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1
Ronalds, B. F. „TOWARDS DEVELOPMENT OF AUSTRALIA’S LARGE DEEPWATER GAS FIELDS“. APPEA Journal 45, Nr. 1 (2005): 35. http://dx.doi.org/10.1071/aj04003.
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Australia can anticipate a more extensive gas production future than any other OECD country. At the same time, much of our gas resource is located in large, remote, deepwater reservoirs. There is very little experience in bringing such fields to market, although several current developments internationally indicate that a new era of deepwater gas production is beginning. The limited knowledge base suggests that Australia could, and indeed should, take a lead in developing strategies and technologies necessary to produce major deepwater gas and gascondensate fields in an economically, environmentally and socially sustainable manner in the long-term.This paper draws on a comprehensive database of deepwater field developments around the world to identify specific capability gaps, and the technology breakthroughs that may enable them to be overcome. Emphasis is placed on both floating facilities and all-subsea production solutions, with ultra-long tiebacks and floating LNG bringing particular benefits in the Australian context. Compact GTL is a key enabling technology for remote deepwater fields with associated gas.
2
Oen, P. M. „THE DEVELOPMENT OF THE GREATER GORGON GAS FIELDS“. APPEA Journal 43, Nr. 2 (2003): 167. http://dx.doi.org/10.1071/aj02073.
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The vast reservoirs of untapped natural gas found in the Greater Gorgon area off Western Australia’s Pilbara coast contain in excess of 11 billion cubic metres (40 trillion cubic feet) of gas, representing some 25% of Australia’s total known gas resources. Developing this world-class resource is a matter of national importance as it would secure Australia’s position as a leading gas producer and provide a huge new source of wealth for both Australia and Western Australia.The key to unlocking the Greater Gorgon reserves is the development of the Gorgon field—one of the largest single gas fields ever discovered in Australia. Establishment of gas processing infrastructure on Barrow Island—which lies between the gas field and the mainland—would provide a catalyst for the future development of other Greater Gorgon area fields. Gas would be processed at that facility and transported through a gas pipeline to shore, enabling large new competitive supplies of gas to be delivered to the mainland.While the development of Gorgon gas would bring significant benefits—A$11 billion investment, A$17 billion in Commonwealth and State taxes and royalties and an annual increase in the nation’s export income of A$2.5 billion—the Gorgon gas field presents some unique challenges. With little associated liquid hydrocarbons, development costs must be kept to a minimum to maintain commercial viability. In addition, Gorgon gas contains a relatively high content of carbon dioxide (CO2) which results in substantial treatment cost and relatively large potential greenhouse gas emissions.Barrow Island—both an internationally important nature reserve and Australia’s largest operating onshore oilfield—has emerged as the development location that would enable gas from the Gorgon gas fields to be competitive in today’s market. The Western Australian Government has said the Gorgon venture (ChevronTexaco, Shell and ExxonMobil) must demonstrate at a strategic level that the proposed Gorgon gas development on Barrow Island can generate economic and social benefits, provide net conservation benefits and mitigate potential on-site impacts.
3
Salmachi, Alireza, Mojtaba Rajabi, Carmine Wainman, Steven Mackie, Peter McCabe, Bronwyn Camac und Christopher Clarkson. „History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review“. Energies 14, Nr. 9 (05.05.2021): 2651. http://dx.doi.org/10.3390/en14092651.
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Coal seam gas (CSG), also known as coalbed methane (CBM), is an important source of gas supply to the liquefied natural gas (LNG) exporting facilities in eastern Australia and to the Australian domestic market. In late 2018, Australia became the largest exporter of LNG in the world. 29% of the country’s LNG nameplate capacity is in three east coast facilities that are supplied primarily by coal seam gas. Six geological basins including Bowen, Sydney, Gunnedah, Surat, Cooper and Gloucester host the majority of CSG resources in Australia. The Bowen and Surat basins contain an estimated 40Tcf of CSG whereas other basins contain relatively minor accumulations. In the Cooper Basin of South Australia, thick and laterally extensive Permian deep coal seams (>2 km) are currently underdeveloped resources. Since 2013, gas production exclusively from deep coal seams has been tested as a single add-on fracture stimulation in vertical well completions across the Cooper Basin. The rates and reserves achieved since 2013 demonstrate a robust statistical distribution (>130 hydraulic fracture stages), the mean of which, is economically viable. The geological characteristics including coal rank, thickness and hydrogeology as well as the present-day stress pattern create favourable conditions for CSG production. Detailed analyses of high-resolution borehole image log data reveal that there are major perturbations in maximum horizontal stress (SHmax) orientation, both spatially and with depth in Australian CSG basins, which is critical in hydraulic fracture stimulation and geomechanical modelling. Within a basin, significant variability in gas content and permeability may be observed with depth. The major reasons for such variabilities are coal rank, sealing capacity of overlying formations, measurement methods, thermal effects of magmatic intrusions, geological structures and stress regime. Field studies in Australia show permeability may enhance throughout depletion in CSG fields and the functional form of permeability versus reservoir pressure is exponential, consistent with observations in North American CSG fields.
4
de Rijke, Kim. „The Agri-Gas Fields of Australia: Black Soil, Food, and Unconventional Gas“. Culture, Agriculture, Food and Environment 35, Nr. 1 (Juni 2013): 41–53. http://dx.doi.org/10.1111/cuag.12004.
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5
Korn, B. E., R. P. Teakle, D. M. Maughan und P. B. Siffleet. „THE GERYON, ORTHRUS, MAENAD AND URANIA GAS FIELDS, CARNARVON BASIN, WESTERN AUSTRALIA“. APPEA Journal 43, Nr. 1 (2003): 285. http://dx.doi.org/10.1071/aj02015.
