ConocoPhillips Alaska is the largest oil producer on Alaska’s North Slope, operates state and federal units and has a major ownership interest in the Prudhoe Bay field, as well as lease positions, 75% of which, the company says, remains to be explored. Producing units operated by the company include the Colville River unit and the Kuparuk River unit on state land and the Mooses Tooth unit in the National Petroleum Reserve-Alaska. ConocoPhillips is in the process of developing a second NPR-A unit, Bear Tooth, which is the site of its large Willow discovery.
Kuparuk River unit
ConocoPhillips Alaska is the majority working interest owner, 92.4%, and operator at the Kuparuk River unit, the second largest field on the North Slope.
The most recent change at the field was the Aug. 14, 2019, state approval of the 12th expansion of the unit, adding some 21,513 acres in 11 leases north and west of existing KRU drill site 3S, adjacent to the northeastern edge of the unit and the southern boundary of the Oooguruk unit. These leases, the Nuna prospect, were previously part of Oooguruk when that unit was owned by Caelus Natural Resources Alaska, which contracted the 11 leases out of Oooguruk before it sold its interest in the unit to Eni earlier in 2019.
In its expansion approval the Alaska Department of Natural Resources’ Division of Oil and Gas reviewed drilling in the expansion area and said Pioneer Natural Resources Alaska drilled the Nuna No. 1PB1 and Nuna No. 1 exploration wells to further delineate the Torok reservoir within the Oooguruk unit. ConocoPhillips has drilled Torok reservoir wells in the KRU adjacent to the expansion area, the state said.
The division said ConocoPhillips applied to expand the KRU to include Nuna “based primarily on the tested, but undeveloped, resource within the Torok formation beyond the current unit boundaries of the KRU,” said even with existing information, development of the expansion area “is not without risk” and cited as a primary risk to further development if there is a lack of connectivity of “thin-bedded reservoir sands at the inter-well spacing between producer and offset injectors.”
The state said ConocoPhillips has undertaken a systematic approach to evaluating the Torok in the area since 2013, and “currently has two Torok horizontal producer and injector well pairs online in the KRU” and continues to evaluate connectivity and water injection pressure support.
A plan of exploration for the expansion area said ConocoPhillips and the other KRU working interest owners plan to explore and appraise the Nuna expansion area “in connection with further appraisal of the Torok FM within the currently existing boundaries of the KRU.”
In a transcript of ConocoPhillips’ July 30, 2019, second quarter earnings call, ConocoPhillips’ Executive VP and COO Matt Fox referred to Nuna as a high value bolt on to the company’s Alaska assets and said the transaction was expected to close in the third quarter.
In response to a question at the earnings call on where Nuna fit into the company’s development pipeline, Michael Hatfield, ConocoPhillips’ president of Alaska, Canada and Europe, described Nuna as a very low cost of supply, in the low $30s, and said it was $100 million for 100 million barrels.
Hatfield said Nuna would be developed from existing pads at Kuparuk and Nuna, gravel and a road are in place and remaining Nuna facilities could be built in a single ice road season.
Appraisal will be over the next couple of years with a target of first oil in 2022, he said, adding that existing drilling and completion technology will be used and the Nuna development will be incorporated as part of the company’s Kuparuk program.
Kuparuk field POD
The division approved the 2019 Kuparuk River unit plan of development, or POD, on July 2, 2019. The POD, submitted in early May, covers the Kuparuk, Meltwater, Tabasco, Tarn and West Sak participating areas.
ConocoPhillips is the majority working interest owner at Kuparuk, at more than 92%. It formerly had a 55.3% ownership, but then it acquired BP’s 39.2% interest in Kuparuk (and a 38% interest in the Kuparuk Transportation Co.) in July 2018 in a swap for assets in the United Kingdom. Prices were not disclosed but ConocoPhillips said in announcing the closing in December 2018: “Excluding customary adjustments, the transaction prices were cash neutral to both companies.”
Other WIOs at Kuparuk are Chevron at 4.95% and ExxonMobil at 2.7%.
ConocoPhillips said its 2019 POD described the status of the field as of the end of 2018.
The Kuparuk field is developed from 45 drill sites, some of which are shared with satellite fields.
