Updated: Jul 7

  • The Delaware Basin trial results were an extraordinary success.

  • The trial wells easily exceeded the hurdle rate of >10% production uplift.

  • The operator is looking to expand the trial to include a larger number of wells.

This operators DEEPROP® trial was designed to minimize the bias from inherent geologic, drilling and completion variability. Despite the amount of design, planning and controls put in place for this trial, the operator set a 10% production uplift hurdle to conclusively determine project success. The combined production uplift from the wells treated with DEEPROP® was 23%, easily exceeding hurdle rate, generated an additional 120,000BOE, and created a 700% return on investment on the cost to incorporate DEEPROP® into their design. This operator is now looking to expand the trials to a significantly larger series of tests.

Trial Methodology

Many variables play a role in well performance in unconventional shale plays – in a broad sense they are the variability in geology, how the well was constructed, and how the well was completed. The methodology employed by the operator for the trial presented below was to minimize the impact these variations would have on interpreting the production impact of using DEEPROP® to enhance production in their Delaware Basin Play.

To achieve this, the operator selected an area of virgin reservoir – to avoid depletion effects from parent wells. They drilled two, 2-well pads to both avoid inside/outside bias, and the possibility of interference effects between wells. One pair of wells was set in the Wolfcamp A, and one pair of wells was set in the Wolfcamp B. The operator also constructed the wells the same, i.e. same lateral length, same landing depth, etc; and kept the completion design the same, i.e. same number of stages, same stage spacing, tonnage etc.

Despite all of these controls to eliminate the inherent variability in horizontal multi-frac well performance, the operator set a 10% production hurdle rate. If the production uplift was less than 10%, the test results would be inconclusive; however, if the production uplift exceeded 10%, it was deemed to be a significant enough production uplift to conclusively say that DEEPROP® was providing the production enhancement.

It is worth noting that the operator used SPE-194340 to estimate the extent of their pre-existing and stimulated secondary fracture network; this led the operator to pump DEEPROP® as 5% of their proppant tonnage in the test wells to ensure that they completely filled the stimulated micro-fracture network; typically we recommend 2.5% as a starting point.

6-Month Production Update

The figures below are the 6-month production update for the DEEPROP® trial. Despite being drilled and completed at the same time, there are differences in the producing periods because the wells were shut in or curtailed periodically due to emission issues. The DEEPROP® well in the Wolfcamp A, also lacked cement integrity for approximately 35% of the lateral but is still the best producer. The black, dashed line represents the type-curve for this area.

Figure 1: Wolfcamp A, 6-month production DEEPROP® Trial

Figure 2: Wolfcamp B, 3-month production DEEPROP® Trial

At 6-months, the DEEPROP® well in the Wolfcamp A has produced 30% more than the type curve, and the DEEPROP® well in the Wolfcamp B has produced 21% more than the type curve; both DEEPROP® wells are outperforming their respective control wells. Below In figure #3, the operator also shows that the DEEPROP® wells have higher sustained casing pressures, and a higher productivity index versus the control wells. The final assessment of the trial would be made after 9 producing months.

Figure 3: Operator supplied plots.

11-Month Production Update

The results after 11-months were astounding, the DEEPROP® treated wells yielded 23% more production than the control wells, easily exceeding the hurdle rate set by the operator. Combined, the wells treated with DEEPROP® produced an additional 120,000 BOE, compared to the offsets without DEEPROP®. Monetized at a $35/bbl netback, the wells treated with DEEPROP® generated an additional $4.2MM in revenue for a cost of $0.6MM, or an ROI of 700% in less than 1-year.

This operator is currently looking to expand their trials to an area where they have a larger footprint and can incorporate DEEPROP® into a more statistically significant test.

Figure 4: Operator supplied 11-month production update.

If you’d like more information about DEEPROP®, or if you’d like to have a chat with us about how you can apply DEEPROP® in your play, get in touch with us at:



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.

