THE CEDUNA SUB-BASIN—A SNAPSHOT OF PROSPECTIVITY

2001 ◽  
Vol 41 (1) ◽  
pp. 321 ◽  
Author(s):  
R. Somerville
Keyword(s):  
Late Cretaceous ◽  
Seismic Data ◽  
Charge System ◽  
The North ◽  
Exploration Risk ◽  
Exploration Drilling ◽  
Marine Seismic ◽  
Hydrocarbon Charge ◽  
Great Australian Bight ◽  
Water Depths

The Ceduna Sub-basin comprises one of the major untested potential petroleum provinces in Australia. It is located in the Great Australian Bight, forming part of the Bight Basin. Water depths range from 100 m in the north to over 4,000 m in the south. Although over 100,000 line km of 2D marine seismic data have been acquired in the Great Australian Bight, only 20,600 line km of 2D marine seismic data of variable vintage and quality have been acquired in the Ceduna Sub-basin. Only one exploration well, Potoroo–1, has been drilled within the Ceduna Sub-basin. The Potoroo–1 well is located on the extreme landward edge of the depocentre which is dominated by the Late Cretaceous Ceduna Delta. Consequently, the hydrocarbon potential of the basin is effectively untested.The most promising play types within the Ceduna Subbasin are dip and fault-dip closures associated with listric faults within the Late Cretaceous (Santonian- Maastrichtian) deltaic sequence and accentuated by slight Late Cretaceous/Tertiary compression. Fault-dip closures are also recognised within the Santonian section. A channel sub-crop play within the Santonian is also potentially viable.Hydrocarbon charge is perceived to be the most significant exploration risk. Although asphaltite strandings have been reported, the hydrocarbon charge system is unproven. Future exploration in the Great Australian Bight will need to address:harsh climatic/meteorological and oceanographic conditions in the Southern Ocean and short seasonal windows;extreme sea floor relief and viability of safe exploration drilling in water depths over 1,500 m; andoperating in a responsible and environmentally sensitive way in proximity to the Benthic Protection Zone.

Bight Basin acreage release—new exploration opportunities in a deep water frontier

2009 ◽  
Vol 49 (1) ◽  
pp. 491
Author(s):  
Jennifer Totterdell ◽  
Heike Struckmeyer ◽  
Andrew Stacey
Keyword(s):  
Late Cretaceous ◽  
Seismic Data ◽  
Source Rocks ◽  
High Quality ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Exploration Risk ◽  
Commonwealth Government ◽  
Exploration Drilling ◽  
Water Depths

In 2009, the Commonwealth Government is releasing six large exploration areas in the frontier Bight Basin. The areas lie in the Ceduna Sub-basin, in water depths ranging from 130 to 4,600 m. At present, no permits are held in this part of the basin. Most exploration drilling in the Bight Basin has focussed on the margins of the Ceduna Sub-basin and on the adjacent Duntroon Sub-basin. Gnarlyknots 1A, drilled by Woodside Energy and partners in 2003, is the only well to have attempted to test the thick, prospective Ceduna Sub-basin succession away from the margins of the sub-basin, but did not reach all its target horizons due to weather and ocean conditions. The key to the petroleum prospectivity of the Ceduna Sub-basin is the distribution of the Late Cretaceous marine and deltaic facies. Recent dredging of Late Cenomanian–Turonian organic-rich marine rocks has confirmed the presence of high quality source rocks in the Bight Basin and has significantly reduced exploration risk. These potential source rocks are mature in the central part of the Ceduna Sub-basin and are likely to have generated and expelled hydrocarbons since the Campanian. Excellent reservoir rocks and potential intraformational seals are present in the Late Cretaceous deltaic successions and regional seals could be provided by Late Cretaceous marine shales. Interpretation of seismic data has identified numerous play types in the basin and some structures show amplitude anomalies, providing many exploration targets for explorers.

