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Providing coverage of Alaska and northern Canada's oil and gas industry
July 2009

Vol. 14, No. 29 Week of July 19, 2009

TAPS transitioning to low flow future

Strategic reconfiguration of the trans-Alaska pipeline moves ahead, while engineers assess the challenges of declining flow rates

Alan Bailey

Petroleum News

At the end of May, the switchover to new electric pumps at pump station 4 of the trans-Alaska oil pipeline marked the latest major step in the upgrade of the pipeline system to accommodate declining rates of oil production from Alaska’s North Slope. In fact, the decline of flow rates from 2.1 million barrels per day in 1988 to around 700,000 bpd at present and a likely 500,000 bpd in the next decade poses one of the biggest challenges faced by Alyeska Pipeline Service Co., the pipeline operator, said Kevin Hostler, Alyeska president and CEO, at a media presentation on July 13.

Hostler said that the installation of electric pumps, part of a project that Alyeska refers to as “strategic reconfiguration,” is matching pumping power to throughput volumes, but that other challenges resulting from low flow rates, such as low oil temperatures, also need to be addressed.

“We’ve put a smaller engine now on a bigger car and, so, there are still other issues associated with lower throughput,” Hostler said.

The trans-Alaska oil pipeline, characterized by Hostler as a simple pipeline, albeit with an exceptionally large diameter of 48 inches, crosses three mountain ranges along its 800-mile route from Prudhoe Bay on the North Slope to Valdez, on the northeastern side of Prince William Sound. At the Valdez Marine Terminal, oil is loaded into tankers that ply the sea route down to the U.S. West Coast.

Five companies own both Alyeska and the pipeline: BP Pipelines (Alaska) Inc., ConocoPhillips Transportation Alaska Inc., ExxonMobil Pipeline Co., Koch Alaska Pipeline Co. and Unocal Pipeline Co.

Fewer pump stations

Perhaps the most obvious evidence of the “smaller engine” that Hostler referred to is the reduced number of pump stations along the pipeline.

Of the original 11 pipeline pump stations used to move oil during peak throughput, only five remain in use. Three of these remaining stations — pump station 1 at the northern end of the pipeline, and pump stations 3 and 4 — propel the oil up to the 4,739-foot Atigun Pass in the Brooks Range. From this high point the oil flows downhill 350 miles south to pump station 9, near Delta Junction. Pump station 9 drives the oil over mountain passes in the Alaska and Chugach ranges, with the oil eventually flowing down into storage tanks in the Valdez Marine Terminal.

Pump station 5 on the south side of the Brooks Range does not pump the oil: It acts as a relief station for oil flowing down from Atigun Pass.

Under strategic reconfiguration, a train of new centrifugal pumps, each driven by a purpose-built 6,500-horsepower electric motor, replaces the turbine-powered pumps that were installed at each pump station when the pipeline was first constructed. Whereas the old pumps had limited capabilities for power adjustment and could not operate at very low flow rates, the new pumps use variable frequency drives and can be switched in and out of operation, thus enabling great flexibility in handling different levels of pipeline throughput.

One at a time

As part of a plan to switch the pump stations over to the new technology, one station at a time, Alyeska applied the on switch to the new pumping system at pump station 9 in February 2007, with the required electrical power flowing from the local electric utility — a backup, on-site generator could plug the power-supply gap, were the utility to experience a blackout.

Pump station 3 started its electric pumps in December 2007, and now pump station 4 has followed suit, both using large turbine generators for power. That leaves pump station 1 to be converted, an operation that Alyeska expects to complete in late 2011 or early 2012.

In the summer of 2008, during a pipeline shutdown, the old turbine system at pump station 9 was disconnected from the system, Alyeska senior project manager Jerry Vega told the media briefing.

“We can’t go back to the old system … any more,” Vega said.

And the old equipment was disconnected in pump station 3 in June of this year, he said.

