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Vol. 16, No. 19 Week of May 08, 2011
Providing coverage of Alaska and northern Canada's oil and gas industry

Fortune Hunt Alaska: Hunt for shale oil begins in Alaska

Crude from three stacked, world-class, source rocks migrated into giant Prudhoe Bay, Kuparuk traps

Randy Brutsche

For Petroleum News

At least two oil companies are going after unconventional shale oil plays in Alaska — three of which are world-class source rocks, stacked one on top of the other.

In the State of Alaska’s latest North Slope lease sale, Great Bear Petroleum LLC, an independent focused only on Alaska, stepped out boldly and bet $8 million to win some 537,600 acres in the oil maturity window along the Dalton Highway and adjacent to the 800-mile trans-Alaska oil pipeline from Prudhoe Bay to Valdez, Alaska’s northernmost ice-free port. Brooks Range Petroleum Corp. joint venture partners already hold a combined 240,000 acres on the North Slope, at least 94,000 acres of which is prospective for shale oil extraction.

These two companies have declared an interest in seeing how well they can repeat the successes reported from Lower 48 states’ unconventional shale plays, such as the Bakken formation in North Dakota and Montana and the Eagle Ford formation in South Texas.

The North Slope is home to Prudhoe Bay and other world-class oil fields. Approaching 16 billion barrels of oil have been produced from the North Slope to date — from 100 billion barrels of oil discovered along the Barrow Arch, all of which migrated from source rock farther inland.

From deepest to shallowest, these source rocks are the Triassic-age Shublik, the Jurassic-age Kingak and the Cretaceous-age Hue. (The Hue shale is also referred to as the GRZ, HRZ or Pebble shale. Although the Pebble shale is a different rock unit from the Hue shale/GRZ, it is generally found in the same location as the Hue.)

Great Bear leading charge

Great Bear hopes to begin producing crude oil and natural gas liquids, or NGLs, in 2013, in three 15-year-phases that call for about 200 factory wells a year, once it drills four 11,000-foot core holes in the second half of this year and four production test wells in 2013.

The company’s plan, which its executives consider aggressive, has gotten kudos from both Alaska’s Republican Gov. Sean Parnell and its legislators, Republicans and Democrats, who invited Great Bear to make several recent presentations to legislative committees.

One of their questions and follow-up comments to Great Bear’s President and Chief Operating Officer Ed Duncan encouraged him to consider drilling 1,000 wells a year. He appeared startled by the question, but said it was not impossible: “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,” he noted.

Great Bear is projecting spending $10 million apiece on the factory wells. That alone is $2 billion a year for drilling, Duncan pointed out.

“We can grab the upward incline of our drill out, that point where we hit 9,000 wells, and drag it to the left if we want to accelerate the program,” he said, pointing to an overhead used in his presentation. “That tilts the production profile up. … We could conceivably rebuild the production down TAPS to well in excess of a million barrels a day. And we could do that relatively quickly if we accelerate the program. … Also, our program is predicated on adding one more source rock to the mix (all three phases will exploit the Shublik) — either the Kingak or the HRZ,” but, he said, Great Bear could increase production by drilling more wells and producing from all three source rocks.

If Great Bear can successfully develop the resource as currently planned, exploiting just two of three stacked shale source rocks in its 45-year measured drill-out program with 200 wells a year, it estimates it will produce 200,000 barrels per day by 2020; 350,000 bpd by 2035; 450,000 bpd by 2041; peaking at 600,000 bpd in 2056, with a sustained long-term production of 450,000 barrels per day out as far as 2074.

Duncan told lawmakers that he believes his leases alone contain at least 2 billion barrels of recoverable oil and 12 trillion cubic feet of natural gas.

According to Great Bear, Alaska has three of the most prolific source rocks in the world — a chunk of the geologic “kitchen” that generated the 100 billion barrels of oil that millions of years ago migrated north into traps along the northern coast.

Recovery percentage getting better

“The percentage of hydrocarbon recovered is a moving target,” Duncan said. “Two years ago it was probably 3-4 percent. Now it’s 5-6 percent, and it’s improving. Technology in this particular field is moving at a spectacular pace, and it’s driven by the success of the plays like the Bakken, the Eagle Ford, the Barnett, the Marcellus, and so forth. So the exploitation, reservoir stimulation and production technologies, are improving dramatically, have improved dramatically. We’re using 5-6 percent as our base case today. My suspicion is … it will be higher than that by the time we drill our full production test next January.”

“The richest source rock on the North Slope and one of the richest source rocks in North America — in fact, one of the richest source rocks in the world — is the Shublik formation,” Duncan told legislators. “Its regional extent, its quality, is extraordinary. And that is our primary target.”

Duncan said he expects the test and resultant factory wells to be roughly 9,000 to 11,000 feet deep with 4,000 to 6,000 foot laterals.

Great Bear scored, but didn’t win it all

But there is still room for other companies to develop shale plays on Alaska’s North Slope. “By no means did Great Bear win all of the acreage that would be prospective, that would appear to be in the oil maturation window,” Alaska Division of Oil and Gas geologist Paul Decker told Petroleum News.

“I think they are very well-positioned geologically,” Decker said. But it’s “a question of geology versus ‘close-ology.’ Based on thermal maturity, the North Slope source rock plays likely extend far beyond Great Bear’s acreage position, particularly to the west. However, from the perspective of needing to build out year-round access and infrastructure tie-backs, someplace very close to the Dalton Highway, TAPS, and producing fields would seem a logical place to start,” and Great Bear’s acreage brackets both the Dalton Highway (Haul Road) and the trans-Alaska oil pipeline, Decker said.

