North Slope Explorers
Resurgence of exploration
Repsol’s Q-5 appraisal well in the Qugruk prospect on the North Slope.
Photo by Judy Patrick, Courtesy of Repsol
Alaska’s North Slope is seeing a resurgence of activity. New companies and new projects—along with the maintenance and redevelopment of existing fields—have all played a role in the Slope’s recent growth.
Even with a steady decline of oil throughput in the Trans Alaska Pipeline System (TAPS) since 1988, employment in the oil and gas industry has fluctuated, but has seen overall growth over the years, according to numbers from the US Department of Revenue and Alaska Department of Labor and Workforce Development (ADLWD).
High oil prices are the best explanation for the past decade’s employment growth, ADLWD said in their June 2013 issue of Alaska Trends. And went on to say a rise in production jobs amid lower output is because “deeper and harder-to-reach oil reserves require greater efforts to extract.”
Many oil companies have changed their attitude towards oil exploration on the North Slope since oil tax reform in Alaska, and are now delving into the economic possibilities.
NordAq Energy is exploring oil and gas reserves in the National Petroleum Reserve-Alaska (NPR-A) as well as offshore locations nearby in Smith Bay.
Australian independent, Linc Energy, is drilling test wells at Umiat, more than seventy miles southwest of the major North Slope fields, to determine whether or not oil deposits discovered by US agencies are commercially viable.
Brooks Range Petroleum completed a gravel access road and production pad to begin production for its Mustang field, adjacent to the Kuparuk River Unit, by the end of 2014.
Exploration Priority One
Repsol, a Spanish multinational oil and gas company based in Madrid, Spain is relatively new to the North Slope, but is one of the most active companies exploring. Repsol started in 2011, with Armstrong Oil and Gas affiliate 70 & 148, LLC, by drilling two exploration wells at the Colville River delta in the 2011 to 2012 season, then three the next season. Repsol will continue oil exploration this year by drilling two appraisal wells designated as Q-5 and Q-7 in the Qugruk area, fifteen miles west of the Kuparuk River field. Repsol is also set to drill one exploration well and acquire 3D seismic information in the area designated Tuttu 1, southeast of Kuparuk.
“We won’t know whether the discovery is commercial until after we analyze this year’s data,” says Alaska Project Manager for Repsol, Bill Hardman.
Repsol’s operations this year had as many as five hundred people in the field, including drillers, seismic contractors, industrial hygienists, heavy equipment operators, caterers, housekeeping, and subsistence representatives, Hardman says.
Unique to exploration, Repsol says the seasonal nature of the process stands out.
“In order to protect the sensitive environment, we wait until the tundra is frozen over and we perform almost all of our work on ice roads and ice pads,” Hardman says. “We even construct an airstrip out of ice.”
Conducting the exploratory phase in this manner is effective at protecting the environment, but Repsol says it creates planning and logistical challenges. There is most often not a set start and end date for operations, companies can only plan and ready crews until weather allows.
“Whenever the weather starts warming up and the ice starts deteriorating, we must be ready to rig down and move out—regardless of whether or not we’ve completed our objectives,” Hardman says. “However, once the exploration and appraisal phase is complete, if a development is justified, then permanent infrastructure is built and year-round operations begin.”
One independent company that does not need to worry about frozen surface operations is Great Bear Petroleum. The small independent oil and gas company leased nearly five-hundred thousand acres of land from the state in 2010 with hopes to find shale-based oil at a commercial scale. Most of the leases cover lands south of the Prudhoe Bay oilfield, near and along the Dalton Highway and TAPS.
Great Bear began operations in 2012 by drilling two stratigraphic test wells along the Dalton Highway, nearly twenty miles south of Pump Station One of the Trans-Alaska Pipeline. Fifty percent of Great Bear’s leasehold is within fifteen miles of the pipeline. And although the science must be there, says Great Bear Petroleum President and CEO Ed Duncan, it has reaped the benefits of drilling during the summer.
Great Bear says the data collection from the drill sites goes in parallel of collecting 3D seismic information, which started 2012 and on through early 2014. Great Bear collected a total of more than four hundred square miles of data.
“Companies that have exploration-led strategies are handcuffed,” Duncan says. “It’s almost impossible to make good business judgments without sound science and engineering, and 3D [seismic data] is a precursor for us to make good decisions.”
Great Bear is pursuing unconventional oil on the North Slope, and with its special recovery process, its engineers are working out ways to recover oil from the shale rocks within its leasehold.
“Part of the puzzle is that these source rocks could have generated a lot more oil, and it hasn’t been found on the North Slope fields, so the question is ‘where did it go?’ Much of it was trapped on the way up there, or trapped within the local source rock [unconventional reservoirs],” says Great Bear’s Exploration Manager Bret Chambers. “So there are billions of barrels of oil that were generated, and a lot of that has never been found.”
Duncan says the company is currently working tirelessly on its 3D data to build exploration inventory and internally debate critical risks in order to compile a list of prospects by the third quarter of 2014.
“I can imagine from the outside, the process looks slow and tedious, but from the inside, this is a pressure cooker,” Duncan says.
