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Great Bear raises eyebrows Without Bakken, Eagle Ford talk of filling TAPS, new oil line, would seem far-fetched Kay Cashman Petroleum News
Can Alaska get in on the shale oil boom that is sweeping the Lower 48, making states like North Dakota a contender for the largest producer in the country?
One company, Great Bear Petroleum, bet $8 million in the State of Alaska’s latest North Slope lease sale that it can.
In the October sale the newly formed independent, which only plans to do business in Alaska, grabbed more than 500,000 acres containing a chunk of the geologic “kitchen” that generated the 100 billion barrels of oil that flowed north into traps along the Barrow Arch, such as the Prudhoe Bay, Kuparuk, Alpine and Point Thomson reservoirs.
In its Feb. 26 presentation to the Senate Resources Committee of the Alaska Legislature, Ed Duncan, Great Bear Petroleum president and chief operating officer, made statements that clearly amazed legislators and bumped what was expected to be a 60-minute presentation to two-plus hours.
The declarations made verbally and in the company’s overheads that most startled the legislators included:
• If the State of Alaska needs 1 million barrels of oil a day in the trans-Alaska oil pipeline, Great Bear’s play can deliver it and more by stepping up the pace of drilling, which is currently expected to peak at 600,000 barrels a day from exploiting just two of three shale plays in a measured drillout program.
• Alaska has three of the most prolific, world class, source rocks in the world. Individually they are superior to the Eagle Ford shale play in Texas, currently considered the hottest conventional oil play in the world. (Great Bear President Ed Duncan said, “We believe that is about to change.”)
• Great Bear’s current plan on its acreage calls for three 15-year phases. In each 15-year period 3,000 wells will be drilled from the same one-acre pads, at an average of 200 wells per year, requiring at least 20 drilling rigs working year-round. The cost for just the drilling, excluding pipelines, facilities, roads, etc. is $2 billion a year at approximately $10 million per well.
• If production begins in 2013 as planned, in a conservatively scaled project, Great Bear shows oil production from its acreage (see slide on page 10) alone at 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.
• This kind of production, Duncan said, especially if other shale developers grab up the hundreds of thousands of acres left in these plays on the North Slope, might eventually necessitate a new pipeline to replace TAPS, or a sister line.
• Great Bear’s longer-term North Slope gas development strategy might include exporting liquefied natural gas.
• Most of the source rocks, or shales, along the Barrow Arch, in leases owned by Alaska’s three major oil producers, BP, ConocoPhillips and ExxonMobil, are thermally immature and/or truncated, meaning they won’t produce oil. The oil trapped in the Alpine, Prudhoe, Kuparuk, Point Thomson and other reservoirs along the Barrow Arch migrated north millions of years ago from a wide swath of acreage to the south, where Great Bear’s leases lie.
• Great Bear is NOT looking for investors or partners, except for a possible shared 3-D seismic shoot next winter across the North Slope from the border of ANWR to the far western edge of the National Petroleum Reserve-Alaska, out into the Beaufort and Chukchi seas.
Could be much larger than Prudhoe Duncan told committee members that Great Bear’s analysis indicated 20 percent of the oil from the source rock in its leases had migrated north to the fields along the Barrow Arch, leaving 80 percent to be tapped as the technology to do so is advanced.
“We base our recoveries on analog performance; specifically the Eagle Ford in south Texas because it is remarkably similar, in several ways, to the Shublik,” the “star” among northern Alaska’s three source rocks, he said.
“The percentage of hydrocarbon recovered is a moving target,” he 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.”
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 target an oil shale play in Alaska’s Brookian Foredeep, also known as the Colville Basin, which lies north of the Brooks Range.
A project supervisor and geologist with the exploration group, Duncan was in charge of everything on and offshore between the Colville River and the Canadian border, 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 fracking operations.
Geology, technology surmountable challenges 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,” he said in a recent interview with Petroleum News.
The answer, Duncan said, is yes.
“We got past that issue pretty quickly,” he said.
“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.
He maintains the technology and the geology are a perfect match — or will be as soon as his associates have tweaked their well design.
“We have some technical uncertainties to address — that’s one of the reason we want to do our core holes soon,” Duncan said, referring to the holes Great Bear has tentatively scheduled for late fall.
“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, explaining that he expects the wells to be roughly 9,000 to 11,000 feet deep with 4,000 to 6,000 foot laterals.
“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,” Duncan said in the interview, repeating much of the same to legislators in his Feb. 26 presentation.
Multiple phases In phase one and two, Great Bear will target the deepest and oldest of the three source rocks, the Triassic-age Shublik formation. In the process the company will drill past the Jurassic-age Kingak shale and the youngest and shallowest source rock, the Cretaceous-age Hue shale, also called the GRZ or the HRZ and the Pebble shale.