Kuparuk had 833 active wells in 2018, 455 producers and 378 injectors, and had an average production rate in 2018 of 80,000 barrels per day of crude oil and 57,000 bpd of water, with an average water injection rate of 69,000 bpd.
Production for the entire unit, including all the participating areas as well as the main Kuparuk field, averaged 106,337 bpd for the 12 months ending July 31, 2019, the most recent data available from the Alaska Oil and Gas Conservation Commission when this issue of Producers was compiled. That compares to 111,142 bpd for the calendar year ending July 31, 2018, 106,800 bpd for the calendar year ending July 31, 2017, and 104,025 bpd for the calendar year ending July 31, 2016.
ConocoPhillips said 11 coiled tubing drilling wells were drilled in 2018, generating peak incremental oil of 3,300 bpd. Six West Sak wells were drilled in 2018.
The well workover program for the Kuparuk PA was scaled down to four wells due to lower well attrition and successful non-rig wellwork activity added some 11,500 bpd in 2018.
ConocoPhillips said five grassroots rotary wells are planned for 2019 in the Kuparuk PA, and some 20 CTD wells.
No additional drill sites are planned.
Natural gas liquids began to come in from Prudhoe Bay again in September 2018, and the increased NGL availability to be blended with gas for miscible injection allowed for an expanded enhanced oil recovery program. “The tertiary flood at Kuparuk is managed continuously by prioritizing immature, efficient patterns,” ConocoPhillips said.
“Gas handling limits with the gas lift compressors will continue to constrain production from the Greater Kuparuk Area,” the company said, with greater impacts in the summer. “Gas capacity debottlenecking continues to be studied as part of the facility management plan,” with emphasis on smaller project with high added value.
Water handling is often a constraint on oil production, more so since 2006 when produced water and seawater injection streams at Central Processing Facility 2 were segregated to reduce high corrosion rates in the water injection system. Upgraded blades began to be phased in in 2014, allowing increase in speed for water injection.
Gas lift is the most common artificial lift method for Kuparuk producers, the company said, but with water cut increasing to as high as 95% in some wells, “many wells cannot lift from the bottom due to the gas lift system pressure constraints,” a situation which miscible water alternating gas and immiscible water alternating gas has mitigated to a large extent with the returned miscible injectant and lean gas.
“Studies are ongoing to improve the artificial lift system, as well as evaluate the lift benefits from large scale lean gas injection,” the company said.
Electronic equipment is becoming obsolete at the field as new equipment is introduced and old equipment is no longer supported, so process control systems continue to be upgraded and automated. Fire and gas systems at the CPFs and seawater treatment plant have been upgraded and drill site upgrades are ongoing, ConocoPhillips said.
Large capital expenditures may be required due to obsolescence of turbines driving water injection pumps and generation equipment and transmission lines, substations and other electrical equipment are 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 KPU satellite fields,” the company said.
Exploration and appraisal
ConocoPhillips said the overlying Cretaceous Brookian Moraine at Kuparuk is being tested for productivity and waterflood, with a two well pilot producer and injector drilled in 2018 to provide performance data in addition to the original 2015 pilot wells, and two follow up pairs planned for early 2020. Coupled with results from special core analyses, this data will guide future plans for Moraine, the company said.
In addition to the Nuna prospect, acquired after the 2019 POD was filed, ConocoPhillips also has 17,920 acres adjacent to KRU drill site 2S, awarded to the company in December 2017, which includes the Cairn opportunity. The company said Kuparuk working interest owners “are currently evaluating the acreage to understand the potential risks associated with further development.”
In a presentation on the company’s 2018 earnings in early 2019, Ryan Lance, chairman and CEO, said the company had drilled two wells in December 2018 from existing gravel pads, testing the Cairn prospect from drill site 2S in the southwest corner of the Kuparuk unit.
The 2S pad, the first new drill site at the unit in 12 years, was built following drilling of the Shark Tooth No. 1 in early 2012. That well appraised an accumulation ARCO discovered, but never developed, in the southwest corner of the unit in the late 1980s with the KRU 21-10-08 well. The Shark Tooth was drilled from an ice pad some 4 miles from drill site 2K. Developing Shark Tooth from any of the existing drill sites in the area would have pushed the limits of drilling technology, the company said at the time.
