Oilfield Water 360 brings together industry experts to explore the latest trends, challenges, and innovations shaping water management in the oilfield. In this discussion, Select Water Solutions’ Christina Williams and Rob Blake dive into what 2025 holds for the industry—covering efficiency gains, produced water recycling, regulatory shifts, and the evolving role of chemistry in completions.
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Full Transcript
Hello, everybody. Welcome to Oilfield Water 360.
My name is Christina Williams, and I’m Senior Director for Integrated Solutions. And I’m Rob Blake, Senior Technical Advisor of Select Chemistry. Today we’re really excited to start a conversation of what 2025 looks like for the oil field.
Well, with customers that I’ve spoken to, they are excited. Last year, we had a lot of M&A activity, and that was kind of the theme of the entire year. This year, the customers are ready to get back to work.
You know, there was a lot of consolidation of operators, but that doesn’t mean there was a lot of consolidation of activity. If anything, activity is looking to grow.
We saw the frac crew count kind of dwindle slightly Q4 last year, and we’re looking forward to a slight uptick in frac crew count growing. You know, we have big operators like Halliburton and Liberty who say they are fully committed already with frac fleets this year.
So we’re looking forward to it. It’s a really optimistic view with the customers. You know, there’s something in the air about it. An example of that is our current Energy Secretary, Chris Wright.
He’s from the industry. He’s a big proponent of it. And right now, he’s taking a look at permitting reform, and that could be huge for the oil and gas sector as well as the overall energy sector as a whole.
But everybody I meet, everybody I talk to is very positive about 2025, and we’re really looking forward to getting back to work. Having the new administration, you think that that’s really going to, is that going to transcribe to more activity or about the same?
You know, the oil field is very cyclical and has its ups and downs. I think we’ve learned over the years not to just jump into a boom immediately. There’s a lot of factors that play into that, like the price of oil, the continued M&A activity, just the appetite for spending capital.
You know, really the theme is we’re doing more with less. So there are fewer rigs, but they’re more efficient. There are fewer frac fleets, but they’re more efficient.
So we’ve taken that from the industry and kind of reflected that ourselves and tried to help the customer base do exactly that, do more with less. So tell me, what do you think Select is doing to be more efficient?ra
Well, a big thing in our company is the idea that we can do more with less water is a big thing, not only monetarily, but just as an environmental responsibility.
We originally had a lot of freshwater sources, and it was pretty easy to get a new one, and it wasn’t too hard to track down a totally clean, fresh volume of water to complete your wells.
Well, the frac volumes at that time were smaller, and we were doing single well operations, maybe a zipper here and there, and we had plenty of fresh water all the time. Now you have operators that want to complete large pads, multiple wells, all at the same time.
Some of them are even pumping up to 24 hours a day, and they can add on multiple fleets to pad simulfrac operations or trimulfrac operations, and this has really just increased the demand for water.
But also, just from a cost constraint, we can’t just continuously use endless supplies of fresh water. It’s limited.
So we take the water from existing operations, from existing projects, recycle it, treat it, reuse it, and use it again in the same scenario over and over again, and that’s where our focus is, is what are the limits of that, and we keep pushing those limits.
In the Delaware Basin, New Mexico, they also have a few fresh water resources. We’re having to really take a long and hard look at how we do things to make them more efficient.
They also have very few permits for disposal, like the disposal capabilities are almost capped out, and so the only way to move forward would be just to recycle the water.
Correct. They are extremely restricted on what they can do with fresh water, and that’s really pushing the limits. It’s leading the edge, as far as technology, on how much produced water they can use and how they use it, and absolutely, chemistry makes a big difference.
You have to really look at your water, look at the operation, and really tailor what you’re doing in the completion space for that, as well as water transfer.
It’s not easy to move these really heavy iron, really heavy sulfur waters long distance and have no spills, but each basin is different.
Some basins are still running fresh water, some still have a large supply, but as we evolve through this water reuse, recycle phase, I think all basins will eventually get to the point where they’re using produced water, as well.
