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

Abstract

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.

A workflow for turbidite reservoir characterization—a case study of the Macedon member, Northern Carnarvon Basin, NW Australia

“…Their complex depositional environment and heterogeneous present significant challenges to their accurate characterization and subsequent development (Mayall and Byrne, 2002;Ruvo et al, 2008). Furthermore, reservoir heterogeneity significantly affects the development of oil reservoirs and drilling strategies (Ementon et al, 2004;McCarthy and Mickelburgh, 2010;Sinan et al, 2020;Mohsin et al, 2023). Previous research has been conducted on the sedimentation of deep-water turbidity, focusing predominantly on the geometric shape of the turbidite channels and the characteristics of sedimentation including the factors that control them (Lutome et al, 2020;Zhao et al, 2022;Peng et al, 2023), and describe planar distribution of turbidite sand bodies (Wu et al, 2022;Lou et al, 2023).…”

The influence of fine particles composition on optimal design of sand control in offshore oilfield

“…There is a lot of research on the blueprint of sand control (Bennett et al 1998;Farrow et al 2004;McCarthy and Mickelburgh 2010;Schwartz 1969;. But the gravel packing is used in concert with other screen in oil field which is fit for the formation of high fine particles content.…”