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  • Charles Wrightson

Vitruvian Deeprop® trials

  • 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.

Background:

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®!

Geology:

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.


Methodology:

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.


Results:

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

Info@DeepropFrac.com

charlesw@DeepropFrac.com


Thank you!





The Future of Well Enhancement