Search

The application of geophysical methods, in particular, electrical resistivity measurements, may be useful for monitoring subsurface contamination. However, interpreting geophysical data without additional data and without considering the associated hydrogeochemical processes is challenging since the geophysical response is sensitive to not only heterogeneity in rock properties but also to the saturation and chemical composition of pore fluids. We present an inverse modeling framework that incorporates the simulation of hydrogeochemical processes and time-lapse electrical resistivity data and apply it to various borehole and cross-borehole data sets collected in 2008 near the S-3 Ponds at the U.S. Department of Energy's Oak Ridge Integrated Field Research Challenge site, where efforts are underway to better understand freshwater recharge and associated contaminant dilution. Our goal is to show that the coupled hydrogeochemical-geophysical modeling framework can be used to (1) develop a model that honors all the available data sets, (2) help understand the response of the geophysical data to subsurface properties and processes at the site, and (3) allow for the estimation of petrophysical parameters needed for interpreting the geophysical data. We present a series of cases involving different data sets and increasingly complex models and find that the approach provides useful information about soil properties, recharge-related transport processes, and the geophysical response. Spatial heterogeneity of the petrophysical model can be described sufficiently with two layers, and its parameters can be estimated concurrently with the hydrogeochemical parameters. For successful application of the approach, the parameters of interest must be sensitive to the available data, and the experimental conditions must be carefully modeled. [ABSTRACT FROM AUTHOR]

Sequestration/enhanced oil recovery (EOR) petroleum reservoirs have relatively thin injection intervals with multiple fluid components (oil, hydrocarbon gas, brine, and carbon dioxide, or CO2), whereas brine formations usually have much thicker injection intervals and only two components (brine and CO2). Coal formations undergoing methane extraction tend to be thin (3-10 m) but shallow compared to either EOR or brine formations. Injecting CO2 into an oil reservoir decreases the bulk density in the reservoir. The spatial pattern of the change in the vertical component of gravity (Gz) is correlated directly with the net change in reservoir density. Furthermore, time-lapse changes in the borehole Gz clearly identity the vertical section of the reservoir where fluid saturations are changing. The CO2-brine front on the order of 1 km within a 20-m-thick brine formation at 1900-m depth with 30% CO2 and 70% brine saturations, respectively, produced a -- 10-µGal surface gravity anomaly. Such an anomaly would be detectable in the field. The amount of CO2 in a coal-bed methane scenario did not produce a large enough surface gravity response; however, we would expect that for an industrial-size injection, the surface gravity response would be measurable. Gravity inversions in all three scenarios illustrate that the general position of density changes caused by CO2 can be recovered but not the absolute value of the change. Analysis of the spatial resolution and detectability limits shows that gravity measurements could, under certain circumstances, be used as a lower-cost alternative to seismic measurements. [ABSTRACT FROM AUTHOR]