Old rocks, new tricks: a reinvigorated Cooper Basin offers growth opportunity

2019 ◽  
Vol 59 (2) ◽  
pp. 928
Author(s):  
Bill Ovenden
Keyword(s):  
Oil And Gas ◽  
Low Cost ◽  
New Technology ◽  
South Australia ◽  
Production Costs ◽  
Imaging Data ◽  
Oil And Gas Development ◽  
North East ◽  
Risk Appetite ◽  
Cooper Basin

The Cooper Basin spans north-east South Australia and south-west Queensland and is Australia’s largest integrated onshore oil and gas development. Santos and Delhi first discovered commercial gas in 1963. First oil was discovered in 1970. Since then, the Cooper Basin has become a strategically important processing and transportation hub for produced gas and liquids. Continuous investment in new technology, the use of existing infrastructure and, recently, an unrelenting drive to lower drilling and production costs has delivered a low-cost, high-margin producer for east coast domestic and liquefied natural gas (LNG) export markets. This improved operating performance has, in turn, offered Santos the opportunity to reassess ‘our backyard’. The Cooper Basin boasts many growth options, remaining and emerging. Seismic advances are providing improved imaging. Data management, the use of play-based exploration studies, innovative geoscience thinking and renewed investment risk appetite are playing key roles in the development of discovered resources and the exploration of new and emerging plays. Targeted wildcat exploration and appraisal programs, supported by low-cost operations, offer the potential to unlock significant remaining oil and gas resources. The Cooper Basin is poised for another stage of growth. This tangible potential emphasises the critical future role the basin is likely to continue to play as an onshore Australian hydrocarbon supply hub.

EXPLORATION IN THE COOPER BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 366 ◽  
Author(s):  
R. Heath
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Mature Stage ◽  
Small Contribution ◽  
Terrestrial Source ◽  
Seismic Acquisition ◽  
Proterozoic Basement ◽  
Gas Fields ◽  
Coal Measures ◽  
Cooper Basin

The Cooper Basin is located in the northeastern corner of South Australia and in the southwestern part of Queensland. The basin constitutes an intracratonic depocentre of Permo- Triassic age. The Cooper Basin succession unconformably overlies Proterozoic basement as well as sediments and metasediments of the Cambro- Ordovician age. An unconformity separates in turn the Cooper succession from the overlying Jurassic- Cretaceous Eromanga Basin sediments.The Permo- Triassic succession comprises several cycles of fluvial sandstones, fluvio- deltaic coal measures and lacustrine shales. The coal measures contain abundant humic kerogen, comprising mainly inertinite and vitrinite with a small contribution of exinite. All hydrocarbon accumulations within the Cooper Basin are believed to have originated from these terrestrial source rocks.Exploration of the basin commenced in 1959 and, after several dry holes, the first commercial discovery of gas was made at Gidgealpa in 1963. To date, some 97 gas fields and 10 oil fields, containing recoverable reserves of 5 trillion cubic feet of gas and 300 million barrels recoverable natural gas liquids and oil, have been discovered in the Cooper Basin. Production is obtained from all sand- bearing units within the Cooper stratigraphic succession.The emphasis of exploration in the Cooper Basin is largely directed towards the assessment of four- way dip closures and three- way dip closures with fault control, but several stratigraphic prospects have been drilled. Furthermore, in the development phase of some gas fields a stratigraphic component of the hydrocarbon trapping mechanism has been recognised.Improvements in seismic acquisition and processing, combined with innovative thinking by the explorers, have facilitated the development of untested structural/stratigraphic plays with large reserves potential. Exploration for the four- and three- way dip closure plays in the Cooper Basin is now at a mature stage. However, reserves objectives are expected to continue to be met, with the expectation of a continuing high success rate.Selected new plays are expected to be tested within a continuing active exploration program as exploration for oil and gas in the Cooper Basin refines the search for the subtle trap.

scholarly journals Unprecedented quiescence in resource development area allows detection of long-lived latent seismicity

Solid Earth ◽  
2021 ◽  
Vol 12 (3) ◽  
pp. 765-783
Author(s):  
Rebecca O. Salvage ◽  
David W. Eaton
Keyword(s):  
British Columbia ◽  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Stock Prices ◽  
Oil And Gas ◽  
Economic Market ◽  
Oil And Gas Development ◽  
Seismicity Rate ◽  
North East ◽  
Correlation Prior

