7-8-15 Larry Persily's Outstanding Gas Pipeline/LNG Project Essay

Pipeline Building Is A Choreography Of Coordinated Steps

By Larry Persily

July 7, 2015

(This update, provided by Larry Persily (NGP Photo) of the Kenai Peninsula Borough mayor’s office, is part of an ongoing effort to help keep the public informed about the Alaska LNG project.)

The Alaska LNG project is a planning and coordinating effort of immense proportions. Not surprising when you consider that the pipeline construction alone requires piecing together about 115,000 40-foot-long sections in precise order, in rough terrain, in remote locations — and with 446 waterbody crossings.

That’s 447 if you count the almost 30 miles across Cook Inlet to reach the proposed liquefaction plant at Nikiski.

The project teams are mapping out every detail of building 870 miles of pipeline to move natural gas from Point Thomson to Prudhoe Bay (about 63 miles of 32-inch-diameter pipe) and on to Nikiski (about 807 miles of 42-inch pipe). The right amount of pipe has to be at the right place at the right time with the right equipment for welding, digging and pipe laying during two years of construction, and that’s after two years of prep work to build construction camp and compressor station pads, storage yards, clear rights of way, develop gravel sources and create access roads.

No easy task when you’re moving and frequently relocating 9,000 pieces of equipment that would be used to build the mostly buried pipeline. Still more equipment would be used to build the North Slope gas treatment plant and the liquefied natural gas plant and marine terminal at Nikiski. An estimated 5,000 to 7,000 workers would be on the pipeline crews, with all of them living in work camps. Several thousand more are expected on the job at the gas treatment plant and the LNG plant, with the project estimating 15,000 workers total.

Pipe storage yards would be sited about every 18 miles along the route, with the project requiring about 18 million cubic yards of gravel for access roads, pipeline right of way and compressor station pads. The project would use existing pads wherever practical.

Think of it as a choreography of engineers, geologists, biologists, environmental specialists and logistics planners. Everyone has a role and everything has its place. And it’s all synchronized for efficiency, cost savings and to limit environmental impact.

“Pipeline construction is a moving assembly line,” an Alaska LNG team member said.

INFORMATION SHARING AT WORKSHOPS

Almost two dozen Alaska LNG team members met with nearly three dozen federal and state regulatory agency personnel June 24-25, 2015, in Anchorage to share preliminary plans for pipeline construction and waterbody crossings and to listen to how and where the plans might be improved.

It’s not only construction needs that dictate the planning work. There are operational issues to consider, too. For example, the gas will be cooled for transit through permafrost zones along the proposed route so that it doesn’t melt the ground. That will require cooling units at the first six compressor stations whose job is to keep pushing gas through the line.

But the last two compressor stations on the route southward, including the one before the line enters Cook Inlet, will be built with heating units to warm up the gas in an effort to match the ground temperature in Southcentral Alaska and the water temperature in the inlet. Just as thawing frozen ground is bad, so too is freezing soil in the wrong places.

The gas temperature should mimic the terrain it moves through, not change it. As an Alaska LNG team member said, the idea is to work with Mother Nature, not against her.

If the project stays on schedule, if the marketplace cooperates, if the project sponsors and the state of Alaska successfully negotiate fiscal terms, and if investors sign up for the $45 billion to $65 billion project, site preparations for the pipeline work could occur in 2020-2021, with actual pipeline construction in 2022-2023 and first LNG production in 2024-2025. There are a lot of unknowns to get to that point, but the project teams are doing their part to get ready.

The teams are from project partners ExxonMobil, BP, ConocoPhillips and TransCanada. The state of Alaska is also an investor in the project.

WATERBODY CROSSINGS

Of the 446 waterbody crossings, Alaska LNG’s preliminary plan is to:

Use open-cut trenching to install the pipe in a little more than half the locations.
Temporarily restrict or divert the water flow for pipeline installation at fewer than half the crossings — called “flow isolation”.
Drill and pull the pipe under the river or bridge the waterway in a small number of locations, likely single digits.

While still preliminary, the plan is to dig trenches and lay pipe across approximately half the open-cut water crossings during the winter, when the flow is frozen or minimal. The others would be crossed during the summer, when crews would work fast and, in some small crossings, the pipe could be in place in a matter of hours.

