Статті в журналах з теми "Beetaloo Basin"
Щоб переглянути інші типи публікацій з цієї теми, перейдіть за посиланням: Beetaloo Basin.
Оформте джерело за APA, MLA, Chicago, Harvard та іншими стилями
Ознайомтеся з топ-46 статей у журналах для дослідження на тему "Beetaloo Basin".
Біля кожної праці в переліку літератури доступна кнопка «Додати до бібліографії». Скористайтеся нею – і ми автоматично оформимо бібліографічне посилання на обрану працю в потрібному вам стилі цитування: APA, MLA, «Гарвард», «Чикаго», «Ванкувер» тощо.
Також ви можете завантажити повний текст наукової публікації у форматі «.pdf» та прочитати онлайн анотацію до роботи, якщо відповідні параметри наявні в метаданих.
Переглядайте статті в журналах для різних дисциплін та оформлюйте правильно вашу бібліографію.
1
Frery, Emanuelle, Conor Byrne, Russell Crosbie, Alec Deslandes, Tim Evans, Christoph Gerber, Cameron Huddlestone-Holmes, et al. "Fault-Related Fluid Flow Implications for Unconventional Hydrocarbon Development, Beetaloo Sub-Basin (Northern Territory, Australia)." Geosciences 12, no. 1 (January 12, 2022): 37. http://dx.doi.org/10.3390/geosciences12010037.
Повний текст джерелаАнотація:
This study assesses potential geological connections between the unconventional petroleum plays in the Beetaloo Sub-basin, regional aquifers in overlying basins, and the near surface water assets in the Beetaloo Sub-basin Northern Territory, Australia. To do so, we built an innovative multi-disciplinary toolbox including multi-physics and multi-depth imaging of the geological formations, as well as the study of potentially active tectonic surface features, which we combined with measurement of the helium content in water sampled in the aquifer systems and a comparative analysis of the surface drainage network and fault lineaments orientation. Structures, as well as potential natural active and paleo-fluid or gas leakage pathways, were imaged with a reprocessing and interpretation of existing and newly acquired Beetaloo seismic reflection 2D profiles and magnetic datasets to determine potential connections and paleo-leakages. North to north-northwest trending strike slip faults, which have been reactivated in recent geological history, are controlling the deposition at the edges of the Beetaloo Sub-basin. There are two spring complexes associated with this system, the Hot Spring Valley at the northern edge of the eastern Beetaloo Sub-basin and the Mataranka Springs 10 km north of the western sub-basin. Significant rectangular stream diversions in the Hot Spring Valley also indicates current or recently active tectonics. This suggests that those deep-rooted fault systems are likely to locally connect the shallow unconfined aquifer with a deeper gas or fluid source component, possibly without connection with the Beetaloo unconventional prospective plays. However, the origin and flux of this deeper source is unknown and needs to be further investigated to assess if deep circulation is happening through the identified stratigraphic connections. Few north-west trending post-Cambrian fault segments have been interpreted in prospective zones for dry gas plays of the Velkerri Formation. The segments located in the northern part of the eastern Beetaloo Sub-basin do not show any evidence of modern leakages. The segments located around Elliot, in the south of the eastern Beetaloo Sub-basin, as well as low-quality seismic imaging of potential faults in the central part of the western sub-basin, could have been recently reactivated. They could act as open pathways of fluid and gas leakage, sourced from the unconventional plays, deeper formations of the Beetaloo Sub-basin or even much deeper origin, excluding the mantle on the basis of low 3He/4He ratios. In those areas, the data are sparse and of poor quality; further field work is necessary to assess whether such pathways are currently active.
2
Côté, Alexander, Brenton Richards, Carl Altmann, Elizabeth Baruch, and David Close. "Australia's premier shale basin: five plays, 1 000 000 000 years in the making." APPEA Journal 58, no. 2 (2018): 799. http://dx.doi.org/10.1071/aj17040.
Повний текст джерелаАнотація:
The successful fracture stimulation and production test of the Amungee NW-1H well placed the Velkerri Shale play and the Beetaloo Sub-basin on Australia’s energy radar. The Velkerri Shale dry gas play is currently Australia’s most promising shale gas prospect; however, it is not the only prospect in the Beetaloo Sub-basin. Four additional potential plays have been identified, each with their own specific risk profile and relative benefits. These are the Velkerri Shale liquids rich gas play, the Kyalla Shale and hybrid liquids rich gas plays, and the Hayfield Sandstone oil/condensate play. Appraising each of these opportunities requires special attention to ensure efficient and appropriate deployment of capital. A framework approach allows for the high-level assessment and comparison of each of the discussed opportunities within the Beetaloo Sub-basin portfolio.
3
Cockerill, Ian. "Australian exploration review 2020." APPEA Journal 61, no. 2 (2021): 331. http://dx.doi.org/10.1071/aj21006.
Повний текст джерелаАнотація:
Australian exploration battled on through the challenging headwinds of 2020 and surprisingly, 2020 saw an increase in exploration drilling on 2019 activity. Twenty-five exploration wells were drilled in 2020 versus 20 exploration wells drilled in 2019. Eight discoveries were made during the year, with the most significant being the Enterprise discovery in the Otway Basin. 2020 also saw a return to exploration drilling in the Beetaloo Sub-basin unconventional plays. Appraisal drilling was dominated by Cooper-Eromanga Basin and coal seam gas activity. There were no offshore appraisal wells in 2020. The exploration farm-in deals of note were Santos taking additional equity from Armour in their South Nicholson Basin unconventional project and Origin taking additional equity from Falcon in their Beetaloo Sub-basin unconventional project. Origin also farmed into the Canning Basin position of Buru Energy and Rey Resources. Australia is set for an exciting year of exploration ahead with a return to exploration drilling in the Bedout Sub-basin, further exploration drilling in the North Perth Basin and a continuation of drilling and testing of the unconventional plays in the Beetaloo Sub-basin.
4
Granger, Dale. "The Empire Strikes Back with Spectacular Results in the Beetaloo." PESA News, no. 164 (March 23, 2022): 22–26. http://dx.doi.org/10.36404/aglz3960.
Повний текст джерела
5
Jarrett, Amber J. M., Tim J. Munson, Ben Williams, Adam H. E. Bailey, and Tehani Palu. "Petroleum supersystems in the greater McArthur Basin, Northern Territory, Australia: prospectivity of the world’s oldest stacked systems with emphasis on the McArthur Supersystem." APPEA Journal 62, no. 1 (May 13, 2022): 245–62. http://dx.doi.org/10.1071/aj21018.
Повний текст джерелаАнотація:
This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales.
6
Lanigan, Kevin, Shane Hibbird, Sandy Menpes, and John Torkington. "PETROLEUM EXPLORATION IN THE PROTEROZOIC BEETALOO SUB-BASIN, NORTHERN TERRITORY." APPEA Journal 34, no. 1 (1994): 674. http://dx.doi.org/10.1071/aj93050.
Повний текст джерелаАнотація:
Exploration over Roper Group outcrop in the McArthur Basin prompted Pacific Oil & Gas to investigate the petroleum potential of the Beetaloo Sub-basin, a 15 000 km2 Proterozoic depression concealed beneath Phanerozoic cover. Since 1989 drilling and seismic has identified a broadly flat-lying sequence with uplifted, eroded margins. A 3 500 m composite Proterozoic section consisting of three sandstone-to-mudstone sequences has been drilled. The lower two sequences comprise conformable units of the Mesoproterozoic upper Roper Group and unconformably overlying them is a previously unknown sequence comprising the informally labelled 'Jamison Sandstone' and 'Hayfield Mudstone', probably of Neoproterozoic age.Organic-rich intervals in the Roper Group mudstones range one to three per cent TOC in the Kyalla Member, and two to seven per cent TOC in the 'Middle' Velkerri Formation. Across most of the sub-basin the oil window lies within the Kyalla Member around 900–1350 m, while the 'Middle' Velkerri Formation is around 2 500 m and well into overmaturity, but may still have potential for gas. Potential reservoirs in the Bessie Creek, Moroak and 'Jamison' Sandstones, and in sandy units within the mudstones, are compromised by diagenesis, but porosities of up to 20 per cent and permeabilities of tens and rarely hundreds of millidarcies have been measured. Encouraging shows were observed in many of these intervals, and small quantities of oil and gas have been recovered in drill stem tests. With only a few targets drilled to date, this frontier area requires more exploration before its hydrocarbon potential can be adequately assessed.