With that said, is there anything that you see, you’ve mentioned produced water, what is it that we’re doing with produced water that is so different from everybody else in the industry?
Well, sure. A lot of the existing infrastructure, as you know, Christina, being in an infrastructure is based on fresh water when it was developed. Select took that idea and kind of adjusted it for produced water, so we came out with new technology like the Tide line, water transfer lines that come in different sizes, so our scientists on both sides came into the lab and asked us to begin testing with them.
Their curiosity was how we could eliminate damage to our water transfer lines, our hoses in the field from a couple different fronts.
One was UV, obviously, the sun is a big driver of damage to those, and the other was chemical resistance to what’s in the produced water itself.
They noticed that the more produced water they run, the more issues they saw with the materials of their hoses that they were using. Christina, when we started looking at the different specs in the industry for water transfer hoses, it was kind of all over the place.
They would list a specification, they would list a burst pressure, they would list a rating, a flow rate, and we began testing that in the lab with both the water side and the chemistry side, and what we found was it was kind of all over the place.
There wasn’t really a true set metric, and those that had metrics, they didn’t really meet it with the materials and the quality of product that they had in development at the time.
So that’s something we really looked at. What is the standard, how to get there, and then how do we do that with the materials we use in our hose?
So Tideline really achieved those things. Like you mentioned earlier, it’s really setting the standard of the industry of what transferring produced water through temporary transfer lines looks like in the future.
I think produced water is key to do anything in the future when it comes to frac. Not only because of ESG incentives, it allows us to continue fracing because we are not limited to freshwater resources.
I think with the use of produced water, it takes a lot more technology to be able to those wells, because you’re commingling water and that creates a whole other slew of problems, scale, paraffin, it’s just, it takes a more refined solution to be able to do those things, but it will allow the oil field to continue doing them long term.
No, that’s a really good point. You know, as technology adapts, I’ve seen we are adapting with it, and I think that’s a very important thing to do.
So your ancillary chemistries, biocide scale, clay control and surfactants, all of these have to work with that produced water, and so the more we recycle and reuse the produced water, the more cycles it goes through, it picks up chemistry and minerals and oil and gas from the formation, and that’s processed again in the recycling facilities, and every time it’s becoming heavier, it has more chemistry inside of it, just naturally, as a produced water.
So we have to take a look at that water and tailor the products that are used in completions to optimize the well specifically for that produced water.
So a big piece of that is friction reducer. How do we get friction reducer to work with higher TDS water, water that has H2S, water that has all of these sulfates and ions and issues inside of it, and it’s pushing the limits.
We’re constantly developing new friction reducers in the industry to push this envelope, and it’s been a very exciting time, and we see it only continuing.
We’re going to continue to use more and more produced water, so we’re going to have to customize more and more chemistry to meet these needs to optimize completions on location. That’s the primary goal.
We need to complete wells faster with the water that we have, and that water is produced water.
To make better wells. To make better wells. Right? So with that said, how do you make a better well? What really affects your reservoir? Well, as you have been seeing in the industry as well, surfactant is a big one.
Late last year, a lot of big players in the oil and gas industry really were pushing surfactants, and it was exciting. So take me back a little, because not everybody’s familiar with surfactants, or what are the purpose of surfactants.
They’re used in the reservoir, right? Sure, yeah. It started a long time ago in the oil field. They were originally used as non-emulsifiers.
In conventional reservoirs. In conventional reservoirs. But now we’re focusing on the unconventional. Now that we’re in the unconventional space, we’re looking at enhanced oil recovery. So we can use surfactants to change the wetting profile of the rock, really get that contact angle down, and produce more oil and gas out of the formation.
And originally, we’d been running it in completions. That’s still going on, but now people are doing it post-completions to recover even more oil and gas.
So we’re just seeing more and more surfactant use in the oil and gas space as of today. It’s important to know that you can’t just simply add a surfactant to a well and expect an increase in oil and gas results, an increase in production or efficiency.
