January 2019

New powerhouse sees plays “taking off” in 2019

As it prepares to set up shop in Oklahoma’s flagship shale plays, Encana Corp. is experiencing a measure of deja vu.
Jim Redden / Contributing Editor

As it prepares to set up shop in Oklahoma’s flagship shale plays, Encana Corp. is experiencing a measure of deja vu. It was just over four years ago that the company paid some $7.1 billion for Athlon Energy, giving it a stake in the behemothic Permian basin, which at the time was in the embryonic stage of its now-historic transition to unconventional development.

Fig. 1. December-to-January oil and gas production in the Anadarko basin is predicted to increase by 7,000 bpd and 95 MMcfd, respectively. Source: U.S. Energy Information Administration (EIA).
Fig. 1. December-to-January oil and gas production in the Anadarko basin is predicted to increase by 7,000 bpd and 95 MMcfd, respectively. Source: U.S. Energy Information Administration (EIA).

“When we entered the Midland [Permian] basin, it was at the very, very early days of moving to horizontal development. We think the STACK and the SCOOP are at exactly that same point in time today,” said President and CEO Doug Suttles.

The Canadian company closed in on becoming a major U.S. shale power player with the Nov. 1 disclosure that it was acquiring Newfield Exploration Co., first mover of the fast-growing STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) multi-zone play in the greater Anadarko basin. Newfield’s 400,000-net-acre asset also takes in the tightly concentrated SCOOP (South Central Oklahoma Oil Province), which premier leaseholder Continental Resources Inc. unveiled pre-STACK. Encana is expected to close by March on the strikingly nostalgic $7.7-billion deal that includes $5.5 billion in stock and $2.2 billion in debt assumption.

“In short, we’re taking two great companies and creating an even better one,” Newfield Chairman, CEO and President Lee Boothby said in an abbreviated third-quarter conference call.

While Encana’s general intention had been well known, the announcement, nonetheless, broadsided market watchers. “We knew management was on the hunt for another core North America oil play, but we weren’t expecting a STACK deal,” Citi Research analyst Robert Morris wrote in a Nov. 1 note, as quoted by Canada’s Financial Post.

Like in the Permian, Encana steps into a region with multiple pay zones, but one with a well-established infrastructure in close proximity to the Cushing, Okla., oil hub and a highly competitive service environment. “There’s a lot of [pressure pumping] horsepower in the basin. So it has pretty, pretty competitive prices relative to that,” said Chaparral Energy Inc. CEO Earl Reynolds, pointing to STACK lease operating expenses (LOE) below $4.50/bbl.


The U.S. Energy Information Administration (EIA) estimates oil and gas production in the Anadarko basin to average 599,000 bpd and 7,644 MMcfd, respectively, in January (Fig. 1), compared to the 487,000 bopd and 6,005 MMcfd delivered at the start of last year. Correspondingly, in the latest data available, the EIA shows the basin with a drilled-but-uncompleted (DUC) inventory of 1,135 wells as of November—trailing only the Texas Permian and Eagle Ford. The EIA added the Anadarko to its monthly Drilling Productivity reports of key unconventional plays in August 2017.

Fig. 2. An average 57 rigs were active in the Cana Woodford in December, including this one at work for Chaparral Energy. Image: Chaparral Energy Inc.
Fig. 2. An average 57 rigs were active in the Cana Woodford in December, including this one at work for Chaparral Energy. Image: Chaparral Energy Inc.

All unconventional activity is centered in the Anadarko’s Cana Woodford subset, where Baker Hughes, a GE company, reported an average 58 rigs active in December (Fig. 2), down sharply from the 72-rig average in December 2017. An average of just over 73 rigs were active in the Cana Woodford last June, topping out at a seven-year high of 76 active rigs over the first week of that month.

The overall year-over-year drop in the rig count, however, comes as combined 2018 drilling authorizations rose significantly to 2,375 approved permits from Jan. 1 to Dec. 10, compared to 1,647 approvals for the SCOOP/STACK fairway in 2017, according to the Oklahoma Corporation Commission (OCC). A dissection of data from the state’s chief regulator validates activity continuing to shift to the three-county STACK core, which had 1,409 approved permits this year, compared to 966 new-drill permits for the five-county SCOOP fairway.

