Delaware Basin Water

[Editor's note: A version of this story appears in the May 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.]

The Permian’s rock is great, but what about all the water? Investors and prospective investors began asking this several years ago about the Midland Basin as shale development ramped up.

In the Delaware, however, the matter of water has taken on the scale of the “Hold my beer” meme. Its outdoing of the Midland is in the math: While water in the West Texas desert for fracture stimulations in the Delaware is as scarce as in the Midland, the ratio of produced water vs. oil in the Delaware can be as much as 7:1. In the Midland, the ratio tends to be 2:1.

A million-barrel-EUR well in the Delaware might also make 7 million barrels (MMbbl) of water. And the next completion job only needs about 600,000 of these.

Michael Hanson, a founding member of investment banker Parkman Whaling LLC, estimated in 2017 that a leading impediment to Delaware production growth was water. This spring, Hanson said that hasn’t changed.

“Sourcing water [for stimulations] isn’t the only problem,” he said. “You’ve got to put the produced water somewhere too, and while recycling may help some operators in the short term, it isn’t a large part of operators’ programs—yet.”

Water played a supporting role in Concho Resources Inc.’s (NYSE: CXO) planned $9.5-billion acquisition of RSP Permian Inc. (NYSE: RSPP) In its slide deck and webcast, Concho cited the “infrastructure optimization benefits” of the deal, including “pad sites, production facilities, water, roads.”

A water conference in Midland in February, hosted by the University of Texas of the Permian Basin, drew more than 400 attendees. Research and consulting firm Wood Mackenzie reported in December, “Today, most [Midland] Permian water is injected into the shallow San Andres zone, but the formation is pressuring up. Some new Wolfcamp wells experience ‘water kicks’ when drilling through zones above the Spraberry.”

Producers, including Laredo Petroleum Inc. (NYSE: LPI), which operates in the Midland, and Callon Petroleum Co. (NYSE: CPE), which operates in both the Midland and Delaware, are injecting into deeper zones, instead, WoodMac added. “This comes at additional cost, but arguably gets ahead of growing pressure issues associated with shallow zones.”

Building A Water Business

Halcón Resources Corp. (NYSE: HK) made Delaware water solutions essential in its acquisition strategy last year, Steve Herod, executive vice president, corporate development, told Investor.

“When we’re looking at acquisitions in this basin, one of the first questions we ask is, ‘What water-handling assets do they have?’” Halcón entered the Delaware in 2017 with a $705-million acquisition and added a $308-million purchase this year. Its interest included that the properties have some surface ownership—for recycling facilities.

Jon Wright, executive vice president and COO, estimates that only the Mississippian Lime play in northern Oklahoma has a higher water cut among U.S. unconventional-resource plays. “That one’s got us all beat.” There, the water-oil ratio is 9:1.

Wright worked the Bakken as senior vice president of operations until the asset was sold for $1.4 billion last year. In the early days of the Bakken, “typically infrastructure was behind the production and water disposal costs were high—trucks lined up for hours, waiting to drop off at a saltwater disposal (SWD) well,” he said.

And the water cut there is low. For example, Whiting Petroleum Corp.’s (NYSE: WLL) Flatland Federal 11-4TFH in McKenzie County has produced 101,000 bbl of water since it came online in October of 2014, compared with 633,000 bbl of oil, according to North Dakota state records.

Wright said, “Water-handling infrastructure must be front-end-loaded. It’s the primary key to reducing your operating costs to an environment comparable to other basins. Our focus from our initial acquisition has been a front-end-loaded water infrastructure that will allow us to grow production without being constrained in any shape or fashion.”

Water handling in the Delaware is slide-worthy: An outline of the program is included in Halcón’s monthly investor presentation—and in the main portion rather than the appendix. For its Hackberry Draw (Pecos County) and Monument Draw (central Ward County) leasehold, it’s placed 50 miles of water pipeline.

Surface ownership for further development of water management facilities totals more than 4,000 acres. Halcon owns its water systems 100%.

Sourcing and handling costs are between 10 and 25 cents a bbl while third-party rates are between 35 and 55 cents for sourcing; for disposal, between 55 cents and $1.50/bbl.

