Heat flow in the Moomba, Big lake and Toolachee gas fields of the Cooper Basin and implications for hydrocarbon maturation

1979 ◽  
Vol 10 (2) ◽  
pp. 149-155 ◽  
Author(s):  
M.F. Middleton
Keyword(s):  
Heat Flow ◽  
Hydrocarbon Maturation ◽  
Gas Fields ◽  
Cooper Basin

EXPLORATION IN THE COOPER BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 366 ◽  
Author(s):  
R. Heath
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Mature Stage ◽  
Small Contribution ◽  
Terrestrial Source ◽  
Seismic Acquisition ◽  
Proterozoic Basement ◽  
Gas Fields ◽  
Coal Measures ◽  
Cooper Basin

The Cooper Basin is located in the northeastern corner of South Australia and in the southwestern part of Queensland. The basin constitutes an intracratonic depocentre of Permo- Triassic age. The Cooper Basin succession unconformably overlies Proterozoic basement as well as sediments and metasediments of the Cambro- Ordovician age. An unconformity separates in turn the Cooper succession from the overlying Jurassic- Cretaceous Eromanga Basin sediments.The Permo- Triassic succession comprises several cycles of fluvial sandstones, fluvio- deltaic coal measures and lacustrine shales. The coal measures contain abundant humic kerogen, comprising mainly inertinite and vitrinite with a small contribution of exinite. All hydrocarbon accumulations within the Cooper Basin are believed to have originated from these terrestrial source rocks.Exploration of the basin commenced in 1959 and, after several dry holes, the first commercial discovery of gas was made at Gidgealpa in 1963. To date, some 97 gas fields and 10 oil fields, containing recoverable reserves of 5 trillion cubic feet of gas and 300 million barrels recoverable natural gas liquids and oil, have been discovered in the Cooper Basin. Production is obtained from all sand- bearing units within the Cooper stratigraphic succession.The emphasis of exploration in the Cooper Basin is largely directed towards the assessment of four- way dip closures and three- way dip closures with fault control, but several stratigraphic prospects have been drilled. Furthermore, in the development phase of some gas fields a stratigraphic component of the hydrocarbon trapping mechanism has been recognised.Improvements in seismic acquisition and processing, combined with innovative thinking by the explorers, have facilitated the development of untested structural/stratigraphic plays with large reserves potential. Exploration for the four- and three- way dip closure plays in the Cooper Basin is now at a mature stage. However, reserves objectives are expected to continue to be met, with the expectation of a continuing high success rate.Selected new plays are expected to be tested within a continuing active exploration program as exploration for oil and gas in the Cooper Basin refines the search for the subtle trap.

SURFACE FACILITIES FOR THE SOUTH WEST QUEENSLAND GAS PROJECT

1994 ◽  
Vol 34 (1) ◽  
pp. 55
Author(s):  
Richard G. Robinson
Keyword(s):  
Full Range ◽  
Operating Experience ◽  
The South ◽  
South West ◽  
Wet Gas ◽  
High Level ◽  
The Cost ◽  
Gas Fields ◽  
Cooper Basin ◽  
Hydrocarbon Development

The South West Queensland Gas Project is the first greenfield gas development in the Cooper Basin for around 10 years. This has allowed a decade of operating experience from wet gas fields in the region to be applied in the design of the new facility. The design also took into consideration potential future expansion of the facility for increased throughput and the production of sales gas to service markets to the east and north.A greenfield hydrocarbon development in such a remote location is much more than just a gathering system and processing facility. A full range of infrastructure was also developed including telecommunications, roads, airstrip, accommodation and utilities.The project offered opportunities for a wide variety of Australian vendors and construction contractors. Many demonstrated a high level of capability to meet the cost, schedule and quality demands of a hydrocarbon development in the 1990s. Unfortunately, a number failed to demonstrate that capability.

Early Cretaceous volcanism in the Scotian Basin 1This article is one of a series of papers published in this CJES Special Issue on the theme of Mesozoic–Cenozoic geology of the Scotian Basin.