Alyeska experienced problems with vibrations, both inside the new pump modules and in the pipeline itself, when the converted pump stations went on line. The pipeline vibrations resulted from the use of new pipeline supports designed to avoid the need for winter snow removal at the pump stations, said Matt Carle, Alyeska external affairs manager.

The pump vibrations have been eliminated, while the pipeline vibrations have been controlled, using steel bracing on the pipeline supports, Vega said. And the new pumps are operating well, following adjustments made to accommodate minor quirks found when operating the systems in cold winter conditions at pump station 3, he said.

“All of the different components of the system have met our performance criteria,” Carle said.

New control systems

In parallel with upgrading the pumping systems along the pipeline, Alyeska has been engaged in a complete replacement of the aging pipeline control systems, using state-of-the-art digital technology to enable monitoring and control of the entire pipeline from a single control center and the collection of data for improved maintenance efficiency, thus reducing operations and maintenance costs as oil volumes decline.

And as part of the control systems upgrade, in early 2008 Alyeska moved the pipeline control center from Valdez to Anchorage, with modern fiber optic telecommunications, backed up by a microwave system, used to transmit data and control commands up and down the pipeline.

One section of the control center manages the pipeline while another section manages the Valdez Marine Terminal, Betsy Haines, Alyeska oil movements director, told the media briefing. There is also a duplicate, backup control center at a secret location in the Matanuska-Susitna Borough, she said.

All of the pump stations, including pump station 1, are now fully controlled from the control center, as distinct from being operated by on-site pump station personnel, Haines said.

“The requirement for any operator support now is primarily at pump station 1, strictly from the point of view of observation as the equipment starts up,” she said.

And, apart from pump station 1, where personnel will always be required for situations associated with operating the storage and oil intake arrangements at the upstream end of the pipeline, centralized control of the pipeline system is leading to de-manning of the pump stations, with just oil spill response and maintenance crews remaining at some pump stations, ready to deploy in the event of an emergency.

Pump stations 9 and 3 are already fully unmanned from an operations perspective, and the living quarters were removed from pump station 3 this summer, Vega said.

The site of the long-defunct and dismantled pump station 8, between Fairbanks and Delta Junction, has found a new role in helping deal with increased wax deposition within the pipeline, as the flow of oil through the line declines. This summer Alyeska is installing new equipment at the site to enable retrieval, cleaning and reinsertion of pigs, torpedo-shaped devices used to clean wax from inside the line, during the devices’ 800-mile journeys from Prudhoe Bay to Valdez — currently the pigs can only be retrieved at pump station 4, towards the northern end of the pipeline, Vega said.

Valdez Marine Terminal

Declining pipeline throughput is also having a major impact at the Valdez Marine Terminal.

The terminal is currently using 15 of the 18 original crude oil storage tanks, senior project manager Curtis Nuttall told the media briefing.

“In the future we plan on dropping it down to eight to 12 tanks,” Nuttall said.

And just two of the original four tanker loading berths continue in operation.

“We are currently overhauling those (operational) berths,” Nuttall said.

And the mandated use of double-hulled tankers at Valdez, as well as the reduced oil throughput, has dramatically reduced the amount of ballast water from arriving empty tankers that needs to be treated.

“The tanker operators elected not only to double-hull, but to use segregated hulls for their ballast (water), which means they don’t have dirty ballast,” Nuttall said.

Previously, the ballast water went into the crude hold, thus contaminating the water and making it necessary to treat the water on removal from the tanker.

Years ago, with the old tankers and large numbers of tanker operations, the processing of perhaps millions of gallons of ballast water per day involved floating the oil from the water, then using air bubbles to float out further oil and finally using bacterial treatment to eliminate any remaining hydrocarbons, before discharging the treated water into the sea.

However, as the ballast water throughput declines, the bacterial treatment becomes ineffective because the bacteria tend to starve.

“So what we’ve had to do is replace that whole large biological system with air strippers,” Nuttall said.

