Based on volumes of production, the industry that calls itself “the oil and gas business” should properly be called the “saltwater business.” In some conventional and most shale plays, there are six or eight barrels (bbl) of water brought to the surface for every barrel equivalent of hydrocarbons.
What to do with it?
The volumes of oil and gas being produced in North America are rapidly rearranging global energy economics and even geopolitics. But at the same time a crisis may be coming to a head as producers wonder how and where to get lakes of water needed to frack wells—and even more to the point—what they are going to do with the oceans of saltwater produced?
The issue is creating a third business for midstream operators—crude oil, natural gas and now water.
Not an afterthought
For ages, water supply and disposal has been an afterthought, handled by producers themselves, truckers, disposal-well operators, oilfield-services firms, and water-treatment suppliers. That haphazard approach is today far from sufficient and integrated water-management has emerged as a major growth area. Midstream operators in particular are taking the matter with the gravity it deserves.
On the supply side, one midstream operator told Midstream Business, “If you don’t have water, you are not in the energy business.” On the disposal side, another confided, “If it is not handled properly, water could end up being the Achilles’ heel of booming U.S. hydrocarbon production.”
Two main factors—availability and cost--have been major drivers in the emergence of water management from an afterthought in oilfield services to a significant segment in the midstream, according to Josh Adler, founder of Sourcewater. “Just in the past few years, fracks have gone from 100,000 bbl (Mbbl) of water to 600 Mbbl or even 800 Mbbl. That is multiplied by the fact that operators plan multiple fracks in series on the same pad,” he told Midstream Business.
Until recently, 100 Mbbl of water in a pit could suffice. Today the need might be more like 3 MMbbl of water—almost all at once.
“Needing 30 to 40 times more water upfront is not just a difference in volume,” Adler explained, “it is a fundamental difference in kind. Until recently, operators could usually get all their water from a single surface-use agreement. But most surface owners just can’t supply that much water in that much time, so operators now have to search the whole area for supplies.”
In most cases that means sending landmen around to knock on doors.
“But when completion engineers say they have planned their water needs 12-18 months in advance, what they usually mean is that they have signed call options and rights-of-way with nearby ranchers and farmers,” Adler said. “Very rarely do they secure a guaranteed supply contract—they just assume the water will be there when they need it because everyone shook hands on a price and they know whom to call. But in a world of $60 oil, it makes economic sense for everyone to drill everywhere in the Permian, so now you suddenly have many different operators all calling on the same surface owners for the same water from the same aquifers at the same time—and needing six to eight times more water per well than before. No one has planned for that simultaneous demand. There are going to be a lot of water supply shocks this year.”
A third of completion
“There has been a complete transformation in the scale of water,” Jim Summers, CEO of H2O Midstream, told Midstream Business. “Today water can account for 20% -30% of the cost of drilling and completing a well, and as much as 50% of the operating cost. That is driving the evolution of the midstream business around water. The model is looking a lot like gas midstream.”
H2O Midstream began commercial operations in July 2017 when it acquired a produced water gathering system from EnCana and spent the subsequent six months converting that proprietary system to a fully integrated commercial one. H2O Midstream has recently added a second and third producer to that system, and is adding capacity for both transportation and disposal.
The company is backed by EIV Capital along with co-investors.
“We have built a produced water hub in Howard County [Texas],” Summers said. “We like this ZIP code and hope to expand, then take that model elsewhere in the Permian and beyond to the Marcellus, Bakken, Scoop and Stack, anywhere there is high density of development and also high water cuts.”
At present all of the water H2O Midstream takes goes to disposal, but recycling is the goal.
“That will be a paradigm shift, at least in the Permian,” Summers said. “We are building a system that will let producers reuse water through our storage and our pipes. We believe we will have the first commercial re-use pond in
Treatment in the pond is a combination of mechanical and chemical, including aeration.
“The biggest challenge for us is getting producers to trust third parties with their water,” Summers noted dryly. “They are willing to let go of their oil and gas, but they are not willing to let go of their water.”
A new sector
Once that becomes more accepted, however, Summers sees water as a major sector in the midstream.
