Listen: A second chance: Operators turn to refracs in mature shale plays (Ep 158)

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Hill Vaden:
All right, this is Hill Vaden from S&P Global Commodity Insights EnergyCents podcast. I'm here with Sam Humphreys, as usual, we've recorded a couple podcasts today. Sam, what did you think about the one we just did with Prescott Roach looking at refracs in North America shale?

Sam Humphreys:
Well, this is good. I say on the podcast, my knowledge of US shale is zero, but I do understand shale gas and shale oil, so it was really interesting. And this whole concept of refracking old wells to increase production rates of existing stock is fascinating, and one thing I think Prescott does very well is just highlight the economics behind it and where it's being targeted, and the difference between where the companies are targeting oil and gas recovery, as well, and what things could look like in the near future. It's a space that I think might change quite quickly as technology improves and this method improves to maybe increase some of the production in, I've already forgotten the name of it, tier one, tier two, tier three? Acreage?

Hill Vaden:

You got it.

Sam Humphreys:
That's it, I knew it. So yeah, it was a really good episode, and ... Well, I learned a lot, so yeah, what about you?

Hill Vaden:
Yeah, I just think it's one of these things that, the shale recovery rate is less than 10%, and so, there's a lot of oil or gas left in the rock that technology can potentially stimulate and get out. I was in a meeting recently where somebody was higher on production growth from applying new technologies to existing discoveries, and they were on existing shale discoveries and discovering new shales. And so, there's a lot of enthusiasm on what people can do in these rocks, particularly on that top tier acreage, which is, of course, getting drilled up. So I think it's an interesting discussion, technology is always fun, and it was good to talk with Prescott, who I used to see all the time, and he moved away, and so, I see him virtually.

Sam Humphreys:
I know, I felt like I was gate crashing a reunion.

Hill Vaden:
Not at all. All right, we'll hand off to the episode from here. Hi, and welcome back to EnergyCents, an S&P Global Commodity Insights podcast, covering all topics on the intersection of energy and finance. I kind of messed that one up, didn't I? Sam Humphreys is ... This is Hill Vaden, and Sam Humphreys is here with me, as usual. Sam, how are you?

Sam Humphreys:
I'm good, it's a lot of words to get out in one go, but I'm good.

Hill Vaden:
You do a lot better job with it than I.

Sam Humphreys:
I don't think so, but how are you doing?

Hill Vaden:
I am doing all right. So before we start recording, Sam and I both sang the Grand Old Duke of York, the old children's song. That was not on tape, our guest, who will be revealed in a second, had never the song. But before we introduce our guest, who was the Grand Old Duke of York, and did he have all of these men who he marched up and down hills? I assume he's English.

Sam Humphreys:
Oh, yeah, he's definitely English. Do you get Dukes anywhere else? I suppose you do, but yeah, he's definitely English, and it's something to do with some battle at some time, and that is as much as I know. I have more knowledge of other weird, obscure British nursery rhymes, they're all kind of dark, but not that one, I think that one's pretty straightforward,

Hill Vaden:
Not the Grand Old Duke of York. All right, well, that's better than Prescott Roach, who's our guest today, who had never heard the song-

Sam Humphreys:
I can't believe that.

Hill Vaden:
... the Grand Old Duke of York.

Prescott Roach:
Morning, guys, thank you very much for having me. And yeah, that was absolutely the first I'd ever heard of that song. I think the extent of my knowledge on British Puritan nobility is pretty much limited to Downton Abbey, so you're dealing with a newbie over here.

Hill Vaden:
You watch Suits, don't you?

Prescott Roach:
I have seen Suits, yeah, so yeah, another good example, watching an American television show to learn about British nobility.

Hill Vaden:
All right, so we're now going to put you on the spot to ask you to sing the Grand Old Duke of York, though you have learned it today. We are going to put you on the spot to talk to us about refracs, which, that's an abbreviation, the refracturing of shale wells, and Prescott has done a report just a few weeks or maybe a month or so ago on this, looking specifically at the Eagle Ford Shale in Texas and the Bakken Shale in North Dakota, so Texas and the southern part of the country, and North Dakota and the northern part of the country for those perhaps not familiar with-

Sam Humphreys:
Thanks, Hill.

