Thanks to unconventional resource plays, the United States is producing more crude oil than any nation in history and more natural gas than any nation ever has before—and it is doing so at the same time!

But it is not just hydrocarbons that are flowing to surface; there is also water. And a lot of it. In the Permian Basin alone, more than 20 million barrels of water are produced each and every day. In total, the United States is expected to produce far more than 50 million barrels a day of water next year.

That is a tremendous volume of water to deal with on an around-the-clock basis, making water management as fundamental to bottom-line success as managing drilling, completion and production operations. Fortuitously enough, however, hydraulic fracturing operations consume a massive amount of water, giving oil and gas companies opportunities to repurpose flowed-back and co-produced waters to stimulate new reservoir rock.

Increasingly, producers are making the switch from freshwater or clean brines to recycled water from both new well completions and older producing wells as the base fluid of choice for fracturing treatments. In regions like the semi-arid Permian, where freshwater resources are limited and oil wells can yield as many as 12 barrels of water per each barrel of oil, the relative abundance of flowed-back and produced water makes reuse something of a necessity.

There are plenty of logistics and operational challenges, however. Pausing frac pumps once treatment begins is a costly proposition, so the operation must go on. That means every component in a water recycling system has to be able to keep up, from the transfer pumps pulling water from storage tanks, to the mechanical filters knocking out sand and other solids, to the mobile chemical facilities providing on-the-fly treatment to varying qualities of water. Even the most efficient recycling operation will still have barrels that must be disposed of, making disposal as indispensable as ever.

Interconnected Networks

To address operator needs, water suppliers, hydraulic fracturing contractors, technology companies and chemical solutions providers are providing innovative solutions across the water supply chain. For water midstream, advancements include configuring interconnected networks of permanent and temporary pipelines, recycled water storage pits and centralized and mobile recycling facility capacity, says Brandon Prill, business unit president for water sourcing and recycling at Select Water Solutions.

On the networks, recycled water is pumped back and forth on pipelines connecting multiple pits to balance out supplies all along the network and ensures that multiple frac crews pulling simultaneously from various points have plenty of water available at any point in time.

Select Water Solutions is using interconnected networks of recycled water storage pits to balance out supply availability all along its system and ensure that multiple frac crews pulling simultaneously from various points have adequate water at any point in time.

The increasing demand for more frac fluid from unconventional wells drilled with ever longer laterals, and simultaneous treatments of two to three wells at once through simulfracs and trimulfracs, make infrastructure network creation imperative, Prill says.

“When I first started, a ‘big’ well completion from a water standpoint was 25,000-30,000 barrels compared to some today with needs in excess of 750,000 barrels,” he observes. “You can imagine the logistics required to move that amount of water and how any kind of hiccup on the supply side can really throw a wrench into the entire completion process.”

In the typical recycling and storage system, frac flowback water and produced water already present in hydrocarbon layers is pumped to permanent and mobile recycling plants near storage ponds for removal of oil, grease, suspended solids, iron, hydrogen sulfide and other constituents, Prill reviews. Biocides are added to kill harmful bacteria and treated water is then discharged to storage pits on the supply network for reuse on future frac jobs.

Select’s largest water network, located in the Delaware Basin, connects five recycling facilities with combined storage of up to 11 million barrels of recycled produced water treated with 1 million barrels of aggregate daily recycling capacity.

Sensors and flowmeters coupled with SCADA computing to analyze real-time data for quick decision making has enhanced automated treatment and water balancing systems that can be remotely operated. Select is in the process of building a central control facility in Midland for all Permian operations, Prill offers.

To ensure adequate water during stimulation and avoid having a single potential choke point, typically multiple water supply lines consisting of lengths of lay-flat hose connect the fixed pipeline and storage network to temporary storage at the frac site. On site, on-the-fly treatment ensures water is treated fully to specification for each customer before being mixed with chemicals at manifolds and pumped downhole, according to Prill.

As efficiency improves in both water transfer and infrastructure, the growing use of recycled produced water is helping operators save money, he says, with recycled water already accounting for 45% of the volume on Select’s water handling systems in unconventional shale plays across the country.

Evaporation Technology

Despite growing reuse of produced water nationally, saltwater disposal takes in 70%-80% of flowback and produced water volumes in the Permian, but seismic activity from water being pumped into faults during disposal has forced reductions and hastened the need for additional solutions, reports Mark Patton, president of Hydrozonix in Odessa, Tx.

