CUTTAPIRRIE 1—AN OIL DISCOVERY IN THE EARLY JURASSIC OF THE EROMANGA BASIN

1981 ◽  
Vol 21 (1) ◽  
pp. 60
Author(s):  
T. M. Barr ◽  
Bridget C. Youngs
Keyword(s):  
South Australia ◽  
Early Jurassic ◽  
Oil Field ◽  
Gas Field ◽  
Oil Accumulation ◽  
Gas Accumulation ◽  
Eromanga Basin ◽  
Cooper Basin

Cuttapirrie 1 discovered a significant oil accumulation at a depth of 8 016 ft in the Early Jurassic Hutton Sandstone of the Eromanga Basin. In addition, it discovered a small gas accumulation at 9 386 ft in the underlying Permo-Triassic Cooper Basin of South Australia. The well was 210 km from the nearest Jurassic oil field and 30 km from the nearest gas field when it was drilled.

THE DEVELOPMENT OF THE TIRRAWARRA OIL AND GAS FIELD

1984 ◽  
Vol 24 (1) ◽  
pp. 278
Author(s):  
H. T. Pecanek ◽  
I. M. Paton
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Gas Injection ◽  
Oil Field ◽  
Oil Reservoir ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Associated Gas ◽  
Oil And Gas Field ◽  
Cooper Basin

The Tirrawarra Oil and Gas Field, discovered in 1970 in the South Australian portion of the Cooper Basin, is the largest onshore Permian oil field in Australia. Development began in 1981 as part of the $1400 million Cooper Basin Liquids ProjectThe field is contained within a broad anticline bisected by a north-south sealing normal fault. This fault divides the Tirrawarra oil reservoir into the Western and Main oil fields. Thirty-four wells have been drilled, intersecting ten Patchawarra Formation sandstone gas reservoirs and the Tirrawarra Sandstone oil reservoir. Development drilling discovered three further sandstone gas reservoirs in the Toolachee Formation.The development plan was based on a seven-spot pattern to allow for enhanced oil recovery by miscible gas drive. The target rates were 5400 barrels of oil (860 kilolitres) per day with 13 million ft3 (0.37 million m3) per day of associated gas and 70 million ft3 (2 million m') per day of wet, non-associated gas. Evaluation of early production tests showed rapid decline. The 100 ft (30 m) thick, low-permeability Tirrawarra oil reservoir was interpreted as an ideal reservoir for fracture treatment and as a result all oil wells have been successfully stimulated, with significant improvement in well production rates.The oil is highly volatile but miscibility with carbon dioxide has been proven possible by laboratory tests, even though the reservoir temperature is 285°F (140°C). Pilot gas injection will assess the feasibility of a larger-scale field-wide pressure maintenance scheme using miscible gas. Riot gas injection wells will use Tirrawarra Field Patchawarra Formation separator gas to defer higher infrastructure costs associated with the alternative option of piping carbon dioxide from Moomba, the nearest source.

GEOLOGY OF THE JACKSON OIL FIELD

1984 ◽  
Vol 24 (1) ◽  
pp. 259
Author(s):  
R. V. Halyburton ◽  
A. L. Robertson
Keyword(s):  
Maximum Rate ◽  
Late Jurassic ◽  
Oil Field ◽  
The Other ◽  
Strong Component ◽  
Initial Belief ◽  
Sand Bodies ◽  
Exploration Well ◽  
Eromanga Basin ◽  
Cooper Basin

