To see the other types of publications on this topic, follow the link: Perth Basin.
Journal articles on the topic 'Perth Basin'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 50 journal articles for your research on the topic 'Perth Basin.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
Hall, Peter B., and Robert L. Kneale. "PERTH BASIN REJUVENATED." APPEA Journal 32, no. 1 (1992): 33. http://dx.doi.org/10.1071/aj91004.
Full textAbstract:
The northern Perth Basin is an area where recent seismic advances combined with new geological insight, have led to exploration success with a significant new gas field discovery at Beharra Springs and a number of other minor discoveries. This paper outlines 'new concepts' with regard to stratigraphy and structure and how this has been balanced with the commercial environment to rejuvenate exploration in the northern Perth Basin. The Perth Basin is unique in Australia, as running through the middle of the Basin is the West Australian Natural Gas (WANG) pipeline which will be operating at approximately 26 per cent of its capacity in 1992. With the deregulation of the natural gas market in 1988, supply of gas to the Western Australian market via the State Energy Commission of Western Australia (SECWA) pipeline from the Carnarvon Basin, and in particular, the North West Shelf project, can now be balanced with supply from the onshore Perth Basin carried by the WANG pipeline.The minimum economically viable gas field in the northern Perth Basin is calculated to be 15 BCF (16.05 PJ) and the expected median field size is 50 BCF (53.5 PJ) of recoverable gas. Based on the historical success rate of one in eight, typical finding costs are 12 c/MCF (12 c/GJ).In the 1990/91 financial year, eight onshore exploration wells were drilled in Western Australia of which five were drilled in the northern Perth Basin. Provided the market access and opportunities remain, it is anticipated that the recent technological developments will sustain exploration and development of the onshore northern Perth Basin.
2
Ghori, K. Ameed. "Petroleum data: leading the search for geothermal resources in Western Australia." APPEA Journal 49, no. 1 (2009): 365. http://dx.doi.org/10.1071/aj08022.
Full textAbstract:
In Western Australian basins, subsurface drill-hole data, primarily from petroleum exploration, allows the identification of regions of high temperature at depth that may be potential geothermal resources. The extent and economic viability of such resources remain poorly known and require further study. Observed temperatures at depths up to 4.5 km reach 150°C in parts of the Canning, Carnarvon and Perth basins, indicating low-enthalpy resources related to regional heat flow. The greatest potential for hydrothermal resources is in the Perth Basin where subsurface temperatures of 65–85°C are reached at 2–3.5 km depth. Heat-flow modelling of 170 Perth Basin wells shows a range of 30–140 mW/m2, with the highest surface heat-flow values in the northern part of the basin. The median value of 76.5 mW/m2 for this basin exceeds the average reported for the Australian continent—64.5 mW/m2. Potential hot rocks resources are present in parts of the Canning, Carnarvon and Perth basins where the depth to 200°C is less than 5 km. Knowledge of high subhorizontal stress conditions that can enhance geothermal water flow from engineered reservoirs are based on data mostly from petroleum wells in the Perth Basin. A systematic quantitative assessment of geological, hydrogeological, geophysical, stress orientation and geochemical conditions is required to further delineate and prove these resources. Progressive compilation, validation and interpretation of subsurface data from more than 800 wells is underway, and includes temperature logs of 47 shallow water bores and 30 new thermal conductivity measurements of Perth Basin wells. Data compilation from 580 wells in the Canning, Carnarvon and Perth basins is complete. To date the greatest number of wells indicating high geothermal gradients and temperatures are in the Carnarvon Basin.
3
Ghori, K. Ameed R. "Petroleum source rocks of Western Australia." APPEA Journal 58, no. 1 (2018): 282. http://dx.doi.org/10.1071/aj17051.
Full textAbstract:
Petroleum geochemical analysis of samples from the Canning, Carnarvon, Officer and Perth basins identified several formations with source potential, the: • Triassic Locker Shale and Jurassic Dingo Claystone of the Northern Carnarvon Basin; • Permian Irwin River Coal Measures and Carynginia Formation, Triassic Kockatea Shale and Jurassic Cattamarra Coal Measures of the Perth Basin; • Ordovician Goldwyer and Bongabinni formations, Devonian Gogo Formation and Lower Carboniferous Laurel Formation of the Canning Basin; • Devonian Gneudna Formation of the Gascoyne Platform and the Lower Permian Wooramel and Byro groups of the Merlinleigh Sub-basin of the Southern Carnarvon Basin; and • Neoproterozoic Brown, Hussar, Kanpa and Steptoe formations of the Officer Basin. Burial history and geothermal basin modelling was undertaken using input parameters from geochemical analyses of rock samples, produced oil, organic petrology, apatite fission track analysis (AFTA), heat flows, subsurface temperatures and other exploration data compiled by the Geological Survey of Western Australia (GSWA). Of these basins, the Canning, Carnarvon, and Perth basins are currently producing oil and gas, whereas the Southern Carnarvon and Officer basins have no commercial petroleum discovery yet, but they do have source, reservoir, seal and petroleum shows indicating the presence of petroleum systems. The Carnarvon Basin contains the richest identified petroleum source rocks, followed by the Perth and Canning basins. Production in the Carnarvon Basin is predominantly gas and oil, the Perth Basin is gas-condensate and the Canning Basin is oil dominated, demonstrating the variations in source rock type and maturity across the state. GSWA is continuously adding new data to assess petroleum systems and prospectivity of these and other basins in Western Australia.
4
Hall, P. B. "THE FUTURE PROSPECTIVITY OF THE PERTH BASIN." APPEA Journal 29, no. 1 (1989): 440. http://dx.doi.org/10.1071/aj88036.
Full textAbstract:
The Perth Basin may have been regarded in the past as prospectively poor, but things are about to change! Seismic quality was generally poor, reservoirs often tight and source- rock maturity data limited. Abundant source rocks which tend to have a predominance of Type III kerogens have been identified and the basin has often been referred to as gas prone, the two largest discoveries having combined recoverable reserves greater than 444 billion cubic feet (12.5 Gm3).Advances in seismic acquisition and processing, available from the early 1980s, is drawing back the veil that has enveloped major areas of the basin for many years. An estimated 29 wells out of 40 exploration wells studied in the northern area of the Perth Basin were drilled off- structure. Established plays are now being correctly delineated and oil- prone source rocks with good generative potential have been identified.Perhaps the most significant occurrence in the Perth Basin was the discovery of a new play in 1987 which stimulated a new round of activity. This will undoubtedly provide economic discoveries for the participants. This renewed prospectivity will spill over into the offshore areas in the near future.The northern area of the Perth Basin has an historic exploration risk of 12.5 per cent. With future exploration risk predicted at 20- 30 per cent, this area will become one of the most prospective onshore basins in Australia.