Petroleum Systems Analysis of The Tungkal PSC Area, South Sumatra – A Means of Adding New Life to A Mature Area

2020 ◽  
Author(s):  
A. Livsey
Keyword(s):  
Seismic Data ◽  
Systems Analysis ◽  
Generation Model ◽  
Hydrocarbon Accumulation ◽  
Petroleum Systems ◽  
Oil Generation ◽  
Exploration Risk ◽  
Exploration Area ◽  
Hydrocarbon Charge ◽  
Surface Geology

South Sumatra is considered a mature exploration area, with over 2500MMbbls of oil and 9.5TCF of gas produced. However a recent large gas discovery in the Kali Berau Dalam-2 well in this basin, highlights that significant new reserve additions can still be made in these areas by the re-evaluation of the regional petroleum systems, both by identification of new plays or extension of plays to unexplored areas. In many mature areas the exploration and concession award history often results in successively more focused exploration programmes in smaller areas. This can lead to an increased emphasis on reservoir and trap delineation without further evaluation of the regional petroleum systems and, in particular, the hydrocarbon charge component. The Tungkal PSC area is a good example of an area that has undergone a long exploration history involving numerous operators with successive focus on block scale petroleum geology at the expense of the more regional controls on hydrocarbon prospectivity. An improved understanding of hydrocarbon accumulation in the Tungkal PSC required both using regional petroleum systems analysis and hydrocarbon charge modelling. While the Tungkal PSC operators had acquired high quality seismic data and drilled a number of wells, these were mainly focused on improving production from the existing field (Mengoepeh). More recent exploration-driven work highlighted the need for a new look at the hydrocarbon charge history but it was clear that little work had been done in the past few year to better understand exploration risk. This paper summarises the methodology employed and the results obtained, from a study, carried out in 2014-15, to better understand hydrocarbon accumulation within the current Tungkal PSC area. It has involved integration of available well and seismic data from the current and historical PSC area with published regional paleogeographic models, regional surface geology and structure maps, together with a regional oil generation model. This approach has allowed a better understanding of the genesis of the discovered hydrocarbons and identification of areas for future exploration interest.

A proven method for acquiring highly repeatable towed streamer seismic data

Geophysics ◽  
2003 ◽  
Vol 68 (4) ◽  
pp. 1303-1309 ◽  
Author(s):  
Ola Eiken ◽  
Geir Ultveit Haugen ◽  
Michel Schonewille ◽  
Adri Duijndam
Keyword(s):  
Seismic Data ◽  
Time Lag ◽  
High Sensitivity ◽  
Seismic Properties ◽  
The North ◽  
Seismic Reservoir ◽  
The North Sea ◽  
Marine Seismic ◽  
Streamer Data ◽  
Proven Method

Seismic reservoir monitoring has become an important tool in the management of many fields. Monitoring subtle changes in the seismic properties of a reservoir caused by production places strong demands on seismic repeatability. A lack of repeatability limits how frequently reservoir changes can be monitored or the applicability of seismic monitoring at all. In this paper we show that towing many streamers with narrow separation, combined with cross‐line interpolation of data onto predefined sail lines, can give highly repeatable marine seismic data. Results from two controlled zero time lag monitoring experiments in the North Sea demonstrate high sensitivity to changing water level and variations in lateral positions. After corrections by deterministic tidal time shifts and spatial interpolation of the irregularly sampled streamer data, relative rms difference amplitude levels are as low as 12% for a deep, structurally complex field and as low as 6% for a shallow, structurally simple field. Reducing the degree of nonrepeatability to as low as 6% to 12% allows monitoring of smaller reflectivity changes. In terms of reservoir management this has three important benefits: (1) reservoirs with small seismic changes resulting from production can be monitored, (2) reservoirs with large seismic changes can be monitored more frequently, and (3) monitoring data can be used more quantitatively.

