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Journal articles on the topic 'Geology, Stratigraphic; Geology – South Australia – Cooper Basin'

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Published: 10 December 2022

Last updated: 28 January 2023

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1

Meixner, Tony J., Peter J. Gunn, Rodney K. Boucher, Tony N. Yeates, L. Murray Richardson, and Robert A. Frears. "The nature of the basement to the Cooper Basin region, South Australia." Exploration Geophysics 31, no. 1-2 (March 2000): 24–32. http://dx.doi.org/10.1071/eg00024.

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2

Holgate, Fiona, and Prame Chopra. "Testing Models for Bottom-of-Hole Temperature Recovery, Cooper Basin, South Australia." Exploration Geophysics 36, no. 3 (September 2005): 272–80. http://dx.doi.org/10.1071/eg05272.

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3

Ambrose, G., M. Scardigno, and A. J. Hill. "PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA." APPEA Journal 47, no. 1 (2007): 127. http://dx.doi.org/10.1071/aj06007.

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Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.

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4

van Ruth, Peter, and Richard Hillis. "Estimating Pore Pressure in the Cooper Basin, South Australia: Sonic Log Method in an Uplifted Basin." Exploration Geophysics 31, no. 1-2 (March 2000): 441–47. http://dx.doi.org/10.1071/eg00441.

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5

Williams, B. P. J., E. K. Wild, and R. J. Suttill. "Late Palaeozoic cold-climate aeolianites, southern Cooper Basin, South Australia." Geological Society, London, Special Publications 35, no. 1 (1987): 233–49. http://dx.doi.org/10.1144/gsl.sp.1987.035.01.16.

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6

Griffis, Neil Patrick, Isabel Patricia Montañez, Roland Mundil, Jon Richey, John Isbell, Nick Fedorchuk, Bastien Linol, et al. "Coupled stratigraphic and U-Pb zircon age constraints on the late Paleozoic icehouse-to-greenhouse turnover in south-central Gondwana." Geology 47, no. 12 (October 2, 2019): 1146–50. http://dx.doi.org/10.1130/g46740.1.

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Abstract The demise of the Late Paleozoic Ice Age has been hypothesized as diachronous, occurring first in western South America and progressing eastward across Africa and culminating in Australia over an ∼60 m.y. period, suggesting tectonic forcing mechanisms that operate on time scales of 106 yr or longer. We test this diachronous deglaciation hypothesis for southwestern and south-central Gondwana with new single crystal U-Pb zircon chemical abrasion thermal ionizing mass spectrometry (CA-TIMS) ages from volcaniclastic deposits in the Paraná (Brazil) and Karoo (South Africa) Basins that span the terminal deglaciation through the early postglacial period. Intrabasinal stratigraphic correlations permitted by the new high-resolution radioisotope ages indicate that deglaciation across the S to SE Paraná Basin was synchronous, with glaciation constrained to the Carboniferous. Cross-basin correlation reveals two additional glacial-deglacial cycles in the Karoo Basin after the terminal deglaciation in the Paraná Basin. South African glaciations were penecontemporaneous (within U-Pb age uncertainties) with third-order sequence boundaries (i.e., inferred base-level falls) in the Paraná Basin. Synchroneity between early Permian glacial-deglacial events in southwestern to south-central Gondwana and pCO2 fluctuations suggest a primary CO2 control on ice thresholds. The occurrence of renewed glaciation in the Karoo Basin, after terminal deglaciation in the Paraná Basin, reflects the secondary influences of regional paleogeography, topography, and moisture sources.

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7

Sun, Xiaowen. "Structural Style of the Warburton Basin and Control in the Cooper and Eromanga Basins, South Australia." Exploration Geophysics 28, no. 3 (June 1997): 333–39. http://dx.doi.org/10.1071/eg997333.

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8

Carr, Lidena, Russell Korsch, and Tehani Palu. "Australia's onshore basin inventory: volume I." APPEA Journal 56, no. 2 (2016): 591. http://dx.doi.org/10.1071/aj15097.

