Figure 2.26: Comparison of P-wave and converted PS- wave (right) images through the same geological section. The BSR is clearly visible on the P-wave data (left) but is not observable on the PS-wave data. Note that the PP and PS data are plotted in opposite direction, to ease the comparison. (Courtesy PGS).


PP


which principally changes in response to variations in lithology, porosity, pore fluid and stress state, can be estimated by pre- stack P-wave AVO analysis. However, the record of hydrocarbon detection by AVO analysis is mixed, and AVO analysis is used nowadays with great care. Te VP/VS ratio can also be estimated from post-stack P- and PS-wave reflections. A key question is whether VP/VS can be found with higher accuracy and reliability using 4C data. Can it be quantitatively estimated from pressure and shear records? Teory predicts that this can be done. However, we need several case studies emphasising the quantitative aspects of measuring elastic subsurface parameters before this question can be fully answered.


Overpressure zones: Except near the surface (typically the first kilometre), the values of VP, VS and therefore VP/VS are quite insensitive to changes in differential pressure. (Differential pressure is the difference between overburden pressure and pore fluid pressure.) However, when an overpressured zone with anomalously high pore fluid pressure is encountered in the deeper section, anomalies in the VP/VS ratio can be measured. Overpressure implies a decrease in differential pressure, which tends to decrease both P- and S-wave velocities but increases the VP/VS ratio. Hence, from VP/VS analysis from pressure and from shear-wave sections, overpressure zones may be identified. Duffaut and Landrø (2007) found that the VP/VS ratio


increased from 1.9 to 7 using time-lapse seismic data acquired at the Gullfaks field. Due to water injection, the pore pressure in the reservoir had increased by approximately 5–7 MPa, and the increase in VP/VS ratio is interpreted as being caused by this pore pressure increase. For the Statford field, where the sand is more consolidated, the corresponding change in VP/VS ratio was estimated to be 1.9 to 2.0, significantly less. Tis difference is not only attributed to the difference in rock consolidation, but also to the fact that for the Gullfaks case the pore pressure in 1996 was close to the fracking pressure. Tis means that the contact between the rock grains weakens, and the shear wave velocity drops essentially to zero, while the P-wave velocity approaches the fluid velocity (1,500 m/s), and hence the VP/VS ratio can be abnormally high. If we assume


PS


that the P-wave velocity is close to the water velocity then it means that the shear velocity is close to 215 m/s (assuming Vp/Vs=7), which is extremely low. It should be noted that the uncertainty in this estimate is significant.


Anisotropy and fractured reservoirs: Any presence of oriented fractures and/or directional horizontal stress fields can create azimuthal anisotropy in the subsurface. Predicting directions of oriented fractures and fracture density and possibly obtaining quantitative information about stress state underground (stress orientation and relative magnitude) may be critical for understanding how fluids and gases flow through a reservoir, and for determining drilling locations and optimising reservoir productivity. Two effective medium models which describe azimuthal


anisotropy are transverse isotropy with a horizontal axis of symmetry (HTI), and orthorhombic anisotropy. HTI can be caused by a system of parallel penny-shaped vertical cracks embedded in an isotropic matrix. Orthorhombic anisotropy, which is believed to be a more realistic model of fractured reservoirs, may result from a combination of thin horizontal layering and vertically aligned cracks. From P-wave data, azimuthal anisotropy is often subtle


and quite difficult to recover. Shear waves, however, are more sensitive to azimuthal anisotropy. Terefore, by estimating azimuthal anisotropy from an analysis of mode-converted shear waves, fracture parameters and/or unequal stress fields can be predicted. Two methods have been proposed to extract this information from marine multi-component data: • the study of shear-wave splitting for near-vertical propagation;


• the study of reflection amplitude variations as a function of offsets and azimuths. Both methods have the potential to determine the fracture


orientation and density of the vertical fractures. Te second method has attracted particular interest, as it is also sensitive to the fluid content of the fracture system. From amplitude analysis it may be possible to find whether the fracture network is fluid-filled or gas-filled.


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