Triassic paleogeography and petroleum systems of the North West Shelf, Australia: key insights from a new regional study

CGG Multi-Client & New Ventures, in collaboration with CGG Robertson, has undertaken a new comprehensive study of the Triassic paleogeography and petroleum systems of the North West Shelf (NWS) including the Northern Carnarvon, Roebuck, Browse and Bonaparte basins. The key objectives of the study were to enhance the understanding of the prospectivity of NWS Triassic petroleum systems, develop new paleogeography maps, establish evidence for Triassic marine-derived source rocks and investigate the prospectivity of Late Triassic carbonate reef complexes. The study comprises new biostratigraphic analyses, quantitative evaluation by scanning electron microscopy (QEMSCAN®) analyses, core logging, 1D and 2D modelling of key wells and seismic sections, plate reconstructed paleogeography and play mapping. Of key relevance to this study is the paleo-depositional framework and subsequent structuring of Triassic successions throughout the NWS basins in the context of petroleum system development.

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Observations on the Lower Triassic petroleum prospectivity of the offshore Carnarvon and Roebuck basins

The APPEA Journal ◽

10.1071/aj15014 ◽

2016 ◽

Vol 56 (1) ◽

pp. 173 ◽

Cited By ~ 3

Author(s):

Stephen Molyneux ◽

Jeff Goodall ◽

Roisin McGee ◽

George Mills ◽

Birgitta Hartung-Kagi

Keyword(s):

Regional Analysis ◽

Lower Triassic ◽

Source Rocks ◽

Upper Permian ◽

Regional Study ◽

North West ◽

Petroleum Systems ◽

The North ◽

Depositional Processes ◽

Water Margin

Why are the only commercial hydrocarbon discoveries in Lower Triassic and Permian sediments of the western margin of Australia restricted to the Perth Basin and the Petrel Sub-basin? Recent regional analysis by Carnarvon Petroleum has sought to address some key questions about the Lower Triassic Locker Shale and Upper Permian Chinty and Kennedy formations petroleum systems along the shallow water margin of the Carnarvon and offshore Canning (Roebuck/Bedout) basins. This paper aims to address the following questions:Source: Is there evidence in the wells drilled to date of a working petroleum system tied to the Locker Shale or other pre-Jurassic source rocks? Reservoir: What is the palaeogeography and sedimentology of the stratigraphic units and what are the implications for the petroleum systems?The authors believed that a fresh look at the Lower Triassic to Upper Permian petroleum prospectivity of the North West Shelf would be beneficial, and key observations arising from the regional study undertaken are highlighted:Few wells along a 2,000 km area have drilled into Lower Triassic Locker Shale or older stratigraphy. Several of these wells have been geochemically and isotopically typed to potentially non Jurassic source rocks. The basal Triassic Hovea Member of the Kockatea Shale in the Perth Basin is a proven commercial oil source rock and a Hovea Member Equivalent has been identified through palynology and a distinctive sapropelic/algal kerogen facies in nearly 16 wells that penetrate the full Lower Triassic interval on the North West Shelf. Samples from the Upper Permian, the Hovea Member Equivalent and the Locker Shale have been analysed isotopically indicating –28, –34 and –30 delta C13 averages, respectively. Lower Triassic and Upper Permian reservoirs are often high net to gross sands with up to 1,000 mD permeability and around 20% porosity. Depositional processes are varied, from Locker Shale submarine canyon systems to a mixed carbonate clastic marine coastline/shelf of the Upper Permian Chinty and Kennedy formations.

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Petroleum geology of the 2018 offshore acreage release areas

The APPEA Journal ◽

10.1071/aj17056 ◽

2018 ◽

Vol 58 (2) ◽

pp. 437

Author(s):

Thomas Bernecker ◽

George Bernardel ◽

Claire Orlov ◽

Nadège Rollet

Keyword(s):

