After languishing through a pandemic-wrecked year and a crippling winter storm, it would be logical to assume that operators in the high-return Eagle Ford would eagerly open the taps, as oil prices touched heights not seen in six years. For now, the reality is anything but.
As borne out in the latest production projections, prioritizing capital discipline over unbridled production growth remains the overriding strategy, even as the West Texas Intermediate (WTI) oil price hovers in the low-to-mid-$70s/bbl. According to U.S. Energy Information Administration (EIA) estimates, August oil production of 1.039 MMbpd (Fig. 1) would be some 60,000 bpd less than production in August 2020, when Covid-induced demand wreckage put many operators on the sidelines.
While many, like newly restructured Chesapeake Energy Corp, are focusing primarily on the play’s clearly defined gas zones, the EIA estimates year-over-year gas production in August will fall by a modest 220 Mcfd to 5,835 MMcfd. Notably, more total volumes this year are pouring from the revitalized Austin Chalk that overlays the Eagle Ford source rock across much of South Texas.
Summer drilling activity has held at a steady 32 active rigs for most of the summer, according to Baker Hughes, after tumbling to a low of nine rigs during the week of July 10, 2020. The Texas Railroad Commission (RRC), the state’s chief regulator, issued 426 drilling permits in the pertinent Eagle Ford districts over the first six months of this year, after approving 981 drilling authorizations in 2020, a 10-year low.
Emblematic of the local trajectory, SilverBow Resources Inc. forecasts full-year oil production of 3,500 to 3,900 bpd, which would fall below the 4,157 bpd produced in 2020. Total production, however, is expected to increase from 183 MMcfed last year to a guided 2021 range of up to 200 MMcfed.
PICK AND CHOOSE
The distinctive oil, dry and wet gas windows rank as perhaps the most defining characteristic of the Eagle Ford, providing the flexibility to quickly capitalize on the higher-priced commodity. SilverBow intends to exploit that distinction over the second half of 2021, even though the oil production target falls short of 2020 actuals.
“We’ve changed our (commodity) allocation for the remainder of the year, with 60% of our full-year budget now directed towards liquids development, compared to just 30% in our original 2021 plan presented in March,” CEO Sean Woolverton said in a May 6 call.
The pure play operator expects to drill 16 net wells and complete 18 wells this year, including further appraisal drilling of the Austin Chalk in the Webb County gas window. An initial Austin Chalk test well in the first quarter flowed at a 30-day initial production (IP) rate of 13 MMcfd at an “all-in well cost” of $6 million.
The company plans to lay down its lone rig and pause new drilling between August and November to “allow a full assessment of the Austin Chalk results” and analyze the market conditions going forward. Drilling will re-commence in the fourth quarter, with the focus switching back to “high-return” gas assets, “which will set us up for a strong start to 2022,” said Executive V.P. and COO Steven Adam.
At finding costs of less than $5/boe, Magnolia Oil & Gas Corp., for one, believes few plays can economically match the re-emerging Austin Chalk in the ultra-mature Giddings field. “By North American standards, it’s probably still some of the best money you could spend,” says President and CEO Steve Chazen.
Magnolia holds a 436,585-net-acre Giddings position, northeast of the 23,512 net acres that it controls in the Eagle Ford/Karnes County core. Together, the two assets produced 62,300 boed in the first quarter, more than half of which came from Giddings.
Magnolia is running two rigs, with one dedicated to drilling multi-well pads in Giddings, with the other operating in both Karnes County and Giddings. After adding eight new producing wells in the first quarter, the company expects to bring 20 to 24 Giddings wells online this year.
For Giddings, prepping wells for production does not mean fracing in the traditional sense. “Basically, you’re just fracing the chalk formation against existing fractures. What we’re doing is creating some from the frac process, but we’re also opening old existing fracture zones. And so, you get more non-frac type production going into the mix,” Chazen said.
Murphy Oil Corp., likewise, says Austin Chalk wells are exceeding expectations and producing on par with Karnes County wells. Of the six Austin Chalk wells that came online in the first quarter, a new three-well pad delivered average IP 30 rates of 1,400 boed, equaling the average 30-day production of the 16 new Karnes County producers.
First-quarter production from the upper and lower Eagle Ford zones, and the Austin Chalk, averaged 30,000 boed at median completed well costs of $4.5 million/well. Production came in at 4% above the original guidance, despite the temporary curtailment of more than 2,000 boed during February’s winter blast. Second-quarter production is expected to increase to 37,900 boed.
Murphy holds 123,237 net acres, where this year it expects to put 19 operated and 45 gross non-operated wells online. The company expects to maintain flat Eagle Ford production of around 30,000 net boed “over many years.”
EOG Resources Inc., meanwhile, is running three rigs and two frac spreads, with plans to complete 145 net completions this year. Along with 516,000 net acres in the oil window, EOG in November 2020 took the wraps off what it describes as the “lowest-cost dry gas play in North America.”
The 163,000-net-acre Dorado asset in Webb County includes development of the Eagle Ford and Austin Chalk (Fig. 2), where 17 delineation wells had been drilled as of early May. One rig and a frac spread will be dedicated to Dorado this year, where 15 net completions are earmarked at wellhead breakeven prices (BEP) of less than $2.50/Mcf. “On natural gas, we’re mildly bullish,” CEO Bill Thomas said. “Inventories are low, and demand is higher this year than supply.”
The company has identified 1,250 net undrilled Dorado locations that comply with a higher return hurdle that demands wells deliver a 60% return at $40/bbl oil and $2.50/Mcf gas. Some 1,900 undrilled Eagle Ford locations fall within the same designation, where EOG has set a 2021 completed well cost target of $4.6 million for wells drilled with an average 8,400-ft lateral.
