There will be another large field season to gather data for a proposed large North Slope gas pipeline and liquefied natural gas project, the company group working on the project said.
The effort will put more than 300 people into the field next summer, and is about twice the size of the 2013 season, which included about 150, said Steve Butt, an ExxonMobil official who is project manager for the group that includes North Slope producers BP, ConocoPhillips, ExxonMobil, and pipeline company TransCanada. Exxon Mobil is leading the effort.
Butt said work is also continuing on engineering, design and regulatory issues.
Costs of the project are estimated at $45 billion to $65 billion, which will include a large Gas Treatment Plant on the North Slope, a 42-inch pipeline of about 800 miles, and a large LNG plant at Nikiski, on the Kenai Peninsula.
Butt spoke at the Resource Development Council’s annual conference Nov. 21.
Meanwhile, engineering and planning is continuing on a state-led 36-inch gas pipeline project on a route from the North Slope to Southcentral Alaska.
Dan Fauske, president and CEO of the state-owned Alaska Gasline Development Corp., or AGDC, said his project is working toward a planned “open season” for potential gas shipping customers in early 2015. Of course, if the large gas project moves forward the AGDC project would not be built, as it is planned as a contingency to get North Slope gas to Alaska communities if the large project is delayed or cancelled.
As for the larger project, Butt said that unstable discontinuous permafrost soil conditions along the pipeline route through Interior Alaska remain a serious concern and that work is underway on pipeline designs that will keep the 42-inch buried pipeline stable through the freeze-thaw cycle of soil temperatures.
“Having TransCanada as part of our team offers a big benefit in addressing this. TransCanada has a long history in building gas pipelines in northern soil,” Butt told the conference.
He said nothing, however, on whether the companies involved are close to agreements among themselves as to how to proceed with the project.
Gov. Sean Parnell had asked the group earlier this year to reach such a commercial agreement and to begin the Pre-Front End Engineering and Design, or pre-FEED, a step that would require a commitment of several hundred million dollars.
The companies missed a milestone Parnell had set to reach the agreement and begin the pre-FEED work in June.
In an earlier interview, however, new state Natural Resources Commissioner Joe Balash downplayed this, saying the design and engineering work the companies are now doing involve elements of work that would be done in a pre-FEED, and that he believes the companies are making progress toward the commercial agreement.
“In some ways this is semantics. They are doing a lot of the work, but don’t yet want to call it pre-FEED,” Balash said. “What they may be waiting for is some signal from the state on a long-term fiscal agreement,” on tax and royalty terms for gas production, which the companies say they need.
“There may be kind of a dance going on, with them taking incremental steps and waiting for us to respond,” he said.
The state took a major step toward this Nov. 18 with release of a study by Black & Veatch, a consulting firm, outlining fiscal issues the project faces and steps the state can take to address those, including a possible state equity investment in the project.
Butt defended the pace of the project in his Nov. 21 briefing, saying careful planning is needed in project management.
“Good project management is all about reducing uncertainty and ensuring the project will work as expected for at least 35 years. This kind of assurance is needed to get customers to sign long-term contracts, and who have to have absolute confidence you will deliver every day,” he said.
Butt outlined key accomplishments of the group so far including agreement on design concepts for a 42-inch pipeline, a three-train LNG plant at Nikiski that would ship 16 million tons to 18 million tons of LNG annually, and a Gas Treatment Plant at Prudhoe Bay that would be integrated into existing gas handling plant infrastructure. A “train” is a production module.
“On previous efforts to build a gas pipeline the parties never gotten this far,” on technical aspects, Butt said.
One noteworthy accomplishment is agreement on how the large Gas Treatment Plant on the North Slope, itself a mega-project, can be built.
“Detailed studies of how to integrate gas treatment facilities into the Prudhoe Bay gas plants, have never been done before,” he said.
The GTP work required an integrated effort with the Prudhoe Bay producers, which involve the same companies with also others minority owners.
That coordination between the gas project and the producer companies will continue because a key problem facing the project is finding some use for carbon dioxide that will have to be removed, which amounts to one-eighth of the raw gas. Using the CO2 in enhanced oil recovery in Prudhoe or other North Slope fields is currently being explored, Butt said.
A major step for the project was the selection, this summer, of the site for the LNG plant at Nikiski, on the Kenai Peninsula south of Anchorage. The pipeline would now be parallel to the existing Trans Alaska Pipeline System from the North Slope to the state’s Interior and then branch off on a new route to Southcentral Alaska.
At the RDC conference, Butt mentioned more details about the LNG plant, that it would include three large LNG storage tanks, two loading berths and that an LNG tanker would be loaded every two days.
On Cook Inlet marine conditions and navigation issues, Butt said, “We are still doing a lot of study on this but we believe we can it work. The ice is different in the Inlet. It is shore ice, and it is broken (by tides) and moves around,” but the group is satisfied that the ships can be moored safely.
Marine pilots from several parts of the world are being consulted on the navigation issues, and the St. Lawrence River seaway in eastern North America is being studied as an analog, he said. Large crude oil carriers navigate the St. Lawrence seaway, where there is also ice similar to Cook Inlet, and tides.
In addition to permafrost soils in the Interior, construction challenges for the pipeline include crossings of two major rivers, the Yukon and Susitna rivers, a corridor through or near Denali National Park, and a crossing of Cook Inlet to the Kenai Peninsula.
In previous interviews, Butt said Nikiski was chosen mainly because sufficient vacant land is available near existing industrial sites and infrastructure, and because weather conditions will allow year-round construction.
In his presentation on the state-sponsored AGDC project, Fauske said his group has spent about $70 million on engineering and permitting to date and that the Legislature’s appropriation of $355 million earlier this year will allow the state corporation to complete engineering and design work that will be sufficient for the open season.
If the project were to proceed, which assumes that the bigger industry-led group fails, AGDC has estimated the cost of a 737-mile, 36-inch pipeline and gas treatment plant at $7.7 billion, which includes $2.8 billion for the gas plant at Prudhoe Bay; $3.03 billion for the 36-inch pipeline to Dunbar, near Nenana in Interior Alaska; $70 million for a 12-inch, 35-mile lateral line to Fairbanks, and $1.8 billion for a remaining 36-inch pipeline from Dunbar to the Matanuska-Susitna region north of Anchorage where the pipeline could connect with existing pipelines owned by Enstar Natural Gas Co.
The pipeline would operate with an operating pressure of 1,480 pounds per square inch, which is sufficient to transport some volumes of propane along with methane, the component of natural gas used for fuel, Fauske said.
The propane would find a ready market in Alaska.
However, AGDC’s project is still limited to moving 500 million cubic feet per day of gas under the state’s current contract with TransCanada Corp., under the state Alaska Gasline Development Act, or AGIA.
The current in-state demand for gas, mostly for utilities, is estimated at about 240 million cubic feet per day, so large industrial customers would have to be found to purchase the remaining gas.
Tim Bradner can be reached at email@example.com.