PEP 38460 partner New Zealand Oil and Gas says in its latest quarterly report that preliminary engineering and reservoir modelling studies have confirmed an FPSO, linked to four or five subsea wells, will be the optimal development for the Tui and Amokura-Pateke oil pools (Tui Oil Area).
The proved and probable (P50) reserves are 20-30 million barrels of recoverable oil, while capital costs for the subsea and subsurface components of the development are currently expected to be in the range of US$120-$150 million and will be refined by the FEED design study.
Preliminary reservoir modelling indicates that production will average 20,000-plus barrels of oil per day during the first nine months, with production rates reducing over approximately 10 years, subject to any additional reserves discovered by drilling nearby prospects.
Further reservoir modelling studies will be completed during the course of the FEED study to refine reserve estimates and determine optimal well locations to drain oil.
The joint venture expects the FEED contract, once awarded in February, to take up to six months to complete. This will allow a final financial investment decision to be made by August, with first oil scheduled for the last quarter of 2006.
The reports also details updates regarding the more southern offshore Taranaki Kupe gas-condensate project in PML38146 and says an assessment of environmental effects (AEE) has been completed and that AEE details demonstrate the adverse environmental effects of the Kupe development will be minimal.
Suitable contractors have pre-qualified for construction of the offshore elements: platform fabrication, platform installation, offshore pipeline purchase and offshore pipeline installation; and the engineering design necessary to go to tender has been completed.
Negotiations are taking place with NGC regarding NGC expanding and providing its onshore Kapuni gas treatment plant to processing raw Kupe gas and condensate. If suitable commercial terms can be agreed, construction of a stand-alone production station will not be required. A decision on the production station is expected during this quarter.
The Kupe joint venture has now set next October as the target date for a final financial investment decision, which provide sufficient time to complete an on and off-shore production facilities tender process.
The Kupe permit area is prospective for additional gas, which could be added to the main field production in due course. These additional prospects may also contain oil in commercial quantities.
NZOG says that in addition to pursuing its three developments, it is continuing working towards the drilling of several exploration prospects in the offshore Taranaki Basin.
Several undrilled Eocene-aged Kapuni F sand prospects within the Tui Oil Area - with reservoir targets of similar size and quality to the Tui-Amokura-Pateke discoveries - had been identified from recent 3D seismic shot and further delineation of these prospects is continuing.
A large (414 sqkm) new 3D seismic survey is planned over a series of Kapuni F sand prospects in the Hector area (PEP 38460-483) during April-June this year.
Reprocessing of seismic data covering Taitapa, a Miocene-aged prospect, had been completed of West Kupe (PEP 38484) and mapping of this relatively shallow oil prospect by the joint venture partner and operator OMV, is in progress to better delineate structural configuration and prospect size.
Further evaluation points to the Mangatoa (Cretaceous) prospect in PEP 38478 having even greater size than previously assessed with reserves possibly as great as 3 tcf of gas. Further assessment of drilling options points to drilling a single vertical well offshore using a jack-up rig.
The Eocene-aged Felix oil prospect (PEP 38729) is presently being refined through reprocessing of the seismic, with the refined definition completed by June. A jack-up is the most likely means of drilling Felix and Mangatoa, perhaps late this year, whereas Mangatoa would require a semi-submersible rig.
NZOG said it was looking for farm-in partners to share drilling costs in all these wells.
