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Artykuły w czasopismach na temat „Gas fields Australia”

Autor: Grafiati
Data publikacji: 4 czerwca 2021
Data aktualizacji: 30 stycznia 2023

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1

Ronalds, B. F. "TOWARDS DEVELOPMENT OF AUSTRALIA’S LARGE DEEPWATER GAS FIELDS." APPEA Journal 45, no. 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, environme
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Oen, P. M. "THE DEVELOPMENT OF THE GREATER GORGON GAS FIELDS." APPEA Journal 43, no. 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
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Salmachi, Alireza, Mojtaba Rajabi, Carmine Wainman, Steven Mackie, Peter McCabe, Bronwyn Camac, and Christopher Clarkson. "History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review." Energies 14, no. 9 (May 5, 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
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de Rijke, Kim. "The Agri-Gas Fields of Australia: Black Soil, Food, and Unconventional Gas." Culture, Agriculture, Food and Environment 35, no. 1 (June 2013): 41–53. http://dx.doi.org/10.1111/cuag.12004.

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Korn, B. E., R. P. Teakle, D. M. Maughan, and P. B. Siffleet. "THE GERYON, ORTHRUS, MAENAD AND URANIA GAS FIELDS, CARNARVON BASIN, WESTERN AUSTRALIA." APPEA Journal 43, no. 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
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Constantine, Andrew, Glenn Morgan, Robin O'Leary, and Simon Smith. "The Halladale–Speculant fields: the first nearshore gas fields to be developed from mainland Australia." APPEA Journal 58, no. 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
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7

Redmond, Helen. "Impact of energy generation on health: unconventional gas." Proceedings of the Royal Society of Victoria 126, no. 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 envi
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8

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 f
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9

Espig, Martin, and Kim de Rijke. "Navigating Coal Seam Gas Fields: Ethnographic Challenges in Queensland, Australia." Practicing Anthropology 38, no. 3 (June 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, no. 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 s
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11

Michael, Karsten, Jonathan Ennis-King, Julian Strand, Regina Sander, and Chris Green. "Suitability of depleted gas fields for underground hydrogen storage in Australia." APPEA Journal 62, no. 2 (May 13, 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 technolo
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Sanford, Elizabeth, and Rama Alapati. "A new, field-proven, cost-effective solution for MEG regeneration unit issues in offshore Australia gas production." APPEA Journal 51, no. 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 conce
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13

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 f
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14

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
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15

Howard, D. "UNDERGROUND GAS STORAGE-LEGAL ANT REGULATORY REQUIREMENTS IN AUSTRALIA." APPEA Journal 39, no. 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 g
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16

Robertson, C. S. "AUSTRALIA'S PETROLEUM PROSPECTS: CHANGING PERCEPTIONS SINCE THE BEGINNING OF THE CENTURY." APPEA Journal 28, no. 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 fut
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17

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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Smith, Peter, and 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, no. 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 numero
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19

van Merwyk, A. M., and A. L. Disney. "ENVIRONMENTAL UPDATE 2004." APPEA Journal 45, no. 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
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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 ne
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21

Parker, K. A. "THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA." APPEA Journal 32, no. 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 f
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Farrell, Bradley. "Remote Operations Centres – what next?" APPEA Journal 57, no. 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
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Pulsford, Will. "Meeting demand in a new era of east coast gas supply." APPEA Journal 59, no. 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 fac
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Carpenter, Chris. "Early Production Life of Wheatstone Project Offshore Australia Yields Key Lessons." Journal of Petroleum Technology 73, no. 08 (August 1, 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
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Hunter, P. C. "PREPARATION AND IMPLEMENTATION OF A SAFETY MANAGEMENT SYSTEM IN BHPP." APPEA Journal 37, no. 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-Jabi
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Byrne, Philip. "Evolution of the east coast gas market." APPEA Journal 58, no. 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 p
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Ziehn, T., A. Nickless, P. J. Rayner, R. M. Law, G. Roff, and 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, no. 6 (March 19, 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
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Baker, G. L., and W. R. Skerman. "THE SIGNIFICANCE OF COAL SEAM GAS IN EASTERN QUEENSLAND." APPEA Journal 46, no. 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
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Saunders, Donald F., K. Ray Burson, Jim F. Branch, and C. Keith Thompson. "Relation of thorium‐normalized surface and aerial radiometric data to subsurface petroleum accumulations." GEOPHYSICS 58, no. 10 (October 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 consump
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Northcott, I. W., and R. C. M. McDonough. "TARDIS: A COMPUTER MODEL TO PREDICT FUTURE GAS SUPPLY." APPEA Journal 29, no. 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
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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,
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Holford, Simon, Nick Schofield, Mark Bunch, Alan Bischoff, and Ernest Swierczek. "Storing CO2 in buried volcanoes." APPEA Journal 61, no. 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 p
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Campbell, G. D. "A CASE FOR A NATIONAL PIPELINE GRID FOR NATURAL GAS." APPEA Journal 26, no. 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
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Miyazaki, S. "COAL SEAM GAS EXPLORATION, DEVELOPMENT AND RESOURCES IN AUSTRALIA: A NATIONAL PERSPECTIVE." APPEA Journal 45, no. 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 me
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Neininger, Bruno G., Bryce F. J. Kelly, Jorg M. Hacker, Xinyi LU, and 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, no. 2210 (September 27, 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 onsho
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Ziehn, T., A. Nickless, P. J. Rayner, R. M. Law, G. Roff, and P. Fraser. "Greenhouse gas network design using backward Lagrangian particle dispersion modelling − Part 1: Methodology and Australian test case." Atmospheric Chemistry and Physics 14, no. 17 (September 10, 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 Syst
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37