5
Southby, Chris, Irina Borissova, Lisa Hall, Ryan Owens, George Bernardel, Emmanuelle Grosjean, Cameron Mitchell, and Guillaume Sanchez. "Structural characteristics of northern Houtman sub-basin, Perth Basin." ASEG Extended Abstracts 2018, no. 1 (December 2018): 1–8. http://dx.doi.org/10.1071/aseg2018abp033.
Full text
6
Gorter, J. D., and J. M. Davies. "UPPER PERMIAN CARBONATE RESERVOIRS OF THE NORTH WEST SHELF AND NORTHERN PERTH BASIN, AUSTRALIA." APPEA Journal 39, no. 1 (1999): 343. http://dx.doi.org/10.1071/aj98019.
Full textAbstract:
The Perth, Carnarvon, Browse, and Bonaparte basins contain Permian shallowmarine carbonates. Interbedded with clastic oil and gas reservoirs in the northern Perth Basin (Wagina Formation), and gas reservoirs in the Bonaparte Basin (Cape Hay and Tern formations), these carbonates also have the potential to contain significant hydrocarbon reservoirs. Limestone porosity may be related to the primary depositional fabric, or secondary processes such as dolomitisation, karstification, and fracturing. However, in the Upper Permian interval of the North West Shelf and northern Perth Basin, where there are no indications of significant preserved primary porosity in the limestones, all known permeable zones are associated with secondary porosity. Fractured Permian carbonates have the greatest reservoir potential in the Timor Sea. Tests of fractured Pearce Formation limestones in Kelp Deep–1 produced significant quantities of gas, and a test of fractured Dombey Formation limestone in Osprey–1 flowed significant quantities of water and associated gas. Minor fracture porosity was associated with gas shows in dolomitic limestones in Fennel–1 in the Carnarvon Basin, and fractures enhance the reservoir in the Woodada Field in the northern Perth Basin. Karst formation at sub-aerial unconformities can lead to the development of secondary porosity and caverns, as in the Carnarvon Basin around Dillson–1. Minor karst is also developed at the top Dombey Formation unconformity surface in the Timor Sea region.
7
Murray‐Wallace, C. V., and R. W. L. Kimber. "Quaternary marine aminostratigraphy: Perth Basin, Western Australia." Australian Journal of Earth Sciences 36, no. 4 (December 1989): 553–68. http://dx.doi.org/10.1080/08120098908729509.
Full text
8
Jones, Andrew. "New exploration opportunities in the offshore northern Perth Basin." APPEA Journal 51, no. 1 (2011): 45. http://dx.doi.org/10.1071/aj10003.
Full textAbstract:
The petroleum prospectivity of the northern Perth Basin has been assessed by Geoscience Australia (GA) as part of the Australian Government’s Offshore Energy Security Program, in support of the 2011 offshore acreage release. This assessment includes the first published synthesis of data from fourteen new field wildcat wells drilled in this part of the basin since the Cliff Head 1 discovery (2001), and the interpretation of new regional 2D seismic data acquired during GA survey 310. Most petroleum accumulations in the northern Perth Basin are associated with Permian and Triassic source and reservoir intervals, and are found onshore and nearshore (ie. Cliff Head, Frankland, Dunsborough and Perseverance discoveries). In addition to the technical and commercial successes, numerous wells in the offshore part of the basin have intersected residual oil columns indicative of trap breach. New and legacy palynological data from Permian to Cretaceous strata in offshore wells have been used to provide age constraints for a sequence stratigraphic framework for this part of the basin. New seismic data show Permo-Triassic strata that are stratigraphic equivalents of the productive onshore and nearshore Perth Basin petroleum system, also occur within Permian half-graben in the outer Abrolhos and Houtman sub-basins. Source rock, oil stain and fluid inclusion sampling from this interval suggest that the proven onshore petroleum system is also effective in the offshore. A refined tectono-stratigraphic model for the offshore basin provides insights into basin evolution, prospectivity and contributing factors driving trap breach. Geochemical sampling in the context of the new detailed sequence framework, including from recently dredged rock samples from incised canyons, has also provided insight into the potential effectiveness of a Jurassic/Cretaceous petroleum system in the Houtman and Zeewyck sub-basins.
9
Marshall, John F., Chao Shing Lee, Douglas C. Ramsay, and Aidan M. G. Moore. "TECTONIC CONTROLS ON SEDIMENTATION AND MATURATION IN THE OFFSHORE NORTH PERTH BASIN." APPEA Journal 29, no. 1 (1989): 450. http://dx.doi.org/10.1071/aj88037.
Full textAbstract:
The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data. This analysis reveals that three sub- basins, the Edel, Abrolhos and Houtman Sub- basins, have formed as a result of three distinct episodes of rifting within the offshore North Perth Basin during the Early Permian, Late Permian and Late Jurassic respectively. During this period, rifting has propagated from east to west, and has culminated in the separation of this part of the Australian continent from Greater India.The boundaries between the sub- basins and many structures within individual sub- basins are considered to have been produced by strike- slip or oblique- slip motion. The offshore North Perth Basin is believed to be a product of transtension, possibly since the earliest phase of rifting. This has culminated in separation and seafloor spreading by oblique extension along the Wallaby Fracture Zone to form a transform passive continental margin.This style of rifting and extension has produced relatively thin syn- rift sequences, some of which have been either partly or completely removed by erosion. While the source- rock potential of the syn- rift phase is limited, post- rift marine transgressional phases and coal measures do provide adequate and relatively widespread source rocks for hydrocarbon generation. Differences in the timing of rifting across the basin have resulted in a maturation pattern whereby mature sediments become younger to the west.
10
Bernardel, George, and Chris Nicholson. "Geoscience Australia seismic survey 310: revealing stratigraphy and structure of the outer northern Perth Basin margin." APPEA Journal 53, no. 2 (2013): 481. http://dx.doi.org/10.1071/aj12092.
Full textAbstract:
Geoscience Australia acquired seismic survey GA 310 in 2008–09, across the southwest margin of Australia, as part of the Australian government’s Energy Security Program. Deep reflection seismic and potential field data were recorded across sparse 2D grids located on the Wallaby Plateau in the north, Mentelle Basin in the south, and the intervening Houtman and Zeewyck sub-basins of the northern Perth Basin. The offshore northern Perth Basin extends for about 700 km along the Western Australia margin, from the towns of Carnarvon in the north to Cervantes in the south. The largely Paleozoic-Mesozoic tectonostratigraphic framework is dominated by Permian and Early-Middle Jurassic rifting, followed by Late Jurassic-Early Cretaceous rifting leading to Valanginian breakup between Australia and Greater India. Underlying Precambrian Pinjarra Orogen structuring, in conjunction with rifting, has resulted in the development of several complex depocentres and basement highs. A recent re-evaluation of the offshore northern Perth Basin well-based lithostratigraphy into a new chronostratigraphic sequence framework has been carried outboard, on the GA 310 seismic lines, into the margin bounding the Zeewyck and northern Houtman sub-basins. The main sequences hosting source rocks—Kockatea and Cattamarra—are widely present in the expansive northern Houtman Sub-basin, and are likely to be present in the deep Zeewyck Sub-basin. The mapping of a thick Late Jurassic Yarragadee Sequence in the Zeewyck Sub-basin indicates a major pre-breakup locus of relatively rapid deposition. The structural interpretation across the sub-basin highlights breakup-drift unconformities and strike-slip faulting and suggests a probable along-margin sheared crustal sliver; tectonic elements commensurate with an evolving rift-shear breakup margin.
