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Vol. 26, No.31 Week of August 01, 2021
Providing coverage of Alaska and northern Canada's oil and gas industry

KRU rig restart

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ConocoPhillips says workover rig in Q3, CTD rig in Q4, rotary in Q2 2022

Kristen Nelson

Petroleum News

Field operator ConocoPhillips Alaska says drilling will restart at the Kuparuk River unit with a workover rig in the third quarter, followed by the coiled tubing rig in the fourth quarter and rotary rig drilling in the second quarter of 2022.

In 2021 plans of development for the five participating areas at the Kuparuk River unit, approved July 23 by the Alaska Division of Oil and Gas, the company also said it will be shutting in the Meltwater participating area this year because of back-out issues at Central Processing Facility 2 and the PA’s low productivity, some 300 barrels per day in 2020.

Division Director Tom Stokes said in the POD approval that ConocoPhillips announced cessation of Kuparuk drilling in March of 2020 due to COVID-19 public health concerns. In April, Stokes said, the company “announced its plan to curtail oil production of approximately 100,000 barrels per day for the month of June 2020 from the KRU and Western North Slope Units.”

The ramp down began in late May, he said, and last July the company ramped production back up.

“CPAI now forecasts that about 50% of the production deferred by the curtailment will be recovered over the next three years with the remainder recovered over the life of the field,” Stokes said.

The current plan covers Aug. 1 through July 31, 2022.

2020 Kuparuk PA POD

At the Kuparuk participating area, the Kuparuk River unit’s main producing area, ConocoPhillips said it completed some work in the 2020 calendar year prior to the shutdown, including a three well coiled tubing drilling program with two producers brought online and one well returned to injection service after sidetracked laterals “failed to encounter resource in a previously untargeted fault block that was found to be water saturated.”

Two Kuparuk rotary wells were completed at drill site 3H, a producer and an injector.

The non-rig well work fleet was maintained throughout the 2020 COVID-19 pandemic, the company said, to ensure “timely response to well integrity events,” with non-rig wellwork adding some 9,000 barrels per day of gross oil in 2020 compared to 8,000 bpd in 2019.

A turnaround was executed at Central Processing Facility 1, while a CPF2 TAR, scheduled for 2021, has been deferred to 2022.

On the exploration side, ConocoPhillips said it continues to monitor two existing horizontal producer/injector well pairs at the Torok (Moraine) reservoir for long-term deliverability and waterflood, using the information to determine optimal inter-well spacing.

“Based on the performance of these wells, a new well pair is planned to be drilled in 2022,” the company said.

2021 Kuparuk PA POD

ConocoPhillips said the drilling program at the Kuparuk PA may include sidetracking existing wells shut-in by mechanical problems or low production to new bottomhole locations, with horizontal, multilateral and CTD sidetrack technologies playing an increasing role in the Kuparuk PA “to access incremental resources at reduced costs. Cost reductions and efficiencies will be essential to unlock the full value of Kuparuk resources,” the company said.

Kuparuk drilling is set to begin with startup of a workover rig and a CTD rig, followed by rotary drilling in 2022 “with an injector/producer pair in the Torok (Moraine) reservoir.”

Enhanced oil recovery at Kuparuk, which switched to full-field miscible injection in 2019, has allowed additional targets to be added to receive solvent injection, ConocoPhillips said, with the oil rate from EOR estimated to be some 4,900 barrels per day.

“The tertiary flood at Kuparuk has historically prioritized immature, efficient patterns to maximize EOR benefit,” the company said, but with natural gas production at Greater Kuparuk continuing to decline, “the MI injection strategy now prioritizes mature patterns with minimal gas trapping to maximize return gas.” Prudhoe Bay natural gas liquids are imported to Kuparuk but in the second half of the year, Prudhoe NGLs will be replaced with fuel gas imports to meet fuel demand at Kuparuk, as the Oliktok Pipeline is converted from NGL to fuel gas.

ConocoPhillips said it is evaluating options for after the OPL conversion. It said studies have shown oil rate benefits from lean gas in previously miscible gas flood areas, but “does not have specific timing for an official lean gas chase through the Kuparuk reservoir.”

The company said water handling capacity has often been a constraint on Kuparuk oil production and said it is looking at seawater demands for end users and “continuously studies future demands and whether expansion is required to meet needs for current and potential future users.”

There are also production constraints from gas handling limits and ConocoPhillips said it is studying forecast of total gas supply across the field after the Oliktok Pipeline conversion “and determining the ideal strategy to maximize EOR from gas injection while staying within critical gas handling compression limits.”

The company continues to replace electronic equipment at the field as it is becoming obsolete “at an increasing rate as manufacturers introduce new equipment and no longer wish to support older equipment.” Fire and gas systems have been upgraded at the central processing facilities and the seawater treatment plant, with upgrades at drill sites ongoing.

As of Dec. 31, 2020, there were 798 active wells, 434 producers and 364 injectors, with average 2020 oil production 62,700 barrels per day.

West Sak PA

Following the Kuparuk PA, largest volumes come from the West Sak PA, with 119 active wells in 2020, 56 producers and 63 injectors, and average daily production of 20,400 barrels.

ConocoPhillips said one new development well was drilled in 2020 prior to the suspension of drilling operations in the second quarter.

In 2014 the Alaska Oil and Gas Conservation Commission approved viscosity reducing water-alternating gas injection as an EOR process for West Sak. There were VRWAG injections in 2020, ConocoPhillips said, with early results suggesting positive results, and pattern-level surveillance efforts continuing.

