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Great Bear’s Duncan: ‘In it together’ A more conservative, but not subdued, Duncan declines to testify to Senate Resources Committee on tax breaks needed for project Kay Cashman Petroleum News
Hours before Gov. Sean Parnell abruptly withdrew his revised production tax bill from consideration by a special session of the Alaska Legislature because of lack of support in the Senate, Great Bear Petroleum’s top executive, Ed Duncan, addressed the Senate Resources committee, in testimony that was supposed to address the governor’s compromise tax bill, Senate and House bills 3001.
Although more conservative in terms of what his company’s pioneering efforts in oil extraction from Northern Alaska’s three great source rocks might contribute to the state’s declining oil production, Duncan did not offer a positive or negative comment on SB 3001, although he did say that Great Bear officials “are amazed at the cost differential between North Alaska” and the much lower-cost South Texas, “whether it’s rig rates, whether it’s labor costs, whether it’s the cost of pipe, wellheads, you name it, it’s there.”
But with Great Bear just starting its multi-well, proof of concept drilling and testing phase, expected to last until the end of December, followed by a one-year pilot production test, Duncan made it clear that he still does not know whether Alaska’s source rocks can be enticed to produce commercial qualities of oil and natural gas liquids, and thus what the state of Alaska can do to help his company and others.
So when asked by Sen. Lesil McGuire to contribute to the tax dialogue about “any potential (production tax) bill that could come out of this session” and whether he had “a preference in what type of incentive the state would offer,” Duncan responded with a question that defined his goal for state participation in what he referred to numerous times in his testimony as shared state/industry/societal concerns and challenges.
Make Alaska competitive with lower 48 states “What are the things that the state can do, realistically do, to help us push the finding and development costs in North Alaska down to something that competes (with), or is better than — let’s make it better than — the Lower 48. Let’s turn this thing around,” he said.
But Duncan said he “preferred” that the answer(s) “be the product of a different type of discussion than the answer to a simple question because we can lay out to you where our big cost points are, things that keep me awake at night, and let’s engage the bigger brain of the state and the industry to solve that problem because it doesn’t just solve it for us — it solves it for everybody on the map.”
“We’re all in this together — that’s the other thing that is critical here. The challenge isn’t just Great Bear’s, or the challenge isn’t just the state of Alaska’s … the challenge effects everyone from the super majors on the Slope to the smallest company,” he said many times, in different ways, in his testimony.
Duncan was “happy” to answer McGuire’s question, but not then and there.
Rather, he wanted to begin the discussion after May 8, explaining that “the week after next our all-internal task force on cost-reduction meets. I guess it’s the eighth of May. And I would propose … we join with the state following those meetings — and we’ll have those regularly — and work through where we see major cost drivers and places where the state maybe could facilitate significant cost reductions. … I consider those things good and proper incentives for us without me trying to prescribe what those would be today. Because quite frankly we are working very, very hard across the board with some very smart people internally and close to us consultants to say, ‘look we can move this cost significantly by doing things this way,’ and ‘maybe doing things this way will require the state to help us’ … ‘maybe in a regulatory way to become more efficient’ — again, that’s not Great Bear exclusively but the industry as a whole.”
A more conservative Duncan Although clearly pleased at the thought of spudding his first well in late May or early June, nonetheless in his April 25 presentation of Great Bear’s plans and expectations Duncan talked in terms of the company’s 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,” as compared to previous presentations where three consecutive drill-outs totaling 9,000 wells were proposed.
Also, in his recent presentation Duncan went into more detail about the geologic risk of the North Slope’s three major source rocks, the HRZ/GRZ, Kingak and Shublik than he has in the past.
While emphasizing the three source rocks were very well known, “there is a modeled outcome based on the dominance of oil, natural gas liquids, gas-phased production that has a huge impact on the commercial outcome. If the rocks are too ductile, if they’re too plastic, too play-rich, too gooey to frac well, that could cause a significant challenge that could be terminal to certain portions of the play early on.”
But, he said, the problem was “not necessarily long-term,” his inherent optimism back in place.
“Technology is evolving very, very rapidly. 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,” Duncan said, noting that geologic risk would be addressed “very early on” in Great Bear’s work program.
Duncan: State could help with sand Challenges to source rock exploitation have been compiled by the state Division of Oil and Gas’ shale task force, Duncan said, having composed a list of them with his response to each in blue in the Slide 6 he used in his April Senate Resources Committee presentation (see adjacent graphic titled North Alaska Shale Resource Play Realization: Challenges and Business Development Opportunities).
