Petroleum systems of the Bass Basin: a 3D modelling perspective

2010 ◽  
Vol 50 (1) ◽  
pp. 511 ◽  
Author(s):  
Natt Arian ◽  
Peter Tingate ◽  
Richard Hillis ◽  
Geoff O'Brien
Keyword(s):  
Middle Eastern ◽  
Source Rocks ◽  
Petroleum Systems ◽  
Systems Model ◽  
Basin Scale ◽  
Exploration Risk ◽  
New Locations ◽  
Petroleum Generation ◽  
And Migration ◽  
Hydrocarbon Expulsion

Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.

New insights into the petroleum prospectivity of the Browse Basin: the results of a multi-disciplinary study

2016 ◽  
Vol 56 (1) ◽  
pp. 483 ◽  
Author(s):  
Nadege Rollet ◽  
Emmanuelle Grosjean ◽  
Dianne Edwards ◽  
Tehani Palu ◽  
Steve Abbott ◽  
...  
Keyword(s):  
Source Rock ◽  
Spatial Relationship ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
North West ◽  
Petroleum Systems ◽  
Systems Model ◽  
Hydrocarbon Expulsion

The Browse Basin hosts large gas accumulations, some of which are being developed for conventional liquefied natural gas (LNG). Extensive appraisal drilling has been focused in the central Caswell Sub-basin at Ichthys and Prelude, and along the extended Brecknock-Scott Reef Trend; whereas elsewhere the basin remains underexplored. To provide a better understanding of regional hydrocarbon prospectivity, the sequence stratigraphy of the Cretaceous succession and structural framework were analysed to determine the spatial relationship of reservoir and seal pairs, and those areas of enhanced source rock development. The sequence stratigraphic interpretation is based upon a common North West Shelf stratigraphic framework that has been developed in conjunction with industry, and aligned with the international time scale. Sixty key wells and 2D and 3D seismic data have been interpreted to produce palaeogeographic maps and depositional models for the Cretaceous succession. Geochemical analyses have characterised the molecular and stable isotopic signatures of fluids and correlated them with potential source rocks. The resultant petroleum systems model provides a more detailed understanding of source rock maturity, organic richness and hydrocarbon-generation potential in the basin. The model reveals that many accumulations have a complex charge history, with the mixing of hydrocarbon fluids from multiple Mesozoic source rocks, including the Lower–Middle Jurassic J10–J20 supersequences (Plover Formation), Upper Jurassic–Lowermost Cretaceous J30–K10 supersequences (Vulcan Formation), and Lower Cretaceous K20–K30 supersequences (Echuca Shoals Formation). Burial history and hydrocarbon expulsion models, applied to these Jurassic and Cretaceous supersequences, suggest that numerous petroleum systems are effective within the basin. For example, hydrocarbons are interpreted to have been generated from several source pods within the southern Caswell Sub-basin with migration continuing onto the Yampi Shelf, an area of renewed exploration interest.

The times they are a-changin': Australian biozones, petroleum basins, and the international geologic time scale (GTS) 2012

2014 ◽  
Vol 54 (2) ◽  
pp. 473
Author(s):  
Tegan Smith ◽  
John Laurie ◽  
Lisa Hall ◽  
Robert Nicoll ◽  
Andrew Kelman ◽  
...  
Keyword(s):  
Time Scale ◽  
Age Dating ◽  
Burial History ◽  
Geologic Time ◽  
Petroleum Systems ◽  
Geologic Time Scale ◽  
History Of ◽  
And Migration ◽  
The Times ◽  
Hydrocarbon Expulsion

The international Geologic Time Scale (GTS) continually evolves due to refinements in age dating and the addition of more defined stages. The GTS 2012 has replaced GTS 2004 as the global standard timescale, resulting in changes to the age and duration of most chronological stages. These revisions have implications for interpreted ages and durations of sedimentary rocks in Australian basins, with ramifications for petroleum systems modelling. Accurate stratigraphic ages are required to reliably model the burial history of a basin, hence kerogen maturation and hydrocarbon expulsion and migration. When the resolution of the time scale is increased, models that utilise updated ages will better reflect the true basin history. The international GTS is largely built around northern hemisphere datasets. At APPEA 2009, Laurie et al. announced a program to tie Australian biozones to GTS 2004. Now, with the implementation of GTS 2012, these ties are being updated and refined, requiring a comprehensive review of the correlations between Australian and International biozonation schemes. The use of Geoscience Australia’s Timescales Database and a customised ‘Australian Datapack’ for the visualisation software package TimeScale Creator has greatly facilitated the transition from GTS 2004 to GTS 2012, as anticipated in the design of the program in 2009. Geoscience Australia’s basin biozonation and stratigraphy charts (e.g. Northern Carnarvon and Browse basins) are being reproduced to reflect the GTS 2012 and modified stratigraphic ages. Additionally, new charts are being added to the series, including a set of onshore basin charts, such as the Georgina and Canning basins.

PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 315 ◽  
Author(s):  
K. K. Romine ◽  
J. M. Durrant ◽  
D. L. Cathro ◽  
G. Bernardel
Keyword(s):  
Focal Point ◽  
Source Rocks ◽  
Predictive Tool ◽  
Petroleum Systems ◽  
The North ◽  
Northern Carnarvon Basin ◽  
And Migration ◽  
Play Elements ◽  
Migration Pathways ◽  
Carnarvon Basin

A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.

Pressure solution in carbonate source rocks and its control on petroleum generation and migration

1995 ◽  
Vol 12 (7) ◽  
pp. 717-733 ◽  
Author(s):  
Detlev Leythaeuser ◽  
Ornella Borromeo ◽  
Fausto Mosca ◽  
Rolando di Primio ◽  
Matthias Radke ◽  
...  
Keyword(s):  
Source Rocks ◽  
Pressure Solution ◽  
Petroleum Generation ◽  
And Migration ◽  
Carbonate Source

scholarly journals Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study

GeoArabia ◽  
2004 ◽  
Vol 9 (4) ◽  
pp. 41-72 ◽  
Author(s):  
Janet K. Pitman ◽  
Douglas Steinshouer ◽  
Michael D. Lewan
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Peak Oil ◽  
Fold Belt ◽  
Hydrous Pyrolysis ◽  
Oil Generation ◽  
Petroleum Generation ◽  
And Migration ◽  
Migration Pathways

ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.

Petroleum systems analysis of the northern Houtman Sub-basin

2017 ◽  
Vol 57 (2) ◽  
pp. 755 ◽  
Author(s):  
Lisa Hall ◽  
Emmanuelle Grosjean ◽  
Irina Borissova ◽  
Chris Southby ◽  
Ryan Owens ◽  
...  
Keyword(s):  
Systems Analysis ◽  
Source Rocks ◽  
Rock Properties ◽  
Hydrocarbon Generation ◽  
Petroleum Systems ◽  
Systems Model ◽  
Potential Source ◽  
Lithospheric Extension ◽  
Half Graben ◽  
Potential Field Modelling

Interpretation of newly acquired seismic data in the northern Houtman Sub-basin (Perth Basin) suggests the region contains potential source rocks similar to those in the producing Abrolhos Sub-basin. The regionally extensive late Permian–Early Triassic Kockatea Shale has the potential to contain the oil-prone Hovea Member source interval. Large Permian syn-rift half-graben, up to 10 km thick, are likely to contain a range of gas-prone source rocks. Further potential source rocks may be found in the Jurassic–Early Cretaceous succession, including the Cattamarra Coal Measures, Cadda shales and mixed sources within the Yarragadee Formation. This study investigated the possible maturity and charge history of these different source rocks. A regional pseudo-3D petroleum systems model was constructed using new seismic interpretations. Heat flow was modelled using crustal structure and possible basement composition determined from potential field modelling, and subsidence analysis was used to investigate lithospheric extension through time. The model was calibrated using temperature and maturity data from nine wells in the Houtman and Abrolhos sub-basins. Source rock properties are assigned based on an extensive review of total organic carbon, Rock Eval and kinetic data for the offshore northern Perth Basin. Petroleum systems analysis results show that Permian, Triassic and Early Jurassic source rocks may have generated large cumulative volumes of hydrocarbons across the northern Houtman Sub-basin, whereas the Middle Jurassic–Cretaceous sources remain largely immature. However, the timing of hydrocarbon generation and expulsion with respect to trap formation and structural reactivation is critical for the successful development and preservation of hydrocarbon accumulations.

Prospectivity of the 2014 offshore acreage release areas for petroleum exploration

2014 ◽  
Vol 54 (1) ◽  
pp. 383
Author(s):  
Thomas Bernecker ◽  
Dianne Edwards ◽  
Tehani Kuske ◽  
Bridgette Lewis ◽  
Tegan Smith
Keyword(s):  
Large Scale ◽  
Oil And Gas ◽  
Gas Production ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Oil And Gas Production ◽  
Northern Margin ◽  
Petroleum Systems ◽  
Basin Scale ◽  
Northern Carnarvon Basin