Hansen, Lein Mann. "Australia well positioned to become a CCUS leader." APPEA Journal 62, no. 2 (May 13, 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
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38

Seggie, Robert, Simon Lang, Neil Marshall, K. Adamson, W. Bailey, T. Prater, and D. Dawson. "The geology of the Brecknock, Calliance and Torosa gas fields, Browse Basin, Western Australia." ASEG Extended Abstracts 2019, no. 1 (November 11, 2019): 1. http://dx.doi.org/10.1080/22020586.2019.12072915.

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39

McNicoll, Russell. "HORIZONTAL DRILLING IN AUSTRALIA: THREE CASE HISTORIES." APPEA Journal 31, no. 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. T
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Young, Wendy May, and David Lumley. "Feasibility analysis for time-lapse seafloor gravity monitoring of producing gas fields in the Northern Carnarvon Basin, offshore Australia." GEOPHYSICS 80, no. 2 (March 1, 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 fiel
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41

Larkin, Patrick. "Small GTL technology for a big country." APPEA Journal 56, no. 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 econ
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42

Hart, T., B. Mamuko, K. Mueller, C. Noll, T. Snow, and A. Zannetos. "IMPROVING OUR UNDERSTANDING OF GIPPSLAND BASIN GAS RESOURCES—AN INTEGRATED GEOSCIENCE AND RESERVOIR ENGINEERING APPROACH." APPEA Journal 46, no. 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 obs
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43

Saraceni, Pat, and Keely Liddle. "Decommissioning – What's the fuss about?" APPEA Journal 58, no. 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 bett
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Sibley, D., F. Herkenhoff, D. Criddle, and M. McLerie. "REDUCING RESOURCE UNCERTAINTY USING SEISMIC AMPLITUDE ANALYSIS ON THE SOUTHERN RANKIN TREND, NORTHWEST AUSTRALIA." APPEA Journal 39, no. 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 acquisi
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Moriarty, Hayden, Jennifer Clifford, James Donley, and Lewis Maxwell. "Unlocking material gas resources – Moomba South case study." APPEA Journal 60, no. 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 econ
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Fagg, Kathryn J. "GAS LIFT IN BASS STRAIT." APPEA Journal 25, no. 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 op
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47

Riley, J. M. "THE RISE AND RISE OF COAL SEAM GAS IN THE BOWEN BASIN." APPEA Journal 44, no. 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
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48

Seggie, R. J., S. C. Lang, N. M. Marshall, C. J. Cubitt, D. Alsop, R. Kirk, and S. Twartz. "INTEGRATED MULTI-DISCIPLINARY ANALYSIS OF THE RANKIN TREND GAS RESERVOIRS NORTH WEST SHELF, AUSTRALIA." APPEA Journal 47, no. 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 st
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Jung, Brian, Niel Kritzinger, Steven van Wagensveld, and John Mak. "A case study for cost-effective design of relocatable deep dewpoint control gas plant." APPEA Journal 57, no. 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
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Evans, P. R. "Australia's Potential for Petroleum." Energy Exploration & Exploitation 4, no. 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
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