A Dodsland - Hoosier Viking Waterflood Prediction
Authors: Carlson M.R. , Andrews R.J. 
Published: March 2010

Abstract
A waterflood prediction study has been developed for the Dodsland Viking field in Saskatchewan. 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 use of a modem simulator, which is fully implicit and uses improved Orthomin-type matrix solvers enables modelling of this problem where older technology fails. Finally, the results are compared against actual offset production performance and models which do not account for local wellbore effects.

Introduction
The Dodsland-Hoosier Viking field was discovered in 1953. Its location 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 occurred rapidly during the late 1950s followed by unitization and subsequent waterfloods. A resurgence of development occured during the early 1980s in response to government incentives.
The Kiyiu Lake Voluntary Unit No. I 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 J.C. International Petroleum Ltd. to more closely evaluate waterflood economics under the more severe economic conditions of 1988.

Geology
The geology of the field was comprehensively documented in a paper by W.E. Evans(1). Two main factors control the occurrence of oil and gas:the separate linear sandstone bodies, which overlap; and,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 centre of the members (Fig. 5) demonstrate how both of the above factors resulted in a system of oil and gas accumulations shown earlier in Figure 2.
The lithology of the field has been studied in detail by Tooth et al(2). The vast majority of the reservoir rock consists of finely interlaminated sands, siltstone, and shales. These laminations are typically 13 mm (0.5 in.) thick. Core analysis, from wells near the study area, had porosities ranging from 16% to 24% and permeabilities ranging from 0.1 mD to 40.0 mD. The average porosity and permeability was 20.7% and 6.3 mD, respectively. A basal chert 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 quality.

Production Characteristics
Production from such a low permeability reservoir required hydraulic fracture stimulation. These treatments, coupled with the low permeability of the reservoir, 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. A production forecast for an individual well is determined by multiplying the initial production rate by the normalized rates. After two years an exponential decline is used.