Second only to the mighty Permian Basin in terms of combined oil and natural gas output, the Eagle Ford Shale ranks as America’s third largest tight oil basin and fourth most productive shale gas basin. So is it an oil or a gas play?

With distinctive oil, dry gas, and gas condensate windows defined by formation depth, pressure and temperature characteristics, the Eagle Ford is not an either/or scenario. To put it simply, the correct answer is “all the above.”

And that inherent optionality continues to serve operators well, providing them the flexibility to selectively develop liquids, gas, or both. The fact that the Eagle Ford is overlaid by the Austin Chalk and other oil and gas-rich formations gives South Texas operators even more choices.

Baytex Energy Corp. is developing a 269,000-acre, liquids-rich position it acquired two years ago after purchasing Ranger Oil to complement its light and heavy oil operations in Alberta and Saskatchewan. The company is spreading the drill bit across thermal maturity windows with black oil and condensate phases while persistently seeking efficiency gains, says Chief Operating Officer Chad Lundberg.

The Calgary-based company, with a U.S. headquarters in Houston, plans to invest $520 million in 2025 on 41 net wells, including 37 in the Lower Eagle Ford and four in the Upper Eagle Ford, along with well refracs and infrastructure.

Diverse Strategies

Like other regions, the Eagle Ford is seeing its share of consolidation as larger public companies further expand their footholds and smaller and mid-sized independents pick up complementary properties.

In November, the play’s biggest producer, ConocoPhillips, closed on a $22.5 billion acquisition of Marathon Oil and its 300,000-plus acres in South Texas. The second-largest gas producer and third-biggest oil producer in South Texas, Crescent Energy Co., followed up on its mid-2024 acquisition of SilverBow Resources by adding the Eagle Ford assets of Ridgemar Energy.

Other Eagle Ford players are also taking advantage of the shifting landscape. Tidal Petroleum Inc. continues to add to its position with peripheral acreage and divested assets in the basin’s oil window. Strand Energy LLC is using development approaches typical of Eagle Ford horizontals to exploit traditional shallower vertical tight sands. Meantime, Warwick Investments is building on its successful transition from non-operator to operator, leveraging an acreage position grown through 15 successive Eagle Ford acquisitions over the past decade.

Baytex’s Drilling Focus

Focused mostly in Gonzales, Fayette and Lavaca counties, drilling targets typically include wells with average choked-back 30-day initial productivities of 700-800 barrels a day, reinforcing Baytex’s overall daily production of about 90,000 barrels of oil equivalent in South Texas.

Baytex Energy’s $520 million capital budget in the Eagle Ford this year includes drilling 41 net wells, concentrated in the Lower Eagle Ford in Gonzales, Fayette and Lavaca counties, along with pumping several well refracs.

Baytex is expanding its drilling focus from exclusively black oil phases to volatile oil windows. Running two rigs and one frac crew in the Eagle Ford, Lundberg says the company anticipates an additional 7% improvement in drilling and completion costs on top of 8% realized in 2024 from longer laterals and operational improvements. Lateral lengths on its wells now extend to 9,500 feet on average.

“We have pushed as long as 14,000 feet in different areas and continue to see capital efficiency gains by drilling longer,” he comments. “It just makes sense with all the fixed costs.”

Regarding well designs, Baytex has gone from 6.0-inch to 5.5-inch casing and altered stage spacings with the help of machine learning, Lundberg explains. “We are continually running multivariate regression model machine learning basically behind the scenes on all the wells in the Eagle Ford,” he says.

Lundberg adds that completion and production improvements resulting from tighter stage spacings first used in the second half of 2024 will continue into the new year.

Led by an operations team that calls “exceptional in every aspect,” assessments of gas production, lift deployment and compression adjustments have created a 10% overall improvement in base decline.

The company also continues to experience gains in spud-to-rig release times, surpassing 3,000 feet drilled per day. A record three-casing string “deep” design was drilled at a rate of more than 1,800 feet a day, and the company set a frac pumping record of over 19 hours a day in 2024, buttressed by improvements that included automated valve greasing, which alone increased pump times by one to two hours a day.