Regulatory shifts to deal with seismicity are challenging oil and gas producers to consider options that include evaporation technology to eliminate excess water altogether, he says. Providers are deploying portable infrastructure and moving water processing farther upstream to lease tank batteries and disposal sites, where evaporation technology can be deployed to remove produced water on site.

Hydrozonix is providing evaporation systems that use spray nozzles to create a fine mist over storage pits and tanks to allow water to quickly evaporate.

“Evaporation is going to be a growing field until desalination becomes more prevalent,” Patton assesses.

In evaporation systems, spray nozzles create a fine mist over storage pits and tanks that allows water to evaporate quickly. However, leftover salt in powder form can be blown skyward and contaminate the land nearby.

To eliminate dispersion, salt drift can be modeled and available evaporation technologies can manage dispersion patterns, Patton notes. Instead of spraying water vertically, nozzles can spray droplets horizontally or downward into a storage facility in a process that slows the evaporation rate.

“There is a tradeoff,” Patton says. “If you really want to control the salt, you are going to affect your evaporation efficiency, but if the salt contamination is the biggest concern, you sacrifice some of that operational efficiency by spraying not vertically up in the air but more horizontally and downward using nozzles with larger droplet sizes.”

Smart evaporation systems can make adjustments to processes or even shut them down entirely based on changes in wind speed, direction and dispersion, he adds. Moving the process to lease or centralized tank batteries takes efficiency one more step by reducing gathering system maintenance and costs, cutting emissions and improving oil cuts enough so that additional recovery can pay for a treatment system.

The evaporation technology can include pre-treatment with dissolved air flotation to remove solids and oxidizers that remove bacteria, soluble iron and sulfides. Additionally when using ozone, volatile organics, methane and benzene can be oxidized providing significant emission reduction, Patton concludes, noting that the same pre-treatment process can be used in the future on a desalination process.

Desalination Advances

Advancements in desalination will provide operations with feasible options to beneficially reuse large volumes of produced water, reduce disposal quantities, and mitigate seismicity, says Jonathan Malone, director of business development at TETRA Technologies.

Currently, some Permian operators are building pipelines to transport water for disposal from seismically sensitive areas to other locations with more porous, less over pressured reservoirs . However, 20-30-inch pipelines extending for 80-100 miles can cost well over $1 million per mile in installed cost, he points out, with an additional yearly operational cost. Although this strategy could provide temporary relief, it is inevitable that the subsurface where the water is being transported to will also become over pressured in time.

TETRA Technologies’ membrane-based field desalination technologies are designed to reduce expenses while giving operators the option to sell water that meets standards for agriculture, industry, surface discharge and drinking water.

Desalination systems can help reduce risks associated with disposal while giving operators the option to sell water that meets regulatory standards for agriculture, industry, surface discharge and drinking water, Malone says. “We look at this produced water as a resource rather than a waste and these technologies convert the previously deemed ‘wastewater’ into something valuable, especially in drought-stricken areas,” he remarks.

TETRA offers an “end-to-end” desalination solution that encompasses pre-treatment, desalination, post-treatment, and mineral extraction to convert the produced water into something valuable. For desalination, TETRA successfully tested and licensed two membrane-based desalination technologies, he details. Additional pilots are planned for 2025 as oil and gas producers in the Permian, Appalachia, the Rockies, and overseas locations such as Argentina and the Middle East express interest.

The technologies achieve desalination in a process that follows initial pretreatment. One membrane technology is electrically driven and is an enhanced version of reverse osmosis. It works efficiently on the lower end of the salinity spectrum, Malone explains. The other membrane technology is a thermal desalination process and can produce distilled quality water if desired. In the field, systems could be powered directly from the electric grid, natural gas, and has the potential to take advantage of waste heat systems such as natural gas compressor stations.

“Coming out of that desalination system is a concentrated brine and also a clean desalinated water stream,” he details. “That clean desalinated water requires a little post-treatment to remove ammonia and other constituents that remain after the desalination process. We then have this clean supplemental stream for beneficial reuse to take the burden off the freshwater supplies.”

The concentrated brine contains minerals that can be extracted for sale, such as lithium, iodine, magnesium, strontium and others that are on U.S. Department of Energy’s critical minerals list, he says.

