Lower Paleozoic stratigraphy and petroleum potential of the Wallal Rift System, southwest Canning Basin, Western Australia

2014 ◽  
Vol 54 (2) ◽  
pp. 521
Author(s):  
Norman Alavi ◽  
Leon Bagas ◽  
Peter Purcell ◽  
Irena Kivior ◽  
John Brett
Keyword(s):  
Source Rocks ◽  
Granitic Rocks ◽  
Large Igneous Province ◽  
Rift System ◽  
Seismic Line ◽  
Lower Paleozoic ◽  
Petroleum Potential ◽  
Continental Flood Basalts ◽  
Canning Basin ◽  
The North

The Wallal Rift System (new name) extends north-northwest for more than 300 km along the southwestern margin of the Canning Basin. The rift contains the Wallal and the Waukarlycarly embayments and the Samphire Graben. The rift segments vary in depth to 4.5 km and are all under-explored. Seismic coverage is better in the north than in the south. Six shallow wildcat and stratigraphic wells in the north provide some control on the age of the pre-Permian section. Another well on the northeastern flank of the Samphire Graben terminated in Neoproterozoic granitic rocks beneath the Lower Ordovician Nambeet Formation. The well is tied to a seismic line that indicates a synrift Ordovician section in the graben. An equivalent section is inferred in the Wallal and the Waukarlycarly embayments, and Permian syn-rift sediments are recognised in all rifts. Transtension along a regional geosuture—the Camel-Tabletop Fault Zone—may have caused initial rifting during the waning of the Paterson Orogeny (c. 550 Ma), co-incident with extrusion in the Kalkarindji Large Igneous Province. Thus, Cambrian volcano-clastics deposits may be present at the base of the (2–3 km thick) pre-Permian section, which is considered to be primarily Early Paleozoic sediments and expected to contain potential source rocks. A relatively hot Proterozoic crust and eruption of continental flood basalts during the Cambrian may have facilitated source rock maturation. Reservoirs may be more common along rift-margins and intra-rift ridges, where fault-controlled traps are also present.

Central- and North-East Greenland Rifted Margin Composite Tectono-Sedimentary Element, From Onshore East Greenland to the Greenland Sea

2021 ◽  
pp. M57-2017-15
Author(s):  
Michael B. W. Fyhn ◽  
Peter Alsen ◽  
Morten Bjerager ◽  
Jørgen A. Bojesen-Koefoed ◽  
Flemming G. Christiansen ◽  
...  
Keyword(s):  
Depositional Environments ◽  
Source Rocks ◽  
Rift System ◽  
East Atlantic ◽  
Petroleum Potential ◽  
East Greenland ◽  
North East ◽  
The North ◽  
Marine Sedimentation ◽  
Uplift And Erosion

AbstractThe Devonian to lower Eocene Central-East and NE Greenland Composite Tectono-Sedimentary Element CTSE) is a part of the North-East Atlantic rift system. East and NE Greenland geology is therefore analogues to that of the prolific basins on the conjugate Atlantic margin and in the North Sea in many respects. None the less, hydrocarbon discoveries remain. The presence of world-class source rocks, reservoirs and seals, together with large structures, may suggest an East and NE Greenland petroleum potential, however. The TSE was established through Devonian - Carboniferous, Permian - Triassic and Jurassic - Cretaceous rifting interspersed by periods of uplift and post-rift sagging. Subsequently, Paleocene - Eocene magma-rich rifting accompanied the North-East Atlantic break-up. Depositional environments through time varied in response to the changing tectonism and climate. None-marine deposition dominated until the end of the Triassic, only interrupted by marine sedimentation during Late Permian - Early Triassic times. Subsequently, marine conditions prevailed during the Jurassic and Cretaceous. Volumetric series of basalt erupted over most of the CTSE during the latest Paleocene - early Eocene following a significant latest Cretaceous - Paleocene regression, uplift and erosion event. Since the Eocene, denudation pulses have removed much of these basalts uniquely exposing the up to 17 km strata of the CTSE.

scholarly journals A missing link in the peri-Gondwanan terrane collage: the Precambrian basement of the Moroccan Meseta and its lower Paleozoic cover

2018 ◽  
Vol 55 (1) ◽  
pp. 33-51 ◽  
Author(s):  
Dominik Letsch ◽  
Mohamed El Houicha ◽  
Albrecht von Quadt ◽  
Wilfried Winkler
Keyword(s):  
Carbonate Platform ◽  
Source Area ◽  
Source Rocks ◽  
Lower Paleozoic ◽  
Northern Margin ◽  
Precambrian Geology ◽  
The North ◽  
Late Cambrian ◽  
Paleozoic Rocks ◽  
Rifted Margin

