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.

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.

New insights into the Hercynian Orogeny, and their implications for the Paleozoic Hydrocarbon System in the Arabian Plate

GeoArabia ◽  
2009 ◽  
Vol 14 (3) ◽  
pp. 199-228 ◽  
Author(s):  
Mohammad Faqira ◽  
Martin Rademakers ◽  
AbdulKader M. Afifi
Keyword(s):  
Oil And Gas ◽  
Seismic Imaging ◽  
Structural Features ◽  
Source Rocks ◽  
Arabian Plate ◽  
Arabian Shield ◽  
Tectonic Event ◽  
Angular Unconformity ◽  
The North ◽  
Hercynian Orogeny

ABSTRACT During the past decade, considerable improvements in the seismic imaging of the deeper Paleozoic section, along with data from new well penetrations, have significantly improved our understanding of the mid-Carboniferous deformational event. Because it occurred at the same time as the Hercynian Orogeny in Europe, North Africa and North America it has been commonly referred to by the same name in the Middle East. This was the main tectonic event during the late Paleozoic, which initiated or reactivated many of the N-trending block uplifts that underlie the major hydrocarbon accumulations in eastern Arabia. The nature of the Hercynian deformation away from these structural features was poorly understood due to inadequate seismic imaging and insufficient well control, along with the tectonic overprint of subsequent deformation events. Three Hercynian NE-trending arches are recognized in the Arabian Plate (1) the Levant Arch, which extended from Egypt to Turkey along the coast of the Mediterranean Sea, (2) the Al-Batin Arch, which extended from the Arabian Shield through Kuwait to Iran, and (3) the Oman-Hadhramaut Arch, which extended along the southeast coast of Oman and Yemen. These arches were initiated during the mid-Carboniferous Hercynian Orogeny, and persisted until they were covered unconformably by the Khuff Formation during the Late Permian. Two Hercynian basins separate these arches: the Nafud-Ma’aniya Basin in the north and Faydah-Jafurah Basin in the south. The pre-Hercynian Paleozoic section was extensively eroded over the arches, resulting in a major angular unconformity, but generally preserved within the basins. Our interpretation suggests that most of the Arabian Shield, except the western highlands along the Red Sea, is the exhumed part of the Al-Batin Arch. The Hercynian structural fabric of regional arches and basins continue in northern Africa, and in general appear to be oriented orthogonal to the old margin of the Gondwana continent. The Hercynian structure of arches and basins was partly obliterated by subsequent Mesozoic and Cenozoic tectonic events. In eastern Saudi Arabia, Qatar, and Kuwait, regional extension during the Triassic formed N-trending horsts and graben that cut across the NE-trending Hercynian mega-structures, which locally inverted them. Subsequent reactivation during the Cretaceous and Neogene resulted in additional growth of the N-trending structures. The Hercynian Arches had major impact on the Paleozoic hydrocarbon accumulations. The Silurian source rocks are generally preserved in the basins and eroded over the arches, which generally confined Silurian-sourced hydrocarbons either within the basins or along their flanks. Furthermore, the relict Hercynian paleo-topography generally confined the post-Hercynian continental clastics of the Unayzah Formation and equivalents to the Hercynian basins. These clastics contain the main Paleozoic oil and gas reservoirs, particularly along the basin margins where they overlie the sub-crop of the Silurian section with angular unconformity, thus juxtaposing reservoir and source rock.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

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.

SOUTHERN GEORGINA BASIN: A NEW PERSPECTIVE

1990 ◽  
Vol 30 (1) ◽  
pp. 137 ◽  
Author(s):  
W.R. Lodwick ◽  
J.F. Lindsay
Keyword(s):  
Mirror Image ◽  
Source Rocks ◽  
Carbonate Production ◽  
Northern Margin ◽  
Middle Ordovician ◽  
Upper Proterozoic ◽  
Clastic Sediments ◽  
Early Palaeozoic ◽  
New Perspective ◽  
Reservoir Potential