Although the company would consider merger and acquisition opportunities, the focus for now will continue to be on improving its base business and adding bolt-on assets to fill out existing positions.

“Sometimes it is tricky to make a business case for M&A other than you are just getting bigger,” Lundberg says. “It would have to be a true value-add proposition and we would think about it, but we are not being aggressive in the M&A space right now.”

Eagle Ford Refracs

Tidal Petroleum is acquiring tracts and putting together drilling units as merging companies divest of non-core, peripheral Eagle Ford assets and some smaller capital-strapped operators let go of undeveloped mineral holdings, says President Lee Novikoff. 

Tidal Petroleum drilled six Eagle Ford wells and participated in 11 others in 2024. This year, the company expects to drill 12 wells, including a development scheduled for the first quarter targeting the liquids-rich Lower Eagle Ford in McMullen and Fayette counties.

With a hydrocarbon mix that is 80% liquids, the San Antonio-based company has grown from about 15,000 acres along the Eagle’s Ford northern edge to 25,000 acres over the past year. Monthly production is expected to eclipse 120,000 barrels during the first quarter of 2025.

Depending on location, tracts come with opportunities for new wells and refracs, and Tidal is realizing gains from both, Novikoff relates. Refracs typically work better where the oil is deeper and original frac treatments are older, he explains, with modern completions that include 3,000 pounds of sand per foot yielding good results in wells completed a decade or more ago with 800 pounds on longer spacings.

Where possible in its Eagle Ford lease position, Tidal Petroleum is fracturing new-drill wells in close proximity to older wells suitable for refracturing. In some cases, refractured older wells produce at rates comparable to their original stimulation performance.

When considering refracs, the company, looks to drill new wells nearby where feasible and pump refracs along with the new-well completions to save money. In one area, two older wells drilled 1,200 feet apart were barely producing.

“We drilled a new well between them, fractured it and then refractured the other two at the same time. All three wells came in really nicely,” Novikoff says. “We tapped into a bunch of rock that was not exposed before. Our fracs were better, the pressures were higher, and the velocity was faster. It opened the older wells back up. I actually look for the two older wells to recover about as much after refracturing as they did after their original fracs.”

Tidal has also experienced improvements in some older wells from parent-child well contacts with new offset wells. “In the past, ‘frac hit’ was a bad word,” Novikoff remarks. “Now, if the frac defense is doing well, you will see a slight recharge. We have had some older wells that were producing only 10-15 bbl/d, but after an offset frac, they now produce without a pump. They are flowing.”

As a case in point, he references a well in Karnes County that had been on pumpjack but subsequently placed on gas lift after nearby stimulations reinvigorated production.

In 2024, the company drilled six wells and participated in 11 others. This year, Novikoff expects to drill 12 more wells, including a development slated for the first quarter for liquids-rich benches in McMullen and Fayette counties, where the Lower Eagle Ford remains the primary target.

Conventional Tight Sands

Focusing on drilling horizontally in traditional conventional tight sands, Strand Energy is developing the oil-saturated San Miguel on 6,000 acres in the Faith Ranch in portions of Dimmit, Maverick and Webb counties near the Mexico border, says President Kent Brock. 

Strand Energy is drilling 3-D seismic guided horizontal wells in conventional tight sands targets in the oil-saturated San Miguel on the Faith Ranch in Dimmit, Maverick and Webb counties near the Mexico border.

Much of Brock’s experience included conventional drilling and fracturing of tight sands in the Rockies, Permian, and East Texas. Armed with extensive 3-D seismic, his company still drills vertically in East Texas and along the Texas Gulf Coast and has drilled horizontally in the Eagle Ford and Cline shales.

“We have also drilled a few horizontal Austin Chalk wells, but our sweet spot is tight sand conventional reservoirs that can be better exploited horizontally. That is what led us to the San Miguel,” Brock explains.