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The Geryon, Orthrus, Maenad and Urania Gas Fields are located in permit WA-267-P in approximately 1,200 m of water, and between 35 km northwest and 70 km north of the Gorgon Gas Field in the offshore Carnarvon Basin of Western Australia. Five wells were drilled in these fields between August 1999 and February 2001 as part of a six-well, three-year obligatory drilling program. The primary objectives were late Triassic sandstones of the upper Mungaroo Formation. The Geryon and Urania Fields are three-way footwall structures, while the Orthrus and Maenad Fields comprise four-way horst structures where progressively older units subcrop against the Callovian Unconformity. All objective reservoirs were amplitude associated and had strong AVO signatures, which was instrumental in the high exploration success rate and excellent exploration prediction of OGIP from seismic data.This paper will briefly discuss the description of late Triassic and early Jurassic reservoirs and the transition of the AA sand of the Mungaroo Formation from fluvial to marginal marine facies in the Greater Gorgon Area, the recent drilling results of the Triassic Prospects in WA-267-P, and the geophysical attributes of the AA sand Mungaroo Formation reservoirs.The WA-267-P Triassic Gas Fields are estimated to contain approximately 210 billion m3 (7.4 TCF) recoverable sales gas. The close proximity of these Triassic gas fields to each other, the clean gas composition and size of resource base suggests these fields are excellent candidates for a future gas development in Western Australia.
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Constantine, Andrew, Glenn Morgan, Robin O'Leary und Simon Smith. „The Halladale–Speculant fields: the first nearshore gas fields to be developed from mainland Australia“. APPEA Journal 58, Nr. 1 (2018): 255. http://dx.doi.org/10.1071/aj17180.
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Extended-reach drilling (ERD) is becoming an increasingly common technique used to explore for hydrocarbons and develop fields in areas where simple vertical wells cannot be drilled due to access problems, stakeholder concerns, environmental issues, poor reservoir quality and/or cost. While these types of wells are generally more expensive and technically challenging to drill than vertical wells, they can be very cost-effective, and if a discovery is made, considerably quicker to monetise when future development costs are also taken into consideration, particularly in offshore environments. In 2014–2015, the conventional Exploration and Production division of Origin Energy (now Lattice Energy) drilled three onshore-to-offshore ERD wells and a geological sidetrack in the Otway Basin with horizontal offsets of 1929, 2576, 4239 and 5152 m targeting an undeveloped gas field (Halladale) and exploration prospect (Speculant) located in Victorian state waters near Port Campbell. The three wells (Halladale-2, Speculant-1 and Speculant-2) and sidetrack (Speculant-2ST1) were drilled during a single drilling campaign from the same pad to reduce mobilisation, drilling and development costs. Halladale-2 was designed to develop the Halladale Field, while Speculant-1, -2 and -2ST1 were designed to evaluate the Speculant Prospect. Both Speculant wells and the sidetrack encountered significant gas columns with Speculant-1 and Speculant-2ST1 subsequently completed as producers after being successfully flow tested. A 33 km onshore pipeline was then constructed to transport the gas from Halladale and Speculant back to the Otway Gas Plant (OGP) for processing and sale. The arrival of first gas at the OGP from the Halladale and Speculant gas fields on 26 August 2016 marked a significant milestone for Origin Energy in terms of accelerated project delivery. It also represented the end of a 15-year journey for Halladale from exploration to discovery to development. The drilling campaign also set several records in the process with: (1) Speculant being the first offshore field to be discovered from mainland Australia; (2) Halladale and Speculant being the first offshore fields to produce gas back to mainland Australia from onshore wells; (3) Halladale-2, Speculant-1 and Speculant-2 being the three longest onshore-to-offshore wells drilled to date in Australia (in horizontal departure terms); and (4) Halladale-2 being the longest well (in mMDRT terms) drilled to date in the Otway Basin. Speculant is a good example of how transition zone (TZ) seismic and ERD technology can be used successfully to explore and develop resources in areas previously considered too difficult by using more conventional seismic acquisition and drilling technology.
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Redmond, Helen. „Impact of energy generation on health: unconventional gas“. Proceedings of the Royal Society of Victoria 126, Nr. 2 (2014): 38. http://dx.doi.org/10.1071/rs14038.
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In this age of human-induced climate change, drilling for unconventional gas is expanding rapidly. In the United States hundreds of thousands of wells tap into shale gas, tight sands gas and coal seam gas (CSG). In Australia we have large CSG fields containing thousands of wells in Queensland, and several smaller fields in New South Wales and Victoria. The scale of proposed development of shale gas in South Australia, Western Australia and the Northern Territory will eclipse CSG in the eastern states. Yet unconventional gas extraction has the potential to undermine every single one of the environmental determinants of health: clean air, clean water, a safe food supply and a stable climate.1 To ensure health, water has to be sufficient in quality and quantity. The unconventional gas industry impacts both in a number of ways. Water quality can be threatened both by chemicals in drilling and fracking fluids, and by chemicals mobilised from deep underground in the process.
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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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Espig, Martin, und Kim de Rijke. „Navigating Coal Seam Gas Fields: Ethnographic Challenges in Queensland, Australia“. Practicing Anthropology 38, Nr. 3 (Juni 2016): 44–45. http://dx.doi.org/10.17730/0888-4552-38.3.44.
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Pulsford, Will. „A reserves driven view of the eastern Australian gas supply and demand balance through the 2020's“. APPEA Journal 57, Nr. 2 (2017): 526. http://dx.doi.org/10.1071/aj16217.