Hill Vaden:
American geography. And the idea is that these shale plays are getting developed, people are running out of inventory, and so, people are perhaps looking more at refracs to simulate production from acreage that has fewer remaining locations. So Prescott, if you can help to set us up on why the paper now and why the focus also on the Bakken and Eagle Ford.

Prescott Roach:
Yeah, I mean, refracs, exactly what you just said, essentially, the recompletion of an existing well. And the whole concept isn't new by any means, I mean, these have been employed for years, but they've really started to get a lot of attention over the last few months. Back in 2015, 2016, I think our shop did some work around refracs, and there was a bit of excitement then, and then, there was a bit of a lull, and now, 2023, coming into mid-2024 now, suddenly, it seems to be at the forefront of a lot of conversations. And we really think that there are a couple reasons for that. The first is just an adoption of new technology. So previous refrac designs used bullhead fracks, and what I mean by that is, you'd essentially take a well that had existing fractures, that had been fracked years before, and they would go in and essentially just refrac those existing perforations.
And so, this is a really spotty method, I mean, you kind of never knew what you were going to get, and the spottiness, I think was exemplified by their less attractive name, which was the pump and pray method, because you never really were sure what you were going to get off these things. So you fast-forward a few years, and now, the gold standard in refracs is what's called mechanical isolation. And what that essentially entails is running a a liner down the casing of a well, and you do that to seal off the existing fracks, and then, you go in and you do plug and perf operations, so that is, you frack new rock in between those existing fractures. And so, by doing that, you get all of the benefits of targeting virgin undeveloped reservoir, you get those really high pressures, really high production rates. And so, with this process you're able to derive really, really high productivity off of refracs, and so, that's really improved the economics of them.
And then, the second reason that we think refracs are having a moment is exactly something that you had alluded to earlier, Hill, and that's just the exhaustion of core inventory. That's something that we talk about a lot with regard to US shale, that core acreage is ultimately limited, and more and more of it is developed every year, and so, operators need to look elsewhere. And so, refracs offer a potential avenue for them to prevent their capital efficiency from eroding. The economics on a refrac are likely a lot better than going into peripheral acreage and drilling wells in relatively low productivity areas. So I'd say those are probably the two main reasons that we're here today, just lots of discussion around refracs on earnings calls, and I think the culmination of that, probably ConocoPhillips' acquisition of Marathon here a few weeks back, in which they had estimated that they believed they'd be acquiring about 1000 potential refrac candidates by acquiring Marathon in the Bakken and Eagle Ford.

Sam Humphreys:
I mean, you almost answered the question I'm going to ask you now, but refrac to me, it's a little strange. My knowledge of US unconventional is quite limited, but I've quite a lot of experience with Australian CBM. So just to clear a couple of things up for me, very selfishly, are we talking about refrac to increase oil or gas or both from these shales? And you talked about increasing production rates, what scale are they increasing? If they drilled a new well adjacent and fractured that, would that have a better yield, or is that uneconomical, or is its it beneficial enough to make it worthwhile compared to drilling a new well?

Prescott Roach:
Yeah, great question. So I think the first part of your question, is it oil or gas, the short answer is, it's both. Most refrac activity in horizontal wells that we've seen up to this point, pretty much concentrated in four plays in the US, and that's the Bakken and the Eagle Ford, and those are oily plays, and then, also, the Haynesville and the Barnett, and those are predominantly gas plays. And so, the composition of activity changes, right? I mean, since natural gas prices have suffered over the last year or so, you've really seen a drop-off in refracs in gas plays, whereas refracs in oily plays have held up and have really increased as oil prices have risen following COVID over the last couple of years. So the short answer to that is both.
As for the extent of how much productivity uplift you might get off a refrac, we looked specifically at the Eagle Ford and the Bakken in our last report. We're currently working on one for gas plays for the Haynesville and the Barnett, so I can give maybe a couple of indicators on those later on, those are still in process. But for the Bakken and the Eagle Ford, we're seeing that refracs have, at the median, the potential to increase EURs by up to about 70% in the Eagle Ford, and then, more than doubling in the Bakken. So pretty significant volumes.
The thing that I'd really caution here is that one of the big uncertainties with refracs is just how much variance there is in their productivity. Repeatability can be really, really difficult with these. Our analysis has broken out refracs into deciles, so breaking it out into multiple buckets based on their productivity. So everything that I'll be talking about from here on out will be kind of just your median, but just please understand that there's a lot to wiggle rooms at any numbers that I give. But short answer, in the Eagle Ford, your median refrac gives you about 70% oil production uplifts, on your EUR, Bakken, you're more than doubling.

