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Producers 2021: Eni focus on facilities, maintenance Drops eastern North Slope acreage, but Nikaitchuq and Oooguruk facilities work, drilling picking up
Kay Cashman Petroleum News
The fates of the North Slope Nikaitchuq and Oooguruk units have been intertwined for two decades.
Bill Armstrong, who ran a small independent, entered Alaska in 2001 to pursue smaller oil prospects overlooked by ExxonMobil, BP and ConocoPhillips, the last two the only producer-operators on the North Slope at the time.
For example, the Exxon-operated Thetis Island exploration drilling program in the Beaufort Sea west of Oliktok Point found oil in the prospect. Development was not pursued at that time, but it proved a lead to Oooguruk and in 2007 the Thetis lease became part of an expanded Oooguruk oil field.
Because Armstrong preferred to operate without debt, he took a novel approach to exploring the complex and expensive world of the North Slope - attracting partners that were large independents and super-majors not yet active in the state. Because the prospects Armstrong identified were small in comparison to northern Alaska giants Prudhoe Bay and Kuparuk, they proved less risky and therefore attractive to these companies.
Through his partnering efforts, Armstrong brought Pioneer Natural Resources, Kerr-McGee and Eni Petroleum to Alaska by proving up the Northwest Kuparuk (now called Oooguruk), Nikaitchuq and Tuvaaq prospects in the nearshore waters of the Beaufort Sea. (Eni eventually merged the Nikaitchuq and Tuvaaq prospects into a single unit.)
In addition to stemming production declines, the Oooguruk and Nikaitchuq units helped diversify the historically small world of northern Alaska oil developments. Pioneer became the first independent operator in North Slope history, and Eni became the first company on the North Slope to operate production facilities independent of BP and ConocoPhillips.
The Nikaitchuq and Oooguruk units are now more intertwined than at any point in their producing lives. After being a minority partner at Oooguruk for its entire existence as a producing field, Eni US Operating Co., the American subsidiary of the Italian major Eni Petroleum, is wrapping up its second year as the operator and 100% working interest owner of both the units.
Nikaitchuq 14th POD Fifty-seven development wells have been drilled and completed in the Nikaitchuq unit as of June 28, 2021. They included two Class I disposal wells, three Ivishak source water wells, a N-sands test well, 29 Shrader Bluff OA Sands oil production wells and 22 Schrader Bluff OA Sands water injection wells. Of the 29 OA Sands oil producer wells, 24 have been twinned into dual lateral producers.
The primary cause for well shut-ins and workovers in the unit are electrical submersible pump, or ESP, failures and tubing corrosion. To mitigate the corrosion risk, all workovers and new drills incorporate coated tubing.
The 14th plan of development for the Nikaitchuq unit runs from Oct. 1, 2021, through Sept. 30, 2022, and was approved by Alaska’s Division of Oil and Gas on Aug. 25, 2021.
In its 14th POD application Eni said that facility upgrades will be completed to support the planned Nikaitchuq North exploration well (NN-02), as well as drilling the two remaining Spy Island Drillsite injection wells and the “potential” of six new wells discovered from the SP03-NE2 pilot-hole analysis from the 12th POD. (The work will include completing internal piping and electrical tie-ins for the new six-slot well containment shelter installed during that time.)
The Nikaitchuq unit consists of 11 state leases encompassing some 21,200 acres north of the Kuparuk unit. It produces from the Schrader Bluff formation with drilling from two locations - the Oliktok Point Pad, or OPP, and the Spy Island Drillsite, or SID, which is a man-made gravel island in shallow state waters off Oliktok Point where Nikaitchuq’s onshore production and processing facilities are located.
Nordic Calista Rig No. 4 is scheduled to conduct workover activities on OPP in Q4 of 2021 and Q1 2022, as needed. Workovers are planned on OI15-S4, OI13-03, OP16-03, OI20-07, OI06-05, OP09-S1.
Eni currently has plans to drill five wells (four grassroots and one sidetrack) during the 14th POD period. The injector SI02-SE6 of the original development plan is scheduled to be drilled Q4 2021 and will help support the SP01-SE7 and SP04-SE5 producers, Eni said in its 14th POD application.
Two new production wells and an injection well are also planned to be completed as part of the northeast extension during the 14th POD period. A second lateral is tentatively planned to be added to SP05-FN7.
