THE EVOLUTION OF THE BERNIER RIDGE, SOUTHERN CARNARVON BASIN, WESTERN AUSTRALIA:IMPLICATIONS FOR PETROLEUM PROSPECTIVITY

2004 ◽  
Vol 44 (1) ◽  
pp. 241 ◽  
Author(s):  
A.M. Lockwood ◽  
C. D’Ercole
Keyword(s):  
Seismic Data ◽  
Large Scale ◽  
Sedimentary Basins ◽  
Early Carboniferous ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Large Igneous Province ◽  
Satellite Gravity ◽  
Tectonic Events ◽  
Carnarvon Basin

The basement topography of the Gascoyne Platform and adjoining areas in the Southern Carnarvon Basin was investigated using satellite gravity and seismic data, assisted by a depth to crystalline basement map derived from modelling the isostatic residual gravity anomaly. The resulting enhanced view of the basement topography reveals that the Gascoyne Platform extends further westward than previously indicated, and is bounded by a northerly trending ridge of shallow basement, named the Bernier Ridge.The Bernier Ridge is a product of rift-flank uplift prior to the Valanginian breakup of Gondwana, and lies east of a series of small Mesozoic syn-rift sedimentary basins. Extensive magmatic underplating of the continental margin associated with this event, and a large igneous province is inferred west of the ridge from potential field and seismic data. Significant tectonic events that contributed to the present form of the Bernier Ridge include the creation of the basement material during the Proterozoic assembly of Rodinia, large-scale faulting during the ?Cambrian, uplift and associated glaciation during the early Carboniferous, and rifting of Gondwana during the Late Jurassic. The depositional history and maturity of the Gascoyne Platform and Bernier Ridge show that these terrains have been structurally elevated since the mid-Carboniferous.No wells have been drilled on the Bernier Ridge. The main source rocks within the sedimentary basins west of the Bernier Ridge are probably Jurassic, similar to those in the better-known Abrolhos–Houtman and Exmouth Sub-basins, where they are mostly early mature to mature and within the oil window respectively. Within the Bernier Ridge area, prospective plays for petroleum exploration in the Jurassic succession include truncation at the breakup unconformity sealed by post-breakup shale, and tilted fault blocks sealed by intraformational shale. Plays in the post-breakup succession include stratigraphic traps and minor rollover structures.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

2011 ◽  
Vol 51 (2) ◽  
pp. 746
Author(s):  
Irina Borissova ◽  
Gabriel Nelson
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Magnetic Data ◽  
Long Distance ◽  
Potential Field Data ◽  
Petroleum Potential ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
Insight Into ◽  
Carnarvon Basin

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

New play type, southern Bonaparte Basin-Petrel Sub-basin—WA-442-P and NT/P81 exploration permits

2012 ◽  
Vol 52 (1) ◽  
pp. 525
Author(s):  
Margaret Hildick-Pytte
Keyword(s):  
Seismic Data ◽  
Early Carboniferous ◽  
Oil Fields ◽  
Source Rocks ◽  
Lower Carboniferous ◽  
Petroleum Systems ◽  
Seismic Data Acquisition ◽  
Early Palaeozoic ◽  
Hydrocarbon Charge ◽  
3D Seismic Data

Recent investigation, including mapping re-processed seismic data, suggests there is deeper hydrocarbon potential in the WA-442-P and NT/P81 exploration permits beneath the Early Carboniferous Tanmurra Formation horizon. Earlier interpretation of the area showed tilted fault blocks commonly thought of as economic basement in the vicinity of the Turtle and Barnett oil fields and extending to the northwest to connect with the Berkley Platform. The deep-gas play type is structural and is believed to be two nested three-way dip anticlines developed against a large bounding fault to the northeast, with axial trends northwest to southeast, and axial plane curving towards the northeast for the deeper structure. This play type is believed to be associated with structural compression and movement along the master fault with incremental re-activation most recently during the Cainozoic as recorded in overlying sediments. The Nova Structure and the deeper Super Nova structure have closures of about 450 and 550 km2, respectively. The sediments beneath the Nova horizon are believed to be of Devonian Frasnian-Famennian age but have not been drilled offshore in the Southern Bonaparte Basin (Petrel Sub-basin). Earlier work suggests that there are two petroleum systems present in the southern Bonaparte Basin, a Larapintine source from Early Palaeozoic Devonian to Lower Carboniferous source rocks, and a transitional Larapintine/Gondwana system sourced from Lower Carboniferous to Permian source rocks. Hydrocarbon charge for the structures is most likely from the Larapintine source rock intervals or yet to be identified older intervals associated with the salt deposition during the Ordovician and Silurian. Independent estimates place close to 7 TCF (trillion cubic feet) of gas in the Nova Structure. New 3D seismic data acquisition is planned over the structures to better define the geology and ultimately delineate well locations.

