Forty-eight years (and over 3,000 exploration wells) on from the first commercial discovery at West Sole, much of the United Kingdom continental shelf has long been considered a mature exploration province. Obviously, throughout this time the fortunes of the province have fluctuated along with the prevailing economic conditions and strategic considerations. These issues, along with a steady flow of technological advances, have driven exploration from the early large oil and gas discoveries to progressively more challenging prospects and hard to win reserves. In the current climate, with sustained high oil prices balanced by high capital costs, and not least by rig rates, a sharp focus has been kept by the industry on the technical risks of the UKCS prospect portfolio, with recent trends in exploration thinking reflecting the fine balance between prospect size, technical risks (of all aspects) and exploration costs.
New Challenges
Despite an overall drop in exploration and appraisal drilling over the last few years – from 85 completions in 2009 to 45 in 2013 (to the end of October) exploration has held up surprisingly well, with 33 wells completed or currently operating this year, compared to between 25 and 37 completed each year from 2009 to 2012. With, by some measures, over 120 exploration and 50 appraisal wells planned or committed over the next three years, the nation’s prospect portfolio looks healthy.
It goes without saying that within a mature exploration area all of the ‘easy’ oil and gas has been proven. The ‘difficult’ plays that remain provide a number of challenges. For those with large reserve potentials the challenges are generally technical and commercial. One of the most active areas with the potential to add significant reserves is the Central Graben HPHT/uHPHT province, with recent drilling including the Thunderer (30/2a-10) and Oakwood (30/1d-12Z) tight holes and the Lacewing gas/ condensate discovery (23/22b-6Z). A considerable resource base is building in this province, with several large structures yet to be drilled to targets in Fulmar, Pentland and Skagerrak sandstones at depths in excess of 14,000 ft, with HPHT drilling in the Fisher Bank Basin (22/4b-6; White Bear) and planned in the Viking Graben demonstrating the willingness of operators to apply their experience to under-drilled deep basins. Up to fifteen exploration wells could be drilled on the HPHT play within the next few years.
Heavy oil provides a quite different set of challenges, particularly in sustaining commercial flow rates of viscous oil from an unconsolidated sandstone. EnQuest continued appraisal of Kraken in 2013 and plan to drill a large Heimdal pinch-out (Wayland’s Smithy) next year. With several large heavy oil plays under development along the west flank of the Viking Graben, focus is shifting back to the Moray Firth in the search for large reserves, with wells planned on the shallow Norfolk pinch-out trap in block 12/16b and Bagpuss on the Halibut Horst in block 13/24a. Both wells have Lower Cretaceous objectives.
The risk of heavy oil partially explains the delay in drilling the Catcher prospect – a discovery that has acted as a play opener arguably along the entire western margin of the Central Graben from Quadrant 28 to 39. By demonstrating the viability of long distance lateral migration within Tertiary carrier beds and the potential for light, unbiodegraded oils at shallow depths, Catcher not only derisked several Cromarty and Tay amplitude plays on block 28/9 (most recently with 28/9a-6 proving oil in the Bonneville prospect) but opened up the adjacent margin, with five firm and two contingent wells bid in the 27th Round. These wells will target not only Tertiary amplitude plays but deeper Fulmar Sandstones in small sub-basins away from the graben margin where migration and charge provide the challenge.
Further south along this margin, the Andromeda prospect is scheduled for drilling next year. This will be drilled updip of a 1973 Shell well which encountered oil pay in a Zechstein dolomite, with objectives also in the underlying Lower Permian Auk Sandstone. This is the principle reservoir in the Auk Field to the east. The Auk was also a deep objective for the recent Taggart/Rebus 22/23c-8 tight hole, showing a renewed interest in deeper, older reservoirs along the basin margins, where regional 3D coverage may aid derisking of oil charge.
The 2013 Lacewing gas/condensate discovery lies in the high pressure/high temperature (HPHT) zone of the Central Graben province, an area of increasing interest to operators. Source: PGS
The Bonneville discovery is one of several amplitude plays on the western margin of the Central Graben. Source: PGS
3D Data Major Driver
The availability of regional 3D data sets covering almost all mature areas of the North Sea has been a major driver for exploration within the last few years. However, the inventory of Lower Tertiary channel/fan plays with amplitude support is being progressively drilled up, with some recent wells, such as 21/7b-4 (Cyclone) failing to prove hydrocarbons. Throughout the Outer Moray Firth and Central Graben more focus is being placed on the Upper Jurassic and Lower Cretaceous in subtle structural and stratigraphic plays. The Fulmar, for example, has a complex reservoir distribution, with strong structural controls and local erosion, not to mention the highly diachronous nature of the sands, making this a difficult play. However, recent success along both margins of the Forties-Montrose High have encouraged drilling, including Taggart and Seagull North (22/24e-12) this year and with several more wells slated within the near future.
The search for new plays has literally reached rock bottom in some areas, with 3D seismic used to identify permeable fracture zones cutting large basement closures. The Lancaster discovery has proven this concept, with 205/21a-4Z (2010) flowing light oil from two seismically defined fracture zones. Hurricane plan two further wells on this play, whilst EnQuest are drilling an appraisal well on Cairngorm (block 16/3d) to test an analogous basement fracture system.
Finally, the focus west of Shetlands remains on large plays in deep water, with recent wells on Paleocene amplitude-supported stratigraphic traps and dip closures (Glenrothes and Cragganmore; 208/11-1 and 208/17-3), and Cretaceous and pre-Cretaceous fault structures, with Triassic gas/condensate proven in the North Uist structure (213/25c-1V).
The future of exploration in the UK sector lies in a continued push to HPHT prospects in the deep basins and into deepwater areas west of Shetland, with higher risk plays in mature areas requiring significant lateral migration along basin margins or with uncertainties over reservoir quality or trap integrity within basins.
Acknowledgments
This review is based on detailed well reviews from the bi-annual United Kingdom Discovery Digest, prepared by Beagle Geoscience on behalf of Exploration Geosciences (UK) and Canadian Discovery. The map is from EG (UK)’s WHAT Map, and seismic examples, from the latest volume of the Digest, are reproduced here by the kind permission of PGS.
