Stimulation of Amerada's Cardium formation in the Western Foothills has produced mixed results. Stimulation techniques have been performed as early as the 1960's. Before 1990, hydraulic fracturing treatments were the primary stimulation technique with treatment sizes up to 20 tonnes and maximum proppant concentrations of only 600 kg/m3. Due to the inconsistent results, an acidizing program was incorporated in 1990. This program produced marginal results due to an increase in formation scaling tendencies. An intense re-fracturing program was initiated in 1992 with intentions of increasing success through careful candidate selection and job-design.

The re-fracturing program was initialized with mini-frac techniques to enhance geological and reservoir data. A fluid capable of transporting high concentrations of proppants through the highly tortuous near wellbore region was required. With the evolution of the hybrid fracturing fluid total fluid volumes have been reduced, therefore minimizing proppant convection and increasing fracture conductivity, and reducing costs.

The new fluid has allowed the proppant concentrations to be increased 3.3 fold, and proppant tonnage by 100 % while decreasing the frac fluid to proppant ratio from 4.35 m3/tonne average to 1.35 m3/tonne. The three month average oil production rate has increased by 2.5 times.


In 1992 Amerada began a re-fracture program in their foothills Cardium wells. Re-fracture programs had been performed in the area before with mixed success. The current program has achieved economic success through better candidate selection and treatment design.

Candidate selection was improved by instituting strict quality control on pressure transient data. Job design was to be improved by lowering the amount of fluid used and increasing the maximum proppant concentration, thereby increasing the overall proppant pack conductivity. This goal proved to be more elusive than that of improved candidate selection; initial attempts to place higher proppant concentrations resulted in early near-wellbore screen outs. At first, conventional fracture theory prevailed. The problem was believed to be due to excessive fluid leak off. Higher pump rates, larger fluid volumes, and leak off control agents were employed to no avail. Finally, inadequate width eneration was determined to be the problem. Unfortunately, it was also determined that standard fracturing fluids do not retain enough viscosity under high shear to generate the required width and proppant transport ability through the tortuous region. This realization led to the development of the Super Polyemulsion. With standard fracturing fluids it was difficult to place sand concentrations higher than 700 kg/m3, now with the Super Poly, concentrations of 2000 kg/m3 are routinely placed.

2.0 Geological Description

The main reservoir units at the Western Foothills Cardium Pool #1 & Pool #2 are the Cardium Formation Sandstones and Conglomerates. Each facies in both pools was deposited in a NW-SE trending marine shoreface environment.

The sandstone facies range from Muddy Siltstones (non-reservoir), to well sorted fine to medium grained sandstone which are economically the most important in Pool #1 & #2. The sandstone net pay ranges in thickness from 0.3 - 10.0 m (1 - 35 ft) averaging 3.7 m (12 ft). Porosity ranges from 10 - 20 % averaging 14.5 %. Air permeability ranges from 01 - 20 md averaging 5 md (air permeability).

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