Temporary diversions would be used for the flow-isolation crossings, which could include water-filled “aqua dams,” sand bags, concrete blocks, steel flumes or pipes — it just depends on the water flow, soil and site conditions, team members explained.

Alaska LNG will decide on the most appropriate water-crossing methods in consultation with the Alaska Department of Fish and Game, U.S. Army Corps of Engineers and other state and federal agencies. Pipe specifications will be under the jurisdiction of the U.S. Pipeline and Hazardous Materials Safety Administration.

The “trenchless” crossings will use horizontal directional drilling to run pipe under the river bottom. The process involves drilling an initial pilot hole beneath the river, about 5¼ inches in diameter, then using successively larger drill heads to ream out the hole, making it bigger until it is maybe a foot larger in diameter than the 42-inch steel pipe, team leaders told federal and state regulators. The full length of the pipeline, all welded together and laid out in a large staging area at the entrance to the hole, is then pulled through to the other side.

An Alaska LNG pipeline team member said the process is so accurate that crews can drill the pilot hole and hit a stake on the other side of a river.

But sometimes the river is too deep, the ground too full of boulders or the geology just not right to go through or under the waterway. In those cases, the Alaska LNG teams are looking at building pipeline bridges, especially in areas of steep terrain.

A particularly steep area along the route is in the Nenana Canyon, just south of the community of Healy and east of Denali National Park, in a tight area of the Parks Highway, Nenana River and Alaska Railroad. Project teams are working to find the best way through that congestion.

The bridge proposals are still preliminary, as are all of the water crossings, team members told state and federal regulators. The teams and their consultants have a lot of work to do this summer to firm up their plans, with more information and a lot of details to come in the next round of environmental reports the project expects to file in February 2016 with the Federal Energy Regulatory Commission.

In addition to consulting with state and federal wildlife, lands and water managers, Alaska LNG will be working with a visual-impact consultant regarding the bridges, which likely would be within eyesight of travelers on the Parks Highway, a National Scenic Byway.

PIPELINE CONSTRUCTION PLANS

Much of this summer’s field work and office analysis is aimed at better identifying soil conditions, terrain, hillsides, vegetation, geology, safety and environmental concerns as Alaska LNG continues to make decisions not only on waterbody crossings but also pipeline specifications to match different ground conditions such as discontinuous permafrost that would put additional stress on sections of pipe.

Highway and road crossings will be underground, generally at least four feet below the road base, the teams reported, with heavier steel pipe for additional protection.

Current plans, subject to change, show about 45 percent of the Prudhoe-to-Nikiski pipeline built in the winter season and 55 percent in the summer, over two years. Depending on the weather — freeze-up, break-up, road restrictions and terrain — some of the pipe laying could be done in shoulder months, the teams said.

All 63 miles of the Point Thomson line would be built above ground and during the winter.

The mainline would likely be divided into four “spreads” of about equal mileage, with four contractors all working at the same time on their spread. Crews would move around, laying pipe in areas best suited for the season. Frost heaves, permafrost, thaw settlement, steep terrain and fish and wildlife would be among the considerations in deciding summer and winter work.

Some areas will be more easily accessible to work crews than others. Reaching the pipeline work on the West Side of Cook Inlet will be challenging, the teams reported. Contractors would move some equipment and pipe by barge from Anchorage, and the current proposal is to move much of the equipment across the frozen Yenta River in the winter, then park it there until construction work resumes with warmer weather for the final southerly push toward tidewater

For those last miles on the West Side of Cook Inlet, the pipeline route would be in the uplands, away from the wetlands and the ENSTAR gas line and behind the Beluga power plant before turning toward the inlet.

The Cook Inlet crossing would be a separate contract; that work will be covered in an Alaska LNG workshop for state and federal regulators in August.

Pipe laying on the Kenai Peninsula, for the last miles to the LNG plant site, would be scheduled for the second construction summer, 2023, according to preliminary schedules.

Tokyo Gas sees Alaska in potential LNG supply mix

By Larry Persily lpersily@kpb.us

June 9, 2015

This report, provided by the Kenai Peninsula Borough mayor’s office, is part of an ongoing effort to help keep the public informed about global LNG markets and the potential for the Alaska LNG project.)

Natural gas can grab a bigger share of Japan’s energy mix in the years ahead if the price is “economically reasonable,” said a senior vice president of Tokyo Gas, adding that diversified supply sources are also important to the country that is so dependent on imported energy.