Worker preparing to raise a rig tank at Repsol’s Qugruk prospect on the North Slope.
Photo by Judy Patrick, Courtesy of Repsol
Although BP does not conduct exploratory drilling, it plans to explore through technology. It knows the potential of oil and gas on Prudhoe Bay, and is focused on expanding its possibilities.
“Prudhoe Bay is just a resource rich opportunity that it has not been fully developed yet,” says BP Alaska Spokesperson Dawn Patience.
Before tax reform was put into place, BP added two drill rigs this year, which it says accounts for increased activity on the North Slope, but planning for these rigs started in 2006—prior to Alaska’s Clear and Equitable Share tax law, or ACES. BP expects to complete production-enhancing well work on one hundred more wells than last year. “There’s a lot of work that goes toward optimizing production, and well work is a key part of that,” Patience says.
Looking for future potential, BP plans to gather 190 square miles of 3D seismic data this summer in North Prudhoe Bay to support land-based oilfield development. BP says preliminary data shows about 55 million barrels of recoverable resources, with the potential of 30 new wells.
“Prudhoe Bay has great opportunity. We always say the best place to find oil is on or near an oil field. It just has all sorts of resource opportunity yet to be developed,” Patience says.
In addition to the seismic data and two new rigs this year, BP plans to add a drilling rig in 2015 and again in 2016 to Prudhoe Bay, a $1 billion investment over five years. BP says the two new rigs will account for two hundred new jobs and about thirty to forty additional wells drilled each year.
BP’s major project, in accordance with fellow owners of the Prudhoe Bay Unit [ConocoPhillips, ExxonMobil, and Chevron] is the West End Prudhoe Bay development project. The assessment stage is estimated to cost about $3 billion in capital investment. The project consists of expanding two existing oilfield pads by adding facilities and creating new wells, and constructing one new drill site altogether. BP says the new development will call for increased capacity of existing infrastructure and pipelines.
“As you move west [on Prudhoe Bay], the oil has become a partly viscous oil which tends to be thicker and heavier, a bit like maple syrup, with sand particles in it,” Patience says. “So part of the work is infrastructure and pipeline upgrades to be able to handle the volumes of viscous oil, as well as volumes of increased water and gas capacity at the facility.”
ConocoPhillips is also looking to expand existing operations west, and expand its reach.
ConocoPhillips is currently laying gravel for Drill Site 2-S, known as the Shark Tooth project. Operations began with drilling an appraisal well in winter 2012 to gain more reservoir information. Located on the southwest edge of the Kuparuk oilfield, this project will target an undeveloped section of the Kuparuk formation.
“The results looked good, and later this year we’ll go back to our partners and our board to seek approval to fully develop it with wells, roads, facilities, and bring it on stream,” says Scott Jespen, vice president of external affairs at ConocoPhillips Alaska. “And if we get that funding, we would probably have first oil in 2015, and producing about eight thousand barrels a day. We’re estimating about $600 million to develop it, and somewhere in the range of 200 to 250 people working during the construction period.”
Production for Drill Site 2-S will be processed through the Kuparuk River Unit facilities.
Next on the horizon for ConocoPhillips is to pursue development in the Greater Mooses Tooth Unit in the National Petroleum Reserve-Alaska, thirty miles west of Kuparuk. ConocoPhillips was in the regulatory and permitting phase as of April, and continues to progress the engineering for final project approval by late 2014. ConocoPhillips says the Greater Mooses Tooth One (GMT-1) will be connected to CD-5, another satellite site connected to the Alpine oilfield in the Colville River Unit. CD-5 is currently undergoing engineering and material acquisition, and oil from both GMT-1 and CD-5 will be processed through existing Alpine facilities, and connected by a 7.8 mile road and pipeline.
ConocoPhillips drilled two exploration wells in NPR-A this winter: Rendezvous 3 and Flat Top 1.
Photo by Judy Patrick, Courtesy of ConocoPhillips Alaska Inc.
More Alaska Production Act
For projects in the exploration phase, the shift to development lies heavily on whether or not Senate Bill 21, the More Alaska Production Act, is repealed this August.
Many companies say if Senate Bill 21 is repealed, it will negatively affect their investment decisions.
“The funding decision for [the exploratory and developmental] investments is going to be heavily influenced by the results of the referendum on [oil] tax reform this August,” says Jepsen. “If the tax reform gets repealed, it’s going to have a very adverse impact on the corporation’s view on investment.”
BP attributes the decision to pursue many of its development projects to Senate Bill 21.
“After oil tax reform was passed and signed into law, it aligned the Prudhoe Bay working interest owners behind these projects and opportunities, in particular the West End and the two rigs set for 2015 and 2016,” Patience says.
Even Repsol says Senate Bill 21 plays a role after discovery. “Besides the size of the discovery, the other critical variable will be the outcome of Ballot Measure One,” Hardman says. “The oil tax structure could mean the difference between a ‘go’ and a ‘no go’ decision on a development project.”
Russ Slaten is the Associate Editor at Alaska Business Monthly.