This article provides stratigraphic and geochronological data from a central part of Gondwana’s northern margin — the Moroccan Meseta Domain. This region, located to the north of the Anti-Atlas area with extensive outcrops of Precambrian and lower Paleozoic rocks, has hitherto not received much attention with regard to its Precambrian geology. Detrital and volcanic zircon ages have been used to constrain sedimentary depositional ages and crustal affinities of sedimentary source rocks in stratigraphic key sections. Based on this, a four-step paleotectonic evolution of the Meseta Domain from the Ediacaran until the Early Ordovician is proposed. This evolution documents the transition from a terrestrial volcanic setting during the Ediacaran to a short-lived carbonate platform setting during the early Cambrian. The latter then evolved into a rifted margin with deposition of thick siliciclastic successions in graben structures during the middle to late Cambrian. The detritus in these basins was of local origin, and a contribution from a broader source area (encompassing parts of the West African Craton) can only be demonstrated for postrifting, i.e., laterally extensive sandstone bodies that seal the former graben. In a broader paleotectonic context, it is suggested that this Cambrian rifting is linked to the opening of the Rheic Ocean, and that several peri-Gondwanan terranes (Meguma and Cadomia–Iberia) may have been close to the Meseta Domain before drifting, albeit some of them seem to have been constituted by a distinctly different basement.

The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand

2008 ◽  
Vol 48 (1) ◽  
pp. 53 ◽  
Author(s):  
Chris Uruski ◽  
Callum Kennedy ◽  
Rupert Sutherland ◽  
Vaughan Stagpoole ◽  
Stuart Henrys
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
East Coast ◽  
Plate Boundary ◽  
Source Rocks ◽  
Fault System ◽  
Northern Coast ◽  
The South ◽  
Petroleum Potential ◽  
The North

The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary. The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.

scholarly journals Oligocene-Pleistocene Paleogeography within Banyumas Basin and implication to petroleum potential

2018 ◽  
Vol 1 ◽  
pp. 00006 ◽  
Author(s):  
Eko Bayu Purwasatriya ◽  
Sugeng Sapto Surjono ◽  
Donatus Hendra Amijaya
Keyword(s):  
Depositional Environment ◽  
Tectonic Setting ◽  
Volcanic Rocks ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Magmatic Arc ◽  
The North ◽  
Potential Source ◽  
Back Arc ◽  
Exploration Activity

<p>This study attempts to reconstruct paleogeography of Banyumas Basin in association with magmatic arc evolution and its implication to petroleum potential. Based on the volcanic rocks distribution, their association and relatives age, there are three alignments of a magmatic arc, that are: (1) Oligo-Miocene arc in the south (2) Mio-Pliocene arc in the middle (3) Plio-Pleistocene arc in the north. The consequences of the magmatic arc movement were tectonic setting changing during Oligocene to Pleistocene, as well as their paleogeography. During Oligo-Miocene where magmatic arc existed in the southern part, the Banyumas tectonic setting was a back-arc basin. This tectonic setting was changing to intra-arc basin during Mio-Pliocene and subsequently to fore-arc basin since Plio-Pleistocene until today. Back-arc basin is the most suitable paleogeography to create a depositional environment for potential source rocks. Exploration activity to prove the existence of source rocks during Oligo-Miocene is needed to reveal petroleum potential in Banyumas Basin.<br></p>

scholarly journals Petroleum Potential of the Deep Ordovician- Lower Devonian Oil and Gas Complex in the South-East of the Timan-Pechora Petroleum Province

2021 ◽  
Vol 20 (3) ◽  
pp. 274-283
Author(s):  
E.A. Kuznetsovа ◽  
Keyword(s):  
Lower Devonian ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
The South ◽  
Reservoir Properties ◽  
Lower Paleozoic ◽  
Petroleum Potential ◽  
Middle Paleozoic ◽  
Gas Potential

The article is devoted to the assessment of the oil and gas potential of the deep Ordovician-Lower Devonian oil and gas complex in the south-east of the Timan-Pechora oil and gas province. Within the Upper Pechora Basin of the Pre-Ural trough and in the south of the Pechora-Kolva aulacogen, several wells were drilled with a depth of more than 5 km, some of which entered the Lower Paleozoic deposits. These strata are difficult to access and poorly studied, and the prospects for their oil and gas potential are unclear. The article describes the composition of the complex, gives geochemical characteristics, describes reservoir properties, and presents the results of 1D and 2D basin modeling. Models of the zoning of catagenesis are presented. The oil and gas complex includes a variety of oil and gas source rocks. It is possible to allocate collectors, as well as the seals. In the Lower Paleozoic sediments, the processes of oil, gas and gas condensate generation took place, which could ensure the formation of deposits both in the deep strata of the Lower and Middle Paleozoic, and in the overlying horizons. The generation and accumulation of hydrocarbons in deep-buried sediments occurred at a favorable time for the formation of deposits. However, it is considered that the scale of hydrocarbon generation for the Lower Paleozoic deposits is not high.