11
Bernecker, Thomas. "A petroleum geological overview of the 2013 offshore acreage release for petroleum exploration." APPEA Journal 53, no. 1 (2013): 69. http://dx.doi.org/10.1071/aj12007.
Full textAbstract:
The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. The previous two releases were characterised by several large, gazetted areas in underexplored regions, a trend that is maintained this year with several frontier areas comprising more than 100 graticular blocks on offer. The recent uptake of new exploration permits in the Bight Basin, the offshore North Perth Basin, and the Roebuck Basin indicates a continuing strong industry interest in offshore frontier exploration. A total of 31 areas in 13 geological provinces are formally released in 2013, and work program bids are invited for two rounds closing on 21 November 2013, and 22 May 2014. Area gazettal was, again, well supported by industry nominations. The areas on offer are represented by an even mix of shallow and deepwater areas, as well as by areas close and distant to previous discoveries and producing fields. The Northern Carnarvon, Browse, and Bonaparte basins dominate new exploration opportunities in the 2013 release, while only four areas were gazetted in the North Perth, Otway, and Gippsland basins. These also deserve attention as they have exploration potential in underexplored parts of the basins and offer opportunities to test new play concepts. Data coverage varies from being excellent in more mature areas to sparse in underexplored areas such as the North Perth Basin. The Australian Government continues to assist offshore exploration activities by providing free access to a wealth of open-file geological and geophysical data.
12
Owens, Ryan, Irina Borissova, Chris Southby, Lisa Hall, George Bernardel, Emmanuelle Grosjean, and Cameron Mitchell. "Tectono-stratigraphic development of the northern Houtman Sub-basin, Perth Basin." ASEG Extended Abstracts 2018, no. 1 (December 2018): 1–8. http://dx.doi.org/10.1071/aseg2018abp034.
Full text
13
Wellmann, J. Florian, and Lynn B. Reid. "Basin-scale Geothermal Model Calibration: Experience from the Perth Basin, Australia." Energy Procedia 59 (2014): 382–89. http://dx.doi.org/10.1016/j.egypro.2014.10.392.
Full text
14
Grice, K., R. E. Summons, E. Grosjean, R. J. Twitchett, W. Dunning, S. X. Wang, and M. E. Bottcher. "DEPOSITIONAL CONDITIONS OF THE NORTHERN ONSHORE PERTH BASIN (BASAL TRIASSIC)." APPEA Journal 45, no. 1 (2005): 262. http://dx.doi.org/10.1071/aj04023.
Full textAbstract:
An oil-source rock correlation has been established for the northern onshore Perth Basin (Western Australia) based on unusual aromatic and polar biomarkers attributed ultimately to a green sulphur bacterial source. Several of these biomarkers have been identified throughout the entire Sapropelic Interval of a proven petroleum source rock intersected within a recently discovered marine Permian- Triassic Perth Basin borehole (Hovea–3) and several Perth Basin crude oils. Today, green sulphur bacteria live in the anaerobic zones of stratified lakes or in marine environments with restricted water circulation, where the upper sulphide limit coincides with the lower limit of oxygen. The presence of photosynthetic pigments and carotenoids of green sulphur bacteria, or their diagenetic alteration products in sediments provide unequivocal evidence for photic zone euxinic conditions in the paleowater column. Multiple lines of evidence for photic zone euxinia and euxinic depositional conditions for the Hovea–3 source rock have been obtained from biomarker analyses. Photic zone euxinia is usually associated with the widespread deposition of organic-matter-rich sediments that constitute important source rocks for petroleum deposits that are being exploited today. With the exception of the Perth Basin, such organic-matter-rich sediments are virtually absent from Upper Permian and Lower Triassic sediments globally. Several lines of evidence indicate localised surface ocean productivity may have played a key role in the deposition of a petroleum source rock at this location, although photic zone euxinia was globally more widespread during the Permian-Triassic Superanoxic Event.
15
Rollet, Nadege, Chris Nicholson, Andrew Jones, Emmanuelle Grosjean, George Bernardel, and John Kennard. "New exploration opportunities in the offshore Houtman and Abrolhos sub-basins, northern Perth Basin, WA." APPEA Journal 53, no. 1 (2013): 97. http://dx.doi.org/10.1071/aj12008.
Full textAbstract:
The 2013 Acreage Release Areas W13-19 and W13-20 in the offshore northern Perth Basin, Western Australia, cover more than 19,000 km2 in parts of the Houtman, Abrolhos, Zeewyck and Gascoyne sub-basins. The Release Areas are located adjacent to WA-481-P, the only active offshore exploration permit in the Perth Basin, granted to joint venture partners Murphy Australia Oil Pty Ltd, Kufpec Australia Pty Ltd and Samsung Oil and Gas Australia Pty Ltd in August 2012. Geoscience Australia recently undertook a regional prospectivity study in the area as part of the Australian Government’s Offshore Energy Security Program, which provides fresh insights into basin evolution and hydrocarbon prospectivity. A sequence stratigraphic framework, based on new biostratigraphic sampling and interpretation, and an updated tectonostratigraphic model, using multiple 1D burial history models for Permian to Cenozoic sequences, have been developed. New geochemical studies of key offshore wells demonstrate that the oil-prone source interval of the Lopingian–Lower Triassic Hovea Member extends regionally offshore into the Abrolhos Sub-basin and potentially as far as the Houtman Sub-basin. This is supported by fluid inclusion data that provide evidence for palaeo-oil columns within Permian reservoirs in wells from the Abrolhos Sub-basin. Oil trapped in fluid inclusions in Houtman-1 can be linked to Jurassic source rocks, suggesting that multiple petroleum systems are effective in the Release Areas. The presence of active petroleum systems is also supported by the results of a recent marine survey. Potential seepage sites on the seafloor over reactivated faults correlate with hydroacoustic flares, pockmarks and dark colored viscous fluids that were observed over the areas. This may indicate an active modern-day petroleum system in the Houtman Sub-basin. Finally, a trap integrity analysis was undertaken to mitigate exploration risks associated with trap failure during Early Cretaceous breakup and provides a predictive approach to prospect assessment. These results provide strong support for the presence of active petroleum systems in the offshore northern Perth Basin and upgrade the prospectivity of the Release Areas.
16
Gorter, John, Robert S. Nicoll, Ian Metcalfe, Robbert Willink, and Darren Ferdinando. "The Permian–Triassic boundary in Western Australia: evidence from the Bonaparte and Northern Perth basins—exploration implications." APPEA Journal 49, no. 1 (2009): 311. http://dx.doi.org/10.1071/aj08020.