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The Australian Energy Market Operator (AEMO) issued a Gas Statement of Opportunities in March 2016, which reports that gas supply to the domestic and liquefied natural gas markets in eastern Australia will be largely satisfied by proved and probable reserves until 2026 and by the addition of contingent resources until 2030. However, in parallel, there are widely reported concerns by energy consumers of insufficient gas supplies to meet demand by the early 2020s and a lack of new gas supplies to replace existing expiring contracts. Gas shortages have already contributed to black outs and load shedding events in South Australia. This paper reviews the eastern Australian gas supply position at a basin level. The AEMO basin level supply forecasts are reviewed and adjusted to generate forward profiles, which are consistent with reported reserves levels, production histories and depletion behaviour of typical gas fields. The revised supply forecast is compared with the AEMO’s demand profiles, and the likely commercial behaviour of key participants in the market is considered to build a picture of the domestic gas supply-demand balance through the 2020s. This analysis provides a transparent link from market outcomes back to the underlying reserves classifications to guide interpretation of supply-demand forecasts, and highlights the critical role of key suppliers in the eastern Australian gas market in the coming decade.
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Michael, Karsten, Jonathan Ennis-King, Julian Strand, Regina Sander und Chris Green. „Suitability of depleted gas fields for underground hydrogen storage in Australia“. APPEA Journal 62, Nr. 2 (13.05.2022): S456—S460. http://dx.doi.org/10.1071/aj21055.
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If there is a significant adoption of hydrogen in Australia as an energy carrier, it will be necessary to have storage options to buffer the fluctuations in supply and demand, both for domestic use and for export. For large-scale storage in a single location, underground hydrogen storage (UHS) is the preferred option for reasons of both cost and safety. The search for suitable sites for UHS will depend on the proximity to potential hydrogen generation, ports, and processing infrastructure, as well as CO2 storage options for blue hydrogen. Although UHS in salt caverns is an established technology, most of the suitable salt deposits in Australia (in the Canning Basin in WA, the Adavale Basin in Qld, and the Amadeus Basin in the NT) are not always well-located for production and transport. Depleted gas fields have been used previously for storage of hydrogen-rich gas mixtures as well as natural gas storage and appear to be the most promising and widely available UHS option in Australia. There appears to be sufficient storage capacity in depleted gas fields in most of the geographic areas with hydrogen production potential. However, there are still technical challenges to be addressed, such as the extent of possible contamination of the stored hydrogen with residual hydrocarbons, and the possible effects of geochemical reactions and microbial processes.
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Sanford, Elizabeth, und Rama Alapati. „A new, field-proven, cost-effective solution for MEG regeneration unit issues in offshore Australia gas production“. APPEA Journal 51, Nr. 1 (2011): 193. http://dx.doi.org/10.1071/aj10013.
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Several gas fields are being developed off the coast of Western Australia. The risk for hydrate blockages in these fields is high and presents several challenges for hydrate inhibition, including high subcoolings, low water salinities, and high system temperatures. The current strategy is to use mono-ethylene glycol (MEG) for hydrate inhibition, which includes MEG regeneration units (MRUs) in the design of the facilities. The installation and maintenance of MRUs capable of handling the large required volumes of MEG is costly and other issues such as scale, foaming, and accumulation are a concern when using an MRU. Therefore, the use of a low dosage hydrate inhibitor (LDHI) is being considered for some developments. Kinetic hydrate inhibitors (KHIs) are typically considered for gas fields, not anti-agglomerate low dosage hydrate inhibitors (AA-LDHIs). KHIs, however, are not effective at high subcoolings and can become unstable when subjected to the high temperatures of the MRUs. Instead, a new generation of AA-LDHI chemistry can be considered for Australian gas fields. Field data will be presented supporting the new AA-LDHI’s effectiveness in inhibiting hydrate blockages in a gas/condensate field, eliminating the need for MEG and the MRU. The new AA-LDHI chemistry is being evaluated for several Australia projects, and data supporting the chemistry’s stability at temperatures greater than 150°C and its effectiveness with low-water salinities will also be presented. The new AA-LDHI chemistry could eliminate the need for MEG or greatly reduce the volume of MEG required for inhibition, which would reduce CAPEX and OPEX.
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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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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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Howard, D. „UNDERGROUND GAS STORAGE-LEGAL ANT REGULATORY REQUIREMENTS IN AUSTRALIA“. APPEA Journal 39, Nr. 1 (1999): 663. http://dx.doi.org/10.1071/aj98045.
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The storage of gas in underground naturally occurring reservoirs takes place in a variety of forms and for a variety of reasons. In many jurisdictions within Australia, the regulatory framework to deal properly with underground gas storage requires attention and, in some cases, significant refinement. Underground natural reservoir storage of gas in Australia is an option which is being increasingly investigated as fields close to infrastructure (such as pipelines and processing plants) become depleted and alternative uses are sought for those depleted reservoirs. In addition, gas storage may give flexibility to spot gas sales and other commercial operations, and facilitate greater market sophistication. Accordingly, it is important for the industry in Australia to understand the legal implications and their impact on this type of storage.
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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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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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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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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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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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Parker, K. A. „THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA“. APPEA Journal 32, Nr. 1 (1992): 67. http://dx.doi.org/10.1071/aj91007.
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The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.
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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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Pulsford, Will. „Meeting demand in a new era of east coast gas supply“. APPEA Journal 59, Nr. 2 (2019): 686. http://dx.doi.org/10.1071/aj18045.