The Jackson oil field was discovered late in 1981 with the drilling of Jackson 1, which was programmed as an exploration well designed to test the Jurassic-Cretaceous Eromanga Basin sequence and the Permian Cooper Basin sequence, if present. The well tested oil from three formations.The first test to produce oil was carried out across a sand in the Early Cretaceous Murta Member of the Mooga Formation. The zone produced 47° API gravity oil at the rate of 338 barrels (53.7 kilolitres) of oil per day. This was followed by two tests which produced 41° API gravity oil at the rates of 188 and 1165 barrels (29.9 and 185.2 kilolitres) per day respectively from thin sands in the Late Jurassic Westbourne Formation. As a fitting conclusion, the well intersected a 100ft (30 m) oil-saturated section in the Jurassic Hutton Sandstone which on testing flowed 41° API gravity oil at a maximum rate of 2616 barrels (415.9 kilolitres) per day.Four appraisal wells subsequently drilled in the Jackson Field confirmed the initial belief that development of the field was a viable proposition.Compared to the Hutton and Westbourne accumulations, the size of the Murta accumulation is relatively insignificant. The accumulation in the Murta is primarily controlled by structure. On the other hand, the Westbourne accumulation appears to have a strong component of stratigraphic control. In the Hutton accumulation, there is a fair amount of variation in the geometry of the sand bodies at the top of the reservoirs. The accumulation is, however, dominantly controlled by structure.

ECONOMICS OF GAS FIELD DEVELOPMENTS IN THE COOPER BASIN AFTER 1999

1997 ◽  
Vol 37 (1) ◽  
pp. 600
Author(s):  
R.C.M. McDonough
Keyword(s):  
Operating Cost ◽  
South Australia ◽  
Competitive Market ◽  
Field Size ◽  
Gas Field ◽  
Field Development ◽  
The Public ◽  
Cooper Basin

In February 1999 all Cooper Basin exploration acreage in South Australia, which has been under licence since 1954, will be relinquished and therefore become available to new explorers. To assist new explorers in evaluating exploration opportunities, Mines and Energy South Australia (MESA) has developed feasibility level costs for gas field developments which are independent of existing infrastructure owned by the Cooper Basin Joint Venturers. Alternatively, new producers may be able to negotiate access to existing facilities. MESA has developed estimated tolls based on pricing principles which imitate a competitive market. Tolls in this instance should lie between the operating cost of the facility as a minimum and the deprival value cost as a maximum.The study shows that if access to existing facilities is negotiated on a deprival value cost, fields with as little as 5 BCF (141 Mm3) recoverable raw gas are economic. However, if field development is totally independent of existing facilities, the minimum economic field size exceeds 35 BCF (987 Mm3) recoverable raw gas (assuming flaring of LPG is not permitted).MESA conducted this study based on data available in the public and commercial arenas. This demonstrates that it is possible for any company to develop their own data for development and negotiation purposes.

SEISMIC AVO STUDIES ASSIST IN THE MAPPING OF A PERMIAN GAS SAND AT KERNA FIELD, COOPER BASIN

1991 ◽  
Vol 31 (1) ◽  
pp. 244
Author(s):  
J. Pinchin ◽  
A.B. Mitchell
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
Seismic Facies ◽  
Gas Field ◽  
Seismic Modelling ◽  
Coal Beds ◽  
South Central ◽  
Amplitude Versus Offset ◽  
Modelling Studies ◽  
Cooper Basin

Kerna is a gas field within the south-central part of the Cooper Basin, 12 km southwest of the Dullingari Field and adjacent to the border of South Australia and Queensland. The trap is a domal anticline containing gas structurally trapped within the Early Permian Patchawarra Formation. The overlying Permian Epsilon Formation, above intervening shale, also contains gas, which may be stratigraphically trapped or restricted by permeability barriers around the southern and western flanks of the field.Seismic reflection amplitudes can be used to map the extent of the Epsilon gas sand. Seismic modelling studies show that the gas sand displays an amplitude-versus-offset (AVO) effect which distinguishes the gas sand from a wet sand or from a coal reflection at the same stratigraphic level. The spatial distribution of the AVO anomalies, and of the overall seismic stack response, has been mapped across the field. The interpreted 'seismic facies' map shows a meander belt across a coal swamp dominated flood plain. The distribution of AVO anomalies within and around this meander belt shows the likely occurrence of gas-bearing sandstones.This study has implications for other areas of the Cooper Basin where adequate separation between coal beds and gas sands allows the AVO effect of the latter to be observed. These AVO effects can then be used as a direct indicator of gas in stratigraphic and structural traps.

