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Injection of fluids into geologic formations for long term disposition (CO 2 ) or to improve energy extraction operations can benefit from subsurface monitoring programs capable of providing three dimensional spatial imaging of fluid distributions in the host reservoirs. More importantly, advancements in horizontal drilling and fluid fracking technologies are attracting a broader portfolio of non-traditional engineered subsurface reservoirs that possess complex fluid flow typically through engineered fracture networks. For example, producing fossil fuels from tight sands or shale formations, geothermal based heat extraction operations in low-permeability rock formations, and storing injected fluids (i.e. CO 2 , acid gases, waste waters, etc.) in the subsurface all require rigorous tracking techniques capable of identifying fluid migration. Current methodologies for four dimensional (3D spatial changes over time) subsurface monitoring of injected fluids are typically geophysical, using surface stations and borehole devices which employ seismic, electromagnetic, and gravitational techniques. However current methods often lack sufficient measurement sensitivity to adequately track fluid migration, and often incur a large economic cost. In this paper, we describe an entirely new class of acoustically responsive contrast agents to enable high-sensitivity, high-resolution tracking of injected fluids via conventional seismic imaging that have the potential of improving subsurface fracture network mapping and plume monitoring in CO 2 storage operations. [ABSTRACT FROM AUTHOR]

The proliferation of commercial development in U.S. gas-bearing shales helped to drive a twelve-fold increase in domestic gas production between 2000 and 2010, and the nation's gas production rates continue to grow. While shales have long been regarded as a desirable caprock for CCS operations because of their low permeability and porosity, there is increasing interest in the feasibility of injecting CO 2 into shales to enhance methane recovery and augment CO 2 storage. Laboratory work published in recent years observes that shales with adsorbed methane appear to exhibit a stronger affinity for CO 2 adsorption, offering the potential to drive additional CH 4 recovery beyond primary production and perhaps the potential to store a larger volume of CO 2 than the volume of methane displaced. Recent research by the authors on the revenues associated with CO 2 -enhanced gas recovery (CO 2 -EGR) in gas-bearing shales estimates that, based on a range of EGR response rates, the average revenue per ton of CO 2 for projects managed over both EGR and subsequent storage-only phases could range from $0.50 to $18/tCO 2 . While perhaps not as profitable as EOR, for regions where lower-cost storage options may be limited, shales could represent another “early opportunity” storage option if proven feasible for reliable EGR and CO 2 storage. Significant storage potential exists in gas shales, with theoretical CO 2 storage resources estimated at approximately 30-50 GtCO 2 . However, an analysis of the comprehensive cost competitiveness of these various options is necessary to understand the degree to which they might meaningfully impact U.S. CCS deployment or costs. This preliminary analysis shows that the degree to which EGR-based CO 2 storage could play a role in commercial-scale deployment is heavily dependent upon the offsetting revenues associated with incremental recovery; modeling the low revenue case resulted in only five shale-based projects, while under the high revenue case, shales accounted for as much as 20 percent of total U.S. storage in the first 20 years of deployment. Interestingly, even in this highest revenue case, there appear to be no negative-cost projects that would be profitable in a no-policy environment as modeled under the assumptions employed. While this reflects a very first look at the potential for shales, it is clear that more laboratory and experimental work are needed to reduce uncertainty in key variables and begin to differentiate and identify high-potential shales for early pilot study. [ABSTRACT FROM AUTHOR]