[00:00:22] Bridget Scanlon: Hi. I'm pleased to welcome Shane Walker to the podcast today. Shane joined the faculty at Texas Tech University in 2023 and is currently the Director of the Texas Produced Water Consortium and also Director of the Water and Environment Research Center at Texas Tech. Prior to joining Texas Tech, Shane was a professor at the University of Texas at El Paso for over a decade.
His research focuses on desalination and in the past on wastewater reuse. And today we are going to discuss the challenges and opportunities for managing produced water in the Permian Basin in Texas. Thank you so much, Shane for joining me today.
[00:01:09] Shane Walker: Oh, thank you. It's my privilege.
[00:01:11] Bridget Scanlon: So Shane, you grew up near Lubbock which is in the Permian Basin, and you left there maybe well, you went for your PhD at, University of Texas at Austin.
So you've been gone for many years and now you are back since 2023. So you've noticed a lot of changes in that region related to oil and gas development. Maybe you can describe a little bit what you've noticed since you came back.
[00:01:35] Shane Walker: Yes, indeed. Yeah. So I had the privilege of growing up on a cotton farm. You see the value of water, especially in irrigated agriculture, a lot of cotton in this area, some cattle. There was a little bit of oil and gas on the south side of Lubbock. So I had the privilege of coming to Texas Tech for undergrad and then went to UT Austin for graduate school.
And then I was a professor for 13 years in El Paso. And so, Lubbock as a kid, we were kind of east of most of the oil patch, certainly in the Artesia conventional oil development in the Permian Basin area, and then when I was in El Paso, I was bit west of the oil and gas Permian Basin patch.
So moving back to Lubbock, the chance to come back home to my alma mater. Most of my family lives here. My wife and I are high school sweethearts, so it's a real privilege to be back home, but also the privilege to connect and learn a lot about industrial water, especially produced water in the Permian Basin.
And so, seeing that evolution, certainly with horizontal drilling capability that has advanced a lot in the last couple of decades. And then hydraulic fracturing, really advanced as well. And so the combination of those two pieces really allowed petroleum development from tighter geologic formations, especially the shales in the Permian Basin. So, whereas previously with conventional oil development you, have a good feeling, the wildcatters, oh, we should drill here, you drill a vertical well and try to tap into a pool of oil. Now with the hydraulic fracturing and the horizontal drilling, you could essentially make nearly any well drilling endeavor profitable if you're confident that the oil is in that geologic formation. So that really led to a lot more oil production in the Permian Basin. And along with that came a lot of gas. I mean, even recently I've seen headlines of negative gas prices in the Permian Basin presently.
So an abundance of natural gas as well. But really interestingly with the Permian Basin in particular: high water to oil ratios in the Permian Basin that's led to an abundance of produced water as well.
[00:03:55] Bridget Scanlon: And the Permian Basin is extremely important for oil and gas production in the US I guess it accounts for about half of crude oil production in the US. And as you mentioned now you can extract oil and gas from the source rocks from the shales with the hydraulic fracturing and the horizontal drilling.
And so those wells could be up to two or three miles long. And so by fracturing them then. And then you mentioned that you produce water with the oil and gas. And so that's a big issue in the Permian Basin these days.
Conventional production generated a lot of water also maybe 10 - 15 barrels of water per barrel of oil with the mature plays. But they were able to put it back into the reservoir because it's an open reservoir, high permeability reservoir. And now with the shales, they cannot put it back into the same units and so they have to put it deeper or shallower. And so that's been a concern and so the Permian Basin is a fairly large basin, it includes the Midland Basin, which is where you are, and then also the Delaware Basin to the West. So you've been doing, through the produced water consortium, we've been doing a lot of work on the ratio of produced water to oil and looking at these issues in the basin.
[00:05:15] Shane Walker: So, as you mentioned, the Permian Basin presently is almost half of the US oil production, so it's a significant player, even globally. There are two basins, as you mentioned. Midland Basin, which is to the east, starts up at the top Lubbock and then down towards Midland. On average, roughly a couple of barrels of water per barrel of oil, so roughly two to one ratio.
So a lot of people may have some misconceptions with that. With hydraulic fracturing, you do put some water into the well as part of the well completion process, but that's a small amount of water compared to what comes out with the oil. So this is water that was embedded in the shale formation, in the geologic formation.
