Parts of Alaska Pipeline Face Corrosion Threat : Energy: Oil firms once swore the metal was protected. But inspections now show costly repairs are required.


Although oil executives once swore that it wouldn’t happen, corrosion is eating through critical sections of the 800-mile-long Trans Alaska Pipeline, threatening its structural integrity and forcing an expensive and unprecedented crash program of repairs.

Pipeline officials were in Juneau, Alaska, last week to explain a rehabilitation plan that could cost the oil pipeline’s operators $1.5 billion and perhaps more over the next five years. That in turn could cost the Alaska state government hundreds of millions of dollars in oil royalties and related revenues.

Federal officials also are concerned because the nation’s foreign trade deficit could increase by more than $1 billion if the pipeline must be shut down for even a few days. Line operators have promised to complete repairs without disrupting oil flow for more than 2.5 days over the next 18 months, though federal regulators say they have heard that the interruption would be longer.

The Times has learned that the federal Office of Pipeline Safety is investigating possible violations of safety regulations. Inspection reports reviewed by The Times question the quality of installation, repair, maintenance and operations of the pipeline.

The reports of large-scale corrosion, coming on the heels of the environmentally devastating Exxon Valdez oil spill last March, have served here to heighten suspicion of Alyeska Pipeline Service Co., the oil industry consortium that runs the pipeline.


“They tell us they just got this state-of-the-art surveillance system, and that’s why they found this,” said Alaska Atty. Gen. Douglas B. Baily. “But we’re not buying that story. This corrosion didn’t just happen. They’ve had other technology to use.”

Because every month of delay represented enormous losses to its owners, the pipeline was built under tremendous pressure to get the job done. Both federal records and regulators suggest now that the severity of corrosion problems might have been lessened and repair costs minimized had Alyeska heeded warnings from critics before completion, not rushed construction work in bad weather and been more aggressive in looking for problems once oil was flowing.

“In the oil business they always say ‘pay me now or pay me later,’ ” said federal pipeline engineer Mark A. Reis, an inspector on the Alaskan line. “This is the ‘pay me later.’ This is the price of deferred maintenance.”

Although company officials acknowledge difficulties, they insist that there is no crisis and that problems can be corrected without imperiling pipeline operations or the ecologically fragile tundra. “We aren’t shutting down the line,” said Bill Howitt, Alyeska’s manager for engineering. “We’re doing the repairs on the fly. We have sufficient early warning in this case. . . . We don’t have pipeline integrity problems.”

But Jack Overly, head of the Western regional division of the federal Office of Pipeline Safety, had a different view. “The extent of it we don’t know,” Overly said of the corrosion problem, “but it’s big enough that it could affect the integrity of the pipeline.”

Interviews with state, federal and company officials, as well as a check of federal records on the pipeline dating back to the early 1970s, indicate that:

--Most of the corrosion was caused by the failure of protective coating and tape wraps, which many critics had warned were flawed long before the pipeline was finished.

--Preparations for lab tests of corrosion protections were begun at the National Bureau of Standards before the pipeline started up. But the tests were never conducted.

--Almost from the start, promises to conduct regular corrosion checks were not kept. During construction, the company said it would make regular runs with corrosion detecting “pigs,” sensing devices designed to slide through the interior of the pipe and indicate thinning of the walls. Officials blamed technical problems, among them fears that a pig might get stuck and gum up the pipeline. Alyeska continued to develop more sophisticated pigs, but not until two years ago did equipment sensitive enough to detect significant amounts of corrosion come on-line.

--Storage tank bottoms at the Valdez terminal are wearing through. Federal inspectors blame salty, untreated sea sand, which they say was used as landfill under the tanks in violation of normal construction principles. Since salt is highly corrosive, sea sand is usually washed with fresh water before it is used as a construction base. However, Alyeska officials insist that the tanks were built atop an asphalt base, not sand.

Corrosion is a slow process that weakens metal over years. And both federal and industry experts agree that, on the basis of information they now have, the corrosion problems on the Alaska pipeline pose no immediate threat to the environment or to pipeline operations.

Textbooks describe corrosion as an electrochemical phenomenon--nature’s way of trying to return refined metals to their natural state. Electromagnetic currents flow naturally through the Earth and enter submerged pipelines. When buried metal comes in contact with water or soil, those substances conduct current off the metal, gradually degrading it by stripping away electrons.

