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.

Anisotropy signatures in the Cooper Basin of Australia: Stress versus fractures

2016 ◽  
Vol 4 (2) ◽  
pp. SE51-SE61 ◽  
Author(s):  
Stephanie Tyiasning ◽  
Dennis Cooke
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Seismic Anisotropy ◽  
Transverse Isotropy ◽  
Ground Truth ◽  
Tectonic Stress ◽  
Reverse Fault ◽  
Stress Regime ◽  
Velocity Anisotropy ◽  
Cooper Basin

Theoretically, vertical fractures and stress can create horizontal transverse isotropy (HTI) anisotropy on 3D seismic data. Determining if seismic HTI anisotropy is caused by stress or fractures can be important for mapping and understanding reservoir quality, especially in unconventional reservoirs. Our study area was the Cooper Basin of Australia. The Cooper Basin is Australia’s largest onshore oil and gas producing basin that consists of shale gas, basin-centered tight gas, and deep coal play. The Cooper Basin has unusually high tectonic stress, with most reservoirs in a strike-slip stress regime, but the deepest reservoirs are interpreted to be currently in a reverse-fault stress regime. The seismic data from the Cooper Basin exhibit HTI anisotropy. Our main objective was to determine if the HTI anisotropy was stress induced or fracture induced. We have compared migration velocity anisotropy and amplitude variation with offset anisotropy extracted from a high-quality 3D survey with a “ground truth” of dipole sonic logs, borehole breakout, and fractures interpreted from image logs. We came to the conclusion that the HTI seismic anisotropy in our study area is likely stress induced.

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.

Design and optimisation of multi-stage hydraulic fracturing in a horizontal well in a shale gas reservoir in the Cooper Basin, South Australia

2015 ◽  
Vol 55 (1) ◽  
pp. 1 ◽  
Author(s):  
Kunakorn Pokalai ◽  
Yang Fei ◽  
Maqsood Ahmad ◽  
Manouchehr Haghighi ◽  
Mary Gonzalez
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Horizontal Well ◽  
Productivity Index ◽  
Stress Profile ◽  
Stress Regime ◽  
Vertical Well ◽  
Fracture Simulation ◽  
Multi Stage ◽  
Cooper Basin

Multi-stage hydraulic fracturing in horizontal wells is a well-known technology and is a key mechanism for gas recovery from extremely low permeable shale gas reservoirs. Since Australia’s Cooper Basin has a more complex stress regime and higher temperatures when compared to US shale gas formations, the design and optimisation of this technology in the Cooper Basin has not been explored to the authors’ knowledge. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. Deeper zones are difficult to fracture, as fracture gradients are often above 1 psi/ft. In this study, 1D vertical mechanical earth modelling using petrophysical log data was developed. Then, the stress profile was tuned and validated using the minimum horizontal stress from a mini-frac test taken along a vertical well. A 3D hydraulic fracture simulation in a vertical well as developed as a pilot to select the best locations for horizontal drilling. The selection criteria for the best location included the stress regime, gas flow rate and fracture geometry. Then a multi-stage fracture treatment in a horizontal well was designed. A large number of cases were simulated based on different well lengths, stage spacing and the number of stages. The productivity index was selected as the objective function for the optimisation process. The best case finally was selected as the optimum multi-stage hydraulic fracturing in a horizontal well in the Cooper Basin.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

Emerging continuous gas plays in the Cooper Basin, South Australia

2012 ◽  
Vol 52 (2) ◽  
pp. 671
Author(s):  
Sandra Menpes ◽  
Tony Hill
Keyword(s):  
Shale Gas ◽  
South Australia ◽  
Flood Plain ◽  
Source Rocks ◽  
Early Permian ◽  
Gas Shale ◽  
Freshwater Lakes ◽  
Gas Desorption ◽  
Wet Gas ◽  
Cooper Basin

Recent off-structure drilling in the Nappamerri Trough has confirmed the presence of gas saturation through most of the Permian succession, including the Roseneath and Murteree shales. Basin-centred gas, shale gas and deep CSG plays in the Cooper Basin are now the focus of an escalating drilling and evaluation campaign. The Permian succession in the Nappamerri Trough is up to 1,000 m thick, comprising very thermally mature, gas-prone source rocks with interbedded sands—ideal for the creation of a basin-centred gas accumulation. Excluding the Murteree and Roseneath shales, the succession comprises up to 45% carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. The Early Permian Murteree and Roseneath shales are thick, generally flat lying, and laterally extensive, comprising siltstones and mudstones deposited in large and relatively deep freshwater lakes. Total organic carbon values average 3.9% in the Roseneath Shale and 2.4% in the Murteree Shale. The shales lie in the wet gas window (0.95–1.7% Ro) or dry gas window (>1.7% Ro) over much of the Cooper Basin. Thick Permian coals in the deepest parts of the Patchawarra Trough and over the Moomba high on the margin of the Nappamerri Trough are targets for deep CSG. Gas desorption analysis of a thick Patchawarra coal seam returned excellent total raw gas results averaging 21.2 scc/g (680 scf/ton) across 10 m. Scanning electron microscopy has shown that the coals contain significant microporosity.

