A version of this story appears in the October 2017 edition of Oil and Gas Investor. Subscribe to the magazine here.

During one of its regular weekly operations meetings this July, Devon Energy Corp.’s (NYSE: DVN) Stack team announced something irregular—and significant: the company’s stunning Privott 17-H well in southwestern Kingfisher County, the heart of the booming Stack area in Oklahoma’s Anadarko Basin.

Word about the well spread quickly through the offices and into Devon’s C-suite, for the Privott had set a new play record with an IP-24 of 6,000 barrels of oil equivalent per day (boe/d) from the Mississippian Meramec. It could have flowed more, the company said, but was constrained by the capacity of the production facilities.

“This well certainly created a lot of buzz,” recalled Wade Hutchings, senior vice president in charge of the company’s Stack team.

“You don’t see wells like that every day, but we’re seeing more big wells like that in the Stack. You know at Devon, we don’t normally focus on 24-hour IPs, but this was such a big number we just had to talk about it. We were surprised to the upside by the size of this well, and its 50% oil.”

Arkoma Basin Stack

“Stack and Scoop have sucked up a lot of the air in the room, but there are very real, and interesting, returns available on the other side of the state in the Arkoma Basin,” said president and CEO Luke Essman of Canyon Creek Energy-Arkoma LLC.

He has been active in Oklahoma since 2012; he and his management team have been involved in 10 E&P start-ups during their career—this is Essman’s third under the Canyon Creek moniker. The Tulsa-based company recently received funding from Vortus Investment Advisors LLC, and then in July, it announced having acquired 30,000 acres in the liquids-rich Arkoma Basin via grassroots leasing in Hughes, Pittsburg and Coal counties, where acreage is less expensive than in the hot Anadarko Basin.

At press time, Canyon Creek was drilling its seventh of 10 wells planned this year. Total vertical depth ranges from 4,000 to 8,000 feet, shallower than in the Stack counties to the west. Very rich gas is the main play, yielding 1,300 to 1,400 British thermal units (Btu) of gas per well. Essman said he expects to receive 45% to 60% of the price of West Texas Intermediate per NGL barrel.

He calls this the Arkoma Stack because he’s exploring two Woodford benches, but in addition, the Mayes Shale and the Caney Shale, both Mississippian in age. Drilling here is shallower than to the west, but in thermally mature rock, he explained. Average EURs are lower than to the west, but AFEs (authorizations for expenditure) are also lower.

“We can get into the leases cheaper, and our AFEs are sometime half what it costs to drill and complete on the western side of the state, yet we still average up to 1.2 Bcf per lateral foot, with high Btu gas, so that’s generating good rates of return.”

Because the basin was developed before, in the early 2000s, a lot of midstream capacity is still available.

“History doesn’t always repeat but it certainly tries—this basin has a lot of private equity companies jockeying for position to put together consolidated operating acreage. We’ve been here about four years.”

In the Scoop-Stack, there wasn’t much Woodford development back then, but after the Barnett Shale took off, big operators like Devon, Chesapeake and Newfield did a lot of lateral work in the Arkoma Woodford, principally in the natural gas window. “Then gas prices cratered, they left and the basin went dark, so it wasn’t fully explored,” Essman said.

“We have 10 years of production history here, so we’ve used that to help support our work going forward and expand by using today’s technology,” Essman said. “There were several hundred Woodford wells drilled here in the heyday, so that shapes our outlook.

“Recovery was low then, but gas prices were so high that it worked. Now, well recoveries here are much higher due to your sand concentration, your longer laterals and other technical advances.”

Essman said he thinks his full-cycle returns will compete with other plays across Oklahoma and elsewhere. Because leasehold acquisition costs are so low, less than $2,000 per acre, compared to the Scoop-Stack at $10,000, “it looks really interesting to drill.”

Subsequently, the Privott averaged 4,800 boe/d during the first 30 days, above the original 30-day type curve, Hutchings added. The estimated EUR for this one well is 2 million boe, analysts said. He credited the well’s success to good rock, a proprietary completion design and several optimizations based on data analytics.

Devon’s Stack position is a franchise asset with 670,000 net acres and 5,700 risked locations. Through the second quarter, its Stack production was up 20% to 105,000 boe/d (53% liquids). It plans to have from seven to 10 rigs in the Stack by year-end.

