Podcast Transcript: Why Microbial Control Is Becoming More Important in 2020

Ken Wunch, energy technology advisor at DuPont Microbial Control, recently joined the MP Interview Series to discuss growing concerns in 2020 related to microbiologically influenced corrosion (MIC). 

[This podcast was recorded in October 2020.]

[introductory comments]

Ben DuBose: Ken, good morning. How are you?

Ken Wunch: I’m doing well, thank you. And yourself?

BD: Very well. Thank you for joining us. For our audience, any newcomers, in this MP Interview Series, what we typically do, we talk to a range of leaders and experts across the corrosion industry to break down some of the hot-button issues that are going on these days. In 2020, one of those issues definitely involves microbes, and we’ll be talking with Ken about why that is over the next 20 minutes or so. Ken, I think a good place to start off is by explaining your role. Also, for anyone who isn’t familiar, can you give us a little bit of background information about how DuPont’s technologies relate to the corrosion audience?

KW: Sure. Thanks again for having me, Ben. My name is Ken Wunch. I’m the energy technology advisor for DuPont Microbial Control, based out of Houston. My responsibilities are for business development, technology transfer, and shaping the innovation pipeline and strategy for global oil and gas applications. Relating to your corrosion audience, basically, uncontrolled biofouling, microbially influenced corrosion, which I’ll use the abbreviation MIC moving forward, and reservoir souring can all exacerbate corrosion. There are consequences of an inadequate microbial control program.

Dow Microbial Control (DMC) is the industry leader in microbial control. We have a very broad portfolio of biocidal actives, deep technical field, regulatory expertise, and we have unmatched testing and laboratory capabilities to customize microbial control programs to specific field conditions and issues.

BD: Your work specifically, I know, deals with the energy sector. What typically are some of the big concerns for oil and gas operators as it pertains to corrosion? What type of help do they really need on a day-to-day basis?

KW: When microbes are growing in oil and gas operations, they typically attach to a surface and form a protective biofilm that can become highly problematic and very difficult to control and eradicate. In oil and gas operations, these biofilms have three detrimental processes. The first one is MIC, microbial-influenced corrosion, where biofilms will form on equipment or metallurgical surfaces and create or exasperate corrosion mechanisms, leading to pitting corrosion, which can potentially lead to loss of primary containment (LOPCs) and equipment failure. The second one is reservoir souring or souring in general. Basically, bacteria or microbes will eat organic compounds. They’ll breathe in sulfate and biosulfate the way we breathe in oxygen, and they’ll exhale H₂S.

H₂S is deadly to personnel if you’re exposed in too high of a concentration. It devalues hydrocarbon, so sour crude is less valuable than sweet crude. And also itself, H₂S, is corrosive. The last one, a little bit less with corrosion but important to the industry, is biofouling. When you get the biomass growing, it can reduce conductivity through hydraulic fractures and decrease hydrocarbon transport and production. In conventional operations, it can dramatically reduce injectivity. The cost of implementing an effective microbial control program is really minimal compared to the long-term benefits of improved production rates, better asset integrity, and hydrocarbon quality.

That was the first part of your question. The second part of your question is, ‘What help do I think operators need?’ What I really think is operators don’t really understand the risk of poorly designed microbial control programs. For example, chlorine dioxide, bleach, other oxidizers are commonly used in water treatment and hydraulic fracturing due to its very low cost. The operator says, “I checked my box and I added a biocide. We are good to go. Let’s go run our operations.” Well, oxidizers provide a good short-term kill, but it offers no long-term activity and they’re also highly corrosive at higher prolonged doses. If it’s okay, can I do a little math for you, Ben?

BD: Yes, absolutely.

KW: When you talk about the water use in completions, there are about a million cells per mil. In log, that’s 10 to the sixth. When you look at oxidizers, a lot of times you’ll get oxidizers, they say, “We have a 99.99% kill,” which is four logs, and it sounds great. I’m killing 99.99% of the organisms. But that leaves 100 cells per mil alive and getting dumped into your reservoir. Not all these cells are going to survive because the reservoir is a hot, salty, and pretty nasty place for a lot of these microbes to grow. But we estimate about 1% will. So out of that 100, you have one cell surviving per mil. Now one cell per mil, no big deal. But when you consider that a gallon of water has about 4,000 ml, so that’s 4,000 microbes. When you pump 5 million gallons of water in an average frack job and multiply that by 4,000, you are injecting 20 billion microbes into the reservoir that can thrive, form populations, produce H₂S, because of a poorly designed biocide program. To put it in perspective, the earth’s population is 8 billion. So at the end of the day, the operator has wasted money in paying for the oxidizer and also potentially caused massive and chronic corrosion, souring, and biofouling issues.

There are other chemistries as well that can cause problems. Other one is TTPC, which is tributyl tetradecyl phosphonium chloride. It’s a quad-based biocide common in hydraulic fracturing, and it’s marketed as both quick-quick biocide for top side as well as a long-acting preservative down hole. But under real-world conditions, this chemistry has issues. It’s deactivated by high TBS. A lot of the water they use in frack is salty, interacts with potential — and potentially damages frack packages, slick water fracks. And it’s deactivated by binding to proppant and shale. Just like oxidizers, TTPC is not available for long-term control. And if you don’t have long-term control, you're putting 20 billion bacteria into your reservoir to go wreak havoc.

The last thing about this question, when we recommend biocide packages for longer-term control, we basically look at our AQUCAR glutaraldehyde and preservative DMO and THNM formulations.

BD: With 2020 specifically, is there any new feedback that you've heard from oil and gas clients this year? You’ve got these production slowdowns. You've got periods of inactivity with the pandemic going on, COVID-19. Also lower oil prices, which are somewhat tied in with that. Does that potentially increase the corrosion issues that these operators might face? If so, what are some of the strategies that they can potentially adopt to address that?