And so most of the water, roughly 90% of the water that comes back up Is from the formation, not the water that we put down there for the hydraulic fracturing. And so that abundance of water, two to one, roughly in the Midland Basin, in the Delaware basin to the west, think Carlsbad, New Mexico, down towards Pecos, Texas, that area it's four to five times as much water as oil.
So the operators are handling a lot of water. And, early on a lot of the upstream oil developers were handling that there was an opportunity for another industry to develop. So historically we've thought about the upstream being the developers and the downstream being the refining and, gas and diesel production, et cetera.
And now we've got the midstream in between. And one of the key focus areas of the midstream is handling the water, managing the water. So part of that is helping deliver water to the wells for hydraulic fracturing, but then also receiving water that's produced from the wells. 20 years ago, 15 years ago, as this really developed and took off the horizontal drilling and hydraulic fracturing picked up and a lot more produced water was being managed, originally, they were relying on trucks to move it around. And over a few years, it got to the point where it was really heavy traffic on a lot of the roadways around some of the epicenter points in development.
And so finally somebody had the realization, you know what, if we're handling this much water, we really should shift gears to pipe networks. So now there are thousands of miles of pipelines across the Permian Basin, both Delaware and Midland Subbasins to move the water around to convey the water around. And as you mentioned it's not practical to put water back down into the shales because of the tight formation, low permeability but they have disposal wells with other formations and there have been some concerns with that disposal, especially for the deep disposals. It has facilitated increase in seismicity or earthquakes, and so the Railroad Commission has regulated seismic response areas, SRAs, to mitigate that. And so in the last couple years, that has largely been attenuated. Then they've shifted gears also to include what they call shallow. So the, deep disposal, greater than 10,000 feet deep typically. And then in the, what they consider shallow, is five to 6,000 feet deep, which, coming from my background growing up on a cotton farm, I certainly would not call that shallow.
That's quite deep compared to a couple hundred feet for a irrigation well. But one of the challenges or concerns with that is well integrity and, pressures. And, more broadly, some of the work from your team, certainly identifying concerns about the finite capacity of pore space open void space to facilitate that disposal.
So as we've also thought about cost transitions, there's this idea which created the Texas Produced Water Consortium. Hey, what if we could actually recover that water as a valuable resource instead of treating it as a waste?
[00:09:32] Bridget Scanlon: Right. And I think, early on, in the early days, there was a lot of seismicity in Oklahoma. But they were injecting the produced water into the Arbuckle unit, which was near the basement. And that was linked to the seismicity, so that deep injection was linked to the seismicity
We still hadn't seen much seismicity in the Permian basement. But then over time then with some deep disposal now the move towards a shallow disposal. And I think, early on they thought that a hydraulic fracturing would have a big impact on water use and water scarcity issues.
And so, over time then they have realized that they can reuse the produced water for hydraulic fracturing. So maybe you can describe that a little bit Shane, that evolution.
[00:10:17] Shane Walker: So early on, the thought was that you needed fresh water which first of all, fresh water is required for drilling the well. And then after that, in terms of the completion the hydraulic fracturing it wasn't required from a regulatory perspective to use fresh water. And so early on there was a concern as a lot of fresh water resources were being used, Hey, we got to pivot to figure out something else.
In terms of the water chemistry, part of the challenge is you don't want to form mineral precipitates in the water because that would plug or clog the well. So they learned with experimenting with different chemistries that they did not actually need low salinity. And so that's one of the key features of produced water from the Permian Basin.
It's very high salinity, what we say, hyper saline. So typically three to five times the salinity of ocean water or sea water. What they realized is if they could remove a few of the key components that were lower concentrations, you didn't have to worry about things like sodium chloride. Which is roughly 90% of the salinity, that constitutes this hyper saline produced water.
So over time, especially in the last several years, a lot of the companies have begun to recycle produced water for hydraulic fracturing. So they clean it up a little bit to produce what they call a clean brine or treated produced water. So you need to remove the suspended solids. Certainly, you don't want to put muddy water down hole, that's a bad idea. But also a few other things for stabilizing it, removing iron, which could be dissolved originally and get oxidized and come out of suspension. And so with some basic oil separation you remove the gas, the oil, any residual grease.
