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House O&G moves heavy oil incentives Bill intended to mesh with production profits tax to provide tax credits for challenged oil and gas goes on to House Resources Kristen Nelson Petroleum News
Rep. Norm Rokeberg, R-Anchorage, is working on a bill that would provide tax credits for challenged oil and gas development in the state, a bill which would work in conjunction with the production profits tax now under consideration in the Legislature.
The bill, House Bill 498, was heard and passed out of the House Special Committee on Oil and Gas April 11. It goes next to Resources.
Rokeberg told the committee the bill came out of a decade’s work begun with former Rep. Joe Green in 1996 and is intended to mesh with HB 488, the production profits tax, to provide a 15 percent credit against the PPT for challenged or non-conventional oil and gas.
Rokeberg said a 10-year sunset was included because newer technologies may mature to the point where credits are no longer warranted.
There was considerable committee discussion about what the bill should include — possibly only heavy oil — and Oil and Gas Chair Vic Kohring said he would write up the issues discussed to pass along to House Resources, while Rokeberg said he would work with interested parties and with the administration on amendments or a committee substitute.
Challenged oil or gas is defined in the bill to include Ugnu and West Sak-Schrader Bluff formation oil; oil from a carbonate reservoir; oil produced using various enhanced oil recovery techniques; oil requiring extended reach drilling with a step-out greater than 25,000 feet laterally from the surface hole; oil certified by the Department of Natural Resources to be challenged or non-conventional; gas produced with non-conventional oil; gas from hydrates; gas from coal gasification; tight gas; oil from tar sands; and oil from oil shale.
ConocoPhillips favors incentives Jeff Spencer, ConocoPhillips Alaska’s greater Kuparuk area heavy oil supervisor, reviewed the North Slope heavy oil resource for the committee, an estimated 23-24 billion barrels in place, about half in the viscous West Sak-Schrader Bluff formation and about half in the shallower heavier Ugnu formation. ConocoPhillips has been developing the West Sak core area in the Kuparuk River unit and Spencer said the company would like to continue development, if projects are competitive.
This is the easiest of the viscous oil to produce, he said, “everything from here on out gets tougher.” Development of heavier oils, and eventually the shallower Ugnu, would require new technology and a longer timeframe, but is economically challenged and incentives could help with development, Spencer said.
Brian Wenzel, ConocoPhillips Alaska’s vice president of finance and administration, said ConocoPhillips viewed HB 498 as providing incremental incentives to develop heavy oil. While the PPT, the production profits tax, is still evolving, Wenzel said the deductions and credits allowed in the proposed PPT would not provide enough incentives because of the higher cost of heavy oil.
Asked by Rep. Ralph Samuels, R-Anchorage, co-chair of House Resources, about incentives for gas hydrates, included in the bill the committee discussed April 11, Wenzel said he looks at the bill as an incentive for a number of technologies, to “prime the pump” to get a number of things going long-term in the state.
BP: viscous next big development target Frank Paskvan, BP’s western Prudhoe Bay heavy oil team leader, said viscous oil is the company’s next big development target in Alaska, with a $2 billion western region development project being planned. He said economics are the project’s biggest challenge. Incentives are needed, he said, and noted that one of every eight barrels belongs to the state.
Samuels asked if heavy oil is developed separately or is mixed in with lighter oil, and Paskvan said oil is separated into different depths with thicker oil in shallower fields with wells to those horizons. Drilling is targeted, he said, with wells going down a mile, then out a mile and a half to hit a target the size of a window. With the ability to be that accurate, he said, there shouldn’t be too much in the way of overlap between light and heavy oil targets.
Rokeberg asked if they could encounter lighter oil in shallow reservoirs and Paskvan said it was possible although to date they haven’t run into a shallow viscous reservoir which contains light oil. He said they could find deeper heavy oil, which would need different technology.
The committee also got updates on BP’s Schrader Bluff-West Sak production at the Milne Point field and on studies under way in conjunction with the U.S. Department of Energy on gas hydrates. Robert Hunter of ASRC Energy Services described U.S. Geological Survey estimates of the hydrate resource on the North Slope, and said while a dedicated North Slope stratigraphic test is planned there are many remaining technical challenges before the resource can be produced.
Rokeberg asked about free gas under the hydrate and Hunter said there is typically some free gas in the same reservoir as hydrates, at or just below the hydrate stability zone.
Lisburne challenged, but how? The committee got two different views on challenges at the Lisburne field. BP’s Sam French, the Lisburne field project lead, said the prize there is very large with an estimated 2 billion barrels of original oil in place, only some 8 percent of which, 150 million barrels, has been recovered. The field is a carbonate reservoir, the only one producing in Alaska, and is much denser than sandstone reservoirs. The statistical mean worldwide for recovery from carbonate reservoirs is 36 percent, he said, which would be another 500 million barrels.
French said the key is new technology.
Production is from natural fractures and wells and wells are drilled to target the fractures, enabling oil to move to the well bores. Problems at Lisburne, he said, include low permeability, which means the rock doesn’t give up oil easily, and the inability to predict the locations of fractures. It results in a lot of risks in new wells and new projects, French said. Conventional drilling — with drilling fluid at a higher pressure than the reservoir — typically damages the fractures so one technology goal is to find ways to prevent damage to the fractures or repair it if it occurs.
Division of Oil and Gas Director Bill Van Dyke agreed that viscous oil projects are challenged on the North Slope, but urged constraint on credits.
On Lisburne, however, Van Dyke told the committee the problem is gas production.
Lisburne is in production and its wells are not competitive because Prudhoe Bay facilities are gas-constrained, lack the capacity to handle more gas, he said.
It’s not that they can’t produce oil from the field — it’s that they produce too much gas with the oil, he said. Van Dyke said Lisburne has a large gas cap, and the gas can run down natural fractures to where the oil is and from there to the well bores.
Revenue also has some concerns Robynn Wilson, director of Revenue’s Division of Tax, said the division had concerns about administering the bill and believes that for each category a definition of time and place of production and allowable costs need to be included. The location of projects qualifying for enhanced oil recovery is not clear, she said: would Liberty, a project with the reservoir on federal leases and the well site on state land, qualify for credits?
Wilson said she was concerned that allowable costs were not clear.
Rokeberg said the intent of the bill was to piggyback off the PPT and qualified capital expenditures described in that bill.
Van Dyke also had other concerns about the bill.
He told the committee that viscous oil projects on the North Slope are challenged and not on a par with light oil, but he urged constraint on credits and said the bill as drafted is very board in scope. Particularly with respect to non-conventional gas he said the bill’s scope is the entire state.
He said there might be unintended consequences from the bill as drafted and recommended a more narrow focus, perhaps just on viscous oil, “a prize we can describe today.”
One issue was how to define viscous oil and Samuels and Rokeberg had a discussion with Van Dyke about the use of API gravity measurements taken at the surface vs. in situ viscosity measures. Van Dyke said he could live with API gravity as a measure if sideboards were added to measurements in the bill.
Rokeberg asked about the possibility of tight gas in the Brooks Range Foothills and Van Dyke said tight rock or tight gas is a fair description of the geologic models for the area. As to whether that gas would need help to be productive, Van Dyke said a lot of tight gas reservoirs are fractured and gas can get to well bores through the fractures. He said he didn’t know whether Foothills gas would need incentives to be economic, but did say that once there is a start-up date for a gas line, Foothills’ economics will change.
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