Jordan Blum, Hart Energy’s editorial director, spoke with Bob Barba, the president and CEO of Integrated Energy Services on its program to refrac spent wells—wells otherwise consigned for plugging and abandonment (P&A). Barba argues there’s plenty of oil and gas remaining in those wells, even those in line for P&A.
Jordan Blum, editorial director, Hart Energy: We’re here at Hart Energy’s DUG Haynesville Conference in Shreveport, and I’m joined by Bob Barba, the president and CEO of Integrated Energy Services.
JB: So we're talking refracs here and kind of making the case for refracs as a lower-cost alternative in this low price environment to keep LNGs essentially fed. Can you make the case for that?
Bob Barba, president and CEO, Integrated Energy Services: Refracs have been long misunderstood. I mean, the long history of refracs prior to mechanical isolation was with bullhead diverter refracs—you might get a 1% increase in your recovery factor. Eagle Ford, for example, we used to have a 3% recovery factor. They did a bullhead and it went to 3.8%. Then they did a liner on the same well and it went to 14%. So, I mean, that's the progression. But a lot of people think ‘refracs,’ they think the 1% increase with a lot of variability and results, and a lot of people that were in the field doing those refracs are now in the C-suites writing checks. So I think that's probably the major issue. But people are starting to realize that the mechanical isolation techniques really do work very well. And there's kind of a dearth of information on them because there's really no standardized reporting practice for it.
You've actually got to go look at the declines. For the Eagle Ford and Haynesville, I had to look at every single well to see whether you had the spike or not, and then go back and scrub through the records and then maybe visit with the operators or whatever. There's no, you know, IHS for refracs... So it's very hard. And we just really started doing that about a year and a half ago too. I didn't really actually see the results from the actual refracs until really, the last two years at the most. But looking at the actual results, they're good. As you saw in the talk today, they're even better in the other areas as well, because they didn't have the mechanical constraints. They don't have the treating pressure constraints that Haynesville does.
JB: Great. Well, can you compare the refracs in the Haynesville versus other basins a little bit? I think we were talking about the Eagle Ford comparison a little bit?
BB: A lot lower pressures. I mean, you got some that are somewhat comparable in the deeper regions … but most of those are in the gas window, which is not really very active right now down there. But you know, typically you're not limited by your treating pressures down there if you do it right. And same thing in the Permian, if the Permian ever takes off. In the Eagle Ford there has been over 200 refracs right now, to date. And about half of those are liners. Haynesville has 170 right now, and probably half of those are liners as well. So there's a lot of refracs out there. But what's keeping it from being more widely accepted is that it's concentrated within a few operators between both plays really. Ninety percent of the refracs are done by less than maybe a dozen operators at most out of the several hundred operators that are actually operating.
JB: What’s stopping the business argument from convincing other operators to essentially jump on board?
BB: If I knew the answer to that, I'd be a rich man right now.
JB: Well, there's definitely a business case for refracs as the lower cost alternative. But how tough is it to just to make the case for new activity of any kind with gas prices notably down now?
BB: Gas prices are a little bit problematic. I mean, I think most of the areas that are going to really be working [and] I think that the most activity is going to be in the oily-er parts of the play. But to try and capitalize on this, [there] is a big disconnect right now between money and refracs. Only a handful of operators are actually doing it, but that's why we're forming this new company that we're going to try and bring those two together. Because I think there's a huge need for that. Everybody we talked to suggests it is a pretty good business model; the returns are there. We can show the returns are there. The mechanical risk has been largely, you know, minimized.
I mean, there's never zero, but you know, with the proper conditioning, proper preparation, doing your homework on the wells ahead of time, refracs have probably the same risk level as a new well and on execution, which most people have associated refracs with risky, uncertain, unknown. Most of the operators that have refrac-ed wells now didn't actually do the refracs. So for a while there, we thought that operators didn't want to admit that they'd mess the wells up to begin with. There's very few of those around. It’s almost [like they said], ‘I'm not going to refrac that well, I did a good job the first time.’ But I don't think that's an issue. I mean, we thought that was the issue for a while, but really, almost all the ones I presented today were done by operators that current operators had bought. And so they weren't even done by the operators that were in the room.