At Hackberry in Pecos County, produced-water injection capacity is 45,000 bbl/d with three SWDs; recycling capacity, 120,000 bbl/d at three facilities. Freshwater-sourcing capacity is 40,000 bbl/d from four wells. Produced- and recycled-water storage capacity is 2.7 MMbbl; freshwater storage, 1 MMbbl.

At Monument in Ward County, the company has 20,000 bbl/d of SWD capacity with three wells; recycling, 40,000 bbl/d at one facility. Freshwater comes from 10 wells for 60,000 bbl/d. Produced- and recycled-water storage is 900,000 bbl; freshwater, 1.1 MMbbl.

The third-party cost for water disposal at Hackberry is $11.43/bbl; Halcon’s operated cost is $1.43/bbl. From a vendor, freshwater would cost $271,000 per completion; Halcon’s self-sourced cost is $149,000/well.

Herod said, “That’s a huge savings as opposed to having this much water getting trucked by a third-party disposal company.”

When looking to acquire in the Delaware Basin, a key question is whether the seller has any water-handling assets already, said Steve Herod, executive vice president, corporate development, Halcón Resources Corp.

Wright added, “Frankly, it’s completely ineffective to not have these types of capabilities in-house when you think about the potential number of wells per square mile.” On 660-foot spacing with four different zones within the Wolfcamp and Third Bone Spring, “you may have 32 wells per section.

“Consider how much water you’re producing from the wells and the volumes you’re using in the completion. It’s astonishing.”

Target: 100%

Halcón’s current completion design uses 600,000 bbl per well, and it’s using recycled produced water for 75% or 450,000 barrels of that currently. Its goal is 100% by year-end.

“We’ve recycled nearly 5 million barrels so far,” Wright said. “These volumes put into perspective the magnitude of what we’re accomplishing.”

In Pecos County, Halcón is working on a permit for a fourth disposal well, giving it 60,000 bbl/d of SWD capacity there. Plans for additional storage capacity will take that up to 3.6 MMbbl.

The target of using 100% recycled water in completions “means we’re not drawing from the aquifer. We have to consider smart management of our water—how can we put it to reuse? It makes sense for us and, more importantly, it makes sense for the environment.”

In water treatment, “we utilize a few proprietary and non-proprietary processes. A number of options are available to operators,” Wright said.

The typical processes focus on removal of dissolved solids and bacteria. Removing the sulfates and bacteria is essential in not creating hydrogen sulfide downhole.

As it’s working toward 100% recycled water on each frack, “compatibility with the surfactants and maintaining gel yields are essential,” Wright said. “We’ve been able to dial in the process. We’re still tapping freshwater, but it’s not unrealistic that, by the end of this year, we’ll be at 100% [recycled].”

A pump transfers water at a Halcón Resources Corp. facility in Pecos County, Texas.

Halcón’s water-oil ratio in its Pecos County area is 5.5:1. North of there, in central Ward, the ratio is 2:1; in western Ward in its West Quito leasehold area, it’s about 3.5:1. Whether landing in the Wolfcamp or Third Bone Springs, the water cut is similar.

“This is a water management program in the Delaware Basin. And we produce a fair amount of oil with that.”

Would Halcón have plenty of recycled water to spare for sale to other operators? “That’s an option,” he said. “It’s all about logistics and how we can feasibly transfer water from the source to a specific frack operation.”

Seaport Global Securities LLC (SGS) analysts reported recently that Halcón has “received a number of bona fide offers” for its entire midstream operation, “but no divestiture plans are being entertained, given infrastructure still remains critical to execution.”

Herod said Halcón’s goal is to sell the entire company, fitting with the build-to-sell model founder Floyd Wilson has used in prior start-ups. The most recent sale, Petrohawk Energy Corp., was closed in 2011 for $15.1 billion.

In late March, SGS analysts had Halcón on a short list of operators “oft-mentioned within the Permian M&A conversation.” Also listed were Callon, Abraxas Petroleum Corp. (NASDAQ: AXAS), Energen Corp. (NYSE: EGN) and Lilis Energy Inc. (AMEX: LLEX).

Meanwhile, Halcón plans to grow production—all from the Delaware—from 4,500 barrels of oil equivalent per day (boe/d) in 2017 to 45,000 in 2020. “We have the assets in place to manage our requirements,” Wright said. “We’re well ahead of it.”