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Historically LNG projects have been established to monetise large gas finds in remote areas with little existing gas demand. The development of gas supply to the LNG project generally stimulated demand growth in the domestic gas market. As the supplying fields depleted, the LNG projects faced competition with domestic producers for declining gas supplies, but this was late in the project life when LNG plant capital had already been recovered. Recently, LNG export projects have been established within existing mature gas markets, most notably in Australia and North America. These plants now face competition with domestic gas consumers for access to feed gas from the beginning of their operational life when strong revenue has the greatest impact on the return earned on capital invested, with the greatest stress felt in Australia. This paper considers the underlying causes of domestic price rises experienced in Australia following the start-up of LNG export supplied from gas fields linked to the domestic market and the response by both plant developers/operators and the government. This historical view is used to inform forecasts of how the east coast gas market will react to the interplay between domestic and LNG plant demand, declining Bass Strait production, maturing CSG operations, LNG imports and completion of the Northern Gas Pipeline. In particular the ability of gas supply and pipeline capacity to meet the strongly seasonal domestic demand in Victoria and to a lesser extent NSW will be examined, together with the linkage to counter-cyclical seasonal demand for LNG from the Queensland LNG export plants in the key north Asian markets.
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Carpenter, Chris. „Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons“. Journal of Petroleum Technology 73, Nr. 08 (01.08.2021): 51–52. http://dx.doi.org/10.2118/0821-0051-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, 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. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.
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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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Byrne, Philip. „Evolution of the east coast gas market“. APPEA Journal 58, Nr. 2 (2018): 513. http://dx.doi.org/10.1071/aj17236.
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This extended abstract reviews how the east coast gas market is managing the major transition from being a ring-fenced domestic market to being part of an interconnected global trading market, and what still needs to be done to rebalance after half a decade of disruption. The east coast gas market has a great future ahead of it, but only if Australia acts quickly to open up access to new gas supply sources as existing gas fields mature and decline. The presence of a global liquefied natural gas (LNG) supply market on the east coast now provides an incentive for gas producers to invest in new provinces and new plays at a scale the domestic gas market could not have supported on its own. This can only be good for competition in the east coast gas market over the medium to long term, and potentially open up enormous supplies for the growth of Australian industry, akin to the US shale gas revolution. To make the most of the resources and infrastructure we now have on the eastern seaboard, there is a role for governments to play in ensuring access to resources and providing stable, coordinated, robust energy policy and regulatory frameworks that attract investment in further growth in the gas sector, the benefits of which will flow on to Australian industry more generally.
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Ziehn, T., A. Nickless, P. J. Rayner, R. M. Law, G. Roff und P. Fraser. „Greenhouse gas network design using backward Lagrangian particle dispersion modelling – Part 1: Methodology and Australian test case“. Atmospheric Chemistry and Physics Discussions 14, Nr. 6 (19.03.2014): 7557–95. http://dx.doi.org/10.5194/acpd-14-7557-2014.
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Abstract. This paper describes the generation of optimal atmospheric measurement networks for determining carbon dioxide fluxes over Australia using inverse methods. A Lagrangian particle dispersion model is used in reverse mode together with a Bayesian inverse modelling framework to calculate the relationship between weekly surface fluxes and hourly concentration observations for the Australian continent. Meteorological driving fields are provided by the regional version of the Australian Community Climate and Earth System Simulator (ACCESS) at 12 km resolution at an hourly time scale. Prior uncertainties are derived on a weekly time scale for biosphere fluxes and fossil fuel emissions from high resolution BIOS2 model runs and from the Fossil Fuel Data Assimilation System (FFDAS), respectively. The influence from outside the modelled domain is investigated, but proves to be negligible for the network design. Existing ground based measurement stations in Australia are assessed in terms of their ability to constrain local flux estimates from the land. We find that the six stations that are currently operational are already able to reduce the uncertainties on surface flux estimates by about 30%. A candidate list of 59 stations is generated based on logistic constraints and an incremental optimization scheme is used to extend the network of existing stations. In order to achieve an uncertainty reduction of about 50% we need to double the number of measurement stations in Australia. Assuming equal data uncertainties for all sites, new stations would be mainly located in the northern and eastern part of the continent.
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Baker, G. L., und W. R. Skerman. „THE SIGNIFICANCE OF COAL SEAM GAS IN EASTERN QUEENSLAND“. APPEA Journal 46, Nr. 1 (2006): 329. http://dx.doi.org/10.1071/aj05018.
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The commercial production of coal seam gas [CSG] in Australia is only a decade old. Over the last 10 years it has become a significant part of the Australian gas industry, particularly in Queensland where about 31 PJ or 30% of all natural gas used in the State was recovered from coal seams in eastern Queensland. In 2005 CSG was expected to have supplied 55 PJ or 44 % of the eastern Queensland gas demand. The mining, mineral processing and power generations in northwest Queensland, serviced by the Carpentaria Gas Pipeline, will continue to use gas from the Cooper-Eromanga Basin.The CSG industry is reaching a stage of maturity following the commissioning of a number of fields while some significant new projects are either in the commissioning phase or under development. By the end of 2008 CSG production in Queensland is expected to reach 150 PJ per year, the quantity needed to meet Gas Supply Agreements for CSG that are presently in place.Certified Proved and Probable (2P) gas reserves at 30 June 2005 in eastern Queensland were calculated to be 4,579 PJ, of which 4,283 PJ were CSG. Gas reserves (2P) for eastern Queensland a decade earlier were less than 100 PJ with those for CSG being less than 5 PJ.The coal seam gas industry in both the Bowen and Surat basins—which includes major gas producers such as Origin Energy Limited and Santos Limited along with smaller producers such as Arrow Energy NL, CH4 Gas Limited, Molopo Australia Limited and Queensland Gas Company Limited—is now accepted by major gas users as being suppliers of another reliable source of natural gas.
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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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Northcott, I. W., und R. C. M. McDonough. „TARDIS: A COMPUTER MODEL TO PREDICT FUTURE GAS SUPPLY“. APPEA Journal 29, Nr. 1 (1989): 41. http://dx.doi.org/10.1071/aj88007.
