Kuparuk: Rigs down right now, but Conoco’s goal 25 more years
ConocoPhillips Alaska, operator of the North Slope’s second largest field, Kuparuk, prefaces its newly filed Kuparuk unit plan of development with a warning that the plan was “envisioned prior to COVID-19 and the market downturn.”
“The nature and extent of impacts to previously planned activities is very uncertain and will depend in part on the duration and severity of public health and market conditions,” the company said in the POD submitted to the Alaska Department of Natural Resources’ Division of Oil and Gas May 1. It covers Aug. 1 through July 31, 2021.
ConocoPhillips has already announced responses to COVID-19 and market conditions.
In early April the company said it was demobilizing its North Slope rig fleet (see story in April 12 edition of Petroleum News), citing the COVID-19 risk to its North Slope workforce and the need to significantly reduce the number of personnel on the Slope.
On April 30 ConocoPhillips announced company-wide production cuts for June, including a curtailment of 100,000 barrels per day of production from Kuparuk River and the western North Slope, citing “unacceptably low oil prices resulting from global oil demand destruction caused by the impacts of the COVID-19 pandemic, combined with a global over supply of oil.” (See story in May 3 edition of Petroleum News.)
But while there may not be a lot of activity in the coming year, in discussing facilities issues the company said it was looking at upgrades to support another 25 years of Kuparuk production.
Kuparuk fieldConocoPhillips is the majority working interest owner at Kuparuk. Chevron U.S.A. Inc. and ExxonMobil Alaska Production Inc. each hold minority working interests.
There are 46 drill sites for Kuparuk and 878 active wells, 506 producers and 372 injectors, with average oil production in 2019 of 73,000 bpd, water production of 557,000 bpd and water injection 675,000 bpd.
Activities for calendar year 2019 included: 22 coiled tubing drilling wells, including five West Sak wells, for a peak incremental oil rate of approximately 2,100 bpd gross.
Non-rig wellwork activity included slickline, electric line and service coiled tubing jobs, adding some 8,000 bpd gross.
The greater Kuparuk area “operates under full field miscible injectant with approximately half being imported and half being indigenous,” the company said.
To optimize production, depletion mechanisms must be prioritized and staged “to load the existing pipeline and facilities infrastructure in the most cost efficient manner,” ConocoPhillips said.
Development drilling targets high value locations and shut-in wells are candidates to be sidetracked to new bottomhole locations, with horizontal multilateral and CTD sidetrack technologies expected to play an increasing role.
The company said no new drill sites are planned before July 2021.
Natural gas liquids imports from Prudhoe Bay resumed in September 2018, and the increased NGLs to blend with gas for miscible injectant, MI, allowed for an expanded enhanced oil recovery program at Kuparuk, with the switch to full-field MI in October 2019 allowing for additional targets at Central Processing Facility 3 and several CPF1 drill sites.
ConocoPhillips said Kuparuk received an average of 83 million cubic feet of MI injection in 2019, with an oil rate from EOR estimated at 7,700 bpd.
“Alternative EOR opportunities for Kuparuk are being explored with laboratory investigation and field testing of promising methods to recover additional resources that are currently considered residual oil,” the company said.
A long-term plan of lean gas chase is anticipated, given favorable gas production in the field, since studies have shown oil rate benefits from injecting lean gas following an MI flood, allowing for recovery of a proportion of NGLs trapped as a result of the EOR process and maintaining liquid rates in high water cut producers.
FacilitiesConocoPhillips said gas handling limits will continue to constrain greater Kuparuk area production and debottlenecking continues to be studied, with an emphasis on smaller projects with high added value.
Water handling capacity has also been a constraint, and the company said upgraded blades began to be phased in during turbine overhauls beginning in 2014, allowing for increased speed and increased water injection capacity.
Several facility projects are being evaluated to restore and enhance water injection capability.
Gas lift is the most common artificial lift method at Kuparuk and with water cuts now as high as 95% in some Kuparuk wells, “many wells cannot lift from the bottom due to the gas lift system pressure constraints,” ConocoPhillips said.
This has been mitigated in miscible water alternating gas and immiscible water alternating gas areas “by the returned miscible injectant and lean gas, which provides an artificial lift benefit from the sand face,” the company said, but there are issues such as increased water injection and studies are underway “to improve the artificial lift system, as well as evaluate the lift benefits from large scale lean gas injection.”