Jacob Harrison an HSE supervisor for Apache Corp., checks valves at a water-recycling facility in the southern Delaware Basin.

Herod added, “It’s critical to do all of that upfront—and not just the water management, but gas gathering and oil handling. You’re spending money, but it’s going to pay off big in the long run when it’s time to sell the company.”

Disposal Bottlenecks

Herod added that "while the Delaware makes considerable amounts of water, the economics are still awesome, which is why there are so many rigs running out there.”

At the end of March, 443 rigs were at work in the Permian Basin—more than half of all 797 targeting oil across the U.S.—according to the Baker Hughes Inc. (NYSE: BHGE) count. The second-most active oil rig count was in the Eagle Ford at 64; the Cana-Woodford, which includes the Scoop and Stack plays, had 61; the Williston Basin, 54.

Some Delaware operators weren’t ready for the water cut. Capital One Securities Inc. analysts reported that Carrizo Oil & Gas Inc.’s (NASDAQ: CRZO) “Delaware water disposal constraints in the first quarter of this year slowed growth out of the gate for [its] relatively new asset.” The stock price was down 27% at the end of the first quarter.

J.P. Morgan analysts wrote, “Carrizo struggles to get out of the penalty box.” One of its wells in Ward County had a 24-hour IP of 765 boe/d, 40% oil, “but what’s notable is this Durham-East Allocation well had a 22:1 water-oil ratio.”

Raymond James & Associates analysts wrote that Carrizo has been encountering “unexpected water disposal bottlenecks in the Delaware, resulting in delays to development activity.”

A new leadership team at Jagged Peak Energy Inc. cited improving its costs “through efficient water transport/disposal” as being on its short list of 2018 initiatives, SGS reported.

Parkman Whaling’s Hanson said, “We’ve heard of large operators expanding their water-recycling efforts, but many operators are either still uncertain about the effects of produced water in frack operations on well performance or too early in the development lifecycle to build out the infrastructure necessary to recycle water.”

Ultimately, though, he expects recycling to be required at some point—“whether by regulations or simple economics.”

SGS projects that, “going forward, it is going to be a dogfight in the Permian to secure pipeline capacity, service equipment, water and people.”

Devon Energy Corp. (NYSE: DVN) received a thumbs-up from Capital One Securities analysts for getting ahead of water demand. “Water in the Delaware Basin is a hot topic and Devon appears to be well positioned. [It] notes it is the biggest water recycler in southeastern New Mexico and is currently using some 80% recycled water for stimulations.

“Moreover, most of Devon’s water logistics are on pipeline, which is a meaningful advantage in the Permian, where the trucking market is especially tight.”

Matador Resources Co. (NYSE: MTDR) received praise from SGS analysts. Among the five areas cited was its midstream operation, including its San Mateo venture that has added water disposal.

WoodMac reported in December that Permian operators’ exposure to water issues is increasing rather than subsiding. “We believe all companies in the Permian, even the established players, need to follow the lead of firms such as Pioneer Natural Resources Co. [in the Midland], Matador [in the Midland and Delaware] and Devon [in the Delaware] and be more transparent with their water-management solutions.

“Investors and project partners should challenge operators on how water is being managed.”

95% Piped

Shell Oil Co.’s Delaware focus is in the northern part of the Texas portion of the basin. It hasn’t trucked water for Permian completions in 2.5 years, said Erik Hansen, water manager and principal hydrogeologist for Permian operations. “That’s all done via fast pipe/hose as well. The more water we get into pipe, the better.”

Shell’s recycling facility is in the Slash Ranch area of Block 53 in Loving County. It was completed in late 2016. A second one is planned for University Lands about 20 miles away, also in Loving County and near the border with Winkler County.

Shell Oil Co. hasn't trucked water for its Delaware completions in 2.5 years, said Erik Hansen, water manager and principal hydrogeologist for Permian operations.

The operator’s roughly 300,000-net-acre prospect has been reduced from more than 600,000 acres at basin entry in 2017 and is focused now where Shell primarily operates in Loving, Ward and Winkler counties, producing some 100,000 boe/d from more than 400 wells.

Brice Peterson, Shell’s Permian technical manager, said, “We have done a lot with getting our produced water into pipe as soon as possible.” Of what isn’t recycled, 95% is piped to SWD facilities via more than 250 miles of water pipelines.

