Dilation, or increased pore volume caused by multiple shear parting tangentially off a created vertical tensile fracture, is estimated using fall-off data from a minifrac test performed on a McMurray formation oil sands well at a depth of 300 m. For an assumed fracture height of 16 m, permeability enhancement in the dilated zone is estimated at 420 md for the open shear fractures and 5 md for the slightly plastic closed shear fractures. This compares with an original reservoir permeability of 0.91 md. Since the fall-off data showed immediate pseudo-radial flaw, and the permeability ratio was very high, the reservoir could be thought of as a composite system with a dilated, high permeability zone around the wellbore surrounded by an infinite zone of low permeability.

The distance to the boundary between the two zones was calculated at 7.6m using the average of three different well test techniques. Dilation, or pore volume increase, was estimated at about 0.007 to 0.014 depending upon whether the assumed fracture height was 16 m or 8 m, respectively. A history match of the injection and fall-off data was then conducted using numerical and analytical fracture modelling.

Field generated input data was used, and the resulting permeability enhancements, failure zone size, and rapid pressure fall-off were matched within reasonable limits.


The Athabasca oil sands, one of the 1argest bitumen deposits in the world, does not yel have any commercialized in situ recovery projects. Many pilots have been opera1ed since the early sixties but with limited success as the high oil viscosity (to 2 kPa s al reservoir conditions), shallow depth of burial (0–500 m) and high oil saturation (80–90%) prevent economic rates of steam from entering the formation through a short perforation interval without fracturing.

The PCEJ Hangingstone project, under operation since 1985, has been concentrating on improving recovery by controlling some of the mechanisms of fracturing during cyclic steam injection. Improvements in recovery were achieved over the sequence of the three single well pilots1, sufficient to allow the construction and operation of a nearby thirteen-well pilot.

History matching of the bitumen recovery required significant understanding of the formation processes occurring during high rate steam injection and subsequent fluid production. Proper data on fracture orientation length, azimuth, and strike were required, along with geomechanical stress values (including dilation) to consistently match cycle-to-performance2. Dilation was shown to occur during steam injection3, 4 as photographed in post-stearn field cores and imaged by open-hole logging. The core factures were more vertical than horizontal, consistent with laboratory fractures of the same homogeneous material if the core was turned sideways and loading was now from the side instead of the top, i.e. from a nearby vertical tensile fracture.

Although it is known that continuous steam injection can generate shear fractures and dilation, it was only assumed but not quantified that significant dilation can occur when a small volume of cold water is injected. In both cases, dilation occurs when local pore pressures increase, causing the effective stress stale to reach and exceed the failure envelope.

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