Plant maintenance shutdown Well operations were planned to continue until late July 2021 when all rig operations were suspended in preparation for the production plant’s scheduled 10-year maintenance turnaround and the arrival of materials to continue workover and drilling operations. The Nikaitchuq turnaround occurred over 23 days in August and September 2021.
Reservoir management plans Eni said that reservoir management activities will continue in the Schrader Bluff participating area, or SBPA, with the following objectives:
* Maximize daily volumes and value by optimizing hydrocarbon production.
* Minimize risk exposure to key producing wells and maintain well integrity.
* Continue the polymer injection test at OPP through Q1 2022.
* Tracer sampling and interpretation in the OP-I2 polymer pilot area.
* Proactively define and develop mitigation plans related to water production.
* Proactively acquire reservoir performance data critical to reservoir management and overall recoverable volumes determination.
* Ensure timely execution of reservoir surveillance plans, workovers, re-completions and infill drilling.
* Update current reservoir simulations and studies to reproduce the field behavior.
* Find cost-effective solutions to optimize production.
Eni also said that a simulation model will continue to be maintained and updated to support the ongoing operations and future development of the Schrader Bluff OA reservoir. (The company has said the top of the Schrader Bluff pool is the Cretaceous shale below the Ugnu formation and the bottom of the pool is some 45 feet below the base of the Schrader Bluff OA sand.)
Other facilities work In addition to the Nikaitchuq facilities upgrades previously mentioned, during the 14th POD period, Eni said it will perform routine maintenance and mechanical integrity inspection of piping, equipment, vessels, tanks and other safety systems. The company has several planned minor facility upgrades at OPP and SID.
For example, process hazard analysis revalidation action items from the 11th POD will continue to be addressed and mitigated and cleaning and replacing inlet heat exchanger bundles will continue to add more heat to the processing system. Actions will be based on the heat exchanger analysis performed in the 12th POD.
An alarm management and rationalization study will be performed to reduce nuisance alarms in the OPP control room.
Financial approval is expected on the electrical power sharing, or EPS, project to connect the Nikaitchuq power infrastructure with the Oooguruk power infrastructure. Eni said it will allow more robust and efficient power system sharing between the two development projects.
Detailed design and fabrication will also occur during the 14th POD. Once approved, EPS startup is scheduled for 2023.
Exploration outside PA Eni drilled the Nikaitchuq North extended reach exploration well, NN-01 outside the Nikaitchuq unit’s participating area from SID into the Harrison Bay Block 6423 federal unit north of the Nikaitchuq state unit boundary.
The NN-01 well was first spud at SID on Dec. 25, 2017, but drilling did not get underway until February 2018 because of what Eni said were “unforeseen impacts to the drilling schedule.”
The well was drilled to a measured depth of 30,010 feet and suspended in August 2018, but not fully logged as it was short of its target which seismic showed to be at approximately 34,150 feet. NN-01 drilling was done with Doyon Rig 15, which had been specially modified for the well.
Drilling operations resumed in mid-January 2019, but due to the “drilling complications” at NN-01 that had plagued it from the start, Eni said it suspended the well in April of that year.
The U.S. Bureau of Ocean Energy Management said Eni’s NN-02 well would be “targeting the same seismic anomaly” as the first well.
Like the first ultra-extended reach well, NN-02 will be an S-shape wellbore into the target reservoir.
Eni had planned to drill NN-02 in Q2 2020 during the winter drilling season and complete it in Q3 2020. However, the company’s working interest partner in the Nikaitchuq North leases elected to go non-consent (not participate) in the drilling of NN-02, resulting in Eni temporarily postponing its drilling plans.
Eni applied for and received from the U.S. Bureau of Safety and Environmental Enforcement, or BSEE, a suspension of operations for an additional 2-year period, or until April 2022, to drill NN-02.
One of the reasons Eni gave for stepping out north of the Nikaitchuq unit to test the Nikaitchuq North prospect was it wanted new oil to take advantage of significant spare capacity in the standalone Nikaitchuq unit production facility, which can currently handle 40,000 barrels per day and can easily be expanded to 50,000 bpd, according to Eni.
May 2021 production from Nikaitchuq averaged 17,250 bpd.
Unit contraction delayed Low oil prices, reduced oil demand and impacts of the COVID-19 pandemic prompted Eni to request a delay in unit contraction on state leases for the Nikaitchuq unit.
The division approved the Nikaitchuq deferral on Feb. 17, 2021.
