Basic Research Needs for Geosciences - Energetics Meetings and ...

PANEL REPORT: SUBSURFACE CHARACTERIZATIONanthropogenic or naturally occurring substances that, with the appropriate model, can provideestimates of the mean residence time of the sampled water. Examples include isotopes (e.g., 14 C,36 Cl, 3 H-He) as well as anthropogenic compounds such as chlorofluorocarbons (CFCs) and sulfurhexafluoride (SF 6 ) (Phelps et al. 2006). Recent work (e.g., Weissmann et al. 2002; Bethke andJohnson 2002; DePaolo 2006) indicates that these methods tend to provide a biased estimate ofthe mean age of a typically broad distribution within the groundwater sample (Figure 14). Thebroad distributions of age are indicative of the multiple scales of complexity that cause scaledependentdispersion, preferential flow (including leakage along faults), physical and chemicalanthropogenic transients, and, in some cases, chemical reactions. Unfortunately, environmentaltracer methods are currently insufficient to estimate the full range of groundwater ages within asample and to thereby deduce the actual age distributions. In particular, methods are needed forreliably estimating groundwater ages in the range of 40 to ~3000 years. When methods exist tocover virtually the full range in most ages within groundwater samples (10 0 –10 4 years), it will bepossible to estimate actual age distributions, which will represent a powerful tool forcharacterization of multiscale heterogeneity via model calibration and for validation of thesemodels.Monitoring dynamic subsurface processesMeasuring time-lapse changes (monitoring) is especially critical for understanding processes inthe subsurface. In the seismic image of Figure 10, clear fault zone reflections are visible.Figure 12 shows the reflectivity of the B-fault in map-view as inferred from two seismic surveysrecorded seven years apart. A zone of high reflectivity is moving in the northeast direction,which is the up-dip direction. This moving zone of high reflectivity is indicative of fluidmigration along the fault (Haney et al. 2005). Another example of fluid migration is shown inFigure 15, where CO 2 changes the reflectivity of the seismic image during enhanced oilrecovery. Note that in the examples of Figures 12 and 15 the spatial and temporal scales of thisobserved moving fluid migration are low. Within the limits of this low resolution, the presenceof the fluid pulse can be established, but details of the interaction of the fluid with the subsurfacestructure are lacking.Courtesy of Martin Landro and Statoil.Figure 15. Time-lapse seismic images of a reservoir in which CO 2 is injected. The yellow and red regions indicatelow acoustic impedance; this indicates the presence of fluid or gas.Basic Research Needs for Geosciences: Facilitating 21 st Century Energy Systems 43