7
Huddlestone-Holmes, Cameron R., Kate Holland, and Luk J. M. Peeters. "Geological and Bioregional Assessments: a tale of two basins." APPEA Journal 61, no. 2 (2021): 491. http://dx.doi.org/10.1071/aj20036.
Повний текст джерелаАнотація:
The Australian Government’s $35.4 million Geological and Bioregional Assessment (GBA) Program is assessing the potential impacts of shale, tight and deep coal gas development on water and the environment in the Beetaloo, Isa and Cooper GBA regions. This paper compares the outcomes of impact assessments for the Beetaloo and Cooper GBA regions, highlighting the role that local geology, hydrogeology, ecology and regulatory regimes play when assessing potential impacts of unconventional gas development. Unconventional gas development activities between basins are broadly consistent, involving drilling, stimulation of the reservoir (typically through hydraulic fracturing), production and processing of hydrocarbons, export to market and decommissioning and rehabilitation. The characteristics of these activities and their potential impacts are strongly influenced by local factors including the geology, environment, industry practices and regulatory regimes. While subsurface impacts associated with hydraulic fracturing and well integrity are considered unlikely in both regions, regional geology means there is greater stratigraphic separation between target resources and overlying aquifers in the Beetaloo Sub-basin than in the Cooper Basin. Local ecological conditions and species influence the nature of potential impacts on protected matters in the two basins, which are mostly associated with surface disturbance and spills or accidental release of fluids. A key similarity between the two regions is the broadly consistent regulation and management of potential impacts in the two basins. Preliminary results of the causal network analysis indicate that mitigation measures are available for all pathways in which unconventional gas resource development activities may have the potential to impact on endpoints.
8
Close, David, Alexander Côté, Elizabeth Baruch, Carl Altmann, Faiz Mohinudeen, Brenton Richards, Rachael Ilett, Ross Evans, and Stephanie Stonier. "Exploring the Beetaloo: will Australia's first viable shale play be sourced by billion year old gas?" APPEA Journal 57, no. 2 (2017): 716. http://dx.doi.org/10.1071/aj16054.
Повний текст джерелаАнотація:
Origin Energy completed exploration campaigns in 2015 and 2016 in the Beetaloo Sub-basin of the Greater McArthur Basin in the Northern Territory, drilling three vertical wells and one horizontal well. These wells have provided a wealth of technical data to assist in the characterisation of the primary source rock reservoirs or ‘shale gas’ plays in the Basin – the Velkerri Formation Play and the Kyalla Formation Play. In this paper we demonstrate the presence of thick, gas saturated and over-pressured source rocks across the sub-basin. In addition to the drilling campaign, the multi-stage hydraulic fracture stimulation of the Amungee NW-1H horizontal well was completed in 2016 – this operation was unique as it represents the first horizontal stimulation operation in the Beetaloo Sub-basin and the longest ‘plug and perf’ type horizontal completion in Australia. Data from the extended production test of the Amungee NW-1H are critical from a technical and, potentially, economic and political perspective. In addition to the technical work program, Origin has undertaken preliminary environmental baseline studies and substantial stakeholder engagement. Ensuring environmental baseline data are available is key to demonstrating that onshore gas developments can be undertaken without adverse environmental outcomes, and also for gaining social acceptance. However, data and facts alone are not sufficient to build community confidence. Origin has engaged extensively with pastoralists, local communities and Traditional Owners to build direct relationships and partnerships that encourage acceptance of the gas industry’s ability to coexist and deliver mutual benefits to the businesses and communities of the Barkly region and the Northern Territory more broadly.
9
Markov, Jelena, Claudio Delle Piane, Ernest Swierczek, Clive Foss, and Mohinudeen Faiz. "Structural interpretation of the Beetaloo Sub-basin, NT from nonseismic geophysical data." APPEA Journal 61, no. 2 (2021): 679. http://dx.doi.org/10.1071/aj20194.
Повний текст джерелаАнотація:
The Beetaloo Sub-basin is known for its vast unconventional hydrocarbon resources even though it is relatively underexplored. There is reasonably good coverage of 2D seismic within the sub-basin which is used as the basis for most structural interpretations. However, seismic quality varies, and it is occasionally deteriorated by the presence of basalts from the Kalkarindji suite and the karstic nature of the Gum Ridge formation. Aeromagnetic data, constrained by petrophysical logs are used, to map faults in the basalts of the Kalkarindji suite and their lateral extent to the South and the East of the sub-basin. The same structural elements are identified in the full tensor gravity gradiometry data. The top of this unit is observed in the electrical conductivity profiles, derived from Tempest data, in the NW part of the eastern sub-basin.
10
Robinson, David, Merrie-Ellen Gunning, Tim Evans, Lisa Hall, Baskaran Sundaram, Anthony Swirepik, Andrew Stacey, Rodney Dann, and Kate Holland. "Geological and bioregional assessments – enabling future tight, shale and deep coal gas development – Cooper Basin case study." APPEA Journal 59, no. 2 (2019): 946. http://dx.doi.org/10.1071/aj18165.
Повний текст джерелаАнотація:
The Australian Government’s Geological and Bioregional Assessment (GBA) Program is a series of independent scientific studies conducted by Geoscience Australia and CSIRO, supported by the Bureau of Meteorology and managed by the Department of the Environment and Energy. These studies focus on the Cooper, Isa and Beetaloo GBA regions, all of which include basins which are prospective, but under-explored, for shale, tight and/or deep coal gas. The GBA Program seeks to expedite development in order to bring new gas resources to the east coast gas market within the next 5–10 years through increased understanding of the potential environmental impacts posed by gas development and increasing the efficiency of assessment, monitoring and ongoing regulation, including improved data capture and reporting. This multi-agency program addresses the potential environmental impacts of gas development through geological and environmental baseline assessments and identification of major information gaps (Stage 2), followed by an analysis of the potential impacts on assets, including groundwater, surface water, environmental and cultural assets as well as Commonwealth and State matters of environmental significance (Stage 3). This paper will discuss how integrated conceptual models of the geology and hydrogeology of selected unconventional petroleum resources can be utilised by industry, regulators and other stakeholders. By establishing a baseline assessment for the Cooper Basin, which includes an integrated shale, tight and deep coal prospectivity and groundwater study, future development scenarios can be envisaged and the potential impact on groundwater and other resources contemplated. Similar baseline assessments and conceptual models are being developed for the Isa and Beetaloo GBA regions.
11
Close, David. "Why the wait? Shale gas exploration review and look ahead." APPEA Journal 55, no. 2 (2015): 404. http://dx.doi.org/10.1071/aj14039.
Повний текст джерелаАнотація:
Despite unconventional targets being recognised across many Australian sedimentary basins and the Energy Information Administration (EIA), estimating a technically recoverable shale gas resource of >400 tcf in Australia, there have been no definitive tests that prove that any of these potential plays will flow gas at commercial rates. There has, however, been a number of technical successes reported from both shale gas and basin centred gas plays. This extended abstract reviews select plays from both frontier and mature basins across Australia, including basins where Origin is actively exploring or appraising unconventional gas plays—the Perth, Cooper and Beetaloo basins. The technical challenges vary from play to play, but many of the above ground challenges are not play specific. To advance the industry, Origin and other companies will have to demonstrate a resource sufficiency that is economic in a high cost environment like Australia, while maintaining a positive relationship with communities. In its expansion into the NT, through its interest in the Beetaloo Basin, Origin has the benefit of 20 years' experience dealing with complex stakeholders and environmental challenges through its CSG development projects in Queensland. This experience is invaluable in advising best practices for engaging with local communities, landholders, traditional owners, and regulatory and government bodies. For the technically-minded asset development teams charged with exploring unconventional plays in frontier basins, where stakeholders are unfamiliar with oil and gas development projects, new skills are required that need deep organisational support.