It has to be tailored to the well, to the water, to the application. So a great surfactant is supposed to maximize your oil recovery and then minimize reservoir damage.
Exactly. That’s the goal. Yes. Having the right dosage of it to create this critical micelle pattern inside of it that can change the wettability of the rock and formation to produce more oil and gas.
That needs to be studied. And there’s a lot of different ways to study it. A bunch of new technology has come out. But the most important thing is that you have the right product for your well as well as the right product for your completion fluids.
This all has to work in synergy in order to produce oil and gas. You can’t just pick a one-size-fits-all and just assume a standard treatment rate and expect good results.
It’s going to have to be optimized basically well by well, pad by pad, to get the most efficiency out of the ground.
So what selects methodology when it comes to surfactants? Sure. There’s a myriad of tests we could cover. But probably the most interesting and newest technology is microfluidics.
That is a technology where we actually take the formation, if you will, and laser etch it onto a chip, like a microchip.
And what’s interesting about that is you can actually flow oil and gas through the chip and then you can flow completions fluids through the chip. Now this is at temperature and pressure.
And you can watch with a microscope and see what’s happening inside those micro-Darcy pore spaces and look for things like compatibility, for scaling, for surfactant interaction.
And this will tell you a lot of things. It’ll tell you if your fluids are compatible. It’ll tell you what mechanism drives the release of oil and gas in your formation. And it’ll also tell you how you can optimize to become more efficient.
And so this technology is really breaking a lot of ground and we’ve seen a lot of optimization, a lot of cost savings, and a lot of new technology come out of it.
So is this similar to core flooding? Oh, it works in conjunction with core flooding. So in a matrix of a whole bunch of different options, we can test a lot faster in all the different combinations and scenarios and identify our key drivers that are going to really determine the test down to maybe two or three choices.
And then we go into the core flood phase to optimize with actual rock, with actual oil and gas from the formation. So it’s honestly a time saver.
Because as you know, Christina, core flooding takes a lot of time. It takes a lot of time and there’s a lot of factors. Not one core is similar to the other.
If I understand you correctly, microfluidics just allows you to focus on the chemistry and just makes all the other factors the same or uniform.
And repeatable. That’s a big deal. Repeatability in testing is a big deal. How one test in the past was run could change operator to operator, lab tech to lab tech. How the sample was changed.
Trying to eliminate those things, trying to automate processes and making things repeatable is really how you move forward with technology.
So taking the human factor out of it and running it on a repeatable microchip just really increases efficiency.
Using all the resources that Select has, may it be in chemistry, may it be with highland and water services, automation is something that Select has taken great strides to. So on the chemistry side, we have apps that allow our customers to see where their products are coming, if they need to move it to the next batch.
Are there any other ways that Select chemistry is focused on increasing efficiencies for customers? Oh, absolutely.
That’s kind of the goal, right? How do we increase efficiency? increase efficiency. You and I were talking earlier about simulfracs and trimulfracs and the water demand it takes to get that much volume onto a completion job. Well, it’s not just that we’re using produced water, it’s that we just need more volume in general.
And we had a customer come to us with a question, really, a concern, how could they use their existing water transfer infrastructure, which was already quite elaborate, to get more rate to location? And we thought about that for a long time, and a solution came up, and it’s in the form of a drag reducer. We call it DRA for short. So the drag reducer is an additive used in oil and gas to typically move oil or gas quicker, but our application is with water. We wanted to move oil and gas like they did in the pipelines, the same way in the water transfer line, and move it more efficiently. So we developed a drag reducer.
Tell me about this drag reducer. Is there a concern about compatibility with other chemistries that are used for completions? Oh, so that was a big concern. Select actually developed technology just for the creation and testing of this technology. So they built a custom flow loop that had removable sections in it that could be adjusted to match the diameter of the water transfer system. Select uses customers’ KMZ files and software to model their water transfer lines and rates, and from that data, we can model in the lab what that flow rate and shear regime looked like for the drag reducer, and optimize the technology. Drag reducer is not just one chemistry. It’s a multiple group of families of chemistries, and it’s picked based on the water and the flow rate regime. Another concern with drag reducers is how many times it has a shear cycle. It has to hit a water transfer pump and then be transferred some distance and hit another water transfer pump, and this is a much longer time to be in solution before reaching formation than a typical completion job, right?
