TECTONIC CONTROLS ON SEDIMENTATION AND MATURATION IN THE OFFSHORE NORTH PERTH BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 450 ◽  
Author(s):  
John F. Marshall ◽  
Chao- Shing Lee ◽  
Douglas C. Ramsay ◽  
Aidan M.G. Moore
Keyword(s):  
Seismic Reflection ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
The West ◽  
Australian Continent ◽  
Multichannel Seismic Reflection ◽  
Well Data ◽  
Coal Measures

The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data. This analysis reveals that three sub- basins, the Edel, Abrolhos and Houtman Sub- basins, have formed as a result of three distinct episodes of rifting within the offshore North Perth Basin during the Early Permian, Late Permian and Late Jurassic respectively. During this period, rifting has propagated from east to west, and has culminated in the separation of this part of the Australian continent from Greater India.The boundaries between the sub- basins and many structures within individual sub- basins are considered to have been produced by strike- slip or oblique- slip motion. The offshore North Perth Basin is believed to be a product of transtension, possibly since the earliest phase of rifting. This has culminated in separation and seafloor spreading by oblique extension along the Wallaby Fracture Zone to form a transform passive continental margin.This style of rifting and extension has produced relatively thin syn- rift sequences, some of which have been either partly or completely removed by erosion. While the source- rock potential of the syn- rift phase is limited, post- rift marine transgressional phases and coal measures do provide adequate and relatively widespread source rocks for hydrocarbon generation. Differences in the timing of rifting across the basin have resulted in a maturation pattern whereby mature sediments become younger to the west.

AN INTEGRATED GEOLOGICAL AND GEOPHYSICAL INTERPRETATION OF A PORTION OF THE OFFSHORE SYDNEY BASIN, NEW SOUTH WALES

2003 ◽  
Vol 43 (1) ◽  
pp. 495 ◽  
Author(s):  
P.A. Arditto
Keyword(s):  
New South ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Late Permian ◽  
Early Permian ◽  
South Wales ◽  
Permian Coal ◽  
Coal Measures ◽  
Reservoir Facies

The study area is within PEP 11, which is more than 200 km in length, covers an area over 8,200 km2 and lies immediately offshore of Sydney, Australia’s largest gas and petroleum market on the east coast of New South Wales. Permit water depths range from 40 m to 200 m. While the onshore Sydney Basin has received episodic interest in petroleum exploration drilling, no deep exploration wells have been drilled offshore.A reappraisal of available data indicates the presence of suitable oil- and wet gas-prone source rocks of the Late Permian coal measure succession and gas-prone source rocks of the middle to early Permian marine outer shelf mudstone successions within PEP 11. Reservoir quality is an issue within the onshore Permian succession and, while adequate reservoir quality exists in the lower Triassic succession, this interval is inferred to be absent over much of PEP 11. Quartz-rich arenites of the Late Permian basal Sydney Subgroup are inferred to be present in the western part of PEP 11 and these may form suitable reservoirs. Seismic mapping indicates the presence of suitable structures for hydrocarbon accumulation within the Permian succession of PEP 11, but evidence points to significant structuring post-dating peak hydrocarbon generation. Uplift and erosion of the order of 4 km (based on onshore vitrinite reflectance studies and offshore seismic truncation geometries) is inferred to have taken place over the NE portion of the study area within PEP 11. Published burial history modelling indicates hydrocarbon generation from the Late Permian coal measures commenced by or before the mid-Triassic and terminated during a mid-Cretaceous compressional uplift prior to the opening of the Tasman Sea.Structural plays identified in the western and southwestern portion of PEP 11 are well positioned to contain Late Permian clean, quartz-rich, fluvial to nearshore marine reservoir facies of the coal measures. These were sourced from the western Tasman Fold Belt. The reservoir facies are also well positioned to receive hydrocarbons expelled from adjacent coal and carbonaceous mudstone source rock facies, but must rely on early trap integrity or re-migrated hydrocarbons and, being relatively shallow, have a risk of biodegradation. Structural closures along the main offshore uplift appear to have been stripped of the Late Permian coal measure succession and must rely on mid-Permian to Early Permian petroleum systems for hydrocarbon generation and accumulation.

