A quantitative approach to regional screening of petroleum systems, Westralian Superbasin

2015 ◽  
Vol 55 (2) ◽  
pp. 401
Author(s):  
Christopher Paschke ◽  
Rob K. Sawyer ◽  
Catherine Belgarde ◽  
Chris Yarborough ◽  
Christina Huenink
Keyword(s):  
Source Rock ◽  
Systems Analysis ◽  
Regional Scale ◽  
Source Rocks ◽  
Regional Study ◽  
Seismic Line ◽  
Petroleum Systems ◽  
Reflection Seismic ◽  
Stratigraphic Position

The greater Westralian Superbasin comprises multiple petroleum systems ranging in age from the Early Paleozoic to the Paleogene (Bradshaw et al, 1994). A subset of these systems is typified by marine incursions with a deposition of liquids-prone source rocks. Variability in Westralian sediment fill and source rock stratigraphic position can be demonstrated on a continuous mega-regional 2D deep reflection seismic line that extends from Carnarvon through Browse and into the Bonaparte Basin. Beginning in 2013, BHP Billiton initiated a comprehensive regional study of the Westralian margin to better risk existing and new play fairways. From this work, a hydrocarbon systems analysis from the Dampier Sub-basin and its application for exploration as a regional analogue is described. From a compilation of both open-file and proprietary data, a subset of Dampier well penetrations was chosen, based on the quality of available source rock data. 1D models were constructed and thermally calibrated to BHP Billiton’s recent re-interpretation of the sub-regional crustal architecture. The ultimate expelled petroleum (UEP) was calculated at each well and then extrapolated regionally to determine the total basin hydrocarbon potential. Maturity of the source rock is described using the state of thermal stress (STS) parameter (Pepper and Corvi, 1995). Compared with more data- and labour-intensive 3D basin modelling, integration of 1D basin models, UEP and STS parameters allow for a rapid quantitative and regional-scale basin analysis. Using this workflow in data-constrained basins like the Dampier Sub-basin serves as an important analogue for assessing and risking petroleum systems in both of the established and frontier portions of the Australian margin.

scholarly journals Integrated petroleum systems analysis to understand the source of fluids in the Browse Basin, Australia

2017 ◽  
Vol 57 (2) ◽  
pp. 781 ◽  
Author(s):  
Tehani Palu ◽  
Lisa Hall ◽  
Emmanuelle Grosjean ◽  
Dianne Edwards ◽  
Nadege Rollet ◽  
...  
Keyword(s):  
Source Rock ◽  
Systems Analysis ◽  
Saturation Pressure ◽  
Phase Behaviour ◽  
Dew Point ◽  
Source Rocks ◽  
Fluid Composition ◽  
Burial History ◽  
Terrestrial Organic Matter ◽  
Petroleum Systems

The Browse Basin is located offshore on Australia’s North West Shelf and is a proven hydrocarbon province, hosting gas with associated condensate in an area where oil reserves are typically small. The assessment of a basin’s oil potential traditionally focuses on the presence or absence of oil-prone source rocks. However, light oil can be found in basins where source rocks are gas-prone and the primary hydrocarbon type is gas-condensate. Oil rims form whenever such fluids migrate into reservoirs at pressures less than their dew point (saturation) pressure. By combining petroleum systems analysis with geochemical studies of source rocks and fluids (gases and liquids), four Mesozoic petroleum systems have been identified in the basin. This study applies petroleum systems analysis to understand the source of fluids and their phase behaviour in the Browse Basin. Source rock richness, thickness and quality are mapped from well control. Petroleum systems modelling that integrates source rock property maps, basin-specific kinetics, 1D burial history models and regional 3D surfaces, provides new insights into source rock maturity, generation and expelled fluid composition. The principal source rocks are Early–Middle Jurassic fluvio-deltaic coaly shales and shales within the J10–J20 supersequences (Plover Formation), Middle–Late Jurassic to Early Cretaceous sub-oxic marine shales within the J30–K10 supersequences (Vulcan and Montara formations) and K20–K30 supersequences (Echuca Shoals Formation). These source rocks contain significant contributions of terrestrial organic matter, and within the Caswell Sub-basin, have reached sufficient maturities to have transformed most of the kerogen into hydrocarbons, with the majority of expulsion occurring from the Late Cretaceous until present.