scholarly journals Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea

2020 ◽  
Vol 38 (6) ◽  
pp. 2695-2710
Author(s):  
Yao-Ping Wang ◽  
Xin Zhan ◽  
Tao Luo ◽  
Yuan Gao ◽  
Jia Xia ◽  
...  
Keyword(s):  
Source Rock ◽  
Principal Component ◽  
Sedimentary Basins ◽  
Oil Field ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Crude Oils ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.

Voluminous crustal degassing and immiscible sulfide genesis caused by magma-shale interaction in Large Igneous Provinces

2020 ◽  
Author(s):  
Frances Deegan ◽  
Jean Bédard ◽  
Valentin Troll ◽  
Keith Dewing ◽  
Harri Geiger ◽  
...  
Keyword(s):  
Large Scale ◽  
Sedimentary Basins ◽  
High Arctic ◽  
Large Igneous Province ◽  
Carbonaceous Shale ◽  
Canadian High Arctic ◽  
Oceanic Anoxic Event ◽  
Igneous Provinces ◽  
Basin Scale ◽  
Sulfide Melt

<p><span>Large Igneous Province (LIP) activity is hypothesized to impact global volatile cycles causing climate changes and environmental crises deleterious to the biosphere. Recent work suggests that the potential of LIPs to impact climate is magnified where they intrude organic-rich (i.e. shale-bearing) sedimentary basins. However, the chemical and degassing dynamics of magma-shale interaction are not well understood. Here we present the first experimental simulations of disequilibrium interaction between LIP magma and carbonaceous shale during upper crustal sill intrusions in the Canadian High Arctic LIP (HALIP), the latter of which were co-eval with oceanic anoxic event 1a. Experiments show that magma-shale interaction results in intense syn-magmatic degassing and simultaneous precipitation of sulfide droplets at the ablation interface. Magma-shale interaction on a basin-scale can thus generate substantial amounts of climate-active H-C-S volatiles, while the presence of strongly reducing volatiles may also increase the likelihood of magma to segregate a sulfide melt. These findings have fundamental consequences for our understanding of both large-scale Earth outgassing and metal prospectivity in sediment-hosted LIPs.</span></p>

Differential diagenetic evolution and hydrocarbon charging of the tight limestone reservoir of the Da’anzhai Member in the central Sichuan Basin, China

2020 ◽  
Vol 8 (4) ◽  
pp. T1007-T1022
Author(s):  
Jiao Su ◽  
Zepu Tian ◽  
Yingchu Shen ◽  
Bo Liu ◽  
Qilu Xu ◽  
...  
Keyword(s):  
Sichuan Basin ◽  
Large Scale ◽  
Depositional Environments ◽  
Carbonate Reservoir ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Porosity Reduction ◽  
Hydrocarbon Charging ◽  
Pore Evolution ◽  
Central Sichuan Basin

