Shaletech: Scoop/Stack

Newfield Exploration plans to run 10 to 11 rigs this year across its 350,000-net-acre STACK/SCOOP leasehold. Image: Newfield Exploration Co.

Unveiled by respective first-movers Continental Resources Inc. and Newfield Exploration Co., the tightly concentrated South Central Oklahoma Oil Province (SCOOP), the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (STACK), and their offshoots are among the nation’s fastest-growing unconventional oil and gas plays. “Generally, we think the economics are pretty good and are on par with anything in the Permian and the best unconventional plays in the United States,” Imre Kugler, associate director of energy research at IHS Markit, told the The Oklahoman on Aug. 18, 2017, as the benchmark West Texas Intermediate oil price hovered around $48/bbl.

A concurring Rystad Energy NASWellCube analysis shows SCOOP wells completed in the first three months of 2018 averaging wellhead break-even prices of $34.60/bbl, compared to $42.74/bbl for geologically complex STACK wells.

Intersecting the delineated boundaries of the two plays, the self-explanatory Merge is said to offer near-identical attributes of both SCOOP and STACK, and at entry costs of less than $1,000/acre. Meanwhile, although the dual-bench Woodford and Meramec, and now-developing Springer shales capture the spotlight, Newfield’s year-old Sycamore, Caney, Osage Resource Expansion (SCORE) initiative looks to further expand the prospective horizons across its 350,000-net-acre leasehold. Reverting to the more traditional geological reference, Newfield kicked off SCORE in 2017 with a $100-million injection.

Nomenclature aside, nearly all activity is huddled in the CanaWoodford subset of the greater Anadarko basin, which averaged 63 active rigs in April, compared to a 52-rig average in April 2017, according to Baker Hughes. Notably, those rigs now have the green light to drill longer-reach horizontals, after state lawmakers in late 2017 overturned an outdated regulation that limited lateral lengths to one mile, ostensibly to avoid interference with innumerable legacy conventional wells.

Mirroring the increased rig count, the regulatory Oklahoma Corporation Commission (OCC) issued 268 new drilling permits in the five core SCOOP counties—Carter, Garvin, Grady, McClain and Stephens—between Jan. 1 and April 10, up from 184 new authorizations for the like period last year. The OCC issued 345 permits for the more condensed STACK play, compared to 308 permits approved between Jan. 1 and April 10, 2017, in the fairway of Blaine, Canadian and Kingfisher counties.

Fig. 1. Anadarko oil and gas production in May is forecast to rise 1,000 bopd and 6 MMcfd, month-over-month, to 506,000 bpd and 6.544 Bcfd, respectively. Source: U.S. Energy Information Administration (EIA).

 
Oil and gas production in the Anadarko basin were expected to reach 506,000 bpd and 6.544 Bcfd, respectively, in May, according to the U.S. Energy Information Administration (EIA). The agency last year saw fit to include the basin in its monthly Drilling Productivity reports of key unconventional plays, Fig. 1. The inaugural EIA Anadarko report, in August 2017, estimated production of 447,000 bopd and 5.879 Bcfd of gas.

4,000+ BOED WELLS

High flowrates and prospects aplenty have the aptly named STACK shaping up as the premier CanaWoodford development target. “The Oklahoma STACK play is economic for many operators at current prices, and it offers multiple drilling targets, due to its complex geology, which is attractive for drillers seeking to leverage pads to expand resources,” IHS’ Kugler wrote in a separate investor note on Aug. 17. “While the play covers about one-fifth the aerial extent of the Permian basin, it is attractive to many operators, who find the Permian over-heated in terms of acreage availability and cost of entry.”

Fig. 2. One of three rigs that Chaparral Energy has directed to its STACK holdings this year. Image: Chaparral Energy Inc.

Homegrown Devon Energy Corp. exemplifies the play-wide strategy, as it transitions from appraisal to full-field development of its multi-zone STACK assets, where five wells completed in the fourth quarter averaged 30-day initial production (IP30) rates of 4,650 boed. Notably, the first well completed early this year in the planned seven-well Coyote Lower Meramec development hit a 24-hr IP rate of 8,200 boed.

A cumulative 12 wells in the Meramec oil window were brought online in the fourth quarter at average IP30 rates of 3,200 boed, helping drive quarterly STACK production to 120,000 boed. The start-up of 50 newly completed wells has early 2018 production jumping to 130,000 boed.

