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| Titel |
Geochemical effects of impurities in CO2 on long-term storage integrity |
| VerfasserIn |
Mariëlle Koenen, Tim Tambach |
| 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 |
250048388
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| Zusammenfassung |
| CO2 capture and storage (CCS) is considered as a potential means of CO2 emission
reduction. Emitted CO2 is, however, almost never a pure stream. Depending on its source, a
number of impurities can be present in variable amounts. For geological storage, the most
important ones are O2, H2S, SO2 and NOx. These impurities, even if present in low
concentrations, are able to influence the pH of the formation water and may subsequently
disturb geochemical, and accordingly geomechanical, properties of the reservoir rock, cap
rock and well bore material. Purification of the CO2 stream at the source is very costly and
requires a lot of energy. Therefore, it is important to investigate the severity of the effects of
these impurities.
Geochemical interactions between different impurities, CO2 and brine are complex and not
yet understood. It is known that the pH of the formation water decreases to values of around 4
after CO2 dissolution. Previous modeling research using PHREEQC (Koenen et al., 2010)
predicts formation of nitric and sulfuric acid due to dissolution of impurities and reaction
with other aqueous species in the formation water. The presence or absence of
O2 is of great importance, especially in the oxidation of H2S. Accordingly, the
pH of the brine may decrease to values lower than 3, depending on the types and
concentration of impurities in the stream. This effect could be severe near the injection
well due to the high solubility and further dissociation of the impurities. Acidic
formation water near the injection well could affect the integrity of well-bore cement,
unless drying out of the well-bore area occurred as a result of water evaporation into
the CO2. In the latter case, transport of impurities into the reservoir may cause
brine acidification and geochemical reactions of minerals in the reservoir and cap
rock.
According to Ellis et al. (2009) the long-term pH effect of impurities in an aquifer will, even
on a time scale of thousands of years, be limited to a narrow zone at the contact of the
supercritical CO2 (scCO2) plume and the water saturated area. Diffusion of impurities within
the CO2 and within the brine is assumed to be slow. However, dissolution of impurities will
also occur in residual (capillary) brine in the unsaturated zone (or in a depleted gas reservoir),
with pH lowering and alteration of the geochemical balance as a consequence. For the cap
rock such effects will be diffusion limited, but a narrow and upward progressing acid front
seems likely.
In this work several PHREEQC geochemical modeling approaches are applied to study the
effects of impurities at the interfaces of the reservoir, cap rock, and well-bore area in more
detail. The first results show that progress of the acidification front in the cap rock is
predicted to be highly dependend on the diffusion coefficients assumed. Sensitivity of several
other parameters is investigated. The results will show in more detail the rate and severity of
the potential geochemical degradation of the materials as a consequence of the presence of
impurities.
References
Ellis B.R., Crandell L.E. and Peters C.A., 2010. Limitations for brine acidification due to SO2
co-injection in geologic carbon sequestration. International Journal of Greenhouse Gas
Control 4, 575-582
Koenen M., Tambach T.J. and Neele F.P., 2010. Geochemical effects of impurities in CO2 on
a sandstone reservoir. GHGT-10, Energy Procedia (in press) |
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