The Britannia Field Development
Authors: Tetlow Jeff , Wingate Peter 
Published: June 2014

This paper (SPE 57065) was revised for publication from paper OTC 11013, originally presented at the 1999 Offshore Technology Conference held in Houston, 3–6 May. Original manuscript received 5 February 1999. This paper has not been peer reviewed.

The Britannia field was developed ahead of schedule at a cost 20% lower than the approved budget. This paper provides an overview of the development project and, by use of a performance-improvement model, explains how these outstanding results were achieved. This outcome would not have been possible with traditional project-management philosophies. The processes and techniques described are applicable to other capital investment projects.

Introduction

The 13,000-ft-deep Britannia field is located in U.K. Continental Shelf Blocks 15/29a, 15/30, 16/26, 16/27a, and 16/27b, 130 miles northeast of Aberdeen in approximately 450 ft of water (Fig. 1). The reservoir, which has considerable areal extent, is approximately 20 miles long (west to east) and as much as 5 miles across (north to south). Simplistically, the reservoir is inclined along its length, with its highest elevation in the north and its lowest in the south.

The reservoir contains a retrograde gas/condensate fluid whose composition varies from west to east. The hydrocarbon is richer in the west (condensate/gas ratio of 100 bbl/MMscf) and leaner in the east (condensate/gas ratio of 70 bbl/MMscf). An oil rim lies along the southern edge of the reservoir. Although the oil is a good-quality, light but waxy, sweet crude, it is relatively immobile. An aquifer lies under the oil rim. The length of the reservoir has five distinct regions, each of which has an aquifer with different water chemistry.

The reservoir has recoverable reserves of 3.1 Tcf of gas and 145 million bbl of liquids. The distribution of reserves, however, is such that the majority lies in the east. The latest reservoir model puts the west/east split at 25 : 75.

The field has been developed to meet the needs of gas-sales contracts. Therefore, any development plan involved a significant pre-drilled-well program.1 The concept eventually chosen to develop the reservoir (Fig. 2) used two drill centers.

A subsea center is at the western end of the field.2 This center produces approximately 25% of the reserves. It comprises a manifold adjacent to seven predrilled production wells. The manifold can handle gas and associated liquids from up to 14 wells and is designed to produce up to 380 MMscf/D.

The subsea manifold is linked by a unique flowline bundle to a minimum-facilities production platform located 9.3 miles away at the eastern end of the field.3 The bundle contains a series of flowlines grouped together and surrounded by a 37-in.-diameter carrier pipe. The carrier pipe provides a hot-water jacket to prevent hydrates from forming as the reservoir fluids travel from the subsea center to the platform. A number of production-chemistry challenges also faced the system designers.4,5

A minimum-facilities platform is located in the east part of the field. The topsides6 include production, drilling, and accommodation facilities. A total of 36 well slots, incorporated in a center-wellbay concept, is provided. The topsides are supported by an eight-leg steel substructure located over a 10-slot well template for the predrilled wells.

Reservoir fluids from both the subsea center and the platform are processed on the topsides to produce a dry, dense-phase export gas at a rate of 740 MMscf/D and a 125-psi true-vapor-pressure condensate suitable for export at rates of 76,000 B/D.

The gas is exported through a dedicated 27-in.-diameter pipeline with a landfall at St. Fergus in northeast Scotland.7 The export gas is then processed in an extension to the Mobil-operated Scottish Area Gas Evacuation (SAGE) terminal to meet a U.K. national grid specification. Gas liquids recovered at the SAGE terminal are pumped to the British Petroleum (BP) -operated Forties pipeline system terminal at Kinneil, Scotland.

Condensate leaving the platform is pumped to the BP-operated Unity platform and then into the Forties Pipeline System. Liquids arriving at Kinneil are processed to produce a stabilized crude oil and a raw gas product.

Preproject Phase

When the Britannia reservoir was discovered in the mid-1970's, the two oil companies that held interest in the five separate licensing blocks it straddles gave it different names; Chevron called the field Kilda and Conoco called it Lapworth. Individually, both operators had too large a stake in any development project to be ignored.

Conoco and Chevron decided to develop the reservoir together. Their joint agreement on the name Britannia became a symbol of the spirit of cooperation that underlined the entire development. It also embraced the interests of the many companies and suppliers involved in bringing the project to a successful completion. In this way, Britannia Operator Ltd. came into being. The responsibility of the joint operator was to develop the field and operate it throughout the production life.8

In the early days of the development-planning phase, the engineers were faced with a number of challenges. The period during which development-plan screening was being conducted coincided with the U.K. government's gas-deregulation proposals. At the time, a contract was being negotiated with one company to buy all Britannia gas; however, the company became reluctant to purchase large volumes of gas in a changing market. Contract negotiations were suspended, and the commercial team was charged with finding alternative buyers.

The initial budget for the field-development concept was U.K. £1,800 million. Coventurers indicated that a development with this potential cost might not be economically viable. The development-planning team was challenged to reduce the development cost by 20%.