Aker BP confirms gas discovery in North Sea’s Alpehumle prospect, estimates up to 15 MMboe recoverable
Aker BP has confirmed a gas discovery at the Alpehumle prospect in production license PL 1153, roughly 15.5 miles north of the Duva field in the North Sea. The find came through exploration well 36/4-2, drilled by the Scarabeo 8 rig, with a sidetrack well also completed at the site. Preliminary estimates put recoverable resources between 1 and 15 MMboe — a range wide enough to leave the discovery’s commercial future genuinely uncertain.
Aker BP announces gas find in Alpehumle prospect
Well 36/4-2 is the first exploration well ever drilled in the Alpehumle prospect. It confirms gas in production license PL 1153, sitting 15.5 miles north of the Duva field — a producing asset that gives the new find some useful geographic context. Recoverable resources are currently estimated at 1–15 MMboe, or 5.3–84.8 million standard cubic feet of oil equivalent. That’s a wide spread, reflecting how early the evaluation still is.
The licensees will now assess the well results to determine whether the discovery is economically profitable and whether additional delineation drilling makes sense. Neither outcome is guaranteed. A 1 MMboe low end is a modest find by North Sea standards. Fifteen MMboe would be considerably more interesting commercially, and next steps will likely narrow that range.
The sidetrack had a narrower job: delineate what the main well found and identify where hydrocarbons end and water begins — the hydrocarbon-water contact.
Drilling operations: Well details and technical parameters
The Scarabeo 8 rig handled the drilling campaign at Alpehumle. The main well, 36/4-2, reached a total depth of 7,382 feet TVD subsea in water depths of 837 feet, terminated in basement rock — meaning the drill bit hit the hard crystalline foundation beneath the sedimentary layers, with no further reservoir section to test below.
A sidetrack designated 36/4-2 A was drilled from the same wellbore to a slightly deeper total depth of 7,612 feet TVD subsea, terminated in an unidentified formation. That detail adds a layer of geological uncertainty to the results. The main well’s primary target was proving petroleum in Early Cretaceous reservoir rocks belonging to the Agat formation, which has drawn consistent exploration interest across the North Sea for its sandstone reservoir potential. The sidetrack had a narrower job: delineate what the main well found and identify where hydrocarbons end and water begins — the hydrocarbon-water contact.
What the wells found: Reservoir results and limitations
The main well delivered a clear gas hit. Well 36/4-2 encountered a 33-foot gas column in the Agat formation, with all 33 feet sitting in sandstone rated as very good reservoir quality — good porosity and permeability means gas could be produced efficiently if the volumes justify development. The catch is that the hydrocarbon-water contact wasn’t proven in well 36/4-2. Without knowing exactly where the gas zone ends and the water zone begins, pinning down the size of the accumulation with confidence becomes difficult. That uncertainty explains much of why the resource estimate spans such a broad range.
The sidetrack, 36/4-2 A, was drilled specifically to address that question — but it came back aquiferous. It encountered 13 feet of very good quality sandstone in the Agat formation, water-bearing rather than gas-bearing. So instead of locating the contact it was looking for, the sidetrack found water, which complicates the picture further. Data acquisition and sampling were conducted in both wells, giving the team core and fluid samples to work with as they refine their models. Both wells will be permanently plugged following the campaign.
License ownership and partnership structure Aker BP operates PL 1153 with a 40% working interest — the largest stake among the four licensees and the lead role in any decisions about next steps. Partners include Inpex Idemitsu Norge AS at 30%, Okea ASA at 20%, and Harbour Energy Norge AS at 10%. All four will weigh in on whether to pursue further delineation or move toward a development decision, assuming the economics work out. Proximity to the Duva field, 15.5 miles to the south, is worth noting.
Existing infrastructure nearby can sometimes make smaller discoveries more viable than they’d otherwise be, since tieback options may reduce the cost of bringing gas to market. Whether Alpehumle could benefit from that kind of arrangement is still an open question. The Agat formation keeps attracting exploration interest across the North Sea, and this discovery adds another data point — even if the results are mixed.
Is further delineation drilling warranted?
Aker BP has confirmed gas at the Alpehumle prospect in PL 1153, with recoverable resources estimated between 1 and 15 MMboe. The main well found a gas column in good-quality Agat formation sandstone, but the hydrocarbon-water contact remains unproven. The sidetrack came back water-bearing, adding uncertainty rather than resolving it. The licensees — Aker BP (40%), Inpex Idemitsu Norge (30%), Okea (20%), and Harbour Energy Norge (10%) — will now evaluate whether the discovery is commercially viable and whether further delineation drilling is warranted. Both wells will be permanently plugged. Any future development would likely factor in available regional infrastructure.
Kelly is an experienced writer with 15 years of experience exploring the big stories that shape our world, from tech breakthroughs and space exploration to climate, energy, and the fascinating quirks of science. She has a talent for turning complex ideas into sharp, memorable insights that stay with readers long after they’ve finished reading.