The items that “appear to be hot buttons in the discussion,” Duncan said, are as follows:
• Access to gravel for infrastructure support.
• Water for supporting the work force in the context of drinking water, but also frac water used in the stimulations.
• Developing an in-state supply of proppant for hydraulic fracturing operations.
Proppant, Duncan said, is “sand, silica rich sand.” Something, “in a state this size with the big rivers and mountain belts and things of that nature, the mining operations that have gone on in this state for years, my expectation is that, with time, we’ll sort out an in-state supply of proppant, or silica rich sand. It’s something we are working on right now, but the state certainly could facilitate that, too.
Mother Nature’s gift of water Sen. Bill Wielechowski asked Duncan to “talk a little bit about fracking, where you intend to get the water, whether you foresee problems with the fracking here in Alaska impacting the aquifers or causing other environmental problems.”
Wielechowski also asked whether Great Bear was looking at using propane instead of water in fracking operations.
“Water’s a big one,” Duncan replied. “There’s little doubt that the public outcry in certain regions of the U.S., the need for better oversight of the industry in all of these operations, (has been) clearly played out in newspapers over the last couple of years. For Alaska, we have a number of gifts that are provided us by Mother Nature on the North Slope.”
“There is, to my knowledge, virtually no fresh water aquifers that are not frozen as permafrost on the North Slope of Alaska,” he said. “The water sources that we see as potentially available to us regionally lie subsurface between the base of the permafrost and depth of about 5,000 feet. There are very thick, regionally extensive, sandstone aquifers that contain, predominantly, brackish waters — saline water that has a salinity that is not acceptable for human consumption (and) agricultural use, if that was ever an issue on the Slope, but serendipitously, chemically very suitable for fracking.
“There’s very active research on, in the direction of making or providing, seawater as an allowable component for frac make-up. Obviously if that bit of research is successful then there isn’t a shortage of water that would be suitable for fracking operations.
“The operation of fracture stimulating a well and flowing it back and testing it for commercial production involves capture of the flowback water. The water that you pumped into the subsurface, as well any water that comes back out of it as part of post-frac operations; that water is captured and cleaned,” Duncan said.
“We expect, as I think most of the industry now, that recycling operations and technologies of captured water for flowback operations will become very prevalent. I know that our current venture partner Halliburton (is) very actively involved in that kind of research of using filtering, actually reverse osmosis filtering, in part of flowback water before it’s reinjected and then the captured chemicals that are oftentimes naturally occurring, that flow back with the flowback water are disposed of appropriately.”
“So for our operations in North Alaska we don’t see shallow aquifers as being a significant challenge. We believe that water supply regionally through the subsurface aquifers is something that ultimately will be extremely valuable to the players that are exploiting this play,” he said.
But access to gravel is another issue, Duncan said.
“We see challenges with access to gravel, perhaps being one that we’re going to need help with. There’s plenty of gravel around but we have to access gravel in an appropriate and reasonable way. So that’s certainly something we need to work on.”
“As far as propane fracking is concerned, that’s not part of our plan at this point,” he said.
Level of activity Wielechowski also asked the amount of activity that could be generated by Great Bear’s development program; specifically the number of wells that would be drilled.
Referring to an article he’d recently read, Wielechowski said, “a shale well may initially produce oil at a high rate, perhaps a 1,000 barrels a day, (but) production tends to decline rapidly … stabilizing at a long-term rate of maybe 100 to 200 barrels a day. It goes on to say that in the Bakken play of North Dakota, for example, total production from the play (at the time) was running at about 488,000 barrels a day from 6,000 wells, indicating an average daily well production of just 80 barrels. Could you comment on what that would mean — the number of wells you would need to drill to fully commercialize the shale development that you’re looking at?”
Duncan said, “It’s our expectation that a well spacing in North Alaska will ultimately be somewhere around 160 acres per well” with 200 new wells and eight pads per year. … If we’re trying to develop the Shublik, the Kingak and the HRZ all at the same time it portends a significant number of wells.”
Great Bear’s focus, he said, “in addition to getting an effective test of the play, is also to focus on reducing surface footprint and have more things going on under the ground with pipe than above the ground with wellheads and things of that nature. So 200 wells a year, which is less than the number drilled per month in the Eagle Ford will support an operation here that goes well past my career and probably most of the folks in this room, in fact,” Duncan said.
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