The Duvernay Shale Completion Journey

Abstract The unconventional Shale and Tight play concept has grown to dominate the North American energy landscape, now accounting for the vast majority of onshore activity levels. However, not all Shale or Tight reservoir plays are created equal and what works for one play/Formation may not work for another. How should you design your stimulation, where to begin, what parameters are most impactful and what are some of the large economic leavers that can either make your project successful, or potentially cause it to fail. The Duvernay is an Upper Devonian mudrock, with significant quartz, carbonate and total organic carbon content, making it an attractive Shale gas target. Total Organic Carbon (TOC) varies from 2-17 wt.% and porosity ranges from 3-8% (averaging approximately 5%). The Formation is approximately 2,800 – 3,800 meters deep in the project area and is approximately 35-60m thick. Importantly, the target is significantly overpressured, with nearly double normal hydrostatic reservoir pressure (15-21 Kpa/m gradient). The native permeability of the Duvernay Formation is extremely tight, measuring in the 70-150 nano Darcy range, thus the formation requires horizontal wells with multi stage hydraulic fracturing, to be economically productive. The natural fracture density of the formation partially explains how a rock with such low matrix permeability can be so prolific, background tectonic fracturing is significantly greater than most other low permeability reservoirs being exploited in North America. Fracture densities have been measured in core and image logs at up to 8 fractures per meter, with average open fracture density's approximating 1-2 per meter. These fractures are steeply dipping (75-85 degrees) and created during tectonic events, both open and healed/calcite filled fractures are present. While the presence of natural fractures aid in the productive stage of the well's life, it can complicate the stimulation design and challenge the placement of a wellbore treatment. During the initial planning stages of an unconventional hydraulic stimulation program, the first step is to examine what other operators in the play are already utilizing. Early due diligence into what design elements are successful and almost as important, not successful, can save significant amounts of capital early in the evolution of a project. An example of this within the Duvernay project were uncemented ball drop liner completion systems. Due to the high-pressure pumping requirements of the Duvernay (up to 90 Mpa), these systems were not able to adequately stimulate the reservoir and were prone to install and isolation challenges. Limited entry Plug and Perf design dominates the Canadian unconventional energy landscape, this is where Chevron Canada Limited and KUFPEC Canada ("The JV") began its journey. The next critical stimulation parameters to decide on are proppant and water intensities, these will govern the duration of the stimulation and are key economic drivers (proppant intensity is typically the most significant variable in terms of cost and well productivity). Other major inputs into the frac program center around cluster design; number of clusters to be treated as part of a single frac stage, the spacing between the clusters and the number and orientation of perforations within a cluster/stage are key parameters. The treatment pressure is usually dictated by the breakdown and fracture extension pressure inherent to the reservoir, where the target treatment rate is a selection made by the operator (typically 10-15 m3/min for most unconventional reservoirs). Stimulation fluid design also varies by play type, Slickwater designs are some of the most popular in use today with hybrids, reverse hybrids and high viscosity friction reducer (VFR), also used in various quantities across play types. Connected to the stimulation design, is the interwell spacing distance, usually the wider wells are spaced from one another, the higher the proppant intensity. The key premise of limited entry design assumes that all the clusters within a fracture stage are taking fluid and sand equally and thus, have equal fracture half lengths, this is not the case (concept known as cluster efficiency), more discussion on that topic to follow later in the manuscript.

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