There is excitement in the air, and not just in Alaska, over recent oil discoveries on Alaska’s North Slope.
During an April 25 presentation to the Alaska Senate Finance Committee, Paul Decker, resource evaluation manager for Alaska’s Division of Oil and Gas, commented on recent trips by Alaska Department of Natural Resources staff to promote Alaska’s oil and gas resources.
“We’ve recently come back from Houston on the second of two outreach trips, this one for the American Association of Petroleum Geologists national meeting,” Decker said. “Our booth was literally humming. There was an audible buzz.”
Decker was particularly referring to major new discoveries in the North Slope’s Brookian sequence of rocks, including Armstrong and Repsol’s Nanushuk development in the Pikka unit; ConocoPhillips’ Willow discovery, also in the Nanushuk; and the discovery by Caelus Energy of a major oil resource under Smith Bay.
His comments came as part of an overview of the outlook for North Slope oil development.
Pikka and Willow
Decker said that, in their project, Armstrong and Repsol had drilled more than 13 wells in the Pikka unit and had very methodically explored and delineated some very interesting discoveries in the Nanushuk and in older Jurassic-age Alpine sands. The recent drilling of the Horseshoe Nos. 1 and 1A wells had confirmed the extension of the Pikka discovery to the south.
“This is very good news and it helps confirm what they expected about the extent of that long north-south belt of reservoir in the Nanushuk formation,” Decker said.
ConocoPhillips’ Willow discovery, in a similar but completely separate Nanushuk reservoir, lies 55 to 60 miles west of Pikka, in the northeastern part of the National Petroleum Reserve-Alaska. A two-well exploration drilling program has confirmed a discovery originally made in 2002 from the Hunter A well, Decker said. The Willow find has a north-south extent of at least about 10 miles he said.
Smith Bay
Caelus’s Smith Bay find is in the Torok formation within the Brookian sequence. The company has drilled two wells in the shallow waters of the bay and has found some interesting sand bodies. However, the company has yet to conduct any flow tests for oil in the reservoir and has not yet collected large diameter rock cores for fully testing the reservoir quality. The reservoir rocks appear challenging for oil production, but Caelus anticipates that hydraulic fracture stimulation can overcome those reservoir challenges - Caelus hopes to drill another well in 2018 to test one of the several sands in the prospect. And, especially given that Smith Bay is more than 100 miles from the central North Slope oil infrastructure, much remains to be determined about this particular development opportunity, Decker said.
“But it’s certainly something of scale and scope, and we hope that good things will continue to unfold,” he said.
Decker commented on the drilling that Accumulate Energy is currently conducting in its Icewine No. 2 well, next to the Dalton Highway, south of the central North Slope. The intention is to hydraulically fracture the Hue Shale/HRZ source rock, to test the potential for producing oil from the source rock, in the manner of shale oil development elsewhere in North America.
“This will be the first time that that concept has been deliberately tested on the North Slope,” Decker said.
And Italian oil company Eni plans to conduct very long extended reach drilling north from the Nikaitchuq field’s Spy Island facilities later this year, to test for oil in leases in the federal outer continental shelf, immediately north of Nikaitchuq, Decker commented.
Upcoming projects
Decker reviewed oil projects at various stages of planning and development on the North Slope. He started with projects expected to come on line at some time between 2018 and 2021. He presented information about what is known about expected peak production rates from each development, emphasizing that different developments would peak at different times and that production would typically decline after peaking.
In the Colville River unit ConocoPhillips is continuing its drilling operations into the Alpine and Kuparuk formations from the CD-5 pad in the eastern NPR-A. Production from the pad is anticipated to peak at 15,000 barrels per day, Decker said.
The company is also engaged in two phases of development in the Greater Mooses Tooth unit. It looks as if each of these developments could result in oil production of up to 30,000 bpd.
Developments on hold
Following the drop in oil prices, Caelus Energy has postponed its Nuna development in a challenging Torok reservoir in the Oooguruk field. The company has also put on hold further expansion of the Jurassic Nuiqsut reservoir, one of the main reservoirs in the field. Nuna, if developed, could result in production of 20,000 to 25,000 bpd, Decker said.
