[00:00:22] Bridget Scanlon: I'm really pleased to have Katie Smye on the podcast. Thank you so much for joining me, Katie.
[00:00:33] Katie Smye: Thank you for having me, Bridget. Pleasure.
[00:00:36] Bridget Scanlon: Katie is a Research Professor at the Bureau of Economic Geology within the Jackson School of Geosciences at the University of Texas, so we're basically at the same organization and have been for many years.
And Katie currently serves as the Principal Investigator for the Center for Injection and Seismicity Research, which is a consortium of the university with support from the Railroad Commission, and also a number of different industry partners. She leads a team of about 20 scientists on evaluating impacts of produced water management on seismicity, and focusing a lot on the Permian Basin in Texas.
Katie was recently recognized as the Woman in Energy Making Waves Award at the 2026 Permian Basin Water and Energy Conference. Congratulations, Katie.
[00:01:26] Katie Smye: Thank you, very kind of you.
[00:01:28] Bridget Scanlon: Katie we've been working together off and on over the years on these different issues related to produced water, and I think most recently we've been hearing about blowouts in the Permian Basin related to oil and gas activity.
I think the most recent one mentioned was in Grand Falls, in the Permian Basin, and earlier blowouts in Crane County and Reeves County. Maybe you can describe a little bit about those.
[00:01:58] Katie Smye: Sure. This is a relatively recent development in the Permian Basin, but what we've seen in the last several years is a few high-profile events that are covered in the news and talked about among the general public of surface flows of brine. And so this is a fluid, a release of fluid at the surface, and this is fluid that should be contained in the subsurface.
It's talked about as water, but it's really a very saline brine, many times saltier than seawater, produced from the formations in the subsurface of the Permian Basin. This is just a really visible sign of things that are happening in the subsurface. And so we've seen these events in the news and we've researched them, and the regulatory agencies have tracked them, and they're occurring in a couple of key regions in the Permian Basin.
So the one that you mentioned in Grand Falls recently, there are several others in Crane County. Those are on what we call the Central Basin Platform, which is this uplifted region of the Permian Basin where there was a lot of historical conventional production. There are a lot of old well bores, and so any changes to the subsurface pressures and fluids, may cause releases of fluids at the surface. That's one locus of issues in the Permian Basin.
There's another area where we've seen some of these surface flows or well blowouts or geysers, as they're called in the news, and that's in the Delaware Basin, the central Delaware Basin, where there have been vast volumes of shallow injection.
These things sometimes result in geysers that go 100 feet in the air. They take a long time in some cases to get under control; to find the well bore that's leaking, to properly plug the well bore. They pose a real challenge for the regulatory agencies and for operators in the region. And then of course for the public who's impacted; ranchers and landowners in these areas who have these incidents happening on their acreage.
[00:03:53] Bridget Scanlon: Katie, we're talking about the Permian Basin in West Texas, and it extends into New Mexico. You mentioned the Delaware Basin, where there's a lot of unconventional oil and gas production. There's also the Midland Basin to the east, and between the two then is the Central Basin Platform, which is more of a conventional producing zone.
Your work and that of the CISR group, Center for Injection and Seismicity Research, focuses a lot on subsurface and what you were describing is this produced water then that is generated with oil production coming to the surface, and it can be up to three to five times the salinity of seawater.
To put these numbers in context there Katie, you work closely with the B3 Insight, and they provide data on disposal and stuff. Some people are interested in how much water is produced and then how much we use to hydraulically fracture these shales to produce the oil and gas.
Maybe if you can give an idea of the relative volumes of water that are produced or that are disposed of, that are used for hydraulic fracturing so people get a feel for that.
[00:05:02] Katie Smye: This is a, yeah, great question. So, across the Permian Basin region, most of the produced water that we're managing today comes from unconventional production, and we can talk more about unconventional versus conventional later or now if you'd like. But this water, the volumes that we're talking about are in excess of 20 million barrels a day. 2022, '23, '24, now a million barrels a day of water being produced. To put that in context, that's something like an Olympic-sized swimming pool every minute or two being produced in the Permian Basin region. So these are vast volumes of water.
There are a couple of reasons for those volumes. One is that the scale of production in the Permian Basin region is very vast. We produce a lot of oil and gas from the region. Half of the US oil is coming from the Permian Basin, so it's a major producer. In fact, the largest oil producing region globally at the moment. And so associated with that is a vast volume of produced water.
The second reason for the volumes of produced water here are that in the reservoir, the fraction of fluid contained in the pore space is, in the Permian Basin, mainly water. Three to five times the volume of oil produced, we have the volume of water produced. So for every barrel of oil, we get a few barrels of water produced back. These are very wet reservoirs. In some areas, 80 or 90% of the fluid produced is water.
That water has to be managed in some way and in the Permian Basin, it's managed by injection for permanent disposal. We see similar volumes of water being disposed daily on the order of about 20 million barrels a day of water being disposed.
