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Vol. 12, No. 41 Week of October 14, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

30 STRONG: TAPS: Young after 30 years

Over past 10 years Alyeska achieved 99.5% pipeline mechanical reliability rate

Rose Ragsdale

It is an unrivaled engineering marvel compared by some with the Great Wall of China. It has safely and reliably delivered incomparable wealth in petroleum riches to the American people over three decades. And it continues to transport oil and natural gas liquids some 800 miles from Alaska’s North Slope to the marine terminal in Valdez, for shipment by tanker to the U.S. West Coast and elsewhere.

The trans-Alaska pipeline accepted its first barrel of oil at pump station 1 at Prudhoe Bay on June 20, 1977. Since then this 48-inch-diameter steel conduit that snakes its way across three major mountain ranges, 834 rivers and streams and numerous creeks has quietly moved more than 15 billion barrels of North Slope crude towards market.

The pipeline was first conceived in the late 1960s after the discovery of the giant Prudhoe Bay oil field. The concept soon evolved into the world’s largest ever privately funded construction project. A massive engineering achievement, it cost about $30 billion in today’s dollars. That includes $24 billion in initial capital investment, plus ongoing costs.

Oil flow through the line peaked at 2.15 million barrels per day in January 1988. But a gradual decline in production from North Slope oil fields has since curtailed oil flow to about 800,000 barrels per day. At its peak, oil put through the pipeline was a major component of the total U.S. and West Coast oil supply, and it still represents 16 percent of total U.S. domestic production.

Alyeska Pipeline Service Co. operates the pipeline and Valdez terminal on behalf of five owner companies, BP Pipelines (Alaska) Inc., ConocoPhillips Transportation Alaska Inc., ExxonMobil Pipeline Co., Unocal Pipeline Co. (now part of Chevron) and Koch Alaska Pipeline.

A construction milestone

It took just two years to build the pipeline, with six years of construction planning before the first shovel bit the earth — a total of 515 federal and 832 state permits was required to secure use of the right of way and meet other requirements.

About 2,000 contractors and subcontractors were chosen to work on the project. Five contractors were each given responsibility for different sections of the pipeline. These were Morrison-Knudson-Rivers, Perini Arctic Associates, H.C. Price, Associated Green and Arctic Constructors. And construction contractors hauled a variety of earthmoving equipment into the wilds of Alaska, from backhoe loaders to tractors, excavators and trucks, for everything from clearing the right of way to digging trenches, cutting through bedrock and erecting bridges.

A total of 70,000 contractor personnel worked on the pipeline over the life of the project, from 1969 to 1977. At its peak, in October 1975, the project involved 28,072 people, including Alyeska employees and contractors. There were 31 fatalities directly related to the construction, including Alyeska, contractors and subcontractors.

The pipeline crosses several high mountain passes, requiring pumping of the crude up the mountain slopes. Four different pump stations, for example, successively raised the pressure of the oil to push it over Atigun Pass, at an elevation of nearly 4,800 feet.

More than 225 access roads were built, linking state roads to pump stations and 14 temporary airfields.

Thirteen bridges were built for the pipeline system, including two suspension bridges.

Three million tons of materials, including 0.5-inch-thick pipes manufactured in Japan, were shipped to Alaska for the pipeline construction.

And because the oil entering the pipeline is hot, about 420 miles of the pipeline is elevated on 78,000 specially designed vertical support members, to protect the underlying permafrost. The remaining 376 miles of pipeline are buried.

Many upgrades

The pipeline system involves a complex assembly of mechanical components, together with supporting computer systems. And over the years Alyeska has made many upgrades, in response to operational, maintenance, safety and environmental needs.

But Alyeska personnel have tended to adopt innovations from others, rather than inventing untried solutions.

“We are following the development of technology,” said Mike Joynor, vice president of oil movements at Alyeska. “We never want to be on the absolute edge of technology, but once it’s mature, we reach a point when it’s hard to find support for our legacy technology.”

That attitude is grounded in a certain amount of common sense.

“We want to avoid having to create our own design. The way we say that is ‘serial number 0001.’ We don’t want our own designs because they usually have issues when they are first deployed. We like to go to people who have done this kind of work and have proven technology,” explained Greg Jones, Alyeska’s senior vice president of operations.

