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Right sizing Alyeska doing preliminary Valdez terminal reconfiguration engineering Kristen Nelson Petroleum News Editor-in-Chief
Alyeska Pipeline Service Co. is continuing its efforts to reduce the cost of transporting Alaska North Slope crude oil.
Earlier this year owners of the trans-Alaska pipeline system approved a $250 million reconfiguration project for the pipeline, which is focused on upgrading pump stations.
The company is now looking at changes in how it does business at the Valdez Marine Terminal — changes reflecting both reduced throughput volumes and technology not available when the facility was built in the 1970s.
Conceptual engineering is complete and owners of the pipeline system have approved funding of preliminary engineering for changes at the terminal, where crude oil from Alaska’s North Slope 800 miles away is transferred to tankers.
By the end of this year, or early next year, preliminary engineering work will be complete on changes identified in the conceptual phase, and the owners will be asked to approve work at the terminal, based on costs and schedules developed this year.
The objectives of the terminal reconfiguration are the same as those of the pipeline reconfiguration: “reducing the cost of moving oil off the North Slope,” Rod Hanson, manager of the terminal, told Petroleum News May 24.
The goals of reconfiguration at the terminal, he said, are “to right size the terminal for what we anticipate the future needs are going to be” and to look at technology changes since the terminal was built and use technology to simplify how the facility operates, to “pull complexity out of the system.” Fewer tanks needed The potential changes identified in conceptual engineering include the amount of tankage.
The 18 tanks at the terminal — 14 at the east tank farm and four at the west tank farm — can hold more than 9 million barrels, Hanson said, capacity built to handle throughput which peaked at more than 2.1 million barrels a day. Today, however, the pipeline moves less than a million barrels a day and inventory in the terminal’s tanks runs at around 30 percent.
“We haven’t seen more than 35 or 40 percent now in several years, and it’s often down in the teens” compared to 75 to 80 percent in the late 1980s and early 1990s, Hanson said.
Alyeska has worked with the trans-Alaska pipeline system owners, the mariners and the refineries, he said, “to really take a hard look at how much tankage do we need at the terminal. And the current thinking is that we can likely reduce from 18 tanks down to 14 or possibly 12.” The entire west tank farm would be taken out of service (see terminal diagram) along with some tanks at the east tank farm.
The remaining tanks would more than meet storage needs, Hanson said, noting that at times tankers have to wait to load because previous tankers have drawn down the inventory.
And the tankers also play a role, said John Barrett, Alyeska’s strategic reconfiguration program manager: “The fleet is very well designed right now for the amount of flow that we have through the system, so everything works very efficiently.” Power/vapor major focus While the tanks are the largest feature at the terminal, a major target of the preliminary engineering work is focused on the power plant and vapor recovery system, referred to as power/vapor.
Power/vapor uses vapor from the crude oil storage tanks and from loading tankers, supplemented with diesel, to produce electricity for the terminal. Exhaust from the plant’s steam boilers is used as blanket gas to fill the crude oil storage tanks as the oil is removed.
The electrical generating capacity is 38.5 megawatts, of which the terminal currently uses nine or 10 megawatts, Hanson said, with usage expected to drop to five or six megawatts in the future.
The power/vapor facility will be the first focus of preliminary engineering, said Chuck Strub, Alyeska special projects manager in charge of the changes at the terminal: “The tanks, the vapor recovery off ships and the electrical power generation, all is connected to being able to reduce that facility.” Preliminary engineering will “take those conceptual ideas and from a planning perspective, take a look at how much it’s going to cost” and how long it will take to get payback on that investment, Strub said. Reducing vapors The proposed change would have vapors from loading tankers incinerated close to the berths in use, No. 4 and No. 5, in vapor combustors. Hanson said vapor combustors have been described as an “incinerator in a can.” The vapor combustors operate on demand, unlike the facility’s current incinerators which take a long time to heat up and cool down, so “you can’t just cycle them on and off.”
The vapors from the storage tanks would be eliminated, as would the need for blanket gas, by installing internal floating roofs in the tanks. “It is a roof that floats on top of the oil and moves up and down inside the tank on top of the oil,” preventing formation of vapors as the tank is filled and eliminating the need for blanket gas as the tank is emptied.
That leaves power generation, and with the facility operating at only about 30 percent of its capacity now, the preliminary engineering study will look at two options: “new diesel-fired generators on the facility, sized to meet our demand” or contracting for electricity from the Copper Valley power grid, with “full diesel backup power generation” capability at the terminal.
The idea, Hanson said, is to eliminate everything that’s now done at power/vapor. It would no longer be needed to manage tanker vapors or tank vapors; no longer needed for inert blanket gas; no longer needed for power.
“So, we can shut down this whole facility, which is a pretty significant chuck of our operating and maintenance costs.”
In fact, he said, some major pieces of what the terminal does now, it wouldn’t be doing anymore under the proposed reconfiguration: “You’re not operating west tank farm, you’re not operating (power/vapor).
“You’re operating a smaller east tank farm, two berths and a vapor system.”
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