GEOLOGY, SOURCE ROCKS AND HYDROCARBON GENERATION IN THE CLARENCE-MORETON BASIN

1982 ◽  
Vol 22 (1) ◽  
pp. 5
Author(s):  
A. R. Martin ◽  
J. D. Saxby
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Tectonic Events ◽  
History Of ◽  
Rock Eval ◽  
Coal Measures ◽  
Migration Pathways

The geology and exploration history of the Triassic-Cretaceous Clarence-Moreton Basin are reviewed. Consideration of new geochemical data ('Rock-Eval', vitrinite reflectance, gas chromatography of extracts, organic carbon and elemental analysis of coals and kerogens) gives further insights into the hydrocarbon potential of the basin. Although organic-rich rocks are relatively abundant, most source rocks that have achieved the levels of maturation necessary for hydrocarbon generation are gas-prone. The exinite-rich oil-prone Walloon Coal Measures are in most parts relatively immature. Some restraints on migration pathways are evident and igneous and tectonic events may have disturbed potentially well-sealed traps. Further exploration is warranted, even though the basin appears gas-prone and the overall prospects for hydrocarbons are only fair. The most promising areas seem to be west of Toowoomba for oil and the Clarence Syncline for gas.

scholarly journals A reconstruction of Iberia accounting for W-Tethys/N-Atlantic kinematics since the late Permian-Triassic

2020 ◽  
Author(s):  
Paul Angrand ◽  
Frédéric Mouthereau ◽  
Emmanuel Masini ◽  
Riccardo Asti
Keyword(s):  
Plate Boundary ◽  
Strike Slip ◽  
Late Permian ◽  
Seismic Profiles ◽  
The West ◽  
Geological Evidence ◽  
The North ◽  
Kinematic Evolution ◽  
Well Data ◽  
Strike Slip Movement

Abstract. The West European kinematic evolution results from the opening of the West Neotethys and the Atlantic oceans since the late Paleozoic and the Mesozoic. Geological evidence shows that the Iberian domain well preserved the propagation of these two rift systems and is therefore key to significantly advance our understanding of the regional plate reconstructions. The Late Permian-Triassic tectonic evolution of Iberian rift basins shows that they have accommodated significant extension, but this tectonic stage is often neglected in most plate kinematic models, leading to the overestimation of the movements between Iberia and Europe during the subsequent Mesozoic (Early Cretaceous) rift phase. By compiling existing seismic profiles and geological constraints along the North Atlantic margins, including well data over Iberia, as well as recently published kinematic and paleogeographic reconstructions we propose a coherent kinematics model of Iberia that considers both the Neotethyan and Atlantic evolutions. Our model shows that the Europe-Iberia plate boundary was a domain of distributed and oblique extension made of two rift systems, in the Pyrenees and in the Iberian intra-continental basins. It differs from standard models that consider left-lateral strike-slip movement localized only in the northern Pyrenees in introducing a significant strike-slip movement south of Ebro accounting for Late Permian-Triassic extension and by emphasizing the need for an Ebro microcontinent. At a larger scale it emphasizes the role played by the late Permian-Triassic rift and magmatism, as well as strike-slip faulting in the evolution of the western Neotethyan Ocean and their control on localization of the Atlantic rift.

scholarly journals Inversion tectonics: a brief petroleum industry perspective

2020 ◽  
Author(s):  
Gábor Tari ◽  
Didier Arbouille ◽  
Zsolt Schléder ◽  
Tamás Tóth
Keyword(s):  
Petroleum Industry ◽  
Structural Complexity ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Data Sets ◽  
Hydrocarbon Generation ◽  
Seismic Reflection Data ◽  
Reflection Seismic ◽  
Reflection Data ◽  
Well Data

Abstract. The concept of structural inversion was introduced in the early 1980s. By definition, an inversion structure forms when a pre-existing extensional (or transtensional) fault controlling a hangingwall basin containing a syn-rift or passive fill sequence subsequently undergoes compression (or transpression) producing partial (or total) extrusion of the basin fill. Inverted structures provide traps for petroleum exploration, typically four-way structural closures. As to the degree of inversion, based on large number of worldwide examples seen in various basins, the most preferred petroleum exploration targets are mild to moderate inversional structures, defined by the location of the null-points. In these instances, the closures have a relatively small vertical amplitude, but simple in a map-view sense and well imaged on seismic reflection data. Also, the closures typically cluster above the extensional depocentres which tend to contain source rocks providing petroleum charge during and after the inversion. Cases for strong or total inversion are generally not that common and typically are not considered as ideal exploration prospects, mostly due to breaching and seismic imaging challenges associated with the trap(s) formed early on in the process of inversion. Also, migration may become tortuous due to the structural complexity or the source rock units may be uplifted above the hydrocarbon generation window effectively terminating the charge once the inversion occurred. For any particular structure the evidence for inversion is typically provided by subsurface data sets such as reflection seismic and well data. However, in many cases the deeper segments of the structure are either poorly imaged by the seismic data and/or have not been penetrated by exploration wells. In these cases the interpretation of any given structure in terms of inversion has to rely on the regional understanding of the basin evolution with evidence for an early phase of substantial crustal extension by normal faulting.

