, 2000 bbl oil recovered on test from Sawpit sandstone; offshore oil shows and non-commercial gas.|
|First commercial discovery||1987 (Katnook 1) 1967 CO2 (Caroline 1)|
|Identified reserves||78.1 PJ (74 x 1012 Btu) sales gas (in 6 fields)|
|Undiscovered resources (50%)||1630 PJ (1545 x 1012 Btu) sales gas (DSD, formerly DMITRE estimate, April 1995) - not including deep water.|
|Current Production (12 months to June 2015)||0 PJ sales gas; 0 kL condensate (Katnook, Ladbroke Grove, Redman, Haselgrove South); 6380 t saleable CO2 (Caroline)|
|Depositional setting||Fluvial-lacustrine-marginal marine-deep water marine.|
|Reservoirs||Braided and meandering fluvial, deltaic and slope fan sandstones.|
|Regional structure||Early half graben, late shelf collapse.|
|Seals||Marine and lacustrine shales|
|Source rocks||Early half graben, late shelf collapse|
|Number of wells (August 2015)||100 (10 developmental/appraisal)|
Seismic line km
|10495 2D onshore, 782 km2 3D (5262km) onshore; 25842 2D offshore, 373 km2 3D (1272 km) offshore|
The following information is available for individual download or as one document (see images below).
The economic viability of small gas discoveries has been improved by the proximity to markets for such discoveries, their potential use for peak electricity generation opportunities in the national electricity market (as demonstrated by the 80 MW Ladbroke Grove Power Station). In 2002–03, the SEA Gas pipeline was constructed to transport offshore Otway gas from the Iona gas facility in Victoria to Adelaide. Origin Energy Retail Ltd constructed and commissioned the SESA Pipeline in 2005. This 45 km pipeline connects the SEA Gas Pipeline in Victoria to Epic Energy’s South East Pipeline System and the Ladbroke Grove Power Station.
See figure 1
Two major sedimentary sequences are targets for petroleum exploration in South Australia. (i) The Berriasian to Hauterivian sequence (Crayfish Group, early rift) is known only from the northern area, where E–W and NW–SE trending half-grabens (Robe, Penola, St Clair and Tantanoola Troughs contain fluvial to lacustrine sediments that are proven gas reservoirs. (ii) The Late Cretaceous sequence (Sherbrook Group) occurs as a deltaic to deep-water wedge south of the Tartwaup Hinge.
See figures 2, 3, 4 and 5
The Otway Basin in South Australia has been actively explored since the 1890s, with the first deep exploration well (Robe 1) being drilled in 1915. Early drilling was based on the theory that coorongite, subsequently found to be a surface algal deposit, was an underground oil seepage. Commercial CO2 was discovered in Caroline 1 in 1968, but it was not until 1987 that the first commercial gas discovery was made at Katnook, followed by discovery of the Ladbroke Grove Field in 1989.
In 2007 the appraisal of the Jacaranda Ridge Field significantly upgraded the northern portion of the Penola Trough as a wet gas–condensate play. The lack of early success may be attributed to poor quality seismic data prior to the early 1980s, and a poor understanding of structure and stratigraphic relationships in the Robe and Penola Troughs. Good-quality modern seismic coverage now exists over the offshore and most of the onshore parts of the basin and stratigraphic relationships are better understood.
See figure 1
In addition, the South East of South Australia and western Victoria exhibit a high diversity of local industry — consequently, opportunities for gas marketing linked to industry development in the region are good given the industry base and service provision in the region. The region is strategically located between the major cities of Adelaide and Melbourne and the eastern Australian market.
See figure 1
The oldest unit is the Casterton Formation, a volcanic and shale unit that occurs in some wells on the northern flank of the Penola Trough and in Victoria, and may occur in the undrilled deeper parts of the Robe and Penola Troughs. The oldest sequence known in South Australia is the Crayfish Group, which fills half grabens that can be identified in Figure 7.
The first unit is the Pretty Hill Formation, a braided fluvial sandstone that occurs in the deepest parts of the troughs. This is followed by fluviolacustrine shale and siltstone (Laira Formation), which in turn is overlain by the braided fluvial Katnook Sandstone. The Katnook Sandstone thickens to the NW, essentially as a sandy facies of the Laira Formation. On the extreme northern margin, both the Katnook Sandstone and Pretty Hill Formation are absent, and the Crayfish Group comprises only the shaly Laira Formation. The Crayfish Group is unconformably overlain by the Eumeralla Formation, which is a fluvial siltstone – shale sequence with some minor coal and meandering fluvial sandstone units. The Windermere Sandstone is a regionally extensive transgressive sand unit which overlays the Crayfish unconformity and thickens within the Early Cretaceous troughs. The Eumeralla Formation comprises extensive fluviolacustrine volcanogenic sediment deposited during the sag phase of the basin.
