Despite there still being major uncertainties for operators on the UK Continental Shelf, as Niall McLean from Brodies Solicitors clearly explained in his talk about the Finch ruling, when talking to people during coffee breaks at the recent Devex Conference, the mood still seemed more upbeat than it was last year. Maybe Ian Cross is right, we reached rock bottom already and therefore the only way is up.
The opening talks at the conference may also have helped, with Iain Lewis from Ithaca talking about the ambitions of his company and the senergies of developing partnerships such as the one with ENI. Peter Kavanagh from Anasuria also highlighted that when they took over operatorship of the Teal cluster in 2016, the economic horizon of the asset stood at 2025. This has now shifted to 2035 thanks to a range of measures, amongst which the successful drilling of infill wells.
It is indeed the (future) drilling activity that plays a pivotal role in extending the life of many UK North Sea assets, as was shown during the conference by a number of excellent operator talks.
Joseph Sherratt and Geoff Minielly from Equinor discussed a number of drilling targets around the mature Martin Linge field in the Norwegian sector. Situated close to the UK median line, the platform allows for drilling a few step-out wells, one of which is targeting the Laphroaig prospect in UK waters. This prospect nicely shows the challenges that these step-out wells face; having to avoid depleted Cenozoic and Brent reservoirs whilst the prospect is HPHT, an AVA response that is not overly conclusive, combined with an expected volume of between 8 and 24 MMboe.
Peter Morgan from Harbour gave a very insightful talk about the Gilderoy discovery made last year, with a lot of data to support the findings. And again, this well (15/28b-10) is an example of the types of prospects drilled these days – targeting a narrow turbidite channel only around 500 m wide. Back in the early days, this would either have been missed or by-passed and got stuck behind pipe; now it is a viable target on its own with around 10 MMboe recoverable. Peter showed that the operations went smoothly, with the entire Eocene reservoir being cored as well.
Florence Henriet from Dana Petroleum subsequently showed that a well-established field can still come up with drilling surprises. She presented about the Bittern field, which was identified as a candidate to get a horizontal well drilled in the crest of the structure. When the bit was nearing the top of what was thought to be the reservoir, an injectite sand was hit. Only after pumping a lot of cement, drilling continued and the underlying reservoir was found. As all previous wells drilled on Bittern were vertical and in other locations, this injectite was missed or not properly identified. It caused a downward revision of the top reservoir at the crest of the structure, which had always been difficult to map anyway because of the presence of a gas cloud.
Another perfect example is the development of the Talbot field in the J-area of the Central North Sea. Even though its existence was known since the 1970’s and appraised during multiple campaigns by a variety of operators, it ultimately took almost 60 years before the field was taken into production. It looks like a simple 4-way structure, but it was the lack of a consistent oil-water contact – now thought to be caused by differential aquifer pressure – and a relatively thin reservoir of around 20 ft that caused reluctance to proceed to development. Only now, with ultra-deep resistivity tools allowing more accurate geosteering, has it been viable to progress Talbot to development. The potential prize looks good though, as Carl Elliott showed; Talbot’s range of in-place oil varies between 25 and 175 MMboe.
