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1
Kalinowski, Aleksandra, Eric Tenthorey, Mojtaba Seyyedi und Michael Ben Clennell. „The search for new oil and CO“. APPEA Journal 62, Nr. 1 (13.05.2022): 281–93. http://dx.doi.org/10.1071/aj21077.
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Residual oil zones (ROZs) could present a new, potentially large and commercially viable oil resource for Australia and provide an avenue for geological storage of carbon dioxide (CO2) through CO2 enhanced oil recovery (CO2-EOR). These reservoirs, which can contain a moderate amount of residual oil and resemble water-flooded oil fields, can be associated with conventional fields (brownfields) or occur with no associated main pay zone (greenfields). Both types of ROZ are currently produced commercially through CO2-EOR in the Permian Basin, USA, and are of growing interest internationally, but our understanding of the occurrence and economic viability of oil production from ROZs in Australia is limited. We are employing geological and petrophysical methods to identify, map and quantify the potential oil resources of ROZs, initially in central Australian basins. Complementing this, we are conducting a series of CO2 core-flooding experiments combined with reservoir modelling to investigate the techno-economic feasibility of producing oil and storing CO2 in these formations. We aim to establish and test a workflow for characterising and evaluating ROZs in Australia. ROZs could prove to be good targets for CO2-EOR+, potentially even producing carbon-neutral or carbon-negative oil by using CO2 from anthropogenic sources, such as from blue hydrogen production.
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Loro, Richard, Robin Hill, Mark Jackson und Tony Slate. „Technologies that have transformed the Exmouth into Australia“. APPEA Journal 55, Nr. 1 (2015): 233. http://dx.doi.org/10.1071/aj14018.
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The oil and gas fields of the Exmouth Sub-basin, offshore WA, have presented a number of significant challenges to their exploitation since the first discoveries of heavy oil and lean gas were made in the late 1980s and early 1990s. Presently, some 20 oil and gas fields have been discovered in a variety of Late Jurassic to Cretaceous clastic reservoirs from slope turbidites to deltaic sands. Discovered oils are typically heavily biodegraded with densities ranging from 14–23° API and moderate viscosity. Seismic imaging is challenging across some areas due to pervasive multiples and gas escape features, while in other areas resolution is excellent. Most reservoirs are poorly cemented to unconsolidated and thus require sand control. Modest oil columns, most with gas caps, and variable permeability, present challenges for both maximising oil recovery and minimising the influx of water and gas. Oil-water emulsions also present difficulties for both maximising oil rate and metering production. To date, more than 300 MMbbls have been produced from five developments (Enfield, Stybarrow, Vincent, Van Gogh and Pyrenees), and in 2013 the Macedon gasfield began production. This peer-reviewed paper focuses on the variety of technologies—geoscience, reservoir, drilling and production—that have underpinned the development of these challenging fields and in doing so, transformed the Exmouth into Australia’s premier oil producing basin.
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Slate, Tony, Ralf Napalowski, Steve Pastor, Kevin Black und Robert Stomp. „The Pyrenees development: a new oil development for Western Australia“. APPEA Journal 50, Nr. 1 (2010): 241. http://dx.doi.org/10.1071/aj09014.
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The Pyrenees development comprises the concurrent development of three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin. The development will be one of the largest offshore oil developments in Australia for some time. It is a complex subsea development consisting of a series of manifolds, control umbilicals and flexible flowlines tied back to a disconnectable floating production, storage and offloading (FPSO) vessel. The development involves the construction of 17 subsea wells, including 13 horizontal producers, three vertical water disposal wells and one gas injection well. The project is presently on production with first oil achieved during February 2010. This paper gives an overview of the field development and describes the engineering and technologies that have been selected to enable the economic development of these fields. The Pyrenees fields are low relief, with oil columns of about 40 metres in excellent quality reservoirs of the Barrow Group. Two of the fields have small gas caps and a strong bottom water drive common to all fields is expected to assist recovery. The oil is a moderate viscosity, low gas-to-oil ratio (GOR), 19°API crude. Due to the geometry of the reservoirs, the expected drive mechanism and the nature of the crude, effective oil recovery requires maximum reservoir contact and hence the drilling of long near horizontal wells. Besides the challenging nature of well construction, other technologies adopted to improve recovery efficiency and operability includes subsea multiphase flow meters and sand control with inflow control devices.
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Miyazaki, S. „CHARACTERISATION OF AUSTRALIA'S OIL FIELDS BY FLUID AND RESERVOIR PROPERTIES AND CONDITIONS“. APPEA Journal 29, Nr. 1 (1989): 287. http://dx.doi.org/10.1071/aj88025.
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An extensive data compilation of reservoir rock and fluid properties, and temperature and pressure conditions, in Australia's oil fields, has provided regional information on the nature of crude oil accumulations. It has also allowed the determination of systematic trends and regional variations. These trends and variations are depicted in cross- plots of porosity against depth, porosity against permeability, temperature against depth, pressure against depth, oil gravity against depth, and formation- water salinity against depth.Offshore oil reservoirs, principally based on Gippsland Basin data, are of better quality than onshore ones, even after the porosity cut- off effect is taken into consideration. The Eromanga and Cooper Basins have a higher heat flow than other basins containing oil fields. Pressure trends are consistent with the low salinity nature of formation waters. In Australia, oil reservoirs have an average depth of 1500 m sub- sea and an average temperature of 90°C, and crude oils are light, with an average gravity of 45° API.Interpretation of systematic trends and regional variations can facilitate prospect evaluation by predicting the most likely reservoir qualities and conditions and the fluid properties in potential drilling targets.
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Craig, Adam, Stephen Newman, Peter Stephenson, Chris Evans, Shaun Yancazos und Simon Barber. „Hydrogen storage potential of depleted oil and gas fields in Western Australia“. APPEA Journal 62, Nr. 1 (13.05.2022): 185–95. http://dx.doi.org/10.1071/aj21146.
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The global subsurface hydrogen storage industry is at an embryonic stage and is currently dominated by a handful of manufactured salt caverns worldwide. There are currently no known depleted oil or gas fields used to store pure hydrogen, although there are examples of hydrogen and natural gas mixtures. The Government of Western Australia has developed a renewable hydrogen strategy with a vision for Western Australia becoming a significant producer, exporter and user of renewable hydrogen. An element of the strategy and roadmap includes the possibility of utilising depleted oil and gas fields for transitory geological storage of hydrogen. The physical characteristics of hydrogen are quite different to natural gases and a number of potential loss mechanisms need to be considered for transitory geological storage. Currently, 30 renewable energy projects with associated hydrogen generation are proposed or being considered in Western Australia. It is assumed that some, if not all, of these projects may require transitory geological storage of hydrogen. An assessment of the required storage potential has been made and 23 onshore depleted oil and gas fields of the onshore northern Perth Basin and Carnarvon Basin were screened for their suitability to satisfy the storage requirements of a renewable hydrogen industry. Seven fields were then selected as suitable candidates for transitory hydrogen geological storage sites.
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Ronalds, B. F. „SHARED INFRASTRUCTURE: A COST-EFFECTIVE DEVELOPMENT STRATEGY FOR SMALLER FIELDS OFFSHORE AUSTRALIA?“ APPEA Journal 44, Nr. 1 (2004): 569. http://dx.doi.org/10.1071/aj03025.
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B.F. RonaldsFuture oil discoveries offshore Australia are unlikely to be large fields that can support the development of a one-off self-sufficient facility. Fixed platforms are generally only feasible in shallow water when the water depth (in metres) to well count ratio d/w The construction and ongoing re-use of a generic FPSO suited to Australasian field conditions might be of considerable assistance in monetising small oil fields in deeper water. Similarly, aptly located, designed and operated gas hubs could open up large areas for satellite gas development long into the future, aided by new technology to enable ultra-long tiebacks. Both approaches suggest the benefit of overlaying a regional perspective on the oil companies’ field-specific development philosophy.
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Wilmshurst, Jan. „USE OF DRAG REDUCER CHEMICAL IN THE BASS STRAIT CRUDE OIL PRODUCING SYSTEM“. APPEA Journal 25, Nr. 1 (1985): 119. http://dx.doi.org/10.1071/aj84010.
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Esso Australia Ltd (on behalf of the Esso/BHP joint venture) operates a crude oil and natural gas processing system based on the offshore fields in Bass Strait.Crude oil is discharged from the offshore fields via a 132-km pipeline to the crude stabilization plant at Longford. A 187-km pipeline is then used to transfer stabilized crude to Long Island Point, where the oil is held in storage prior to discharge to Australian refineries and to export.Without the use of drag reducer chemical, Bass Strait crude production is limited by pipeline hydraulic capacity. Since the last quarter of 1983, drag reducer has been injected at both Halibut platform and Longford as required to meet the demand for crude oil. As a result, daily production rates have been increased by more than ten per cent.Drag reducer chemical is a long chain polymer which acts to reduce the extent of turbulence in the flowing oil stream. The chemical is highly viscous, and specifically designed gear pumps are required to achieve satisfactory injection into the pipeline systems.
