Three realities are converging in many basins to encourage more producers to refracture existing wells. One is that, other than in the Permian Basin, the best prospects have been drilled, so that newer wells are costing more to drill while producing less. Another factor is that newer frac technology is releasing much more oil than did the older versions. So after evaluating which wells are good candidates, a refrac can bring in many times the well’s previous production.
Third, refracs cost a fraction of the amount for new drilling, so producers that are new converts to the fiscal restraint gospel are seeing that they can realize a return on investment (ROI) much faster with a refrac.
But only the latter two apply to the Permian. Mark Chapman, senior vice president of Intelligence for Enverus, said there are so many good prospects remaining in the Permian—possibly ten more years’ worth—that few producers there are availing themselves of the opportunity. It’s different in mature fields like South Texas’s Eagle Ford, Ft. Worth’s Barnett Shale, North Dakota’s Bakken, and the Haynesville of East Texas and northern Louisiana. As new refrac products and procedures come from service companies like Peak Completions and Nine Energy Service, however, pushing costs down and results up, that may begin to change.
Where refracs are happening, Chapman said, there are two important issues. The first is that the best existing wells usually make the best refrac candidates, “if you’re looking solely for the economic uplift of a refrac on its own.” But the second point is that child wells are often more impacted than the parent well in a refrac scenario, especially in more recent, closely-spaced fields.
Parent and Child Reunion
Chapman said that there are cases in the Eagle Ford where “Your parent well might not pay out. But if you do not protect that child from the refractured parent, your child well, a virgin well, it might produce worse than its peers if you don’t do something about it.”
In some cases the refrac amounts more to re-pressurizing, where operators “are pumping into these parent wells trying to re-pressurize the depleted formation” so that, when they later frac the child well, those fractures can grow into new areas rather than following the path of least resistance into existing fracs in the nearby parent well.
He observed, “I think this is the most common use of refracs right now—purely to make better brand-new wells/child wells.”
While there are indeed some benefits to the parent well, he said that alone doesn’t usually justify the cost. Instead, “You’re going for pad-level economics. You’re improving the economics of the entire project.”
Parent well age also matters. “If it’s less than a year-old parent, the reservoir around it has very little depletion and stress-shadowing that will affect the child wells.” But after a few years, often less than five, there’s more inter-well communication in a refrac, depending on the reservoir. “You’ll get more of that communication in wells that are directly offset,” he said.
How much uplift is optimal? Refracs in the Haynesville, Chapman observed, have seen production increases of up to 100 percent, with 50 percent being more typical in other plays. In the Haynesville, most wells before about 2015 were likely under-fractured. Since then, the consensus has become that larger amounts of proppant—3,500 pounds per foot—and fluid of 50 barrels per foot—“are really what makes the optimal well,” along with increasing frac stages to 30 or so instead of the older standard of 10-12. Chapman said this makes these wells excellent refrac candidates.
Still Plenty Left in the Tank for Refrac
Historically, virgin wells in tight shales have produced only about 5-10 percent of the zone’s oil or gas. That’s because, Chapman said, “We’re only draining the first maybe three feet, maybe 10 feet” because even gas molecules don’t travel very far in tight formations” with the first frac. “So if we can go in there, be more intensive, do more stages and more individual clusters to create more openings in the pipe, we can fracture much more intensely all that rock in between and try and produce as much of that untouched 90 percent as possible.” In other words, producers “have to get that fracture really close to where the molecule lives in the rock” to make recovery economical.
Nine Energy Service
The company’s Regional Sales Manager for Texas, Don McLean, who manages the completions team in the Midland Basin and in the Eagle Ford Basin, along with Nine’s President of Completion Tools Nick Pottmeyer, agreed that other basins are doing more refracs than the Permian—but some are indeed being done. Nine has handled refracs in the Midland and Delaware basins, and in doing so has proven it can be successful.
To be feasible, refracs must have demonstrable stranded reserves and refracs have to be cost-effective and consistently repeatable, McLean noted. And what makes a good refrac candidate? He explained that, from the company’s experience and study of other projects, “The better candidates are going to be older wells. The earliest wells we’ve worked on have been from 2013.” He noted that refracs on wells older than that may have issues with casing integrity—which is a key to the refracability of any well. He identified 2013 to 2018 as being the “sweet spot” for refrac candidates.
“They were drilled in some of the better rock, what we would call Tier One acreage, with wider original well spacing,” much further apart than current spacing, and with much less effective frac procedures than current standards. Those were what McLean called Gen One completions, “whereas today we’re closer to Gen Four or Five” due to further research. Current gens use more sand, larger volumes of water, tighter perforation clusters, and higher pressures, options that also lead to successful refracs.
