MESOZOIC EVOLUTION OF THE GREATER TARANAKI BASIN AND IMPLICATIONS FOR PETROLEUM PROSPECTIVITY

2004 ◽  
Vol 44 (1) ◽  
pp. 385 ◽  
Author(s):  
C. Uruski ◽  
P. Baillie
Keyword(s):  
New Zealand ◽  
New Caledonia ◽  
Petroleum System ◽  
Source Rocks ◽  
Coal Measure ◽  
Low Grade ◽  
Volcanic Arc ◽  
Petroleum Systems ◽  
Basement Rocks ◽  
Jurassic Coal

A paradigm of New Zealand petroleum geology was that the oldest source rocks known in the region were of Cretaceous age, so any older sedimentary rocks were considered to be economic basement. Two major projects have revealed that this is not universally the case and that a Jurassic petroleum system should now be considered.Firstly, the Astrolabe 2D speculative survey, acquired by TGS-NOPEC in 2001, has revealed that a significant section underlies the traditional Cretaceous petroleum systems. Secondly, the Wakanui–1 well, drilled by Conoco, Inpex and Todd in 1999, which has recently become open-file, penetrated a Mid-Jurassic coal measure sequence.Jurassic rocks, including coal measure units, are known onshore in New Zealand, They are part of the Murihiku Supergroup, one of the basement terranes comprising the Permian to Cretaceous volcanic arc that forms the basement rocks of the present New Zealand landmass. Wherever they have been seen in outcrop, these rocks generally record low grade metamorphism and have been discounted as petroleum source rocks. Where rocks of the same age were deposited distal to the volcanic arc (and the effects of heat and pressure), however, they may form components of an effective petroleum system.The New Caledonia Basin, extending more than 2,000 km from Taranaki to New Caledonia, may have been the site of a Mesozoic back-arc basin. Jurassic coal measure successions and their equivalent marine units may be locally, or regionally important as source rocks. Implications of a Jurassic petroleum system for prospectivity of the region are investigated.

Research for the Upstream Petroleum Sector: The Crown Research Institute Concept

1995 ◽  
Vol 13 (2-3) ◽  
pp. 245-252
Author(s):  
J M Beggs
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Publicly Funded ◽  
Petroleum Systems ◽  
Oil And Gas Resources ◽  
Petroleum Sector ◽  
Geological Sciences ◽  
Research Institute

New Zealand's scientific institutions have been restructured so as to be more responsive to the needs of the economy. Exploration for and development of oil and gas resources depend heavily on the geological sciences. In New Zealand, these activities are favoured by a comprehensive, open-file database of the results of previous work, and by a historically publicly funded, in-depth knowledge base of the extensive sedimentary basins. This expertise is now only partially funded by government research contracts, and increasingly undertakes contract work in a range of scientific services to the upstream petroleum sector, both in New Zealand and overseas. By aligning government-funded research programmes with the industry's knowledge needs, there is maximum advantage in improving the understanding of the occurrence of oil and gas resources. A Crown Research Institute can serve as an interface between advances in fundamental geological sciences, and the practical needs of the industry. Current publicly funded programmes of the Institute of Geological and Nuclear Sciences include a series of regional basin studies, nearing completion; and multi-disciplinary team studies related to the various elements of the petroleum systems of New Zealand: source rocks and their maturation, migration and entrapment as a function of basin structure and tectonics, and the distribution and configuration of reservoir systems.

scholarly journals Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

2018 ◽  
Vol 36 (4) ◽  
pp. 801-819 ◽  
Author(s):  
Shuangfeng Zhao ◽  
Wen Chen ◽  
Zhenhong Wang ◽  
Ting Li ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Natural Gas ◽  
Tarim Basin ◽  
Oil And Gas ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Measure ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Isotopic Analyses ◽  
Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

2016 ◽  
Vol 8 (1) ◽  
pp. 187-197 ◽  
Author(s):  
Iain C. Scotchman ◽  
Anthony G. Doré ◽  
Anthony M. Spencer
Keyword(s):  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Gas Field ◽  
Petroleum Systems ◽  
Unknown Source ◽  
Porcupine Basin ◽  
Break Up ◽  
Northern North Sea ◽  
The Uk