“We see this business through the lens of a midstream operator,” Summers said. “We see opportunity for the big midstream names to grow their portfolios through water. There will also be room for new standalone water midstream companies.”
DistributionNOW (DNOW) claims primacy in the segment of pumps as well as fabricated water transfer and disposal skids for injection wells. As such, the company is on the front lines of the evolution of water management in the midstream.
“This is a market we are watching very closely,” Brian Verdehem, director of engineering for process solutions, told Midstream Business. “The biggest concern for the folks we talk to is what are they going to do with all the produced water in shale wells. Operators have said that 7 bbl-10 bbl of produced water are separated for every one of oil.”
DNOW also has an upstream business supplying portable, high-capacity diesel pumps for getting freshwater to frack sites, but that is a discrete operation from the larger business in rotating equipment and other machinery for produced water.
“Reducing water costs goes straight to the bottom line,” Verdehem said. “And if the water issue is not dealt with properly it could drive up operators’ disposal costs and make some fields less profitable or necessitate a higher breakeven oil price.”
That strong assertion is being underwritten to the tune of millions of dollars in inventory that DNOW is accumulating.
“We are expanding our existing stock in pumps that usually need 10 or more weeks of lead time to help our customers,” Verdehem said. “We are doing this because produced water volume is very difficult to predict. Lots of times a producer will put a well on production and get a lot more water than [they] thought they would. That means they need pumps in very short lead times or from stock.”
The pumps being stocked are being tailored for the predominant parameters of size, flow rate and fluid characteristics for each basin, he said.
The disposal challenge
Cost has indeed grown, in some plays by an order of magnitude.
“Water used to be about 2% of the cost of a Permian well,” Sourcewater’s Adler said. “Now it can be as much as 20%. In the northern Delaware Basin water costs $1/bbl-$3/bbl without transportation. That means water can cost over $1 million per well. And it’s not an optional cost. If you don’t have all of the water you need, you are not in the energy business.”
Water costs, availability, and infrastructure vary greatly from basin to basin, and even within basins.
“The Delaware and Midland basins are very different,” Adler said. “In the
Sourcewater is an online marketplace where producers and midstream operators can find and acquire water for fracking and place flowback and produced water for disposal or reuse.
“We started in the Marcellus as a way for producers to recycle produced water among themselves. There is a lot of inter-operator recycling in the Marcellus, but it is still rare in the Permian. That is not because of greater distances or lack of infrastructure, but mostly less economic motivation and fear of commercial and environmental liability. Produced water is classified as a waste stream, so there are statutory requirements for liability in the chain of custody,” Adler continued. “The cost and scarcity of water sources and saltwater disposal is not yet high enough in the Permian to overcome those hesitations—unlike in the Marcellus where there is virtually no saltwater disposal so recycling is a necessity.”
Produced water disposal may be an even bigger long-term challenge than water supply. The large volumes of water needed for fracking are dwarfed by the volumes of produced water that flow over the life of all the producing wells in a field. Adler believes produced water recycling between operators is the future of oilfield water supply.
“Produced water is plentiful exactly where you need it, which is where the oil is. There is no technical reason to use freshwater for any frack,” he said. “And if you go to one of the [Hart Energy] DUG conferences you will hear evidence that produced water actually works better for fracking. Reuse gets better results, it costs less, it’s better for the environment and our communities, and there is plenty available.”
That said, “the bigger midstream companies are not playing on the supply side of water because of the lack of long-term guaranteed supply contracts,” Adler explained. “This is currently a spot market business so more of a segment for smaller, local or regional operators.”
Regional operators active
The major continental midstream companies have not been highly visible in water. The bulk of the activity has come from mid-size and smaller firms, either dedicated to water or operating on the model of integrated hydrocarbons and water. In February, two separate companies that are growing their water midstream business announced expansions in their Permian operations.
Layne Christensen completed a six-mile extension of its Hermosa water-supply pipeline. The 26-mile Hermosa system extends from company-owned land near Pecos, Texas, northward in Reeves County. It can deliver 175 Mbbl/d through 18 different delivery points along the route for use in drilling and completion.