Nine’s procedure involves inserting a new, smaller casing into the existing hole and cementing in place, covering up the existing fracs in the horizontal section. “We essentially rebuild the wellbore,” he said. If the original casing is 5-1/2”, they will replace it, usually with 4” casing, an operation known as mechanical isolation. This seals off previous fracs and prevents the new sand and fluid from simply taking the path of least resistance into the old openings, reducing the ability to create newer, deeper fracs. McLean added that this smaller diameter has little effect on the well’s production because refrac flow rates are “not as high as during the frac itself.”
Among the top lessons learned therein:
- Managing depletion-related bottom hole pressures. Since older wells have been produced for years, bottom hole pressure is lower than in a virgin well. New pipe must accommodate higher pressures inside along with lower pressures outside the pipe to support the equipment.
- Effectively re-entering wells with aged casing. Damage and corrosion accumulated over the years can create questions about a well’s worthiness to be revisited. In the case of excess damage, McLean said the decision must be made regarding whether to eliminate it as a refrac candidate or to spend up-front money on repairs to make it refrac-worthy. Anticipating potential failure points in the process greatly expands the list of refrac candidates, he pointed out, which is why Nine/NewGen has developed a number of options for doing so, and for remediating damage should it occur.
McLean said the partnership with NewGen began about five years ago. NewGen offered to design, develop, and manufacture a specialized expandable packer technology for Nine to use in refracs, which ultimately expanded into the full suite of refrac liner tools and service offered today.
Parent-Child Part II
In line with the Enverus assessment, McLean said operators’ goals have changed over the last five years. Previously, a refrac was just about the parent well, but no more. Again involving the holistic model, it is a more complete approach to reservoir pressure management. Tighter placement of child wells means E&Ps are using the refrac of the parent well to “protect the new frac treatments on child wells.” Repressurizing older wells “helps control the fractures of the new wells,” eliminating pressure sinks that could pull new fracs toward old wells instead of focusing on the new rock.
In a variation on the zipper fracturing of new wells, Potmeyer noted that more companies are combining into one operation the fracturing of infill wells with refracturing of parent wells, to make the most economical use of frac crews onsite. Added McLean, “One of our customers in South Texas will go in and drill two new wells in between three older wells and they’ll zipper frac,” refracturing the old wells while fracturing the new ones.
One way of making refracs feasible is to have a system that speeds up the operation—and Peak Completions has adapted an existing system of retrievable frac plugs to do that. Here’s how company CEO Justin Heller described its difference from others.
“In standard plug and perf operations, after each stage is treated, you then have to deploy a new isolation device, whether it be a frac plug or whatever it might be.” The first step is installing the smaller liner inside the 5-1/2” casing. In plug and perf, the liner is permanent. In Peak’s operation, after the retrievable liner is installed and the frac is completed, the liner is pulled out of the well “So you return your casing ID [inside diameter] to the largest size possible.” He noted that this allows the customer to return to the primary production casing size, maximizing the casing ID and ultimately increasing production. In plug and perf it takes approximately one hour to place the plug, then it takes half an hour to pull the wireline out of the well before stimulation of the next stage. So, he noted, that is approximately one-and-a-half to two hours per plug. “Then you have to pump your frac stage and shut down, switch back to wireline and run another plug, etc.”
Peak’s ball-activated system, he said, allows balls to be dropped while pumping continues, “and you never have that down time to deploy another plug,” Heller said. “The ball is pumped down as part of the displacement fluid at the end of the previous stage, it lands on the seat and provides isolation, and then a new sleeve opens so you can stimulate the next zone.” That repeats for every stage, seven to ten in many cases. Ball sizes range from smallest to biggest.”
Heller added that they have done more fracs in vertical wells than horizontal, having had success in both. This system is usually used in acid stimulations rather than sand because sand buildup can make the plugs harder to retrieve.
While refracs are a more recent addition to the Peak toolbox, the retrievable system is not. “All of those components are actually part of our overall frac system that we’ve been using forever,” Heller noted. “In this application we’re really just repurposing it.”
As stated above, the Permian Basin is not a hotbed of refracs, but, said Heller, the calls they get for it “seem to come in waves. We’ll do multiple ones and then there’ll be quite a while where we don’t do any. Right now it’s not a consistent need.”
At some point, Heller sees the refrac market growing, “Given the number of wells that are being drilled and knowing that, at some point, restimulation is going to be needed in most, if not all, of those, it certainly is an area of the market that is expected to increase. It certainly has, over time, already.”