There are a lot of questions about volumes of water being produced because this is not something that's tracked really closely by regulatory agencies. It's not easily reported by operators, but we can get a sense of how much is being produced by how much is being injected, which is nearly all of what's being produced at the moment. In the Permian Basin, a lot of the produced water is treated very lightly, but reused for hydraulic fracturing. Rather than producing groundwater to use in frack jobs, operators are more and more going to produced water and recycling it for fracking.
This is a great bit of progress because it abates the need for groundwater to be used for fracking. But in fact, all of that water comes back and then some. So really it pushes the need for disposal out into the future. We're still disposing all the water we're producing, but we're just pushing that volume out into the future a bit more.
I think current estimates are that something like 60% of hydraulic fracturing demand is met by recycled produced water now. You might have better numbers on that, but that's the type of numbers I'm seeing from our commercial partners like B3 Insight.
[00:07:51] Bridget Scanlon: To put some of that in context then for Texas water use, Katie mentioned you know, about 20, 21 million barrels per day of produced water in, 2025. That is equivalent to about 1 million acre feet per year. Texas uses about 15 million acre feet a year. As you mentioned, Katie, more and more recycling of that produced water for hydraulic fracturing and reducing the demand for using groundwater to source water for hydraulic fracturing so that helps. It's a lot of water that needs to be managed and will probably continue to need to be managed for many as throughout the life of the play.
You mentioned conventional and unconventional oil and gas production, and I grappled with that way back in the day trying to get my head around it. Thank goodness the researchers here in conventional oil production were patient enough to explain some of those concepts to me. Maybe you can describe a little bit, the differences between conventional and unconventional and what that means for water.
[00:08:53] Katie Smye: Yes, I can speak to it in the context of water. But Bridget, of course, you're the expert on this, having written the seminal papers on especially conventional water production and the transition to unconventionals. I'll give it a shot. You can correct me.
We, when we think of oil and gas production there are really two main types of production. One is what we call conventional, and this is the case where oil and gas are produced from reservoirs that have porosity and permeability. Porosity is really the pore space that holds fluids between grains. That fluid can be oil and gas, it can be water, and it's usually a combination of those two things.
Permeability is the ability of those fluids to flow in the rock structure. That's really a question of how fluids are getting out. Conventional reservoirs have good porosity and they have good permeability. They have oil and gas in them that have migrated from reservoirs where the oil and gas are produced. They've moved from shales into these rocks that have porosity and permeability, where they sit and can be produced in a way that you think of pumping out fluids from the subsurface.
Conventional production actually has resulted in greater volumes of water, especially per unit of oil and gas produced, per unit of hydrocarbon produced. And Bridget, your work is seminal in showing this. There are vast volumes of water associated with conventional production.
However, that's been less challenging for industry to manage because they can be reinjected into the reservoirs they're produced from. You have the pore space, you have the permeability. You can use those fluids to inject in one well and push fluids, oil and gas specifically, toward other wells using a technique called enhanced oil recovery. Those fluids have not been problematic.
Unconventional production is a different thing. With unconventional production and the advent of that throughout the US in what we think of as shale basins, we have to create the permeability pathways by artificially fracturing the rock, creating hydraulic fractures.
We make those permeability pathways, make artificial fractures, produce oil from those reservoirs, but we can't reinject the fluids that are produced into those same reservoirs we've taken them from. This is what's posing the challenge in the Permian Basin and in other basins throughout the US that have unconventional production.
Those fluids have to go back into other reservoirs, more conventional reservoirs that are already filled with fluids, and that results in pressure increases leading to well blowouts, induced seismicity, and many other challenges that we can talk about here.
It's really this unconventional produced water that we're working to manage now in the Permian Basin.
[00:11:32] Bridget Scanlon: Katie, you mentioned, we've been producing from conventional reservoirs for over a century. So it's only in the last 20 years that we've been seeing all this seismicity. And so people may be wondering "Why?" and you explained that. And we could produce 10 to 15 barrels of water per barrel of oil from conventional reservoir as they mature in the Permian Basin, but we're able to put it back into that high permeability reservoir.
But now because you're going after the source rocks, the low permeability shales, you have these long lateral wells, maybe a couple of miles long, and then you hydraulically fracture them to produce the oil and gas. But you can't put the produced water back into those low permeability source rocks.
You put it somewhere else, and then you change the pressure and, sometimes cause seismicity. And I think, it seems like the first time in my recollection there's been seismicity in specific locations maybe for a long time. Oklahoma was the first place that we heard about a lot of seismicity. They were relating that to injecting the produced water near the basement the Arbuckle.
So maybe you can describe that a little bit, Katie, and how that compared with the Permian, and how the Permian has been evolving in terms of seismicity recently.
[00:12:47] Katie Smye: Yeah. you're absolutely right. Oklahoma was this first case of injection-induced seismicity associated with disposal of produced water from unconventional reservoirs that was on folks' radar and it was earlier than- any of the Texas basins. The Fort Worth Basin, which was the first in Texas to get a lot of attention, and then now the Permian Basin.
And in Oklahoma, earthquake rates peaked in 2015, '16, and '17. We learned a few things from that case in Oklahoma. We learned that very deep injection right above basement is particularly problematic. In each of these basins, we have a stack of sedimentary rocks that host our production and our injection, and those sedimentary rocks, that basin, is underpinned by what we call basement.