What we know (and what we don't) about the petroleum prospectivity of the Northland Basin, North Island, New Zealand

2009 ◽  
Vol 49 (1) ◽  
pp. 383 ◽  
Author(s):  
Chris Uruski
Keyword(s):  
New Zealand ◽  
Early Cretaceous ◽  
Late Cretaceous ◽  
Middle Jurassic ◽  
Source Rocks ◽  
The West ◽  
Eastern Margin ◽  
Gondwana Margin ◽  
Jurassic Coal ◽  
Coal Measures

The offshore Northland Basin is a major sedimentary accumulation lying to the west of the Northland Peninsula of New Zealand. It merges with the Taranaki Basin in the south and its deeper units are separated from Deepwater Taranaki by a buried extension of the West Norfolk Ridge. Sedimentary thicknesses increase to the northwest and the Northland Basin may extend into Reinga. Its total area is at least 65,000 km2 and if the Reinga Basin is included, it may be up to 100,000 km2. As in Taranaki, petroleum systems of the Northland Basin were thought to include Cretaceous to Recent sedimentary rocks. Waka Nui–1 was drilled in 1999 and penetrated no Cretaceous sediments, but instead drilled unmetamorphosed Middle Jurassic coal measures. Economic basement may be older meta-sediments of the Murihiku Supergroup. Thick successions onlap the dipping Jurassic unit and a representative Cretaceous succession is likely to be present in the basin. Potential source rocks known to be present include the Middle Jurassic coal measures of Waka Nui–1 and the Waipawa Formation black shale. Inferred source rocks include Late Jurassic coaly rocks of the Huriwai Beds, the Early Cretaceous Taniwha Formation coaly sediments, possible Late Cretaceous coaly units and lean but thick Late Cretaceous and Paleogene marine shales. Below the voluminous Miocene volcanoes of the Northland arc, the eastern margin of the basin is dominated by a sedimentary wedge that thickens to more than two seconds two-way travel time (TWT), or at least 3,000 m, at its eastern margin and appears to have been thrust to the southwest. This is interpreted to be a Mesozoic equivalent of the Taranaki Fault, a back-thrust to subduction along the Gondwana Margin. The ages of sedimentary units in the wedge are unknown but are thought to include a basal Jurassic succession, which dips generally to the east and is truncated by an erosional unconformity. A southwestwards-prograding succession overlies the unconformity and its top surface forms a paleoslope onlapped by sediments of Late Cretaceous to Neogene ages. The upper succession in the wedge may be of Early Cretaceous age—perhaps the equivalent of the Taniwha Formation or the basal succession in Waimamaku–2. The main part of the basin was rifted to form a series of horst and graben features. The age of initial rifting is poorly constrained, but the structural trend is northwest–southeast or parallel to the Early Cretaceous rifting of Deepwater Taranaki and with the Mesozoic Gondwana margin. Thick successions overlie source units which are likely to be buried deeply enough to expel oil and gas, and more than 70 slicks have been identified on satellite SAR data suggesting an active petroleum system. Numerous structural and stratigraphic traps are present and the potential of the Northland Basin is thought to be high.

PRE-EOCENE STRATIGRAPHY, STRUCTURE, AND PETROLEUM POTENTIAL OF THE BASS BASIN

1985 ◽  
Vol 25 (1) ◽  
pp. 362 ◽  
Author(s):  
P.E. Williamson ◽  
C.J. Pigram ◽  
J.B. Colwell ◽  
A.S. Scherl ◽  
K.L. Lockwood ◽  
...  
Keyword(s):  
Mineral Resources ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Seismic Survey ◽  
Normal Faults ◽  
Petroleum Potential ◽  
Northerly Direction ◽  
Potential Reservoir ◽  
Well Data ◽  
Coal Measures