“We view this as world-class, and the amount of future development is massive,” Hutchings said. “In the Stack, the emergence of the Meramec has been transformative—it’s really opened our eyes.”

Many projects and single-well tests are underway through year-end. Four other Devon Meramec wells began producing recently, each with 30-day IPs of at least 2,000 boe/d.

A highlight to watch should be Devon’s Showboat project, which is kicking off in the fourth quarter in Kingfisher County just north of the Privott. The unique project will test four landing zones across the Meramec and Woodford Shale in up to 25 wells, most drilled with -mile laterals. Five such large-scale projects, centered in Kingfisher and Blaine counties, are planned within the next year.

“Our strong preference is 10,000-foot laterals; on a total value basis, the capital efficiency is much higher,” Hutchings said. “What you’ll see for us in 2018 will be dominated by more Showboat-like projects, and we still have a handful of single-well targets to test secondary landing zones and the edges of the play.” A host of other companies are testing additional Mississippian targets, he noted.

Devon has optimized its Woodford play in the Stack with a lot of history under its belt, Hutchings said, but today, it finds the Meramec has better economics, and it is devoting more capital to it. The formation is shallower and higher pressure than the Woodford and yields better EURs, he said.

Devon Energy's senior vice president Wade Hutchings said, "The emergence of the Meramec has been transformative."

Another Big Reveal

Shortly after Devon’s big well, Continental Resources Corp. (NYSE: CLR) unveiled its own Meramec playmaker, the Tres C. It had an even bigger 24-hour IP of 7,442 boe/d, if one counts oil, natural gas and 1,978 barrels (bbl) of estimated NGL, post-processing. Pre-processing, the well flowed 1,000 bbl/d and 29.6 million cubic feet per day (MMcf/d) of gas at a flowing casing pressure of 6,500 psi (pounds per square inch) from a 9,748-foot lateral.

“I emailed Tony [Vaughn, Devon Energy COO] to congratulate him on their well and told him to keep them coming. I didn‘t expect that a few weeks later, our Tres C would come on so strong,” said Jack Stark, Continental president.

“The Tres C is the biggest well I’ve been involved with in my career. These two wells demonstrate the remarkable potential of the Meramec reservoirs in the Stack.”

Continental has so far revealed completion of 48 overpressured Meramec wells in the Stack, extending the play from northeast Blaine County 25 miles south, and another 35 miles west into nearby Dewey and Custer counties, Stark said.

The company has density tests underway on seven Meramec drilling units on its 207,000 net acres in the Stack area. The Blurton eight-well test is still flowing back, but so far, the seven “children” were producing at about 80% of the rate of the “parent” well as of day 22, Stark said. These wells were still flowing back (load water is coming off), “and they have not yet reached peak rates, so we would like to see longer-term data to understand the relationship” between parent and child, he told Investor.

Continental also reported a newly established Stack condensate type curve of 2.4 MMboe (for a 9,800-foot lateral, 14% oil).

Further south in the Scoop area’s Springer play, Continental completed its Cash 1-26H to flow 1,200 boe/d (82% oil) during its first three months, and the well has produced almost twice as much oil as the company’s historical type curve of 940,000 boe, he said.

“Our technical innovations continue to improve the performance of all of our assets,” Stark said. Continental is as enthusiastic about the Springer’s potential as it is about the Bakken, he added.

All told, the company is going into development mode at a faster pace in the Stack because it has so much acreage HBP, Stark said. Currently it has two rigs drilling the Woodford and seven in the Meramec.

Making The Scoop-Stack Pivot

Companies and investors alike are turning to Meramec, Woodford, Osage and other plays spread throughout the Scoop-Stack counties after hearing about well results like these, seeing the region as a very competitive alternative to the overheated Permian Basin. Second-quarter conference calls rolled out some big wells, and almost every operator has revised its type curves upward for the Meramec. Numerous pilot tests like Continental’s are underway to test the most optimum well spacing, which will lead to full-field development in 2018.

“Scoop-Stack is the second-biggest play in terms of mind-share after the Permian; it’s really the only other game in town,” Subash Chandra, E&P analyst at Guggenheim Securities, told Investor.