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Powell, T. G. „UNDERSTANDING AUSTRALIA’S PETROLEUM RESOURCES, FUTURE PRODUCTION TRENDS AND THE ROLE OF THE FRONTIERS“. APPEA Journal 41, Nr. 1 (2001): 273. http://dx.doi.org/10.1071/aj00013.
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Relative to its needs over the last 30 years, Australia has enjoyed a high level of self-sufficiency. Whilst the overall remaining reserves of oil have been relatively constant, reserves of condensate have grown substantially as major reserves of natural gas have been added to Australia’s resource inventory. Oil and condensate reserves stand at 3.43 billion barrels (505 GL), of which 50% is condensate in gas fields. Australia’s undiscovered oil potential in its major offshore hydrocarbon producing basins has been upgraded to an indicative 5 billion barrels (800 GL) at the average expectation, following evaluation of the assessment results for Australia in the authoritative worldwide assessment of undiscovered potential by the US Geological Survey.Current reserves, however, are insufficient to sustain present levels of production in the medium term. Estimates of future production of oil and condensate suggest that at the mean expectation, production rates will drop by around 33% by 2005 and 50% by 2010, largely as a result of a decline in oil production. This forecast includes production from fields that have not yet been discovered. Condensate production will continue to grow, but the rate of growth is constrained by gas production rates and overall by the development timetable for the major gas fields.The rate of discovery of new oil fields is insufficient to replace the oil reserves that are being produced. If Australia is to maximise the opportunity to maintain production at similar levels to the recent past, it is probable that exploration effort will have to diversify to the frontier basins to locate a new oil province whilst continuing to explore the full potential of the known hydrocarbon-bearing basins. Australia still has a remarkable number of basins which have received little or no exploration. Whilst there is no substitute for a discovery to stimulate exploration in poorly known areas, demonstrating that petroleum has been generated and migrated is the key to attracting continued exploration interest.
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Bagheri, Mohammad B., Matthew Wallace, Vello Kuuskraa, Hadi Nourollah, Matthias Raab und Tim Duff. „CO“. APPEA Journal 62, Nr. 2 (13.05.2022): S372—S377. http://dx.doi.org/10.1071/aj21144.
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This paper discusses the potential for storing CO2 and producing lower carbon intensity oil from onshore oil fields in the Cooper and Surat basins of South Australia and Queensland. A comprehensive database was compiled for the oil fields in the basins above, including the key required data to assess the potential of the basins for CO2 enhanced oil recovery (EOR). The South Australia and Queensland oil field databases contain 140 reservoirs with a combined original oil in-place of 1497 million barrels. These reservoirs have, to date, produced a total of 382 million barrels, with 458 million barrels of expected ultimate recovery (EUR). The database was compiled with support from Santos, Bridgeport, and Beach Energy. These reservoirs were screened further based on their size and pressure. The next step was to model the application of a CO2 flood in each of the shortlisted reservoirs using the CO2 EOR Prophet model developed by Advanced Resources International. The modelling showed that joint implementation of CO2 storage and CO2 EOR would allow the Cooper and Surat basins to store 116–158 million metric tons of CO2 and produce 248–518 million barrels of additional oil. Creating hubs and clustering fields based on their geographical location helps to reduce the cost of infrastructure and CO2 transportation. Therefore, the reservoirs in this study, were grouped and anchored to the most dominant oil reservoir that has the largest CO2 storage and EOR capacity. The results of the clusters are summarised in this paper.
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Tucker, David H., Ross Franklin, N. Sampath und Stan Ozimic. „Review of airborne magnetic surveys over oil and gas fields in Australia“. Exploration Geophysics 16, Nr. 2-3 (Juni 1985): 300–302. http://dx.doi.org/10.1071/eg985300.
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Farrell, Bradley. „Remote Operations Centres – what next?“ APPEA Journal 57, Nr. 2 (2017): 440. http://dx.doi.org/10.1071/aj16115.
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Integrated Operations (IO) is a well-established concept in oil and gas. In Australia, upstream oil & gas operators have made significant investments in their local IO capability. For many operators this has meant the creation of a dedicated Remote Operations Centre for their new LNG production assets. By ‘Remote Operations Centre’ (or ‘ROC’) we mean a purpose-built facility where multi-disciplinary teams work together to monitor, support or control production fields and/or assets; with the ROC being geographically distant from those fields/assets. For operators with new LNG facilities, a key challenge has been implementing their ROCs while also focusing on completion of their large complex asset builds. As a consequence, there is an opportunity for further development of Australian ROCs, post start-up, to capture greater value from the new producing assets. For the established LNG operators, rapid advances in collaboration techniques, and in data management and visualisation, present new opportunities to augment their legacy ROCs. In this paper we examine leading practices from ROCs worldwide along with lessons learned that are relevant for Australian operators. We conclude by asking ‘what next?’ for Australian operators.
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McNicoll, Russell. „HORIZONTAL DRILLING IN AUSTRALIA: THREE CASE HISTORIES“. APPEA Journal 31, Nr. 1 (1991): 354. http://dx.doi.org/10.1071/aj90027.
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Three horizontal wells with horizontal sections of up to 331 m were drilled successfully during the development of the marginal North Herald and South Pepper oil and gas fields, which have relatively thin oil columns (6 to 12 m) at a depth of some 1200 m sub-sea. A steerable motor system was used to maintain directional control within the design parameters. This system proved to be successful from the start and no major changes to the bottom hole assembly design were required to drill all the wells. Average drilling time including running and setting the seven inch liner amounted to 12 days. The wells were tested with rates up to 7500 BOPD through a one inch choke.
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Bint, A. N. „DISCOVERY OF THE WANAEA AND COSSACK OIL FIELDS“. APPEA Journal 31, Nr. 1 (1991): 22. http://dx.doi.org/10.1071/aj90003.
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Exploration of the Dampier Sub-basin on the North West Shelf of Australia commenced with a reconnaissance seismic survey in 1965. In 1969 Madeleine-1, the first well drilled on the Madeleine Trend, encountered water bearing Upper Jurassic sandstones. Following acquisition of a regional grid of modern seismic in 1985 and 1986, and comprehensive hydrocarbon habitat studies, the Wanaea and Cossack prospects were matured updip from Madeleine 1. They were proposed to have improved reservoir development and an oil charge.The Wanaea Oil Field was discovered in 1989 when Wanaea-1 encountered a gross oil column of 103 m in the Upper Jurassic Angel Formation. The well flowed 49° API oil at 5856 BPD (931 kL/d) with a gas-oil ratio of 1036 SCF/STB. Two appraisal wells were drilled in the field in 1990.The Cossack Oil Field was discovered in 1990 when Cossack-1 encountered a gross oil column of 54 m also in the Angel Formation. The oil-water contact is 18 m deeper than in Wanaea-1. Cossack-1 flowed 49° API oil at 7200 BPD (1145 kL/d) with a gas-oil ratio of 98 SCF/STB.The Angel Formation reservoir consists of mass flow sandstones interbedded with bioturbated siltstones. Sandstone porosities average 16 to 17 per cent for both the Wanaea and Cossack Fields. Permeabilities average about 300 mD at Wanaea and about 500 mD at Cossack.An extensive 3-D seismic survey was conducted over the Wanaea and Cossack Fields in 1990. Final reserves calculations await interpretation of this survey, but it is clear that the combined Wanaea and Cossack oil reserve is the largest outside Bass Strait.
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Hunter, P. C. „PREPARATION AND IMPLEMENTATION OF A SAFETY MANAGEMENT SYSTEM IN BHPP“. APPEA Journal 37, Nr. 1 (1997): 657. http://dx.doi.org/10.1071/aj96046.