Full textAbstract:
Several sedimentary basins in Western Australia contain petroleum reservoirs of Late Permian or older age that are overlain by thick shaly sequences (400–2,000 m) that have been assigned an Early Triassic age. The age of the base of the Triassic shales has been, and continues to be, contentious with strata being variously ascribed to the latest Permian (Changhsingian Stage) or wholly in the earliest Triassic (Induan Stage). In the Perth Basin the Permian-Triassic boundary appears to be located somewhere in the Hovea Member of the Kockatea Shale. In the Bonaparte Basin, the boundary would appear to be either in the uppermost Penguin Formation or at the boundary between the Penguin and Mairmull formations. The uncertainty of the boundary placement relates to the interpretation of the sedimentological, biostratigraphic and geochemical record in individual sections and basins. Major problems relate to the recognition, or even the presence of unconformities, complications related to the presence of reworked sediments and paleontological material (both conodonts and spore-pollen) and to the significance of geochemical shifts. The age of the basal Kockatea Shale (northern Perth Basin) and the basal Mt Goodwin Sub-group (Bonaparte Basin) is reassessed using palaeontological data, augmented by carbon isotopic measurements and geochemical analyses, supported by wireline log correlations and seismic profiles. The stratigraphy of the latest Permian to Early Triassic succession in the Bonaparte Basin is also revised, as is the nomenclature for the Early Triassic Arranoo Member of the Kockatea Shale in the northern Perth Basin. The Mt Goodwin Sub-group (new rank) is composed of the latest Permian Penguin Formation overlain by the Early Triassic Mairmull, Ascalon and Fishburn formations (all new).
17
Reynolds, S. D., and R. R. Hillis. "Thein situstress field of the Perth Basin, Australia." Geophysical Research Letters 27, no. 20 (October 15, 2000): 3421–24. http://dx.doi.org/10.1029/2000gl011538.
Full text
18
R. Ghori, K. Ameed. "Emerging unconventional shale plays in Western Australia." APPEA Journal 53, no. 1 (2013): 313. http://dx.doi.org/10.1071/aj12027.
Full textAbstract:
Production of shale gas in the US has changed its position from a gas importer to a potential gas exporter. This has stimulated exploration for shale-gas resources in WA. The search started with Woodada Deep–1 (2010) and Arrowsmith–2 (2011) in the Perth Basin to evaluate the shale-gas potential of the Permian Carynginia Formation and the Triassic Kockatea Shale, and Nicolay–1 (2011) in the Canning Basin to evaluate the shale-gas potential of the Ordovician Goldwyer Formation. Estimated total shale-gas potential for these formations is about 288 trillion cubic feet (Tcf). Other petroleum source rocks include the Devonian Gogo and Lower Carboniferous Laurel formations of the Canning Basin, the Lower Permian Wooramel and Byro groups of the onshore Carnarvon Basin, and the Neoproterozoic shales of the Officer Basin. The Canning and Perth basins are producing petroleum, whereas the onshore Carnarvon and Officer basins are not producing, but they have indications for petroleum source rocks, generation, and migration from geochemistry data. Exploration is at a very early stage, and more work is needed to estimate the shale-gas potential of all source rocks and to verify estimated resources. Exploration for shale gas in WA will benefit from new drilling and production techniques and technologies developed during the past 15 years in the US, where more than 102,000 successful gas production wells have been drilled. WA shale-gas plays are stratigraphically and geochemically comparable to producing plays in the Upper Ordovician Utica Shale, Middle Devonian Marcellus Shale and Upper Devonian Bakken Formation, Upper Mississippian Barnett Shale, Upper Jurassic Haynesville-Bossier formations, and Upper Cretaceous Eagle Ford Shale of the US. WA is vastly under-explored and emerging self-sourcing shale plays have revived onshore exploration in the Canning, Carnarvon, and Perth basins.
19
Warris, B. J., T. Grocke, and A. Lane. "PETROLEUM OPERATIONS IN THE ENVIRONMENTALLY SENSITIVE NORTHERN PERTH BASIN, WESTERN AUSTRALIA." APPEA Journal 30, no. 1 (1990): 428. http://dx.doi.org/10.1071/aj89031.
Full textAbstract:
Barrack Energy Limited is an Australian company involved in the search for petroleum in Australia. The company's principal area of exploration and production is the northern portion of the onshore Perth Basin in Western Australia. In this area, the company operates four permits and one production licence covering an area of almost 15 000 square kilometres (3.7 million acres).For the period 1987 to 1989, Barrack Energy Limited acquired 1238 line km of seismic in the northern Perth Basin. This was conducted in fourteen surveys extending from Lancelin in the south to Dongara in the north.Petroleum exploration and production operations in the northern Perth Basin are highly visible and require painstaking and careful planning, permitting and negotiation to achieve the multiple land use goals of minimum disturbance to private landowners and minimum impact and zero long term effects on the environment.Due to the large areas of Vacant Crown Land and flora and fauna reserves in the northern Perth Basin, the impact of seismic line clearance upon the terrain was a major consideration. Barrack Energy Limited decided to experiment with various mechanical systems to clear seismic lines in order to determine the optimum operational and environmental technique. The bulldozer/ grader combination proved to be the most practical line clearance method available. The dozer need not be a tool of destruction and when operated correctly does no more damage than other methods tried.At all times Barrack Energy Limited has striven to ensure that the impact on the surrounding countryside by its exploration and production activity is kept to an absolute minimum. The company works closely with the local community to ensure that the local residents are comfortable at all times with the company's operating methods.
20
Lech, Megan, Chris Southby, David Lescinsky, Luiqi Wang, Diane Jorgensen, Irina Borissova, and Stephen Johnston. "Using palaeogeographic reconstructions to understand lithological variability within the Early Cretaceous Gage Sandstone and South Perth Shale in the Vlaming Sub-Basin, offshore southern Perth Basin." APPEA Journal 54, no. 2 (2014): 535. http://dx.doi.org/10.1071/aj13108.
Full textAbstract:
The Early Cretaceous Gage Sandstone and South Perth Shale formations are a prospective reservoir-seal pair in the Vlaming Sub-basin. Plays include post-breakup pinch-outs in the Gage Sandstone with the South Perth Shale forming top seal. The Gage reservoir has porosities of 23–30% and permeabilities of 200–1,800 mD. It was deposited in palaeotopographic lows of the Valanginian breakup unconformity and is the lowstand component of the thick deltaic South Perth (SP) Supersequence. To characterise the reservoir-seal pair, a detailed sequence stratigraphic analysis was conducted by integrating 2D seismic interpretation, well log analysis and new biostratigraphic data. Palaeogeographic reconstructions for the SP Supersequence were derived from mapping higher-order prograding packages and establishing changes in sea level and sediment supply. Higher resolution Gage reservoir reconstructions were based on seismic facies mapping. The Gage reservoir forms part of a sand-rich submarine fan system and ranges from canyon confined inner fan deposits to middle fan deposits on a basin plain. Directions of sediment supply are complex, with major sediment contributions from a northern and southern canyon adjacent to the Badaminna Fault Zone. The characteristics of the SP Supersequence differ markedly between the northern and southern parts of the sub-basin due to variations in palaeotopography and sediment supply. Palaeogeographic reconstructions reveal a series of regressions and transgressions leading to infilling of the palaeo-depression. Palaeogeographic reconstructions for the SP Supersequence portray a complex early post-rift depositional history in the central Vlaming Sub-basin. The developed approach is applicable for detailed studies of other sedimentary basins.