A careful, informed selection; not a land grab

Why is Duncan so certain his company’s acreage holds billions of barrels of recoverable oil?

The geology of the North Slope is well known and understood, documented by seismic, numerous field studies and well data, Duncan said. So when his company bid on 537,600 acres in last year’s North Slope lease sale, it was not making a blind land grab.

“There are massive amounts of very, very good technical information and studies on this basin. I kept reviewing everything, looking for critical problems, talking to the best geoscientists that I knew of. … We knew where the source rocks were, we knew their thermal maturity. I went over all of it several times alone and with colleagues,” Duncan said.

“I am quietly confident … had we not made our move in this lease sale we would have been locked out of it by next. Our timing was fortuitous,” Duncan said, echoing the sentiments of the early leaseholders in the shale plays in the Lower 48.

Matching geology with technology for BP

Considering the job Duncan did for Sohio (now BP) in Alaska, from 1982 to the late 1980s, it’s not surprising that Great Bear was first to pick up leases targeting an oil shale play in Alaska’s Brookian Foredeep, also known as the Colville basin, which lies north of the Brooks Range and south of the North Slope’s producing oil and gas fields.

As a project supervisor and geologist with the Sohio exploration group, Duncan was in charge of everything on and offshore between the Colville River and the MacKenzie Delta in Canada. He was tasked with matching the geology of an area or prospect with advances in technology that might make it economically viable.

So not only was he well versed in the North Slope’s petroleum systems, but he was trained to watch for the convergence of technology and geology, which he saw initially with Petrohawk Energy’s advances in well design at Eagle Ford, involving everything from increased lateral lengths to less restrictive choke sizes, tighter perforation cluster spacing, increased proppant and the use of new vegetable based fracking gels to overcome concerns about the use of toxic chemicals in hydraulic fracturing operations.

Duncan asserts the challenge of producing oil and gas from North Slope source rocks in Great Bear’s leases has little to do with the area’s geology. “The challenge is not the geology; it’s well understood here. The challenge for the play is: Is it operationally doable on the slope.”

The answer, he said, is yes. “We got past that issue pretty quickly.”

“There’s always a chance the rocks just won’t perform the way we want them to. We don’t expect that. That’s way outside our prediction range of outcomes. Also, there’s a chance the rocks will perform well beyond what we might imagine from an analog perspective,” Duncan said.

“We need to design our fracs. Our first four planned full production test wells have large R&D research element in them. We’ll perfect a method very quickly in the first few wells, then we go into factory drilling, and the costs go down at that point.

“That’s the operational model that has been developed in the Lower 48,” he said.

“We’ll drill down to the source rock and then run the laterals along the source rock strata and using state-of-the-art rock fracturing techniques to cause oil to flow direct from the sources.”

Brooks Range joins Alaska shale game

Alaska-based Brooks Range Petroleum Corp., or BRPC, is drilling the state’s only exploration well on the North Slope this winter.

Brooks Range was formed in 2006 as the Alaska operating entity for the joint venture working interest owners, who are currently Kansas-based Alaska Venture Capital Group, or AVCG, which holds a 50 percent working interest in the JV’s 240,000 acres on the North Slope and nearshore Beaufort Sea; TG World Energy, a small Calgary public corporation; and Ramshorn Investments, a wholly owned subsidiary of Nabors Drilling USA, out of Houston.

Ken Thompson, managing director of AVCG, recently told state legislators that his “job in the last … nine months has been to pound the pavement, make a lot of contacts and get our … next investor … that can bring capital, as well as expertise, to us.” In the same period of time, he said, the partners were assessing their acreage for source rock potential.

“Starting with our working interest owners’ meeting in Anchorage on July 20, 2010, we discussed the source rock potential and began some of our geologic assessment on AVCG et al acreage and surrounding areas. We feel our JV’s almost 100,000 acres to the west around Tofkat, Big Island and even our Southern Miluveach unit area has source rock potential being in the right maturation and depth window. And we are also studying source rock and low-permeability sands potential in our Beechey Point unit,” Thompson said.

Thompson said the JV partners “have made great progress on a comprehensive well log assessment and we plan visual core studies in 2011. Could these source rock shales and/or lower-permeability sands in these areas on the North Slope be the next Bakken or the next Eagle Ford development? AVCG and our JV partners plan to find out!”

JV’s focus on next frontiers

Thompson said AVCG and its partners focus “is on what we call the next frontiers for major developments on the North Slope,” which “fall into two categories for what we do.”

One frontier, he said, is exploration for smaller fields. Smaller being “in the 25-to-50 million-barrel range,” noting it was possible they would find something larger, “but for now we’re focused on those.” Both in his days with ARCO and more recently with AVCG, looking at seismic, he “saw a lot of” 25-50 million barrel fields.

“We believe there’s a lot of potential production in low permeability sands; there are a couple of resources, they’re more expensive to develop, but on our Southern Miluveach unit to the west … we have identified about 1 billion barrels in place, maybe about only 20 percent of that’s recoverable, but it’s … more expensive to develop.”

The second frontier for major developments that his company and its partners are “excited about” is the “oil-source shales,” believing the JV’s acreage holds “significant potential” for shale plays.

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