The role of deep seismic reflection data in understanding the architecture and petroleum potential of Australia's onshore sedimentary basins

2010 ◽  
Vol 50 (2) ◽  
pp. 726 ◽  
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Leonie Jones ◽  
Josef Holzschuh
Keyword(s):  
Seismic Reflection ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Petroleum Potential ◽  
Deep Seismic Reflection ◽  
Reflection Data ◽  
Stratigraphic Sequences

The onshore energy security program, funded by the Australian Government and conducted by Geoscience Australia, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Detailed interpretation of deep seismic reflection profiles from four onshore basins, focussing on overall basin geometry and internal sequence stratigraphy, will be presented here, with the aim of assessing the petroleum potential of the basins. At the southern end of the exposed part of the Mt Isa Province, northwest Queensland, a deep seismic line (06GA–M6) crosses the Burke River structural zone of the Georgina Basin. The basin here is >50 km wide, with a half graben geometry, and bounded in the west by a rift border fault. Given the overall architecture, this basin will be of interest for petroleum exploration. The Millungera Basin in northwest Queensland is completely covered by the thin Eromanga Basin and was unknown prior to being detected on two seismic lines (06GA–M4 and 06GA–M5) acquired in 2006. Following this, seismic line 07GA–IG1 imaged a 65 km wide section of the basin. The geometry of internal stratigraphic sequences and a post-depositional thrust margin indicate that the original succession was much thicker than preserved today and may have potential for a petroleum system. The Yathong Trough, in the southeast part of the Darling Basin in NSW, has been imaged in seismic line 08GA–RS2 and interpreted in detail using sequence stratigraphic principles, with several sequences being mapped. Previous studies indicate that the upper part of this basin consists of Devonian sedimentary rocks, with potential source rocks at depth. In eastern South Australia, seismic line 08GA–A1 crossed the Cambrian Arrowie Basin, which is underlain by a Neoproterozoic succession of the Adelaide Rift System. Stratigraphic sequences have been mapped and can be tied to recent drilling for mineral and geothermal exploration. Shallow drill holes from past petroleum exploration have aided the assessment of the petroleum potential of the Cambrian Hawker Group, which contains bitumen in the core, indicating the presence of source rocks in the basin system.

The Carribuddy Group and Worral Formation, Canning Basin, Western Australia: reassessment of stratigraphy and petroleum potential

2010 ◽  
Vol 50 (1) ◽  
pp. 425 ◽  
Author(s):  
Peter Haines
Keyword(s):  
Middle Devonian ◽  
Late Ordovician ◽  
Source Rocks ◽  
Local Source ◽  
Petroleum Potential ◽  
Canning Basin ◽  
Petroleum Wells ◽  
Reservoir Potential ◽  
Drill Holes ◽  
Reservoir Facies

Reassessment of stratigraphic relationships and biostratigraphic data pertaining to the Carribuddy Group and Worral Formation in all relevant petroleum wells and many mineral drill holes across the southern Canning Basin has led to the following important results. The Carribuddy Group is restricted to the Late Ordovician to earliest Silurian. The overlying Worral Formation is mostly of Silurian age and does not intertongue with the Middle Devonian Tandalgoo Formation, as previously thought. A thin basin-wide chronostratigraphic marker—the Pegasus Dolomite Member (previously referred to as dolomite spike or dolomite marker) of the Sahara Formation—allows improved correlation between salt-bearing sub-basins and adjacent condensed Carribuddy Group successions. The Mallowa Salt is not as extensive as previously thought; rather the Minjoo Salt thickens to become the only salt seal in the eastern and southern Kidson Sub-basin. The Carribuddy Group forms the regional seal to the prospective Larapintine 2 petroleum system, but also contains local source and reservoir facies. The Bongabinni Formation contains extremely rich oil-prone source rocks in local lagoonal facies along the Admiral Bay Fault Zone; these rocks have been linked by other studies to migrated oil in that area. The distribution of the source facies is poorly known, but it may extend down-dip into more mature parts of the Willara Sub-basin, and west into offshore areas. Other local source units may be present in the Mallowa Salt, and possibly the Nibil Formation, but are not well documented. Aeolian sandstone with excellent reservoir potential is locally present in the Nibil Formation, but is more extensive in the lower Worral Formation, particularly the Elsa Sandstone Member.

