Water management

It seems like there will always be continuous change in the oilfield water management sector. I recently talked about the new changes announced at COP28 by the U.S. EPA, announcing the Methane Emission Reduction Program (MERP), and included in MERP were emission factors (EFs) for produced water. As a re-occurring theme, managing produced water will get more complex. 

Also announced at COP28 was a new program from New Mexico Governor Michelle Lujan Grisham, which provides up to $500 million in state funding for new water sources, including treated produced water. Unfortunately, on Thursday, Feb. 15, 2024, there was a setback in New Mexico. Governor Lujan Grisham scaled back the program to $100 million and eliminated produced water, but even that change didn’t get support for the governor’s program, and the state closed its session without approving the new legislation. It’s not completely dead, as the New Mexico Environmental Department (NMED) will be responding to a request for information on the legislation by March 31.  

Despite the state’s dwindling water supplies, the environmental groups opposing this legislation seemed to get a win this round. The main argument here is the potential risk to aquifers. This argument is a bit disingenuous, since the treated produced water was looking at industrial sources and not public consumption. This is unfortunate, because you will continue to see potential drinking water being used for industrial purposes in a state that already has a water supply problem. But the fight isn’t over.  

Lithium in the Permian and elsewhere. In other news, lithium has been recovered successfully from produced water in the Permian basin. This may be exciting news to some, but the economics are still not well-defined and, more importantly, we have seen recent discoveries in Nevada that have been called “potentially the world’s largest lithium deposit” at the McDermitt Caldera.  

Additionally, a discovery at the Salton Sea in California has been reported to supply 40% of the world’s lithium demand. We also have the Great Salt Lake in Utah as a major source, while ExxonMobil continues its plan for lithium from Arkansas’s Smackover region. You see, the amount of lithium in the Permian basin produced water, or produced water in general, is much lower than other sources. It is more likely that these economically more attractive options will be considered first, making any commercial operations for lithium in the Permian basin not very likely. 

Staying the course. It may sound like things are not going well for produced water management, but no one ever promised you there wouldn’t be adversity. We need to stay the course, which means overcoming the legislative and public perception hurdles to get to beneficial reuse. Of course, this may take a few years, but it’s a critical step towards our future. We will continue to see growth in the recycling of produced water, as completion fluid and disposal wells will continue to provide the majority of our capacity. We should explore enhanced evaporation, especially where seismicity requires new capacity that isn’t disposal wells. 

Injectivity/solids control. One area that deserves further exploration—or at least some level of discussion—is improving injectivity in disposal wells. Improved solids control has always been a method to improve injectivity, but in the oilfield water management world, before seismicity, improved solids control and the cost associated was not worth the lower injectivity. But in today’s seismically challenged disposal networks, does improving injectivity move the needle enough to reduce seismicity? 

I could never understand why we adopt solids control in produced water recycling programs, where a clean brine is used to carry sand (i.e. proppant) that can have 10-20% fines, but not in a disposal well, where the improved injectivity will lower pump pressure. You start off, after all the upstream processes, wellhead separation, tank batteries and gun barrels, at the disposal well, with produced water that goes as high as 300 ppm of Total Suspended Solids (TSS). Clean brine gets this standard to under 50 ppm.  

Then, we put this treated product in a storage pit, where dust loading gets it back to 100 ppm or higher. Then we add our sand fines. The sand fines, alone, amount to 7,500-15,000 ppm of TSS. This does not count the sand, however; the sand is assumed to be filling the fractures, but the fines stay in the fluid. It makes no sense. 

There’s also the argument that I’m preventing the solids from filling my pits. We evaluated that, and most operators empty their pits regularly to inspect the liners; they wash down the solids and dispose of them. This can cost anywhere from $150,000 to $300,000, depending on the size of the pit, with the disposal of the wash-down being about 50%. Even if we pretend that this cost can be eliminated, it can’t, because you are still washing down your pit, and there will be dust loading.   

However, maybe you can reduce the solids, so that the disposal cost is reduced. Now compare this to a 50,000-bpd operation, where your solids control is costing you at least $0.10/bbl and you’re paying $1,800,000 annually to potentially save a percentage of $75,000–$150,000 per year?  

There have been operator studies that have already proven that a clean brine does not give them better producing wells, and if you’re not saving money on your pit clean-outs, then why? But when it comes to injectivity in a disposal well, where you are reducing injection pressure, potentially getting more capacity, lowering utility cost and potentially reducing seismicity, why not spend that money there? 

It's about reducing seismicity. We need to allocate money in the right places, and anything to reduce seismicity or potentially reduce seismicity should be explored. We can’t get distracted by things like lithium recovery when the economics are not favorable. We can’t take our eyes off the prize, which is beneficial reuse, but even with beneficial reuse, we will produce a concentrated brine, so disposal wells will never go away. We need to understand how to use injectivity to reduce seismicity. We need a disposal well water quality specification, not a recycling one. For recycling it’s basic: bacteria, sulfides and iron—that’s it. Let’s allocate our resources more strategically. 

So, even with the recent setbacks in New Mexico, we need to continue the march towards beneficial reuse. We may need to explore some enhanced evaporation to compensate for capacity shortfalls, but we also need to make sure we are not spraying salt everywhere, as well. I will continue to say it: “imagine a future where oil and gas is not only the provider of clean energy but also clean water.” Now that’s a future we should march towards. 

About the Authors

Mark Patton

Hydrozonix

Mark Patton is president of Hydrozonix and has more than 30 years of experience developing water and waste treatment systems for the oil and gas industry. This includes design, permitting and operation of commercial and private treatment systems, both nationally and internationally. He has seven produced water patents and two patents pending. He earned his B.S. in chemical engineering from the University of Southern California (USC) in 1985.