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Vol. 19, No. 29 Week of July 20, 2014
Providing coverage of Alaska and northern Canada's oil and gas industry

Explorers 2014: Great Bear still pursuing source rock development

The Alaska company sees great potential in the geology just south of the giant North Slope oil fields

Eric Lidji

For Petroleum News

The public policy discussion around Great Bear Petroleum LLC describes the company as the future of the North Slope, but it may be more accurate to describe it as the past.

The local independent and its investors want to develop source rocks, the ancient geologic formations believed to have generated the massive North Slope oil fields.

If successful, Great Bear could usher a new era of development in Alaska. Source rocks could contain enough oil to fuel the Alaska economy for decades, but developing those resources will require the state and the industry to adapt many long-standing practices.

‘Very bullish’

Great Bear came growling into Alaska in October 2010, when it took more than 500,000 acres with more than $8 million in apparent high bids at the North Slope lease sale.

The first clue that Great Bear was up to something new was the location of its bids. The company took a broad swath of acreage across the central North Slope, just south of the Prudhoe Bay and Kuparuk River units. While exploration companies have sniffed around those regions for decades, Great Bear President and COO Ed Duncan told Petroleum News in October 2010 that he believed the leasehold contained “expansive new plays.”

While Duncan thought the industry as a whole had a “general malaise” about the North Slope, he said Great Bear had “almost polar opposite positions, it appears.” The results of the lease sale reinforced the distinction: Great Bear took every lease on which it bid, and took 92 percent of all the leases bid on during the sale. “We’re very bullish,” he said.

The five principals of Great Bear formed the company to chase the source rock potential of the North Slope. Duncan and Vice President of New Ventures Bob Rosenthal met 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,” he said. The idea was to develop the source rock, just as producers had done with the Eagle Ford shale of south Texas.

In a tantalizing statement for policymakers concerned about production, Duncan said that “through the success of our program and the exploitation of the North Slope’s resource plays that we’re going to establish long-term, growing and stable production in the state.”

Program different

From the start, the Great Bear program differed greatly from traditional North Slope exploration. A conventional reservoir is the result of oil and natural gas migrating into porous rocks trapped by a seal. For decades, exploration companies have used surface geology and seismic information to make informed guesses about where to drill wildcat wells. Sometimes, they drilled dry holes and sometimes they found massive oil fields.

While hopeful about conventional resources, Great Bear wanted more. “It’s going to be unlucky if we don’t have conventional potential in that lease position, but that’s not why we’re here,” Duncan said. “We’re not here exploring for these conventional resources.”

In a source rock “reservoir,” the oil or natural gas is contained within the rock itself.

The North Slope is home to three stacked source rock intervals: the Shublik, the Kingak and the HRZ/Hue shale system, from deepest to shallowest. These source rocks exist some 8,000 to 13,000 feet underground, in the area south of Prudhoe Bay and Kuparuk.

Existing seismic and well data had already confirmed the oil-bearing source rock south of those fields, though. Great Bear just needed to figure out how to produce it. As such, Great Bear said it could start drilling without conducting prospect-specific 3-D seismic.

Eager to start, Great Bear planned to drill two test wells in the winter of 2010 and 2011. “We’ll begin the permitting process almost immediately,” Duncan said in late October 2010. “We’ll let that run in parallel with the lease review. … As soon as the leasehold is cleared we would be in a position to drill, if the clearance occurs early enough.”

Four core-holes planned

By January 2011, logistics seemed to demand a slower timeline. With the state saying it expected to issue the leases in May, Great Bear pushed its drilling plans to late 2011.

Great Bear planned to drill vertical wells into the North Slope source rocks with laterals extending through actual formations and use fracturing stimulation to extract the oil. To start, Great Bear envisioned drilling at least four 11,000-foot vertical test wells, or narrow diameter “core-holes” to better determine the rock depths and to collect rock samples.

Among the factors unique to source rock exploration is thermal maturity, which measures the slow geologic process of making hydrocarbons. The maturity must be high enough to turn organic materials into oil, but low enough to keep the oil from becoming natural gas.

With the right test results, Great Bear planned to drill an initial lateral into one of the formations. If it worked, Great Bear said it could produce oil by mid-2012. Using on-site production equipment and its proximity to the road system, Great Bear would be able to truck any oil production to existing infrastructure along the trans-Alaska oil pipeline.