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Following the publication of Geoscience Australia Record 2014/09: Petroleum geology inventory of Australia’s offshore frontier basins by Totterdell et al (2014), the onshore petroleum section of Geoscience Australia embarked on a similar project for the onshore Australian basins. Volume I of this publication series contains inventories of the McArthur, South Nicholson, Georgina, Amadeus, Warburton, Wiso, Galilee, and Cooper basins. A comprehensive review of the geology, petroleum systems, exploration status, and data coverage for these eight Australian onshore basins was conducted, based on the results of Geoscience Australia’s precompetitive data programs, industry exploration results, and the geoscience literature. A petroleum prospectivity ranking was assigned to each basin, based on evidence for the existence of an active petroleum system. The availability of data and level of knowledge in each area was reflected in a confidence rating for that ranking. This extended abstract summarises the rankings assigned to each of these eight basins, and describes the type of information available for each of these basins in the publically available report by Carr et al (2016), available on the Geoscience Australia website. The record allocated a high prospectivity rating for the Amadeus and Cooper basins, a moderate rating for the Galilee, McArthur and Georgina basins, and a low rating for the South Nicholson, Warburton and Wiso basins. The record lists how best to access data for each basin, provides an assessment of issues and unanswered questions, and recommends future work directions to lessen the risk of these basins in terms of their petroleum prospectivity. Work is in progress to compile inventories on the next series of onshore basins.

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9

Khaksar, A., and A. B. Mitchell. "An Improvement in Lithology Interpretation from Well Logs in the Patchawarra Formation, Toolachee Field, Cooper Basin, South Australia." Exploration Geophysics 26, no. 2-3 (June 1, 1995): 347–53. http://dx.doi.org/10.1071/eg995347.

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10

Hou, B., N. F. Alley, L. A. Frakes, L. Stoian, and W. M. Cowley. "Eocene stratigraphic succession in the Eucla Basin of South Australia and correlation to major regional sea-level events." Sedimentary Geology 183, no. 3-4 (January 2006): 297–319. http://dx.doi.org/10.1016/j.sedgeo.2005.10.007.

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11

Salmachi, Alireza, Mojtaba Rajabi, Carmine Wainman, Steven Mackie, Peter McCabe, Bronwyn Camac, and Christopher Clarkson. "History, Geology, In Situ Stress Pattern, Gas Content and Permeability of Coal Seam Gas Basins in Australia: A Review." Energies 14, no. 9 (May 5, 2021): 2651. http://dx.doi.org/10.3390/en14092651.

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Coal seam gas (CSG), also known as coalbed methane (CBM), is an important source of gas supply to the liquefied natural gas (LNG) exporting facilities in eastern Australia and to the Australian domestic market. In late 2018, Australia became the largest exporter of LNG in the world. 29% of the country’s LNG nameplate capacity is in three east coast facilities that are supplied primarily by coal seam gas. Six geological basins including Bowen, Sydney, Gunnedah, Surat, Cooper and Gloucester host the majority of CSG resources in Australia. The Bowen and Surat basins contain an estimated 40Tcf of CSG whereas other basins contain relatively minor accumulations. In the Cooper Basin of South Australia, thick and laterally extensive Permian deep coal seams (>2 km) are currently underdeveloped resources. Since 2013, gas production exclusively from deep coal seams has been tested as a single add-on fracture stimulation in vertical well completions across the Cooper Basin. The rates and reserves achieved since 2013 demonstrate a robust statistical distribution (>130 hydraulic fracture stages), the mean of which, is economically viable. The geological characteristics including coal rank, thickness and hydrogeology as well as the present-day stress pattern create favourable conditions for CSG production. Detailed analyses of high-resolution borehole image log data reveal that there are major perturbations in maximum horizontal stress (SHmax) orientation, both spatially and with depth in Australian CSG basins, which is critical in hydraulic fracture stimulation and geomechanical modelling. Within a basin, significant variability in gas content and permeability may be observed with depth. The major reasons for such variabilities are coal rank, sealing capacity of overlying formations, measurement methods, thermal effects of magmatic intrusions, geological structures and stress regime. Field studies in Australia show permeability may enhance throughout depletion in CSG fields and the functional form of permeability versus reservoir pressure is exponential, consistent with observations in North American CSG fields.