SCOOP pioneer Continental, for one, ramped up to an 18-rig fleet at year-end, mostly dedicated to its recently initiated “Project SpringBoard,” an in-line development strategy, targeting the Springer and underlying Woodford and Sycamore shales. An additional five rigs were at work in the over-pressured oil and condensate windows of Continental’s STACK position, where third-quarter production of 56,129 boed was up 58% year-over-year. Continental holds a commanding SCOOP/STACK leasehold of more than 1.13 million net reservoir acres.

As of Oct. 30, Continental had 14 rigs dedicated to the SpringBoard initiative, eight of which targeted the well-hyped Springer, where 18 wells also have been drilled in the first row. Nine Woodford and Sycamore wells also have been drilled, as part of what Senior V.P. of Production & Resource Development Gary Gould described as “a massive oil project, where we are concurrently developing three reservoirs.”

Continental put nine gross SCOOP wells online in the third quarter, which helped lift quarterly production to 63,270 boed on average, up 10% from the same 2017 quarter. Elsewhere, the company singled out three STACK Meramec units, developed with the equivalent of six wells with 2-mi horizontal reaches, which notched a combined 24-hr initial production (IP) rate of 74,260 boed. Of those, wells in one unit delivered what Continental claims is an industry-record 24 IP rate of 4,234 boed for the over-pressured STACK oil window.


Suttles, for one, believes his company chose an opportune time to grab a foothold in the acronymic plays. “I think it is set to take off in 2019. Exactly what quarter, it’s a little early to say,” he said. “But I think we agree this thing is ready now to go into large-scale development mode and to get the efficiencies from that.”

Citing half-cycle wellhead break-even prices from the mid-to-high-$30/bbl range, the Encana chief says the Newfield assets are a competitive fit with the company’s portfolio. He particularly singled out the soon-to-be acquired STACK acreage in the southwest part of Kingfisher County. “We view this as the sweet spot of the play, as it combines some of the thickest, highest-quality reservoir with the high-value fluids in the oil window,” he said.

For its part, Newfield appears to have a head start on the integration phase with the adoption of Encana’s signature cube development strategy, with row drilling operations commencing in the third quarter across the STACK’s copious horizons. “The STACK/SCOOP lends itself to cube development,” said Suttles. “The reservoir is thick and laterally extensive. With reservoir thickness up to 650 ft in the core of the STACK, we see at least two-to-four target benches across the position. In the STACK, the Meramec is the primary target, with additional STACK potential in the underlying Cana-Woodford.”

“In the SCOOP, the Woodford shale is the primary target, with additional upside in the Springer. The reservoir is over-pressured, which enhances well productivity,” he added.

Newfield operated 11 rigs in the third quarter, with production of 143,700 boed, exceeding the mid-point of the quarterly target by more than 8,700 boed. Full-year production was increased to 130,000 boed to 135,000 boed.

Meanwhile, a handful of asset-holders have long been greasing the wheels for full-field development, with a number of spacing pilots and completion refinements, along with the recent emergence of wells with 2-mi lateral reaches. Much of the appraisal work of late has been undertaken in the STACK, a nom de plume reflecting its geographic and geological characteristics.


Count Alta Mesa Resources Inc. as among the most active of the pure play STACK operators. The Houston company boasts one of the play’s most aggressive drilling and completion campaigns, averaging eight rigs in 2018 (Fig. 3), with 145 wells drilled and 142 put on production as of Nov. 1.

Fig. 3. One of the rigs contributing to Alta Mesa Resources’ aggressive 145-well 2018 drilling program. Image: Alta Mesa Resources Inc.
Fig. 3. One of the rigs contributing to Alta Mesa Resources’ aggressive 145-well 2018 drilling program. Image: Alta Mesa Resources Inc.