21
Glubokovskikh, Stanislav, Andrej Bona, Roman Pevzner, Anton Egorov, and Ludovic Ricard. "Feasibility of Seismic Monitoring of CCS in Perth Basin." ASEG Extended Abstracts 2018, no. 1 (December 2018): 1. http://dx.doi.org/10.1071/aseg2018abw9_1b.
Full text
22
Varma, S., J. Underschultz, S. B. Giger, B. Field, L. Roncaglia, J. Hodgkinson, and D. Hilditch. "CO2geosequestration potential in the Northern Perth Basin, Western Australia." Australian Journal of Earth Sciences 60, no. 1 (February 2013): 23–44. http://dx.doi.org/10.1080/08120099.2012.682737.
Full text
23
Tupper, Neil, Eric Matthews, Gareth Cooper, Andy Furniss, Tim Hicks, and Suzanne Hunt. "The Waitsia Field, onshore North Perth Basin, Western Australia." APPEA Journal 56, no. 1 (2016): 29. http://dx.doi.org/10.1071/aj15003.
Full textAbstract:
The Waitsia Field represents a new commercial play for the onshore north Perth Basin with potential to deliver substantial reserves and production to the domestic gas market. The discovery was made in 2014 by deepening of the Senecio–3 appraisal well to evaluate secondary reservoir targets. The well successfully delineated the extent of the primary target in the Upper Permian Dongara and Wagina sandstones of the Senecio gas field but also encountered a combination of good-quality and tight gas pay in the underlying Lower Permian Kingia and High Cliff sandstones. The drilling of the Waitsia–1 and Waitsia–2 wells in 2015, and testing of Senecio-3 and Waitsia-1, confirmed the discovery of a large gas field with excellent flow characteristics. Wireline log and pressure data define a gross gas column in excess of 350 m trapped within a low-side fault closure that extends across 50 km2. The occurrence of good-quality reservoir in the depth interval 3,000–3,800 m is diagenetically controlled with clay rims inhibiting quartz cementation and preserving excellent primary porosity. Development planning for Waitsia has commenced with the likelihood of an early production start-up utilising existing wells and gas processing facilities before ramp-up to full-field development. The dry gas will require minimal processing, and access to market is facilitated by the Dampier–Bunbury and Parmelia gas pipelines that pass directly above the field. The Waitsia Field is believed to be the largest conventional Australian onshore discovery for more than 30 years and provides impetus and incentive for continued exploration in mature and frontier basins. The presence of good-quality reservoir and effective fault seal was unexpected and emphasise the need to consider multiple geological scenarios and to test unorthodox ideas with the drill bit.
24
Langhi, Laurent, Yanhua Zhang, Chris Nicholson, Nadege Rollet, George Bernardel, Richard Kempton, John Kennard, and Peter Schaubs. "Trap integrity framework for the offshore northern Perth Basin." APPEA Journal 52, no. 2 (2012): 682. http://dx.doi.org/10.1071/aj11096.
Full textAbstract:
The presence of hydrocarbon accumulations and several palaeo-oil columns in Permian reservoirs across the offshore northern Perth Basin attests to a widespread charge system and suggests that trap integrity is a critical exploration risk. The local structural evolution between the Beagle Ridge and the Wittecarra Terrace and the impact of renewed mid-Jurassic extension on a series of prospects (Cliff Head, Dunsborough, Lilac and Morangie) is assessed to define a regional trap integrity framework. The focus is on the potential development of pathways through the Early Triassic Kockatea Shale regional top seal caused by reactivation of trap bounding faults and/or interaction with newly formed overlying structures. A series of 3D geo-mechanical models are constructed to simulate the Mid-Jurassic deformation and to evaluate the first-order factors controlling the partitioning of reactivation stresses/strains and the development of seal bypass. In parallel, the local fault seal potential is assessed by focusing on the likelihood of the fault surfaces to reactivate and conduct fluid within the Jurassic stress regimes. The stress data are also used to compute the risk of reactivation in terms of the increase in pore fluid pressure required to bring a fault segment to a state of instability. The overall risk of top seal bypass is primarily driven by the reservoir-bounding faults orientation and dip. The distribution of jogs, the interactions between fault tips, the fault density, the location of regional major fault, the fault propagation mechanisms and top seal brittleness also control locally the integrity of the top seal.
25
Torghabeh, Amir Karimian, Reza Rezaee, Reza Moussavi Harami, and Nuno Pimentel. "Unconventional resource evaluation: Kockatea Shale, Perth Basin, Western Australia." International Journal of Oil, Gas and Coal Technology 8, no. 1 (2014): 16. http://dx.doi.org/10.1504/ijogct.2014.064420.
Full text
26
Bernecker, Thomas, Steve Abbott, George Bernardel, Megan Lech, Ryan Owens, Tegan Smith, and Jennifer Totterdell. "The 2017 offshore acreage release areas: petroleum geological overview." APPEA Journal 57, no. 2 (2017): 304. http://dx.doi.org/10.1071/aj16029.
Full textAbstract:
In 2017, 21 new offshore petroleum exploration areas have been released. The majority of the areas are located along the North West Shelf spanning the Westralian Superbasin from the Bonaparte Basin in the north-east to the Northern Carnarvon Basin in the south-west. New areas have been released in offshore south-eastern Australia with new opportunities provided in the Otway, Bass and Gippsland basins. Two large areas in the northern Perth Basin, an offshore frontier, complete the 2017 Acreage Release. All Release Areas are supported by industry nominations and one new cash bid area has been offered in the Dampier Sub-basin. 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. A new regional 2D seismic survey was acquired in the Houtman Sub-basin of the Perth Basin, forming the basis of the latest prospectivity study carried out by Geoscience Australia. The results of the study are presented in the technical program of the 2017 APPEA conference. A wealth of seismic and well data, submitted under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGSSA) are made available through the National Offshore Petroleum Information Management System (NOPIMS). Additional datasets are accessible through Geoscience Australia’s data repository.
27
Bailey, Adam, Rosalind King, and Guillaume Backé. "Integration of structural, stress, and seismic data to define secondary permeability networks through deep-cemented sediments in the Northern Perth Basin." APPEA Journal 52, no. 1 (2012): 455. http://dx.doi.org/10.1071/aj11036.