Layne claims primacy as “the largest water-well drilling company in the U.S.” It maintains exclusive water rights on about 88,000 acres owned by the Texas General Land Office in Reeves and Culberson counties to develop non-potable uses.
“The extended pipeline expands our water-midstream business farther north into Reeves County where access to water is more limited for oil and gas producers,” J. Michael Anderson, president and CFO of Layne Water Midstream, told Midstream Business. “We expect to see continuing demand growth for water in the energy sector, especially in the
Separately, Goodnight Midstream Permian is conducting a binding open season for producers to enter long-term contractual commitments for its Llano produced-water pipeline system. That line is to be built in Lea County, N.M. The open season will conclude March 30 and the company hopes to have the line in service by the end of the year.
The high-pressure line will have an initial capacity of 200 Mbbl/d of water and is already supported by a long-term dedication from a key producer. Goodnight owns and operates a network of water gathering pipelines and saltwater disposal wells. Beyond the Permian it also operates in the Bakken, and has an emerging presence in the
In Eddy County, N.M., Solaris Midstream is adding 40 miles of 16-inch pipe and drilling a series of new disposal wells, some owned and operated by the company itself, some operated on behalf of producers. The bulk of produced water is going to injection, but some recycling and reuse is already in effect across its system.
Callon Petroleum Co. has been among the most active producers in working with midstream partners in water management.
Tanks for the water, tanks for the oil. This tank battery handles water for producers on the Guitar Lease outside Big Spring, Texas. Source: H2O Midstream
“Managing source water for frack jobs has typically consisted of purchasing directly from landowners when possible, purchasing from other operators and most recently working with companies to bring water in from other sources,” Gary Newberry, COO, told Midstream Business.
“Once fracked, we’ve handled the disposal based on our best nearby options, with an emphasis on disposing in intervals deeper than our producing horizons. In the Midland Basin, we’ve placed a priority on piped connections to Ellenberger disposal wells to increase reliability and reduce early time flowback limitations sometimes caused by trucking. More recently in Spur [Texas], we’ve entered into an agreement where portions of our produced water will be moved via pipe to nonproductive portions of the Central Basin Platform,” he added.
A Gastar Exploration Inc. crew draws water from the Cimarron River for a frack job in Oklahoma's Stack play. Surface water is not always available in the quantities needed as producers increase the size of well hydraulic fracturing programs. Source: Hart Energy
Decisions on whether or not to farm out to a third party always come back to economics, Newberry explained.
“That is not just cost of disposal, but anticipated reliability of their system to mitigate the risk of production curtailment. When needed we’ve always been ok with developing this part of our business ourselves to ensure capacity, but we’re happy to partner or completely dedicate this part of the business to other parties who have built out redundant systems and can provide competitive rates.”
As activity continues to increase, Callon believes water management will emerge as more of a commercial service.
“The major challenge we see today has been isolated cases of overpressure in the shallow disposal formations making it more difficult to drill into the deeper formations to access our resources,” Newberry said. “We’re committed to disposing of as much water as we possibly can into deeper formations and, in the Delaware Basin, reached an agreement to move our produced water away from our leasehold into a nonproductive portion of the basin.”
Beating back bugs
“We are seeing the rise of the midstream water-management business,” Mark Patton, president of Hydrozonix, told Midstream Business. “We are seeing companies buying and commercializing systems, with the focus on reuse. No one takes salt out for reuse anymore because there is no need. Frack formulations are not sensitive to salt. Still, reuse means control of bacteria, iron, sulfide and solids in produced water.”
After the water is treated for those elements, it can be stored, but the bacterial bugs will be back.
“Stored water needs to be aerated to prevent bacteria,” said Patton. “Surface aerators don’t get the water at the bottom, and bottom aerators tend to get buried. We have seen our business in portable, drop-in, agitator-pod aerators take off this year.”
As an equipment and chemicals supplier, Hydrozonix is agnostic to the business type of water management company, and thus has a perspective into all segments.
“We are seeing growth all over,” said Patton. “There are producers that are never going to sell their water operations. There are midstream companies buying saltwater disposal operations just to get into the water sector. There are also disposal well operators moving back upstream to water management.”