AbstractThe exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×109 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×109 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

LAND-PLANT SOURCE ROCKS FOR OIL AND THEIR SIGNIFICANCE IN AUSTRALIAN BASINS

1982 ◽  
Vol 22 (1) ◽  
pp. 164 ◽  
Author(s):  
B. M. Thomas
Keyword(s):  
Depositional Environment ◽  
Land Plant ◽  
Source Rocks ◽  
Coal Measure ◽  
Terrestrial Plants ◽  
Geological Time ◽  
Close Relationship ◽  
Jurassic Coal ◽  
Paraffin Waxes ◽  
Gippsland Basin

Many Australian oils are rich in paraffin waxes which are derived from the remains of terrestrial plants. Although the land-plant contribution to oils, particularly those found in a paralic or deltaic environment, is well established, opinion is divided on the ability of non-marine coaly sediments to generate and expel commercial quantities of oil. It appears that some coal measure sequences have generated mainly gas whilst others are the source of large oil accumulations. The composition of coals deposited in Australia has varied through geological time as a result of differences in climate, geological setting, depositional environment and stage of floral evolution. Consequently, most Australian pre-Jurassic coal measure sequences are deficient in exinite macerals and are therefore mainly gas-prone. In contrast, Jurassic to Tertiary coal-rich sequences often contain abundant exinite and may have substantial potential to generate oil in commercial quantities, as demonstrated by the well-known Gippsland Basin (Bass Strait) oilfields.A similar trend is observed worldwide, where, despite the extraordinary global abundance of Late Palaeozoic coals, only minor amounts of crude oil of land-plant origin are known to be associated with them. However, there appears to be a close relationship between the occurrence of waxy, land-plant-derived crudes and coaly sediments of Cretaceous and Tertiary age. This is thought to be a result of the dominance of conifers in swamp floras of these periods, together with the evolution of the angiosperms (flowering plants) in the Late Cretaceous.

Seeing through the dolerite-seismic imaging of petroleum systems, Tasmania, Australia

2015 ◽  
Vol 55 (1) ◽  
pp. 297
Author(s):  
Malcolm Bendall ◽  
Clive Burrett ◽  
Paul Heath ◽  
Andrew Stacey ◽  
Enzo Zappaterra
Keyword(s):  
Seismic Energy ◽  
Petroleum System ◽  
Source Rocks ◽  
Contact Metamorphism ◽  
Seismic Surveys ◽  
Reservoir Rocks ◽  
Petroleum Systems ◽  
Potential Reservoir ◽  
Frequency Sweeps ◽  
The Many

Prior to the onshore work of Empire Energy Corporation International (Empire) it was widely believed that the widespread sheets (>650 m thick) of Jurassic dolerite (diabase) would not only have destroyed the many potential petroleum source and reservoir rocks in the basin but would also absorb seismic energy and would be impossible to drill. By using innovative acquisition parameters, however, major and minor structures and formations can be identified on the 1,149 km of 2D Vibroseis. Four Vibroseis trucks were used with a frequency range of 6–140 Hz with full frequency sweeps close together, thereby achieving maximum input and return signal. Potential reservoir and source rocks may be seismically mapped within the Gondwanan Petroleum System (GPS) of the Carboniferous to Triassic Parmeener Supergroup in the Tasmania Basin. Evidence for a working GPS is from a seep of migrated, Tasmanite-sourced, heavy crude oil in fractured dolerite and an oil-bearing breached reservoir in Permian siliciclastics. Empire’s wells show that each dolerite sheet consists of several intrusive units and that contact metamorphism is usually restricted to within 70 m of the sheets’ lower margins. In places, there are two thick sheets, as on Bruny Island. One near-continuous 6,500 km2 sheet is mapped seismically across central Tasmania and is expected, along with widespread Permian mudstones, to have acted as an excellent regional seal. The highly irregular pre-Parmeener unconformity can be mapped across Tasmania and large anticlines (Bellevue and Thunderbolt prospects and Derwent Bridge Anticline) and probable reefs can be seismically mapped beneath this unconformity within the Ordovician Larapintine Petroleum System. Two independent calculations of mean undiscovered potential (or prospective) resources in structures defined so far by Empire’s seismic surveys are 596.9 MMBOE (millions of barrels of oil equivalent) and 668.8 MMBOE.