2012 ◽  
Vol 49 (12) ◽  
pp. 1523-1539 ◽  
Author(s):  
Sarah J. Bowman ◽  
Georgia Pe-Piper ◽  
David J.W. Piper ◽  
Robert A. Fensome ◽  
Edward L. King
Keyword(s):  
Heat Flow ◽  
Early Cretaceous ◽  
Volcanic Rocks ◽  
Magma Source ◽  
Seismic Profiles ◽  
Scotian Shelf ◽  
Grand Banks ◽  
Hydrocarbon Maturation ◽  
Stratigraphic Position ◽  
Cretaceous Volcanism

Early Cretaceous volcanism is widespread in the eastern Scotian Basin. The stratigraphic position of volcanic rocks within wells was re-evaluated and the volcanological character of the rocks was refined by study of cuttings and well logs. Hauterivian–Barremian volcanic rocks on the SW Grand Banks and Aptian–Albian volcanic rocks in the Orpheus Graben and SE Scotian Shelf resulted from Strombolian type eruptions. More extensive Hawaiian type flows were mapped from seismic profiles near the Mallard and Brant wells on the SW Grand Banks and they appear to have been derived from local basement highs with a positive magnetic anomaly interpreted as volcanic centres. Igneous rocks in the Hesper well on the SE Scotian Shelf are the erosional remnant of basaltic flows that terminated at the paleoshoreline. They correlate with basalt flows both in extensive outcrop on Scatarie Ridge and in several Orpheus Graben wells. The interpretation of the Hesper basalts as an erosional remnant of more extensive basalt flows is consistent with detrital petrographic evidence for substantial uplift of the inboard part of the Scotian Basin in the Hauterivian–Aptian. Widespread volcanic activity indicates a regional and long-lived magma source, which resulted in elevated regional heat flow. Effects of this heat flow are seen in sedimentary rocks of the Sable Subbasin and it had a discernable impact on hydrocarbon maturation.

STRUCTURE AND HYDROCARBONS IN THE SHIPWRECK TROUGH, OTWAY BASIN: HALF-GRABEN GAS FIELDS ABUTTING A CONTINENTAL TRANSFORM

2004 ◽  
Vol 44 (1) ◽  
pp. 417 ◽  
Author(s):  
D. Palmowski ◽  
K.C. Hill ◽  
N. Hoffman
Keyword(s):  
Lateral Displacement ◽  
Seismic Survey ◽  
Early Eocene ◽  
Regional Study ◽  
Large Structures ◽  
Hydrocarbon Maturation ◽  
Half Graben ◽  
Hinge Zone ◽  
Gas Fields ◽  
Great Australian Bight

As part of a regional study of the evolution of the Otway Basin, the Investigator 3D seismic survey has been structurally analysed, using 11 extracted 2D sections and 3D interpretations of key horizons. South-southwest directed extension was widespread in the Turonian forming the Shipwreck Trough, coincident with uplift of the Otway Ranges to the northeast. The Turonian extension, at ~1.5 myrs, resulted in planar faults in the northeastern part of the Trough, but large half-graben above south-southwest dipping listric master faults in the southwest, both fault sets soling into an Early Cretaceous shale detachment. The half-graben propagated north from the Mussel-Tarpwaup Hinge-Zone by footwall collapse and accommodated deposition of reservoir rocks for the known hydrocarbon accumulations. The half-graben die out along strike to the east at tip-points against an accommodation zone that developed into a continental transform (the Shipwreck Fault).Santonian breakup in the Great Australian Bight coincided with considerable south-southwesterly extension in the Otway Basin juxtaposed against the failed Bassian rift across the Shipwreck Fault. Extension of ~1.21 km to the west of the Shipwreck Fault contrasts with ~0.42 km on the eastern side accommodated by ~0.79 km left-lateral displacement along the Shipwreck Fault. The Belfast Mudstone was deposited during this time, forming the regional seal for the known hydrocarbon accumulations.Limited slow extension during the Campanian to Early Eocene resulted in a further 0.33 km sinistral slip along the Shipwreck Fault. Late Early Eocene Breakup in the Otway Basin ended the transitional phase, terminating extensional and Shipwreck Fault offset. The breakup caused local uplift and ~1 km erosion of Wangerrip Group sediments. The post breakup phase is characterised by prograding sequences indicating progressive-regressive cycles.The Thylacine and La Bella gas fields occur in large tilted fault-blocks near the Hinge-Zone. These successful large structures lie along a longstanding High probably sourced from south of the Hinge-Zone. Key elements for a successful hydrocarbon play are deposition of the Turonian Waarre Formation sandstone reservoirs at rift onset and of a thick Belfast Mudstone seal during continuous Coniacian-Santonian extension. Footwall collapse north of the Hinge-Zone, bound by the deepwater Otway Basin and the continental transform, controlled the distribution of traps, regional seal and hydrocarbon maturation.

