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Low energy density keeps gas on slope Three approaches to commercializing North Slope gas under way and we need to support them all, petroleum economist Alliance Kristen Nelson PNA News Editor
Three approaches are being studied to commercialize Alaska North Slope natural gas. But none of them is a sure thing, Roger Marks, petroleum economist with the Division of Oil and Gas Audit, Alaska Department of Revenue, told the Alaska Support Industry Alliance Feb. 18.
Liquefied natural gas, gas to liquids and a gas pipeline through Canada are all being promoted to move North Slope gas, Marks said.
Why hasn’t it that gas been commercialized yet?
The reason, Marks said, “can be summed up in three words: low energy density.”
A cubic foot of crude oil, he said, has a million BTUs, while a cubic foot of natural gas has only 40,000 BTUs. And both are sold for energy or BTU content.
From a BTU perspective, he said, a natural gas pipeline would have to be 25 times the size of a crude oil pipeline to move the same BTUs.
“And that’s expensive. And that in a nutshell is why gas is not commercialized yet. It’s just too expensive to build what you need to get to market given what you can get for the resource,” Marks said.
The low-BTU value of natural gas will also impact revenues the state will get if the resource is commercialized, Marks said. Taxes from natural gas, he said, are going to be a lot lower than those from oil.
“Just from what I’ve looked at, I’d be very surprised under good scenarios, whether North Slope gas would ever generate more than about $200 million a year to the state. And that’s given long-run average energy prices,” he said.
Three strategies being promoted Natural gas is methane. “Liquefied natural gas, LNG, is simply cold methane — it’s methane that’s refrigerated to about 250 degrees below zero Fahrenheit and that way it compresses and you can … increase the energy density by freezing it and having it compress,” Marks said.
The gas to liquids strategy involves “converting a natural gas to high-valued refined product, mainly diesel fuel and naphtha,” he said.
The other strategy is a pipeline to move the natural gas directly to market.
Initially, Marks said, the source of gas would be the 26 trillion cubic feet of gas at Prudhoe Bay, some 8 billion cubic feet a day of which is currently produced along with the oil and re-injected to maintain reservoir pressure.
Some oil is lost once you start to sell off the natural gas, calculated at about 1 BTU of oil lost for every 10 BTUs of gas you produce.
But, he said, gas commercialization could extend “the life of the oil reservoir because of the synergies between the two operations,” actually increasing oil production and “if you were wait until the oil was all gone to start producing the gas, at that point in time then you may forego the opportunity of every producing the gas, in which case you’ve really wasted a lot of resource.”
LNG has had the most focus recently Liquefied natural gas has had the most focus in the last few years, Marks said. LNG involves building an 800-mile pipeline to Valdez or to Cook Inlet — getting the gas to a port where it would be liquefied and then shipped as LNG to markets in the Far East.
Communities along the pipeline could get natural gas in an LNG project, he said.
The biggest challenges an LNG project faces are marketing and cost, especially since competing projects don’t have to build an 800-mile pipeline.
The LNG market is “fairly finite,” Marks said, presently about 80 million metric tons a year in the Far East. At a growth rate of 3 percent a year, he said, the incremental market by 2010 would be about an additional 30 million metric tons a year.
A project sized at 2 million cubic feet a day, he said, would produce 15 million metric tons a year, which means it would have to capture about half of the incremental market by 2010.
The advantages of an Alaska LNG project include the fact that the gas is already being produced and that Alaska is stable politically compared to other potential sources of LNG such as Indonesia. Also, he said, pipeline welding and trenching technologies are improving and bringing down the cost of pipeline construction.
Two LNG projects There are two major competing LNG projects, the sponsor group consortium (ARCO Alaska Inc., BP Exploration (Alaska) Inc., Phillips Petroleum Co., Foothills Pipeline and Marubeni) and the port authority (North Slope Borough, Fairbanks North Star Borough and City of Valdez associated with Yukon Pacific Corp.).
The strategy of the sponsor group, Marks said, “is to try to develop a smaller project.” That would attack two problems: a smaller pipeline and facilities would reduce the cost and a smaller quantity of LNG would be easier to market.
Marks said “from what I can tell they’ve been able to … reduce the volume by about 50 percent, to only a 7 million ton a year project, by reducing the costs 40 percent. So at this point the economics are a little bit worse but they’ve solved the big marketing problem and they’re working on bringing the cost down.”
The port authority, on the other hand, has reduced costs because as a political subdivision the authority is exempt from federal income taxes as well as state income and property taxes.
“I estimate that on a financial basis, not having to pay federal income taxes on your income, is sort of a financial equivalent of about a $2 billion reduction in your capital costs on the project,” Marks said.
He noted that a group supporting a Cook Inlet pipeline terminus has been formed recently, and may form their own port authority.
Marks said that Cook Inlet may or may not be running out of gas — but that gas from the North Slope would certainly cost more in Southcentral than local gas.
In addition to ensuring supplies of gas in Cook Inlet, he said, “Some people think there might be a lot of industrial development that would occur if North Slope gas would come to Cook Inlet. … Cook Inlet gas since start up has been about the lowest gas prices in the country. Right now it’s about a $1.50 per MCF. It has been a lot less.
“If North Slope gas came to Cook Inlet, again I suspect it would cost more than what Cook Inlet gas has been, and we really haven’t seen a lot of — beyond what’s there now — we haven’t seen industrial development going on at lower prices, so it would be interesting to see if industrial development would occur with higher prices with the higher volumes of gas.”
