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Автор: Grafiati
Опубліковано: 4 червня 2021
Оновлено: 28 січня 2023

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  1. Статті в журналах
  2. Дисертації
  3. Книги
  4. Частини книг
  5. Тези доповідей конференцій

Статті в журналах з теми "Oil fields Australia":

1

Kalinowski, Aleksandra, Eric Tenthorey, Mojtaba Seyyedi, and Michael Ben Clennell. "The search for new oil and CO." APPEA Journal 62, no. 1 (May 13, 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.
2

Loro, Richard, Robin Hill, Mark Jackson, and Tony Slate. "Technologies that have transformed the Exmouth into Australia." APPEA Journal 55, no. 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.
3

Slate, Tony, Ralf Napalowski, Steve Pastor, Kevin Black, and Robert Stomp. "The Pyrenees development: a new oil development for Western Australia." APPEA Journal 50, no. 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.
4

Miyazaki, S. "CHARACTERISATION OF AUSTRALIA'S OIL FIELDS BY FLUID AND RESERVOIR PROPERTIES AND CONDITIONS." APPEA Journal 29, no. 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.
5

Craig, Adam, Stephen Newman, Peter Stephenson, Chris Evans, Shaun Yancazos, and Simon Barber. "Hydrogen storage potential of depleted oil and gas fields in Western Australia." APPEA Journal 62, no. 1 (May 13, 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.
6

Ronalds, B. F. "SHARED INFRASTRUCTURE: A COST-EFFECTIVE DEVELOPMENT STRATEGY FOR SMALLER FIELDS OFFSHORE AUSTRALIA?" APPEA Journal 44, no. 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.
7

Wilmshurst, Jan. "USE OF DRAG REDUCER CHEMICAL IN THE BASS STRAIT CRUDE OIL PRODUCING SYSTEM." APPEA Journal 25, no. 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.
8

Powell, T. G. "UNDERSTANDING AUSTRALIA’S PETROLEUM RESOURCES, FUTURE PRODUCTION TRENDS AND THE ROLE OF THE FRONTIERS." APPEA Journal 41, no. 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.
9

Bagheri, Mohammad B., Matthew Wallace, Vello Kuuskraa, Hadi Nourollah, Matthias Raab, and Tim Duff. "CO." APPEA Journal 62, no. 2 (May 13, 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.
10

Tucker, David H., Ross Franklin, N. Sampath, and Stan Ozimic. "Review of airborne magnetic surveys over oil and gas fields in Australia." Exploration Geophysics 16, no. 2-3 (June 1985): 300–302. http://dx.doi.org/10.1071/eg985300.

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Статті в журналах

Дисертації з теми "Oil fields Australia":

1

Nakanishi, Takeshi. "Practical application of sequence stratigraphy and risk analysis for stratigraphic trap exploration." Title page, contents and abstract only, 2002. http://web4.library.adelaide.edu.au/theses/09PH/09phn1635.pdf.

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"September 2002" Includes bibliographical references (leaves 200-209) Outlines an evaluation procedure for stratigraphic trap exploration by employing sequence stratigraphy, 3D seismic data visualisation and quantitative risk analysis with case studies in an actual exploration basin.
2

Saraiva, Isabel. "Reservoir characterization and depositional model for the Stag oil field, North West Shelf, Australia /." Title page, abstract and contents only, 2002. http://web4.library.adelaide.edu.au/theses/09SB/09sbs243.pdf.

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3

Newlands, Ian. "The structure, deposition and diagenesis of Jurassic sandstones in the Mount Horner oil field, Northern Perth basin, Western Australia /." Title page, contents and introduction only, 1993. http://web4.library.adelaide.edu.au/theses/09S.B/09s.bn549.pdf.

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4

Ryan, Melanie J. "The use of biomarkers and molecular maturity indicators to determine the provenance of residual and produced oils in the Gidgealpa Field in the Cooper-Eromanga Basin, Australia /." Title page, contents and abstract only, 1996. http://web4.library.adelaide.edu.au/theses/09S.B/09s.br9891.pdf.

