Challenges in the Brent Field: Implementation of Depressurisation
Authors: Christiansen S.H. , Wilson P.M. 
Published: December 2007

In 1992 the decision was taken to go ahead with the depressurisation of the Brent Field to recover an additional 1.5 Tscf of gas and 34 MMstb of oil, extending the field's life by 5–10 years. Three of the four Brent platforms have been redeveloped at a total cost of 1.3 billion to install process facilities for low pressure operations, to reduce operating costs, to implement safety upgrades and to refurbish the ageing facilities to satisfy the fitness certification standards. The fourth platform has also been upgraded but no low pressure facilities have been installed. Each platform has been shut down for up to a year while field production was maintained from the other platforms.

Previous papers have focused on the conceptual design of the field's depressurisation. As we start to depressurise we move to the implementation stage with initial results impacting on the detailed future plans. As studies progress to define depressurisation plans in ever-increasing detail, the combination of the optimisation process and the deviation of the actual events from the conceptual plan tend to reveal new opportunities for adding or securing value. New technology advances open up major avenues to additional production and/or cost savings. "Designer wells" help to locate and produce oil from corners of the reservoir. New concepts in well completion and gas lift technology not only provide major cost savings but also release rig time on heavily congested rig sequences, creating opportunities for additional oil recovery.

The challenges outlined above call for a highly effective management system, skilled people, a continuity plan, an effective reservoir model and full integration of all disciplines. Embedded in the management system is a business improvement plan that identifies additional opportunities for adding value in all parts of the business and schedules the work necessary to achieve the improvements. The continuous improvement culture flourishes in an atmosphere of empowered teams working in a highly challenging environment.

Introduction

The Brent Field (Figs. 1,2,3) is located 186 kin Northeast of Lerwick, Shetlands Islands and has a STOIIP of 3.8 MMMstb and a GIIP of 7.5 Tscf. The field was discovered in July 1971, and brought on production just over five years later, on the 11th November 1976.

The field reached a maximum annual average oil production of 410 Mb/d in 1984. Since the mid-80s, oil production has been declining but, because of the high solution GOR (ranging from 250 to 980 v/v) substantial gas reserves still remain, dissolved in the residual and bypassed oil. Since the outset of field development there have been conceptual ideas to recover these large gas volumes and to further optimise oil recovery. As oil production started to decline, a wide range of IOR/EOR options was systematically evaluated. In 1992 the decision was taken to go ahead with the field depressurisation, necessitating one of the largest ever offshore, brownfield redevelopments, at a cost of 1.3 billion. The justification for depressurisation has been reported previously. This paper presents an overview of the depressurisation plan, some early results, and a number of related issues and how they are being managed. Reference is made to a number of papers describing these issues in more detail.

The Depressurisation Plan

The plan is to depressurise the reservoir to release solution gas from the bypassed (unswept) and remaining (swept) oil, and to encourage migration to the crest of the structure from where the gas may be produced.

Until recently, the field has been producing under conventional water flooding, maintaining the reservoir pressure at 5500–6000 psia, close to the initial pressure in order to keep most of the oil above bubble point pressure. P. 61^