DEEP BASIN GAS: A NEW EXPLORATION PARADIGM IN THE NAPPAMERRI TROUGH, COOPER BASIN, SOUTH AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 185 ◽  
Author(s):  
R.R. Hillis ◽  
J.G.G. Morton ◽  
D.S. Warner ◽  
R.K. Penney
Keyword(s):  
South Australia ◽  
Source Rocks ◽  
Deep Basin ◽  
Gas Accumulation ◽  
Impermeable Barrier ◽  
Trapped Gas ◽  
Giant Fields ◽  
Rock Section ◽  
Sweet Spots ◽  
Cooper Basin

Deep basin hydrocarbon accumulations have been widely recognised in North America and include the giant fields of Elmworth and Hoadley in the Western Canadian Basin. Deep basin accumulations are unconventional, being located downdip of water-saturated rocks, with no obvious impermeable barrier separating them. Gas accumulations in the Nappamerri Trough, Cooper Basin, exhibit several characteristics consistent with North American deep basin accumulations. Log evaluation suggests thick gas columns and tests have recovered only gas and no water. The resistivity of the entire rock section exceeds 20 Ωm over large intervals, and, as in known deep basin accumulations, the entire rock section may contain gas. Gas in the Nappamerri Trough is located within overpressured compartments which witness the hydraulic isolation necessary for gas saturation outside conventional closure. Furthermore, the Nappamerri Trough, like known deep basin accumulations, has extensive, coal-rich source rocks capable of generating enormous hydrocarbon volumes. The above evidence for a deep basin-type gas accumulation in the Nappamerri Trough is necessarily circumstantial, and the existence of a deep gas accumulation can only be proven unequivocally by drilling wells outside conventional closure.Exploration for deep basin-type accumulations should focus on depositional-structural-diagenetic sweet spots (DSDS), irrespective of conventional closure. This is of particular significance for a potential Nappamerri Trough deep basin accumulation because depositional models suggest that the best net/gross may be in structural lows, inherited from syndepositional lows, that host stacked channel sands within channel belt systems. Limiting exploration to conventionally-trapped gas may preclude intersection with such sweet spots.

THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 67 ◽  
Author(s):  
K. A. Parker
Keyword(s):  
South Australia ◽  
Subsequent Development ◽  
Hydrocarbon Exploration ◽  
Gas Field ◽  
Water Contact ◽  
Field Development ◽  
Gas Accumulation ◽  
Seismic Acquisition ◽  
History Of ◽  
Gas Fields

The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.

THE DELIA FIELD, COOPER BASIN, SOUTH AUSTRALIA

1973 ◽  
Vol 13 (1) ◽  
pp. 58
Author(s):  
Martin Pyecroft
Keyword(s):  
Joint Venture ◽  
South Australia ◽  
Upper Permian ◽  
Gas Field ◽  
Water Contact ◽  
Reservoir Characteristics ◽  
Cooper Basin

The Della gas field of the Cooper Basin, South Australia, was discovered by Pursuit Oil No Liability and joint venture associates in July 1970. The field covers an area of approximately 17,000 acres in a discrete culmination on the Nappacoongee-Murteree anticlinal trend.Production is from several fluviatile sandstone units within the Toolachee Formation of the Upper Permian Gidgealpa Group. The trap is essentially structural with a maximum closure of some 450 ft on the top of the Toolachee Formation above a probable gas-water contact at 6,460 ft subsea.Five of the seven wells drilled to date in the field have been completed as potential gas producers. Production occurs between 6,270 and 6,670 ft and the average total depth is 7,180 ft. Net pay thicknesses vary from 37 to 98 ft and good reservoir characteristics are typical of the producing sands in the field. Twenty-two days are normally required to drill and complete a productive well.

Sign in / Sign up

Export Citation Format

Share Document