Abstract. Recent seismicity in Alberta and north-east British Columbia has been attributed to ongoing oil and gas development in the area, due to its temporal and spatial correlation. Prior to such development, the area was seismically quiescent. Here, we show evidence that latent seismicity may occur in areas where previous operations have occurred, even during a shutdown in operations. The global COVID-19 pandemic furnished the unique opportunity to study seismicity during a long period of anthropogenic quiescence. Within the Kiskatinaw area of British Columbia, 389 events were detected from April to August 2020, which encompasses a period with very little hydraulic fracturing operations. This reduction in operations was the result of a government-imposed lockdown severely restricting the movement of people as well as a downturn in the economic market causing industry stock prices to collapse. Except for a reduction in the seismicity rate and a lack of temporal clustering that is often characteristic of hydraulic fracturing induced sequences, the general characteristics of the observed seismicity were similar to the preceding time period of active operations. During the period of relative quiescence, event magnitudes were observed between ML −0.7 and ML 1.2, which is consistent with previous event magnitudes in the area. Hypocentres occurred in a corridor orientated NW–SE, just as seismicity had done in previous years, and were located at depths associated with the target Montney formation or shallower (<2.5 km). A maximum of 21 % of the detected events during lockdown may be attributable to natural seismicity, with a further 8 % potentially attributed to dynamic triggering of seismicity from teleseismic events and 6 % related to ongoing saltwater disposal and a single operational well pad. However, this leaves ∼65 % of the seismicity detected during lockdown being unattributable to primary activation mechanisms. This seismicity is unlikely to be the result of direct pore pressure increases (as very little direct injection of fluids was occurring at the time) and we see no patterns of temporal or spatial migration in the seismicity as would be expected from direct pore pressure increases. Instead, we suggest that this latent seismicity may be generated by aseismic slip as fluids (resulting from previous hydraulic fracturing injection) become trapped within permeable formations at depth, keeping pore pressures in the area elevated and consequently allowing the generation of seismicity. Alternatively, this seismicity may be the result of fault and fracture weakening in response to previous fluid injection. This is the first time that this latent seismicity has been observed in this area of British Columbia and, as such, this may now represent the new normal background seismicity rate within the Kiskatinaw area.

Offshore Oil and Gas: The Future Engineering Contribution

1974 ◽  
Vol 188 (1) ◽  
pp. 11-24 ◽  
Author(s):  
L. C. Allcock
Keyword(s):  
Continental Shelf ◽  
Oil And Gas ◽  
New Technology ◽  
Gas Production ◽  
Oil And Gas Development ◽  
Oil And Gas Production ◽  
The Future ◽  
Offshore Oil And Gas ◽  
Offshore Oil ◽  
Production Industry

Development of offshore oil and gas production from the continental shelf and in even deeper water will be dependent on engineers. It is of primary importance to understand the nature of the oil and gas production industry in order to follow more clearly the contribution that will be required from many of the professional branches of engineering, and a great deal of new technology must be developed in order that the problems of the future may be overcome. The difficulty may not be in defining the future engineering of oil and gas development but in finding engineers in sufficient numbers to meet the demand.

THE NATURAL CONVERSION OF OIL TO GAS IN SEDIMENTS IN THE COOPER BASIN

1971 ◽  
Vol 11 (1) ◽  
pp. 121
Author(s):  
J.D. Brooks ◽  
W.R. Hesp ◽  
D. Rigby
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
High Rank ◽  
Average Chain Length ◽  
Low Grade ◽  
Liquid Hydrocarbons ◽  
Gaseous Products ◽  
Underground Gasification ◽  
Long Chain ◽  
Cooper Basin

In the Permian Cooper Basin, South Australia, in which oil and gas occur in coal-bearing sediments, there appears to be a relation between the degree of low grade metamorphism of the coaly matter and the nature of the hydrocarbons in the reservoirs. Liquid hydrocarbons are not found in areas and at depths where the coals are at the high-rank bituminous stage (88-89% carbon, dry mineral-free); there, methane is the main hydrocarbon present. Oil occurs in association with coals of lower rank (80-85% carbon, dry mineral-free) and it seems possible that underground gasification of the liquid hydrocarbons has occurred under natural conditions during advanced coalification.In order to test this, mixtures of long chain paraffins (C10-C28) and (C16-C31) from Kingfish crude oil (East Gippsland Basin) were heated at various pressures, with and without water at temperatures between 255-375°C with the intention of reproducing in one week reactions which might occur at lower temperatures in sediments during geological time.The formation of gaseous products (C1-C4 hydrocarbons; hydrogen and carbon dioxide), light liquid paraffins (C10-C16) and aromatic hydrocarbons was observed. The average chain length of the long chain hydrocarbons was reduced and the effect was more pronounced with the longer chain (C16-C31) fraction. It is concluded that during extended time at temperatures near 400°F which prevail in the deeper parts of the Cooper Basin, gasification reactions involving progressive chain shortening could be responsible for the absence of liquid hydrocarbons in regions where the coals are of the high-rank bituminous type.

