Big Rates In Alaska

When was the last time a really strong flow rate from a conventional well rocked you back on your heels? And when was the last time such news came from Alaska, where multiyear exploration programs are typically the province of tight-lipped majors?

We’ve become so accustomed to talking in unconventional oil and gas terms—discussing metrics on density and size of frack stages, proppant loads and fluid volumes—that we are almost at a loss when hearing how modest the “old school” completion was that allowed a conventional well to prove remarkably productive.

Consider a multiday test demonstrating a flow rate of more than 2,100 barrels per day (bbl/d) from a perforated section amounting to just five feet and employing just a single frack stage in a vertical wellbore—a completion hardly pressing the limits of modern technology. Or consider a 17-day, tubing-constrained flow rate as high as 4,600 bbl/d from a lateral wellbore of 2,000 feet, with just six frack stages, which with a 6,000-foot lateral in a development program is projected to flow at 7,500 to 10,000 bbl/d with little to no decline for years.

Even allowing for the wide rift of geologic and economic differences between drilling in Alaska and the Lower 48, such results from the North Slope are generating excitement. And with good reason.

The North Slope is blessed with “an unbelievably great petroleum system,” according to Armstrong Oil & Gas Inc. president Bill Armstrong, who has been active in Alaska for the past 15 years. Most recently, the Denver-based firm has been operating under a five-year exploration program with Spain’s Repsol and U.S. independent GMT Exploration Co. The consortium recently released some of the striking results it achieved in the 2014-2015 drilling season.

The program began in 2011-2012 and is focused on an area between the 3.5-billion-barrel Kuparuk River Field and the 650-million-barrel (MMbbl) Alpine Field complex. Repsol operates the consortium with a 70% stake, with an Alaskan subsidiary of Armstrong Oil & Gas holding 22.5% and GMT Exploration holding 7.5%.

Multiple pay, multiple fields

The North Slope is blessed with an “unbelievably great petroleum system,” according to Armstrong Oil & Gas Inc. president Bill Armstrong, who has been active in Alaska for the past 15 years.

The latest results mean that the consortium has, to date, gone “16 for 16” in terms of wells finding hydrocarbons, most with multiple pay zones. Activity has led to the discovery of “multiple” oil fields on the North Slope of Alaska, according to Armstrong, with the latest results justifying the development of two fields. Permitting for the fields—one to produce from the Nanushuk Formation and the other from the Alpine—is underway.

Because the North Slope is dominated by three major oil companies (ExxonMobil, BP and ConocoPhillips), it is not unusual for new discoveries to fly under the radar, according to Armstrong. In fact, however, some fourteen 100-plus-MMbbl fields or field extensions have been developed since 1998, he noted.

He is quick to cite a medley of factors favoring exploration in Alaska: U.S. rule of law versus “rogue” states, projects that are onshore, multiple pay zones at shallow depths, good conventional sandstone reservoirs, easy drilling conditions, lots of running room, sweet, high-gravity oil, and in-place, underutilized infra­structure.

In addition, Alaska North Slope (ANS) pricing trades more in line with Brent than West Texas Intermediate (WTI), he notes, and new tax legislation covering oil and gas has replaced the prior “punitive” regime. As Armstrong says, “What’s not to like?”

Away from the legacy mega fields (Prudhoe Bay, Kuparuk River, Alpine), well control on the North Slope is minimal, with old wells sometimes townships apart. In other words, there is plenty of room for big fields to hide.

Armstrong Oil & Gas Inc. is part of a consortium that was formed in 2011-2012 and is focused on an area between the 3.5-billion barrel Kuparuk River Field and the 650-million barrel Alpine Field complex.

“Almost all of the new discoveries have been in sneaky, hard-to-detect stratigraphic traps, at least in comparison to more easily identifiable four-way closures. But now, with new 3-D seismic technologies, these subtle fields can be imaged,” he explained.