12
Faiz, Mohinudeen, Alison Zoitsas, Carl Altmann, Elizabeth Baruch, and David Close. "Compositional variations and carbon isotope reversal in coal and shale gas reservoirs of the Bowen and Beetaloo basins, Australia." Geological Society, London, Special Publications 484, no. 1 (August 14, 2018): 51–70. http://dx.doi.org/10.1144/sp484.3.
Повний текст джерелаАнотація:
AbstractStable isotope composition of gas is widely used in hydrocarbon exploration to determine the composition and thermal maturity of source rocks. Many isotope classification systems used for gas to source rock correlation and thermal maturity determination are primarily based on empirical observations made in conventional reservoirs and the kinetic isotope effects observed during pyrolysis experiments performed on source rocks. However, such relationships may not be readily applicable to onshore unconventional reservoirs due to the strong molecular and isotope fractionation that occur during extensive gas expulsion associated with basin uplift and depressurization.Degassing studies of freshly recovered core samples can provide useful insight into the behaviour of gas molecules in unconventional reservoirs during basin uplift. The analyses of Australian coal and marine shale samples demonstrate that during desorption both molecular and isotopic compositions of gas change at variable rates. Gas initially desorbed from the samples is mostly CH4, whereas later desorbed gas becomes increasingly enriched in C2H6 and higher hydrocarbons. Hydrocarbon molecules also fractionate according to their isotopic composition, where the early released gas is enriched in 12C causing the remaining gas in the reservoir to be enriched in the heavier 13C isotope. During the release of gas from the Bowen Basin coals the C isotope ratio of CH4 (δ13C1) changes by up to 21‰ (VPDB), whereas that for C2H6 (δ13C2) and C3H8 (δ13C3) changes by <6‰. Similar changes in the isotope composition can be seen during the release of gas from marine source rocks of the Beetaloo Sub-basin. In a fully gas-mature middle Velkerri shale sample, δ13C1 changes by up to 28‰ and δ13C2 by up to 3‰ with no appreciable change occurring in δ13C3.The extent of molecular fractionation during gas flow through carbonaceous rocks is primarily related to the adsorption–desorption properties of organic matter and diffusivity through the overall rock matrix. Using the current dataset, the magnitude of the contributions exerted by the desorption and diffusion processes cannot be readily distinguished. However, both Bowen Basin coals and Beetaloo Sub-basin shale show similar fractionation effects during gas flow, where the heavier alkane molecules, including those containing more 13C, desorb and move slowly compared with the lighter components, in particular CH4. Different rates of isotope fractionation between hydrocarbon molecules during gas flow cause the shape of compound-specific-isotope (CSI) curve to change with time. Early released gas is characterized by a normal CSI trend where the short-chain hydrocarbons are isotopically lighter compared with the longer-chain hydrocarbons. Because CH4 and C2H6 molecules enriched in 12C desorb and diffuse more readily than the heavier hydrocarbons (including those enriched 13C), the gas remaining in the coal and shale samples after extensive desorption shows a reversed CSI trend where CH4 and C2H6 are isotopically heavier compared with the longer chain hydrocarbons. Reversed isotope trends may also develop over geological time, particularly where the source rock is fully gas-mature and has expelled hydrocarbons due to prolonged degassing. As seen in the Beetaloo Sub-basin, the CSI trend in the dry-gas-mature Velkerri shale is reversed, possibly due to the loss of a large proportion of originally generated CH4 during post-Cambrian basin uplift.
13
Delle Piane, Claudio, I. Tonguç Uysal, Mohinudeen Faiz, Zhejun Pan, Julien Bourdet, Zhongsheng Li, Mark D. Raven, and David N. Dewhurst. "Thermal maturity and reservoir quality of the Velkerri Formation, Beetaloo Sub-basin, Northern Territory." APPEA Journal 60, no. 2 (2020): 697. http://dx.doi.org/10.1071/aj19189.
Повний текст джерелаАнотація:
The Proterozoic (~1.43 Ga) Velkerri Formation (McArthur Basin, Northern Territory) is believed to host one of the world’s oldest petroleum systems. Drilling and production tests demonstrated the encouraging potential of this unconventional gas resource and current efforts are aimed at better defining the extent of the gas and liquid-rich portions of this shale play. In this context, we conducted a comprehensive characterisation of specimens from the Amungee Member of the Velkerri Formation (previously referred to as the Middle Velkerri) sampled along a thermal maturity gradient from wells drilled across the Beetaloo Sub-basin. The scope of our analysis was to shed light on how the organic matter in the Velkerri Formation is affected by thermal maturity and how this affects the pore structure of the host rock. To this end, we integrated light and electron microscopy imaging with Raman spectroscopy and pyrolysis techniques to define the maturity of the sediments and visualise the shale pore network. In concert with the direct imaging, bulk samples were experimentally tested to measure their gas permeability and gas adsorption capacity. The results indicate that porosity is mostly organic-hosted with pore size dominated by meso- and micro-pores (i.e. <50 nm). Methane adsorption isotherms measured at temperatures up to 80°C also show that organic content is one of the main factors controlling the amount of adsorbed gas in the Velkerri shale.
14
Levy, Daniel C. "Evaluating the sources and impact of new east coast gas supply." APPEA Journal 60, no. 2 (2020): 464. http://dx.doi.org/10.1071/aj19041.
Повний текст джерелаАнотація:
Rystad Energy has conducted a well level supply side study for the Australian east coast gas market, quantifying the widely expected supply shortfall and its timing. This paper presents these findings, along with an economic and technical evaluation of new sources of supply relief and their potential impacts on the market balance. The study suggests the east coast has adequate gas supply to meet demand until 2024, with an average excess of 73 billion cubic feet (Bcf) per annum over this period. However, in 2025 the market will shift to under-supply, starting at 93 Bcf in 2025 and increasing to over half a trillion cubic feet by 2030. Sufficient supply in the short term does not warrant complacency. With the average duration between discovery and first gas for the region being 7.1 years since 1990, even if new (traditional) supply is discovered in 2020, the market will still be undersupplied for at least 3 years. We have identified the four most likely sources of supply relief for the market, each with their own merits, difficulties and development timelines. These new sources include the Beetaloo Sub-basin shales of the Northern Territory, undeveloped coal seam gas acreage, electrifying liquefied natural gas (LNG) export facilities to preserve in-field usage, and finally, LNG importation. A combination of at least two of these sources is required to balance the east coast gas market to 2030. Of the options, LNG importation is the most viable to stave off undersupply in the medium term (3 to 7 years). While Beetaloo Sub-basin shale gas appears the most viable option for secure, long-term supply relief.
15
Cockerill, Ian. "PESA Australian exploration review 2019." APPEA Journal 60, no. 2 (2020): 348. http://dx.doi.org/10.1071/aj20007.
Повний текст джерелаАнотація:
Australia has continued its recent run of exploration success by yielding a series of impressive discoveries in 2019, despite a contraction in exploration activity. In 2019, Australian explorers were rewarded with six conventional onshore discoveries and three offshore discoveries, while only drilling 20 exploration wells. The exploration drilling highlights were the discoveries in the Vulcan Sub-basin (Bratwurst and Orchid) and the North Perth Basin (Beharra Springs Deep and West Erregulla). 2019 also saw successful appraisal drilling on the Dorado and Corvus discoveries as well as renewed exploration efforts in the Beetaloo Sub-basin unconventional plays. The exploration farm-in deals of note were Santos farming into Armour’s South Nicholson Basin acreage and Conoco farming into 3D Oil’s Otway Basin acreage. Australia is set for an exciting year of exploration with further drilling planned in the North Perth Basin and other high impact exploration wells on the North West Shelf. In a positive sign for future exploration, 13 new offshore permits were awarded with committed work programs or cash bids totalling AU$223 million. This is the first uptick in offshore permit awards since 2010.