For years, the oil and gas industry has tinkered with schemes to minimize or defeat the corrosion process. Although techniques vary, the primary weapons against corrosion are coatings and tapes to seal out moisture and so-called “cathodic protection” systems that divert the flow of natural current from the pipeline to sacrificial metals placed nearby, which bear the brunt of corrosive effects.

As an important backup, operators periodically run internal corrosion sensing pigs through the pipelines.

But it is the very adequacy of such safeguards--as Alyeska adapted them to the harsh, technologically challenging Arctic climate--that has been called into question by the latest findings.

The primary concern is that, if it is unchecked, corrosion could eventually weaken the half-inch-thick, 48-inch-diameter pipe wall and lead to a blowout, spewing thousands of barrels of crude oil onto pristine wilderness and forcing a shutdown of the line.

Until repairs can be completed, Alyeska has reduced pressure in the line by 20% in key locations. At the same time, the company has kept the oil flowing evenly at about 1.9 million barrels per day by injecting costly friction-reducing chemicals into the line.

Despite such precautions, investigations into corrosion, maintenance, operating procedures and repair programs have been launched by Alaskan officials as well as several federal agencies.

Alaska, where 85% to 90% of revenue in the state Treasury comes from oil-related income, has formally challenged Alyeska’s plans to add corrosion repair costs to a complex formula used to determine the value of oil royalties and wellhead taxes. Baily estimated that such charges could cost Alaska $22 million in 1990 and “hundreds of millions of dollars” over the next five years. If negligence is to blame, then Alaska should not lose a penny, Baily argued.

Meanwhile, The Times has learned, the Office of Pipeline Safety, part of the Transportation Department, may decide by spring whether to cite Alyeska for violations of federal guidelines. OPS is the principle regulatory overseer for 155,000 miles of gas and oil lines across the country.

Although the OPS probe is not complete, staff reports have suggested that Alyeska may have violated federal safety regulations by failing to adequately maintain portions of its cathodic protection system. Another possible violation, according to the same reports, could involve improper welding and repair procedures used to install containment sleeves--in effect, large metal bandages--welded over problem areas on the pipeline.

Federal investigators say the company, under revamped ownership and management, is now moving aggressively to deal with the problem and appears willing to spend whatever it takes to overhaul a structure that, before its completion, planners said would never need a major overhaul. Alyeska has increased the number of corrosion engineers on its staff over the last year from about six to 75, according to OPS sources.

The $7.7-billion line was built by a partnership of oil firms, among them industry giants Sohio, Arco, Exxon and Mobil. Three years ago, Sohio was absorbed by British Petroleum PLC. Through that takeover, the British conglomerate now owns slightly more than 50% of Alyeska and has become its dominant force.

Alyeska’s Howitt said that in 1988 and 1989, runs with the new, more sensitive “super-pigs” identified 827 so-called “anomalies"--spots along the line that may indicate corrosion. But only closer scrutiny, generally digging up suspect spots of buried pipeline, can confirm if anomalies indicate real problems or are merely glitches recorded by the sensing device.

So far, Howitt said, 308 suspect sites have been excavated, including all the company deemed most critical. Inspections at 30 of those locations revealed corrosion “so extensive that there was a danger the line couldn’t support maximum pressures,” he said. Protective sleeves were welded to those spots.

Although half of the pipeline is buried and half sits above ground, Howitt said all potential corrosion problems detected so far involve buried sections.

Howitt said the anomalies under investigation are not sprinkled throughout the pipeline but are bunched largely in four sections totaling about 13.5 miles.

Howitt blamed most of the corrosion problems on a failure of the protective coating system applied to pipes, including both the outer tape wraps and an epoxy sealer known as Scotchkote 202. In testimony Wednesday before the Alaska Senate Oil and Gas Committee, Howitt declared: “If the tape outer wrap had not failed, we would not be here today.”

In an interview, Howitt cited several theories that could have contributed to coating problems: a bad batch of Scotchkote; bad pipes; shoddy application of sealer; installation during bouts of snow, rain and temperatures sometimes dipping to minus 30 degrees below zero; damage from rocks as ditches were filled in after pipes were laid, and even exposure to corrosive salt air when the raw pipes were shipped across oceans from suppliers abroad.

Alyeska, he said, has scheduled a minimum of 2.5 days of service interruptions during the spring of 1991 to replace at least 9 miles of the most suspect pipe, in the Atigun River flood plain zone about 150 miles south of Prudhoe Bay, with new material. OPS officials, however, said they had been told the shutdown could last 10 days and said Alyeska had ordered 22 miles of new pipe as a backup.