“There are eight or more known sandstone pay targets above 8,000 feet, and for the most part, if you find sand, you find pay,” he said. “Size, as they say, matters, but it is generally not a problem on the North Slope, as the median field size is in excess of 550 million barrels and the average reserves per well is over five million barrels.”

How important are the consortium’s new discoveries on the North Slope, specifically in its focus area known as the Colville High? Additional drilling will be needed to confirm the ultimate size, but there is plenty of reason for optimism.

In the Nanushuk reservoir, the consortium has drilled seven appraisal wells to date, including four in the most recent drilling season. The Nanushuk Formation lies at a depth of about 4,100 feet—that’s right, 4,100 feet. The two wells that were tested in March and April of this year—the Qugruk 8 and the Qugruk 301—are roughly two miles apart. The two other wells drilled most recently by the consortium, the Qugruk 9 and Qugruk 9A, about five miles away, encountered pay in both the Nanushuk and Alpine and are poised to produce from the latter.

The Qugruk 8 vertical well flowed 30-degree-API-gravity crude at rates of up to 2,160 bbl/d from a perforated section of only five feet, using a single frack stage. The well found approximately 150 feet of net pay with average porosity of 22% in an oil column of more than 650 feet, as it did not reach an oil-water contact.

Two miles to the north, the Qugruk 301 exhibited “negligible” bottomhole pressure drawdown in flowing at tubing-constrained rates of up to 4,600 bbl/d. The well had six frack stages along a 2,000-foot lateral, which is expected to be replaced with 6,000-foot laterals in a development program. These future wells are projected to deliver flow rates of 7,500 to 10,000 bbl/d.

Permeability of the reservoir averages 20 millidarcies, or a level translating to “100,000 times greater than the permeability of most shale plays,” observed Armstrong. “These are ‘old school’ conventional reservoirs.”

Also in the Colville High region, the consortium has drilled two wells in East Alpine Field in the most recent drilling season, adding to two previous East Alpine successes. The reservoir is at a depth of around 6,500 feet.

“One of the two earlier penetrations, the Qugruk 5, was drilled roughly eight miles from the main Alpine Field and found 100 feet of net Alpine pay,” Armstrong said.

In the latest drilling season, the Qugruk 9 and Qugruk 9A wells, located five miles from the Qugruk 5, which encountered both Nanushuk and Alpine pay, each found oil-productive Alpine sand more than 95 feet thick with porosities in excess of 20% and “excellent” permeability.

What does the analog production suggest in terms of performance of these new wells?

Every field is different, of course, but the established portion of Alpine Field provides a possible marker for how “robust” these wells may prove.

“Alpine Field would fall under the category of one of the best fields no one has ever heard of,” said Armstrong.

Not counting its numerous satellites, the field is well on its way to producing almost a half-billion barrels, with the average well producing about 8 MMbbl. After reaching peak production of around 130,000 bbl/d, the field produced at more than 100,000 bbl/d for six years. Production from the field, which was discovered in 1994 by Arco and later developed by ConocoPhillips, is still running at more than 50,000 bbl/d.

“We have really high expectations for the development phase,” said Ed Kerr, vice president of land and business development for Armstrong Oil & Gas. “With record pay thicknesses and excellent reservoir parameters, we model these wells to produce at high rates for a long time and to have EURs [estimated ultimate recoveries] that should exceed 10 million barrels per well,” he added.

Big pay, big play

“The Nanushuk is a new and different play for the North Slope, notable for even thicker pay than that discovered in the Alpine reservoir and at such a shallow depth,” Kerr said. “That’s what makes it so exciting. Nobody has seen this formation productive in this depositional environment before. You look at how thick it is, how good the oil is, how good the reservoir is—it all bodes really well for the play.”

