Explorers 2015: Great Bear returning to exploration drilling

A need to bolster existing knowledge of its leases led the company to conduct two years of intense fieldwork

Eric Lidji

For Petroleum News

After several seasons of fieldwork and evaluations for its North Slope exploration program, Great Bear Petroleum Operating LLC returned to drilling wells this year.

In late 2014, the Alaska-based independent permitted a three-well exploration program along the Dalton Highway, its first drilling activity since drilling a pair of wells in 2012.

The company had spent the interim evaluating well results and conducting fieldwork.

This year, the program targeted both conventional and unconventional accumulations simultaneously. While Great Bear remains committed to its long-term goal of launching a source rock development program in Alaska, that goal is complex. It would require the company to adapt still-evolving Lower 48 development techniques to the unique environment of the North Slope. A conventional discovery would provide cash flow in the near term and would allow the company to start building infrastructure on its leases.

The Great Bear program sits close to existing infrastructure, which has allowed the company to continue working after most companies have packed up their supplies for the winter. As a result, the program was unfinished when The Explorers went to press.

In a lease plan of operations submitted to the state in October 2014, Great Bear detailed plans to use Nabors rig 106AC to drill the Alkaid No. 1, Phecda No. 1 and Talitha No. 1 wells just west of the Dalton Highway and trans-Alaska oil pipeline corridor. The proposed locations were southwest of the two vertical wells Great Bear drilled in 2012.

Great Bear began drilling the Alkaid No. 1 well in mid-February, which was later than the company had intended to start the program. As such, the company said it would likely drill only two wells this season, rather than three. Through March, the company had yet to receive an Alaska Oil and Gas Conservation Commission permit for the second well.

Coming on strong

As its introduction to Alaska, the company took more than 500,000 acres across a broad swath of the central North Slope, just south of the Prudhoe Bay and Kuparuk River units.

The size of the leasehold and the location of the leases suggested the company was pursuing something unique. The five principals of Great Bear formed the company to develop the source rock potential of the North Slope. Great Bear President and COO Ed Duncan had met Vice President of New Ventures Bob Rosenthal while working at the BP-predecessor Sohio during the early 1980s and gained insights about North Slope petroleum systems. “We believe that there are expansive new plays and we’ve captured a very significant piece of what we came here to do,” Duncan said in October 2010.

While most North Slope independents have been pursuing relatively large conventional reservoirs passed over by the major companies, Great Bear saw an opportunity to develop the source rocks responsible for the giant oil fields of the North Slope - just as other industrious independents were doing with the Eagle Ford shale formation of south Texas.

A conventional reservoir is usually the result of oil and natural gas migrating through porous rocks until they reach a seal. Exploration companies use surface geology, previous wells and seismic surveys to make informed guesses about where to drill wells. Some wells are dry holes, some encounter non-commercial volumes and some lead to big finds.

An unconventional exploration program, such as the one Great Bear is undertaking, targets the source of the oil in those reservoirs. The North Slope contains three stacked source rock intervals at depths between 8,000 and 13,000 feet. They are, from deepest to shallowest, the Shublik, the Kingak and the HRZ/Hue shale system. The Prudhoe Bay and Kuparuk River oil fields are believed to have migrated from these source rocks.

Instead of drilling wildcat wells in search of a “gusher,” Great Bear is trying to devise an economic way to tackle a massive resource. That means searching for “sweet spots” where the slow geologic process of making hydrocarbons, known as “thermal maturity,” has converted organic materials into oil but not yet converted the oil into natural gas.

If successful, the Great Bear program - and similar efforts by other companies, particularly Royale Energy Inc. - would bring a new development model to Alaska.

Testifying before state lawmakers in February 2011, Duncan presented “a factory type drilling” model, where development wells would be drilled and completed quickly.

To illustrate this model, Duncan said Great Bear wanted to use 20 rigs to drill some 200 wells each year over three 15-year phases targeting two of the three source rock formations. Those wells would produce 200,000 barrels per day by 2020, 350,000 bpd by 2035, 450,000 bpd by 2041 and peak at 600,000 bpd in 2056 before dropping to a sustained long-term production rate of 450,000 barrels per day out as far as 2074. This system would require some $2 billion each year in capital, Duncan told lawmakers.

