waves in isotropic and anisotropic media with respect to reservoir geophysical property changes. Conventional seismic surveys are designed based on seismic‐wave illumination of the entire subsurface imaging region, and require a large number of sources and receivers to produce high‐resolution images of the subsurface. By contrast, time‐lapse seismic monitoring is not designed to image the entire subsurface region, but only the target monitoring regions, such as the CO2 storage reservoir, caprock, and faults. Therefore, time‐lapse seismic monitoring needs only seismic information from such regions, rather than from the entire subsurface region. The optimal design of time‐lapse seismic surveys is based on elastic‐wave sensitivity analysis, that is, numerical modeling of elastic‐wave changes with respect to changes of geophysical properties within target monitoring regions. The method numerically solves the elastic‐wave sensitivity equations obtained by differentiating the elastic‐wave equations with respect to geophysical parameters, such as density, compressional‐ and shear‐wave velocities, and saturation parameters, in isotropic and anisotropic media. Receivers should be placed in surface regions for surface seismic surveys or borehole locations for vertical seismic profiling (VSP) surveys with significant values of elastic‐wave sensitivity energies. The number of receivers needed for cost‐effective time‐lapse seismic monitoring is only a fraction of a regular 3D seismic survey.
The 3D surface seismic monitoring has the advantage of monitoring a large subsurface area to track CO2 migration in the 3D space. However, seismic imaging/monitoring resolution decreases with the depth, particularly for CO2 storage at geologic formations at several kilometers in depth. Compared with surface seismic monitoring, VSP monitoring improves seismic imaging/monitoring resolution in the deep region when receivers are placed in the deep region of the subsurface. The image resolution of VSP monitoring is usually twice that of surface seismic monitoring. The limitation of VSP monitoring is that the lateral monitoring range is smaller than surface seismic monitoring.
VSP surveys use active seismic sources at various offset locations (offset VSP), or along various walkway lines from the monitoring well (walkaway VSP), or using a 2D surface source distribution (3D VSP). Offset VSP monitoring uses only a few offset source points, and has the lowest cost among the three different types of time‐lapse VSP survey. However, offset VSP can monitor only in the sparse azimuthal directions along a monitoring well to offset source directions. 3D VSP monitoring is the most expensive among the three VSP monitoring approaches, with the highest spatial coverage of the monitoring region. The walkaway VSP monitoring is the trade‐off between the offset VSP monitoring and 3D VSP monitoring.
In Chapter 8, on offset VSP monitoring, Zhang and Huang study the capability of offset VSP imaging for monitoring CO2 injection/migration, and present monitoring results at the Aneth CO2‐EOR (Enhanced Oil Recovery) field in Utah. The offset VSP monitoring uses a permanent geophone string with 60 levels and 96 channels cemented into a monitoring well. Because of uncertainties in the offset VSP source locations during repeat VSP surveys, they present a method to use travel times of the downgoing VSP waves and double‐difference tomography to invert for the “true” VSP source locations. This approach addresses the source repeatability issue in practical offset VSP monitoring. Zhang and Huang apply wave‐equation migration imaging of the preprocessed and balanced time‐lapse offset VSP data from the Aneth CO2‐EOR field and the inverted “true” VSP source locations to infer the reservoir changes. To reduce the imaging noise of the offset VSP data, they employ an angle‐domain imaging condition with reflection angle constraint for different offset VSP data sets to produce time‐lapse migration images, showing reservoir changes caused by CO2 injection/migration along different offset directions are different, indicating an anisotropic CO2 migration pattern relative to the injection wells.
In Chapter 9 on walkaway VSP monitoring, Wang et al. apply reverse‐time migration (RTM) to time‐lapse walkaway VSP data acquired at the SACROC CO2‐EOR field in Scurry County, Texas, USA, to reveal changes in the reservoir caused by CO2 injection and migration. Before they apply RTM to the data, they perform statics correction and amplitude balancing to the time‐lapse walkaway VSP data sets. To mitigate the image artifacts caused by the limited subsurface seismic illumination of the walkaway VSP surveys, they analyze and process the RTM images in the angle domain to greatly improve the image quality.
Because of limited seismic illumination of VSP surveys, migration imaging of VSP data often contains significant image artifacts, which can be alleviated using an angle‐domain imaging condition. This alleviation is tedious if not impossible for 3D VSP data. 3D least‐squares reverse‐time migration (LSRTM) is an alternative approach to addressing such a problem. To demonstrate the improved imaging capability of 3D LSRTM of 3D VSP data, Tan et al., in Chapter 10, apply the method to a portion of the 3D VSP data acquired at the Cranfield CO2‐EOR field in Mississippi, USA, for monitoring CO2 injection to obtain a high‐resolution 3D subsurface image. LSRTM solves for a reflectivity model by minimizing the difference between the observed data and modeled data. The advantages of LSRTM over RTM of VSP data include: (1) LSRTM significantly improves the spatial resolution of the layer images, and (2) LSRTM extends the horizontal imaging region to areas that cannot be imaged using RTM.
Besides time‐lapse seismic imaging, quantifying changes of subsurface geophysical properties caused by CO2 injection/migration can provide crucial information of CO2 plumes. In Chapter 11, Lin et al. present a double‐difference seismic‐waveform inversion method to jointly invert time‐lapse seismic data for reservoir changes of elastic parameters. Inverting individual time‐lapse seismic data sets separately may result in significant inversion artifacts and inaccurate inversion results. Double‐difference acoustic‐ or elastic‐waveform inversion constrains time‐lapse seismic data sets with each other to improve the robustness of inversion of time‐lapse changes and reduce inversion artifacts. In Lin et al.'s double‐difference seismic‐waveform inversion methods, they employ an energy‐weighted preconditioner, a spatial priori information (target monitoring regions), and a modified total‐variation regularization scheme to improve the inversion accuracy of changes of subsurface geophysical properties. They validate the method using time‐lapse walkaway VSP data acquired at the SACROC CO2‐EOR field, and reveal the velocity decrease in the geologic formation where CO2 was injected.
Multicomponent seismic surveys acquire not only compressional‐wave signals, but also shear‐wave signals that carry useful information for high‐resolution subsurface site characterization and monitoring. When using shear‐wave sources, the multicomponent seismic surveys record the full nine‐component elastic wavefields, which are the most complete seismic data. Such data contain compression‐to‐compression and shear‐to‐shear waves in addition to converted waves including compression‐to‐shear and shear‐to‐compression waves. Multicomponent seismic data are far more sensitive to fracture zones than compressional‐wave data, allowing improved characterization/monitoring of potential leakage pathways or preferential flow directions compared with one‐component data. In Chapter 12, on site characterization using multicomponent seismic data, DeVault et al. describe joint inversion of multicomponent seismic data for deriving elastic parameters from multicomponent data and demonstrate the unique advantages for geophysical CO2 reservoir characterization. They present results of joint inversion for characterizing the Duperow CO2‐bearing zone at Kevin Dome, Montana, USA. They demonstrate that the additional amplitude and polarization information contained in multicomponent data allows for the estimation of shear impedance, density, and azimuthal anisotropic parameters with much greater accuracy than using compressional‐wave seismic data.
In Chapter 13, Mur et al. develop