The company also said it brought the 1H-Ugnu-401 well back online in April of 2019. The well had been shut in due to problems with the electric submersible pump. ConocoPhillips said it “continues to work through ESP troubleshooting in an effort to determine if higher oil production rates can be sustained.”
Meltwater PA
The Meltwater participating area, or PA, is physically separate from the rest of the Kuparuk River field, a small area south of the Tarn PA developed from the 2P drill site with 16 active wells in 2018, 10 producers and six injectors. In 2018 Meltwater’s average production rate was 700 bpd and its average water production was 40 bpd.
NGL imports resumed in September 2018 and Meltwater was returned to miscible injection flood in November. ConocoPhillips said MI was expected to last until the summer of 2019 “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.”
Meltwater injection was shut in from September through November 2018 while the 8 inch injection line was being replaced to covert the field from gas to water injection.
ConocoPhillips said the produced oil line from the 2P drill site “has a low average velocity and is monitored closely via several physical locations,” with the injection line a potential backup should the produced oil line be taken out of surface.
Further drilling opportunities are being analyzed and could include coiled tubing drilling sidetracks or producer to injector conversions.
Following conversion to water injection at 2P, “it is anticipated that the producers will be switched to jet pump when the wells are unable to lift without aid.”
Tabasco, Tarn
The Tabasco satellite field is within the boundaries of the Kuparuk River unit, on the west central side. In 2018, ConocoPhillips said, Tabasco had seven active wells, five producers and two injectors, and oil production averaged 1,200 bpd, water production 10,900 bpd and average water injection 11,400 bpd.
The major recovery mechanism at Tabasco is waterflood.
The Tarn participating area is at the southwest corner of Kuparuk. In 2018 Tarn had 65 active wells at two drill sites, 2L and 2N, 39 producers and 26 injectors. Average 2018 production at Tarn was 6,900 bpd of oil and 19,900 bpd of water with average water injection of 27,800 bpd.
Tarn oil is prone to paraffin deposition so hydraulic jet pumps were the primary method of artificial lift, with production increases of some 10% from use of hydraulic jet pumps.
“Recent Tarn wells were planned with gas lift for artificial lift, and current jet pump wells are being considered for conversion to gas lift as well design allows,” with only four remaining wells on jet pump at the end of 2018.
Ten wells have been converted to miscible water alternating gas injection service.
In 2017 and 2018, the company said, there were “reservoir characterization efforts” in the Tarn area, including development of a thin-bed petrophysical model, re-mapping the field and the beginning of work on a reservoir model to “enable the evaluation of the field’s remaining development potential. This analysis will continue in 2019.”
West Sak, NEWS
West Sak is developed from eight drill sites and had 123 active wells in 2018, 56 producers and 67 injectors. The West Sak PA and North East West Sak PA, NEWS, had combined production averaging 22,700 bpd in 2018, with 14,700 bpd of water and an average water injection rate of 36,100 bpd.
The 1H NEWS development project was completed in 2017 and 2018, ConocoPhillips said, including expansion of the existing 1H drill site to accommodate new wells. Waterflooding continues for pressure maintenance and enhanced oil recovery at the West Sak oil pool, with produced water the primary source of injection fluid for the core area in 2018 and seawater injection beginning at 1H in May 2018.
The company said injection and production at West Sak “is challenged by matrix bypass events … or highly conductive conduits between an injector and a producer,” which short circuit the waterflood “resulting in poor pattern sweep without remediation.” Six remediation treatments were attempted in 2018, but three failed before the end of the year. “A review of these failures is underway as well as an evaluation of alternative treatment methodologies.”
The Alaska Oil and Gas Conservation Commission has approved viscosity reducing water alternating gas injection for West Sak. “Early results of VRWAG suggest positive benefits and pattern-level surveillance efforts continue,” ConocoPhillips said.
Well completions and artificial lift continue to evolve at West Sak, the company said.
The focus at West Sak in 2019 will be delivery of the 3R drilling program, with expansion of that drill site to add nine new wells, including formation the North West Sak PA, incorporating 2017 3R development wells.
