ABSTRACT
A multiple hydraulic fracture field test was conducted in the McMurray formation of the Athabasca oil sands in Alberta, at a depth of 235 mKB. Due to the low fluid injectivity into the formation, hydraulic fracturing preceding hot water and/or steam injection was considered a viable means of establishing interwell communication. In situ stress tests conducted at the wells indicated the minimum principal stress to be in the vertical direction. This meant horizontal fracturing was feasible at 235 mKB. Subsequently two fracture treatments were conducted, a mini-fracture test followed by the main propped fracture. The fracture monitoring methods used were as follows:
Tiltmeters
Temperature observation well
Radioactive proppant
Fracture extension pressures
Post fracture log evaluation wells
Tiltmeter and observation well data indicated horizontal fracturing during the mini-fracture test. The subsequent main fracture treatment showed similar results during the initial injection stage, however evidence of vertical fracturing was prevalent during the proppant injection stage. Numerical modelling conducted at a later date, using a finite element stress-strain model, indicated that in a near isotropic stress environment there existed a critical maximum formation strain, beyond which the minimum principal stress direction can change. As a result of the above work, the fracture design parameters for oil sands, such as injection rates and fracture fluid viscosities can be adjusted to minimize vertical fracturing at shallow depths, where initially horizontal fractures are favoured.
