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AOGCC updates Milne well requirements Wells with electrical submersible pumps will be evaluated for packer installation case-by-case based on ability to flow to surface KRISTEN NELSON Petroleum News
The Alaska Oil and Gas Conservation Commission has amended, rather than rescinding, a 1997 order which allowed wells at the Milne Point unit with electrical submersible pumps to be completed without a packer regardless of the potential of the wells to flow to surface.
BP Exploration (Alaska), which was the Milne Point field operator until Hilcorp Alaska became operator in 2014, had asked for and received an exemption from a packer requirement for wells completed at Milne Point with electrical submersible pumps.
Earlier this year the commission decided to review that exemption, Conservation Order 390; Hilcorp Alaska requested a hearing, which was held in September.
The commission issued Conservation Order No. 390A on Nov. 19, amending the original order.
In CO 390A the commission noted that under CO 390, Milne Point was the only operating field in Alaska with a field-wide waiver of the packer requirement for ESP equipped flow to surface wells.
In a Sept. 24 post-hearing response, answering some questions raised at the hearing, Hilcorp said the commission “has specific concerns about packerless ESP completions on certain Milne Point Wells within the Kuparuk Oil Pool, particularly wells that exhibit ‘quite high surface pressures’ relative to other ESP wells throughout the state.”
“Overall,” the company said, “AOGCC’s objective is to ensure safe operation of all wells, and to regulate consistently across the state.” Hilcorp also noted the commission’s concern that assumptions made in 1997 when CO 390 was issued may no longer be true.
Unassisted flow In the post-hearing letter Hilcorp provided the commission with information on the ability of ESP wells at Milne Point to flow unassisted to the surface, based on static bottom-hole pressure and water cut data. Hilcorp said it “conservatively predicts that 22 out of 84 active ESP production wells at Milne Point Field are capable of unassisted flow to the surface,” 22 in the Kuparuk oil pool and one in the Schrader Bluff oil pool.
The commission was also concerned about monobore wells at Milne Point, all of which are completed in the Schrader Bluff, Hilcorp said, telling the commission that no monobore wells at the field are capable of flowing unassisted to the surface.
Hilcorp said it is “committed to aggressively reducing overall reservoir pressures” at the Milne Point field, and has target pressures of 3,260 psi for the Kuparuk oil pool and 1,860 psi for the Schrader Bluff pool. These, the company told the commission, are the pressures at which a well can be killed with seawater.
Hilcorp said it plans to manage the issue of wells which are estimated to be capable of unassisted flow by “actively reducing overall reservoir pressure.”
Only Milne In its findings in CO 390A the commission said Milne Point is the only operating field in Alaska with a field-wide waiver of the packer requirement for ESP equipped flow to surface wells.
Milne Point ESP wells are either monobore wells, with single string casing, or conventional completions with multiple string casing. Of the 10 monobore ESP wells at Milne, only two are active and neither is capable of flowing to surface, the commission said.
“All packerless ESP completions in the Kuparuk River Oil Pool have multiple casing strings providing two mechanical barriers to flow,” the commission said.
Issues with packers The commission noted that Hilcorp testimony documented advantages and disadvantages of ESP with packers, and said while the installation of packers in ESP wells “provides an extra measure of safety” it also adds cost to the completion and “makes some routine well servicing procedures difficult or impossible.”
Hilcorp told the commission in its September testimony that use of a packer increases well complexity and shortens ESP life, and provided an economic analysis plotting economic limit vs. ESP life.
Based on an average run life for an ESP of 2.7 years, Hilcorp said the economic limit - the point at which if a well breaks Hilcorp won’t fix it - is 95 barrels per day. Packers may degrade the run life of ESPs, increasing cost and decreasing economic life, the company said, noting that if ESP life degraded to 1.7 years and workover costs increased 33 percent, the economic limit would rise to 145 bpd, which could reduce field recovery efficiency by 1 percent.
Commission decision The commission said that Hilcorp, in its September letter, voluntarily agreed to manage reservoir pressures at Milne Point by reducing injection rates in offset service wells where needed. Of 21 flow-to-surface Kuparuk River oil pool ESP completions, 11 have pressures greater than seawater gradient. For those wells, the commission said, Hilcorp committed to either run an ESP with a packer when workovers are needed or wait until the bottomhole pressure is reduced enough not to require a packer.
The commission also said monobore ESP completions should be phased out at Milne Point as those wells have only one mechanical barrier to flow, and said more frequent casing pressure tests are warranted for those wells.
While multi-casing packerless ESP wells are required to have production casing pressure tested at least every 8 years, monobore packerless ESP wells will be pressure tested at least every 4 years.
The commission also said no monobore ESP completions will be approved unless a suitable monitoring annulus is provided as part of well construction.
And, wells covered by CO 390 must be brought into compliance with commission regulations the next time a workover that requires pulling the tubing/ESP is performed. “Requirement for ESP packer installation will be made on a case by case basis,” the commission said, with ESP wells having a pressure gradient greater than seawater gradient at the time of the workover will require installation of a packer as part of the completion hardware.
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