This is usually crystalline rock, and it has a lot of faults in it, and some of those faults extend into the rocks that are used for deep injection. You think of these faults as rooted in basement and extending upward into deep injection strata. We learned that injection near basement is particularly problematic for seismicity causing earthquakes on these faults that exist in basement.
We also learned that we can create earthquakes with relatively small pore pressure changes from injection at great distances. We don't have to have one causal injection well right next to an earthquake to think about earthquake causality. We can be tens of kilometers away, and we can have pore pressure changes that are relatively minor, tens of PSI.
So If you think about that pore pressure change associated with injection, it's something like a bike tire equivalent. It's a relatively small change in pressure that can cause some of these sensitive faults to slip and host earthquakes. We learned those things in Oklahoma in 2015, '16, and '17.
Then we saw seismicity really starting in Texas in the Fort Worth Basin, the Dallas-Fort Worth area, near the airport. That really caused Texas to start to think a little bit more broadly, both industry and regulatory agencies and academics, including the University of Texas Bureau of Economic Geology. About how we can start to think about and address this seismicity issue. That is when state-funded monitoring programs for earthquakes started, the TexNet program that started monitoring and cataloging earthquakes in twenty-sixteen and twenty-seventeen in the Fort Worth Basin and elsewhere in Texas.
My research group, CISR, which was really started by Peter Hennings who led it for a decade. Started as the industry-funded group that could do research on this earthquake catalog- funded by the state of Texas through TexNet; and able to do a bit more of a deep dive into what's causing these earthquakes and how can we mitigate them.
From there we move to the Permian Basin, which is really the focus now. Not only because of its role in US energy security and US energy supply, and in fact in global energy supply, but also because of the rates of seismicity that we've seen really peaking in twenty 2022 and 2023.
Interestingly, Oklahoma and the Permian Basin in different years have had earthquake rates that put them on par with California, which is this naturally very seismically active place. We have plate boundaries, we have faults, and we have all sorts of stuff happening in California, but we don't think of Texas and Oklahoma, as these seismically active areas in the middle of the continent.
But we have seen earthquake rates that are on par with California in some years.
[00:16:19] Bridget Scanlon: Disposing near, in the Arbuckle, near the basement in Oklahoma and the equivalent unit in the Permian is, it would be the Ellenberger. Initially, a lot of the disposal wells in the Permian were shallow above the oil and gas reservoir because I guess it's less expensive to install saltwater disposal wells above the reservoir.
But there's a trade-off. You mentioned the seismicity linked to deep disposal below the oil and gas reservoir. But if you go above it then you have to drill through it to get to the reservoir and that can be problematic. And so there's no free lunch, it seems.
[00:16:53] Katie Smye: There's no free lunch in disposal in the Permian Basin, but right.
There's been shallow and deep disposal in the Permian since disposal for management of unconventional produced water started to occur. And those have happened to varying degrees in varying places, and we can talk about the details of all of that.
But when we talk about shallow and deep, one thing I want to clarify is that we're not talking here necessarily about absolute depths in the subsurface, we're talking about relative depths. There's a lot of structure in the Permian Basin. You mentioned the Central Basin platform. The Delaware Basin is very deep. The Midland Basin's a bit shallower. The Central Basin platform is very shallow, and we have shelves and margins surrounding the basins.
When we talk about shallow and deep, we mean above the producing reservoirs or below. Deep is anything between the shales and the basement we talked about before, and shallow is between the shales and the ground surface. But It's still below groundwater resources, it's still below the base of usable quality water. About a mile deep on average across the Permian basin is what we think of as shallow. There's been deep and shallow injection to varying degrees in varying places.
One thing though we have seen is that given the link between deep injection and seismicity, the rates of deep injection have plateaued in the Permian Basin because they've been curtailed or decreased in local areas.
As water production has gone up, we've seen more and more shallow injection in recent years. Those shallow injection rates have skyrocketed while deep injection is still continuing, but at a relatively modest rate, about fifty million barrels a month in each of the two basins. Deep injection is a couple of hundred million barrels a month in both basins.
[00:18:36] Bridget Scanlon: Katie, we both are very fortunate to receive funding from the Sloan Foundation and that kickstarted a lot of this work. Really benefited from that. In those studies then we were able to look at all of the plays throughout the US. There's quite a lot of variation in oil and gas production in the different plays and then produced water volumes and recycling and all of that.
Maybe you can give a little bit of background. You mentioned that the Permian accounts for about half of the crude oil production in the US, and other plays are gas plays and how that relates to produced water.
[00:19:11] Katie Smye: Yeah, this is a really important point. Across the US, there are many unconventional producing plays. Some produce oil, some produce gas, many produce a combination of the two. In our early work funded by the Sloan Foundation and then EIA and DOE-- and now actually there's an industry-funded consortium-- those studies focused mainly on the reservoirs themselves and how much oil and gas could be produced from these tight reservoirs.
