The latest results from Continental Resources Inc.’s SpringBoard project in Oklahoma’s Scoop play show the stacked development is on track to boost the company’s oil production by about 10% from third-quarter 2018 to this year’s third quarter. And that’s just from this singular project.

But this isn’t a typical pad development project. With SpringBoard, Continental is testing the boundaries of achieving maximum returns from full-field development across multiple pay zones.

“There are a lot of names for full-field development,” said Continental vice president of exploration Tony Barrett, speaking at Hart Energy’s DUG Midcontinent conference in November. “There’s the cube, there’s sequence development. But we’re basically talking about the same thing: What is the best way to capture all of the resource most efficiently and most economically in a drilling and spacing unit?

“In the Anadarko Basin, we’re lucky in that we have multiple stacked pays, and this type of development, we believe, is going to be the future of the industry going forward.”

Continental advertises that some 711,000 net “reservoir” acres across the Scoop—broken out by prospectivity per formation—have the potential for co-development.

Pushing off the Springer

The SpringBoard project, specifically, focuses on co-development of the Springer, Sycamore and Woodford reservoirs and spans 73 square miles and 33,000 net acres of contiguous leasehold in Grady County. It has an unrisked resource potential of up to 400 million barrels of oil equivalent (MMboe).

The Oklahoma-headquartered company is currently running 12 rigs as of January—down two thanks to improved efficiency—as part of the project. Seven of the rigs are in the less thick Springer reservoir with the rest in the thicker Woodford and Sycamore reservoirs. Springer has a maximum thickness of 90 feet but trends as thin as 15 feet at the edges of the project, while Sycamore and Woodford each have a maximum thickness of 200 feet, the company said.

“In general, we expect wells located in the thicker portions of the reservoir to outperform our type curve and wells located in thinner portions of the reservoir to underperform the type curve,” Continental president Jack Stark said during an investor update on Jan. 29.

“Our updated 1.3 million boe type curve represents the average performance expected from a 9,800-foot Springer well in SpringBoard, assuming average reservoir thickness and bottomhole pressure,” Stark added. “Regardless of thickness, however, these are prolific flowing oil wells.”

Row development is the name of the game in SpringBoard. The project is divided into five rows, with differing formation thickness, depths and pressures in each one—and thus various expected results. Row 1, where Continental focused its efforts in 2018, is the most updip, and thus less pressured.

Most of the Springer wells drilled last year were in Row 1. The 18 wells drilled here had a combined IP of 23,255 barrels of oil equivalent per day (boe/d), or 1,292 boe/d per well, Continental reported.

The 2018 Springer drilling program also included four wells in what the company called “Triple H,” which partly lies in Row 2 and Row 3, where the reservoir is thicker. The combined IP for Triple H was 6,065 boe/d, or 1,516 boe/d per well—perhaps signaling growth ahead as the company prepares to tap into more of the thicker reservoirs.

Over 80% of the production was oil, Gary Gould, senior vice president of production and resource development for Continental, said on the investor call.

“Comparing these initial rates of the Triple H to Row 1 provides a great example of the influence of reservoir thickness on production. The Triple H unit was developed in a thicker reservoir area, which is why it resulted in a higher average IP per well,” Gould said. “It is important to note that our 2019 development activities are focused on rows 2 and 3 immediately west of the Triple H and will benefit from both thicker reservoir and increasing pressures.”

The results, so far, are in line with expectations, company executives said. Economics also have improved. As the lateral length rose by 30%, from 7,500 to 9,800 feet, the company reduced the cost per lateral foot by 20% and increased EUR per well by 8% to 1.3 MMboe. The declines were driven by lower drilling costs and cycle times along with an increase in frack stages completed per day.

“Combining this with the 5% increase in capex, our finding cost is improved by 3% [$9.62 per boe],” Gould added.

Streamlining logistics

Barrett offered one example of cost cutting at his DUG Midcon speech. “We eliminated intermediate casing, which was normally run in that area, which saved us a million dollars per well,” he said. “Think of that—over the course of drilling hundreds of wells, we estimate 300 to 400 wells in SpringBoard, that’s $300- to $400 million. We’re talking real money.”

Improved logistics also have reduced costs. “Hats off to our teams,” he said. “The volume of materials and men and hardware that are moved every day with 14 drilling rigs and two to three completion crews is astronomical. We calculate that at any hour during the day, we have 400 to 450 people actively working in this very concentrated effort, so it requires a lot of logistical planning to make this work.”

As part of the project, Continental streamlines material management with a centralized stockpile of equipment and supplies. “It allows us to sequence our completions and to maximize recovery,” Barrett said.