Patton is convinced “the water management part of the midstream is valid, but it is complicated matching surges in supply and demand. The key is to put together a system where recycle—capital and operating expense—is cheaper than disposal. The price for recycle has come down but producers are still reliant on disposal wells.”
The major water-treatment operations are keeping their hands in as well. Veolia Water Technologies claims primacy as “the world’s largest environmental company” and has been active in oil and gas for 30 years, James Welch, director of business development for upstream oil and gas, told Midstream Business.
“We are certainly willing to contract with midstream companies, but historically we have contracted directly with [E&P] companies. Our expertise is in water reuse and recycling, [and] we are beginning to see some E&P companies show interest in opening their facilities to accept water from other sources. We are working with several companies on this merchant plant concept.”
Water management is already a commercial service, Jeremy Sherman, director of sales and marketing for Cudd Energy Services, told Midstream Business. “And we expect it to grow significantly over the next few years. The potential for larger fixed recycling facilities is there; however, mobile systems that can be relocated in a matter of days will play a significant role in the sector. Mobile systems capable of processing over 50 Mbbl/d with very small footprints are now available. This is ample capacity to service an active frack fleet operating in a particular area.”
The sector is still in flux, Sherman added.
“There is obviously a need for midstream development. In most cases these systems are being designed to optimize water disposal; however, the infrastructure can also be used to share or broker waters. Once the water is in a pipeline system, the midstream operator will have significant input as to where the water is directed, whether that is to a disposal site or to a recycling site.”
“The water business is growing much more rapidly than any other part of the midstream,” David N. Capobianco, CEO and managing partner at Five Point Capital Partners, told Midstream Business. Five Point has midstream water operations in the northern and southern
“Three pipes in a ditch is the way all midstream development will be done from now on,” Capobianco said, “but there still remains a meaningful transition from spot market water handling to permanent water management infrastructure. For the past few years producers have been like race cars speeding around a race track toward a wall at the end of the track. They have known the wall was there, but had no strategy relative to what they were going to do when they got there. ... but now it is in sight. The wall is the mass-water management challenge they face as they ramp up production. We have crossed the tipping point, or the moment when the need for a permanent solution is no longer a luxury but a necessity.”
In many ways the development of the water segment of the midstream is following the path of the hydrocarbon midstream. “Originally, producers built out there own infrastructure, and later divested,” Capobianco noted. “Over time, I would expect that the lion’s share of water management infrastructure will be owned by independent third-party companies.”
Capobianco reckons that within a few years “almost all midstream operators will have water operations of some kind. It will be impossible to avoid if you are a midstream business.” The form the water midstream will ultimately take remains unclear. “It could end up like a utility, with large companies managing an array of local operations,” Capobianco said. “There is not really an existing model. Unlike oil and gas, the water molecules are not going to move very far.”
Gregory DL Morris is a freelance writer based in New York City specializing in energy and petrochemical topics.
Water disposal has emerged as a major issue in Oklahoma due to the region’s unique geology. Water injected into suitable, porous formations has lubricated inactive faults, trigging sometimes significant earthquakes in a part of the country where seismic activity has been rare.
Water injection, understandably, has become a significant political and economic issue for the Sooner State. The quakes have been centered in central and north-central portions of the state.
And while injection is down in Oklahoma, seismicity is little changed.
“For all of 2017 the state of Oklahoma had 304 magnitude 3 earthquakes, which is more than California did,” Jake Walter, state seismologist with the Oklahoma Geological Survey, told Midstream Business. “That is even though Arbuckle Formation injection is now down to levels not seen since the middle of 2012, and at that time there were just a few magnitude 3 earthquakes.”
Current Arbuckle injection has dropped from a peak of 90 million barrels (MMbbl) per month in late 2014 to 40 MMbbl/month in early 2018.
The reduction of injection volumes has been driven by both regulation and economic forces on the oil and gas industry. The survey, based in Norman, Okla., has been working closely with the regulatory Oklahoma Corporation Commission on the issue.
“Mississippi Lime wells sometimes produce 80%- 90% water,” Walter said. “We hear that those kinds of wells are only economical at high prices for oil and low prices for water disposal. Now what happens if oil prices rise? We don’t know.”
—Gregory DL Morris