Abstract

Barium sulphate scale is a major problem in the BP Magnus field, even at low water cuts (<1%). In the late 1990's BP Magnus adopted a policy of performing pre-emptive scale squeeze treatments on newly completed wells to prevent scale deposition and maintain well productivity on water breakthrough.

Squeezing dry and low water cut wells with aqueous inhibitor treatments can cause formation damage and result in changes in near well bore wettability. At this time, core flood studies carried out with conventional aqueous based inhibitor treatments indicated that it was possible to safely deploy these treatments in BP Magnus core material. A successful field trial was performed in 1998 since when it has been standard practice on the BP Magnus asset to pre-emptively treat dry and low water cut wells with aqueous inhibitor treatment packages.

Over the last few years a range of non-aqueous treatments technologies have been developed including oil miscible, emulsion and truly oil soluble scale inhibitors. Laboratory core flood studies have therefore been performed with these technologies, as they were developed to compare and contrast their performance to the use of aqueous based scale inhibitors.

This paper will detail a comparison of the core flood studies with both non-aqueous and aqueous based inhibitor treatments and will highlight that it is not always necessary to perform non-aqueous based treatments in dry and low water cut wells. An economic comparison of non-aqueous and aqueous based inhibitor treatments will be presented and, in addition, the paper will present the field experience gained to date with aqueous pre-emptive squeeze treatments in the BP Magnus field and outline the future scale management strategy for treating multi-lateral wells.

Introduction

The Magnus field, discovered by BP in 1974, lies approximately 160km north east of the Shetland Islands in blocks 211/7a and 211/12a of the UK sector of the North Sea. The Magnus oilfield, which is the most northerly field in the UKCS, began production in August 1983 and a peak annual average production rate of 144,301 stb/day was achieved in 1994.

Reservoir Description

The Magnus field is produced from three intervals, the Lower Kimmeridge Clay Formation (LKCF) which is overlain by the Magnus Sandstone Member (MSM) and the Turonian Reworked Sandstone. Initially, the producing interval was estimated to contain 1,650 mmstb of oil, of which up to 77% was contained within the MSM and this zone is currently the main producing interval. The MSM formation is well defined with discrete sandstone zones separated by shale mudstone units that are 1–20m thick and act as vertical permeability barriers. The permeability of the MSM is approximately 200–500mD with an average porosity of 21% and a maximum net pay zone of 108m. The MSM and LKCF sands have low compressive strengths and there is a tendency for sand production, which is particularly associated with high water cuts1.

Both the MSM and LKCF intervals are typically late Jurassic submarine fan sandstones. The sandstones are fine to medium grained that grade to fine and coarse grained conglomerate material. The grainstones are subrounded to angular, sub-arkosic with a low detrital clay content. Monocrystalline quartz is the major detrital constituent. Potassium feldspar, polycrystalline quartz, rock fragments, mica and glauconite are also important detrital components.

This content is only available via PDF.
You can access this article if you purchase or spend a download.