Speaking at Hart Energy’s recent Executive Oil Conference, B3 Insight CEO Kelly Bennett noted that disposal volumes in Texas and New Mexico—a strong indicator for the water management business as a whole—were down significantly from their March 2020 peaks.

“We observed a pretty significant drop from the peak in March to the trough in May for disposal of water in the Permian Basin,” he said. “In Texas, it was about a 26% drop; in New Mexico it was a little more, about a 28% drop.”

The cause of the disposal volumes drop was a result of widespread well shut-ins, as prices and demand plummeted over the late spring and early summer.

“We started to see those wells come into production over the course of late June, July, August and September,” Bennett said. “And that’s what accounts for (an increase) through July in disposed water volumes. Since then, we’ve started to see those volumes fall again. While there are some wells being completed, it looks a little more like a natural decline in water volumes.”

Although this year is likely to see some small amount of production growth, Bennett explained much of it will come from the estimated 1,000 or so DUCs throughout the Permian, as companies continue to reduce capex in favor of generating returns. He said it could take some time before the water management industry recovers the approximate 20% of disposal volume it lost last year.

“In the water management industry, which is still in a fairly nascent stage, there are companies that did far better than this and far worse,” he said. “So when we talk to our clients and work through some of the challenges that they have, anecdotally there are some companies that lost 50% or more of volumes in their key facilities, and there are some who weathered this far better.”

Growth after the downturn

Even before the double headwinds of 2020, operators began to transform from a grow-at-all-costs mindset to placing a priority on reducing expenses and generating cash flow. Those efforts have included identifying efficiencies in their water management program and working with service providers to achieve the best possible price on sourcing, recycling and disposing of water.

“Operators are looking for ways to drive efficiencies through their operations while simultaneously lowering costs,” said Andy Adams, senior director water management and infrastructure with Select Energy Services. “One way they are doing that is through the use of large-scale, centralized treatment facilities. Select has multiple facilities planned or under construction in the Permian.”

In February, Select announced it had been awarded two recycling facility contracts for producers in the Permian Basin. According to the company, the first facility is a new fixed infrastructure produced water recycling facility project serving the core of the Midland Basin in both Martin and Midland counties, Texas. Select believes the $5 million facility should be fully operational by the end of the first quarter of 2021.

Progress continues despite recent weather challenges in West Texas on Select Energy Services’ treatment facility. The facility features a 2-MMbbl storage capacity with an expected throughput of 50,000 bbl/d of treated produced water. (Source: Drew Smith, Select Energy Services)

“This project is supported by a long-term contract with a leading, large independent operator in the Midland Basin for the purchase and delivery of recycled produced water,” the company stated in a release. “This facility will support the recycling of up to 50,000 barrels of water per day while providing 2 million barrels of recycled water storage capacity. Additional incremental capacity beyond the contracted volumes creates additional opportunity for growth with the contracted customer as well as the opportunity to further commercialize the facility to support the needs of other operators in the area.”

Select is also developing a centralized produced water recycling facility for a major integrated operator in Loving County, Texas, in the Delaware Basin. The facility is designed to recycle up to 30,000 bbl/d of produced water and will be supported by 1 MMbbl of adjacent recycled water storage capacity. Select expects this facility to also be fully operational by the end of the first quarter of 2021 as well.

“The scale of the facilities we are building today is changing the economics of oilfield water treatment by allowing operators to achieve the high-volume output required for 100% produced water fracturing over a short period,” Adams said. “A 1-million-barrel facility capable of supporting multiple frac crews is becoming the norm.”

Adopting digitalization in water management

Like essentially every other component of the upstream oil and gas industry, water management is entering the era of digitalization. Automation technologies are helping companies keep track of where their water is going, where it’s coming from, how much is needed, how much is being used and how much it’s costing them.

SitePro applies SCADA systems to remotely monitor and control assets in fluid management.

“We put our systems on production batteries, pits, ponds, pipelines, disposal wells and interconnected closed-loop systems,” said SitePro co-CEO David Bateman. “And we offer people the ability to manage this stuff on their computer or from an application on their phone. It’s somewhat the traditional automation, remote monitoring and control combined with a commercial transaction element for managing a lot of tickets and loads, whether that’s by truck or pipeline.”