Thank you!

  • The goal of a hydraulic fracturing treatment is to create a high permeability pathway to limit how far the reservoir fluids have to move through the matrix.

  • Micro-proppant pack permeability can become close to the permeability of the matrix.

  • Silica micro-proppants, and angular ceramic micro-proppants have reduced permeability and crush strength, if the permeability of these proppants is the same, or is close to the permeability of the matrix, operators are wasting capital.

  • DEEPROP® provides a high degree of permeability relative to the rock matrix into operators micro-fracture network, and keeps these fractures propped open due to its high crush strength..

  • 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.

The purpose of hydraulically fracturing unconventional shale plays is not just to contact as much reservoir surface area as possible, it is also to efficiently drain as much reservoir as possible. The issue with current proppant technology, like 100 mesh proppants or larger, is that they are to big to enter the tiny pre-existing fractures and faults, and too big to enter the hundreds of propagating hydraulic fractures that are being created; micro-proppants can enter fractures that are 5-10x smaller than 100 mesh, or about the width of a human hair (100µm). But proppants that are this small, have a very tiny proppant pack permeability, simply due to their small size. In fact, the permeability of a micro-proppant pack can be the same order of magnitude as the matrix permeability in the formation. It is critical for operators to select a micro-proppant that provides enough permeability to transmit the fluids through the narrow micro-fracture network efficiently, if they don’t, they will be wasting capital.

The purpose of hydraulically fracturing the rock is to create a more efficient flow path for the reservoir fluids to move from the matrix to the wellbore. The reason is because, for example, it takes 3-years for methane to diffuse 3-10 meters in 10-100 nano Darcy rock, and it takes oil 3-years to move 1-2 meters in the same rock. The shorter the distance the produced fluids must travel through the low permeability matrix, to a high permeability pathway, and keeping these pathways open for as long as possible; is beneficial for an operator’s production.

Figure 1: The time required for methane to diffuse through typical matrix permeabilities is given on a linear scale on the left and a log-log scale on the right. The gray region indicates that approximately three years are required for gas to diffuse approximately 3-10 m through 10-100 nanodarcy matrix to a high permeability pathway. The corresponding time/distance relationship for oil is shown in red, with an approximately factor of 10 higher viscosity resulting in a corresponding decrease in diffusion distances. The gray and pink boxes reflect a representative range of matrix permeabilities for unconventional reservoirs. From Hakso & Zoback (2019), taken from Zoback and Kohli (2021).

Using micro-proppants to enter tiny fractures allows operators to prop more reservoir surface area and prevent those tiny fractures from closing over time. In the past, operators have tried using silica micro-proppants but the permeability of silica micro-proppants is so low that it doesn’t provide any benefit; DEEPROP® is a ceramic micro-proppant technology. There are several differences between silica and ceramic micro-proppants that I believe are what makes DEEPROP® successful; they are differences in crush resistance and permeability/conductivity.

It seems counterintuitive that proppant conductivity could play a role in unconventional, low-permeability shale plays. But I want you to consider the size of the particles of a micro-proppant, the width of the fractures that a micro-proppant can enter, and the permeability of the micro-proppant pack relative to the permeability of the rock matrix that is being stimulated. I’ll demonstrate this using conductivity data for DEEPROP®1000. Conductivity testing was carried out by C&A Labs, and the results are shown below.

Figure 2: Conductivity testing data conducted by C&A labs on DEEPROP®1000. The conductivity data indicates that DEEPROP®1000 can provide a high permeability pathway for reservoir fluids in formations with matrix permeability less than 5µD.

Using the conductivity data above, If I assume a minimum fracture width of 0.21mm (a 3x bridging factor for DEEPROP®1000), the minimum permeability of a DEEPROP®1000 proppant pack ranges from 0.138 µD to 0.413 µD, or 138 nD to 413 nD at effective stresses of between 10,000 psi to 2,000 psi. The permeability of the proppant pack is perhaps an order or two in magnitude above the matrix permeability for a typical shale formation – The Key Takeaway is that the Permeability of a Micro-Proppant Pack is Tiny.