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.

Integration of structural, stress, and seismic data to define secondary permeability networks through deep-cemented sediments in the Northern Perth Basin

2012 ◽  
Vol 52 (1) ◽  
pp. 455 ◽  
Author(s):  
Adam Bailey ◽  
Rosalind King ◽  
Guillaume Backé
Keyword(s):  
Fluid Flow ◽  
Seismic Data ◽  
Geothermal Energy ◽  
Fracture Network ◽  
Strike Slip ◽  
Reverse Fault ◽  
3D Seismic ◽  
Natural Fractures ◽  
Stress Regime ◽  
Petroleum Wells

Understanding natural fracture networks has increasingly been recognised as an important factor for the prospectivity of a geothermal play, as they commonly exert a prime control over permeability at depth. The onshore Northern Perth Basin provides a good example of how fracture stimulation, and subsequent enhancement of the structural permeability, during hydrocarbon production can enhance flow rate from original tight gas reservoirs. Low primary porosity and permeability values have been initially recorded in the Northern Perth Basin due to silica-rich groundwater infiltration and consequent quartz cementation. Geothermal energy prospectivity in the region will therefore depend heavily on similar engineering techniques or on the presence of secondary permeability due to interconnected natural fractures. The existence and extent of these natural fractures are verified in this study through an integrated analysis of geophysical logs (including wellbore image logs), wells tests, and 3D seismic data. Wellbore image logs from 11 petroleum wells in the Northern Perth Basin are used to identify borehole failure (such as borehole breakout and drilling-induced tensile fractures) to give a present-day maximum horizontal stress orientation of N076°E (with an s.d. of 13°). Density logs and leak off tests from 13 petroleum wells are used to constrain the present-day stress magnitudes, giving a transitional strike-slip fault to reverse-fault stress regime in the Northern Perth Basin. 870 fractures are identified in image logs from 13 petroleum wells in the Northern Perth Basin, striking roughly north to south and northwest to northeast. Fractures aligned in the present-day stress field are optimally oriented for reactivation, and are hence likely to be open to fluid flow. Electrically resistive and conductive natural fractures are identified on the wellbore image logs. Resistive fractures are considered to be cemented with electrically resistive cement (such as quartz or calcite) and thus closed to fluid-flow. Conductive fractures are considered to be uncemented and open to fluid-flow, and are thus important to geothermal exploration. Fracture susceptibility diagrams constructed for the identified fractures illustrate that the conductive fractures are optimally oriented for reactivation in the present-day strike-slip fault to reverse-fault stress regime, and so are likely to be open to fluid flow. This is reinforced by the correlation of drilling fluid loss and conductive natural fractures in three wells in the Northern Perth Basin. To gain an understanding of the extent and interconnectedness of these fractures, it is necessary to look at more regional data, such as 3D seismic surveys. It is, however, well-documented that fault and fracture networks like those generally observed in image logs lie well below seismic amplitude resolution, making them difficult to observe directly on amplitude data. Seismic attributes can be calculated to provide some information on sub-seismic scale structural and stratigraphic features. Using a 3D seismic cube acquired over the Dongara North gas field, attribute maps of complex multi-trace dip-steered coherency and most positive curvature were used to document the presence of natural fractures and to best constrain the likely extent of the fracture network. The resulting fracture network model displays relatively good connectivity, which is likely to extend across much of the basin. These optimally oriented fractures are therefore likely to form a secondary permeability network throughout the cemented sediments of the Northern Perth Basin, offering potential deep fluid flow conduits, which may be exploited for the production of geothermal energy.

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.

Oil and gas exploration in Australia in 2014—a year of extremes

2015 ◽  
Vol 55 (1) ◽  
pp. 163 ◽  
Author(s):  
Peter Stickland
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Business Environment ◽  
Oil Price ◽  
Gas Flows ◽  
Leading Indicators ◽  
Unconventional Gas ◽  
Oil And Gas Exploration ◽  
Seismic Data Acquisition ◽  
Cooper Basin

In 2014, explorers in Australia experienced a range of highs and lows. There have been discoveries in new play types such as Phoenix South–1 in the Roebuck Basin, offshore WA, as well as discoveries that rejuvenate mature basins such as Seneco–3 in the onshore Perth Basin and a number of wells demonstrating unconventional gas flows in the Cooper Basin. Exploration lows include the inevitable unsuccessful wells, the general low level of drilling activity both offshore and in some states, frustrations at approval delays and constraints—particularly in NSW and Victoria—and the sharply contracting business environment towards the end of 2014 as the oil price rapidly fell to its lowest levels in five years. This PESA review looks in detail at the trends and highlights for oil and gas exploration both onshore and offshore Australia in 2014; not just outcomes with the drill bit, but also leading indicators such as 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.

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