In August, the U.S. Energy Information Administration (EIA) recognized this when it added the Anadarko Basin to its monthly Drilling Productivity Report (DPR), giving the Sooner state the attention it clearly deserves. The rig count has jumped to 129 in the region from 84 in January, and the EIA forecasts production will reach 500,000 bbl/d by the end of 2018, up from 437,000 bbl/d as of July.

For the record, the Stack region contains multiple stacked pays in the Woodford Shale; the Upper, Middle and Lower Meramec; the Osage and other zones. Although the Stack’s sweet spots cover Blaine, Kingfisher and Canadian counties, they are expanding northwest and northeast. In the Scoop (Grady, Garvin and Stephens counties), Meramec and Springer are the favored targets. The learning curve here will be at least as rapid as in the Permian Basin, with delineation the name of the game this year.

Research consultancy Wood Mackenzie is among those watching all this unfold closely. It breaks the Anadarko Basin into 12 sub-plays for in-depth analysis (see map).

“Productivity in the core areas of some of the sub-plays is increasing, and the former range of oil price breakevens, which was between $40 and the high $70s, is narrowing to $40 to $50,” said Jessica Van Slyke, WoodMac research analyst, Lower 48, based in Houston.

The firm issued its second annual Scoop-Stack-Cana Key Play Report in September. “One issue we’ve had is the first-half rig count in the Stack shot up quite a bit, so it was difficult for us to keep track of events there,” she told us.

“Another issue is when we started, we thought this would run out of locations, area-wise, vs. a more established play like the Bakken, but with all these extension areas being drilled now, we’d add at least another 50% proved, risked locations. The northwest extension to Stack (Blaine, Dewey and Woodward counties) will add the most, some 3,500 locations.

“We think Scoop-Stack has a lot more room for improvement relative to the other hot resource plays. Operators are just now starting to talk about moving into the development cycle.”

Some observers have complained that getting accurate, timely well data from Oklahoma regulators is a problem in these fast-moving plays; numbers don’t jive with what operators say publicly. “Oklahoma’s state-reported data discrepancies have created what we call a ‘dog’s breakfast’ for investors and offset operators,” Eric Busslinger, principal, Unconventional Energy Research Ltd. in Calgary, told Investor.

Nevertheless, the trends are up and to the right. Operators say they have begun testing well-spacing parameters. A few have begun to shorten their extended-reach laterals as they fine tune the process, although Newfield Exploration Co., which discovered the Woodford Shale a decade ago in the Arkoma Basin, has drilled some laterals as long as 18,000 feet.

It’s the beginning of a new era for the Anadarko Basin, which has been drilled for decades. In 2007, Devon Energy unveiled its Cana Woodford play in Canadian County. The play was mostly rich gas back then. Ten years ago, Oil and Gas Investor wrote about the Woodford: “Production of liquids—both oil and condensate—from horizontal shale wells was beyond the technical pale. … That didn’t stay the case for long, however. Rapid and revolutionary changes in drilling and completion techniques have now broken through both the depth and the liquids barriers.”

A decade later, technical progress is stunning yet still evolving. In summer 2016, Devon announced a record-breaking well in the same general area, Pony Express 27-1H, whose 30-day average was 2,100 boe/d (70% oil). But records are made to be broken; hence the Privott well. Chandra said that Newfield and Chesapeake Energy Corp. share a large offset position to the Privott.

Oklahoma’s increasing value surfaced at press time when Silver Run Acquisition Corp. II said it will acquire two companies to form a public, $3.8-billion Stack pure play: Alta Mesa Holdings LP and Kingfisher Midstream LLC will become Alta Mesa Resources Inc., listed on NASDAQ. The deal is supposed to close in the fourth quarter.

Alta Mesa was running six rigs at press time. It has drilled 205 horizontal Stack wells to de-risk its 300-square-mile position in the play’s oil window, said Hal Chappelle, who will remain CEO of the new entity; founder Mike Ellis will remain COO.

Marathon’s Pilot Projects

About a year ago, Marathon Oil Corp. (NYSE: MRO) bought PayRock Energy Holdings LLC for just under $900 million to add 61,000 net acres in the Stack. It compares these new assets favorably with its other recent deals, including large Permian acquisitions, as far as reserve potential and capital allocation. In the second quarter, its Oklahoma production was 49,000 net boe/d.