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Because much of South Australia's electricity is gas- generated the future supply of gas from the Cooper Basin is the central issue in the state's energy planning. Available proven reserves of gas are only sufficient to meet the state's demand until the early 1990s.The TARDIS computer program has therefore been written to enable production scheduling of proved and probable gas reserves and, by using historically derived discovery- rate algorithms, to calculate the exploration- drilling effort necessary to meet future gas supply requirements.The mandatory requirement was that the program should complete a simulation within several minutes. This necessitated the decomposition of complex engineering procedures to a simple level without unacceptable loss of accuracy.TARDIS simulates a network of discovered and undiscovered fields which may be allocated to four zones. The fields supply a defined gas market via a processing plant. Appraisal drilling in zones one and three converts estimates of possible gas- in- place into the proved and probable category after allowance for risk. Exploration drilling in zones two and four predicts the discovery of additional reserves using an algorithm, calibrated by historical data, based on the observation that field size decreases as cumulative drilling effort increases.Fields are scheduled in development priority and sufficient fields are brought on line to satisfy a defined gas market. The required number of on- line fields is determined by the cumulative field deliverability and the peak day gas demand. As each field comes on line development wells are drilled until the field is fully developed.A processing plant is simulated to produce sales gas which is within the required specification for chemical composition. The quantity of each of the ancillary gaseous and liquid products is also computed.Data entry and graphical display of results is processed with a spreadsheet and the program runs on a personal computer.TARDIS enables an assessment of whether the current and forecast drilling effort is likely to discover sufficient reserves to satisfy the market. It has proved an invaluable tool in investigating future gas- supply options for South Australia.
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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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Holford, Simon, Nick Schofield, Mark Bunch, Alan Bischoff und Ernest Swierczek. „Storing CO2 in buried volcanoes“. APPEA Journal 61, Nr. 2 (2021): 626. http://dx.doi.org/10.1071/aj20056.
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Australia contains rich natural gas resources, but many of Australia’s currently producing and undeveloped gas fields contain relatively high CO2 contents; if not captured and stored, the venting of co-produced CO2 could hinder efforts to meet Australia’s emission reduction targets. The most mature technology for isolating produced CO2 from the atmosphere is by containing it in deep sedimentary formations (e.g. saline aquifers or depleted oil and gas reservoirs). The effectiveness of this approach is dependent on factors such as reservoir capacity, the presence of low-permeability seals that physically impede vertical migration of injected CO2, the chemical reactivity of both reservoir and seal minerals, the risk for leakage, and a gas-entrapping structure. An alternative and attractive mechanism for permanent storage of CO2 is geochemical or mineral trapping, which involves long-term reactions of CO2 with host rocks and the formation of stable carbonate minerals that fill the porosity of the host rock reservoir. Natural mineral carbonation is most efficient in mafic and ultramafic igneous rocks, due to their high reactivity with CO2. Here we review the outcomes from a series of recent pilot projects in Iceland and the United States that have demonstrated high potential for rapid, permanent storage of CO2 in basalt reservoirs, and explore the practicalities of geochemical trapping of CO2 in deeply buried basaltic volcanoes and lava fields, which are found in many basins along the southern (e.g. Gippsland Basin) and northwestern (e.g. Browse Basin) Australian margins, often in close proximity to natural gas fields with high CO2 content.
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Campbell, G. D. „A CASE FOR A NATIONAL PIPELINE GRID FOR NATURAL GAS“. APPEA Journal 26, Nr. 1 (1986): 36. http://dx.doi.org/10.1071/aj85004.
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The development of an integrated natural gas pipeline system should be a goal within a national energy policy for Australia. Australia has in excess of 100 years supply of natural gas in the proved and probable category and another 250 years of supply that we can expect to find with reasonable confidence.There are clear indications that if markets can be created or developed, gas producers will respond by establishing reserves to service those markets. A recent example is the rapid increase in proved/probable reserves established in the Amadeus Basin following the Northern Territory Government's interest in constructing a pipeline to Darwin.The Australian Gas Association has taken the view that reserves will be a limiting factor in natural gas development and hence pipeline systems will only be developed to access more remote and expensive fields as the current reserves are depleted. This paper takes the contrary view that natural gas reserves eventuate from market driven policy. That is, if an attractive market is opened to natural gas then reserves will be forthcoming.A number of policy guidelines which would allow the economic development of a national natural gas grid are the key incentives for the explorers.Utilisation of natural gas for the generation of electricity in New South Wales to the extent of 10 per cent of the annual load would enhance the performance of the total electrical system. By providing this substantial natural gas market an economic basis can be provided for the proposed national grid links.For the electrical generation market in New South Wales gas producers should be guaranteed a well head price of say $1.50 to $2.00 a gigajoule for onshore gas.
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Miyazaki, S. „COAL SEAM GAS EXPLORATION, DEVELOPMENT AND RESOURCES IN AUSTRALIA: A NATIONAL PERSPECTIVE“. APPEA Journal 45, Nr. 1 (2005): 131. http://dx.doi.org/10.1071/aj04011.
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A total of 2,223 PJ of proved plus probable gas reserves has been identified in coal seam gas fields and pilot production areas in Australia. The production of coal seam gas is rapidly growing, reaching about 40 PJ per year in 2003. A total of more than 108 PJ will be supplied annually by the end of 2007 under existing contracts, representing about 9% of Australia’s projected total primary consumption of natural gas. About two thirds of Queensland’s natural gas consumption will be met by coal seam gas by the end of 2007. Further expansion of the coal seam gas industry depends largely on the medium-term production performance of the pioneering production projects now in operation.The long-term production performance of a coal seam gas well is not well understood. Analogues of conventional natural gas have often been applied to the estimation process of coal seam gas reserves without proper consideration of the fundamental differences in trapping mechanisms and production techniques. Definitions of petroleum reserves recommended by various organisations are not always applicable to coal seam gas, and the inconsistent application of reserves definitions may have resulted in inconsistencies in reserves reporting in Australia.
