The vast majority of oil and gas exploration in Alaska takes place on the North Slope and in the Cook Inlet basin, but Doyon Ltd. has been searching in the middle of the state.
The Alaska Native corporation has spent more than a decade collecting information about underexplored and even some unexplored areas of the Interior. Doyon has primarily been exploring the Nenana Basin, but is also eyeing the Yukon Flats area.
Exploration companies have long sensed many advantages to the Interior.
A commercial discovery in the center of the state could take advantage of the existing road and rail system, could avoid some of the harsher aspects of Arctic exploration and development, and would be several hundred miles closer to markets in the Lower 48.
Unocal drilled the Nenana No. 1 to a total depth of 3,062 feet in 1962 and ARCO drilled the Totek Hills No. 1 to a total depth of 3,590 feet in 1984, but neither led to development. “Except for minor amounts of gas associated with coal beds no hydrocarbon shows were observed in the wells,” the Alaska Division of Oil and Gas reported in early 2002. “Reports of oil seeps in the basin are unconfirmed.” Given the considerable quantities of coal in the region, the state expected the basin to be gas-prone.
The Alaska Native Claims Settlement Act of 1971 allotted considerable acreage across the region to Doyon, the Alaska Native corporation for the Interior region. Seeing the opportunities both for revenues and for a cheaper local energy source for the Interior, Doyon took an interest in the possibilities of the region. When industry interest tapered off in the late 1990s, Doyon began pursuing exploration opportunities on its own.
In recent years, Doyon has helped drill two exploration wells in the Nenana basin.
Initial joint venture
In late 2001, Doyon formed a joint venture with the Houston-based independent Andex Resources LLC to explore a section of the Nenana basin through an exploration license.
While most exploration occurs on leases acquired at annual sales, the state exploration license program allows companies to nominate lands for exploration and make specific work commitments over a given period of time. If the exploration is successful, the company can convert the license into traditional leases and continue exploring the area.
At the time, Doyon estimated that the Nenana basin contained 250 million barrels of recoverable oil and between 250 billion and 1 trillion cubic feet of recoverable natural gas, enough to meet the needs of Fairbanks with some potential leftovers for Anchorage.
“When industry explored the basin in the early ’80s, their focus was oil but they knew it was a gas-prone basin and thought there was also a good shot at oil. Andex’s focus is gas,” Andex Resources Executive Vice President Jim Dodson told Petroleum News in August 2001. “We’d be happy if we found oil, but our focus is traditional natural gas.”
The program envisioned applying for an exploration license in early 2001, shooting seismic in the basin in the winter of 2002 and 2003 and drilling as early as 2004.
The Alaska Department of Natural Resources issued a seven-year license to Andex Resources in August 2002. The license covered 482,942 acres in the Nenana basin and required Andex to post bonds and spend at least $2.525 million exploring. The joint venture grew its land position several months later when the Alaska Mental Health Land Trust leased it 9,500 acres adjacent to the exploration license area in January 2003.
In January 2002, Andex told lawmakers that it expected to spend $24 million on the program, including $18 million to drill three exploration wells and $6 million for seismic.
Andex Resources came to Alaska, in part, because of a 10-year natural gas exploration incentive program approved in 1994. The program allowed the state to issue extensive tax credits in return for access to geophysical information, but the program had yet to issue any credits by the time Doyon and Andex came onto the scene. The data sharing provision kept Anadarko Petroleum Corp. from accepting credits for National Petroleum Reserve-Alaska exploration. The state rejected a second application from a different company because it already had geophysical information for the proposed region.
During the 2002 legislative session, Andex Resources and Doyon advocated for the state to continue the program beyond 2004 to ensure they would be able to drill a well under the program. Seeing the benefit, lawmakers extended the credits until 2007. The program eventually gave way to the exploration credits in Alaska’s Clear and Equitable Share.
“Although the Nenana basin is a good place to look for gas, the exploration risks are still very high. The credits help temper those risks, including the ‘Alaska factor’ of high costs, compared to opportunities in the Lower 48. It would be a shame if this program is allowed to expire just as it begins to fulfill its initial promise,” Doyon Vice President of Lands and Natural Resources Jim Mery told Petroleum News in February 2002.
Growing optimism
Andex began searching for joint venture partners to help shoulder the cost.
In December 2004, Andex and Doyon announced a partnership with the local Usibelli Coal Mine affiliate Usibelli Energy and Arctic Slope Regional Corp., which is the Alaska Native corporation for the North Slope region. The joint venture planned to drill a well in early 2006. With a commercial discovery, the companies believed they could move into development by early 2007, with an eye toward building a pipeline to Fairbanks in 2008.
PGS Onshore began conducting a $3 million 2-D seismic campaign over some 218 square miles of the region on behalf of Andex in early 2005. Andex planned to spend another $3 million acquiring seismic information from previous surveys in the region.
Even before the seismic program was complete, Andex was growing optimistic about the region. Measuring just the thermogenic gas, Andex believed the basin could contain 3 trillion cubic feet of recoverable reserves and 10 tcf of total reserves. “That number was based on some very, very conservative inputs,” Andex Vice President of Exploration for the Northern Region Bob Mason told Petroleum News in March 2005. In addition to the thermogenic supplies, he said, “We know that there’s biogenic gas in this basin.”
The U.S. Geological Survey had estimated technically recoverably reserves for central Alaska at 500 billion to 7.3 trillion cubic feet with a mean of 2.8 tcf.
Unlike the early shallow wells, the joint venture planned to drill to 10,000 feet or deeper. “I want to take a look at structures that preserve a very thick layer for my initial well,” Mason said. “We are evaluating structures deeper in the basin where we don’t have to worry about flushing, we don’t have to worry about section missing - that sort of thing.”