Affordable pricing, as it affects Japan’s demand for liquefied natural gas imports, could mean a difference of up to 40 million metric tons a year (more than 5 billion cubic feet of natural gas per day) by 2030, said Tomo Hoshizaki, senior vice president for midstream and downstream business development at Houston-based Tokyo Gas America, the utility’s U.S. subsidiary.

Price is that important, he said, particularly for power generation and industrial customers, though Hoshizaki never quoted a price or provided a range of what might be considered “economically reasonable.”

He did, however, list several potential new long-term LNG supply sources for Japan, including Alaska, Canada, the U.S. Gulf Coast, Russia and East Africa. Hoshizaki presented at the Canada LNG Export Conference May 21 in Calgary, Alberta.

Tokyo Gas was an original customer of the LNG plant in Nikiski, Alaska, when Phillips Petroleum and Marathon Oil started shipments of Cook Inlet gas in 1969 from the first export plant in the United States. The small plant is still in operation. A partnership of ConocoPhillips, ExxonMobil, BP, TransCanada and the state of Alaska is looking at the same industrial area in Nikiski to build a much larger plant — almost 20 times the capacity — to liquefy Alaska North Slope gas for export. An investment decision could come by 2019.

Much of Japan’s potential for increased LNG demand could come from the permanent retirement of many of its nuclear power plants, Hoshizaki explained. Though Japan is expected to restart some of its shuttered nuclear reactors — closed down after the 2011 Fukushima disaster — their output will start declining in the 2020s as many reach the end of their 40-year life span. That opens up the potential for increased natural gas imports, but only if the gas is affordable and the supply is sustainable, Hoshizaki said

Price is imperative. Japan paid $29 billion for LNG in fiscal year 2010, the last full year before the Fukushima meltdown drove up gas imports to replace lost nuclear power. The country’s LNG import bill in calendar 2014 was $65 billion, according to a presentation in Calgary by Takashi Yamada of the Japan Oil, Gas and Metals National Corp.

Tokyo Gas, Japan’s third largest buyer of LNG behind Tokyo Electric and Chubu Electric, last year purchased almost 13 million tons of LNG, holding long-term contracts for supply from Australia, Malaysia, Brunei, Indonesia, Qatar and Russia. It also has contracts for LNG deliveries from two U.S. export plants under construction.

The utility forecasts its import volume climbing to 16 million tons by 2020, mostly for increased sales to industrial users and power generators. “LNG and natural gas demand can be increased by competitive and sustainable supply,” Hoshizaki said.

LNG prices in Asia have come down substantially in the past year, both long-term contract prices linked to oil and spot prices driven down by the current oversupply in the market. To keep prices affordable in the years ahead, Tokyo Gas is looking for pricing linked to market supply and demand, not just strictly oil. And it wants more flexibility to move around the cargoes it buys to better serve its own financial interests, not the market-control interests of exporters.

Hoshizaki showed a slide listing seven Japanese LNG importers that have all signed contracts to take LNG from plants under construction in Texas, Louisiana and Maryland, with the cargoes priced at the U.S. benchmark for natural gas plus liquefaction and shipping costs — no oil linkage.

The Japanese trading company Mitsubishi is one of those seven buyers of U.S. LNG, and an official from one of the company’s subsidiaries said at the Calgary conference that the biggest long-term growth potential for LNG demand in Asia will not come from the two largest customers today, Japan and South Korea, but from China, India and Southeast Asia.

Shinya Miyazaki, CEO of Diamond Gas Management Canada, a Mitsubishi subsidiary active in Canadian gas development and LNG export proposals, said his company forecasts an additional 130 million tons a year of LNG demand in Asia between 2015 and 2030, much of it from China and India.

Vancouver-based Teekay Corp., which operates 48 LNG tankers, also sees the strongest long-term growth potential in China and India, said Ian Fraser, director of Teekay Gas Services. LNG import capacity in those two countries is set to triple by 2018, Fraser said, with further growth expected.

Potential new suppliers include Canada, the U.S. West and Gulf coasts, Russia and East Africa, along with expansions in supply from Australia and the Middle East, Miyazaki said.

Positive qualities for potential LNG suppliers looking to sign up customers include abundant, proven resources, along with predictable delivery, government support, proximity to the Asian market, destination flexibility and allowing investment in the full value chain. Negatives, Miyazaki said, include no history of LNG exports, and regulatory, fiscal and labor uncertainties.

