Eagle Ford/Austin Chalk Shales: High returns fail to stave off summer retreat
The caliche roads cutting through the blackbrush and mesquite of the South Texas brush country are a bit less congested of late, as Eagle Ford drilling and completion activity dips in what is ranked among the most profitable of the unconventional plays.
The slump of sorts coincides with the Eagle Ford and overlying Austin Chalk ostensibly checking all the investor boxes, with typically high oil cut, relatively low drilling costs, and unfettered access to waterborne prices, fetching per-barrel returns at a premium to the West Texas Intermediate (WTI) benchmark. Favorable metrics aside, operators laid down five rigs over the second week of July, dropping the monthly average to 68 rigs (Fig. 1), down from a steady 81 active units in July 2018, according to Baker Hughes, a GE company.
A dissection of horizontal drilling permits approved by the Texas Railroad Commission (RRC), the state’s chief regulator, shows around 100 less wells given the green light over the first half of 2019. The RRC authorized 1,981 new drills between Jan. 1 and July 10, compared to the 2,080 permits for the same period last year in the six applicable RRC districts that stretch as far south as the Mexican border.
Production, likewise, is down some 3.7%, year-over-year, with the latest data available from the U.S. Energy Information Administration (EIA) also documenting a 1,519-wells drilled-but-uncompleted (DUC) inventory as of June, second only to the Permian basin. The EIA’s best guesstimate has the Eagle Ford delivering 1.382 MMbopd in August, down from 1.436 MMbopd, Fig. 2. Gas production, however, is expected to increase to 6,848 MMcfd, from 6,391 MMcfd in August 2018, according to EIA.
Across a commanding 516,700-net-acre asset encompassing the core of the distinctive oil window, EOG Resources Inc., is belying recent statistics with an ambitious 2019 campaign. The program comprises an average 10 rigs and 7.5 completion crews, with 300 net completions on tap. At completed costs of $4.3 million/well, Executive V.P. of Exploration Kenneth Boedeker said that the first three months of 2019 “was our best drilling efficiency quarter that we’ve ever had in the Eagle Ford on our dollar-per-foot basis The best days of the Eagle Ford are still ahead.”
Meanwhile, operators continue to drill longer reaches, while testing new completion designs, aimed partly to help alleviate nettlesome frac hits. In addition, the extensively drilled, but largely undeveloped, Austin Chalk, developed singularly or conjointly with its Eagle Ford source rock, adds heft to the multi-zone prospects.
Moreover, acreage has changed hands at a brisk pace over the past year, with Shale Experts putting Eagle Ford properties in play in no less than 18 small-to-large transactions between April 2018 and March 18, at an average cost of $13,935/acre. The most recently proposed deal came on July 15, with Callon Petroleum Co. releasing plans to acquire Carrizo Oil & Gas Inc, and its 76,500-net-acre Eagle Ford position, in a $3.2-billion all-stock deal.
INTEGRATING NEW ASSETS
Earlier buyers have wasted little time integrating new assets, as illustrated by Chesapeake Energy Corp., which is running four rigs (Fig. 3) and two frac spreads in the newly designated Brazos Valley business unit, officially acquired with the February closing of the $4-billion acquisition of WildHorse Resource Development Corp. The roughly 470,000 net acres take in the northern part of the Eagle Ford and Austin Chalk trend, where the company plans to put 85 new wells into production this year.
After the first two months of operating the asset, Chesapeake says it shaved costs by some $500,000/well, thanks partly to the wholly owned sand mine in Burleson County, which commenced operations in February. Chesapeake also will drill appreciably longer reaches than the former owner. “Historically, the lateral lengths were around 5,000 to 6,000 ft. We’re pushing those lateral lengths out to somewhere around 9,200 to 9,300 ft for the year,” says Executive V.P. of Exploration and Production Frank Patterson.
Chesapeake is running an additional four rigs and two frac crews in its 235,000-net-acre position in Dimmit and LaSalle counties, where a cumulative 133 wells are expected to be turned in line this year.
Rebranded BPX Energy assumed full control in March of some 300,000 net acres in the Eagle Ford core formerly owned by first mover BHP Billiton. The asset is part of BP’s $10.5-billion acquisition of BHP’s unconventional properties. BP’s U.S. onshore entity plans to average five to six rigs in the Eagle Ford between 2019–2021.
The Eagle Ford acreage has been operated under a 50/50 joint venture with Devon Energy Corp.—a partnership that for now appears to have strengthened. “The relationship that we’ve had with BP is working quite well. We picked up an additional rig, so we have four rigs currently working there,” said Devon COO Tony Vaughn on May 1. “This relationship is so good that one of the four rigs currently working right now is being operated by Devon. The technical dialogue between the two companies could not be better, and I think we’re more closely aligned probably than we had been with the previous partner there.”
Devon, for its part, controls 65,000 net acres in DeWitt County, where nine wells were hooked to production in the first quarter. After adding a third rig in January, Devon plans to spud 70 wells this year.
REVISITING AN ELDER
Year-old Magnolia Oil & Gas Corp. is staking much of its early fortunes on the historic Giddings field, the Austin Chalk bellwether sweeping across parts of seven counties in the eastern extension of the Eagle Ford. Magnolia holds 440,000 net (650,000 gross) acres in the naturally fractured field.
