In common with much of rural Alaska, Nome uses expensive diesel fuel to generate electricity. So it might seem obvious that developing natural gas from the nearby gas-prone Norton basin could bring down electricity prices and perhaps generate an economic resurgence in the Nome area.
But it’s not that simple.
A recent study by Cameron Reitmeier, a petroleum geologist with the Minerals Management Service in Anchorage, has concluded that the economics of this type of development are marginal. Reitmeier carried out his study as part of a masters program at the University of Alaska Anchorage.
The Norton basin lies under the Norton Sound, south of Nome, and contains a sequence of gas-prone sedimentary rocks. A 1995 assessment by MMS concluded that there might be 2,708 billion cubic feet of undiscovered natural gas in the basin.
Drilling in the 1980s
ARCO drilled two stratigraphic test wells in the Norton basin in the early 1980s. Then, looking to find oil, Exxon and ARCO drilled six exploration wells in 1984 and 1985. Several of the wells encountered gas shows and two of these wells found moderate to strong shows. However, there was little interest in gas at the time and all of the wells were plugged and abandoned.
MMS has in the past looked at the potential for extracting gas from the Norton basin for liquefied natural gas production. But the MMS analysts have found that the development costs make it highly unlikely that LNG from this modest sized basin could compete in world markets.
Reitmeier’s new study instead focused on the potential for developing gas production for local use in the Nome area.
“This was … a change for us … because in the past when we looked at gas we were always looking at large LNG facilities and that kind of thing,” said Larry Cooke, an MMS supervisory geologist.
A field near Nome
Gas production might be viable for local use if a significant gas field lies not too far from Nome. And the MMS 1995 assessment did point to the possibility of as much as 18 billion cubic feet of gas that could be produced over a 30-year period within about 30 miles of the city.
So, for his analysis of gas economics for Nome use, Reitmeier has assumed gas production from a mid-Tertiary play in a 12,400-acre area 30 to 40 miles directly south of Nome — the geology of the basin makes it unlikely that there’s a workable field much closer to land. And, to test the economics, Reitmeier assumed that a gas field of appropriate size would definitely be found at around this location.
Could a field like this prove viable?
The Nome area currently consumes about 1.8 million gallons per year of diesel fuel. That equates to the energy from about 97 million standard cubic feet of natural gas per year, a production rate that ought to be well within the capabilities of the type of field that Reitmeier envisages.
The scale of the operation would be too small to support a production platform, so Reitmeier’s economic modeling assumes the use of subsea well completions, rather like a gas field that Statoil has developed in the Barents Sea. Subsea completions represent a theory that needs to become reality for future Alaska offshore exploration and production, Reitmeier said.
Two production wells
The Norton Sound field would involve two production wells and a disposal well. A 40-mile 4.5-inch subsea pipeline would carry the gas to the existing electrical power plant in Nome. An onshore base would remotely control the offshore wells.
“The infrastructure that I assumed went directly to the power plant … and then used the existing power lines,” Reitmeier said.
Reitmeier estimated that the field would cost about $42 million to develop, plus leasing and appraisal costs of slightly more than $10 million. The pipeline would probably cost about $47 million to construct. Reitmeier’s economic analysis then assumes operating costs of $5 per mcf of produced gas, fixed costs of $3.37 million per well per year and gas transportation costs of $2.22 per mcf.
High priced gas
Although the costs of developing even a small gas field like this seem rather daunting for a relatively small community, these costs would be somewhat offset by the potential for being able to price the gas at a fairly high level in the closed local market.
“Basically they’re looking to power their lights and they’re looking to drop their power bills — as long as you do that it should work out,” Reitmeier said.
Essentially the gas would compete on price with diesel fuel. Reitmeier calculated the volume of gas that provides the equivalent energy to a gallon of No. 2 diesel fuel. He then determined that, at $1 per gallon for diesel fuel, $18.65 per mcf
gas could deliver electrical energy at the same cost as diesel. That’s a considerably higher gas price than current hub prices in the Lower 48 states. And the $18.65 price may be an underestimate since diesel prices are currently trending well above $1 per gallon.
Power cost equalization, a state program that provides funds to reduce the cost of rural domestic electricity, could impact the gas price in Nome. However, power cost equalization in Nome is quite small and would have little impact on the economics of gas production, Reitmeier said.
Might make money
Reitmeier plugged the estimated costs, production volumes and gas prices into an economic model that assumed inflation-adjusted discount rates from 11.2 percent to 18.4 percent. A 30-year field life resulted in a net present value of $15.29 million for the project. The ratio of profit to required investment indicated a risky project that might just prove viable.
The economics weren’t totally negative, so you can’t discount the project, Reitmeier said.
However, the assumption that gas would definitely be found at a suitable location eliminated a significant risk factor from the project economics. And discovering the gas would require a jack-up rig in Norton Sound — an unlikely proposition just to support this project.
“One idea is that (the jack-up rig) would have to be in transit — bringing one up wouldn’t be economic,” Cooke said.
Other factors
However, there are some factors that Reitmeier did not include in his calculations and that could help the economics.
In particular gold mining may start again near Nome — NovaGold Resources Inc. is considering re-opening the Rock Creek mine just outside town. Mining requires large quantities of electricity and this industrial demand could really impact the viability of gas development.
“That would help out the economics, just on an economy of scale,” Reitmeier said.
Reitmeier also excluded from his calculations the possibility of using gas for heating buildings in Nome. However, the construction of a domestic gas distribution infrastructure would be fairly expensive.
There are also some federal incentives that could impact the economics. Reitmeier’s field design includes sequestration of carbon dioxide that’s known to exist in Norton basin gas. That sequestration might qualify for an EPA incentive. Also, it’s quite likely that MMS would suspend or reduce the royalty rate for this type of gas production — Reitmeier’s calculations assumed a 12.5 percent royalty rate.
And there are programs that help with rural energy projects. Internally we discussed what it might take to get this started — perhaps getting help from the Denali Commission, Department of Energy or whatever, Reitmeier said.
So, although the basic economics of gas production from the Norton basin don’t look good under current conditions, future possibilities such as gold mining could bring viability to a gas development project. And possible future EPA regulations for sulfur content in no. 2 diesel fuel may further escalate the price of diesel.
Perhaps the time will come to drill for gas under the Norton Sound.
