E&P companies must deal with the new energy reality: low commodity prices and an oil and gas oversupply offset by reduced costs and better well design. In a world such as this, they just need to behave prudently and find new opportunities, speakers said at Hart Energy’s recent DUG Eagle Ford Conference & Exhibition held in San Antonio.

For its part, the Eagle Ford Shale may be down, but it is not even close to out. Early findings from a new study unveiled at the con¬ference by the University of Texas’ Bureau of Economic Geology indicate the play holds 10 billion barrels (Bbbl) of recoverable oil and 34 trillion cubic feet (Tcf) of recoverable gas at current prices.

The play will support 80,000 more wells using today’s technology, the UT study esti¬mated. And, about 1,000 drilled but uncom¬pleted wells await completion in the near term.

In the Eagle Ford, Marathon Oil Corp. has achieved a 100% improvement in drilling feet per day and a 60% reduction in flat times since 2012. It’s pared stimulation days per well by about 75% and more than doubled average completion stages per day over the same time period.

‘Pump by priority’

Today’s depressed prices have not deterred Eagle Ford operators from wringing even more out of the South Texas shale, and at lower cost. To do so, they are using every trick in the book: upgraded drilling and frack designs, digital oilfield practices and “big data.” They intend to keep making step changes through every phase of the spud-to-rig release path¬way, said executives from E&Ps operating in the play.

Marathon Oil Corp. called its best effort “the new pacesetter well.” Others said they are chasing the “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, Marathon regional vice president, Eagle Ford, who manages the technical team. Summing up all of Marathon’s methods for adding value, 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 produc¬tion] 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, foretelling a continued slowdown. But operators have faith in the play. “What if the price of oil had not dropped? This inven¬tory 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 man¬aging the 1,400 wells we will operate. We’ve gone from hyper growth to managing produc¬tion 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 effi¬ciency 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 Energy Co.’s Eagle Ford assets for $3.5 billion. From a standing start at zero, it has proved it can be as nimble as an independent, Kokoski said. The company has improved drilling footage per day by 100% since 2012 by optimizing every step of the process and using high-spec rigs. It has reduced flat times by 60% via multiwell pads, offline cementing and walking packages. It has cut the time it takes to fracture stimulate by 75% by using sliding sleeves, faster frack sand offloading in the stacked and staggered laterals and zipper fracks. Overall it has cut production operating costs by half.

“We’ve moved to the digital oilfield, and we’ve asked some of our best operations peo¬ple to turn in their hard hats for time behind a computer. 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.”

A quick study

Noble Energy Inc. is creating similar suc¬cesses in the Eagle Ford, said Chip Rimer, senior vice president, U.S. onshore. The com¬pany claims to have drilled five of the 10 best wells in the shale—and this after being in the play only a year, since its July 2015, $2.1 bil¬lion acquisition of Rosetta Resources Inc. In that deal it picked up 50,000 net acres in the Eagle Ford, primarily in Webb County.

“We’re being very disciplined, and we look at our wells on an NPV basis. Our engineer¬ing 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 67,000 boe/d or about 25% of its U.S. production in second-quarter 2016. Noble has completed some 18 wells in the Lower Eagle Ford since the Rosetta deal closed. The Gates Ranch lease is its biggest asset; in the South Gates Ranch area, production history supports downspac¬ing from 1,000 to 750 feet. The Gates Ranch North wells, meanwhile, are tracking above a 3 MMboe type curve—more than three times what was expected.

One of the first things Noble did post-acqui¬sition was get its teams in the Eagle Ford and Marcellus shales to compare notes in order to drive improvement in enhanced completions, Rimer said. “We needed to change, to use more proppant, more fluids and basically open up more rock.”

To that end, the company’s frack stages have cut cluster spacing by a quarter to a half. “We were in the range of 35 to 45 bar¬rels per foot and 800 pounds of proppant before. Now, we are closer to 20- to 40-foot frack clusters [vs. 80 feet previously], and our proppant is 2,000 to 2,220 pounds per foot,” 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.”

Left, Noble Energy’s Gates North wells are tracking above the 3 MMboe type curve, with more than 3x the planned EUR. Right, Sanchez Energy Corp.’s manufacturing approach and direct sourcing have helped drive its cost structure lower than most of its Eagle Ford peers.

Debundling services

With capital discipline and the right approach, Eagle Ford operators such as San¬chez Energy Corp. are still making wells economic in a $45 to $50/bbl oil price envi¬ronment.

Sanchez is driving returns in acreage other companies have overlooked, according to Chris Heinson, the company’s COO. As with many E&Ps, Sanchez rapidly expanded before the downturn. The company built a 200,000-net-acre position after buying Hess Corp.’s holdings in 2013 and Royal Dutch Shell Plc’s Catarina Eagle Ford assets in 2014. Since then it’s chopped its well costs by more than half to $3.3 million from $8.8 million.

