HYDROCARBON POTENTIAL OF THE ARCKARINGA REGION, CENTRAL SOUTH AUSTRALIA

1982 ◽  
Vol 22 (1) ◽  
pp. 237 ◽  
Author(s):  
P. S. Moore
Keyword(s):  
Source Rock ◽  
South Australia ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
Large Area ◽  
Entire Area ◽  
Central Platform ◽  
Active Exploration ◽  
Central South ◽  
Eromanga Basin

The Arckaringa region is a large area which lies between the Officer Basin and the Peake and Denison Ranges in central South Australia. It includes sedimentary rocks of Jurassic-Cretaceous, Permo-Carboniferous and ?Cambrian ages. The thickest sequence of sediments (about 2000m) occurs in the Boorthanna Trough, located immediately to the west of the Peake and Denison Ranges. Cretaceous sediments of the Eromanga Basin form a veneer over much of the area. Oil shows at very shallow depths in immature sediments at Oodnadatta 1 raise speculations about the possibility of shallow generation of hydrocarbons in the Eromanga Basin. However, most of the petroleum exploration in the region has been aimed at delineating the underlying Permo-Carboniferous Arckaringa Basin sequence. The Arckaringa Basin is not a simple sedimentary depression but rather a series of peripheral depressions surrounding a central platform region. Unlike the Cooper and Pedirka Basins, it contains some marine sediment, suggesting the possibility of an oil-prone rather than a predominantly gas-prone province. Due to the thin nature of the sequence and its shallow depth of burial, most of the Arckaringa Basin is predicted to be immature for hydrocarbon generation in traditional terms. However, source-rock and vitrinite studies in the Boorthanna Trough indicate that the basal units are marginally mature to mature in this area. Early Cambrian carbonates are interpreted to extend southeastwards in an arc from Byilkaoora 1 in the Officer Basin, through the Boorthanna Trough, and onto the Stuart Shelf. In the Boorthanna Trough these carbonates are named the Cootanoorina Formation. They are of varied lithology and are associated with terrigenous clastics and minor evaporites. Vugular porosity occurs sporadically in the sequence, which may be thicker than 1000m in some of the deeper parts of the trough. Source-rock studies suggest that the sequence is immature to marginally mature in Weedina 1 and Cootanoorina 1.It is emphasised that the Arckaringa region is largely unexplored for hydrocarbons, with only two wells drilled on structural targets in the entire area of about 60 000 sq km. This report presents source-rock and maturation data which suggest that the sequence is more mature than originally predicted, and that the deeper parts of the Boorthanna Trough may have a modest potential for oil, both in the basal Permo-Carboniferous and in the ?Cambrian Cootanoorina Formation. An active exploration programme has begun, with several hundred kilometres of seismic surveys planned for 1982.

The transformation effect of source rock-derived acidic fluid on carbonate reservoir from simulation experiments

2020 ◽  
Author(s):  
Qian Ding ◽  
Zhiliang He ◽  
Dongya Zhu
Keyword(s):  
Physical Properties ◽  
Source Rock ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
High Quality ◽  
Simulation Experiments ◽  
Deep Layers

<p>Deep and ultra-deep carbonate reservoir is an important area of petroleum exploration. However, the prerequisite for predicting high quality deep ultra-deep carbonate reservoirs lays on the mechanism of carbonate dissolution/precipitation. It is optimal to perform hydrocarbon generation-dissolution simulation experiments to clarify if burial dissolution could improve the physical properties of carbonate reservoirs, while quantitatively and qualitatively describe the co-evolution process of source rock and carbonate reservoirs in deep layers. In this study, a series of experiments were conducted with the limestone from the Ordovician Yingshan Formation in the Tarim Basin, and the low maturity source rock from Yunnan Luquan, with a self-designed hydrocarbon generation-dissolution simulation equipment. The controlling factors accounted for the alteration of carbonate reservoirs and dissolution modification process by hydrocarbon cracking fluid under deep burial environments were investigated by petrographic and geochemical analytical methods. In the meantime, the transformation mechanism of surrounding rocks in carbonate reservoirs during hydrocarbon generation process of source rock was explored. The results showed that: in the burial stage, organic acid, CO<sub>2</sub> and other acidic fluids associated with thermal evolution of deep source rocks could dissolve carbonate reservoirs, expand pore space, and improve porosity. Dissolution would decrease with the increasing burial depth. Whether the fluid could improve reservoir physical properties largely depends on calcium carbonate saturation, fluid velocity, water/rock ratio, original pore structure etc. This study could further contribute to the prediction of high-quality carbonate reservoirs in deep and ultra-deep layers.</p>