16
Sheridan, Mattilda, D. Rhodri Johns, Howard D. Johnson, and Sandra Menpes. "The stratigraphic architecture, distribution and hydrocarbon potential of the organic-rich Kyalla and Velkerri shales of the Upper Roper Group (McArthur Basin)." APPEA Journal 58, no. 2 (2018): 858. http://dx.doi.org/10.1071/aj17224.
Повний текст джерелаАнотація:
Recent exploration studies on the stratigraphic framework, depositional environment and tectonic setting of the Mesoproterozoic Roper Group in the McArthur Basin, have led to an improved understanding of the highly prospective organic-rich shales of the Velkerri and Kyalla Formations. From a review of open-file drill core and well logs, several major regressive–transgressive (R–T) cycles have been identified along with four key facies associations within the Roper Group. The R–T cycles show sedimentary features typical of deposition within a clastic-dominated marine deltaic setting and show marked lateral variation in facies and thicknesses. The lateral thickness variations are particularly noticeable across regional 2D seismic lines. Seismic interpretation and well correlation confirm the extensive and relatively undeformed nature of the Velkerri and Kyalla Formations in the subsurface, they appear thickest in the south-east of the Beetaloo Sub-Basin.
17
Craig, Adam. "Exploration and appraisal year in review 2021." APPEA Journal 62, no. 2 (May 13, 2022): S527—S536. http://dx.doi.org/10.1071/aj21222.
Повний текст джерелаАнотація:
Petroleum exploration and appraisal activity increased in 2021. Exploration spend increased for the year, continuing a positive trend. Onshore exploration and appraisal activity continues to dominate the petroleum exploration scene in Australia. Positive indications of increased work program bids (wells, seismic and spend) are, however, tempered by the downward trend of total exploration acreage (by area) and new acreage awards. In addition to petroleum exploration acreage, greenhouse gas sequestration acreage was released across Australia in 2021. Twenty-nine exploration wells were drilled in the year compared to twenty-five in the previous year. Eight conventional petroleum discoveries were reported, with the Artisan-1 discovery in the Otway Basin being the only offshore discovery. The Lockyer Deep-1 gas discovery in the Northern Perth Basin continues the exploration success of the Permian Kingia and High Cliff Sandstone play. The Cooper–Eromanga Basin continues to yield discoveries with the Odin-1, Rosebay-1, Lowry South, Liger-1 and Chimera-1 discoveries reported for the year. Thirty-one appraisal wells were drilled for the year with significant activity in the Northern Perth Basin, Cooper-Eromanga Basin and Bowen-Surat Basins. Exploration and appraisal drilling also continued in the Beetaloo Sub-basin with the drilling of the Tanumbirini-2H, Tanumbirini-3H and Carpentaria-2/2H wells during the year.
18
Smith, Tegan, Andrew P. Kelman, Robert Nicoll, Dianne Edwards, Lisa Hall, John Laurie, and Lidena Carr. "An updated stratigraphic framework for the Georgina Basin, NT and Queensland." APPEA Journal 53, no. 2 (2013): 487. http://dx.doi.org/10.1071/aj12098.
Повний текст джерелаАнотація:
The Georgina Basin is a Neoproterozoic to Lower Devonian sedimentary basin covering 325,000 km2 of western Queensland and the NT. It is a northwest-southeast-trending extensional basin, with prospective conventional and unconventional hydrocarbon targets in Cambrian and Ordovician carbonate and siliciclastic rock units. The unconventional gas and oil potential of the basin has led to recent exploration interest, although the basin has been relatively less explored in the past. At the southern end of the basin, depocentres contain up to 2.2 km of Cambrian to Devonian sedimentary rocks, overlying Neoproterozoic sedimentary rocks more than 1.5 km thick. The basin succession thins toward the north, where Cambrian sediments overlie the McArthur Basin sediments in the Beetaloo Sub-basin. Biostratigraphic interpretations of the prospective southern, central and eastern regions of the basin have been revised to reflect the 2012 Geological Time Scale (Gradstein, Ogg, Schmitz, and Ogg, 2012), resulting in an updated chronostratigraphic framework for the basin. The revised biostratigraphic interpretations have implications for important hydrocarbon source rocks. For example, the limestone unit in the southern parts of the basin, generally regarded as the Thorntonia Limestone, is of a different age to the type section for this unit, located in the Undilla Sub-basin. Additionally, the basal hot shale of the Arthur Creek Formation is diachronous across the Dulcie and Toko synclines, which may have ramifications for hydrocarbon exploration. This revised chronostratigraphic framework (by Geoscience Australia) for the Georgina Basin provides a baseline for the first basin-wide assessment of the unconventional hydrocarbon potential of the basin.
19
Sander, Regina, Zhejun Pan, Luke D. Connell, Michael Camilleri, Mihaela Grigore, and Yunxia Yang. "Controls on methane sorption capacity of Mesoproterozoic gas shales from the Beetaloo Sub-basin, Australia and global shales." International Journal of Coal Geology 199 (November 2018): 65–90. http://dx.doi.org/10.1016/j.coal.2018.09.018.
Повний текст джерела
20
Gorton, Justin, and Alison Troup. "Petroleum systems of the Proterozoic in northwest Queensland and a description of various play types." APPEA Journal 58, no. 1 (2018): 311. http://dx.doi.org/10.1071/aj17115.
Повний текст джерелаАнотація:
As part of Queensland Government’s Strategic Resources Exploration Program, in conjunction with the Australian Government’s Exploring for the Future program, a study to improve the subsurface knowledge of Proterozoic basins in northwest Queensland (NWQ) is underway. Proterozoic sedimentary basins are prevalent across central and western Australia. Several of these basins have proven petroleum systems, with the best discoveries to date being in the Greater McArthur Basin, Northern Territory. Recent exploration and appraisal in the Beetaloo Sub-basin of the Greater McArthur Basin has identified large volumes of gas resources contained within unconventional shale reservoirs. In NWQ, the Isa Superbasin and overlying South Nicholson Basin are related in both age and likely deposition to the Greater McArthur Basin. The thick, extensive shale units of the Isa Superbasin are excellent source rocks, while the Mullera Formation in the South Nicholson Basin also has potential but has not been investigated in detail. There are several potential reservoirs within the Proterozoic section and younger units of the overlying Georgina and Carpentaria basins, including clastic and carbonate types. Exploration in the Isa Superbasin identified an estimated 22.1 trillion cubic feet of prospective resources (Armour Energy 2015) in unconventional shale reservoirs of the Lawn Hill Formation and Riversleigh Siltstone. This paper will discuss the stratigraphy, depositional and structural history of these Proterozoic basins and characterise their source and reservoir units using existing and recently acquired geophysical, geochemical, petrographic and petrophysical datasets. From this, several plays or play concepts will be identified and described to help understand the region’s potential for both conventional and unconventional petroleum resources.
21
Henson, Paul, David Robinson, Lidena Carr, Dianne S. Edwards, Susannah K. MacFarlane, Amber J. M. Jarrett, and Adam H. E. Bailey. "Exploring for the Future—a new oil and gas frontier in northern Australia." APPEA Journal 60, no. 2 (2020): 703. http://dx.doi.org/10.1071/aj19080.
Повний текст джерелаАнотація:
Exploring for the Future (EFTF) is a four-year, AU$100.5 million initiative from the Australian Government conducted by Geoscience Australia in partnership with state and Northern Territory government agencies, CSIRO and universities to provide new geoscientific datasets for frontier regions. As part of this program, Geoscience Australia acquired two new seismic surveys that collectively extend across the South Nicholson Basin (L120 South Nicholson seismic line) and into the Beetaloo Sub-basin of the McArthur Basin (L212 Barkly seismic line). Interpretation of the seismic has resulted in the discovery of new basins that both contain a significant section of presumed Proterozoic strata. Integration of the seismic results with petroleum systems geochemistry, structural analyses, geochronology, rock properties and a petroleum systems model has expanded the knowledge of the region for energy exploration. These datasets are available through Geoscience Australia’s newly developed Data Discovery Portal: an online platform delivering digital geoscientific information, including seismic locations and cross-section images, and field site and well based sample data. Specifically for the EFTF energy project, a petroleum systems framework with supporting organic geochemical data has been built to access source rock, crude oil and natural gas datasets via interactive maps, graphs and analytical tools that enable the user to gain a better and faster understanding of a basin’s petroleum prospectivity.
