The energy business may be focused on the Permian Basin, but it should keep an eye on the Midcontinent. That was the message at Hart Energy’s 2017 DUG Midcontinent Conference and Exhibition in Oklahoma City.

It has many similarities to its big brother out in West Texas and New Mexico. Both are historic plays with great midstream infrastructure in place that have come back to life as producers tap multiple unconventional pay zones. Put all of the Midcontinent’s attributes together and its Scoop, Stack and other plays should stay busy for many years, conference presenters agreed.


George Solich, president and CEO of Denver-based FourPoint Energy LLC, told attendees in his opening keynote that his firm is focused on the Western Anadarko Basin—which he said enjoys “a world-class position in a world-class basin.”

Solich noted his organization is hardly a new player in the Western Anadarko and is building on nearly 20 years’ of expertise. “FourPoint is the fourth company of a proven franchise rooted in the Western Anadarko Basin,” he said.

The private firm and its predecessors, Cordillera Energy Partners I, II and III, were active in the basin since 2000. But these previous incarnations “were very adept at buying high and selling low,” Solich added with a chuckle. The basin offers unsurpassed opportunities for value creation and FourPoint was created in 2013—and returned.

“Each time we build a company we come back to the Western Anadarko Basin,” he said. Quoting country singer Alan Jackson, Solich said, “Oklahoma has always been good to me.”

Since its start, FourPoint has gone on to establish a significant position, with interests in about 2.2 million gross (800,000 net) acres. That acreage spreads across 13 Oklahoma counties and crosses into the northeast corner of the Texas Panhandle.

Solich said the company has 18,000 gross locations with exposure to an undeveloped resource of 17 trillion cubic feet equivalent. Current production stands at 400 million cubic feet equivalent per day with an internal rate of return range of 20% to 100%.

“That is one of the largest land positions in the Lower 48,” Solich noted.

Using technology

Technology gives FourPoint an opportunity for great growth, he said, noting the firm’s database “is a significant advantage. The industry’s long legacy has created extensive information on the basin’s geology. He said FourPoint has access to 20,000 well logs and more than 1,500 square miles of 3-D seismic, as well as a proprietary production database from 7,300 wells.

It knows the Western Anadarko so well that “when we go out and lease, we’re actually buying reserves.”

The Western Anadarko enjoys five characteristics that make any producing basin top notch, attributes that have always created “haves and have-nots,” he said. Solich ticked off stacked-pay potential, areal extent, a positive regulatory environment, an established infrastructure and an attractive commodity mix.

He compared the Western Anadarko to the Bakken, Denver-Julesburg, Permian and Scoop/Stack in his presentation and noted the Western Anadarko “checks nearly all of boxes for key drivers.”

But the region’s prospects have been held back by regulatory hurdles in Oklahoma, fragmented operatorship that inhibits creation of multi-unit laterals in both Texas and Oklahoma, and drilling challenges and consistency, he said. One particular challenge has been the application of advanced technology.

“The Western Anadarko has seen a cyclical reinvention over time with a new application of technology,” Solich said, with improvements occurring in completion technology tweaked according to the geologic target. “Completions should be custom-tailored to the formation and well that is being drilled. To complete wells smarter, you must understand your rocks thoroughly,” he explained.

Given all of the Western Anadarko’s positives, FourPoint “is here for a reason,” he concluded.

Midstream’s challenges

With Oklahoma’s big Cushing pipeline terminal in place between Tulsa and Oklahoma City, the Midcontinent doesn’t have many oil and gas infrastructure shortcomings. But that doesn’t mean there aren’t some serious challenges to solve.

With repurposing and new shale plays emerging, there is a need to think about how the industry is going to move added production, Mike Burdett, senior vice president, commercial, at EnLink Midstream LLC, told the conference. Burdett addressed the current buildout of natural gas, crude oil and NGL infrastructure, and future needs, to the crowd of more than 1,100 attendees.

“This is truly an exciting time to be active in the Midcontinent,” Burdett said. “It’s clear there’s no shortage of opportunity on the upstream side or the midstream side.”

