Abstract
The North Sea Block 16/7a West Brae and 16/6a Sedgwick fields were discovered in 1975 and 1985 respectively. The developments languished for several years because of limited reserves, unconsolidated sands, and slightly heavy (22 deg API) oil. Advances in horizontal drilling techniques, mud systems, sand control, and subsea completion technology, revived the potential of an economic development during 1996. Infrastructure synergies and utilisation of an experienced core team of six Marathon engineers and one geologist, helped minimise development costs of this subsea tieback to the existing Brae Alpha platform.
This paper intends to record the considerations for effective and economic engineering of sand control requirements for the West Brae/Sedgwick wells. Horizontal wells were selected as the best solution to delay coning of water or gas, thereby maximising oil drainage. The goal of the production well design was simply to maximise recovery of hydrocarbons by minimising formation drawdown and sand production. To achieve this goal, emphasis was placed on proper engineering and testing of drill-in fluids and sand screens. The upper completion components were selected based on reliability and ease of installation to minimise costly rig time. Similar engineering emphasis was placed on the injection well design to ensure completion longevity and long term pressure support.
Thus far, the implemented completion strategies appear to have met the West Brae/Sedgwick sand control objectives. The designed drill-in fluid system cleaned up quickly and efficiently without the requirement for potential formation or screen damaging breakers. No evidence of sand production was found during clean-up to the rig, or during 16 months production.
Furthermore, results of a wireline conveyed production spinner log demonstrated flow contribution along the entire horizontal length of the first West Brae completion, thus increasing the likelihood of proper drainage. Four wells are currently producing to the host platform at a combined liquid rate of 40,000 bpd. Water encroachment has lagged model projections and productivity has exceeded expectations. A single injection well is providing pressure support to the Balder reservoir in both the West Brae and Sedgwick fields. Finally, total development costs for this project have been recovered within 16 months despite a depressed oil product price.