Full textAbstract:
Understanding natural fracture networks has increasingly been recognised as an important factor for the prospectivity of a geothermal play, as they commonly exert a prime control over permeability at depth. The onshore Northern Perth Basin provides a good example of how fracture stimulation, and subsequent enhancement of the structural permeability, during hydrocarbon production can enhance flow rate from original tight gas reservoirs. Low primary porosity and permeability values have been initially recorded in the Northern Perth Basin due to silica-rich groundwater infiltration and consequent quartz cementation. Geothermal energy prospectivity in the region will therefore depend heavily on similar engineering techniques or on the presence of secondary permeability due to interconnected natural fractures. The existence and extent of these natural fractures are verified in this study through an integrated analysis of geophysical logs (including wellbore image logs), wells tests, and 3D seismic data. Wellbore image logs from 11 petroleum wells in the Northern Perth Basin are used to identify borehole failure (such as borehole breakout and drilling-induced tensile fractures) to give a present-day maximum horizontal stress orientation of N076°E (with an s.d. of 13°). Density logs and leak off tests from 13 petroleum wells are used to constrain the present-day stress magnitudes, giving a transitional strike-slip fault to reverse-fault stress regime in the Northern Perth Basin. 870 fractures are identified in image logs from 13 petroleum wells in the Northern Perth Basin, striking roughly north to south and northwest to northeast. Fractures aligned in the present-day stress field are optimally oriented for reactivation, and are hence likely to be open to fluid flow. Electrically resistive and conductive natural fractures are identified on the wellbore image logs. Resistive fractures are considered to be cemented with electrically resistive cement (such as quartz or calcite) and thus closed to fluid-flow. Conductive fractures are considered to be uncemented and open to fluid-flow, and are thus important to geothermal exploration. Fracture susceptibility diagrams constructed for the identified fractures illustrate that the conductive fractures are optimally oriented for reactivation in the present-day strike-slip fault to reverse-fault stress regime, and so are likely to be open to fluid flow. This is reinforced by the correlation of drilling fluid loss and conductive natural fractures in three wells in the Northern Perth Basin. To gain an understanding of the extent and interconnectedness of these fractures, it is necessary to look at more regional data, such as 3D seismic surveys. It is, however, well-documented that fault and fracture networks like those generally observed in image logs lie well below seismic amplitude resolution, making them difficult to observe directly on amplitude data. Seismic attributes can be calculated to provide some information on sub-seismic scale structural and stratigraphic features. Using a 3D seismic cube acquired over the Dongara North gas field, attribute maps of complex multi-trace dip-steered coherency and most positive curvature were used to document the presence of natural fractures and to best constrain the likely extent of the fracture network. The resulting fracture network model displays relatively good connectivity, which is likely to extend across much of the basin. These optimally oriented fractures are therefore likely to form a secondary permeability network throughout the cemented sediments of the Northern Perth Basin, offering potential deep fluid flow conduits, which may be exploited for the production of geothermal energy.
28
Falvey, D. A., P. A. Symonds, J. B. Colwell, J. B. Willcox, J. F. Marshall, P. E. Williamson, and H. M. J. Stagg. "AUSTRALIA'S DEEPWATER FRONTIER PETROLEUM BASINS AND PLAY TYPES." APPEA Journal 30, no. 1 (1990): 239. http://dx.doi.org/10.1071/aj89015.
Full textAbstract:
Vast areas of Australia's continental margin sedimentary basins lying seawards of the 200 m water depth line, or shelf edge, are under-explored for petroleum. Indeed, most are essentially unexplored. However, recent advances in drilling and production technology, as well as recent reconnaissance seismic, geochemical, geothermal and seabed sampling data collected by the Bureau of Mineral Resources' (BMR) Marine Division, may reduce the perceived economic risk of many of these deepwater basins relative to their shelf counterparts. Triassic reefs have been identified off the northern Exmouth Plateau and possibly in the deepwater Canning Basin, locally within a predicted oil window. In the deepwater North Perth Basin, major wrench structures have been identified. The deepwater areas of the Great Australian Bight and Otway Basin are actually the main depocentres of a major basin complex lying along the almost totally unexplored southern Australian continental margin. The Latrobe Group in the outer Gippsland Basin is likely to have similar geology to the well explored and productive shelf basin, but remains untested. The Queensland and Townsville troughs, in deepwater off northeast Australia, contain many significant structures typical of unbreached rift systems.All these areas have been risked relative to each other and their prospectivity assessed. The most attractive frontier areas in terms of relative risk may be the Otway and North Perth basins. The highest potential may occur in the deepwater rift troughs off northeast Australia, although the relative risk is very high. Triassic reefs of the Northwest Shelf may have the best prospectivity in the shorter term, given that they are known from drilling in a region with proven source potential and a substantial exploration infrastructure.
29
Liu, Shanyin, Paul Lennox, and Nigel T. Jones. "Structure styles and tectonic evolution of the Abrolhos Sub-Basin, Perth Basin, Western Australia." ASEG Extended Abstracts 2010, no. 1 (December 2010): 1. http://dx.doi.org/10.1081/22020586.2010.12041836.
Full text
30
Martin, Robert, Brett Harris, and David Schafer. "Airborne TEM for the recovery of basin scale solute distribution; Perth Basin, Western Australia." ASEG Extended Abstracts 2012, no. 1 (December 2012): 1–5. http://dx.doi.org/10.1071/aseg2012ab177.
Full text
31
Bergmark, S. L., and P. R. Evans. "GEOLOGICAL CONTROLS ON RESERVOIR QUALITY OF THE NORTHERN PERTH BASIN." APPEA Journal 27, no. 1 (1987): 318. http://dx.doi.org/10.1071/aj86026.
Full textAbstract:
The major onshore Dongara gas field and a number of adjacent minor gas and oil pools are reservoired in basal Triassic sandstones that are sealed by the overlying Kockatea Shale. Reservoir quality is found to be controlled primarily by the local provenance of the sandstones, by diagenesis and the regional palaeotopography. Sandstones east of Dongara are reworked products of a Late Permian fan delta (Wagina Sandstone) that extended westwards from the basin's eastern, fault controlled margin. Localised high energy streams drained the palaeoslope, depositing thin wedges of mainly fluvial sediments upon and around the flanks of the Permian fan delta during a regional rise in sea level in the Early Triassic. Sandstones to the north of Dongara are localised, low energy offshore bars and strandline deposits derived from Precambrian of the Northampton Block. Diagenetic alterations of the Triassic sandstones, also controlled by the sandstones' provenance, have substantially reduced primary porosity and control permeability. The common presence of the authigenic clay mineral, dickite, is taken as evidence that a fluvial environment of deposition controlled formation of the reservoir rocks.
32
Harris, L. B. "STRUCTURAL AND TECTONIC SYNTHESIS FOR THE PERTH BASIN, WESTERN AUSTRALIA." Journal of Petroleum Geology 17, no. 2 (April 1994): 129–56. http://dx.doi.org/10.1111/j.1747-5457.1994.tb00123.x.