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BHP is a leading global resources company which comprises four main business groups: BHP Copper, BHP Minerals, BHP Steel and BHP Petroleum. BHP Petroleum (BHPP) global operations are divided into four Regions and Australia/Asia Region is responsible for exploration, production, field development and joint ventures in the Asia-Pacific region. In Australia, the Company's largest producing assets are its shares of the Gippsland oil and gas fields in Bass Strait and the North West Shelf project in Western Australia.BHPP operates three Floating Production, Storage and Offloading (FPSO) vessels-Jabiru Venture, Challis Venture and Skua Venture-in the Timor Sea and one FPSO, the Griffin Venture, in the Southern Carnarvon Basin. Stabilised oil is offloaded from all four FPSOs by means of a floating hose to a shuttle tanker. Gas from the Griffin Venture is compressed and transferred through a submarine pipeline to an onshore gas treatment plant.BHPP's Asian production comes from the Dai Hung oil field offshore Vietnam where BHPP is the operator and from Kutubu in Papua New Guinea.In Melbourne, BHPP operates a Methanol Research Plant and produced Australia's first commercial quantities of methanol in October 1994.BHPP is an extremely active offshore oil and gas explorer and has interests in a number of permits and blocks in the Australian-Indonesian Zone of Co-operation.This paper discusses BHPP's approach to safety management, both for its worldwide operations and specifically in Australia/Asia Region. It explains how BHPP's worldwide safety management model takes regional regulatory variations into account. It shows, specifically, how this has been done in Australia/Asia Region using what BHPP considers to be a best practice approach.The paper describes how BHPP Australia/Asia Region benchmarked its performance against other operators in Australia and the North Sea. It explains how the findings of the benchmarking study were used to plan the preparation of a safety management system (SMS). The structure of the SMS is described along with the legal requirements in Australia.The paper concludes that implementation of the SMS is progressing according to plan and points out that safety cases for the FPSOs have been submitted to the Regulators. Implementation of the SMS and the drive for world class safety standards is having a substantial effect and safety performance is improving. One measure of safety performance, the Lost Time Injury Frequency Rate (LTIFR) is down from around 15 at the end of 1994 to under 3 in December 1996.
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Evans, P. R. „Australia's Potential for Petroleum“. Energy Exploration & Exploitation 4, Nr. 4 (August 1986): 255–83. http://dx.doi.org/10.1177/014459878600400402.
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The viability and direction of future exploration for petroleum in Australia appear to have been set, particularly by the results of the petroleum industry's endeavours over the past four years. The limited local markets for the abundance of natural gas, with which Australian basins are characterised, will control the direction and rate of exploration for many years. Even so, the local markets for petroleum should provide a continued incentive to search for oil. The Gippsland Basin is at a mature stage of exploration, and a replacement for it is still required in order that Australia maintain its present position of supplying the bulk of its needs for crude oil into the 1990s. Sectors of the Timor Sea are the most likely areas of relatively untested continental shelf to produce the requisite large fields. The previously disregarded Mesozoic plays of the Eromanga Basin hold promise for continued small discoveries that cumulatively may provide a substantial contribution to the nation's needs. The Canning Basin is the most promising of the still generally non-productive basins, but realisation of its potential will be expensive.
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Williams, R. C. „THE CREATION AND FLOTATION OF NOVUS PETROLEUM LTD“. APPEA Journal 36, Nr. 1 (1996): 706. http://dx.doi.org/10.1071/aj95050.
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Novus Petroleum Ltd listed on the Australian Stock Exchange on 24 May 1995 having raised $157.5 million of equity. It was the largest initial public offering (IPO) of an oil company ever undertaken in Australia, and the third largest equity-raising on the Australian market during financial year 1994-5.The creation of Novus involved the creation of a team of professional advisers comprising ANZ McCaughan (broker), Indosuez Australia (financial adviser), Ernst and Young (accounting and taxation adviser), Phillips Fox (legal adviser) and Fern Consultants (technical adviser). During the period from mid 1994 to May 1995, the team identified and procured a portfolio of producing and exploration assets (including shares in over 30 oil and gas fields); negotiated sale and purchase, underwriting, loan and other necessary agreements; wrote and issued a prospectus and performed the necessary due diligence and other processes involved with a public equity offering; and marketed the stock in the new company globally.The success of the IPO is attributed to having a very clear business focus and strategy, a diverse portfolio of quality assets, a strong and experienced management team, good earnings arithmetic and a strong balance sheet. Delivery of the success is attributed to the commitment and enthusiasm of the professional team involved with the float process.
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Robertson, C. S. „AUSTRALIA'S PETROLEUM PROSPECTS: CHANGING PERCEPTIONS SINCE THE BEGINNING OF THE CENTURY“. APPEA Journal 28, Nr. 1 (1988): 190. http://dx.doi.org/10.1071/aj87016.
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Perceptions of Australia's petroleum prospectivity, both by the general public and by professional explorationists, have changed considerably over the years. By the 1920s there had already been a considerable change from the optimism of the early part of the century, engendered largely by gas and condensate indications in water bores drilled in the Roma area, to a comparatively pessimistic view due to the failure of numerous small drilling ventures, and to the published opinions of some overseas experts.The public then remained generally apathetic or pessimistic about Australia's petroleum future until the Rough Range discovery in 1953 finally dispelled the myth that Australia was barren of producible oil. Rough Range proved to be the first of a series of discoveries which significantly upgraded industry and public perceptions of Australia's petroleum potential.Other particularly significant discoveries were the Moonie oilfield in 1961, the Gidgealpa and Barracouta gas fields in 1963 and 1964, the giant King-fish and Halibut oilfields in 1967, gas/condensate and oilfields on the North West Shelf in 1971, the Strzelecki and Fortescue oilfields in 1978, and the Jabiru oilfield in 1983. Exploration of the Exmouth Plateau from the early 1970s onwards initially caused a significant increase in estimates of Australia's petroleum potential, followed by downward revisions in the early 1980s because of the failure of the Plateau to live up to expectations.Perceptions of the prospects of some individual basins have also changed dramatically with time. Notable examples are the onshore Carnarvon Basin, the Georgina Basin and the Eromanga Basin.The most significant change in methods of assessing Australia's prospectivity was the introduction of quantitative, probabilistic methods in the 1970s. BMR's current assessment is that we can expect to find an additional 2 400 million barrels of oil, 23 trillion cubic feet of gas, and 550 million barrels of condensate on the Australian continental plate (average estimates).
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van Merwyk, A. M., und A. L. Disney. „ENVIRONMENTAL UPDATE 2004“. APPEA Journal 45, Nr. 2 (2005): 157. http://dx.doi.org/10.1071/aj04069.
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This paper presents the highlights of development activity of 2004 for the petroleum industry within Australia. In the face of declining oil production within Australia there were few new oil field developments in 2004 (Exeter- Mutineer; Jingemia). The start up of liquids stripping at Bayu-Undan in the Timor Sea and other gas/condensate fields such as Apache’s Linda, however, helped to arrest the declining trend. The first oil fields that define a new oil province in the Exmouth Sub-basin were the subject of extensive appraisal programs and Woodside gave the green light for start of the A$1.48 billion Enfield development.The story for natural gas in 2004 is somewhat more buoyant with several developments in domestic supply around Australia, including coal seam methane (CSM) production on-stream on the east coast. The national pipeline grid extended with the opening of the A$500 million SEAgas pipeline between Port Campbell and Adelaide. Minerva gas production followed at the end of the year, leading the way for the approval of gas developments at Thylacine- Geographe (A$1.1 billion) and Casino (A$200 million) in the Otway Basin. The Yolla gas production platform was installed on site in the Bass Basin. Apache and Santos signed an agreement to supply gas from John Brookes, offshore Carnarvon Basin, and Woodside looked to Blacktip, in the Bonaparte, to supply gas to the Northern Territory.2004 was a cornerstone year for LNG. A new carrier was delivered to the NWS Joint Venture and gas flowed from the fourth LNG train for the first time. Deliveries under new contracts started to Japan and Korea and a major contract for supply was signed with China. Other potential LNG projects began significant appraisal programs at fields such as Scarborough on the NWS.
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Davidson, John K. „TECTONIC CONTROL OF WORLD OIL RESERVES: AUSTRALIA'S POSITION“. APPEA Journal 32, Nr. 1 (1992): 183. http://dx.doi.org/10.1071/aj91015.
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Although simple extensional clay models may be representative of grabens tens of kilometres in length, rotational divergence of continents on a sphere produces very different structures. Repeated periods of compression during separation result in wrench faults and compressional anticlines developing along major crustal fractures as a consequence of changes in momentum between a continent and adjacent smaller continental blocks along its rifted margin.The global distribution of rotationally divergent continental margins can be accounted for by asymmetric expansion of the earth. The southern bulge caused by expansion has emphasised non-marine deposition on southern continents with marine deposition more common in the northern hemisphere.Phanerozoic source rocks of the northern hemisphere account for 97 per cent of the world's produced and current reserves of oil. Australia's share of this extreme distribution asymmetry is less than one half of one per cent, yet the country covers five per cent of the Earth's continental crust.The proportion of undiscovered oil reserves outside OPEC and the former USSR is approximately 30 per cent, or some 12 per cent of the world's estimated ultimately recoverable reserve of 2 trillion (Tera) barrels. The majority of Australia's undiscovered reserves lie on the North West Shelf where about 12 per cent of the country's estimated ultimately recoverable reserve could be found.Although Australia is politically stable, lower petroleum taxes would attract exploration for smaller, structurally complex oil fields. While such taxes may be considered politically difficult at present, a by-product of concerted oil exploration would be an enormous increase in Australia's gas reserves to feed the national pipeline grid for the 21st century. Industry can assist increased success rates by greater attention to current technical deficiencies, such as the structural interpretation of seismic lines.