As a corollary, we learned about how much water is produced from these basins as well. There are a few observations that I think are relevant today. One is that there are some basins that produce relatively little water compared to the volumes of oil and gas produced. The Marcellus is one of those, the Appalachian Basin, Marcellus and Utica produce relatively little water. But the challenge there is there's not a lot of disposal, and there's not a lot of disposal optionality. Even small volumes of water are challenging to manage.
And then there are basins that sit somewhere in the middle in terms of water production and disposal balances. I think of the Haynesville Shale Play on the Gulf Coast, so East Texas and western Louisiana. In that basin, there's not nearly as much water produced as the Permian but there are challenges associated with disposal, even of the volumes that we're seeing today. Some of the shallow reservoirs are challenging as far as containment, so injection into the Rodessa Formation in Texas.
Any of these basins that cross state lines are challenging. We see water moving across state lines to be disposed because of differing regulatory frameworks, so some water comes from Louisiana into Texas for disposal. Recently we saw a large magnitude earthquake in Louisiana, likely associated with a combination of hydraulic fracturing and disposal.
So those vast volumes being injected into the reservoir. There are some challenges there in Gulf Coast plays and then of course, we have the Permian. Where there are two things happening in the Permian; there are disposal capacity constraints, although not to the degree we see other areas.
What the challenge in the Permian is the vast volumes of water. There are disposal reservoirs available, and there's a regulatory framework for disposal, but the volumes of water produced are so vast which makes management challenging. It's just the scale of production that we see. Underpinning that are two things, it's the scale of oil and gas produced, and then it's the relative volumes of water being produced from the Permian.
There are a range of situations across the US and these oil and gas basins regarding volumes produced and disposal capacity. And I think, the Permian is really sitting in that crux of large volumes and decreasing capacity over time.
[00:21:55] Bridget Scanlon: I think early on, you know, at some of the National Academy panels and things like that, people would say the Marcellus, which is a gas play and produces much less water than the Permian, which is an oil play. They said they were recycling most of the water, so "Why can't you do that in the other plays?"
But as Katie described, all of these plays are different and the Bakken sits in the middle, too; different geology and everything. And then the Eagle Ford also maybe produces oil and gas more gas than, the Permian. One size fits nobody and you can't really describe all of them with one characteristic, set of characteristics.
They're all different in types of fluid that they produce and then the volumes of water. As Katie also mentioned, even if they produce low volumes, if they don't have disposal wells or things like that, then they can still have problems.
[00:22:46] Katie Smye: I think one-- sorry, Bridget-- one thing to add to that, though, is that, it depends where we dispose to. We may have more production impacts and if we have nearer surface shallower disposal. There might be areas where we see challenges associated with drilling and producing our wells because of the types of disposal that we take out that takes place.
I think there are a handful of basins across the US where- disposal capacity or water management more broadly may impact production, and probably is locally already, but may do so at a broader scale in the next 5 to 10 years across the US.
[00:23:21] Bridget Scanlon: Through the CISR consortium then you work very closely with the Railroad Commission. It's a great collaboration and in the seismically active areas, you define seismic response areas, more monitoring going on in those areas. Maybe you can describe that a little bit and, how they curtail production and how you work together to identify those zones and try to figure out what's happening.
[00:23:46] Katie Smye: Our consortium is mainly funded by industry, including E&P companies. People producing oil and gas, folks producing oil and gas, but also midstream water management companies, and then land and minerals companies who care about what happens on their acreage and associated with - land and minerals rights, and then regulatory agencies.
Both the Railroad Commission of Texas and the New Mexico Oil Conservation Division are members of our research consortium, play an active role in helping to guide the research questions that are important for us to address that allow industry and regulators to have more informed decision-making.
That's a really valuable part, I think, of our research consortium, and a really unique part of what we do. In both Texas and New Mexico, in the Permian Basin, to address seismicity, both state regulatory agencies have developed what are called seismic response areas or, in some cases, seismic investigation regions.
These are areas where earthquakes have been observed, associated mainly with deep injection. I should say there are some earthquakes associated with shallow injection. In the Delaware Basin mainly, but those are relatively low magnitude and don't occur at the rates that we see for deep injection, and they're less concerning and less problematic.
These deep injection-induced earthquakes, some of which have been up to a magnitude 5.4 in cases, which is pretty large earthquake for a human-caused and anthropogenic earthquake. These have resulted in development of areas where deep injection volumes might be curtailed; either voluntarily by operators or be required to be curtailed by regulatory agencies.
There might be magnitude thresholds that trigger a response. For example in New Mexico, if there's an earthquake of- a certain magnitude, deep injection volumes will be paid attention to. This has actually been a great success, I think, for the combined academic regulatory industry consortium because earthquake rates have come down across the Permian Basin.
In some places, like the North Culberson Reeves Seismic Response Area in the Delaware Basin on the Texas side, they've come down by two-thirds since 2023. This is a great collective success where we can identify earthquakes through monitoring through the state-funded program TexNet.
We can research the causes of those earthquakes, publish our findings, share them with regulators and industry, and that leads to changes in operational practices and changes in regulations, such as curtailment of injection volume. I think this has been a great success story on the deep injection and seismicity side.