Full text
33
Iasky, R. P., R. A. Young, and M. F. Middleton. "Structural Study of the Southern Perth Basin by Geophysical Methods." Exploration Geophysics 22, no. 1 (March 1991): 199–205. http://dx.doi.org/10.1071/eg991199.
Full text
34
Iasky, R. P., and A. J. Mory. "Structural and Tectonic Framework of the Onshore Northern Perth Basin." Exploration Geophysics 24, no. 3-4 (September 1993): 585–92. http://dx.doi.org/10.1071/eg993585.
Full text
35
Johnston, Stephen, and Peter Petkovic. "Depth to magnetic sources in the offshore northern Perth Basin." ASEG Extended Abstracts 2012, no. 1 (December 2012): 1–4. http://dx.doi.org/10.1071/aseg2012ab274.
Full text
36
Warris, B. J. "THE GEOLOGY OF THE MOUNT HORNER OILFIELD, PERTH BASIN, WESTERN AUSTRALIA." APPEA Journal 28, no. 1 (1988): 88. http://dx.doi.org/10.1071/aj87009.
Full textAbstract:
The Mount Horner oilfield is located 30 km east of the town of Dongara, some 360 km north of Perth, Western Australia. It was discovered by WAPET in 1965 but it was not until 1980-81 that a further four appraisal wells were drilled on the field. One additional appraisal well was drilled in 1987.The structure consists of a tilted fault block downthrown to the east with a roll-over anticline on the downthrown side of the fault. Sandstones within the Lower Triassic Kockatea Shale produced oil in 1965 from Mount Horner No. 1 on the upthrown tilted fault block. This well was eventually plugged and abandoned due to the low productivity of the reservoirs and the then prevailing low oil price. Production also occurred in the Basal Triassic Sandstone on the downthrown side of the fault. Mount Horner Nos 4 and 5 produced from this horizon from 1984 to 1986, when they were shut in due to increasing water cut.At the top of the Lower to Middle Jurassic Cockleshell Gully Formation, a complex transition zone exists between the fluvial sandstones of the Cattamarra Coal Measures Member and the marine sediments of the Champion Bay Group. Sandstones in this transition zone produce oil from Mount Horner No. 5 which was re-completed in 1986 and from No. 7 which was drilled in 1987.There are four distinct oil pools on the Mount Horner structure. Geochemical and maturation studies have shown that the bulk of the reserves was generated from the basal part of the Kockatea Shale and has migrated up the main fault and into the Jurassic reservoirs.Recent workover and appraisal drilling programs on the field have established the first commercial oil production from Jurassic sediments in the Perth Basin. This opens up an exciting new exploration play in the northern Perth Basin.
37
Warris, B. J. "THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA." APPEA Journal 33, no. 1 (1993): 123. http://dx.doi.org/10.1071/aj92010.
Full textAbstract:
There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.
38
Tinapple, Bill. "Australian states and Northern Territory acreage update at APPEA 2011." APPEA Journal 51, no. 1 (2011): 79. http://dx.doi.org/10.1071/aj10004.
Full textAbstract:
Bill’s presentation is on behalf of the NT, Queensland, NSW, Victoria, SA and WA. Some highlights are: • NT: 24 onshore exploration applications were received in 2010 (an increase of 50 % from 2009). About 479,100 sq km of the NT is now under application, including grassroots areas. • Queensland: In 2011, a variety of exploration opportunities are being offered in basins ranging in age from Precambrian to Cretaceous. Targets include conventional oil and gas as well as shale gas. • NSW: There are now more than 800 unallocated petroleum exploration blocks, including the Darling Basin, the Tamworth Moratorium area, and the Oaklands Basin Moratorium area. • Victoria: Acreage release is proposed for the onshore Otway Basin in 2011. • SA: The CO2010 acreage release, comprising three blocks in the Cooper and Eromanga basins, closed on 10 March 2011. • WA: To coincide with the APPEA Conference, acreage has been made available for bidding from the Canning Basin, Northern Carnarvon Basin, Officer Basin and Perth Basin.
39
Bradshaw, Marita. "Review of the 2008 offshore petroleum exploration release areas." APPEA Journal 48, no. 1 (2008): 359. http://dx.doi.org/10.1071/aj07025.
Full textAbstract:
Each year the Australian Government releases new offshore opportunities for petroleum exploration. Thirty-five new exploration areas located across five of Australia’s offshore sedimentary basins are offered in the 2008 Release. All the areas are available through a work program bidding system with closing dates for bids at six and 12 months from the date of release. Acreage in the first round closes on 9 October 2008 and includes the more explored areas. The second closing round on 9 April 2009 comprises acreage located in less well explored and frontier regions. The 2008 exploration areas are in Commonwealth waters offshore of Western Australia and the Northern Territory, and in the Territory of the Ashmore and Cartier Islands adjacent area. The 2008 Release focusses on the North West Shelf, as well as offering two new exploration areas in the Vlaming Sub-basin in the offshore Perth Basin. Seven of the new release areas are located in Australia’s major hydrocarbon producing province, the Carnarvon Basin. They include a shallow water area in the western Barrow Sub-basin and another on the Rankin Platform, three areas in deeper water in the Exmouth Sub-basin and two on the deepwater Exmouth Plateau. Six areas are available for bidding in the Browse Basin and another five in the Bedout Sub-basin of the Roebuck Basin. In the Bonaparte Basin, the 15 Release areas are located in shallow water and represent a range of geological settings, including the Vulcan and Petrel sub-basins, Ashmore Platform and Londonderry High. The 2008 Offshore Petroleum Exploration Release of 35 areas in five basins covers a wide range in size, water depth and exploration maturity to provide investment opportunities suited to both small and large explorers. The Release areas are selected from nominations from industry, the States and Territory, and Geoscience Australia. The focus of the 2008 Release is on the North West Shelf where there is strong industry interest in the producing Carnarvon and Bonaparte basins and in the Browse Basin, the home of super-giant gas fields under active consideration for development. Also included in the 2008 Release is the Bedout Sub-basin, in the Roebuck Basin, located on the central North West Shelf, between the hotly contested Carnarvon and Browse basins. In addition, the Release show-cases the southern Vlaming Sub-basin, Perth Basin, where recent studies by Geoscience Australia provide a new understanding of petroleum potential (Nicholson et al, this volume).
40
Cockerill, Ian. "PESA Australian exploration review 2019." APPEA Journal 60, no. 2 (2020): 348. http://dx.doi.org/10.1071/aj20007.