Information Management System ◽

Source Rocks ◽

Petroleum Exploration ◽

Data Repository ◽

North West ◽

Work Program ◽

Petroleum Systems ◽

The North ◽

Well Data ◽

Offshore Petroleum

A total of 21 areas were released in 2018 for offshore petroleum exploration. They are located in the Bonaparte, Browse, Northern Carnarvon, Bight, Otway and Gippsland basins. All release areas were supported by industry nominations, indicating that interest in exploring Australia’s offshore basins remains strong, despite the significant decrease in the number of exploration wells drilled in recent years. Sixteen areas are being released under the work program bidding system with two rounds, one closing on 18 October 2018 and the other on 21 March 2019. Five areas are being released for cash bidding and include the producible La Bella gas accumulation in the Otway Basin. Prequalification for participation in the cash-bid auction closes on 4 October 2018 with the auction scheduled for 7 February 2019. Geoscience Australia continues to support industry activities by acquiring, interpreting and integrating pre-competitive datasets that are made freely available as part of the agency’s regional petroleum geological studies. The regional evaluation of the petroleum systems in the Browse Basin has been completed and work continues on assessing the distribution of Early Triassic source rocks and related petroleum occurrences across the North West Shelf. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, are made available through the National Offshore Petroleum Information Management System. Additional datasets are accessible through Geoscience Australia’s data repository.

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Hydrocarbon fluid inclusions in the Argo salt, offshore Canadian Atlantic margin

Canadian Journal of Earth Sciences ◽

10.1139/cjes-2012-0040 ◽

2013 ◽

Vol 50 (6) ◽

pp. 607-635 ◽

Cited By ~ 4

Author(s):

Yawooz A. Kettanah

Keyword(s):

Fluid Inclusions ◽

Fluorescent Microscopy ◽

Freezing Temperature ◽

Homogenization Temperature ◽

Source Rocks ◽

Late Triassic ◽

Peritectic Temperature ◽

Petroleum Systems ◽

Initial Melting ◽

Atlantic Margin

Fluid inclusions hosted in rock salt from the Triassic Argo Formation in the Canadian Atlantic continental margin were studied to investigate the nature and origin of petroleum fluids in them. Inclusions were studied in two wells: Glooscap-C63 and Weymouth-A45. The pillow-shaped salt body intersected by the Glooscap-C63 well is autochthonous, and the salt is transparent and colorless compared with that in the allochthonous, canopy–diaper-shaped body cut by the Weymouth-A45 well which is translucent and buff-colored. Aqueous (AFI), petroleum (PFI), and heterogeneously trapped, mixed petroleum – aqueous (MFI) fluid inclusions were identified using transmitted and fluorescent microscopy, and representative samples were analyzed microthermometrically. Petroleum-bearing fluid inclusions (PFI and MFI) are more common and contain more concentrated petroleum phases in the allochthonous salts of Weymouth-A45 well. Based on microthermometric studies, the AFI and MFI in Glooscap-C63 salt mostly belong to NaCl–H2O and NaCl–H2O–petroleum systems, respectively; in contrast, those of Weymouth-A45 belong to NaCl–MgCl2–H2O and (or) NaCl–CaCl2–H2O and NaCl–MgCl2–H2O–petroleum and (or) NaCl–CaCl2–H2O–petroleum systems, respectively. Each of the AFI, PFI, and MFI types consists of different phases. The medians of Tf (freezing temperature), Tim (initial melting temperature), Te (Eutectic temperature), Tm (final melting (peritectic) temperature), and Th (homogenization temperature) in the AFI and MFI in the salts of Glooscap-C63 well are (−82, −75 °C), (−39, −38 °C), (−25, −24 °C), (−1.8, −3 °C), and (291, 287 °C), respectively. The corresponding medians for the Weymouth-A45 well are (−71, −78 °C), (−52, −52 °C), (−37, −38 °C), (−2.7, −3 °C), and (122, 20 °C), respectively. The median Th of PFI in Glooscap-C63 and Weymouth-A45 salts are 79 and 23 °C, respectively. The most probable source rocks for the petroleum are the shales of the Late Triassic – Early Jurassic Eurydice Formation which is widely distributed at depth underlying the Argo salt.

