Detecting Reservoir Compartmentalization from the Mixing Time-Scales of 87Sr/86Sr Isotope Ratio Variations in Oilfield Formation Waters

Vertical and lateral changes in the 87Sr/86Sr isotope ratio in formation water are sometimes used during appraisal as indications of reservoir compartmentalization. These variations will tend to homogenize slowly over time by diffusion and flow. They will only be robust indications of compartmentalization if their mixing time in the absence of a flow barrier is less than the time since the process causing those variations stopped.

Improved analytical solutions that estimate mixing times of 87Sr/86Sr isotope ratio variations in formation water are presented. Whereas previous solutions have only modelled the mixing of 87Sr/86Sr isotopic ratios in a homogeneous reservoir, the new solutions evaluate the diffusive mixing of formation waters between two formations with different properties (adsorption, porosity, permeability and connate water saturation). These formations may be separated by a low permeability baffle, a discontinuous shale or be in good communication. The increase in diffusion time resulting from prevailing high tortuosities of irreducible water films in hydrocarbon columns are also captured in the analytical solutions.

The analytical solution predictions are shown to compare well with results from an existing numerical simulator developed to predict contaminant transport in groundwater flows. The time for diffusive mixing over a typical reservoir thickness (i.e. < 100m) is typically ~ 10 m.y. As expected this time reduces when formation porosity and/or water saturation is higher. For heterogeneous formations separated by a discontinuous “impermeable” shale, formation water mixes around the barrier faster than through it due to the low porosity, high tortuosity and high adsorptivity characteristics of the shale barrier despite being fully saturated with pore water. The equations can be used to estimate a critical shale length to thickness ratio where formation water diffuses around the shale at the same rate as through the shale barrier.

The equations can also be used to constrain the barrier or baffle properties (e.g. the shale length) based on the time at which the initial perturbation to the fluid properties took place. These improved analytic solutions are thus a significant addition to the suite of published expressions for evaluating reservoir compartmentalization during appraisal using reservoir fluid mixing.

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California