Hill Vaden:
So I'm going to date myself here, that, I don't know, some 15 years ago, I did a paper on refracs in the Barnett, I think in Wise County. It was a long time ago, and I don't remember exactly what the answer was, but I don't think at that point in time, refracs were really having that much impact. And this was so long ago that a lot of these wells, the design has changed so much that it's kind of unfair to even compare that to what's going on now. Can you talk a little bit more about what's changing with refracs? You mentioned the bullhead refrac, which is a super cool name, but is this being led by the service sector, or is this being led by operators? Where are the advancements in technology coming from ... Ignoring the inventory question, what's the technology side of this that is really changing the game, or potentially changing the game?

Prescott Roach:
I think a lot of it is coming from the service side, just, anecdotal evidence seems to be that a lot of equipment suppliers, particularly smaller ones that really focus on completion services, have brought out product lines that are specifically dedicated toward this mechanical isolation method of refrac, so things like expandable liners. The other, I wouldn't necessarily say it's a technological shift, but on the part of operators, there's a bit of, I guess a logistical shift, in that, they may have a completion crew that happens to be sitting idle in between completing new wells, and one thing that they may do is to have that completion crew go in and perform a refrac on an old well in between completions operations on their new wells. So it's really being driven, I think, on both sides.

Sam Humphreys:
So if we're just looking at well integrity, are there good wells and bad wells to refrac, is what I'm going to say? Because this is, I think, what has it been, about 10, 15 years-ish, we've had a lot of these wells drilled? Are some of the older wells good enough to refrac still? Are they still active? Or are we talking about wells that have been sort of half decommissioned, half abandoned, but just going to reenter, or are these producing wells that are just going to be uplifted?

Prescott Roach:
So earlier, I had mentioned that most of your refracs tend to be concentrated in the Bakken and the Eagle Ford, the Haynesville and the Barnett, and one of the big reasons for that is that those are the plays that really saw early development during the first years of the shale revolution, and so, thousands of wells were drilled in these plays prior to 2014, 2015. And many of those wells had suboptimal completion methods, they had very, very low profit intensity, very low fluid, very wide cluster spacing. And all of those three things combined with their location in the core of each of these plays and the best acreage, all of these things really, we think, form the recipe for what makes a good refrac candidate.
And so, when we're considering, what will lead an operator to choose to ref fracture a well, we're pretty much looking at any well that would've been completed prior to 2015 or 2016, again, with those conditions, being located on really good acreage, being originally completed with very low prop and fluid volumes, and then, having wide cluster spacing in between the original fracks that allows them to go in and stimulate rock in between those original perforations.

Hill Vaden:
And how much are we talking about on a spending basis? I guess, two things, one, on the absolute dollars basis, how much do these things cost, and is it OpEx or CapEx?

Prescott Roach:
Yeah, so it's CapEx, really, because one of the attractive things about a refrac is that the land is paid for, the facility is already paid for, you already have your infrastructure in place, and so, from an operating expense standpoint, not a whole lot changes when you refrac the well, other than paying your variable cost per unit of production. So most of these costs are going to be on the CapEx side. All of the estimates that we've looked at and heard for the cost of a refrac, pretty much from anecdotal sources.
One of the consistent themes, though, that we've heard, in the Eagle Ford, anyway, is that modern refrac on a, say, 5 to 6,000-foot lateral well, tends to cost somewhere between four to five million dollars. So five million dollars is that baseline figure we've used for the Eagle Ford. Bakken, we've also used that five million dollar cost estimate. And the reason for this is that, in the Bakken, even though lateral lengths are twice as long as they are in the Eagle Ford, almost every well in the Bakken is 10,000 feet. They tend to be completed with much less propent, less fluid, and that brings down the cost, so surprisingly, we think the refrac costs in both of these plays are probably right in line with one another.