In terms of rigs operating, wells drilled, oil produced and capital spent, those figures would make the Great Bear program the largest development on the North Slope.

At the time, then-Gov. Sean Parnell had set an ambitious goal of increasing throughput on the trans-Alaska oil pipeline to 1 million barrels per day within a decade. When policymakers asked whether Great Bear could single-handedly produce 1 million barrels per day from its leases by drilling as many as 1,000 wells each year, Duncan said, “Two hundred wells a year is a lot, but it’s scalable. If the capital is there, if the development infrastructure is there, and the ability to move that produced oil into the pipeline is there - all of those are challenges - but if all of those are there, it can be done. There’s nothing that we’re waiting for from a technology perspective. The ability to drill and complete these wells is proven. It will be better a year from now than it is today.”

Slowing down

Eager to start, the company figured it could drill two test wells in the winter of 2010 and 2011 by starting the permitting process while the state completed its lease review. But by January 2011, logistics appeared to be dictating a slower timeline. The state had said it expected to issue the leases in April or May. Great Bear pushed its plans to late 2011.

Once Great Bear discovered it could drill year round, its ambitiousness accelerated. The company decided to drill as many as three vertical wells between October and December 2011 and return the following spring to drill a horizontal sidetrack from each vertical.

A September 2011 lease plan of operation outlined a yearlong program to determine a “proof of concept” for commercial source rock development. The plan proposed six drill sites along a 15-mile industrial area along the Dalton Highway. The company named the proposed wells after the stars in the Ursa Major (or “Great Bear”) constellation: Alcor No. 1, Merak No. 1, Mizar No. 1, Megrez No. 1, Dubhe No. 1 and Alioth No. 1.

By November 2011, Great Bear had announced a technical partnership with the oil field services company Halliburton Co. With a successful proof of concept program, Duncan said, the companies could initiate a pilot development by late 2012. By January 2012, Great Bear had obtained preliminary permits but still needed a rig. The company eventually scaled back its plans to a three well program for the second half of 2012.

Once drilling began, Great Bear became somewhat tight-lipped about the results.

By July 2012, the Alcor No.1 well had almost reached the HRZ, and crews were preparing to take core samples. At a shale conference, in August 2012, Duncan said, “The results to date are within our expected outcome.” Looking ahead, he added, “We expect to be testing and producing and … selling produced hydrocarbons potentially by the end of the year, and certainly early next year.” With good results, Duncan believed Great Bear could produce at least 100,000 barrels per day in five years. By September, when the company was drilling the Merak No. 1 well, he said, “I can tell you with absolute confidence that where we thought we would find oil in these source rocks, we found oil.”

Great Bear suspended its drilling operations for the season in December 2012, having drilled the vertical sections of two wells and conducted a small 3-D seismic survey around the well locations. At the time, Duncan expressed confidence in the initial results of the program. “We have drilled through all of our targeted source rock units,” he said. “We’ve proven those (to be) present at the depths predicted and in the state of thermal stress or thermal maturity, certainly within the range of expected outcomes.”

Collecting data

The same held true that fall. “We are right on the original timeline. So our hope would be that you’ll see us sanction a full-field development in the next year or so,” Duncan said.

Great Bear Petroleum commissioned 3-D seismic surveys over various portions of its large leasehold in 2012, 2013 and 2014 in search determining “sweet spots” for drilling and said it expected to commission another survey over the area this year. The company also commissioned two LIDAR, or Light Detection And Ranging, surveys, which use laser beams to precisely map surface topography, which speeds the pace of planning.

One of the reasons Great Bear took a two-year hiatus from drilling to conduct field work is to bolster a somewhat flimsy data set for the area. Compared to unconventional plays in the Lower 48, the region where Great Bear is exploring is relatively underdeveloped, which means there is little previous information upon which to build an drilling program, according to Vice President of External Affairs and Deputy General Counsel Pat Galvin.

The program this year used the information from those surveys to choose locations. The Talitha No. 1 well, for instance, was discovered from the 2013 survey. It required the company to acquire an additional lease, which was only recently available at auction.

Asked how oil prices would impact the program, Galvin said investors are willing to risk funding exploration wells now in the hopes of prices rising in the future. Development is another story. With a breakeven price of around $50 per barrel, Great Bear would need to look at its economics if the prices stay at their lower level for an extended period of time.