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Open-File Report 2012-1062

Migration Rates and Formation Injectivity to Determine Containment Time Scales of Sequestered Carbon Dioxide

By Lauri Burke

Thumbnail of and link to report PDFAbstract

Supercritical carbon dioxide exhibits highly variable behavior over a range of reservoir pressure and temperature conditions. Because geologic sequestration of supercritical carbon dioxide is targeted for subsurface injection and containment at depths ranging from approximately 3,000 to 13,000 feet, the investigation into the physical properties of this fluid can be restricted to the pressure and temperature conditions likely encountered in the sedimentary strata within this depth interval. A petrophysical based approach was developed to study the widest range of formation properties potentially encountered in sedimentary strata. Fractional porosities were varied from 5 to 95 percent, in 5-percent increments, and permeability values were varied over thirteen orders of magnitude, from 10.0 darcys down to 1.0 picodarcy.

Fluid-flow modeling incorporated two constitutive equations from fluid dynamics: hydraulic diffusivity for near-surface applications, and Darcy’s Law for deeper formations exhibiting higher pressure gradients. Based on the flow modeling results, first-order approximations of carbon dioxide lateral migration rates were determined. These first-order approximations enable the establishment of a permeability classification system for dividing the subsurface into flow units that provide short, moderate, and long-term containment of carbon dioxide. These results enable a probabilistic determination of how fluids will enter and be contained in a subsurface storage formation, which is a vital step in the calculation of the carbon dioxide storage capacity of a reservoir.

Additionally, this research establishes a methodology to calculate the injectivity of a target formation. Because injectivity describes the pressure increase due to the introduction of fluids into a formation, the relevant application of injectivity is to determine the pressure increase, due to an injection volume and flow rate, that will induce fractures in the reservoir rocks. This quantity is defined mathematically as the maximum pressure differential between the hydrostatic gradient and the fracture gradient of the target formation. Injectivity is mathematically related to the maximum pressure differential of the formation, and can be used to determine the upper limit for the pressure increase that an injection target can withstand before fracturing.

First posted April 17, 2012

For additional information contact:
Director, USGS Central Energy Resources Science Center
Box 25046, Mail Stop 939
Denver, CO 80225

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Suggested citation:

Burke, L.A., 2012, Migration rates and formation injectivity to determine containment time scales of sequestered carbon dioxide: U.S. Geological Survey Open-File Report 2012–1062, 23 p.





Fluid Flow Modeling

Permeability Classifications

Formation Injectivity

Maximum Pressure Differential



References Cited

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