Exploration in the Bass Basin has mainly concentrated on the Eocene part of the Eastern View Coal Measures with the pre-Eocene stratigraphy hardly being tested. Structural mapping using a good quality Bureau of Mineral Resources regional seismic survey and infill industry seismic data, in conjunction with seismic stratigraphy and well data, has generated an understanding of the structure and stratigraphy of the pre- Eocene basin, which suggests that exploration potential exists in structural and stratigraphic leads of both Paleocene and Cretaceous age.The Paleocene structure is influenced by the reactivation of normal faults developed at the time of the mid Cretaceous rift unconformity and reflects drape over deeper features. Consequently fault dependent structural closures often persist from Paleocene to (?)Jurassic levels. Possible stratigraphic traps are also observed against horst blocks and around the basin margins. The longitudinal fault directions are northwest and west northwest with an oblique northerly direction and a prevailing north northeasterly transverse direction.The Paieocene and Upper Cretaceous part of the Eastern View Coal Measures consists of sands, shales and coals deposited in alluvial fans, on flood plains, and in lakes. These are underlain by Early Cretaceous Otway Groups, sands, shales and volcanics. Both intervals have potential reservoir and source rocks and often occur at mature depths. No pre-Otway Group sediments have been encountered in wells in the Bass Basin. However, the Permo- Carboniferous and possibly Triassic strata that occur in Northern Tasmania exhibit reservoir and source rock potential and may extend offshore beneath the Bass Basin.Pre-Eocene structural and stratigraphic studies of the Bass Basin thus point to reservoir and hydrocarbon source potential for possible multiple hydrocarbon exploration targets.

scholarly journals Modeling Hydrocarbon Generation of Deeply Buried Type Ⅲ Kerogen: A Study on Gas and Oil Potential of Lishui Sag, East China Sea Shelf Basin

2021 ◽  
Vol 8 ◽  
Author(s):  
Jinliang Zhang ◽  
Yang Li ◽  
Jinshui Liu ◽  
Xue Yan ◽  
Lianjie Li ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Generation Model ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
The West ◽  
Organic Matter Sources ◽  
Type Iii

The hydrocarbon generation model and hydrocarbon potential are investigated in the Lishui Sag, based on gold-tube pyrolysis experiments of deeply buried type Ⅲ kerogen. From this, we discuss the classification of kerogen types of source rocks with mixed organic matter sources. The hydrocarbon generated from the source rocks of the Lingfeng Formation and Yueguifeng Formation is dominated by natural gases with little oil in the West subsag, and the hydrocarbon generation model of the Lingfeng Formation is similar to that of Yueguifeng Formation, but the gas potential of Lingfeng Formation is higher than that of Yueguifeng Formation. The hydrocarbon potential of the Yueguifeng Formation in the East subsag is much higher than the West subsag, and it has considerable oil potential. Macerals diversity of source rocks is responsible for the difference of hydrocarbon generation characteristics for type Ⅲ kerogen in the Lishui Sag. It is not rigorous to evaluate the hydrocarbon potential of kerogen only based on pyrolysis parameters. Application of kerogen type index (KTI) can improve the accuracy of the classification of kerogen types with mixed organic matter sources. According to the classical kerogen classification template, the selected samples belong to type III kerogen. In this article, the selected samples were further subdivided into type III and type II/III based on the KTI value. Type III kerogen (0.5 ≤ KTI < 1.5) mainly produces gas, and type II/III kerogen (1.5 ≤ KTI < 5) mainly produces gas, but its oil potential is higher than that of type III.

scholarly journals Burial history and the evolution of hydrocarbon generation in Carboniferous-Permian coal measures within the Jiyang super-depression, China

2021 ◽  
Vol 24 (4) ◽  
pp. 397-408
Author(s):  
Han Sijie ◽  
Sang Shuxun ◽  
Zhou Peiming ◽  
Jia Jinlong ◽  
Liang Jingjing
Keyword(s):  
Source Rocks ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Geographical Differences ◽  
Subsidence Rate ◽  
Multi Stage ◽  
Residual Thickness ◽  
Permian Coal ◽  
Coal Measures

In the Jiyang Sub-basin, Carboniferous-Permian (C-P) coal-measure source rocks have experienced complex multi-stage tectonics and therefore have a complex history of hydrocarbon generation. Because these coal measures underwent multi-stage burial and exhumation, they are characterized by various burial depths. In this study, we used the basin modeling technique to analyze the relationship between burial history and hydrocarbon generation evolution. The burial, thermal and maturity histories of C-P coals were reconstructed, including primary hydrocarbon generation, stagnation, re-initiation, and peak secondary hydrocarbon generation. The secondary hydrocarbon generation stage within this reconstruction was characterized by discontinuous generation and geographical differences in maturity due to the coupled effects of depth and a delay of hydrocarbon generation. According to the maturity history and the delay effect on secondary hydrocarbon generation, we concluded that the threshold depth of secondary hydrocarbon generation in the Jiyang Sub-basin occurred at 2,100 m during the Yanshan epoch (from 205 Ma to 65 Ma) and at 3,200 m during the Himalayan period (from 65 Ma to present). Based on depth, residual thickness, maturity, and hydrocarbon-generating intensity, five favorable areas of secondary hydrocarbon generation in the Jiyang Sub-basin were identified, including the Chexi areas, Gubei-Luojia areas, Yangxin areas, the southern slope of the Huimin depression and southwest of the Dongying depression. The maximum VRo/burial depth (%/km) occurred in the Indosinian epoch as the maximum VRo/time (%/100Ma) happened in the Himalayan period, indicating that the coupling controls of temperature and subsidence rate on maturation evolution play a significant role in the hydrocarbon generation evolution. A higher temperature and subsidence rate can both enhance the hydrocarbon generation evolution.  

