A waterflood prediction study has been developed for the Dodsland Viking field in Saskatchewan, Canada. This study demonstrates the importance of the geological description used to account for fieldwide variations in PVT properties. The methodology identifies the significance of local wellbore effects (hydraulic fracture stimulations). The increased power of SimBest II which is fully implicit and uses an improved matrix solver, 'ESPIDO", enables modelling of this problem where older technology fails (Beta 11). Finally, the results are compared against actual offset production performance and models which do not account for local wellbore effects.


The Dodsland-Hoosier Viking field was discovered in 1953. The location of the field in southwestern Saskatchewan is shown in Figure 1. The field consists of a complex series of oil and gas pools, as depicted in Figure 2. Development of the field occurred rapidly during the late 1950's, followed by unitization and subsequent waterfloods. A resurgence of development occurred during the early 1980's in response to government incentives.

The Kiyiu Lake Voluntary Unit No.1 was developed in 1983 and 1984. A waterflood was planned, and government approval obtained during 1985. However, the dramatic dip in oil prices in early 1986 delayed implementation of the project. A detailed re-evaluation was commissioned by the client, J.C. International Petroleum Ltd. to more closely evaluate waterflood economics under the more severe economic conditions of 1988.


The geology of the field was comprehensively documented in a paper by W.E. Evans1. Two main factors control the occurrence of oil and gas in this field:

  • the separate linear sandstone bodies, which overlap.

  • the structure, which is controlled by underlying solution collapse and post depositional compaction.

Figure 3 shows the axes of the overlapping members and Figure 4 displays the stratigraphic relationship of the sandstone bodies. Cross sections through the center of the members (Figure 5) demonstrate how both of the above factors resulted in a system of oil and gas accumulations shown earlier (Figure 2).

The lithology in the field has been studied in detail by Tooth et al 2. The vast majority of reservoir rock consists of finely interlaminated sands, siltstones, and shales. These laminations are typically 1/2" thick. Core analysis near the study area yields porosities from 16 to 24% and permeabilities ranging from 0.1 mD to 40 mD. The average porosity and permeability are 20.7% and 6.3 mD, respectively. A basal chart conglomerate is also found in some members, but is not thought to be present in significant amounts within the study area.

Overall, the Viking formation in this field is of poor reservoir quality.


Production from such a low permeability reservoir requires hydraulic fracture stimulation, and results in a characteristic production profile. Economic evaluations have been conducted for a number of companies with substantial production from this field. Reserves are determined using type curves, an example of which is shown in Figure 6. The production profile is determined by multiplying the initial production times the normalized rates in Figure 6. After two years an exponential decline is used.

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