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  • Writer's pictureCharles Wrightson

Devon Delaware Basin 60 month Deeprop® Trial Lookback

  • 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!



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