Simulfrac: More Effective While Lowering Pressures

At a recent SPE Workshop in Salt Lake City, a topic of discussion was simulfrac’ing: Is it applicable in high-pressure environments like the Marcellus and Haynesville Shale?

Simulfrac and trimulfrac are taking on a more important role as our industry scales up to frac at higher rates. Pumping in two wells at the same time, at a higher overall rate but a lower rate per well, uses the physics principle that wellbore friction scales with about the square of the rate. When lowering the rate per well by about 25%, wellbore friction reduces by about 40%, thus focusing more of the energy during pumping for creating fractures downhole instead of wasting resources to overcome wellbore friction.

Still, during a workshop poll, participants expressed their reluctance to use this technology in environments where surface treating pressures are already high. The reason for these higher pressures is often deeper wells with higher closure stress gradients.

I think these high-pressure environments are ideal for simulfrac, because they provide the opportunity to lower surface pressures during operations. This technology could even lower the surface pressure below the 10,000-psi threshold. How would that work?

In the graph below I am comparing the measured treating pressures during zipper-frac operations (frac into one well on the left) in the Haynesville with a pressure forecast for simulfrac’ing into two wells at a lower rate per well. Let’s compare a single-well rate of 90 bpm vs a two-well rate of 120 bpm, split in 2 x 60 bpm, on the far right. A key assumption is that I am keeping the rate per cluster the same across all comparisons, so no cutting corners: the 90 bpm serves 9 clusters in one well; the 120 bpm serves 6 clusters in each of the two wells. That means that perforation friction, in yellow below, remains the same at about 500 psi. Most other pressures, except wellbore friction, are not much impacted by these rate changes.

Wellbore friction, in light green, is cut in half to 2,600 psi. That reduces the surface average treating pressure from 12,300 psi to 9,700 psi, a major reduction that may warrant a change in wellhead infrastructure.

A 21% reduction in wellhead pressure, together with a 33% increase in rate, results in a 5% increase in required horsepower to conduct this job. This allows a throughput increase in various metrics – proppant placed per day, lateral length completed by day – by 33%, while the amount of work (HHP-HRs) only increases by 5%.

Granted, this comes at a scaling requirement to have more wells connected to pumping iron, requiring more pad space for ops and to have more wells ready at any given time. But the reduction in pressure and “wasteful work” is a step-change that can provide real savings and make your $/bo production cost lower than ever.