Abstract

The Elgin and Franklin fields, located in the Central Graben area of the North Sea in 92m of water, contain important quantities of rich natural gas condensates (circa 750 MMBOE). The reservoirs (sandstones of the upper Jurassic period) are deep (5,500m) and sour, with abnormally high pressures, extreme temperatures (HP/HT: 1100 bar/200°C) and significant levels of both CO2 and H2S. This paper introduces the major challenges, particularly the HP/HT conditions, the means to overcome them and the current development plans.

The development plan is discussed and the present progress status described.

The Project has reached 86% progress at end November 1999, is on schedule and within budget, and on track to achieve its objective of CAPEX below $3/boe.

Introduction

The Elgin and Franklin fields are HP/HT (high pressure/high temperature) accumulations located in the Central Graben Area in the UK sector of the North Sea as indicated in Figure 1.

The Franklin field was discovered in 1985 and delineated with two appraisal wells drilled in 1988/89 and in 1991. The nearby Elgin field, discovered in 1991, was appraised with 2 further wells drilled in 1992/93 and in 1994. The close proximity of the two fields, within just a few kilometres of each other, provides the critical mass on which to build a sound and robust joint development and in February 1997 the coventurers in the Elgin and Franklin Fields entered into a Unitisation and a Joint Development and Operating Agreement for development of the Elgin/Franklin Unit Area. The pressure and temperature conditions found in these fields are near the extremes of current experience, as indicated in Figure 2.

The main reservoir characteristics are summarised in Figure 3. Reservoir fluids are characterised as gas condensate with one compartment of the Elgin field particularly being quite rich, containing about 1.7sm3 condensate/ 103sm3 gas (300 bbl/1000 mcf), twice the liquid content of Franklin. The 3-4% CO2 and about 40ppm H2S impose additional metallurgical and processing demands.

The fluid, rock and pressure/temperature conditions yield field parameters for which there is little analogous experience. As a consequence one of the major challenges that development planning assessments faced was the ability to predict with sufficient confidence the field production levels.

The impact of reservoir performance uncertainties are compounded by drilling challenges. Not only are wells very expensive but they need to be drilled prior to significant reservoir depletion (i.e. before significant production history will be available on which to base subsequent well location decisions).

The exploration and appraisal wells, requiring substantial time to drill and utilising high specification, state of the art drilling rigs, were very costly and confirmed that drilling costs would represent a major portion of the total field development investment. The Elgin appraisal drilling programme was conducted on the basis that the wells would be retained for potential use during the development. The two appraisal wells drilled subsequent to the discovery well were deviated from adjacent surface locations to facilitate their later use for development.

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