“By having everything together and drilled in sequence, it allows us to tailor our completions across the entire field to maximize unit value. It’s economy of scale: if you’ve got 14 rigs [at that time] and tons of sand and everything being delivered all day, you get a break on your costs. That affects the bottom line.”

Additionally, 100% of SpringBoard’s oil, gas and water is on pipe, effectively removing 230,000 trucks from the roads, he said. All water is recycled.

In its January investor call, Continental acknowledged a lower EUR per 1,000 feet of lateral than previously guided, but pointed out that this reflected maximizing NPV per section on a fully developed basis. Gould explained that the new type curve’s lower IP of 1,430 boe/d was due to increased early completion load water recovery associated with unit development.

“Overall, the refined type curve well economics generates 60% to 90% rates of return based on $50 to $60 WTI oil prices, which today reflects one of the strongest rate of return oil plays in the entire United States,” Gould said. “We continue to be on schedule to increase Continental’s net oil production by 10% or more from third-quarter 2018 to third-quarter 2019 just from Project SpringBoard alone.”

Springer oil volumes are expected to hit 16.9 million barrels per day (MMbbl/d) by third-quarter 2019.

“This is a massive scale project,” Barrett said. “It’s a very large resource potential for oil, in that we’re dealing with 70% to 80% oil in this project, and it’s part of our plan as a company as we move forward to continue to push our oil growth.”

Winning in the Woodford

In 2016, pure-play, dry-gas Utica Shale operator Gulfport Energy Corp. strategically decided to secure acreage that had the potential for a more liquid production. Oklahoma’s wet-gas Scoop play seemed a natural fit. Two years after entering the play, the Scoop appears to have been a profitable decision for Gulfport Energy: The returns on Woodford Shale wells are competitive with Gulfport’s Utica asset and, in some cases, are outperforming the best Utica dry-gas wells.

“Every dollar that we have, we are going to re-invest that in the asset that has the highest rate of return,” Joshua Lawson, vice president of operations at Gulfport Energy, said during the DUG Midcontinent conference. “So there is this effort to continue to try to transition more and more of our activity into the Scoop and try to focus on the more liquids portion of the asset.”

Oklahoma City-based Gulfport has 15,000 net acres in the Utica, but more than 92,000 net acres in its Scoop asset. As of the end of third-quarter 2018, Gulfport was producing more than 1.4 billion cubic feet per day companywide, including 275 million cubic feet per day (MMcf/d)—or 20%—from the Scoop. These Scoop wells produce from 10% to 30% oil, and 30% to 60% liquids when adding in NGL.

“That’s what’s really driving that return on investment.”

Gulfport’s Oklahoma drilling program targets wet-gas Woodford Shale in central Grady County, where it’s completed 27 wells since entering the play. Here, the Woodford is about 200 feet thick at vertical depths ranging from 13,000 to 16,000 feet. When the company began operations in first-quarter 2017, just 54% of the laterals were being placed in zone. In 2018, 98% attributed to the use of 3-D seismic to place laterals better.

“When you’re at a 98% success rate, landing and staying within that target zone, it really does help with your efficiencies,” Lawson said.

With the geosteering solved, Gulfport wasted no time upping the ante. It extended laterals from 5,000 feet to 7,500 and nearly 10,000 feet, with total measured depth extending past 25,000 feet. “We’re trying to push the technical limits,” he said.

Completions were no exception. Stimulations of acquired wells and offset wells at sub 1,000 pounds of proppant per foot were “a little lackluster,” he noted, so Gulfport ratcheted proppant intensity to 2,000 to 2,500 pounds per foot, taking learnings from its Utica program. “We saw an immediate opportunity to raise the bar. When you’re talking about 250 feet of reservoir in multiple benches, we just saw that as a real opportunity to get more aggressive with our frack designs.”

Gulfport deploys RS Energy’s Prism platform, a data analytics model, to monitor parameters for drilling, completions and well results. It also develops its own 3-D earth model to extrapolate fracture stimulations and production from multiple zones.

At the end of the third quarter, net production in the Scoop had increased 41% year-over-year.

Upside abounds in emerging Scoop zones. Sitting on top of the Woodford is the Sycamore Formation, a 250-foot-thick section in which Gulfport holds about 40,000 net prospective acres. It has drilled two wells into it to date, one into the lower section with a 5,980 lateral and 15.7 million cubic feet equivalent per day (MMcfe/d) 24-hour rate, and another in the upper with a 9,600-foot lateral and a 7.8 MMcfe/d rate, 63% liquids.

“We’re very encouraged by that. We’re really excited about the Sycamore,” Lawson said.

Gulfport began full-section development of Woodford wells in 2018 to capture cost efficiencies, and in 2019 plans to co-develop upper and lower Sycamore wells simultaneously with the Woodford. But there’s one thing critical with that game plan, he said.

