The Pluto gas field, North West Shelf of Australia, was discovered in April 2005. It is located in production licence area WA-34-L some 190 km northwest of Karratha, and is situated beneath the continental slope in water depths of 400–1,000 m. The seabed topography initially hindered the recognition of this field. The presence of large seabed channels and steep dips in the overburden, together with the variable water depth, result in seismic ray-bending effects which reduce the quality of imaging and attenuate amplitudes over the southern and eastern parts of the field. Consequently the depth conversion of seismic data over the Pluto structure has been a key uncertainty for the field definition. Structurally, the trap is a tilted fault block, bounded on the west and north by major bounding faults, and sealed by overlying regionally extensive shales. The Triassic reservoir sequence dips gently to the east, and subcrops against the regional Jurassic Unconformity. Pluto–1 encountered a gross gas column of around 209 m in Triassic sands of the Mungaroo Formation and Tithonian sands, sealed by Cretaceous shales of the Forestier and Muderong formations. Petrophysical analyses of the conventional wireline dataset confirmed an average net porosity of 28% and average gas saturation of 93% for the Mungaroo Formation (Lower E Unit). Production tests proved the high deliverability of the Mungaroo E Unit (46.5 MMscf/d) but showed the Tithonian section to be of poor deliverability (9.5 MMscf/d with possible in-wellbore leakage from the deeper Mungaroo DST). Since the discovery, five appraisal wells (excluding sidetracks) have been drilled to delineate the accumulation, and to target areas of higher quality sand development for optimisation of development well locations. In addition, the Pluto 3D data has been twice processed to a pre-stack depth migration—once, immediately following the Pluto–1 discovery to aid in the appraisal campaign and then again following final investment decision (FID) to take advantage of new and improved techniques for seismic processing which has led to increased confidence in the proposed development well locations. The Xena gas field, a satellite field adjacent to Pluto, was discovered by Xena-1ST1 in September 2006. Since then a further two appraisal wells have been drilled to delineate the structure and define the accumulation. The Triassic reservoir section has been extensively cored, logged and analysed in detail for reservoir characterisation and correlation. The reservoir is composed of thickly developed, amalgamated fluvial multi-valley sandstones of the Mungaroo Formation, and coastal plain sediments (tidal bars and channels, estuarine beach deposits) of the more tidally influenced Brigadier Formation.

The design and application of a chemical EOR pilot for a complex, low-permeability waterflood will be presented. Our focus has been on developing appropriate field application options, allowing flexibility of operation against a background of reservoir complexity and uncertainty. Australia’s Barrow Island Windalia reservoir, the nation’s largest onshore waterflood, was developed in the late 1960s. Cumulative oil production to date is over 288 MMSTBO. Planning a chemical EOR scheme needs to address the following reservoir and production characteristics: highly heterogeneous, very fine grained, bioturbated argillaceous sandstone, high in glauconite; high porosity (0.28) but low permeability (5 mD with 20 mD+ streaks); production and injection necessarily stimulated by induced fractures highly saline and hard brine; and, large waterflood pattern volumes (10 MMbbl at 20 acre well spacing). Initial screening recommended that polymers be considered for sweep improvement and conformance control, although reservoir complexity presented a challenge. In this paper, we summarise the subsurface studies, and subsequent petroleum engineering and facilities design, which lead to the successful pilot start-up in May 2009. In particular, we discuss the implications on design and operation of a pilot in a Class A nature reserve. Results from the proposed polymer pilot flood will allow assessment of further chemical EOR applications and potential field-wide scale-up.

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Australia’s Barrow Island Windalia reservoir—the nation’s largest onshore waterflood—was developed in the late 1960s. The Barrow Island oilfield is Chevron Australia’s only mature waterflood, comprising more than 220 active injectors. The injectors pressurise and increase oil recovery from the geologically complex, low-permeable and heterogeneous Windalia Sand Member. To date it is estimated that the value of waterflooding has effectively reduced the field decline rate from approximately 18 % per annum to less than 2 %—adding millions of barrels in recovery and years on to productive field life. In September of 2008, the Windalia Waterflood achieved full field restitution. This involved the replacement and commissioning of glass-reinforced epoxy injection flow lines, a ring-main network and produced water re-injection facilities. Significant challenges were overcome in the process of realising the restitution’s full potential. Several waterflood optimisation activities have now been executed to achieve oil uplift and to capitalise on Chevron Australia’s investment. Compounded with restitution, the activities have successfully achieved the asset objective of arresting field production decline. This paper highlights the challenges encountered by the waterflood team, providing insights and lessons learned in the dynamic and holistic nature of waterflood management. It also highlights the interplay of considerations and what is crucial to achieving optimum sweep efficiency and pressurisation.

Barrow Island’s Windalia reservoir is Australia’s largest onshore waterflooding operation, developed in 1965 with waterflooding starting in 1967. The Windalia reservoir is highly heterogeneous and geologically complex, showing low permeabilities and extensive fault networks. Presently, injection rates are constrained by water availability because of aging source water facilities and increased injector failures because of high integrity risks, highlighting the importance of optimised distribution of injection volumes. Static allocation of injection water has historically been conducted on a pattern basis. This approach, however, is not grounded on the relationships between injection and production wells; instead, it honours the geometric layout of the wells. A more dynamic approach was required to account for the changes in status of injectors and water availability that are often encountered in mature waterflood systems. The successful completion of the Windalia capacitance-resistance model (CRM) was leveraged to develop a comprehensive ranking system of all capable injectors, quantifying short-term normalised oil response to maximise the oil production achieved for a given volume of water injected. Improved understanding of injector-producer communication has also provided the ability to extract the maximum value from limited injection water volumes and has the potential to reduce water cycling and the associated water-handling costs. It can also improve the ability to identify and prioritise workover and stimulation opportunities. This work describes the advances in reservoir management capabilities by quantifying the relationships between injector-producer pairs and the dynamic allocation of injection volumes.