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. Industry nominations provided guidance for the selection of gazettal areas, and in 2014 all 30 areas are supported by such nominations. The release areas are located across various offshore hydrocarbon provinces ranging from mature basins with ongoing oil and gas production to exploration frontiers. Work program bids are invited for two rounds closing on 2 October 2014 and 2 April 2015, while the closing date for four cash bid areas is 5 February 2015. Twenty-nine of the 2014 Release Areas are located along Australia’s northern margin within the Westralian Superbasin, which encompasses the rift-basins that extend from the Northern Carnarvon Basin to the Bonaparte Basin. Evolution during Gondwana break-up established a series of petroleum systems, many of which have been successfully explored, while others remain untapped. Only one area was nominated and approved for release on Australia’s southern margin. The 220 graticular blocks cover almost the entire Eyre Sub-basin of the Bight Basin. In the context of the recent commencement of large-scale exploration programs in the Ceduna and Duntroon sub-basins, this release area provides additional opportunities to explore an offshore frontier. Geoscience Australia’s new long-term petroleum program supports industry activities by engaging in petroleum geological studies that are aimed at the establishment of margin to basin-scale structural frameworks and comprehensive assessments of Australian source rocks underpinning all hydrocarbon prospectivity studies.

Using Spatial Analysis of Hydrocarbon Compositions to Better Understand the Petroleum Systems of the South Sumatra Basin, Indonesia

2021 ◽  
Author(s):  
A. R. Livsey
Keyword(s):  
Spatial Analysis ◽  
Source Rock ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
The South ◽  
Petroleum Systems ◽  
Late Neogene ◽  
Palaeoenvironmental Reconstructions ◽  
And Migration ◽  
Definition Of

The South Sumatra Basin has been a focus for hydrocarbon exploration since the earliest oil discoveries in the late 1890s. Despite production of over 2500MMbbls of oil and 9.5TCF of gas our regional understanding of the basin’s petroleum systems is still evolving. Most discoveries occur along a series of Late Neogene NNW-SSE elongated anticlines. The most prolific reservoirs are fluvial – shallow marine sandstones of the Upper Oligocene – Lower Miocene Talang Akar Formation but hydrocarbons have also been discovered in numerous sandstone and carbonate reservoirs ranging in age from Middle – Late Miocene to Eocene. Pre-Tertiary fractured Basement reservoirs are also important gas producers. A geochemical database for produced, tested and seep oils and gases has been compiled from the analytical reports, produced by different service companies over a 40-year period, to understand the spatial distribution of hydrocarbon types and relate this to source type, source maturity and migration patterns. Integration with published palaeoenvironmental reconstructions for the time intervals associated with source rock deposition has enabled a better understanding of migration directions and migration limits. The database of over 100 oils and 40 gases has revealed a wider variation in geochemical character than previously thought, indicating the presence of numerous fluvio-deltaic and lacustrine types suggesting subtle variations in the character of the effective source rocks within the basin, related to both organic matter type and depositional environment. Seven major oil families, often with several sub-groups, have been identified, while the presence of both biogenic and thermogenic gases of varying maturities are also noted. Spatial analysis of these hydrocarbons, integrated with source rock indications, palaeoenvironmental reconstructions and structural maps have allowed definition of kitchen areas and drainage areas for these hydrocarbon accumulations and a better understanding of the charge risk and likely hydrocarbon type in undrilled areas.

scholarly journals A review of oil and gas seepage in the Nuussuaq Basin, West Greenland – implications for petroleum exploration

2020 ◽  
Author(s):  
Flemming G. Christiansen ◽  
Jørgen A. Bojesen-Koefoed ◽  
Gregers Dam ◽  
Troels Laier ◽  
Sara Salehi
Keyword(s):  
Structural Model ◽  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Lateral Migration ◽  
West Greenland ◽  
Gas Seepage ◽  
Petroleum Generation ◽  
And Migration ◽  
Migration Pathways

The Nuussuaq Basin in West Greenland has an obvious exploration potential. Most of the critical elements are well documented, including structures that could form traps, reservoir rocks, seals and oil and gas seepage that documents petroleum generation. And yet, we still lack a full understanding of the petroleum systems, especially the distribution of mature source rocks in the subsurface and the vertical and lateral migration of petroleum into traps. A recently proposed anticlinal structural model could be very interesting for exploration if evidence of source rocks and migration pathways can be found. In this paper, we review all existing, mostly unpublished, data on gas observations from Nuussuaq. Furthermore, we present new oil and gas seepage data from the vicinity of the anticline. Occurrence of gas within a few kilometres on both sides of the mapped anticline has a strong thermogenic fingerprint, suggesting an origin from oil-prone source rocks with a relatively low thermal maturity. Petroleum was extracted from an oil-stained hyaloclastite sample collected in the Aaffarsuaq valley in 2019, close to the anticline. Biomarker analyses revealed the oil to be a variety of the previously characterised “Niaqornaarsuk type,” reported to be formed from Campanian-age source rocks. Our new analysis places the “Niaqornaarsuk type” 10 km from previously documented occurrences and further supports the existence of Campanian age deposits developed in source rock facies in the region.

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