Some of my students, when they've seen a sample of clean brine, they're amazed because it's so salty three to five times the salinity of sea water, but you look at it in a beaker and it's clear water, so they do a really good job of cleaning up the water to create a clean brine that they can then use for hydraulic fracturing so that they don't have to rely on fresh water resources in the region, which is great.
[00:12:37] Bridget Scanlon: Right. And I think, early on also maybe landowners some of their lease agreements required operators to use freshwater because maybe that was an additional revenue stream for the landowner. So, so they were a bit constrained in that way. But also with the evolution of all these midstream companies like Water Bridge, or many of these others NGL they were able to facilitate the movement of the produced water to link the supplies where it was being generated to the demands where they were fracking. And so the logistics of all of that and the pipe system and everything it's a lot of logistics.
[00:13:13] Shane Walker: It is, yeah, an engineering marvel, really. Yeah, sometimes they're moving hundreds of thousands of barrels of water in a short period of time to and from. So they have a lot of flow equalization ponds where they can store water in preparation for a hydraulic fracture event or receiving water back from wells that when they come online.
And so, and then, managing the excess being sent to disposal.
[00:13:40] Bridget Scanlon: Right. And, people are flying over these areas where they're developing these unconventional plays or these shale plays. You'll see a lot of these frack pads from the air and these little squares. And then that's where they drill the vertical wells and then the horizontals extend out from those frack pads.
And those are spaced. So it's a pretty interesting to see them in the Permian and other areas, the Barnett Play, and the Bakken.
[00:14:03] Shane Walker: Really? That's right.
[00:14:04] Bridget Scanlon: And to put the Permian in context, I mean, there are a lot of these shale plays throughout the US, the Marcellus, the Bakken, and then the Eagle Ford in Texas and the Haynesville.
But the gas plays generate very low volumes of produced water. And so the Permian is number one in terms of the produced water volumes. And I think that's why it's a challenge manage it. And as you mentioned, we have a group at the Bureau of Economic Geology, the Center for Injection and Seismicity Research, that looks at seismicity issues and those concerns.
So, I really appreciate the reports and also the regular meetings that the Produced Water Consortium has every couple of weeks, to keep people informed and everything and of progress They have been very informative. So, looking at the last one, and if we look at the volumes, so B-3 Insight does a lot of analysis of the data, the produced water volumes, the hydraulic fracturing, water demand, and all of those things.
So looking at B-3 Insight data for 2025 I noticed that, they mentioned about 20 million barrels per day, or 21 million barrels per day of produced water generated. So, for water people, water resource people, that's about 1-million-acre feet. And Texas uses about 15-million-acre feet a year.
And for people that are into metric, that's 1.2 cubic kilometers of water, so about 7% of Texas water use. And you said, it'd be nice if we could get some beneficial uses of that. And so I think the lowest hanging fruit is to reuse it for hydraulic fracturing, of course that just cycles it around.
But, so in 2025 then about 8 million barrels of water were required for hydraulic fracturing. And they were recycling maybe 60 to 70% of the hydraulic fracturing water was sourced from produced water. So that was about 25% of the produced water. So, we're still left with a lot. And even if we sourced all of the fracking water with produced water that we would still be left with about 13 million barrels of produced water. So, the Produced Water Consortium has been intensively looking at ways for beneficial reuse of the produced water outside of the oil and gas industry. You're doing very intensive research on the treatment options, maybe you can describe those a little bit, Shane.
[00:16:27] Shane Walker: Yes, indeed. just to recap, over 20 million barrels a day estimated in 2025 of produced water generated. So, if you convert that to acre feet it's a million-acre-feet per year. Or another unit that people think of for municipalities is millions of gallons per day. So we're looking at roughly a thousand MGD or a billion gallons per day.
So this is a significant volume of water that could be available if we could recover, say, 40 to 50% of it. That would be significant contribution of water, especially to West Texas. So Senator Perry had the vision about five years ago to establish the Texas Produced Water Consortium. And the charge is to study the technical and economic aspects of beneficial reuse of treat and produced water.