The tight lacustrine carbonate reservoir of the Da’anzhai Member, Lower Jurassic Ziliujing Formation, in the central Sichuan Basin is a typical tight oil reservoir, and it is one of the crucial petroleum exploration targets in the Sichuan Basin. The porosity of the limestone ranges from 0.5% to 2%, and the permeability ranges from 0.001 to 1 mD. The Da’anzhai limestone experienced multiple diageneses, including compaction, cementation, dissolution, and recrystallization. Different diageneses occurred in the burial process due to the various fabrics and depositional environments, eventually forming distinct rock types; therefore, the pore evolution and hydrocarbon charging characteristics are inconsistent. In our research, there are two stages of major maturation and hydrocarbon expulsion in the source rocks of the Da’anzhai Member. The first large-scale expulsion of hydrocarbon is oil-based and gas-supplemented, whereas the second expulsion is dominated by gas. Hydrocarbon-filling characteristics are different in different types of reservoir rocks. Compared with the bioclastic grainstone and crystalline limestone, we have considered that the argillaceous shell packstone and bioclastic packstone deposited in the shallow and semideep lake environment still contain residual intergranular pores, which have not become fully compacted and are partly filled with hydrocarbons. The presence of hydrocarbon fluid hindered the secondary porosity reduction and was helpful for reserve space preservation.

Exploring New Zealand's marine territory

2011 ◽  
Vol 51 (1) ◽  
pp. 549 ◽  
Author(s):  
Chris Uruski
Keyword(s):  
New Zealand ◽  
Deep Water ◽  
Seismic Data ◽  
East Coast ◽  
Sedimentary Basins ◽  
Petroleum Exploration ◽  
Seismic Survey ◽  
Data Set ◽  
Eastern Australia ◽  
Deep Water Part

Around the end of the twentieth century, awareness grew that, in addition to the Taranaki Basin, other unexplored basins in New Zealand’s large exclusive economic zone (EEZ) and extended continental shelf (ECS) may contain petroleum. GNS Science initiated a program to assess the prospectivity of more than 1 million square kilometres of sedimentary basins in New Zealand’s marine territories. The first project in 2001 acquired, with TGS-NOPEC, a 6,200 km reconnaissance 2D seismic survey in deep-water Taranaki. This showed a large Late Cretaceous delta built out into a northwest-trending basin above a thick succession of older rocks. Many deltas around the world are petroleum provinces and the new data showed that the deep-water part of Taranaki Basin may also be prospective. Since the 2001 survey a further 9,000 km of infill 2D seismic data has been acquired and exploration continues. The New Zealand government recognised the potential of its frontier basins and, in 2005 Crown Minerals acquired a 2D survey in the East Coast Basin, North Island. This was followed by surveys in the Great South, Raukumara and Reinga basins. Petroleum Exploration Permits were awarded in most of these and licence rounds in the Northland/Reinga Basin closed recently. New data have since been acquired from the Pegasus, Great South and Canterbury basins. The New Zealand government, through Crown Minerals, funds all or part of a survey. GNS Science interprets the new data set and the data along with reports are packaged for free dissemination prior to a licensing round. The strategy has worked well, as indicated by the entry of ExxonMobil, OMV and Petrobras into New Zealand. Anadarko, another new entry, farmed into the previously licensed Canterbury and deep-water Taranaki basins. One of the main results of the surveys has been to show that geology and prospectivity of New Zealand’s frontier basins may be similar to eastern Australia, as older apparently unmetamophosed successions are preserved. By extrapolating from the results in the Taranaki Basin, ultimate prospectivity is likely to be a resource of some tens of billions of barrels of oil equivalent. New Zealand’s largely submerged continent may yield continent-sized resources.

THE PETROLEUM PROSPECTIVITY OF THE CLARENCE-MORETON BASIN IN NEW SOUTH WALES

1985 ◽  
Vol 25 (1) ◽  
pp. 15
Author(s):  
P. Ties ◽  
R.D. Shaw ◽  
G.C. Geary
Keyword(s):  
Source Rock ◽  
Seismic Data ◽  
New South ◽  
New South Wales ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
South Wales ◽  
Oil Generation ◽  
Single Fold ◽  
Coal Measures