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Hansen, Lein Mann. „Australia well positioned to become a CCUS leader“. APPEA Journal 62, Nr. 2 (13.05.2022): S25—S28. http://dx.doi.org/10.1071/aj21107.
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Australia’s carbon capture, utilisation and storage (CCUS) sector could be set for fresh boost as oil and gas players are investing heavily in large-scale projects. In 2020, Australia emitted around 499 million tonnes of CO2-equivalent (CO2e). Country-wide, only 2.5 million tonnes of CO2 is captured and stored annually in the Gorgon CCUS project. Starting its CCUS journey on the wrong foot, Australia’s ambitious Gorgon project suffered from cost overruns, delays and much lower capture rates than planned. Nevertheless, 3 years after startup we now see renewed momentum on the back of significant budgetary support from the Federal Government, in addition to inclusion of CCUS projects in the Emissions Reduction Fund and Australian Carbon Credit Units (ACCU), which increased its value ever since. Large players are sizing up opportunities for CCUS in the country and to invest in research and development of next-generation CCUS as well as direct air capture technologies. Considering the vast CO2 storage potential in depleted oil and gas fields and saline aquifers, Rystad Energy have identified three potential storage hotspots in Australia: the northwestern hub, the mid-eastern hub and the southeastern hub. These storage hubs have a cumulative CO2 storage potential of 855 gigatonnes, that is located near to important industrial clusters and is sufficiently large, so it does not pose any barrier for CO2 storage.
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Saunders, Donald F., K. Ray Burson, Jim F. Branch und C. Keith Thompson. „Relation of thorium‐normalized surface and aerial radiometric data to subsurface petroleum accumulations“. GEOPHYSICS 58, Nr. 10 (Oktober 1993): 1417–27. http://dx.doi.org/10.1190/1.1443357.
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A new exploration method has been developed using surface and aerial gamma‐ray spectral measurements in prospecting for petroleum in stratigraphic and structural traps. Formerly troublesome lithologic and environmental variables are suppressed by correcting potassium and uranium readings using a new process of thorium normalization. Normalized potassium shows characteristic low concentrations above petroleum deposits. Normalized uranium shows higher values than normalized potassium over petroleum and generally lower values elsewhere. We attribute these anomalies to effects of microbial consumption of microseeping light hydrocarbons. Studies of National Uranium Resource Evaluation (NURE) Program aerial, gamma‐ray, spectral data covering portions of six states have shown characteristic normalized potassium and uranium anomalies above 72.7 percent of 706 oil and gas fields. Additionally, an average of 27 similar untested anomalies were found for each 1000 square mi (2600 square km) covered. Similar aerial gamma‐ray spectral data are available over large portions of potential petroleum areas of the U.S. including Alaska and Australia. Preliminary tests in two basins in Australia showed positive correlation between radiometrically favorable areas and known oil and gas regions. Ground‐based, gamma‐ray, spectral measurements found the same types of potassium and uranium anomalies over all twelve fields evaluated. Since 1988, our research of surface radiometric data coupled with soil gas hydrocarbon and soil magnetic susceptibility surveys has resulted in discovery of four oil and gas fields in Concho County, Texas.
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Smith, Peter, und Iain Paton. „From wells to decisions—data management for coal seam gas operators in Australia as compared to conventional oil and gas operators“. APPEA Journal 51, Nr. 2 (2011): 716. http://dx.doi.org/10.1071/aj10096.
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The large number of wells associated with typical coal seam gas (CSG) developments in Australia has changed the paradigm for field management and optimisation. Real time data access, automation and optimisation—which have been previously considered luxuries in conventional resources—are key to the development and operation of fields, which can easily reach more than 1,000 wells. The particular issue in Australia of the shortage of skilled labour and operators has increased pressure to automate field operations. This extended abstract outlines established best practices for gathering the numerous data types associated with wells and surface equipment, and converting that data into information that can inform the decision processes of engineers and managers alike. There will be analysis made of the existing standard, tools, software and data management systems from the conventional oil and gas industry, as well as how some of these can be ported to the CSG fields. The need to define industry standards that are similar to those developed over many years in the conventional oil and gas industry will be discussed. Case studies from Australia and wider international CSG operations will highlight the innovative solutions that can be realised through an integrated project from downhole to office, and how commercial off the shelf solutions have advantages over customised one-off systems. Furthermore, case studies will be presented from both CSG and conventional fields on how these enabling technologies translate into increased production, efficiencies and lift optimisation and move towards the goal of allowing engineers to make informed decisions as quickly as possible. Unique aspects of CSG operations, which require similarly unique and innovative solutions, will be highlighted in contrast to conventional oil and gas.
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Crowley, A. J. „THE M. AUSTRALIS SANDSTONES, DAMPIER SUB-BASIN, AUSTRALIA“. APPEA Journal 39, Nr. 1 (1999): 104. http://dx.doi.org/10.1071/aj98007.
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Three independent Barremian sandstone units that are characterised by the M. australis palynozone have been identified in the Lewis Trough and Enderby Terrace of the southeastern Dampier Sub-Basin, offshore Western Australia. They constitute a basin-floor fan unit and shelfal transgressive unit that are characterised by the lower Af. australis sub-zone, a shelfal marine to fluvial unit that is characterised by the middle M. australis sub- zone and a shelfal marine unit that is characterised by the upper M. australis sub-zone. The M. australis sandstones are characterised by their excellent reservoir quality, generally common to abundant glauconite content and common provenance.Core, wireline log and seismic data from wells in the Lewis Trough indicate the sediments characterised by the lower M. australis sub-zone form a mass-flow deposit on the regionally extensive Intra-Muderong Hiatus. Transgressive shelfal greensands, interpreted to lie within the latter part of the lower M. australis sub-zone overlie the In tra-Muderong Hiatus on the Enderby Terrace. The glauconitic sandstones characterised by the middle M. australis sub-zone were deposited during a relative highstand and overlie a maximum flooding surface identified in wells on the southern Enderby Terrace. These deposits form the reservoir section for the Wandoo and Stag oil fields. At Wandoo they form a series of seismically definable progrades, whereas at Stag they are the distal toe-sets that lie sub-parallel to the underlying surface. The subsequent sequence boundary is identified in wells and on seismic data as an erosional surface cutting the underlying sediments. Glauconite-rich, transgressive deposits form a fining-up sequence overlie the sequence boundary. Glauconitic sandstones characterised by the upper M. australis sub-zone were deposited at the palaeo- shelf break during a minor regression.
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Mensah, RK, W. Liang, D. Gibbs, R. Coates und D. Johnson. „Evaluation ofnC27 petroleum spray oil for activity againstHelicoverpaspp. on commercial cotton fields in Australia“. International Journal of Pest Management 51, Nr. 1 (März 2005): 63–70. http://dx.doi.org/10.1080/09670870400028300.
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Tenthorey, Eric, Ian Taggart, Aleksandra Kalinowski und Jason McKenna. „CO2-EOR+ in Australia: achieving low-emissions oil and unlocking residual oil resources“. APPEA Journal 61, Nr. 1 (2021): 118. http://dx.doi.org/10.1071/aj20076.
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The petroleum industry, through the production and consumption of oil and gas, contributes to global greenhouse gas emissions. However, the industry’s leadership and experience in underground injection and storage of CO2, especially through CO2 enhanced oil recovery (CO2-EOR), which has been proposed as a possible solution to reducing atmospheric CO2 levels, has not been well acknowledged. Unlike traditional CO2-EOR, which tends to be a net carbon emitter due to the use of predominantly natural CO2, rather than anthropogenic, CO2-EOR+ focuses on storing a larger volume of CO2. Thus CO2-EOR+ not only provides a potential solution to dispose of anthropogenic emissions but at the same time reduces reliance on imported oil through increased domestic production. Increased industry interest and energy policy strategies directed at reducing and/or removing emissions from industry processes reflect the growing social and economic impetus to improve operation practices and the petroleum industry’s reputation. Residual oil zones (ROZs) below identified oil–water contacts provide an excellent target for the application of CO2-EOR+. They offer a producible residual oil resource accessible through CO2-EOR, as well as a large pore volume for CO2 storage, with efforts focused on converting ROZs into resources and reserves. Existing fields in the Surat and Cooper-Eromanga Basins are already well placed to utilise anthropogenic CO2 sources to achieve conventional CO2-EOR metrics. The ROZs in these basins will hopefully allow potential EOR projects to increase the CO2 volumes stored, per incremental barrel of oil, well past traditional levels (0.2–0.3 tCO2/bbl), and in doing so, potentially achieve net negative-emission oil.
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Foster, M. T. Bradshaw C. B., M. E. Fellows und D. C. Rowland. „THE AUSTRALIAN SEARCH FOR PETROLEUM: PATTERNS OF DISCOVERY“. APPEA Journal 39, Nr. 1 (1999): 12. http://dx.doi.org/10.1071/aj98001.