There are also on-going trials of through-tubing conveyed electric submersible motor and pump systems, with six systems continuing to run “demonstrating the increasing potential of this technology to improve overall uptime with improved drawdown of West Sak producers. Assuming continued success with Rigless ESP field trials, additional systems may be considered for future wells.”

In discussing the 2021 POD, ConocoPhillips said West Sak injection and production “is challenged by matrix bypass events or highly conductive conduits between an injector and producer,” effectively short-circuiting waterflood “resulting in poor pattern sweep without remediation.”

Remediation treatments will be prioritized in the 2021 POD period, the company said.

Two CTD sidetracks are planned as part of a pilot program testing the viability of CTD at West Sak. Rotary drilling will be resumed following development of opportunities with future drilling focused on completion of the 3R well drilling program.

ConocoPhillips said it is evaluating candidates for West Sak well workovers, including future CTD sidetracks using Kuparuk donor wells.

Some 4D seismic is being used to understand some of the dynamic changes in the reservoir, the company said, with one survey in 2005 and one in 2011. “The 4D processing applied to these two surveys demonstrated reservoir changes and fault compartmentalization in and around the existing developments,” ConocoPhillips said, with the West Sak reservoir appearing conducive to 4D technology, and efforts underway to “understand the potential areas and timing for additional application and acquisition.”

Eight Kuparuk drill sites currently have West Sak production. “New developments at existing drill sites in the West Sak/NEWS area may require facilities upgrades such as the addition of heaters, electrical upgrades, and pipelines,” with additional facility requirements adding to the economic challenge of further West Sak/NEWS development “in the current business environment.”

The company said it is also “evaluating potential solutions for sand control within West Sak.”

Tarn PA

ConocoPhillips said there are 61 active wells at the Tarn PA, 38 producers and 23 injectors, with average oil production of 5,900 bpd in 2020.

No development wells were drilled during 2020; a producer was converted to gas lift service from jet pump service; a producer which developed annular communication was shut in; two injectors which were shut-in were brought online again after successful wellwork.

The company said routine paraffin scrapes and hot diesel flushes were conducted on many Tarn wells to maintain production.

Tarn was initially developed with miscible injectant for pressure maintenance and EOR, with miscible water alternating gas, MWAG, not recommended due to lower permeability in exploration wells and signs of water damage in laboratory tests of exploration well core.

But higher quality reservoir was discovered during development drilling from the 2N and 2L pads, reopening the potential for MWAG, which compared to continuous MI injection, is expected to yield higher recovery due to improved mobility control. Immiscible water-alternating gas using lean gas was applied to the Tarn reservoir from 2014-18, following cessation of NGL imports from Prudhoe, but when those imports returned in 2018, the field was returned to MWAG flood.

ConocoPhillips said there are no current plans for drilling at Tarn in the current plan period.

The majority Tarn wells have been converted to gas lift due to well integrity issues from jet pump power fluids, with paraffin scrapes and hot diesel flushes used to mitigate paraffin deposition to some extent - mitigation measures expected to continue to be applied in the plan period.

The three remaining wells on jet pump are being considered for conversion to gas lift.

Plans are in place to recomplete wells at Tarn with new perforations or by isolating high water cut zones, with feasibility of fracking or refracking the wells also being considered.

ConocoPhillips said “there is potential to further develop Tarn through new development well drilling” provided economics are competitive.

As a first step a new full field model for Tarn is being history matched and once complete, the FFM will be used to identify drilling opportunities and the associated economics and to compare then with other Kuparuk opportunities.

Tabasco PA

The Tabasco PA has just eight active wells, five producers and three injectors, and 2020 oil production averaged 1,100 barrels per day. Water production averaged 14,200 bpd.

There were no development wells drilled at Tabasco during 2020 and one well was shut-in when a high shut-in bottomhole pressure was measured.

The company said there are no plans for drilling activity at Tabasco during the 2021 plan period.

Waterflood operations will continue to be optimized, with plans to use artificial neural network machine learning in two wells in 2021.

“The reservoir management strategy is predicated upon injecting water deep into the central canyon and producing from the periphery,” ConocoPhillips said.

Meltwater PA

ConocoPhillips said it will be shutting-in the Meltwater PA south of the unit at drill site 2P. As of the end of 2020 it had 16 active wells, nine producers and seven injectors, with average oil production of just 300 barrels per day. Production is expected to continue at least through this summer, the company said in the 2021 POD for the Meltwater PA.

The company said shutting in Meltwater will “eliminate backout impacts to the rest of CPF2 production.”

In 2020, there were no development wells drilled; two producers were converted to jet pump operations, one of which had to be subsequently shut down due to low productivity.

The company said the nature of the reservoir requires reduced injection pressure, not enough to maintain reservoir pressure, resulting in a steady decline. “Insufficient pressure support and limited connectivity between producers and injectors impacted Meltwater well production, and low rates, frequent freezing, and no-flow situations have impacted Meltwater well uptime.” Some wells were converted to jet pump artificial lift but with limited success.

Some 15,000-17,000 barrels of water per day is cycled to and from DS2P to keep the line warm.

“This additional water cycling causes backout at CPF2, which significantly exceeds all existing and expected Meltwater oil production,” ConocoPhillips said, with daily backout at CPF2 caused by Meltwater estimated at 600 bpd, compared to Meltwater production of 300 bpd last year.

ConocoPhillips said it is working on detailed plans for the indefinite shut-in, which will address a timeline to plug and abandon the wells, possible movement of pigging equipment at DS2P, suspension of the surface kit, potential reuse of some surface kit elsewhere and potential use of DS2P gravel and pipelines for other developments.



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