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Neininger, Bruno G., Bryce F. J. Kelly, Jorg M. Hacker, Xinyi LU und Stefan Schwietzke. „Coal seam gas industry methane emissions in the Surat Basin, Australia: comparing airborne measurements with inventories“. Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences 379, Nr. 2210 (27.09.2021): 20200458. http://dx.doi.org/10.1098/rsta.2020.0458.
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Coal seam gas (CSG) accounts for about one-quarter of natural gas production in Australia and rapidly increasing amounts globally. This is the first study worldwide using airborne measurement techniques to quantify methane (CH 4 ) emissions from a producing CSG field: the Surat Basin, Queensland, Australia. Spatially resolved CH 4 emissions were quantified from all major sources based on top-down (TD) and bottom-up (BU) approaches, the latter using Australia's UNFCCC reporting workflow. Based on our TD-validated BU inventory, CSG sources emit about 0.4% of the produced gas, comparable to onshore dry gas fields in the USA and The Netherlands, but substantially smaller than in other onshore regions, especially those where oil is co-produced (wet gas). The CSG CH 4 emission per unit of gas production determined in this study is two to three times higher than existing inventories for the region. Our results indicate that the BU emission factors for feedlots and grazing cattle need review, possibly requiring an increase for Queensland's conditions. In some subregions, the BU estimate for gathering and boosting stations is potentially too high. The results from our iterative BU inventory process, which feeds into TD data, illustrate how global characterization of CH 4 emissions could be improved by incorporating empirical TD verification surveys into national reporting. This article is part of a discussion meeting issue ‘Rising methane: is warming feeding warming? (part 1)’.
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Ziehn, T., A. Nickless, P. J. Rayner, R. M. Law, G. Roff und P. Fraser. „Greenhouse gas network design using backward Lagrangian particle dispersion modelling − Part 1: Methodology and Australian test case“. Atmospheric Chemistry and Physics 14, Nr. 17 (10.09.2014): 9363–78. http://dx.doi.org/10.5194/acp-14-9363-2014.
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Abstract. This paper describes the generation of optimal atmospheric measurement networks for determining carbon dioxide fluxes over Australia using inverse methods. A Lagrangian particle dispersion model is used in reverse mode together with a Bayesian inverse modelling framework to calculate the relationship between weekly surface fluxes, comprising contributions from the biosphere and fossil fuel combustion, and hourly concentration observations for the Australian continent. Meteorological driving fields are provided by the regional version of the Australian Community Climate and Earth System Simulator (ACCESS) at 12 km resolution at an hourly timescale. Prior uncertainties are derived on a weekly timescale for biosphere fluxes and fossil fuel emissions from high-resolution model runs using the Community Atmosphere Biosphere Land Exchange (CABLE) model and the Fossil Fuel Data Assimilation System (FFDAS) respectively. The influence from outside the modelled domain is investigated, but proves to be negligible for the network design. Existing ground-based measurement stations in Australia are assessed in terms of their ability to constrain local flux estimates from the land. We find that the six stations that are currently operational are already able to reduce the uncertainties on surface flux estimates by about 30%. A candidate list of 59 stations is generated based on logistic constraints and an incremental optimisation scheme is used to extend the network of existing stations. In order to achieve an uncertainty reduction of about 50%, we need to double the number of measurement stations in Australia. Assuming equal data uncertainties for all sites, new stations would be mainly located in the northern and eastern part of the continent.
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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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Seggie, Robert, Simon Lang, Neil Marshall, K. Adamson, W. Bailey, T. Prater und D. Dawson. „The geology of the Brecknock, Calliance and Torosa gas fields, Browse Basin, Western Australia“. ASEG Extended Abstracts 2019, Nr. 1 (11.11.2019): 1. http://dx.doi.org/10.1080/22020586.2019.12072915.
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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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Young, Wendy May, und David Lumley. „Feasibility analysis for time-lapse seafloor gravity monitoring of producing gas fields in the Northern Carnarvon Basin, offshore Australia“. GEOPHYSICS 80, Nr. 2 (01.03.2015): WA149—WA160. http://dx.doi.org/10.1190/geo2014-0264.1.
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Highly accurate seafloor gravity data can detect small density changes in subsurface hydrocarbon reservoirs by precisely repositioning the gravimeters on the seafloor. In producing gas fields, these small density changes are primarily caused by production-related changes to the pressure and gas/fluid saturations in the reservoir pore space. Knowledge of the pressure and saturation changes is vital to optimize the gas recovery, especially in offshore environments in which wells are expensive and sparse. We assessed the feasibility of time-lapse seafloor gravity monitoring for the giant gas fields in Australia’s premier hydrocarbon province, the Northern Carnarvon Basin. We determined that gravity monitoring is more feasible for reservoirs with a large areal extent and/or shallow burial depths, with high porosities and high net-to-gross sand ratios. Forward modeling of the gravity responses using simple equivalent geometry shapes and full 3D complex heterogeneous models predicted that density changes in several of these producing gas reservoirs will result in readily detectable gravity signals ([Formula: see text]) within just a year or so of gas production. In a pure water-drive production regime, this gravity response equated to a fieldwide change in the gas-water contact height of approximately 2–3 m, or in a pure depletion-drive regime, a pressure decline equated to approximately 3–4 MPa (435–580 psi). We assessed the feasibility of time-lapse seafloor gravity monitoring for producing gas reservoirs that is flexible and practical, and it may be useful for a wide range of subsurface fluid-flow monitoring applications.
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Larkin, Patrick. „Small GTL technology for a big country“. APPEA Journal 56, Nr. 2 (2016): 611. http://dx.doi.org/10.1071/aj15117.