Bateman said those capabilities can synchronize data into an accounting or billing system that can serve as an analytical tool for understanding the analytics behind water management. Additionally, SitePro has initiated some work as well into produced water recycling technologies.

SitePro’s technology provides automation of water storage and treatment facilities. (Source: SitePro)

“We’ve put our systems on those facilities as well, where we’re monitoring water quality and water chemistry to help make decisions for blends and mixes,” Bateman said. “And even in water wells, we help manage and monitor any kind of water quality issues that may exist downhole.”

As far as how automation and digital technologies can improve water management efficiencies, Bateman said they can provide an array of benefits.

“For instance, if you own a water midstream asset, you can use analytics to see which customers are bringing you the most water by volume and what the quality of that water is,” he said. “And you can learn what service companies are using it, when peak demand is [and] when low demand is. I would call that market intelligence.”

He added that automation technologies can be applied to pumps, drives and valves that can provide data that can measure wellbore integrity, predictive analytics and equipment maintenance information.

Natural gas foam

One method to curtail freshwater usage as a fracking fluid is to nearly bypass water as a whole altogether. In early March, the Southwest Research Institute (SwRI) announced it had completed a pilot-scale facility to create and test natural gas foam as an alternative to water for fracturing. According to the SwRI, the six-year project is part of an effort to show that stable natural gas foam can be generated on site at a fracturing location using commercially available products.

“Fracking doesn’t always occur near water resources, so the water has to be trucked in,” said Griffin Beck, the project’s principal investigator. “That process is time-consuming and can wreak havoc on local roads and related transportation infrastructures, not to mention the tens of millions of gallons of water consumed by the fracking process.”

Beck and his SwRI colleagues took note of the abundance of natural gas being flared and began exploring natural gas foam as an alternative to water. The team initially determined that the most efficient way to create the natural gas foam was to use standard compressors to pressurize the natural gas and then mix it with water to create the foam.

“The foam is created by jetting the natural gas stream into the pressurized water,” Beck said. “The process utilized up to 80% less water than typical fracking treatments.”

The SwRI team found that the foam’s viscosity was capable of carrying sand particles into well fractures as efficiently as pressurized water. Beck also found that the foam’s properties produced less swelling in clay environments and could possibly improve production rates.

“We created a reservoir model to test the foam’s efficiency,” Beck said. “We compared production to a reservoir treated with water and with natural gas foam. The model showed a 25% improvement in cumulative oil production.”

According to the SwRI, the next step is to field-test the foam. The project is scheduled for completion in March, with $2.67 million in funding from the U.S. Department of Energy.

Evaporation

For operators in remote areas without easy access to disposal wells and facing high trucking costs, one option for managing produced water is evaporation.

Gradient Energy Services (GES) recently brought to market its Carrier Gas Concentration (CGC) technology. Gradient completed a pilot of the project for a supermajor in the Permian Basin in 2019.

According to GES, the process involves evaporating water and concentrating dissolved solids in the wastewater stream via a multistage bubble column humidifier. GES has designed its fully automated and mobile system to run with limited supervision. The company stated on its website that the process results in clean vapor released into the atmosphere and a concentrated brine that can be used for drilling, workovers and completions or simply to reduce disposal volumes.

“Disposal constraints are becoming a major concern for operators in the Permian,” said Kushal Seth, vice president of applications and business development with GES. “Longer term, excess produced water volumes will create higher disposal costs, potential environmental liabilities and limited disposal capacity for E&Ps operating in the basin.”

The CGC system was recently adopted by an operator producing about 2,000 bbl/d in the Marcellus facing high disposal costs. As a result of logistical and policy challenges, the northeast has limited disposal sites and evaporation has faced regulatory challenges.

“Operators have considered evaporation in the past, but one of the key requirements for evaporation technology is strict regulatory permitting, specific to particulate matter [PM] emission levels,” GES stated in a recent case study. “Several evaporation technologies, such as submerged combustion or flash evaporation, will not meet the strict PM emission requirements and also require high levels of energy. As a result, operators would truck the majority of produced water to Ohio. This came at an extremely high cost of $8 to $15/bbl just to dispose of the produced water.”

GES provided the CGC for a trial, which evaporated 67% of the influent total, according to the company. Of the highly concentrated brine, about 33% was saturated to concentrations greater than 220,000 mg/L, which could then be used by the operator for drilling operations or disposal.

