Trent Jacobs, JPT Digital Editor | 15 July 2020 Topics: Hydraulic fracturing
This past April in Texas, Schlumberger was asked by a client to hydraulically fracture two multistage horizontal wells at the same time, but with only a single pressure-pumping fleet.
When the job was over, Schlumberger had completed the wells 10 days earlier than it would have by using a standard zipper fracture approach. For the client—a pure-play Eagle Ford Shale producer named Sundance Energy—the approach removed about $500,000 from the total project cost.
The industry’s largest provider of well stimulation services by total horsepower calls the tactic simultaneous fracturing. Other service companies are touting the approach too, sometimes using less formal names that include “dual-stim,” “simul-stim,” and “double-barrel fracturing.”
For shale producers, the ability to pump two wells using roughly the same equipment spread it takes to stimulate one offers a clear route to achieving savings at scale on rental and personnel costs.
For the North American service companies, the emerged method represents a new way to win work amidst a historically tight pressure-pumping market.
“It’s proof that we can utilize our technology in order to perform jobs that are outside the box,” said Robbie Haidar, a product and services delivery manager at Schlumberger who was involved in planning the simultaneous fracturing operation.
Haidar explained that while the pumping fleet and crew were typical in size, “for all intents and purposes, they were treated as two different fleets.” This meant the crew could pump 60 bbl/min into one well, while at the same moment, 60 bbl/min was being pumped into the offsetting well.
The flexibility of its modern and partly automated technology spread also meant that if needed, Schlumberger could stop pumping early in one well without stopping the pumping of the other stage in the adjacent wellbore.
Schlumberger and its OneStim consultancy arm for unconventionals took things a step further by using geologically driven fracture-stage designs, which meant different proppant and fluid concentrations may be flowing into each well at any given time to account for variations in rock properties along the lateral.
Jayanth Krishnamurthy, a regional technology domain manager at Schlumberger, pointed out that with the lower ceiling on pump rates (e.g., 60 bbl/min vs. 90 bbl/min) concerns are raised over whether there is enough pressure within the stage to initiate a fracture at all or most of the perforations.
The solution is to adopt extreme-limited entry (XLE) which calls for a lower number of perforations to increase the pressure each receives—the idea being that this results in more-even fracture propagation.
The requirement is notable since not all of the shale business has embraced, or is proficient in, the application of XLE. But without it, the simultaneous fracturing technique would run the risk of low cluster efficiency, a subsurface tradeoff big enough to negate any operational upside.
Schlumberger is not alone in its efforts to openly test the market with simultaneous fracturing.
The Calgary-based pressure-pumping company Calfrac reported that in the first half of 2019 it completed more than 40 wells for an unnamed operator in the Piceance Basin which spans Utah and Colorado. Using the term “double-barrel fracturing,” Calfrac concluded that by simultaneously pumping two wells at once, it more than doubles its surface efficiencies.
In its case study, Calfrac said the biggest challenge faced was managing communications, noting, “While only one data van is used, the amount of information it reads is effectively doubled.”
NexTier, the industry’s third-largest pressure pumper, also published a case study late last year that included details of its first “simul-frac” done in the Permian Basin of Texas for an unnamed operator. The scope of this study included an adjacent well pad where the wells were stimulated using the traditional zipper fracture technique.
Though the proppant and fluid volumes were the same, the simultaneous completion pumped more stages in about three-quarters of the time. It took just over 17 days to complete 132 stages on the zipper pad compared with about 12½ days and 168 stages on the simultaneous fracture pad.
Aaron Burton, a completions consultant and the owner of Unconventional Oil and Gas Training, said his clients have been quietly discussing the method for almost 2 years.
“Nothing stays a secret in our industry for long, but I think this may be one of the longest-held secrets I’ve seen in my career,” he said. “I’m not sure why or how it stayed under the radar for so long, but it may be because ‘simo-frac’ seems crazy or impossible right now—just like zipper fracturing, deepwater, and low-permeability reservoirs did not too long ago.”
