Commission reduces BP fine by half

AOGCC says ‘bad faith’ not a factor in 2002 explosion at Prudhoe well; BP also credited for cost of pilot remote monitoring project

Kristen Nelson

Petroleum News Editor-in-Chief

Last December the Alaska Oil and Gas Conservation Commission proposed fining BP Exploration (Alaska) penalties of $2,530,000 for the company’s actions leading up to the August 2002 explosion at the Prudhoe Bay well A-22 which severely injured a BP worker.

On Nov. 15 the commission reduced the proposed civil penalty, which was the maximum it could charge, by half.

In reducing the amount, the commission said it carefully considered the facts and BP’s arguments, and said it “is persuaded that although the potential — and in this case the actual — consequences of this type of violation are extremely serious,” the company’s “acts and omissions here were not the result of bad faith.”

The commission said it also took into account the company’s “extensive self-investigation” into the “precise cause of the incident” and the company’s voluntary actions since the A-22 explosion “to develop new and better methods to monitor and manage well conditions.” In response to the incident, the commission said, BP has put “into place more stringent and specific operating requirements designed to avoid a recurrence of such an event.”

The commission said that taking all of these factors into consideration, it was reducing the maximum daily penalty of $5,000 per day by one half. The penalty period was based on the commission’s view that in March 2001 BP had a clear opportunity to implement better policies, and did not do so.

Credit for pilot program

BP also argued, the commission said, that the proposed penalty was “inconsistent with constitutional principles of due process and equal protection” since other operators on the North Slope have testified that at the time of the incident they were following policies similar to BP’s, the implication being that BP “may have been unfairly singled out.”

The commission said it disagreed with this argument, and said that, to its knowledge, “no other operator’s well has been allowed to develop avoidable annular pressures sufficient to rupture a casing. It is the incident,” the commission said, not any desire to penalize BP, “which brought about this enforcement action.”

The commission said that BP has argued that in August 2002, its policies were in compliance with commission statutes, regulations and orders, because none of those “expressly addressed annular pressure issues.”

In August 2002, the commission said, its practice “was to rely upon each operator to manage annular pressures in accordance with good oil field engineering practices.” After the A-22 well explosion, the commission said, it “concluded it could no longer rely upon individual operators to self-employ good oil field engineering practices in annular pressure management,” and enacted specific orders “establishing explicit annular pressure management requirements for Prudhoe Bay and other fields in Alaska. The fact that these specific orders were not in place at the time of this incident in no way relieves BPXA from its responsibility to carry out operations in a safe and skillful manner in accordance with good oil field engineering practices,” as required by the commissions regulations.

The remote monitoring pilot

BP’s engineering group and pad operators evaluated options, assisted by BP’s global engineering network and based on evaluation and feedback, “a remote monitoring option was determined to have the best potential for improving detection (and thus control) of annular pressure, while having the least likelihood for generating additional risks.” Remote pressure relief options were rejected because of concerns that they could introduce “additional reliability risk,” BP told the commission.

The $549,000 pilot program will assess two designs for remote monitoring of outer annular pressure in real time, with a goal of testing long-term reliability, potential for freeze-up or hydrate plugging and potential mitigation measures for any such problems.

“The two designs minimize the amount of equipment exposed to freezing and hydrate potential compared to the other alternatives considered, while offering the potential for early detection of annular pressure problems,” BP said. The company said its North Slope experience “has shown that the severe arctic conditions materially impact the reliability of mechanical, hydraulic and electronic devices,” and therefore “any engineered solution must decrease risk beyond that of the enhanced administrative controls” BP put in place following the implementation of the commission’s new annular pressure management rules.

BP said “technical success of the pilot would not necessarily reflect larger scale viability,” but “technical success of this pilot might enable us to integrate this kind of monitoring into other automation and construction projects.”

BP began the pilot program in the middle of the 2003-04 winter, and will continue it through the 2004-05 winter to gather data over a full winter season.

BP selected X pad for the pilot because several wells on the pad have outer annulus pressure waivers, and the pad had the necessary electrical power and control wiring for the monitoring devices. Two systems are being pilot tested to measure the outer annulus pressure; each was installed on four wells.