A combined laboratory/field investigation of the Cardium Formation was performed in an attempt to define specific rock properties for design purposes, and to compare the data with well-log predictions. The study included an extensive suite of well logs, physical rock property testing under simulated downhole conditions, geological descriptions of cored samples, and porosity and permeability measurements.

The Cardium sand zone was investigated in detai1 and revealed that the mechanical property logs generally gave different elastic constants, the difference with the laboratory data becoming more severe as the clay content increased. The paper discusses the reasons for such variations. Permeability studies were undertaken to determine the influence of the confining pressure.

Stimulation treatment design can be enhanced by incorporating 1aboratory predictions of physical rock properties and in-situ stress conditions (Differential Strain Curve Analysis) with available well-treatment and production records.


Hydraulic fractures in deep, tight reservoirs can only be effectively designed if reservoir conditions are known with sufficient confidence. An educated appreciation of a reservoirs characteristics depends on a knowledge of mechanical formation properties, geological features and in-situ stress conditions. As some of these parameters must be inferred, post-treatment analysis of preliminary treatments provides an invaluable source of information for refining predictions of the in-situ environment and improving treatment procedures.

A well in the Cardium Formation provided an ideal candidate for a comprehensive determination of appropriate reservoir properties. The well is located approximately 70 km from Grande Prairie, Alberta. Mechanical properties required for prediction of fracture geometry were determined from laboratory core testing at simulated in-situ conditions. All laboratory predictions were compared with features indicated by an extensive suite of well logs run in this well.

Pressure-time records during treatments in adjacent wells were evaluated in order to infer characteristic growth Features of fractures in this particular locality. These records were interpreted in light of buildup tests performed on the stimulated wells. The entire package of laboratory testing and treatment and production records was considered in conjunction with pseudo-three-dimensional simulations of fracture geometry in order to optimize future treatments.


The Cardium Formation, in the Central foothills, contains littoral marine beds of thick-bedded, fine- to medium-grained cherty sandstone. As well. there are marine shales and lagoonal and marsh deposits of carbonaceous shales, si1tstones, argillaceous sands tone and some coal. The Cardium grades 1aterally eastward into shaley siltstones and shales. A generalized table of formations's shown in Figure 1. At the locality under investigation. a typical stratigraphic column is shown in Figure 2. Formation units can be generally categorized as follows.


    A dirty, argillaceous sandstone. Very fine to fine grained with some glauconitic components (locally included in or at the bottom of Puskawaskau).


    Often a conglomerate, sandstone and siltstone "mixture" The conglomerate may be cherty and the sandstone is usually very fine grained to silty.


    Predominant1y a siltstone. Shale stringers, narrow conglomerate and narrow coal layers may be locally present.

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