So initially, the consortium under the original executive director Rusty Smith, focused on policy aspects that needed to evolve to allow this water to be used because the oil and gas industry in Texas is regulated principally by the Railroad Commission. And so, since water is mostly regulated by Texas Commission on Environmental Quality, TCEQ, over a couple of legislative sessions, the legislature transitioned authority for two main permitting options. One is surface discharge, so that's treated water, not raw produced water, but treated water that's been treated to permit requirements can be discharged to the river. So in the, Permian Basin area, the Pecos River is the principal river in that region. So many of the operators midstream companies are thinking about treatment plants that would treat water to clean standards that could then be discharged to the Pecos River. And so the TCEQ has developed a permitting framework and they're in the process of evaluating several applications for surface discharge.
And so one of the questions is how do you treat the water to be clean enough to meet those standards? So we don't exactly yet know what those standards will be required, but we can anticipate there are three main categories of treatment that are required. So if you're going to run desalination, which we know we will, because it's hypersaline, then you need to perform pre-treatment steps to make sure that the water's clean enough to go through desalination. And so pre-treatment followed by desalination, followed by post-treatment or polishing. And that's just because while desalination can remove roughly 98 to 99% of most of the constituents, there still may be some trace materials, organics, metals that need to be removed.
And so with that main three step process, pre-treatment, desalination, and post-treatment, we can achieve water quality that is clean. So in terms of pre-treatment steps, like we said earlier, similar to the clean brine or the treated water solid removal suspended solids removal. So they have what they call a gun barrel separation where you get pretty good separation of the oil, and gas and, grease and suspended solids, but it needs to go through additional pretreatment. So for instance, dissolved air flotation, DAF is effective method to get pretty clean.
In terms of desalination, we have a couple of categories. So for really high salinity produced water, a lot of the companies are looking at thermal distillation based processes, and you could think of it similar to our hydrologic cycle where water evaporates. And in that evaporation process, the salts stay behind with the liquid water. And so that water vapor that comes up is really pure water, very low salinity. That's why our rainwater is very low salinity, and then it's condensed and then we are able to retain that product water as distillate or condensate. And that's a really low salinity, very effective desalination process. So for treatment processes, like 150,000 milligrams per liter total dissolved solids and higher, a lot of people are thinking about this thermal process.
For the lower range, traditional reverse osmosis, which we might use on seawater, most of those membranes can't handle as high of a salinity as what we're looking at here in the Permian Basin. But there are some upcoming reverse osmosis based membrane desalination processes that might have opportunity. So some people use the term osmotically assisted reverse osmosis as a category.
For some people it's a specific term, but then there's another one called low salt rejection, reverse osmosis, LSRRO. And so some of the companies are exploring these membrane based treatment solutions. We did notice in some of the statistical data that the southern portion or Texas portion of the Delaware sub basin has a little bit lower salinity.
And so there might be an opportunity to apply single stage, ultra high pressure, reverse osmosis, really pushing the limits of reverse osmosis technology in terms of pressure rating. And so we're going to do some pilot testing with that as well. So we have a rigorous water quality analysis, including organics, metals, radionuclides.
We're also doing rigorous toxicological analysis, both aquatic and terrestrial. The standard regulatory methods, and then also sub lethal endpoints, looking at modifications of behavior in some of the organisms that are studied. And so we're really performing a rigorous analysis on the water quality at each step.
But especially that final step of polished desalinated produced water to confirm that the water is clean. And then we'll, like I said, we'll know hopefully soon as TCQ releases their draft permits pretty soon, I think hopefully within this year we'll see what those exact requirements are, but we have a good idea of what technology is required to get us there to, for that to be safe, to be used in the environment.
[00:23:08] Bridget Scanlon: So, so this is a big change for you, Shane. Moving from El Paso when you were dealing with brackish groundwater and that's probably like freshwater to you now, and now you're dealing with multiple times sea water. And so, the Midland Basin seems like the produced water is more saline than the Delaware Basin, and I know in your 2024 report you mentioned maybe median values for the Delaware basin about 70,000 milligrams per liter.
And sea water is 35, so that's about two times sea water. And the median value for the Midland Basin was about 130,000 milligrams per liter or so total dissolved solids. And then reading your reports, which are excellent describing the advances that have been made in RO systems.
