HR: 12:05h
AN: H12D-08    [Abstracts]
TI: Simulations of dry-out and halite precipitation due to CO₂ injection
AU: * Hurter, S
EM: SHurter@slb.com
AF: Schlumberger, Parkstraat 83, The Hague, 2514 JG, Netherlands
AU: Labregere, D
EM: DLabregere@slb.com
AF: Schlumberger, Parkstraat 83, The Hague, 2514 JG, Netherlands
AU: Berge, J
EM: JBerge@slb.com
AF: Schlumberger, Parkstraat 83, The Hague, 2514 JG, Netherlands
AB: Although H₂O is not very soluble in supercritical CO₂, a continuous stream of CO₂ injected into a formation, will cause a region around the injection well to dry out. As the water of the formation brine is continuously evaporated into the CO2, the irreducible water saturation may attain practically zero. Enhanced injectivity is the result of this process in a low salinity brine environment. In formations saturated with highly saline brine (e.g. Northern German Basin) the outcome is opposite: injectivity is impaired. In this case, the brine becomes supersaturated as continuously H₂O evaporates into the CO₂ phase and salt (halite) precipitates in the pores. The porosity and permeability diminish, which can lead to the loss of a well. We present simulations of these processes as an example of pre-injection study for a CO₂ injection and storage site. The simulation tool consists of a commercial compositional code used extensively in the oil and gas industry to simulate the flow of multiple phases (oil, water, gas) in porous or fractured media. The mutual solubility of CO₂ and H₂O with a correction for salinity is implemented as described in Spycher and Pruess (2005). The brine salinity is adjusted accordingly until the saturation threshold is reached and halite is precipitated. The distribution of precipitation in the reservoir depends not only of the relationship between permeability change as a function of porosity change, but also on the relative permeability curves for the CO₂-brine system. Therefore it is essential to establish relative permeability curves in the laboratory, as well as to obtain a relationship between porosity change and permeability variation with precipitation by laboratory experiments on cores to obtain meaningful results from numerical simulations. References Spycher N. and Pruess, K. (2005), CO₂-H₂O mixtures in the geological sequestration of CO₂, II Partitioning in chloride brines at 12-100^o and up to 600 bar, Geochim. Cosmochim. Acta 69, 13, 3309-3320.
DE: 0426 Biosphere/atmosphere interactions (0315)
DE: 0900 EXPLORATION GEOPHYSICS
DE: 1009 Geochemical modeling (3610, 8410)
DE: 1800 HYDROLOGY
DE: 8430 Volcanic gases
SC: Hydrology [H]
MN: 2007 Fall Meeting