The Interpretation of Reservoir Pressure Data in the Dunbar Field (UKCS)
Authors: Bigno Y. , Baillie J. , Coombes T. 
Published: December 2007

Abstract
The Dunbar field consists of five hydrocarbon accumulations in Jurassic and Triassic sandstones. The existence and extent of dynamic connectivity between these reservoirs as well as lateral and vertical compartmentalisation within each accumulation has always been a concern for choosing the optimum reservoir development of Dunbar. Combined with these uncertainties, the existence of downdip permeability deterioration and the near-critical nature of the reservoir fluid complicates the estimation of volumes connected to each well. The benefit of implementing secondary recovery schemes is also greatly dependent on these factors.
This paper presents the role of pressure monitoring as one of the main reservoir management tools for Dunbar and also the different forms of pressure measurements implemented to reduce the uncertainties eg: formation pressure tests, long term pressure gauges, bottom hole pressure surveys and interference tests. Pressure monitoring, combined with geophysical and geological data - eg: Strontium isotope residual salt analysis (SrRSA) and geochemistry - has played a key role in the early field development.

Introduction
The Dunbar field lies 135 km east of the northernmost Shetland Islands and 25 km south of the Alwyn North field (Figure 1). It consists of several hydrocarbon accumulations in the Jurassic and Triassic sands, of the Brent, Statfjord and Upper Lunde formations. The field can be divided into four main areas : the Westflank, the Central, the Frontal and Dunbar South.
The field was discovered in 1973. However production did not start until December 1994, primarily as a result of the high levels of geological and geophysical uncertainty. Compartmentalisation into panels with limited or no interaction has been a main obstacle in assessing the actual potential of the field and the possibility for secondary recovery methods. Definition of reservoir scale heterogeneities through seismic imaging is made difficult due to a combination of low seismic resolution and a thin reservoir section which renders it insensitive to complex attribute analysis. The existence of large hydrocarbon-bearing volumes of rock with poor characteristics - the Dunbar "tight zones" - has reinforced the need for a predictive geological/reservoir model giving sufficient confidence prior to sanctioning development. This lack of understanding was also influenced by the nature of the fluid which is near-critical and therefore behaves like a volatile oil deeper in the reservoir and like a condensate gas at the crest, with no 2-phase interface (compositional gradient).
The main reservoir uncertainties and their impact on the development are summarised in Table 1.
All the above uncertainties could only be reduced through the acquisition of new data from new wells. The development of Dunbar was therefore designed on the basis that additional data acquired while drilling and producing new wells could be incorporated into the reservoir model and allow fine tuning of the development plan, all this while paying off the investments.
Acquisition of the new data has involved the following techniques:–pressure monitoring: formation pressure tests, long term pressure gauge surveys, bottom hole pressure surveys, interference testing,–non-pressure monitoring: SrRSA, geochemistry, production logging, saturation logging.
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