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Vol. 24, No.35 Week of September 01, 2019
Providing coverage of Alaska and northern Canada's oil and gas industry

Producers magazine preview: Glacier looking for Killian sands investor after successful well

Kay Cashman

Petroleum News

Glacier Oil and Gas Corp., which is solely focused on oil and gas fields in Alaska’s Cook Inlet basin and the North Slope, is continuing to move forward on two fronts in the state: maintenance and well workovers at its four producing units and plans for more exploration and appraisal drilling of the oil-bearing Cretaceous Killian interval in its eastern North Slope Badami unit. The formation was missed by previous operators but confirmed by Glacier in 2018 drilling.

That year the Houston independent’s capital spending was about $20 million, whereas this year it appears to be closer to $8-10 million. The difference was the cost of drilling the 2018 exploration well into the Killian sands in the Starfish prospect.

Savant Alaska LLC, a Glacier company, drilled the Starfish B1-07 well to test the Killian interval, a turbidite sandstone reservoir that sits immediately above the oil source rock and below the Brookian Badami sands that form the main reservoir for Badami.

With payout in about 15 months the well was promptly put online. In mid-May 2018, B1-07 produced 2,500 barrels of per day in early testing, tapering off to 1,600 bpd by January of this year.

Glacier President Phil Elliott told Petroleum News in April the company’s success at Starfish called for “investing nearly $200 million (gross) to prosecute a Killian-focused drilling program over the next 3-4 years.”

The value and price tag of that program impelled the small independent to begin a search for investors.

“It makes zero economic sense to drill one well at a time except to prove a concept (e.g., the Starfish/B1-07 well). To develop the Badami field in the most thoughtful way, we need to drill several wells over several drilling seasons, which results in a fairly significant capital outlay. Given the quantum required,” Glacier is seeking investors to help fund the drilling program, Elliott told PN in an Aug. 27 email.

In plans of development filed with the Alaska Department of Natural Resources’ Division of Oil and Gas for Badami, Glacier describes Starfish as one of “several new target pods of interest” identified through a geologic and geophysical review of the Badami and Killian sands.

Until Glacier can bring in an investor, no new wells are expected to be drilled in 2019, per an August email from Elliott. He also said Glacier “continues to evaluate the results of B1-07, which have been positive to-date.”

Glacier in Alaska

Glacier was created in early 2016 through the bankruptcy proceedings of Tennessee-based Miller Energy Resources Inc.

Unlike its predecessor, which had quickly acquired multiple oil and gas assets in Alaska and eventually became overextend when commodity prices dropped, Glacier has been taking a gradual approach by concentrating on maintenance activities to improve operations at existing wells and reserving its larger resources for targeted exploration prospects, starting with Starfish.

The four Alaska oil and gas units owned and operated by Glacier companies Savant and Cook Inlet Energy, or CIE, are as follows:

* Badami unit (Savant);

* West McArthur River (CIE);

* Redoubt Shoal (CIE);

* North Fork (CIE).

Whereas the Badami, Redoubt and West McArthur units mainly produce crude oil, North Fork is a natural gas field.

Badami problematic for BP

The fact that the Badami production facility and pipelines can handle 38,500 bpd is a reminder of the ambitions of the unit’s previous operator, BP Exploration (Alaska) Inc.

Conoco Inc., predecessor to ConocoPhillips, discovered the Badami oil pool in 1990 and BP brought the oil field into production in August 1998.

From nearly the beginning, the complex geology involving the compartmentalization of the oil reservoir into multiple, discrete sand bodies rendered the Badami unit challenging to produce. Oil output declined severely quite early in field life - BP suspended production on three occasions, with the second suspension lasting for two years. Field suspension allowed the reservoir pressure to recharge, as subsurface oil slowly migrated between the various sand units.

Oil production peaked a month after startup at some 7,450 bpd but soon began to drop, falling as low as 876 bpd by August 2007.

Savant, ASRC enter Badami

In mid-2008, BP took a different approach. The company gave Savant and ASRC Exploration LLC a stake in Badami in return for returning the unit to operation. With Savant taking the lead with a 67.5% interest, the companies succeeded in bringing the unit to sustained production, albeit at low levels. (Later, ASRC sold small pieces of working interest to other companies, ending up with a 25% share by mid-2019.)