DEPOSITIONAL SEQUENCE OF THE WITHNELL FORMATION, DAMPIER SUB-BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 296
Author(s):  
J. S. Rasidi
Keyword(s):  
Late Cretaceous ◽  
Seismic Data ◽  
Depositional Environment ◽  
Thickness Distribution ◽  
Well Logs ◽  
Hydrocarbon Potential ◽  
Depositional Sequence ◽  
Well Data ◽  
Water Depths ◽  
Reservoir Facies

The Late Cretaceous Withnell Formation has attracted very little exploration attention because of the perception that it has poor hydrocarbon potential. This unfavourable perception has arisen from the fact that very little is known about its depositional environment and lithofacies and therefore, its petroleum prospectivity.A sudden fall of relative sea level occurred at the end of the Santonian, and was followed by the deposition of the siliciclastic Withnell Formation. The occurrence of a number of channels and canyons at the base of the formation, over the old shelf and slope on the southern margin of the sub-basin, supports the hypothesis that the Withnell Formation began as a lowstand systems tract. The thickness distribution of the formation and the progradation direction of seismic packages suggest a southeasterly provenance. Correlation of seismic data and well logs, and rock descriptions demonstrate the presence of units deposited during increasing water depths and subsequent highstand systems tract.Much more information, both seismic and well data, is required to establish the facies distribution within the Withnell Formation which may contain sand-prone lowstand facies such as basinfloor or slope fans. The presence of such reservoir facies would enhance the petroleum prospectivity of the Withnell Formation.

The petroleum prospectivity of the Oobagooma Sub-basin and adjacent Leveque Platform, North West Shelf, Australia

2016 ◽  
Vol 56 (2) ◽  
pp. 563
Author(s):  
Paul Harrison ◽  
Chris Swarbrick ◽  
Jim Winterhalder ◽  
Mark Ballesteros
Keyword(s):  
Oil And Gas ◽  
Long Distance ◽  
The West ◽  
North West ◽  
Canning Basin ◽  
The Past ◽  
The North ◽  
Late Tertiary ◽  
Exploration Drilling ◽  
Hydrocarbon Charge

The Oobagooma Sub-basin of the Roebuck Basin includes the offshore extension of the onshore Fitzroy Trough of the Canning Basin. Together with the Leveque Platform, it covers an area of approximately 50,000 km2, yet only 14 exploration wells have been drilled in the area to date, five of which were drilled in the past 30 years. The sub-basin contains sediments ranging in age from Ordovician to Recent. This study examines the petroleum prospectivity of a region that is one of the least explored on Australia’s North West Shelf. Recent exploration drilling has revived interest in the area, with the 2014 Phoenix South–1 oil discovery in the offshore Bedout Sub-basin and the 2015 Ungani Far West–1 oil discovery in the onshore Fitzroy Trough. The two most significant source rock sequences relevant to the Oobagooma Sub-basin are the Carboniferous Laurel Formation and the Jurassic section. The former interval is part of a proven petroleum system onshore and is the source of the gas discovered at Yulleroo and oil at Ungani and Ungani Far West. A thick Jurassic trough to the north of the Oobagooma Sub-basin is believed to be the source of the oil and gas in Arquebus–1A and gas in Psepotus–1. Hydrocarbon charge modelling indicates significant expulsion occurred during both the Cretaceous and Tertiary from both source intervals. Trap timing is generally favourable given that inversion structures formed in several episodes during the Late Jurassic to Late Tertiary. The Early Triassic, now proven to be oil prone in the Phoenix South area (Molyneux et al, 2015), provides an additional (albeit less likely) source for the Oobagooma Sub-basin. These rocks are thin to absent within the Oobagooma Sub-basin, so long-distance migration would be required from deep troughs to the west.