BASEMENT AND CRUSTAL CONTROLS ON HYDROCARBON MATURATION—LESSONS FROM BREMER SUB-BASIN FOR OTHER FRONTIER EXPLORATION AREAS

2006 ◽  
Vol 46 (1) ◽  
pp. 237 ◽  
Author(s):  
A. Goncharov ◽  
I. Deighton ◽  
P. Petkovic ◽  
H. Tassell ◽  
S. McLaren ◽  
...  
Keyword(s):  
Heat Flow ◽  
Surface Heat ◽  
Seismic Survey ◽  
Low Grade ◽  
Sea Floor ◽  
Rock Samples ◽  
Surface Heat Flow ◽  
Hydrocarbon Maturation ◽  
Refraction Seismic ◽  
Consistent Approach

A consistent approach to the assessment of basement and crustal controls on hydrocarbon maturation in the Bremer Sub-basin, offshore southwest Australia, has been undertaken as part of the Australian Government’s Big New Oil initiative. Geoscience Australia acquired marine reflection seismic survey in this area during late 2004 in conjunction with recording of refraction seismic data by sonobuoys at sea and by land stations in the onshore/offshore observation scheme. One of the key findings of the refraction seismic study is that velocities in the basement are generally in the 5.0–5.7 km/s range, indicating that, contrary to prior expectations, basement in the area is mostly not granitic in composition. Results from the conjugate margin in Antarctica also show low velocities in the basement on the inner side of Antarctic continent-ocean boundary, consistent with results from the Australian margin. It appears that a ~400-km-wide zone in Gondwana prior to break up had basement velocities significantly lower than the normal continental values of 6.0–6.2 km/s most commonly associated with granites and gneisses. Low-grade metasediments of the Albany-Fraser Orogen and its Antarctic equivalent is the preferred interpretation of this observation. Granites, dredged from the sea floor in the Bremer area, may represent only a small fraction of the basement, as within the basement highs where higher velocities have been detected by refraction work. As metasediments produce substantially less heat than granites, a different scenario for hydrocarbon maturation in the Bremer Sub-basin is possible. To quantify possible heat production in the Bremer basement and crust below it we have used contents of radioactive elements in rock samples taken from outcrops of Yilgarn Craton and Albany-Fraser Orogen onshore, as well as in rock samples dredged from the sea floor in the Bremer Sub-basin. Advanced burial and thermal geohistory modelling in this area was carried out using Fobos Pro modelling software for the first time in Australia without relying on default or inferred values (such as heat flow or geothermal gradient). Modelling showed that subsidence curves can be matched in various basement composition scenarios, but the high heat-producing granitic scenario leads to a present-day surface heat flow of 68 mW/m2 predicted by the model—unrealistically high given the context of heat flow measurements on the Australian Southern Margin. Other basement compositions (low heat- producing granite, metasediments, basalts) lead to a present-day surface heat flow of 46–57 mW/m2 and cannot be ruled out on the basis of heat flow modelling and data alone. This work details a methodologically consistent approach to burial and thermal geohistory modelling for other frontier areas where appropriate geophysical data have been collected.

scholarly journals Reservoir characterisation of the Patchawarra Formation within a deep, basin-margin gas accumulation

2014 ◽  
Vol 54 (1) ◽  
pp. 45 ◽  
Author(s):  
Tim Stephens ◽  
Brenton Richards ◽  
Joseph Lim
Keyword(s):  
Gas Flows ◽  
Deep Basin ◽  
Gas Accumulation ◽  
Reservoir Architecture ◽  
Trap Potential ◽  
Gas Fields ◽  
Depositional Setting ◽  
The Impact ◽  
Basin Margin ◽  
Cooper Basin

An exploration program to assess the basin-centred gas (BCG) and stratigraphic trap potential of the Mettika Embayment in the southern Cooper Basin resulted in the discovery of gas at Hornet–1 and Kingston Rule–1. The embayment is a confined fluvial sedimentary depocentre surrounded by prolific gas fields producing from structurally closed anticlines. Gas pay was identified and both wells produced sustained gas flows to surface of between 1.2 and 2.2 MMscf/d after fracture stimulation. Core collected from the Patchawarra Formation sandstone reservoir was analysed to constrain the depositional environment and establish petrophysical properties by routine and special core analysis. An integrated reservoir study was undertaken to understand depositional setting, reservoir architecture, trapping mechanisms, permeability, and saturation controls on productivity. Gas identified in the embayment appears to have accumulated in subtle stratigraphic and combination structural traps against the flanks of existing fields and does not display the geological and physical characteristics of a BCG play. The impact and analysis of hydrocarbon migration and reservoir trapping influences in this basin-margin gas accumulation may be applicable to other under-explored flank and trough plays of the Cooper Basin.

Sign in / Sign up

Export Citation Format

Share Document