The partners acquired the field outright in early 2012, followed by the Badami pipeline system, which BP sold to Nutaaq Pipeline LLC, a 67.5/32.5% partnership of Savant and ASRC in 2014.

Miller closed on the purchase of Savant in December 2014, becoming majority owner of the unit. As the deal was moving toward closing, oil prices fell by more than half, which severely challenged the economics of an already complex operating environment. Savant, and then Miller, decided to defer much of the development plan outlined for 2014 and early 2015. Miller’s bankruptcy further disrupted plans and then Savant and Badami became part of Glacier in 2016.

East Mikkelsen prospect

In late 2012, Savant asked the state to add seven leases, covering some 10,121 acres leases between Badami and the Point Thomson unit, to the Badami unit. The addition would have incorporated the East Mikkelsen prospect into the unit. Instead, in March 2013, DNR agreed to include only portions of two of the seven leases, some 2,204 acres from ADL 391001 and ADL 390825.

Both leases were set to expire on Jan. 31 and Feb. 29, 2012, respectively, but were extended by unitization proceedings.

The 2013 ruling also approved an exploration plan that required Savant to drill a directional well through the entire Canning formation and into the underlying Hue shale to evaluate the potential of the hydrocarbon-bearing Killian sands encountered in the East Mikkelsen Bay No. 1 well drilled in 1971 by ExxonMobil predecessor Humble Oil & Refining Co. (Humble had drilled the well to a total depth of 15,205 feet and encountered hydrocarbons in the Killian sandstone interval of the Canning between 11,516 feet and 11,572 feet, measured depth, with a tested flow rate of 700 bpd of 24 degree API oil.)

Savant would have needed to complete the well, perform an extended test and present the results of the test to the state by June 30, 2014. If the drilling was successful, East Mikkelsen would be developed jointly with the existing Badami unit.

Savant appealed the ruling in April 2013, saying it needed all seven leases to effectively explore the prospect. To address the pending drilling deadline, Savant also requested a stay of its plan of exploration in August 2013.

The company said it would review all potential targets outside the Badami sands participating area, “including, but not limited to, the Killian sands on the east side of the unit” and “intends to continue exploration to fully explore the unit area as economic conditions warrant, and once the unit expansion appeal issue is resolved.”

Although there has been intermittent paperwork surfacing between Savant and DNR, the unit expansion appeal has not been decided.

New pad for Badami

The latest and 16th plan of development, or POD, for the Badami unit approved by the division in June, includes activities in the lease expansion area outside of the Badami sands participating area.

Glacier promised to do the following during the term of the POD, which is July 16 through July 15, 2020:

* Apply for a permit to construct a new Badami drilling pad, the “Dock Pad,” which will be the surface drilling pad for additional Killian wells drilled toward the eastern side of the Badami unit.

* The B1-01 well workover will include pulling and replacing tubing; Savant also will run a casing inspection log for evaluation purposes.

* Convert the B1-14 well to a gas injection service well.

Savant said these operations would “occur during the second and third quarters of the 2019 POD period.”

In the June 17 approval letter acting division Director James Beckham wrote, “The division remains encouraged by Savant’s continued efforts to develop the Badami unit’s resources and looks forward to further positive production development soon.”

Savant production

In April 2018 Badami production had fallen to 698 bpd, but in May the field was up 203%, a difference of 1,419 bpd, to an average of 2,117 bpd because Savant had put the B1-07 Starfish exploration well online in the middle of that month.

In May of this year, the Badami unit averaged 1,721 bpd, down 26.7% from a June 2018 average of 2,180 bpd.

Glacier’s other two oil fields on the west side of Cook Inlet, West McArthur River and Redoubt Shoal, respectively, averaged 553 bpd and 1,191 bpd.

North Fork a small gas field

Standard Oil of California discovered North Fork in 1965, but the southern Kenai Peninsula field sat idle until the 1990s, when several independents attempted to develop it. An affiliate of Armstrong Energy acquired the property in 2007, brought on four partners and drilled several wells.

