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An optimistic outlook
ConocoPhillips ups GMT-2 forecast; moves ahead on Willow, further exploration
Alan Bailey Petroleum News
In a highly upbeat presentation to a joint meeting of the Alaska House and Senate Resources committees on Sept. 10, Scott Jepsen, ConocoPhillips Alaska vice president of external affairs and transportation, overviewed his company’s current exploration and development plans in Alaska, and the resulting major uptick in the company’s expectations for its future Alaska oil production.
Increased production estimate Jepsen said that his company has upped the estimated peak production for its Greater Mooses Tooth 2 development in the northeastern National Petroleum Reserve-Alaska from 30,000 barrels of oil per day to 38,000 bpd. The federal Bureau of Land Management has published a final environmental impact statement for the project, with a record of decision anticipated in October. That could lead to a final investment decision for the project later this year, Jepsen said.
Meanwhile the Greater Mooses Tooth 1 development is moving ahead, with first oil anticipated by the end of the year. Peak production is expected to run at about 30,000 bpd.
The GMT-1 development is expected to cost a little under $1 billion. GMT-2, with more wells required but with higher expected production rates, will likely cost about $1.5 billion.
The environmental impact statement scoping process is underway for ConocoPhillips’ proposed major Willow development, in the Bear Tooth unit, to the west of Greater Mooses Tooth. That development could result in peak production of some 100,000 bpd, with first oil around 2024 to 2025, ConocoPhillips has indicated. Initial development of Willow will likely cost $2 billion to $3 billion, with a further $2 billion to $3 billion required for full field development.
Exploration and appraisal this winter Jepsen said that, following a particularly successful exploration drilling program last winter, ConocoPhillips plans an aggressive two-rig exploration and appraisal drilling program for the coming winter. The company has used seismic surveying to identify a patchwork of exploration targets in its western North Slope leases, including in the northeastern NPR-A. Currently 75 percent of those targets remain untested.
The coming winter’s plan involves the drilling of six to eight wells.
Two of those wells would be drilled by the end of the year, testing prospects reachable from existing oil field well pads. One of these is the Cairn prospect in the southwestern corner of the Kuparuk River unit. The other involves the Putu prospect, near the village of Nuiqsut, in what ConocoPhillips terms the Narwhal trend, to the east of the Colville River. This is the same trend as the Pikka/Horseshoe trend, where Oil Search and its partners are planning the development of a major oil field primarily involving a reservoir in the Nanushuk formation.
Third Putu well During last winter’s exploration drilling season, ConocoPhillips drilled two wells, the Putu 2 and 2A wells, in the Putu prospect. Those wells, which tested successfully for oil, targeted two distinctive seismic amplitude anomalies, Jepsen explained. But there is a third anomaly, immediately west of the two tested anomalies - the plan for later this year is to drill into this third anomaly from the CD-4 pad in the Colville Delta unit, Jepsen said.
The focus of the remainder of the coming winter’s drilling will be Willow - ConocoPhillips wants to drill some horizontal wells, to better understand the potential productivity from the field, and some vertical wells to test inter-well communication, Jepsen said. The company wants to further delineate the field and to conduct further well tests. Exactly how much will be done during the winter season will depend on how fast the drilling projects proceed and on the weather conditions, Jepsen said.
In the Narwhal trend, ConocoPhillips experienced success last winter in finding oil in two zones at its Stony Hill well, in addition to the Putu discoveries. But the Stony Hill and Putu discoveries require additional appraisal drilling and additional analysis, Jepsen said. Putu has the advantage of being situated inside the Colville River unit, somewhat closer to existing facilities than Stony Hill, Jepsen remarked.
Looking further ahead, from 2020 onwards, ConocoPhillips anticipates drilling into that remaining 75 percent of its North Slope prospects that have not yet been tested, Jepsen said.
Dramatic change in outlook Jepsen’s comments about ConocoPhillips’ upcoming plans came within the context of a dramatic change in the company’s outlook for its future Alaska oil production. As recently as 2013 the company was forecasting a continuing decline rate of 6 to 8 percent per year in its oil output from its North Slope operations. But now the company anticipates a complete reversal of that situation, with production in 2028 expected to be some 100,000 bpd above where it is now, Jepsen said.