scholarly journals Last Cretaceous Geology of Taranaki Basin, New Zealand

2021 ◽  
Author(s):  
◽  
Glenn Paul Thrasher
Keyword(s):  
New Zealand ◽  
Late Cretaceous ◽  
Coastal Plain ◽  
New Caledonia ◽  
Strike Slip ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Petroleum Reservoir ◽  
The North ◽  
Potential Source Rock

<p>Taranaki Basin is a large sedimentary basin located along the western side of New Zealand, which contains all of this countries present petroleum production. The basin first formed as the late-Cretaceous Taranaki Rift, and the first widespread sediments are syn-rift deposits associated with this continental rifting. The Taranaki Rift was an obliquely extensional zone which transferred the movement associated with the opening of the New Caledonia Basin southward to the synchronous Tasman Sea oceanic spreading. Along the rift a series of small, en-echelon basins opened, controlled by high-angle normal and strike-slip faults. These small basins presently underlie the much larger Taranaki Basin. Since the initial rift phase, Taranaki Basin has undergone a complex Cenozoic history of subsidence, compression, additional rifting, and minor strike-slip faulting, all usually involving reactivation of the late-Cretaceous rift-controlling faults. One of the late-Cretaceous rift basins is the Pakawau Basin. Rocks deposited in this basin outcrop in Northwest Nelson as the Pakawau Group. Data from the outcrop and from wells drilled in the basin allow the Pakawau Group to be divided into two formations, the Rakopi Formation and the North Cape Formation, each with recognizable members. The Rakopi Formation (new name) is a sequence of terrestrial strata deposited by fans and meandering streams in an enclosed basin. The North Cape Formation is a transgressive sequence of marine, paralic and coastal-plain strata deposited in response to regional flooding of the rift. The coal-measure strata of the Rakopi Formation are organic rich, and are potential petroleum source rocks where buried deeply enough. In contrast, the marine portions of the North Cape Formation contain almost no organic matter and cannot be considered a potential source rock. Sandy facies within both formations have petroleum reservoir potential. The Rakopi and North Cape formations can be correlated with strata intersected by petroleum exploration wells throughout Taranaki Basin, and all syn-rift sediments can be assigned to them. The Taranaki Rift was initiated about 80 Ma, as recorded by the oldest sediments in the Rakopi Formation. The transgression recorded in the North Cape Formation propagated southwards from about 72 to 70 Ma, and the Taranaki Rift remained a large marine embayment until the end of the Cretaceous about 66.5 Ma. Shortly thereafter, a Paleocene regression caused the southern portions of Taranaki Basin to revert to terrestrial (Kapuni Group) sedimentation. The two distinct late Cretaceous sedimentary sequences of the Rakopi and North Cape formations can be identified on seismic reflection data, and the basal trangressive surface that separates them has been mapped throughout the basin. This horizon essentially marks the end of sedimentation in confined, terrestrial subbasins, and the beginning of Taranaki Basin as a single, continental-margin-related basin. Isopach maps show the Rakopi Formation to be up to 3000m thick and confined to fault- controlled basins. The North Cape Formation is up to 1500m thick and was deposited in a large north-south embayment, open to the New Caledonia basin to the northwest. This embayment was predominantly a shallow-marine feature, with shoreline and lower coastal plain facies deposited around its perimeter</p>

scholarly journals Stratigraphic development and petroleum prospectivity of northern Zealandia

2021 ◽  
Author(s):  
◽  
Zelia Dos Santos
Keyword(s):  
New Zealand ◽  
Papua New Guinea ◽  
Source Rock ◽  
New Caledonia ◽  
New Guinea ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Seismic Unit ◽  
Eastern Australia ◽  
Basin Floor