Full textAbstract:
Australia has continued its recent run of exploration success by yielding a series of impressive discoveries in 2019, despite a contraction in exploration activity. In 2019, Australian explorers were rewarded with six conventional onshore discoveries and three offshore discoveries, while only drilling 20 exploration wells. The exploration drilling highlights were the discoveries in the Vulcan Sub-basin (Bratwurst and Orchid) and the North Perth Basin (Beharra Springs Deep and West Erregulla). 2019 also saw successful appraisal drilling on the Dorado and Corvus discoveries as well as renewed exploration efforts in the Beetaloo Sub-basin unconventional plays. The exploration farm-in deals of note were Santos farming into Armour’s South Nicholson Basin acreage and Conoco farming into 3D Oil’s Otway Basin acreage. Australia is set for an exciting year of exploration with further drilling planned in the North Perth Basin and other high impact exploration wells on the North West Shelf. In a positive sign for future exploration, 13 new offshore permits were awarded with committed work programs or cash bids totalling AU$223 million. This is the first uptick in offshore permit awards since 2010.
41
Gaull, Brian A., Hiroshi Kagami, and Hitoshi Taniguchi. "The Microzonation of Perth, Western Australia, Using Microtremor Spectral Ratios." Earthquake Spectra 11, no. 2 (May 1995): 173–91. http://dx.doi.org/10.1193/1.1585810.
Full textAbstract:
This paper indicates new microzonation maps of Perth, Western Australia, utilising microtremor spectral ratios. This metropolitan area has been developing in recent times on Perth Basin which is one of the most active seismic zones in the country. The authors carried out simultaneous measurings of microtremors over most of metropolitan Perth, using a 3 km grid as a basis and hard rock reference site throughout. They calculated spectral ratios of microtremors at deposit site to rock reference site and plotted and contoured on maps for 6 frequency bands from 0.2 to 5.0 Hz. Spectral ratio contours appeared to correlate well with various geological subsurface contours. They also showed that previously estimated earthquake risk estimates underestimated ground motions by up to a factor of two.
42
Hall, Lisa, Emmanuelle Grosjean, Irina Borissova, Chris Southby, Ryan Owens, George Bernardel, and Cameron Mitchell. "Petroleum systems analysis of the northern Houtman Sub-basin." APPEA Journal 57, no. 2 (2017): 755. http://dx.doi.org/10.1071/aj16026.
Full textAbstract:
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.
43
Thomas, B. M., and C. J. Barber. "A RE-EVALUATION OF THE HYDROCARBON HABITAT OF THE NORTHERN PERTH BASIN." APPEA Journal 44, no. 1 (2004): 59. http://dx.doi.org/10.1071/aj03002.
Full textAbstract:
Recent oil discoveries at Hovea, Cliff Head, Jingemia and Eremia have challenged the perception that the northern Perth Basin is largely gas prone and renewed interest in the identification of oil source rocks in the succession. A major geochemical reassessment of all units from the Middle Triassic to the base of the Permian shows that the principal oil prone source rocks are restricted to a discrete zone within the basal Kockatea Shale, the Sapropelic Interval of the Hovea Member (defined herein). The source zone, typically 10–40 m thick, is laterally continuous over much of the onshore northern Perth Basin. It immediately overlies the Permian-Triassic boundary and may form part of a global anoxic event. These are some of the best oil source rocks ever identified in Australia. A combination of diagnostic biomarkers and compound specific isotopic data consistently link the Hovea Member source rocks to all oils analysed from the northern Perth Basin. Gas prone source rocks are developed at several levels in the Permian, and particularly in the Irwin River Coal Measures. In most areas of the basin, oil charge from the Triassic is in direct competition with any gas generated from the Permian, as seen in the large Warradong Kitchen, southeast of the Dongara Field. This has resulted in a predominance of gas discoveries, often with a thin oil leg. The smaller but oil prone Jingemia Kitchen, southwest of Dongara, has sourced the recent oil discoveries at Hovea, Jingemia and Eremia. There is evidence that the Hovea Member source rocks are also widely distributed offshore in the Abrolhos Sub-basin where they appear to have sourced the Cliff Head oil discovery and strong oil shows in Morangie–1 and Livet–1, some 300 km northwest of Dongara.
44
Bernecker, Thomas. "Geological overview of the 2011 offshore acreage release for petroleum exploration." APPEA Journal 51, no. 1 (2011): 7. http://dx.doi.org/10.1071/aj10002.
Full textAbstract:
The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. In 2011, 29 areas in eight offshore basins are being released for work program bidding. Closing dates for bid submissions are either six or 12 months after the release date (i.e. 13 October 2011 and 12 April 2012)–this depends on the exploration status in these areas and on data availability. The 2011 Release is the largest since the year 2000 with all 29 areas located in Commonwealth waters offshore NT, WA, Victoria and Tasmania, covering about 200,000 km2. The producing hydrocarbon provinces of the Carnarvon, Otway and Gippsland basins are represented by gazettal blocks that are located close to existing infrastructure and are supported by extensive open file data-sets. Other areas that are close to known oil and gas discoveries lie in the Caswell Sub-basin (eastern Browse Basin) and on the Ashmore Platform (northwestern Bonaparte Basin). A particular aspect of the 2011 release is provided by 13 areas in under-explored regions offshore NT and WA–all of which range from 100–280 graticular blocks in size. These areas, located in the Money Shoal, outer Browse, Roebuck, northeastern Carnarvon, Southern Carnarvon and North Perth basins, offer new opportunities for data-acquisition and regional exploration. The release of three large areas in the Southern Carnarvon and North Perth basins is supported by new data acquired and interpreted by Geoscience Australia as part of the Offshore Energy Security Program, which selected results are being presented at this year’s conference.
45
Wan, X., V. Rasouli, B. Damjanac, and H. Pu. "Lattice simulation of hydraulic fracture containment in the North Perth Basin." Journal of Petroleum Science and Engineering 188 (May 2020): 106904. http://dx.doi.org/10.1016/j.petrol.2020.106904.
Full text
46
Ahmad, Abualksim, Reza Rezaee, and Vamegh Rasouli. "Significance of compressional tectonic on pore pressure distribution in Perth Basin." Journal of Unconventional Oil and Gas Resources 7 (September 2014): 55–61. http://dx.doi.org/10.1016/j.juogr.2014.01.001.
Full text
47
King, R. C., R. R. Hillis, and S. D. Reynolds. "In situstresses and natural fractures in the Northern Perth Basin, Australia." Australian Journal of Earth Sciences 55, no. 5 (July 2008): 685–701. http://dx.doi.org/10.1080/08120090801982843.
Full text
48
Lambeck, Kurt. "The Perth Basin: a Possible Framework For its Formation and Evolution." Exploration Geophysics 18, no. 1-2 (March 1, 1987): 124–28. http://dx.doi.org/10.1071/eg987124.
Full text
49
Dentith, M. C., I. Bruner, A. Long, M. F. Middleton, and J. Scott. "Structure of the Eastern Margin of the Perth Basin, Western Australia." Exploration Geophysics 24, no. 3-4 (September 1993): 455–61. http://dx.doi.org/10.1071/eg993455.
Full text
50
Leven, James, and Mike Middleton. "Near-surface seismic expression of gas chimneys in the Perth Basin." ASEG Extended Abstracts 2007, no. 1 (December 1, 2007): 1–4. http://dx.doi.org/10.1071/aseg2007ab074.
Full text