22
Bailey, A. H. E., E. Grosjean, L. Wang, C. J. Boreham, G. A. Butcher, C. J. Carson, A. J. M. Jarrett, et al. "Resource potential of the Carrara Sub-basin from the deep stratigraphic well NDI Carrara 1." APPEA Journal 62, no. 2 (May 13, 2022): S378—S384. http://dx.doi.org/10.1071/aj21075.
Повний текст джерелаАнотація:
NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland.
23
Altmann, Carl, Elizabeth Baruch, David Close, Mohinudeen Faiz, Brenton Richards, and Alexander Cote. "Could the Mesoproterozoic Kyalla Formation Emerge as a Viable Gas Condensate Source Rock Reservor Play in the Beetaloo Sub-Basin?" ASEG Extended Abstracts 2018, no. 1 (December 2018): 1–8. http://dx.doi.org/10.1071/aseg2018abw9_2c.
Повний текст джерела
24
Taylor, Dennis, Aleksai E. Kontorovich, Andrei I. Larichev, and Miryam Glikson. "PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS." APPEA Journal 34, no. 1 (1994): 279. http://dx.doi.org/10.1071/aj93026.
Повний текст джерелаАнотація:
Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.
25
Yang, Bo, Todd M. Smith, Alan S. Collins, Tim J. Munson, Brenton Schoemaker, De Nicholls, Grant Cox, Juraj Farkas, and Stijn Glorie. "Spatial and temporal variation in detrital zircon age provenance of the hydrocarbon-bearing upper Roper Group, Beetaloo Sub-basin, Northern Territory, Australia." Precambrian Research 304 (January 2018): 140–55. http://dx.doi.org/10.1016/j.precamres.2017.10.025.
Повний текст джерела
26
Roshan, Hamid, Xiao Chen, Muhammad Asad Pirzada, and Klaus Regenauer-Lieb. "Permeability measurements during triaxial and direct shear loading using a novel X-ray transparent apparatus: Fractured shale examples from Beetaloo basin, Australia." NDT & E International 107 (October 2019): 102129. http://dx.doi.org/10.1016/j.ndteint.2019.102129.
Повний текст джерела
27
Hall, Lisa S., Meredith L. Orr, Megan E. Lech, Steven Lewis, Adam H. E. Bailey, Ryan Owens, Barry E. Bradshaw, and George Bernardel. "Geological and Bioregional Assessments: assessing the prospectivity for tight, shale and deep-coal resources in the Cooper Basin, Beetaloo Subbasin and Isa Superbasin." APPEA Journal 61, no. 2 (2021): 477. http://dx.doi.org/10.1071/aj20035.
Повний текст джерелаАнотація:
The Geological and Bioregional Assessment Program is a series of independent scientific studies undertaken by Geoscience Australia and the CSIRO, supported by the Bureau of Meteorology, and managed by the Department of Agriculture, Water and the Environment. The program consists of three stages across three regions with potential to deliver gas to the East Coast Gas Market. Stage 1 was a rapid regional prioritisation conducted by Geoscience Australia, to identify those sedimentary basins with the greatest potential to deliver shale and/or tight gas to the East Coast Gas Market within the next 5–10 years. This prioritisation process assessed 27 onshore eastern and northern Australian basins with shale and/or tight gas potential. Further screening reduced this to a shortlist of nine basins where exploration was underway. The shortlisted basins were ranked on a number of criteria. The Cooper Basin, the Beetaloo Subbasin and the Isa Superbasin were selected for more detailed assessment. Stage 2 of the program involved establishing a baseline understanding of the identified regions. Geoscience Australia produced regional geological evaluations and conceptualisations that informed the assessment of shale and/or tight gas prospectivity, ground- and surface-water impacts and hydraulic fracturing models. Geoscience Australia’s relative prospectivity assessments provide an indication of where viable petroleum plays are most likely to be present. These data indicate areal and stratigraphic constraints that support the program’s further work in Stage 3, on understanding likely development scenarios, impact assessments and causal pathways.
28
Doble, Rebecca, Dirk Mallants, Yousef Beiraghdar Aghbelagh, Dennis Gonzalez, Phil Davies, Luk Peeters, and Russell Crosbie. "Potential impacts of shale and tight gas developments on unconfined aquifers – a chemical screening framework." APPEA Journal 61, no. 2 (2021): 389. http://dx.doi.org/10.1071/aj20022.
Повний текст джерелаАнотація:
The Geological and Bioregional Assessment Program examines the potential impacts of shale, tight and deep coal gas development on water and the environment. A key part of the project was quantifying the potential for a decline in the water quality of unconfined aquifers due to unintentional chemical release at the soil surface. To assess this hazard, a quantitative analysis of chemical migration pathways was undertaken, which involved the estimation of contaminant attenuation by dilution and dispersion in soil and groundwater. This provided a conservative screening approach to identify areas for further analysis. Attenuation calculations involved one-dimensional advection-dispersion (AD) simulations through the unsaturated zone, and three-dimensional AD solute transport within the surficial aquifers. Dilution factor (DF) relationships for the combined effect of attenuation in the unsaturated and saturated zone were used to construct spatial maps of the potential for impact on aquifer properties after accidental chemical spills. A higher DF (therefore lower consequence of the surface contamination) was associated with deeper unsaturated zones characterized by heavier soils near the surface, and lower ground water velocities due to lower hydraulic conductivity and/or hydraulic gradient in the saturated zone. The framework was applied across the Cooper Basin and Beetaloo Sub-basin and resulted in two types of maps. The first identified areas being more susceptible to contamination if soil remediation does not occur within a 10-year period. The second map shows the spatially variable combined DFs for a ground water receptor, which may be used to develop site-specific management plans and mitigation measures.
29
Mackie, Steve. "Australian exploration review 2016." APPEA Journal 57, no. 2 (2017): 363. http://dx.doi.org/10.1071/aj16254.
Повний текст джерелаАнотація:
In 2016, explorers in Australia were called upon to demonstrate realistic optimism. The year clearly demonstrated that during an industry contraction, such as that seen by the upstream oil and gas industry since the oil price crash of late 2014, near field conventional exploration still produces discoveries. These include Shefu, Muruk, Davis, Outtrim and Spartan. Amungee NW demonstrated unconventional gas flows in the Beetaloo Basin. As usual, new reservoirs were discovered in appraisal programs such as at Roc and Phoenix South. Exploration lows, however, were the general mood with the inevitable unsuccessful wells, decreases in permit awards and associated work programs, the general low level of drilling activity both offshore and onshore, frustrations at approval delays and constraints and the still contracting business environment. This Petroleum Exploration Society of Australia review looks in detail at the trends and highlights for oil and gas exploration both onshore and offshore Australia during 2016; not just outcomes with the drill bit, but also leading industry health indicators such as drilling, seismic data acquisition and permit awards. It also seeks to be insightful and to make conclusions about the condition of oil and gas exploration in Australia, as well as comment on future implications for the industry.
30
Altmann, Carl, Brenton Richards, Alexander Côté, Cassandra Bein, Elizabeth Baruch-Jurado, and Les Jenkinson. "The Hayfield Sandstone Play: the characterisation of a Mesoproterozoic sourced, Proterozoic sandstone reservoired, tight oil and gas play in the Beetaloo Sub-basin." APPEA Journal 60, no. 1 (2020): 242. http://dx.doi.org/10.1071/aj19079.
Повний текст джерелаАнотація:
The Hayfield Sandstone is a Neoproterozoic, 10–15 m thick, very fine- to fine-grained sandstone, interpreted to have been deposited in a shelfal-marine environment. The reservoir sandstone is characterised by high porosity and low matrix permeability, which is complimented by partially mineralised open fractures which may contribute significantly to overall system permeability. Hydrocarbon phase across the identified play fairway is interpreted to range from a gas with the potential for condensate and liquefied petroleum gas streams to a light, ~38 API gravity oil. The extent of the prospective play fairway and the distribution and connectivity of reservoir facies is poorly constrained due to a limited number of well penetrations and poor resolution 2D seismic data. From the wells drilled to date, the gross area of the prospective play fairway could be as low as 300 km2 or greater than 1500 km2.
