Optimization of a CO2 storage project based on thermal, geomechanical and induced fracturing effects

Goodarzi, Somayeh; Settari, A.; Zoback, Mark D.; Keith, David W.

doi:10.1016/j.petrol.2015.06.004

Cited by 44 publications

(26 citation statements)

References 25 publications

(37 reference statements)

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“…Therefore, the injected CO 2 from the well-head was always to be supercritical state. However, in the field implementation, the high CO 2 temperature implies high energetic cost requiring for heating up CO 2 [52]. Therefore, for the consideration of economically optimum CCS operations, the injection of gaseous CO 2 should be evaluated using the wellbore dynamic model too.…”

Section: Discussionmentioning

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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Section: Discussionmentioning

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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“…However, stiffer rocks or larger cooling may induce a stress reduction that could cause tensile failure and thus formation of hydraulic fractures (Goodarzi et al . , ). If hydraulic fractures propagate into the caprock, they may lead to CO 2 leakage, which is a situation that should be avoided.…”

Section: Discussionmentioning

confidence: 99%

“…As a result, the horizontal stress changes induced by tectonic movements are larger in the stiffer reservoirs than in the softer caprocks, as occurs in the Ohio River Valley, USA (Goodarzi et al . ), or the Molasse Basin, Switzerland (Hergert et al . ).…”

Section: Discussionmentioning

confidence: 99%

“…If the horizontal stresses are such that the deviatoric stress is smaller in the caprock than in the reservoir, the caprock may remain stable with respect to shear failure despite the thermal stress reduction (Goodarzi et al . ). Simulation results have also shown a stabilizing situation when injecting cold CO 2 through a vertical well because the thermal stress reduction that occurs in the vertical stress within the reservoir causes stress redistribution to satisfy stress equilibrium and displacement compatibility.…”

Section: Introductionmentioning

confidence: 97%

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The role of the stress regime on microseismicity induced by overpressure and cooling in geologic carbon storage

Vilarrasa

2016

Geofluids

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Fluid injection in deep geological formations usually induces microseismicity. In particular, industrial-scale injection of CO 2 may induce a large number of microseismic events. Since CO 2 is likely to reach the storage formation at a lower temperature than that corresponding to the geothermal gradient, both overpressure and cooling decrease the effective stresses and may induce microseismicity. Here, we investigate the effect of the stress regime on the effective stress evolution and fracture stability when injecting cold CO 2 through a horizontal well in a deep saline formation. Simulation results show that when only overpressure occurs, the vertical total stress remains practically constant, but the horizontal total stresses increase proportionally to overpressure. These hydro-mechanical stress changes result in a slight improvement in fracture stability in normal faulting stress regimes because the decrease in deviatoric stress offsets the decrease in effective stresses produced by overpressure. However, fracture stability significantly decreases in reverse faulting stress regimes because the size of the Mohr circle increases in addition to being displaced towards failure conditions. Fracture stability also decreases in strike slip stress regimes because the Mohr circle maintains its size and is shifted towards the yield surface a magnitude equal to overpressure minus the increase in the horizontal total stresses. Additionally, cooling induces a thermal stress reduction in all directions, but larger in the out-of-plane direction. This stress anisotropy causes, apart from a displacement of the Mohr circle towards the yield surface, an increase in the size of the Mohr circle. These two effects decrease fracture stability, resulting in the strike slip being the least stable stress regime when cooling occurs, followed by the reverse faulting and the normal faulting stress regimes. Thus, characterizing the stress state is crucial to determine the maximum sustainable injection pressure and maximum temperature drop to safely inject CO 2 .

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“…For example, the temperature difference between the temperature at which CO 2 entered the storage formation and the rock was of 55 ºC at Cranfield, Mississippi (Kim and Hosseini, 2014) and of 45 ºC at In Salah, Algeria (Bissell et al, 2011). Despite these large temperature differences, thermal effects have received little attention and only a few studies deal with them (Han et al, 2010;Singh et al, 2011;Goodarzi et al, 2012Goodarzi et al, , 2015Fang et al, 2013;Bao et al, 2014;Vilarrasa, 2016;Vilarrasa and Rutqvist, 2017). In particular, the geomechanical effects of cold CO 2 injection on caprock stability have been investigated in a generic repository (Vilarrasa et al, 2013a;Kim and Hosseini, 2015) and at the In Salah storage site (Preisig and Prevost, 2011;Gor et al, 2013;Vilarrasa et al, 2015).…”

Section: Introductionmentioning

confidence: 99%

Long-term thermal effects on injectivity evolution during CO2 storage

Vilarrasa

Rinaldi

Rutqvist

2017

International Journal of Greenhouse Gas Control

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Carbon dioxide (CO 2 ) is likely to reach the bottom of injection wells at a colder temperature than that of the storage formation, causing cooling of the rock. This cooling, together with overpressure, tends to open up fractures, which may enhance injectivity. We investigate cooling effects on injectivity enhancement by modeling the In Salah CO 2 storage site and a theoretical, long-term injection case. We use stress-dependent permeability functions that predict an increase in permeability as the effective stress acting normal to fractures decreases. Normal effective stress can decrease either due to overpressure or cooling. We calibrate our In Salah model, which includes a fracture zone perpendicular to the well, obtaining a good fitting with the injection pressure measured at KB-502 and the rapid CO 2 breakthrough that occurred at the observation well KB-5 located 2 km away from the injection well. CO 2 preferentially advances through the fracture zone, which becomes two orders of magnitude more permeable than the rest of the reservoir. Nevertheless, the effect of cooling on the long-term injectivity enhancement is limited in pressure dominated storage sites, like at In Salah, because most of the permeability enhancement is due to overpressure. However, thermal effects enhance injectivity in cooling dominated storage sites, which may decrease the injection pressure by 20 %, saving a significant amount of compression energy all over the duration of storage projects. Overall, our simulation results show that cooling has the potential to enhance injectivity in fractured reservoirs.

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Optimization of a CO2 storage project based on thermal, geomechanical and induced fracturing effects

Cited by 44 publications

References 25 publications

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

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

The role of the stress regime on microseismicity induced by overpressure and cooling in geologic carbon storage

Long-term thermal effects on injectivity evolution during CO2 storage

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Optimization of a CO2 storage project based on thermal, geomechanical and induced fracturing effects

Cited by 44 publications

References 25 publications

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

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

The role of the stress regime on microseismicity induced by overpressure and cooling in geologic carbon storage

Long-term thermal effects on injectivity evolution during CO2 storage

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Product

Resources

About

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

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