And Alyeska is engaged in a three- to four-year, $100 million retrofit of the entire ballast water plant, including the installation of vapor control equipment, equipment not legally required but viewed by Alyeska as a safety need, Nuttall said.

Low flow

However, Alyeska foresees further technical challenges along the pipeline system as oil throughput continues to go down: The company has initiated a $10 million low-flow study, to find solutions to the various issues involved.

The study started in August 2008 and is slated for completion at the end of 2010, Pat McDevitt, the low-flow study project manager, told the media briefing.

“As the flow rates decline, the transit time for the oil to travel increases,” McDevitt said. “So, at 2 million barrels per day … it took four and a half days or so to get from pump station 1 to Valdez. Right now it’s about 13 days. … At 500,000 barrels per day it’s about 18 days.”

The declining velocity of the oil causes the flow to become less turbulent, thus increasing the likelihood of any water and sediment in the oil dropping out. And, because the oil remains in the pipe longer at low flow rates, the oil becomes colder as it traverses the line — at a throughput of 500,000 barrels per day, Alyeska expects the oil temperature to drop below 32 F, the freezing point of water, along some pipeline segments, McDevitt said.

Most water is removed from the crude oil before the oil enters the trans-Alaska oil pipeline, but a small amount of residual water remains in the oil, McDevitt explained. And although the water is saline, ice formation within the pipeline or associated equipment could cause problems, while the salty water and sediment separated from the oil could heighten the risk of internal pipeline corrosion.

In addition, the lowering temperatures will further increase the amount of wax deposited in the pipeline from the oil, thus increasing the amount of pipeline and tank cleaning required.

And cold oil could change the thermal characteristics of the ground around the pipeline, potentially causing frost heaves that could move the pipe.

McDevitt characterized the low-flow study as science research that is proceeding along several fronts, such as flow testing in a test rig in a special cold room at Imperial Oil’s facility in Detroit, and the testing of ice formation and ice strength in sample oil that is cooled down.

Possible solutions to pending problems include tightened limits on the amount of water allowed in the pipeline; adding chemicals to prevent wax deposition; increased pigging for wax and water removal; heating of the oil at certain points on the line; and the use of freeze-suppressant chemicals.

Corrosion

But given the pipeline corrosion problems and associated leaks in the aging oilfield infrastructure at Prudhoe Bay, where low oil flow rates have also become an issue, how confident is Alyeska that similar problems can be avoided in the trans-Alaska pipeline?

To prevent corrosion, which has proved in the past to be less of a problem on the inside of the pipeline than on the pipeline exterior, the pipeline has a protective coating; there are cathodic protection systems for pipelines and tank bottoms; corrosion inhibitors are mixed with the oil; and pigs are used frequently to clean the inside of the main pipeline, Tom Webb, Alyeska’s engineering integrity manager, told the press briefing.

“We run cathodic protection surveys on an annual basis … to measure the level of protection to the buried metallic piping structures,” Webb said. There are test stations every half mile on the pipeline, he said.

Alyeska runs a magnetic flux leakage pig down the line every three years to obtain a profile of precise pipeline wall thicknesses and hence determine where corrosion is occurring. And every five years another type of instrumented pig detects any changes in pipeline shape.

“We’ve got locations of every corrosion point on the pipeline,” Webb said. “We know the magnitude of that corrosion.”

Successive runs of the magnetic flux leakage pig enable engineers to trend and map the corrosion, enable people to determine where the corrosion is focused and then take any necessary actions such as reviewing the cathodic protection levels, or repairing the line.

Facilities in the pump stations that cannot be accessed by a pig are subject to regular inspections under a pipeline integrity testing program — more than 800 inspections are scheduled for 2009 under this program, Webb said. Tanks are also inspected regularly.

“We have had no corrosion leaks in over 30 years of service on TAPS to date, and we intend to keep it that way,” Webb said.






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