SAN ANTONIO—With capital discipline and the right approach, companies such as Sanchez Energy Corp. (NYSE: SN) are still making wells economic in a $45 per barrel (bbl) to $50/bbl oil price environment.
Sanchez is driving returns in acreage other companies have overlooked, according to Chris Heinson, the company’s COO. Sanchez has chopped its well costs by more than half in the past few years to $3.3 million from $8.8 million prior to buying its Catarina position in the Eagle Ford Shale.
As with many E&Ps, Sanchez rapidly expanded before the downturn. The company built a 200,000 net acre position after buying Royal Dutch Shell Plc’s (NYSE: RDS.A) Catarina assets in 2014 and Hess Corp.’s (NYSE: HES) holdings in 2013.
But Sanchez Energy is not alone in driving down costs.
Chesapeake Energy Corp. (NYSE: CHK) has lowered its well costs in the shale play by about $4 million from a range between $7 million and $8 million, despite wells that run twice as long as previous wells, said Jason Pigott, executive vice president of operations for Chesapeake’s southern division.
The company’s strategic move to longer laterals, which were on average 9,300 ft in second-quarter 2016 with a year-end goal of 10,500 ft, has reduced development costs per foot by 60%. Generally, longer laterals are more expensive but increase performance.
The two were among the speakers during Hart Energy’s recent DUG Eagle Ford Conference & Exhibition, shedding light on how capital efficiencies are leading to competitive returns as the industry endures one of the worst downturns in its history. Lower commodity prices, which have chomped away at profits, have driven E&Ps to adjust strategies in their quest for higher returns.
Sanchez Energy’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, directly seeking out services and supplies on its own, have been one of the driving forces behind falling costs.
“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, he said; however, difficulty lies in execution.
Take, for example, debundling hydraulic fracturing-related services, a task the company took on to lower service costs.
In the past, Sanchez used frack services vendors for acid, sand, fuel, logistics and chemicals, but moved to secure the services itself. The job was met with few challenges when securing contracts with mines for sand and with other companies for chemicals. More effort was required when it came to logistics, particularly with trucking coordination, he said.
“We hit the wall in 2014 on the pressure pumping side,” Heinson said. The company wanted to bid out horsepower only on pressure pumping but found companies were not willing to budge from traditional models of doing business for various reasons, so Sanchez ultimately connected with a startup.
Before debundling frack services, Sanchez spent roughly $3.5 million for a frack job in early 2014. Since taking more control of the process, costs have fallen to an average of about $1 million, Heinson said.
The task wasn’t easy. For one, internal infrastructure 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 process approach has also led to savings on the process side. Instead of having two project engineers including a project manager and a wellsite manager coordinating activities, Sanchez moved in 2014 to having a project manager with a completions support team, he said. But now the company has a team of project engineers each focused on specific areas, such as frack prep, flowback, millout 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 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 less than 10 days in its Catarina asset. One rig is capable of drilling 40 wells per year on the company’s assets, he added. Since first-quarter 2015 total drilling costs have fallen 54% to $1.3 million in second-quarter 2016.
“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 1quality assets,” Heinson said.
For Chesapeake, extended laterals are driving value.
“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 impacts of it.”
Chesapeake’s rate of return for its 2016 development program is about 25% at 5,300 ft and about 65% at 10,500 ft. 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 $405/1,000 ft.
Extended laterals provide 2-for-1 net present value at 30% less well cost than two equivalent wells, according to Pigott, who pointed out efficiencies gained from longer laterals trump small reductions in performance beyond 6,000 ft. “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 ft and 7,500 ft. In 2016, just 16% of laterals fall into that span as horizontal wells of greater than 10,000 ft take over.
Chesapeake wants to drive its inventory of laterals even longer in 2017, with a goal of 72% of its laterals with lengths greater than 10,000 ft. In 2016, 41% of its laterals are at that length. “We’re getting wells that are 3,000 ft longer. We’re drilling them faster,” Pigott added.
Feats have included an 8-day spud-to-rig release and a single-well record length of 14,289 ft. “The money is made in the horizontals. So as we go longer we’re diluting the cost of the total drilling expense. … The record today is the normal for the future.”
Strides also have been made on the completions side with high intensity fracture designs. Chesapeake typically uses about 1,200 pounds per foot (lb/ft). However, in the Eagle Ford, he said the company is seeing 25% gains, pumping 2,400 lb/ft. Plans are to increase this to 3,000 lb/ft in an effort to further improve gains across its acreage.
Chesapeake still has plenty of room to grow, considering only 25% of its Eagle Ford position is developed. The company believes it has about 5,260 remaining locations to drill.
Velda Addison can be reached at firstname.lastname@example.org.
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