And that comes within a context of new oil production from other companies operating on the North Slope, in what Jepsen characterized as a North Slope renaissance. For example, Oil Search and its partners are planning a major development in the Pikka prospect, Hilcorp is planning the Liberty development in the Beaufort Sea, and Brooks Range Petroleum has been moving ahead with its Mustang development. All told, there is the potential for a total of 400,000 bpd of new oil, although that new production would not all start at the same time.
There is also the continuing health of the core North Slope fields: Prudhoe Bay, Kuparuk and Alpine. These fields provide the economies of scale in oil output that make the new developments viable, Jepsen commented.
Jepsen divided ConocoPhillips’ predicted future oil production into four tranches: base production from existing fields; additional production from new developments in those fields; further developments from new field projects; and potential future production resulting from exploration.
Impact of new technologies Base production in the Prudhoe Bay, Kuparuk and Alpine fields has benefited from exciting new technologies, in particular new drilling technologies.
“We have really advanced drilling technology to the point where it’s making a significant difference in terms of what we can develop and how much we can develop,” Jepsen said.
For example, earlier this year ConocoPhillips drilled a 21,000-foot horizontal lateral from a CD-5 well in the Colville River unit, the longest lateral ever drilled in North America, Jepsen said. It is now possible to steer a well more than 4 miles through a 10- to 15-foot thick reservoir sand, enabling a more than 4-mile exposure to oil bearing rock. By contrast, in the early years of Prudhoe Bay drilling, a directional well might penetrate a reservoir sand at a 45-degree angle, enabling perhaps an exposure to just 21 to 22 feet of oil-bearing rock in a 15-foot thick sand body.
Highly deviated drilling can also reduce the surface footprint of an oilfield development. ConocoPhillips has commissioned a new Doyon Drilling ultra-extended reach rig that can drill out to a distance of more than 37,000 feet, allowing access to 154 square miles of subsurface from a 14-acre drilling pad. The company plans to use this rig to develop its Fiord West prospect, in the northwest corner of the Colville River unit, from the existing CD-2 well pad. Fiord West has presented a development challenge because of its environmentally sensitive location on the Beaufort Sea coast.
Other new developments Other new ConocoPhillips developments include expansion of operations at the CD-5 pad in the Colville Delta unit, GMT-1, GMT-2, and NE West Sak or NEWS in the Kuparuk River unit. The company is also considering extending its West Sak development into an area it refers to as Eastern NEWS, Jepsen said.
Also, in terms of oil from new development, there is the Willow project. As previously reported in Petroleum News, ConocoPhillips has prepared a master plan for that project, involving the development of up to five drill sites hooked into a central processing facility for the field. Modules for the development would be delivered by sealift via an artificial island in the nearshore waters of the Beaufort Sea.
Another new technology, ConocoPhillips’ compressed seismic imaging technique, has enabled the company to increase its resource estimate for Willow from 400 million to 750 million barrels of oil. The new seismic technique enables seismic data to be gathered four times faster than previously and enables the production of better seismic images, Jepsen said.
Jepsen said ConocoPhillips anticipates Willow production involving a technique referred to as MWAG, the alternating injection of water and miscible injectant into the reservoir. The injection of water would require seawater from the Kuparuk seawater treatment plant, probably delivered by pipeline from Kuparuk Central Processing Facility 2, Jepsen said.
Oil from a discovery in the West Willow No. 1 exploration well, also drilled last winter, could tie into the Willow facilities at some stage in the future. But that discovery requires further testing and delineation, Jepsen said.
A combination of factors Jepsen attributed the transformation of ConocoPhillips’ outlook for its North Slope oil production to a combination of technical innovation, a reduced cost of supply, and a competitive tax environment under the provisions of tax legislation, Senate Bill 21.
Technical innovation, including the advances in drilling techniques, has helped the company target more resources in existing fields, as well as improving the viability of new developments. To manage costs, following the oil price crash of 2014, the company has taken a hard look at how to do things better, bringing its Alaska cost profile down to be competitive with other components of the company’s portfolio, Jepsen said.
Jepsen particularly cautioned that Alaska’s fiscal environment needs to remain competitive with other oil producing regions - the current fiscal framework under SB 21 keeps Alaska in the game, he said. He also expressed concern about the upcoming ballot on a proposed new anadromous fish habitat protection law. Uncertainty and potential litigation associated with this measure could become a big drag on development, he said.
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