|
Piping North Slope gas to Southcentral Alaska might be cheaper New study suggests a spur line from the north might be more economic than developing new Cook Inlet gas sources Kristen Nelson Petroleum News Editor-in-Chief
The cliff is getting to be a well-known graphic: It shows Cook Inlet natural gas production falling off steeply in this decade, first curtailing industrial uses and then utility and home heating.
Known reserves can be developed and more gas can probably be found at existing fields, but beyond that, into the realm of exploration, the costs rise. North Slope gas may be an attractive alternative, if the local market is large enough for gas — not at historically low Cook Inlet stranded gas rates — but still perhaps at a favorable price differential to Lower 48 Henry Hub prices.
The U.S. Department of Energy’s Arctic Energy Office funded a study to look at future demand and supply of natural gas in Southcentral Alaska and evaluate options to meet the demand.
The study is still in draft, but Charles Thomas of Science Applications International Corp., one of the study’s authors, said April 12 that a spur line to Southcentral from a North Slope gas pipeline may be an attractive option compared to exploring for and developing more gas in the Cook Inlet basin, if there is enough of a market for the North Slope gas in Southcentral Alaska.
Thomas reviewed study results to date for the International Association for Energy Economics in Anchorage April 20. A draft of the report is being circulated for comments, and Thomas said he expects that the final report will be released in early May.
Options considered include conventional natural gas resources, a spur line from a North Slope gas pipeline and limiting industrial usage. More local gas Increased natural gas resources in the Cook Inlet area could come from reserve additions in existing fields, exploration and discovery of additional conventional gas fields or unconventional gas.
The study looked at how much gas there might be in the Cook Inlet basin — the total endowment. Thomas said the study used “the accepted geologic theory that fields should be log normally distributed,” and then tried to come up with a good fit for the basin total by filling in “missing” fields expected on a log-normal distribution, and concluded that a total of 25 to 30 trillion cubic feet additional gas in place was a good fit with both number of fields and resource distribution.
“Now, I emphasize an analysis like this, number one, doesn’t prove it’s there, and it certainly doesn’t tell you where to go look,” Thomas said. Prime exploration areas could be restricted or off limits The study looked at land classifications, and the authors concluded that because a major portion of the Cook Inlet land area is in federal and state wildlife refuges, parks and restricted areas, and because of historical production in some areas, that up to 30 percent to 50 percent of the prime exploration areas could have restricted access or be off limits.
Thomas noted that historically exploration has been for oil, with gas discoveries prior to 1970 accidental. All exploration has been for structural plays, “and we would expect that there would be a lot of gas to be found in stratigraphic plays, and no one has even looked for that gas.”
Of the estimated endowment of 25-30 tcf, about 20-25 tcf should be technically recoverable, with 13-17 tcf of that in upper Cook Inlet, including 2.5-3 tcf reserves additions to existing fields and 10-14 tcf possible in undiscovered resources.
But land access is required, application of 3-D seismic and long-reach drilling, “and major investments — this is not going to be free gas,” Thomas warned. He said people advising on the study emphasized the cost, telling study authors, “Yes, we would say there’s a lot of gas to be found in the Cook Inlet, it’s pretty under explored, but it’s not going to be free.” Money will have to be spent to find the gas. Cost of spur line gas The option to bring North Slope gas to Anchorage included Alaska-only capital costs and throughputs based on the MidAmerican proposal for the line from Prudhoe Bay — now defunct, Thomas noted — and used estimates from Enstar for a spur pipeline. The result was an estimated tariff of $1.40 per thousand cubic feet to bring gas from the North Slope to Anchorage, not including the price of the gas. “This is what I’d call definitely our first-cut analysis,” he said, but it does suggest that gas to Anchorage would have about a $1 per mcf cost advantage over gas to Chicago, creating “some opportunities for value-added products in Alaska — it might give us some competitive industrial businesses located in this region compared to people who are operating on gas at Lower 48 prices.”None of the options are cheap Compare that to costs to find and develop gas.
None of this gas is cheap, Thomas said. Even proven reserves will require $77 million to develop.
“We hear discussions of 3-D seismic they want at Beluga and I think maybe at North Cook Inlet and any number of other places. Marathon has gotten approval for a new zone in the Kenai field,” so an estimated 1.4 tcf of reserves growth is estimated to cost $465 million.
If 50 percent of the estimated undiscovered 13-17 tcf of gas had a finding and development cost of 75 cents per mcf that would be a total of $5.6 billion of investment for onshore discoveries, with offshore costs higher.
That kind of investment may be hard for Alaska operations to get, based on international competition for investment, Thomas said.
At $500 million for a spur pipeline, that “certainly may be an attractive option, but you do have to have a market for the gas.” And the price for gas in Anchorage could be less than in the Lower 48. Conventional gas coverage until 2012 Because of statements made by Agrium about the uncertainty of plant operation after 2005, Thomas said the study assumed that Agrium operations stop in 2005 and that the LNG plant stops operations at the end of its current export license, which runs through the first quarter of 2009.
If gas stops going to the Agrium fertilizer plant after 2005, and to the LNG facility after the first quarter of 2009, there is gas to meet commercial and residential consumer demand until 2012 with the existing reserves base, but the critical date is 2009 with existing reserves, if gas continues to be dedicated to industrial use.
Successful exploration and production effort will be needed to maintain current levels, and the economics look favorable for 30-100 bcf fields onshore and 120-220 bcf fields offshore, depending on the price of gas.
Thomas said exploration or reserves growth — or some combination — can provide additional supply and with an assumed growth in reserves of 1.4 tcf, there would be sufficient gas through 2025 for commercial and residential consumers and perhaps one industrial user.
Another option, Thomas said, is to import liquefied natural gas into Southcentral — a reverse of the current pattern, which sees LNG shipped from Southcentral Alaska to Asia.
The study did not analyze incremental contributing factors such as gas storage, conservation and increased efficiency and power generation alternatives such as wind, coal and hydropower. Thomas said the study did not estimate the economic potential of coalbed methane since there is such limited information available on its economic potential in Southcentral.
| 