Controls on Porosity and Permeability Distribution in the Southern Cooper Basin, Australia: Implications for Petroleum Exploration

SCHULZ-ROJAHN, J. P., and W. J. STUART, NCPGG, University of Adelaide, Adelaide, Australia

The Cooper basin, containing fluvio-lacustrine sediments of Permo-Triassic age, is one of Australia's major onshore hydrocarbon provinces, with sales gas reserves of about 6 tcf and gas-liquids and oil reserves of 310 MMSTB. It is characterized by dominantly low-porosity, low-permeability reservoir sandstones occurring at burial depths between about 1.8 to 3.6 km subsea. Average core porosity is 10.7% and permeability is 30 md. However, over 75% of sandstones have permeabilities less than 5 md.

An early phase of silicification has mainly suppressed mechanical compaction in moderate to well-sorted sandstones of point bar origin. These reservoirs are prominent on major mid-flank structures and marginal areas of the basin. Toward the interior of the basin, microporosity associated with kaolin clays becomes predominant, accounting for the generally poor quality reservoir characteristics of most Cooper basin sandstones. Significantly, two of the largest gas fields in the basin, Moomba and Big Lake, produce from reservoirs dominated by microporosity.

Log-derived porosity estimates may overestimate effective porosity in sandstones containing kaolin minerals. Microporosity is likely to hold relatively large irreducible water, affecting hydrocarbon reserve calculations.

The spatial distribution of core porosity and permeability is variable across the basin. Whereas porosity gradually decreases with depth from about a 14% average at 1.8 km to 6% at 3 km, the decline in mean permeability is more rapid from 184 md at 1.8 km to 8 md at 2.4 km. The permeability relationship can be attributed to grain packing and orientation, differential cementation, and sedimentary facies. However, sandstones of good reservoir quality still occur within low-permeability sequences, offering deep targets for petroleum exploration.

The study is based on diagenetic investigation of 887 core and ditch samples from 82 wells located throughout the southern Cooper basin. A variety of tools was used, including optical petrography, X-ray diffraction, scanning electron microscopy, and cathodoluminescence. The results were integrated with an excess of 6000 porosity and permeability values derived from 148 field and wildcat wells.

AAPG Search and Discovery Article #91004 © 1991 AAPG Annual Convention Dallas, Texas, April 7-10, 1991 (2009)