It’s been 30 years since the first oil entered the trans-Alaska oil pipeline system on June 20, 1977. And, with 15 billion barrels of North Slope crude already under its belt, the pipeline is entering a new era. Alyeska Pipeline Service Co. President and CEO Kevin Hostler talked to Petroleum News about how the pipeline is faring and how his company plans to address the challenges that the pipeline will face in the future.
Alyeska operates the trans-Alaska oil pipeline on behalf of the pipeline owners, which include BP, ConocoPhillips, ExxonMobil, Chevron and Koch Alaska Pipeline.
In the 1970s, as the world’s largest ever privately funded construction project, the trans-Alaska pipeline system proved to be a massive engineering achievement. In today’s dollars, about $30 billion dollars have been put into the system, including continuing investment and the initial $24 billion that the system cost, Hostler said.
Oil throughput peaked at 2.1 million barrels per day in the 1980s. But with the subsequent decline in production from the Kuparuk and Prudhoe Bay fields, throughput has dropped to about 800,000 barrels per day. At its peak, the oil passing through the pipeline constituted a major component of the total U.S. and West Coast oil supply.
“We’re still 16 percent of the domestic production. … We’re still 7 to 8 percent of the total U.S. demand,” Hostler said. “We’re still a significant proportion of the West Coast supply.”
In good shapeDespite its 30-year age the pipeline is in pretty good shape, Hostler said. A corrosion-related oil spill has never occurred in the trans-Alaska oil pipeline system, he said.
And, 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,” Hostler said.
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.
“We would run inline pigs,” Hostler said. “We would look for these anomalies. Where we saw anomalies we would go in and dig it up and repair if necessary.”
Alyeska requires pipeline repair or replacement in any area where surveillance discovers a corrosion anomaly impacting 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 mandates repair or replacement when corrosion anomalies impact 80 percent of the pipeline wall thickness, he said.
Alyeska does worry that the aging infrastructure issues that have surfaced on the North Slope might also 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 reconfigurationAs 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 and pump station-based control systems with state-of-the-art electric powered pumps.
“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. “… The infrastructure itself is being modified to deal with the future throughput, along with the future compositional issues.”
In February Pump Station 9, the first pump station to convert to the new technology, switched over to the electrical pumps (see “TAPS switches to 21st century” in the March 4 edition of Petroleum News).
Day-to-day control of the original pump systems resides in the individual pump stations, with the Valdez control room providing general operational oversight. But after strategic configuration, control and monitoring of all operations will take place from a single control room, thus enabling greatly enhanced efficiency in the pipeline operations and maintenance.
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.
The new electrical pumping systems will run more efficiently than the old systems over a wide range of pipeline throughputs.
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 bpd. In the event of a large new oil find, the reinstatement of old pump stations using new equipment could increase throughput to 2 million bpd.
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.
More waxWhile Alyeska upgrades the pipeline architecture, the company is also having to deal 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.
Regulatory environmentThe regulatory environment for Alaska pipelines in general is changing with, for example, the formation of the state’s Petroleum Systems Integrity Office and a joint agreement between DOT and the Alaska Department of Natural Resources, Hostler said.
“It all plays to a desire on the part of the regulators and a desire on our part, working in a collaborative way, for increased monitoring and oversight of our operations,” Hostler said. “… There’s more scrutiny on our repair and prevention methods, as it relates to corrosion or any other integrity issue.”
Hostler said that Alyeska welcomes the opportunity to work with all stakeholders on environmental issues. And the company understands the desire of regulators to make their own assessments of the challenges and risks that the company faces.
“The message that I hear from all of the agencies is that they want to work with us,” Hostler said. “They want to do their own analysis and their own thinking about the challenges and risks that we face. And that’s fine — we’re happy to work with them as they do that. … I think the governor’s order for PSIO is exactly the right thing to do from their perspective.”
“Tremendous staff”Alyeska’s other major focus point, beyond the mechanical pipeline infrastructure and the changing regulatory environment, is personnel and staffing.
“We have a tremendous staff, really talented,” Hostler said.
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 declined from around 1,300 in the early 1990s to about 800 today. And, as in most parts of the Alaska oil industry, that workforce is aging.
“The issue with staffing is more to do with the aging workforce,” Hostler said. “Fifty percent of my workforce is retirement eligible.”
Hostler isn’t so much concerned with replacing an individual employee who might leave the company as he is with the looming need to renew substantial numbers of the workforce.
“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 workforce by targeting critical skills and bringing in people early in their career developments.”
But the institutional knowledge that comes with the years of experience of 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 reevaluating 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 reliabilityOver the past 10 years Alyeska has achieved a 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 an 800-mile, 48-inch pipeline that passes over mountain ranges and crosses 34 major rivers and streams, plus a number of creeks and creek beds, 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 said.