Such a program represents a major turnaround for Alyeska, which long had resisted shutdowns of any kind. In June, 1979, for example, 5,500 barrels of oil squirted from the line when ground subsidence buckled two underground sections, one of them in the Atigun mountain pass, another area were corrosion problems are suspected. Instead of replacing the damaged portions, Alyeska plugged the leaks by welding sleeves over the bad pipe.

Defending the procedure in a later report on the incidents, the company pointed to what it said was the “infeasibility” of taking the line out of service to replace a cylinder of pipe. Such an operation, the company said, would have forced a shutdown of more than 10 days for each leak--far longer than Alyeska now says it should take in 1991 for a much bigger job--resulting in a loss of 25.6 million barrels of production.

“To replace that 25.6 million barrels on the world spot market would have increased the national imbalance of payments by about $1.25 billion,” the company wrote in a follow-up report.

At present, the company is also planning major overhauls of several of the dozen pump stations that keep oil moving through the line. Corrosion has attacked internal piping at many of the facilities. Repairs are also targeted for the corroded Valdez terminal tanks.

Estimates of repair costs vary widely. Howitt guessed that the Atigun pipe-replacement program alone would cost $180 million. Reis, a federal inspector on the line, said Alyeska staff had told him that the price tag would run conservatively in the area of $250 million.

Baily, the Alaska attorney general, says he has been told that the entire repair and maintenance bill over the next five years could reach $1.8 billion. This is significant to the state because Alaska stands to lose money if repair costs are subtracted from the net value of crude oil shipped to the Lower 48 states. Alyeska puts the five-year figure at a slightly more modest $1.5 billion.

“I believe we have a middle-aged pipeline that’s getting up to old age,” Howitt said. “It can last indefinitely if it’s carefully maintained, but like a house or a car, the older it gets the more expensive it’s going to be to maintain.”

Howitt said Alyeska never expected the pipeline to remain corrosion free, but some critics remember it differently. They say that when it was trying to win construction approval, Alyeska said the line’s planning was so intricate and quality so good that there was little likelihood it would suffer serious problems until the North Slope oil fields began to play out. “It was the general understanding that the pipeline had a useful life of 30 years--and that meant 30 years without major renovation,” Baily said.

Ever since its conception in 1969, the Alaskan pipeline project was nagged with doubts about safety, quality and ecological impacts. It was the largest and most technologically complex construction project of any kind ever attempted. Engineers had little experience building a pipeline in such a harsh and fragile climate.

Because of court challenges from environmentalists and other opponents, groundbreaking didn’t get under way until 1974. By then, an Arab oil embargo and soaring oil prices had exposed the nation’s growing dependence on foreign fuel sources. That gave the Alaskan project a new sense of urgency.

“Back in ’76 and ’77, the attitude was that we will build this line at all costs,” said George Tenley, the Washington-based director of the pipeline safety office. “The operator and the public got caught up in that passion to get that line going.”

By 1975, serious doubts had already been raised about the Scotchkote protective epoxy. It began flaking and chipping off some stockpiled pipe cylinders. And, it was learned, other pipelines in the Lower 48 states had experienced similar problems with the product. Alyeska sued the manufacturer, but the case was settled out of court and the records of the litigation sealed.

Rather than scrape off the suspect Scotchkote and start fresh, Alyeska won federal approval to add an extra layer of moisture-resistant tape. Critics at the time complained that the tape had not been adequately tested. Even worse, they charged, taping over a “disbonding” layer of epoxy might create an effect similar to wallpaper buckling and popping after being slapped over peeling paint. That could permit moisture and corrosion-enhancing bacteria to seep under the tape and migrate to bare metal.

Whatever controversy the corrosion safeguards were generating, there was some doubt that they were necessary. The company argued, and some experts agreed, that a pipeline buried in permafrost would not have problems because frozen ground is a poor conductor of the electromagnetic currents that promote corrosion.

But because the pipeline carries oil heated to around 140 degrees, it altered the characteristics of the soil. Bill Wilson, who monitored the construction as a consultant for the U.S. Interior Department, said the hot oil flow gradually created a “thermal bulb” of thawed subsoil that does conduct electricity.

Times copy editor Larry Pryor contributed to this story.