Sam Humphreys:
Just how much is it to drill a new well? Just to give some context with that.

Prescott Roach:
Yeah, great question. Rule of thumb is that completions account for somewhere between 60, 70% of the total cost of a well. So let's say, in the Eagle Ford, for instance, refrac costs five million dollars. A new drill, so drilling completion and facilities, probably cost somewhere in the neighborhood of around seven or eight million US, just ballpark.

Hill Vaden:
And you mentioned earlier, Marathon and Conoco and their potential inventory of 1000 or so, which is a pretty large number. I think the report mentioned that 230 wells have, according to our calculations, been refracked in the Bakken since 2020, across industry, and maybe 70 or so within the Eagle Ford over the same three or four-year period. How much are we still learning as we're doing? Has the code been cracked, or are we seeing ... You mentioned variability, is that variability with linear improvement, or is that variability all over the place? Or is the sample size still not big enough for us to see trends?

Prescott Roach:
My guess would be that the sample size is probably still too small at this point. Predictability and repeatability still does seem to be an issue there, because that variance does seem to remain very wide. One of the things that makes it challenging to try and tease out long-term themes is, there just isn't a whole lot of long-term data when it comes to refracs, particularly when we're trying to look at just those refracs that employ these sort of new methods. We can really only look at wells from the last maybe four or five years. So there's not a ton of data points there.

Sam Humphreys:
So we've talked about ConocoPhillips, Marathon, so who are the major players that are driving this at the moment? Are we seeing one company or a couple of companies really going for this, or is it kind of universal across the area?

Prescott Roach:
It is definitely not universal. So the Eagle Ford has really been the center of much of the attention on refracs over the last few months, that's where we've heard most of the commentary publicly disclosed by operators around their refrac plans. And the main companies leading in this space are Devon, and their most recent commentary is that they'll do about 25 refracs in the Eagle Ford this year. They also estimated that of all of the wells in their portfolio that they think are good candidates for refracking, they think about half of those are competitive with the economics on newly drilled wells within core acreage. So Devon is one, Marathon, before they were acquired by ConocoPhillips, was another one. They had also given estimates that they do about 25 refracs in the Eagle Ford this year, and they had also cited that same figure of about half of their total refrac candidate list being competitive with new wells on upper tier acreage.
SilverBow, within the Eagle Ford, is another one, I think they're going to do 10 FRAs this year. And then, Baytex just did their first refrac in the Eagle Ford, something at a cost of like, four and a half million dollars, I believe. They haven't given any forward-looking guidance as to what that refrac program will look like, but the indication that they provided was that they are sort of screening wells right now for refrac programs in 2024 and 2025. In the Bakken, there's been a lot less public commentary around 2024 plans for refracs, but the leading operators there are Grayson Mill, White Rock, ConocoPhillips, and Marathon. So a couple of your usual suspects on that list.

Hill Vaden:
All right, and so, we probably should've brought this out earlier, but part of the reason that refracs are so interesting for shale is because shale recovery rates are extremely low, they're seven, eight, maybe ten percent, and so, there's a lot of oil or gas that is still in the rock, that if engineering and/or prices can stimulate it to come out, then there's a lot more to produce. So I guess two questions here, if recovery rates are what, I guess confirm for me, please, but seven, eight, ten percent today, where do we expect them to be with the new refrac technology? And on the aggregate basis, forecasting has historically used rigs and well counts to predict oil production and gas production. Refracking is going to make that a lot harder, or is it just going to be a rounding error in the overall production mix?

