Early Reservoir Management Insights from the Enfield Oil Development, Offshore Western Australia

Hamp, R.; Bada, Inyau Anak; Mee, Benjamin; Dunggan, Tim

doi:10.2118/116915-ms

Cited by 5 publications

(2 citation statements)

References 2 publications

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“…Hurren et al (2012) described how inter-well tracers were used in the Stybarrow Field to characterise producer-injector pair connectivity and transit times. A similar application is described by Hamp et al (2008) in Enfield. Napalowski et al (2012) demonstrated the use of inflow tracers in several key wells in Pyrenees for surety in wellbore cleanup completion (oil soluble tracer) and timing and location of water breakthrough (water soluble tracer) in horizontal production wells.…”

Section: Tracersmentioning

confidence: 92%

Technologies that have transformed the Exmouth into Australia

et al. 2015

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The oil and gas fields of the Exmouth Sub-basin, offshore WA, have presented a number of significant challenges to their exploitation since the first discoveries of heavy oil and lean gas were made in the late 1980s and early 1990s. Presently, some 20 oil and gas fields have been discovered in a variety of Late Jurassic to Cretaceous clastic reservoirs from slope turbidites to deltaic sands. Discovered oils are typically heavily biodegraded with densities ranging from 14–23° API and moderate viscosity. Seismic imaging is challenging across some areas due to pervasive multiples and gas escape features, while in other areas resolution is excellent. Most reservoirs are poorly cemented to unconsolidated and thus require sand control. Modest oil columns, most with gas caps, and variable permeability, present challenges for both maximising oil recovery and minimising the influx of water and gas. Oil-water emulsions also present difficulties for both maximising oil rate and metering production. To date, more than 300 MMbbls have been produced from five developments (Enfield, Stybarrow, Vincent, Van Gogh and Pyrenees), and in 2013 the Macedon gasfield began production. This peer-reviewed paper focuses on the variety of technologies—geoscience, reservoir, drilling and production—that have underpinned the development of these challenging fields and in doing so, transformed the Exmouth into Australia’s premier oil producing basin.

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Section: Tracersmentioning

confidence: 92%

Technologies that have transformed the Exmouth into Australia

et al. 2015

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“…Produced gas is compressed and injected into the gas cap, excluding fuel gas for power generation. (Ali et al 2008, Hamp et al 2008 …”

Section: Spe 127394mentioning

confidence: 99%

The Evolution of Sand Control Completion Practices for the Enfield Deep Water Development

McCarthy

Mickelburgh

2010

SPE International Symposium and Exhibition on Formation Damage Control

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The Enfield development was the first oil field to be put into production in the Greater Enfield Area. These fields lie in deep water off the North West Cape area of Western Australia. Operated by Woodside on behalf of the Enfield Joint Venture, this was the first oil field development for Woodside requiring horizontal open hole completions with sand control. The challenge for this project was to deliver early oil production from a low well count with wells producing from an unconsolidated and faulted formation containing shale. The remote location posed an additional challenge for the development. SPE 127394A key feature of Enfield is the presence of faults in the reservoir that act as flow barriers during production and injection. Due to lack of aquifer connectivity, the development concept for Enfield uses a line drive type water injection pattern, with a row of injectors near the oil-water contact and another row of injectors up-dip near the gasoil contact. Seawater is used for water injection, and this has been combined with produced water after breakthrough in the oil producers. Produced gas is compressed and injected into the gas cap, excluding fuel gas for power generation. (Ali et al. 2008, Hamp et al 2008 Geology and Formation DescriptionAt Enfield, the Macedon sandstone can be divided into upper and lower reservoir units, based on seismic architecture and sedimentology. The upper unit, which extends across the field and varies in thickness between 10 to 20 m, is characterised by very friable, fine to medium grained sandstones. They are generally massive, clean and homogeneous with rare bedding features and occasional shale intra-beds. The lower unit is more confined and can be up to 50 m thick consisting of stacked packages of very fine to fine grained relatively clean sandstones. They have more internal sedimentary structures (e.g. laminations and cross-bedding) with shale interbeds locally preserved between the cleaning-upward packages.The sandstones are interpreted to have been deposited from a series of high-density, rapidly deposited, sandy turbidity currents (submarine sand avalanches), initially infilling the existing seabed topography before becoming more unconfined and expanding areally. The intra-reservoir shale beds represent background deposition between the turbidite flows.

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Shaly sand rock physics analysis and seismic inversion implication

Widyantoro¹,

Saul

2014

The APPEA Journal

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The analysis of well data from the Enfield field of the Exmouth Sub-basin, WA, indicates that both cementation and pore-filling clay appear to have a stiffening effect on the reservoir sands. The elastic contrast between brine sand and the overlying shale is often small and the large amplitudes observed from seismic data are associated with hydrocarbon content. More detailed rock physics and depth trend analysis of elastic and petrophysical properties, however, indicate significant spatial variability in the cap rock shales across the field with different sand shale mixtures, causing changes in the elastic response of the rock. Areas where shales are softer produce weak seismic amplitude contrasts even with high hydrocarbon saturation; the amplitude response being similar to areas with stiffer shales and brine-filled sands. The variations in reservoir quality are, therefore, masked by the distribution of the brine, oil and gas, as well as the variations in the cap rock. The Enfield rock physics analysis provides an example of reducing amplitude ambiguity over lithology-fluid variation and improves the chance of successful interpretation of the results of seismic inversion.

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Early Reservoir Management Insights from the Enfield Oil Development, Offshore Western Australia

Cited by 5 publications

References 2 publications

Technologies that have transformed the Exmouth into Australia

Technologies that have transformed the Exmouth into Australia

The Evolution of Sand Control Completion Practices for the Enfield Deep Water Development

Shaly sand rock physics analysis and seismic inversion implication

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