How to Enhance Proppant Placement in Unconventional Reservoirs
DEEPROP® can enter fractures that are 10x narrower than 100 mesh.
DEEPROP®’s settling velocity is 35x slower than 100 mesh.
Most of the fractures that operators are creating are unpropped because the fracture apertures are too narrow for the proppants they are using.
The apertures of hydraulic fracture swarms and complex fracture systems are likely too narrow for proppants that are 100 mesh or larger to enter. Micro-proppants can enter fractures that are 10 times smaller than 100 mesh, and the settling velocity of micro-proppant is 35 times slower than 100 mesh. Micro-proppant expands operators ability to place proppant inside smaller more complex fracture systems, and incrementally increase the propped fracture area in unconventional shale plays.
There are several theories for how DEEPROP® is providing uplift in unconventional shale plays. What we have are several hypotheses and the results from field trials. I am splitting this section up into two components. The first section I will look at the benefits of micro-proppants versus conventional proppants; and in the second section will look at the differences between silica micro-proppants and DEEPROP®.
Fundamentally, the principle of using smaller proppants is that they can enter smaller fractures and prop more reservoir surface area. A smaller proppant is going to have several advantages over proppants that are graded 100 mesh or larger, these advantages are:
They can be carried further into the reservoir due to a slower settling velocity.
They can enter narrower fracture apertures.
They have a surface area advantage i.e., a small amount can prop a huge surface area.
Proppant diameter controls how small of a fracture the proppant can enter. Conventional theory states that the minimum fracture diameter that a proppant can enter is 3 times the mean proppant diameter, this is due proppant bridging across the fracture aperture, which may plug the fracture. The minimum fracture width that 100 mesh proppant can enter is 0.91mm; any fracture smaller than 0.91mm will not receive any proppant, once the well is put on production and the fluid pressure inside these fractures is less than the effective stress, they will close.
Unpropped, tiny fractures are where I believe operators have a huge opportunity to improve recovery in unconventional shale plays. Recent experiments that have collected both core and image logs to study hydraulic fracture propagation and proppant placement in unconventional shale plays have provided evidence of what the industry is calling - hydraulic fracture swarms; hundreds of propagating hydraulic fractures which strike parallel to the direction of maximum principal stress. There is a debate around if these fractures are propagating simultaneously or sequentially, in either case, the core through studies found that these fractures were primarily unpropped. I believe that the proppant the industry is currently using is too large to enter and prop most of the fractures that are being created.
Figure 1: Comparison of Proppant Entry Diameters
The concept that current proppant sizes are too large to enter the small fractures that are being created extends to the pre-existing fractures and faults that are activated during hydraulic fracturing. As Mark Zoback states in his book “The high pore pressure perturbation associated with multi-stage hydraulic fracturing is capable of triggering slip on pre-existing fractures and faults in the formations surrounding the hydraulic fractures. The fact that many of these old, dead fractures and faults (often mineralized with calcite) often have a wide variety of orientations is critical for the pressures associated with hydraulic fracturing to create an interconnected permeable fracture network, which, in turn, is critical to facilitate production”. It is theorized that these fractures are held open by the asperities that exist between the two surfaces that have slipped. Due to the variation in orientation of these fractures, the effective stress is higher than the minimum principal stress, resulting in narrow apertures. A micro-proppant could enter these fractures and keep them open for a longer period of time, improving storage and drainage; I believe that it would be impossible for 100 mesh or larger proppants can enter these types of fractures.
Figure 2: Illustration of the manner in which elevated pore pressure during hydraulic fracturing triggers slip on pre-existing fractures and faults.
