A numerical hydraulic fracture simulator was used to evaluate and design stimulation treatments for the Medicine Hot sand in the Atlee area of Alberta.
The simulator was first used to analyze the previous treatment conducted on two wells which represented the range of expected reservoir quality. Fracture height, propped fracture length, and effective reservoir permeability were revealed through history matching the postfracture productivity.
The knowledge gained from the history matches was used as a basis for the design of a new treatment. This design study was conducted using the simulator and was formulated to provide a more efficiently propped fracture of optimum length.
Seven wells were fractured with the new treatment and two of these wells were subjected to post-fracture analysis. The results confirmed that a greater effective fracture length was created with the new treatment and showed fracture height to be a strong function of injection rate. In addition, it was discovered that drainage from offsetting wells is substantial in some areas of the pool.
The shallow Medicine Hat gas sands of Southeastern Alberta contain significant reserves. Hydraulic fracture stimulation is necessary to recover these reserves because of the low reservoir permeability thickness and pressure.
Fracture treatment design in the past has been mainly by a trial and error approach conducted in the field. The most popular design to evolve has been one using a refined Xanthan Gum Polymer in water to place up to 30 tonnes of 10/20 and 8/12 mesh sand. Typical injection rates are between 5.5 and 9.5 m3/min.
Analysis of past treatment success has been primarily based on a qualitative assessment of the post fracture productivity. Analytical transient analysis techniques have been used in some instances to define such parameters as effective fracture length and skin effect.
INTERCOMP has recently developed a numerical simulator which models the hydraulic fracture process and allows quantification of the results. The Simulator (HFS) is a two-dimensional, two-phase reservoir model which is mathematically coupled to a fracture or crack propagation model and a proppant transport model. The formulation has been described previously by Settari et al1,2. Briefly, because of the linking of the reservoir and fracture solutions, it is possible to rigorously simulate the effects of fluid loss into the reservoir and the flow of fracture fluid and hydrocarbons back into the fracture during the production sequence. The fracture conductivity is determined from the calculated distribution of the proppant in the crack at closure. rather than by analytical techniques.
North Canadian Oils Ltd. expressed an interest in using the simulator to evaluate their current stimulation program for Medicine Hat zone gas wells in the Atlee area. They had realized that some variation in productivity between wells was caused by differences in the reservoir quality. The contributing effect of the fracture treatments was unknown.
Two wells were chosen by North Canadian to represent the high and low permeability thickness areas of the pool. INTERCOMP's simulator was used to model the previous fracture treatments conducted on these wells.