Pilot plants can process up to 300 bbl/d, but systems designed on paper could easily process 100,000-150,000 bbl/d. Larger ones can be designed and built, but the bigger the size, the longer construction takes. Consequently, Malone says most customers are interested in smaller systems, from 10,000-25,000 bbl/d, before adopting the technology more broadly. An operator or midstream company could partner on a desalination project and pay a per-barrel or daily fee depending on the commercial agreement.

“Disposal wells are not going to go away, but they need a relief valve,” Malone remarks. “When you couple that with the fact that freshwater resources are declining, you need these plants in order to treat water that can be useful.”

Multitiered Approach

Desalination and evaporation technologies, both considered Tier 4 recycling, are warranted to help the industry deal with growing volumes of produced water from higher water cuts in aging wells, says Enrique Proaño, vice president of water management at Cudd Energy Services.

“There is this wall of water, as people like to call it, that is heading our way,” he says. “As fields age and water cuts grow, more produced water is going to have to be dealt with.”

Failing to find workable answers could eventually hobble production in the Permian, where recycled produced water accounts for about 35% of consumption in frac work, Proaño estimates.

Yet, even if produced water met 100% of the demand in West Texas and Southeast New Mexico, only about a third of all volumes would be utilized, he points out. The issue will only intensify over the next 10-15 years.

Even with chemical advancements in recent years, oil and gas producers as well as service providers such as Cudd Energy Services view tried-and-true solutions such as chlorine dioxide biocides as critical for treating bacteria and ensuring well productivity.

While others are developing Tier 4 technologies, the Houston company will continue to participate in pilot projects to test them, Proaño says.

In the meantime, Cudd continues to deploy the latest chemistries and techniques for Tier 2 and Tier 3 processing standards that apply to most frac jobs, he says.

In recycling, Tier 1 includes water volumes in Appalachia and elsewhere that require little, if any, treatment before reuse, Proaño explains. Tier 2, which is quickly becoming the norm, involves chemical removal of contaminants such as iron and hydrogen sulfide. Tier 3 adds solids control techniques such as dissolved air flotation (DAF) for removing precipitants and solids.

Growth opportunities in treatment and deployment will come from additional well remediation previously hindered by limitations in technologies and systems to apply chemistries to one- to two-mile horizontal wellbores full of perforations, Proaño says.

Amid advancements in determining chemistries and applying them, producers and service companies have become increasingly appreciative of the importance of competent biocides to kill bacteria that can sour wells and create blooms that clog up pores downhole. As an example, he says oxidative biocides such as chlorine dioxide and a competent downhole extender are essential basic elements to optimize well productivity.

“Over the past four or five years, the importance of robust biocide programs in frac jobs has been better understood instead of it being a treatment with token amounts of biocide,” Proaño comments. “People are paying a lot of attention to biocides because they understand how much bacteria can impair production in later years.”

Data-Based Methods

The accelerated pace of identifying chemical solutions, applying them and even adjusting dosages on the fly—for on-the-spot shifts in the quality of recycled water from different sources and other issues—is enabling operators to get the most out of their frac treatments, according to James Silas, technology adviser at Flotek Industries.

The move from testing-based chemistry methods to data-based methods has sped up the process substantially for identifying the right fluid chemistries on longer lateral wells and requirements for more intense hydraulic fracturing on multiple wells simultaneously, he says.

Traditional testing-based recommendations rely on field samples to find solutions for expected work, whereas data-driven recommendations rely on fast access to a trove of data from previous field samples of oil, water and rock from wells mapped by state, county and interval, Silas explains. For Houston-based Flotek, that means having quick access to information on as many as 20,000 wells the company has worked.

Flotek Industries is using data-based analytics in addition to traditional testing-based methods to identify chemical solutions for treating recycled water, reducing time while increasing treatment effectiveness and enhancing the ability to respond to changes by adjusting dosages on the fly.

“In this way, we can connect analytical results to both basin- and reservoir-level studies that describe the stratigraphy, structure, petroleum system, and depositional environment,” Silas details. “This aligns our fluid development and deployment with the geologic description of the reservoir from the operator to help mitigate their risks to production.”

With the increase in intensity of operations, getting to the right answer quicker is important in driving operational efficiency, says Leon Chad, Flotek’s senior vice president of chemistry.

