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AOGCC sees BP’s remedial plan as positive Commission was not involved in risk assessment of Prudhoe Bay wells; has been briefed on work planned on shut-in wells Kristen Nelson Petroleum News Editor-in-Chief
The Alaska Oil and Gas Conservation Commission wasn’t involved in the BP risk evaluation of North Slope wells that resulted in the company shutting in some 70 Prudhoe Bay and Endicott wells for remedial work. (See story in Oct. 2 issue of Petroleum News.)
But the commission has been briefed on the work and views this “as a big positive step,” says Commissioner Cathy Foerster, who holds the petroleum engineer seat on the three-member commission.
BP is taking the commission’s concerns “very seriously,” they are taking those concerns “to a higher level for their own internal review, risk management reasons” and “they’re taking this opportunity to squeeze some more” production from the wells, she said.
In addition to its responsibilities to oversee drilling, development and production, the commission also is charged with ultimate resource recovery.
It’s about risk management, Foerster told Petroleum News in an Oct. 5 interview.
The North Slope operators, BP Exploration (Alaska) and ConocoPhillips Alaska, manage their risk by knowing and following the rules, she said.
No one operating on the North Slope ignores risk, she said, and no one breaks the rules on the chance that they won’t get caught.
If there were operators like that on the slope, the commission would be “riding them hard,” she said.
What the commission sees, she said, is operators who know the rules and generally try to follow them, but occasionally make a mistake.
“And when they make a mistake our inspectors are there to catch them” and remind them what the rules are, Foerster said.
Above that is a level of perfection, followed by a level where extra precautions are taken, and a final level where risk aversion is so high that — Forester used the analogy of a driver who simply sells the car and refuses to drive again.
The issue, she said, is “how you manage risk.”
BP, by taking those 70 wells out of service for remedial work, has taken a position “just on the safe side of following the rules. They’ve applied a higher risk factor to their operations than the state requires them to.” Briefing from BP Jim Regg, the petroleum engineer who manages the commission’s inspectors, said BP gave them an outline of the risk assessment “in broad terms” and also provided a breakdown of the number of wells “In the various risk categories that they established.”
In addition to operating within commission guidance, Regg said, the operators also have their own system of internal waivers, which puts wells on “heightened alert.”
“And that’s above and beyond meeting our minimum requirements,” Forester said. “They’re meeting all of our requirements and taking another step.”
The criteria the commission puts in conservation orders is the commission’s “line in the sand … you just don’t operate beyond this,” Regg said. The risk assessment is something BP has done “on their own … on their own initiative.”
There is risk in the oil and gas business: “And we don’t mandate that operators get to zero risk,” Foerster said. “The only way to do that is to have them plug everything and go home. We manage to what we deem as an acceptable risk.”
Acceptable risk, she said, is something everyone has to define for themselves, and BP has “just chosen to be a little bit more risk adverse in this area, based on their own experiences.” Wells meet commission criteria The commission keeps an inspector on the North Slope and does inspections to make sure that pressure is bleed from the annulus of a well before a well is started up, one of the things inspectors look for when they witness a well startup. Regg said inspectors typically see about 80 percent of mechanical integrity tests on wells. If a well has been shut in for repairs, he said, “there will be some commission involvement on that well, whether it’s a BOP (blow out preventor) test or a follow-up safety valve test or mechanical integrity test, checking pressures.”
Regg said that if the commission’s inspectors looked at the 70 wells that BP shut in, they would be operating “within the pressures that we’ve allowed them to operate in those wells.”
But when a well starts to show integrity problems the company has to put a watch on that well, which requires personnel, personnel that have to be taken from other duties. At some point a company has to decide “whether they want to continue to apply those personnel and those resources to monitoring and to the cost of surveillance and even maybe diagnostic testing of those wells to determine if they can still be operated properly and safely” or if they just want to repair the well. Best use will be determined A risk analysis ranks wells by consequence and frequency, and these 70 wells, “even though they don’t really represent a risk,” have been identified as being in the most at-risk category, he said.
“If something bad happened these are the ones that could cascade into an event and create a problem, could result in a problem, therefore these are the ones that we need to work on,” Regg said.
BP estimated that about half of the 70 wells were already shut in when it made its decision, and the company could have chosen to continue operating the wells and repair them as they could get to them, but decided instead to shut them in immediately and keep them shut in until they could be repaired.
Foerster said being shut in “automatically moves them up on the priority list for getting repaired,” and is positive from a safety standpoint, and also from a resource conservation standpoint.
BP is “talking about quite a range of things that they expect to do or could end up doing” on the 70 wells, Forester said.
When the company goes in to work on these wells, she said, they’re not just going to do repair work, they’re going to look at what they can do to the well to get the most out of it, such as an opportunity to add perforations to improve production.
Regg described it this way: “they’re looking for how they can make this well work best in the scenario that they have.” Maybe they could use another injector in that area of the field and the best use of a well is to retrofit it and make it an injector. Other wells might not be adding much to production, and the company will determine just to leave the well shut in.
“And there might be sidetrack opportunities,” Foerster said. The company will look at all the options for a well in the part of the field where it is located. Its best use might “be a sidetrack into a different strata,” conversion to an injector, turning it back on the way it was or shutting it in.
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