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Optimize your CAPEX now to gain 5 wells’ worth of production with the total expenditure of 4.

Managing CAPEX and quickly getting a positive ROI in shale wells calls for proppants that dramatically boost BOE production from smaller fractures for longer periods.

Deeprop® is custom-engineered to maximize uplift at lower costs by propping open a shale formation’s vast network of secondary fractures. In nearly 200 wells, Deeprop® increased cumulative production by 25%-50%, while allowing operators to achieve payback in as little as 3 months.

We are proposing that you consider pumping DEEPROP® in a slurryin order to reduce costs.


We are suggesting the following (based on a 40 stage well):

  • A Devon Energy Deeprop® trial conducted in 2015

  • The study incorporated fracture modelling, reservoir modelling, lab testing and an 11-well field trial

  • 5-Year lookback shows a production uplift of 52% for the Deeprop® wells generating an additional $3,000,000 in production revenue for an incremental cost of $180,000.


Devon Energy conducted a series of Deeprop® trials in the Barnett Shale back in 2015. The results are reported in SPE-174060-MS. The study consisted of laboratory testing of Deeprop® using split shale core, numerical hydraulic fracturing simulation, reservoir modelling and a field trial consisting of 4 test groups totalling 11 wells. The conclusions of the study found that using microproppant in the pad of an already optimized fracture design provided a consistent additional and significant uplift in well productivity over the first 210 of production in the 11-well study. A 5-Year lookback (60 months of production data) on this study shows a production uplift of 52% generating an additional $3,000,000 for an incremental cost of $180,000.


Methodology Initial Trial:

The study was conducted with the understanding that shale reservoirs are inherently heterogenous, with a combination of continuously varying fluid properties, dense laminations, variable mechanical properties, variable reservoir characteristics, and unevenly spaced natural fractures making these reservoirs extremely complex in terms of production results. However, some consistency in production results were achieved by reducing the drilling target to a range of 50ft in the 400ft Barnett interval. It was also determined through net pressure matching that there was significant fracture complexity/natural fractures in the area. This was verified using microseismic interpretation alongside open hole logs within and near the project area.

A complex fracture modelling tool that was used suggested that even though a natural fracture system could be stimulated, the fracture widths might not be wide enough to enable effective proppant placement within the fracture network; so utilizing a smaller proppant could be extremely beneficial.

The study architects also conducted a sensitivity study using a reservoir simulation model to assess how natural fracture density, intersecting with hydraulic fractures, would affect production. The results were that the more natural fractures intersecting the hydraulic fractures in higher densities results in larger production values.

The field tests were conducted within the Grassland area located in Northeastern Wise County, Texas. The furthest distance between wells was approximately 1.5 miles. All of the wells were designed with similar treatment parameters with the average presented below. It’s worth mentioning also that the study also included the use of an ASMA, an aqueous-based solution of a surface modification agent that was used as a tackifying agent to promote proppant adherence to the surface of the reservoir rock. However, the study conclusion was that this had no noticeable impact on performance with the dominant factor in production being the presence of microproppant. There were a total of 11 wells in the study comprising 4 well groups, with 2 groups containing Deeprop® versus 2 groups without Deeprop®.

Figure 1: Deeprop® wells are shown in Red.

5-Year Cumulative Production Lookback:

The authors of the paper describe the results using all the offset wells in the study. However, Deeprop® was only pumped in outside wells as shown in the pad layout image above shown in red. This would introduce an outside well bias in the data and could impact the study results. For this analysis I will look at the 5-year cumulative production for only the outside wells in the study to remove this bias. The provides a study comparison of 4 Deeprop® wells versus 4 wells without Deeprop® within a 1.5 mile radius.

5-Year cumulative production comparison between the outside wells in the study

5-year cumulative production comparison between the outside wells in the study normalized for lateral length.

The wells treated with Deeprop® in this study produced approximately 26% more hydrocarbons than the offset wells without Deeprop® over the 5-Year period. In this study, 500 gals of Deeprop were pumped per stage and there were between 10-15 stages per well. A simple economic analysis results in a total production benefit of $3,000,000 over the 5-Year study for the Deeprop® wells, for an incremental cost of $180,000.

When the production data is normalized by ft drilled, the difference in the wells treated with Deeprop® versus the offsets becomes even larger. This is evident in the plot below that shows the average production per foot of lateral drilled for the study wells. This was another successful Deeprop® trial in the Permian, Delaware basin.

Average production rates of Deeprop® versus offset wells normalized by lateral length.

It is worth mentioning that well 7HA, an offset well, is shut in after 40 months, and well 7HA was a dog of a well, whereas the MP offset, 8HA produced about on par with the other outside wells in the study.