JB: And like you said, you're essentially competing against new wells. I mean, is that difficult to get people to put their minds around that?
BB: It's getting more attention when people start realizing this damage aspect of it. I mean, because basically with just the refracs themselves, as you saw in the talk, you got probably half the NPV 10 of a new well, you know. So I mean your rate of return is competitive, about half. But the thing is, if you add the parent protection –protect the child from the parent – because the 40% number I presented in the slides is just the first order well. We're seeing damage on second order wells and third order wells. I mean, the whole pad is affected by not having that pressure wall there. What a refrac does on a new well development is basically, you have an old well, and you put new wells around it. Don't complete the refrac well until you actually do the new wells and do a zipper pattern.
And basically what that does is it protects the offset wells from degradation. Because … on a per well basis, I'd say one well’s NPV on a pad—the data we're getting suggests that 40% number is just the first one. You probably have 80%, 90%, or even a 100% of wells of one well PV-10 on the lease pad on the four- or five-well pad is not going to be there if you don't refrac it. So that got people's attention a lot more than just the ‘oh yeah you're going to make, you know, 4 Bcf or whatever.’ ‘Whatever, okay, I’m spending $5 million for a 4 Bcf well. okay, whatever.’ When you can spend $10 (million) and get 15%. But I think the parent protection end of it is what's going to make a difference because not protecting the child well with a parent refrac is this huge expense. Like I say with optimized techniques, it's actually a higher NPV than a new well in the Haynesville under current conditions.
JB: And we're in this energy transition world to an extent. I mean, how much of the argument is refracs as a lower carbon footprint argument?
BB: Exactly. You're wasting a resource. Just like recycling, we’re basically recycling old wells. I mean an old well that’s going to become a plugging and abandonment, you know, in fact, I was trying to order a license plate that's to [plugging and abandonment wells] to P1, you know. So, but most of the ones we're looking at now are currently producing, but there's still a lot of wells out there that could be plug-in candidates, but there's no connection between current production and what's left in the ground, particularly these early wells. So, I mean, you can pick up a well for abandonment costs and refrac it for $5 million or $6 million PV-10.
JB: Very good. And I'm assuming there's a lot of bullishness just longer term as we talk about more and more LNG trains coming online?
BB: Yeah. Overall in general, I mean, I think people get more comfortable with refracs, because there's still, like I say, we really haven't had a good handle on the actual production from the refracs because of the reporting issues for about the last two years. And, you know, it takes industry a long time to move around. You know, we typically don't respond on a dime. It takes a while before everybody gets the same group-think mentality that ‘yeah, this is okay.’ Right now the group think is, ‘ah, it's okay, but you know, I want to see it.’ You got a lot of engineers that … [and] geologist says, ‘oh, look at the brown cow on the hill. And the engineer goes, well at least he's brown on this side.’ You know, you're having to fight that all the time. You know, always ‘show me.’
The Permian right now is a good example. The Permian potential based on the recovery factor of the refrac candidates and the current recovery factors is twice the size of the Eagle Ford as far as NPV 10 per well – you're looking at probably a $15 million PV-10 per refrac versus five or six in the Eagle Ford. More than that. More than twice. But we keep [getting] talked up or ‘well, who’s in it?’ …’Well, it’s there, refracs work.’ ‘Oh no, we want to see somebody do it,’ you know? ‘Okay we'll see.’ In fact, I'm presenting to Chevron [soon] about this to try and get them to try and get them off dead center. But, that's a subject of my talk in several areas, is the Permian potential because it's just huge. I mean, the Permian potential, it's going to dwarf the Eagle Ford in refrac potential because there's just so much more oil there. But no refracs. Go figure.
JB: Again, thank you so much for taking the time here with this Hart Energy Live exclusive at the DUG Haynesville Conference in Shreveport.
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