Blackbrush Oil & Gas of San Antonio and Endeavor Natural Gas of Houston were the first to apply unconventional techniques to the bench and prove it up, he says. Strand first contemplated the play earlier while drilling the Eagle Ford in Zavala County.

Eventually, a Strand shareholder offered the opportunity to lease acreage on the western portion of the ranch. Chesapeake Energy had drilled some 300 wells on the ranch earlier targeting deeper benches, which provided a trove of 3-D data to help guide geosteering in a thin play averaging only 20-25 feet in thickness and surrounded on each side by a silky sand.

Since 2023, Strand has drilled three four-well pads. A fourth pad is now under construction with drilling scheduled to get under way in February. Full development potential on the position could be up to 34 wells, with the company looking to drill its first 9,000-10,000 foot lateral later this year.

Total vertical depths range from 3,600 to 3,800 feet to tap the shallow cretaceous sand just above the Austin Chalk. The play has 20% porosity and tight permeability in the core with a lot of oil in place. The sand is oil-productive down to a certain depth and then starts transitioning to gas downdip, Brock explains.

Since 2023, Strand has drilled three four-well pads. A fourth pad is under construction with drilling expected to get under way in February. Full development potential on the position could be as many as 34 wells. The company started drilling 5,000-6,000 foot laterals to establish a learning curve and anticipates its first 9,000-10,000 foot lateral later in the year, according to Brock.

Stage spacings for completions are ±200 feet with 250,000-350,000 pounds of sand pumped per stage using linear gel with 30-50 mesh sand instead of slickwater, he details.

Vertical wells drilled in the 1960s and 1970s produced only about 10,000 barrels each. The type curve for a 5,000-foot lateral is based on 30-day IP of 300 barrels of oil and 300 Mcf of gas per day. Estimated ultimate recovery is 300,000 barrels of oil and 500 million cubic feet of gas.

The company’s lease goes to the Rio Grande on the south side. Brock says Strand recycles some frac water, but gets the rest from parties with supplies fed by the river.

Growing Through Acquisitions

Warwick Investment Group views the Eagle Ford as a key acquisition area. Today, the firm has over 70,000 acres in the basin with an intent to continue its consolidation and expansion. Warwick has been active in the Eagle Ford for over a decade.

Since entering the play as a non-operator in 2014, Warwick Investment Group has closed on 15 transactions in the Eagle Ford. The company began operating in 2021 after buying an Eagle Ford asset from Rosewood Resources. In December, Warwick was drilling the company’s 12th well of the year and completing two refracs, with another 17 planned in 2025.

Shown here is the ribbon cutting ceremony for Warwick’s new Eagle Ford office. CEO Kate Richard is holding the scissors.

Founded in 2010 by Kate Richard, Warwick is an SEC registered investment adviser with $2.5 billion in managed assets for pension funds, endowments, insurance companies and families globally. 

“As a firm, we view the investment opportunity in U.S. upstream energy as compelling for investors and critical to the strategic national interest of the United States. We invest in the Eagle Ford because the basin is proven, well-situated close to the U.S. refinery and petrochemical complex, and has a stellar mix of oil, natural gas and natural gas liquids,” Richard says.

In 2024, Warwick completed its 15th transaction in the Eagle Ford since entering the play in 2014 acquiring assets in Karnes and Live Oak counties. The company has operated in the Eagle Ford since its 2021 acquisition of the Eagle Ford assets of Rosewood Resources.

“Our operations team is focused on operations innovation in the Eagle Ford. We are seeing real results in the field through drilling and completions as we come into known rock and optimize extraction and production,” Richard remarks.

“In 2024, we drilled some of the fastest Eagle Ford wells drilled by any operator in the basin. We are doing a number of cemented liner refracs, targeting older vintage slim hole wellbores, across the position. We think there is significant potential to conduct refracs as well,” reports co-chief information officer Ian Rainbolt.