I think it's important to say too that deep injection has continued in these basins, outside some of these seismic response areas at a plateaued rate. We are managing to still have deep injection in areas where we don't have appreciable seismicity. That provides optionality for operators to dispose of their water.
[00:26:46] Bridget Scanlon: you mentioned earlier, Katie, that some of these basins cross state lines, so the Delaware Basin crosses the Texas-New Mexico. And then, New Mexico has different regulations for disposal than Texas. A lot of 3 or 4 million barrels per day of produced water move across from New Mexico to Texas for disposal.
Maybe you can describe that a little bit?
[00:27:09] Katie Smye: The Delaware Basin is an interesting case because if you plot injection wells, you'll see a very clear demarcation at the state line and if you model pore pressure changes associated with injection, you'll also see a pretty clear demarcation, especially in shallow injection at the state line.
I get asked in talks frequently by folks, "Is this because you don't have data?" No, this is real. This is real. The challenge though, is that the subsurface doesn't know state lines. It doesn't know lease lines. The subsurface is this shared resource that's impacted by what happens a mile to the north or a mile to the south or east or west in the case of that corner of the Texas-New Mexico state line.
What we see in the Texas-Delaware or in the Delaware Basin, is that in Texas, we presently have only shallow injection. There were 20 deep injection wells, those were curtailed. Actually, they were shut- in in the North Culberson Reeves Seismic Response Area due to seismicity. That area is one of the most seismically active regions in the world in terms of induced seismicity, at least in 2022 and 2023.
Our group is doing a lot of work to understand those earthquakes, but those rates have come down as those deep injection wells were curtailed. Shallow injection takes place in Texas. New Mexico is this different story because New Mexico has deep injection, and it has some seismicity in areas on the county line, near Dagger Draw.
Those are two separate areas. There are a few areas of seismicity that kind of have different levels of curtailment and a different regulatory response. But New Mexico is maintaining a rate of deep injection without the same levels of seismicity we saw in the Texas Delaware Basin, and that just is due to the presence, the occurrence of these sensitive basement-rooted faults.
But what New Mexico is not doing is permitting at appreciable rates shallow injection. This goes to your point, Bridget, about water moving across the state line. Quite a lot of Delaware Basin production is coming from New Mexico. Eddy and Lee counties are very productive oil reservoirs, and there's a lot of water produced.
Because New Mexico isn't permitting shallow injection due to this idea of correlative rights, which means that you can't impact production, and injection may impact relatively shallow producing reservoirs. We're talking Avalon and Bone Spring producing reservoirs. New Mexico is not issuing these permits apart from in a few cases and at relatively low surface injection pressures that don't make for economic injection wells.
Several million barrels a day of fluid, according to our friends at B3 Insight, are moving across the state line from New Mexico into Texas for shallow disposal. And that means that right on the Texas side of that state line, we have some very concentrated disposal, and we have a lot of challenges.
Going back to the first question you asked me about surface flows and blowouts, some of those are occurring in that area where we have this concentrated shallow injection on the Texas side of the Delaware Basin.
[00:30:19] Bridget Scanlon: It's interesting, difference in regulations, and the pressures that they allow and all of that sort of thing between the two states.
[00:30:27] Katie Smye: Considerations and different, yeah, legislative and regulatory frameworks in those two states. One could advocate that some standardization or consistency would be useful for industry, but I think that's just a challenge that these regulators face in these two states. We on the other hand, think more holistically about the basin and the subsurface because it's not really a regulatory question, it's a question of what the subsurface will allow us to inject safely.
[00:30:53] Bridget Scanlon: In New Mexico, maybe they were seeing some oil wells being watered out by injection from nearby wells, and so that led to reducing shallow injection. Yeah.
[00:31:04] Katie Smye: Shallow injection has these challenges, watering out is one of them. But, these are reservoirs that you have to drill through to reach your current producing reservoirs. Even in Texas, actually even especially in Texas, that has posed other challenges.
And maybe we'll get to this, Bridget, but additional strings of casing required, increased mud weights, operators needing to ask offset injection well operators to shut in their injection for a little while so they can complete wells safely. We are seeing challenges on the producing side and a little bit of added expense to producing from our shales in the in the Permian Basin.
[00:31:44] Bridget Scanlon: Since we were involved in these issues from the get-go, we've seen a lot of things evolve over time. One of the things at first people talked about all the water that was required to hydraulically fracture these shales and, that we were going to use all the water on the planet.
Initially they thought they could only frack with fresh water, but then realized that they could use produced water with a very minimal treatment, so a clean brine. Now they reuse the produced water a lot to support hydraulic fracturing.
But sometimes landowners want to sell their fresh water to operators and things like that. It gets quite complicated. Yeah, one of the things that we discussed was various approaches to manage produced water, and you mentioned a number of different options and of course the one is the reuse for hydraulic fracturing.
The Texas Produced Water Consortium, and I did a podcast with Shane Walker recently, looking at treatment and beneficial use of produced water. Lastly, improving management of disposal reservoirs. Maybe we can walk through those a little bit, Katie.