For those with long memories in the shale business, the emergence of simultaneous fracturing may feel more like a reemergence.
Burton cited SPE papers from 2011 and earlier that refer to “simultaneous fracturing” (along with some of the other same terms used today) as a popular technique used in shale fields in Oklahoma and Texas. But in many cases the term is used interchangeably with operations that used two distinct fleets hooked up to two distinct wellheads—a procedure that delivers far less efficiency gains to an operator.
In a few other cases, when the vintage literature cites simultaneous fracturing it does indeed refer to using a single fleet to treat two wells at once. While the practice has been well-established for at least a decade, it nonetheless failed to become mainstream as larger fracture designs and surface complexities outpaced what the older equipment spreads could keep up with.
The confusion is further amplified since zipper fracturing—i.e., the sequential fracturing of stages in multiple wells—has become an industry standard because it enables “simultaneous operations” which means completions crews are used more efficiently.
As the nomenclature sorts itself out, the biggest challenge Burton sees facing the truly simultaneous fracturing technique involves how companies learn to manage having double the volume of fluids and sand on site. If that hurdle is cleared, then it may usurp zipper fracturing as “the next true game changer when it comes to surface efficiency during the frac job.”
Because the approach places extra demands on the service provider, Haidar highlighted that Schlumberger delved deep into its arsenal of planning tools as it was forced to “rethink the basic building blocks of a fracturing job.”
Among other things, he said managing a single fleet that had the demands of two required figuring out new billing and inventory tracking processes. The company was also challenged with how to safely and efficiently rig up a twin fracturing operation that included two independent wireline units.
To aid in the effort, drones were sent ahead of the fracturing crew to scan the site from above and then recreate it digitally as what Schlumberger calls a “frac twin.” This virtual version of the pad site allowed the planning team to plug in different components of the fracturing spread and decide weeks ahead of time the best configuration for the high-traffic site.
Haidar also credited the latest in Schlumberger’s pump and blending technology which was required to effectively duplicate the fleet’s capabilities. All pumping units were controlled remotely from a single data van where crews applied slurry rates differently for each well. With its two independent discharge points, the new blender system was deemed equally critical since it performed the work of two units—reducing the need for added equipment.
The only potential bottleneck Schlumberger reports at this point is if a pair of wells require above-normal volumes of friction reducer (the key ingredient of slickwater treatments) which may exceed the ideal operating conditions of its blender system.
“Apart from that, when it comes to rate, there are not a lot of limitations,” said Haidar, adding that the template hatched out on the first job can be expanded to allow a combined rate of 180 bbl/min.
This setup means operators can step up the pump rate in two wells up to 90 bbl/min. Or, they could stimulate three wells simultaneously at 60 bbl/min—a possibility Haidar said is currently being discusseds with other operators.
Beneath the surface, Krishnamurthy pointed out that each of the wells in the project with Sundance had a “bespoke design” based on extensive modeling and simulation work. This was done to account for the existence of parent wells on the pad their effects on the geomechanics and stress regimes of each stage in the new wells.
It also points out that a simultaneous fracture operation can be married with a more complex geologic-based completion design (as opposed to the sector’s simpler and predominate geometric completion recipe).
When the operator inquired about using the simultaneous fracture technique earlier this year, OneStim had already done much of the forward-looking modeling.
Krishnamurthy said the subsurface team went back to the drawing board once more and asked a slew of new questions: “When would these fractures start communicating? What kind of pressure responses should we see? And if we see a pressure response, because we are pumping into two wells, and if they sand out or screen out, what do we do?”
“Based on all of this study,” he said, “we thought that even if the wells start interfering with each other, based on the design that we had, we should not see an issue.” He added that screenouts ended up being a nonissue on this project.
Further, an analysis of pressure data collected from treatment and offsetting passive wells during the operation gave OneStim confidence that its design achieved the desired fracture geometries. It also reported that a post-completion analysis of the wells, which came onto production in June, showed 90% of the perforations in each well were stimulated effectively.