Community acceptance, also called “social license,” is one of those uncertainties, and a frustrating one for proponents of LNG export projects on Canada’s West Coast. A lack of social license for energy projects is denying Canada access to global markets, said Perrin Beatty, president and CEO of the Canadian Chamber of Commerce.

“It is so often discouraging to read the news and see the headlines” of energy-vs-environment debates, he said, referring to disputes over oil and gas pipeline routes and LNG plant sites. “Anything that diminishes the Canadian brand costs us.”

Energy Department approves Alaska LNG exports

By Larry Persily lpersily@kpb.us

May 29, 2015

(This update, provided by the Kenai Peninsula Borough mayor’s office, is part of an ongoing effort to help keep the public informed about the Alaska LNG project.)

Acknowledging that the Alaska LNG project is different from 32 other export applications on file, the U.S. Department of Energy May 28 granted conditional approval for liquefied natural gas exports from the proposed terminal at Nikiski, Alaska.

Approval for exports to nations lacking free-trade agreements with the United States — including major LNG buyers Japan, Taiwan, China, India and other Asian nations — is a big step for project developers looking to make sales calls on prospective customers. The Alaska LNG partners applied for export authority 10 months ago; some Lower 48 projects have been waiting three years for Energy Department approval.

Alaska LNG received approval for exports to free-trade nations in November 2014, but other than South Korea, none of the 20 nations on the U.S. free-trade list are significant LNG customers.

In granting conditional approval for sales to non-free-trade nations, the Energy Department said Alaska LNG is different from Lower 48 proposals because North Slope gas is stranded, unable to reach domestic or foreign markets. As such, exports of Alaska gas overseas would not diminish the amount available to Lower 48 consumers — a major consideration for the department in its review of proposed export projects on the U.S. Gulf, East and West coasts.

The department in August 2014 amended its procedures and stopped issuing such conditional approvals, instructing applicants that they needed to complete their full environmental review at the Federal Energy Regulatory Commission before a decision would be taken on their export application. That rule change did not apply to Alaska, which the department said it would consider separately.

In its May 28 order, the department noted the Alaska project “is substantially more capital-intensive and will require substantially greater expense toward environmental review than any project that has been proposed for the Lower 48.” As such, the regulatory certainty of export approval — even conditional approval — “will be of greater benefit” for the Alaska project, which the sponsors told the department could cost $1.5 billion for environmental and engineering work to reach FERC approval.

Energy Department approval of Alaska is conditioned on FERC completion and acceptance of an environmental impact statement for the project. The partners are working with federal regulators on gathering environmental and engineering data that will go into the EIS, with the project expected to file its formal application with FERC in late summer 2016.

Alaska LNG, under its current work schedule, hopes for a final EIS and FERC decision by fall 2018, putting the partners in a position to make a final investment decision on the $45 billion to $65 billion development. The sponsors include North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips, along with the state of Alaska and pipeline partner TransCanada.

Construction could take four or five years, with first gas deliveries possible by 2024-2025.

The boom in U.S. shale gas production has sparked a push to build liquefaction plants to ship the fuel to overseas buyers. LNG export terminals are under construction in Texas (one), Louisiana (two) and one on Chesapeake Bay in Maryland. The department has granted export approval to an additional four projects, though each lacks either FERC approval to proceed or an investment commitment by project sponsors.

The Energy Department granted Alaska LNG’s request for 30 years of exports, at a maximum of 20 million metric tons per year — averaging 2.5 billion cubic feet per day of natural gas liquefied and loaded aboard specially designed ships to keep the LNG cold during the voyage overseas. At 30 years, the approval is 10 years longer than the department has granted most export applications.

Under federal law, natural gas exports are generally considered to be in the public interest unless challengers can prove otherwise or the department determines the public would be harmed. The only significant opposition to the Alaska LNG application came from the Sierra Club, which cited alleged environmental damages. The department dismissed the group’s objections.

Among the conditions imposed on Alaska LNG, the Energy Department required:

– Project updates April 1 and Oct. 1 each year, including reports on the status of any long-term sales contracts.

– Alaska LNG partners must file with the department any long-term sales contracts, though the companies may request confidentiality of proprietary information.

– Department approval for any change in management control of the project.