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Prospectivity of the Triassic successions of the North West Shelf of Australia: New insights from a regional integrated geoscience study

The Leading Edge ◽

10.1190/tle40030172.1 ◽

2021 ◽

Vol 40 (3) ◽

pp. 172-177

Author(s):

Jarrad Grahame ◽

Victoria Cole

Keyword(s):

Evaluation Tool ◽

System Perspective ◽

Sea Levels ◽

North West ◽

Petroleum Systems ◽

The North ◽

Study Results ◽

Half Graben ◽

Rift Zones ◽

Rising Sea Levels

The North West Shelf (NWS) of Australia is a prolific hydrocarbon province hosting significant volumes of hydrocarbons, primarily derived from Jurassic and Cretaceous targets. A new regional, integrated geoscience study has been undertaken to develop insights into the paleogeography and petroleum systems of Late Permian to Triassic successions, which have been underexplored historically in favor of Jurassic to Cretaceous targets. Within the NWS study area, graben and half-graben depocenters developed in response to intracratonic rifting that preceded later fragmentation and northward rifting of small continental blocks. This, coupled with contemporaneous cycles of rising sea levels, brought about the development of large embayments and shallow, epeiric seas between the Australian continental landmass and outlying continental fragments in the early stages of divergence. Key elements of the study results discussed herein include the study methodology, the paleogeographic and gross depositional environment mapping, and the reservoir and source kitchen modeling. The study results highlight the presence of depocenters that developed within oblique rift zones due to regional Permo-Triassic strike-slip tectonics that bear compelling similarities to modern-day analogues. These intracratonic rift zones are well-known and prominent tectonic features resulting from mantle upwelling and weakening of overlying lithospheric crust, initiating the development of divergent intraplate depocenters. The comprehensive analysis of these depocenters from a paleogeographic and petroleum system perspective provides a basin evaluation tool for Triassic prospectivity.

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Exploration success on the North West Shelf via continuous application of seismic technologies

The APPEA Journal ◽

10.1071/aj08013 ◽

2009 ◽

Vol 49 (1) ◽

pp. 205

Author(s):

Mark Thompson ◽

M Royd Bussell ◽

Michael Wilkins ◽

Dave Tapley ◽

Jenny Auckland

Keyword(s):

Seismic Imaging ◽

Leading Edge ◽

Seismic Survey ◽

Water Contact ◽

North West ◽

Depth Migration ◽

Petroleum Systems ◽

The North ◽

Continuous Application ◽

Near Term

Expansion of the North West Shelf Venture (NWSV) production infrastructure is driving plans for sequential development of the small satellite fields. The desire for additional gas reserves has fuelled increased exploration and appraisal drilling in recent years with encouraging results. The NWSV area is a complex geologic environment with multiple play levels, petroleum systems and trapping styles. Seismic imaging is poor in many areas, primarily due to multiple contamination. In 2004, the NWSV acquired the leading edge, regional Demeter 3D Seismic Survey. Since then, continuous application of improved processing techniques, such as 3D Surface-related Multiple Elimination (SRME) and Pre-Stack Depth Migration (PreSDM), have been key to providing significant imaging enhancements. Exploration drilling based on Demeter data resulted in three significant new gas discoveries. Pemberton–1 (2006) explored Triassic sub-cropping sands in a horst block at the southwestern end of the Rankin Trend. The well encountered an upside gas column due to the presence of intra-Mungaroo Formation shales providing a base-seal trapping geometry. Lady Nora–1 (2007) tested the fault block west of the Pemberton horst and encountered a 102 m gross gas column with gas on rock. The upside result accelerated a near term appraisal opportunity at Lady Nora–2 (2008). Persephone–1 (2006) drilled a down-thrown Legendre Formation dip closure in the Eaglehawk graben. Success relied on the sealing potential of the North Rankin Field bounding fault. In spite of pressure depletion associated with over 20 years of production, Persephone–1 encountered a 151 m gross gas column at virgin pressures and a different gas-water contact to North Rankin. The result demonstrated active and significant fault seal along the major North Rankin Field bounding fault. These recent, successful exploration wells have resulted in identification of follow-up drilling opportunities and a drive for ongoing seismic imaging improvements. The discoveries have material impacts on NWSV development plans for the Greater Western Flank and in the vicinity of the Perseus, North Rankin and Goodwyn gas fields.