A HYDROCARBON GENERATION MODEL FOR THE COOPER AND EROMANGA BASINS

2003 ◽  
Vol 43 (1) ◽  
pp. 433 ◽  
Author(s):  
I. Deighton ◽  
J.J. Draper ◽  
A.J. Hill ◽  
C.J. Boreham
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Generation Model ◽  
Hydrocarbon Generation ◽  
Control Points ◽  
Seismic Structure ◽  
Dynamic Topography ◽  
Late Tertiary ◽  
Petroleum Generation ◽  
Eromanga Basin

The aim of the National Geoscience Mapping Accord Cooper-Eromanga Basins Project was to develop a quantitative petroleum generation model for the Cooper and Eromanga Basins by delineating basin fill, thermal history and generation potential of key stratigraphic intervals. Bio- and lithostratigraphic frameworks were developed that were uniform across state boundaries. Similarly cross-border seismic horizon maps were prepared for the C horizon (top Cadna-owie Formation), P horizon (top Patchawarra Formation) and Z horizon (base Eromanga/Cooper Basins). Derivative maps, such as isopach maps, were prepared from the seismic horizon maps.Burial geohistory plots were constructed using standard decompaction techniques, a fluctuating sea level and palaeo-waterdepths. Using terrestrial compaction and a palaeo-elevation for the Winton Formation, tectonic subsidence during the Winton Formation deposition and erosion is the same as the background Eromanga Basin trend—this differs significantly from previous studies which attributed apparently rapid deposition of the Winton Formation to basement subsidence. A dynamic topography model explains many of the features of basin history during the Cretaceous. Palaeo-temperature modelling showed a high heatflow peak from 90–85 Ma. The origin of this peak is unknown. There is also a peak over the last two–five million years.Expulsion maps were prepared for the source rock units studied. In preparing these maps the following assumptions were made:expulsion is proportional to maturity and source rock richness;maturity is proportional to peak temperature; andpeak temperature is proportional to palaeo-heatflow and palaeo-burial.The geohistory modelling involved 111 control points. The major expulsion is in the mid-Cretaceous with minor amounts in the late Tertiary. Maturity maps were prepared by draping seismic structure over maturity values at control points. Draping of maturity maps over expulsion values at the control points was used to produce expulsion maps. Hydrocarbon generation was calculated using a composite kerogen kinetic model. Volumes generated are theoretically large, up to 120 BBL m2 of kitchen area at Tirrawarra North. Maps were prepared for the Patchawarra and Toolachee Formations in the Cooper Basin and the Birkhead and Poolowanna Formations in the Eromanga Basins. In addition, maps were prepared for Tertiary expulsion. The Permian units represent the dominant source as Jurassic source rocks have only generated in the deepest parts of the Eromanga Basin.

Maturity Evolution of the Cambrian Source Rocks in the Tarim Basin

2012 ◽  
Vol 622-623 ◽  
pp. 1642-1645
Author(s):  
Zong Lin Xiao ◽  
Qing Qing Hao ◽  
Zhong Min Shen
Keyword(s):  
Source Rock ◽  
Tarim Basin ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Mature Stage ◽  
Hydrocarbon Generation ◽  
Foreland Basins ◽  
Structural History ◽  
Depositional Age ◽  
Petroleum Basin

The Tarim basin is an important petroleum basin in China, and the Cambrian strata are the major source rock successions in the basin. Integrated the source rock depositional and structural history with its geochemical and thermal parameters, this paper simulates the evolution of the Cambrian source rocks with the software Basinview. The simulation result shows that the main hydrocarbon-generation centers of the Manjiaer sag in the Tabei depression and the Tangguzibasi sag in the Southwest depression are characterized by their early hydrocarbon generation, and in the late Ordovician depositional age, they reached dry gas stage. The Kuqa and Southwest depressions developed in the Cenozoic foreland basins made the Cambrian source rocks mature rapidly in the Cenozoic period. The source rock maturity in the Tarim basin now is characterized by high in the east and west and low in the middle, and most of the area is in the over-mature stage in the present. This study can provide available maturity data for the next petroleum exploration work.

THE EROMANGA BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 379
Author(s):  
H.R.B. Wecker
Keyword(s):  
Middle Triassic ◽  
Significant Proportion ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Structural Deformation ◽  
Tectonic Activity ◽  
Hydrocarbon Generation ◽  
Basin Region ◽  
Migration Pathways ◽  
Eromanga Basin

The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.