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12

Heath, A. M., A. L. Culver, and C. W. Luxton. "Gathering good seismic data from the Otway Basin." Exploration Geophysics 20, no. 2 (1989): 247. http://dx.doi.org/10.1071/eg989247.

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Cultus Petroleum N.L. began exploration in petroleum permit EPP 23 of the offshore Otway Basin in December 1987. The permit was sparsely explored, containing only 2 wells and poor quality seismic data. A regional study was made taking into account the shape of the basin and the characteristics of the major seismic sequences. A prospective trend was recognised, running roughly parallel to the present shelf edge of South Australia. A new seismic survey was orientated over this prospective trend. The parameters were designed to investigate the structural control of the prospects in the basin. To improve productivity during the survey, north-south lines had to be repositioned due to excessive swell noise on the cable. The new line locations were kept in accordance with the structural model. Field displays of the raw 240 channel data gave encouraging results. Processing results showed this survey to be the best quality in the area. An FK filter was designed on the full 240 channel records. Prior to wavelet processing, an instrument dephase was used to remove any influence of the recording system on the phase of the data. Close liaison was kept with the processing centre over the selection of stacking velocities and their relevance to the geological model. DMO was found to greatly improve the resolution of steeply dipping events and is now considered to be part of the standard processing sequence for Otway Basin data. Seismic data of a high enough quality for structural and stratigraphic interpretation can be obtained from this basin.

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Williams, A. F., and D. J. Poynton. "THE GEOLOGY AND EVOLUTION OF THE SOUTH PEPPER HYDROCARBON ACCUMULATION." APPEA Journal 25, no. 1 (1985): 235. http://dx.doi.org/10.1071/aj84020.

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The South Pepper field, discovered in 1982, is located 30 km southwest of Barrow Island in the offshore portion of the Barrow Sub-basin, Western Australia. The oil and gas accumulation occurs in the uppermost sands of the Lower Cretaceous Barrow Group and the overlying low permeability Mardie Greensand Member of the Muderong Shale.The hydrocarbons are trapped in one of several fault closed anticlines which lie on a high trend that includes the North Herald, Pepper and Barrow Island structures. This trend is postulated to have formed during the late Valanginian as the result of differential compaction and drape over a buried submarine fan sequence. During the Turonian the trend acted as a locus for folding induced by right-lateral wrenching along the sub-basin edge. Concurrent normal faulting dissected the fold into a number of smaller anticlines. This essentially compressional tectonic phase contrasted with the earlier extensional regime which was associated with rift development during the Callovian. A compressional tectonic event in the Middle Miocene produced apparent reverse movement on the South Pepper Fault but only minor changes to the structural closure.Geochemical and structural evidence indicates at least two periods of hydrocarbon migration into the top Barrow Group - Mardie Greensand reservoir. The earlier occurred in the Turonian subsequent to the period of wrench tectonics and involved the migration of oil from Lower Jurassic Dingo Claystone source rocks up the South Pepper Fault. This oil was biodegraded before the second episode of migration occurred after the Middle Miocene tectonism. The later oil is believed to have been sourced by the Middle to Upper Jurassic Dingo Claystone. Biodegradation at this stage ceased or became insignificant due to temperature increase and reduction of meteoric water flow. Gas-condensate, sourced from Triassic or Lower Jurassic sediments may have migrated into the structure with this second oil although a more recent migration cannot be ruled out.The proposed structural and hydrocarbon migration history fits regional as well as local geological observations for the Barrow Sub-basin. Further data particularly from older sections of the stratigraphic column within the area are needed to refine the interpretation.