THE GEOLOGY AND PETROLEUM POTENTIAL OF THE WESTERN ARAFURA SEA

1990 ◽  
Vol 30 (1) ◽  
pp. 91 ◽  
Author(s):  
Jeanette M. McLennan ◽  
John S. Rasidi ◽  
Richard L. Holmes ◽  
Greg C. Smith
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Northern Margin ◽  
The North ◽  
Australian Plate ◽  
North Eastern ◽  
Arafura Sea ◽  
Good Potential ◽  
Reservoir Potential

The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill.A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc.In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement.The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks.The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.

Structural and stratigraphic architecture of Australia's frontier onshore sedimentary basins: the Arckaringa, Officer, Amadeus, and Georgina basins

2011 ◽  
Vol 51 (2) ◽  
pp. 703
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Wolfgang Preiss ◽  
Sandra Menpes ◽  
Josef Holzschuh ◽  
...  
Keyword(s):  
Sedimentary Basins ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Petroleum Potential ◽  
Northern Margin ◽  
The North ◽  
Reflection Data ◽  
Southern Margin ◽  
Seismic Lines

The Onshore Energy Security Program—funded by the Australian Government and conducted by Geoscience Australia—has acquired deep seismic reflection data in conjunction with state and territory geological surveys, across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Here, we present data from two seismic lines collected in SA and NT. Seismic line 08GA-OM1 crossed the Arckaringa and Officer basins in SA and the southern-most Amadeus Basin in NT. Seismic line 09GA-GA1 crossed the northeastern part of the Amadeus Basin and the complete width of the southern Georgina Basin in NT. Structural and sequence stratigraphic interpretations of the seismic lines will be presented here, followed by an assessment of the petroleum potential of the basins. Seismic line 08GA-OM1 also crosses the Neoproterozoic to Devonian eastern Officer Basin. The basin is structurally complex in this area, being dominated by south-directed thrust faults and fault-related folds—providing potential for underthrust petroleum plays. The northern margin of the basin is overthrust to the south by the Mesoproterozoic Musgrave Province. To the north, the Moorilyanna Trough of the Officer Basin is a major depocentre of up to 7,000 m deep. Both seismic lines cross parts of the eastern Amadeus Basin. Seismic line 08GA-OM1 shows that the southern margin of the basin is overthrust to the north by the Musgrave Province with the main movement during the Petermann Orogeny. In the northeast, seismic line 09GA-GA1 crosses two parts of the basin separated by the Paleoproteroozic to Mesoproterozoic Casey Inlier (part of the Arunta Region). The northern margin of the basin is imaged seismically as a southward-verging, thinned-skinned thrust belt, showing considerable structural thickening of the stratigraphic succession. Seismic line 09GA-GA1 was positioned to cross that part of the southern Georgina Basin that was considered previously to be in the oil window. Here, the basin has a complex southern margin, with Neoproterozoic stratigraphy being thrust interleaved with basement rocks of the Arunta Region. The main part of the basin, containing a Neoproterozoic to Devonian succession, is asymmetric, thinning to the north where it overlies the Paleoproterozoic Davenport Province. The well, Phillip–2, drilled adjacent to the seismic line, intersected basement at a depth of 1,489 m, and has been used to map the stratigraphic sequences across the basin.

Northern Houtman Sub-basin prospectivity—preliminary results

2016 ◽  
Vol 56 (2) ◽  
pp. 577
Author(s):  
Irina Borissova ◽  
Chris Southby ◽  
George Bernardel ◽  
Jennifer Totterdell ◽  
Robbie Morris ◽  
...  
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Large Igneous Province ◽  
The North ◽  
Structural Style ◽  
Igneous Province ◽  
Line Spacing ◽  
History Of

In 2014–15 Geoscience Australia acquired 3,300 km of deep 2D seismic data over the northern part of the Houtman Sub-basin (Perth Basin). Prior to this survey, this area had a very sparse coverage of 2D seismic data with 50–70 km line spacing in the north and an industry grid with 20 km line spacing in the south. Initial interpretation of the available data has shown that the structural style, major sequences, and potential source rocks in this area are similar to those in the southern Houtman and Abrolhos sub-basins. The major difference between these depocentres, however, is in the volume and distribution of volcanic and intrusive igneous rocks. The northern part of the Houtman Sub-basin is adjacent to the Wallaby Plateau Large Igneous Province (LIP). The Wallaby Plateau and the Wallaby Saddle, which borders the western flank of the Houtman Sub-basin, had active volcanism from the Valanginian to at least the end of the Barremian. Volcanic successions significantly reduce the quality of seismic imaging at depth, making it difficult to ascertain the underlying thickness, geometry and structure of the sedimentary basin. The new 2D seismic dataset across the northern Houtman Sub-basin provides an opportunity for improved mapping of the structure and stratigraphy of the pre-breakup succession, assessment of petroleum prospectivity, and examination of the role of volcanism in the thermal history of this frontier basin.

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