Water management

We have previously discussed Volatile Organic Compounds (VOCs) in produced water. In New Mexico, it became a requirement, effective January 2023, to start monitoring VOCs in produced water systems with storage capacities over 50,000 bbls. By 2025, VOCs will have to be reduced 30%, and by 2026, 35%. All of this is a result of New Mexico being established as a “non-attainment zone.” 

There are ongoing discussions within the EPA to establish the broader “Permian basin” as a “non-attainment zone.” If this happens, expect similar monitoring, followed by emission reduction requirements. Expect the management of produced water to become more complex as time goes on. Personally, I consider this an expected and welcome change. As we transition from produced water as a waste product to a resource, the complexity will increase, as we enter a more regulated environment. This, in turn, will require water management companies with a higher level of expertise. I see these as all positive changes for the water management industry, or at least for those that can keep up with the change. So, what about methane? 

In the case of VOCs, the EPA had already started publishing data, using produced water sources in Colorado and Wyoming. So, we can really anticipate some of these regulatory changes by paying attention to what the EPA is paying attention to. In the case of methane, this process is significantly accelerated. In September 2020, the EPA published “Inventory of Greenhouse Gas Emissions and Sinks 1990-2019; Updates Under Consideration for Produced Water.” They updated this memorandum in April 2021. In this document, they established “Emission Factors (EFs)” for methane for produced water from the Powder River basin in Wyoming and the Black Warrior basin in Alabama. They then established EFs by adjusting this, using methane-specific data for Colorado and the Gulf Coast Region. So why are we paying attention to the methane EFs, and what does this mean? 

Methane regulations and the IRA. Methane regulation has taken a complicated path. In 2016, EPA adopted “New Source Performance Standards,” or NSPS. The NSPS only applied to facilities constructed after Sept. 18, 2015. This was later rescinded under President Trump but re-established under President Biden. Additionally, under the “Inflation Reduction Act” (IRA), there was the establishment of a “Methane Emission Reduction Program” (MERP). Under MERP, there is a methane charge, starting at $900/ton in 2024, $1,200/ton in 2025 and going to $1,500/ton in 2026. Then, there is the “Responsibly Sourced Gas” (RSG) certification, which we have discussed before. All of these requirements drive methane reduction programs to the point that methane emission reduction has become an industry to itself. 

There is a bit of carrot and stick going on here. With RSG, there is a certification process, with companies like MiQ and Project Canary leading the certification process. Under this process, your methane intensity has to be below industry standards to become certified. There are other factors, including water usage, that factor into this certification. The idea is that with ESG and Carbon Zero goals increasing, natural gas users will begin requiring RSG and potentially, RSG will trade at a higher price. These certifications use third party auditors. Roy Harstein, with Responsible Energy Solutions, is an experienced auditor, who has tremendous oil and gas experience, if you’re looking for more advice on this topic. The upside of RSG is the carrot; the stick is the methane charge established under the IRA. 

Methane and produced water. We’ve talked about how the IRA has bolstered decarbonization through the increasing of 45Q tax credits for capture and sequestration of CO2. The IRA also added the methane charge and, additionally, new requirements for produced water tanks by requiring a “Methane Standard.” Previous to this, methane EFs didn’t apply to produced water, just surface facilities. Now, methane has entered into the produced water management arena.  

I know, this was a long introduction to methane in produced water, but I think the background is important. There will be methane EFs for different areas, and your produced water will factor into a calculation to estimate your Methane Intensity. If your methane exceeds the standard, then you will be charged $900-$1,500/ton for the excess methane. This will drive the need to understand methane levels in produced water and how to mitigate them, to reduce them. Many conventional processes exist today for methane removal, but, unfortunately, most will not work well in produced water. So, where does that leave us? 

How to reduce methane in produced water. When disinfecting produced water, the choices are oxidizers or biocides. Fortunately, choose the right oxidizer, and it will reduce methane. Biocides will have no effect on your methane. So, this creates a preference for oxidizers for bacteria control. This is the same for VOCs which can also be reduced by the right oxidizer.  

One potential area of concern is the use of chlorinated oxidizers, which, in the presence of organics like VOCs and methane, can produce chlorinated organic byproducts. There is an actual EPA Disinfection Byproduct Rule that requires monitoring for these potential byproducts. So, alternatively, non-chlorinated oxidizers would be preferential and Advanced Oxidation Processes (AOPs), which have had great success with organics oxidation.  

We have conducted tests with AOPs and exceeded 90% removal of VOCs and methane reduction to Non-Detect (ND). Popular AOPs are combinations of ozone, peroxide and UV, none of which include chlorine to prevent the byproducts I mentioned earlier. Be warned, not all oxidizers are strong enough to reduce VOCs, so pick the right one. We have had great success with ozone and combinations of ozone and peroxide as an AOP. AOP chemistry is very tricky; in the right ratio, there is a tremendous increase in oxidation. But, get the ratio wrong, and there will be a detrimental effect. The good news is by adjusting your current treatment process, you can effectively reduce both methane and VOCs in produced water. 

We have mentioned previously that managing produced water will be more complex over time, and it needs to be, as we get toward reuse and beneficial reuse. Reuse and beneficial reuse will require meeting new standards with a much higher level of scrutiny, and the industry must prepare for this. So, this increase in complexity is not only a certainty, but it must be embraced, if you expect to continue managing produced water. And believe me, it will get more complex—just wait and see what happens when benzene enters the discussion. But that’s a topic for the future. 

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.