Produced water management remains an ongoing challenge facing operators in the heart of the US shale sector as they also deal with tightening inventories of new well locations and a more muted oil price outlook. The pressure is greatest in the Permian Basin where produced-water volumes dwarf the record volumes of oil being produced there each day.
Since the beginning of 2017, tight-oil production in the region has expanded from about 1.5 million B/D to nearly 5.8 million B/D by the end of 2025. Over that same period, produced-water volumes more than doubled, rising from about 11.2 million B/D to nearly 24 million B/D in 2025, according to data from the Texas Railroad Commission (RRC), which regulates the state’s oil and gas sector.
Since only a fraction of this water is needed for recycling for hydraulic fracturing operations, the majority is simply returned to the subsurface through saltwater disposal wells, an almost century-old practice that has drawn increasing scrutiny as induced seismic activity has intensified.
In the Delaware Basin, which makes up half of the broader Permian region, more than 8,000 earthquakes exceeding a magnitude level of 2.0 have been recorded since 2017, including 10 events above magnitude 4.5. Earthquakes of that size are not only felt on the surface but can also cause damage to structures and infrastructure.
Researchers from The University of Texas at Austin said in a 2025 paper that they used satellites to find that the injections also led to as much as 20 in. (53 cm) surface uplift across an area of almost 2 sq mile (5 km2) in one part of the Permian that was followed by a gradual subsidence of almost 4 in. (10 cm) after a blowout event relieved some of the pent-up pressure.
In response to induced seismicity, operators and disposal companies began adjusting injection strategies around 2022, moving volumes away from deep basement formations where quake-prone faults are more common and toward shallower layers of reservoir rock.
While this approach appears to have reduced seismic risk in some areas, it has introduced a new set of problems. Primarily, the shallow injection zones have been blamed for watering out some producing wells and, in more severe cases, to uncontrolled flows of produced water reaching the surface through long-dormant orphan wells with poor to nonexisting zonal isolation.
Texas has seen some high-profile incidents in recent years due to this issue. In one 2022 case, an orphaned well released an estimated 25,000 bbl of produced water to the surface over a 2-week period before it was successfully plugged. The UT at Austin research team, which included geoscience and geology experts, concluded that elevated pressure and fluid migration from that event may have been redirected to a nearby well only a few hundred meters away, which experienced a blowout roughly a year later and remained unplugged for 6 weeks.
With each of these incidents potentially requiring multimillion-dollar remediation and cleanup efforts, the Texas RRC received $100 million in state funding in 2025 to address orphan wells and reduce future risks.
The region’s operators are also increasingly paying closer attention to where their produced water ultimately ends up. A representative from Chevron said at the recent SPE Permian Basin Energy Conference in Midland, Texas, that the supermajor is working with third-party disposal firms to track injection locations relative to its tight-oil operations, with a preference for disposal sites farther from producing assets where additional pore space is believed to be available.
But there is another option beginning to gain traction.
Beneficial reuse of produced water has been discussed for at least a quarter of a century, but high treatment costs, the sheer availability of subsurface disposal sites, and questions around the environmental impact have largely rendered this approach moot. However, there are a handful of pilot projects in Texas trying to change all this.
In October, JPT featured a report exploring the potential of using treated produced water for cooling purposes at newly constructed artificial intelligence data centers. But Texas regulators are also considering whether to allow the discharge of treated produced water into some of the state’s rivers and smaller tributaries.
The Texas Commission on Environmental Quality (TCEQ) is reviewing at least four permit applications that would collectively allow more than 18.7 million gal/D of treated produced water to be discharged into the Pecos River watershed and the Lower Atascosa River—both found in west Texas. That volume is equivalent to about 445,000 B/D of treated produced water.
Some of the permit filings indicate the discharges may contain trace amounts of organic matter, ammonia, volatile organic compounds, and total dissolved solids.
