SAN ANTONIO—Low oil prices have not deterred Eagle Ford operators from wringing even more out of the South Texas shale at lower costs.

To bring on better-flowing wells at lower costs, they are using every trick in the book: upgrading drilling and frack designs, bringing the digital oilfield to bear and analyzing “big data.” They intend to keep making step changes in every single step along the spud-to-rig release pathway, said executives from Marathon Oil Corp. (NYSE: MRO) and Noble Energy Inc. (NYSE: NBL), who bookended Hart Energy’s recent DUG Eagle Ford Conference & Exhibition with opening and closing keynotes that detailed just how efficient their companies have become.

Marathon called its best effort “the new pacesetter well.” Others at DUG said they are chasing the elusive perfect well.

“When trade magazines start to talk about optimization, that might be a sign the party’s over. But I think it may still be time to pop some Champagne corks,” said Dale Kokoski, regional vice president for Eagle Ford, who manages Marathon’s technical team.

Summing up all the things the company is doing to add value to the Eagle Ford, he said, “We’ve got this. But there’s always room for improvement, so what I challenged my group to do is pursue a slower level of drilling, but a higher level of [field drilling and production] management.”

In seven or eight years, the Eagle Ford went from contributing next to nothing to more than 1.5 million barrels of oil equivalent per day (MMboe/d) by 2015, or the equivalent of 15% of U.S. production, he said.

Recently the rig count has declined and drilling permits are off their peak as well, foretelling a continued slowdown. But operators have faith in the play. “What if the price of oil had not dropped? This inventory is not going away,” Kokoski said.

“We’re not making a choice of drilling or not drilling a well; we’re making a choice of how we want to drill a well. We are going from a drill-and-complete environment to one of managing the 1,400 wells we will operate. We’ve gone from hyper-growth to managing production while still growing.”

In second-quarter 2016, Marathon’s average completed well cost was about $4.2 million, down 30% year-over-year. Drilling cost per foot fell to $100 from $150 the year prior, Kokoski said. “These are the things that have allowed us to survive. We’re now completing a well in 25% of the time it took us when we first started in 2012.”

Marathon is focused on achieving efficiency at scale and making sure those gains are repeatable and sustainable, he said. It entered the play with a splash in June 2011 by buying Hilcorp’s Eagle Ford assets for $3.5 billion. So from a standing start at zero, Marathon has proved it can be as nimble as an independent, Kokoski said.

From 2012, MRO has improved drilling footage per day 100% through optimizing every step of the process and using high-spec rigs. It has seen a 60% reduction in flat times by using multiwell pads, offline cementing and walking packages. It has cut the time it takes to fracture stimulate by 75% since 2012 by using sliding sleeves, faster frack sand offloading in the stacked and staggered laterals, and zipper fracks.

“We’ve moved to the digital oilfield and we’ve asked some of our best operations people to turn in their hard hats for time behind a computer. Since 2012, Marathon has reduced its production operating costs by half. We call it ‘pump by priority.’ We cannot continue to keep adding more people and trucks …,” he said.

“It’s not about finding bigger IPs. It’s about finding a few more barrels a day over many years—this remains a very satisfying endeavor.”

Chip Rimer, senior vice president for U.S. onshore, Noble Energy, addresses attendees of DUG Eagle Ford in San Antonio. (Source: Hart Energy)

Noble Energy is creating similar successes, said Chip Rimer, senior vice president for U.S. onshore. The company now claims to have drilled five of the 10 best wells in the Eagle Ford after being in the play only a year since its July 2015, $2.1 billion acquisition of Rosetta Resources Inc. In that deal, it picked up 50,000 net acres in the Eagle Ford, primarily in Webb County, Texas.

“We’re being very disciplined and we look at our wells on an NPV [net present value] basis. Our engineering and operations folks meet weekly. We ask, ‘How do you manage this? How do you improve? How do you create the best value possible?’”

Its Eagle Ford production is now 67 Mboe/d or about 25% of its U.S. production in second-quarter 2016. Some 18 wells have been completed in the Lower Eagle Ford since the deal closed. The Gates Ranch lease is its biggest asset where, in the South Gates Ranch area, production history supports downspacing from 1,000 ft to 750 ft. The Gates Ranch North wells, meanwhile, are tracking above a 3 MMboe type curve—more than 3x what was expected.

One of the first things Noble did post-acquisition was get its teams in the Eagle Ford and Marcellus to compare notes to drive step changes through every part of the process of enhanced completions, Rimer said. “We needed to change, to use more proppant, more fluids and basically open up more rock,” he said.

To that end, the company’s frack stages have tighter cluster spacing of 20 ft to 40 ft vs. 80 ft previously. “We were in the range of 35 to 45 bbl/ft and 800 lbs of proppant before. Now, we are closer to 20 to 40 ft frack clusters and our proppant is 2,000 to 2,220 lbs/ft,” he said.

“What excites me most is the way our guys are working together and challenging each other. We’re lucky to have the fiscal structure to allow this to happen. The Eagle Ford is a value for our company, our state and our country.”

Leslie Haines can be reached at lhaines@hartenergy.com.