Delays and more delays
Andex delayed the program in early 2006, saying it would wait for a resolution of the proposed Petroleum Profits Tax debate before deciding whether to explore. When the tax became law in August 2006, the joint venture delayed its plans for early 2007, too.
The joint venture felt squeezed. The new fiscal system taxed Cook Inlet production at a lower level than North Slope production, but the provision excluded the Interior. And a proposed fiscal contract for North Slope natural gas also excluded the Interior basins.
When the state revisited the fiscal system in late 2007 to pass ACES, lawmakers included a provision that taxed any gas used within Alaska at the lower Cook Inlet level. The provision underpinned efforts at the time to build a “bullet line” connecting a northern gas supply to Southcentral communities to offset declining Cook Inlet gas production.
The changes ultimately proved untenable to Andex, though.
The operator pulled out of the joint venture in late 2007, leaving Doyon and its two partners to find another independent willing to grab a 50 percent stake in the program.
A new partner
Even so, Doyon was aiming to drill in early 2009. The timeline, though, pushed against the September 2009 deadline of the exploration license. In late 2008, the state agreed to give the three-company joint venture until September 2012 to operate under its license.
Around the same time, the Denver-based independent Babcock & Brown Energy joined the joint venture as operator and announced plans to drill at least one 10,500-foot well in the summer of 2009. Babcock & Brown subsequently changed its name to Rampart Energy Co. A fifth company, Cedar Creek Oil and Gas Co., also joined the joint venture.
The summer drilling schedule made it easier to find a rig. The joint venture was able to schedule time with the Arctic Wolf No. 2 after North Slope winter exploration finished.
As summer approached, Rampart told lawmakers that a dry hole would be disappointing and a producing well would be exciting, but neither would dictate the fate of the project.
“Finding that we have an active petroleum system, meaning oil and/or natural gas being generated, would be a significant success in this first well,” said Jim Dodson, the former Andex Resources executive who returned to Alaska as an executive for Rampart Energy.
The joint venture was now estimating that the basin contained 1 tcf to 6 tcf of gas, with the Nunivak prospect containing a median estimate of 60 billion cubic feet. “It could be smaller; it could be larger. We just don’t know,” Mery told Petroleum News in August 2009, adding, “We just felt that this was the best first place to look.”
The joint venture drilled the roughly $15 million Nunivak No. 1 well about three miles west of the town of Nenana in July and August 2009 to a total depth of 11,100 feet.
The well failed to find commercial volumes of gas, but information collected during the drilling suggested that the basin was much deeper and cooler than previously expected and offered tantalizing clues about high resource potential in the basin, Doyon said.
Going it alone
The information convinced Doyon to continue exploring the basin.
Eager for a wider understanding of its large license area, Doyon announced planned to conduct a seismic campaign focused on the northern end of the Nenana basin during the winter of 2010 and 2011. “Other than a few gravity measurements at the northern end of the basin, there really isn’t any exploration,” Mery told Petroleum News in April 2010.
The announcement came as Interior utilities started looking to truck liquefied natural gas from the North Slope and as lawmakers discussed plans to unite the Railbelt utilities.
Those uncertainties led Doyon to hold off on its Nenana plans, as did the need to find new investors. The joint venture partners had lost interest after the Nunivak No. 1 well.
Ultimately, Doyon decided to go it alone. The company conducted the 2-D seismic survey in the northern end of the basin in the winter of 2011 and 2012, and announced plans to drill the Nunivak No. 2 exploration well some seven miles west of its first well.
The venture got a boost in early 2012 when lawmakers approved a “frontier basins” incentive program, including tax credits for exploration and lower production taxes.
With the end of its exploration license fast approaching, Doyon began converting much of the license area to leases starting in mid-2012. In the summer of 2013, the company drilled the Nunivak No. 2 well to a total depth 8,667 feet using the Nabors rig 105.
Like the first well, the second encountered geologic features that suggested an oil and gas system in the basin, but failed to find commercial volumes of oil or natural gas.
“The Nunivak No. 2 drill program was only the second deep test of this basin,” Doyon CEO Aaron Schutt said in a November 2013 announcement. “Despite the disappointment of a non-commercial effort, other results from the well clearly indicate the potential for significant commercial discoveries of oil and gas and we consider it a success. Follow-on studies are under way which will assist us in the development of our forward program.”
The results that indicated a reason for optimism included “excellent potential reservoirs, competent top seals, source rocks actively expelling wet gases and similar shows of likely migrated gas which are indicative of an oil and/or gas-condensate system,” Doyon said.
Now, Doyon is permitting a seismic survey scheduled for the winter of 2014 and 2015.
In the Yukon Flats
Throughout all this, Doyon has also been sniffing around the Yukon Flats.
Originally, the U.S. Fish and Wildlife Service and Doyon proposed to swap resource-rich acreage in the Yukon Flats National Wildlife Refuge with nearby Doyon acreage, but the proposal proved controversial and ended in 2010 after more than five years of wrangling.
After the setback, Doyon reassessed its existing acreage using a 2010 seismic survey and existing geological and geophysical data, and found the region to be much more prospective than originally thought - potentially an Alpine-sized accumulation. “So we’re kind of happy that land exchange didn’t happen,” Schutt said in September 2013.
SAExploration conducted a 3-D seismic survey in the Stevens Village region of the Yukon Flats in the winter of 2012 and 2013, on behalf of Doyon. As of December 2013, Doyon was studying the results of the survey to determine potential drilling locations.
A 2004 USGS estimate of the 13,500 square mile lowland between the trans-Alaska oil pipeline and the Canadian border estimated mean technically recoverable resources of 173 million barrels of oil, 127 million barrels of natural gas liquids and 5.5 tcf of natural gas, which exceeded earlier estimated for the entire central Alaska region.