The company’s basin-centered, unit-based approach and its process-oriented way of operating have played a role in what Heinson said are “sustainable” cost savings. But its direct-sourcing capabilities—seeking out ser¬vices and supplies on its own—have also been a driving force.

“Direct sourcing plays a big part in why we are able to achieve what we are able to achieve,” Heinson said.

The concept is simple; the difficulty lies in execution, he said.

An example is debundling of hydraulic frac¬turing-related services.

In the past, Sanchez used frack service vendors for acid, sand, fuel, logistics and chemicals, but now it secures services on its own. Securing contracts with mines for sand and with other companies for chemicals went smoothly, but more effort was required when it came to logistics, particularly trucking coordination.


“We hit the wall in 2014 on the pres¬sure-pumping side,” Heinson said. The com¬pany wanted to bid out horsepower only on pressure pumping but found companies were not willing to budge from traditional models. Eventually, Sanchez connected with a start-up to get the job done.

In early 2014, before it debundled frack ser¬vices, Sanchez was spending about $3.5 mil¬lion for a frack job. Since taking more control of the process, average costs have fallen to about $1 million, Heinson said.

The task wasn’t easy. For one, internal infra¬structure needed to be built to manage the logistics.

“The service companies are quite good at managing those logistics for you. It takes a big effort to bring it in-house,” he added, “but we’ve done that and made that transformation successfully.”

The company’s manufacturing approach has also led to savings on the process side. Instead of having two project engineers including a project manager and a wellsite manager coor¬dinating activities, Sanchez moved to having a project manager with a completions support team. Now the company has a team of project engineers, each focused on specific areas such as frack prep, flowback, mill-out and water transfer, with each looking for drilling and operational efficiencies.

“They’re getting quite good at optimizing,” Heinson said. “In 2014 we were at $7.4 million [drilling and completion costs] per well. In this downturn we’ve been able to reduce our costs to $3.5 million.”

Sanchez has also reduced its rig release-to-rig release time, or total cycle, to fewer than 10 days for its Catarina asset. One rig is capable of drilling 40 wells per year on the company’s assets. Total drilling costs have fallen 54% since first-quarter 2015 to $1.3 million in the second quarter of this year.

“By focusing and really optimizing what we’re doing here, we’ve been able to optimize and turn areas that most people perceived as Tier 2 into Tier 1 quality assets,” Heinson said.

Going long

Extended laterals are what is driving value for Chesapeake Energy Corp. The company has lowered its well costs in the Eagle Ford by about $4 million from $7 million to $8 million, despite laterals that are twice as long as they were previously, said Jason Pigott, executive vice president of operations for Chesapeake’s southern division.

The company’s strategic move to longer laterals, which averaged 9,300 feet in sec¬ond-quarter 2016 with a year-end goal of 10,500 feet, has reduced development costs by 60% per foot. Generally, longer laterals are more expensive but increase performance.

“This has been a transformative year for us in the Eagle Ford,” Pigott said. “We started the long lateral technology company a few years ago, and it’s taken time to get rolling, but you can see the impact of it.”

Chesapeake’s rate of return for its 2016 development program is about 25% at a lateral of 5,300 feet and about 65% at 10,500 feet. Total well cost per lateral foot has fallen from an average of $1,000 at year-end 2014 to $430 in second-quarter 2016, he said. The company aims to end the year at $405 per 1,000 feet.

Extended laterals provide 2-for-1 net present value at 30% less well cost than two equivalent wells, according to Pigott, who pointed out that the efficiencies gained trump small reductions in performance beyond 6,000 feet.

“That’s why today we are committed to the Eagle Ford,” he said. “This has transformed the play for us.”

Two years ago, 58% of Chesapeake’s Eagle Ford portfolio was comprised of wells with lateral lengths between 5,000 feet and 7,500 feet. In 2016, just 16% of laterals fall into that span as horizontal wells of greater than 10,000 feet take over.

Chesapeake wants to drive its inventory of laterals even longer in 2017. Its goal is to have 72% of its laterals be more than 10,000 feet. This year, 41% of its laterals are at that length. “We’re getting wells that are 3,000 feet longer. We’re drilling them faster,” Pigott added.

Such feats include an eight-day spud-to-rig release time and a single-well record length of 14,289 feet. “The money is made in the hor¬izontals,” Pigott said. “So as we go longer, we’re diluting the cost of the total drilling expense. The record today is the normal for the future.”

The company has also made strides on the completions side with high-intensity fracture designs. Chesapeake typically uses about 1,200 pounds per foot. However, in the Eagle Ford, he said, the company is seeing 25% gains, pumping 2,400 pounds per foot. It plans to boost this to 3,000 pounds in an effort to fur¬ther improve gains across its acreage.

Chesapeake still has plenty of room to expand in the play, considering only 25% of its Eagle Ford position is developed. It estimates it has about 5,260 locations remaining to drill.