Burdett pointed to the “operational momentum” being realized by producers in the region, many already with focused growth plans in place. “All of this tremendous success on the upstream side presents a number of challenges from a midstream perspective, but these are exactly the kind of challenges that we really enjoy,” he added.

The great success that producers have had with long laterals has resulted in extremely high flow rates. When combined with large pads, the flow rates present challenges specifically from the standpoint of timing, Burdett said.

“These pads have 20 to 30 wells at a time. One or two of those coming online in proximity to each other can cause challenges to having those processing plants ready and available,” he added. “Producers want all of their gas to flow all of the time, so in order for us to provide the service they expect and deserve it requires a great deal of planning and coordination to ensure we have gathering lines and processing facilities installed and online on a timely basis.”

As a result of all of the drilling activity in the Midcontinent, Burdett said, the industry needs to be focused on four areas on the midstream side:

  • Gas gathering and processing expansions;
  • Crude gathering and takeaway expansions;
  • NGL takeaway expansions; and
  • Residue takeaway expansions.

Burdett said EnLink has taken steps to shore up its connections for getting NGL, crude oil and residue gas to demand markets. In the case of NGL, he said EnLink evaluated several options for getting NGL out of its Chisolm operation to the Gulf Coast.

Going to the Gulf

“Instead of building new, we entered into a long-term NGL transport contract with ONEOK to provide additional physical connectivity to [the Gulf Coast] Cajun-Sibon [system],” he said. “Clearly, this solution was immediate and required no additional capital spending. So while we like to build pipelines and do large projects, we were very excited to enter into this arrangement in order to get our NGLs from the Stack.”

Burdett said the deal leaves EnLink with the optionality for future NGL infrastructure once Cajun-Sibon is full.

“On the crude side, I think there is less of an immediate need for new large takeaway infrastructure. There is, however, a need for more efficient means to gather crude.”

EnLink recently announced it is expanding into crude gathering with its Black Coyote crude terminal and pipeline. Burdett said the system’s initial buildout is focused on the core of the Stack play, and that it provides reliable and efficient transportation for customers with full-scale development production volumes. The system utilizes partners for takeaways.

Meanwhile, Burdett said Oklahoma residue is expected to increase from about 6.7 billion cubic feet per day (Bcf/d) to more than 8 Bcf/d within the next few years.

Over the last few years several projects have been discussed to handle that takeaway, Burdett said. Cheniere’s Midship Pipeline, which has a targeted startup for early 2019, will connect to EnLink’s Chisholm and Cana systems, he added.

“We are deeply committed to continuing to grow in the Stack,” Burdett said. “We’ve diversified our service offerings, and about 60% of our total capex for 2017 will be spent in Oklahoma. We see more capital being directed toward Oklahoma over the next few years.”

‘Something spectacular’

No one should expect to get something for nothing, but that doesn’t mean you can’t make something from nothing. After all, Rumpelstiltskin spun gold riches from straw, right?

Producers in the Anadarko Basin aren’t able to magically spin out gold coins, of course, but many have found a way to turn the Stack into one of the top shale plays in the world, particularly during this shale renaissance. Newfield Exploration Co., founder of the Stack play, has led the charge in moving from concept in the region to full-field development.

Trevor Reuben, vice president of corporate development at Newfield, told the audience that the last decade has seen his company truly transform from a diverse offshore entity to a U.S. onshore resource player focused on the Anadarko. Today, two-thirds of its production and reserves and 80% of its capital are focused in the basin.

“In the Meramec and Woodford alone we see 2.5 billion barrels of oil equivalent gross unrisked resource, which will provide us with decades of economic drilling locations for the future,” he said during the second-day opening keynote at the conference. “[The Anadarko] really has gone from nothing to something spectacular.”

Reuben said Newfield is “upward of 90,000 barrels of equivalent production and 330 million barrels for reserves.” In 2016, Newfield was the top oil producer in Oklahoma, he said.

For the audience at DUG Midcontinent, it was a rare glimpse into how Newfield came to discover the Stack. The company actually started in the Arkoma to the east, which was where it made its first onshore U.S. resource play. From there, it moved to drilling the Blevins 3H-9, a horizontal Woodford gas discovery.