The company is applying technical lessons from other plays to Oklahoma, said Mike Henderson, regional vice president, since most of its Stack acreage is now HBP.

“Our differentiated and complementary position in three other low-cost oil basins, coupled with the ability to manage ‘big data,’ is a key,” he said. “It helps us with accelerated, and in many cases real-time, decision-making. It’s a big part of the story.”

So far this year Marathon has been focused on retaining leases, Stack infill spacing pilots to prepare for full-field development, and achieving the highest risk-adjusted returns, he said. It has already tested six and seven wells per section but plans a nine-well pilot before the end of the year.

The driller on the Nabors M-43 rig monitors progress at Chaparral Energy's High Valley well in Kingfisher County, Okla.

Current results look good, paving the way for well optimizations: On the Hansens pilot, the six infill wells averaged 915 boe/d over 30 days (55% oil), with average lateral length of 4,650 feet and completed well costs of $4.3 million. The pilot tested five wells at 660-foot spacing, and one additional well was placed between two strong existing producers, effectively testing density of eight wells per section.

The Hansens’ trail also tested multiple completion designs where pump rates, fluid types and volumes and the use of diversion were altered across the pad.

“We collected a lot of technical data, including electromagnetic proppant, microseismic and other fracture characterization methods, which we’re integrating with well-performance data,” Henderson said.

"Continental Resources Inc. has seven density tests underway in the Meramec," said COO Jack Stark.

Marathon drilled and brought to sales 32 wells in first-half 2017 and will drill another 30 to 40 by year-end. Currently, it has 10 rigs across the Stack and Scoop, with the majority in the Stack.

“It’s returns-driven,” Henderson told Investor. “We like both plays, but the returns we get in the Stack are better. We are going to focus on areas with the best return, and at the moment that is the Meramec oil window, primarily in Blaine, Kingfisher and Canadian counties.”

In first-half 2017, Marathon primarily targeted Upper and Lower Meramec, but it is considering opportunities in the Osage and Woodford for the coming quarters, he said.

“The sexy, headline-making IP numbers we hear about are great, but we are more focused on capital efficiencies, which involve balancing costs with well performance and generating strong returns. We’re putting an incredible emphasis on costs, and technology plays a big part in that."

“We have some dedicated folks on our drilling and completions team who are laser-focused on continuing to improve our efficiencies—where we are spending money and how it is contributing to the bottom line. How do we move a rig faster and with less cost? How do we drive NPT (nonproductive time) out of the business? Does it make sense to self-source our frack sand? We’re looking at all those things and more.”

"It's all about achieving the highest returns," said Mike Henderson, Marathon Oil Corp. regional vice president.

Marathon has done two of the only three or four industry infill pilots in the normally pressured black oil window in Kingfisher County. “It’s a fairly aggressive learning cycle, trying to crack the nut around well spacing and completion design—they go hand in hand. The more we learn from our spacing pilots and delineation drilling, the better we can apply that to our plan of development, and that’s where the value will come from,” Henderson said.

“We go from the black oil window to the volatile oil window in central Kingfisher. … The geology is more variable than the Bakken, where I’ve also worked. It’s got phenomenal upside, but we are really early—we’re trying to gather as much data as we can: core samples, proppant placement distribution, artificial lift optimization.

“Our team loves these kinds of problems; if it was easy, anyone could do it.

“Maybe one solution works at $50 per barrel but there’s a different solution at less than that, or it depends where you are in the play—there are so many moving parts, but that’s what makes it exciting.”

Sycamore Innovation

Several private operators that have plied the Anadarko Basin for decades with vertical wells are enjoying newfound horizontal success. Ward Petroleum Co. is one.

“The Permian has great reservoir rock, stacked pays and good infrastructure, but the Scoop-Stack pretty much checks all those boxes too,” said Bill Ward, CEO of this longtime Oklahoma private operator, which has been drilling here since the early 1960s under the late CEO, Lew Ward, his father.

