Q: With the appointment of Brett Darley, the drilling segment of the project seems to be coming back into line with the rest of the project doesn't it? Can you outline the schedule as it stands now?

A: The drilling and completion segment of the project has always been integrated with the overall project via the inclusion of an experienced Well Engineering Manager in the project team. Preliminary well design work commenced in early 2003 with an overall philosophy that if Electric Submersible Pumps (ESPs) were to be included in the completions then well design and trajectory should be kept comfortably within known technical experience. In order to keep the project moving on a fast track schedule long lead equipment was identified and ordered in July 2003, ahead of final project sanction in October.

However the detailed completion design and selection of final well locations had to be progressed in parallel with results from reservoir modelling work which has left final preparations for Operations on a tight schedule also. Hence the rapid build up of the team under Brett.

The schedule for development drilling has remained unchanged over the last 4 months. The first Exeter well is to be spudded in early February. Well bores of the phase 1 wells should be finished prior to sub sea completion operations due to commence in early August with the delivery of the trees. All development wells are planned to be completed and ready for tieback to the sub sea pumping manifolds around the end of 2004.

Q: What is the current field development plan and what is the production profile of the field?

A: Oil production is forecast to commence in first half of 2005, at around 70-80,000 bopd, building up to a plateau of 100,000 bopd. Field life varies between 5 and 13 years, dependent on reserves and production rates, near field exploration drilling results and economic factors (oil price / FPSO contract rate, etc)

Seven initial horizontal sub sea production wells are planned, five at Mutineer and two at Exeter, each group producing into a sub sea pumping manifold. Each well is expected to be capable of 20,000 bopd and each will have down hole sand exclusion screens and dual electric submersible pumps (ESP's), rated at 600 to 900 HP.

Two seabed multiphase pumps will also be used, one at each manifold, to boost production rates. The manifolds are 6km and 3km from the FPSO (Mutineer and Exeter respectively) and will be tied back through 12" production lines. The FPSO will have 930,000 bbls of storage and be offloaded initially every six days using trading tankers of around 600,000 bbl capacity.

Q: ESP's (electrical submersible pumps) are an essential part of the development plan aren't they? Why?

A: There is uncertainty on the degree of natural aquifer influx that can be expected. Although some natural aquifer water influx may occur, it may not provide sufficient energy to allow the wells to continue to produce at their expected initial high rate, i.e. the reservoir pressure is expected to fall off significantly within the first 18 months of production. The oil itself is considered nearly dead, in other words it has a very low gas oil ratio (GOR) of around 10 scf/bbl.

Hence additional energy is required to allow the wells to continue to produce at high rates, and reservoir simulation and well modelling shows that artificial lift will have a significant benefit to the project. However, there is insufficient solution gas for gas-lifting the wells, and there is no nearby external source of gas that could be utilised cost-effectively. ESP's are therefore the preferred solution.

Q: With the lessons of Stag in mind, and given you were the project manager there, what allowances have you made for a possible gas cap in the reservoir, given you don't want to repeat the Stag scenario where the presence of a previously undetected gas cap effectively ruined the production schedule?

A: This question of a gas cap is more fully addressed below. To clarify, there were a number of reservoir factors which contributed to the initial performance at Stag. Stag reservoir fluid was at bubble point at initial conditions, and therefore the possibility of a gas cap was recognised at the appraisal stage, however it was believed to be very small and could not be detected on 3D seismic.

The lesson learnt, and very effectively applied in the production phase at Stag, is to identify and engineer the facility with as much flexibility as is practicable to cover the widest range of uncertainty.

Q: Are you certain there is no gas cap? Given Stag, one would assume this scenario would have been factored into planning - is this a correct assumption?

A: The presence of a gas cap is inconsistent with the nature of the oil so far encountered at Mutineer and Exeter, which from both fields is approximately 42 deg API crude, with a GOR of around 10 scf/bbl. In addition, the oil has a very low bubble point of less than 100 psia. The presence of a gas cap would imply that the oil would have a bubble point basically equal to the reservoir pressure (which is around 4,500 psia at 3,100 metres subsea). Such an oil would also have a much higher gas-oil ratio (GOR).

Oil has been recovered from MDT's taken in various wells in the Mutineer and Exeter fields, as well as from the Mutineer -3 production test, and the fluid properties are consistent across all samples (i.e. low GOR, low bubble point, all pointing to no gas cap). In addition, the measured pressure depth gradient in every well is consistent with a low GOR oil, further evidence pointing to the absence of a gas cap.

Our subsurface team has identified the performance of the aquifer and the behavior of the faults as the major uncertainties controlling the possible range of reservoir performance during the production phase. For this reason the FPSO facility also includes water injection equipment for 150,000 bbls/day.