Interpreting and understanding overburden seismic changes are important to avoid health, safety, and environmental (HSE) accidents and well-drilling problems. Furthermore, overburden time shifts might indicate areas with reservoir compaction and depletion. In the Snorre sandstone field, 4D seismic time shifts of as much as 3 ms are observed in the overburden. The cumulative overburden time shifts captured at top reservoir correlate well with pressure-depletion areas in the reservoir, indicating that the time shifts might be related to changes in stress and strain because of reservoir compaction. For further investigation, a 2D geomechanical model is built in the area with the most prominent overburden time shifts. Based on the stiffness of the reservoir and surrounding rocks and simulated reservoir pore-pressure changes, the geomechanical model predicts a maximum downward displacement at the top reservoir of 0.4 m and maximum seabed subsidence of 0.25 m. By defining an appropriate strain-sensitivity parameter, the results from the geomechanical model are forward-modeled into velocity changes. For comparison, velocity changes are estimated from the time shifts. A good qualitative match is obtained between the geomechanical model and the observed time shifts, indicating that the time shifts are caused by geomechanical effects related to production. Other explanations of the observed overburden time shifts, such as fluid leakage, out-of-zone-injection, or seismic acquisition or processing problems, are found to be less realistic causes of the observed time shifts.

Quantitative 4D seismic interpretation can be successfully achieved by exploiting the causal link between the temporal variation in well activity and the 4D seismic signatures they induce. This is achieved by capturing in mathematical form the common interpretational practice of identifying the origin of dynamic signals in the 4D seismic volumes or maps on the basis of their association with a particular injector or producer. Thus, for example, a region of reservoir hardening (impedance increase) around a producer may be interpreted as a signal of pressure decrease. Similarly, an area of softening (impedance decrease) around an injector is interpreted as a signal of pressure increase when pressures are above bubble point. In the literature, a hardwired integration between the seismic and engineering domain has been obtained to some extent using methods such as seismic history matching, where the observed seismic and well production history data are simultaneously fit by predictions from a common simulation model. However, this approach is computationally expensive and suffers from nonuniquenesses, inaccuracies in the petroelastic model, and is ultimately only as accurate as the model itself. As an alternate approach, we reconcile here the well production history and time-lapse seismic data in the data domain without the need for a model. This approach involves the use of many frequently repeated seismic surveys shot over the same field, and mathematically correlates changes in the mapped seismic attributes directly to the fluid volumes injected and produced from the wells. Thus, well data normally used exclusively for history matching in the reservoir engineering domain can now also be directly integrated with the time-lapse seismic data.

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