The benefits of Simulfracs

LEEN WEIJERS, Liberty Energy 

One of the frac industry’s recent innovations, spearheaded by Ovintiv in the Permian basin, is to pump into two, three or maybe even four wells simultaneously. Simul-, trimul- or quattrofrac’ing (is that a word?) aims to reduce the rate per well, achieving lower wellbore friction, while increasing water and proppant throughput faster than the increase in necessary time and horsepower to do the job.  

Pumping into two or more wells at the same time, at a higher overall rate but a lower rate per well, uses the physical principle that wellbore friction scales more than proportionally with flowrate. In essence, it enables the work that pressure pumping crews do, to focus more of their energy into creating fractures downhole instead of overcoming wellbore friction.  It has gained widespread acceptance and is currently used in about 30% of all the work across U.S. pressure pumpers. 

THE PHYSICS 

Fig. 1. Schematic of single-well and multi-well pumping operations.

During pumping operations, a lot of energy is “wasted” to overcome friction. While perforation friction may be a necessary evil to encourage better limited-entry-driven proppant distribution between perforation clusters, and the industry’s near-wellbore friction battle in horizontals has been mostly won with better initiation and perf designs, wellbore friction serves absolutely nothing.  

Surface pumping pressure is determined by six individual components.  As shown in Fig. 1, some of these are independent of rate, such as the downhole formation closure stress and hydrostatic head, which mostly depend on depth and rock properties. Net pressure, perforation friction and near-wellborn friction are dependent on lots of things, but where rate is involved, they are most dependent on rate per frac (or perf cluster). We assume there are no downhole changes between single-well and multiple-well simultaneous pumping operations, and as such that the rate per perf cluster, and therefore theoretical perforation friction, remains the same. 

Only wellbore friction depends on the flowrate per well. It scales with the flowrate to the power ~1.7.   

THE BENEFITS 

Fig. 2. Simulfrac pressures (top) and gains (bottom). From left to right, zipper ops at 90 bpm per well, moving from two-well to four-well ops by further lowering the rate per well. While most pressure components remain (about) the same, wellbore friction changes dramatically as a function of rate per well and causes most of the pumping surface pressure reduction that delivers the benefits for this technique.

The benefits in pressure reduction can be substantial. As an example of this power-law relationship, a 33% reduction in flowrate per well can deliver a 50% reduction in wellbore friction. If the wellbore friction in a single well pump ops is of order 5,000 psi, that is a reduction of 2,500 psi in surface pumping pressure. 

In Fig. 2, we compare the measured treating pressures during zipper-frac operations (frac into one well) in the Haynesville shale with a pressure forecast for simulfrac’ing into two or more wells at a lower rate per well. From left to right, pump rate per well is reduced from 90 bpm to 60 bpm, while overall rate for the frac fleet increases from 90 bpm to 240 bpm, as we increase from one well to four simultaneously. That is a 33% reduction in pump rate per well and a 2.7x increase in the pump rate from the frac crew.   

A key assumption is that the rate per cluster remains the same across all comparisons, so no “cutting corners”: the 90 bpm serves nine clusters in one well; the 160 bpm serves eight clusters, each, in two wells; the 240 bpm serves six clusters, each, in four wells. That means that theoretical perforation friction, in yellow, remains the same; in this case at about 500 psi. Most other pressures, as highlighted on the top side of Fig. 2, are not impacted much by these rate changes. The wellbore friction in green, however, is cut in about half.   

Since it is a major component in frac’ing during single-well ops, that reduces the surface average treating pressure from ~12,300 psi to ~9,700 psi, a major reduction. 

As shown on the bottom half of Fig. 2, the brown line shows that it results in a 21% reduction in surface pumping pressure, or a surface pressure multiplier of 0.79. If we compare the far right to the far left—four wells vs a single well—these four wells require only 50% more pumping time; only 2.1x the number of single-well pump engines with 2.7x original total rate; and then deliver 4x the work with only a 3.1x increase in horsepower-hours (HHP-hrs).  All in all, that represents about ~22% in savings in work done. 

Granted, these savings come at the expense of scaling requirements, to have more wells connected to pumping iron, require more wireline runs, require larger pads for ops and for E&P operators to have more wells drilled and ready to go for fracing. But the reduction in “wasteful work” is a step-change that can provide real savings and reduce the cost to bring a barrel of crude oil to the surface.  