A ‘factory’ model

Given the success of source rock development in the Lower 48, Great Bear turned heads as soon as it announced its intentions for Alaska. But the company really captured the imagination of policy makers when it hypothesized about what the future could hold.

When Duncan testified before lawmakers in February 2011, he envisioned drilling two production tests in early 2012. He described the wells as “full exploration style wells,” but, he said, full development would be unlike anything currently under way in Alaska.

As unconventional plays become understood, he said, “industry tends to move toward a factory type drilling,” where wells can be drilled and completed at a much quicker rate.

To illustrate this “factory” 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.

While the initial startup capital for Great Bear came from friends and family, the full proposal would require some $2 billion each year in capital, Duncan told lawmakers.

When asked if Great Bear could single-handedly produce 1 million barrels per day from its leasehold 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.”

For comparison, only about 1,000 wells have been drilled in the main Prudhoe Bay field since 1968, throughput on the trans-Alaska oil pipeline is currently around 550,000 barrels per day and the state is usually home to between 20 and 30 rigs at any given time.

A paradigm shift

Clearly, the Great Bear model would require major changes in how the oil industry operates in Alaska, which would mean major changes in how the state regulates industry.

Speaking in March 2011, Nabors Alaska Drilling’s Dave Hebert told Petroleum News it would be “no small task by any means, but certainly not impossible” to provide the 20 rigs needed for the program. In November 2011, Great Bear announced it was partnering with the oil field services giant Halliburton Co. on technical aspects of the program.

Testifying before lawmakers in March 2011, Alaska Oil and Gas Conservation Commission Commissioner Cathy Foerster said the existing system of units, participating areas and pool rules may be irrelevant for source rock exploration. What constitutes a pool when the oil is distributed somewhat evenly throughout miles and miles of rock?

Source rock wells drain from a limited area, and so correlative rights are less of a concern than in conventional drilling, according to Foerster. “The only time that unitization might be warranted in this kind of development is if there are economies that could encourage greater ultimate recovery. In other words, stopping competition between checkerboard small leases and having one set of facilities, one gathering system, rather than everybody going out on their own little patch of land and building the whole shebang,” she said.

Year-round exploration

The Great Bear program changed again in the summer of 2011.

Originally, Great Bear had planned a two-phase program. In late 2011 it would drill four 11,000-foot vertical core holes and in early 2012 it would drill two 11,000-foot production test wells, each with at least one 4,000-foot horizontal lateral. Depending on the results, the company planned to drill additional wells in the winter of 2012 and 2013.

When a contractor identified previously used gravel sites along the Dalton Highway, though, Great Bear no longer needed to wait for seasonal tundra openings to begin operations, which meant the company was able to accelerate its plans considerably.

The Alaska Department of Natural Resources issued 99 leases to Great Bear in April 2011. Great Bear 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.

In September 2011, Great Bear filed a lease plan of operation outlining a yearlong program to determine a “proof of concept” for commercially producing oil from source rock. The plan proposed six drill sites along a 15-mile industrial area following the Dalton Highway and the trans-Alaska oil pipeline. The company named its proposed wells after the stars in the Ursa Major constellation, which is also known as Great Bear: Alcor No. 1, Merak No. 1, Mizar No. 1, Megrez No. 1, Dubhe No. 1 and Alioth No. 1.

The corridor was important. If Great Bear moved farther west on its leases, it would reach an area where the preponderance of wetlands shifted permitting dominance from the Alaska Department of Natural Resources to the U.S. Army Corps of Engineers.

While the plan would accommodate six wells with a lateral at each well, Great Bear said told the state it would be unlikely to drill more than four wells, each with one lateral.

By November 2011, when Great Bear announced the Halliburton deal, Duncan said that a successful proof of concept program could yield a pilot development by late 2012.

The pilot program would use a modular processing unit to bring crude oil up to the standards required for the trans-Alaska oil pipeline. The one-year program would give Great Bear “a collection of well production curves for North Slope shale oil development,” which Duncan said would inform Great Bear’s decisions about a full development scheme. “One year from now we’ll be going to pilot development; a year after that we’ll have tight curves in front of us and we’ll be sanctioning then, hopefully, corridor development - that’s the 200 hundred wells a year,” he told lawmakers.

The initial program, though, came during a bumper year for North Slope exploration, which placed a strain on the supply of drilling rigs available for winter activities.

In December 2011, Great Bear offered nearly $3 million in high bids in the North Slope lease sale to bolster its leasehold in the area south of the Kuparuk River unit.