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Guo, Fengtao, Peter McCabe, Zhiqiang Feng, Changwu Wu, Xueyan Lyu, Weilong Peng, and Jinrui Guo. "Core-based sedimentological and sequence stratigraphic analysis of shale-dominated gas plays: An example of the early to middle permian Roseneath-Epsilon-Murteree strata in the Cooper basin, Australia." Marine and Petroleum Geology 129 (July 2021): 105070. http://dx.doi.org/10.1016/j.marpetgeo.2021.105070.

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15

Lukasik, Jeff, and Noel P. James. "Carbonate sedimentation, climate change and stratigraphic completeness on a Miocene cool-water epeiric ramp, Murray Basin, South Australia." Geological Society, London, Special Publications 255, no. 1 (2006): 217–44. http://dx.doi.org/10.1144/gsl.sp.2006.255.01.14.

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16

Stalker, Linda, Dominique Van Gent, Sandeep Sharma, and Martin Burke. "South West Hub Project: appraising a carbon storage resource in Western Australia." APPEA Journal 55, no. 2 (2015): 472. http://dx.doi.org/10.1071/aj14107.

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The South West Hub Carbon Capture and Storage Project (SWH), managed by the WA Department of Mines and Petroleum (WA DMP), is evaluating the potential for a commercial-scale carbon storage site near major emissions sites in southwest WA. The area under investigation is in the southern Perth Basin, focusing on a 150 km2 area in the shires of Harvey and Waroona. WA DMP is conducting a major feasibility study and collecting pre-competitive data in partnership with the local community. The activities are done in a stage-gate model to obtain relevant information on the potential storage capacity, containment security and injectivity of the geology. Following a smaller 2D seismic survey and the drilling of the Harvey–1 stratigraphic well, a more complex 3D seismic survey was undertaken in February to March, 2014. These activities have confirmed the potential for commercial-scale CO2 storage. A new work package has been initiated with the drilling of three wells (Harvey–2, –3 and –4) underway and plans to drill a fifth well in the next 12 months. The stage-gate approach has been cost-effective, resulting in a carefully planned data acquisition and research program. The approach allows new results, information and potential future activities to be rolled out to stakeholders and the community in the area.

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17

Molyneux, S. J., H. F. Wu, S. Delaney, and A. Gongora. "Outcome focused: how to deliver value in a field (re)development. A case study from the Cooper–Eromanga Basin, South Australia." APPEA Journal 60, no. 2 (2020): 491. http://dx.doi.org/10.1071/aj19030.

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The share of global hydrocarbon production from ‘aging’ assets is increasing, whereas global demand for energy continues to increase at 1–2% per year (IEA 2019). In 2018, the International Energy Agency estimated the global average production decline at 4% per annum (Gould and McGlade 2018). Production from many of Australia’s established basins, such as the Cooper–Eromanga basin and the North West Shelf, is dominated by aging assets. To arrest this decline, actions must be taken to meet global demand for oil and gas, sustain production and underpin shareholder expectations of a return on their investment. Arresting field decline is a multifaceted problem. A single fix, whether technological or operational, will not maximise production or asset value. Any project to arrest field decline, grow production or (re)develop a field must be considered in its entirety, as an integrated system, by a multidisciplinary team. In addition, and critical to success, the required outcome must be clearly established and committed to by field owners, consultants and staff assigned to the project. This paper demonstrates how using a committed, outcome-focused approach, an integrated project team identified field redevelopment opportunities that significantly increased estimated ultimate recovery in an aging oilfield (that had already produced more than 70–80% of the developed resource) in the Cooper–Eromanga basin, South Australia. Factors critical to success were: (1) a commitment to look at all aspects of the field, from geology and geophysics, through the completion, well and field performance and operational infrastructure to identify development opportunities; (2) an ability to be agile, cycling quickly through the workflow as new information became available; (3) dedicated resources, clear communication and a commitment to integrated work across consultant and staff resources; and (4) management support.

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18

Wecker, H. R. B. "THE EROMANGA BASIN." APPEA Journal 29, no. 1 (1989): 379. http://dx.doi.org/10.1071/aj88032.