“The Meramec is a little bit different than some of your unconventional plays, and it has some conventional porosity and permeability. And so you may actually be able to increase your EUR (estimated ultimate recoveries) and drill less wells to recover a similar amount of hydrocarbons than you originally anticipated,” said Wade Hutchings, senior vice president of exploration and production.

Fig. 3. The Merge play capitalizes on the best characteristics of the SCOOP and STACK. Source: Jones Energy Inc.

Devon places its more than 600,000-net-acre STACK position on equal footing with its Permian Delaware leasehold, both of which are expected to see 100 new wells drilled this year.

Following aggressive infill development in 2017, Marathon Oil Corp., likewise, is moving to multi-well pad drilling in its STACK Meramec leasehold, with plans to bring 40 to 50 operated wells to sales. Production from its 200,000-net-acre STACK/SCOOP holdings increased 10% in the fourth quarter, to 64,000 net boed, from 58,000 net boed in the previous three months.

The debut Tan volatile oil infill development program last year in southwestern Kingfisher County averaged 30-day IP rates of 1,840 boed. The nine infills comprised eight 10,400-ft-lateral wells and one 5,400-ft-lateral well.

Meanwhile, private equity investor Bayou City Energy LLC. again opened its vault last September with a $100-million joint development agreement (JDA) with pure play STACK operator Chaparral Energy Inc.

The Oklahoma City-based operator drilled or participated in 128 gross (28 net) STACK wells in 2017, including 28 Meramec and Osage wells with average gross IP30 rates of 720 boed. A spokesperson said Chaparral plans to run three rigs throughout 2018 and drill 61 gross wells, including 26 as part of the joint venture, Fig. 3.

After the 2017 bolt-on acquisition of 7,000 net acres in Kingfisher County, at a cost of roughly $8,500/acre, Chaparral now controls a 117,000-net-acre leasehold.

Fellow pure-play STACK operator Alta Mesa Resources Inc. also signed a JDA with the Houston-based equity firm in early 2016. Last year, the agreement funded 37 of the 134 gross wells that Alta Mesa drilled and completed across a largely contiguous, 130,000-net-acre position in the STACK oil window. Alta Mesa plans to maintain an eight-rig fleet throughout the year and drill between 170 and 180 gross wells.

KEEPING SCORE

In unveiling its three-year plan on Feb. 21, STACK pioneer Newfield Exploration said the 21 wells drilled and tested as part of its SCORE initiative had delivered 30-day flowrates of around 1,386 boed. The SCORE wells, which Newfield credits with expanding its total Anadarko, net-effective reservoir footprint to more than 1 million acres, comprise a mix of Sycamore, Caney, Osage, Woodford and Meramec targets across its STACK and SCOOP properties, with gross perforated intervals (GPI) ranging from 4,412 ft to 10,460 ft.

One stacked Woodford/Osage well in eastern Canadian County delivered IP30 rates of 1,549 boed (61% oil).

Over the next three years, Newfield plans to invest approximately $365 million to drill and test between 80 and 90 wells to further hold acreage and delineate the play.

SCORE coincides with the northwest extension of the STACK Meramec and the eastern expansion of the North SCOOP oil plays. This year, Newfield plans to run 10 to 11 rigs in the Anadarko basin, with activity centered on multi-well pad developments. Of the 150 wells expected to go online during 2018, 70% will be drilled and completed in STACK, where infill development drilling will take center stage over the next three years.

In the fourth quarter, Newfield turned to sales what was described as the most “technically comprehensive” of the nearly 80 wells drilled in STACK infill spacing pilots. The 12-well, four-pad Velta June Meramec development, which featured an assortment of fiber optics, high-resolution pressure monitoring and DNA rock sequencing, went online at a combined gross rate of more than 10,000 boed from 5,000-ft lateral reaches.

The company put 25 wells onstream during fourth-quarter 2017, with production averaging 117,300 boed. Newfield estimates the average STACK well in the three-year plan will generate around 1.3 MMboe at average well costs of $7.9 million.