Like gas, Thomas said the current oil supply-demand ratio, in tandem with the industry-wide fiscal discipline, should pay dividends in short order. “The fundamentals are definitely improving. I think we’re up to maybe 95-million-barrel-a-day demand right now. We think, maybe by the end of the year, that will get to pre-Covid levels of somewhere around 100 million barrels a day,” he said in a May 7 call.
Callon Petroleum Co., which saw first-quarter production fall below year-end 2020 volumes, completed 10 gross wells in the lower Eagle Ford in the first quarter, with production of 2,088 boed, compared to 2,710 boed delivered during fourth-quarter 2020. Four of those wells were completed on the Gardendale pad, with laterals averaging more than 12,000 ft.
“These long laterals tend to exhibit very nice, flat production curves and hold the rates quite well. And in fact, the older vintage wells, which directly offset these Gardendale wells, are some of the longest-time producers in our portfolio, and these new wells are producing right on par with our expectations,” says COO Jeff Balmer.
With the all-stock acquisition of Carrizo Oil & Gas in December 2019, valued at around $740 million, Callon acquired some 76,500 net acres in the Eagle Ford, which it describes as “an efficient cash machine.”
Elsewhere, Penn Virginia Corp. moved into the regional heavyweight ranks in July, with the announced acquisition of privately held, pure play operator Lonestar Resources and its 53,550 net (72,682 gross) acres and 13,000 boed of production. Valued at $370 million and expected to close during the second half of 2021, the all-stock transaction gives Penn Virginia a largely contiguous leasehold of around 143,000 net acres, which will drive the company’s strategy to drill longer laterals.
“We’re working to put as many wells onto one pad as we can, and to drill the longest laterals that we can,” President and CEO Darrin Henke said in an abbreviated call two months before the announced acquisition.
Penn Virginia’s stand-alone first-quarter production was 20,534 boed (80% oil). The year-end oil production target has since been revised from 17,200-19,000 bpd to 18,300-20,100 bpd. Prior to the acquisition, the company planned to maintain a two-rig program for the remainder of 2021, providing commodity prices continue to cooperate.
A sampling of other operators shows a mixed bag of near-term activity.
ConocoPhillips Co. netted first-quarter production of 187,000 boed from a 200,000-net-acre Eagle Ford position, where it entered the second quarter with four active rigs (Fig. 3) and two frac spreads.
After taking a break for most of 2020, Devon Energy Corp. and 50/50 joint venture (JV) partner BPX Energy returned to active duty in the first quarter with two rigs and one completion crew targeting both the Eagle Ford and Austin Chalk. The 300,000-net-acre leasehold averaged first-quarter production of 30,000 boed, with roughly 40 wells expected to be turned-in-line this year.
Marathon Oil Co. brought 25 gross wells online in the first quarter, with net production reaching 77,000 boed. Some 50 wells are expected to go to sales in the second quarter at average completed well costs of $3.5 million/well.
After emerging from Chapter 11 on Oct. 1, 2020, EP Energy Corp. is now seeking “strategic alternatives to maximize shareholder value,” with a sale or merger among the options being considered. EP Energy operates exclusively in the Eagle Ford, with roughly 115,000 net acres under lease. In the latest information made available, the company planned to spend much of this year whittling down a drilled-but-uncompleted (DUC) well inventory, with full-year production targeted at between 46,000 and 51,000 boed (64% oil).
Citing the need to pay down debt, Ovintiv Inc. sold its 42,00-net-acre Karnes County asset to privately held Validus Energy Co. in May. The $880-million deal includes 21,000 boed of production from 495 net producing wells. Validus has not responded to requests for comment on its near-term plans for the newly acquired acreage.
STICKING WITH GAS
Six months removed from exiting bankruptcy court, Chesapeake is sticking to its gassy roots, while holding off further development of a blockbuster pre-restructuring acquisition, pending more clarity on the long-term direction of oil prices.
In its first post-bankruptcy guidance, Chesapeake expects production to remain flat this year and next, with gas comprising nearly 85% of the total production mix. In the first quarter, Chesapeake’s 220,000-net-acre Eagle Ford leasehold produced 73,000 boed, while the oilier Brazos Valley asset in the northeastern quadrant contributed 41,000 boed. Chesapeake acquired the 420,000-net-acre asset in the $3.98-billion takeover of WildHorse Resource Development Corp. on Feb. 1, 2019, 16 months before filing for Chapter 11 bankruptcy protection.
Chesapeake is running a single rig in the Eagle Ford and plans to drill around 17 wells this year. No rigs or new wells are currently on tap for the Brazos Valley, where six earlier-drilled wells were put online in the first quarter. “There’s some great wells we can drill in Brazos Valley today, and we hope with more stability in (oil) prices to drill a bunch of them,” said interim CEO Mike Wichterich in the first post-bankruptcy earnings call on May 11. “We have to have confidence in the longer-term oil price, but that’s not where we are yet.”
- Singlet oxygen-generating treatment technology achieves sustainable operations, helps operators meet production goals (November 2023)
- Rig electrification drives down emissions, bolsters efficiency while improving onshore drilling economics (October 2023)
- What's new in production (August 2023)
- Machine learning-assisted induced seismicity characterization of the Ellenburger formation, Midland basin (August 2023)
- Downhole tool integrity maximizes completion efficiency and ultimate recovery (July 2023)
- Mobile electric microgrids address power demands of high-intensity fracing (July 2023)