A low-profile state commission most Alaskans have never heard of helps keep the oil industry safe. Only rarely does the Alaska Oil and Gas Conservation Commission get into the mainstream news, and that’s a good thing according to its three commissioners.
If the AOGCC weren’t doing its job there might be a lot more news, of the unwelcome kind.
The three commissioners appointed to the commission, all long-time members and with extensive prior experience in industry, are Cathy Foerster, currently the chair; Dan Seamount and John Norman.
One seat is designated by law to be filled by a petroleum engineer and that is Foerster. One seat is designated for a geologist, and that is Seamount. The third seat is designated for a public member, and the requirement by statute was modified to require the public member be someone with knowledge of the industry.
Norman, who has had many years in private legal practice in oil and gas and natural resources law, fills that requirement.
Among other duties, the commission supervises tests of blowout preventers, or BOPs, on rigs before they start drilling. The BOPs are the fail-safe devices that close if there’s an unexpected surge of high-pressure oil or gas in a well, the kind that can cause a blowout at the surface unless they’re controlled.
The infamous Gulf of Mexico offshore blowout that killed people, destroyed the Deepwater Horizon drill rig and caused the largest oil spill in U.S. history resulted because the federal agency that was supposed to keep tabs on well-operator BP didn’t do its job.
The AOGCC wants to ensure that never happens here, and the job has taken on more importance since small independent companies have started drilling offshore wells in Cook Inlet with jack-up rigs. Newcomers often have lean budgets and staffs and are in a hurry to get wells drilled, and are not as familiar with Alaska operating conditions as the larger companies that have been here for decades.
So far there has been no “down-hole” incident with the jack-up rigs, or even the onshore wells drilling by the independents. The companies involved and the state agencies like the AOGCC, the state Division of Oil and Gas and the state Department of Environmental Conservation, have all been doing their job.
The commission does a lot of other things regarding well-safety, including approving the “down-hole” drilling and well-completion plans and procedures in drilling that are to prevent uncontrolled flows of oil and gas in the first place and the need for BOPs, although those are always a requirement as backup protection.
A new issue before the commission that has become controversial within the industry is over proposed changes to rules regulating hydraulic fracturing, or “fracking,” which has become a center of debate in other states.
Foerster said fracturing has been done for years in Alaska but that larger “frac” jobs on wells, similar to what is being done in the Lower 48, are now being done her or planned. The Alaska rules of fracturing need some tweaking, she said.
“We’re revising these rules for three reasons, one being that we’re always reviewing our regulations and making changes to keep up with technology changes in industry, and this is one example,” she said.
“Second, fracturing has become an issue of public concern in other states and potentially in Alaska. A lot of what we’re doing is just consolidating our existing rules into one place, for it’s easier for the public to see and understand.
Thirdly, there are some important things that our rules now do not cover. For example, we want disclosure of what is being pumped into the ground,” the chemical used in fracturing. “All the operators say they volunteer this information to ‘Frac Focus,’ a national information site, but it is not required. We would require it.”
The proposed new rules also require sampling of water in water wells if they are near an area being fractured, and for notification to adjacent landowners, she said. Contamination of water aquifers that support water wells has become a hot topic in some Lower 48 states. It would not be a factor on the North Slope, where there is permafrost, but it might on the Kenai Peninsula or other parts of Alaska if there is drilling near where people live.
Many in industry are not happy with the new proposals. Kara Moriarty, executive director of the Alaska Oil and Gas Association, said the AOGCC’s proposals would be the toughest “fracking” rules in the nation if they are put into effect.
Service companies that support fracturing jobs are also very concerned about how the chemicals they use, at least the volumes and combinations of them, are disclosed because these constitute company intellectual property.
Aside from drilling, the commission supervises tests of well safety valves on producing wells, one area getting more attention because of the aging of Alaska’s oil and gas fields, and it also approves operators’ plans for producing the fields, to ensure no oil and gas resources are lost due to rapid depletion schemes.
