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Oklahoma’s SCOOP and STACK mini-trends could best be described as a condensed version of the Permian basin. The similarities are striking: a smorgasbord of stacked pay zones with record flowrates, shrinking cost curves, high returns and a well-grounded infrastructure, which have elevated the acronymic duo to among the nation’s most active plays.
Devon Energy, for one, puts its aptly named STACK holdings on a near-even keel with its Permian and Delaware assets. “We will continue to aggressively ramp up our drilling programs within the U.S., with the majority of this capital directed toward the STACK and Delaware basin,” says Dave Hager, president and CEO. “This low-risk drilling activity is expected to drive production growth of greater than 30% from our STACK and Delaware basin assets in 2018.”
The tightly concentrated SCOOP (South Central Oklahoma Oil Province) and north-central Oklahoma STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) are controlled by a handful of players, led by respective first-movers Continental Resources and Newfield Exploration. Collectively, five operators hold a commanding leasehold of more than 2.14 million acres, prospective for multiple oil and gas pay zones within the Cana-Woodford subset of the greater Anadarko basin.
Activity in the Cana-Woodford basin rose to 37 (a single-rig increase) during the final week of 2016 for a December average of 36 active rigs, according to Baker Hughes, which does not distinguish between the SCOOP and STACK plays. Those numbers are expected to increase this year. Like Devon, operators are nearly universal in plans to enlarge their rig fleets. “We are planning to add additional rigs to our Anadarko basin drilling program as we enter 2017,” Newfield CEO Lee K. Boothby said in November. “Even at today’s prices, we are seeing excellent returns in SCOOP and STACK, and any uplift in oil prices from here simply brightens our view.”
According to the latest data available, the U.S. Energy Information Administration (EIA) on Nov. 30 pegged Oklahoma’s total oil production for the first nine months of 2016 at 415,000 bpd, up modestly from the 414,000-bpd average in September 2015. Gas, likewise, was up slightly to 6,837 MMcfgd, from 6,810 MMcfgd delivered in the same 2015 period. Owing to Oklahoma’s notorious reporting delays, more up-to-date production numbers are unavailable, nor does the EIA or Oklahoma Corporation Commission (OCC), the state’s chief regulator, break out production between conventional and unconventional sources. Most operators, however, individually have reported significantly higher year-over-year production from their SCOOP/STACK holdings.
Like the Permian, the nearly across the board production increases flow from myriad targets, including, among others, the Woodford shale—the source rock for nearly all of Oklahoma’s production— as well as the upper Springer and STACK-centric Meramec shales. However, the Permian’s multiple pay zones have one characteristic missing from the SCOOP/STACK: excessive volumes of produced water.
“An underappreciated aspect of STACK and SCOOP is that these petroleum systems produce very little formation water,” says Continental President and COO Jack Stark. “In fact, we recover only a portion of the fluid used to stimulate Meramec wells in STACK. In contrast, Permian basin wells typically produce between 60% and 80% formation water. Not having to handle volumes of water in STACK and SCOOP significantly reduces our operating costs, of course.”
As recent drilling permit authorizations suggest, most activity is trending toward the STACK, where operators point to no less than five production zones, which can be tapped at comparably shallower, and cheaper, depths. Over the past year, companies continue to delineate the play with activity that, of late, is shifting increasingly to the over-pressured oil window of the thick (275-475 ft) Meramec shale, where Continental on Dec. 14 released details of a new well with a company-record 4,642- boe flowrate in a 24-hr test, at a completed cost of $8.9 million.
As of Dec. 5, the OCC had authorized 659 new drilling permits for the three core STACK counties (Blaine, Canadian and Kingfisher), compared to 560 permit approvals between Jan. 1-Dec. 5, 2015. By contrast, the OCC in 2016 approved 342 permits for the five counties comprising the SCOOP fairway (Carter, Garvin, Grady, McClain and Stephens), compared to 536 drilling authorizations in the same 2015 period.
