NCG is increasingly being co-injected with steam in heavy oil production systems to reduce heat loss and greenhouse gas emissions, as well as to maintain reservoir pressure. Given increased use of NCG co-injection, the validity of conventional subcool models must be revisited since they assume that the steam chamber is comprised of water alone. The current study makes modifications to the pure-steam hydrostatic subcool model, as well as the Yuan & Nugent (2013) subcool model to account for the presence of NCG in the steam chamber. Using typical values from the Athabasca oilfield, the study then compares the liquid-height predictions made by the original and modified models and proposes rules-of-thumb that correct for the presence of NCG. In general, increasing NCG in the steam chamber results in a reduction in subcool relative to pure steam. According to modified hydrostatic model, to achieve a liquid-pool height equal to that of pure steam injection, the subcool must be increased by 0.60K per 1% increase in the vapor-phase molar fraction. In contrast, over a wide range of production rates and drawdowns, the modified Yuan & Nugent (2013) model predicts that to achieve a liquid-pool height equal to that of the pure steam case, the subcool must be increased by 0.66K per 1% increase in the vapor-phase molar fraction. Despite the rule-of-thumbs being qualitatively in line with expectations, they suffer from the inability to accurately calculate subcool from field data. The final section of the paper reviews limitations of subcool as a well performance metric and proposes an alternative method of assessment that relies on data that are more readily available to operators.

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