Ian Palmer is a partner of Higgs-Palmer Technologies, and is based in Albuquerque, New Mexico. He consults in shale gas, coalbed methane, well completions and production, hydraulic fracturing, sand prediction, compaction/ subsidence, and general geomechanics. He was a Geomechanics Specialist with BP in Houston. He was an SPE Distinguished Lecturer in 2001-02. He has taught to industry training courses in shale gas and in coalbed methane. He has been a principal of various industry consortia, and is currently concluding a contract from RPSEA “Characterizing Stimulation Domains, for Improved Well Completions in Gas Shales”. Ian has a Ph.D. from Adelaide University, Australia.

Stimulating shale oil & gas wells: defining the fracture network, with new implications for proppant

Abstract

Microseismic measurements provide qualitative information about where a fracture stimulation goes. However, there is also quantitative information, which has largely been neglected. We have developed a geomechanical model to predict the extent of shear failure during fracture stimulation of a well. By matching the model to the extent of the microseismic cloud of shear failure, we obtain an injection permeability and porosity which characterize the volume of the microseismic cloud.

A high injection permeability (≥100 md) is required to pressure the formation and achieve failure out as far as the microseismic events extend. Low injection porosity (< 0.1%) is required for the frac fluid to leak off that far (this is much less than formation porosity of 3-5% typically). These numbers are symptomatic of fracture-controlled flow during well stimulation. As a case history, the method and results for sequential stimulation of two sister horizontal wells in the Barnett shale are described. 

If we assume the microseismic cloud to be underlain by a quasi-uniform fracture network with a system permeability enhancement, the injection permeability and porosity can provide information on average fracture spacing and aperture width during injection (ie, fracture stimulation). These can be important for tailoring proppant size to access the fracture network in gas and oil plays in tight shales (eg, proppant mesh size that is too large cannot enter the fracture network). Further, for smaller proppant that can enter the network, the spreading of the proppant depends on the spacing and aperture width of the network fractures, as well as the diameter and density of the proppant. All these factors have been included in a conceptual model of proppant spreading away from a horizontal well. This model may help operators optimize proppant transport in shale gas and oil wells, to retain a larger SRV (stimulated reservoir volume), and greater permeability enhancement within the SRV.