At measured depths (MD) of roughly 22,000 ft or more, horizontal SCOOP wells largely target the Springer, an overpressured shale and sandstone conglomerate, or the underlying Woodford. Between the sloughing Springer shale and the fragile sandstones of the Red Fork formation, which overlay the Woodford, operators in the SCOOP and, to a lesser degree, the STACK, have to confront often severe loss circulation issues. “The Springer tends to collapse, so you need higher mud weights to prevent sloughing shales, which can exceed the fracture initiation limit of the Red Fork. Either way, you can have several losses in these mechanically weak formations,” says Cody Wellman, North America technical sales manager for Impact Fluid Solutions.
Wellman said the incorporation of Impact’s proprietary wellbore shielding additive in the active oil-based mud has proven effective in applicable Grady County wells, to prevent losses and eliminate a casing string. “One operator went from a two string to a monobore well design, and we drilled 20,000 ft of open hole with no losses,” he said.
Further attesting to the migration north, Continental augmented its aggregate 914,000-net-acre leasehold with thirdquarter acquisitions that added more than 10,000 acres to its STACK position. The Oklahoma City independent closed out 2016 with 11 active rigs across the 357,000 net acres that it now controls in STACK, six of which targeted the Meramec. The remaining five rigs were drilling the Woodford as part of the three-year Northwest Cana gas-directed JDA with South Korea’s SK E&S Co. Ltd. In 2016, Continental also averaged four rigs in its 557,000-net-acre SCOOP position, where it targets both the Woodford and Springer shales.
At year-end, Continental had completed seven new wells as part of an eight-well Meramec STACK density pilot, anchored around the parent Ludwig well that, over a 338-day period of production, delivered a cumulative 298,000 boe. The seven wells produced average peak 24-hr rates of 2,653 boe, Continental said during the Capitol One Securities’ “SCOOP/STACK Day” on Nov. 29. “The average completed well cost for Ludwig density wells came in at $7.8 million each,” Stark said.
Meanwhile, four newly completed STACK Woodford gas wells included in the JDA averaged 24-hr initial production (IP) rates of 15.35 MMcfg, at average flowing casing pressures of roughly 5,938 psi. The quartet was completed with laterals ranging from 6,800 ft to 9,900 ft.
To the south, Continental also completed a seven-well enhanced completion density test in the SCOOP Woodford oil window. Stark said the pilot wells were completed with “triple the proppant and 0% more fluid” than offsets with average laterals of 7,300 ft. At a median completed cost of $9.3 million/well, the wells averaged peak production of 983 boed.
Elsewhere, STACK pioneer Newfield plans to transition to full-blown development mode this year, which it says will necessitate an undisclosed number of additional rigs. Newfield entered 2017 with more than 350,000 net acres across the Anadarko basin, where net production, as of November, had reached a record 93,400 boed. At year-end, Newfield was running three rigs in STACK, and two rigs in its SCOOP leasehold.
Newfield says its completion designs going forward will feature sand proppant loadings of 2,100 lb/lateral ft, 2,100 gal frac fluid/lateral ft, and tighter spacing between perf clusters.
Last May, Newfield agreed to acquire Chesapeake Energy’s 42,000-acre STACK holding for $470 million. The acquisition was followed up in August with the $390-million sale of non-strategic Eagle Ford and South Texas conventional gas assets, with the proceeds providing “the near-term fuel to accelerate development of the SCOOP and STACK assets,” Boothby says.
Meanwhile, Devon CEO Hager credits the 430,000-acre STACK leasehold as a primary contributor to the “best quarterly drill-bit results” in the company’s 45-year history. He was referring to the play’s thirdquarter 2016 production, which jumped year-over-year from 67,000 boed to 92,000 boed. The record production was accompanied by lease operating costs (LOC) of $4.03/bbl—the lowest in Devon’s total portfolio, the company said.
Devon exited 2016 with a six-rig fleet that will increase in 2017, as the company shifts to development, with primary focus on Meramec infill drilling pilots and continued derisking of the Woodford oil window. If current plans hold, drilling activity will concentrate largely in the overpressured Meramec until around mid-year, when up to four of the rigs are likely to transition to Woodford targets. Devon says some 60% of the Meramec wells drilled this year will feature 10,000-ft laterals.
In the third quarter, Devon operated or participated in 18 over-pressured Meramec wells, with quarterly record 30-day production rates averaging 1,900 boed. Of those, six operated wells delivered average 30-day rates of 2,400 boed.
