Frac Fluids Run to the Bottom

The Shale Revolution has inspired a screaming run to the bottom for frac fluid system requirements. The goal at the bottom is simply water. 

Fracking did not start out that way. The early days of fracking often placed strenuous requirements on frac fluids for proppant placement, with fluids needing to transport and place ultra-high proppant loadings to create sufficient fracture conductivity. Requirements of frac fluids rose steeply like the first half of the Pikes Peak Marathon. Now, the Shale Revolution has pushed these requirements into a screaming downhill run to the bottom, towards water.

While 100% water may be an elusive goal for fluid composition in most frac jobs, the industry today requires fewer additives and lower additive quantities than ever before to carry proppant far into hydraulic fractures. 

Opponents of fracking often point to the hundreds of chemicals found in frac fluid, but they point to past exceptions and are behind the times when it comes to current fluid formulations. Our industry reports chemicals going downhole through FracFocus.org, and trends per well for most chemicals except water are heading down.

Most properties of traditional gels can be obtained through common household products available at a grocery store. Two new Liberty Educational Videos show step-by-step recipes to make a frac fluid at home from just four common components. 

The core requirement for a frac fluid is to carry proppant, mostly sand, from the well’s surface location all the way down to the reservoir across from the rock formation that will produce hydrocarbons. Traditional gels like the ones our Lab Manager Joel demonstrates in the videos were originally created to provide a high proppant carrying capacity that can withstand high reservoir temperatures for some time while keeping proppant in suspension. Often, a gallon of this gel may be required to carry as much as 10 pounds of proppant, and sometimes even more. 

While there is a necessity in some frac jobs for these extreme requirements, shale fracking is on the other end of the proppant-carrying spectrum. That is because conductivity of the proppant pack is not as important as creating a complex fracture surface area to touch as much rock as possible. As such, it is not necessary to pump very high-quality proppants and it is not required to pump slurries with very high proppant concentrations.

The graph below shows how proppant choices in the South Texas Eagle Ford Shale have turned to the local, finer (brown) sands in recent years, a similar trend we observed in the Permian, DJ and Williston Basins. It appears that local sands, though inferior to the White Sands from Wisconsin with about one-third of its overall conductivity, are sufficient for providing adequate conductivity, at least for the first year of typical shale production. 

Physics, Stokes’ Law in particular, has inspired a change in frac fluid requirements and composition associated with these changes in the industry’s proppant preferences. Stokes’ Law defines the equilibrium between drag force and gravitational force for a spherical grain moving through a medium. In the frac business, that applies to a grain of sand moving through frac fluid.  

Settling velocities for crosslinked fluids are practically zero but can be substantial for low-viscosity fluid systems such as slickwater or water with friction reducer (FR). In these jobs, proppant can settle into a proppant bank at the bottom of the fracture and initiate a local tip screen-out where further downward growth is arrested through the presence of this bank. The balance between viscous and gravitational forces is embodied in Stokes’ law for the settling velocity vs of an unobstructed particle with radius Rp:

Where ρp and ρf represent the specific density of the particle and the fluid it is embedded in, g represents the gravitation acceleration and μ represents the dynamic viscosity of the fluid system, assuming a Newtonian fluid system. 

In a frac job, settling velocity is the enemy. If proppant settles or accumulates in a wellbore, perforations or near-wellbore area of the fracture, a blockage may be created, and a premature screen-out may be the result. Also, if a fracture stays open for a long time (bingo for shale fracs!), proppant may settle toward the bottom of the fracture. This may be desirable in some cases where fracture grow outside the target zone, but may be undesirable in other cases.

As proppant choices have gone from 20/40 mesh to mostly 100 mesh, the average proppant radius Rp has been reduced by a factor of about 3. According to Stokes’ Law, only one-ninth of the original viscosity is therefore required to obtain the same settling velocity.

Proppant transport and placement have also been aided by a viscosity – velocity trade. In pipes and fracture, a higher injection rate provides less time for proppant settling. As shown by the top of the plot below for Eagle Ford fracs, injection rate per lateral foot have increased steadily, just as they have in other shale basins.

While minimizing fluid cost, we have also become better at obtaining better properties out of these fluids. Lower quantities of guar in traditional fluids lead to less damage from polymers we cannot effectively flow out of the proppant pack. 

For example, in the DJ Basin operators opted for low-residue CMHPG systems until about 2014. Then, they started switching to ultra-low loading guar systems. While guar leaves a higher residue in the fracture, the much lower loading of guar left lower overall conductivity damage. 

This trend has continued as FR fluid systems have become the fluid system of choice for our industry. We see in PS-50 regained conductivity tests that we routinely conduct on all proppant we pump for customers that FRs provide better cleanup (regained conductivity) and thus a more effective proppant pack. 

Also, FRs get a viscosity boost in an area of low shear rates. In the graph below, we compare the apparent viscosities of a linear gel and a high-viscosity FR (HVFR). Both have a target viscosity of 20 cP at a standard shear rate of 511 s-1. If we test apparent viscosities at normal shear rates above about 10 s-1, these fluids behave the same. In the range below that, where we can extrapolate to “zero-shear” viscosity, the differences are significant, with the HVFR showing superior viscosity.

At ultra-low shear rates, FRs can therefore sometimes provide a superior proppant carrying capacity in comparison to more traditional linear gels. While this capability is greatly dependent on water quality, it can greatly boost the viscosity term μ in Stokes Law.

The elusive goal for frac fluids is to be comprised 100% of the chemical H2O. In some cases, we are already at 99.83%. We may get closer if pump rates for frac jobs keep rising and if properties of some concentrated additives keep improving as they have during the screaming downhill run to water we have experienced over the last 15 years. 

Thank you

To our Lab Manager Joel and Lindsey for some of the technical fluid data presented here, Matty and Jes for Liberty’s Eagle Ford FracTrends viewer, Robert for filming and Liz for moral support.