“The client was able to manage the water production while cutting the disposal costs by over 45%,” GES reported.

Operational flexibility

The first challenge for operators when addressing water management is securing the millions of barrels of water needed to fracture even a single well. Setting up adequate water supply, identifying water sources, negotiating rights-of-way, installing pipeline and storage units, and pumping water to the well site can take months of preparation.

Oftentimes, the distance between the water supply and well site can extend more than 10 miles, which requires the installation of miles of temporary pipeline. Flow-Sync, a Texas-based automation integrator, has built a skid-based water transfer pump control system for fracturing operations that optimizes and simplifies complex water transfer logistics. Flow-Sync utilizes Bedrock Automation’s Open Secure Automation technology that enables better control of the complex pump control to manage water flow.

“Water is probably a more difficult problem to solve overall when in fracking than most other parameters because you need so much water,” said Albert Rooyakkers, Bedrock Automation’s founder and CEO. “You’re in a place where there is so little of it, and you have to produce the water to use it, and then you have to store it and treat the water once you’re done with it. So it’s a significant management problem for the users. And what Flow-Sync is doing is exploiting that process and providing this highly flexible infrastructure. They can run miles of flexible piping in days instead of months or years in order to run water infrastructure across miles of Texas or New Mexico or many other places.”

Rooyakkers explained that the entire Flow-Sync system is mobile, including the pumps, the flexible pipes and power generation. But total automation, he said, is what is paramount to drive costs down.

“You can control pressure more accurately, [and] you can control the sequential startup and shutdown of pumps more accurately,” Rooyakkers said. “With basic flow metering, you can conduct leak detection. Once you have some simple data, you’re not having to drive 10 miles to the next pump to manually check it. You can instantly get this data. By having the wisdom of human intelligence, looking at the data in a centralized location, you’re going to be able to achieve a lot of improvements in safety, reliability and operational integrity.”

Seismicity

A growing concern among producers and service providers in the water management industry is induced seismicity in the Permian Basin. Seismic activity can often occur in areas around saltwater disposal wells. While most instances of seismic activity are modest, more severe instances having been trending upward in the Permian over the past few years.

According to the Bureau of Economic Geology’s TexNet Seismic Monitoring Program, between 2016 and 2018, there were 284 seismic events measuring a magnitude of 2 or greater. Since 2019, there have been 699. On March 26, 2020, a record 5.0 magnitude earthquake occurred in the Permian Basin.

“When we started looking at the growth rate of these, the growth rate has been really incredibly high,” B3 Insight’s Bennett said. “I would say over the last few years it’s grown over a 46% rate just in terms of the number of instances. And we’re also starting to see more and more of the Permian affected by it.”

Bennett noted that the increased number of seismic events are not just focused in the Delaware Basin, where many of the initial problems occurred early on.

“We see a significant impact across not just most of Reeves County, but also large parts of Ward and Loving counties,” he said. “The growing number of events in the Midland Basin is of growing concern to the operators there and the [Texas] Railroad Commission, and it’s starting to result in real implications for operators in disposal capacity.”

Those implications have included capacity reductions during the permitting process and additional special conditions being added to disposal wells in terms of requiring additional data gather, ongoing seismicity monitoring and the implementation of earthquake response plans.

“The Railroad Commission has been looking at existing locations where there have been concerns about seismicity and adding conditions or simply saying [operators] need to revise permits,” Bennett said.

Reductions in disposal volumes have been credited with reductions in seismic activity in Oklahoma.

“In Texas what it means is that there is a lot more scrutiny on these permits,” Bennett said. “In New Mexico, it’s really starting to trend that way.”

According to B3 Insights, more than 500 new and amended disposal permits have been impacted by special conditions since 2019.

“When we think about the implications for the market, what we are seeing is that new wells being permitted today are smaller than they were last year, which were smaller than they were the year before that,” Bennett said. “So that really begs the question: If we have more smaller wells injecting into those formations where we already know there is some overpressurization, or there is a potential for those issues, will that require more significant investment in transporting water farther away from the origin of production?”

He added that such dynamics will likely continue to give rise to produced water recycling and reuse.

“These issues, a lot of them are local,” Bennett said. “But when you start thinking about them on a landscape scale, there is a lot of investment that is going to be needed to see this industry through.”