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AOGCC considering enforcement action against BP for test failures Commission asking for specific safety valve system management: assignment of responsibility for preventing, correcting failures; performance reporting Kristen Nelson PNA Editor-in-Chief
The Alaska Oil and Gas Conservation Commission has completed a review of safety valve system problems in the western operating area of Prudhoe Bay and is considering enforcement action against field operator BP Exploration (Alaska) Inc.
The commission told BP in a Feb. 14 letter that it was concerned about failures in safety valve system tests on six pads in the western operating area (C, F, G, H, K and Z) during the first quarter of 2001.
Mechanical parts have occasional failures, Alaska Oil and Gas Commission Chair Cammy Taylor told PNA Feb. 15, and while it is not uncommon to have component failure rates greater than 10 percent, those failures would typically be in a random pattern across the North Slope. What the commission saw in the western operating area was a cluster of test failures in both timing and geographic area, she said.
Taylor told PNA that at other pads — in the Phillips Alaska Inc.-operated Kuparuk River field and the BP-operated Milne Point field — the commission saw a pattern of problems identified and corrected, not repeat failures such as it saw in tests at the six western operating area pads. Cluster identified last year A commission petroleum inspector witnessed tests with component failure rates greater than 10 percent on three of the western operating area pads in March 2001; three other pads in the western operating area were also identified as having component failure rates greater than 10 percent. A commission study of component failure rates at the six pads found both component failure rates above 10 percent (as high as 30 percent) and repeat component failure rates of greater than 10 percent at four of the six pads.
The commission said in its letter to BP that the enforcement action the commission is considering would require BP to implement a specific safety valve system management system “that more effectively ensures compliance with AOGCC Order and Regulations.”
The management system would include: how BP will monitor operability and reliability of safety valve system performance; who will be responsible for determining appropriate remedial action to prevent failures or correct failures; how performance reporting will be accomplished; and detailed procedures for analyzing and implementing corrective action. Testing requirements The commission requires that components of the safety valve system be operational; if components cannot be repaired within 24 hours the well is shut in until repairs are completed and successfully re-tested.
The Alaska requirement is for wells to be tested by pad every six months unless a shorter period is specified. Tests are conducted by the operators and commission petroleum inspectors randomly witness scheduled safety valve system tests and periodically require unscheduled tests. Component failures are recorded as failures even if corrected immediately. If a pad’s component failure rate is greater than 10 percent, surveillance on that pad is increased and the next pad test is scheduled for 90 days.
The commission in its Feb. 14 letter said the safety valve system is “one part of a larger set of systems designed to prevent uncontrolled release of produced fluids (hydrocarbons and water).” The safety valve system automatically shuts in the well if pressure drops in the flow line carrying the produced fluid (crude oil and water) from the producing well on the pad, signaling a rupture in the flow line.
Commissioner Dan Seamount told PNA that while there are redundancies farther down the line in the shutoff system, the safety valve system is the only automatic shutoff between the well head and the manifold.
An inoperable safety valve system risks a release of produced fluids only in the event of a flow line rupture and the commission said it is “unaware of any release of hydrocarbons as a consequence of an automatic SVS component failure.” No benchmarks available The safety valve system is required on offshore wells, but is “not generally required for onshore wells by the majority of oil producing jurisdictions,” the commission said, so there are no benchmarks or performance measures available from other oil producing jurisdictions.
Alaska’s North Slope safety valve system requirement, Taylor told PNA, is included in field conservation orders. The commission’s rules don’t necessarily address the safety valve system, she said, but for all North Slope fields safety valves are required in the conservation order which governs field operation, starting with Prudhoe Bay. Those pool rules were put forward by the companies.
“Historically the companies proposed rules when they developed the fields,” Taylor said. Development in the Arctic was relatively new when Prudhoe Bay was brought on line and there were relatively new issues, such as drilling through permafrost, she said.
The commission said BP has reviewed the safety valve system failure rates “and concluded that there was insufficient internal communication concerning the objectives, practices and results of SVS testing. They also acknowledged that there was inadequate attention to frozen pilots and a lack of analysis of test failure data.”
But the commission said “it is not clear that the failures on these WOA pads were solely the result of poor communication within BPXA.” The commission said that it recognizes that mechanical failures occur, but “maintenance is required to keep the SVS in working condition. The majority of problems that cause component failures are avoidable. The frequency and type of maintenance are the keys to consistent successful SVS performance.” The commission said BP has made recommendations and developed proposals to address some of the commission’s concerns, but it would like the opportunity to evaluate all aspects of BP’s proposed safety valve system management system before proceeding with an enforcement action, and is requesting complete details of the proposed system.
The commission has also asked for the names of all well pad operators for the six western operating pads, and said it would like to provide notice to all Prudhoe Bay field well pad operators “of any future hearings or public meetings regarding SVS rules or regulations.”
Taylor said that if the commission decides pool rule changes or regulation changes are needed, either of those changes would require a public hearing.
BP has made recommendations and developed proposals to address some of the commission’s concerns and the commission said it wanted the opportunity to evaluate all aspects of BP’s proposed safety valve system management system before proceeding with an enforcement action.
BP has until March 1 to provide the commission with requested information.
Taylor said that once the commission has evaluated BP’s proposed management system it will decide if that will be the enforcement action; BP will then have 15 days to accept or reject the commission’s action, or to request a hearing.
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