In the next blog we’ll go over a multivariate analysis that was conducted on all of the Deeprop® wells in the Permian, and the average results from these trials. If you’d like to know more, or have a discussion about trialing Deeprop® in your play please get in touch with us at

Thank you!


  • An 11 well study conducted by Vitruvian Exploration in the Woodford SCOOP.

  • The Original Objective was to Overcome Surface Treating Pressure Limitation set by Casing Specifications and Reduce the Number of Screen Outs.

  • The Study Transitioned to Assessing Production Uplift, after 120-days the Engineers Noticed that the Wells Treated with Deeprop® Showed Higher Expected EUR.

  • The 3-Year Cumulative Increase in Production was Valued at Approx $7,000,000 for a Cost of $700,000, a 10X Return on Capital.



An 11 well study was conducted by Vitruvian Exploration in the Woodford SCOOP. The initial application of Deeprop® was in an area of the field where an increased number of natural fractures existed. Vitruvian Exploration was at the upper limit of their treating pressures, based on casing spec, so Deeprop® was originally used in the pad to open the natural fractures and prevent a screen out. On each stage where Vitruvian Exploration pumped Deeprop® they saw a decrease in the average treating pressure by 500-800psi. Vitruvian Exploration stopped screening out, so they continued to conduct additional paired tests to further vet Deeprop®. Not only was the average treating pressure lowered in each well, but the engineers also began to notice that the EUR was higher on the wells where Deeprop® was used; they observed a shallower decline curve after 120 days. Vitruvian Exploration continued with several more paired tests with similar results. The EUR of the Deeprop® test wells was 18-34% higher (normalized by PPF proppant pumped) at the 120 day mark. Each pair of wells tested had the same conclusion.

Fun fact: Anita Fowler, the best well in the state of Oklahoma, was treated with Deeprop®!



The Woodford shale is a laminated, brittle, silica-rich shale play that produces gas, condensate, and oil. The Woodford SCOOP is a world-class source rock that is oil-prone type 2 kerogen. The shale has good horizontal and poor vertical continuity showing the need for hydraulic fracturing.


As mentioned in the background, Vitruvian Exploration’s engineers conducted paired tests to validate their initial results. Unfortunately, we were not given access to any logs, well path or geological information for this series of trials. However, we do know spatially where the paired test wells were positioned relative to each other. The paired tests were typically conducted on the same pad - the exception was the well: Anita Fowler. The study wells and groupings are shown below, the groups were chosen based on distance to the well treated with Deeprop®. ata from 4 pads was provided to us with 7 wells treated with Deeprop® versus 12 control wells. All of wells were treated similarly with slickwater, 100-mesh, 40/70-mesh and 30/50 mesh sand using 800-1100lbm/ft. The primary difference between the Deeprop® wells and the control wells was that in the Deeprop® wells, Deeprop® 1000 was pumped in the pad at 0.1ppg for a total of 4200lbs/stage.

Table: Vitruvian Exploration Trial Well Lest, Lateral Length and Areal Grouping.

Figure: Vitruvian Exploration Deeprop® Pad Location and Area Map.


Deeprop® was initially used by Vitruvian Exploration to open the natural fracture network and reduce the surface treating pressure to prevent screen outs. The results were a 500-800psi drop in treating pressure as soon as Deeprop® hit the perforations. A sample is shown below, where a small pressure drop is observed when acid hits the perforations, followed by a large pressure drop when Deeprop® hit the perforations. The results were a reduction in the frequency and intensity of screen outs.

Figure: Surface Treating Pressure Reductions from Acid and Deeprop®.

Vutruvian Exploration was not expecting any production uplift when they began using Deeprop® as a solution for high treating pressure. The uplift was noticed after the wells were on production for 9-12 months.

Figure: Ernesteen Pad 20 month Cumulative Production

Figure: Johnny-Rogers pad 29 month Cumulative Production – 19% uplift.

Figure: Joyce pad 18 month Cumulative Production – 4% uplift.

Figure: Parks & Ellis pad 16 month cumulative production results, note A second variable is that the Parks wells were treated with slickwater and the Ellis wells were treated with crosslinked gel – 42% uplift

Figure: The Anita Fowler well, the best well in the State of Oklahoma, was treated with Deeprop®. Below is Anita Fowler’s Cumulative Production versus the Closest Offset.

Figure: Three Year Total Cumulative BOE for all wells in the Study Area

Study Conclusions:

On the six pads where Deeprop®1000 was used there was a 3-year cumulative increase in production compared to the offset wells of 500,228 BOE. At a $15.61/BOE netback this increase in production would be valued at $7,809,433 for a product cost of $752,000, or a 10X return on investment.

On the wells where Deeprop® 1000 was used there was also a 500-800psi drop in near wellbore pressure allowing for an increase in pump rate with improved fluid efficiency, lowering treatment costs with fewer screen outs/dropped stages.