“Soon we were on to focusing on the liquids window in the Arkoma,” he said.

However, the company ended up making its first horizontal oil discovery in the Woodford in 2009. But it wasn’t until 2012 when, using geological mapping and an engineering study, Newfield struck oil in the first Woodford/Stack horizontal oil well, the Rock Island 1H-14.

Less than a year later, Newfield drilled the first Stack/Meramec horizontal oil well, State 1H-16.

“Today, we’ve grown our position from 100,000 net acres to over 350,000,” Reuben said. “We’re really excited about the Anadarko because we consider it absolutely world-class. It’s one of the largest and deepest onshore U.S. basins, with significant total organic content, low clay content, excellent seals and, as everyone knows, there have been literally thousands of wells drilled into it, all validating the potential,” he continued.

Multiple horizons

Like others speakers at DUG Midcontinent, Reuben pointed out that the industry has only begun to the scratch the surface in the Anadarko. He said there are more than 10 productive horizons in the basin.

Reuben also said the economics of the play “really are top-tier.” Even at around $50 per barrel, the Stack and Scoop are competitive, he said. “They are going to be a focus of industry attention for a long time to come.”

He cited low lease operating expenses and finding and development costs “because of the prolific nature of these wells relative to the capital cost required for investment.” In addition, water/oil ratios remain 1:1, which is significantly less than other basins that are getting attention at the moment.

“The superior economics of these plays just speaks to the fact that we’ve seen a tremendous amount of activity sustained through the cycle,” he said.

Rubik’s Cube

Reuben said Newfield is focusing a new comprehensive pilot program on the Meramec. “This doesn’t even scratch the surface of what I think the next exciting opportunities are, which are actually going back in the Woodford and doing higher density tests, as well as in the Osage and down in the Scoop,” he said.

“What we’re trying to do is unlock the Rubik’s Cube and understand vertical and horizontal spacing as well as what the optimal completion design is,” he continued. “We’re using all kinds of science to maximize value out of a section so that we don’t find ourselves in five or 10 years having missed a tremendous amount of resource.”

Reuben closed out his address by discussing Newfield’s Score program, which stands for the Sycamore, Caney, Osage Resource Expansion. “We are out there hunting right now for the next Stack,” he said. “There’s tremendous opportunity right under our old footprint.”

The company plans to spend about $100 million this year to test the potential. “We think we’re assessing over 1 billion barrels equivalent of resource potential,” he said.

Arkoma’s promise

The Score is not the only Midcontinent play that has just started to perk up. Drive 100-plus miles southeast of the bustling Stack play and Oklahoma’s landscape changes dramatically. Gone are the flat Great Plains, replaced by rolling, wooded countryside where the “oak and blackjack trees kiss the playful prairie breeze,” as made famous by Woody Guthrie’s folk ballad, “Oklahoma Hills.”

But the oil and gas are still there, waiting belowground.

The Arkoma Basin in the eastern part of the state may not have received the recent publicity that the Stack and Scoop enjoy, but that is changing due to excellent prospects, according to Nathaniel Harding, founder and president of Antioch Energy LLC.

“The play is first-class. It is equivalent to the Stack and Scoop,” Harding said in his presentation.

He added that his private firm’s Hughes County, Okla., acreage is “shallow, low decline, liquids-rich with several targets” and requires less capex to exploit than the sprawling Stack in the Anadarko Basin.

He referred to the “Arkoma Stack” in his presentation to emphasize the similarities between the two regions. Both offer multiplay/multipay opportunities, he said. The Arkoma Stack has up to five unique, high-quality reservoirs, including two Woodford benches and one Caney bench that are proved economic, with the Mayes in early economic appraisal.

“Additional potential exists in other shallow intervals,” Harding said.

The Woodford and Caney are both prolific resource-rock plays with production driven by matrix porosity. The area offers producers excellent commodity optionality.

“There is ample takeaway and processing capacity and that means low differentials,” Harding said.

The play enjoys good midstream infrastructure since the region has been producing since the first days of Oklahoma’s early 20th century oil boom. Harding noted the Arkoma has produced more than 1 billion barrels of oil equivalent since its discovery more than 100 years ago.