“Our trucked loads have gone down tremendously since we took over,” Hansen said. “We had more than 550 truckloads a day for produced-water disposal in 2014. Today, we’re down to fewer than 50 a day—and that’s while our production has more than tripled.”

“We don’t overly treat our produced water for recycled-water completions,” he added. The operator’s aim is to protect potable groundwater, reduce freshwater use while increasing recycling and to store, treat and dispose of produced and flowback water in an environmentally responsible manner.

The current recycling facility has the capacity to supply up to two frack spreads in that area and has some 750,000 bbl of produced-water storage. “We are able to use that produced water 100% without any blending and frack successfully with that water.”

He added that the water operation was built to foster concentrated development, enabling cost-effective “piping solutions that you normally wouldn’t have.”

Anticipating more than 5,000 wells in its leasehold, the team knew in advance there would have to be water management. The initial cost is “a big part of the capex in terms of facilities and pipelines,” Hansen said.

On the operating-cost side, “water disposal is a big part of that. We’ve made great improvements in our opex costs in large part due to the water disposal costs coming down, transitioning from getting all those trucks off the road.”

In Shell’s area, Peterson said, the water:oil ratio is between three and four. “So we produce an awful lot of water. Anything we do to reduce costs on water is going to help economics. Recycling makes economic sense, and it makes sense in terms of minimizing use of the groundwater.”

In addition, “getting trucks off the road is economically beneficial, but it’s also the right thing to do to minimize road safety exposure,” Peterson said.

There is some variation in water cut from target to target in Shell’s leasehold, and variations appear areally as well. “But, in general,” Hansen said, “the deeper you go in the Wolfcamp, the higher water-oil ratio you will get.”

None of Shell’s operations are as water productive as the Delaware. Within its unconventional-resource assets—in the Permian, Appalachia and Canada—“they all produce different amounts of produced water,” Hansen said.

“They have different access to economic disposal. They are all somewhat unique. The other assets are gas and tight oil, and they don’t produce near as much water as the Permian Basin.”

Recycling Delaware produced water was a new venture; the facility completed in 2016 was a first for Shell in the Permian. “We learned as we progressed and tried to gather as much information as we could from other operators before we began,” Hansen said.

“It turned out well for us, and it’s economically very beneficial as well. So it’s a win-win.”

In analyzing its source of brackish water, he added, Shell studied how much it needed from the Pecos Valley Alluvium aquifer versus what the source could give throughout the development of the asset “to conclude that it would not be overly stressed.”

‘Midwaterstream’

Shell is looking at collaborating on water with other operators where there is an overlap, particularly on short-term and long-term produced-water management and on recycling. Because of logistics and current economics, there hasn’t been much progress among operators, though.

“It comes down to pipeline transfers and logistics and being able to work out the logistics of storage and priority of usage of the water,” Hansen said. “If you’re in a collaborative group, you’ve got to be able to schedule the deliveries appropriately, and no one wants to be delayed by the lack of water availability for fracking.”

Tyler Hussey, a water resource engineer for Apache Corp. (NYSE: APA), also cited collaboration as needed in the basin, while speaking at the water conference in February, the Midland Reporter-Telegram reported.

Mark Houser, CEO of University Lands, told Investor that he expects operators will either sell their water infrastructure to a midstream operator or commit acreage to a midstream operator and let it build the infrastructure.

“I think we’re going to see that through all of the Permian Basin,” he said.

University Lands owns 2.1 million surface and mineral acres in 19 West Texas counties with about 200,000 of these in the Delaware Basin in Culberson, Loving, Winkler and Ward counties. Among these, only Culberson County has a groundwater conservation district (GCD), which regulates water-well spacing and production.

Going south, Reeves County residents voted to form a GCD in 2015; Pecos County formed one in 2002. In New Mexico, the state owns all groundwater resources, so use is regulated statewide.

Texas GCDs are the water version of the Texas Railroad Commission. Texas’ “rule of capture” common law gives to surface and subsurface owners what they can produce from the property without regard to the issue of whether the product may have drifted there from neighboring property. A GCD’s role is to—like the Texas RRC’s role with hydrocarbon production—protect against wastefulness.

