• Shale Resource Evaluation

Shale Resource Evaluation

Shale Resource Evaluation

Shale Resource Evaluations have become one of the top INEXS core competencies over the recent decade. The INEXS evaluation includes:

  • Every shale resource evaluation begins with identifying the objective acreage position within the basin and determining which tight reservoir(s) are prospective targets for horizontal drilling and completions, based on offset operators’ production.
  • For each prospective target reservoir, historical production is pulled from all relevant offset wells with at least 6 months of production to project estimated ultimate recovery (EUR) of each individual well. A technical production limit is placed on each projection to keep production estimations within reason.
  • One of the most difficult and contentious aspects of predicting EUR’s for future drilling locations is the selection of wells that make up the dataset for future EUR prediction.  While SPE and SPEE guidelines help determine the appropriate size dataset for reserve audits requiring a P90 reserve value, a client company may be more interested in the Most Likely or P50 value for future drilling results. 
  • Most shale resource and tight reservoir plays demonstrate significant year-on-year improvements in EUR based on the combination of longer laterals, greater frac fluid and proppant, staged fracs, and better choke management.  For some shale reservoirs, these Y-O-Y improvements plateau over time until the next technological breakthrough.
  • As such EUR calculations are often ‘normalized’ to a certain recovery per lateral foot, and for proppant volume when available.
  • Once the data has been normalized, an EUR ‘heat map’ is generated either for the entire basin, or local to the objective acreage, and future drilling locations can be added to the map, extracting the EUR for each of those future locations.
  • Using these extracted EUR values and a set of economic assumptions, a single well economic model can be built to calculate IRR and NPV-10 to determine the economic threshold of drilling a new well in the target reservoir.
  • These economic assumptions are derived from investor presentations, public announcements, and press releases from offset operators. These costs typically consist of assumptions for drilling, completions, fixed & variable lease operating expenses, gathering, processing, transportation, basis differential, and state & local taxes. Commodity price is another crucial component of developing an accurate economic model.
  • The single well economic model can then be adjusted for varying rates of production and applied to relevant acreage to estimate a value of a drill-out scenario.
  • The reality is that in any shale resource play, there are a certain percentage of wells drilled (5% – 15%), that underperform relative to their pre-drill predictions.  The underperformance may be caused by the combination of one or more of the following, including but not limited to:
    • The wellbore weaves up and down, or in and out of the formation reducing the lateral feet of actual reservoir face, and creating low areas that slow liquids production
    • Poor quality casing, or poor casing cement job that reduces the effectiveness of the fracs and potentially could lead to failed or collapsed casing
    • Incomplete or failed frac stages that cumulatively add up to a poorer performing well
    • Locally altered reservoir rock that has less thickness, porosity, or permeability due to a variety of possible causes

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