This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 97255, "Numerical Simulation of the Storage of Pure CO2 and CO2-H2S Gas Mixtures in Deep Saline Aquifers," by R.C. Ozah, SPE, S. Lakshminarasimhan, G.A. Pope, SPE, K. Sepehrnoori, SPE, and S.L. Bryant, SPE, U. of Texas at Austin, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October.
The long-term storage potential of CO2 and CO2/H2S mixtures in deep saline aquifers was studied by use of a compositional reservoir simulator. Aquifer characteristics were varied to deter-mine their effect on storage potential and injectivity. The opportunity for gas escape from the aquifer can be minimized by careful injection strategies. One such strategy is to use horizontal wells low in the formation so all injected gases are trapped, dissolved, or precipitated before they reach geological seals and/or faults.
Geological sequestration of CO2 and other greenhouse gases is one of the few ways to store such gases in sufficient volumes to mitigate the greenhouse effect. Most schemes depend on storing CO2 in the supercritical state. In these schemes, buoyancy forces drive the injected CO2 upward in the aquifer until a geological seal is achieved. The permanence of this type of sequestration depends on seal integrity. Ensuring seal integrity over very-long time periods is difficult.
The focus has been on an alternative scheme built on three sequestration modes that avoid this concern.
Pore-level trapping of the gas phase within the geological formation.
Dissolution into brine in the aquifer.
Precipitation of dissolved gases as minerals.
Each of these modes is permanent for the time frame of interest for gas sequestration, where "permanent" means gas placed in the aquifer will not reach the surface any sooner than other species or fluids originally present in the formation. The two key issues then become maximizing these three sequestration modes so that large volumes can be stored permanently in aquifers without ensuring long-term seal integrity and predicting the time required for injected gas to become immobilized by one or more of these storage modes.
The principal petrophysical parameters influencing storage as an immobile gas phase are relative permeability, including hysteresis, and residual gas saturation. Both depend on rock properties in the aquifer and thus can vary with location. Phase behavior of the gas/brine mixture controls storage in solution. The geochemical driver accompanying storage is the acidification of the brine resulting from dissociation of dissolved CO2 and H2S. Low-pH brine induces several reactions with minerals in the formation. Dissolution reactions can release cations such as Ca++ and Fe++. These cations can form relatively insoluble carbonate precipitates such as siderite and sulfide precipitates such as pyrite. Time scales for these processes vary widely. Once gas injection ends, fluid displacement leading to residual saturations depends on absolute and relative permeabilities, hysteresis, buoyancy forces, aquifer dip, natural back-ground flow gradient, and magnitude of the residual saturation.