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Three cycles of successful commercial hydrocarbon exploration and discovery have occurred in Australia since 1960, although sporadic efforts to locate oil accumulations have occurred since 1860. The first cycle of successful exploration, from 1960 to 1972, revealed most of the productive basins and all of the giant oil fields found to date. After an interval of very low drilling rates between 1973 and 1978, exploration activity returned to strong levels for a second cycle of discovery between 1978 and 1988. A third cycle commenced in 1989 when there was an increase in exploration activity and the number of hydrocarbon discoveries again, after a low point in the mid 1980s.The discovery of oil and gas fields is dependent on the rate of exploration activity, geological endowment, exploration efficiency and chance. Technology and geological knowledge influence exploration efficiency. The main driver of exploration activity is the profit motive, which is modified by government policies, oil price, markets, and perceived prospectivity. Discovery itself is a powerful stimulus to further exploration. Through the last 40 years these factors have varied in their impact on exploration and the resulting petroleum discoveries.
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Carpenter, Chris. „Technical Solution Improves Safety, Efficiency of Well Construction Offshore Australia“. Journal of Petroleum Technology 73, Nr. 10 (01.10.2021): 46–48. http://dx.doi.org/10.2118/1021-0046-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202353, “Drilling-Performance and Risk-Management Optimization Offshore Australia: Improving Overall Safety and Efficiency of the Well-Construction Process,” by Chandrasekhar Kirthi Singam, Farshid Hafezi, and Clyde Rebello, Schlumberger, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The emergence of real-time well construction performance-monitoring centers has improved the service delivery for operators across numerous offshore oil fields in Australia significantly. The complete paper details new technologies and work flows implemented for three Australian offshore wells, with the primary objective of improving drilling efficiency while managing associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the operator and highlighting areas of possible improvements. Introduction The paper describes a successful drilling campaign in a challenging field in the Timor Sea. It describes how data analysis, risk evaluation, and real-time performance monitoring can be influential in saving rig time and project success. As part of this project, a major operator in Australia decided to perform an infill drilling campaign involving three high-angle directional wells (J type) in a saturated, complex field. The campaign design stage was initiated in 2017 with a main objective of delivering the project within authority-for-expenditure (AFE) budget and with planning for all potential challenges. Technical Overview The technical solution (Fig. 1) was deployed using drilling-interpretation software and executed its work flows to achieve the required objectives.
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Williamson, P. E., und C. B. Foster. „ACCESS TO AUSTRALIAN EXPLORATION AND PRODUCTION DATA: A CRITICAL FACTOR IN ATTRACTING INVESTMENT“. APPEA Journal 43, Nr. 1 (2003): 693. http://dx.doi.org/10.1071/aj02040.
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During the past 10 years, Australia has maintained 65– 85% self-sufficiency in oil and better than 100% sufficiency in gas. This has generated significant societal benefits in terms of employment, balance of payments, and revenue. The decline of the super-giant Gippsland fields, discovery of smaller oil pools on the North West Shelf, and the increasing reliance on condensate to sustain our liquids supply, however, sharpens the focus on Australia’s need to increase exploration and discover more oil. Australia is competing in the global market place for exploration funds, but as it is relatively underexplored there is a need to simulate interest through access to pre-competitive data and information. Public access to exploration and production data is a key plank in Australian promotion of petroleum exploration acreage. Access results from legislation that initially subsidised exploration in return for lodgement and public availability of exploration and production (E&P) data. Today publicly available E&P data ranges from digital seismic tapes, to core and cuttings samples from wells, and access to relational databases, including organic geochemistry, biostratigraphy, and reservoir and shows information. Seismic information is being progressively consolidated to high density media. Under the Commonwealth Government’s Spatial Information and Data Access Policy, announced in 2001, company data are publicly available at the cost of transfer, after a relatively brief confidentiality period. In addition, pre-competitive regional studies relating to petroleum prospectivity, undertaken by Government, and databases and spatial information are free over the Internet, further reducing the cost of exploration. In cooperation with the Australian States and the Northern Territory, we are working towards jointly presenting Australian opportunities through the Geoscience Portal (http:// www.geoscience.gov.au) and a virtual one-stop data repository. The challenge now is to translate data availability to increased exploration uptake, through client information, and through ever-improving on-line access.
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Saraceni, Pat, und Keely Liddle. „Decommissioning – What's the fuss about?“ APPEA Journal 58, Nr. 2 (2018): 748. http://dx.doi.org/10.1071/aj17223.
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Offshore decommissioning is complex, challenging (both legally and operationally) and costly. With the rise in the number of fields approaching end of life (or economic viability), the interest in decommissioning in and around Australian waters is set to increase in the near to medium future. The lack of established federal laws regulating all aspects of decommissioning opens the door for Australia to show innovative leadership in how best to tackle end of life asset management in the oil and gas sector. Australia’s learning in this area will be aided by the laws of jurisdictions that are better-versed and more experienced in offshore decommissioning, such as the United Kingdom, the United States and Norway. This paper will explore Australia’s current legal framework and the issues faced by Australia in this area. While clear policies and regulations are essential, this does not equate to a single rigid approach. A flexible (but consistent) approach is the ideal. By considering how international regulatory regimes for decommissioning may be adapted to Australia, the paper will propose actions regulators and participants in the industry can take now to prepare for and ride (rather than drown in) the decommissioning wave.
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Passmore, V., und R. Towner. „A History of Geological Exploration in the Canning Basin, Western Australia“. Earth Sciences History 6, Nr. 2 (01.01.1987): 159–77. http://dx.doi.org/10.17704/eshi.6.2.jm774585j6382583.
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The Canning Basin in northern Western Australia is a large, relatively remote, mainly desert-covered Phanerozoic basin covering 595 000 sq km. Aborigines probably first entered the basin area 30-40 000 years ago, but the main European expeditions were not until the nineteenth and twentieth centuries. Geological exploration in the basin has been largely devoted to the discovery and exploitation of natural resources, primarily oil. Earliest geological traverses were conducted by geologists of the Geological Survey of Western Australia (GSWA). The accidental discovery of traces of oil in a water well in 1919 in the northern part of the basin diverted exploration to assessment of sediments and structures for petroleum potential. The earliest phase of oil exploration was a pioneering phase, concentrating on surface mapping and surface delineated structures as drilling sites, that was dominated by the Freney Kimberley Oil Company. West Australia Petroleum Ltd became the most active oil exploration company in the 1950s, 1960s and 1970s, using geophysics as an exploration tool in petroleum search in the basin. The late 1970s and 1980s saw an influx of companies and the application of diverse scientific approaches to the oil search. Persistence was rewarded in 1981 and 1982 with the discovery of the Blina and Sundown fields, small commercial oil accumulations. Commonwealth Government involvement in exploration was initially in the form of financial aid to exploring companies or commissioning specialist consultants for special studies. In the 1940s and 1950s and again in the 1970s the Bureau of Mineral Resources carried out basin-wide regional geological mapping in conjunction with the GSWA; onshore and offshore geophysical surveys were conducted until the 1970s. Exploration has revealed exploitable resources in the basin besides oil - diamonds, lead-zinc, coal, salt, phosphate, uranium, and heavy minerals. Only lead-zinc has present economic viability.
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McLerie, M. K., A. M. Tait und M. J. Sayers. „THE YAMMADERRY, COWLE AND ROLLER DISCOVERIES IN THE BARROW SUB-BASIN, WESTERN AUSTRALIA“. APPEA Journal 31, Nr. 1 (1991): 32. http://dx.doi.org/10.1071/aj90004.
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The TP/3 Part I permit in the Barrow Sub-basin has been held by WAPET since 1952. Improvements in seismic quality and oilfield economics in the early 1980s resulted in the 1985 Saladin oil discovery, which subsequently led to the Yammaderry, Cowle and Roller discoveries.Yammaderry-1, drilled in 1988, encountered 16.5 m of gas capping a nine metre oil column. In 1989, Cowle-1 penetrated a 14 m oil column and tested at 1016 m3 (6390 BBL) of oil per day. Roller-1, drilled in 1990, encountered six metres of gas capping nine metres of oil and tested at 866 m3 (5450 BBL) of oil per day. Roller-2, deviated downdip to find the oil/water contact, proved an 18 m oil column, confirmed later by Roller-4.Early Cretaceous Barrow Group deltaic sandstones are the reservoirs for the Saladin, Yammaderry, Cowle and Roller oil fields. The Barrow Group is overlain by the Mar- die Greensand, the basal unit of the Muderong Shale which forms the regional seal. The transitional acoustic character of the Mardie Greensand and its thickness, variable fluid saturation and lithology, cause problems in picking a top Barrow Group event. Vertical Seismic Profiles acquired in the Yammaderry, Cowle and Roller wells have helped tie the wells to the seismic data.With Saladin on stream, and Yammaderry and Cowle under development, a major seismic survey was completed in late 1990 to delineate Roller and to detail prospects for future drilling in the revitalised TP / 3 Part 1 permit.