31
Stacey, Andrew, Mitchell Bouma, Emily Turner, and Mitchell Baskys. "Geological and Bioregional Assessments: a program to encourage industry development and improve regulatory efficiency while maintaining the highest possible environmental standards." APPEA Journal 61, no. 2 (2021): 471. http://dx.doi.org/10.1071/aj20032.
Повний текст джерелаАнотація:
The Australian Government’s $35.4 million Geological and Bioregional Assessment (GBA) Program provides independent scientific information and baseline data to governments, the community and regional industries on the potential impacts of shale, tight and deep coal gas development on water and the environment. The program aims to encourage industry development and growth by improving the understanding of upstream operations and their potential impacts to drive regulatory efficiency while maintaining the highest environmental standards. The GBA program comprises a series of independent scientific studies undertaken by CSIRO and Geoscience Australia, supported by the Bureau of Meteorology and managed by the Department of Agriculture, Water and the Environment. The program was conducted in three stages and focuses on where industry is currently exploring, conducting assessments across three regions; the Cooper Basin, Beetaloo Sub-basin and the Isa Superbasin, each with potential to supply gas to the East Coast Gas Market. The GBA program brings together a range of disciplines to collect, aggregate and analyse environmental baseline data to conceptualise the geologic, hydrologic, ecologic and anthropogenic features of these regions. This robust ‘conceptual’ understanding of the regions combined with rigorous hazard identification enables the program to prioritise potential impacts on water and the environment, improving regulatory efficiency by focusing regulators towards managing those activities where the potential impacts can’t be avoided. Additional papers and presentations from our partners in the GBA program tell the story of how the Program was developed and delivered. The Program leaves a legacy of publicly available baseline data, information and assessment tools that will make regulation of the industry more efficient in the regions assessed.
32
Suckow, Axel, Alec Deslandes, Christoph Gerber, Sebastien Lamontagne, Dirk Mallants, Philip Davies, Andrew Taylor, et al. "Multi-isotope studies investigating recharge and inter-aquifer connectivity in coal seam gas areas (Qld, NSW) and shale gas areas (NT)." APPEA Journal 60, no. 1 (2020): 335. http://dx.doi.org/10.1071/aj19187.
Повний текст джерелаАнотація:
Large sedimentary basins with multiple aquifer systems like the Great Artesian Basin and the Beetaloo Sub-Basin are associated with large time and spatial scales for regional groundwater flow and mixing effects from inter-aquifer exchange. This makes them difficult to study using traditional hydrogeological investigation techniques. In continental onshore Australia, such sedimentary aquifer systems can also be important freshwater resources. These resources have become increasingly stressed because of growing demand and use of groundwater by multiple industries (e.g. stock, irrigation, mining, oil and gas). The social licence to operate for extractive oil and gas industries increasingly requires robust and reliable scientific evidence on the degree to which the target formations are vertically and laterally hydraulically separated from the aquifers supplying fresh water for stock and agricultural use. The complexity of such groundwater interactions can only be interpreted by applying multiple lines of evidence including environmental isotopes, hydrochemistry, hydrogeological and geophysical observations. We present an overview of multi-tracer studies from coal seam gas areas (Queensland and New South Wales) or areas targeted for shale gas development (Northern Territory). The focus was to investigate recharge to surficial karst and deep confined aquifer systems before industrial extraction on time scales of decades up to one million years and aquifer inter-connectivity at the formation scale. A systematic and consistent methodology is applied for the different case study areas aimed at building robust conceptual hydrogeological models that inform groundwater management and groundwater modelling. The tracer studies provided (i) in all areas increased confidence around recharge estimates, (ii) evidence for a dual-porosity flow system in the Hutton Sandstone (Queensland) and (iii) new insights into the connectivity, or lack thereof, of flow systems.
33
Meredith, Christopher. "Australia's unconventional future: where next?" APPEA Journal 59, no. 2 (2019): 654. http://dx.doi.org/10.1071/aj18098.
Повний текст джерелаАнотація:
Eastern Australia is now reliant on coal-seam gas (CSG) for its domestic gas supply; in 2018, it accounted for two-thirds of total eastern coast gas production. Australia has seen a rapid transition from relying on ‘conventional’ resources to relying on ‘unconventional’ gas supply. As legacy conventional supply sources mature and decline, exploration has been insufficient to keep up with market demand. This has created the opportunity for Australia’s vast CSG resources to fill the gap. But the development of CSG has been neither easy nor straightforward. And the costly requirement to drill hundreds, if not thousands, of wells in every single development has driven up the cost of supply. Most CSG reserves will be produced for the Pacific Basin LNG market via the three LNG projects on the east coast of Queensland. However, it is the resources beyond these LNG projects that will need to be developed, so as to ensure future supply to the east coast gas market. It is these other resources, both CSG and shale, that we evaluated to gain a picture of future gas supplies and costs. Our indicative economics showed that alternative CSG resources and Beetaloo shale both have high well-head break-even costs. In addition, the infrastructure required to get them to market will be expensive. The high costs, coupled with the demand from the LNG plants of Gladstone leads us to conclude that eastern-coast gas prices are likely to remain closely linked to global LNG prices for the foreseeable future.
34
Mumford, Nicholas. "Commercial realities of the proposed LNG import terminals on the east coast of Australia." APPEA Journal 59, no. 2 (2019): 663. http://dx.doi.org/10.1071/aj18175.
Повний текст джерелаАнотація:
Recent government intervention in the East Australian Gas Market (EAGM) may have temporarily settled short-term supply availability concerns; however, gas prices in the EAGM now inevitably trend with the spot LNG Netback Price. Notwithstanding, supply remains tight, due to lack of upstream investment from overhang of some state government policies restricting exploration and development, and the lack of investment stemming from the recent period of low oil prices. Save further government intervention to retrospectively reserve already contractually committed export supply from the three Queensland LNG export projects, there is no ‘quick fix’ solution to fully address market tightness in the short to medium term from indigenous sources of gas supply. The only real solution to ensure security of supply over a reasonable tenure is to import LNG into the EAGM. However, the clear commercial reality of gas supply sourced from an LNG import terminal is that it can only be supported by high gas prices, albeit also providing other market benefits such as peaking capacity and storage. Without a solution to the EAGM supply–demand issue, there will be demand destruction as industrial users and electricity power generators seek alternatives to gas supply or simply cease operations. Most indigenous gas supply alternatives to LNG imports stem from the northern states and may provide solutions over the longer term (e.g. Beetaloo Basin), but do not solve the immediate need for gas supply in the southern states by 2020/21. New supply from the north is in any event physically pipeline-constrained over this timeframe.
35
Yang, B., A. S. Collins, M. L. Blades, N. Capogreco, J. L. Payne, T. J. Munson, G. M. Cox, and S. Glorie. "Middle–late Mesoproterozoic tectonic geography of the North Australia Craton: U–Pb and Hf isotopes of detrital zircon grains in the Beetaloo Sub-basin, Northern Territory, Australia." Journal of the Geological Society 176, no. 4 (March 28, 2019): 771–84. http://dx.doi.org/10.1144/jgs2018-159.
Повний текст джерела
36
Subarkah, Darwinaji, Angus L. Nixon, Monica Jimenez, Alan S. Collins, Morgan L. Blades, Juraj Farkaš, Sarah E. Gilbert, Simon Holford, and Amber Jarrett. "Constraining the geothermal parameters of in situ Rb–Sr dating on Proterozoic shales and their subsequent applications." Geochronology 4, no. 2 (September 6, 2022): 577–600. http://dx.doi.org/10.5194/gchron-4-577-2022.
