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Scientific Investigations Report 2011–5083

Carbon Dioxide Fluid-Flow Modeling and Injectivity Calculations

By Lauri Burke

Thumbnail of and link to report PDF (1.62 MB) Abstract

At present, the literature lacks a geologic-based assessment methodology for numerically estimating injectivity, lateral migration, and subsequent long-term containment of supercritical carbon dioxide that has undergone geologic sequestration into subsurface formations. This study provides a method for and quantification of first-order approximations for the time scale of supercritical carbon dioxide lateral migration over a one-kilometer distance through a representative volume of rock. These calculations provide a quantified foundation for estimating injectivity and geologic storage of carbon dioxide.

A geologic-based approach was developed in which subsurface pressure and temperature conditions were held constant while the petrophysical properties of fractional porosity and matrix permeability were varied simultaneously. The Span and Wagner equations of state were used to determine thermophysical properties of carbon dioxide at appropriate reservoir conditions. The fluid-flow calculations assume mass transport through a laterally continuous, homogeneous isotropic formation and were based on two constitutive equations from fluid dynamics: hydraulic diffusivity for near-surface applications, and a modified version of Darcy’s Law for deeper formations exhibiting higher pressure gradients.

The first-order approximations of the lateral migration time scales, for both hydraulic diffusivity and Darcy flow, can be expressed as a quasi-linear function over a range of porosity and permeability values. This method is applicable to a substantial range of sedimentary formations exhibiting porosities up to 95 percent and permeabilities from 10.0 darcy to 1.0 picodarcy.

These results were used to classify subsurface formations into three permeability classifications for the probabilistic calculations of storage efficiency and containment risk of the U.S. Geological Survey geologic carbon sequestration assessment methodology. This methodology is currently in use to determine the total carbon dioxide containment capacity of the onshore and State waters areas of the United States.

First posted July 26, 2011

For additional information contact:
U.S. Geological Survey
Central Energy Resources Science Center
Box 25046, MS-939
Denver Federal Center
Denver, CO 80225-0046

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Suggested citation:

Burke, Lauri, 2011, Carbon dioxide fluid-flow modeling and injectivity calculations: U.S. Geological Survey Scientific Investigations Report 2011–5083, 16 p.





Fluid-Flow Modeling

Hydraulic Diffusivity

Sensitivity Analysis for Hydraulic Diffusivity Flow Modeling

Darcy’s Law of Fluid Flow


The Maximum Pressure Differential for Injectivity

Results from Darcy’s Law of Fluid Flow

Darcy Sensitivity Analysis

Permeability Classifications

Discussion and Conclusions


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