And then you also mentioned a mechanical vapor recompression. And then with all of these different techniques, first of all, when I thought about a thermal distillation, get that vapor off, but, so you could still have some volatiles in it or you could have ammonia in it and things like that.
And you describe that in your report. So there are tradeoffs in terms of, capital costs operational costs, energy requirements and then recovery. So as the salinity increases, then your recoveries may decrease from maybe about 50% to maybe 30% for very high salinity water.
Maybe you can describe some of these trade-offs between thermal and RO and things like that.
[00:24:36] Shane Walker: Yes, so generally when you approach desalination, we estimate that the mechanical vapor compression or distillation based approaches are greater capital cost and greater operating costs. The principal factor of the operating cost is energy, so there may be some opportunities with some of the thermal technologies to use waste heat in that thermal distillation process, and that would certainly offset some of the operational costs, but generally, just back of the envelope, you estimate that the thermal desalination is going to be more expensive, both from a capital cost and an operating expense perspective. The membrane processes, while they are more energy efficient and lower capital cost, they do require more pre-treatment. And pretreatment is not a trivial component of the total system cost.
So there's a tradeoff in the lower Capex and opex of the RO or membrane based desalination, but it also requires more capital cost and operating costs on the pretreatment side, such as membrane filtration, to make sure that we've got really low particle. Basically, low suspended solids as a feed to the membrane desalination systems, That's a play on the pre-treatment and the desalination. On the post-treatment side, as you mentioned, the thermal processes, because they rely on water changing phases from liquid to vapor, which is really effective for removing the salts, the sodium and the chloride, et cetera it is not as effective in removing volatile compounds.
When we say volatile, we mean it prefers to be in the gas phase, so it prefers to be vapor. So for example, ammonia. So ammonium ion NH4+ likes to stay in the water, but the ammonia molecule NH3 is volatile. And so it can go with the water into that distillate. And so you can have a distillate or condensate product from the thermal desalination that is really low salinity, except for it still has too much ammonia.
And why is ammonia a concern? Well, certainly if you discharge it to a river. That could provide toxicity to the river. So a small amount of nitrogen is an important nutrient we want to protect and avoid eutrophication, too much nutrients in the river. We also want to avoid ammonia concentrations that would be toxic in the river.
So the membrane desalination in the studies that have been performed have, we've realized that they do a little bit better job of removing the ammonia. So there's a tradeoff there in terms of performance, in terms of post-treatment, because you may have to invest more in ammonia removal downstream.
So I think some companies are optimistic about the membrane options and some other companies are taking an approach. Well, we know the thermal systems are going to be able to treat the high salinity because these are well established technologies. So we're just going to move forward with that. It'll be really interesting over the next several years to see how several companies approach it in different ways, and we'll get to see the advantages and disadvantages of these technologies in the next few years.
[00:28:03] Bridget Scanlon: Right, and I think it may be the thermal distillation approach may not be too sensitive to the feed water and variability in the feed water. And so, that could be another thing because we don't know how uniform that will be and there are a lot of uncertainties out
[00:28:18] Shane Walker: So, so for the larger midstream companies, their aggregation network of bringing the produced water together does a pretty good job of concentration equalization. So they're getting pretty steady concentrations. It's not like it varies wildly from one day to the next
[00:28:33] Bridget Scanlon: Right, right. And your 2024 Texas produced water consortium report. I know you probably are about ready to pop out another one in 2026. You mentioned five pilot plants and it seemed like, they were managing a hundred to 500 barrels of produced water per day. And the salinity has ranged from about 50,000 to 130,000 parts per million or milligrams per liter.
So any idea, Shane, scaling this up, what it might look like, whether you'll have, a lot of decentralized plants are maybe, yeah, more hubs, where you will bring the water together and have larger treatment plans or is it too early to tell and if you maximize, how much you can treat.
And then we estimate maybe 50% recovery. And 30% with the high salinity, then you could be left with, still with about 7 million barrels per day. But that's a third of what they're dealing with now with maximizing the water use for hydraulic fracturing and then the treatment and beneficial use.