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The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.

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19

Khalifa, M. Kh, and K. J. Mills. "SEISMIC STRATIGRAPHIC ANALYSIS AND STRUCTURAL DEVELOPMENT OF AN INTERPRETED UPPER CAMBRIAN TO MIDDLE ORDOVICIAN SEQUENCE IN THE NW BLANTYRE SUB-BASIN, DARLING BASIN (WESTERN NEW SOUTH WALES, AUSTRALIA)." Journal of Petroleum Geology 37, no. 2 (March 25, 2014): 163–81. http://dx.doi.org/10.1111/jpg.12576.

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20

Abul Khair, H., D. Cooke, and M. Hand. "The effect of present day in situ stresses and paleo-stresses on locating sweet spots in unconventional reservoirs, a case study from Moomba-Big Lake fields, Cooper Basin, South Australia." Journal of Petroleum Exploration and Production Technology 3, no. 4 (September 13, 2013): 207–21. http://dx.doi.org/10.1007/s13202-013-0082-x.

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21

Dunlop, Erik C., David S. Warner, Prue E. R. Warner, and Louis R. Coleshill. "Ultra-deep Permian coal gas reservoirs of the Cooper Basin: insights from new studies." APPEA Journal 57, no. 1 (2017): 218. http://dx.doi.org/10.1071/aj16015.

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There is a vast, untapped gas resource in deep coal seams of the Cooper Basin, where extensive legacy gas infrastructure facilitates efficient access to markets. Proof-of-concept for the 5 million acre (20 000km2) Cooper Basin Deep Coal Gas (CBDCG) Play was demonstrated by Santos Limited in 2007 during the rise of shale gas. Commercial viability on a full-cycle, standalone basis is yet to be proven. If commercial reservoirs in nanoDarcy matrix permeability shale can be manufactured by engineers, why not in deep, dry, low-vitrinite, poorly cleated coal seams having comparable matrix permeability but higher gas content? Apart from gas being stored in a source rock reservoir format, there is little similarity to other unconventional plays. Without an analogue, development of an optimal reservoir stimulation technology must be undertaken from first principles, using deep coal-specific geotechnical and engineering assumptions. Results to date suggest that stimulation techniques for other unconventional reservoirs are unlikely to be transferable. A paradigm shift in extraction technology may be required, comparable to that devised for shale reservoirs. Recent collaborative studies between the South Australian Department of State Development, Geological Survey of Queensland and Geoscience Australia provide new insight into the hydrocarbon generative capacity of Cooper Basin coal seams. Sophisticated regional modelling relies upon a limited coal-specific raw dataset involving ~90 (5%) of the total 1900 wells penetrating Permian coal. Complex environmental overprints affecting resource concentration and gas flow capacity are not considered. Detailed resource estimation and the detection of anomalies such as sweet spots requires the incorporation of direct measurement. To increase granularity, the authors are conducting an independent, basin-wide review of underutilised open file data, not yet used for unconventional reservoir purposes. Reservoir parameters are quantified for seams thicker than 10feet (3m), primarily using mudlogs and electric logs. To date, ~3750 reservoir intersections are characterised in ~1000 wells. Some parameters relate to resource, others to extraction. A gas storage proxy is generated, not compromised by desorption lost gas corrections. A 2016 United States Geological Survey resource assessment, based on Geoscience Australia studies, suggests that the Play remains a world-class opportunity, despite being technology-stranded for the past 10years. Progress has been made in achieving small but incrementally economic flow rates from add-on hydraulic fracture stimulation treatments inside conventional gas fields. Nevertheless, a geology/technology impasse precludes full-cycle, standalone commercial production. A review of open file data and cross-industry literature suggests that the root cause is the inability of current techniques to generate the massive fracture network surface area essential for high gas flow. Coal ductility and high initial reservoir confining stress are interpreted to be responsible. Ultra-deep coal reservoirs, like shale reservoirs, must be artificially created by a large-scale stimulation event. Although coal seams fail the reservoir ‘brittleness test’ for shale reservoir stimulation practices, the authors conclude from recent studies that pervasive, mostly cemented or closed coal fabric planes of weakness may instead be reactivated on a large scale, to create a shale reservoir-like stimulated reservoir volume (SRV), by mechanisms which harness the reservoir stress reduction capacity of desorption-induced coal matrix shrinkage.