Over the next five years, viscous opportunities beyond 3R will include drilling from existing drill sites and may include new drill sites to access new drilling targets.
There has been one dedicated 4D seismic shoot over 60 square miles including most of the West Sak core area, with the time period between the two surveys from 2005 to 2011.
“The 4D processing applied to these two surveys demonstrated reservoir changes and fault compartmentalization in and around the existing developments. These results are being incorporated into surveillance activities and development planning.
“The West Sak reservoirs appear to be conducive to 4D technology,” the company said. “Efforts are underway to understand the potential areas and timing for additional application and acquisition.”
ConocoPhillips said the eastern NEWS 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.”
The division approved the 2019 POD in early July; it has since been amended, most recently, Aug. 27, 2019, to add four new wells at the 3R drill site.
Colville River unit
There are four working interest owners at the Colville River unit who collectively hold less than 1%; then there is operator ConocoPhillips Alaska, which since it bought out Anadarko Petroleum Corp.’s 22% unoperated interest in the western North Slope in 2018, an interest which included 22% at Colville, has held a Colville WIO of more than 99%. ConocoPhillips also now holds 100% in the two federal units in NPR-A, Bear Tooth and Greater Mooses Tooth.
In the 21st status update to the Colville River unit agreement, submitted to the division, Arctic Slope Regional Corp. and the U.S. Department of the Interior’s Bureau of Land Management March 15, 2019, ConocoPhillips reported on the status of the unit as of Jan. 1, 2019, and on plans for development for 2019 and the first quarter of 2020, with 14 wells planned for the CRU in that period.
There are six participating areas, four oil pools and eight reservoir areas in the CRU, the company said, with an application to form the new Fiord West Kuparuk PA submitted Dec. 21, 2018.
There are satellite oil pools at three drill sites - Qannik at CD2, Fiord at CD34 and Nanuq at CD4, with separate PA agreements.
“All CRU oil pools are developed primarily with horizontal well technology,” ConocoPhillips said. The Qannik and Nanuq PAs are primarily waterflooded, while Alpine, Fiord Nechelik, Fiord Kuparuk and Nanuq Kuparuk employ MWAG, gas-alternating waterflood using either miscible gas or sub-miscible enriched gas.
Alpine PA
In 2018, 152 wells had been drilled at the Alpine PA (78 producers, 72 injectors, two disposal wells). Average 2018 oil production at the Alpine PA was 37,100 barrels per day, with 32,400 bpd of water and an average water injection rate of 80,800 bpd.
Initial drilling planned from CD1 and CD2 was completed by November 2005, with peripheral opportunities pursued since then.
In 2006 development of the Alpine A and C sands began from CD4; CD5 was completed in 2015 with production startup in late October 2015.
Five Alpine rotary producers and three injectors were planned beginning in the first quarter of 2019 and continuing through the first quarter of 2020. Development during the period will also include coiled tubing drilling targets.
“In early 2020 the heel space between injectors CD5-23 and CD5-25 will be reduced via CTD laterals drilled into the gap between the wells,” the company said. There are other opportunities for CTD in 2020.
“Development of the Alpine reservoir continues to focus on the expansion of the existing MWAG flood and the use of line-drive horizontal well patterns.”
The company said performance from the Nanuq Kuparuk PA, which started in 2006, continues to exceed expectations, with current production of some 13,000 barrels per day of oil and 6,000 bpd of water.
ConocoPhillips reviewed the CD5 drilling program and noted that two wells, CD5-313 and CD5-314X account for most of current production from Nanuq Kuparuk.
“Drilling results from each CD5 well supported the next westward target,” the company said. “With CD5-316, results suggest another target exists to the west, but the location will need a drilling rig larger than Doyon 19 to access its potential,” so no additional Nanuq Kuparuk wells are planned for 2019, although a potential infill/CTD sidetrack could be drilled in 2019 or the first quarter of 2020 “as rig optimization/utilization dictates.”
The CD5 wells have been setting onshore drilling records since 2016, ConocoPhillips Alaska’s VP of external affairs and transportation, Scott Jepsen, told the Alaska Support Industry Alliance Sept. 12, 2019, with the onshore North American record for the longest combined footage for a well and laterals, 47,828 feet, set in July 2019 at the CD5-98 well, which also set an Alaska record, at 32,468 feet, for the longest single well.
