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BP opposes proposed Prudhoe Bay rules At AOGCC hearing operator suggests alternative annular pressure rules Kristen Nelson Petroleum News Editor-in-Chief
Are new operating rules necessary for Prudhoe Bay wells? And if so, what kind of rules?
In the aftermath of the explosion at the A-22 well at Prudhoe Bay last August which seriously injured a BP worker, the Alaska Oil and Gas Conservation Commission has proposed new rules governing annular pressures in Prudhoe Bay development wells. Annular pressure was determined as the cause of the explosion.
Prudhoe Bay operator BP Exploration (Alaska) and the Alaska Oil and Gas Association testified at a November hearing that operating procedures and training had been revised after the explosion and told the commission that no new commission rules were necessary.
The commission disagreed.
It published proposed new regulations in April and heard testimony from BP May 27 on those proposed regulations.
Steve Rossberg, BP’s Prudhoe Bay wells manager, testified for BP. He told the commission that BP and the other Prudhoe Bay working interest owners continue to believe that no new rules are necessary.
“BP continues to believe,” Rossberg said, “that sustained casing pressures are appropriately addressed by its well integrity program parameters.”
If the commission does adopt new rules, he said, BP recommends changes. BP asking for changes First, he said, BP believes that the commission should include definitions of inner annulus, outer annulus and sustained pressure in a new rule.
The commission has proposed requiring that the operator demonstrate, by mechanical integrity testing, that all wells can be safely operated. BP proposed that the rule require it to conduct and document a pressure test of tubulars and completion equipment at installation and replacement. Once installation is done, monitoring and surveillance would ensure that integrity is maintained.
In response to a question from Commissioner Randy Ruedrich, Rossberg said that while BP does use mechanical integrity testing in its operations, it is not always the most reliable means of testing tubing once a well is online, “so what we’re asking,” he said, “is that other options be allowed other than just straight mechanical integrity testing.”
The commission’s proposed rules require that wells be monitored daily for pressure. BP recommended that the rule provide an exception for weather conditions or emergency situations. Rossberg told the commission that wells are monitored on a daily basis, but would like a rule to acknowledge “unusual circumstances when it is not safe or not feasible to monitor a well on a daily basis.” Frequency of bleeds, pressure measurement Ruedrich asked about the technical basis for doing two bleeds a week of well pressure.
Rossberg said wells need to be bleed to start them up. In addition, for wells with outer annulus pressure the threshold is 1,000 pounds per square inch pressure. “And we ask that the operators report any wells that cannot be kept below that pressure with two or fewer bleeds per week,” he said.
The two bleeds a week standard, he said, has developed through 20 years of operating Prudhoe wells.
The commission wants to receive reports of wells with pressure problems, and has proposed a standard of “sustained inner annulus pressure or outer annulus pressure greater than 20 percent of the burst pressure rating of the annulus’s outer tubular.”
BP proposed defining the pressures as the thresholds it now uses: for the inner annulus, 2,500 psi for wells processed through the Lisburne Production Center and 2,000 psi for other Prudhoe Bay development wells; and 1,000 psi for the outer annulus.
Ruedrich said that in the November hearing, “BP indicated that clearly rules needed to be flexible … one size does not fit all.” In response to that, he said, the commission wrote a flexible rule, which BP opposes.
“Why the change?” he asked.
Rossberg said the request for flexibility reflected differences in wells at Prudhoe Bay and other North Slope fields. That difference, he said, is reflected in BP’s definitions of inner annulus pressure as 2,500 psi for Lisburne wells and 2,000 psi for other Prudhoe wells.
“At Prudhoe Bay and Lisburne,” he said, “we have some of the highest gas-lift pressures in the world. Those systems run at 2,000 pounds, 2,500 pounds, respectively.” Administrative control Ruedrich asked why a percentage system would be more difficult than a fixed number when the operator would be doing the same thing, reading the pressure gauge, regardless of the system.
The well pressure safety system is based on administrative controls, Rossberg said.
“In order for administrative controls to work, the key element is people have to follow those controls. They have to understand and follow them.” A percentage system, he said, would result in “a different pressure limit on each well, they’ll be less well understood by the operators and we think … result in a higher likelihood that we would miss a threshold pressure.”
Ruedrich said the operator is just collecting the data, and is not the ultimate decision maker. The technology in a database, he said, could compare an actual reading with casing specifications — the management system, he said, would identify problems, not the operator.
Rossberg said there is technical justification for the 1,000, 2,000 and 2,500 psi numbers. “They provide an ample safety factor and are well within the operating range of all of our casing design on the slope,” he said.
There are some 1,500 wells to manage at Prudhoe, Rossberg said, there are “at least six generations of casing design, wellbore design” and they “do have slightly different threshold pressures and it would make it more difficult, I think, to identify a well that exceeds specific threshold versus a consistent 1,000 and 2,000…”
Rossberg said the percentage measure was a concern “because we do view the operator as the first line of defense in well integrity” and want “a very clear, understandable and consistent trigger pressure that that operator knows that he has to report.”
Because while operators are required to read the pressure gauge daily, he said, “that data isn’t recorded.” What’s crucial, he said, is that the operator knows at what pressure reading he needs to report a well, and “we may have four, five or six different well designs on any given pad.” The existing trigger numbers cover all of those designs, Rossberg said, but with a percentage rule, the trigger points for wells would vary.
The commission expects to issue a final rule within 30 days.
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