SANDSTONE RESERVOIR GEOMETRY OF NON-MARINE SEDIMENTS IN THE TOOLACHEE GAS FIELD

1977 ◽  
Vol 17 (1) ◽  
pp. 50
Author(s):  
S. Bevan Devine ◽  
Colin G. Gatehouse
Keyword(s):  
Gas Field ◽  
Cross Sectional ◽  
Field Extensions ◽  
Trapping Mechanism ◽  
Reservoir Geometry ◽  
Structural Closure ◽  
Basin Boundaries ◽  
Field Area ◽  
Reserve Estimates ◽  
Cooper Basin

The concept of Genetic Increments of Strata (GIS) has been applied to correlations of the non-marine rocks of the Early Permian Patchawarra Formation of the Cooper Basin. Boundaries of GIS in the non-marine rocks are related to a dynamic model of non-marine deposition in which discrete sandstone bodies result from channel activity.In the 9 wells in the Toolachee Gas Field area of about 150 sq. miles, log correlations based on these principles determined eight major sandstone bodies, six of which hold gas reserves. The sandstone bodies are elongate and sinuous. They have cross-sectional dimensions of about 5 miles wide by up to 60 ft thick. Faulting and differential compaction have influenced the locations of the axes of the channel sandstone bodies.The value of mapping the geometry of the channel sandstones in the Cooper Basin lies in establishing a possible trapping mechanism which is independent of structural closure and which requires only a structural dip nonperpendicular to the channel sandstone direction; and providing a geologic basis for gas reserve estimates, the positioning of future appraisal and development wells and the prediction of field extensions and nearby new fields.An estimate of the proven-probable gas in place in the Toolachee Gas Field (560 BCF) based on the channel sandstone mapping is comparable with estimates based on lumping all pay intervals together in each well and drawing geometric pay isoliths. Estimates of possible reserves are increased by the mapping because of the introduction of the trapping mechanism of sandstone margins. The Toolachee Field has the potential to be perhaps doubled in size.

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.

SEISMIC INVESTIGATION OF THE MERRIMELIA FIELD

1983 ◽  
Vol 23 (1) ◽  
pp. 192
Author(s):  
B. L. Smith
Keyword(s):  
Oil And Gas ◽  
Seismic Survey ◽  
Gas Field ◽  
Central Dome ◽  
Oil Reserves ◽  
Oil And Gas Field ◽  
Well Data ◽  
Field Area ◽  
Made In ◽  
Commercial Oil

The Merrimelia oil and gas field, 40 km north of Moomba in SA, is located on the central dome of the Gidgealpa-Merrimelia-Innamincka Trend within the Cooper/Eromanga Basins.Geophysical studies have been instrumental in the investigation of the field since the discovery of commercial Permo-Triassic gas at Merrimelia- 5 in 1970 based on the results of the Merrimelia Seismic Survey. Subsequent seismic recorded during the 1980 Karawinnie Survey resulted in the location of Merrimelia-6 which, in 1981, discovered commercial oil in the Jurassic Namur Member and Hutton Sandstone, and Triassic gas, previously unknown.To allow accurate mapping of the field's oil reserves, a detailed half kilometre grid was recorded during the 1981 Namooka Seismic Survey. The programme comprised 110 km of 24-fold Vibro- seis coverage. Interpretation of the seismic and well data has resulted in recognition of a complex stratigraphic component superimposed on the Merrimelia structural high. Considerable detailed seismic work has contributed to a better understanding of the seismic reflection sequence and hence improved geophysical prognoses.Seismic studies of the Merrimelia field are continuing as further discoveries, most recently oil in the Triassic at Merrimelia-12 and gas in the Tirrawarra Sandstone at Merrimelia-13, are made in the field area.

scholarly journals Exploration history and trapping mechanism of Peciko gas field, East Kalimantan, Indonesia.

1996 ◽  
Vol 61 (1) ◽  
pp. 25-34 ◽  
Author(s):  
Yoshiyuki Hayashi ◽  
Tsuyoshi Inage ◽  
Ikuo Suzuki ◽  
Hiroshi Nagura
Keyword(s):  
Gas Field ◽  
Trapping Mechanism ◽  
East Kalimantan

Completion Practices and Reserve Estimates for Pecos Slope Abo Gas Field

1982 ◽  
Author(s):  
David F. Boneau ◽  
Joe Braswell ◽  
Albert R. Stall ◽  
Robert E. Tisdale
Keyword(s):  
Gas Field ◽  
Reserve Estimates

From play to production: the Cooper unconventional story—20 years in the making

2015 ◽  
Vol 55 (2) ◽  
pp. 407 ◽  
Author(s):  
Carl Greenstreet
Keyword(s):  
East Coast ◽  
Market Access ◽  
Horizontal Wells ◽  
Gas Flows ◽  
Resource Potential ◽  
Unconventional Resources ◽  
Gas Shales ◽  
Reservoir Conditions ◽  
Structural Closure ◽  
Cooper Basin

The Cooper Basin is Australia’s leading onshore producing hydrocarbon province, having produced more than 6 Tcf of natural gas since 1969. The basin is undergoing renewal 45 years later, driven by the emerging growth of east coast LNG export-driven demand. Following North America’s shale gas revolution, the Cooper Basin’s unconventional potential is now widely appreciated and it is believed to hold more than 100 Tcf of recoverable gas. This resource potential is held in four stacked target unconventional lithotypes, each having demonstrated gas flows: tight sands—heterogeneous stacked fluvial sands; deep coal—porous dry coals, oversaturated with gas; shales—thick, regionally extensive lacustrine shales; and, hybrid shales—mixed lithotype containing interbedded tight sandstones, shales and coals. Industry activity initially focused on the Nappamerri Trough, where more than 25 contemporary exploration wells have been drilled, proving up an extensive basin-centred gas play with >1,000 m of continuous overpressured gas saturated section outside of structural closure. Santos has had a team focused on unconventional resources for nearly 20 years and successful results have been quickly tied into the producing infrastructure. This has been demonstrated with the Moomba–191 REM shale success, Moomba–194 and the recent Moomba–193H connection, one of the basin’s first fracture-stimulated horizontal wells. Prospective geology, existing infrastructure and market access makes the Cooper Basin well positioned for unconventional success. Each resource play is unique and commercial success requires considered adaptation of established technologies and workflows, based on a understanding of local geological and reservoir conditions. Commercialisation activity now seeks to define play fairways, characterise and prioritise reservoir targets and determine appropriate drilling and completion approaches.

