ABSTRACT

We present a new method to determine the total dissolved solids (TDS) concentration and the stable isotope composition of drill-core-derived Porewater in oil sands reservoirs of northeastern Alberta, Canada. The technique described here uses two end-member mixing relationships between the stable isotope compositions of drilling fluids and formation waters from mechanically extracted porewater samples to calculate the formation water TDS, δ2H, and δ18O values. Analysis of water samples extracted directly from McMurray Formation drill core provides an inexpensive and robust advance in the ability to characterize the properties of reservoir pore waters that can be widely deployed because of the ubiquity of drill-core sampling. Porewater data from three oil sands wells from different locations within the Athabasca region are presented in this study. Water derived from these wells had TDS values of 860 to 45,000 mg/L, δ2H values of −172 to −149‰, and δ18O values of −22.4 to −19.3‰. These values are consistent with regional trends in formation water salinity and stable isotope compositions, and illustrate the wide range of TDS values that can be found in McMurray Formation waters. The ability to characterize aqueous fluids within bitumen-saturated reservoirs is a new development that enables measurement of aqueous fluid properties that is not easily obtained by other sampling means. This methodology provides a tool to understand the origin and movement of reservoir water related to natural groundwater flow, or to anthropogenic influence by steam injection. Novel in situ extraction technologies that use electromagnetic heating systems may also benefit from detailed characterization of aqueous reservoir fluids to accurately determine the properties of the reservoir porewater.

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