[00:32:50] Katie Smye: Yeah. And it's a good segue, Bridget, because we talked about these volumes of water moving across the state line. One of the things that I think is important to remember is that this is a really arid region. West Texas, Southeast New Mexico, right? And to your point about fresh water, these are precious resources. Many folks, including one comes to mind, Mike Hightower in the New Mexico Produced Water Consortium, right?
When we talk about the volumes of water moving across the state line, I think of that as a liability for Texas. It's a challenge to manage. We have well blowouts, we have earthquakes. When he talks about it, he says, "We're giving away three million barrels a day of water from New Mexico to Texas." And that's a paradigm shift, for us to think about, does this produced water have some value?
Right now it's mainly seen and treated as a liability because it costs money to dispose of. E&P companies have to pay to dispose of their water. They have to pay a midstream company to manage their water, and those disposal costs are going up due to some of the things that we've talked about and some of the challenges. It's a paradigm shift to think about, is there some value either in the water itself or in a treated version of the water, or in some concentrate that's left over that folks could make use of?
The options there are many, and there are folks working on this. My group's not one of them and that's not a strength of ours. But I do, really hope some of these solutions come to light to treat this produced water. Desalination is one of the things that's, required to bring down-- these are very salty fluids. Several times saltier than seawater; can be a couple hundred thousand PPM of, chlorides, for example. So you have to bring that salinity down to do something with the water. Then what can you do with the treated produced water? Maybe land application for crops or non-food agriculture would be an option. Aquifer recharge could be an option.
These things are managed by a different regulatory agency in Texas. I think there are some hurdles to get through for us to see permits being issued for those types of beneficial uses of treated produced water. They aren't there yet. We're not seeing those permits coming through yet. Maybe they will.
I think one of the things that's, a challenge is that the volumes we're talking about are so vast that even with those beneficial uses, we're still left with probably half of the original volume of fluid produced as a concentrated brine that we have to do something with. There are thoughts about maybe getting some, lithium or other critical minerals out of these very concentrated brines, and doing something with that. Those things are not economically feasible certainly now, and perhaps not even technologically feasible. To be determined.
But I do think we need to talk about the fact that we still have to manage at least half of the volumes of fluid produced. The timelines for some of these beneficial uses are several years out --5 years, 10 years, who knows how many years-- for them to be economic and scalable, and those two things tie together.
There are other challenges or hurdles there. One of them, for example, is electricity. The demands for electricity for desalination, for example, are pretty extreme. There's already a challenge of electrification in the Permian Basin and getting well pads, to be brought onto electrical grids.
There are some hurdles there.
That brings us to the second thing you mentioned, which is managing disposal in existing reservoirs. Along with that, maybe looking at additional pore space in the Permian, moving water around the basin, looking for additional places to dispose of water.
Because in my view, disposal is really the only strategy, and better managing disposal in, the next 5 to 10 years. That's still going to be taking the vast majority of produced water in the Permian. We have to do a better job on our disposal to avoid some of the negative impacts we're talking about.
[00:36:50] Bridget Scanlon: Say if we just take ballpark numbers for 2025, 20 million barrels per day of produced water and about eight million barrels per day of frack water. Even if we sourced all the frack water with the produced water, we're still left with about 12 million barrels per day of produced water.
If we treat that, the Texas Produced Water Consortium usually assumes maybe a recovery of half, so then we're still left with about six million barrels per day. My feelings are that we will forever be working on subsurface reservoirs for disposal. For some fraction of it, and it could be a third of what we're doing now, but still be important as we continue to dispose as the capacity decreases over time.
[00:37:40] Katie Smye: Well and Bridget these remaining fluids are unlikely to dispose in the same way too. That's a thing that we need to talk about and think about. The Bureau is well-placed to do this type of research, and there are other groups too, but what does it look like to dispose of this much more concentrated brine?
What's the injectivity? How will the reservoirs respond to that different fluid being injected? That's an area of future research that needs to be done in parallel with these treatment and beneficial use research avenues.
[00:38:10] Bridget Scanlon: We are several times seawater salinity. Say, for example, median value may be about 100 parts per million total dissolved solids. With the treatment we have 50% recovery, so you double the TDS of that, and so you get up to 200. Injecting water that is twice as saline as what we're injecting now also needs to be considered.
We've talked a lot about trade-offs between deep and shallow disposal and, you say, "Okay, don't dispose deep because near basement and seismicity." But then you go shallow, then you have to drill through it like you described. Also you're nearer to aquifers like brackish groundwater aquifers, the Dockum, and other units.
You are relying on the confining layers separating that disposal. Then we've got all of these legacy wells. Maybe can you describe that a little bit? These confining layers like the Castile and the Salado formations and how reliable they are, in terms of containing the injection water?
[00:39:12] Katie Smye: Yeah. The Permian Basin the shallow injection reservoirs, which are Guadalupian age; which may not mean much to many, but they're about a mile deep on average across the Permian Basin. They are sitting below a world-class caprock, which is a seal that sits above them, which helps to contain injected fluids.