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Gas to liquids (GTL) technology has been applied and proven at large industrial scale in various parts of the world. Such projects, however, consume large quantities of gas, are capital intensive, generate large product volumes, and take decades to bring to fruition. For remote areas of Australia where there are small stranded gas fields and where there is local demand for liquid transportation fuels—which must be transported from manufacturing or import terminal centres—the development of the microchannel GTL reactor is an enabling technology that presents an innovative solution to allow economic development of small GTL projects near the gas deposit, and in the process satisfies local product demand. A microchannel reactor designed to enhance heat transfer in the GTL reactor has been developed and patented by Velocys When used with more active catalysts it provides process intensification to overcome the usual economies of scale benefits associated with larger reactors. The first commercial application of this technology is, at present, being commissioned at ENVIA’s East Oak Oklahoma site using a mixed feedstock of landfill gas and natural gas. Products made by this process do not contain aromatics or sulphur and burn cleaner than petroleum-derived fuels, resulting in lower emissions of NOx, SOx and particulates. Assessment of the use of this novel microchannel reactor technology in remote central Australia is being undertaken. Using a modular skid approach for equipment design and construction to improve site efficiencies, the small GTL concept should be very attractive for a remote Australian context. The standardised modular plants are easier to transport and quicker to install, with lower risk even in the most remote or challenging locations.
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Hart, T., B. Mamuko, K. Mueller, C. Noll, T. Snow und A. Zannetos. „IMPROVING OUR UNDERSTANDING OF GIPPSLAND BASIN GAS RESOURCES—AN INTEGRATED GEOSCIENCE AND RESERVOIR ENGINEERING APPROACH“. APPEA Journal 46, Nr. 1 (2006): 47. http://dx.doi.org/10.1071/aj05003.
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The Barracouta and Marlin gas fields are located within the Gippsland Basin, offshore Australia, and have been on production for more than 36 years. Combined, these fields represent over 6.5 TCF of recoverable gas. Structurally the fields are relatively simple, but they are significantly warped in seismic two-way time by high velocity channels above the reservoir that make time to depth conversion and volumetric assessment difficult.Fundamental to management of these fields has been surveillance data and history matching based on simulation of detailed geologic models. In the late 90s, the observation was made that actual contact movement within the fields was lagging behind model predictions, suggesting that the fields were potentially larger than previously assessed.Results from the 3D seismic surveys acquired in Barracouta in 1999 and both fields in 2001 were used to help answer questions related to contact movement, resource size and remaining recoverable gas. Two significant outcomes from these surveys were the observation of double Direct Hydrocarbon Indicators (DHIs) across both fields, representing both the original and current gas-water contacts (OGWC and CGWC respectively), and mappable amplitude features related to depositional trends.The double DHIs were used to calculate contact movement and sweep uniformity. The original contact DHI was also used to assist in depth conversion. The position of shorelines and upper to lower delta plain boundaries were extracted from the seismic amplitude features to refine net-to-gross distribution.The interpreted 3D data are integrated with well logs and surveillance data to create detailed geologic models used for material balance simulation of reservoir performance. A good match was obtained between the model and field measured pressures and contact movement. Based on this work, the estimates of recoverable gas in the two fields were increased by 0.7 TCF, a 14% increase over the previous estimate.
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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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Sibley, D., F. Herkenhoff, D. Criddle und M. McLerie. „REDUCING RESOURCE UNCERTAINTY USING SEISMIC AMPLITUDE ANALYSIS ON THE SOUTHERN RANKIN TREND, NORTHWEST AUSTRALIA“. APPEA Journal 39, Nr. 1 (1999): 128. http://dx.doi.org/10.1071/aj98009.
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Between 1973 and 1996 West Australian Petroleum Pty Limited (WAPET) discovered five major gas fields on the southern Rankin Trend including Spar, West Tryal Rocks, Gorgon, Chrysaor, and Dionysus (collectively termed the Greater Gorgon Resource). Recent discoveries at Chrysaor and Dionysus emphasise the role of subtle 3D seismic attributes in finding hydrocarbons and defining reserves with a minimum number of wells.The Gorgon, Chrysaor, and Dionysus fields were covered by 3D seismic data shot in 1991 and 1995, which led WAPET to discover Chrysaor and later Dionysus. Subsequent to the 3D acquisitions, field reservoirs have been correlated with anomalous seismic events (seismic amplitude and amplitude versus offset) that conform to depth structure. Follow-up work has shown that combining these 3D seismic attributes improves the prediction of wet sands, gas sands, and other lithologies.The resulting understanding and confidence provided by this 3D seismic has driven an aggressive exploration program and defined field reserves at a high confidence level. Results include the recent award of permit area WA-267-P to WAPET and the ongoing studies to begin development of the Greater Gorgon Resource.
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Moriarty, Hayden, Jennifer Clifford, James Donley und Lewis Maxwell. „Unlocking material gas resources – Moomba South case study“. APPEA Journal 60, Nr. 2 (2020): 736. http://dx.doi.org/10.1071/aj19222.
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In the last two years, Santos has identified and unlocked a significant contingent resource in the Cooper Basin, onshore Australia. Commercialisation of these resources has been enabled through the application of phased appraisal programs, combined with Santos’ disciplined low-cost operating model. The implementation of a disciplined low-cost operating model as part of the current Santos strategy has resulted in unprecedented cost reductions in the Cooper Basin. Sub-economic contingent resources across many fields have become primary targets for appraisal and development for conversion to economic reserves. One of Santos’ largest contingent resources lies in the deep tight rocks of the Moomba Field.
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Fagg, Kathryn J. „GAS LIFT IN BASS STRAIT“. APPEA Journal 25, Nr. 1 (1985): 107. http://dx.doi.org/10.1071/aj84008.