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5

Nakanishi, Takeshi. "Practical application of sequence stratigraphy and risk analysis for stratigraphic trap exploration / Takeshi Nakanishi." Thesis, 2002. http://hdl.handle.net/2440/21828.

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"September 2002"
Includes bibliographical references (leaves 200-209)
xi, 209, [51] leaves : ill. (chiefly col.), maps, plates (chiefly col.) ; 30 cm.
Outlines an evaluation procedure for stratigraphic trap exploration by employing sequence stratigraphy, 3D seismic data visualisation and quantitative risk analysis with case studies in an actual exploration basin.
Thesis (Ph.D.)--University of Adelaide, National Centre for Petroleum Geology and Geophysics, 2002

Книги з теми "Oil fields Australia":

1

Geological Survey of Western Australia. Western Australia atlas of mineral deposits and petroleum fields, 1999. Edited by Eddison F, Loan G, and Collopy S. Perth, W.A: Dept. of Industry and Resources, 2003.

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2

Geological Survey of Western Australia. Western Australia atlas of mineral deposits and petroleum fields, 2001. Edited by Eddison F, Loan G, Collopy S, Prause M, and Williams B. Perth, W.A: Dept. of Minerals and Energy, 2001.

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3

South-Eastern, Australia Oil Exploration Symposium (2nd 1985 Melbourne Vic ). Second South-Eastern Australia Oil Exploration Symposium: Technical papers presented at the PESA Symposium held in Melbourne on 14th and 15th November, 1985. Melbourne: The Petroleum Exploration Society of Australia, Victorian & Tasmanian Branch, 1986.

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4

United States International Trade Commission. Calcined bauxite proppants from Australia: Determination of the commission in investigation no. 731-TA-411 (final) under the Tariff Act of 1930, together with the information obtained in the investigation. Washington, DC: U.S. International Trade Commission, 1989.

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5

United States International Trade Commission. Calcined bauxite proppants from Australia: Determination of the Commission in investigation no. 731-TA-411 (preliminary) under the Tariff Act of 1930, together with the information obtained in the investigation. Washington, DC: U.S. International Trade Commission, 1988.

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6

Association, Australian Petroleum Exploration, ed. Petroleum in Australia: The first century. [Sydney]: Australian Petroleum Exploration Association, 1988.

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7

Newton, Peter W., ed. Transitions. CSIRO Publishing, 2008. http://dx.doi.org/10.1071/9780643097995.

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Formidable challenges confront Australia and its human settlements: the mega-metro regions, major and provincial cities, coastal, rural and remote towns. The key drivers of change and major urban vulnerabilities have been identified and principal among them are resource-constraints, such as oil, water, food, skilled labour and materials, and carbon-constraints, linked to climate change and a need to transition to renewable energy, both of which will strongly shape urban development this century. Transitions identifies 21st century challenges to the resilience of Australia’s cities and regions that flow from a range of global and local influences, and offers a portfolio of solutions to these critical problems and vulnerabilities. The solutions will require fundamental transitions in many instances: to our urban infrastructures, to our institutions and how they plan for the future, and perhaps most of all to ourselves in terms of our lifestyles and consumption patterns. With contributions from 92 researchers - all leaders in their respective fields - this book offers the expertise to chart pathways for a sustainability transition.
8

Olsen, Jerry. Australian High Country Owls. CSIRO Publishing, 2011. http://dx.doi.org/10.1071/9780643104105.

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Australian High Country Owls provides the latest scientific information on Australian owl species, especially Ninox owls. It details studies of Southern Boobooks and Powerful Owls, visits to North America and Europe to learn about owl research, and the resulting publications that overturned some existing beliefs about Australian owls. Ultimately, this led to the discovery of a new owl species in Indonesia, the Little Sumba Hawk-Owl. Appendices cover the biology, conservation and rehabilitation of Australian owls, including: field recognition, subspecies taxonomy, habitat, behaviour, food, range, migration, breeding, voice and calls, status and myths, questions about each species, and techniques for caring for injured and orphaned owls. The book includes numerous photographs of different owl species, and will be a handy reference for bird researchers and amateur bird watchers alike. 2012 Whitley Award Commendation for Vertebrate Natural History.
9

Cooper, William T. Capturing the Essence. CSIRO Publishing, 2012. http://dx.doi.org/10.1071/9780643103382.