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ACCURATE RECOGNITION OF SOURCE ROCK CHARACTER IN THE JURASSIC OF THE NORTH WEST SHELF, WESTERN AUSTRALIA

The APPEA Journal ◽

10.1071/aj91023 ◽

1992 ◽

Vol 32 (1) ◽

pp. 289 ◽

Cited By ~ 1

Author(s):

John Scott

Keyword(s):

Source Rock ◽

Organic Material ◽

Source Rocks ◽

Higher Plant ◽

Pyrolysis Gas ◽

Screening Analysis ◽

North West ◽

The North ◽

Potential Source Rock ◽

Rock Eval

The main potential source rock intervals are generally well defined on the North West Shelf by screening analysis such as Rock-Eval. The type of product from the source rocks is not well defined, owing to inadequacies in current screening analysis techniques. The implications of poor definition of source type in acreage assessment are obvious. The type of product is dependent on the level of organic maturity of the source rock, the ability of products to migrate out of the source rock and on the type of organic material present. The type of kerogen present is frequently determined by Rock-Eval pyrolysis. However, Rock-Eval has severe limitations in defining product type when there is a significant input of terrestrial organic material. This problem has been recognised in Australian terrestrial/continental sequences but also occurs where marine source rock facies contain terrestrially-derived higher plant material. Pyrolysis-gas chromatography as applied to source rock analysis provides, by molecular typing, a better method of estimating the type of products of the kerogen breakdown than bulk chemical analysis such as Rock-Eval pyrolysis.

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Prospectivity insights from automated pre-interpretation processing of open-file 3D seismic data: characterising the Late Triassic Mungaroo Formation of the Carnarvon Basin, North West Shelf of Australia

The APPEA Journal ◽

10.1071/aj14002 ◽

2015 ◽

Vol 55 (1) ◽

pp. 15 ◽

Cited By ~ 1

Author(s):

Cliff C. Ford ◽

James K. Dirstein ◽

Alistair John Stanley

Keyword(s):

Spatial Databases ◽

Late Triassic ◽

Data Sets ◽

3D Seismic ◽

Gas Reservoirs ◽

Waveform Data ◽

Open File ◽

North West ◽

The North ◽

Carnarvon Basin

Waveform data from pre-interpretation processing is used in nine Late Triassic interpretation case studies from an area extending more than 30,000 km2 across the Exmouth Plateau, Kangaroo Trough and Rankin Trend on the North West Shelf of Australia. Events selected from a database of automatically generated surfaces extracted from six large open-file 3D marine surveys (~16,000 km2) are used to analyse reservoirs, seals, and pore fluid within the Brigadier and Mungaroo formations in this peer-reviewed paper. Today, geoscience teams are challenged with vast data sets such as the archived versions of more than 125 Carnarvon Basin 3D seismic surveys. Pre-interpretation processing delivers a database of numerous seismic events that cannot be effectively managed using traditional interpretation workstations. With, however, a 3D viewer to query, edit and merge the results, geoscience teams are able to review many large surveys and the surfaces in their interpretation workflows. At the 2013 WABS Conference in Perth, WA, two papers offered models for the Late Triassic gas reservoirs. These models represent many years of synthesis and integration of data by teams of geoscientists from two of the major operators on the North West Shelf. Validation and corroboration of the proposed models was gained by using selected pre-interpretation surfaces. Stacking patterns, waveform fitness, amplitude and two-way time surfaces from these spatial databases revealed geological insights about the formations, such as their complexity of structure, extent of reservoirs, and continuity of seals, along with a better understanding about the trapping and charge systems of the fields.

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

The APPEA Journal ◽

10.1071/aj17165 ◽

2018 ◽

Vol 58 (2) ◽

pp. 871 ◽

Cited By ~ 2

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.

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PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

The APPEA Journal ◽

10.1071/aj99002 ◽

2000 ◽

Vol 40 (1) ◽

pp. 26

Author(s):

M.R. Bendall C.F. Burrett ◽

H.J. Askin

Keyword(s):

Oil And Gas ◽

Source Rocks ◽

Petroleum Exploration ◽

Late Triassic ◽

Upper Permian ◽

Lower Permian ◽

Peak Oil ◽

Petroleum Systems ◽

Upper Proterozoic ◽

Oil Seep

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.

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