Evaluating Connected Reservoir Volume for Optimizing Reservoir Management in Farragon Field a North Sea New Development
Authors: Herbas Julio Gonzalo , Usman Munawar H. , Parr Ronald Stanley , Buter Jordy 
Published: February 2016

The Farragon field, discovered in April 2003, is a low relief, pancake shaped reservoir located in the UK sector of the North Sea. This relatively small offshore field was developed with two sub-sea horizontal wells tied to existing production facilities. Initially the light 34°API oil was produced by natural flow and subsequently gas-lift has been used for artificial lift. A few months after first oil, the field was consistently achieving production rates higher than predicted which led to a decision to enhance the application of early extensive reservoir engineering studies aiming to better understand the reservoir mechanism, volumes in place and their implications for field depletion plans.

Data from permanent pressure gauges installed in the two open-hole gravel-packed horizontal producers was analysed to improve understanding of the reservoir. Average reservoir pressure, productivity index and connected volume were interpreted from build-up & drawdown tests. The calculated oil in place volumes were history matched with multiple Material Balance runs which used BP's TDRM, Top Down Reservoir Modelling1 process. This powerful tool is designed to evaluate reservoir engineering uncertainties in a wide range of scenarios considering multiple variables providing much greater confidence in the obtained results.

Full field multidimensional numerical simulation models with updated volumes from new 3D seismic reinterpretations, history matched the field performance, confirming previous classical reservoir engineering conclusions.

The outcome before the first 18 months of field life demonstrated the value of extensive application of reservoir and petroleum engineering techniques in a very early stage of the field life as it resulted in a 25% increase in estimated oil recovery. This paper outlines the general methodology applied that drove the implementation of optimized reservoir management strategies.

Introduction

Preliminary classical reservoir engineering studies performed on the Farragon field during the first year of oil production, suggested a bigger than originally estimated volume of initial oil in place. This was in-line with the production performance which was consistently above the initial expectations.

Basic Decline Curve Analysis, Pressure Transient Test interpretations, material balance and numerical simulation models, demonstrated consistency with field trends and with analogous fields, although the production period by the time the first studies were performed was quite short.

Transient test data were interpreted to determine the reservoir properties and to estimate the connected volumes. Material balance provided oil in place results consistent with those from the pressure transient tests, a quantitative insight into the production mechanism and water front displacement. Water breakthrough occurred in the deeper well # 2, 6 months after 1st oil. The water cut was matched and, the water breakthrough in the shallower well # 1 has been predicted to occur after some 20 months of the field production start.

Full field numerical reservoir simulation studies were then performed confirming previous results from the classical reservoir engineering analyses. This provided the basis to justify an important increase in the field volumes and recoveries and for the initiation of further studies aiming to investigate alternate exploitation schemes to increase the final recovery further.

Geology and Reservoir Description

The Farragon reservoir lies in sands of Palaeocene age, close to several existing fields: the mature Andrew and Cyrus fields to the South-West and the Arundel discovery to the North-West. The sediments were deposited in a submarine fan environment consisting of distal turbiditic facies. The reservoir thickness is up to 55 m gross (40 m net), limited at the top by a structural seal and at the bottom by a large aquifer of regional extent. The oil water contact is at 2556.5m TVDss. Figure 1 shows a depth map of one realisation of the four-way dip closed structure.