In the beginning, it was an occasional skirmish. Thirty years later, Alyeska Pipeline Service Co. is embroiled in a full-scale war on corrosion and destructive forces attacking the trans-Alaska oil pipeline.
Alyeska President and CEO Kevin Hostler boasted in June that the pipeline is in pretty good shape after 30 years of operation.
But like any well-toned mechanism, the pipeline system pays a considerable price for its attractive condition.
A corrosion-related oil spill has never occurred in the trans-Alaska oil pipeline system, Hostler said. And, since dry oil passes through the pipeline, internal corrosion isn’t as much of an ongoing concern as external corrosion.
Alyeska addresses corrosion control, monitoring and prevention with the best technologies the industry has to offer, many of which the company helped develop.
From the beginning, the company has committed to aggressive inspection and monitoring designed to detect the tiniest changes possible in the 800-mile mainline from Prudhoe Bay to Valdez and in the ancillary pipelines, storage tanks, valves, pumps and other equipment in the system.
“Alyeska was one of the more aggressive users of in-line inspection tools from Day 1, so that when changes occurred in the pipeline we were on top of them,” said engineering advisor Elden Johnson, who was there at the beginning after helping to design and develop the pipeline in the mid-1970s.
In-line inspection tools, or pigs as they are commonly called, have become one of Alyeska’s most important inspection technologies.
“Thirty years ago the pigs were pretty rudimentary. We were lucky if they detected a 50 percent wall loss,” Johnson said. “Now they can detect as little as a 10 percent wall loss.”
Alyeska’s leadership also encouraged others in the oil industry to use inspection pigs, Johnson said.
Focus on external corrosion
Alyeska’s corrosion program began in the late 1980s and resulted in the replacement of about nine miles of corroded pipeline in the Atigun floodplain in the early 1990s. The Atigun pipeline replacement triggered an ongoing “pig and dig” program, Hostler said.
“If you look at our history over the past 30 years, as we do our inline surveillance and our inline pigging runs … what we’ve always seen and continue to look for is the impact of external corrosion, primarily as a result of water getting underneath the insulation,” Hostler said.
The company requires pipeline repair or replacement in any area where surveillance discovers a corrosion anomaly impacting more than 40 percent of the pipeline wall, he said.
That standard applies to the whole length of the pipeline, despite the fact that only about one-third of the pipeline lies in “high-consequence” areas where the U.S. Department of Transportation would mandate that 40 percent limit, Hostler said. In less critical areas DOT mandates repair or replacement when corrosion anomalies impact 80 percent of the pipeline wall thickness, he said.
Alyeska also uses cathodic protection to help prevent corrosion, especially on buried sections of the pipeline, which span close to 380 miles. However, the pipeline’s location relatively close to one of the earth’s magnetic poles created special challenges. Telluric currents, the forces that cause the Northern Lights, interfere with the cathodic protection.
With the help of the Geophysical Institute of the University of Alaska Fairbanks, Alyeska developed a method to measure and compensate for telluric currents.
Alyeska buried about 800 steel coupons along the 380 miles of buried pipe. Corrosion engineers can observe differences before and after the cathodic protection current running through the pipeline and the coupons are switched on and off.
It’s an important part of controlling corrosion along buried sections of the pipeline. The coupons yield reliable information about the condition of corrosion protection in the pipeline, Alyeska officials say. Alyeska also buried zinc ribbons next to the pipeline to act as “sacrificial anodes” to inhibit corrosion. In Atigun Pass where nine miles of pipe has been replaced, four magnesium ribbon anodes are used instead of zinc.
The pipeline and zinc anodes pick up the telluric currents and the anodes act like grounding rods to safely return the currents back to the earth, reducing the risk of corrosion damage.
Technology developer role
“We didn’t invent these devices, but the development of them and turning them into common usage in the industry happened at TAPS,” Johnson said.
If Alyeska found that telluric currents were causing interference at a location, engineers would beef up the cathodic protection by using impressed current to fill in the gaps or painting a half-inch-wide zinc ribbon onto the pipeline if the metal’s protective coating is damaged, Johnson said.
Over the years, certain places along the pipeline have experienced significant corrosion, that is, wall loss in the metal of 20 percent or more. Typically, additional corrosion protection is added to the spot, but in some instances, the company covers the affected pipe with a section of new metal called a “sleeve.”
“In an extreme case, we can place the sleeve around the pipe and coat it. Then it’s good as new,” Johnson said.
Sleeves are also used to repair cracks and holes caused by pipe movement and in at least two cases, sabotage.
Alyeska also regularly checks for corrosion the old-fashioned way.
“We have a dig program every year. This year we’ve dug up the pipeline six times,” said Dave Hackney, program engineer in charge of pigging at Alyeska.
In three decades, Alyeska has dug up buried sections of the pipeline 1,000 times, typically 20 feet at a time, according to Hackney.
Looking inside the pipe
Internally, corrosion has not been a significant problem for the main pipeline. Sales quality crude and natural gas liquids have very little water or other corrosive materials in them, and they flow through the pipeline as such high velocities that little water has a chance to settle out of the petroleum.
The pump stations and the Valdez Marine Terminal are a different story.
“We can’t pig those lines and some are low-flow or ‘dead legs’ where the oil just sits in there,” Johnson said.
Transportation crude contains up to 0.35 percent water, “so you can get a little water layer at the bottom of the pipe,” Johnson said.
Alyeska uses coupons to check for corrosion in the low-flow and dead leg lines at least once every six months, he said.
Another method, remote field eddy current, or RFEC, testing, uses a coil of wire carrying low-frequency alternating current to induce eddy currents. Such coils can be made quite narrow, and can thus be used to inspect “unpiggable” pipes from inside.
The U.S. Department of Transportation is funding projects to test this idea in natural gas pipelines. Another concern, especially on the North Slope since the Prudhoe Bay oil spills in 2006, is the possibility of bacteria speeding corrosion, Johnson said.
Alyeska adds corrosion inhibitor to the pipeline system to prevent the little bugs from thriving in water that may be present in the smaller lines.
At the terminal in Valdez, the company has encountered another set of corrosion problems. Pipes inside the treatment system for the highly corrosive ballast water coming off the oil tankers have leaked.
“We learned early on that corrosion took place at joints. In the early 1980s, we had to recoat the ballast water pipeline on the insides,” Johnson said.
Another problem area has been the huge crude storage tanks at the terminal, where water settles to the bottom of the tanks and causes corrosion over time.
Alyeska has placed anodes inside and outside the tanks with cathodic protection and inspected them every 10-20 years, depending on the observed corrosion rates, Johnson said.
One technique the company has used and improved over the years to combat tank corrosion is a Magnetic Flux Leakage, or MFL, detector, a machine that resembles a huge lawn mower. The MFL, which a technician drives over the bottom of the tank, actually casts a magnetic field over the tank floor.
A difference in the thickness of the metal floor will register on the MFL as a disturbance in the magnetic field. This tells the technician that corrosion may be present.
“We can judge the change in the signal to determine how thick the floor is and where we need to replace a section of it,” Johnson said.
Alyeska does worry that the aging infrastructure issues that have surfaced on the North Slope might also apply to the pipeline’s pump stations, said Hostler. So, the company is running a continuous monitoring program in the pump stations, using inline investigation tools. An analysis of monitoring data collected since the summer of 2006 has indicated that the infrastructure in pump stations 1 to 4 is in good condition, he said.
—Petroleum News staff writer Alan Bailey contributed to this article.
