Liquid CO2 injection for geological storage in deep saline aquifers

Vilarrasa, Víctor; Silva, Orlando; Carrera, Jesús; Olivella, S.

doi:10.1016/j.ijggc.2013.01.015

Cited by 139 publications

(98 citation statements)

References 47 publications

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“…CO 2 will generally reach the storage formation at a temperature lower than that of the rock (90). In fact, injecting liquid (cold) CO 2 and maintaining liquid conditions along the wellbore is energetically advantageous (and therefore, it is likely to become a common practice) because it significantly reduces compression costs (91). Cold injection will cause a cold region around the injection well, which will induce thermal stress reduction.…”

Section: Discussionmentioning

confidence: 99%

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂could leak

Vilarrasa

Carrera

2015

Proc. Natl. Acad. Sci. U.S.A.

180

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Zoback and Gorelick [(2012) Proc Natl Acad Sci USA 109(26): [10164][10165][10166][10167][10168] have claimed that geologic carbon storage in deep saline formations is very likely to trigger large induced seismicity, which may damage the caprock and ruin the objective of keeping CO 2 stored deep underground. We argue that felt induced earthquakes due to geologic CO 2 storage are unlikely because (i) sedimentary formations, which are softer than the crystalline basement, are rarely critically stressed; (ii) the least stable situation occurs at the beginning of injection, which makes it easy to control; (iii) CO 2 dissolution into brine may help in reducing overpressure; and (iv) CO 2 will not flow across the caprock because of capillarity, but brine will, which will reduce overpressure further. The latter two mechanisms ensure that overpressures caused by CO 2 injection will dissipate in a moderate time after injection stops, hindering the occurrence of postinjection induced seismicity. Furthermore, even if microseismicity were induced, CO 2 leakage through fault reactivation would be unlikely because the high clay content of caprocks ensures a reduced permeability and increased entry pressure along the localized deformation zone. For these reasons, we contend that properly sited and managed geologic carbon storage in deep saline formations remains a safe option to mitigate anthropogenic climate change.

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Section: Discussionmentioning

confidence: 99%

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂could leak

Vilarrasa

Carrera

2015

Proc. Natl. Acad. Sci. U.S.A.

180

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“…Moreover, whereas thermal equilibrium is assumed at all times, this would not be the case in the vicinity of the injection point. For instance, as discussed in (Vilarrasa et al 2013b), the injection of liquid CO 2 would lead to smaller displaced volumes close to the well, resulting in lower induced overpressure overall.…”

Section: Discussionmentioning

confidence: 98%

Vertically Averaged Equations with Variable Density for $$\hbox {CO}_2$$ CO 2 Flow in Porous Media

2014

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Carbon capture and storage has been proposed as a viable option to reduce CO 2 emissions. Geological storage of CO 2 where the gas is injected into geological formations for practically indefinite storage, is an integral part of this strategy. Mathematical models and numerical simulations are important tools to better understand the processes taking place underground during and after injection. Due to the very large spatial and temporal scales involved, commercial 3D-based simulators for the petroleum industry quickly become impractical for answering questions related to the long-term fate of injected CO 2 . There is an interest in developing simplified modeling tools that are effective for this type of problem. One approach investigated in recent years is the use of upscaled models based on the assumption of vertical equilibrium (VE). Under this assumption, the simulation problem is essentially reduced from 3D to 2D, allowing much larger models to be considered at the same computational cost. So far, most work on VE models for CO 2 storage has either assumed incompressible CO 2 or only permitted lateral variations in CO 2 density (semi-compressible). In the present work, we propose a way to fully include variable CO 2 density within the VE framework, making it possible to also model vertical density changes. We derive the fine-scale and upscaled equations involved and investigate the resulting effects. In addition, we compare incompressible, semi-compressible, and fully compressible CO 2 flow for some model scenarios, using an in-house, fully-implicit numerical code based on automatic differentiation, implemented using the MATLAB reservoir simulation toolkit.

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“…Due to such complex alteration processes, both bottom-hole pressure and temperature would be significantly different from ones at the well-head. Subsequently, altered pressure and temperature profiles would significantly affect thermophysical properties of CO 2 such as density, viscosity, enthalpy, internal energy, and solubility [19,26,[30][31][32].…”

Section: Introductionmentioning

confidence: 99%

Dynamic Behavior of CO₂ in a Wellbore and Storage Formation: Wellbore-Coupled and Salt-Precipitation Processes during Geologic CO₂ Sequestration

et al. 2018

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For investigating the wellbore flow process in CO 2 injection scenarios, coupled wellbore-reservoir (WR) and conventional equivalent porous media (EPM) models were compared with each other. In WR model, during the injection, conditions for the wellbore including pressure and temperature were dynamically changed from the initial pressure (7.45-8.33 MPa) and temperature (52.0-55.9∘ C) of the storage formation. After 3.35 days, the wellbore flow reached the steady state with adiabatic condition; temperature linearly increased from the well-head (35 ∘ C) to the well-bottom (52 ∘ C). In contrast, the EPM model neglecting the wellbore process revealed that CO 2 temperature was consistently 35∘ C at the screen interval. Differences in temperature from WR and EPM models resulted in density contrast of CO 2 that entered the storage formation (∼200 and ∼600 kg/m 3 , resp.). Subsequently, the WR model causing greater density difference between CO 2 and brine revealed more vertical CO 2 migration and counterflow of brine and also developed the localized salt-precipitation. Finally, a series of sensitivity analyses for the WR model was conducted to assess how the injection conditions influenced interplay between flow system and the localized salt-precipitation in the storage formation.

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Liquid CO2 injection for geological storage in deep saline aquifers

Cited by 139 publications

References 47 publications

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂could leak

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂could leak

Vertically Averaged Equations with Variable Density for $$\hbox {CO}_2$$ CO 2 Flow in Porous Media

Dynamic Behavior of CO₂ in a Wellbore and Storage Formation: Wellbore-Coupled and Salt-Precipitation Processes during Geologic CO₂ Sequestration

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Liquid CO2 injection for geological storage in deep saline aquifers

Cited by 139 publications

References 47 publications

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO2could leak

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO2could leak

Vertically Averaged Equations with Variable Density for $$\hbox {CO}_2$$ CO 2 Flow in Porous Media

Dynamic Behavior of CO2 in a Wellbore and Storage Formation: Wellbore-Coupled and Salt-Precipitation Processes during Geologic CO2 Sequestration

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Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂could leak

Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂could leak

Dynamic Behavior of CO₂ in a Wellbore and Storage Formation: Wellbore-Coupled and Salt-Precipitation Processes during Geologic CO₂ Sequestration