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STACK Fracture Mapping Diagnostic Tools

ESG combined both new and commonly accepted technologies to quantify stimulated fracture geometry and provide a better understanding of fracture geometry and optimal well spacing during early field development.

Understanding the stimulated fracture geometry in unconventional reservoirs allows for optimal development of the asset, and both new and commonly accepted technologies can quantify this geometry. A thorough understanding of fracture geometry and well spacing early in the field development process can drastically improve the project net present value, especially when developing stacked intervals.


An unconventional spacing pilot in the STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties), located in the Anadarko Basin, required monitoring for one of the basin’s stacked reservoir intervals. We provided fiber optic monitoring for Well C in a five-well layout.

ESG Solution

We applied several diagnostic technologies to improve understanding of fracture geometry, including the following.

  • Fiber optic monitoring (Distributed Acoustic Sensing and Distributed Temperature Sensing) to assess cluster efficiency, fluid and sand distribution per cluster, and diverter effectiveness
  • Borehole microseismic to estimate hydraulic half-lengths, heights, and fracture azimuth
  • Electromagnetic imaging to provide insight on hydraulic half-length for 12 stages
  • Offset well pressure monitoring with IMAGE Frac technology to provide hydraulic and propped half-lengths, heights, and fracture azimuth
  • Water hammer analysis with history-matching at multiple rate drops and at pumping stage conclusion to correlate responses to fracture geometry
  • Fracture modeling with a planar 3D finite difference model and a diagnostic fracture injection test to provide fracture, closure, and pore pressure gradients

Findings were validated with a production interference test, rate transient analysis, oil-soluble tracers, and fracture fluid identifiers.

Overall, integration of the outlined diagnostic tools led to an improved understanding of hydraulic, propped, and conductive fracture geometries and a corresponding improvement in optimal well placing. Since this data was identified during early field development, the client could realize significant cost savings as a result of the well spacing and treatment strategy recommendations provided.

Figure 1: Impact of diverter drop size on fluid distribution along the lateral.
Figure 2: Varying diverter and fluid comparison.
Figure 3: Conductive geometries for range of proppant placed relative to design.
Figure 4: Summary of geometries.