[00:29:39] Shane Walker: Right. Yeah, so on in terms of scale up order of magnitude, I think long term people are thinking in the range of 10,000 to a hundred thousand barrels per day for treatment plants. So obviously that's going to require multiple plants across the basin. It's not just going to be one single massive treatment plant in the middle, centralized treating everything.
So from a piloting perspective, several years ago we were looking at pilot plants in the range of that a hundred to 500 barrels per day. Now, in 2026, we're looking at, in the range of 2,000 to 20,000 barrels per day of feed going into these pilots. So the companies have gone to the next order of magnitude.
And so from my perspective, we're going to learn a lot in 2026 as these pilot systems and nearly full scale plants For some people, considering that 10 to 20,000 barrels per day, a size that they might like to look at as a model for having other plants in a similar order of magnitude size range.
We're going to learn a lot in 2026. I would anticipate, in the next several years as these technologies are approved out and the draft permits are finalized, then we'll probably see companies invest in that next range that might go up to 50,000 barrels a day or maybe even up as, as much as a hundred thousand barrels per day.
There can be some economies of scale where the economics are a little bit better at a larger size, but then as you mentioned, we've got a pretty large region geographically that we're covering, so there's a tradeoff between having a centralized facility with a lot of conveyance to get it to the facility.
And then there's the question of the beneficial reuse. Where is that water going to go? So we've talked a little bit about surface discharge to a river. Another permitting opportunity that TCEQ will be developing is land application. So maybe crops, possibly even range land rehabilitation. Growing up on a farm, I'd really love to see agriculture have the opportunity to benefit from this water.
From a rangeland perspective, a lot of the Permian Basin area the grasslands have been damaged so that the opportunity to restore or rehabilitate based on the water volumes that we're looking at. It could be hundreds of thousands of acres of rangeland that could be restored. And the great thing is you would probably only have to irrigate a couple of years to get those grasses reestablished with native grasses that then could be sustained on native precipitation.
So I'm really excited about these long-term opportunities for flow to the river. but yeah, it will take in the next couple years, some small, full scale, or large pilot scale demonstrations for engineers to really confirm the reliability and consistency of treatment performance to really clearly understand the economics and then roll those out across the basin to hopefully larger treatment facilities.
[00:32:57] Bridget Scanlon: So going to take quite a while.
[00:32:59] Shane Walker: It'll be several years. Yeah, that's right.
[00:33:01] Bridget Scanlon: maybe they're looking at also looking at pipelines to take it out of the basin to address some of the seismicity concerns. When I went to a conference last February, in 25, I was really impressed with, the advances in treatment and the cost. Because I always felt like, oh my gosh, they're never going to make it economically viable. But I mean, with the increasing cost of disposal and then the decreasing cost of treatment, it seems like they're starting to move closer and closer together.
And so maybe you can describe that a little bit, Shane.
[00:33:34] Shane Walker: That's right. Yes. There's an economic convergence that's happening. We mentioned the seismicity and the limited pore space and the well integrity concerns on disposal. So the disposal efforts have had to move a little bit further out, further away from the epicenter of the oil production.
And so that's a little bit further conveyance cost. And so, the cost, the average cost across the basin for disposal of produced water is increasing. So, whereas you might be in the range of 70 cents a barrel on disposal costs, some people are predicting in the next couple years that would likely be over a dollar per barrel just for disposal.
And then, I've heard that the out of basin pipeline the conveyance costs would be comparable to disposal costs plus the additional disposal costs on the other end. And so we could be looking at some disposal options mid dollar to $2 range in the next few years.
On the flip side, thinking about treatment I think there was general confidence within the last couple years that treatment could be less than $2 per barrel. Some bullish and optimistic that it could even approach $1 per barrel. So if you think about bracketing those ranges, we see the cost of disposal rising and the cost of treatment as technologies have been proven and tested and evaluated, and we're converging on more efficient solutions. I'm optimistic that in that dollar and a half to $2 range is very confident in the next couple years and maybe with economies of scale over the next several years, we could see those costs drive down closer to a dollar per barrel.
And at that point it just makes good economic sense to reuse the water beneficially instead of throwing it away.
