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 the design of effective hydraulic fractures, to optimize future waterflood patterns and to understand production performance data. The vertical distribution of the minimum principal 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 horizontal stress gradient or fracture gradient, close 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 principal in situ stress in the Cardium sand is between 1.1 and 3.7 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 area. Regardless of whether 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 adequate account is taken of the tectonic component at the in situ stress.
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. Actual induced hydraulic fracture orientation has been determined by monitoring microseismic events downhole. The average predicted fracture orientation of between N35 °E and N43 °E compares favorably with the actual N35 °E azimuth measured in one vertical well.
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 which is often assumed to be one of the principal stresses, usually dominates the geometry and azimuth of hydraulic fractures, eg. see Perkins and Kern1, Smongen et al.2 or Warpinski et al3. In the ease 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 interval will almost invariably have higher stresses than an adjacent sandstone reservoir unit. As shown by Kry and Gronseth4 for the Deep Basin in Alberta this assumption is not always valid. With the increased emphasis on methods to predict m situ stress from petrophysical data. It is important to recognize the limitation of these procedures and the need for careful calibration with actual in situ stress measurements such as low rate micro-fracturing. This is particularly important for reservoirs in Western Canada which are likely to be affected by either active or residual tectonic stresses.
It is therefore the purpose of this paper to present a case history of a program to determine the magnitude and azimuth of σHmin by actual measurement and predictive methods, for the Wapiti reservoir located 50 km south-east of Grande' Prairie (Figure 1).