Integration of DST Flow Results with Sedimentary and Diagenetic Studies, Cooper Basin, Australia

Abstract

Petroleum reserves in the Permian-Triassic Cooper basin of central Australia are reservoired in fluvial channel and crevasse splay sandstones, as well as distributary delta mouthbar/shoreline deposits. The reservoir intervals are buried to depths between 1.8 and 3.6 km, and contain about 6 tcf of sales gas. Gas flow rates determined from drill-stem tests are highly variable, ranging from rates too small to measure of 13 MMCFD. Diagenetic investigation of over 800 core and ditch samples shows that remnant primary porosity is the key control in determining these flow rates. However, microporosity associated chiefly with kaolin stores much of the gas and contributes to long-term production in many petroleum fields. Microporosity is the dominant porosity type in the cooper basin where almost 75% of reservoir rocks have permeabilities of 5 md or less. Preservation of primary porosity was made possible by a lack of detrital clay in the lower to midpoint bar sections where early reservoir silicification helped to resist the effects of compaction. Primary porosity is also prominent in delta mouthbar/shoreline deposits of proximal nature where extensive winnowing resulted in high-textural and compositional sediment maturity. With increasing depth, the overall proportion of Cooper basin rocks dominated by microporosity increases. Advancedmore » reservoir cementation, mechanical and chemical compaction, clay authigenesis, and broad downbasin facies changes from fluviatile to [open quotes]lake[close quotes] environments all combine to decrease average core porosity and permeability. Locally, however, high-permeability intervals interfinger with microporous zones to depths approaching 3 km. Two of the largest gas fields in the Cooper basin, Moomba and Big Lake, produce from reservoir zones, where much of the total porosity is microporosity. These findings underscore the importance of deep-basin gas exploration.« less