By late January 2012, Great Bear was still looking for a rig, but it had obtained all the preliminary federal, state and local permits needed for a year-round drilling program, and planned to conduct site preparations in March or April with drilling scheduled to begin sometime thereafter, Division of Oil and Gas Director Bill Barron told lawmakers.

By May 2012, as Great Bear was preparing to drill, Duncan presented a more conservative view to lawmakers. While previously outlining plans for 9,000 wells over 45 years, Duncan spoke of the play being “drilled out at a very high rate for at least the next 10 or 15 years, maybe longer” with 200 wells per year for a total of 3,000 wells.

And while remaining optimistic in the ability of technology to solve problems, he acknowledged that the program might determine that Alaska source rock was not yet commercial. “Technology is evolving very, very rapidly,” he said. “I am a great believer that if we put the challenge out to the Halliburtons, the Schlumbergers, the Baker Hughes, the Weatherfords and the others of the world, that it’ll get cracked - the code will get cracked. Whether today, next year, or subsequent, I am a great believer in that.”

Drilling under way in 2012

Great Bear planned a three well program for the second half of 2012.

The original goal was to drill an 11,000-foot vertical well bore at the Alcor No. 1 site, move south to drill a vertical well bore and a horizontal lateral at the Merak No. 1 site and send the rig the north again to complete a horizontal lateral at Alcor No. 1. Great Bear also wanted to drill a vertical at its Mizar No. 1 location before the end of the year.

After spudding the Alcor No.1 in late June or early July, Great Bear announced on July 9 that it had almost reached the HRZ and was preparing to start take core samples. But Duncan was cautious at a shale conference in August 2012. Describing the program in his conference speech, Duncan said, “The results to date are within our expected outcome.”

Asked about his near term expectations, Duncan said, “We expect to be testing and producing and … selling produced hydrocarbons potentially by the end of the year, and certainly early next year.” With a successful testing and development program, Duncan believed Great Bear could produce at least 100,000 barrels per day within five years.

Speaking at an industry conference in September, by which time Great Bear was in the process of drilling the Merak No. 1 well, Duncan said, “I can tell you with absolute confidence that where we thought we would find oil in these source rocks, we found oil.”

The results prompted Great Bear to accelerate its program.

Great Bear asked the state for permission to extend its proposed production test on the two wells to 180 days, from its initial timeline of 15 days. Having studied similar wells in the Lower 48, Great Bear believed the initial 15 days of production would mostly consist of flowback water from hydraulic fracturing operations. A longer test would also provide a better sense of the decline curve for shale wells in Alaska, Great Bear told the state.

A longer test would eliminate the need for a pilot well pad for production testing, which would speed up the entire timeline for the project, Duncan said. Great Bear could potentially make a decision about full-scale development in mid-2013, instead of 2014.

Great Bear also asked the state for permission to drill a second well at the Alcor pad, saying that complications prohibited it from drilling a horizontal lateral at the first well.

By December, having drilled only the vertical sections of the two wells and conducted a small 3-D seismic survey around the well locations, Great Bear suspended its drilling operations for the season. “Certainly operations took a little bit longer than we expected, particularly on Alcor, and the lab analysis quite frankly has taken much longer than we had hoped,” Duncan told the Alaska Geological Society. Great Bear drilled Alcor No. 1 to 10,813 feet and Merak No. 1 to 11,094 feet, collecting more than 600 feet of rock core.

Even with the slower than expected schedule, 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.”

Pursuing seismic

Great Bear remained quiet in early 2013, as it analyzed the results from its program.

“We have not yet determined our activities for the rest of the year,” Vice President for External Affairs Patrick Galvin told Petroleum News by email in early April. “When the technical analysis of our drilling results is complete, bolstered with the 3-D seismic data, we will be in a strong position to determine the next steps in our exploration program.”

That plan held firm for most of the year.

Speaking to an industry conference in September 2013, Duncan said Great Bear would hold off on making further drilling plans until it finished analyzing the rock samples it collected the year before. “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,” he said. Speaking to the Alaska Public Radio Network in early October, Duncan said Great Bear would conduct a 3-D seismic survey in early 2014 and present its development plan at the end of the year.

In late 2013, CGG Land Inc. announced the Great Bear and Niksik 3-D seismic programs, which together covered some 280 square miles south of the Prudhoe Bay unit.



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