The CD5-25, drilled in May 2018, has the record for the longest lateral onshore North American well at 21,748 feet.
Overall, the 10 longest well in Alaska have been drilled at CD5.
Fiord PAs
Fiord Kuparuk production averaged 400 bpd of oil in 2018 and 3,900 bpd of water, with average water injection of 6,400 bpd. Fiord Nechelik PA oil production averaged 5,500 bpd of oil in 2018 and 11,000 bpd of water, with average water injection of 16,800 bpd.
At Fiord, 23 wells, 13 producers and 10 injectors, have been completed in the Fiord Nechelik PA, with no new rotary wells planned for that PA in 2019 through the first quarter of 2020. There are three producer and two injector CTD sidetrack opportunities which could be drilled.
There were six active wells in the Fiord Kuparuk PA in 2018, three producers and three injectors. “The Fiord Kuparuk wells produce at high water cut making them non-competitive with other wells in the field,” the company said, with the wells brought online as water handling capacity allows. No additional Fiord Kuparuk wells are planned through the first quarter of 2020, although one well is being evaluated as a rig workover completion.
First quarter 2019 development plans at Fiord West included a Fiord West Kuparuk reservoir slant pilot hole well near where the extended reach drilling rig will be drilling extended reach laterals, ConocoPhillips said. This well is intended to evaluate static subsurface properties and production to assist detailed ERD well planning and execution.
The company said in its 2019 plan that the well would be included in the Fiord West Kuparuk PA - that new PA was approved May 30, 2019. It includes some 12,015 acres, is jointly managed by the state, ASRC and BLM and includes state, joint state-ASRC and BLM leases.
The PA is about a mile west of the Fiord Nechelik PA - an area with seven exploration wells, six of which encountered the Lower Cretaceous Kuparuk River formation.
In its approval of the PA ASRC said ConocoPhillips plans to drill seven wells in the Fiord West Kuparuk PA with production from the first well expected in the second quarter of 2019 and the other six wells to be drilled by the ERD rig due onsite in the second quarter 2020.
The ERD rig, which will be Doyon 26, will arrive on the North Slope in the fourth quarter of 2019 from Nisku, Canada, in 267 truckloads, Jepsen said. Drilling from a 14-acre pad, it will allow the company to develop 154 square miles of reservoir, compared to 55 square miles which could be developed without the ERD rig. He said Fiord West was a known accumulation, but development was problematic because the area is along the coast in wetlands. The CD2 pad has been extended with a little more gravel for the development.
Nanuq, Qannik
2018 oil production from the Nanuq pool averaged 1,200 bpd, with 100 bpd of water and average water injection of 1,500 bpd.
ConocoPhillips said the Nanuq pool has been developed primarily from CD4 and includes wells in the Nanuq PA, with six producers and four injectors active in the pool.
One CTD sidetrack is planned in 2019-quarter one of 2020; rotary drilling will be considered.
Qannik production averaged 1,600 bpd of oil in 2018 and 300 bpd of water, with average water injection of 1,900 bpd.
The Qannik pool has been developed from CD2 and includes nine wells, six outboard producers and three inboard water injectors with waterflood supplemented with a natural gas cap expansion from the east.
One producer-injector pair is planned for 2019-quarter one 2020 drilling; other drilling will be considered.
Alpine facilities
ConocoPhillips said there were no major process expansions planned for the Alpine Central Facility in 2019 but noted that in 2018 engineering studies were performed to evaluate current water, oil and gas systems limitations at the ACF and analyze options to maximize facility capacity.
In 2018 the Alpine Gas Expansion project was kicked off with the objective of debottlenecking ACF gas handling facility by upgrading the C1 turbine-compressor package and addressing other facility gas handling bottlenecks resulting from increasing gas throughput.
No CD1, CD3 or CD4 expansions are planned for 2019. The first expansion at CD5 was installed in 2017, adding 12 well slots, with engineering design studies completed for a second CD5 expansion in 2018. That expansion will add 10 well slots in 2019.