The Georgina Basin formed as a shallow intracratonic depression on the Australian craton along with a number of other basins in the Proterozoic and early Palaeozoic, probably in response to the break up of the Proterozoic supercontinent. Since all of these basins evolved under similar tectonic and sea-level controls, the basins all have similar sediment successions and, it might thus be assumed, similar petroleum prospectivity. One basin, the Amadeus Basin, currently has petroleum production, suggesting a potential for exploration success in the other intracratonic basins.In the Amadeus Basin the main petroleum prospects lie within or adjacent to major sub-basins that formed along the Basin's northern margin. The Georgina Basin has sub-basins that formed along its southern margin, almost as a mirror image of the Amadeus Basin. The lower Palaeozoic section of the Toko Syncline in the southern Georgina Basin has hydrocarbon shows in Middle Cambrian to Middle Ordovician rocks. Source rocks appear to have developed within the transgressive systems tract and the condensed interval of the highstand systems tract, at times when the basin was starved for clastic sediments and carbonate production was restricted.Seismic data acquired in the 1988 survey are of a higher quality than that previously obtained in the area. Its interpretation portrays the westward thrusting French Fault at the eastern edge of the Toko Syncline with potential hangingwall and footwall traps. Cambro- Ordovician Georgina Basin sediments subcrop the overlying Eromanga Basin with angularity, providing potentially large stratigraphic traps. Fracturing of the Cambrian and Ordovician carbonates within fault zones, and solution porosity at the unconformity, would also enhance reservoir potential in the area. Perhaps most significantly, the new data also shows an earlier, apparently independent basin completely buried beneath the Georgina section. The concealed section may simply be a very thick, early Upper Proterozoic section, or perhaps an equivalent to, or a lateral extension of the McArthur Basin. Recent work in the McArthur Basin has shown considerable source potential in the McArthur and Roper Groups, which may support the possibility of an additional, as yet unrecognised, source beneath the Georgina Basin.

Recent exploration results in the Lower Triassic, Bedout Sub-basin: Australia's next petroleum province?

2018 ◽  
Vol 58 (2) ◽  
pp. 871 ◽  
Author(s):  
Melissa Thompson ◽  
Fred Wehr ◽  
Jack Woodward ◽  
Jon Minken ◽  
Gino D'Orazio ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Lower Triassic ◽  
Effective Porosity ◽  
Petroleum System ◽  
Source Rocks ◽  
Commercial Development ◽  
North West ◽  
The North ◽  
Productive Potential ◽  
Detailed Interpretation

Commencing in 2014, Quadrant Energy and partners have undertaken an active exploration program in the Bedout Sub-basin with a 100% success rate, discovering four hydrocarbon accumulations with four wells. The primary exploration target in the basin, the Middle Triassic Lower Keraudren Formation, encompasses the reservoirs, source rocks and seals that have trapped hydrocarbons in a self-contained petroleum system. This petroleum system is older than the traditional plays on the North-West Shelf and before recent activity was very poorly understood and easily overlooked. Key reservoirs occur at burial depths of 3500–5500 m, deeper than many of the traditional plays on the North-West Shelf and exhibit variable reservoir quality. Oil and gas-condensate discovered in the first two wells, Phoenix South-1 and Roc-1, raised key questions on the preservation of effective porosity and productivity sufficient to support a commercial development. With the acquisition and detailed interpretation of 119 m of core over the Caley Member reservoir in Roc-2 and a successful drill stem test that was surface equipment constrained to 55 MMscf/d, the productive potential of this reservoir interval has been confirmed. The results of the exploration program to date, combined with acquisition of new 3D/2D seismic data, have enabled a deeper understanding of the potential of the Bedout Sub-basin. A detailed basin model has been developed and a large suite of prospects and leads are recognised across a family of hydrocarbon plays. Two key wells currently scheduled for 2018 (Phoenix South-3 and Dorado-1) will provide critical information about the scale of this opportunity.

A geochemical investigation into the resource potential of the Lawn Hill Platform, northern Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 722
Author(s):  
Amber J. M. Jarrett ◽  
Adam E. H. Bailey ◽  
Christopher J. Boreham ◽  
Tehani Palu ◽  
Lisa Hall ◽  
...  
Keyword(s):  
Organic Geochemistry ◽  
Source Rocks ◽  
Geochemical Data ◽  
Northern Australia ◽  
Hydraulic Stimulation ◽  
Petroleum Potential ◽  
North West ◽  
North Eastern ◽  
Resource Exploration ◽  
Geochemical Investigation

The Lawn Hill Platform (LHP) is a sedimentary province in north-eastern Northern Territory and north-western Queensland that hosts a significant Paleoproterozoic–Mesoproterozoic sequence, often referred to as 'the ‘Isa Superbasin’, and includes the overlying South Nicholson Group. Shale gas resources and base-metals mineralisation are known in north-west Queensland, but the larger basin is underexplored. The Australian Government’s Exploring for the Future (EFTF) 2016−2020 program aims to boost resource exploration in northern Australia. New precompetitive geochemical data obtained in this program includes source rock geochemistry, kerogen kinetics, bitumen reflectance, biomarker and δ13C n-alkanes for understanding the petroleum potential, organic geochemistry of source rocks and fluids, stratigraphic correlations and mineralogy to determine the brittleness of shales. All data and derived reports are accessible on the EFTF portal (www.eftf.ga.gov.au), providing a central location for informed decision making. The results in this study demonstrate fair to excellent source rocks in multiple supersequences that are brittle and favourable to hydraulic stimulation. A comparison to the greater McArthur Basin demonstrates, that although there are many similarities in bulk geochemistry, LHP mudstones are largely heterogeneous, reflecting local variations that may be inherited from variations in contributing biomass, microbial reworking, depositional environment, sediment input and paleoredox conditions.

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