The fracture planes and the stress state are from an image log in a horizontal well in the Barnett shale, characterized by a normal/strike-slip stress state (Shmin << Shmax ≈Sv). The blue, yellow and green planes are the hypothetical planes normal to Shmin (like a hydraulic fracture), Shmax (normal to hydraulic fractures) and Sv (parallel to horizontal bedding planes) respectively. (a)Reference case assuming near hydrostatic pore pressure. (b) Slightly elevated pore pressure indicates a group of NE-trending planes are activated – those releatively well oriented for slip in a SS/NF stress state. (c) At a relatively high pore pressure perturbation, shear is expected on more planes. (d) At a pressure corresponding to the least principal stress, shear is expected on many planes of highly varied orientation From Zoback and Lund Snee (2018). Taken from Zoback and Kohli (2021).
Figure 3: Generalization of the way in which slip on a pre-existing natural fracture is likely to increase its initial permeability and decrease the sensitivity of the permeability to depletion (after Barton et al. 2009). Taken from Zoback & Kohli (2021).
There is also a significant difference in settling time between micro-proppants and conventional proppants. The Stokes settling velocity for a 20/40 proppant is 1.00 ft/s; for 100 mesh it is 0.063 ft/s; and for 400-500 mesh proppant it is 0.0018ft/s. The settling velocity of the 400-500 mesh proppant is 35 times slower than the settling velocity of 100 mesh. This is a difference that becomes especially important if operators are creating hundreds of hydraulic fracture swarms.
To illustrate this, let's assume we are pumping proppant into a single planar fracture that is 500 ft long, at a rate of 60 bbl/min (10m3/min). Assume the fracture aperture is 0.035 in (.000889m), and the fracture height is 164 ft (50m); this gives a fluid velocity of 12 ft/s (3.75m/s). It would take 41 seconds for the fluid to reach the tip of the fracture; in 41 seconds a particle of 100 mesh would fall 2.5 ft - the proppant would reach the tip of the fracture. Now assume we have 1 large fracture and 900 hydraulic fracture swarms, the pump rate is 60 bbl/min (10m3/min), one fracture is .035 in (.000889m) in width, and 900 fractures are .0029 in (.000074m) in width; the fluid velocity drops to 0.16 ft/s (.05m/s). It would take 3125 seconds for the fluid to reach the tip of the fracture, but in 2603 seconds, the proppant would fall 164 ft meaning the proppant would not be carried to the tip of the fracture.
There are a lot of assumptions here, I am assuming no dynamic leak-off, no reactivation of pre-existing fractures or faults, limiting the fracture widths, and assuming that all 900 of the fractures are propagating simultaneously. The idea is that fracture complexity can severely impede Operators’ ability to effectively place proppant. This would explain the results in Raterman et al (2017) and in GTI/Laredo, where they found little evidence of proppant transport greater than 75ft (20m) from the wellbore. In 43 seconds, a 400-500 mesh proppant would fall 0.073 ft, and in 3125 seconds, it would fall 5.6 ft.
Table 1: Difference in Fall distance for 100 mesh and DEEPROP® in a planar fracture scenario and hydraulic fracture swarm scenario.
Evidence from core through studies indicate that the fracture systems that are being created are much more complex than what has been previously thought. This has been proven by both the Raterman et al (2017) and GTI/Laredo studies, along with work performed by experts in the field of geomechanics. Micro-proppant technology allows operators to place proppant further into the reservoir, and into smaller fracture systems, resulting in 10% more production.
Figure 4: Schematic view of well paths in the core through experiment in the Eagle Ford formation reported by Raterman et al. (2017). Hydraulic fractures as identified in either core or calibrated logs are shown as white discs. Cored intervals are shown in blue. Over 900 hydraulic fractures were recorded in S3. From Zoback & Kohli Unconventional Reservoir Geomechanics.
In the next blog post I’ll talk about why I think silica micro-proppants have failed in the past, and some of the theories we have for what makes DEEPROP® work!
If you would like to learn more about how DEEPROP® can be a solution for your company and lower your decline rates, please get in touch with me or send an email to firstname.lastname@example.org
We’re also hosting a booth at URTeC, booth 4600 from July 26-28th! I would encourage you to stop by for a chat, we would love to meet you.