The major groundwater source underlying Texas’ Delaware Basin is the 6,829-square-mile Pecos Valley aquifer that fills the Pecos and Monument Draw troughs and, with treatment, is made potable. Minor aquifers Dockum and Rustler lie underneath.

University Lands expects to gross $1 billion in oil and gas royalties and lease sales this year, said Houser, a longtime oil and gas operator who signed on in 2015 to lead UL, which manages the land the state dedicated to produce revenue for the University of Texas and Texas A&M systems.

Mark Houser, CEO of University Lands, said a new business he calls 'midwaterstream' is developing around sourcing, recycling and disposal in the Permian Basin.

“Operators are producing 250,000 boe/d off our land,” Houser said. With UL’s average 20% royalty, “our share is about 50,000 boe/d of that. Production is at a record level right now.”

From 2004 through 2010, roughly 25 horizontals were drilled on University Lands a year and between 200 and 300 verticals. Between 2010 and 2014, the number grew to more than 1,000 a year with 450 of these horizontals.

That declined in 2015 and into 2016, but the 2017 horizontal count was 280. And oil and gas production continues to grow, Houser said.

In water, “what you’re generally seeing is that folks are starting to understand what the water need is in the greater Permian Basin,” Houser said. “It’s about 500,000 barrels of water per well [for completions] in a round-number basis.

“If you’re needing to complete so many wells per year, industry, in the past few years, has been thinking more comprehensively about ‘Where does this water come from? And what do we do with it when we’re done?’

“The water coming off the wells is going to be greater than the demand [for completions] over the long term.”

Producers have been solving for this themselves, but a new business segment Houser calls “midwaterstream” is developing around sourcing, recycling and disposal. UL has received interest from eight parties in water development on its land; most are interested in the Delaware.

The goal of soliciting proposals is to “have more macro-solutions for water sourcing and disposal on our land,” Houser said. “We’re trying to get a bit more sophisticated in how we help midstream producers and operators manage their strategy.”

"It's ineffective for an operator to not have water capabilities in-house if developing as many as 32 wells per section," said Jon Wright, executive vice president and COO, Halcón Resources Corp.

On University Lands alone, some 10,000 drilling locations have been identified by operators, and each well will need some 500,000 bbl of water for completion.

“The infrastructure needed on our land is going to be significant. We would prefer a lot more pipe and a lot less road. The question we have is whether that is going to stay in the hands of these upstream companies over time or is that going to go into the hands of these water enterprises.

“To me, that’s a logical step over the next few years.”

UL has formed a water group, led by Richard Brantley, senior vice president of operations. “Revenue for us has gone from $2 million a year to about $30 million in water in the past few years,” Houser said.

In the Delaware in 2017, only about 200,000 bbl of UL water were used. In Andrews County on the Central Basin Platform, about 11 million were used; in the southern Midland Basin, about 40 million.

“So, to date, the attractiveness of water from [UL] properties has been less in the Delaware Basin. Part of it is due to a perceived lack of water resource; so far producers have brought a lot of water in from off-lease.”

UL sells water to oil and gas operators on a per-barrel schedule. “On the surface side, like for ranchers, typically they’re drilling pretty shallow wells and using minimal amounts of water for livestock. Typically, we do a joint-investment participation with them.”

For both oil and gas and agricultural/ranching wells, the lessor will have the well drilled. “For agricultural and ranching wells, University Lands has some cost-sharing funds, and there are some funds available through federal and state programs. Once it’s drilled, the well belongs to University Lands.”

Ranchers aren’t being pushed out of the competition for water; generally, operators and ranchers are co-existing, he said. “It’s not without its moments but, in terms of having enough water, we don’t see many problems on University Lands.

“We’re very committed to there being a co-existence because the surface folks—our ranchers and such—are another set of eyes for us to make sure everyone is doing what they’re supposed to, which is to manage these lands for the long term.”

Nissa Darbonne can be reached at ndarbonne@hartenergy.com.

[Editor's note: The following appeared as a sidebar story in the May 2018 Oil and Gas Investor cover story.]

The Southern Reeves Story

A stream runs through Balmorhea, Texas, fed by the San Solomon Springs about three minutes west along Highway 17. Shallow foot and vehicle bridges line the highway at each of its intersections with the community’s gravel roads.

