An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to make money (if possible), demonstrate oil recovery, verify the properties of the EOR agent in situ, and provide the information needed for scale-up to an economic process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in situ in the midst of geological uncertainty. We propose the “modified Egg Model” case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water-oil reservoir. The polymer is designed to have a viscosity of 20 cp in situ. We start with 100 realizations of this 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. For a population of reservoirs representing reduced geological uncertainty after five years of waterflooding, we select three groups of 10 cases out of 100 with similar water breakthrough dates at the four production wells. We then simulate five years of polymer injection. We allow that the polymer process might fail in situ and viscosity could be half that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of the geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity to the scatter caused by the geological uncertainty at the 95% confidence level. Among the signals considered, polymer breakthrough time, minimum oil cut and rate of rise in injection pressure with polymer injection give the most reliable indications of whether a polymer viscosity was maintained in situ. Unfortunately, given the likelihood of an unknown extent of fracturing of the injection well, injection pressure may be an unreliable indicator of in situ polymer viscosity.

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