Devon also operates under a Woodford- centric JDA with Cimarex Energy Co., which singularly holds 250,000 net acres, prospective for both the Woodford and Meramec. Cimarex says it plans to continue running four rigs throughout the year, mainly to hold and further delineate its 135,000 Meramec-prospective acres.
Production averaged 427 MMcfed for the third quarter—down 8% over the previous quarter, which Cimarex blamed partially on completion delays caused by its change to upsized stimulations. Cimarex says its 5,000-ft lateral Woodford wells are now being completed with sand loadings of 3,500 lb/lateral ft, at costs of $7.1 million to $7.5 million. The company also is examining different frac design scenarios for its extended-reach (2-mi) Meramec wells, where authorizations for expenditures (AFE) are ranging from $10.5 million to $12 million/well.
Marathon Oil Corp., for one, wasted little time capitalizing on the $888-million acquisition of PayRock Energy Holdings last June, which gave the Houston independent an additional 61,000 net acres and 9,000 net boed production in the STACK oil window. Within a leasehold now comprising just over 200,000 net acres, Marathon said production in the third quarter was up nearly 80% year-over-year, thanks in no small part to the new STACK acreage.
During the third quarter, the STACK and SCOOP holdings averaged 41,000 boed, compared to 23,000 boed during the same period in 2015, and 52% higher than second-quarter 2016. Marathon brought 10 gross operated STACK Meramec and two SCOOP Woodford wells online in the third quarter, including two Meramec extended-reach wells in Blaine County that delivered average 30-day production rates of just under 2,428 boed. Both wells were completed with sand proppant loadings of 2,900 lb/lateral ft.
Marathon added a fifth rig in the fourth quarter, with drilling activity going forward focused squarely on the STACK. The company maintained an average of three rigs in its STACK and SCOOP leasehold in 2016, and planned to exit the year with the drilling of 31-35 net (36-40 gross) wells.
“As we look into 2017, we would anticipate a minimum four-rig drilling program in our pro forma STACK position, which will achieve leasehold drilling requirements while accelerating delineation work,” said Lee Tillman, president and CEO. “Our first call on capital is going to be in Oklahoma, and specifically achieving our strategic objectives in the STACK.”
While Marathon built up its established holdings, Jones Energy, of Austin, Texas, made its debut last September with the $136.5-million purchase of 18,000 net acres in southern Canadian and northern Grady counties. Jones planned to have its first “fit-for-purpose” rig on location in December, where it will operate under an atypical half-year contract. “We just wanted a six-month commitment, so that we knew we could keep that rig onboard for six months,” said Founder and CEO Jonny Jones. Jones plans to ramp up to three rigs in the SCOOP/STACK this year.
The company’s founder said more SCOOP/STACK acquisitions are in the works. “We’re looking at 10 deals that range in size from as small as 100 acres, which is just probably us trying to buy operations in one section, to deals as large as 4,000 acres. There’s been a number of transactions that have happened since we closed, with acreage values going up dramatically,” Jones said during the Nov. 3 third-quarter earnings call.
One of those later acquisitions came on Dec. 13, when Gulfport Energy Corp. announced plans to acquire 46,000 net acres in the SCOOP core, held by Vitruvian II Woodford LLC for $1.85 billion. The planned acquisition includes Woodford and Springer stacked play prospects in Grady, Stephens and Garvin counties that produced roughly 183 MMcfed last October.
Meanwhile, pure play operator Gastar Exploration in November liquidated some 24,000 non-core “South STACK” acres, in northern Canadian and southeast Kingfisher counties, to an undisclosed buyer for roughly $71 million. The Houston independent, which now controls 81,500 net STACK acres, said the proceeds will be used to accelerate delineation of its core acreage in northern Kingfisher and southern Garfield counties, where it targets Meramec, Osage, Woodford and Hunton pay zones.
Coinciding with the divestiture, Gastar formed a JDA with a private investment fund that will include 60 STACK wells in three 20-well increments. The JDA covers some 18,000 of the 54,400 net acres that Gastar holds in the northern STACK quadrant.
At year-end, the company had drilled six wells as part of the agreement, with the initial 20-well package expected to be completed by the second quarter. Gastar plans to continue running two rigs in the JDA area until at least early 2017.