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| Titel |
Comparative modeling of fault reactivation and seismicity in geologic carbon
storage and shale-gas reservoir stimulation |
| VerfasserIn |
Jonny Rutqvist, Antonio Rinaldi, Frédéric Cappa |
| Konferenz |
EGU General Assembly 2016
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| Medientyp |
Artikel
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| Sprache |
en
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| Digitales Dokument |
PDF |
| Erschienen |
In: GRA - Volume 18 (2016) |
| Datensatznummer |
250136931
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| Publikation (Nr.) |
 EGU/EGU2016-18083.pdf |
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| Zusammenfassung |
| The potential for fault reactivation and induced seismicity are issues of concern related to
both geologic CO2 sequestration and stimulation of shale-gas reservoirs. It is well known that
underground injection may cause induced seismicity depending on site-specific conditions,
such a stress and rock properties and injection parameters. To date no sizeable seismic
event that could be felt by the local population has been documented associated
with CO2 sequestration activities. In the case of shale-gas fracturing, only a few
cases of felt seismicity have been documented out of hundreds of thousands of
hydraulic fracturing stimulation stages. In this paper we summarize and review
numerical simulations of injection-induced fault reactivation and induced seismicity
associated with both underground CO2 injection and hydraulic fracturing of shale-gas
reservoirs. The simulations were conducted with TOUGH-FLAC, a simulator for
coupled multiphase flow and geomechanical modeling. In this case we employed both
2D and 3D models with an explicit representation of a fault. A strain softening
Mohr-Coulomb model was used to model a slip-weakening fault slip behavior, enabling
modeling of sudden slip that was interpreted as a seismic event, with a moment
magnitude evaluated using formulas from seismology. In the case of CO2 sequestration,
injection rates corresponding to expected industrial scale CO2 storage operations were
used, raising the reservoir pressure until the fault was reactivated. For the assumed
model settings, it took a few months of continuous injection to increase the reservoir
pressure sufficiently to cause the fault to reactivate. In the case of shale-gas fracturing
we considered that the injection fluid during one typical 3-hour fracturing stage
was channelized into a fault along with the hydraulic fracturing process. Overall,
the analysis shows that while the CO2 geologic sequestration in deep sedimentary
formations are capable of producing notable events (e.g. magnitude 3 or 4); the
likelihood for such felt events is much smaller in the case of shale-gas fracturing.
The reason is that CO2 geological sequestration involves injection and pressure
disturbances at much larger scale and with much larger reservoir permeability than in the
case of shale gas fracturing. In the case of shale-gas fracturing, the expected low
permeability of faults intersecting gas saturated shales is clearly a limiting factor
for the possible rupture length and seismic magnitude. For a fault that is initially
impermeable, the only possibility of larger fault slip events would be opening by hydraulic
fracturing allowing pressure to permeate along the fault causing a reduction in the
frictional strength over a sufficiently large fault surface patch and very brittle fault
properties that would allow shear slip to develop over a sufficient large rupture area. |
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