New wells at Kuparuk
Conoco says 5 grassroots rotary wells, some 20 CTD wells are planned for 2019-20
ConocoPhillips Alaska says five grassroots rotary wells are planned for the Kuparuk participating area in the Kuparuk River unit, along with some 20 coil tubing drilling wells. ConocoPhillips filed the 2019-20 plan of development for the Kuparuk River unit ConocoPhillips with the Alaska Department of Natural Resources’ Division of Oil and Gas May 2 on behalf of itself as operator and working interest owners Chevron U.S.A. Inc. and ExxonMobil Alaska Production Inc.
The company said it is testing the “overlying Cretaceous Brookian Moraine” at Kuparuk and the WIOs are evaluating acreage near drill site 2S which includes the Cairn opportunity.
The POD covers the period from Aug. 1, 2019, through July 31, 2020.
Kuparuk is developed from 45 drill sites and various of those are shared with Kuparuk satellites Meltwater, Tabasco, Tarn and West Sak. In 2018 there were 833 active wells in the Kuparuk PA, 455 producers and 378 injectors. Production from the Kuparuk PA in 2018 averaged 80,000 barrels per day of oil (110,893 bpd for the Greater Kuparuk Area, which includes the satellites), 18 million standard cubic feet per day of natural gas and 57,000 bpd of water.
ConocoPhillips said that an 11-well coiled tubing drilling program in 2018 generated a peak incremental oil rate of some 3,300 bpd. Six West Sak wells were also drilled in 2018.
A non-rig wellwork program including slickline, electric line and service coiled tubing jobs added some 11,500 bpd of gross oil in 2018. And miscible injection continued in 2018 with natural gas liquids from the Greater Kuparuk Area at five drill sites.
2019 Kuparuk planThe drilling program in the 2019 POD includes five grassroots rotary wells in the Kuparuk PA and some 20 CTD wells; no additional drill sites to access Kuparuk A and C sands are planned during this POD period.
For enhanced recovery, imports of NGLs from Prudhoe Bay recommenced in September, increasing the availability of NGLs for blending with gas for miscible injectant, allowing for an expanded EOR program. Drill sites 1B, 1C, 1D, 1E and 2C have been previously targeted and will continue to receive MI, the company said. Drill sites at Central Professing Facility 2 will become additional targets.
In 2018, ConocoPhillips said, Kuparuk received an average of 64 million cubic feet per day of MI injection, with an oil rate from EOR estimated at some 9,400 bpd.
NGLs are expected to be received from Prudhoe until 2022 and until the cessation of those imports the primary expected gas injection fluid for the majority of Kuparuk is MI, with a long-term plan of following that with a lean gas chase. The injection of lean gas following the ramp down of EOR will allow for recovery of a portion of NGLs trapped as part of the EOR process and maintenance of liquid rates in high water cut producers as gas cycles through the reservoir from injectors to producers.
ConocoPhillips said gas handling limits with gas lift compressors will continue to constrain GKA production. “Gas capacity debottlenecking continues to be studied as part of the facility management plan,” the company said.
Water handling has often been another constraint on oil production and several facility projects are being evaluated to restore and enhance water injection at each of the CPFs.
Facility projectsConocoPhillips noted that electronic equipment at Kuparuk “is becoming obsolete at an increasing rate as manufacturers introduce new equipment and no longer wish to support older equipment.”
The company said process control systems are among those which will continue to be upgraded as existing equipment “becomes obsolete and no longer maintainable.”
Fire and gas systems have already been upgraded at the CPF and at the seawater treatment plant, the company said, and drill site upgrades are ongoing.
Large capital expenditures may be required as turbines driving the water injection pumps and power generation equipment become obsolete, and transmission lines, substations and other electrical equipment in the field is approaching expected end of life.
“Much of the operations support infrastructure will be assessed for upgrade or replacement to target another 25 years of production from the KPA and the KRU satellite fields,” ConocoPhillips said. The company noted that some of the large infrastructure projects in the past have included upgrading and refurbishing portions of the Kuparuk camp and office.
ExplorationConocoPhillips said the “overlying Cretaceous Brookian Moraine” is currently being tested at Kuparuk “to evaluate for productivity and waterflood performance.” The 3S-611 and 3S-612 wells, a producer-injector pair, were drilled late last year and are “providing reservoir performance data in addition to the original pilot wells drilled in 2015.”
In early 2020 two additional well pairs are planned “to further de-risk waterflood performance.”
“Coupled with results from special core analyses, this dynamic data will guide future plans for the Moraine.”
The WIOs are evaluating 17,920 acres adjacent to KRU drill site 2S, in the southern portion of the unit, awarded to ConocoPhillips in late 2017, which includes the Cairn opportunity.
The 1H-Ugnu-401 well was brought back online in April. It had been shut-in in 2016 due to electric submersible pump problems. ConocoPhillips said it is working through ESP troubleshooting to determine if higher oil production rates can be achieved.
Meltwater, Tabasco, TarnThe Meltwater PA is being developed from DS 2P, the most southernly portion of Kuparuk. There were 16 active wells in 2018, 10 producers and six injectors, with an average oil production rate of 700 bpd. The field was returned to MI in November after the resumption of NGL imports. ConocoPhillips said MI is expected to last until this summer, “at which point the injection line will be fully converted to water injection, which is the service expected for the remainder of the field life.”
The company said further development opportunities at Meltwater are being analyzed and could include coiled-tubing drilling sidetracks or producer to injector conversions.
Tabasco had seven active wells in 2018, ConocoPhillips said, six producers and two injectors, and averaged 1,200 bpd in 2018. The major recovery mechanism at Tabasco is waterflood. No further exploration or delineation drilling is planned for this POD period.
Tarn had 65 active wells in 2018 at two drill sites, 39 producers and 26 injectors. Average production for the year was 6,900 bpd.
Tarn was returned to miscible water alternating gas flood following the resumption of NGL imports.
ConocoPhillips said the use of hydraulic jet pumps has resulted in production increases of some 10%.
Ten wells have been converted to MWAG injectors and other future conversions will be considered, the company said.
Reservoir characterization efforts completed in the Tarn area in 2017 and 2018 include development of a thin-bed petrophysical model for the Tarn-Meltwater areas and re-mapping of the field. Last year, construction began on a reservoir model which “will enable the evaluation of the field’s remaining development.” ConocoPhillips said the analysis would continue in 2019.
West Sak, NEWSWest Sak is developed from eight drill sites. In 2018 there were 123 active wells, 56 producers and 67 injectors. Average West Sak PA and NEWS PA combined production was 22,700 bpd.
The 1H NEWS development project was completed in 2017 and 2018, including expansion of existing DS 1H, drilling of four multilateral production wells, 11 vertical/slant injection wells and recompletion of an existing wellbore into injection service.
During 2019, the company said, West Sak operations will focus on the 3R drilling program where the plan is to expand the drill site to accommodate nine new wells, a project which would include formation of the North West Sak PA, incorporating the 3R development wells that have been producing under tract operations.
ConocoPhillips said new drill sites are possible for West Sak and NEWS.
The Eastern NEWS, ENEWS, oil pool is being evaluated for development opportunities, with the evaluation “heavily dependent on the results seen from other viscous development opportunities the company is currently exploring.”
- KRISTEN NELSON