Control of Scaling in the South Brae Field
Authors: Hardy J.A. , Barthorpe R.T. , Plummer M.A. , Rhudy J.S. 
Published: October 2008

Severe scaling conditions exist in South Brae due to the high barium content of formation water and low pH downhole. Formation water is also susceptible to calium carbonate scaling. This paper presents experiences with control of scale on topsides and downhole during development of the field.

A sulphonate-based inhibitor has been developed and app1ied for downhole control of BaS04. The benefits achieved by the use of d.s sulphated sea water to minimise the BaS04 potential are presented. The methods developed for controlling calcium carbonate scale are described.

INTRODUCTION

The deposition of mineral scale is a common problem in the oil industry, nowhere more so than in the North Sea (1-5). The type of scaling and its severity varies between fields, however, calcium carbonate and barium sulphate scaling are common problems. Calcium carbonate scaling can be problematic irrespective of injection water breakthrough whereas barium sulphate scaling is a problem due to co-production of formation water and incompatible injection water. Because of its insolubility and consequent difficulty in removing, barium sulphate is usually the more troublesome scale and its inhibition more critical. The barium content of most North Sea formation waters is in the range 10–200 mg/1. By comparison the Brae formation water is as high as 2500mg/1, This high barium content in conjunction with sea water injection presents a severe scale problem, compounded by the relatively low downhole pH. As a result, development of the South Brae field has necessitated development of special scale control procedures. Although similar highbarium levels have also been found in other North Sea fields, eg T Block (6), South Brae is the first such North Sea field to be developed. This paper presents an overview of the experience gained of the scale problem and the control measures developed, The South Brae field is located in block 16/7a of the UK sector of the North Sea. The reservoir and its geology has been described recently by Phillips (7). The field has been on production since 1983. Reservoir pressure maintenance and voidage has been achieved by a combination of down dip water injection and crestal gas injection. Injection of filtered sea water commenced in 1984. In 1988 the first phase of a 120,000 bbl capacity facility to reduce sulphate levels in seawater wasinstalled. From 1986 until 1990 the gas used for injection and gas lift purposes had the C02 content reduced from 32-35 mol% to 9-10% by a Selexol processing facility. In 1990 the Selexol plant was decommissioned and produced gas with a typical C02 content of 22 mol% has been used. Fluids are processed through twin, three-stage separation trains, each train having separate high pressure and medium pressure manifolds. Water is separated at the MP and LP separation stages. It is degassed and treated via flotation units prior to discharge.

SCALINGPREDICTIONS

Formation water composition

Assessment of the scale potential was initially uncertain due to the large variation in the compositions evident in the limited number of formation water samples.