After this study, Vitruvian Exploration began incorporating Deeprop® as a standard into their completions program. Unfortunately for us, Vitruvian Exploration was subsequently purchased by another operator; we were informed that the high purchase price was in part due to the performance increase in this area.

In the next blog we’ll take a look at the trial results in the Marcellus Shale, an area where Deeprop® didn’t work. We’ll go over the results and why we believe this is the case.

If you’d like to have a discussion about Deeprop® and if it can improve well performance in your play, get in touch with me or send an email to

Thank you!

Updated: Aug 24, 2021

  • An Operator spied on their neighbour’s completion design and began conducting their own Deeprop® trials in the Woodford SCOOP.

  • The Operator tried to normalize their study for geology, well construction and completion design.

  • It took 90-120 days for the wells treated with Deeprop® to begin outperforming the control wells in the study.

  • The production rates of the wells treated with Deeprop® appear to decline slower, and a much flatter GOR was observed.


In this blog series we will explore the results from a trial an operator conducted in the South Central Oklahoma Oil Province (SCOOP) – Woodford Shale. The operator’s design consisted of 4.6 tonnes of 100 mesh, and 145 tonnes of 40/70. This operator was monitoring the results from Deeprop trials being conducted by a competitor in the area and began conducting Deeprop trials of their own. This small operator eventually began incorporating Deeprop into their completion designs and subsequently sold the field.



The Woodford shale is a laminated, brittle, silica-rich shale play that produces gas, condensate, and oil. The Woodford SCOOP is a world-class source rock that is oil-prone type 2 kerogen. The shale has good horizontal and poor vertical continuity showing the need for hydraulic fracturing. This small operator surmised that they could enhance their production be incorporating a highly permeable 400-500 mesh proppant into their completion design.

Trial Methodology:

The intention of the trial design was the minimize the effect of geological and well construction variations on the interpretation of the trial results. The operator conducted an extensive logging program and determined that the geology in the trial area was consistent for normalization purposes; however, one control well was identified as having a higher reservoir quality and was expected to produce the best.

The operator maintained a consistent well construction program with similar lateral lengths, well orientations, and stage spacing. The operator also maintained a consistent frac design, with the only difference being the addition of 8,200lbs of Deeprop® per stage in the Deeprop® test wells.

Initial Production Results (30 & 60 Day):

The initial production results from the wells treated with Deeprop® do not appear to provide any upside versus the control wells. However, as mentioned in previous blogs; the upside isn’t seen in the initial 30-day or even 60-day production results, but over the long term producing life of the well. Deeprop® wells are characterized by slower production decline rates, not higher initial production rates.

90-Day Production Results:

After 90-days the cumulative production of 2 of the wells treated with Deeprop® is higher than then the control wells, while the trend of the third Deeprop® well does not appear to be overtaking the best producing control wells. Again, I want to emphasize that the initial production rates of the Deeprop® wells were not significantly different from the control wells. The animation below shows the production rates of the Deeprop® wells versus the control wells. What the animation makes it clear that the production decline rates of the Deeprop® wells is slower than the control wells.

Production decline rates of the Deeprop® wells versus control wells.

6-Month Production Results:

After 150 days on production the two best producers are the Deeprop® wells by significant margins. The third Deeprop® well is now on trend to overtake the highest producing control wells over the next 30-60 days. Unfortunately, this is the extent of the data that was shared with us for this series of trials.

6-Month cumulative production results.


The results from this Deeprop® trial in the SCOOP mirror the trial conducted in the Delaware basin discussed in the previous blog. The operator conducted tests in area where the geology was identified to be relatively homogenous for normalization purposes. The well construction between the control wells and the Deeprop® was designed to minimize variability and the completion program was kept relatively consistent.

The results show that the Deeprop® wells do not outperform the control wells during the early production period of 30 to 60 days. What characterizes wells treated with Deeprop®, are the slower production decline rates. After 90-days the cumulative production of the two Deeprop® wells surpassed the control wells with the highest initial production rates – After 120-days the remaining Deeprop® well was on trend to outperform the control wells.

There was one other observation made, the very flat gas-oil-ratio in the Deeprop® control wells. One explanation could be a more efficient use of reservoir pressure in the wells treated with Deeprop®, possibly associated with improve cluster efficiency, or erosion of near wellbore tortuosity.

After this study, the operator began incorporating Deeprop® as a standard part of their completions program until the sale of this asset.

In the next blog I will go through another series of trials that were conducted in the SCOOP, where the operator initially utilized Deeprop® to reduce surface treating pressure to allow the effective placement of proppant. However, after a couple of years on production the operator noticed a difference in well performance!

If you’d 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

Thank you!

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