The Eagle Ford and Austin Chalk

The Eagle Ford Shale in South Texas remains one of the most attractive horizontal resource plays for independent oil and gas companies, according to Adrian Lara, senior analyst for upstream Americas at GlobalData.

“During the past two years, the play has shown a revival in terms of major merger and acquisition deals, drilling and completion activity, improved oil recovery activity, and even a re-evaluation of the Austin Chalk formation as an additional target zone within the Eagle Ford play’s boundaries,” Lara observes.

With well-defined oil, natural gas liquids and dry gas windows, activity is concentrated in the liquids-prone areas in the northern parts of the Eagle Ford play, particularly in the top three oil-producing counties of Karnes, DeWitt and La Salle, he relates.

In its weekly rig count, Baker Hughes tallied 66 rigs operating in the Eagle Ford in mid-September. That was the highest for any North American basin outside of the Permian, and proof of operator interest in the Eagle Ford, and renewed interest in a re-emergent horizon, the Austin Chalk.

“The Eagle Ford continues to see improved well efficiency. The added cost of longer laterals and larger fracturing treatments is matched with proportionally higher initial production rates and increased ultimate recoveries,” Lara says, noting that the South Texas region also offers a well-developed midstream infrastructure for trunk lines, gathering systems, condensate splitters and associated services. “This has benefited Eagle Ford producers by allowing them to bring on stream new oil and gas wells without facing major transmission capacity bottlenecks, added costs or delays.”

Moreover, he points out that the high-quality crude oil produced from the Eagle Ford reservoir is being sold at a premium compared with the oil produced in other conventional oil plays, including benchmark West Texas Intermediate. In mid-September, Eagle Ford oil was trading 3% higher than WTI.

“Together, all of these factors continue to put the Eagle Ford high on the list of best unconventional plays for independents,” Lara remarks.

According to the Texas Railroad Commission, daily Eagle Ford production peaked in 2015 at 1.2 million barrels of oil, 6.1 billion cubic feet of natural gas, and 306,389 barrels of natural gas liquids. After enduring the effects of collapsed commodity prices in 2015-16 followed by the wrath of Hurricane Harvey in 2017, Eagle Ford output began to stabilize in 2018, Lara notes. Through the first half of 2019, production averaged 936,213 bbl/d of oil, 5.1 Bcf/d of gas, and 179,030 bbl/d of NGLs, RRC data shows.

Most of the drilling activity has been concentrated in prolific Karnes County, located south of San Antonio in the central part of the Eagle Ford play. However, Lara points out that Karnes County can be considered mature acreage, which has been developed aggressively over the play’s productive life.

“With major merger and acquisition deals happening outside of Karnes County, we expect future growth in drilling activity in La Salle, Dimmit, McMullen and Webb counties,” he states. “Eagle Ford activity has generally been moving eastward, with drilling occurring as far east as western Louisiana. Moreover, several companies within the Eagle Ford are now planning to implement improved oil recovery methods, mainly carbon dioxide injection. These pilot projects are spread across counties such as Karnes, Gonzales, De Witt, McMullen, La Salle and Dimmit.”

Expanded Position

Oklahoma City-based Chesapeake Energy Corp. has expanded its Eagle Ford position to 655,000 total net acres after acquiring Wildhorse Resource Development and its 420,000 net acres in the Brazos Valley, which Frank Patterson, executive vice president for exploration and production, describes as defining the eastern flank of the Eagle Ford’s productive extent.

Chesapeake Energy Corp. has expanded its Eagle Ford position to 655,000 total net acres after acquiring Wildhorse Resource Development and its 420,000 net acres in the Brazos Valley on the eastern edge of the play. The company is running four rigs in its Brazos Valley asset and another four rigs in its legacy Eagle Ford position in South Texas.

“Our Brazos Valley acquisition west of College Station, Tx., is on the eastern edge of the Eagle Ford play,” he explains. “As you move east from there, the Eagle Ford becomes less productive. As you go west and southwest, the Eagle Ford gets thinner until it crosses the San Marcos Arch. Once it crosses the San Marcos Arch into the Karnes Trough, it gets really thick. Move farther to the southwest, and you get to our legacy South Texas position, which is north of Corpus Christi.”

Although Chesapeake Energy has years’ worth of primary development activity across its leasehold and has not yet started any IOR projects, Patterson predicts that CO₂ flooding in older wells will be the “next big phase” in the Eagle Ford.