The Clarence-Moreton Basin covers an area of some 28 000 km2 in north-eastern New South Wales and south-eastern Queensland. The basin is relatively unexplored, with a well density in New South Wales of one per 1600 km2. Since 1980, Endeavour Resources and its co-venturers have pursued an active exploration programme which has resulted in the recognition of significant petroleum potential in the New South Wales portion of the basin.Previous studies indicated that the Upper Triassic to Lower Cretaceous Clarence-Moreton Basin sequence in general, lacked suitable reservoirs and had poor source- rock potential. While exinite rich, oil-prone source rocks were recognised in the Middle Jurassic Walloon Coal Measures, they were considered immature for oil generation. Moreover, during the 1960's the basin acquired a reputation as an area where seismic records were of poor quality.These ideas are now challenged following the results of a new round of exploration which commenced in the New South Wales portion of the basin in 1980. This exploration has involved the acquisition of over 1000 km of multifold seismic data, the reprocessing of some 200 km of existing single fold data, and the drilling of one wildcat well. Over twenty large structural leads have been identified, involving trapping mechanisms ranging from simple drape to antithetic and synthetic fault blocks associated with normal and reverse fault dependent and independent closures.The primary exploration targets in the Clarence- Moreton Basin sequence are Lower Jurassic sediments comprising a thick, porous and permeable sandstone unit in the Bundamba Group, and channel and point-bar sands in the Marburg Formation. Source rocks in these and the underlying Triassic coal measures are gas-prone and lie at maturity levels compatible with gas generation. In contrast, it was established from the results of Shannon 1 that the Walloon Coal Measures are mature for oil generation and this maturity regime is now considered to be applicable to most of the basin in New South Wales.A consideration of reservoir and source rock distribution, together with structural trends across the basin in Petroleum Exploration Licences 258 and 259, has led to the identification of three prospective fairways, two of which involve shallow oil plays. Exploration of these fairways is currently the focus of an ongoing programme of further seismic data acquisition and drilling.

The Paleoproterozoic Kombolgie Subgroup (1.8 Ga), McArthur Basin, Australia: Sequence stratigraphy, basin evolution, and unconformity-related uranium deposits following the Great Oxidation Event

2021 ◽  
Vol 59 (5) ◽  
pp. 1049-1083
Author(s):  
Eric E. Hiatt ◽  
T. Kurtis Kyser ◽  
Paul A. Polito ◽  
Jim Marlatt ◽  
Peir Pufahl
Keyword(s):  
Large Scale ◽  
Sedimentary Basins ◽  
Uranium Mineralization ◽  
Coarse Grained ◽  
Uranium Deposits ◽  
Burial Diagenesis ◽  
Fine Grained ◽  
Braided Rivers ◽  
Tectonic Events ◽  
Regional Tectonic

ABSTRACT Proterozoic continental sedimentary basins contain a unique record of the evolving Earth in their sedimentology and stratigraphy and in the large-scale, redox-sensitive mineral deposits they host. The Paleoproterozoic (Stratherian) Kombolgie Basin, located on the Arnhem Land Plateau, Northern Territory, is an exceptionally well preserved, early part of the larger McArthur Basin in northern Australia. This intracratonic basin is filled with 1 to 2 km-thick, relatively undeformed, nearly flat-lying, siliciclastic rocks of the Kombolgie Subgroup. Numerous drill cores and outcrop exposures from across the basin allow sedimentary fabrics, structures, and stratigraphic relationships to be studied in great detail, providing an extensive stratigraphic framework and record of basin development and evolution. Tectonic events controlled the internal stratigraphic architecture of the basin and led to the formation of three unconformity-bounded sequences that are punctuated by volcanic events. The first sequence records the onset of basin formation and is comprised of coarse-grained sandstone and polymict lithic conglomerate deposited in proximal braided rivers that transported sediment away from basin margins and intra-basin paleohighs associated with major uranium mineralization. Paleo-currents in the upper half of this lower sequence, as well as those of overlying sequences, are directed southward and indicate that the major intra-basin topographic highs no longer existed. The middle sequence has a similar pattern of coarse-grained fluvial facies, followed by distal fluvial facies, and finally interbedded marine and eolian facies. An interval marked by mud-rich, fine-grained sandstones and mud-cracked siltstones representing tidal deposition tops this sequence. The uppermost sequence is dominated by distal fluvial and marine facies that contain halite casts, gypsum nodules, stromatolites, phosphate, and “glauconite” (a blue-green mica group mineral), indicating a marine transgression. The repeating pattern of stratigraphic sequences initiated by regional tectonic events produced well-defined coarse-grained diagenetic aquifers capped by intensely cemented distal fluvial, shoreface, eolian, and even volcanic units, and led to a well-defined heterogenous hydrostratigraphy. Basinal brines migrated within this hydrostratigraphy and, combined with paleotopography, dolerite intrusion, faulting, and intense burial diagenesis, led to the economically important uranium deposits the Kombolgie Basin hosts. Proterozoic sedimentary basins host many of Earth's largest high-grade iron and uranium deposits that formed in response to the initial oxygenation of the hydrosphere and atmosphere following the Great Oxygenation Event. Unconformity-related uranium mineralization like that found in the Kombolgie Basin highlights the interconnected role that oxygenation of the Earth, sedimentology, stratigraphy, and diagenesis played in creating these deposits.