KW: Basically, as the demand and price for oil and gas has decreased in this truly unprecedented time, operators are shutting in a lot of wells. I’ve seen wells they’re shutting in because there’s not the same demand for the product. There’s also a lot of ducts. Ducts are drilled but uncompleted. A lot of times, operators have to drill on a lease to keep the lease. But they don’t go through the rest of the process of completing a well, so they’re called ducts. What happens is, whether the operation is new, online, paused, or planning, these microbes can be injected into the reservoir and the operations still need to be managed. These shutdowns, these ducts or shut-ins, are potentially increasing the bacterial formation down hole. I’ll keep referring to the 20 billion. The 20 billion bacteria. If you have poorly designed treatments, these 20 billion bacteria can cause lots of issues down hole, H₂S, corroding down-hole equipment and waiting to colonize top-side equipment once production happens.

The proper use of biocides can help protect operations from these microbes. But selecting biocides that are effective and compatible with the operation, with the needs of an operator, is really key. We really go in, with these ducts and with these long-term shut-ins, we advocate long-lasting, what we call preservative biocides that can protect the reservoir and operations for weeks to months. Specifically, some of the ones that we recommend are glutaraldehyde formulations. These are kind of the workhorses of the industry and very commonly used.

And as I mentioned earlier, preservatives. DMO and TH&M are preservative chemistries that are very slow acting, but they remain efficacious in the reservoir and can delay these souring or corrosion for a period of months. Basically, benefits by adding them, you can add a one-time dosage that provides months of protection and can reduce OPEX because you don’t have to use H₂S scavengers or corrosion inhibitors nearly as much. And you reduce CAPEX. You don’t have equipment failures or pitting corrosion in your lines.

BD: Another theme along those same lines that we’ve heard some in 2020 is companies wanting to minimize, as much as they can, these in-person maintenance visits. That’s because travel, logistics, all of that stuff during COVID, can be pretty challenging. What types of technologies can potentially help out if an operator wants to minimize the amount of in-person maintenance visits? I’m guessing that these packages that you're referring to, one of the benefits is that, if you invest on the front end, then especially during COVID, you reduce some of the in-person maintenance that you might have to do on the back end. Is that right?

KW: Yes, Ben. You answered the question for me. Well done. Exactly, the point you made. If you control the microbes for a longer period of time, that means the less amount of trips you have to make to the field to maintain your production equipment because bugs have come up and are producing H₂S, so you need to add scavenger. Or bugs are coming up into your production equipment and causing corrosion that you need to do interventions or add corrosion inhibitors or add more biocides. Yes, preservative chemistries really preserve the well and allow operators and field personnel to not have to visit the operations as much.

BD: We’ve talked a lot on this podcast about the technologies that are out there now, the options available to oil and gas operators. Moving forward, what technologies are you hoping to further develop in the coming months or years? What type of feedback have you gotten from the industry as far as what they need to be further developed and enhanced moving forward?

KW: One of the big things, and I’ve talked about it in this podcast, has been biofilm. We are focusing a lot of efforts on better biofilm control. Chemistries — not only chemistries but other technologies. A lot of times you typically associate microbial control with biocides. But there are other technologies out there, non-biocidal technologies that can help control biofilm. So we’re spending a lot of efforts in our R&D group working on that. Obviously, greener, more sustainable, greener chemistries are also important. It’s a little bit difficult right now in the applications. A lot of operators are just trying to keep their doors open. So having chemistries isn’t a priority.

But as the industry comes back, which it inevitably will, greener and more sustainable chemistries will be very important. The last thing we’re spending a lot of time on is targeted sulfide production inhibitors. As I said earlier, these sulfate reducers eat hydrocarbons. They breathe in sulfate and they exhale H₂S or sulfide. We’re working on new technologies to specifically control this mechanism and prevent H₂S production in oil and gas operations.

BD: You guys at DuPont are obviously a very large company. Moving forward, what’s the timetable? You mentioned that right now, there’s a little bit of a survivalist mode because of how 2020 and the pandemic, the lower oil prices, how that’s just thrown the industry into chaos. So I’m guessing certainly this year, maybe 2021 as well, you’re at a point where a lot of these companies are just trying to do what they can to stay in business. But at some point down the line, as you mentioned, you might see some of these greener technologies becoming more important again. Is there any time estimate that you guys are working on for when that might be? I’m guessing, the consensus from the people I’ve spoken to is 2022 when you might have something closer to normalcy. Is that what you all are thinking or is it even longer than that?

KW: I think the end of 2021, early 2022 is when we’ll come back to where we were before COVID. When you think about conventional operations, they’re still going, because they’ve already made all their CAPEX investment in keeping going. So those operations are still moving. When you talk about hydraulic fracturing, the activity’s really low right now. We don’t expect to do a lot more work or get into the field with operators until first quarter 2021, and then I think your estimate’s pretty spot on. End of 2021, early 2022 before operations start coming back and the demands for better technologies really kick in because cost pressures aren’t as high.

BD: That makes sense. As always, great insight there. Ken Wunch, energy technology advisor at DuPont Microbial Control. Ken, before we sign off, if anyone listening wants more information from you or DuPont, how can they get it? What’s the best way that they can access further resources from you all?

KW: You can visit DuPont Microbial Control’s LinkedIn page or website. You can visit my LinkedIn page, which has all my activity and experience in the industry. Or feel free to email me. It’s kenneth.wunch@dupont.com. Happy to field any questions from any of your listeners, and Ben, thanks so much for having me on your podcast.

BD: Absolutely. Thrilled to do it.

[closing statements]