Hydro-thermo-mechanical analysis during injection of cold fluid into a geologic formation

Kim, Seung-Hee; Hosseini, Seyyed A.

doi:10.1016/j.ijrmms.2015.04.010

Cited by 57 publications

(14 citation statements)

References 28 publications

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“…For instance, even though the injection of cold water will give rise to a somewhat different shape of the cooled region due to the buoyancy and the lower thermal conductivity of CO 2 , the effective stress changes will be similar in both cases. This similarity can be seen by comparing the results of Kim & Hosseini () for cold water injection with those of this study. Therefore, the implications of this study on how cooling affects fracture stability, and thus microseismicity, depending on the existing stress regime can be generalized to fluids different from CO 2 .…”

Section: Discussionsupporting

confidence: 82%

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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Section: Discussionsupporting

confidence: 82%

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

Vilarrasa

2016

Geofluids

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“…All analytical computations and numerical simulations in this manuscript assume isothermal fluid-injection conditions. Poroelastic analyses for nonisothermal conditions can be found elsewhere (e.g., single-phase fluid flow (De Simone et al, 2013;Goodarzi et al, 2010;Kim and Hosseini, 2015;Kim and Hosseini, 2014;Neuzil, 2003); two-phase fluid flow (Preisig and Prévost, 2011;Vilarrasa et al, 2014;Vilarrasa et al, 2013b)).…”

Section: Introductionmentioning

confidence: 99%

Study on the ratio of pore-pressure/stress changes during fluid injection and its implications for CO2 geologic storage

Kim

Hosseini

2017

Journal of Petroleum Science and Engineering

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The success of fluid injection into geological formations, which is the main operation during both carbon dioxide (CO 2 ) geologic storage and wastewater injection, is contingent on the geomechanical integrity of the site. A key task that allows us to evaluate the risk of geomechanical failure is the precise prediction of pore-pressure buildup and subsequent change in the state of stresses during and after the fluid injection. Contrary to traditional approaches, where total stresses are assumed to remain constant, recent studies have ascertained that total stresses in fact change in every direction as fluid extraction/injection disturbs the pore-pressure field and causes deformations. In this study, we conduct an in-depth investigation of the ratio of change in total stress to that in pore-pressure, ∆ζ/∆P, which has been denoted in the literature as the pore-pressure/stress coupling. We employ a numerical simulation method that couples singlephase fluid flow in porous media with poroelasticity to explore the spatiotemporal evolution of the ∆ζ/∆P ratio for various conditions. These numerical experiments allow us to examine how different material properties and structural geometries would influence the evolution of ∆ζ/∆P in both vertical and horizontal directions. These ratios of pore-pressure/stress changes exhibit different spatiotemporal evolutions depending on key factors that include the hydraulic boundary condition, Biot's coefficient, Poisson's ratio, and the hydraulic diffusivity of both the injection zone and caprock. On the basis of observations, we suggest firsthand guidelines for analytically determining the ratio of pore-pressure/stress changes, ∆ζ/∆P. Finally, we use examples and case studies to illustrate how the ∆ζ/∆P ratio can be incorporated into an analytic calculation for determining a maximum sustainable pressure limit.3

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“…Injected CO 2 is usually colder than the reservoir. This causes thermal contraction and thermal stress [7,8]. When high pressure CO 2 is injected into the low pressure reservoir, the CO 2 expands, causing further temperature drop due to Joule-Thomson cooling.…”

Section: Introductionmentioning

confidence: 99%

Coupled hydro-thermal-mechanical analysis for cold CO2 injection into a deep saline aquifer

Wang

et al. 2019

THERM SCI

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Original scientific paper https://doi.org/10.2298/TSCI180511127WThis study investigated the thermal effects of thermal stress and Joule-Thomson cooling on CO 2 migration in a deep saline aquifer through a hydro-thermal-mechanical model. Firstly, the temperature variation of injected CO 2 was analyzed through the coupling of two-phase flow, deformation of porous medium and heat transfer with Joule-Thomson effect. Then, the effect of capillary entry pressure on CO 2 plume was numerically investigated and compared. It is found that injection temperature and Joule-Thomson effect can significantly affect the distributions of CO 2 mass and temperature, particularly in the upper zone near the injection well. The reduction of capillary entry pressure accelerates the upward migration of CO 2 plume and increases the CO 2 lateral migration distance.

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Hydro-thermo-mechanical analysis during injection of cold fluid into a geologic formation

Cited by 57 publications

References 28 publications

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

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

Study on the ratio of pore-pressure/stress changes during fluid injection and its implications for CO2 geologic storage

Coupled hydro-thermal-mechanical analysis for cold CO2 injection into a deep saline aquifer

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