[00:35:31] Bridget Scanlon: Right, right. And you've described a couple of the beneficial uses outside of the oil and gas sector. We talked that the lowest hanging fruit was reusing it for hydraulic fracturing, we just recirculate it but the discharge of the Pecos River and as I recall, some of the Pecos River has salinities up to about 7,000 milligrams per liter.
So your treatment will probably get it down to less than a thousand, will you, do you think you'll be able to discharge that higher quality water into the Pecos and that won't be a problem for the aquatic ecosystems?
[00:36:05] Shane Walker: Yes. Yeah, in fact, it's the opposite. It'll really benefit some of the native species there. There's a particular type of fish that's actually a fresh water fish that has been surviving in the higher salinity, but that's not its preferred context. And there're actually some invasive species that are suitable for brackish and saline waters that would likely not be so fond of the fresh water. And so we could actually see a restoration of some of these aquatic organisms back to what the Pecos used to be years ago. So yes the desalination in our studies has been effective to, to produce across the samples that we analyzed recently, about 300 milligrams per liter total dissolved solids.
Now some of those treatments might be as high as 500 or more, a little more milligrams per liter, but that's a fresh water comparable to drinking water from a salinity perspective. So it still has some of the basic minerals in it. So it's not too low of salinity, but I will remind you that, rainwater is extremely low salinity, typically less than 50 milligrams per liter total dissolved solid. So I think from a salinity perspective, that's a really good option. The desalination has been demonstrated to be very effective in that regard. It's the post-treatment polishing for these, remove trace organics and metals and ammonia certainly, possibly even boron for some of the land application. But really optimistic that those treatments sequences, treatment systems, can be operated in a range that's economically competitive with disposal in the next several years.
[00:37:52] Bridget Scanlon: Right. And some of that ammonia might actually be beneficial for some of your land application. And a lot of people think, well, fit for purpose. But I mean, really, the thermal desalination desalinates the water and so you can't just stop it halfway or anything like that.
And maybe the post-treatment, maybe you get some, add some stuff back in or whatever.
[00:38:11] Shane Walker: That's right in brackish desalination, let's say you've got a well that's 2000 milligrams per liter or 1500 milligrams per liter. If you're running a treatment process that generates a hundred milligrams per liter total dissolved solids, you might be able to blend a little bit of your raw water, your brackish water with the product water to dial in a salinity of 300, 400 milligrams per liter total dissolved solids. So can use blending to achieve more flow and a water salinity that's comparable to what your freshwater supplies are already producing for a city, for example.
In the produced water space, we would not do that one because the salinity is so high. The desalination process requires a significant investment of cost and energy to get the product water clean, but it would only take the tiniest smidge of that raw water to take the salinity back too high. So it's just impractical to blend source water with product water to try to dial in a salinity. It doesn't really make sense.
[00:39:16] Bridget Scanlon: And another aspect you mentioned the land application and discharge to the Pecos but there's also managed aquifer recharge, I think, which is a potential that we should collaborate on. And I think the Pecos Valley aquifer, should be very suitable in the Delaware basin. If you could sync those things together.
[00:39:33] Shane Walker: Yes, yeah, I think that's a longer-term conversation, certainly with, TCEQ that manages managed aquifer recharge or aquifer storage and recovery. Texas Water Development Board certainly involved in those conversations as it relates to regional water supply. So, yeah, I think I'm optimistic that those could be a portfolio of beneficial uses.
I know certainly people are thinking about industrial reuse opportunities. There's a lot of interest in data centers right now. My personal recommendation is that data centers prioritize dry cooling, air cooling to not require water. Because we need water for things that only water can do. For example, we cannot drink a cup of electrons, we have to drink water. We can't grow plants, crops with electrons. So if we can use electricity to help cool the industrial operations, data centers or manufacturing or whatever. My request to those leaders in those areas is to use dry cooling so that we can reserve and preserve the water for things that only water can do.
[00:40:49] Bridget Scanlon: It's early days with data centers and it reminds me of the early days with hydraulic fracturing. There's a lot of uncertainty about which way things will go, and so,
[00:40:57] Shane Walker: yes.
[00:40:58] Bridget Scanlon: we'll see how it evolves. But another aspect I think I'm not sure, but is the energy use then for desalination, maybe about, makes up about 40% of the cost.