Expansion engineering, design studies and permitting of the CD2X expansion to support the Fiord West development were completed in 2018, with gravel haul for the 5.3 acre pad expansion completed in the 2018 winter ice road season.
Drill site facility expansion of 21 well slots will be installed in 2019, ready for startup in the first quarter of 2020. Three existing well slots will be available for the ERD rig and three additional slots will be added to the CD2 Qannik well row, with a total of 27 well slots available for ERD drilling in the first quarter of 2020 with future expansion capacity for an additional 11 well slots.
Greater Mooses Tooth
Greater Mooses Tooth in the National Petroleum Reserve-Alaska is ConocoPhillips Alaska’s newest unit development, and the first unit on federal land in NPR-A.
The first pad, GMT1, is in production; the second pad, GMT2, is under construction.
In its CRU plan ConocoPhillips Alaska said GMT1 development began in late March 2018 with initial development drilling activities completed in mid-February 2019. The drilling rig was then moved back to CD5. Production at GMT1, the Lookout oil pool, started in October 2018 and is being processed through the Alpine Central Facilities.
GMT1 has an 11.8-acre drilling pad and the company said when production began in October 2018 that the pad will initially have nine wells with capacity for as many as 33. Peak gross production was estimated at 25,000 to 30,000 bpd and the gross cost was estimated at $725 million, including construction and drilling.
Alaska Oil and Gas Conservation Commission records show four development wells, five service wells and two wells listed as unknown drilled at GMT1. As of July 2019, the most recent data available from AOGCC, three wells were on production, and the field was averaging 11,335 barrels per day. However, 86.7% of that volume came from one well, MT6-05, 12.2% from a second well, MT6-03 and just 1.1% from the third well, MT6-06.
In the company’s July 30, 2019, earnings call, Matt Fox, ConocoPhillips executive VP and chief operating officer, said the company was getting lower than expected performance in two areas nationwide, one of which was at GMT1, where one of four production wells was performing below expectations.
In response to an analyst’s question, Michael Hatfield, ConocoPhillips president of Alaska, Canada and Europe, said with only four producers at GMT1, underperformance by a single producer “ends up significantly impacting the overall development.” He said no remediation is planned, but learnings from GMT1 are being applied to the company’s GMT2 plans, although he said GMT2 was a different reservoir.
ConocoPhillips began planning satellites after it brought the Alpine field online in 2000, the satellites being accumulations worth developing but not large enough to justify standalone processing facilities. The 2003 Alpine Satellite Development Plan proposed five satellites: Fiord, Nanuq, Lookout, Spark and Alpine West, with hints of as many as 10 additional accumulations within 30 miles of Alpine.
Fiord was developed from CD3 in 2006, Nanuq from CD4 in 2006 and Qannik from an expanded CD2 pad in 2008. Alpine West was developed from CD5 in 2015.
The other satellites ConocoPhillips listed were the Lookout satellite at a CD6 pad and the Spark satellite at a CD7 pad - both of those in NPR-A. Around that time ConocoPhillips described Lookout as “marginally economic,” but said the economics would be improved by the bridge across the Nigliq Channel which was part of the CD5 development. In a 2009 revised application for CD5, ConocoPhillips changed the names of CD6 and CD7 to GMT1 and GMT2, distinguishing Greater Mooses Tooth from Alpine. Spark No. 1, Spark No. 1A, Moose’s Tooth C, Lookout No. 1, Rendezvous A and Rendezvous No. 2 were the NPR-A discoveries ConocoPhillips predecessor Phillips Alaska announced in 2001.
GMT2
Jepsen gave the Alliance a GMT2 update in his Sept. 12, 2019, presentation. The gravel pad and 8-mile road are scheduled for 2019, and Jepsen said that gravel was being reworked for the project. 2019 will also see preparation for pipeline installation, which begins in 2020 and is completed in 2021, with drilling beginning that year at GMT2 with first oil planned for late in the year.
A joint record of decision for GMT2 was issued in October 2018 by BLM and the U.S. Army Corps of Engineers, following a final supplementary environmental impact statement in September 2018.
ConocoPhillips is estimating peak production of 35,000 to 40,000 barrels of oil per day from up to 48 wells and a gross capex for the project of some $1 billion.