The Late Cretaceous Sherbrook Group overlies the Otway Supergroup as a deltaic wedge that rapidly thickens to the south accounting for most of the sediment in the Morum Sub-basin. In the northern part of the basin, where the group is thin, it comprises a coarse sandstone that represents a condensed equivalent of the Copa, Waarre, Flaxman, Belfast, Paaratte and Timboon units found to the south. Offshore, beyond the present day shelf, thick packages of high-amplitude reflectors indicate the possible presence of paralic oil-prone coals or marine oil shale. From Belfast Mudstone to Timboon Sandstone the sequence represents a prograding delta, with early marine influence and deep-water submarine slope-fans along the outer margin. A regional section across the Otway Basin is shown in Figure 3.
See figures 4 to 11
TOC values range from 0.6 to 9 percent, averaging 1.9 percent (39 samples; 6 wells). The Tmax vs. HI cross plot shows that these organic rich shales are Type II (algal rich oil prone kerogen) to Type III (Gas prone) at the threshold of the oil window. However, in the deeper portions of the Penola, Robe and Saint Clair troughs they are expected to be gas prone with liquids potential.
Maturity modelling indicates that the Casterton Formation lies within the gas window at depths in excess of 3800m in the Penola Trough and Robe Trough but may be locally shallower in the Robe Trough where seismic is poor.
The Upper and Lower Sawpit shales represent lacustrine deposits at the base of the Crayfish Group and can reach thicknesses up 900 m and 250 m thick respectively. The shales are better developed on the northern flank of the Penola Trough, away from the axial drainage in the central part of the trough which is dominated by stacked fluvial channel fill of Pretty Hill Sandstone or Sawpit Sandstone.
Rock Eval analyses of samples from the Upper and Lower Sawpit Shales indicate that the shale is dominated by Type III gas prone kerogen with some Type II algal rich kerogen present. TOC values range 0.37 to 2.61 percent and average 1.12 percent (10 wells, 87 samples).
Maturity modelling suggest that the northern flank of the Otway Basin represents the most prospective area for shale oil play where the Casterton Formation lies in the oil window at depths between 2300 m to ~3050 m (early mature for oil; Ro 0.7 to 1.0 percent) and ~3050 m to 3800 m (later mature for oil; Ro 1.0 to 1.3 percent) in the Robe, Penola, Rivoli and St, Clair troughs. In South Australia oil is produced in negligible amounts from Caroline 1 and in 1992 heavy crude was recovered from Sawpit 1 over a 32 m interval below 2514 m. The oil is presumably sourced from Otway Supergroup sediments. In 1994 Wynn 1 recorded the first liquid hydrocabon flow in the Otway Basin and Killanoola 1 (1998) produced 160 kL (1000 bbl) on test, however neither are currently deemed economic.
Maturity modelling in the Katnook area of the Penola Trough indicates that peak gas generation from the Casterton Formation and Upper and Lower Sawpit Shales occurred in the Maastrichtian at ~73 Ma and has remained in the gas window to present day at depths below ~3800 m.
The Eumeralla Formation is not deep enough in the northern portion of the basin to be a source and shallow northern targets would rely on long-range migration, which may be impeded by the high density of E–W faults. However to the south, where thick Sherbrook sediments occur, the Eumeralla could be a source for Waarre and Flaxman targets. Offshore beyond the present day shelf, possible thick, oil-prone coal measures, or oil shale equivalent to the world wide Albian ocean anoxic event, occur.
The Belfast Mudstone is a relatively poor gas-prone source rock, and is only marginally mature (VR = 0.6%), even in the deepest wells drilled to date. The CO2 in Caroline Field has a volcanic source, assumed to be from the Holocene Mt Gambier volcanic chain, which trends NW through the Tantanoola Trough. Carbon dioxide from a magmatic source has also been noted in Ladbroke Grove Field and Kalangadoo 1. The Caroline 1 well is the single most profitable well in South Australia.
See figure 11
ConventionalProven plays in South Australia include the fault bounded 4 way dip closures in the Pretty Hill and Windermere Sandstone in the Penola trough (oil and or wet gas), although gas discoveries to date are relatively modest in size (average recoverable reserves per field is ~23 PJ (21 bcf)), Fault leakage is a key risk factor. There is considerable potential for significant oil discoveries particularly in the northern flanks of the basin in the future.
In the northern part of the basin, where exploration is for Otway Supergroup targets, Pretty Hill Formation reservoirs of the fields in the Penola Trough comprise complex, steep sided, E–W tilted fault blocks, with the upper Sawpit shale member and Laira Formation acting as the seals. Common palaeohydrocarbon columns have been intersected and leakage is probably caused by the creation of structural permeability across the regional seal. The location of leakage depends on the interaction between the seal, associated faults, and the regional stress field.