As one might expect, the permit requests have drawn concern from scientists and environmental groups. Some applicants have reported low but detectable levels of naturally occurring radioactive material along with benzene, toluene, ethylbenzene, and xylene—a toxic mix collectively known as BTEX and one that is very familiar to anyone in the oil industry that works with produced water.
Regulators acknowledge that standards for safe levels of some constituents in discharged produced water are still evolving. In a report cited last year by The Texas Tribune, TCEQ said it intends to set discharge limits for both currently regulated pollutants and others not yet addressed under existing law.
The Tribune also noted that Texas joins a small group of US states, including Wyoming and Pennsylvania, that have permitted produced-water discharges, where past experience has shown mixed environmental outcomes. In contrast, neighboring New Mexico has opted to delay approval pending further study.
Given the scale of Texas’ oil and gas industry, the state represents a major test case for how beneficial reuse might be implemented. The Texas RRC is supporting pilot studies focused on safe reuse pathways and has stated that one of its core objectives is to establish public confidence that treated produced water can be reused in ways that protect human health and the environment.
Outside of river discharge, the use of treated produced water for nonedible crops such as cotton or grasses has been discussed for years, in part because it is viewed as a lower-risk option than reuse strategies with more direct human exposure. Last March, Houston-area-based Tetra Technologies announced a pilot project with US independent EOG Resources to treat and desalinate produced water from the Permian using proprietary technology. The pilot will assess water quality, recovery rates, and potential nonpotable reuse applications, including a rangeland grass growth study.
Success for these projects would not only strengthen the industry’s case for beneficial reuse, but could also help address water stress in west Texas, a region rich in hydrocarbons but chronically short of fresh water. And beyond Texas, the outcome may influence how other producing regions and countries approach the issue.
A recent paper, SPE 225604, authored by researchers at the University of Wyoming, notes that adequately treated produced water could supplement a significant portion of the fresh water consumed by the oil and gas industry while extending to livestock, irrigation, and even potable water applications. While conversion to drinking water is not yet a practical option due to cost, the paper also highlights the potential to extract valuable minerals such as rare earth elements and lithium from produced water, as well as its possible use as a feedstock for hydrogen production.
Researchers in the fresh water-scarce Middle East are also examining approaches to produced-water treatment. In SPE 218959, authors representing the UAE environmental regulators and local academic institutions reported that inorganic ions commonly found in produced water, including sodium, potassium, calcium, and chloride, are generally not a major concern for offshore discharges but pose greater risks when released into surface waters.
Their paper also notes that nutrients such as nitrate, phosphate, ammonia, and organic acids can overstimulate microbial and phytoplankton growth, while some treatment chemicals themselves may be toxic, increasing pressure on technology developers to limit residual concentrations.
In addition to what remains in the treated water, there is the issue of cost, which has long been the tallest hurdle for technology developers and regulators to clear.
More recent analysis from Texas A&M University’s Real Estate Research Center cited state data and figures from the US Department of Energy showing that subsurface disposal of produced water typically costs about $0.60/bbl. Treating produced water for agricultural use can raise costs to as much as $4.00/bbl, while treatment to potable standards can approach $7.00/bbl, an order of magnitude higher than injection disposal.
If economic, regulatory, and public-trust barriers can be resolved simultaneously, then it can be argued that beneficial reuse could help many millions of barrels of produced water move from a disposal liability toward a new resource for the communities that host some of the world’s biggest oil and gas operations. Of course, this will be a highly monitored effort and only time will tell if the engineering and money going into it will actually solve one of the industry’s growing challenges.
For Further Reading
SPE 218959 Produced Water Treatment and Reuse Options: Alternatives for Sustainable Water Resources by M.A. Dawoud, A. Sefelnasr, A.A. Ebraheem, and F. Alnaimat, et al.
SPE 225604 Water Resources for Hydrogen Production in Wyoming by E. Holubnyak, D. Jones, S.M. Buckhold, and C. Nye, University of Wyoming.