Late Accumulation of Kunbei Area in Qaidam Basin

2013 ◽  
Vol 690-693 ◽  
pp. 3549-3552
Author(s):  
Hui Shi ◽  
Hui Li
Keyword(s):  
Seismic Data ◽  
Qaidam Basin ◽  
Scientific Evidence ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Tibet Plateau ◽  
Hydrocarbon Generation ◽  
Long Distance ◽  
Hydrocarbon Charging ◽  
The Tibet Plateau

This paper is aimed to find out the main reason of late accumulation of Kunbei area in Qaidam Basin using geochemistry and seismic data and to provide scientific evidence to the potential petroleum exploration in this area. Reservoirs in Kunbei fault terrace zone originate from petreoleum generated by source rocks of E32 in Zhahaquan depression after N23(about 5.2Ma), which means a charcteristic of hysteretic hydrocarbon generation. Brine inclusions shows two hydrocarbon charging periods.The first charging most likely happens at N1 and the second begins at N21,continuing to Q.Two deformaton stages exist in the study area due to the Tibet Plateau uplifting. The accumulations of first stage have been damaged after Middle N1. The reservoirs of Kunbei zone at present are almost orignated from E32 in depression. Above all,the primary cause of late accumulation is due to long-distance effects of the Tibet Plateau uplifting.

scholarly journals Tectonosedimentary framework of Upper Cretaceous –Neogene series in the Gulf of Tunis inferred from subsurface data: implications for petroleum exploration

2017 ◽  
Vol 68 (2) ◽  
pp. 97-108 ◽  
Author(s):  
Wissem Dhraief ◽  
Ferid Dhahri ◽  
Imen Chalwati ◽  
Noureddine Boukadi
Keyword(s):  
Seismic Data ◽  
Upper Cretaceous ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Tectonic Activity ◽  
Petroleum Systems ◽  
Subsurface Structures ◽  
Gulf Of Tunis ◽  
Northeastern Tunisia ◽  
Well Data

Abstract The objective and the main contribution of this issue are dedicated to using subsurface data to delineate a basin beneath the Gulf of Tunis and its neighbouring areas, and to investigate the potential of this area in terms of hydrocarbon resources. Available well data provided information about the subsurface geology beneath the Gulf of Tunis. 2D seismic data allowed delineation of the basin shape, strata geometries, and some potential promising subsurface structures in terms of hydrocarbon accumulation. Together with lithostratigraphic data obtained from drilled wells, seismic data permitted the construction of isochron and isobath maps of Upper Cretaceous-Neogene strata. Structural and lithostratigraphic interpretations indicate that the area is tectonically complex, and they highlight the tectonic control of strata deposition during the Cretaceous and Neogene. Tectonic activity related to the geodynamic evolution of the northern African margin appears to have been responsible for several thickness and facies variations, and to have played a significant role in the establishment and evolution of petroleum systems in northeastern Tunisia. As for petroleum systems in the basin, the Cretaceous series of the Bahloul, Mouelha and Fahdene formations are acknowledged to be the main source rocks. In addition, potential reservoirs (Fractured Abiod and Bou Dabbous carbonated formations) sealed by shaly and marly formations (Haria and Souar formations respectively) show favourable geometries of trap structures (anticlines, tilted blocks, unconformities, etc.) which make this area adequate for hydrocarbon accumulations.

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