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Capturing the Essence is a step-by-step personal guide – by one of Australia's greatest living bird artists – to observing, retaining the essential information and then painting birds from field notes and sketches, photographs and other field observations. The author takes the reader through the processes involved in oil painting, watercolour and acrylic techniques, and a piece of art is built up in stages to demonstrate the skills required in each of these media. While the book covers some of the general basics relevant to various kinds of painting of natural history subjects, the concentration is very much on birds. Painting or drawing any subject well, gives great satisfaction. In this book the author hopes to help the reader become competent at drawing and painting birds, or at least to enjoy trying!
10

Delgado Martín, Jordi, Andrea Muñoz-Ibáñez, and Ismael Himar Falcón-Suárez. 6th International Workshop on Rock Physics: A Coruña, Spain 13 -17 June 2022: Book of Abstracts. 2022nd ed. Servizo de Publicacións da UDC, 2022. http://dx.doi.org/10.17979/spudc.000005.

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[Abstract] The 6th International Workshop on Rock Physics (6IWRP) was held A Coruña, Spain, between 13th and 17th of June, 2022. This meeting follows the track of the five successful encounters held in Golden (USA, 2011), Southampton (UK, 2013), Perth (Australia, 2015), Trondheim (Norway, 2017) and Hong Kong (China, 2019). The aim of the workshop was to bring together experiences allowing to illustrate, discuss and exchange recent advances in the wide realm of rock physics, including theoretical developments, in situ and laboratory scale experiments as well as digital analysis. While rock physics is at the core of the oil & gas industry applications, it is also essential to enable the energy transition challenge (e.g. CO2 and H2 storage, geothermal), ensure a safe and adequate use of natural resources and develop efficient waste management strategies. The topics of 6IWRP covered a broad spectrum of rock physics-related research activities, including: • Experimental rock physics. New techniques, approaches and applications; Characterization of the static and dynamic properties of rocks and fluids; Multiphysics measurements (NMR, electrical resistivity…); Deep/crustal scale rock physics. • Modelling and multiscale applications: from the lab to the field. Numerical analysis and model development; Data science applications; Upscaling; Microseismicity and earthquakes; Subsurface stresses and tectonic deformations. • Coupled phenomena and rock properties: exploring interactions. Anisotropy; Flow and fractures; Temperature effects; Rock-fluid interaction; Fluid and pressure effects on geophysical signatures. • The energy transition challenge. Applications to energy storage (hydrogen storage in porous media), geothermal resources, energy production (gas hydrates), geological utilization and storage of CO2, nuclear waste disposal. • Rock physics templates: advances and applications. Quantitative assessment; Applications to reser voir characterization (role of seismic wave anisotropy and fracture networks). • Advanced rock physics tools. Machine learning; application of imaging (X-ray CT, X-ray μCT, FIB-SEM…) to obtain rock proper ties. This book compiles more than 50 abstracts, summarizing the works presented in the 6IWRP by rock physicists from all over the world, belonging to both academia and industry. This book means an updated overview of the rock physics research worldwide.

Частини книг з теми "Oil fields Australia":

1

"Fortescue Field, Gippsland Basin, Offshore Australia." In Giant Oil and Gas Fields of the Decade 1978-1988, 483–92. American Association of Petroleum Geologists, 1992. http://dx.doi.org/10.1306/m54555c30.

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2

Gillies, Alexandra. "“Being a Friend in a Nest of Vipers”." In Crude Intentions, 25–60. Oxford University Press, 2020. http://dx.doi.org/10.1093/oso/9780190940706.003.0002.

