The Moomba and Big Lake Gas Field area has been actively explored for 25 years. However, recent drilling and field studies have identified new reservoir objectives for appraisal of established fields and for exploration in wildcat areas. Cooper Basin reserves have been increased and further additions are likely. Integration of drilling, production and pressure data for the Moomba and Big Lake Fields has resulted in the discovery of a structural-stratigraphic trap on the south-west flank of the Moomba Dome. Moomba-65 flowed gas at 9.8 MMCFD (0.27 Mm3/d) from deltaic sandstone of the Epsilon Formation (Early Permian). Similar plays are likely to be found on the flanks of other Cooper Basin fields and will become increasingly important as opportunities for conventional crestal tests of anticlines diminish.Exploration to the south-west of the Moomba Field has established the first significant gas flows from rocks beneath the conventional reservoirs of the Cooper Basin. Lycosa-1 drilled a faulted anticline and achieved a maximum gas flow of 5.0 MMCFD (0.14 Mm3/d) from fractured metasiltstone of the Dullingari Group (Ordovician). Moo- lalla-1 drilled a low-side fault terrace and flowed gas at 9.6 MMCFD (0.27 Mm3/d) from 'protoquartzite' tentatively assigned to the Dullingari Group. Consequently, structures where 'basement' reservoirs are faulted against mature Patchawarra Formation source rocks are attractive exploration targets.Petrological studies have identified 'glauconitic illite' in the Cooper Basin sequence suggesting hitherto unrecognised marine conditions. A reassessment of the source and reservoir potential of the region will be necessary if the presence of marine environments is substantiated by further studies.

Geochemical analysis, petrographic examination and wireline log interpretation have identified intervals within the lower Eumeralla Formation of the Otway Group (Early Cretaceous) with good source potential. The sequence has a maximum penetrated thickness of 260 m and consists of thinly interbedded coal and siltstone deposited in peat swamp and lacustrine environments. Vitrinite is the dominant maceral present in the coal although the proportion of more oil-prone liptinite commonly exceeds 10 per cent. This is consistent with the intermediate Type II/ III kerogen composition indicated by Rock-Eval and is comparable with data from proven terrestrial oil-productive source rocks in the Gippsland and Cooper Basins. The siltstone is organically-lean but has some algal input. Algal-rich lacustrine source rocks could be developed nearer the basin centre.Regional stratigraphic, structural and thermal modelling studies highlight the exploration potential of the Chama Terrace in the northwest Otway Basin. Structures on the terrace are ideally situated to receive a hydrocarbon charge from mature Eumeralla Formation source rocks in fault blocks on the downthrown side of the Tartwaup Hingeline.Seismic mapping of offshore permit EPP 24, and adjacent onshore permit PEL 40, has delineated several large fault blocks where Crayfish Subgroup (Otway Group) reservoir is juxtaposed against, and sealed by, the lower Eumeralla Formation sequence. Drilling scheduled for late 1992 will determine the credibility of the Eumeralla-sourced play and provide a key test of the ultimate hydrocarbon potential of the Otway Basin.

The methylphenanthrene index (MPI) molecular maturity parameter is available for over 100 Cooper and Eromanga Basin oils. Oil maturity data define the threshold and range of expulsion maturity for source rocks and can be used to determine oil-source affinity. Mapping of this maturity range for all potential source rocks identifies areas of greatest oil potential.Cooper and Eromanga oils were expelled over a wide maturity range commencing at 0.6 per cent calculated vitrinite reflectance equivalent in some parts of the basin. Oil occurrence and expulsion maturity are controlled by variations in source quality such that no single expulsion threshold can be applied basin-wide. The full oil potential of the basin will only be realised by selective drilling of prospects with access to source rocks in the 0.60-0.95 per cent vitrinite reflectance range.The timing of oil expulsion is determined by using oil maturity data to calibrate thermal modelling of basin depocentres. Peak expulsion occurred during the Cretaceous and therefore prospects with pre-Tertiary structural growth are favoured.Structural embayments with thick Permian section at the southern margin of the Cooper Basin, plus the flanks of the Patchawarra and Nappamerri troughs, are highly prospective in terms of oil source potential and will be further evaluated by drilling in 1990.

The Waitsia Field represents a new commercial play for the onshore north Perth Basin with potential to deliver substantial reserves and production to the domestic gas market. The discovery was made in 2014 by deepening of the Senecio–3 appraisal well to evaluate secondary reservoir targets. The well successfully delineated the extent of the primary target in the Upper Permian Dongara and Wagina sandstones of the Senecio gas field but also encountered a combination of good-quality and tight gas pay in the underlying Lower Permian Kingia and High Cliff sandstones. The drilling of the Waitsia–1 and Waitsia–2 wells in 2015, and testing of Senecio-3 and Waitsia-1, confirmed the discovery of a large gas field with excellent flow characteristics. Wireline log and pressure data define a gross gas column in excess of 350 m trapped within a low-side fault closure that extends across 50 km2. The occurrence of good-quality reservoir in the depth interval 3,000–3,800 m is diagenetically controlled with clay rims inhibiting quartz cementation and preserving excellent primary porosity. Development planning for Waitsia has commenced with the likelihood of an early production start-up utilising existing wells and gas processing facilities before ramp-up to full-field development. The dry gas will require minimal processing, and access to market is facilitated by the Dampier–Bunbury and Parmelia gas pipelines that pass directly above the field. The Waitsia Field is believed to be the largest conventional Australian onshore discovery for more than 30 years and provides impetus and incentive for continued exploration in mature and frontier basins. The presence of good-quality reservoir and effective fault seal was unexpected and emphasise the need to consider multiple geological scenarios and to test unorthodox ideas with the drill bit.

The East Spar gas condensate field is located in production licence WA-13-L in the offshore Carnarvon Basin. Production commenced in 1996 with two subsea wells linked to processing facilities on Varanus Island via a multi-phase pipeline. The pressure performance of the field has been significantly different to predevelopment expectations. This prompted a reexamination of the seismic and well data to investigate the potential for alternative reservoir models.Integrated stratigraphic and seismic interpretation reveals that the Barrow Group reservoir sands were deposited within an incised valley of limited lateral extent. Sea level fall instigated erosion of a valley that on transgression was filled with successive fluvial, estuarine and marine sediments. Good quality sands are expected to be limited to this valley, the upper part of which can be mapped on seismic. Poor sand development in East Spar–2ST is consistent with its location at the edge of the incised valley.Before development, the primary production mechanism was expected to be a strong bottom water drive comparable with other Barrow Group fields in the Carnarvon Basin. The revised depositional model, however, and the observed decline in reservoir pressure, indicate that connection to this regional aquifer is limited. This implies that water influx will probably be later, and ultimate recovery higher, than previously anticipated.