Some may think it’s all about the oil in the Permian Basin, where production has surpassed 3.8 MMbbl/d and continues to rise as operators perfect drilling and completion techniques while driving down costs.
But if a company operates in the Delaware Basin, “it really is all about the water,” said Rita Behm, regional engineer manager for Cimarex Energy Co., during AAPG’s recent “Global Super Basins 2019: The Permian” conference.
Given disposal needs for the massive amounts of water used during hydraulic fracturing, water management has become a hot topic in the Permian Basin. Behm used a well with a water cut of between 80% and 90% to illustrate how much water is being pulled from the ground to get to oil.
“For one well, 1 million barrels booked for a 2-mile Wolfcamp well in Reeves County, that’s about 8 million barrels of water that you’re going to have to find a home for to dispose of,” Behm said.
A typical saltwater disposal (SWD) well in the Delaware Basin can take about 40,000 bbl/d at its peak, she explained, before illustrating further. Assume an operator is drilling 12 wells per section, equating to about 12 MMbbl of oil. “That’s 100 million barrels of water, or 48,000 barrels of water per day,” she said.
Water, water everywhere
The barrels of water produced continue to mushroom when taking into account batch drilling and zipper fracs, for example. Though such techniques may save money in one area, they could prompt the need for more SWD wells to handle all the water.
“Want to develop two or even four sections together?” she said. [That’s] “50 million barrels of oil [and] 384 million barrels of water. Almost 200,000 barrels of water a day will be coming from one isolated spot. That’s five SWD [wells] running. One SWD [well] is going to cost you about the same for full facility buildout as the same as putting another well into that pilot that doesn’t make any money. These are big dollars.”
As companies in the Permian and other U.S. shale plays work to get a better handle on water and water-related issues, the water market for upstream oil and gas operations is burgeoning. A report released in December 2018 by IHS Markit states the water management market for upstream oil and gas operations in the U.S. was worth an estimated $33.6 billion last year. That is expected to continue growing through 2023 at a 3.9% compound average growth rate.
“Due to a high number of legacy wells and intense levels of ongoing activity, the Permian Basin continues to produce and demand the largest volume of oilfield water among all U.S. onshore regions; water spending in the region is estimated at $12.2 billion in 2018 under our base case assumptions,” according to IHS. “Particularly, U.S. land drilling and completions water demand increased robustly in 2018. Frac water use is expected to grow in the future owing to an intensification of completions design, proppant intensity and longer lateral lengths.”
With all of the water usage comes the potential for big challenges.
‘Biggest drilling hazard’
Andrew Hunter, drilling manager at Guidon Energy, a Blackstone Energy Partners-backed E&P company focused on the Midland Basin, shared insight during the conference on what was called the “biggest drilling hazard in the Midland Basin”—shallow disposal in the San Andres Formation.
Looking at the six core oil-producing counties in the Midland, Hunter said there are more than 2,000 shallow SWD wells. Using rough estimates, he said the industry is disposing of about 2.7 MMbbl/d of water.
“That’s seven times the amount that we were disposing in 2010 before the horizontal revolution,” Hunter said. Given production is expected to rise through 2025, more barrels will have to find a home.
Citing data from the Texas Railroad Commission, Hunter added that there has been a 563% increase in commercial disposal for the six counties in the Midland since 2010. He asked conference attendees to recall lessons taught during high school physics.
“What happens when you add volume to a closed system? The pressure is going to go up,” Hunter said, noting that is what is happening in the San Andres. Overpressurized pockets can cause problems for operators drilling into deeper formations in search of oil, especially if the appropriate mud weight is not properly taken into account for the fracture gradient of the rock.
“Sometimes that rock becomes unstable and will actually cave in on you,” Hunter said. “It’s a real challenge.”
To combat the challenge, Guidon modified its casing design, keeping its mud weight below the fracture gradient, Hunter said. The technique was used while drilling in the Upper Spraberry. But different formations call for different techniques. The company’s solution for Wolfcamp wells included setting a 7⅝ flush joint liner—but at a cost of $600,000 per well.
It could become an expensive problem for the industry moving forward. Spending money on liners won’t change the cause of the issue, which is getting worse with time, Hunter said.
Guidon has been studying deep disposal, but the company’s biggest focus has been on reusing all of its produced water. “We’ve been successful in recycling 100% of our horizontal produced water,” Hunter said. The company sees the future as recycling as much as possible.
The company is not the only one recycling produced water. Many others operating in the Permian Basin and other shale plays across the U.S. are recycling and keeping taps on water usage.
Cimarex has a water recycling facility to help manage water. Behm described it as an “on-the-fly recycling process.” Instead of using pits or tanks aboveground to hold water, the company uses existing pipes to transport and dispose of water.
“We put that in before the well’s drilled, and we use that system to send water on the fly to our fracture treatments. All we have to do is filter and treat it for bacteria,” she said, noting there is minimal capital outlay required.
Exxon Mobil subsidiary XTO Energy, which is working to grow its production in the Permian Basin, is developing an integrated water management system.
“Currently under construction in New Mexico, our system will allow us not only to move water efficiently across a very large acreage position. It will also allow us to treat produced water and reuse it again and again,” said Staale Gjervik, senior vice president of Permian integrated development for XTO Energy.
Modeling water inventory is something every company operating in the Permian Basin should be doing, Hunter added.
For Petrobras, the world’s largest deepwater producer, technology remains on the radar to push forward limits offshore, according to Rudimar Andreis Lorenzatto, the company’s chief technology and production development executive officer.
Technology for reusing flowback and produced water offers solutions for regions facing limited water sources and drought.
Volumes could reach 50 MMbbl/d in just the Permian; all options are on the table.