THE KALLADEINA FORMATION – A WARBURTON BASIN CAMBRIAN CARBONATE PLAY

1990 ◽  
Vol 30 (1) ◽  
pp. 166 ◽  
Author(s):  
D.C. Roberts ◽  
P.G. Carroll ◽  
J. Sayers
Keyword(s):  
Large Scale ◽  
Oil And Gas ◽  
Source Rocks ◽  
Gas Oil ◽  
Gas Field ◽  
Oil And Gas Field ◽  
Shelf Sediments ◽  
Wrench Fault ◽  
Very High ◽  
Cooper Basin

The Warburton Basin is currently considered economic basement to the gas-oil productive Cooper Basin and the oil productive Eromanga Basin. Only 10 wells have penetrated more than 100 m of the Kalladeina Formation which is identified as the most prospective section within the Warburton Basin. The Kalladeina Formation consists of more than 1600 m of carbonate shelf sediments deposited during the early Cambrian to early Ordovician in a basin consisting of half grabens on the continental side of an active margin.Several intra-Kalladeina Formation seismic events in a 500 km2 region to the west of the Gidgealpa oil and gas field have been tied to wells with palaeontological control. Structure and isopach mapping illustrates large scale thrusts, wrench fault zones and subcrop edges for the Kalladeina Formation. Maps of unconformities and of formations above the Warburton Basin define source, seal and trap relationships.Good carbonate reservoirs have been identified in the Kalladeina Formation but the source potential of this succession appears to be restricted. The overlying Cooper Basin source rocks may have charged the underlying carbonates and this represents one of three play types identified in the area.All Warburton Basin plays are very high risk but potential reserves are also large.

Exploiting the Cooper Basin: conventional lessons and appropriate analogues to guide an unconventional future

2018 ◽  
Vol 58 (1) ◽  
pp. 339
Author(s):  
Brenton Richards ◽  
Alexander Côté
Keyword(s):  
Development Strategy ◽  
Horizontal Well ◽  
Tight Gas ◽  
Vertical Wells ◽  
Gas Field ◽  
The Status ◽  
Potential Reservoir ◽  
Capital Efficiency ◽  
Gas Potential ◽  
Cooper Basin

Over the past decade, there has been a paradigm shift in the exploitation strategy in North American tight gas plays from vertical to horizontal wells. This shift has yet to occur in Australia. The Cooper Basin has vast amounts of contingent and prospective tight gas resources that have yet to be unlocked commercially. These resources continue to be developed primarily with hydraulic fracture stimulated vertical wells. Operators have yet to challenge the status quo and test the Cooper Basin tight gas potential with a drilled, completed and tested horizontal well. There are many advantages to horizontal well developments, from the ability to target a specific high graded reservoir unit to increased capital efficiency. Operators need to break away from convention and take a new approach to Cooper Basin tight gas exploration and development in the quest to demonstrate commerciality. A review of the inherent challenges in Cooper Basin gas field developments and the current exploitation strategies employed in analogous tight gas plays have been integrated to produce a pragmatic workflow to identify potential reservoir units that would benefit from a change in development strategy.

The Nappamerri Trough, Cooper Basin unconventional plays: proving a hypothesis

2012 ◽  
Vol 52 (2) ◽  
pp. 662 ◽  
Author(s):  
Carrie Trembath ◽  
Lindsay Elliott ◽  
Mark Pitkin
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Primary Source ◽  
Gas Flows ◽  
Gas System ◽  
Central Trough ◽  
The Usa ◽  
Early Exploration ◽  
Structural Closure ◽  
Cooper Basin

Beach Energy has started exploring unconventional gas in the Nappamerri Trough, the central trough within the Cooper Basin, where the Permian section has long been regarded as the primary source for most of the conventional hydrocarbons found within the basin. This extended abstract discusses the data used to identify the unconventional play and the exploration program carried out to date. Mud weights, drill stem test (DST) pressures and log data from early exploration wells identified the Permian formations as overpressured. This with geochemical and mineralogy analyses indicated that the Roseneath and Murteree Shales had potential similar to successful shale gas plays being developed in the USA. The quartz and siderite content within both shale sections indicated sufficient brittleness for successful fracture stimulation. In addition, the Nappamerri Trough Permian section showed low permeabilities, which, when combined with overpressure, suggested a basin-centred style play within the Epsilon and Patchawarra sandstones and possibly the Toolachee Formation sandstones. During 2010–11, Beach drilled two exploration wells sited outside structural closure to test both the shale gas and basin centred gas system. Both wells have now been fracture stimulated, with very encouraging gas flows from the Roseneath to Patchawarra section. The latest geological data confirms the pre-drill potential for both gas flow from the shales and the presence and production of gas from sandstones outside structural closure, resulting in a significant shale and tight gas resource booking. Ongoing exploration and development will target a potential 300 Tcf gas in place in PEL 218.

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