How the industry is addressing the challenges and opportunities surrounding produced water.
Aris Water Solutions is working with ConocoPhillips, Chevron and Exxon Mobil on a desalination pilot project that is scheduled for completion at the end of September. (Source: Aris Water Solutions)
By
Sandy
Segrist
Hart Energy
Steve Coffee finds it ironic that an industry so reliant on hydraulic fracturing is just beginning to give water management the attention it deserves.
“Very few oil and gas companies have a water team or even a water person,” said Coffee, president of the Produced Water Society. “It’s hard to manage something if you don’t even have a person or small team responsible for it.”
According to API, the average fracking job uses about 4 million gallons of water per well, and that poses challenges. As the industry has grown, the infrastructure and logistics necessary to provide and dispose of millions of gallons of water for a single well—often in areas where supplies are scarce—have become more and more complicated. At the same time, the public is becoming more concerned about water supply and pollution, and the possible connection between reinjected water and seismic activity.
For the companies involved in midstream water management, current conditions mean a lot of opportunities are on the table.
Midstream water, once considered part of the oilfield services industry, is now a separate industry within the upstream space, according to an analysis released by Mercer Capital in May.
“Water management went from being kind of fringe and an issue that people would talk about like, ‘Ah, it’s so annoying’ to being table stakes,” said Kelly Bennett, co-founder and CEO of B3 Insight, a water midstream analytics firm.
“Now, if you don’t have a viable water management strategy, if you can’t understand where that’s going over the next X number of years, you do not have a viable company,” Bennett said.
Crossing streams
Although the midstream water sector has expanded rapidly in the 2020s, it is still growing into the role of a major energy industry player. According to the Mercer Capital report, there are only two pure-play public participants in the market, Aris Water Solutions and NGL Energy Partners, and although the midstream water segment has not seen significant M&A, growth dynamics are favorable for more acquisitions.
In May, Aris reported 15% growth year-over-year and an EBITDA of $53 million in the first quarter. The company is working with ConocoPhillips, Chevron and Exxon Mobil on a desalination pilot project scheduled for completion at the end of September. In June, NGL Energy Partners Water Solutions reported a record full-year adjusted EBITDA of $508.3 million, a 10% increase over the prior year.
During investor conference calls, both companies discussed the potential for expansion through M&A, and both said they were cautious about being too aggressive in the market.
Aris Founder and Executive Chairman Bill Zartler explained why the company is not pursuing an acquisition at present. “As this water industry has evolved and developed, the way businesses have grown has been very different in approaches around contracting and around building assets,” he said. “And so, we’re very careful in evaluating and valuing bolt-on acquisitions. We do think there’s some synergies there.”
Zartler said the Delaware Basin has a “tremendous opportunity” for growth, but because the water midstream industry includes a very diverse set of players, easy add-ons can be difficult to find.
NGL CFO and Executive Vice President Brad Cooper said his company is focused on its own projects.
“I think there’ll be a time for M&A here in the future,” Cooper said. “But as Doug (White, executive vice president of NGL Water Solutions) continues to bring the returns he’s bringing, we’re going to deploy capital to (the organic projects) to the extent we can ahead of M&A.”
One of the factors limiting consolidation of water midstream companies, according to the Mercer Capital report, is that E&Ps prefer a market with a multitude of options for bringing in, using and disposing of produced water. A major consolidation would most likely take away avenues of supply and disposal for a product that producers either need quickly or need to dispose of quickly.
A steel pipe drains suspension fluid into a hydraulic dump as part of the process to separate effluents for reuse of water in a closed cycle. (Source: Shutterstock)
A history of fossil water
Supply and disposal have been the primary drivers for change in the sector.
Expanding operations have changed things, but when the fracking revolution began, a lot of producers had a single option—themselves.
Although the total amount of water used for fracking varies by basin, an enormous amount of water is required in the Permian, which is the nation’s most productive play. The basin has been the focus of the U.S. water midstream development because of the volume of water used and the fact that the region is a desert where average rainfall is less than 20 inches per year.
Operators in the Permian Basin, as it became the unconventional production leader, were concerned primarily with getting enough water to drill. Around the 2010s, however, some companies took a more active role in addressing the problem of produced water disposal.
Fracking water contains chemicals and other materials and can bring additional impurities to surface when it comes back up. Water that is left untreated can be toxic and is no longer usable.
Initially, producers pumped produced water into subsurface formations. Though this process sometimes is referred to as “storage,” Coffee explained that the term is a misnomer because it implies the water will be extracted again at some point. “It’s pouring it down a drain in the ground,” he said. “You’re not going to be able to use it again.”
Seismic activity in basins across the U.S. surged along with the uptick in fracking. Although tying earthquakes directly to fracking activity is difficult—as the exact location and reason for a seismic event is hard to determine—several scientific studies have linked an increase in seismic events with well injections. Oklahoma, which had measured few earthquakes in the years prior, recorded more than 800 events with a magnitude of 3.0 or greater in 2016.
According to Bennett, the thought in the late 2010s was that deeper injection wells, often twice the depth of the earlier wells, would cut the seismic activity and provide more room for disposal.
“So all of a sudden, you have the ability to take way more water in these facilities. They may be significantly more expensive, but they seem like perhaps they’re a better reliable, long-term solution” he said.
With the introduction of deep wells, seismic activity diminished, at least temporarily.
Meanwhile, the scale of activity in the Permian led producers to develop an extensive network of water pipelines to cut trucking costs and move water more effectively. At the same time, technological advancements allowed lower quality water to be used in the fracking process, allowing for greater reuse, rising to around 10% to 15% before the end of the decade.
Same problems, different times
The percentage of reused produced water continues to grow, but with the current scale of fracking activity, particularly in West Texas and New Mexico, focus has shifted to the water midstream sector. A New York Times article in the latter part of 2023 addressed the growing demand for completions and its threat to the region’s aquifers. Politico discussed the same issue in June.
Meanwhile, earthquakes have become prevalent again in West Texas. On July 26, a 5.1 magnitude quake was reported in Hermleigh, Texas, a small town in Scurry County. The event was felt nearly 100 miles to the northwest in Lubbock and 250 miles east in Dallas.
In Coffee’s opinion, the focus on water usage could be helpful in the long run.
“More attention, probably, is what is needed to move the dial,” he said. “Really most of the reporting isn’t thorough enough, or it’s just one little slice. How do you write this big novel in 500 words?”
Governments are also taking a more active role. Colorado legislators ordered the creation of a research committee to study potential uses for produced water. In May, New Mexico revealed a draft of new prohibitions for discharging liquid into waterways or using it for agriculture, and provides a path toward more industrial usage. Texas has also been reviewing rules, potentially allowing for agricultural uses and possibly discharge in dry riverbeds.
Companies in oil and gas also are looking for solutions, Bennett said, but he thinks the industry does not get enough credit for the active role it is taking in dealing with its problems. He pointed to an example of an industry initiative called the Texas Produced Water Consortium. The program operates under the administrative oversight of Texas Tech University in coordination with the Government Agency Advisory Council and the Stakeholder Advisory Council.
“One thing that’s been pretty remarkable and very unprecedented, that the industry maybe doesn’t get enough credit for, is the incredible mobilization of research and science capital to fund it,” Bennett said. “It’s all focused on understanding this issue. It’s a huge amount of operational coordination to get the data that were needed to contribute to the scientific community, the academic community and to the industry itself to better democratize the understanding of what’s actually happening here.”
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