The Denver-based independent began delivering natural gas from the North Fork unit into the Enstar Natural Gas system in March 2011.

In 2013 CIE purchased the field from the Armstrong partnership.

In its current POD, which covers March 31 through March 30 of 2020, the company said it “plans to enhance production from currently producing wells through infrastructure improvements,” including additional compression and separation facilities.

CIE will also continue to monitor and analyze production from existing wells and optimize production, including monitoring water volumes and converting a depleted producer for water disposal if necessary.

If data and market conditions warrant, CIE said it will continue development drilling “to fully delineate and develop all fault blocks within the current unit.”

The company said it is also considering reprocessing North Fork 3-D seismic “to enhance resolution for possible additional development activities.”

It will also continue to evaluate drilling wells outside the current boundaries of the North Fork Gas Pool No. 1 participating area.

From December 2017 through November 2018, gas production from the field’s five producing wells totaled 1.74 million mcf, with monthly production ranging from a high of 164,934 mcf to a low of 129,544 mcf.

Enhancing output at West McArthur

The 28th POD for the West McArthur River unit runs from May 1 through April 30, 2020.

There are three producing wells in the unit, two in the Area No. 1 participating area and one in the Sword PA.

Activities in the 27th POD included continued analyzing of production within the 1991 WMRU No. 1 discovery well and enhancing production through perforation adds, well workovers and pump replacements.

CIE said it continues to monitor production to maximize uptime and conducted “small optimization and well maintenance operations to prolong field life” during the 27th POD, completing all operations discussed in that POD.

For the 28th POD, CIE said it will maintain an outstanding health safety and environment record at the unit and “continue to explore ways to enhance production, manage production decline, and increase total ultimate recovery from existing wells.”

CIE said it has filed a permit request with the Alaska Oil and Gas Conservation Commission to dispose of produced water by converting shut-in wells to produced water disposal wells. Four shut-in wells are listed in the POD.

The company told the division it continues to permit drilling plans for the Sabre offshore exploration prospect. CIE said it was seeking partners in Sabre, although the company is more focused on Badami and the Killian sands

CIE said it would continue to analyze production from all wells within the unit and enhance production “as appropriate through perforation adds within wells, well workovers and pump replacements.”

Redoubt Shoal activities

The Redoubt unit was formed by Forcenergy Inc. in 1997. It reached sustained production in 2002, and Glacier’s predecessor, Miller, acquired Redoubt in late 2009 and undertook redevelopment efforts between 2010 and 2013.

The new Redoubt POD under Glacier’s CIE is the 19th for the unit and covers May 1 to April 30, 2020.

Reporting on work accomplished under the 18th POD, CIE told the division it had proposed examining results of current and planned enhanced recovery waterflood and converting additional nonproducing wells to waterflood if appropriate; drilling and stimulating a sidetrack of the RU-4A well for use as waterflood injection; and changing out the failed electric submersible pump in the RU-9 well and stimulating that well as needed.

The company said it monitored Redoubt waterflood daily but did not complete the sidetrack of RU-4A, deferring that project to the second quarter of this year. It deferred changing out the failed ESP in the RU-9 well to the third quarter of 2020.

For the 19th POD, CIE said it plans to sidetrack the RU-6 and use it as a water injection well, work which would replace the company’s plan in the 18th POD to sidetrack the RU-4A.

The company said it anticipates the ESP in RU-2 will fail this year and plans to replace it in conjunction with the RU-6 sidetrack.

Results of enhanced recovery waterflood efforts will be examined, CIE said, and additional nonproducing wells might be converted to water injection.

Glacier said it is working on plans for wells to evaluate oil and gas potential north of the Redoubt Northern Fault Block and would resume plans to drill when economic conditions justify that work.

In the next year the company said it plans to drill and stimulate a sidetrack to RU-6 and use that sidetrack “as a waterflood injection well to further enhance production,” and is considering plans for additional produced water disposal.

“Redoubt is a mature field and we are reaching the practical limit for water disposal using currently available methods,” CIE said, adding that it “is considering alternatives to allow continued production to the economic limit of the field.”

The company also plans minor modifications to the Osprey platform “and add additional space for surface ESP support equipment.”



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