“We have the equipment procured, and we expect to start gas injection in 2020,” he points out. “It is really hard to get waterflood injection going because the Eagle Ford formation is super tight. So you can penetrate better into the reservoir with gas molecules. In a tight reservoir, only 7%-10% of the oil in place is recovered during primary recovery operations. If you have, say, 8% recovery in the oil window and you take that up to 12%-14% with IOR, that would be huge. With additional improved oil recovery, we might be able to get another 30%-70%.”

One thing that Chesapeake has learned is “spacing really matters” in both its South Texas acreage and its new acquisition in the Brazos Valley, according to Patterson. “We had gotten down to 330 feet spacing in South Texas, and we had a lot of cross-well interference,” he points out. “Three years ago, we recognized that and moved out to 500- to 1,000-foot spacing, and have had really good well responses.”

Chesapeake discovered the same thing in its new Brazos Valley acreage. Patterson says Wildhorse originally was drilling wells with 500-foot spacing. “We thought that was too tight, and data proved we were right,” he continues. “We have moved to 1,000- to 1,200-foot spacing with improved well performance.”

Changing The Dynamics

He credits Wildhorse with doing “a fantastic job of putting together a really big footprint” in the Brazos Valley, which he claims largely had been bypassed by earlier Eagle Ford development activity.

“It had been tested by other companies, but only with small completions,” Patterson offers. “Wildhorse changed the dynamics by using large fractures (pumping 3,000-3,500 pounds per linear foot). The Eagle Ford in the Brazos Valley has a higher clay content, similar to our acreage in the Haynesville Shale in Northwest Louisiana. The more sand pumped, the better the rock behaves.”

He says Wildhorse had hit a lull in its development, so Chesapeake came in and purchased the company outright earlier this year. Through the first six months of its ownership of the Brazos Valley asset, Chesapeake has realized a savings of approximately $600,000 a well.

“We have driven down drilling and completion costs by using the standards we have developed in other plays,” he points out. “We had done a lot of core work in South Texas, so we had high confidence that our experience would translate. We thought we could do it faster, too. It has been really interesting, because everything we thought has come to roost.”

As an example of the improved efficiencies, Patterson notes that Wildhorse had averaged completing six to seven stages per day. Chesapeake is now averaging 15 stages/day. “We will deliver the same number of wells with four rigs this year that was initially planned for five rigs,” he adds.

Although Chesapeake is running four rigs in the Brazos Valley, Patterson says the company still is trying to learn more to further improve productivity. “We just finished taking two cores to our core lab on our campus in Oklahoma City,” he states. “We will get the core analyzed and we are getting 3-D seismic data reprocessed.”

Historically, the Eagle Ford wells were drilled with 6,000-foot laterals, but Chesapeake is now pushing lateral lengths to 9,500-10,000 feet, Patterson reports. Because there were so many Austin Chalk vertical wells drilled in the historic Giddings Field, he points out that Chesapeake has to set casing as new Eagle Ford wellbores penetrate through the Chalk, which lies above the Eagle Ford.

Patterson believes Chesapeake has been able to determine that the Eagle Ford oil window is larger than originally thought. Its Brazos Valley wells have averaged 67% black oil and 12% NGLs in the past six months, but he says production will be more than 70% black oil moving forward. The expansion of the black oil window, based on subsurface analytics and validated by production data from wells drilled in the first quarter, has allowed the company to add 230 additional locations in the black oil window, according to Patterson.

High-Rate Wells

Chesapeake placed 24 wells on production (20 Eagle Ford oil wells and four Austin Chalk gas wells) during the second quarter, and projects to place 26 more wells, all in the Eagle Ford oil window, on production in the third quarter. The company already has placed 10 wells to sales in 2019 that have reached maximum 24-hour oil production rates of more than 900 bbl/d in Burleson and Robertson counties, compared with three in the same time period last year.

Chesapeake brought on line 20 Eagle Ford oil wells and four Austin Chalk gas wells during the second quarter, and expected to place 26 more wells, all in the Eagle Ford oil window, on production in the third quarter. Several of these wells have reached maximum 24-hour production rates of more than 1,000 bbl/d, including the Schoeneman No. C-1H, which had peak daily rates of 1,332 barrels of oil and 581 million cubic feet of gas from a 9,362-foot lateral.

Seven of those 10 wells have reached maximum 24-hour production rates of more than 1,000 bbl/d, including the Schoeneman No. C-1H, which had peak daily rates of 1,332 barrels of oil and 581 million cubic feet of gas from a 9,362-foot lateral section, he notes. All but one of these wells incorporated Chesapeake’s new enhanced flowback techniques, allowing production to exceed the company’s internal expectations since the acquisition, according to Patterson.

