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| Titel |
Multiphase flow of CO2 and water in reservoir rocks at reservoir conditions |
| VerfasserIn |
Samuel Krevor, Ronny Pini, Lin Zuo, Sally Benson |
| Konferenz |
EGU General Assembly 2011
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| Medientyp |
Artikel
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| Sprache |
Englisch
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| Digitales Dokument |
PDF |
| Erschienen |
In: GRA - Volume 13 (2011) |
| Datensatznummer |
250056359
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| Zusammenfassung |
| A firm understanding of the multiphase flow properties of CO2 and water in porous media is
essential to predicting the long-term fate of CO2 in geologic storage. Recently, pilot-scale and
simulation based studies have highlighted the importance that properties of relative
permeability, residual saturation, and rock heterogeneity will play in determining the
long-term distribution of CO2 in the subsurface1-3. There is a clear need for more
observations to expand the current dataset of experimental work, as well as an in-depth
discussion of these results in the context of the multiphase flow theory that is used in
reservoir-scale predictions of subsurface flow.
In this paper we present the results of an experimental investigation into the flow
properties of CO2 and water in 5 distinct rock lithologies: a Berea sandstone and 4 reservoir
rocks from formations into which CO2 injection is either currently taking place
or is planned. Drainage and imbibition relative permeability, as well as end-point
saturations were measured using the steady-state method in a high pressure and
temperature core-flooding apparatus with fluid distributions observed using X-ray
computed tomography. In addition, absolute permeability, capillary pressure curves,
and petrological studies were performed on each sample to fully characterize the
rocks.
The results are discussed in terms of their potential impact on basin-scale modeling of
industrial CO2 injection projects. Theoretical explanations for generally low end-point CO2
relative permeabilities are discussed as well as its relevance for reservoir simulations. It is
shown that small-scale heterogeneity plays an important role in both the overall saturations of
CO2 in a rock as well as the saturation distribution within the rock. Clear evidence of
heterogenous flow-properties are observed even in rocks of homogeneous rock lithology.
Observations of residual CO2 saturation are discussed in the context of the long-term stability
of CO2 injected in the subsurface. The experiments are compared with results reported by
other laboratories4; Similarities are highlighted and differences are discussed in the context of
rock types, experimental conditions, and laboratory procedures. Finally, the treatment of
parameter inputs used in previous modeling studies is evaluated in the context of these results
and some suggestions for making decisions about model inputs in the future are
provided.
References
1. Juanes, R. Spiteri, E.J., Orr Jr., F.M., Blunt, M.J. 2006. Impact of relative
permeability hysteresis on geological CO2 storage. Water Resources Research. Vol. 42,
W12418
2. Hovorka S.D., Benson, S.M., Doughty C., Freifeld, B.M., Sakurai, S., Daley, T.M.,
Kharaka, Y.K., Holtz, M.H., Trautz, R.C., Nance, H.S., Myer, L.M., Knauss, K.G. 2006.
Measuring permeanence of CO2 storage in saline formations: the Frio experiment.
Environmental Geosciences, V. 13, No. 2, pp 105-121.
3. Krause, M., Perrin, J.-C. and Benson S.M. 2011. Modeling Permeability Distributions
in a Sandstone Core for History Matching Coreflood Experiments. SPE Journal, Published
Online 7 January 2011.
4. Bachu, S., Bennion, B., 2008. Effects of in-situ conditions on relative permeability
characteristics of CO2-brine systems. Environmental Geology 54:1707-1722 |
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