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AOGCC hears from BP, AOGA on possible well control regulations Commission grapples with whether to establish new rule following A-22 explosion; Prudhoe Bay operator, Alaska Oil and Gas Association, oppose regulation Kristen Nelson PNA Editor-in-Chief
The Alaska Oil and Gas Conservation Commission took testimony Nov. 14 on whether or not it should prescribe “a rule to govern the operation of development wells within the Prudhoe Bay field that exhibit pressure communication or leakage in any casing, tubing or packer.” The hearing is a result of the explosion Aug. 16 which severely injured a worker at the Prudhoe Bay A-22 well.
Both Prudhoe Bay operator BP Exploration (Alaska) Inc. and the Alaska Oil and Gas Association told the commission that changes have been made in operating procedures and training following A-22, and both said no new regulations are needed.
Tom Gray, BP’s Prudhoe operations integrity manager, said BP is continuing engineering studies to fully understand what happened at the A-22 well, but said preliminary results do not show that corrosion or drilling operations damaged the casing. “Instead,” he said in prepared remarks, “we believe the pressure in the outer annulus exceeded the surface casing pressure rating of 5,380 pounds per square inch, due to the thermal expansion related to well start-up.”
Procedures changed External casing failures in development wells are rare, Gray told the commission, and he said BP has already taken steps to prevent a recurrence.
BP is also initiating a “peer assist,” he said, at which BP experts and representatives from other operating companies in Alaska will review the Prudhoe Bay well integrity program and AOGA has established a task force to ensure that lessons and information are shared among operators.
In response to a question from commission Chair Cammy Taylor, Tom Wellman, ConocoPhillips Alaska Inc.’s field manager for the greater Kuparuk area, who was testifying on behalf of AOGA, said the AOGA work group would share what it learns from A-22 with the commission. Taylor asked if AOGA would consider having commission staff participate in its work group, and Wellman said he would find out.
Wellman said AOGA opposes new regulations for annular communications. “The variety of well completions and field characteristics in the state means that one set of criteria will not meaningfully address all locations in the state or all circumstances within a single field,” he said in prepared testimony. And, he said, if “regulations are too conservative, they will result in wells being shut-in for repairs unnecessarily, thus deferring production without increasing the safety factor.”
Gray said BP opposes new regulations. Commissioner Dan Seamount asked if BP was aware of pressure regulations in Alberta or by MMS. Gray said BP has been looking at other jurisdictions and was aware of some Canadian guidelines, but didn’t know the details.
If the commission decides to regulate, it will propose a rule and hold public hearings on that rule. The commission had not yet made that decision Nov. 20.
30 percent require pressure Gray said that 30 percent of Prudhoe wells require inner annulus (between the production tubing and the production casing) pressures of 2,000-2,500 psi for gas lift.
Of the some 1,200 wells remaining, 35 percent have inner annulus pressures of zero to 500 psi; 29 percent have 501-1,000 psi; 32 percent have 1,001-1,500 psi; and 3 percent have 1,501-2,000 psi.
There are approximately 1,589 wells at Prudhoe — including producers and injectors — and Gray said the spread of pressure in the outer annulus (between the production casing and the surface casing) is: 73 percent zero to 500 psi; 22 percent 501-1,000 psi; 3 percent 1,001-1,500 psi; less than 2 percent 1,501-2,000 psi; and less than 1 percent greater than 2,000 psi.
Wells with waivers Gray said a number of the changes made at Prudhoe after A-22 were related to “waivered” wells — naturally flowing wells where the inner annulus exceeds thresholds for pressure building, which exhibit other signs of tubing leak or require more than two bleeds per week to keep pressure under 2,000 psi. If outer annulus pressure tracks inner annulus pressure or requires more than two bleeds a week to keep pressure under 1,000 psi, that is also evaluated.
Gray said that wells which exceed the threshold trigger further evaluation and diagnostics, and based on those results, “wells are either shut in or considered for a waiver to operate at higher annular pressures with additional monitoring criteria.”
Asked about changes in trigger points by Commissioner Mike Bill, Gray said that the whole process has evolved over time and the threshold has changed. It was lower, he said, and was changed as the companies became experienced operating at Prudhoe. Gray said about 260 Prudhoe wells — producers and injectors — have waivers or are under evaluation.
He said new procedures include: operators are required to stay on site to monitor pressures when “waivered” wells are started up until pressures and temperatures are stable; additional management approvals are required for waivers; a three-day time limit for initial review of well integrity problems and 21 days to begin diagnostic work.
Additional training has also been provided for well operators and others working on wells.
Thermal causes of pressure George King, a distinguished advisor with BP and an adjunct professor at the University of Tulsa, said annular pressures is a common condition in oil and gas operations worldwide. Gas-lifted wells at Prudhoe Bay, he said, require pressure of 2,000-2,500 psi in the inner annulus to produce the wells.
King said in prepared testimony that annulus pressure becomes a problem when it becomes too high. Most wells have an inside annulus between the production tubing and the production casing and an outside annulus between the production casing and the surface casing, he said. Fluids are not supposed to be in communication between the inner annulus and the outer annulus, King said, but for a variety of reasons they can be, which can contribute to annular pressure.
“Temperature changes can have dramatic impact on annulus pressure,” King said. Produced fluids can change the well temperature from ambient earth temperature near the wellhead to more than 200 degrees Fahrenheit, and pressure buildup will be very rapid if the system is filled with liquid.
Two-thirds of gulf wells require bleed off The industry doesn’t have much in the way of annular pressure records, he said, but the Minerals Management Service provided some numbers in 2000, estimating that about two-thirds of more than 11,000 wells in the MMS Gulf of Mexico had some form of annular pressure than had to be bled off at some point in the well’s life.
Bleeding off pressure is the most typical way to manage it, King said, and works as long as the monitoring process works. Where this is not possible, as in subsea wells, gas is maintained in the annulus because gas doesn’t pressure up with temperature changes the way liquids do. Using extremely heavy-walled casing is another method, but it only works in new wells and the higher-alloy pipes, King said, are more susceptible to some corrosion.
An open shoe — where the well is not cemented in at the top — is another option, allowing pressure to bleed off naturally.
At Prudhoe Bay, King said, where the annulus is sealed with cement, pressure can’t just bleed off. At Prudhoe, he said, BP prefers to have the outside annulus sealed and filled with fluid so pressures can be monitored and managed, and relies on annular bleeding.
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