In addition to the four rigs it is running in its new Brazos Valley asset, Chesapeake also is operating four rigs in its Eagle Ford Shale position in South Texas. Patterson says the company operates 2,200 wells in its legacy South Texas leasehold and plans to turn 89 wells on line in South Texas in the second half of the year.

He notes that Chesapeake will drill 130-140 wells in South Texas this year on its acreage, which “sits in the oil/gas condensate window and is in a strong development mode,” although the company does not consider it a growth play. “In South Texas, we have good access to pipelines to both Corpus Christi and Houston,” Patterson explains. “Wildhorse was moving the oil in the Brazos Valley by truck, but we are seeking to have a pipeline built to get that oil to Houston.”

Patterson adds that Chesapeake also is pursuing a new gathering agreement in the Brazos Valley area that would reduce the current reliance on trucking oil volumes and improve its cost structure in the region.

Maximizing Recovery

Frank Bracken III is chief executive officer of Fort Worth-based Lonestar Resources Inc., a pure Eagle Ford player. He says his company is concentrating on maximizing hydrocarbon recovery per foot of lateral utilizing petrophysics and engineered completion designs.

“We use lots of petrophysics and geophysical analysis to land the drill bit in a specific target to maximize reservoir properties,” he explains. “We do a lot of advanced log analysis. In fact, we run logs to the total depth after we drill to design our fracturing treatments. That is unique in the industry.”

He claims operational experience also is important in optimizing well results, pointing out that Lonestar has been involved in the Eagle Ford since 2012. “We think the Eagle Ford is exceptional rock,” Bracken notes. “The Eagle Ford is unique among unconventional shale plays in that it was pioneered and developed in a $100 oil price environment. Companies could put in wells, not focus on improving well results, yet still make very high returns. Like any unconventional play, there was a huge land grab when the Eagle Ford first took off. The industry was trying to hold as much as acreage as possible by production as fast as possible.”

That approach does not lend itself to developing best practices, Bracken notes. “Best practices evolve more slowly. We can use information from the earlier wells that were drilled and de-risk our activity. There is no need for us to rush development to hold acreage by production, and competition is relatively low in the Eagle Ford today compared with when we were getting started in the play.”

Bracken says Lonestar Resources’ operational activities encompass 11 Texas counties, which it divides into three distinct regions: the western Eagle Ford (Dimmit, La Salle and Frio counties), central Eagle Ford (Gonzales, Karnes, Fayette, Wilson, DeWitt and Lavaca counties) and eastern Eagle Ford (Brazos and Robertson counties). However, Bracken says Lonestar intends to sharpen its focus on its highest-graded assets and divest of its eastern Eagle Ford position by year’s end.

“The eastern Eagle Ford wells are good, but they do not compete with some of the wells in our western and central regions,” he says. “We want to keep our attention on the areas where we get the best returns.”

Lonestar operates 85% of its Eagle Ford position, and approximately 95% of its acreage is held by production, Bracken notes.

“Spacing varies widely from one area to the other, ranging from 400 feet in DeWitt and Karnes counties to up to 700 feet in La Salle County,” he maintains. “We can review the historical well spacing and correlate ultimate recoveries. We have an abundance of well data, and again, we do a lot of rock analysis, which helps us optimize spacing.”

The majority of Lonestar’s wells today have 10,000-12,000 foot laterals and generally are completed with ±300-foot frac stage intervals. “We have really focused on acquiring acreage in geometries that allow us to drill long laterals. There is a lot better rate of return on the extended laterals,” Bracken explains. “As far as completions, everything we do is custom designed. We take a technically informed view where we tailor our completions specific to what the logs tell us.”

Increased Production

Lonestar Resources reported a 22% increase in net oil and gas production to 13,630 barrels of oil equivalent a day during the second quarter, and that climbed to 16,000 boe/d in July thanks to its new Horned Frog and Sooner assets. Production was 78% crude oil and NGLs on an equivalent basis.

In its western region, Lonestar’s newest wells on its 4,975-acre Horned Frog South property represent continued progress in the advancement of its geo-engineered completion practices, according to Bracken.

“On a per-foot basis through the first 30 days, our 2019 wells have recorded production rates that are 20% higher than our initial pad at Horned Frog, the Horned Frog Nos. A1H and B1H (completed in 2015) and 7% higher than our most recent Horned Frog wells, the Horned Frog G1H and H1H (completed in 2018),” the company reported in its second-quarter earnings report. “Our 2019 Horned Frog wells recorded maximum 30-day rates that eclipsed 200 boe/d per foot, and are registering oil production rates that are 17% better than our 2018 completions on a per-foot basis.”