SPRINGER TIME

Owing to more favorable oil prices, Continental has initiated long-awaited full-field development of its 170,000-net-acre SCOOP Springer asset. Five of the 15 rigs that Continental plans to run this year in its basin-high 1,133,500 net reservoir acres will be dedicated to developing the Springer shale, where 31 gross operated wells are on tap for completion this year. “We deferred development of the Springer for several years, patiently waiting for better oil prices,” President Jack Stark said in a Feb. 22 earnings call. “During this time, we conducted strategic tests for optimized completions and longer laterals up to 8,300 ft long, and as expected, the longer laterals and optimized completions clearly improved well performance.”

Stark says the Springer may be developed in combination with the underlying Woodford and Sycamore horizons. “These reservoirs are stacked on top of each other throughout much of SCOOP, within a column of rock up to 2,000 ft thick. This means, in some areas, we could be looking at as many as 18 wells in three reservoirs, with up to 10 wells in the Woodford, four wells in the Sycamore, and four wells in the Springer.”

A cumulative 12 gross wells were completed in the fourth quarter, during which SCOOP net production averaged 62,242 boed in the fourth quarter, representing 22% of Continental’s total quarterly production.

Continental also plans to operate eight rigs in its 409,500-net-acre STACK Woodford/Meramec position, where density tests are underway. Four to six of the STACK-directed rigs will be dedicated to the four-year-old joint venture with South Korea’s SDK E&S.

With the results of six largely dual-zone Meramec density tests completed (as of Feb. 22) in the over-pressured oil window, Continental has settled on a development strategy of four wells/zone. Assuming completed costs of $9.5 million for a 9,800-ft lateral well at $60/bbl oil and $3/Mcf gas, Continental projects the eight-well scenario will recover 9.6 MMboe with a 96% return.

Fourth-quarter net STACK production was up 96%, year-over-year, averaging 47,914 boed, with 23 net (63 gross) operated and non-operated wells completed. The company will allocate four stimulation crews to its STACK and SCOOP plays in 2018.

BEST OF BOTH

Jones Energy Inc. says 2018 activity will focus on the newly acquired 22,500-net-acre Merge leasehold, which it says captures the “best of both” attributes of the STACK Meramec and the SCOOP Upper Woodford extensions, Fig. 3. The Austin, Texas, independent drilled six and completed 10 Merge wells in the fourth quarter, with production averaging 5,892 boed as of Jan. 31. Jones drilled 27 gross Merge wells in 2017, targeting the upper and lower benches of the Woodford and Meramec, and plans to maintain a two-rig program this year. As of year-end 2017, Jones had 1,737 gross drilling locations in the western Anadarko.

With its transition to the Merge trend, Jones limited fourth-quarter drilling activity in its 152,000-net-acre Western Anadarko asset, in the Cleveland area, with plans to drill and complete only five “obligatory wells” this year.

After quietly amassing a 50,000-net-acre position on the eastern fringe of Merge at $750/acre, EOG Resources, Inc., has proclaimed the moderately over-pressured Woodford shale a premium oil play, defined as those requiring a minimum 30% direct after-tax rate of return at a flat $40/bbl oil price. EOG plans to average two rigs and one completion spread in 2018 and complete 25 net wells.

The Curry Woodford introductory well in McClain County demonstrated what David Price, executive vice president of exploration and production, described as an atypically low decline rate, with a 150-day rate of more than 1,100 bopd, compared to the initial 30-day rate of around 1,500 bopd. “The Curry well is solidly in the oil window, as opposed to many SCOOP/STACK wells that are in the gas condensate window,” he said.

Elsewhere, western Anadarko-centered Cimarex Energy Co.’s 2018 guidance includes four Meramec developments, and continued drilling and completion activity on its emerging Lone Rock Woodford play. Cimarex was running four rigs in the first quarter across its cumulative 253,000-net-acre Meramec/Woodford position, where a total of 43 net Meramec and Woodford wells is on tap for this year.

An aggregate 85 gross (10 net) wells were brought online during the fourth quarter of 2017, which likewise saw the completion of a three-well, stacked Woodford/Meramec test in Canadian County. Production start-ups in 2017 included 13 Meramec wells with 10,000-ft laterals, delivering average 30-day IP rates of 2,383 boed.

As of March 27, Cimarex was drilling or completing two infill spacing tests in its Lone Rock Woodford asset, where eight to 12 wells/section are being evaluated. A revised completion design is seeing costs for 1-mi. lateral Woodford wells running between $7.5 million and $8 million, while the completed costs of Meramec wells with 2-mi. laterals range from $10 million to $11.5 million. 

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.