scholarly journals Impacts of Neogene-Recent compressional deformation and uplift on hydrocarbon prospectivity of the passive southern Australian margin

2010 ◽  
Vol 50 (1) ◽  
pp. 267 ◽  
Author(s):  
Simon Holford ◽  
Richard Hillis ◽  
Ian Duddy ◽  
Paul Green ◽  
Adrian Tuitt ◽  
...  
Keyword(s):  
Vitrinite Reflectance ◽  
Critical Role ◽  
Plate Boundary ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Similar Data ◽  
Gas Field ◽  
Southern Margin ◽  
Australian Continent ◽  
Compressional Deformation

The passive southern margin of the Australian continent, which formed following Cretaceous–Palaeogene separation from Antarctica, contains a rich record of Neogene–Recent compressional deformation and uplift. This deformation and uplift is manifested by reversal of displacement along syn-rift extensional faults, folding of mid–late Cenozoic post-rift sediments, and regional unconformities that can be traced for distances of up to 1,500 km along the margin. Palaeothermal data from onshore and offshore exploration wells indicate that erosion associated with deformation and uplift locally exceeds 1 km in the eastern Otway Basin. Both neotectonic palaeostress trends inferred from these structures and present-day stress orientations are consistent with northwest–southeast directed compression controlled to first-order by plate boundary forces. The critical role of the relative timing of trap formation and source rock maturation in controlling hydrocarbon prospectivity in the southern Australian margin is investigated by comparing two structures that formed during Neogene–Recent deformation in the Otway Basin: the Minerva and Nerita anticlines. While the Minerva Anticline hosts a major gas field (558 BCF GIP), the Nerita Anticline was found to be dry. A combination of apatite fission track analysis (AFTA), vitrinite reflectance (VR) and present-day temperature data show that all units intersected in Minerva–1 are presently at their maximum post-depositional temperatures, and are presently mature for hydrocarbon generation. In contrast, similar data collected from the preserved section at Nerita–1 indicate cooling from maximum post-depositional temperatures prior to formation of the Nerita Anticline in the late Miocene. Based on regional AFTA data, the underlying early Cretaceous source rocks probably reached maximum palaeotemperatures and ceased hydrocarbon generation during mid-Cretaceous uplift. These results indicate that areas of the southern margin that were deformed during the Neogene–Recent have the greatest potential to trap hydrocarbons where potential source rocks are presently at their maximum post-depositional temperatures.

scholarly journals Modelling the hydrocarbon generation and migration in the West Netherlands Basin, the Netherlands

2000 ◽  
Vol 79 (1) ◽  
pp. 29-44 ◽  
Author(s):  
R.T. van Balen ◽  
F. van Bergen ◽  
C. de Leeuw ◽  
H. Pagnier ◽  
H. Simmelink ◽  
...  
Keyword(s):  
Lower Jurassic ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
The West ◽  
Hydrocarbon System ◽  
Coal Deposits ◽  
Geochemical Analyses ◽  
And Migration ◽  
Potential Traps

AbstractThe hydrocarbon systems of the Mesozoic, inverted West Netherlands Basin have been analyzed using 2-D forward modelling. Three source rocks are considered in the modelling: Lower Jurassic oil-prone shales, Westphalian gas-prone coal deposits, and Lower Namurian oil-prone shales. The Lower Namurian hydrocarbon system of the basin is discussed for the first time.According to the modelling results of the Early Jurassic oil system, the oil accumulations were filled just after the main inversion event. Their predicted locations are in agreement with exploration results. Modelling results of the Westphalian gas system, however, show smaller and larger sized accumulations at unexplored locations. The gas reservoirs were filled during the Late Jurassic-Early Cretaceous rifting phase. Results of modelling of the Lower Namurian oil system indicate that gas formed by secondary cracking of the oils can have mixed with the Westphalian coal-derived gas. Such a mixing is inferred from geochemical analyses. The existence of a Lower Namurian hydrocarbon system in the West Netherlands Basin implies that hydrocarbons are possibly trapped in the Westphalian and Namurian successions. These potential traps in the basin have not yet been explored.

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