I have requested conductivity data from 5 silica micro-proppant and one ceramic micro-proppant supplier, none have been willing to share conductivity or crush data, which is telling by itself, but if we assume it is an order of magnitude less than DEEPROP® – not a crazy assumption; then silica micro-proppant permeability would be on the same order of magnitude as the matrix permeability. This would not be surprising, given that the average diameter of the clastic grains in a shale matrix are 50µm, which is about the diameter of 200-300 mesh silica flour and fumed silica. This would explain the lack of incremental production when using silica micro-proppants; the permeability of the silica micro-proppant pack is the same as the matrix permeability. For a micro-proppant, conductivity matters because the proppant pack permeability becomes close to the permeability of the shale matrix. If the micro-proppant selected does not have a high permeability relative to the shale matrix, it will not provide any production upside – it is like re-filling the micro-fractures you created with matrix material.

I also believe that crush strength play an important role, both in keeping the micro-fractures open and for maintaining conductivity/permeability within the micro-fracture network. As mentioned above, no supplier that I have contacted has been willing to provide crush data for their silica micro-proppant, the same can be said of the competitive ceramic product, again, this is telling. Given the angular, jagged shape of silica flour and fumed silica micro-proppants (shown below), I believe the crush strength is low, this probably explains why no one is willing to supply the data. A low crush strength would cause spalling, and fragmentation of the proppant grains, further reducing the already low permeability values, and allow the micro-fractures to begin to close.

Figure 3: Silica flour and fumed silica, it’s clear how the grains would stack together like lego bricks, and that there are many contact points for grains to crush, spall, and fragment to reduce the proppant pack permeability even further.

One final theory for what makes DEEPROP® work so well at providing incremental production is the erosion of near wellbore tortuosity. As the fracture initiates, and re-orients as it propagates away from the wellbore, there is often a near wellbore constriction that the fluid must pass through. This constriction can cause significant friction pressure during the hydraulic fracturing treatment, and acts as a choke during production, causing pressure loss in the reservoir. What has been observed during treatments with DEEPROP®, are pressure drops of between 800-1,200 psi as soon as DEEPROP® hits the perforations. What we believe is that the Bernoulli effect causes DEEPROP® to be concentrated in the centre of the fluid stream, as DEEPROP® is a very hard and durable material, it abrades this near wellbore constriction. This reduces the near wellbore convergent effects and limits the reservoir damage during production.

At proppant diameters of 100 mesh or larger, the permeability ratio of the proppant pack to the matrix is so high it does not matter what kind of proppant operators choose; silica, or ceramic. But when you begin to consider the permeability of proppants that are 200 – 300 mesh, or 400 – 500 mesh, like DEEPROP®, the permeability of the proppant pack becomes critical, and it is something that needs to be carefully considered. Pumping a micro-proppant that has the same permeability as the rock fabric is not going to be beneficial for operators, in fact, it will be a waste of capital. As Carl Montgomery often says - when you pump a frac, what you are paying for is conductivity. DEEPROP® has been successful because it is small enough to enter micro-fractures and delivers a high permeability to the micro-fracture network, relative to the rock matrix, in spite its tiny size.

Figure 4: Microscopic image of DEEPROP®1000 placed on a core sample prior to conductivity testing. DEEPROP® is perfectly spherical, the best shape for retaining conductivity and providing a high crush resistance.

Next week I will start to dive into the field trials and the results that operators have achieved using DEEPROP®!

If you would like to learn more about how DEEPROP® can enhance your proppant placement and provide incremental production, please get in touch with me or send an email to info@deepropfrac.com

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.

Thank you!

  • 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 info@deepropfrac.com

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.

Thank you!

The Future of Well Enhancement