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Gas lift has proved a most effective artificial lift method for the fields operated by Esso Australia Ltd in Bass Strait for the Esso-BHP joint venture. Gas lift is now used to produce approximately 5 st ML/d of the total crude production from the Strait. It has enabled wells to be produced to water cuts higher than 90 per cent, increasing the oil recovery from the fields by up to 35 per cent.Gas lift work in Bass Strait to date has included the use of special packoff gas lift assemblies for wells with sliding sleeves, the development of a tool to assist the opening of the sleeves, improved operating techniques to limit slugging from gas-lifted wells, and the testing of gas lift performance. Gas lifting has been more successful than expected, and as a result, workovers initially planned to install full gas lift strings for older wells have not been necessary. The two phase flow correlations available have been improved to match the performance of the gas-lifted wells. The correlations are now used to design tubing strings with a number of gas lift mandrels prior to running the initial completions and to select the optimum gas injection depth.Future work in gas lift for Bass Strait will involve the optimisation and automation of lift gas distribution on the platforms. Gas lift will also be used for planned future developments, including mini-platforms and subsea completions.
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Riley, J. M. „THE RISE AND RISE OF COAL SEAM GAS IN THE BOWEN BASIN“. APPEA Journal 44, Nr. 1 (2004): 647. http://dx.doi.org/10.1071/aj03032.
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The coal seam gas (CSG) industry has been active in Australia for almost three decades, with interest largely focussed on the Bowen and Sydney basins. Sporadic activity has also occurred in a number of other areas including the Galilee, Ipswich, Clarence–Moreton, Gunnedah, Gloucester, and Otway basins to name a few, with significant recent interest shown in the promising Surat Basin. Of these basins it is the Bowen Basin in eastern central Queensland which has continued to shine as the premier coal seam gas province in the country.From humble beginnings in the mid-1970s in the Moura area, CSG from the Bowen Basin now supplies around 20% of Queensland gas demand. Since the start of commercial production from the basin in 1996, production has grown to about 20 PJ per year from five separate fields, with three new fields under construction expected to more than double this volume over the next 2–3 years.The largest contribution to this growth will come from the Comet Ridge region which is proving itself to be a world class CSG deposit. The high-productivity fairway in the south of the region extends over an area about 80 km long and 20 km wide and includes the Tipperary Fairview field, and the Origin Energy Spring Gully project. In the last year proved and probable gas reserves have more than doubled to 1,500 PJ across the fairway, with upside recoverable gas estimated to be 4,700 PJ. The rapid rate of CSG reserves increase in the Bowen Basin demonstrates the key role this industry will play in the eastern Australia gas market.
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Seggie, R. J., S. C. Lang, N. M. Marshall, C. J. Cubitt, D. Alsop, R. Kirk und S. Twartz. „INTEGRATED MULTI-DISCIPLINARY ANALYSIS OF THE RANKIN TREND GAS RESERVOIRS NORTH WEST SHELF, AUSTRALIA“. APPEA Journal 47, Nr. 1 (2007): 55. http://dx.doi.org/10.1071/aj06003.
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An integrated geological study of the Rankin Trend of the North West Shelf, Australia, was undertaken to underpin the ongoing development of the giant gas fields it contains. The study applied an improved understanding ofthe regional stratigraphy in conjunction with interpretation of the regional-scale Demeter 3D seismic survey and focussed on existing fields, undeveloped discoveries, and exploration prospects. The study included a redescription of 1,500 m of core, a new facies-based petrological analysis, a revision of the well-based stratigraphy and palaeogeographic mapping, and a seismic stratigraphic analysis. Reservoir production and hydrodynamic data were also integrated. The stratigraphic framework was improved by implementing a broad range of depositional and facies analogues and a system-wide sequence stratigraphic approach to understanding lateral and vertical stacking patterns of the reservoir succession. Visualisation and modelling technologies were also employed to more adequately describe genetic reservoir packages.Specific outcomes include: improved correlation of reservoir sequences, application of appropriate subsurface depositional analogues to field descriptions, updated palaeogeographic maps and recognition of palaeosols as stratigraphic marker horizons—resulting in a more consistent regional interpretation framework. This forms the basis for seismic stratigraphic interpretation away from well control.The new regional geological model has enabled the linkage of exploration, development and production understanding across the North West Shelf assets as well as management of geological uncertainties.
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Jung, Brian, Niel Kritzinger, Steven van Wagensveld und John Mak. „A case study for cost-effective design of relocatable deep dewpoint control gas plant“. APPEA Journal 57, Nr. 2 (2017): 607. http://dx.doi.org/10.1071/aj16030.
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Australia has significant smaller-capacity gas fields, in relatively remote areas. An economically viable design for the Australian market is a small to mid-size gas plant to produce pipeline-quality gas and recover attractive amounts of liquid products (NGLs) for export by truck. Such a plant has minimal equipment, is highly modularised to be cost-effective for remote locations with high labour costs, can be relocated, and can be implemented in a substantially shorter time frame than conventional projects. For the North and South American markets, we have developed a deep dewpointing process that combines high NGL recovery with simplicity of design, yet is flexible enough to accommodate a range of compositions and flow rates. This design is well suited for standardisation of small to medium-size gas plants where feed gas compositions may vary and capacity increases are not well known. A short implementation schedule provides first-to-market economic benefits. We have developed 3rd Generation ModularisationSM that is proven to significantly reduce a plant’s footprint compared with more traditional modularisation practices. This new approach makes it possible to design a gas processing facility as transportable modules that can be built in the most cost-effective location, are low cost to install and may be relocated in the future. This has been demonstrated in a recent project completed in 2015 for Shell in Canada. This paper presents the solution for the Australian market that combines the benefits of high gas liquids recovery with low investment, delivered in compact relocatable modules that enable very flexible field development strategies.
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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.