Building on a wealth of vertical well control, more recent 3-D seismic data and, of course, horizontal drilling and advanced completions, Ward has racked up its own successes, most notably its Lynda well in southern Grady County (in the Scoop). That well tested 15.9 MMcf/d of gas and 860 bbl/d of oil from the Lower Mississippian Sycamore. Lateral length was 7,500 feet.

Chaparral Energy's Anthony Witter, gang foreman, gauges oil levels in tank batteries at the company's Low Valley well in Kingfisher County, Okla.

“We’ve drilled a lot of vertical wells in Grady County over the years for multiple zones, because it’s a stacked basin,” Ward explained.

“Historically, the Springer and Bromide were the most prolific zones, but we always found good backup zones in what we called the Big Four—that’s the Springer, Woodford, Hunton and Viola. As plays emerged and technology advanced, along with acquisition of high-resolution 3-D, we better understood the geological framework, further identifying the Sycamore as being a high-quality target,” Ward explained.

Because horizontal drilling is more expensive than the traditional vertical wells Ward has drilled for years, it obtained additional capital with a recently formed partnership with Trilantic North America. “We want to be a significant player in the Scoop-Stack, so we searched for ways to recapitalize Ward Energy Partners as our growth entity,” Ward said.

The latter holds a 71% interest in the Lynda well. For now, Ward said, he’s evaluating the timing on when to drill his next operated well, because the company owns plenty of working interests in nearby wells that are already being drilled by other operators. These will provide additional data that should further de-risk the acreage, Ward said, adding that companies throughout the Scoop-Stack are sharing information.

There’s a lot to do, because Ward sees a 450-foot thick reservoir in Grady County. The company has 15,000 net acres in the Scoop, 90% in Grady County and another 17,000 net in the Stack in southern Blaine and eastern Custer counties.

Next Challenges

This year, operators are focused on finding answers: How long can well laterals be before they see diminishing returns, how much proppant is optimum, and is shorter space between fracture stimulations more effective? Well density is also a big question, with the relationship between parent wells and their “children” the subject of numerous pilot programs in both the Stack and Scoop.

Ward Petroleum Co.'s Lynda well in Grady County is the biggest Sycamore test yet in the Scoop. CEO Bill Ward expects more E&Ps to drill the formation in 2018.

“I would say our biggest opportunity is to be an early successful implementer of full-field development in both the Stack and the Permian,” said Devon’s Hutchings. “How can we get to optimal well spacing, and what is the right amount of money to spend to optimize well performance, while reducing costs and cycle times?”

Devon prides itself on technical R&D and its partnership with the University of Oklahoma and the new GE oilfield research center, as well as with its vendors. It cites proprietary completion designs and the use of big data for part of the Privott’s success, Hutchings said. “We have made and we continue to make fairly substantial investments in technology.

"It's all in how the rock talks to you during stimulation," said Chaparral Energy Inc. CEO Earl Reynolds. He'll keep two rigs active to year-end.

“The Meramec has incrementally better economics than the Woodford, and we’re allocating more capital to it,” Hutchings said. “The next big resource for us to capture is the Meramec. It’s a little shallower but has higher pressure, so it’s just a higher-quality reservoir with better economics. Its IPs and recoveries are larger than the Woodford.”

A Stack Pure-Play

Chaparral Energy Inc. emerged from bankruptcy earlier this year with a clean balance sheet and went public shortly thereafter (symbol is CHPE) with a goal to transition to being a pure-play Stack operator.

With 110,000 net acres, its assets have the ability to deliver value even if oil prices stay below $50, said CEO Earl Reynolds. He said he intends to keep two rigs running this year on its mostly HBP acreage, in either Canadian, Kingfisher or Garfield counties.

Good results in the second quarter were the first steps in this process. Chaparral’s Stack production was about 9,000 boe/d, with a lease operating expense of less than $4/bbl. During the quarter it brought on four Meramec, one Woodford and two Osage wells. It also participated in 28 outside-operated wells in the Stack area.

The strategy is to remain focused on maintaining low costs as it develops its 3,000 gross-operated drilling locations in the Stack’s black oil window, where Reynolds says 1-mile laterals are the order of the day.

“We’re currently working on our 2018 plans but right now, we believe we’ll have three rigs running in 2018 as we put more capital to work in the play. I do feel we haven’t had the opportunity to develop our acreage at the pace we would have liked,” Reynolds said.