“They are co-located meaning more or less on top of one another,” Duncan said. “From a drilling depth perspective we will drill down through the HRZ on the way down to the Kingak, on the way down to the Shublik.”
In phase one, the spacing between the wells (about eight to a pad) will be 160 acres. In phases two and three, the company will use the same one-acre pads it used for phase one, but it will likely reduce spacing between wells to 80 acres, Duncan said, in phase two.
In phase three, 30 years from when development drilling gets under way — in 2013, if Duncan has his way — Great Bear will target one of the other two source rocks.
“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.
“But, again, I can’t emphasize enough; we believe that the Kingak and the Hue individually could supply an unconventional resource development on their own. The fact that we have three on the North Slope provides … an extraordinary opportunity. You don’t get that in south Texas, you don’t get this in the Bakken and you really don’t get that in the Marcellus.”
Decker and Duncan address water issues But even if geology is not a challenge as it is in conventional oil and gas plays, there are technical challenges associated with producing oil and gas from shale. One of those challenges is water.
The hydraulic fracturing critical to making source rock permeable enough to release hydrocarbons requires large quantities of water.
But of most concern to the public is any potential for water supply contamination.
A few days before Duncan spoke in Juneau, State of Alaska petroleum geologist Paul Decker addressed that exact concern in another legislative hearing where he talked about the shale oil potential on the North Slope.
“Are there environmental risks?” he asked legislators. “Well, I think we have all heard some of the stories from the Lower 48 plays where they have done fracking,” Decker said. “There is the possibility that shallow aquifers could be contaminated if great care isn’t taken to ensure that those fractures don’t extend up into that fresh water aquifer, but this is something that is clearly avoidable with good engineering, good geologic practice. Responsible operators can certainly avoid this, particularly on the North Slope. I had asked you to try and envision the base of the permafrost where the fresh water aquifers need to be protected. That is essentially a mile or 6,000 feet or so above our zones of interest for fracking, so I think we can really avoid this kind of environmental risk.”
Duncan talked about advancing technology in regard to water use, as well as known water sources on the North Slope.
“Fortunately the technology evolving today allows for the recycling of frac water, so that reduces water needs significantly. Additionally we talked to the water folks at DNR in Fairbanks ... and with virtually every service provider that’s going to be involved in this play. … We believe there are adequate water resources on the North Slope, both from the Sag River, for example, as well as surface water. But more importantly, as this play develops we may see accessing subsurface water; some of the brackish aquifers, not suitable for drinking water. … These water resources may be perfectly adequate for making up our frac fluids and that could definitely change the balance of surface water use in this program. It’s a challenge. We know that. And we’re working on it.”
Alaska challenges Duncan then addressed another challenge that all want-to-be commercial projects face by pulling out a slide with Wood Mackenzie data that compared the ability to execute projects in Alaska compared to other petroleum provinces, including all the major oil producing countries in the world.
Alaska ranked 129 out of 141, in large part because of the impediments the federal government has put on companies trying to develop on and offshore Alaska leases.
Great Bear’s project, he said, had to make sense for all stakeholders, including the people of the North Slope, the State of Alaska, the environment and wildlife, and his company.
That said, “What I think is the most important thing about this slide,” Duncan said, “is in bold type, ‘the request for capital in the United States has taken on the appearance of state versus state competition. … The State of Alaska should not be in a position where a decision in its future runs through the Bakken in North Dakota, or the Eagle Ford in south Texas, or the Marcellus in the Northeast. Alaska’s resource base is global in scale. It’s an international oil and gas player. And access to capital, interested investment and activity in the state shouldn’t be dependent on competition with North Dakota. I just find that an aberration. My brain simply can’t process that.”
Great Bear, he said, “is built around building Alaska back to where it should be … where it was just a few short years ago. Not preoccupied with North Dakota or South Texas or the Northeast U.S.”
Great Bear’s vision “The easy conventional oil on the North Slope has been found. … As with every other basin in North America, the future is unconventional — oil and gas. … It’s unconventional resource plays that are going to drive the energy economy of this country and this state going forward for a very long time,” he said.
“Our company aims to be the leading unconventional oil and gas producer in Alaska. Our leasing is focused very heavily on good science. We’re reasonably proximal to infrastructure. We bracket the pipeline. We see every reason to believe these rocks will produce at commercial rates. We believe that effective and efficient development of our resource base from our leasehold alone provides a growing and stable forecast-able energy and economic future for the State of Alaska for the next 50-plus years, effectively, in the near term, reversing the state’s oil decline,” Duncan said.
The “volumetric outcome” of northern Alaska’s source rocks plays “will exceed the conventional exploration and production targets on the North Slope. In our opinion,” he said.
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