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AOGCC studying Prudhoe production problems John Norman, Alaska Oil and Gas Conservation Commission chairman, says commission will monitor well integrity closely, standardize orders, and work with Alaska Oil and Gas Association on making sure required paperwork is meaningful Kristen Nelson Petroleum News Editor-in-Chief
John Norman, named head of the Alaska Oil and Gas Conservation Commission in January, told Petroleum News in a September interview that the commission, whose “mission is to prevent waste, to protect supplies of fresh water and to protect correlative rights,” is reviewing this summer’s events at Prudhoe Bay, when operator BP Exploration (Alaska) struggled to get its facilities back online following a planned shutdown.
Norman said the commission, along with other agencies, is evaluating the causes of the reduced production. BP took Prudhoe Bay down for maintenance and upgrading in conjunction with a maintenance shutdown of the trans-Alaska oil pipeline in early August, and had difficulties getting Prudhoe gathering centers back on line.
He said the commission is particularly concerned by allegations of unsafe conditions and unauthorized venting of gas, “and finally because of the size of that reservoir and importance to Alaska, we wanted to be able to have the assurance that the operator was moving toward getting it back into production.” On Sept. 17, when Norman spoke to Petroleum News, the commission had an engineer and a field inspector at Prudhoe “going through the gathering centers.”
Norman said the commission has received information on the situation from BP, as well as correspondence and calls from other parties, and has been following the situation very closely. The commission has a good understanding of some of the reasons for the reduced production. “Other malfunctions appear to be just random events,” and Norman said that while the commission doesn’t have a full understanding yet of those events, “we intend to get one.”
The production slowdown occurred in the context of an ongoing labor dispute at Prudhoe, and Norman said there have been allegations ranging from insufficiently trained replacement personnel to the possibility that, as part of that labor dispute, one side may have disabled certain equipment. Reviewing event while it’s fresh While it hasn’t reached a conclusion, Norman said “we have no reason right now to believe that anything unsafe has or is occurring.”
“We have a strong sense that the operator is behaving responsibly, but we’re in the process of carrying out our own independent investigation.”
Norman said the commission “had good cooperation from the operator,” BP, and coordinated with other state agencies, “but we did not want to get into the middle of it and interfere with their efforts to bring it back online. And I think that proved to be a correct decision, because now they are up and near full production.”
But he said this is the time, “while this event is fresh to review it and identify causes, not in a way necessarily to find fault” but to see what can be learned from it.
One thing in particular that the commission will look at is the flaring of some 44 million cubic feet of gas flared over a period of 70.5 hours as the facilities were coming back online. The commission regulates flaring and Norman said it will be looking very carefully at that, and “will make a determination as to whether that was in the ordinary course of business or whether it constitutes waste.”
As for the overall event, the commission may “conclude that this was within the realm of normal operational shutdowns that happen in any production facility.”
A second option, Norman said, is a finding that perhaps some things were not done the way they should have been, but before the commission reached that point, “if we thought we didn’t have all the answers, then we will continue with our investigation.”
If the commission is able to identify the causes “fairly quickly, then we can make that available and it may be as simple as us confirming what the operator’s already told the press.” But if the commission sees a need for continuing monitoring or enforcement action, then the commission’s policy is not to release preliminary results while an investigation is going on. The waste issue Norman said the flaring of 44 million cubic feet of gas at Prudhoe is a reminder of a crucial role the commission played in the 1970s when it required operators to stop flaring gas in Cook Inlet. “In 1970 at Granite Point alone there was about 8.5 billion cubic feet flared,” he said. At that time the gas had no value: “We had enough gas onshore” and facilities to bring the gas to shore cost money.
That “illustrates the importance of having a commission,” Norman said, and also the fact that at the “commission you really have to be thinking somewhat of future generations.”
The gas had no value then, and “the operators, properly so, were focused on their profit motive… Someone, though, needs to look out and make sure that there is not physical waste. And that’s the commission’s job.”
It’s easy to look back now and say wasting 8.5 bcf a year was foolish, “but the real question is not that, it’s what today is occurring — right now — and how might we be wasting resources.”