Bracken reports that the company began flowback operations on two wells in June in its western region. The Horned Frog F 1AH, with a 12,461-foot perforated interval, recorded a maximum 30-day production rate of 549 bbl/d of oil per day, 674 bbl/d of NGLs and 7,283 Mcf/d of gas (2,436 boe/d on a three-stream basis). The Horned Frog F 61H has a 12,170-foot perforated lateral and a maximum 30-day production rate of 578 bbl/d of oil, 74 bbl/d of NGLs and 7,605 Mcf/d of gas (2,550 boe/d).

In Karnes County in its central region, Lonestar’s four Georg 3H-6H wells delivered average maximum initial production rates of 1,045 boe/d, he goes on. Those four wells follow six wells that Lonestar placed on stream in 2018. The four wells this year had increased lateral lengths of 18% compared with the 2018 wells and outperformed the type curve by 19%.

Lonestar Resources also began flowback operations on three wells on its Sooner property in DeWitt County, which it acquired last November. The Buckhorn No. 4H, which has 6,157 perforated feet, tested at 542 bbl/d oil, 1,311 bbl/d NGLs and 9,857 Mcf/d gas (3,496 boe/d) on a 24/64-inch choke. The Buckhorn 5H (5,981-foot lateral) tested at 3,333 boe/d on a 22/64-inch choke and the Buckhorn 6H (6,021-foot lateral) tested at 3,549 boe/d on a 22/64-inch choke.

“We have built a fairly substantial position in the core of the Eagle Ford, and we have built the infrastructure,” Bracken maintains. “We believe we will continue to be dominant in the Eagle Ford. Scale and success breeds more of the same.”

Eagle Ford Entry

Houston-based Callon Petroleum Company has been a pure Permian Basin operator, with activity in both the Midland and Delaware sub-basins, but will be adding the Eagle Ford Shale play to its portfolio soon. Callon announced in July that it has reached a definitive agreement to acquire Carrizo Oil & Gas in an all-stock transaction valued at $3.2 billion. The deal is expected to close in the fourth quarter.

“We are excited about this transformational transaction, creating a differentiated oil and gas company by integrating core asset bases in premier basins,” Callon President and Chief Executive Officer Joe Gatto says. “Together with Carrizo, we will accelerate our free cash flow, capital efficiency and deleveraging goals through an optimized model of large-scale development across the portfolio. We will also benefit from leading cash margins to navigate commodity price volatility and allow for reliable, continuous development of the combined asset base.

“With a deep inventory of high rate-of-return well locations in well-established areas and substantial upside opportunities for organic inventory delineations, we will be able to drive differentiated growth deploying our life-of-field development model for many years to come,” Gatto continues.

In creating what it calls “a premier oily mid-cap” company, Callon Petroleum views the Eagle Ford play as a “highly efficient free cash flow machine with repeatable, low-risk inventory for re-investment.”

The acquisition increases Callon’s scale with more than 100,000 boe/d of pro-forma first-quarter 2019 production and 200,000 net acres in the Permian Basin and Eagle Ford. In a press release, the company stated that the addition of the Eagle Ford acreage will allow it to allocate more capital to the Permian Basin than the combined Callon and Carrizo standalone development plans, an opportunity that results from the robust free cash flow from Eagle Ford production.

Adding Carrizo’s 45,000 acres in the Delaware Basin to Callon’s already existing leasehold provides “complementary high-quality assets to better compete in this dynamic basin,” the company says in the release. But it also claims its entry into the Eagle Ford will “further diversify end market exposure by providing additional access to Gulf Coast and waterborne markets receiving a premium to West Texas Intermediate pricing.”

Callon will gain some 77,000 net acres in the Eagle Ford with the acquisition. Carrizo drilled 11 gross (10 net) operated wells during the second quarter and completed 30 gross (27 net) operated wells in the Eagle Ford. Production from the play was more than 41,300 boe/d for the quarter, up 5% versus the prior quarter, and the company had 23 gross (21 net) operated Eagle Ford wells in progress or waiting on completion as of the end of the second quarter.

Crude oil accounted for 81% of Carrizo’s Eagle Ford production during the second quarter. The company, which is operating one rig in the Eagle Ford, credited its high well-count development pads for driving the strong growth. Carrizo says it brought on production a 13-well multipad in its Brown Trust project area in June, achieving a peak 30-day rate of 11,100 boe/d (85% oil) from restricted chokes. Then in July, Carrizo brought on production from a 14-well multipad in its Irvin project area. The Irvin product achieved a peak seven-day rate of more than 8,000 boe/d (93%) from restricted chokes. The average lateral length of the wells was approximately 6,100 feet and 6,700 feet for Brown Trust and Irvin, respectively, according to the company.