Other facility issues include the need to upgrade electronic equipment since that used at Kuparuk “is becoming obsolete at an increasing rate as manufacturers introduce new equipment and no longer wish to support older equipment.”
“Obsolescence of the turbines driving the water injection pumps and power generation equipment may require large capital expenditures,” the company said.
Key here is ongoing field 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.
Large infrastructure projects done in the past include upgrading and refurbishing portions of the Kuparuk camp and office, the company said.
AppraisalsConocoPhillips said the overlying Nuna Moraine is being tested for productivity and waterflood performance, with a two-well pilot drilled in late 2018 and two follow-up well pairs planned to further de-risk waterflood performance.
“Coupled with results from special core analyses, this dynamic data will guide future plans for Nuna Moraine.”
The company said it brought the 1H-Ugnu-401 well back online in April 2019. The well had been shut-in in 2016 because of electric submersible pump problems, which the company said it is continuing to troubleshoot “in an effort to determine if higher oil production rates can be sustained.”
Alaska Oil and Gas Conservation Commission records show the 1H-Ugnu-401 produced 822 barrels in April 2019 but nothing since.
West SakNext to the main field itself, West Sak has the most production of the greater Kuparuk area pools, averaging 21,700 bpd of oil in 2019 and 18,300 bpd of water, with 36,000 bpd of water injected. There were 117 active wells at West Sak in 2019, 55 producers and 62 injectors. West Sak is developed from 10 drill sites.
ConocoPhillips said injection and production in the West Sak oil pool is challenged by matrix bypass events - highly conductive conduits between injectors and producers which “effectively short circuit the waterflood resulting in poor pattern sweep without remediation.” Four new matrix bypass events, MBEs, developed in 2019; five MBE remediation treatments were attempted.
AOGCC approved viscosity reducing water alternating gas injected as an EOR process for the West Sak oil pool in 2014; four injectors received viscosity reducing injection in 2018 and ConocoPhillips said results suggest positive benefits.
A five well West Sak program was approved and started in 2019, with two injectors and a dual lateral producer completed in 2019. Future drilling at West Sak will initially focus on completion of the five well program; there are also plans to expand the 3R drill site to accommodate up to nine new wells, a project that could include formation of the North West Sak participating area.
“Development of the West Sak and NEWS oil pools may be enhanced by installation of new drill sites to provide infrastructure and access for new drilling targets,” the company said.
Smaller poolsThere are also three smaller pools at Kuparuk: Tarn, Tabasco and Meltwater
There are 56 active wells at Tarn, 39 producers and 17 injectors, and the field averaged 6,150 bpd of oil production in 2019 and 16,300 bpd of water, with 26,900 bpd of water injection.
Continuous MI injection was the development plan for Tarn, but a higher quality reservoir discovered during drilling from the 2N and 2L pads “reopened the potential of using an MWAG recovery process,” which, compared to MI, “is expected to yield higher recoveries than the original straight gas injection approach due to improved mobility control,” ConocoPhillips said.
NGL importation from Prudhoe ceased in 2014, and “immiscible water-alternating gas utilizing lean gas was applied to the Tarn reservoir through late 2018.” NGL imports resumed in 2018 and the field was returned to MWAG flood.
Tabasco had eight active wells in 2019, five producers and three injectors. Oil production averaged 1,390 bpd, water production averaged 13,640 bpd and water injection averaged 13,970 bpd.
Waterflood is the major recovery mechanism at Tabasco.
ConocoPhillips said that in recent years “reservoir management optimization by shutting in the central canyon producers to increase the pressure support on the peripheral wells shows positive results on total oil production and stabilization of water production,” with study of waterflood optimization strategies planned for the next 5 years and long term.
“In-depth geological study shows that the shallow portion of the Tabasco reservoir has not been adequately swept when compared to the deeper portion,” the company said.
Meltwater, at drill site 2P, has 10 producers and seven injectors, and averaged 450 bpd of oil in 2019, and 40 bpd of water.
Miscible injection stepped at Meltwater in 2019, ConocoPhillips said, and the field was converted to waterflood. There was a decade of gas-only injection, and the company said it expects it will be at least 7 years before it sees benefits of water injection.
Further development drilling opportunities are being analyzed, with possible opportunities for coiled tubing drilling sidetracks or conversion of producers to injectors.
- KRISTEN NELSON