Is simulfrac applicable in high-pressure environments like the Marcellus and Haynesville shales?  The reason for these higher pressures is that these are deeper wells with higher closure stress gradients. These high-pressure environments could be ideal for simulfrac, because they provide the opportunity to lower surface pressures during operations. For wells that routinely frac at 12,000+ psi, providing significant operational and logistical constraints, this technology could potentially lower the surface pressure below the 10,000-psi threshold, where it can benefit from a step-change in lower-cost wellheads and frac iron.  

Fig. 3. Example of simulfrac operation in West Texas, including the use of split-flow.

The image in Fig. 3 shows two missiles serving two wells treated simultaneously in split-flow (separate proppant laden “dirty” and clean stream that meet at the well). In another industry innovation to use cheaper and lower-emission fuel, this crew utilizes brand-new direct-drive single-speed natural gas engines and a fully natural gas-run electric backside. 

The massive scale of this operation shows that a frac fleet of old is not a fleet anymore. As per Liberty Market Intelligence, North American frac fleet count is down 29% since early 2023, while HHP demand is only down ~10%. This explains why U.S. production hasn’t dropped in line with fleet count declines. Also, with decreased capital being invested in frac HHP, our industry supply is tightening, and a modest increase in activity could create a very tight market. 

BEWARE!  

Some companies are currently experimenting with this while they also reduce the rate per cluster / perforation. We recommend against cutting corners like that.  We have seen in many studies, there are significant production benefits from higher rate intensity, stage intensity, proppant intensity and fluid intensity per lateral foot.   

Another word of caution is against pushing rate reductions too far.  If rate per well becomes too low, this could impact proppant transport inside the well.  While proppant grain size is smaller than in the past, and in some cases proppant density is lower, it is still useful to review proppant settling velocities and calculate a minimum fluid velocity to keep it in suspension. 

While rate per cluster is maintained, could simulfrac still cause sand redistribution issues? There are fewer perforation clusters across the high end of wellbore travel velocities.  While this could have an impact on overall proppant distribution - it is probably a secondary effect. 

THE REPORTING GAP 

One interesting side-effect of this technology is that we need to change the way we discuss this. A stage is not a stage anymore: simulfracs double or triple the well stage count, as compared to the pumping stage count. So, we must include “pump” or “well” to qualify what type of stage we mean.  

For modelers and industry trend trackers, understanding how the U.S. frac industry is progressing, how market shares are changing, and who is pumping what, is becoming a tougher exercise.  

At Liberty, we have been tracking simulfrac and trimulfrac ops, but there is no industry-wide champion currently doing this. If ignored, when we use the common well efficiencies, rates per frac fleet get underreported, but pumping efficiencies per fleet (uptime) get overreported. 

CONCLUSIONS 

• Simulfracrequires scale, and as such may lead to further industry consolidation 
• Benefits fromsimulfrac are significant and could trigger a step-change 
• Simulfracis now used by an expected 30% of U.S. frac crews and could now represent more than 40% of all work done. Adoption has especially been strong in the Permian basin, where scale is available 
• Simulfrac is well-suited to lower pressures in high-pressures basins, such as the Haynesville. 

LEEN WEIJERS serves as the Senior Vice President of Engineering at Liberty Energy. He has worked at Liberty since its founding in 2011, originally serving as its Business Manager. Mr. Weijers’s role at Liberty focuses on two main aspects. One, delivering improved well economics to customers through optimized frac designs, and two, on customer and internal data sharing and reporting to improve business efficiencies. Mr. Weijers worked at Pinnacle Technologies from 1995 to 2011, where he oversaw the development of the industry’s most widely used fracture growth simulator, FracproPT. He was Pinnacle’s Rocky Mountain Regional Manager from 2007 to 2011, where he helped rebuild its Rocky Mountain operations. He has authored dozens of industry courses and publications. He also played a key role in the calibration of fracture growth models with various fracture diagnostics such as tiltmeter and micro-seismic fracture mapping technologies. Mr. Weijers completed his doctoral research at the Faculty of Mining and Petroleum Engineering at Delft University of Technology in the Netherlands by conducting fracture growth model experiments to investigate the interaction of hydraulic fracture systems with horizontal and deviated wells. Before that, he completed a Master’s degree in geophysics, also from Delft University of Technology.