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Khaksar, Abbas, and C. M. Griffiths. "Influence of Effective Stress on the Acoustic Velocity and Log-Derived Porosity." SPE Reservoir Evaluation & Engineering 2, no. 01 (February 1, 1999): 69–75. http://dx.doi.org/10.2118/54564-pa.

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Summary Experimental studies indicate that when effective stress increases, compressional wave velocity in porous rocks increases. Reservoir pressure reduction, resulting from hydrocarbon production, increases effective stress. For a rock with a given porosity the sonic log may show decreasing values as the pressure in the reservoir decreases. This in turn may lead to underestimation of the actual porosity of the reservoir rocks in low pressure reservoirs. The range of such underestimation for liquid saturated reservoirs may not be significant, but since the influence of effective stress on velocity increases as fluid saturation changes to gas, porosity underestimation by conventional velocity-porosity transforms for gas bearing rocks may increase. Examples are taken from partially depleted gas reservoirs in the Cooper basin, South Australia. The stress dependent nature of velocity requires that the in situ pressure condition should be considered when the sonic log is used to determine the porosity of gas producing reservoir rocks. Introduction Knowledge of the elastic velocities in porous media is of considerable interest in many research fields including rock mechanics, geological engineering, geophysics, and petroleum exploration. In petroleum exploration this concept mainly concerns the relationship between reservoir rock characters and the acoustic velocity. Porosity estimation is one of the most common applications of acoustic velocity data in hydrocarbon wells. There are numerous empirical equations to convert sonic travel time (ts) to porosity. It is well known that the P-wave velocity (vp), for a rock with a given porosity, is also controlled by several other factors such as pore filling minerals, internal and external pressures, pore geometry, and pore fluid saturation, etc.1 These factors may have significant effect on measured ts and thus on porosity interpretation from the sonic log. Several investigators (see Refs. 2-4) have studied the effect of clay content and the type and saturation of pore fluids on acoustic velocity and the sonic log derived porosity in reservoir rocks. In contrast, the in situ pressure condition has rarely been considered as a parameter in the commonly used velocity-porosity equations. This paper addresses the influence of effective stress on the elastic wave velocities in rocks and its implications on porosity determination from the sonic log in hydrocarbon bearing reservoirs. Examples from the literature and a case study in a gas-producing reservoir are used to highlight the importance of the issue. Effective stress is the arithmetic difference between lithostatic pressure and hydrostatic pressure at a given depth. It may normally be considered equivalent to the difference between confining pressure (pc) and pore pressure (pp).5 Experimental studies indicate that as effective stress increases, vp increases.6 This increase depends on the rock type and pore fluid. The change in vp due to effective stress increase is more pronounced when the pore fluid is gas.7 Current sonic porosity methods do not account for the variation of vp due to pressure change in hydrocarbon producing fields. Effective Stress Versus Velocity Wyllie et al.6 measured ultrasonic P-wave velocity as a function of effective stress in water saturated Berea sandstone. They showed that at constant confining pressures vp increases with decreasing pore pressure, and for constant effective stress, the vp remains constant. Similar relationships between effective stress and P-wave velocity have also been reported by other researchers.7–10 King,9 and Nur and Simmons7 reported a more pronounced stress effect on vp when air replaces water. Experimental results indicate that confining and pore pressures have almost equal but opposite effects on vp. Confining pressure influences the wave velocities because pressure deforms most of the compliant parts of the pore space, such as microcracks and loose grain contacts. Closure of microcracks increases the stiffness of the rock and increases bulk and shear moduli. Increases in pore pressure mechanically oppose the closing of cracks and grain contacts, resulting in low effective moduli and velocities. Hence, when both confining and pore pressures vary, only the difference between the two pressures has a significant influence on velocity8 that is Δ p = p c − p p , ( 1 ) where ?p is differential pressure. The more accurate relationship may be of the form of p e = p c − σ p p , ( 2 ) where pe is effective stress and ? is the effective pressure coefficient. The value of ? varies around unity for different rocks and is a function of pc11 Eq. 2 indicates that for ? values not equal to unity, changes in a physical property caused by changes in confining pressure may not be exactly canceled by equivalent changes in pore pressure. Experimentally derived ? values for the water saturated Berea sandstone by Christensen and Wang10 show values less than 1 for properties that involve significant bulk compression (vp), whereas a pore pressure increment does more than cancel an equivalent change in confining pressure for properties that significantly depend on rigidity (vs).

