Earthquake activity in West Texas is on the rise and, as of last year for the first time, Texas leads California in earthquake activity greater than 2.5 on the Richter scale. Both Texas and New Mexico have reacted with rules that limit deep well injection in those geographical areas until earthquake activity subsides.
As alarming as this may sound, this is a problem that has already been solved. For those of you familiar with the work of Mark Zoback, who is a professor of Geophysics and the director of the Stanford Natural Gas Initiative at Stanford University. He also co-directs SCITS Stanford Center for Induced and Triggered Seismicity (SCITS). Professor Zoback’s work was used in Oklahoma to reduce seismicity and essentially resolve the problem. The solution was to decrease the density of wells in the geographical areas of the seismic events and essentially reduce the volume of produced water injected. I know this is an oversimplification that will make my geologist friends upset, but essentially, this is the solution.
The problem is that the Permian basin produces much more water than other basins, as much as 10 times more in some areas and on average 4-6 times more. Redirecting these large volumes isn’t easy, and then spread the problem over two states, and you add another level of complexity. As New Mexico gets more aggressive on seismicity, more produced water finds its way across the border to Texas, where earthquake activity is also on the rise. Again, the Permian basin solution becomes a bit more complicated than Oklahoma, but the solution is the same, reducing injection volumes, especially deeper injection.
Is recycling the solution? I’ve heard many people call for more recycling, but this isn’t a permanent solution. By the numbers, if we recycled all of the produced water as a completion fluid, we would only account for about 30% to 40% of the total volume. To complicate this, some landowners restrict recycling to allow them to sell well water; in other cases, the completion activity is far enough away from the produced water volumes that there is a logistical hurdle.
So, practically speaking, 100% recycling will not occur across the Perman basin. Yes, there are plenty of operators at 100% recycling within specific geographies, but as an industry, we will not see 100% recycling across the entire basin. Then, there is the problem of completion activity or reliability. Completion activity is tied to oil price and, like oil price, fluctuates. It can never be a reliable outlet. And, realistically, completion activity will stop and produced water will continue to flow, so recycling as a completion fluid is, at best, a temporary measure to offset disposal volumes.
Will beneficial reuse have an impact? So, as we limit disposal in the seismically active areas, what is the solution? Personally, it will be a combination of things. We will see some larger produced water handling systems moving water to less seismically active areas; we will see an increase in recycling, also an increase in the use of evaporation where practical, understanding that salt drift will be the main concern there. Another promising area is waterflooding in unconventional wells. And finally, a transition into beneficial reuse. Although this seems like a likely approach with every major oil company in the search for the best desalination technology, this will not be easy.
New Mexico Governor Michelle Lujan Grisham announced at COP28 in Dubai recently a program to buy produced water for reuse in industrial and clean energy applications. In Texas, Proposition 6 passed on Nov. 7, 2023, creating the Water Fund Amendment. In both these cases, money will help offset the cost of desalinating produced water. Today, this is a very expensive process, and conventional technologies have not been effective, leading to more energy-intensive approaches of thermal distillation for the separation of salts. So, with some subsidies, beneficial reuse can become another option.
But, unfortunately, there are other regulatory hurdles that must also be overcome that make this an even more complicated option, but likely the most important option listed. You see, produced water is a new potential water source that is primarily overlooked. It is difficult to find a new water source produced in the millions of gallons every day. If we overcome the regulatory hurdle, the oil and gas industry can become a net supplier of water, as well.
Is the produced water industry ready? Things will continue to get more complicated in the management of produced water. In New Mexico, we have new Volatile Organic Compound (VOC) standards that will apply to produced water, requiring a 25% reduction by 2025. At COP28, the U.S. EPA announced new methane rules, which also include produced water.
When I look at produced water management today, I’m frankly disappointed. We essentially pay attention to a few parameters—bacteria, iron, sulfides and solids. Yet, most companies do limited testing, use the wrong test methods, and don’t know the difference between total iron and soluble iron.
For bacterial disinfection, most water professionals are familiar with CT disinfection, but not in the oilfield water management arena. This is a concentration and time formula that has already been calculated for many viruses and bacterial strains with different oxidizers, yet the oilfield uses ORP (Oxidation Reduction Potential) values, ignoring the time dependance, and, in many cases, are undertreating their water.
For simplicity, injection manifolds add the ORP probe near the injection point, this automatically results in a higher reading, leading to undertreating. Hydrogen peroxide is gaining in popularity and is great for iron and sulfide oxidation, but bad as a disinfectant. You will not find peroxide listed on CT tables, because, as it degrades, it can become an oxidation scavenger reducing free chlorine, oxygen and other oxidizers, meaning you no longer have residual disinfection. Adding to my disappointment is that many local labs in Midland and Odessa aren’t certified.
As we move into more complicated treatment methods, we need, for example, to incorporate VOC and methane testing, which requires zero headspace samples and chilling. Maybe even the use of preservatives in the sample.
We will see, for compliance testing, the need for certified lab results and chains of custody, verifying the zero headspace and chilling. The oil and gas industry knows this all too well in their environmental divisions, where compliance testing, certified labs, third-party labs, split sampling and strict compliance standards, and reporting are the norm.
But, in oilfield water, we have never faced this level of complexity or scrutiny. Are we ready? Will the industry internalize these functions? All I can say, if you want to continue to work in the oilfield water management industry, you need to step it up. We’ve stressed getting water volumes to the right location, over water quality, and our view of water quality has been a very “simpled” down set of parameters. We are moving toward a compliance-driven program, where reporting will be scrutinized, and fines will be issued as we move into testing for VOCs, methane and desalination for beneficial reuse. We need to get prepared for what’s coming, like it or not. Believe me, change is a good thing. WO
MPATTON@HYDROZONIX.COM / MARK PATTON is president of Hydrozonix, an oil and gas-focused water management company. He is a chemical engineer with more than 25 years of experience developing new technologies for wastewaters and process residuals.