RIASSUNTO
Abstract
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 24th 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.
Introduction
The Enfield oil field was the first offshore hydrocarbon field to be developed within the Exmouth Sub-Basin, offshore North West Cape, Western Australia (Fig. 1). As such, the project had to face a number of additional uncertainties and challenges during start up and early field life compared to greenfield projects in established producing areas offshore Australia. The field itself, which takes its name from the classic British Royal Enfield ‘Bullet' motorbike, is located in production permit WA-28-L, some 38km north of North West Cape and 50km north of Exmouth, offshore Western Australia. The field is jointly owned by Woodside Energy Ltd (60%, Operator) and Mitsui E&P Australia Pty. Ltd. (40%). Water depth across the field varies from approximately 325m in the east, where the production facility is located, to 550m in the west, with the area being subject to strong and variable marine currents.