<p>Northern Zealandia lies between Australia, New Zealandia, and New Caledonia. It has an area of 3,000,000 km2 and is made up of bathymetric rises and troughs with typical water depths of 1000 to 4000 m. I use 39,309 line km of seismic-reflection profiles tied to recent International Ocean Discovery Program (IODP) drilling and three boreholes near the coast of New Zealand to investigate stratigraphic architecture and assess the petroleum prospectivity of northern Zealandia.  Sparse sampling requires that stratigraphic and petroleum prospectivity inferences are drawn from better-known basins in New Zealand, Australia, New Caledonia, TimorLeste and Papua New Guinea. Five existing seismic-stratigraphic units are reviewed. Zealandia Seismic Unit U3 is sampled near New Zealand and may contain Jurassic Muhiriku Group coals. Elsewhere, Seismic Unit 3 may have oil-prone equivalents of the Jurassic Walloon Coal Measure in eastern Australia; or may contain Triassic-Jurassic marine source rocks, as found in offshore Bonaparte Basin, onshore Timor-Leste, and the Papuan Basin in Papua New Guinea. Seismic Unit U2b (Mid-Cretaceous) is syn-rift and may contain coal measures, as found in Taranaki-Aotea Basin and New Caledonia. Seismic Unit U2a (Late Cretaceous to Eocene) contains coaly source rocks in the southeastern part of the study area, and may also contain marine equivalent carbonaceous mudstone, as found at Site IODP U1509. Unit U2a is transgressive, with coaly source rocks and reservoir sandstones near its base, and clay, marl and chalk above that provides a regional seal. Seismic Unit U1b (Eocene-Oligocene) is mass-transport complexes and basin floor fans related to a brief phase of convergent deformation that created folds in the southern part of the study area and regionally uplifted ridges to create new sediment source areas. Basin floor fans may contain reservoir rock and Eocene folding created structural traps. Seismic Unit U1a is Oligocene and Neogene chalk, calcareous ooze, and marl that represents overburden. Mass accumulation rates (MAR) and climatic temperatures were high in the late Miocene and early Pliocene, resulting in peak thermal maturity and hydrocarbon expulsion at ~ 3 Ma.  Approximately one-fifth of the region has adequate source rock maturity for petroleum expulsion at the base of Seismic Unit U2: Fairway Basin (FWAY), southern New Caledonia Trough (NCTS) and Reinga Basin (REIN). Plays may exist in either Seismic Unit U3 or U2, with many plausible reservoir-seal combinations, and several possible trapping mechanisms: unconformities, normal faults, folds, or stratigraphic pinch-out. The rest of the region could be prospective, but requires a source rock to exist within Seismic Unit U3, which is mostly unsampled and remains poorly understood.</p>

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.

Stratigraphic development and petroleum prospectivity of northern Zealandia

2021 ◽  
Author(s):  
◽  
Zelia Dos Santos
Keyword(s):  
New Zealand ◽  
Papua New Guinea ◽  
Source Rock ◽  
New Caledonia ◽  
New Guinea ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Seismic Unit ◽  
Eastern Australia ◽  
Basin Floor

