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Origin, Evaluation And Controls Of Permian Reservoir Sandstones In The Southern Cooper Basin, South Australia

Schulz-Rojahn, J.R.

Doctor of Philosophy, 1991

University of Adelaide


The Cooper Basin, containing Permo-Triassic sediments of fluvio-lacustrine and deltaic origin, is characterised by dominantly low-porosity, low-permeability reservoir sandstones for oil and gas occurring at burial depths between about 5400 and 12,000 feet subsea. Ambient core porosity averages 10.7% and permeability 30md, with over 75% of sandstones having permeabilities less than 5md. Despite its overall poor reservoir characteristics, the basin is one of Australia?s major hydrocarbon provinces; ultimate sales gas reserves amount to about 6 TCF, and gas-liquids and oil reserves approach 310 MMSTB.

The objective of this thesis was to define the interaction of factors influencing reservoir quality in Permian sandstones of the southern Cooper Basin. A total of 887 core and ditch samples from 82 field and wildcat wells were investigated, including the Wancoocha, Daralingie, Toolachee, Strzelecki, Munkarie, Big Lake and Moomba Fields. In all, almost 900 feet of core were logged. The samples collected were studied using an array of different techniques such as optical petrography, X-ray diffraction, scanning electron microscopy, cathodoluminescence and oxygen/carbon isotope geochemistry. The results were integrated with over 7000 porosity and permeability values derived from 148 petroleum wells, as well as DST and production test data.

Diagenetic factors, sedimentary facies and basin architecture all influence reservoir quality. Principal cementing agents include authigenic quartz and various carbonate minerals, mostly siderite but also ankerite, dolomite and calcite. Authigenic clay minerals include illite, kaolinite, dickite, clinochlore and pyrophyllite.

Petrographic evidence enabled establishment of the diagenetic sequence for the authigenic minerals relative to the timing of hydrocarbon generation and migration in the study area. The results suggest the precipitation of several authigenic mineral phases occurred synchronous with, or postdating hydrocarbon migration. Mineral authigenesis involved both grain replacement and precipitation from migrating pore fluids. Pyrophyllitc is considered to have formed under conditions of low-grade metamorphism in the central Nappamerri Trough (Rv max. >5 %).

An early phase of silicification provided a rigid grain framework which mainly suppressed mechanical compaction in numerous moderate to well-sorted sandstones of point bar and crevasse splay origin. These sandstones represent the most common hydrocarbon reservoirs in the southern Cooper Basin, and despite multiple phases of silicification retain the highest average porosity and permeability. Effective primary intergranular porosity was retained in such reservoir facies particularly in marginal and midflank areas of the basin, but also in more basinal areas to depths approaching 10,000 feet. Other attractive targets for petroleum exploration include distributary delta mouthbar and shoreline sands. Where secondary dissolution pores occur in conjunction with primary pores, effective permeability is enhanced. Sandstones with abundant macroporosity can produce at initial flow rates in excess of 11 MMCFD.

With increasing depth of burial, there is a broad transition towards reservoirs dominated by microporosity associated with kaolin clays. Microporous rocks are characterised by core porosities as high as about 15% but permeabilities of typically 2md or less. Significantly, microporosity in sandstones of the Moomba and Big Lake Fields accounts for much of the total porosity in reservoirs which have produced more than a trillion cubic feet of gas. Where there are remnants of primary pores in microporous zones, DST flow rates of 2 MMCFD and more are recorded. Undoubtedly, the drilling of deeper targets has the potential to yield large commercial hydrocarbon discoveries in the study area. It is suggested that high-quality reservoir facies occur within low-permeability sequences.

Irreducible water associated with kaolin clays likely affects hydrocarbon reserve calculations. Pessimistic computation of Sw due to bound water of irreducible nature may lead to productive zones being by-passed because they appear water-wet.

Isotope results provide constraints on the modes of formation of carbonate cements in the study area. Likely carbon sources include atmospheric CO2, thermal decarboxylation reactions, and bacterial fermentation reactions and/or methanogenesis. Siderite precipitation occurred throughout the Permian and may have continued into the Late Cretaceous.

Massive carbonate-cemented zones may serve as a guide to commercial hydrocarbon accumulations in the Eromanga Basin overlying the Cooper Basin. The formation of intensely carbonate-cemented zones in the Eromanga Basin is believed to be controlled by the injection of Cooper Basin carbon dioxide into the calcium-bearing Eromanga aquifers. The zones of intense carbonate cementation are considered to reflect the preferred migration pathways of the carbon dioxide and hence also the hydrocarbons. The delineation of such zones in the subsurface using seismic sections and wireline logs may prove to be an invaluable new exploration tool. The origin of the carbon dioxide is poorly understood but is believed to be at least partly related to thermal maturation reactions involving organic matter.

Australian School of Petroleum



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