You need this in kind of any injection scenario. One of the things we need to do is ensure containment. The fluids stay where they're supposed to stay. The Permian has this beautiful caprock, the Castile and Salado, Ochoan in age, evaporites that are halite and anhydrite salts that are interbedded.
They're finely layered, and our group has done some work to characterize those. In the Delaware Basin in particular, they're very thick and sitting right above our injection resource. There are a couple challenges though. As we move further east across the Permian, we have dominantly halite rather than anhydrite.
It's a lot less dense and a lot lighter. There's less pressure being applied to our shallow injection reservoirs, which means we have less stress contrast. That may play a role in how fluids migrate in the subsurface. There are also some areas across the Permian where across geologic time, millions of years some of these evaporites have been dissolved by fluids in the subsurface.
As some layers dissolve and others don't, you have collapse of some of these features and and you have more fluid pathways through the subsurface. Rather than these nicely confining layers, you have additional fluid conduits that can serve as leakage pathways. And then we have the challenge you mentioned at legacy wells in the Permian Basin.
A couple hundred thousand vertical wells that were drilled. Early in this podcast, you said the, a century of production. The Permian Basin's had a century of production, so we have wells now that are 100 years old, drilled in 1930. We have a lot of wells drilled in the '50s and '60s and '70s, and those wells were not necessarily cased to modern standards, right?
When we drill a well now, we know a lot about how to protect usable quality water, how to protect aquifers, how to make sure our wells are cased properly, to make sure when we're done with them, they're plugged properly and left in a condition to ensure containment of injected fluids. That wasn't the case many decades ago.
Some of these aging wells are now exposed to pressures from shallow injection that they weren't really prepared for. They can serve as fluid pathways too. I think one of the great, concerns, and it's a legitimate concern across the Permian, is how are we protecting our groundwater resources across the Permian and our ground surface?
When we see these instances of fluid leakage at the surface, they're indicative of something happening in the subsurface. Fluid leakage, cross flow in and out of zone migration of fluids in the subsurface reaching some legacy wells, or fracture fluid fault conduits and allowing migration to the ground surface.
If it's getting to the ground surface, it's probably getting to other formations in the subsurface. That's something that's being paid a lot of attention to now by industry, by regulatory agencies, and by our research group in academia.
[00:42:34] Bridget Scanlon: And Jeff Paine, at the Bureau has also been working on this for many years and doing research on the Wink sink which was resulted from a salt dissolution at depth.
[00:42:44] Katie Smye: Yes that's a great point, Bridget. A lot of the areas where we see issues now with legacy wellbores, some of them associated with injection and some of them just associated with how many legacy wells we have, are also the areas where we've seen sinkhole development and other things because it's indicative of a lower quality caprock sitting above the shallow injection strata.
Something to pay attention to, especially with injection in the central basin platform. One of the things we're seeing, in terms of water dynamics in the basin, is more produced water from the Delaware Basin moving up to the Central Basin platform. We have decreasing capacity in the Delaware Basin associated with these issues we talked about earlier on the Texas side.
More of that water moving to the CBP. It's something to pay attention to is these areas of poor caprock quality and legacy density and age.
[00:43:35] Bridget Scanlon: And CISR has really advanced the techniques that you're using to monitor the subsurface. Analysis of subsurface pressures-- similar to reservoir modeling for the people have been doing for a long time. But also the satellite data that Ann Chen, the interferometric synthetic aperture radar data, InSAR data to monitor the land surface movement.
Can you talk about that a little bit, Katie?
[00:44:02] Katie Smye: There are several ways that we can monitor fluid and pressure buildup in the subsurface. We of course model what's happening in the subsurface, and that's work led by JP Nicot, who we both know and work with and his group modeling these pressure changes. Some monitoring is down whole. We have an occasional set of data from an operator where we actually know what the pressures are at the bottom of a wellbore in the injection reservoirs, but those are very few and far between.
We have a handful of them across the Permian Basin region where we actually know the pressures. We have to infer pressure in the subsurface from other monitoring strategies; there are several of these. One that we've relied on heavily that you just pointed out, is developed by our academic partner or advanced by our academic partner in UT Aerospace Engineering Anne Chen and her group, is what satellites that pass over this area of West Texas and southeast New Mexico are picking up about changes to the elevation of the ground surface.
These Sentinel satellites pass over, take paths over West Texas and southeast New Mexico every twelve days or so, and we can get a measurement of the line of sight, the distance from the satellite to the ground surface. That changes based on whether the ground surface is going up or going down.
This might be hard to believe, but actually from production a couple of miles underground, we are seeing the ground surface itself, in New Mexico especially, subsiding. Tens of centimeters over the last fifteen years of subsidence, the ground surface going down. We're sucking out fluids, the ground elevation is going down.
What we know in the Texas Delaware Basin is there's this area where we see the ground surface going up. We still have production, but we have so much shallow injection that the ground surface is going up. It's overcoming that subsidence signal and uplifting. As you walk from New Mexico into Texas, you go from an area where the ground surface has gone down by fifteen centimeters, to an area where it's gone up by fifteen centimeters.