Geology and petroleum prospectivity of the deepwater Otway and Sorell basins: new insights from an integrated regional study

2011 ◽  
Vol 51 (2) ◽  
pp. 692 ◽  
Author(s):  
Andrew Stacey ◽  
Cameron Mitchell ◽  
Goutam Nayak ◽  
Heike Struckmeyer ◽  
Michael Morse ◽  
...  
Keyword(s):  
Continental Margin ◽  
Regional Scale ◽  
Rift System ◽  
Aeromagnetic Data ◽  
Regional Study ◽  
Sequence Stratigraphic ◽  
Petroleum Systems ◽  
Tectonic History ◽  
Complex Structural ◽  
Potential Field Modelling

The frontier deepwater Otway and Sorell basins lie offshore of southwestern Victoria and western Tasmania at the eastern end of Australia’s Southern Rift System. The basins developed during rifting and continental separation between Australia and Antarctica from the Cretaceous to Cenozoic. The complex structural and depositional history of the basins reflects their location in the transition from an orthogonal–obliquely rifted continental margin (western–central Otway Basin) to a transform continental margin (southern Sorell Basin). Despite good 2D seismic data coverage, these basins remain relatively untested and their prospectivity poorly understood. The deepwater (> 500 m) section of the Otway Basin has been tested by two wells, of which Somerset–1 recorded minor gas shows. Three wells have been drilled in the Sorell Basin, where minor oil shows were recorded near the base of Cape Sorell–1. As part of the federal government-funded Offshore Energy Security Program, Geoscience Australia has acquired new aeromagnetic data and used open file seismic datasets to carry out an integrated regional study of the deepwater Otway and Sorell basins. Structural interpretation of the new aeromagnetic data and potential field modelling provide new insights into the basement architecture and tectonic history, and highlights the role of pre-existing structural fabric in controlling the evolution of the basins. Regional scale mapping of key sequence stratigraphic surfaces across the basins, integration of the regional structural analysis, and petroleum systems modelling have resulted in a clearer understanding of the tectonostratigraphic evolution and petroleum prospectivity of this complex basin system.

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

2016 ◽  
Vol 56 (1) ◽  
pp. 173 ◽  
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.

PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA

2007 ◽  
Vol 47 (1) ◽  
pp. 127 ◽  
Author(s):  
G. Ambrose ◽  
M. Scardigno ◽  
A.J. Hill
Keyword(s):  
Oil And Gas ◽  
Regional Scale ◽  
Early Jurassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Red Beds ◽  
Petroleum Systems ◽  
Stratigraphic Architecture ◽  
Central Australia ◽  
Cooper Basin

Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.

Cooper Basin source rock atlas

2016 ◽  
Vol 56 (2) ◽  
pp. 594
Author(s):  
Lisa Hall ◽  
Tehani Palu ◽  
Chris Boreham ◽  
Dianne Edwards ◽  
Tony Hill ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Source Rock ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Predictive Tool ◽  
Resource Potential ◽  
Petroleum Systems ◽  
Petroleum Resource ◽  
Hydrocarbon Yield ◽  
Cooper Basin

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

The persistence of a large stagnation zone in a developed regional aquifer, southwestern Ontario

2004 ◽  
Vol 41 (5) ◽  
pp. 943-958 ◽  
Author(s):  
Muin M Husain ◽  
John A Cherry ◽  
Shaun K Frape
Keyword(s):  
Flow Model ◽  
Regional Scale ◽  
Ground Surface ◽  
Poor Quality ◽  
Lake Huron ◽  
Regional Study ◽  
Natural Conditions ◽  
Isotope Signature ◽  
Regional Aquifer

An extensive groundwater zone of exceptionally negative δ18O (–17.5‰ to –16.0‰) exists in a thin, regional, freshwater aquifer between Lake St. Clair and the southern shore of Lake Huron in southwestern Ontario. The zone occurs at the interface between the overlying thick Quaternary clay aquitard of glaciolacustrine origin and the underlying bedrock shale. This isotope signature, which is 7‰ more negative (lighter) than modern water, indicates a Late Pleistocene origin of the aquifer water. This zone occurs only where the Quaternary aquitard is greater than 35 m thick. In the Quaternary aquitard, the Pleistocene isotope signature extends upward from the aquifer and then has a gradational transition to signature resembling modern water (–10‰) near the ground surface. This regional-scale study of the aquifer–aquitard system indicates that the pattern of flow of the aquifer has allowed the persistence of the Pleistocene groundwater since the aquitard was deposited approximately 10 000 years before present. As part of the regional study, a two-dimensional groundwater flow model was used to assess the origin and persistence of the Pleistocene zone under natural conditions. The persistence of the Pleistocene zone was also assessed based on water budgets prepared from aquifer use history and aquifer–aquitard parameters. Our study finds that the low yield and poor quality of groundwater in this zone have caused minimal use, resulting in the persistence of the Pleistocene groundwater since the beginning of major aquifer use in the 1940s.Key words: regional aquifer, aquitard, Pleistocene water, stagnation, aquifer use.

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

2017 ◽  
Vol 57 (2) ◽  
pp. 744
Author(s):  
Jarrad Grahame ◽  
Emma Cairns ◽  
Stephanie Roy
Keyword(s):  
System Development ◽  
New Ventures ◽  
Source Rocks ◽  
Late Triassic ◽  
Regional Study ◽  
North West ◽  
Petroleum Systems ◽  
The North ◽  
Core Logging ◽  
Seismic Sections

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.

