BPX Energy sees decades of production ahead in the Eagle Ford shale as it redevelops fields in South Texas using EOR and refracking techniques.
“We’re thinking about the long term of the asset and how do we get EOR to work because we don’t want to be here for five years,” Shawn Holzhauser, vice president of development for BP Plc’s onshore U.S. subsidiary, said at Hart Energy’s SUPER DUG Conference & Expo in Fort Worth on May 12. “We want to be here for 20 years, 30 years, and I think there’s plenty of resource to do that.”
The company taking the resource may not be named BPX. Both the subsidiary and the parent company have been the subject of takeover speculation. The Financial Times reported that Shell, Chevron, Exxon Mobil, TotalEnergies and ADNOC have looked at BP. An analysis by Hart Energy suggested BP’s U.S. shale properties could be worth $10 billion.
Holzhauser said at SUPER DUG any takeover decisions would be up to BP CEO Murray Auchinclosss.
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BPX is refracking about 25 wells in the Black Hawk part of the shale, Holzhauser said, with a couple of wells delivering about 4,000 bbl/d.
“Mainly that’s been in our oily areas,” he said. “We see great returns, triple digit, 100% rate returns in that area and we're expanding that out.”
That expansion will go into gassier areas, where BPX expects similar returns, he said.
“We're really, really excited about that project and what that's going to bring in the future,” he said. “To round that out with the whole discussion on recovery factors, we think combining primary development, drilling and redevelopment drilling and then refracs, we can get all the way up to 25% recoveries from the assets.”
BPX is running three rigs now, one from Helmerich & Payne and two from Nabors. It also employs a Halliburton e-fleet that is yielding excellent results, setting a record in the fourth quarter for most hours pumped in a month, Holzhauser said.
The work goes on in tight spaces.
“These wells are 165 feet away from existing assets,” he said. “It’s like trying to thread a needle from 4 miles away. Some of the most complicated patterns in industry exist in this area where we’re weaving wellbores in between other wells.”
Because these areas have been fracked once already, the new wells are hitting frac sand left behind, which increases instability, Holzhauser said. “It’s no different than drilling in unconventional sand in the Gulf of Mexico, or Gulf of America. It’s all unconsolidated. There’s no strength to it. It is just coming back in our return.”
Working so close to existing wells means considering not just the distance to existing wells but also how those wells were drilled.
“We’re aiming at wells that are both far away from offset wells as well as have legacy completion designs,” he said. “The recipe obviously gets way more complicated than that when you start looking at ‘What does the wellbore integrity look like, what was the design of the original?’”
After the well is drilled, complications continue. Hitting an existing well might require an expensive cleanup.
“We’re monitoring the offset wells and their responses and then trying to figure out how we respond to that in real time so that we’re not overstimulating our new well or actually doing damage to your existing assets,” he said. “It’s important to take into consideration how you’re shutting in the wells, how you’re managing the frac stimulative live and really have a good game plan to not bash or blast those legacy wells.”
The payoffs are multiple, Holzhauser said. BPX’s performance measured in thousands of barrels of oil equivalent per lateral foot is far ahead of competitors, and the learnings can be applied to every new well.
The key is “understanding how we can achieve both drilling these wells under technically challenging environments with degree of difficulty of wellbore stability that doesn't exist in a conventional development well,” he said. “As we're drilling these more complicated wells, we're actually learning how to execute better and better and better.”