Gas to liquids A second strategy, gas to liquids, solves “the low energy density problem by converting natural gas into high value refined products,” Marks said.
Natural gas would be converted to about 80 percent high quality clean diesel and about 20 percent high quality clean naphtha, he said, and those products would be shipped down the existing trans-Alaska oil pipeline.
“And as I understand it,” he said, “just the differential specific gravity between these products and the crude oil would actually keep it separate as it goes down the pipeline and then at Valdez it would be separated out and put into specialized product tankers.”
But GTL is not cheap. A project to convert about 2 billion cubic feet a day would produce about 300,000 barrels a day of liquids at a cost of about $10 billion.
There are a handful of commercial GTL operations in the world now, and Marks said he believes they’re all losing money.
“Most of them were subsidized by countries that just wanted to be self sufficient for energy because they feared another oil embargo,” he said. A plant in Malaysia that produces wax as a by product seems he get by because it has a niche market for the wax.
What may make a difference in GTLs, he said, are some significant technological breakthroughs in the process, which involves three steps: synthetic gas is manufactured by combining methane and air or oxygen; the synthetic gas is then converted to long-chain hydrocarbons containing a lot of wax through catalyst, heat and pressure (the Fischer-Tropes process); and in the third step the product of step two is upgraded to high-grade fuels.
“In the GTL research there are two holy grails people talk about finding,” Marks said. In step one, if you start with air you have to separate nitrogen in the air from the rest of the process, which is expensive; if you start with oxygen, it’s expensive to separate oxygen from air.
The first “holy grail,” he said, is a ceramic membrane which separates oxygen from air.
“The other holy grail is looking for a catalyst in step two that would produce shorter hydrocarbon chains that need less expensive upgrading,” Marks said.
Pilot plants Exxon has a pilot plant in Baton Rouge, La., Marks said, has spent several hundred million dollars on the process and received some 400 patents to date.
ARCO has a pilot plant at its Cherry Point, Wash., refinery, and “BP is talking about building a pilot plant either in Cook Inlet or the North Slope.” The U.S. Department of Energy is sponsoring ceramic membrane research at the University of Alaska Fairbanks.
In addition to technological advances in GTLs, Marks said, you can start with a smaller volume. Per-unit costs, he said, stay pretty much the same regardless of size in GTL production, eliminating the marketing challenge.
Another advantage of GTLs is that since they would be shipped through the existing pipeline tariffs would be reduced.
Canadian pipeline The third strategy people are looking at now, Marks said, is “the idea of building a pipeline across Canada to the upper Midwest, to the Chicago area.” This, he noted, was the original 1970s vision of how North Slope gas would be commercialized and the Alaska Natural Gas Transportation System received a government franchise to carry the gas in 1976.
But pipeline costs were too high — estimated at some $40 billion in the 1970s — and there were adequate supplies of domestic and Canadian gas.
“And actually Foothills Pipeline Co., the same Foothills which is part of the LNG sponsor group, they still hold those permits and they’re still active and Foothills is actually looking at this,” he said.
Renewed interest in this strategy, Marks said, comes from improvements in pipeline technology, the extension of the Canadian pipeline grid all the way to northwest Alberta, reducing the amount of new pipeline which would have to be built from Prudhoe Bay, and a belief that U.S. gas production has peaked and that there will be a need for more natural gas in the Lower 48.
Arctic Resources Co., a subsidiary of Municipal Energy Resource Corp., is the main party studying the gas pipeline to the Midwest, Marks said. The parent company has a network in Texas providing gas to individual communities where the distribution system is built by 100 percent bond financing and is owned by local governing bodies, resulting “in tax benefits not dissimilar to what the port authority has.”
Arctic Resources Co. is looking at two options — a pipeline running under the Beaufort Sea to the Canadian Arctic and then south to tie in with Mackenzie Valley gas, and a line south to Fairbanks from Prudhoe Bay and then turning east into Canada. The proposal is to combine gas resources from Alaska and Canada and deliver about 4 billion cubic feet a day to the Midwest.
“The marketability of this idea, like the marketability of anything else, depends on whether you can get the gas to market cheaper than alternative supplies. What this idea banks on is the idea that U.S. supply has peaked and reserves are actually declining,” Marks said. And, as reserves decline, price would also go up — justifying the cost of the pipeline.
“I hope you realize,” Marks said, “that none of these options are a sure thing and that any of them would be better than none of them.”
Any of the options would result in increased exploration and development of gas on the North Slope, he said.
“For sure some people have vested interest in some options over others. But for those of us who don’t, I think it would be good for us to support all of these efforts in the hope of getting one of them to work,” Marks said.
While Prudhoe Bay would probably provide initial gas, Point Thomson is also a source once a pipeline is up and running.
Point Thomson is a very high-pressure gas reservoir with a lot of oil, but you couldn’t produce the oil because, Marks said, “the pressure’s so high you couldn’t re-inject the gas back in so the gas needs an outlet.” But with a gas pipeline, you could produce Point Thomson “and just blow that gas straight down the gas pipeline,” he said.
Marks also said that while he didn’t think it would be possible to build both an LNG project and a Canadian pipeline option, GTL could be combined with either of the other options because GTL could be built as a small project.
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