"The Scoop-Stack gets all the attention, but the Arkoma Stack is due for a revival," said Canyon Creek president and CEO Luke Essman.

“This coming year, we’ll accelerate our program a bit and focus on further delineating our acreage.”

Meanwhile, in Kingfisher County, if the company drills a Meramec well, it won’t immediately drill an offset well; rather, it will go back in and drill to the lower Osage, he said. In Garfield County, Chaparral drilled in 2013 and 2014 with relatively small fracks but now it is using larger fracks with 25 stages and sometimes, 30.

Its first Meramec well, the White Oak, tested more than 600 boe/d, but at press time, was still flowing back. This was despite a third-party gatherer’s pipeline constraints.

Frack size and design will be important for delivering strong rates of return, Reynolds said. “Our standard Meramec frack will use 2,500 pounds of sand per foot, whereas in the Osage, it will be 1,700 pounds. The Osage cannot take as much sand or you run the risk of it screening out.

“It’s all in how the rock talks to you while you stimulate it.”

In most of its locations, Chaparral has Meramec and Osage targets, as well as some Woodford targets that the company is in the early days of assessing—it has drilled three in the past year.

“The economics of the Meramec and Osage look pretty close—I can drill either one and feel really confident about the results we’ll see. The ultimate question is about spacing. Drilling is not the challenge—you have to be careful of various faults in Canadian County and structural complexity as you near the Nemaha Ridge … but in Kingfisher County, the top of the Meramec drills like butter.”

Reynolds said at $50/bbl, he expects Chaparral to realize a 67% rate of return from its Meramec program.

Northwest Stack

The northwest Stack is the focus of several companies trying to expand the limits of the Woodford and Meramec. One such is Corlena Oil Co. III, a private E&P backed by Kayne Anderson Capital Advisors LP and based in Amarillo, Texas. Corlena has been in and out of several plays through 30 years of operation in the Texas Panhandle, drilling the Granite Wash, Morrow and Cleveland sands, but today it is 100% targeted in Woodward County in the northwest Stack.

Corlena operates one rig on its 31,000 net acres and, at press time, was about to spud its fifth well, a 9,000-foot Meramec test, CEO Jeff Chesnut said. It will drill at least two more wells by year-end.

The company is drilling 1-mile laterals to start but is positioned for longer laterals eventually. Like its peers, it has leased most of its own acreage but also trades with other companies to accommodate longer laterals.

“We’re trying to unlock all the secrets now as to which bench is best to target first and how to drill and complete these laterals. We need to determine what kind of drilling mud system we need, lateral lengths, what kind of bits, frack design and so on. This area we’re in is slightly overpressured,” Chesnut said.

“Long story short, we’re trying to prove up the nice position we have; our senior team has put us in a good position to succeed in the northwest Stack. We’re pretty excited with what we’ve got going on,” he said.

“As a private equity-backed company, we’re trying to de-risk the asset and delineate the strategy for completions, then look for a larger operator to come in and do the heavy lifting for full development.”

The Mississippian zone is 1,000 to 1,200 feet thick, with Meramec alone up to 800 feet thick across Corlena’s acreage. Fully developed as economics allow, there could be three wells per bench in the Meramec and Osage, per section, with three to five benches, that could potentially total nine to 15 wells per section, he theorized.

This would equate to 700 short-lateral locations, but it’s very early days. Osage is more prevalent here than to the east, he said.

The Corlena Oil Co. team discusses next moves on its northwest Stack acreage. (From left: Ted Francis, CEO Jeff Chesnut, Johnny Weems and Rob Michelotti.)

One of Corlena’s notable tests so far is the Moss well in Woodward County, whose 30-day IP averaged 698 boe/d from Middle Meramec. Before thinking about deploying a second rig, Chesnut said he’d have to see product prices improve a bit more and have defined which benches are the best to target.

How does Chesnut compare 30 years of drilling experience with today’s Stack potential? “I’d say it’s phenomenal. Before the advent of horizontal drilling and large fracks, you couldn’t go out and put together a prospect with several hundred locations where you could drill so many benches and make such good wells.”

Leslie Haines can be reached at lhaines@hartenergy.com.

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