Prescott Roach:
These are two really, really difficult questions. So to the first point, I would say I'm definitely not a subject matter expert on that, so I really can't speak to what ultimate recovery factors will be. Would just sort of go back to the figures that I tossed out earlier, that the Bakken, you can potentially see a more than doubling in single well EURs, in the Eagle Ford, you can see around maybe 70% at the median increase in liquids EURs. So significant number, but I can't give an exact figure on recovery rates. As for the second question, yeah, you hit the nail on the head, it makes it much harder to try and forecast production volumes with refracs, just because it kind of is this black box activity that can't be tracked as readily as drilling rigs or something like that, that can be easily sort of quantified.
To be honest, I don't know how we get around that. I think it may be, refracs may have significant supply uplift. For the purposes of this report, we'd done just a couple of quick estimates on how much we thought refrac programs might increase supply, and what we modeled out for the Eagle Ford was that a consistent 150 refracs done per year would lead to about 70,000 barrels a day of incremental oil volumes over five years of sustained refrac activity. In the Bakken, again, running 150 refracs a year, after five years, we think that would bring an additional about 100,000 barrels a day of oil production online. So between those two plays, we're looking at almost 200,000 barrels a day of supply just off a combined 300 refracs a year. You can scale that up from there if refracs do gain a lot more traction than that. So we definitely think there's the potential there to impact supply, and yeah, it is definitely something that is much more difficult to forecast than drilling activity alone.

Sam Humphreys:
So you talked then just about how this could be the potential of it scaling up, and how successful it is. So just to clarify, at the moment, if we're looking at Eagle Ford shale, are we looking at a sort of a sweet spot for refrac activity? Is it concentrated in one portion of the basin, or is it across the board. And trends going forward, are operators openly talking about scaling up this method, or is it kind of a wait and see at the moment, how it's going, before they start refracking everywhere that they've got in their inventory?

Prescott Roach:
So in the Eagle Ford, refracs are almost entirely concentrated in the Northeast core sub play. So I think something like 40% of refracs are in DeWitt county, and about a third are in Karnes County, and then, LaSalle County has a bunch, too. So they are definitely pretty tightly concentrated within one geographic area. In the Bakken, I thought an interesting kind of nugget here was that about a third of refracs are not in North Dakota at all, but they're actually in Richland County, across the border in Montana. The rest of those are in the Fairway and [inaudible 00:23:37] sub plays within North Dakota, and I think a third of those are in McKenzie County. So in the Bakken, less tightly concentrated, but still, you tend to see them gravitate toward the best acreage of the play.
In terms of how widespread we think this could be, one of the things that seems fairly likely is that operator strategies are probably going to be pretty divergent. Not sure we can say that refracs will be a universal program adopted by everyone, rather, I think companies that fit a couple of characteristics may be more likely to pursue refracs. One of those characteristics I would suspect would be companies that have core inventory exhaustion issues and are really confronted with basically this ultimatum of, okay, we can either go drill in peripheral lower tier acreage, or we can pursue refracs on our existing wells, but drilling new wells in core areas isn't an option for us. I think those are the companies that'll really be interested in pursuing refracs.

Hill Vaden:
Can you talk a little bit more about that? So if I gave you $10 million, would you rather drill your second tier acreage, a well in your second tier acreage new, or would you rather refrac two wells within your drilled up core portfolio?

Prescott Roach:
Yeah, to answer that question, I think we could look at the breakevens on refracs. So again, let's just use our median numbers, understanding there's a lot of wiggle room to anything I'm about to throw out here. But in both the Bakken and the Eagle Ford, assuming a $5 million refrac cost, we think that refracs break even around in that $45 per barrel range. Again, lots of wiggle room there. $45 a barrel, pretty good when you consider current oil prices. Certainly, economically viable at that level. That's about competitive with a class three well, and either the Eagle Ford or the Bakken. And so, what I mean by class is, you may have discussed these in other podcasts, but we break down acreage within our plays according to five acreage classes.
Class one and class two, those are going to produce your really, really prolific wells. You could consider it core acreage. Class three, going to be sort of middling acreage, class four and five, relatively unproductive. And so, at the median, we think refracs are competitive with that middle in class three acreage. They're not nearly as good as your class one or two wells, which, in the Eagle Ford and the Bakken, deliver breakevens in the mid to high $20 per barrel range. So on balance, we think if an operator has the choice, a new drill on core acreage is always going to be king, they're always going to prefer to develop that. When core inventory is challenged, that may be lacking, suddenly, a refrac looks much more attractive, particularly compared to your class four or five acreage, because the economics and the returns on it are just greater.

