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Shale development requirements tackled Task force led by Division of Oil and Gas; DNR also moving ahead with issues impeding conventional oil, gas development in state Kristen Nelson Petroleum News
What can the State of Alaska do to get more barrels of conventional oil into the trans-Alaska oil pipeline — and to ensure that the potential of shale oil production on the North Slope becomes a reality?
Bill Barron, director of the Department of Natural Resources’ Division of Oil and Gas, addressed those questions from a permitting perspective at a meeting of the House Resources Committee in Anchorage Nov. 1.
DNR has been working with other departments on permitting issues in the state and has also established a multi-departmental shale task force to look specifically at requirements for shale development.
The state wants to make sure it is prepared for shale oil development, hence the task force, which includes DNR, the Department of Environmental Conservation, the Alaska Oil and Gas Conservation Commission, the Department of Fish and Game, the Department of Transportation and Public Facilities and the governor’s office.
Immediate development possible Barron said that successful exploration of the state’s shale resources could lead to immediate development, but cautioned that drilling is required. He said all indications are that the Shublik and Kingak formations are very prospective for shale oil, but drilling will be required to verify the viability of the resource on the North Slope. Some shale plays in the Lower 48, such as the Marcellus and Bakken, have been very successful, he told the committee, but others have not. He said the Eagle Ford is expected to be an analogue for the Shublik, but Eagle Ford wells haven’t been on line long enough to determine how long production will last.
Barron said that drilling shale wells is no different than drilling conventional wells, and said the state is well positioned to manage shale resource play development based on current statutes and regulations.
But, he cautioned, the pace and magnitude of permitting and development for North Slope shale oil could be significant, with a total well count comparable to wells currently in place on the North Slope — and with those new wells being drilled over a 10-year period, compared to the 30 years it has taken to drill the current North Slope well inventory.
Asked by Rep. Peggy Wilson, R-Wrangell, what staff increases agencies would need to handle that, Barron said the task force hadn’t gotten that far yet, but would have information for the Legislature when it reconvenes next year.
The unit issue Conventional oil production in the state takes place from units, groups of leases usually with different owners. The leases are unitized for production to ensure that there is no waste in producing the resource, a reaction to early days of drilling in the Lower 48 when landowners drilled as many wells as they could, competing with adjacent landowners to extract the oil, resulting in damaged reservoirs and less than maximum oil extraction.
State regulators in oil producing areas — the Alaska Oil and Gas Conservation Commission in Alaska — now ensure that drilling and production is done in such a way that resource extraction is maximized.
And landowners, in Alaska DNR’s Division of Oil and Gas or the Bureau of Land Management for federal acreage, require that the acreage over a field be unitized.
But shale oil or gas doesn’t occur in pools or fields. It is continuous over broad areas.
One of the main reasons for unitization — that oil or gas can be sucked from adjacent properties — doesn’t apply to shale.
Unitization is for reservoir management, Barron told the committee in response to a question from Co-Chair Paul Seaton, R-Homer. Whether unitization is even appropriate for shale is in doubt.
There is no pressure communication from well to well, Barron said, and well drainage is limited.
Alaska regulators are discussing the unitization issue with regulators in areas like North Dakota where shale development is under way. Barron said most jurisdictions have just changed spacing requirements for shale wells, rather than unitizing.
Hydraulic fracturing, natural gas Hydraulic fracturing has been a big issue in Lower 48 shale development.
Barron said about 25 percent of Alaska wells — both on the North Slope and in Cook Inlet — are fractured, so the process isn’t new to the state, or unique to shale play development. A large number of horizontal multistage hydraulic fractured wells are required to maintain production and economic feasibility from shale plays.
Frac fluids are approximately 98 percent water and sand and there would be no surface disposal of water in Alaska, Barron said.
Seaton asked about natural gas produced along with the oil.
Barron said that in the Bakken, where the oil wells are very low-rate, the associated gas is also produced at a low rate.
But it’s not the same as conventional production — you can’t re-inject natural gas into a shale formation, so disposal is more complex. With more wells, pumps will need power and gas could be used for that, he said.
But since the resource hasn’t been drilled yet, it’s not known whether the amount of gas will be small or large.
Conventional issues Barron also reviewed issues impeding conventional North Slope development.
The permitting task force led by Deputy DNR Commissioner Ed Fogels is looking for overlaps and gaps in the state’s permitting requirements, Barron said.
But, he told the committee, in permitting, “one man’s impediment is another man’s protection.”
One issue is that smaller companies, and companies new to Alaska, are bidding on leases. These companies have little experience in permit sequencing and timeframes, may not have allotted enough time to address public concerns and local government requirements and are not familiar with conducting business in Alaska.
There is also a new issue, since the demise earlier in the year of the Alaska Coastal Management Program: Applicants are now responsible for project coordination with local, state and federal agencies. Barron said the permitting task force recognizes how critical coordination is; an Alaska project questionnaire is being developed to serve as a road map for permitting.
Drilling season, roads Barron said finding a way to extend the drilling season would reduce one impediment.
And the “Roads to Resources” concept has value beyond the Foothills area.
Roads came up in the shale development discussion, with Sen. Cathy Giessel, R-Anchorage, asking about a requirement for gravel roads for shale play development. Barron said the state’s best interest findings require ice roads for exploration, but not for development. And once Great Bear Petroleum, which acquired some 500,000 acres in last fall’s state lease sales specifically for shale resources, drills its first four wells, in concept there would never be another exploration well for shale. Barron said once the resource is identified, every well will be drilled, fracked and produced.
All development on the North Slope is from gravel roads, he said, except Alpine and Badami which were done as roadless developments.
He said roadless developments haven’t been beneficial for adjacent lease exploration, citing Badami as an example. If there had been a road into Badami, it would have significantly reduced the cost of exploring east of existing fields because ice roads would have been required just from the gravel road. A tremendous expanse of the North Slope has remained unexplored because of cost, he said.
“Roadless” was viewed as the right way to go, Barron said, but it may not be the right way in terms of long-term development.
Resources Co-Chair Eric Feige, R-Chickaloon, asked if there were areas other than the North Slope that would benefit from permanent roads.
Barron said the west side of Cook Inlet would also benefit. The area has pipeline access, he said, but no roads, and a permanent road would increase the exploration opportunities.
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