Some needs have surfaced naturally over the years, reflecting the toll that time can take on any large and complex mechanical system. Examples include repairs that have resulted from the pipeline shifting and settling over time and complications brought on in recent years by the decrease in oil flow in the pipeline.

But other challenges have burst upon the scene on the wings of disaster. Incidents such as the 16,000 barrels of oil spilled in an act of sabotage in February 1978, and the 260,000 barrels of crude spilled in Prince William Sound when the Exxon Valdez oil tanker ran aground on Bligh Reef in March 1989, three days before the system would complete its 9,000th tanker loading. These events haunt the memories of Alyeska Pipeline’s longtime employees, especially those charged with scouring the earth for better and safer technologies with which to operate the pipeline system. Their goal is to prevent future disasters and to be ready if, by some fluke, the worst should happen again.

“We’ve made some pretty bold technological changes since the Exxon Valdez spill,” said Jones. “I think our biggest lesson learned is that you cannot have that spill. We just cannot let that happen ever again.”

Toward that end, Alyeska’s marine and emergency preparedness departments have assembled an impressive inventory of the world’s most sophisticated oil spill prevention and response equipment.

30 years young

But, at 30, the pipeline is relatively young by industry standards. Some oil and gas pipelines built in the Lower 48 before 1950 are still in operation.

And although external forces have conspired against the pipeline’s integrity a handful of times, no corrosion-related oil spill has ever occurred on the main line of the trans-Alaska oil pipeline. Because dry oil passes through the pipeline, internal corrosion isn’t as much of a concern as external corrosion.

“If you look at our history over the past 30 years, as we do our inline surveillance and our inline pigging runs … what we always have seen and continue to look for is the impact of external corrosion, primarily as a result of water getting underneath the insulation,” said Kevin Hostler, president and CEO of Alyeska.

Alyeska’s ongoing corrosion detection program began shortly after startup.

The company requires pipeline repair or replacement in any area where surveillance discovers a corrosion anomaly affecting more than 40 percent of the pipeline wall, Hostler 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 requires repair or replacement when corrosion anomalies affect 80 percent of the pipeline’s one-half inch wall thickness, he said.

Alyeska does worry that the aging infrastructure issues that have surfaced on the North Slope also might apply to the pump stations. So, the company is running a continuous monitoring program in the pump stations, using inline investigation tools. For example, 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, Hostler said.

Strategic reconfiguration

As well as monitoring the mechanical condition of the pipeline system, Alyeska has been engaged in a major upgrade of the pump stations and the Valdez Marine Terminal. Known as strategic reconfiguration, the upgrade is replacing 1970s-era turbine-powered pumps with state-of-the-art electrically powered pumps. And in February 2007 Pump Station 9, the first pump station to convert to the new technology, switched over to the electrical system (see “TAPS switches to 21st century” in the March 4 edition of Petroleum News).

“The technology that built the pump stations was the same technology that was in my Mercury Comet and now we’re dealing with technology and capability that’s more like … one of these electrical hybrids that we’re all looking at,” Hostler said.

Strategic reconfiguration is about increasing the efficiency of how Alyeska operates the pipeline system — both the pumping and the control of the line, said spokesman Mike Heatwole.

“It’s really about applying current pipeline technology to TAPS — much more efficient … and better performance,” he explained. “It also helps us with maintenance as we get a lot more real time data on what is happening with each piece of new equipment. The system is designed to be modular and scalable — greatly improving our ability to operate through changes in pipeline throughput — both increases and decreases.”

Also, the variable frequency drive that sends power to each new pump allows much greater control of pumping over a wide range of pipeline throughputs, unlike the original configuration, which does not allow much variability in the speed of the pumps.

“We’re either going at full speed or we’re off line,” Heatwole said. “We were very challenged in how we operated the pipeline at the low throughputs presented during last year’s shutdown of the Prudhoe Bay field. If we had had the new equipment on line, we would have had significantly better performance of the system.”

In fact, Alyeska will be able to adjust the operation of new pump systems to any oil throughput up to 1.1 million barrels per day, using just four pump stations, plus a relief station on the south side of the Brooks Range. The addition of more pumps at each of those pump stations could up the throughput to 1.5 million barrels per day. In the event of a large new oil find, the reinstatement of old pump stations using new equipment could increase throughput to 2 million barrels per day.