When Alaskans look back in 2040 or 2045, will decisions made today be wasting an asset? “We always have to remember, we’re going to be judged by history,” Norman said. Commission reviewing orders The commission has a number of ongoing projects, Norman said, including “a comprehensive review of a lot of the commission’s orders.” There have been “slightly different versions of the wording” in orders over the years, and different people have worked on the orders, and “some of them will contain one requirement or another, so we’re looking at that to try to standardize.”
The commission is also reviewing its regulations, to “simplify them where we can.”
For example, the commission looked at its requirements for the testing of blowout prevention equipment on development rigs, which required a test every seven days. In looking at requirements by the Minerals Management Service in the Gulf of Mexico, those of several other states and Norway, the commission found all of those jurisdictions had longer intervals between tests, “and the conclusion we reached is that there was no compromise of safety by allowing the operator to test every 14 days as opposed to the seven days that we were requiring.”
The savings to industry will be in the millions of dollars per year, he said. That change is in the final administrative approval stage.
Another change the commission has made is in reports it required of operators on anticipated work. These are not permits, Norman said, but reports of planned work. The commission found the reports often were changed, and weren’t meaningful to the commission, so it has eliminated reports of anticipated work, “and instead we’re going to put the emphasis on promptly reporting what was done.” The change, he emphasized, does not affect requirements for permits, it just eliminates a requirement for “generalized plans months ahead of time.”
The commission has also created a task force with the Alaska Oil and Gas Association to look at the paperwork the commission is getting and “to make sure that the paperwork that we do get is meaningful.”
The flipside, he said, “is they can expect very strict enforcement” of paperwork that is required. Tracking wells a concern Norman said the commission’s role of keeping track of wells is especially crucial with directional drilling, where wells sometimes come within a few hundred feet of each other, “and so it’s extremely important that we have accurate information and at any given time we know exactly what’s going on out there on a rig.” The commission has five fulltime field inspectors, he said, and 70 percent of the time there are two inspectors on the North Slope, 24 hours a day, “doing nothing but checking for compliance.”
Spacing requirements for wells is also a concern for the commission.
Norman said the spacing issue is important because if a well is drilled too close to a neighbor’s boundary, “you might be draining oil from your neighbor, and that’s what this commission oversees.”
A company will often come in and request an exception from the spacing requirements, and the commission has found in recent months that requests for spacing exceptions were being made as drilling permits were requested, and the required notice of the spacing exception was given, but the commission had already issued a permit.
In those cases, Norman said, the commission told operators “that you will be drilling at your own risk, in case there is a protest to this spacing exception,” but that kind of procedure should only be allowed “in exceptional circumstances, because it’s little comfort if somebody’s just completed a 10,000-foot well, to then get into an argument over whether that well was drilled to a proper location.”
The commission “will, in compelling circumstances, still grant waivers, but ordinarily, the procedure will be to first … (go) through the process of getting a spacing exception, then we will grant the permit.”
This is a case, he said, where the commission is “tightening back” on industry to limit waivers. Emphasis on mechanical integrity of wells Another area where the commission is tightening up, Norman said, is on mechanical integrity of wells. It’s a natural outgrowth of Alaska’s gradually aging wells, he said. With new equipment, you might find leaks around fittings, “but as equipment ages, you do get problems with mechanical integrity.”
The commission intends “to carefully scrutinize all wells that lack mechanical integrity,” he said.
When operators report a problem with mechanical integrity, “we are going to expect a plan of corrective action with some specific timelines, or alternatively, if the operator feels that the well can be operated safely, then we expect their application to document that thoroughly to us.”
What the commission expects to see, Norman said, is “a plan for corrective action to restore mechanical integrity” or a very clear showing that “a lack of mechanical integrity is not serious…” Otherwise, he said, “the commission will not permit that well to continue to be operated.”
As Alaska’s infrastructure has matured, “often operators have said well we’d like to watch this just for a while, and the commission’s position is that that’s not a plan for corrective action, just to watch it.” The commission will allow an operator to watch a well while it is ordering equipment for repair. The operator can also argue that the “leak is of so little consequence that it doesn’t pose any threat.” If the commission agrees, it will require the operator to monitor the well.
The commission is also exploring ways to work cooperatively with the Environmental Protection Agency on managing injection wells. Currently the commission is responsible for some 1,100 Class II injection wells and the EPA is responsible for seven Class I wells. Because Alaska’s Class I wells are associated with oil field infrastructure, Norman said, it would save EPA sending inspectors from Seattle if the commission had oversight.
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