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Baronie, F. M., M. Fenton, G. Harman und M. Jury. „CAN SUSTAINABLE DEVELOPMENT THINKING BE APPLIED TO NEW OILFIELDS? A CASE STUDY OF THE EARLY STAGES OF THE ENFIELD AREA DEVELOPMENT IN AN ENVIRONMENTALLY AND SOCIALLY SENSITIVE AREA“. APPEA Journal 43, Nr. 1 (2003): 753. http://dx.doi.org/10.1071/aj02045.
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Can development of a finite resource, such as oil, be consistent with sustainable development? Sustainable development involves meeting the needs of current and future generations through simultaneous consideration of environmental, social and economic aspects (referred to as the triple bottom line).Since 1998, Woodside Energy Ltd (Woodside) has discovered three oil fields in the WA-271-P Permit area offshore North West Cape, northern Western Australia. The fields are some 20 km from the boundary of the Ningaloo Marine Park.The first part of this paper presents a case study of the Enfield Area Development. It describes the approach taken to simultaneously manage environmental, social and economic considerations while planning for the development of oil fields in exploration permit WA-271-P.A range of measures have been employed that are considered examples of best practice for the petroleum industry in Australia, including:early commitment to a range of responsible environmental management measures in design; a comprehensive community engagement program, with links to the development and environmental assessment processes; and pioneering environmental research.Novel methods of establishing environmental and social issues as key priorities within the Woodside development team have been successfully implemented.The case study provides by giving an overview of the most significant environmental risks associated with the proposed development, and concludes that the development does not represent a significant risk to the environment.The second part of the paper then addresses the question of whether oilfields can be developed sustainably, looking at current views from the literature, and whether the approach outlined in the case study can be considered sustainable.While the project is still in an early stage of development, it provides a strong indication that oil development can be consistent with current thinking on sustainability, provided that current needs, which include a dependence on fossil fuels, and future needs, such as preservation of the productive and social value of the environmental resource base, are balanced simultaneously. The paper concludes that oil development, even in an environmentally and socially sensitive area, can help facilitate the transition to a more sustainable future.
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Edwardes, A. K. Khurana R. J. „NEW DEVELOPMENTS IN BASS — STRAIT THE LOW- COST CHALLENGE“. APPEA Journal 29, Nr. 1 (1989): 1. http://dx.doi.org/10.1071/aj88001.
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Esso Australia, with its co- venturer BHP Petroleum, is planning to bring five new fields into production in 1989. These fields are relatively small, with total reserves of approximately 50 million barrels (7950 ML). Development concepts new to Bass Strait have been identified to make them economically attractive.The significant change made to the fiscal environment of Bass Strait in June 1987, when the Government provided an exemption from excise for the first 30 million barrels (4770 ML) of oil production for certain offshore projects, has played a key role in the economic viability of these developments.The Whiting field will be developed with a mini- platform, the Seahorse and Tarwhine fields with satellite sub- sea wells, and the Perch and Dolphin project will use mono- towers.New organisational and technical approaches have been used to select cost- effective development options for these fields. These approaches include increased integration between exploration and production activities, reductions in capital expenditure through applying novel concepts and researching big ticket items such as facilities installation, and minimising of operating costs by remote operation of facilities.With the developments planned for 1989, and with ongoing research, the outlook can be described as optimistic provided tax regimes continue to encourage development of small fields both in Bass Strait and elsewhere offshore in Australia.
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Arouri, Khaled R., David M. McKirdy, Lorenz Schwark, Detlev Leythaeuser und Peter J. Boult. „Accumulation and mixing of hydrocarbons in oil fields along the Murteree Ridge, Eromanga Basin, South Australia“. Organic Geochemistry 35, Nr. 11-12 (November 2004): 1597–618. http://dx.doi.org/10.1016/j.orggeochem.2004.04.008.
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Zannetos, Andy, Will Leonard, Grant Clements, Dean Grant, Andrew Miatello, Anna Galloway, Abdul Aziz Rahim und Julien Celerier. „Making the most of mature field opportunities—2009 Cobia infill drilling campaign“. APPEA Journal 50, Nr. 2 (2010): 703. http://dx.doi.org/10.1071/aj09067.
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The Halibut and Fortescue oil fields are located in the Gippsland Basin, offshore Australia, and have produced 1.3 billion barrels of oil since the 1970s. The fields have been developed from three platforms—Cobia, Halibut and Fortescue—using multiple infill drilling campaigns post initial development. A strong emphasis has been placed on leveraging the latest technology to optimise development of these fields. The advent of high resolution 3D seismic surveys and improved processing techniques have proved invaluable in recent programs. This is illustrated by the 2009 Cobia infill program where the nine wells drilled over six months have increased field production from an average of 4,000 to 20,000 barrels of oil per day. Key success elements for this program included the use of new 3D re-processing technology, the application of past learnings, and the in-house enhancement of 3D data, in addition to seismic modelling and the integration of production data. The maturing of individual leads to economically viable targets used fit-for-purpose analysis of the data in which 3D seismic, well and production data were integrated and later built into 3D geologic models. Location choice was also important to the success of the program, where several potential targets were rejected after failing to meet technical or economic criteria. Drilling performance was exceptional, with all nine wells drilled within budget. The new 2009 Cobia infill wells have already produced over 2.2 million barrels of oil and show how mature fields can be re-invigorated through the use of re-processed 3D seismic and integrated data analysis.
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Bernecker, T., M. A. Woollands, D. Wong, D. H. Moore und M. A. Smith. „HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA“. APPEA Journal 41, Nr. 1 (2001): 91. http://dx.doi.org/10.1071/aj00005.
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After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade.However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems.In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts.The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas.Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.
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Hyden, A. M. „OFFSHORE FACILITIES REMOVAL — A MAJOR ISSUE NOW AND FOR THE FUTURE“. APPEA Journal 29, Nr. 1 (1989): 6. http://dx.doi.org/10.1071/aj88002.
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The costs associated with removal of offshore production facilities can have a serious impact on project economics, especially for the shorter- life marginal fields. The requirements for removal of offshore facilities are set out in the Petroleum (Submerged Lands) Act and the guidelines prepared by the International Maritime Organisation, a United Nations agency. Esso Australia Limited has completed a major study of the removal of Bass Strait platforms and has evaluated the costs of platform removal by various methods. Environmental considerations, the needs and safety of other users of the sea, and cost need to be considered when examining options for removal of offshore platforms. The Australian Government needs to act soon to resolve the issues of residual liability and tax deductibility and so enable the oil industry to select the optimum removal methods and reliably predict future costs for removal.
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Souter, David, Steve Rogers und Jamie Oliver. „An operational and scientific monitoring program (OSMP) for the Prelude and Ichthys fields: a case study from the Browse Basin“. APPEA Journal 54, Nr. 2 (2014): 480. http://dx.doi.org/10.1071/aj13053.
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An OSMP is the principle tool for determining the extent, severity, and persistence of environmental impacts from an oil spill. The OSMP developed for the Shell Prelude and Inpex Ichthys gas fields has 13 operational monitoring programs (OMPs) and 12 scientific monitoring programs (SMPs) reflecting the complexity of the environment in which the developments are located. A partnership of organisations led by the Australian Institute of Marine Science (AIMS) will provide specialist expertise to help implement the OSMP. This unique multi-disciplinary partnership, comprising AIMS, CSIRO, University of Western Australia, Curtin University, WA ChemCentre, and Monash University, guarantees capability and capacity, reducing the level of risk incurred by individual organisations within the partnership. Fundamental to the success of any OSMP is the existence of adequate, fit-for-purpose baseline data against which post spill observations can be compared to determine the extent and severity of the spill and assess effectiveness of oil spill response. In addition, we believe adequate baselines with sufficient temporal resolution are essential for OSMP credibility and maintenance of the scientific reputations of partners. In committing capability to the OSMP implementation, AIMS and its partners have adopted a risk-based approach to assessing the adequacy of existing baseline data, to identify knowledge gaps, and assess the significance of those gaps and the feasibility of filling them. This extended abstract describes the structured approach taken to analyse the various risks and to develop a balanced suite of environmental baseline studies to address these risks.
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Boreham, C. J., J. E. Blevin, A. P. Radlinski und K. R. Trigg. „COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA“. APPEA Journal 43, Nr. 1 (2003): 117. http://dx.doi.org/10.1071/aj02006.
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Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.
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Dean, John, Garry Wall und Kate Parker. „Australia's resource sector supply chain: prospects and policy“. APPEA Journal 53, Nr. 2 (2013): 434. http://dx.doi.org/10.1071/aj12045.
