Oil production began in 1979 in the eastern end of the pool and in the years following, new wells were brought on totalling 11 Whitecap producing wells by 1984. TORC drilled its first well in 1984 in the west, which had a very high initial water cut due to water influx from an aquifer. Since the aquifer influx caused high water cuts, TORC began swapping the producers into injectors in 1987 and so began the waterflood.

The water injection only seemed to support the west side of the reservoir, as the east drops below bubble point pressure soon after injection begins. In response to the east dropping under bubble point, Whitecap swapped three lower producing wells to injectors and began a waterflood in the east in 1989. Following this water injection in the east, the reservoir pressure came back up and the GOR decreased as expected. From 1989 to 1994, both the east and west sides had established a waterflood which was successful in producing at a relatively stable rate until the end of 1994, when production started to decline due to water breakthrough.

Following breakthrough, high water cut wells were converted to injectors and an infill program and multiple well completions were executed in 1996. In 1997 the west side of the reservoir began to decrease in pressure and fall under bubble point as evident in the GOR spike, so injection rates were increased. After these actions, the oil production increased, and the water cut dropped temporarily. However, production began to continually decline, and the water cut reached nearly 80% by 2000. In 2008 there was a notable drop in water injection rates which was followed by an increase in GOR, and a sharper decline in production. By 2012 injection picked back up, but this seems to have a poor effect as production rate continued to decline and water cut increased to nearly 95%. After the water injection was increased again in 2012, the injection rate was slowly decreased as production continued to decline, GOR remained relatively constant, and wells were taken off as they reached abandonment rates.

Currently, the reservoir is producing 8.3m³/d at a 94.5% water cut. Cumulatively, this pool has produced 1.36E6m³ of oil, 1.76E6m³ of water, and 149.3E6m³ of gas, with 3.90E6m³ of water injected.

The key plot used in the Waterflood Surveillance analysis was Recovery Factor vs Hydrocarbon Pore Volume Injected, which was created for each pattern. This plot shows the sweep efficiency comparison between individual patterns, overall reservoir performance, and the hypothetical maximum Buckley-Leverett estimate.

A reservoir simulation was built to assist in providing insight into how to proceed with the pool development. CMG Reservoir Simulation Software was used to model the reservoir using a Black Oil Model in IMEX as this reservoir follows the conventional black oil performance and is the most appropriate choice to model a waterflood. The reservoir was initialized using various maps to capture the structure and petrophysics, as well as raw data inputs such as PVT and Relative Permeability as obtained from Whitecap. The well trajectories, perforations, and historical production/injection data were also inputted. The image shown above highlights the tilted nature of the reservoir, with the lowest end in the west at 1530m up to the shallowest in the east at 1420m. The following image indicates the porosity distribution within the pool, showcasing the higher porosity zone in the west.

In order to adequately capture the structure of the reservoir and shale layer, three distinct maps were used, namely the top pay sand, a layer of shale, and the lower pay sand. These maps were attributed to different grid layers in order to effectively model the flow dynamics that the shale layer presents. A side view snapshot shown below shows the shale layer, which is assigned to null blocks and is discontinuous throughout the pool.

With the simulation initialized, the simulation inputs were edited such that the historical data matched the simulation outputs. A good match between historical and simulation data is of high importance to ensure the model is accurate before utilizing it for development strategy investigation and forecasting. History matching is a highly iterative process and the best results thus far are shown here. Where the oil rates are not currently matching perfectly, specifically from 1992-1998, is most likely due to a lack of injection support in the model. Methods to better match injection rates are described in the following.

The high historical water rates in 1988-1992 are suspected to be due to the aquifer influx causing high water cuts occurring in the western edge of the pool at that time. Altering the aquifer parameters, such as decreasing the size and decreasing the permeability should slow down the water influx and shift the high water rates closer to the historical data.

The GOR and injection rates are parameters that require further investigation to obtain a better match. As mentioned previously, the injection rates are lower than the historical values which is perhaps causing the reduced oil production rates. It is suspected that the injection wells were in fact fractured due to high injection rates and pressures during early pool development, which is not currently being modelled within the simulation. Adding these fractures near the injectors is expected to improve the ability for the injection rates to meet the historical values by providing less resistance to flow with extra fractures in place.

The simulation history match will be investigated further, but nonetheless, the results provide further insight into the remaining pockets of oil that could be targeted. The remaining oil as predicted by the simulation is in a very similar location as what was predicted by the analytical Waterflood Surveillance. Since both the manual investigation and the simulation results tell the same story, the development strategies could be better justified to target the northern, eastern, and southern edges of the pool.

Based on the base case forecast for our pool, the NPV is calculated as $1.10 million at a 10% discount rate with an end of life of 2039. At this economic limit, the ultimate recovery is about 1.4 million m3 of oil, which gives an Ultimate Recovery Factor (URF) of 32%.

The following table details the Capital Investment (CAPEX), Net Present Value (NPV), Economic Limit, and Incremental Recovery above Base Case for each development strategy. The perforation of 06-04 and the drilling of the new horizontal well in Section 4 are the most profitable options, which is as expected due to the large pocket of oil in the eastern edge of the pool. For each of these cases, the most economically favourable method is to increase the injection rates along with reperforating or drilling the well. However, the most profitable option appears to be the perforation of well 06-04-049 with increased injection from turning on existing injectors in Section 5. This method proves to be perhaps more profitable than the drilling of the new horizontal well as it has a drastically lower capital investment.

Following the forecasts and economic analysis for each development strategy investigated thus far, the best choice would be to reperforate the lower zone of well 06-04-049 in the east and turn on both 06 and 10-05-049 injectors. Reporforating 06-04 provides access to the pocket of oil in the east without having to drill a new expensive well which saves time, money, and resources. Further investigation will be done to confirm the feasibility of this strategy as the history matching process continues to improve.