Sam Humphreys:
I'm going to ask you something that I probably should have asked at the very beginning. As someone quite new to the American shale thing, are people still exploring? Because this is something you've talked about, this class of acreage, and that is not something that I'm particularly familiar with, we don't tend to class acreage in the same way for conventional oil and gas, or even for some of the unconventional stuff in other regions. So are we seeing people no longer reaching out to those areas, and it's definitely more of just a drill and produce what we know, rather than go and find something new?

Prescott Roach:
Yeah, that's really been a story of the unconventional space in the US, is that, apart from this handful of plays that have been really, really heavily developed, like the Permian plays, the Bakken, the Eagle Ford, Marcellus, Utica, Haynesville, SCOOP STACK, I'm definitely missing a few others, but those are some of the big ones, there really isn't a lot in the way of exploration activity. One of the more exciting nuggets that came out of new plays opening up was EOG's entry into the western Utica, and that was within the last year or so, but apart from that, there really aren't new plays being discovered or opened up or commercialized. Most of the activity and investment is going into developing what we've got and what we know about.

Hill Vaden:
And this technology that you described much better than the bullhead refrac, is that able to move to the tier three acreage? Are we able to improve the production from acreage that was previously deemed goat pasture, or are we only going to be looking at this in the core, and still, that second tier acreage, third tier acreage remains out of the money, or on the margin?

Prescott Roach:
Would guess the answer to that is, we don't know yet. Most refracs, I'm guessing, are concentrated in core acreage because they almost exclusively target those early wells that were drilled during the first years of shale really taking off, and those wells are just inherently located within core areas of the play. Would also guess that operators are going to prioritize refracking wells on core acreage, because if they're looking to access new rock in between existing fracks, they're going to be looking for the most prolific rock that's going to offer the highest returns for their investment.

Sam Humphreys:
So with that, and we've talked a little bit about technology and the development, is there any new technology for refracs that is being talked about at the moment that isn't in use, that could potentially change the outlook of this?

Prescott Roach:
I have no idea.

Sam Humphreys:
Excellent. Always a good question.

Hill Vaden:
I'm going to follow that up with another crystal ball questions, and we try to wrap up podcasts with these types of forward-looking questions, but next 6 to 12 months. So there's no secret technology that we're going to talk about right now, but what can we watch, or what should we watch out for, either in the Eagle Ford, the Bakken, some of the operators, some the oil field services companies, relevant to the refrac conversation 6, 12 months from now? So let's say six months, so before the end of the calendar year, what should we watch for in the refrac space?

Prescott Roach:
Two things, the first is that there's been a lot of commentary around Eagle Ford refrac programs, so would really pay attention to some of the results from those, and whether or not any other operators jump into that, or if any operators that have announced refrac programs either scale those up or down. So that'll be really interesting to watch. I think the second will be refrac activity in gas-directed plays. During 2023, and coming into 2024, refrac activity in the Haynesville and the Barnett has really declined sharply as a consequence of lower natural gas prices. And so, as we expect something of a recovery, or at least, stabilization in gas prices, would look to see whether or not we're seeing a resurgence in refracs within those gas-directed plays, as well. That's going to give us a lot of good information around what the economic profiles of refracs for gas plays are, and it'll certainly help us validate or correct our estimates for what economics there look like.

Hill Vaden:
All right, Sam, anything else from your side before we wrap up?

Sam Humphreys:
Well, I won't ask any more stumpy questions, but just to reminder to people listening to like and follow the podcast, and if you want any more information, you can reach us at s&pglobal\commodityinsights. I think that's it for me.

Hill Vaden:
Well, thank you, Prescott, and thank you, Sam, we'll wrap up.

Sam Humphreys:
Thank you.

Prescott Roach:
Thanks so much for having me, guys.