And so you are looking at different energy sources in the Permian Basin. You've got plenty of natural gas as you mentioned, but also nuclear. It looks promising, but would probably be longer term.
[00:41:20] Shane Walker: Certainly, in the short term, I think in terms of desalination facilities that require the main component of energy for these treatment systems. In terms of short-term options, natural gas fire power production is the quickest to bring online in the United States. We've, over the last five years especially, we've seen a growth in interest in nuclear.
There's some Gen three technologies that some of the really large companies are investing in presently. There are also some nuclear technology developers looking at Gen four next generation advanced systems like small modular reactors, SMRs. There's a particular type subtype called molten salt reactors that don't use water directly for cooling the nuclear fuel as it generates heat. And so, one such company is Natura Resources based out of Abilene, Texas, and they've had a great collaboration with Abilene Christian University, at that company they're looking at this molten salt reactor. Which is intrinsically safer than the traditional light water reactors because, the salt is heated to a high enough temperature that it becomes liquid so it's molten, so you're recirculating a molten salt. If there was a breach in mechanical integrity of that molten salt recirculation, I got to see a demonstration at Abilene Christian University they dumped some on a countertop and it immediately solidifies.
So from a safety perspective it is not like water vapor or liquid water that can go out into the environment if there's an over pressurization. The molten salt just stays right there. So that's intrinsically safer. So I really like that aspect. They're also thinking about this from a small modular reactor perspective, where they could build the components at a factory, where they could have really tight, quality assurance and quality control and ship the components and assemble it on site. As opposed to the traditional plants having been constructed in a bespoke design. And so I think there could be a really safe approach to the deployment of these. In the range of order of magnitude of 10 to a hundred megawatts per reactor.
So that would be really compatible with desalination deployment in the Permian Basin. In particular for the thermal desalination that requires a heat input. It's possible to recover waste heat from the energy, electricity production process from the nuclear reactor. And pull that in as a feed of thermal energy or heat into the desalination process.
So I think there could be a symbiotic relationship there. And we're working with Natura Resources and Abilene Christian on helping advance that thought, collaborating with some of the midstream companies in the basin to explore what that might look like for pairing desalination nuclear power.
[00:44:33] Bridget Scanlon: Yeah, it's amazing how things are advancing. And then we also visited Abilene and was very impressed with what they're doing. They just have a one-megawatt plant there where they're testing different combinations of salts and everything. And so in contrast to a traditional nuclear power plant. It's a low-pressure system.
And so, then as you say solidify so it's intrinsically safer. So, so that's really good. And so going from one megawatt to a hundred, so I don't know what constitutes small modular is the, is a hundred that the range or does it go even higher? I don't know.
[00:45:04] Shane Walker: Yeah. In terms of size or footprint, it's surprising to me how relatively small that one to 10 megawatt reactor would be, and then you would, you might think just linearly, okay, if it scales up to a hundred, it's going to be 10 times the size. It's not. So there's a significant economy of scale on footprint going from that next order of magnitude.
So, I think it's surprisingly much smaller than a lot of people imagine. Which makes it, possibly feasible in, the basin. I'm optimistic, maybe in the next five years or so we could see a nuclear power desalination facility.
[00:45:45] Bridget Scanlon: Well, our guest today is Shane Walker. And we didn't get an opportunity to talk about your stellar work at El Paso with brackish groundwater desalination and wastewater reuse for the city of El Paso. And when I was at Berkeley last week, they were really touting how excellent and what an example that was for many municipal water systems.
But I really appreciate, it is hard for me to imagine you've only been at Texas Tech since 2023 because you have accomplished so much in the short time that you have been director of the produced water consortium and everything. And really appreciate all your efforts.
[00:46:20] Shane Walker: Yeah, well certainly I had a wonderful season, 13 years in El Paso and the privilege to work with El Paso Water Utilities, a great relationship between UTEP and El Paso Water. And so I learned a lot about end user design, considering the end user of the systems, and just really appreciate, that's a really special season of my life. We really enjoyed our time in El Paso.
[00:46:44] Bridget Scanlon: So thank you so much Shane, and good luck with your work with the produced Water Consortium in the Water Center.
[00:46:50] Shane Walker: Thank you so much, Bridget. Really appreciate the opportunity to join you today.