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This extended abstract identifies potential strengths in the resources sector supply chain, with particular reference to the oil and gas sector. It identifies areas of strength in the supply chain, particularly in fields such as geotechnical services, software, instrumentation, electrical engineering, project management, consultancy, and so on. It argues for a consistent policy approach across the many policy- and service-provision actors involved to maximise industry-development chances in the medium and long term. The economic benefits of the price, investment, and volume impacts of the present phase of mineral and resource development are well documented. They are expected to generate a continuing step increase in Australia's GDP, with benefits that will last for many years. Many actors are involved in shaping policy and providing research and other services across the commonwealth and state spheres. Relevant actors extend beyond government to agencies such as the CSIRO, the CRCs, industry associations, and research capabilities of universities and other institutions pertinent to the sector. The policy setting is complex, but there is an opportunity to build on and expand the industry and services base underpinning the resources-sector supply chain. In this regard, Australia can learn lessons from Norway where a deliberate policy strategy has helped established a vibrant offshore sector, admittedly in a considerably different institutional context. This extended abstract reviews the Norwegian experience against Australian developments and seeks to understand the role policy has played in this case. This experience is then transposed to the Australian situation.
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Baillie, P. W., und E. P. Jacobson. „PROSPECTIVITY AND EXPLORATION HISTORY OF THE BARROW SUB-BASIN, WESTERN AUSTRALIA“. APPEA Journal 37, Nr. 1 (1997): 117. http://dx.doi.org/10.1071/aj96007.
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The Carnarvon Basin is Australia's leading producer of both liquid hydrocarbons and gas. Most oil production to date has come from the Barrow Sub-basin. The success of the Sub-basin is due to a fortuitous combination of good Mesozoic source rocks which have been generating over a long period of time, Lower Cretaceous reservoir rocks with excellent porosity and permeability, and a thick and effective regional seal.A feature of Barrow Sub-basin fields is that they generally produce far more petroleum than is initially estimated and booked, a result of the excellent reservoir quality of the principal producing reservoirs.Structural traps immediately below the regional seal (the 'top Barrow play') have been the most successful play to date. Analysis of 'new' and 'old' play concepts show that the Sub-basin has potential for significant additional hydrocarbon reserves.
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Preston, J. C., und D. S. Edwards. „THE PETROLEUM GEOCHEMISTRY OF OILS AND SOURCE ROCKS FROM THE NORTHERN BONAPARTE BASIN, OFFSHORE NORTHERN AUSTRALIA“. APPEA Journal 40, Nr. 1 (2000): 257. http://dx.doi.org/10.1071/aj99014.
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Geochemical data from oils and source rock extracts have been used to delineate the active petroleum systems of the Northern Bonaparte Basin. The study area comprises the northeastern portion of the Territory of Ashmore and Cartier Islands, and the western part of the Zone of Co-operation Area A, and is specifically concerned with the wells located on and between the Laminaria and Flamingo highs. The oils and condensates from this region can be divided into two distinct chemical groups which correspond with the reservoir types, namely, a smaller group recovered from fracture porosity within the Early Cretaceous Darwin Formation, and a larger group reservoired in sandstones of the Middle-to-Late Jurassic Plover and Elang formations. The oils recovered from the Darwin Formation have a marine source affinity and correlate with sediment extracts from the underlying Early Cretaceous Echuca Shoals Formation. The Elang/ Plover-reservoired oils, which include all the commercial accumulations, were divided into two end-member families; the first includes the relatively land-plant- influenced oils from the northwestern part of the area (e.g. Laminaria, Corallina, Buffalo and Jahal fields), the second includes the relatively marine-influenced oils to the southeast (e.g. Bayu-Undan fields). Another oil family comprises the geographically and geochemically intermediate oils of the Elang and Kakatua fields and adjacent areas. While none of the oils can be uniquely correlated with a single source unit, they show geochemical similarities with Middle-to-Late Jurassic source rock extracts. Organic-rich rocks within the Plover and Elang formations are the major source of hydrocarbons for this area. The range in geochemistry of the Elang/Plover-reservoired oils may arise from facies variation within these sediments, but is more probably due to the localised additional input of hydrocarbons generated from thermally mature organic-rich claystone seals that overlie the Elang reservoir in catchment areas and traps; i.e. from the Frigate Formation for the northwestern oil family and from the Flamingo Group for the southeastern oil family. The short-range migration patterns dictated by the structural complexity of the basin are reflected in the closeness with which variations in the geochemical character of the accumulated liquids track variations in the character of source-seal lithologies. The length of migration pathways can, therefore, be inferred from the similarity or otherwise of source-seal characters with those of the hydrocarbon accumulations themselves. The resulting observations may challenge existing ideas concerning migration patterns, hydrocarbon prospectivity and prospect risking within the Northern Bonaparte Basin.
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Potter, Trent, Wayne Burton, Jan Edwards, Neil Wratten, Rod Mailer, Phil Salisbury und Amanda Pearce. „Assessing progress in breeding to improve grain yield, quality and blackleg (Leptosphaeria maculans) resistance in selected Australian canola cultivars (1978–2012)“. Crop and Pasture Science 67, Nr. 4 (2016): 308. http://dx.doi.org/10.1071/cp15290.
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Canola breeding in Australia began in the early 1970s with the first cultivars being released in the late 1970s. Thirty-four non-herbicide-tolerant canola cultivars, released in Australia between 1978 and 2012, were evaluated for improvements in yield, quality, blackleg resistance and adaptation to Australian environments. The cultivars were sown at three sites in 2008 and one site in 2014. In addition, blackleg susceptibility was assessed in two independent blackleg experiments in 2008. Yield improvement averaged 21.8 kg ha–1 year–1 (1.25% year–1) but ranged from 8 to 39.1 kg ha–1 year–1 at the lowest to the highest yielding sites, respectively. Although the yield gain shown by our study was for conventional canola only, the different herbicide-tolerant types are derived by incorporating the herbicide tolerance genes into Australian germplasm and so the rate of genetic gain would be expected to be similar for all herbicide tolerance types. Oil and protein concentrations have increased by 0.09% year–1 and 0.05% year–1, respectively, whereas glucosinolate concentration was reduced to between 7 and 16 μmoles per gram of meal by the mid-1990s. Cultivars released before 2002 all had low to moderate resistance to the blackleg isolates present in the fields during the experimental period but more recent releases had improved survival under heavy blackleg pressure due to the incorporation of additional or different resistance genes. The data suggests that at least 25% of the yield improvement achieved by the breeding programs over 30 years was associated with improved blackleg resistance and the remainder with gains in other aspects of potential grain yield. The private breeding companies in Australia will need to continue to produce cultivars with high yield potential and deploy blackleg resistance genes wisely in order to maintain the yield improvements required to remain competitive in global markets.
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Rezaee, Reza. „Nuclear Magnetic Resonance (NMR) Outputs Generation for Clastic Rocks Using Multi Regression Analysis, Examples from Offshore Western Australia“. Fuels 3, Nr. 2 (17.05.2022): 316–25. http://dx.doi.org/10.3390/fuels3020019.
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A large database of nuclear magnetic resonance (NMR) logging data from clastic rocks of offshore oil and gas fields of Western Australia was used to assess the performance of multi regression analysis (MRA) to calculate NMR log outputs from conventional well logs. This short paper introduces a set of MRA equations for the calculation of the NMR log outputs using conventional well logs as inputs. This study shows that unlike machine learning methods the MRA approach fails to predict most of the NMR log outputs with acceptable accuracy but can provide Coates and SDR permeabilities with R2 of more than 0.75.
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Pegum, D., und M. Loeliger. „THE LANDER TROUGH—A CENTRAL AUSTRALIAN FRONTIER EXPLORATION AREA“. APPEA Journal 30, Nr. 1 (1990): 128. http://dx.doi.org/10.1071/aj89007.
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The Lander Trough is an almost unexplored area of 30 000 square kilometres in the central western Northern Territory. It has very similar stratigraphy and structural features to the nearby Amadeus, Ngalia and southern Georgina Basins. They all contain fluvio-deltaic to marine sediments of Late Proterozoic to Carboniferous age and were subjected to deformation during several major periods of folding and overthrusting. They are remnants of one depositional basin which covered much of Northern Australia in the Late Proterozoic and Early Palaeozoic Eras. Producing oil and gas fields occur in the Amadeus Basin and there are many oil and gas occurrences in the southern Georgina and Ngalia Basins. The Lander Trough contains up to 3000 metres of largely marine clastic and carbonate sediments which are expected to include mature source rocks and effective reservoirs and seals. Adequate migration paths and trapping mechanisms are believed to be present. The Lander Trough has the potential for commercial petroleum discoveries.
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Allen, J., und M. Williamson. „LEGAL AND TAXATION IMPLICATIONS FOR THE ACQUISITION AND DISPOSAL OF OFFSHORE PETROLEUM PRODUCTION AND EXPLORATION TENEMENTS—A PRACTICAL VIEW AND UPDATE“. APPEA Journal 26, Nr. 1 (1986): 7. http://dx.doi.org/10.1071/aj85001.