Integrated 3D basin and petroleum systems modelling of the Great Australian Bight

2017 ◽  
Vol 57 (2) ◽  
pp. 733
Author(s):  
E. Frery ◽  
M. Ducros ◽  
L. Langhi ◽  
J. Strand ◽  
A. Ross
Keyword(s):  
Heat Flow ◽  
Source Rock ◽  
Source Rocks ◽  
Integrated Modelling ◽  
Hydrocarbon Migration ◽  
Petroleum Systems ◽  
Basin Modelling ◽  
Well Data ◽  
Great Australian Bight ◽  
Migration Pathways

3D stratigraphic, structural, thermal and migration modelling has become an essential part of petroleum systems analysis for passive margins, especially if complex 3D facies patterns and extensive volcanic activity are observed. A better understanding of such underexplored offshore areas requires a refined 3D basin modelling approach, with the implementation of realistically sized volcanic intrusions, source rocks and reservoir intervals. In this study, an integrated modelling workflow based on a Great Australian Bight case study has been applied. The 244800-km2 3D model integrates well data, marine surveys, 3D stratigraphic forward modelling and 3D basin modelling to better predict the effects of 3D facies variations and heat flow anomalies on the determination of the source rock-enriched intervals, the source rock maturity history and the hydrocarbon migration pathways. Plausible sedimentary sequences have been estimated using a stratigraphic forward model constrained by the limited available well data, seismic interpretation and published tectonic basin history. We also took into account other datasets to produce a thermal history model, such as the location of known volcanic intrusion, volcanic seamounts, bottom hole temperature and surface heat flow measurements. Such basin modelling integrates multiple datatypes acquired in the same basin and provides an ideal platform for testing hypotheses on source rock richness or kinetics, as well as on hydrocarbon migration timing and pathways evolution. The model is flexible, can be easily refined around specific zones of interest and can be updated as new datasets, such as new seismic interpretations and data from new sampling campaigns and wells, are acquired.

Observing Maturing Source Rocks on Seismic Reflection Data

Geophysics ◽  
2020 ◽  
pp. 1-56
Author(s):  
T. Matava ◽  
R. G. Keys ◽  
S. E. Ohm ◽  
S. Volterrrani
Keyword(s):  
Source Rock ◽  
Seismic Data ◽  
Pore Space ◽  
Regional Scale ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Maturity Model ◽  
Eastern Canada ◽  
Amplitude Response ◽  
Seismic Reflection Data

Hydrocarbon generation in a source rock is a complex, irreversible phase change that occurs when a source rock is heated during burial to change phase to a fluid. The fluid density is less than the kerogen density so in a closed or partially closed system the volume of the pore space occupied by fluids increases. Burial also increases the effective stress which leads to compaction and a significant reduction in porosity. The challenge of identifying source rocks on seismic data then becomes differentiating the smaller porosity increase due to hydrocarbon formation from the larger porosity decrease associated with burial. We use a calibrated rock physics model to show that Vshale and porosity data can be used to predict the compressional and shear wave velocities and the density in wells over large sedimentary sections, including a source rock of variable maturity. These well data and models show that the difference between an immature and mature source rock is an increase porosity (lower density) relative to compacting, non-source rock sediments. We use these results to identify a potential source interval in the Orphan Basin in Eastern Canada on 2D regional seismic data. We show that the full stack amplitude response of a maturing source rock is significant during the main phase of generation (0.2<transformation ratio<0.8) relative to surrounding sediments. Regional scale consistency of the amplitude response with the kerogen maturity model from an integrated basin simulator reduces exploration risk because the independence of the thermal model from the seismic amplitude response. Finally, combining the seismic response with the source rock maturity model provides insight into the likely kerogen kinetics. Most applications require regional data sets to capture the maturity window, however, applications are also possible around allochthonous salt where geometries can lead to local changes in heat flow.

The Logging Evaluation of the Relationship between Source Rock and Oil Layer Distribution in Southern Songliao Basin

2014 ◽  
Vol 962-965 ◽  
pp. 574-577
Author(s):  
Li Jun Xiu ◽  
He Ping Pan ◽  
Hao Xiu
Keyword(s):  
Source Rock ◽  
Quality Evaluation ◽  
Songliao Basin ◽  
Source Rocks ◽  
Source Control ◽  
Theory Theory ◽  
High Quality ◽  
The Relationship ◽  
Effective Source

At present, Most of the studies on source rocks is above the effective source rock identification and quality evaluation. But the spatial distribution of the high quality source rocks do not necessarily reflect the position of the layer. So, logging evaluation of the relationship between source rock and layer distributed in a region is necessary. In this paper 70 cores have selected from 4 wells in the first period of Qingshankou (q1), Songliao Basin, then get the experimental TOC value after core analysis. On the basis of source rock geochemical analysis, the author estimated the source rock TOC value with the ∆lgR method. As the distribution of high quality source rocks are clarified,the author draw a conclusion by researching on the relationship between the distribution of source rocks and layers which based on the "Source Control Theory" theory. Finally, it is found that the quality of the source rocks and layer distribution match well in both horizontal and vertical in this paper. This discovery is important for layer prediction and researches.

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