Also because of low oil prices, further development drilling has been postponed in Eni’s Nikaitchuq field in the nearshore state waters of the Beaufort Sea.
In the Southern Miluveach unit on the west side of the Kuparuk River unit, capital constraints have put a hold on Brooks Range Petroleum’s Mustang development, although much of the construction work has actually been conducted for this. Production from the field, with its good quality, modest sized Kuparuk formation reservoir, could peak at 15,000 bpd.
In the Kuparuk River unit, ConocoPhillips has drilled two horizontal wells to test potential oil production from the Moraine accumulation, a continuation in the Torok of the Nuna accumulation that Caelus hopes to develop in adjacent the Oooguruk unit. Also in the Kuparuk River unit, ConocoPhillips has postponed the 1H NEWS project, a further oil development in the West Sak accumulation in the Schrader Bluff formation.
And Hilcorp Alaska is planning a 44-well development, mostly targeting the Schrader Bluff formation, at the Moose Pad in the Milne Point unit - that could peak at 10,000 bpd, Decker said.
2022 and beyond
Looking at 2022 and beyond, Decker listed a series of potential developments, starting with developments that seemed relatively likely to move ahead before discussing projects associated with higher levels of uncertainty.
ConocoPhillips seems likely to move forward with its Fiord West development in the northwestern corner of the Colville River unit, given that, under an agreement with DNR, the company has committed to building a drilling rig needed to drill extended reach wells for field development from existing pads in the unit. The company has not released estimates of production rates from this development.
ASRC Energy is planning its Placer project, a project involving a Kuparuk reservoir similar in scale and type to the Mustang development.
Armstrong’s Pikka Nanushuk development has predicted production rates of up to 120,000 bpd over several years.
“We feel pretty good about those numbers, within DNR, having had the opportunity to work closely with Armstrong and Repsol in their offices, and seeing their data,” Decker said.
ConocoPhillips is interested in the Tofkat project, in a Kuparuk C sands reservoir, in what used to be the Tofkat unit. The company has appealed to DNR to add the Tofkat leases to the Colville River unit, with the alternative being to add the leases to a subsequent state lease sale. With the leases lying between the Pikka unit and the Horseshoe wells, there may be Nanushuk interest in the leases, Decker commented.
ConocoPhillips has said that its Willow discovery may hold 300 million barrels of recoverable oil. Peak production through standalone facilities at Willow could be 100,000 bpd, but the production rate may be 40,000 bpd if existing production facilities at Greater Mooses Tooth or Alpine are used, ConocoPhillips has said.
Hilcorp has a plan to develop the Liberty field from an artificial island in the Beaufort Sea. An environmental impact statement is being prepared for the development - EIS documentation suggests a peak production rate of 60,000 bpd.
Point Thomson
ExxonMobil’s Point Thomson gas-condensate field is associated with proposed North Slope major gas sales. If full-scale gas sales move ahead, condensate production from the field’s challenging over pressured reservoir could peak at 70,000 bpd. One option that is part of a settlement agreement with the state for the Point Thomson development is to blow down the field reservoir by transferring gas into the Prudhoe Bay field, thus maximizing Point Thomson condensate production while also increasing the Prudhoe Bay reservoir pressure. But, while this would increase Prudhoe Bay oil production until there is a gas export line from the North Slope, this arrangement could be commercially complex, Decker suggested.
For its Smith Bay find, Caelus has estimated the possibility of production rates as high as 200,000 bpd. However, this is a very large number and the company needs to drill more wells to evaluate the find, Decker said, commenting that even the one well that the company plans for 2018 would not be sufficient to prove out the whole project, given the many different reservoir sands involved.
One wildcard that has sat on the periphery of North Slope production for many years is the cold, thick, heavy oil in multiple accumulations in the shallow Ugnu formation that straddles several oil and gas units in the central North Slope. While remaining an unsolved development challenge, the Ugnu holds tens of billions of barrels of oil in place.
Looking at the number of development projects and potential projects on the North Slope, coupled with recent political developments, Decker expressed some optimism over the future of the industry in the region.
“It’s a very interesting time on the North Slope, a very exciting time, even though with low oil prices we have seen a number of projects that we hoped to see in production being deferred,” he said.