“You have to be able to execute from a drilling perspective. Everyone knows that these wells are a challenge; they are deep and geologically they are a challenge. If you can’t execute from a drilling perspective, then you’re just spinning your wheels. You have a lot of capital invested in one unit and are waiting on a return to come back.”

Also prospective on Gulfport’s acreage is the Caney Formation, which overlies the Sycamore and the Springer above that. The company drilled one Springer well in 2018—returning 79% oil and 11% NGL. But the Springer is for another day, Lawson said. “That is part of our development plans down the road—we’re using our non-op dollars to explore and understand the extent of the Springer.”

In January, Gulfport guided that it would run an average 1.5 rigs in the Scoop in 2019 and drill nine to 10 gross operated wells there during the year. It estimates it holds some 1,950 Scoop locations.

“I wouldn’t say we have all of the answers,” Lawson said. “We’re still exploring, still trying to figure out how to make this whole project work. We are still trying to understand what it’s going to take to gain the best returns on every dollar invested.

“One thing I can say is we are very confident in our ability to have repeated success both in the Woodford and the Sycamore. The results will bear that out.”

Sycamore surprise

Gulfport and Continental aren’t the only companies pleased with their Scoop returns. Greg Casillas, head geologist and president of privately held Casillas Petroleum, has been pleased with returns since the Tulsa-based company turned its attention to the Scoop two years ago.

Casillas controls 53,000 net acres prospective for the Woodford and Sycamore in a contiguous position straddling the intersection of Grady, McClain and Garvin counties. It is currently running three rigs and two frack spreads, and has drilled more than 40 wells in the past two years. Of these, it has completed 26 Woodford wells, accounting for 12% of all wells put on production in the Scoop core, and 14 Sycamore wells, representing 56% of total Sycamore completions.

“We are the leader in Sycamore completions,” Casillas said.

Casillas, with backing from Kayne Anderson Energy Funds, started its Scoop venture in 2015, evaluating the Woodford and Sycamore reservoirs and then purchasing 12,500 acres from Chesapeake Energy Corp. and 30,000 from Continental Resources Inc. The premise: to expand the deeper portion of the Scoop play eastward and updip into a more shallow environment, yielding a higher oil component.

“We have proven this theory to be correct,” said Casillas, “as we have drilled highly economic wells over the last two years with proven repeatability.”

Casillas’ slide presentation indicated the company executed a PSA with a nondisclosed seller in October to acquire an additional 28,000 Sycamore acres.

The company has executed lateral placement within two separate benches in both the Woodford and Sycamore.

The Woodford ranges from 100 to 350 feet thick on Casillas acreage, averaging 250 feet thick, at a vertical depth of 13,500 to 8,500 feet trending east. To date, the company has drilled 15 wells into the upper Woodford target and 11 wells into the middle Woodford target, with vertical separation of 100 to 150 feet. IP30s average 1,036 boe/d with 34% oil, 63% total liquids. Woodford EURs are 2.9 MMboe; rate of returns on the strip in early November were 59% for a $10 million cost for deeper wells; 72% at $9 million for more shallow wells. The breakeven price is $32/bbl.

The Sycamore is proving more interesting to Casillas. Here, thickness is similar to the Woodford, which it overlies, and the company is also targeting two benches. It has drilled six wells into the upper zone and eight wells into the lower with an average IP30 of 1,240 boe/d. Maybe more interestingly, the oil mix is 58%.

“We’ve revealed in our exploration efforts that the Sycamore is actually producing higher oil yields than is the Woodford, so we’re extremely excited about that particular component,” he said.

Based on a 23-well set, Sycamore EURs are 2.85 MMboe, with a 74% ROR at a $10 million well cost and 93% at $9 million. Breakeven is as low as $29 per bbl.

The difference in well costs reveals an evolution of completion design. After testing proppant concentrations as high as 3,000 pounds per foot, Casillas “decreased our proppant concentration substantially while maintaining fluid volumes at 3,000 pounds per foot,” he said, lowering completion costs by $1 million per 10,000 foot of lateral.

Additionally, it tightened cluster spacing from 28 to 18 feet while increasing the cluster count to five per stage. “In making these modifications, we’ve actually exceeded the previous EURs from the larger proppant concentrations,” Casillas noted.

The company planned to initiate its first Woodford-Sycamore co-development program in late 2018, testing 12 wells into the Woodford and eight in the Sycamore. It operates 65 total units, with a total of 877 operated locations and 1,299 nonoperated.

At the time of its presentation, Casillas’ production totaled 17,000 boe/d (65% liquids), but the company expected to exit 2018 at 20,500 boe/d, with a target exceeding 40,000 boe/d by year-end 2021. The company anticipates being cash-flow positive by year-end.

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