In Situ Stress Prediction And Measurement By Hydraulic Fracturing, Wapiti, Alberta
Authors: McLellan Patrick 
Published: March 2010

A combined field and laboratory investigation of the Cardium Formation in the Wapiti Field near Grande Prairie was performed to determine rock mechanical properties and in situ stress magnitude and orientation. This information is needed for thedesign of effective hydraulic/fractures, to optimize future waterflood patterns and to understand production performance data. The vertical distribution of the minimum horizontal in situ stress was determined by conducting a series of small volume, low rate micro-fracturing tests through perforations at depths of between 1231 m and 1260 m. An abnormally high minimum horizontal stress gradient, or fracture gradient, dose to and exceeding the calculated vertical overburden stress gradient of 24.3 kPa/m, is indicated by several pressure decay interpretation techniques. The inferred minimum horizontal in situ stress in the Cardium sand is between J and 4 MPa greater than in the bounding shale units. Other field production performance and geological evidence also suggest the presence of high horizontal stresses in the region. Regardless of whether laboratory static or sonic log-derived dynamic elastic properties are used, simple predictions of the minimum horizontal in situ stress may be grossly in error in this part of Alberta unless residual and active tectonic stresses are accounted for.

The orientations of the major and minor horizontal in situ stresses have been interpreted from wellbore breakouts, differential strain curve analysis, and anelastic strain recovery techniques. The actual induced hydraulic fracture orientation has been determined by monitoring microseismic events downhole during two mini-frac tests. The average predicted fracture orientation of between N35 °E and N43 °E compares favourably with the average measured N35 °E azimuth from these two wells.

Introduction

The design of effective hydraulic fractures in thin low permeability reservoirs often requires a detailed knowledge of rock mechanical properties, in situ stresses and other geological information. In particular, the minimum horizontal in situ stress (σHmin), which is often assumed to be one of the principal stresses, usually dominates the geometry and azimuth of hydraulic fractures, (e.g. see Perkins and Kern(l), Simonsen et al.(2) or Warpinski et al(3)). In the case of relatively thin interbedded sandstone and shale units the role that σHmin plays in containing vertical fractures has been recognized for some time. However, it is often believed that shale intervals will almost invariably have higher stresses than an adjacent sandstone reservoir unit. M shown by Kry and Gronseth(4) for the Deep Basin in Alberta and more recently by Evans and Engelder(5) in western New York, this assumption is not always valid. With the increased emphasis on methods to predict in situ stress from petrophysical data, it is important to recognize the limitations of these procedures and the need for careful calibration with actual in situ stress measurements such as those obtained from low rate micro-fracturing. This is particularly important for reservoirs in the Western Canadian Basin, which may be affected by residual and/or active tectonic stresses.