So does it tend to degrade as it goes from pump to pump? That’s the key. We modified the chemistry. We modified the polymer and the monomer to survive this long shear cycle and still be effective, still be reactive while going down for completions. Also, it’s a very efficient technology. It doesn’t take a lot of chemistry at all because you’re only using 0.1 to 0.2 GPT, and that small amount of additive gives you something like 30 to 50%. We won’t know exactly how much rate you’ll get until we test it for you, but it’s a real simple process. A KMZ file goes into the software. We test it in the lab, and then we put those values, those friction numbers back into the software, and it gives us a rate, and that we field-tried and have tested over and over again.
We’ve been pumping for over 18 months now on dedicated fleets, and every time it’s calculated, we realize the transfer rate value in the field.
So Rob, if I hear you right, DRA gives you shear resistance, allows you to transport more water with less pumps.
Exactly. Does it equate to having to dose less when you’re trying to frac now that your water is being pretreated?
So what we’ve noticed is because of the DRA already in the fluid during completions, they’re having faster times to rate. So during pad, after they’ve run acid, they come up on rate, and because of that polymer already loaded in the pumps and primed in all the lines, they’re getting to rate quicker. And this is giving them more efficiency on pad. We just did a pad the other day, and they were able to save two whole days off of their pad times just from time to rate. As you know, these are large pads with lots of stages on it. So any efficiency gained really pays dividends towards the end. It makes the operator move with the horsepower provider to the next pad sooner.
Okay. Would you say that you’re having to use less chemicals for frac as well? Yes. Oh, yeah. With the addition of DRA, you can reduce the overall use of chemistry on location. So with running DRA at a certain loading, you can reduce your loading of traditional
FR on location to balance out. And there are other benefits, too. DRA is applied upstream of location. So it’s not even on pad. This is an automated select technology that’s off pad and more in line with the water transfer system, obviously integrating with what we do in water transfer very well. But another benefit of this is now that you have this injection point ahead of the frac fleet, you can inject other chemistries off location, such as biocide or a scale inhibitor. That’s really interesting because now you can remove those chemistries from location, move them upstream, automate them, and now you have much less footprint, much fewer deliveries, much less things just to deal with on your completion location.
I’m with you when it comes to that. I know we’re always talking about reducing costs, making things more efficient. But you also have to think about something that we do very often, which is making things sustainable, having to go back and re enter that well because you did not treat with scale inhibitor or biocide. So having your well producing for a longer time, yielding more oil, really it’s key. And I think that’s an approach that Select has taken very seriously to just maximizing oil recovery.
Absolutely. And these systems are easy to implement with existing infrastructure. That’s the key. We didn’t want to change or burden or cost anybody anything additional. This technology already existed. Select just optimized it and put it into the field to make things more efficient and benefit the customer. And it said dividends. I mean, ESG, there is less emissions with DRA because there’s less diesel pumped in each one of the different transfer pumps. You save about two gallons per pump per hour. So that’s just less emissions overall for the entire operation. And as you know, those pumps run all the time. I mean, this is a real time metric of not only cost savings, but emission savings as well.
Well, Rob, it’s been wonderful talking to you. I’ve learned a lot. And I hope that everybody who listens to this, you know, enjoys it as much as I have. I think 2025 is going to be a very positive year, a year of efficiency, a year of sustainability and further growth.
Oh, I agree with you, Christina. Like we talked about with the increase used to produce water, the efficiency gains, just the excitement in the industry. Everybody seems to be looking forward to a really strong 2025 and to the future.
We’re ready to get back to work. We had a lot of M&A activity last year. We’re probably going to see some more of that, but the focus is doing more with less, and we look forward to getting it done.
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