Повний текст джерелаАнотація:
Abstract. Recent developments in tandem laser ablation mass spectrometer technology have demonstrated the capacity for separating parent and daughter isotopes of the same mass online. As a result, beta-decay chronometers can now be applied to the geological archive in situ as opposed to through traditional whole-rock digestions. One novel application of this technique is the in situ Rb–Sr dating of Proterozoic shales that are dominated by authigenic clays such as illite. This method can provide a depositional window for shales by differentiating signatures of early diagenetic processes versus late-stage secondary alteration. However, the hydrothermal sensitivity of the Rb–Sr isotopic system across geological timescales in shale-hosted clay minerals is not well understood. As such, we dated the Mesoproterozoic Velkerri Formation from the Altree 2 well in the Beetaloo Sub-basin (greater McArthur Basin), northern Australia, using this approach. We then constrained the thermal history of these units using common hydrocarbon maturity indicators and modelled effects of contact heating due to the intrusion of the Derim Derim Dolerite. In situ Rb–Sr dating of mature, oil-prone shales in the diagenetic zone from the Velkerri Formation yielded ages of 1448 ± 81, 1434 ± 19, and 1421 ± 139 Ma. These results agree with previous Re–Os dating of the unit and are interpreted as recording the timing of an early diagenetic event soon after deposition. Conversely, overmature, gas-prone shales in the anchizone sourced from deeper within the borehole were dated at 1322 ± 93 and 1336 ± 40 Ma. These ages are younger than the expected depositional window for the Velkerri Formation. Instead, they are consistent with the age of the Derim Derim Dolerite mafic intrusion intersected 800 m below the Velkerri Formation. Thermal modelling suggests that a single intrusion of 75 m thickness would have been capable of producing a significant hydrothermal perturbation radiating from the sill top. The intrusion width proposed by this model is consistent with similar Derim Derim Dolerite sill thicknesses found elsewhere in the McArthur Basin. The extent of the hydrothermal aureole induced by this intrusion coincides with the window in which kerogen from the Velkerri Formation becomes overmature. As a result, the mafic intrusion intersected here is interpreted to have caused kerogen in these shales to enter the gas window, induced fluids that mobilize trace elements, and reset the Rb–Sr chronometer. Consequently, we propose that the Rb–Sr chronometer in shales may be sensitive to temperatures of ca. 120 ∘C in hydrothermal reactions but can withstand temperatures of more than 190 ∘C in thermal systems not dominated by fluids. Importantly, this study demonstrates a framework for the combined use of in situ Rb–Sr dating and kerogen maturation indicators to help reveal the thermochronological history of Proterozoic sedimentary basins. As such, this approach can be a powerful tool for identifying the hydrocarbon potential of source rocks in similar geological settings.
37
Jacobs, Trent. "Unconventional Reservoirs: Australian Exploration Experts Weigh In on Rosy Reserves Estimates." Journal of Petroleum Technology 74, no. 01 (January 1, 2022): 34–37. http://dx.doi.org/10.2118/0122-0034-jpt.
Повний текст джерелаАнотація:
The early days of a new shale play can be exciting, but they can also come with inflated expectations. This is a familiar theme in the unconventional sector which has delivered a myriad of discoveries over the past decade that have failed to achieve commerciality. It’s especially familiar for those involved in Australia’s unconventional projects where big hopes have been pinned on the tight-gas potential of places called the Beetaloo, Canning, and Cooper Basin. Instead, the only long-term success to be found on the Australian unconventional landscape is a mature coal-seam gas sector which, not to be discounted, helped the country claim the status of the world’s top exporter of liquefied natural gas in 2020. For Duncan Lockhart, one of the chief reasons that Australia’s tight-gas ambitions have yet to materialize likewise lies in the fact that tight-rock plays extend for vast areas compared with even the largest conventional systems. As a result, the general manager of exploration with Brisbane-based Central Petroleum said some of the estimates on unconventional prospective resources are “verging on fantasy.” Lockhart issued his critique as a co-chair of a resource valuation panel hosted by the Asia Pacific Unconventional Resources Technology Conference in November 2021 The discussion between several exploration experts tried to identify the biggest missteps in Australia’s tight-gas adventure thus far. At the highest level, the industry depended on the promising results of too few appraisal wells to formulate reserves estimates on areas covering hundreds and sometimes thousands of square kilometers. Lockhart emphasized in trying to evaluate such “massive areas,” operators and appraisers have been pushed into a corner. “We need to make a whole bunch of major assumptions about a whole bunch of inputs,” he said, adding that left out of the initial estimates all too often is “the amount of heterogeneity that we will be experiencing in these rocks over these large areas.” Lockhart was not alone in his concerns. With hindsight, it has become easier to see that the highest-performing wells tend to be drilled in isolated sweet spots and along narrow fairways—not across the entirety of a play’s geographic boundaries as shown on the map. The risk facing every operator in this situation is that it will burn through its capital on the wrong slivers of shale and, in turn, see its investors run for the exit. Martin Wilkes, a managing director with energy consulting firm RISC Advisory in Perth, took aim at what he characterized as the “sales message” approach that tends to ignore such facts of life during the early promotion of tight-gas plays. “[Operators] talk up total organic compound content and use it to develop these large numbers, which then get transferred into a continued resource using standard recovery factors,” he said.
38
Ahmed, EM, MR Amin, R. Basrin, and MSA Bhuiyan. "Phenotypic characterization and production potentials of exotic goat breeds and their crosses in Rajshahi metropolitan area of Bangladesh." Bangladesh Journal of Animal Science 49, no. 2 (May 4, 2021): 100–107. http://dx.doi.org/10.3329/bjas.v49i2.53218.
Повний текст джерелаАнотація:
This study was conducted to investigate the morphology, morphometry and production performances of exotic goat breeds and their crossbreds available at Boalia, Shahmokhdum, Rajpara and Matihar thana under Rajshahi metropolitan city. A total of 73 animals’ information was collected from 39 exotic goat flock owners using a semi-structured questionnaire through interviewing of farmers, visual observation and on-spot measurement of the animals. Exotic goat breeds and their crosses were found predominantly higher (>93%) in Rajshahi Metropolitan areas where less than 7% Black Bengal goats were identified. In most cases, deviation of breed specific coat color due to crossing between different types of crossbreds among the populations was noted. The genotype frequencies of Beetal, Kalahari, Sirohi, Jamunapari, Anglo Nubian and their crossbreds and Black Bengal goats were found to be 50.68, 15.07, 13.70, 8.22, 8.22 and 4.11%, respectively. The average mature live weight (12 to 18 months) of those corresponding exotic genotypes in male and female respectively were found 46.88±5.66, 56.07±8.03, 32.67±8.09, 59.54±7.96 and 64.06±4.67 kg, and 21.70±2.24, 22.41±3.64, 17.37±4.05, 24.5±0.5 and 27.47±6.85 kg. Irrespective of genotypes, the mean age at puberty, lactation length, litter size, kidding interval and days open were found 167.50±3.49 days, 76.61±4.90 days, 1.71±0.10, 224.44±5.56 days and 52.64 ± 2.30 days, respectively. However, none of the aforementioned traits differed significantly (P>0.05) among the five different exotic genotypes. In conclusion, this study provides some basic information on the performances of exotic goat breeds or their crossbreds at Metropolitan areas under intensive management conditions which could be utilized for designing proper breeding plan in their conservation and simultaneous improvement.
Bang. J. Anim. Sci. 2020. 49 (2): 100-107
39
PEABODY, WILLIAM W., STEPHEN G. STO. "Abstract: Proterozoic Prospects in Australia's Beetaloo Basin, NT ." AAPG Bulletin 83 (1999) (1999). http://dx.doi.org/10.1306/c9ebc40f-1735-11d7-8645000102c1865d.
Повний текст джерела
40
Jarrett, Amber J. M. "Concurrent 17. Presentation for: Petroleum supersystems in the greater McArthur Basin, Northern Territory, Australia: prospectivity of the world’s oldest stacked systems with emphasis on the McArthur Supersystem." APPEA Journal 62, no. 4 (June 3, 2022). http://dx.doi.org/10.1071/aj21358.
Повний текст джерелаАнотація:
Presented on Wednesday 18 May: Session 17 This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales. To access the presentation click the link on the right. To read the full paper click here
41
Lamontagne, Sébastien, Axel Suckow, Christoph Gerber, Alec Deslandes, Cornelia Wilske, and Steven Tickell. "Groundwater sources for the Mataranka Springs (Northern Territory, Australia)." Scientific Reports 11, no. 1 (December 2021). http://dx.doi.org/10.1038/s41598-021-03701-1.