Airborne electromagnetic bathymetry and estimation of bedrock topography in Broken Bay, Australia

Geophysics ◽  
2012 ◽  
Vol 77 (4) ◽  
pp. WB3-WB17 ◽  
Author(s):  
Julian Vrbancich
Keyword(s):  
Water Depth ◽  
Seismic Data ◽  
Sea Water ◽  
Unconsolidated Sediments ◽  
Sediment Thickness ◽  
Bedrock Topography ◽  
Transient Electromagnetic ◽  
Airborne Electromagnetic ◽  
Marine Seismic ◽  
Water Depths

A helicopter transient electromagnetic (TEM) survey was flown over shallow coastal waters in Broken Bay, Australia, overlying several palaeovalleys and exposed reef sections. The infilled palaeovalleys contain unconsolidated sediments with variable thicknesses exceeding 100 m. Previous marine seismic reflection and vibrocore studies provide an estimate of sediment thickness and surficial sediment conductivity, respectively, which, combined with known bathymetry (sonar soundings) and measured seawater conductivity, can be used to generate a crude 1D geoelectric ground-truth model consisting of two layers (seawater/sediment) overlying a relatively resistive basement. The primary focus was to examine the accuracy of interpreted water depths obtained by 1D inversion of airborne TEM data, assuming a two-layer over resistive basement model, by comparing these depths with known water depths. The secondary focus was to compare the interpreted sediment thickness (i.e., the thickness of the second geoelectric layer, which combined with bathymetry, gives the bedrock depth) with thicknesses estimated from marine seismic data to test the potential of using airborne electromagnetic systems for remote sensing of the coarse features of the bedrock topography. Interpreted water depths obtained from TEM data resulted in absolute water depth accuracies of 1–2 m for depths between 10 and 30 m, and 0.3–0.5 m in water shallower than [Formula: see text]. More importantly, similar water depth accuracies were obtained using raw TEM data (with birdswing removal) and TEM data obtained by postprocessing using time-consuming empirical corrections based on the TEM half-space response over deep sea water. The interpreted sediment depths derived from TEM and marine seismic data showed good agreement, generally, for example, inversion of TEM data delineated a distinct palaeovalley that transects a beach, with a maximum depth of 60–70 m below the seafloor, in agreement with depths estimated from marine seismic data to within [Formula: see text].

THE EYRE SUB-BASIN: RECENT EXPLORATION RESULTS

1981 ◽  
Vol 21 (1) ◽  
pp. 91 ◽  
Author(s):  
J. Bein ◽  
M. L. Taylor
Keyword(s):  
Seismic Data ◽  
Sedimentary Cover ◽  
Sediment Thickness ◽  
The South ◽  
The North ◽  
Fault Block ◽  
Basement Fault ◽  
Basement Ridge ◽  
Sedimentary Fill ◽  
Great Australian Bight

The Eyre Sub-basin of the Great Australian Bight Basin comprises a series of half-grabens with a maximum sediment thickness in the order of 6 000 m. It is bounded to the north by high-standing basement with a sedimentary cover about 550 m thick. To the west, sedimentary cover gradually thins and onlaps rising basement. To the south, a high- standing basement ridge separates the sediments within the Eyre Sub-basin from those of the Great Australian Bight Basin proper. The sedimentary pile apparently thickens south of the basement ridge where water depth increases to more than 1 400 m.The high basement trend bounding the sub-basin to the south plunges gradually to the east where it is eventually broken up by faulting. Seismic data from the eastern end of the sub-basin show progressive down-faulting of basement and increasing sediment thickness to the south.Jerboa 1 was drilled on a tilted basement fault block. It penetrated 1 739 m of sedimentary section, which is believed to be a condensed sequence representative of most of the total sedimentary fill of the sub-basin. Middle to Late Jurassic (Callovian-Kimmeridgian) sediments were encountered above basement, and the sequence continued almost unbroken into the Late Cretaceous (Cenomanian). Minor unconformities occur between the non-marine Aptian sequence and the overlying marine Albian, and between the Albian and Cenomanian. A major unconformity separates the Cenomanian from the overlying Tertiary section, interpreted to have been deposited after the separation of Australia from Antarctica.

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