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During the boom years, companies, banks, and other private sector players used all kinds of tactics to tilt the oil sector playing field in their favor. They wined and dined top decision-makers, went into business with political insiders, and paid bribes, often via middlemen or fixers. Collusion and tax avoidance reared their heads too. Stories from Angola, Australia, Chad, Congo-Brazzaville, Libya, Nigeria, Norway, and the United States reveal the risks companies took in order to win a piece of the oil boom action.
3

"The Sunrise-Troubadour Gas-Condensate Fields, Timor Sea, Australasia." In Giant Oil and Gas Fields of the Decade 1990–1999, 189–209. American Association of Petroleum Geologists, 2003. http://dx.doi.org/10.1306/m78834c11.

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Тези доповідей конференцій з теми "Oil fields Australia":

1

Xia, Jinzhu, and Richard B. D'Souza. "Floating Production Platform Selection for Developing Deepwater Gas Fields off North West Australia." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/158717-ms.

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2

Barzi, Mohammad, and Ewen Siu Ming Sze. "Optimising the Jansz-Io Trunkline Next Project Using Integrated Production Modelling." In SPE Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/210655-ms.

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Abstract The Chevron-operated Gorgon asset is the largest single resource project in Australia, with a portfolio of offshore gas fields to supply gas via two trunklines (Gorgon and Jansz-Io) to a three-train, 15.6 MTPA LNG plant and a 300 TJ/D domestic gas plant on Barrow Island. Gorgon will be a legacy project, with decades of production anticipated from the development of backfill fields gas resources. To realise the value of the asset, it is critical to select the right projects and execute them at the right time. Greater Gorgon Integrated Production Modelling (IPM) has been developed by Chevron Australia's gas supply team on behalf of the Gorgon Joint Venture (Australian Subsidiaries of Chevron, ExxonMobil, Shell, Osaka Gas, Tokyo Gas and JERA) to specifically enable optimisation of both the subsurface and surface value chain. It integrates reservoirs, wells, and subsea production networks to enable rigorous assessment of various portfolio-level development and planning scenarios. The focus of this paper is on the Jansz-Io trunkline, which is initially supplied by the massive depletion drive Jansz-Io field, and the key decision of how to maintain production post development of the Gorgon Stage 2 (GS2) project. To inform this key decision, extensive evaluation was conducted using coupled INTERSECT (IX) IPM model to assess Jansz-Io Compression (J-IC) concepts (floating platform vs subsea compression). The IX-IPM model includes either detailed IX dynamic simulation or simplified material balance (MBAL) reservoirs, and a detailed production system that captures the full pressure hydraulics and their complex interactions. Using this IX-IPM model, a systematic staircase approach was applied, starting with a minimum facility concept, before sequentially adding more functionalities (power, capacity, phasing and backfill fields tie-in) and quantifying their incremental benefits. This enabled comprehensive understanding of the compression model's pressure hydraulic performance and various value trade-offs at each step. A fit-for-purpose, fixed power compression model was implemented to commence the staircase assessment. Once subsea compression was selected, and as the assessment matured, vendor compressor performance curves were adopted for more rigorous modelling. Overall, the Greater Gorgon coupled IX-IPM model has proved to be invaluable in the assessment of the J-IC concept select and supported the Final Investment Decision (FID) on J-IC in 2021. The coupled IX-IPM model is continually refined with greater engineering resolution and additional production history to support the wider Gorgon asset decisions.
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Bard, K. C., T. Harrison, and K. Meade. "Management Overview of the Integrated Studies of Nine Mature Gas Fields in the Cooper Basin of South Australia." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2000. http://dx.doi.org/10.2118/64389-ms.

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Wang*, Qi, and Huayao Zou. "Tracing the Charging Directions of Biodegraded Oils: A Case Study of the Large Oil Fields on the Shijiutuo Uplift, Bohai Bay Basin, China." In International Conference and Exhibition, Melbourne, Australia 13-16 September 2015. Society of Exploration Geophysicists and American Association of Petroleum Geologists, 2015. http://dx.doi.org/10.1190/ice2015-2209340.

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Rahman, Khalil, and Abbas Khaksar. "Fracture Growth and Injectivity Issues for Produced Water Reinjection Wells - Case Studies with Fields from offshore Australia and UK North Sea." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/158893-ms.