At the Valdez Marine Terminal, Alyeska is reducing the number of oil storage tanks from 18 to 14 or 15. The company is also redesigning and reconfiguring the ballast water treatment facility, to significantly reduce the ballast and storm water capacity, Hostler said.

And the heightened pump station efficiency, together with size reductions at the marine terminal, will all result in reduced emissions, Hostler said.

Control and monitoring of all operations will take place from a single control room after strategic configuration, thus enabling greatly enhanced efficiency in the pipeline operations and maintenance — day-to-day control of the original pump systems resides in the individual pump stations, with the Valdez control room providing general operational oversight.

And the company is moving the pipeline control room from Valdez to Anchorage, into the Government Hill offices of AT&T, Alyeska’s communications service provider, Hostler said.

Wax buildup new challenge

While Alyeska upgrades the pipeline architecture, the company is also dealing with a new technical issue: the increasing amount of wax that is precipitating from the oil in the line. Some of that wax passes through the system and eventually dissolves back into the oil when the oil is later warmed up. However, some wax requires collection and separate shipment.

The wax started appearing in 1989, primarily because, as the oil movement through the pipeline slowed with decreasing throughput, the oil became cooler. The changing mix of crude in the pipeline, as production from the mature North Slope oil field declines and new fields come on stream, is also resulting in more wax formation, Hostler said.

“We’re pigging more often. We’re monitoring it,” Hostler said. “… We continue to look for opportunities to deal with it.”

The reconfigured pump stations also have the capability of cycling and warming the oil, to dissolve some of the wax, he said.

Dedicated but aging staff

Successful operation of the pipeline system over the years has depended on personnel who have responded to challenges facing them with energy and ingenuity.

“We have a tremendous staff, really talented,” said Alyeska President and CEO Kevin Hostler.

And, with a successful Native hire program, 20 percent of the Alyeska staff consists of Alaska Natives, he said.

But, along with declining oil throughput, Alyeska staff numbers have decreased from about 1,300 workers and contractors in the early 1990s to some 800 today. And that work force is aging.

“The issue with staffing is more to do with the aging work force,” Hostler said. “Fifty percent of my work force is retirement eligible.”

Hostler isn’t so much concerned with replacing individual employees who might leave the company as he is with the looming need to fill substantial vacancies in the ranks.

“We do know that on a competitive basis we can go out and replace, like-for-like, a number of our staff,” Hostler said. “… But now we’re starting to look at renewing our work force by targeting critical skills and bringing in people early in their career development.”

But the institutional knowledge that comes with years of experience enjoyed by the current staff becomes a significant issue as people start to retire.

“We’ve got people who’ve been here almost 30 years and know a lot about how to operate the pipeline,” Hostler said.

Alyeska is also taking a close look at its contracting strategy and is re-evaluating the question of what work to do inside the company and what work to contract out.

“Finding the right level of internal capability and third-party capability is a real challenge,” Hostler said. “… We’ve looked at our contracting strategy and thought through where we want to bring some of these skills back in house. And we have done that. And where we want to rely on the external market we’re going to continue to do that.”

High reliability

Alyeska particularly wants to maintain the pipeline’s exemplary performance record. Over the past 10 years the company has achieved a pipeline mechanical reliability rate of 99.5 percent, Hostler said.

“That is terrific,” Hostler said. “… As we’ve seen declining throughput and we’ve seen some of the challenges associated with that, we’ve been able to maintain a high degree of operations confidence.”

But operating the aging pipeline will continue to require careful management.

And the pipeline needs to operate cost effectively, to maintain the viability of North Slope oil production. So, as the company builds its budget each year, the management seeks areas for increased operational efficiency, while at the same time managing risk mitigation.

“We see the challenge, but at the same time our process is intended to provide a stopgap against taking undue risk,” Hostler said. “And that’s what you’d expect of us, that we’d put that priority on the security of supply, maintaining safety and protecting the environment.”

And “no oil to ground” is a company mantra, Hostler added.

—Petroleum News staff writer Alan Bailey contributed to this article.

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