In terms of the size of the oil pools found by the consortium, Armstrong notes that seismic and the seven appraisal wells in the Nanushuk have proven an oil pool covering more than 25,000 acres. In East Alpine Field, well control and seismic data indicate a pool covering in excess of 15,000 acres. Confidentiality and contractual agreements prevent Armstrong from disclosing estimates of ultimate field sizes, but calculations using the above parameters suggest the reserves are significant, according to the company.

Also noteworthy is that the consortium has assembled an acreage position of more than 800,000 acres on the North Slope, with all acreage purchased on identified geologic and geophysical prospects. The exploration program undertaken to date by the consortium has drilled less than 10% of this acreage, leaving more than 90% yet to be tested.

Armstrong’s track record in Alaska has been an exploration success story. In the early 2000s, the company generated two successful plays on the North Slope, in each case bringing in 70% partners. Pioneer Natural Resources came into the Oooguruk prospect, in which more than 225 MMbbl of recoverable oil were found, while Kerr-McGee Corp. entered the Nikaitchuq prospect, in which reserves totaling more than 230 MMbbl were discovered.

Activity by the consortium has led to the discovery of “multiple” oil fields on the North Slope of Alaska, with the latest results justifying development of two fields—one targeting the Nanushuk and the other the Alpine Formation.

Armstrong sold its remaining positions in both partnerships in 2005 to Italy’s Eni, which later acquired the Kerr McGee interest. Oooguruk, now operated by private-equity-backed Caelus, and Nikatchuq, now 100%-owned by Eni, together produce a significant amount of the oil going through the Trans-Alaska Pipeline System (TAPS).

fter several years in the Lower 48 during the early stages of the shale gas revolution, Armstrong returned to Alaska. It’s clear he’s not a fan of most shale plays, citing profit margins that can be “perilously tight,” especially in a low commodity price environment, and entry costs that can be high due to big upfront land prices. In addition, being a private E&P, Armstrong has been averse to taking on debt or bringing in a private equity partner. On returning to Alaska, the company began the work that led to its recent efforts with Repsol.

Armstrong attributes the scarcity of E&Ps in Alaska to what he terms “the Alaska Fear Factor”: concerns over access to infrastructure, limited availability of services, tough weather conditions and high taxes.

“After spending 15 years in Alaska, we have learned that these were either unfounded worries, or they could be solved. You learn to deal with the weather, and the service providers are equipped to handle the cold.

“Our infrastructure concerns were misplaced in that the FERC [Federal Energy Regulatory Commission] now controls most of the infrastructure, rather than the major oil companies. In fact, the infrastructure is largely in place, and there is huge underutilized capacity. The Trans-Alaska Pipeline System [TAPS] is running roughly three-quarters empty at around 550,000 barrels per day versus a peak rate of 2 million barrels per day,” he said.

Perhaps more than anything, prospects on the North Slope have benefited from changes in legislation affecting the oil and gas sector. Without the new legislation, which eliminated what some likened to “a modified version of the windfall profits tax,” the exploration activity of the past few years would likely never have materialized, according to Armstrong.

“The Alaska governor and the legislature passed a new tax law that was a game-changer for investors,” he said. “The old law was tough. The reason that new players are coming in is because the new law is something you can work with. If Repsol hadn’t known Gov. Sean Parnell [governor from 2009 to 2014] was trying to dramatically improve the tax law, they probably wouldn’t have come to the Slope. Current Gov. Bill Walker has continued to support the improved tax law, which will be the catalyst for more companies to come to the North Slope to develop its resource base.”

But Armstrong thinks the scale of the geologic opportunity in Alaska—akin to “what was found in the Lower 48 in the 1950s”—warrants still further increases in activity in tandem with the improved tax law, greater infrastructure build-out and plenty of capacity on TAPS.

“The North Slope needs more players,” he said. “There are huge conventional targets that are yet to be found. We’re just getting warmed up, and there’s so much more to do. There should be 30 E&Ps competing at the state sale, not just a few; more industry activity is good for everyone. The state of Alaska is open for business.”