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Kuzmichev, Dmitry, Babak Moradi, Yulia Mironenko, Negar Hadian, Raffik Lazar, Laurent Alessio, and Faeez Rahmat. "Case Studies of Digitalized Locate the Remaining Oil Workflows Powered by Hybrid Data & Physics Methods." In Abu Dhabi International Petroleum Exhibition & Conference. SPE, 2021. http://dx.doi.org/10.2118/207958-ms.

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Abstract Mature fields already account for about 70% of the hydrocarbon liquids produced globally. Since the average recovery factor for oil fields is 30 to 35%, there is substantial quantities of remaining oil at stake. Conventional simulation-based development planning approaches are well established, but their implementation on large, complex mature oil fields remains challenging given their resource, time, and cost intensity. In addition, increased attention towards reduce carbon emissions makes the case for alternative, computationally-light techniques, as part of a global digitalisation drive, leveraging modern analytics and machine learning methods. This work describes a modern digital workflow to identify and quantify by-passed oil targets. The workflow leverages an innovative hybrid physics-guided data-driven, which generates historical phase saturation maps, forecasts future fluid movements and locate infill opportunities. As deliverables, a fully probabilistic production forecast is obtained for each drilling location, as a function of the well type, its geometry, and position in the field. The new workflow can unlock remaining potential of mature fields in a shorter time-frame and generally very cost-effectively compared to the advanced dynamic reservoir modelling and history-match workflows. Over the last 5 years, this workflow has been applied to more than 30 mature oil fields in Europe, Africa, the Middle East, Asia, Australia, and New Zealand. Three case studies’ examples and application environments of applied digital workflow are described in this paper. This study demonstrates that it is now possible to deliver digitalized locating the remaining oil projects, capturing the full uncertainty ranges, including leveraging complex multi-vintage spatial 4D datasets, providing reliable non-simulation physics-compliant data-driven production forecasts within weeks.
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Coffa*, Andre A., M. J. O’Mara, Connor McLaren, D. L. Thompson, James Karakatsanis, M. Hall, and Jeffrey Stilwell. "Enhancing Oil and Gas Production in Carbonate Turbidite Fields by the Study of High-Resolution Biostratigraphy, Facies and Fracture Variability: An Example From the NW Palawan Basin of the Philippines." In International Conference and Exhibition, Melbourne, Australia 13-16 September 2015. Society of Exploration Geophysicists and American Association of Petroleum Geologists, 2015. http://dx.doi.org/10.1190/ice2015-2213451.

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Skoczylas, Paul. "Update of Field Experience with Hydraulically Regulated Progressing Cavity Pumps." In SPE Artificial Lift Conference and Exhibition - Americas. SPE, 2022. http://dx.doi.org/10.2118/209764-ms.

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Abstract The patented hydraulically regulated progressing cavity pump (HRPCP) has been tested previously in the oilfield, but its range of application is being expanded. The HRPCP can be used in any well where a PCP would be installed and provides added protection in cases where significant free gas may be present. It is as effective as a standard PCP in pumping high viscosity fluids or fluids with high solids content, or both. It retains its effectiveness as a pump even when no gas is present, although its primary benefit is the increase in PCP run-life when there is free gas present at the pump intake. The present study is to evaluate the performance of the HRPCP in new applications around the world. Previous publications on the HRPCP have looked at installations in Argentina, Venezuela, and Kuwait. There are now installations in coal seam gas (CSG) in Queensland, Australia, gassy oil wells in Colombia, and heavy oil wells in the Lloydminster area of Canada, and in wells in the newer operations in the Clearwater formation near Slave Lake in Alberta, Canada. In Canada in particular, there have been 27 installations in thirteen fields by six oil companies at the time this paper was prepared. In Colombia, the HRPCPs were installed in new wells that were expected to produce high gas volumes while still producing some sand. In the Australian CSG wells, operators wanted to land the pumps higher in the well to avoid solids problems, knowing that this would result in higher gas volume fraction at the pump intake, so the HRPCP was chosen. In the Canadian heavy oil areas, there can be a higher GOR in many wells than there was in the past, so the gas fraction at the pump intake can now be a larger factor in PCP run-life than in the past. In some of the Canadian wells, the performance data of the previous installation is available for a direct comparison. Overall, the run-life of the HRPCP has been excellent in comparison to either expectations or to the run-life of previous PCPs in the same wells or fields. In one example well, the previous PCP suffered a significant drop in efficiency (from 60% to 10%) after 90 days. The HRPCP that followed it has been running at 70% efficiency for over 180 days (and still going). In Colombia, the operator saw reduced load on the pump due to the "gas lift" effect from the gas going through the pump and up the tubing, while exceeding expectations for run-life.
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Christensen, David, and Andrew Re. "Is Australia Prepared for the Decommissioning Challenge? A Regulator's Perspective." In SPE Symposium: Decommissioning and Abandonment. SPE, 2021. http://dx.doi.org/10.2118/208483-ms.