In and of itself, this is not necessarily, problematic, but it is a sign of what's going on in the subsurface. This uplift tells us that there is pressurization in shallow injection reservoirs that's leading to this signal. And one of the things that our group is doing is trying to figure out whether this uplift signal is indicative of injection end zone and pressurization and reservoir inflation, or whether, in some cases, it's indicative of containment loss. Which means fluids have migrated out, they've migrated along pathways, they've reached some area where they've pooled and uplifted.
What is that signal of containment loss, which is more concerning than general reservoir pressurization? It might have to do with the size of the bulge that we see, the pace at which that bulge occurs, the scale of it and all of those are the areas of active research for understanding the source of that uplift signal in the subsurface.
[00:47:11] Bridget Scanlon: Possibly you might be able to use that as a warning signal to highlight areas of overpressuring that JP Nicot and his team are modeling, the InSAR data may help guide. Also I think the Railroad Commission and Texas Commission on Environmental Quality, TCEQ, they have these well plugging programs. Maybe you could help rank areas in terms of vulnerability using these modeled pressure data and the satellite data.
[00:47:42] Katie Smye: Absolutely. Right so one of the things that I think is interesting, for all of these legacy wells across the Permian Basin. Historically, when those wells are orphaned and abandoned, they're left without kind of a legally responsible party to care for them. They're a ward of the state for management. These are orphan wells that the state, using either state or federal funds ends up plugging properly.
Those wells are prioritized by different metrics historically, and you might think about age and casing, degradation to casing, exposure to corrosive fluids like H2S or CO2 or whatever. Those are metrics that are interesting. In the Permian, we have this other metric, which is pressurization from shallow injection.
One of the things that we see is that something like 90% of wells that are flowing at the surface, whether they're orphaned and abandoned or legacy wells that have an operator of record are in areas where we've seen surface uplift associated with shallow injection and where we've seen pressurization from shallow injection.
It's certainly the case that these surface flows can be linked back to these early causal agents of shallow injection pressurization and an early signal of surface uplift. One of the things we're working toward is how can we be a bit more proactive in the tools and resources we can provide to regulators and to industry to think about managing these legacy wells.
What are these early warning signals? Can we quantify what an early warning signal might be to allow mitigation strategies? We're working toward that, and I think there's a lot of work left to do, but there are promising signals. The Railroad Commission right now in Texas is dealing with many and a growing list of orphaned and abandoned wells.
Their priority one wells are wells that are flowing at the surface. They have pressure at the surface. Right now, they are focusing on plugging those wells, but we could help prioritize and work together. As we are doing with them to say "There are other areas or regions with pressurization and lots of legacy well bores that could end up being problematic."
We're working toward these solutions.
[00:49:59] Bridget Scanlon: You mentioned a lot of metrics being used to prioritize these wells in the TCEQ margin conventional well, its greenhouse gas emissions, but also potential impacts on groundwater resources and surface water resources. I think we can use these data then to help identify some critical zones.
The message that we want to have, Katie, is that we will really have to manage the subsurface more stringently in the future because the produced water is not all going away ever. But our disposal ability to dispose of it in the subsurface is being challenged.
And the more and more information that we can gain on how to optimize subsurface disposal and management will be more and more critical in the future. And there's also other programs that are interested in subsurface disposal, or subsurface for fluids like carbon capture and storage and hydrogen storage and these sorts of things.
They can learn from your program then, from the produced water management, and of course CCS or enhanced oil recovery, CO2 for enhanced oil recovery. A lot of these programs are related, and they can benefit from all of the work that you guys are doing
[00:51:12] Katie Smye: I hope so. There are really strong links between these different industries. The subsurface can be used and utilized for many storage and injection operations. Right now, the focus for our program is saltwater disposal in the Permian Basin, right? But these techniques can be applied to any basin, any subsurface reservoir, and any type of fluid being disposed of or stored.
One of the things that's unique about this Permian Basin case study is we have everything. We have disposal at multiple stratigraphic levels. We have earthquakes. We have near surface disposal that... Not near surface, but shallower disposal resulting in near surface issues. We have multiple overlapping injection projects, right?
Many CCS projects now are an isolated, a well or a couple of wells in this program. What happens when we are disposing at scale multiple operators, multiple disposers, lots of different acreage partitions, different landowners, different stakeholders, different regulatory agencies across states?
What happens in this complex injection environment, and how can we work together to provide solutions? That's where our research group at the Bureau is trying to sit in this space of this very complex injection environment. What can we learn, and what things can be applied to other injection scenarios and injection operations?
I hope we'll be able to continue to provide some of those tools and resources to stakeholders.
[00:52:41] Bridget Scanlon: Thank you so much Katie.
Our guest today is Katie Smye. She is the principal investigator for the Center for Injection and Seismicity Research Consortium at the Bureau. I really appreciate the role that you and your group play in integrating academic research with the industry and with the regulatory agencies to help advance and develop solutions to many of the challenges with produced water.
[00:53:10] Katie Smye: Thank you, Bridget. Thank you for your collaboration and for allowing us to talk about our work today. Greatly appreciated.