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WEHR, FREDERICK L., Exxon Productio. "Applications of Sequence Stratigraphy to Permian Coal Measures, Cooper Basin, South Australia." AAPG Bulletin 76 (1992). http://dx.doi.org/10.1306/f4c8f174-1712-11d7-8645000102c1865d.

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APAK, S. N., W. J. STUART, and N. M. "Structural Development and Control on Stratigraphy and Sedimentation in Cooper Basin, Northeastern South Australia and Southwestern Queensland." AAPG Bulletin 76 (1992). http://dx.doi.org/10.1306/f4c8f85e-1712-11d7-8645000102c1865d.

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25

Mohammad R. Rezaee, Peter R. Tingat. "Origin of Quartz Cement in the Tirrawarra Sandstone, Southern Cooper Basin, South Australia." SEPM Journal of Sedimentary Research Vol. 67 (1997). http://dx.doi.org/10.1306/d4268522-2b26-11d7-8648000102c1865d.

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HIBBURT, JACQUE, DAVID GRAVESTOCK,. "Reservoirs in the Cooper Basin Basement, South Australia." AAPG Bulletin 76 (1992). http://dx.doi.org/10.1306/f4c8fb7e-1712-11d7-8645000102c1865d.

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27

Chen, Feiyang, Glenn A. Brock, Marissa J. Betts, Zhiliang Zhang, Hao Yun, Robert Matthew Klaebe, Brittany Laing, and Zhifei Zhang. "Sedimentology and integrated chronostratigraphy of the lower Heatherdale Shale (Cambrian, stages 2–3), Stansbury Basin, South Australia." Geological Magazine, December 11, 2020, 1–13. http://dx.doi.org/10.1017/s0016756820001260.

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Abstract:

Abstract Major progress has recently been made regarding the biostratigraphy, lithostratigraphy and isotope chemostratigraphy of the lower Cambrian successions in South Australia, in particular of the Arrowie Basin, which has facilitated robust global stratigraphic correlations. However, lack of faunal and sedimentological data from the lower Cambrian Normanville Group in the eastern Stansbury Basin, South Australia – particularly the transition from the Fork Tree Limestone to the Heatherdale Shale – has prevented resolution of the age range, lithofacies, depositional environments and regional correlation of this succession. Here we present detailed sedimentologic, biostratigraphic and chemostratigraphic data through this transition in the eastern Stansbury Basin. Three lithofacies are identified that indicate a deepening depositional environment ranging from inner-mid-shelf (Lithofacies A and B) to outer shelf (Lithofacies C). New δ13C chemostratigraphic data capture global positive excursion III within the lower Heatherdale Shale. Recovered bradoriid Sinskolutella cuspidata supports an upper Stage 2 (Micrina etheridgei Zone). The combined geochemistry and palaeontology data reveal that the lower Heatherdale Shale is older than previously appreciated. This integrated study improves regional chronostratigraphic resolution and interbasinal correlation, and better constrains the depositional setting of this important lower Cambrian package from the eastern Stansbury Basin, South Australia.

