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Alaska Oil and Gas Conservation Commission completes update of regulations begun in early 1990s Substantive changes include revised regulations for coiled tubing drilling, under balanced drilling, multilateral well bores, larger diverter lines, pit tests, commission enforcement, elimination of some make-work provisions Kristen Nelson PNA News Editor
A complete revision of the regulations of the Alaska Oil and Gas Conservation Commission has been forwarded to the Department of Law for final review. After the Department of Law has finished its review, the regulations will be filed with the lieutenant governor’s office and are effective 30 days after filing.
Commissioner David Johnston, who was on the commission when revisions began, reviewed for PNA in early March the major changes in the regulations. An earlier version of the revisions was forwarded to the Department of Law in 1996, but didn’t come back to the commission until late 1997. Last fall the commission took public testimony on the regulations as revised by the Department of Law and then held a series of public meetings at which it discussed the proposed revisions and accepted additional testimony.
Johnston said he thought recognizing coiled tubing drilling, multilateral well completions and under balanced drilling were important for industry. The big things for the environment, he said, were a requirement for larger diverter lines, pit drills, hydrogen sulfite-gas detection equipment requirements and tightening of the annular disposal regulations.
Changes in requirements for spacing exceptions to match Alaska land ownership patterns will remove a lot of what was essentially meaningless paper shuffling for the commission, Johnston said, as well changes in some reporting requirements. The commission also wrote regulations for enforcement which, Johnston said, “puts some sideboards on the commission” and specified requirements for emergency actions. Multiple well branches The commission made provision for wells with multiple producing branches — recognizing, Johnston said, “that you may have a well that has several branches to it, completed to several different bottomhole locations, and they can be all active at the same time.” The commission’s new regulations require a well permit for each branch, but only the first permit application need contain complete information about the well. Applications for permits for the branches need only refer to the original application and contain information unique to that branch.
Historically, he said, “when you drilled to a new bottomhole location you generally abandoned the old one.” The new regulations recognize that there may be several active bottomhole locations from one surface location. Shutting in, marking wells changed Overall, Johnston said, “a lot of what we did is kind of look back at how we were really operating and tried to make our regs read the way we really operated. Often,” he said, “the regs would say one thing but we were doing something a little bit different. So what we attempted to do when we embarked on this endeavor is not only respond to industry’s needs in terms of writing stuff that would allow coiled tubing drilling and under-balanced drilling, but also to kind of indicate exactly how we were operating as a commission in terms of how we were carrying these wells on our books.”
The commission always recognized, he said, that there were shut-in wells, but “if you read the old regs you were kind of lead to believe that all the wells are active or they’re abandoned or suspended. But quite honestly we have a bunch of wells that are shut in.” It’s important, he said, because it keeps those wells on somebody’s radar scope.
One change which will have a visual impact is that abandonment markers, which under the old regulations had to be on a post sticking out of the ground several feet, now are preferred by the commission to be welded to the casing.
“We’re not saying that you can’t put a post up,” Johnston said. “We’re saying what we want to see, preferentially, is the plate, welded to the top of the casing and presumably then you can back hoe over that so you have no evidence of it.” Changes include environmental, administrative issues Changes incorporated since the commission began working on revisions in the early 1990s include gas detection equipment on rigs — warning systems for both methane gas and hydrogen sulfide. It a worker safety type issue, Johnston said.
A section on enforcement spells out the commission’s procedures. It specifies rights in seeking review with the commission. “We have provision for informal review where we do it in a small setting. And then provisions for a more formal public review.” The commission adopted procedures for emergency actions, recognized procedures in a hearing for an operator or petitioner to be represented by council, to identify witnesses, to pre-file testimony, to cross examine and offer rebuttal. Commission holds firm on cementing, BOP tests An issue on which there was considerable discussion with industry was cementing of surface casing to the surface. Johnston said it was a big issue in the early 1990s and a big issue last year.
The commission required cement to surface, rather than allowing other measures of a good cement bond, for two reasons, and tightened up procedures from earlier regulations, he said. “The surface casing, if you’re using your well for annular disposal, that cement helps ensure that the waste does not come back to the surface. So you want good cement there for containment.
“But probably more importantly, it’s — the surface casing is your first string of casing upon which you hang your BOPs, so if you’re going to have to use those BOPs to shut in an uncontrolled flow, you want to make sure you’ve got a good seal around your surface casing and a good anchor to hold those pressures.”
The commission also disagreed with industry on the issue of how often blow out preventers needed to be tested. A weekly test has been required and the commission kept to that standard. But, Johnston said, “the important thing there is that’s not necessarily a rigid test. We will recognize, grant flexibility there. Because what we want to do is require the test when it makes sense for the well.” Pit drills will test crews, not just equipment The commission has added another feature to its testing — pit drills. The BOP tests, Johnston said, test the equipment. The commission also wants to know if drilling crews know what to do in an event that the equipment needs to be used. So they’ve given their inspectors the authority, working with the drilling supervisor, to have planned exercises to see how the crew responds to an event such as excess fluids in the mud tanks.
“So in concert with the drilling supervisor we’ll do planned exercises to review the capabilities and understanding of the rig crews to operate and respond to an incident,” Johnston said.
“I suspect we’ll hear some grousing that the state is involving itself in things that it shouldn’t be doing, but I think in the long run it’s still money well spent. Getting your crews properly trained, having your state providing a reasonable level of oversight. I think that’s all good business practice,” Johnston said. Spacing exceptions changed The existing regulations require an operator to apply for what is called a spacing exception if a well is to be drilled closer than a set footage to a quarter section line. The regulation, Johnston said, was lifted out of regulations from the Lower 48 where, because of land ownership patterns, the regulation makes sense. The new regulations require a spacing exception only at property lines—and only if ownership changes. On state land where adjoining leases are held by the same parties, exceptions won’t be required. If either lease or land ownership changes, the exception will still be required.
Johnston said that under the existing regulations, 90 percent of spacing exceptions are meaningless—nobody objects, it just makes work for the commission.
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