An example of this is that the commission will have to approve any plan to produce natural gas for sale from the big North Slope fields to ensure no crude oil or other hydrocarbon liquids are lost due to the gas being taken out of the reservoir.
There are many other tasks for the commission, including the approval of the spacing of production wells to ensure proper drainage of an underground reservoir, the protection of neighboring leaseowners’ rights if there is a dispute, and a seemingly mundane task that is vital — the certification of the accuracy of metering devices that measure the flow of oil and gas.
The accuracy of meters ensures that producers in jointly-owned fields keep their full share of allocated production and that the State of Alaska gets its full share of state royalty oil, which is typically one-eighth or one-sixth of production depending on the lease.
The Gulf of Mexico blowout changed the landscape for U.S. oil and gas safety regulation, and it caused all state regulatory commissions including Alaska’s to take a look at what they are requiring of the industry.
The AOGCC undertook that review partly because certain kinds of wells that could be drilled in Alaska — ultra-extended reach wells — could encounter the same kind of “down-hole” issues that were encountered in the deep-water Macondo well in the Gulf of Mexico, mainly the detection of gas coming into the well at the bottom of a long well-bore.
In 2010, there was a proposal, by BP in fact, to drill long, lateral extended-reach North Slope wells from shore out to the offshore Liberty reservoir. Some of the wells would have been eight miles in lateral reach, and would have set world records.
BP has held off on the Liberty project for several reasons, but some of the technical challenges were similar to those with deep-water wells, and the AOGCC was concerned.
Rule changes have not yet been made because all of the technical reviews of the Macondo disaster are not yet complete, said AOGCC commissioner Norman, who has taken the lead on the project. When the Macondo reviews are completed, the commission will finish its work and make tweaks to the regulations if needed, Norman said.
One of the most important jobs of the AOGCC is to ensure there is maximum recovery of the oil and gas resources, which leads the commission to review and approve field operators’ proposals to develop the fields, or to make significant changes in how fields are managed.
It is in the interest of the field owners to ensure their production practices maximize the value, but the state, through the AOGCC, is responsible to ensure that the physical loss of resources are minimized.
There are times when the two goals conflict.
For example, the commission will soon hold hearings to determine if the companies’ current practice of injecting natural gas liquids that are produced in the fields into the Trans-Alaska Pipeline System, where they are mixed with crude oil, might have some adverse effect on ultimate recovery of oil from the fields.
An alternative use of some of the gas liquids, such as ethane, butane or propane, might be in Enhanced Oil Recovery in fields, to get more oil. Some of these liquids are used in EOR now, but others are injected into TAPS and sold. The commission will want to understand why more of the liquids can’t be used to make more oil rather than being sold.
“We were told by BP (the Prudhoe Bay field operator) in an earlier proceeding that they need all the propane that is produced for EOR (enhanced oil recovery),” said Foerster. “A question that has occurred to us is whether we are losing some oil because of all the liquids being sent down TAPS. They need to explain this to us, and show us that ‘waste’ (loss of oil recovery) is not occurring.”
This is an example of how an economic return to the companies by selling the natural gas liquids, a short-term benefit, might conflict with a benefit of maximizing ultimate oil recovery, a more long-term benefit.
The larger public benefit may be in the greater long-term recovery of oil, while the companies’ may seek shorter-term financial benefits through sale of the liquids.
A similar near-term gain vs. long-term recovery question is pending for the commission in approving a natural gas production rate for the North Slope fields to support a natural gas pipeline if one is built.
Natural gas is now used in the Prudhoe Bay field to produce oil, and the concern has always been that taking gas too early, or in volumes that are too large, could impair ultimate oil recovery.
The same issue exists in the Point Thomson field where both gas and liquid condensates are in the same reservoir.
The field operators will never be able to squeeze all the oil out of the rocks at Prudhoe Bay, so the issue is to assess the potential losses and determine if they are acceptable to the public. Similarly, at Point Thomson, a rapid drawdown of reservoir pressure due to gas production for a pipeline could impair future production of the condensate liquids.
Just as at Prudhoe Bay, the commission will have to weigh these effects before approving a gas production rate for the field.