Traps for Windermere reservoirs comprise much lower relief domes (close to the resolution limit of seismic mapping) that are generally un-faulted, and sealed by the Eumeralla Formation. The base Eumeralla seal is likely to improve towards the SW. Considerable potential exists for stratigraphic traps, either as meandering fluvial channels in the Eumeralla Formation (as in Katnook Field), or as pinch-outs of the Pretty Hill Formation to the north.
The Flaxman–Waarre units have proven to be excellent gas reservoirs in the Victorian portion of the basin (up to 350 PJ (~321 bcf) in the Minerva Field and ~0.8 tcf in the Thylacine discovery), and in South Australia contain the Caroline CO2 field. Traps are generally NE tilted fault blocks, bounded by closely spaced rift parallel faults. Offshore, potential exists for overpressured submarine slope-fan traps encased within the Belfast Mudstone.
See figure 11
UnconventionalThe principal targets for shale gas or oil in the onshore Otway Basin are thick basal shale sequences within the Otway Supergroup, in particular the Casterton Formation and the Upper and Lower Sawpit shales. These non-marine shales all have good shale gas potential in the deeper portions of the basin. Complex faulting resulting from rift tectonics, while risk factor for conventional traps, could be advantageous for unconventional gas through enhancement of natural fracture networks that would improve connection with, and drainage of, the rock matrix.
Potential also exists for tight gas in the basal sands of the Pretty Hill Formation, particularly in the deeper portions of the Penola and Robe Troughs.
The Otway Basin in South Australia is an immature exploration province, with high potential for further discoveries (Figure 13). Although gas discoveries to date are relatively modest in size (average recoverable reserves per field is ~23 PJ (21 bcf)), some discoveries in the offshore Victorian portion of the basin are an order of magnitude larger (up to 350 PJ (~321 bcf) in the Minerva Field and ~0.8 tcf in the Thylacine discovery). Oil discoveries have only recently been made, and there is considerable potential for significant oil discoveries in the future. Table 1 summarises the undiscovered potential for recoverable sales gas resources in some the key plays of the onshore South Australian portion of the basin. The offshore potential and unconventional potential is as yet unquantified.
Table 1: Undiscovered recoverable sales gas resources of the onshore Otway Basin (South Australia)
UNDISCOVERED POTENTIAL PJ (~bcf)
Probability that the ultimate potential will exceed the stated value:
DSD is not currently involved in any Otway Basin research projects.
Climate, land and sea use
National parks and reserves
There are a number of national parks and other areas of remnant native vegetation in the area, in some of which exploration is permitted, and in others their small size makes it possible to work around them. The reserves have been created to conserve the best examples of vegetation and landforms in the region. There are three types of South Australian reserves in the Otway Basin including conservation parks, national parks and game reserves. The conditions of access vary from park to park, based upon the type of reserve classification, the activity proposed and its likely impact on the environment.
See figure 13
King et al ( 2012) has provided new insights into the stress regime of the Otway Basin, indicating that faults that strike northeast to south west are most likely to reactivate and hence breach conventional accumulations.
Bailey et al (2014) has shown that interpretation of 3-D seismic can detect and map natural fractures in the Penola trough.
Hall et al (2014) has provide new evidence that the offshore portion of the basin has generated significant hydrocarbons, with evidence that the local coastal ashphaltite strandings found on the South Australian coast may be at least in part sourced from the offshore Morum sub-basin.
Bailey, A., King, R., Holford, S., Sage, J., Backe, G., and Hand,M. 2014 Remote sensing of subsurface fractures in the Otway Basin, South Australia. J. Geophys. Res. Solid Earth, 11:6591–6612
Edwards DS, Struckmeyer, HIM, Bradshaw MT and Skinner JE, 1999. Geochemical characteristics of Australia’s southern margin petroleum systems. APPEA Journal, 39(1):297-321.
Hall, P.A., McKirdy, D.M., Grice, K ,, Edwards, D.S. 2014 Australasian asphaltite strandings: Their origin reviewed in light of the effects of weathering and biodegradation on their biomarker and isotopic profiles Marine and Petroleum Geology 57: 572-593
Jones RM, Boult PJ, Hillis RR, Mildrren SD and Kaldi J, 2000. Integrated hydrocarbon seal evaluation in the Penola Trough, Otway Basin. APPEA Journal, 40(1):194-211.
King, R., Holford, S., Hillis, R.,Tuitt, A., Swierczek, E., Backé, G., D. Tassone, D., and M. Tingay, M., 2012 Reassessing the in situ stress regimes of Australia’s petroleum basins. APPEA Journal, 52:415-425
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