The Ceduna Sub-basin, located in the eastern Bight Basin, is one of the few frontier deepwater provinces in Australia whose hydrocarbon potential remains largely untested. The sediments of the sub-basin span an area of over 95,000 km2—comparable to the combined area of the Exmouth, Barrow and Dampier sub-basins on Australia’s North West Shelf. Prior to 2003, exploration wells had been drilled only on the present day shelf area of the sub-basin. The recent Gnarlyknots–1A well, drilled in May 2003 by the Woodside operated joint venture in EPP29, has provided the first calibration point in the under-explored deepwater area of the sub-basin.The well was the culmination of a basin analysis project that integrated results from prior drilling in adjacent areas, existing seismic surveys, regional gravity and magnetics interpretations, and a newly acquired 16,000 line km 2D seismic survey. Individual play elements of reservoir, seal, and hydrocarbon charge were analysed and combined to form play maps for key stratigraphic intervals. The Gnarlyknots prospect was chosen from more than 40 leads as the best location to test multiple play levels in an area interpreted pre-drill to be favourable for reservoir, seal, and charge.Gnarlyknots–1A confirmed the presence of several favourable play elements but failed to encounter commercial hydrocarbons. Excellent quality sandstone reservoirs, marine shale top seals and thermogenic hydrocarbon shows—indicating the presence of a hydrocarbon source rock in a mature kitchen area downdip—were all encountered in the well. The failure of the well is attributed to the absence of fault seal on the updip bounding fault of the drilled hanging wall structure. The implications of this well result for the prospectivity of the Ceduna Sub-basin have been analysed, and provide encouragement for Woodside to pursue future exploration programs in the region.

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Integration of key information in the early life of the Enfield water-flood development project led to improved understanding of the reservoir's architecture and dynamic behavior. This paper provides an overview of the field and a review of the first two years of production from the Enfield reservoir including start up of the field, water injection optimisation, acquisition and interpretation of Australia's first time lapse '4D' seismic survey, key well and reservoir performance learnings, use of chemical tracer technology to monitor fluid movement, and the benefits of comprehensive real time field data transmission to shore.The Enfield field, discovered in April 1999, is located offshore North West Cape, Western Australia in license WA-28-L. Water depths range from 325m to 550m across the field. Following appraisal drilling and development studies the field was sanctioned for water-flood development in March 2004. The Upper Jurassic Macedon reservoir comprise generally clean, high permeability, unconsolidated sandstone containing a 22° API, moderate viscosity, relatively low GOR oil which is overlain by a significant gas cap. The field has been developed to date via a total of fourteen sub-sea production, water injection and gas re-injection wells producing to a new-build, double hulled FPSO (the 'Nganhurra'). All five production wells, including three high rate horizontal wells, are completed with open-hole gravel packs for sand control. Key challenges during the development execution phase were operating in an extremely environmentally sensitive, cyclone prone deepwater area, in which there was no existing infrastructure or production operations experience.Production commenced on 24 th July 2006 with oil rates peaking at 74,000 bbl/day in September of that year. Initial production rates were constrained by the slower than expected establishment of pressure support from water injectors and then fell to about 43,000 bbl/day in October when a key production well was shut-in due to high levels of sand production. Significantly different water breakthrough and water cut development in two of the production wells coupled with dynamic pressure data and insights from 4D seismic across the field have started to reveal reservoir complexity greater than previously expected, although overall reservoir connectivity appears to be good.During the first two years of production operations the reservoir and facility performance has generally been good and in line with pre-development reservoir models, with the exception of sand control in all three key horizontal production wells, each of which were eventually sidetracked in order to install effective open-hole gravel packs in ~600m horizontal sections.Key successes to date have included the ability to monitor well and facility operating conditions virtually in real time from the Operators onshore offices, the reservoir insights gained from a very early monitor 4D survey, and the organisational integration between the Reservoir Development team and the Production Operations tea...

The Enfield field has a 160 m oil column located between a medium sized gas cap and a water/leg aquifer system. Enfield is undergoing an active water-flood utilizing both up-dip and down-dip water injection. The water-flood reservoir management of such a field requires timely information concerning reservoir pressures, water-flood sweep and movement of gas and water contacts. Conventional reservoir monitoring practice obtains this information by monitoring at the wellbore. Such approaches require significant time and water-cut development to determine how the reservoir and water-flood is performing and provide little spatial information as to how the water-flood is affected by faults, preferential pathways and structural variation. 4D seismic methods represent a powerful tool to assist reservoir management. This work describes the planning, implementation of an early 4D program for the Enfield water-flood and history matching process. Pre-development feasibility work indicated that Enfield had rock properties favourable for 4D monitoring as reservoir sands are acoustically soft and identifiable with seismic amplitudes. Post-production, early 4D monitoring has provided unique and timely insight into water movement both within the reservoir and through active fault networks that wellhead data alone would not provide. This work has shown the benefit of 4D in the following areas; tuning of injected water flows to a northern fault/aquifer system, locating new injector producer pairings, improved utilization of geologic and seismic barrier and baffle features into the history matching process and finally showing how the seismic response to up-dip water injection, around a key injector, was more subtle and supported the choice of imbibition relative permeability relationships and trapped gas saturations. Validation of insights was provided by the use of synthetic seismic modeling of simulation results. Introduction The Enfield field is an active water-flood project located in production permit WA-28-L, some 40km north of Exmouth, offshore Western Australia and is jointly owned by Woodside Energy Ltd (60%, Operator) and Mitsui Australia E&P Ltd (40%). Water depth across the field varies from approximately 325m in the east to 550m in the west. The Enfield oil reservoirs are within the Upper Jurassic to Lower Cretaceous age Macedon Member, comprising generally clean, high permeability, unconsolidated sandstones contained within the crest of a north-easterly plunging fault bounded terrace that covers approximately 16 km2 with a total relief of 350 m. The Enfield trap was created by cross fault juxtaposition of the relatively thin sandstone intervals encased in a thick marine shale sequence. The trap is characterised by structurally conformable high seismic amplitudes associated with the hydrocarbon-bearing reservoir interval. Enfield is highly faulted with a gentle structural dip of 3°.