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The administrative aspects of petroleum mining and exploration companies have become more complex of recent years. One area where this is particularly so is in relation to the livelihood of the industry, i.e. access to tenements.While exploration and development activity onshore has hotted up in particular, offshore activity has been fervent but limited largely to bringing into production fields on the North West Shelf, at Jabiru and new areas in Bass Strait. Generally it is held that the likelihood for discoveries of large fields will be offshore Australia rather than onshore and that present exploration activities offshore are inadequate to maintain Australia's oil self-sufficiency.Recent amendments to the Petroleum (Submerged Lands) Act, a plethora of associated Acts, and proposed new tax imposts (e.g. cash bonus bids, retention licence fees, resource rent tax, and capital gains tax) in relation to the offshore segment of the industry have added significantly to the complexities in planning the acquisition and disposal and ongoing control of tenements. Each of these is examined individually and in conjunction for the benefit of planners and executives administering tenements within their organisations.Both sides of the transaction are viewed with emphasis on their tax positions providing opportunities to control the directions and funding mechanisms for the transaction.
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Lavin, C. J. „A REVIEW OF THE PROSPECTIVITY OF THE CRAYFISH GROUP IN THE VICTORIAN OTWAY BASIN“. APPEA Journal 37, Nr. 1 (1997): 232. http://dx.doi.org/10.1071/aj96014.
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One of two major play fairways investigated by explorationists in the Otway Basin is the Crayfish Group system. This Tithonian-Barremian aged succession of syn-rift, continental siliciclastics was deposited in gra- ben distributed across the basin. All of the elements of a prospective petroleum province are present: lacustrine source rocks, high-quality quartzose sandstone reservoirs, and thick regional seals that are structured by both syn and post-rift tectonic events setting up a variety of play types.There has been a resurgence of drilling of Crayfish Group prospects in South Australia in the past decade. Some 24 wells penetrating the Crayfish Group have been drilled in South Australia during this period. This has resulted in the discovery of five commercial gas-fields, three non-commercial gasfields and two significant oil shows. Contrasting with this is the paucity of exploration for similar plays in the Victorian Otway Basin where, during the last decade, only six wells have penetrated the Crayfish Group, with one significant oil show recorded. With this in mind, the author has been searching for Victorian analogues of the successful Crayfish Group hydrocarbon discoveries in South Australia. This has involved defining the major Crayfish Group depocentres and evaluating their prospectivity.There are no less than 12 major Crayfish Group depocentres in the Victorian Otway Basin. Most have not been drilled, and those that are explored are rarely penetrated by more than one well. Good quality lacustrine source rocks are intersected on the flanks of these troughs and are also interpreted to exist in the troughs from seismic data. Reservoir sandstones are abundant in the Crayfish Group at a variety of stratigraphic levels in both South Australia and Victoria, as episodes of tec- tonism resulted in the influx of quartzose, high-energy fluvial sands into the Crayfish depocentres. Potential for oil and gas generation and entrapment is demonstrated for many of these graben.
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O'Brien, Geoff, Monica Campi und Graeme Bethune. „2013 PESA production and development review“. APPEA Journal 54, Nr. 1 (2014): 451. http://dx.doi.org/10.1071/aj13044.
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The boom in Australian oil and gas development continued in 2013, with record overall investment of $60 billion. This investment resulted from spending on the seven LNG projects under development, together with that on numerous other oil and gas developments. These projects are expected to collectively contribute up to 665 million barrels of oil equivalent (MMboe) to Australia’s oil and gas production, which totaled 513.8 MMboe in 2013. LNG, presently Australia’s seventh largest export, is likely to soon rival the nation’s largest export, iron ore. By the end of 2013, three of the LNG projects under construction—Gorgon, Queensland Curtis LNG (QCLNG) and Gladstone LNG (GLNG)—were more than 70% complete; first LNG will be before the end of 2014 for QCLNG and in 2015 for Gorgon, GLNG and Australia Pacific LNG (APLNG). The other three LNG projects—Wheatstone, Prelude and Ichthys—are close behind. These new LNG projects follow Pluto, Australia’s third LNG project, which commenced production in 2012. A full year of production from Pluto drove increased gas production in 2013. Woodside also completed the North Rankin redevelopment and continued development of the Greater Western Flank, both of which will extend the life of the North West Shelf (NWS) project. A number of other projects also commenced production. In the Carnarvon Basin, oil production began at Santos’s Fletcher-Finucane Field, and at BHP Billiton’s Macedon project, domestic gas production started. In the Timor Sea, PTTEP’s Montara Field began production of oil. In Victoria, the ExxonMobil Kipper-Turrum-Tuna project came online, with the production of gas from Tuna and oil from Turrum. Production of gas from Origin Energy’s Geographe Field (as part of the Otway Gas Project) commenced in mid-2013. Onshore oil production grew in 2013, with the Cooper-Eromanga Basin now producing more oil than any other onshore Australian basin. A major effort is underway to increase production from the western flank oil trend and to develop both the conventional and unconventional gas fields in the Cooper Basin. Spending on the development of new projects probably peaked in 2013 and there is growing concern about a dearth of future projects, with expansion of existing LNG projects and development of new projects being pushed back due to a combination of increased costs and growing international competition. There are also ongoing industry concerns about impediments to onshore gas exploration and development generally.
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Xia, Jinzhu. „Development planning of deepwater gas fields: the application of floating production platforms“. APPEA Journal 54, Nr. 2 (2014): 512. http://dx.doi.org/10.1071/aj13085.
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Producing North West Australia (NWA) deepwater hydrocarbon reserves, particularly gas reserves to LNG plants, poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and LNG plants, as well as high reliability/availability of supply. This extended abstract addresses important technical, commercial, and regulatory factors that drive the field development planning, including the selection of suitable production facilities for these deepwater hydrocarbon developments off NWA. While all-subsea developments have been an inspiration for offshore engineers for a few decades, subsea gas compression, dehydration, power supply, and control are still technically and commercially demanding, especially for long distance tie-backs. Subsea well intervention and facility maintenance requirements also favour the application of dedicated floating platforms. A wet or dry-tree floating production platform, therefore, is required in most cases. Whereas Semisubmersible, TLP, Spar, FPSO, and FLNG (or LNG FPSO) designs all have the attributes to be a host gas production facility or a part of a production system, only oil FPSOs have been installed in this region to date. Linkages between key reservoir and fluid characteristics and surface facility functionalities are discussed in this extended abstract. Advantages and disadvantages of various platform designs are compared. A focus is on the influence of regional drivers and site characteristics, in particular, metocean and geotechnical conditions and remoteness of the NWA fields. The differentiation between oil and gas developments are addressed. It is emphasised that platform applicability and compatibility should be assessed in the context of field development planning for individual projects to achieve optimum risked life cycle financial values.
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Belgarde, Catherine, Gianreto Manatschal, Nick Kusznir, Sonia Scarselli und Michal Ruder. „Rift processes in the Westralian Superbasin, North West Shelf, Australia: insights from 2D deep reflection seismic interpretation and potential fields modelling“. APPEA Journal 55, Nr. 2 (2015): 400. http://dx.doi.org/10.1071/aj14035.
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Acquisition of long-offset (8–10 km), long-record length (12–18 sec), 2D reflection seismic and ship-borne potential fields data (WestraliaSpan by Ion/GXT and New Dawn by PGS) on the North West Shelf of Australia provide the opportunity to study rift processes in the context of modern models for rifted margins (Manatschal, 2004). Basement and Moho surfaces were interpreted on seismic reflection data. Refraction models from Geoscience Australia constrain Moho depth and initial densities for gravity modelling through standard velocity-density transformation. 2D joint inversion of seismic reflection and gravity data for Moho depth and basement density constrain depth to basement on seismic. 2D gravity and magnetic intensity forward modelling of key seismic lines constrain basement thickness, type and density. Late Permian and Jurassic-Early Cretaceous rift zones were mapped on seismic reflection data and constrained further by inversion and forward modelling of potential fields data. The Westralian Superbasin formed as a marginal basin in Eastern Gondwana during the Late Permian rifting of the Sibumasu terrane. Crustal necking was localised along mechanically-weak Proterozoic suture belts or Early Paleozoic sedimentary basins (such as Paterson and Canning). Mechanically-strong cratons (such as Pilbara and Kimberley) remained intact, resulting in necking and hyper-extension at their edges. Late Permian hyper-extended areas (such as Exmouth Plateau) behaved as mechanically-strong blocks during the Jurassic to Early Cretaceous continental break-up. Late Permian necking zones were reactivated as failed-rift basins and localised the deposition of the Jurassic oil-prone source rocks that have generated much of the oil discovered on the North West Shelf.