“What was done in weeks and months a few years back is now being done in hours or days with the predictive modeling that we do,” he relates. “There are multiple inputs that we can take into account and produce models. Speed and the pace of response has grown dramatically.”

The company’s data analytics and real-time sensor capabilities also are being used to help stimulation companies avoid operational risks from changes in the quality of associated field gas used to power dual-fuel frac fleets and generate power for electric-powered spreads, Chad says.

Flotek uses near infrared (NIR) spectroscopy technology to measure gases or liquids in real time using chemometric models to analyze Btu content, composition and other properties. Chad reports that the technology can quickly detect higher Btu or “hot” gas that can potentially damage engines and halt stimulation work.

However, once hot gas and other complications are detected, stimulation companies can quickly switch fuel sources, preventing engine damage and downtime. “That kind of online, real-time information essentially enables companies to completely eliminate diesel from a frac fleet by being able to monitor associated gas quality and quickly switch to reconditioned compressed natural gas when necessary,” Chad concludes. “This is a wonderful example where real-time measurements can really make a difference in an operation.”

All In On NIR

Near infrared technology is also being applied to protect engines and drive efficiencies for hydraulic fracturing company ProFrac Services LLC, says Larry Carroll, ProFrac’s vice president of engineering and technology.

“We think the technology is fantastic, and we are all in on NIR,” he says.

Its introduction is part of the company’s ongoing strategy of deploying innovation to supplement in-house expertise, Carroll says, and operators are the ultimate beneficiaries. Other advancements include more electric frac fleets, which he points out have fewer moving parts, greater operating efficiencies and reduced emissions.

E-fleets can do the same work as traditional diesel-powered fleets but with a smaller footprint—a must in states like Pennsylvania and Colorado. The increased efficiencies that e-fleets provide allow for smaller pads and the ability to use fewer frac pumps than in a traditional fleet, Carroll says. In some cases, ProFrac only needs 10 higher efficiency electric pumps, as opposed to 20 conventional pumps.

ProFrac is applying near infrared technology to protect engines and drive fracturing efficiencies as it strengthens its dual-fuel frac fleet capabilities.

The Willow Park, Tx.-based company recently announced a project with Prairie Operating Co. for a fleet of 25 advanced 3,000-horsepower single E-pumps, allowing both hydraulic fracturing and pump down operations to be fully electrified. Initial frac operations under the new endeavor began in the Denver-Julesburg Basin on a recently drilled, eight-well Shelduck pad in Weld County, Co.

ProFrac’s upgrades ensure ample capacity and operating flexibility, which is required for shifting conditions during treatment, including adapting to variations in water quality during a frac job. “We are constantly adjusting and readjusting, changing packages, and changing chemical types due to water quality,” Carroll says. “That is an ongoing challenge.”

Chemical packages depend on the mix of produced and freshwater. About one-third of ProFrac’s fleets today are pumping some portion of produced water, he says, with Appalachia fleets often pumping 100%. Using charts and graphs that are monitored closely, solutions can be altered for on-the-fly applications to create slickwater with sufficient friction reduction to open or elongate fractures.

“We have used technology where you can access data in real time to monitor the water before it hits the blender, and again post-blending after friction reducer and other chemicals are added to test efficacy. but there are limitations,” Carroll says.

In addition to leveraging technological improvements, the company also provides the human expertise necessary to identify solutions for shifting water qualities, according to Christian Parra, a ProFrac engineering operations manager. Parra points to a solution one of the company’s teams derived for a job in South Texas as an example. As in many jobs, the completion fluid contained both fresh and produced water. However, the total dissolved solid levels in the produced water ended up being much higher than anticipated, which compromised the high-viscosity friction reducer’s performance. As a result, pressures rose and the well stopped taking sand.

In response, engineers quickly collected and analyzed samples, then proposed several remedies. The selected solution included increasing the portion of produced water and the FR concentrations during pad and flush operations, while using more fresh water during the sand-laden stages, Para recounts. This approach worked well, he reports. After a transition, the team began pumping sand successfully.

The company has implemented additional innovations to achieve better results and provide high-quality service, including a customer portal interface available to ProFrac employees, operators, and others involved in a stimulation job. Authorized users can log into the system to access job design specifics, monitor conditions and check on job status, Carroll describes.