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M. H. Holtz, D. S. Hamilton, J. S. "Application of Sequence Stratigraphic Concepts to Reservoir Characterization in an Intracratonic Basin Setting: Toolachee Field, Cooper Basin, Australia: ABSTRACT." AAPG Bulletin 79 (1995). http://dx.doi.org/10.1306/7834e944-1721-11d7-8645000102c1865d.

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29

van Ruth, Peter J.1, Richard R. Hil. "ABSTRACT: The Origin of Overpressure in the Nappamerri Trough, Cooper Basin, South Australia." AAPG Bulletin 84 (2000). http://dx.doi.org/10.1306/a967511a-1738-11d7-8645000102c1865d.

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30

J. M. Bever, P. G. Carroll, E. W. W. "Core Facies, Petrology, and Permeability of Tirrawarra Sandstone, Moorari Field, Cooper Basin, South Australia: ABSTRACT." AAPG Bulletin 72 (1988). http://dx.doi.org/10.1306/703c8335-1707-11d7-8645000102c1865d.

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31

Brian P. J. Williams. "Point-Bar Deposits and Analysis of Subsurface Reservoir Dimensions, Toolachee Formation, Southern Cooper Basin, South Australia: ABSTRACT." AAPG Bulletin 69 (1985). http://dx.doi.org/10.1306/ad4624ac-16f7-11d7-8645000102c1865d.

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Horst Zwingmann1, P. Joe Hamilton1,. "ABSTRACT: The Origin and Timing of Illitic Clays in Reservoir Sandstones of the Cooper Basin, South Australia." AAPG Bulletin 85 (2001). http://dx.doi.org/10.1306/61eed602-173e-11d7-8645000102c1865d.

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Mohammad R. Rezaee, Cedric M. Griff. "Pore Geometry Controls on Porosity and Permeability in the Tirrawarra Sandstone Reservoir, Cooper Basin, South Australia: ABSTRACT." AAPG Bulletin 80 (1996). http://dx.doi.org/10.1306/522b39e3-1727-11d7-8645000102c1865d.

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34

Lanzilli, Elio1 (1) Santos Asia Pac. "ABSTRACT: A sequence stratigraphic approach to reservoir characterisation of the Birkhead Formation, Gidgealpa South Dome, Eromanga Basin, Australia." AAPG Bulletin 84 (2000). http://dx.doi.org/10.1306/a96748f0-1738-11d7-8645000102c1865d.

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35

Khalifa, M. Kh, and K. J. Mills. "Predicting sequence stratigraphic architecture and its implication for hydrocarbon reservoir potential of the uppermost Silurian through Lower Devonian Winduck Interval, central Darling Basin of western New South Wales, SE Australia." Marine and Petroleum Geology, May 2022, 105725. http://dx.doi.org/10.1016/j.marpetgeo.2022.105725.

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Shirley P. Dutton, H. Scott Hamlin. "Compositional, Textural, and Diagenetic Controls on Porosity Distribution and Evolution in Permian Tirrawarra Sandstone, Cooper Basin, South Australia: ABSTRACT." AAPG Bulletin 78 (1994). http://dx.doi.org/10.1306/a25ffc33-171b-11d7-8645000102c1865d.

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Scott H. Hamlin, Shirley P. Dutton,. "Resource Optimization through Facies-Based Characterization of a Braid-Delta Sandstone Reservoir, Tirrawarra Oil Field, Cooper Basin, South Australia: ABSTRACT." AAPG Bulletin 78 (1994). http://dx.doi.org/10.1306/a260004d-171b-11d7-8645000102c1865d.

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W. A. Ambrose, D. S. Hamilton, M. H. "Depositlonai Architecture of Lacustrine-Delta and Fluvlal Systems of the Permian EpsiIon and Toolachee Formations at Duilingari Field, Southeastern Cooper Basin, South Australia: ABSTRACT." AAPG Bulletin 80 (1996). http://dx.doi.org/10.1306/64eda2c6-1724-11d7-8645000102c1865d.

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