Time-lapse monitoring is useful for imaging changes in geophysical attributes due to fluid flow. In trying to use time-lapse data for reservoir characterization, difficulties often arise when relating changes in geophysical observations to changes in fluid saturation and pressure. As an alternative approach for reservoir monitoring and characterization, we introduce the idea of an onset time, the time at which a measured quantity, such as a seismic traveltime or a reflection amplitude, begins to deviate from its background value. We illustrate the idea and demonstrate its utility through the consideration of traveltimes recorded by the continuous active source seismic monitoring system at the Frio pilot site near Houston, Texas. The system, which transmits an elastic wave every 15 min, is used to monitor the movement of carbon dioxide injected into a permeable sand formation. From these data we can estimate the onset of changes in seismic traveltimes to six receivers in an adjacent borehole. Numerical simulation and synthetic tests indicate that the onset times are not very sensitive to the method used to compute the effective fluid bulk modulus and, correspondingly, the seismic compressional velocity. Rather, the onset times are strongly influenced by saturation changes within the formation, specifically by the break-through time of the injected fluid phase. By means of an iterative inversion algorithm we use the onset times to estimate permeability variations between the boreholes at the Frio pilot site. © The Authors 2014. Published by Oxford University Press on behalf of The Royal Astronomical Society.

The In Salah CO2 storage project in Algeria has injected over 3 million tonnes of carbon dioxide into a water filled tight sand formation. Interferometric Synthetic Aperture Radar (InSAR) range change data revealed a double lobbed pattern of deformation that has been modeled as the opening of a sub-vertical fracture, or damage, zone. The location and geometry of the linear feature were subsequently verified using a seismic reflection survey. The elastic properties of the fracture zone, including anisotropic Poisson ratio (ν), Young's (E) and shear (G) moduli, were estimated from coupled geomechanical and hydrological modeling of surface deformation and pressure variations in the injection well. The elastic moduli reflect the fracture properties after CO2 flow through the fracture zone. Thus, the seismic signature of the fracture zone could be used for monitoring the CO2 plume. Using the estimated fracture model, we built two and three dimensional models consisting of an anisotropic fracture zone embedded within an isotropic background. Finite-difference modeling of seismic shot gathers allows us to estimate the effects of scattering from the fracture zone, potentially further constraining the geomechanical model. From the seismic modeling results, we find diffracted waves, induced by the fracture zone, which behave similar to point source diffractions. This modeling is intended to guide a search for diffraction events in the 3D surface seismic field data. The modeling results indicate that using the moduli estimated from geomechanical modeling, fracture scattered events would be 100 times lower amplitude than the interface reflections, and thus would be hard to detect. While diffracted waves are observed in the field data, which may imply the need for revision of the fracture model, including shape and elastic moduli, we are not able to match the field observation with our modeled events. This work presents a frontier study on the integration of geomechanical and geophysical methods at the In Salah site as a means to test the estimate of the subsurface CO2 flooded fracture properties.