Seismic reservoir characterization and monitoring require the knowledge of seismic wave velocities and their dependencies on reservoir properties and production-induced changes. In heavy-oil saturated rocks at cold temperatures, due to the nonzero shear rigidity of the fluid, the saturated shear modulus is higher than the dry shear modulus and, consequently, the observed P- and S-wave velocities are higher than Gassmann’s predicted velocities. Appropriate modeling of the saturated shear modulus can greatly enhance the accuracy of quantitative interpretation of spatial fluid saturation and temperature distribution within a reservoir undergoing thermal production. Using a well-log data set of an Athabasca heavy-oil play and measured oil viscosities from core samples, we estimate fluid viscosity, shear modulus, and the American Petroleum Institute (API) gravity logs by training a neural network (NNT) with available well logs. We also estimate the dry shear modulus of heavy-oil saturated rocks using an NNT approach after modeling the pressure variations within the reservoir. Our empirical model uses the apparent shear modulus of the oil, its saturation, porosity, and dry shear modulus to estimate the saturated shear modulus of the rock. We calibrate the model to ultrasonic lab measurements. Available literature data support the validity of the model and show the improved performance compared to the Ciz and Shapiro model. The range of applicability of the model is defined mathematically, and the behavior of the model with respect to the input parameters is examined through sensitivity analyses.

Seismic monitoring of oil sands during hot or cold production requires a valid rock physics model. The effective elastic properties of heavy oil deposits depend on temperature variations, which consequently alter the P- and S-wave velocities in thermal recovery processes. The authors discuss the relationship between temperature, apparent shear modulus, frequency, and velocity dispersion. We use log data from wells drilled in heated and cold zones of a bitumen reservoir to calculate bulk and shear moduli along the wellbore. We apply various filters to control the unwanted effects of other variables, such as porosity and water saturation. We demonstrate that sonic velocities of steam-saturated sands at reservoir conditions can be lower than the compressional velocity of seismic waves in water. We use modulus-temperature crossplots to verify the existence of the liquidation temperature and apparent shear modulus of the heavy oil. In our study, we observe two rapid-decline events in bulk modulus at around 20°C and 200°C. The first event exhibits the ideas of the viscoelastic model of Maxwell. We attribute the second event to effective replacement of liquid phase with steam. For temperatures between 20°C and 200°C, we use a linear relationship to model bulk modulus decline with temperature. The calculated shear modulus shows a wide range of variations at cold temperatures due to a slight change in the bitumen's API gravity with depth. We attribute the weakening of the shear moduli at temperatures greater than 100°C to thermal expansion of the rock.

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