Magnolia has embarked on an extensive delineation program, including microseismic investigations and the possible addition of a second rig later this year. The pure play operator also is running one rig and a completion crew in Karnes County, where it controls around 21,500 net acres, targeting both the Austin Chalk and Lower Eagle Ford, with wellhead break-even prices (BEP) of $28/bbl to $32/bbl.
Formed in March 2018, Magnolia is headed by former Oxy chief Steve Chazen, who said that unlike Karnes wells, which have “ a very high” decline rate and eventually level out, Giddings Chalk wells tend to “start out weaker and they get better over, say, the first six months (when microfracture production kicks in), and then the decline rate is much less.”
Elsewhere, a sampling of operators reflects the varying levels of 2019 activity across the Eagle Ford and Austin Chalk.
ConocoPhillips has transitioned to high-intensity completions, reflected in the first multi-well pad employing its exclusive Vintage 5 customized completion design. The new completions build on the Vintage 4 design that featured proppant loadings of 14,000–17,000 million lb at 15-ft cluster spacing and customized for the specific area.
The 210,000-net-acre Eagle Ford position is lumped into the company’s Lower 48 portfolio, which also includes the Bakken and Delaware basins. The company plans to operate 10 to 11 rigs in the so-called “Big Three” this year, but declines to break out play-specific rig counts. The Eagle Ford, however, is expected to contribute more than half of the estimated 350,000-boed Lower 48 production for 2019.
SM Energy Co. says a second Austin Chalk well, drilled with a 12,875-ft lateral reach, tested at a three-stream rate of more than 3,500 boed. Operating one rig and a completion crew as of June, SM planned to drill two and complete 14 net wells in the second quarter on a 163,000-net-acre position.
Marathon Oil Co., which holds 145,000 net acres, will bring 125 to 135 gross operated wells to sales this year. The 41wells turned in line in the first quarter averaged 30-day IP rates of 1,515 boed, at an average completed cost of $4.4 million/well.
Marathon also is the operating partner in a joint venture with Canada’s Baytex Energy Corp., which holds 20,200 net contiguous acres in Karnes County. Baytex notched up record-high Eagle Ford quarterly production in the first quarter at 41,097 boed, a 7% increase over the prior quarter. Over the first three months, the 8.9 net (36 gross) wells put online averaged a 30-day IP of around 1,600 boed/well.
Pure play Sundance Energy Australia Ltd. expects to drill and turn-in-line 21 and 25 wells, respectively, this year, after exiting the first quarter with only two wells hooked to production and a 10-well DUC inventory. First-quarter production of 12,300 boed hit the sales lines at a $2/bbl premium over the WTI benchmark. Sundance also is looking at the possibility of giving up its corporate citizenship and re-incorporating in the U.S. to be more closely aligned with its 51,903-net-acre Eagle Ford asset and local capital markets.
Once ranked as one of the play’s most prolific operators, Sanchez Energy Corp. was delisted from the New York Stock Exchange (NYSE) in February, but closed out the first quarter drilling eight gross (two net) wells with 18 gross (four net) wells completed and put on production. Sanchez holds 283,000 net acres, where it targets the Lower, Middle and Upper Eagle Ford Shale with “upside potential” in the Austin Chalk and Pearsall shales.
Also delisted on May 23, EP Energy Corp. completed 13 gross (nine net) wells in the first quarter. EP has since laid down two rigs and is working off a DUC inventory.
While awaiting the fourth-quarter closing of the Callon Petroleum acquisition, Carrizo is putting three additional multi-well pads online this year, where it is employing a gap management strategy, in tandem with a switch to hybrid fracs, to help mitigate parent-child well interactions. “We try to leave very large gaps (between wells) to minimize this parent-child relationship,” says V.P. and COO Brad Fisher. “Rather than drilling three- and five-well pads one at a time, to kind of finish out a gap, we just drill them all at once.
A 13-well pad and 14-well pad were expected to go online in June and July, respectively. A third nine-well pad, with laterals exceeding 10,000 ft, is expected to go into production by early November. The mega-pad project comprises a cumulative 33 wells, distributed among eight pads in the Pena asset in LaSalle County and RPG asset in northeastern Atascosa County.
Carrizo drilled 27 gross (24 net) and completed 32 gross (32 net) operated wells in the first quarter, with average completed costs of $3.9 million to $4.1 million for a 6,600-ft lateral well.
Despite “unusually high” instances of frac hits affecting 23 wells, Lonestar Resources Inc. increased first-quarter production 46%, year-over-year, to 11,372 boed. Much of the increase can be credited to four new wells in the Karnes County Horned Frog asset. With medium reaches of 9,708 ft, the first two wells commenced production in April at average 30-day rates of just under 1,454 boed, 3% higher on a per-foot basis than the two peer wells placed onstream in 2018. Initial tests of two Horned Frog wells with 12,461-ft and 12,170-ft horizontal reaches resulted in company-record flowrates, averaging 2,500 boed.
Lonestar controls more than 57,000 net acres, where offset frac hits kept an aggregate 330 boed out of the first-quarter production picture. The wells have since been returned to production at rates “equal to or above their third-party type curves.”
Murphy Oil Corp, likewise, cited “offset frac impacts” and a delay in the start-up of a 10-well pad, for taking 3,500 boed from first-quarter production. Nevertheless, Murphy averaged production of 36,000 boed, with 13 Upper and Lower Eagle Ford wells brought online. Murphy will run three rigs in 2019 on its 125,000-net-acre leasehold, with 92 new producing wells, including two Karnes County Austin Chalk wells scheduled to commence production in the second quarter.
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