<p>Northern Zealandia lies between Australia, New Zealandia, and New Caledonia. It has an area of 3,000,000 km2 and is made up of bathymetric rises and troughs with typical water depths of 1000 to 4000 m. I use 39,309 line km of seismic-reflection profiles tied to recent International Ocean Discovery Program (IODP) drilling and three boreholes near the coast of New Zealand to investigate stratigraphic architecture and assess the petroleum prospectivity of northern Zealandia.  Sparse sampling requires that stratigraphic and petroleum prospectivity inferences are drawn from better-known basins in New Zealand, Australia, New Caledonia, TimorLeste and Papua New Guinea. Five existing seismic-stratigraphic units are reviewed. Zealandia Seismic Unit U3 is sampled near New Zealand and may contain Jurassic Muhiriku Group coals. Elsewhere, Seismic Unit 3 may have oil-prone equivalents of the Jurassic Walloon Coal Measure in eastern Australia; or may contain Triassic-Jurassic marine source rocks, as found in offshore Bonaparte Basin, onshore Timor-Leste, and the Papuan Basin in Papua New Guinea. Seismic Unit U2b (Mid-Cretaceous) is syn-rift and may contain coal measures, as found in Taranaki-Aotea Basin and New Caledonia. Seismic Unit U2a (Late Cretaceous to Eocene) contains coaly source rocks in the southeastern part of the study area, and may also contain marine equivalent carbonaceous mudstone, as found at Site IODP U1509. Unit U2a is transgressive, with coaly source rocks and reservoir sandstones near its base, and clay, marl and chalk above that provides a regional seal. Seismic Unit U1b (Eocene-Oligocene) is mass-transport complexes and basin floor fans related to a brief phase of convergent deformation that created folds in the southern part of the study area and regionally uplifted ridges to create new sediment source areas. Basin floor fans may contain reservoir rock and Eocene folding created structural traps. Seismic Unit U1a is Oligocene and Neogene chalk, calcareous ooze, and marl that represents overburden. Mass accumulation rates (MAR) and climatic temperatures were high in the late Miocene and early Pliocene, resulting in peak thermal maturity and hydrocarbon expulsion at ~ 3 Ma.  Approximately one-fifth of the region has adequate source rock maturity for petroleum expulsion at the base of Seismic Unit U2: Fairway Basin (FWAY), southern New Caledonia Trough (NCTS) and Reinga Basin (REIN). Plays may exist in either Seismic Unit U3 or U2, with many plausible reservoir-seal combinations, and several possible trapping mechanisms: unconformities, normal faults, folds, or stratigraphic pinch-out. The rest of the region could be prospective, but requires a source rock to exist within Seismic Unit U3, which is mostly unsampled and remains poorly understood.</p>

A reassessment of the petroleum systems in the offshore northern Perth Basin

2013 ◽  
Vol 53 (2) ◽  
pp. 427
Author(s):  
Emmanuelle Grosjean ◽  
Chris Boreham ◽  
Andrew Jones ◽  
Diane Jorgensen ◽  
John Kennard
Keyword(s):  
Primary Source ◽  
Petroleum System ◽  
Source Rocks ◽  
Early Triassic ◽  
Widespread Occurrence ◽  
Petroleum Systems ◽  
Oil Generation ◽  
History Of ◽  
Effective Source ◽  
Commercial Oil

The discovery of commercial oil in the Cliff Head-1 well in 2001 set an important milestone in the exploration history of the offshore northern Perth Basin. The region had been less explored before then, partly due to the perception that the main source of onshore petroleum accumulations, the Late Permian-Early Triassic Hovea Member, had only marginal potential offshore. The typing of the Cliff Head oil to the Hovea Member provided evidence that the key onshore petroleum system extends offshore and has revitalised exploration with 13 new field wildcat wells drilled since 2002. A reassessment of the hydrocarbon generative potential in the offshore northern Perth Basin confirms the widespread occurrence of good to excellent oil-prone Hovea Member source rocks in the Beagle Ridge and Abrolhos Sub-basin. The Early Permian Irwin River Sequence and several Jurassic Sequences are also recognised as prime potential source rocks offshore, mostly for their gas-generative potential. The unique hydrocarbon assemblages exhibited by the Hovea Member extracts are shared by the oils recovered from Permian reservoirs in the offshore Cliff Head-3 and Dunsborough-1 wells, indicating the Hovea Member as the primary source charging these accumulations. Geochemical correlation of oil stains from Hadda-1 and as far north as Livet-1 provides evidence for a working Early Triassic petroleum system across much of the Abrolhos Sub-basin. In this area, the Hovea Member was shown to be both of limited quality and only marginally mature for oil generation, which suggests the occurrence of effective source kitchens in the adjacent Houtman Sub-basin.

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