Fairfield equity = 50%
TAQA Bratani equity = 50%
Darwin is the name Fairfield has given to development of the Southern end of the old NW Hutton field (NWH), block 211/27a together with an extension into block 211/27e, in the Northern North Sea approximately 130 km northeast of the Shetland Islands. Blocks 211/27a and 211/27c were acquired by Fairfield from Amoco (UK), a subsidiary of BP, and partners in September 2009 while block 211/27e was awarded to Fairfield in the 25th Licensing Round in November 2008 with a one well firm drilling commitment. Fairfield now holds a 50% interest in block 211/27 following a 50% farm-out to TAQA Bratani Ltd in March 2012.
Block 3/2b, immediately to the South of Darwin, was awarded to the partnership in the 27th UKCS Seaward Licensing Round and adds further exploration potential to the area.
Operatorship transferred to TAQA on 31st March 2013.
Water depth in the Darwin area is around 480ft. Nearby production platforms include TAQA’s Cormorant South Field (14 km), Shell/ExxonMobil’s Brent Field (24 km) and Fairfield’s Dunlin Field (29 km).
Background & Exploration History
NWH was discovered in April 1975 by the 211/27-3 well, drilled by Amoco (UK). A further 7 delineation wells were drilled and an FDP was submitted in April 1979. Two further appraisal wells, both of which encountered oil bearing BRENT reservoir, were drilled during the NWH development. The field was developed by a large, fixed steel combined drilling and production platform from which a total of fifty-two development wells were drilled over field life. The platform was positioned in the northern part of the NWH field in order to access the crestal areas at the northern margin of the geological structure. Some long reach wells were drilled from the platform, and together with the two most recent appraisal wells, proved produceable oil in the southern part of the field. However, the distance from the platform precluded economic development of this area at that time. It is this southern part of the old NWH field, together with the prospective area further to the south that Fairfield is planning to develop as the Darwin field.
NWH production started in April 1983 and reached a peak of 86,500 boepd in May 1983. The reservoir development strategy was gas-lifted production wells with partial reservoir pressure support through water injection. Enhancement of production through water injection was poorer than anticipated for reasons believed at the time to be predominantly due to an extensive network of interconnected faults across the field. By March 1988 the original 30 well development scheme was complete and because of the poorer than anticipated production performance from many of the wells, a further seven well infill campaign was completed in September 1988. Additional sidetracks, together with infill drilling, were then conducted in two further drilling campaigns between 1989 and 1992. In the mid-1990s came the last campaign with well abandonments and slot recoveries.
Due to high fixed operating costs associated with the large steel platform, relatively low oil prices and the significant cost of importing gas for fuel, the Cessation of Production (‘‘COP’’) process commenced in late 1992 although the last official production was in 2002. The field has now been almost fully abandoned with all wells plugged and the platform removed. Only some intra-field pipelines remain to be decommissioned at the original owners’ liability.
During its life, NWH produced approximately 120 MMbbls of oil, 5 MMbbls of natural gas liquids and 78 Bcf of gas. Current NWH oil in place estimates have an original STOIIP of 805 MMbbls (NWH 615 MMbbls, Darwin 190 MMbbls), indicating the NWH recovery factor is low for Brent province reservoirs. Recoveries per well were highly variable and understanding this variability, and addressing the associated issues, is the key to a successful future development of Darwin.
Field Development Plan
Fairfield’s technical work on NWH has been directed towards understanding its reservoir performance as an analogue of what might be expected in the undeveloped southern part of NWH and further to the south in 211/27e. New 3D seismic was shot across the entire area in 2009 to better define the top and base Brent envelope and improve and rationalise the structural fault pattern. Contrary to the original interpretation of the 1980’s-vintage seismic data, the new data shows significantly less faulting and a much better defined structural grain. This is consistent with the inferred structure and the observations from the production history and stratigraphy in the wells. Dynamic modelling has assisted in defining the extents of some of these faults where the tip points were sub-seismic in scale resulting in localised mismatches to the historical production. This comprehensive picture of the structure, combined with the lack of dedicated water injectors, helps to explain the poor water-flood response observed in many of the producing wells on NWH and highlights the importance of a detailed reservoir management and completion strategy. In 2013 reprocessing of the new seismic was initiated to further subsurface alignment.
Detailed petrophysical, stratigraphic and reservoir quality analyses have been completed based on the log and core data, together with a thorough review of all the NWH production data, well histories and production logs. A comprehensive static model was constructed to assist in understanding the reserves distribution, reservoir performance, optimum perforation strategy and water injection pattern design. This resulted in the identification of a phased development approach comprising the proven, but undeveloped oil accumulations in the south of NWH and the prospective but potentially larger accumulations further to the south within block 211/27e.
Following on from this, in order to address specific uncertainties, exploration and appraisal drilling of three locations within blocks 211/27a and 211/27e was undertaken over the 2012 and 2013 period. Static and dynamic reservoir models were subsequently updated to accommodate the 2012/13 well results.
Development will be achieved by the optimised placement of producers and supporting water injectors in individual fault-panels. These fault panels are now well defined on the new seismic data meaning that with an appropriate completion and well management philosophy, producers will receive dedicated water injection support and reservoir sweep on a layer-by-layer basis from their respective injectors. This in-turn implies that the recoveries per well in the Fairfield development plan will be comparable with the upper-limit of what has already been proven to be achievable in the best of the original NWH development wells where good producer-injector pairing, and vertical sweep, was achieved.
Evaluation of alternative hosting options for the development is ongoing with comparison economics being run for a tie-back solution or a stand-alone FPSO unit. Continued value improvement studies are ongoing. First oil is anticipated in 2020.
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Fairfield acquired 50% of the Glein area which is located in Licence P1746 comprised of blocks 48/11c and 48/12b, and contains two undeveloped discoveries, Glein and Eos
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Before decommissioning its fields, Fairfield will consult pro-actively with a wide range of stakeholders.
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