Summary Time‐lapse seismology is important for monitoring subsurface pressure changes and fluid movements in producing hydrocarbon reservoirs. We analyse two 4‐D, 3C onshore surveys from Vacuum Field, New Mexico, USA, where the reservoir of interest is a fractured dolomite. In Phase VI, a time‐lapse survey was acquired before and after a pilot tertiary‐recovery programme of overpressured CO2 injection, which altered the fluid composition and the pore‐fluid pressure. Phase VII was a similar time‐lapse survey in the same location but with a different lower‐pressure injection regime. Applying a processing sequence to the Phase VI data preserving normal‐incidence shear‐wave anisotropy (time‐delays and polarization) and maximizing repeatability, interval‐time analysis of the reservoir interval shows a significant 10 per cent change in shear‐wave velocity anisotropy and 3 per cent decrease in the P‐wave interval velocities. A 1‐D model incorporating both saturation and pressure changes is matched to the data. The saturation changes have little effect on the seismic velocities. There are two main causes of the time‐lapse changes. Any change in pore‐fluid pressures modifies crack aspect ratios. Additionally, when there are overpressures, as there are in Phase VI, there is a 90° change in maximum impedance directions, and the leading faster split shear wave, instead of being parallel to the crack face as it is for low pore‐fluid pressures, becomes orthogonal to the crack face. The anisotropic poro‐elasticity (APE) model of the evolution of microcracked rock, calculates the evolution of cracked rock to changing conditions. APE modelling shows that at high overburden pressures only nearly vertical cracks, to which normal incidence P waves are less sensitive than S waves, remain open as the pore‐fluid pressure increases. APE modelling matches the observed time‐lapse effects almost exactly demonstrating that shear‐wave anisotropy is a highly sensitive diagnostic of pore‐fluid pressure changes in fractured reservoirs. In this comparatively limited analysis, APE modelling of fluid‐injection at known pressure correctly predicted the changes in seismic response, particularly the shear‐wave splitting, induced by the high‐pressure CO2 injection. In the Phase VII survey, APE modelling also successfully predicted the response to the lower‐pressure injection using the same Phase VI model of the cracked reservoir. The underlying reason for this remarkable predictability of fluid‐saturated reservoir rocks is the critical nature and high crack density of the fluid‐saturated cracks and microcracks in the reservoir rock, which makes cracked reservoirs critical systems.

The time delay changes of stacked time-lapse shear-wave data show a significant 10% change in anisotropy before and after a CO 2 injection process in a fractured dolomite reservoir in Vacuum Field, New Mexico. The time-lapse Pwave data do not show comparable variations in interval travel times. A combined model based on the anisotropic poro-elasticity theory, APE, (Zatsepin and Crampin, 1997) and on Kuster-Tokszos modelling matches the stacked data. Both the saturation change and the measured pore-fluid pressure increase of 1000 psi are considered. The model explains these observations as a pressure effect with the dynamic opening and closing of near-vertical low aspect ratio pores to which shear-wave splitting is more sensitive than P-wave velocities.

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Phase reversals are commonly observed during exploration seismic amplitude-versus-offset analysis, and usually modelled with the Zoeppritz equations. In practice, when multiple fluids are present we often deal with reflections from interfaces having a contrast in both elastic and anelastic properties. In this paper, we present a new phenomenological model for phase reversals in cases in which velocity dispersion and attenuation are present. We demonstrate strong qualitative differences in behaviour between the elastic and anelastic cases, influencing both the amplitude and phase of the reflection coefficient. Analysis of seismic data showing a phase reversal from a gas reservoir in the Vienna basin shows a striking agreement with the modelling. We conclude that the influence of fluid-induced dispersion on reflection data is a significant and measurable phenomenon in cases of practical interest, that recognition of the phenomena may be used as a novel fluid indicator and that frequencydependent rock physics analysis may be an important tool for both industrial geophysics and seismic monitoring of CO 2 storage.

Traditionally, reservoir fracture models are matched to only primary fracture data at well locations, and thus suffer from increasing uncertainty away from wells. In this work the discrete fracture network (DFN) approach is used to show how sub-seismic fracture realizations can also be constrained to seismic data. This methodology provides a route by which the uncertainty in the distribution of reservoir permeability and storage can be significantly reduced, and helps make forward predictions from the simulator more accurate. It also provides a natural way of extracting value from seismic anisotropy measurements and using them to quantitatively control the reservoir model for field development and management.