The canal irrigates farms here along several miles of southern Reeves County, where satellite images show a burst of green in the West Texas desert just north of the Davis Mountains.

Besides a freshwater source for farming, the springs are a tourist attraction. A 1.3-acre pool built during the Great Depression by the Civilian Conservation Corps is the centerpiece of Balmorhea State Park, which attracts more than 200,000 visitors annually.

When this journalist was checking in at the El Oso Floja Lodge, the owner wanted to know what kind of journalist was in town to visit with Apache Corp. “You’re not with CNN, are you?” he asked. “I’m a Fox News guy myself.”

At the adjacent restaurant, co-owner Florinda may be taking the order. A block over, the owner of Jo’s Bar & Grill said residents were initially concerned about Apache’s plans for the area, but they’re no longer worried about the water.

Instead, they’re glad Apache’s come to town. His business is up 50%, and the Houston-based oil and gas operator provided $150,000 of computer equipment for the school. “They sent their own IT people to help,” he added.

Apache appears to have been taken in as family by the Balmorhea community, which sits over what was once a sea and, over time, formed what is Apache’s 320,000-net-acre Alpine High play. Water rose and receded; the solids that remained were compacted.

The situation in Alpine High is different from that to the north. Navneet Behl, vice president of operations for the play, said that, along the 3,000-foot column of target, “this whole transgressive sequence is really tight rock.

“The pressure in these rocks kept increasing, expelling the water out. That’s one of the advantages of being in Alpine High shale. It’s almost free of water.”

Apache’s more than 4,500 wet and dry gas targets are Mississippian- and Pennsylvanian-age underlying the Permian-age, oily Wolfcamp and Bone Spring. While it doesn’t have to deal with much produced water, it does still need water for completions, while being careful to only minimally tap area aquifers. Thus, it’s recycling frack water.

“Our main goal is to maximize the use of produced water and minimize water disposal and the use of freshwater,” Behl said. “These are the three most important things that define our water strategy going forward.”

And it’s the neighborly thing to do. “It’s important that all of the stakeholders in the field are onboard with us—that we stay out of their sources of water.”

Apache’s additional unconventional-resource operations are in the Granite Wash and Scoop plays in the Anadarko Basin and in the Eagle Ford. The deep Alpine High targets are of the same geological age as the Scoop and Stack plays in central Oklahoma, and the reservoirs were made in a similar depositional environment.

Across the Permian, Apache holds 1.6 million net acres. There, it estimates it will grow production from 158,000 boe/d in 2017 to some 200,000 this year and more than 300,000 in 2020.

In Alpine High alone, it expects production of some 170,000 boe/d in 2020, up from about 9,000 last year.

It’s operating six rigs in the play, which it estimates contains more than 3,500 wet gas locations, more than 1,000 dry gas locations and more than 500 oil locations.

“Almost all of the 3,000 feet are dry. You’re not going to connect into a water zone,” Behl said.

Its water sourcing initially required what it needed to get started with a few wells. As for tapping shallow aquifers to supplement this, “that’s a big ‘no no’ for us.” Instead, Apache is tapping the deeper Rustler Formation.

“Our main goal has always been to find a source of non-potable frack water,” Behl said. “That was No. 1 to get the play started.” Next was to build treatment facilities for recycling frack and produced water.

Its Gobble Hole facility east of Balmorhea is on 40 acres, handling 25,000 to 50,000 bbl/d. Chemicals aren’t used; rather, solids settle and the water is aerated. Behl said, “The next phase is recycling 100% of the produced water.”

This will require working with surface owners and others to get permission to start moving water from one part of the play to another. Alpine High stretches nearly 70 miles from north to south. The plan is for a bidirectional water pipeline, “so we can move water anywhere we want to.”

Region operations manager Greg McDaniel said in a recycling facility tour in late March, “Water is a commodity to us.”

Initial costs will be absorbed by the more than 5,000 anticipated well locations in the play, Behl said. “We will be drilling for a quite a long time.”

Apache sees solving for water in the Delaware as a type of midstream function. “The only way to look at water costs is to go from cradle to grave—producing it, recycling it, disposing it and adding it all up to see how much water we have to move.”

Any unconventional play requires an operator to have rigs, frack spreads, sand and water, Behl said. “It won’t work if you don’t have these four strategic components secured.”