Abstract

The South West Ampa Field located in Offshore Brunei Darussalam is a large and complex field containing more than 400 oil rim reservoirs and 380 non-associated gas reservoirs. Of these oil rim reservoirs 320 contain less than 1 E+06 m3 while only 11 reservoirs containing more than 5 E+06 m3.

The field is a growth faulted anticlinal structure and is sub-divided into Southern, Main Field and 21 Areas. The reservoirs are heterogeneous and stratified separated by laterally extensive shales. The Southern Area is predominately non-associated gas while the other two contain extensive oil rims. Initial development of the Main Field and 21 Areas started in 1964 and concentrated mainly on these oil rims which produce via a combination of natural aquifer influx and gas cap expansion. As oil production declines the challenge is to identify and develop any undrained pockets of oil prior to release of the gas caps. By the end of 1995 a total of 404 wells and side-tracks have penetrated these reservoirs. The current cumulative oil production is 106 E+06m3.

Although much is known about the reservoirs in the SW Ampa Field many uncertainties still exist. The major uncertainties which influence reservoir performance are the complex geology and extensive faulting, internal reservoir cross-flow via common gas cap/oil rims and position of the original contacts. In this complex and mature reservoir environment studies have been undertaken to address these uncertainties and assess the potential for infill oil development. These studies range from analytical material balance and displacement calculations to full 3D reservoir simulations.

This paper addresses the methodologies applied for these complex reservoir situations and examples are presented where through the use of advanced technology optimal solutions are obtained. The impact of 3D seismic data and integrated study team approach are also discussed.

Introduction

The South West Ampa field, discovered in July 1963, lies approximately 10 miles Offshore Brunei Darussalam in water depth between 10-40 metres. It is an anticlinal structure sub-divided by a series of growth/wrench faults into Southern, Main Field and 21 Areas (Figure 1). The field is large and complex containing more than 400 oil rim reservoir and 380 non-associated gas reservoirs and has over 400 well penetrations. While the Southern Area contains mainly non-associated gas reservoirs, the other areas contain extensive oil rims and the total field STOIIP is split approximately equally between these two areas. Initial development of the Main field and 21 Areas started in 1964 and concentrated mainly on the oil rim reservoirs which produce via a combination of natural water influx and gas cap expansion. For the Main Field, the oil recovery factor is estimated to be 35% of which approximately 25% remains to be produced. The picture is somewhat different for gas where the recovery factor is 80% of which approximately 50% remains to be produced. Much of these gas reserves are associated with downdip oil rim production. Production of these gas volumes is therefore restricted in order to maintain the reservoir drive energy and ensure oil recovery is maximised.

In order to unlock these strategic gas volumes, a series of development studies have been undertaken to assess the infill opportunities in the oil rim reservoirs. Due to the scale of the field and for study purposes, the reservoirs are grouped into manageable packages. This paper discusses those studies carried out on the Intermediate package of sands in the Main field area which contain a total of 106 reservoirs (67 oil rim and 39 non-associated gas) and some 208 well/side-tack penetrations. While there is a significant amount of data available for these reservoirs many uncertainties still exist. The major uncertainties which influence the ability to identify infill oil development opportunities are the complex geology and extensive faulting, internal reservoir cross-flow and position of the initial and present fluid contacts.

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