Plugging the holes—new Canadian and US regulations to reduce upstream methane emissions

2019 ◽  
Vol 12 (4) ◽  
pp. 294-313
Author(s):  
Allan Ingelson
Keyword(s):  
Environmental Protection Agency ◽  
Oil And Gas ◽  
New Technology ◽  
Oil And Gas Industry ◽  
Methane Emissions ◽  
Oil And Gas Development ◽  
Gas Industry ◽  
Negotiated Settlement ◽  
Enforcement Action ◽  
The Usa

Abstract In the USA and Canada where most of global shale oil and gas development has occurred, due to concerns about climate change the national governments have adopted new regulations to further significantly reduce national methane emissions from the upstream oil and gas industry. The 2016 US Environmental Protection Agency emissions standards and 2018 Canadian methane regulations build on decades old oil and gas conservation schemes to further reduce the volume of methane that is released from facility equipment leaks and venting. In Canada, venting methane at new oil and gas well sites is now prohibited. Operators are required to capture and use a much larger volume of natural gas than in the past. A negotiated settlement of the first US emissions reduction enforcement action was reached in April 2018. The facility operator agreed to pay a civil penalty of US $610,000 and spend a minimum of $2 million to install new technology at its facilities to further reduce methane emissions. The creative settlement agreement contains a comprehensive set of conditions to provide for a reduction in upstream industry emissions.

Fracture mapping and modelling in shale-gas target in the Cooper Basin, South Australia

2011 ◽  
Vol 51 (1) ◽  
pp. 397 ◽  
Author(s):  
Guillaume Backé ◽  
Hani Abul Khair ◽  
Rosalind King ◽  
Simon Holford
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Oil And Gas ◽  
South Australia ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Low Permeability ◽  
Lake Area ◽  
Stress Regime ◽  
Cooper Basin

The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

scholarly journals Oil and Gas in the Arctic: Legal Status and Reserves

2014 ◽  
pp. 60-67
Author(s):  
N. N. Shvets ◽  
P. V. Beresneva
Keyword(s):  
Legal Status ◽  
Oil And Gas ◽  
International Energy Agency ◽  
Business Case ◽  
Gas Production ◽  
Production Costs ◽  
The Arctic ◽  
Outer Continental Shelf ◽  
Oil And Gas Development ◽  
Energy Agency

When researching such a hot topic as development of oil and gas reserves in Artie it's crucial to answer 3 key questions. What is legal status of Artie reserves and Russian offshore zone in Arctic? Are there any gaps in international lawthatinhibits oil and gas development? How big are Arctic oil and gas reserves? Are they well-explored? What are production costs of oil and gas in Artie? Is it profitable to develop reserves in Artie? The article addresses these vital questions with the detailed analysis. 1982 UN Convention on the Law of Sea partially regulates Artie legal status but countries apply sectorial principal to Arctic territories to claim their rights. There are few border disputes left. The borders of Russian outer continental shelf are shaped by international law and bilateral agreements and undergoing final review within UN processes and mechanisms. Arctic reserves'estimates do vary significantly as the region is barely explored. According to with a high 2008 US Geological Survey and 2006 Wood Mackenzie and Fugro Robertson study Arctic reserves are about 10-15% of global reserves. Most of them are offshore (around 85%), and gas accounts for 80% of reserves. Russia has more than a half of Artie reserves. Under International Energy Agency it's profitable to develop Arctic oil reserves as production costs ($40-100 bbl) are below current and 2035 forecast oil price. On the contrary, gas production is questionable from costs point of view. Gas market is projected to remain regional. With Artie gas production cost of$ 4-12 million BTU, there is no business case to develop Artie gas in America and at the edge of profitability in Europe.

Consideration of Geopolitical Challenges within the Analysis of Geoenvironmental Risks for Oil and Gas Development of the Russian Arctic

2019 ◽  
Vol 16 (6) ◽  
pp. 50-59
Author(s):  
O. P. Trubitsina ◽  
V. N. Bashkin
Keyword(s):  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Optimal Operation ◽  
The Arctic ◽  
Stage Model ◽  
Oil And Gas Development ◽  
Gas Industry ◽  
The Impact ◽  
Further Development ◽  
Geopolitical Risks

The article is devoted to the consideration of geopolitical challenges for the analysis of geoenvironmental risks (GERs) in the hydrocarbon development of the Arctic territory. Geopolitical risks (GPRs), like GERs, can be transformed into opposite external environment factors of oil and gas industry facilities in the form of additional opportunities or threats, which the authors identify in detail for each type of risk. This is necessary for further development of methodological base of expert methods for GER management in the context of the implementational proposed two-stage model of the GER analysis taking to account GPR for the improvement of effectiveness making decisions to ensure optimal operation of the facility oil and gas industry and minimize the impact on the environment in the geopolitical conditions of the Arctic.The authors declare no conflict of interest

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