Unit agreements stipulate that 10 years after sustained unit production begins, the unit area must be contracted to include only lands included in an approved participating area, lands included in an approved unit plan of exploration or development, and lands that facilitate production including the immediately adjacent lands necessary for secondary or tertiary recovery, pressure maintenance, reinjection, or cycling operations. The agency may delay contraction of the unit area if the circumstances of a particular unit warrant.
The leases affected by the request - ADL 388571, ADL 388572, ADL 388575, ADL 388577, ADL 388581 and ADL 388582 - lie in the vicinity of Spy Island, approximately 3 miles north of Oliktok Point. They were added to the Nikaitchuq unit in an October 2007 unit expansion.
In approving the 2007 expansion request, DNR said that within the proposed expanded unit, potentially commercially recoverable reserves had been tested in the Cretaceous Schrader Bluff and the Triassic Sag River formations.
In granting the deferral, division Director Tom Stokes said Eni provided “evidence that the Schrader Bluff reservoir extends outside the current participating area and has described long-term plans to drill wells in this area.”
If the wells are drilled, and prove productive, that area would likely be included in the existing Schrader Bluff PA, he said.
Without a contraction delay, Eni might have lost the right to drill there, and if the Nikaitchuq unit was contracted, Stokes said, “the resources outside the unit are unlikely large enough to justify development by another lessee who might acquire the area in a future lease sale.”
The area would also likely require “duplicative facilities to develop.”
If the area was contracted from the Nikaitchuq unit, Stokes said, “then the relatively small resource size and difficult development options could prevent development and thus strand state resources.”
Contraction of the Nikaitchuq unit was deferred through Sept. 30, 2022, which corresponds with the expiration of the unit’s next plan of development, the 14th.
Drops eastern North Slope Eni surrendered its remaining 42 leases on Alaska’s eastern North Slope in July 2021; leases that were adjacent to acreage held by Oil Search and Bill Armstrong’s Lagniappe Alaska.
When asked why Eni relinquished the leases, the company told Petroleum News: “Eni completed its exploration studies on the area the leases covered and the prospectivity of the area didn’t meet Eni’s economic metrics.”
Oooguruk focus on facilities, workovers Eni submitted its 15th plan of development for the Oooguruk unit to the division on June 28, 2021; it was approved by the agency on Aug. 25.
The 15th POD covers Oct. 1, 2021, through Sept. 30, 2022.
The Oooguruk unit has16 state leases encompassing some 35,271 acres, with cumulative production from three participating areas through May 2021 totaling 43.8 million barrels of oil. Oooguruk production averaged 7,020 barrels per day from January through May 31, 2021.
Eni said the automatic 10-year contraction (to just areas under production) for Oooguruk has been revised by the division, delaying that date to Sept. 30, 2022.
Review of first year In its first year (under the 13th POD) as operator of Oooguruk, Eni was hampered by a series of external factors, mostly arising from the impact of the coronavirus pandemic on the Alaska oil industry.
The proration of the trans-Alaska oil pipeline and the curtailment of the gas handling capacity at the Kuparuk River unit created secondary problems at Oooguruk.
Prompted by those infrastructure challenges and by the broader economic conditions of falling oil prices and declining demand, Eni deferred its original plans to perform 15 maintenance and repair projects on 10 wells in 2020 in advance of resuming the drilling of new wells at the unit in 2021.
The company also undertook a range of other maintenance activities, including a gas debottlenecking project responsible for “several hundred” barrels per day of production.
Second year Eni said that during Oooguruk’s 14th POD capital investment and development activities continued to be affected by the low crude oil prices, lack of demand for oil, and the logistical interference of the coronavirus pandemic resulting in budget cuts, production curtailments and project deferrals.
In the three participating areas at Oooguruk - the Oooguruk Nuiqsut PA, Oooguruk Kuparuk PA and Oooguruk Torok PA - there are 37 development wells and a disposal well. There are also four well completions outside of existing Oooguruk PAs, two appraisal wells (one plugged and abandoned), and a Kuparuk test and an exploration well, Sikumi 1 (plugged and abandoned).
Eni said active development wells include 23 oil producers (18 Nuiqsut, three Kuparuk and two Torok), 13 injectors (10 Nuiqsut, two Kuparuk and one Torok) and the one disposal well, with the producers - with one exception - requiring gas lift to produce, limited to some 15 million cubic feet per day.
There is also some 10 million cubic feet per day in formation gas.
The back-out cost at the Kuparuk River unit (Oooguruk crude is processed at Kuparuk’s Central Processing Facility 3) is significant, Eni said, describing KRU as “primarily constrained by gas compression capacity,” so KRU fluid production is backed out when then high total gas oil ratio Oooguruk unit fluids enter the system.
