This paper traces the development of a group of North Sea oil and gas condensate fields, known as the Brae Area, highlighting the considerable gas management challenges.

South Brae, a black oil field, was first on production in 1983. Approximately 40 Bcf (1.1 × 109 m3) of associated sour gas had to be temporarily stored in the reservoir, creating reservoir management complications as the gas cap has fingered downdip to producing wells, and calcium carbonate scale formation has been exacerbated.

Early in 1988 came North Brae, a gas condensate field developed by gas cycling. Along with residual North Brae gas, the gas temporarily stored in South Brae is injected into the reservoir, to enhance pressure maintenance. The liquid recovery benefits of this development technique are examined.

In 1989, Central Brae, a small oil field similar to South Brae, was developed as a subsea satellite to South Brae. Its gas is also used to enhance North Brae liquid recovery.

The recently approved East Brae field is another giant gas condensate reservoir, due onstream in 1993. This field will also be developed by gas cycling, using some

North Brae gas to enhance pressure maintenance. The paper examines the inter-relationship between gas sales, availability of gas for injection into East Brae (from Brae and other fields) and the degree of pressure maintenance (and hence liquid recovery) anticipated for East Brae.

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