On the heels of spacing tests that began in 2014, Alta Mesa—which controls 139,000 net acres—says current developments range from five to 12 wells/DSU (drilling spacing unit), but that could change this year. “In the current commodity price environment, we expect on the order of five to seven wells per DSU for most of our 2019 in-fill drilling,” said President and CEO Hal Chappelle. “In other words, we’re looking at something where we could have three wells per bench in some of the applications.”

The operator brought 53 wells online in the third quarter, which saw a quarter-over-quarter production jump of 30%, to around 33,400 boed. The 2018 exit rate guidance has been reaffirmed at 38,000 to 40,000 boed.

Devon Energy Corp., likewise, is focusing squarely on full-field development of its considerable STACK position, which enters 2019 as the second-highest funded asset in the company’s North American portfolio. “Better days are on the way very soon in the STACK,” said President and CEO Dave Hager.

The home-grown operator ran eight rigs and two frac spreads in the third quarter, and drilled 26 wells, with laterals averaging 9,800 ft. Devon expected to close out 2018 with production of 32,000 boed.

After an extended appraisal period, Hager said, “we are very confident we have determined the optimal well spacing in this four-to-eight wells per drilling spacing unit.” Devon’s more than 600,000-net-acre STACK position includes some 130,000 undeveloped net acres in the over-pressured oil window.

Chaparral Energy, fresh off its July listing on the New York Stock Exchange (NYSE), expected to wrap up 2018 with STACK production of between 16,250 boed to 17,250 boed in the fourth quarter. Third-quarter yield of 15,663 boed represented a 53% year-over-year increase.

Chaparral kicked off the year with four rigs drilling in a combined 127,000-net-acre STACK-Merge leasehold. The self-explanatory Merge intersects the delineated boundaries of the SCOOP and STACK, and features certain characteristics of both plays.

As part of a year-old joint venture with Bayou City Energy, the company was operating three rigs in the third quarter, with 20 joint wells hooked up to production. Chapparal expects to conclude its 30-well joint venture program early this year.

Much of 2018’s joint venture budget was directed to the 20,000 net acres comprising the Merge position, where the partners drilled 17 wells, while evaluating effective section spacing designs “for two distinct drillable targets.” This year, however, Chapparal will concentrate entirely on STACK targets, where it, likewise, will test various pad sizes and spacing. 

Elsewhere, Cimarex Energy Co. was operating four drilling rigs and one completion crew at year-end in its Mid-Continent region, where activity centers largely on a 252,125-net-acre Meramec/Woodford position in western Oklahoma. The acreage includes roughly 24,000 gross acres in the 14N-10W area in the Cana core, where a stacked development campaign is underway. 

As of November, Cimarex had completed 80 gross (20 net) wells, including three multi-well Woodford spacing pilots in the emerging Lone Rock asset in Grady and Canadian counties, with six, eight and four wells/pad. 

With the help of local sand pricing and a “refined completion design,” Cimarex said the total costs for Woodford wells drilled with 5,280-ft laterals in the East Lone Rock area were running $7.3-$7.8 million/well in the third quarter, down $200,000/well from the prior quarter. The total costs of Meramec wells completed with 10,560-ft (2-mi) laterals dropped by $1 million/well, quarter-over-quarter, to a range of $10.5-to-$12 million/well, said COO Joseph Albi.

Meanwhile, less than a year after proclaiming the moderately over-pressured Woodford shale asset its latest premium oil play, EOG Resources Inc. closed out 2018, averaging two rigs and one completion spread with around 25 net completions. As with many of its peers, EOG spent much of the past year testing spacing patterns and various targets across a 50,000-net-acre Eastern Anadarko leasehold. 

“We are in the initial innings of our Woodford oil window play in the Anadarko basin and are experimenting with completion designs, testing various targets, confirming well spacing and lowering cost,” said David Trice, executive V.P. of E&P. wo-box_blue.gif

About the Authors
Jim Redden
Contributing Editor
Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.
Related Articles
Connect with World Oil
Connect with World Oil, the upstream industry's most trusted source of forecast data, industry trends, and insights into operational and technological advances.