Mapping geology beneath volcanics using magnetic data

2018 ◽  
Vol 58 (2) ◽  
pp. 821
Author(s):  
Irena Kivior ◽  
Stephen Markham ◽  
Leslie Mellon ◽  
David Boyd
Keyword(s):  
South Australia ◽  
Sedimentary Basins ◽  
Seismic Signal ◽  
Petroleum Exploration ◽  
Seismic Survey ◽  
Source Distribution ◽  
Magnetic Data ◽  
Large Area ◽  
Magnetic Susceptibilities ◽  
Passive Seismic

Volcanic layers within sedimentary basins cause significant problems for petroleum exploration because the attenuation of the seismic signal masks the underlying geology. A test study was conducted for the South Australia Government to map the thickness of volcanics and sub-volcanic geology over a large area in the Gawler Range Volcanics province. The area is covered by good quality magnetic data. The thickness of volcanics and basement configuration was unknown as there has only been a limited amount of drilling. The Automatic Curve Matching (ACM) method was applied to located magnetic data and detected magnetic sources within different rock units, providing their depth, location, geometry and magnetic susceptibility. The magnetic susceptibilities detected by ACM allowed the differentiation of the volcanics and the underlying basement. The base of volcanics and the depth to the top of basement was mapped along 75 km NS profiles, that were spaced 1 km apart over a distance of 220 km. The volcanic and basement magnetic susceptibilities and the magnetic source distribution pattern were used as key determinants to interpret the depth to the two interfaces. The results for each interface were gridded, and images of the base of volcanics and depth to basement were generated. The mapped volcanics thickness was validated by comparison with the results from drilling, with the volcanics thickness matching very well. After project completion, a passive seismic survey was conducted in part of the test area, indicating a base of volcanics of ~4 km, which further confirmed the results.

Petroleum geological summary of the 2012 offshore acreage release for petroleum exploration

2012 ◽  
Vol 52 (1) ◽  
pp. 7 ◽  
Author(s):  
Thomas Bernecker
Keyword(s):  
South Australia ◽  
Data Availability ◽  
Petroleum Exploration ◽  
Free Access ◽  
Australian Government ◽  
Large Area ◽  
Offshore Area ◽  
North West ◽  
The North ◽  
Gippsland Basin

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2012, 27 areas in nine offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or twelve months after the release date, i.e. 8 November 2012 or 9 May 2013, depending on the exploration status in these areas and on data availability. As was the case in 2011, this year’s Release again covers a total offshore area of about 200,000 km2. The Release Areas are located in Commonwealth waters offshore Northern Territory, Western Australia, South Australia, Victoria and Tasmania (Fig. 1). Areas on the North West Shelf feature prominently again and include under-explored shallow water areas in the Arafura and Money Shoal basins and rank frontier deep water areas in the outer Browse and Roebuck basins as well as on the outer Exmouth Plateau. Following the recent uptake of exploration permits in the Bight Basin (Ceduna and Duntroon sub-basins), Australia’s southern margin is well represented in the 2012 Acreage Release. Three new areas in the Ceduna Sub-basin, four areas in the Otway Basin, one large area in the Sorell Basin and two areas in the eastern Gippsland Basin are on offer. Multiple industry nominations for this Acreage Release were received, confirming the healthy status of exploration activity in Australia. The Australian government continues to support these activities by providing free access to a wealth of geological and geophysical data.

scholarly journals Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2679
Author(s):  
Yuying Zhang ◽  
Shu Jiang ◽  
Zhiliang He ◽  
Yuchao Li ◽  
Dianshi Xiao ◽  
...  
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Content ◽  
Potential Zone ◽  
Hydrocarbon Generation ◽  
Gas Generation ◽  
Longmaxi Formation ◽  
Siliceous Shale ◽  
Organic Pores

In order to analyze the main factors controlling shale gas accumulation and to predict the potential zone for shale gas exploration, the heterogeneous characteristics of the source rock and reservoir of the Wufeng-Longmaxi Formation in Sichuan Basin were discussed in detail, based on the data of petrology, sedimentology, reservoir physical properties and gas content. On this basis, the effect of coupling between source rock and reservoir on shale gas generation and reservation has been analyzed. The Wufeng-Longmaxi Formation black shale in the Sichuan Basin has been divided into 5 types of lithofacies, i.e., carbonaceous siliceous shale, carbonaceous argillaceous shale, composite shale, silty shale, and argillaceous shale, and 4 types of sedimentary microfacies, i.e., carbonaceous siliceous deep shelf, carbonaceous argillaceous deep shelf, silty argillaceous shallow shelf, and argillaceous shallow shelf. The total organic carbon (TOC) content ranged from 0.5% to 6.0% (mean 2.54%), which gradually decreased vertically from the bottom to the top and was controlled by the oxygen content of the bottom water. Most of the organic matter was sapropel in a high-over thermal maturity. The shale reservoir of Wufeng-Longmaxi Formation was characterized by low porosity and low permeability. Pore types were mainly <10 nm organic pores, especially in the lower member of the Longmaxi Formation. The size of organic pores increased sharply in the upper member of the Longmaxi Formation. The volumes of methane adsorption were between 1.431 m3/t and 3.719 m3/t, and the total gas contents were between 0.44 m3/t and 5.19 m3/t, both of which gradually decreased from the bottom upwards. Shale with a high TOC content in the carbonaceous siliceous/argillaceous deep shelf is considered to have significant potential for hydrocarbon generation and storage capacity for gas preservation, providing favorable conditions of the source rock and reservoir for shale gas.

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