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Abstract The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) is Australia's independent expert regulator for health and safety, structural (well) integrity and environmental management for all offshore oil and gas operations and greenhouse gas storage activities in Australian waters, and in coastal waters where regulatory powers and functions have been conferred. The Australian offshore petroleum industry has been in operation since the early 1960s and currently has approximately 57 platforms, 11 floating facilities, 3,500km of pipelines and 1000 wells in operation. Many offshore facilities are now approaching the end of their operational lives and it is estimated that over the next 50 years decommissioning of this infrastructure will cost more than US$40.5 billion. Decommissioning is a normal and inevitable stage in the lifetime of an offshore petroleum project that should be planned from the outset and matured throughout the life of operations. While only a few facilities have been decommissioned in Australian waters, most of Australia's offshore infrastructure is now more than 20 years old and entering a phase where they require extra attention and close maintenance prior to decommissioning. When the NOGA group of companies entered liquidation in 2020 and the Australian Government took control of decommissioning the Laminaria and Corallina field development it became evident that there were some fundamental gaps in relation to decommissioning in the Australian offshore petroleum industry. There are two key focus areas that require attention. Firstly, regulatory reform including policy change and modification to regulatory practice. Secondly, the development of visible and robust decommissioning plans by Industry titleholders. The purpose of this paper is to highlight the importance and benefit of adopting good practice when planning for decommissioning throughout the life cycle of a petroleum project. Whilst not insurmountable, the closing of these gaps will ensure that Australia is well placed to deal with the decommissioning challenge facing the industry in the next 50 years.
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Elliott, Paul, and Melissa Gilbert. "Produced Water Debottlenecking Delivers Low Cost Incremental Production for the Pyrenees FPSO." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21848-ms.

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Abstract The Pyrenees FPSO development, located offshore Western Australia, produced first oil in 2010. By 2017, the topsides facility had became constrained by produced water production, reaching the facility design capacity of 110,000 bbl/d. A strong business driver was presented to debottleneck the water processing train to increase oil production, for which a holistic, system-wide approach was required. A series of brownfield debottlenecking scopes were identified and assessed using a systematic value versus risk approach. The key value drivers were recognised as incremental oil production, execution timing and cost. The assessment focused on improving Produced Water Re-Injection (PWRI) pump throughput and uptime, optimising the produced water treatment and overboard discharge systems, and the use of cargo oil tanks for separation. Project execution was phased to allow early debottlenecking gains to be unlocked as major modification scopes were progressed. The most capital intensive project executed was the installation of a side-stream Compact Flotation Unit package to polish and discharge produced water overboard. In combination, the projects delivered a 36% increase in produced water handling capacity to 150,000 bbl/d, accelerating 8.5% production over a 3-year period. In addition, the projects increased facility uptime by 1.8% and reduced the risk of late-life produced water injection system failures. This case study illustrates a logical and systematic approach to production debottlenecking, resulting in a significant production uplift, safely delivered for low relative CAPEX investment. The processes described and lessons learned in this project may be applicable to other maturing fields and facilities, and can be used to assist resolving late-life produced water challenges.

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