The high gas lift rate and Oooguruk formation gas increase flowline pressure, and that, combined with KRU back-out, means all Oooguruk wells cannot be produced at the same time using gas lift. During 2020, an average of 12 of the producing 23 Oooguruk wells were online with total gas oil ratio ranking typically determining which wells are produced, the company said.
Eni discussed plans for additional wells at only one of the PAs, Nuiqsut. The company said future development plans include 12 additional Nuiqsut PA wells, with eight from available well slots and four from reclaimed well slots.
The company said it had planned several workovers “to recomplete shut-in or low performing wells prior to drilling planned new wells in 2021” in the 14th POD but those plans were deferred due to low crude oil prices, lack of demand for oil and COVID-19 logistical interference.
The company did do a number of rigless well interventions and maintenance operations.
Eni said routine operations during the 14th POD included general maintenance and replacement of critical oil, water and gas piping and valves, along with field-wide maintenance and routine maintenance on the three power generation turbines and two gas injection compressors at the onshore Oooguruk Tie-in Pad. Cathodic protections inspections were completed on the sub-sea production flowline from the offshore Oooguruk Drill Site to the tie-in pad, along with a mandatory U.S. Department of Transportation hydrotest.
In addition to some minor capital projects, major capital projects included finalizing commissioning and startup of the seawater injection system booster pump upgrade at the drill site.
An engineering feasibility study was completed for 20 million standard cubic feet per day partial gas procession, or PGP, at the tie-in “to mitigate gas processing constraints and reduce associated costs from KRU CPF-3.” That project received final Eni approval with detailed engineering beginning in June 2021 and startup forecast for 2023.
15th POD operations Eni said there will be no significant maintenance turnaround at Oooguruk during the 15th POD period from Oct. 1, 2021, through Sept. 30, 2022.
Similar routine maintenance will be performed on facilities as in all past years, including replacement of worn piping and valves and general mechanical integrity inspections of piping and other safety systems.
Engineering and operational efforts will continue in optimizing and debottlenecking existing equipment, including separator control system performance, proportional fluid sampling upgrades and measurement system accuracy.
A complete 5-year revalidation of the facilities Process Hazard Analysis was to be completed in November of 2021.
Minor capital facilities projects being evaluated include: “ODS and OTP control room relocation efforts, installing an access platform on the flowline shore crossing support structure, additional upgrades to the ODS polar bear camera system, upgrades to the compressor lubrication system and installation of a chemical injection system for the new Seawater Injection pipeline.”
Major capital projects include engineering and fabrication work on the PGP project.
Financial approval is also expected on the EPS project to connect the Nikaitchuq power infrastructure with the Oooguruk power infrastructure, allowing more robust and efficient power system sharing between the two development projects. Detailed design and fabrication will occur during the 15th POD period.
Reservoir management During the 15th POD period, Eni plans to further optimize the OKPA waterflood and the ONPA under-saturated water-alternating-gas flood and reestablish the OTPA enhanced recovery operation by repairing ODST-46i.
All OU floods will be managed to maximize voidage replacement.
Individual well and pattern surveillance data will be collected in all reservoirs to monitor performance versus expectations.
Simulation models will be updated to assist in reservoir and flood management decision.
Drilling plans Based on the four-year plan, Eni has approved two rig workovers to be executed during the 15th POD.
The proposed drilling schedule for the next four years is subject to changes depending on global economic environment and company investment objectives, Eni said.
“Drilling activities have been forecasted to be reactivated after the year 2025 based on the maturity of Partial Gas Processing Project,” Eni told the division in its 15th POD application. The company listed eight new wells plus reclaims for drilling between Sept. 1, 2025, and Sept. 1, 2028.
The reclaims were ERD-NO1, ERD-NO2, RC-47, RC-45, RC-40 and RC-35.
Exploration outside PAs Its plan of exploration for outside the existing participating area, Eni said it targets maximizing OU oil production, managing producing gas oil ratios, or GORs, and maximizing long term reservoir performance and value.
Consistent with these objectives, the company said it is evaluating two appraisal wells targeting the northern Nuiqsut reservoir. The wells, “ERD-N01 and ERD-N02 are within the proven drilling radius from ODS (~22,000 ft),” the company said.
Eni’s primary objective is to test the productivity and oil quality of the oil on leases ADL-379301, ADL-389953 and ADL 389949 in several horizons.
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