Повний текст джерелаАнотація:
AbstractThe Mataranka Springs Complex is the headwater of the iconic Roper River of northern Australia. Using environmental tracers measured in springs and nearby boreholes, the origin of groundwater contributing to the springs was evaluated to help assess the impact of proposed groundwater extraction in the Cambrian Limestone Aquifer (CLA) for irrigation agriculture and for hydraulic fracturing in the Beetaloo Sub-basin (an anticipated world-class unconventional gas reserve). Major ions, Sr, 87Sr/86Sr, δ18O-H2O, δ2H-H2O, 3H, 14C-DIC were consistent with regional groundwater from the Daly and Georgina basins of the CLA as the sources of water sustaining the major springs (Rainbow and Bitter) and one of the minor springs (Warloch Pond). However, 3H = 0.34 TU in another minor spring (Fig Tree) indicated an additional contribution from a young (probably local) source. High concentrations of radiogenic 4He (> 10–7 cm3 STP g–1) at Rainbow Spring, Bitter Spring and in nearby groundwater also indicated an input of deeper, older groundwater. The presence of older groundwater within the CLA demonstrates the need for an appropriate baseline characterisation of the vertical exchange of groundwater in Beetaloo Sub-basin ahead of unconventional gas resource development.
42
Yang, Bo, Alan S. Collins, Morgan L. Blades, Tim J. Munson, Justin L. Payne, Stijn Glorie, and Juraj Farkaš. "Tectonic controls on sedimentary provenance and basin geography of the Mesoproterozoic Wilton package, McArthur Basin, northern Australia." Geological Magazine, December 23, 2020, 1–20. http://dx.doi.org/10.1017/s0016756820001223.
Повний текст джерелаАнотація:
Abstract The c. 1.5–1.3 Ga Wilton package, the upper succession of the greater McArthur Basin, preserves detailed tectono-sedimentary evidence for the Mesoproterozoic evolution of the North Australian Craton (NAC). In addition, it is a valuable global sedimentary repository for the poorly explored Mesoproterozoic. New detrital zircon U–Pb age and Lu–Hf isotope data, collected from multiple, geographically separated, basins that make up the Wilton package, are compiled with previously published data to illuminate the basin evolution. The spatial and temporal variation in sedimentary provenance illustrates two major geographic changes that correspond to continent-scale tectonic convulsions of the NAC during the Mesoproterozoic. The first is shown by the influx of sediment sourced from east and southeast terranes. This is linked to rifting between Proterozoic Australia and Laurentia at c. 1.45 Ga, resulting in the uplift of the eastern margin of the NAC–SAC (South Australian Craton). The second basin geographic change is illustrated by a flux of southerly-sourced detritus that is interpreted to be tectonically driven by the uplift of the southern NAC, during the subduction/closure of the Mirning Ocean at c. 1.32 Ga. Spatially, sediment in the Wilton package is separated into two depositional systems: sedimentary rocks within the Birrindudu Basin, the western component of the Wilton package, have different detrital signatures relative to other Wilton package successions found east of the Daly Waters Fault Zone, in the Beetaloo Sub-basin, the McArthur Basin and the South Nicholson Basin. The Daly Waters Fault Zone is interpreted as an ancient bathymetric high, blocking sediment transport. Although they differ in sources, rocks in both the Birrindudu Basin and the eastern Wilton package record coeval shifts of basin provenance to southern sources. The coherent evolution of basin provenance indicates a consistent tectono-sedimentation history, and links the Birrindudu Basin and the other Wilton successions in a tectonic framework.
43
Faiz, Mohinudeen, Carl Altmann, Elizabeth Baruch, Alexander Côté, Se Gong, Richard Schinteie, and Padmasiri Ranasinghe. "Organic matter composition and thermal maturity evaluation of Mesoproterozoic source rocks in the Beetaloo Sub-Basin, Australia." Organic Geochemistry, October 2022, 104513. http://dx.doi.org/10.1016/j.orggeochem.2022.104513.
Повний текст джерела
44
Craig, Adam. "Concurrent 13. Presentation for: Exploration and appraisal year in review 2021." APPEA Journal 62, no. 4 (June 3, 2022). http://dx.doi.org/10.1071/aj21345.
Повний текст джерелаАнотація:
Presented on Wednesday 18 May: Session 13 Petroleum exploration and appraisal activity increased in 2021. Exploration spend increased for the year, continuing a positive trend. Onshore exploration and appraisal activity continues to dominate the petroleum exploration scene in Australia. Positive indications of increased work program bids (wells, seismic and spend) are, however, tempered by the downward trend of total exploration acreage (by area) and new acreage awards. In addition to petroleum exploration acreage, greenhouse gas sequestration acreage was released across Australia in 2021. Twenty-nine exploration wells were drilled in the year compared to twenty-five in the previous year. Eight conventional petroleum discoveries were reported, with the Artisan-1 discovery in the Otway Basin being the only offshore discovery. The Lockyer Deep-1 gas discovery in the Northern Perth Basin continues the exploration success of the Permian Kingia and High Cliff Sandstone play. The Cooper–Eromanga Basin continues to yield discoveries with the Odin-1, Rosebay-1, Lowry South, Liger-1 and Chimera-1 discoveries reported for the year. Thirty-one appraisal wells were drilled for the year with significant activity in the Northern Perth Basin, Cooper-Eromanga Basin and Bowen-Surat Basins. Exploration and appraisal drilling also continued in the Beetaloo Sub-basin with the drilling of the Tanumbirini-2H, Tanumbirini-3H and Carpentaria-2/2H wells during the year. To access the presentation click the link on the right. To read the full paper click here
45
Bailey, A. H. E. "Concurrent 17. Presentation for: Resource potential of the Carrara Sub-basin from the deep stratigraphic well NDI Carrara 1." APPEA Journal 62, no. 4 (June 3, 2022). http://dx.doi.org/10.1071/aj21359.
Повний текст джерелаАнотація:
Presented on Wednesday 18 May: Session 17 NDI Carrara 1 is a deep stratigraphic well completed in 2020 as part of the MinEx CRC National Drilling Initiative (NDI), in collaboration with Geoscience Australia and the Northern Territory Geological Survey. It is the first stratigraphic test of the Carrara Sub-basin, a newly discovered depocentre in the South Nicholson Region. The well intersected Proterozoic sediments with numerous hydrocarbon shows, likely to be of particular interest due to affinities with the known Proterozoic plays of the Beetaloo Sub-basin and the Lawn Hill Platform, including two organic-rich black shales and a thick sequence of interbedded black shales and silty-sandstones. Alongside an extensive suite of wireline logs, continuous core was recovered from 283.9 m to total depth at 1750.8 m, providing high-quality data to support comprehensive analysis. Presently, this includes geochronology, geochemistry, geomechanics and petrophysics. Rock-Eval pyrolysis data demonstrate the potential for several thick black shales to be a source of hydrocarbons for conventional and unconventional plays. Integration of these data with geomechanical properties highlights potential brittle zones within the fine-grained intervals where hydraulic stimulation is likely to enhance permeability, identifying prospective Carrara Sub-basin shale gas intervals. Detailed wireline log analysis further supports a high potential for unconventional shale resources. Interpretation of the L210 and L212 seismic surveys suggests that the intersected sequences are laterally extensive and continuous throughout the Carrara Sub-basin, potentially forming a significant new hydrocarbon province and continuing the Proterozoic shale play fairway across the Northern Territory and northwest Queensland. To access the presentation click the link on the right. To read the full paper click here
46
Clarkson, Christopher R., and Alexander Cote. "Analysis of Multiple Flow/Buildup Tests Including a 5-Year Buildup: Case Study of an Australian Shale Gas Well." SPE Reservoir Evaluation & Engineering, November 1, 2022, 1–19. http://dx.doi.org/10.2118/212851-pa.
Повний текст джерелаАнотація:
Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly “textbook” quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.