The industry has begun to take notice, Harding said. To date in 2017, Hughes County has been the state’s most actively leased county with multiple, private-equity-backed entrants. More than 100 wells have been proposed, spaced, pooled, permitted, drilled and completed and are flowing back, he said. That represents a roughly $4 billion investment by the upstream and midstream sectors.

Midstream support

On the midstream side, Tall Oak Midstream announced in September plans to enter the Arkoma—which it calls the “East Stack”—citing “multiple stacked-pay zones,” Harding noted. The system will serve Hughes County and portions of nearby Seminole, Pontotoc, Coal, Pittsburg, Atoka and McIntosh counties with 50 miles of pipeline, a 5,000 barrels per day (Mbbl/d) stabilizer and condensate storage.

Oklahoma City-based Antioch positioned itself well in the Arkoma before the industry’s attention swung to the area. Harding described Antioch’s current Hughes County holdings as some 23,000 net acres, of which 65% is operated. Some 40% is HBP, which will rise to 65% by first-quarter 2018. The firm currently has one rig running on its Arkoma acreage.

“We are located in the sweet spot as we define it. Our acquisition effort has targeted the best-quality reservoirs. Recent Arkoma wells with improved completions outperform Stack wells,” he said.

Antioch has enjoyed strong returns at current costs and sales prices because the region offers “excellent deliverability and predictable results.” Wells are up to 50% liquids with great differentials. “Costs are going even lower as operators accelerate learning,” Harding said.

Water forum

Some Midcontinent plays produce more water than oil—creating a substantial challenge for producers and their midstream providers that already must deal with frack water demands. The conference featured an opening day water forum focused on water management.

Producers face dilemmas and there are no set, one-size-fits all answers, a panel of water-handling experts agreed. Rather, treatment must be adjusted to match the chemicals and pH balance of water on a continuous basis, they emphasized.

“Do you want your water treated? To what spec? Do you know?” asked Mark Patton, vice president of Hydrozonix, in one discussion of treatment options. “A typical treatment may not match. There are a wide variety of changes.”

Jenifer Lascano, technical sales adviser for well chemical services at Baker Hughes, said water treatment “decisions must be made on the fly” in many situations, as water specifications vary. For producers, the good news is that, often, such tweaks can save producers as much as 50% in disposal or treatment costs, Patton noted.

“There is no silver bullet” to treat the variety of water treatment services, said Naggs Nagghappan, vice president of business development for Veolia North America’s oil and gas upstream market.

The quality of produced water can vary enormously between Midcontinent plays, he explained. He discussed a recent engineering study that found a wide variety of water quality in the region, given the region’s multiple pay zones with varying geologies and their differing chemistries.

Also, water quality can change during treatment of frack water flowed back from a single well, he said, when differing water sources were used. That’s in addition to treatment decisions based on whether the frack employed slickwater, gels or other chemicals. Patton agreed, noting water treatment can change based on “a stage-by-stage analysis. Sometimes we see a complete change in water quality” from start to finish in a single well’s frack treatment.

Another variable can come from pit water stratification, Patton said, and that problem has grown as pits have become larger to handle larger, multistage frack jobs.

“The technology varies” in treating all that water, Nagghappan added. He said produced water from northern Oklahoma wells typically creates the biggest treatment challenges.

Water variables

The panelists ticked off multiple variables they face—chemicals, acid/alkaline balance, bacteria and algae, to name a few. Patton recalled one unusual case where recycled municipal water to be used for a Canadian well’s frack job tested positive for hepatitis virus. The virus is “a complete non-starter” that “can be deactivated with ozone,” he said. The panelists noted simple aeration can be an important first step in water treatment in many situations.

Lascano said bacteria growth has become a problem as producers have increased the use of pond and stream water. Patton urged producers to “pay more attention to what goes in” when they do frack jobs, saying monitoring water quality beforehand can cut treatment costs.

Water treatment challenges will only grow, he added, as the industry pushes fracking technology and produces more oil and gas from water-bearing shales. “This industry will be more and more water-focused in coming years,” he predicted.