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Parnell’s next gas line benchmarks met BP, Conoco, Exxon, TransCanada specify pipe size, volume of gas, location of gas treatment plant, compression stations, LNG plant Kristen Nelson Petroleum News
BP, ConocoPhillips, ExxonMobil and TransCanada have met benchmarks for progress on a natural gas pipeline, Alaska Gov. Sean Parnell said in a Feb. 15 statement.
The governor had called on the companies to provide details by Feb. 15 on the size of the pipe, the daily volume of gas, location of a gas treatment plant, number of compression stations, size and scope of liquefaction plant and LNG storage facilities and number of off-take points for gas for local use by Alaska communities.
The companies said in a joint Feb. 15 letter that they “have completed the concept selection phase.”
The pipeline is specified at 42-inch diameter, with a design rate of 3-3.5 billion cubic feet per day, some 800 miles in length mostly underground with up to eight compressor stations.
Other details provided by the companies included:
•The gas treatment plant would be on the North Slope near Prudhoe Bay;
•The liquefaction plant would have a capacity of 15-18 million tons per year with three trains;
•There would be two LNG storage tanks at 160,000 cubic meters per tank and a terminal with one loading jetty and two berths; and
•There would be five off-take points along the pipeline route with a design rate of 250-500 million cubic feet per day “based on demand.”
Cost repeated The companies also repeated the capital investment they released last year — an estimated $45-$65 billion.
The governor said his next benchmark is this spring, when the companies are required to finalize an agreement to enter the pre-front-end engineering and design phase, followed by a full season of field work this summer.
“Our companies are now working toward the next decision points,” said the letter, signed by Randy Broiles of ExxonMobil Production Co., Trond-Erik Johansen of ConocoPhillips Alaska, Janet Weiss of BP Exploration Alaska and Tony Palmer of TransCanada.
And the companies noted that as they said in their Oct. 1 letter, “a competitive, predictable and durable oil and gas fiscal environment will be required for a project of this unprecedented scale, complexity and cost, to compete in global energy markets.”
LNG site not set yet What about the location for the LNG plant?
The window for that decision is a few months out, Steve Butt of ExxonMobil Development Co., the senior project manager for concept selection for the LNG project, told a House Resources “Lunch and Learn” group Feb. 19.
He said where in Southcentral has been narrowed down from some 20 possibilities to four or five, and the companies continue to work on site selection as it pertains to “cost of supply.”
The cost of supply factor, he said, is how the market judges LNG projects. There are more LNG projects proposed than will survive, “and the key is to have this project be strong enough and competitive enough that it can survive. And the way the market measures that success is through the cost of supplies,” Butt said.
The alternatives In focusing on the concept for the project the companies — BP, ConocoPhillips, ExxonMobil and TransCanada — began by looking at defining the right way to commercialize North Slope natural gas, and looked at LNG, gas to liquids and high-voltage direct current, HVDC, he said.
The project is enormous, and with a “project that big, you want to make sure you have a proven technology.”
That led to the LNG decision, “because there are LNG plants all over the world, it’s a growing market segment, and these other technologies are a lot less proven and they’ve never been done on this type of scale.”
They also focused on LNG because of its efficiency: “About 95 percent of the energy that goes into an LNG facility comes out the other end.”
Integrated design What’s different about this shot at commercializing North Slope natural gas as opposed to past projects that didn’t make it?
Changes in the Lower 48 natural gas market were what ended the recent attempts to send Alaska North Slope natural gas into that market, Butt said.
Two things are new compared to previous LNG projects, he said: “We worked it together as a consortium of all the companies” and “as a result of our work we’ve got a completely integrated basis of design,” including Point Thomson, Prudhoe Bay, the treatment facility, the pipeline and the LNG plant.
“And we look at all of that as one single system. And that is new; that’s something that hasn’t been done,” Butt said.
He said this time around, “we know exactly how we want to integrate it into the existing operations and that’s really important because the size of the project is so big that it’s dependent on the existing facilities that the Prudhoe Bay operator and the other companies have already built.”
The CO2 issue The decision has also been made to put the gas treatment plant on the North Slope.
Prudhoe Bay gas has a very high CO2 content, about 12 percent, much higher than in most fields, with Point Thomson by comparison having only about 4 percent CO2, he said.
“Anytime a gas system has a lot of CO2 it’s very difficult to monetize because you have to deal with this product that doesn’t carry revenue,” he said.
The volume of CO2, about 4 trillion cubic feet, will be pressurized and re-injected for pressure maintenance at Prudhoe Bay.
CO2 is one of the competitive disadvantages of this project, along with the distance between the gas field and the LNG plant, and the fact that the Prudhoe Bay gas has been cycled for 30 years, so liquids have already been removed and sold, and aren’t available for sale in this project.
The advantages of the project include a known resource, existing facilities at Prudhoe Bay, Alaska’s location relatively close to markets and the colder weather in Alaska which makes LNG facilities more efficient, about 15 percent more efficient than in warmer climates, Butt said. And because Alaska is in the northern hemisphere it’s in sync with markets, with compressors making more gas in the winter when the market wants more gas.
Butt said about 2 billion to 2.5 billion cubic feet a day of gas will come from Prudhoe Bay, with Prudhoe continuing to compress and re-inject some 8 bcf of gas a day. About 1 bcf a day will come from Point Thomson, which will require 14 additional wells, facilities to compress and move the gas and a gas pipeline between Thomson and Prudhoe.
There were no big surprises in the concept work done over the last year, Butt said, but they have been able to identify “small improvements, lots of small improvements,” such as beneficial reuse of CO2 on the North Slope.
Does it pencil? Butt said there are issues of “underlying fiscal and commercial uncertainty” remaining.
He said while for the first time there are four parties involved, the fifth party — the state — isn’t yet involved.
The project has strong benefits, particularly the large known resource on the North Slope.
There are ways to make it work with all five parties working together, but collaboration is required, he said.
The companies have called this an “unprecedented opportunity,” Butt said, but “it has unprecedented challenges” and “unprecedented levels of collaboration” will be required for the project to pencil out.
What will be crucial for the project in the market will be cost of supplies, he said, “what you want to do is be in the right place at the right time ... and the way you do that is cost of supply.”
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