Hydromechanical Aspects of CO2 Breakthrough into Clay-rich Caprock

Makhnenko, Roman Y.; Vilarrasa, Víctor; Mylnikov, Danila; Laloui, Lyesse

doi:10.1016/j.egypro.2017.03.1453

Cited by 41 publications

(46 citation statements)

References 25 publications

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“…Natural brine that contains 6.13 g/L sodium chlorite (NaCl), 1.63 g/L sodium sulfate (Na 2 SO 4 ), 1 g/L of CaCl 2 .2H 2 O, and MgCl 2 .6H 2 O and traces of other chemical components (Pearson, ) is used as the pore fluid to minimize the chemical effect. Its bulk modulus K f is measured in a fluid pressure controller to be 2.0 GPa, slightly less than that of pure water (Makhnenko, Vilarrasa, et al, ).…”

Section: Experimental Methodsmentioning

confidence: 99%

Experimental Poroviscoelasticity of Common Sedimentary Rocks

Makhnenko

Podladchikov

2018

JGR Solid Earth

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The success of geoenergy applications such as petroleum recovery or geological storage of CO2 depends on properly addressing the physical coupling between the pore fluid diffusion and mechanical deformation of the subsurface rock. Constitutive models should include short‐term hydromechanical interactions and long‐term behavior and should incorporate the principles behind the mathematical models for poroelastic and poroviscoelastic responses. However, the viscous parameters in constitutive relationships still need to be validated and estimated. In this work, we experimentally quantify the time‐dependent response of fluid‐filled sedimentary rocks at room temperature and isotropic stress states. Drained, undrained, and unjacketed geomechanical tests are performed to measure the poroelastic parameters for Berea sandstone, Apulian limestone, clay‐rich material, and Opalinus clay (shale). A poroviscous model parameter, the bulk viscosity, is included in the constitutive relationships. The bulk viscosity is estimated under constant isotropic stress conditions from time‐dependent deformation of rock in the drained regime for timescales ~105 s and from observations of the pore pressure growth under undrained conditions at timescales of ~104 s. The bulk viscosity is on the order of 1015–1016 Pa s for sandstone, limestone, and shale and ~1013 Pa s for clay‐rich material, and it decreases with an increase in pore pressure despite a corresponding decrease in the effective stress. In the long term, fluid pressure can asymptotically approach minimum principal stress, which in natural reservoirs may lead to liquefaction or rock embrittlement, causing slip instabilities and earthquakes and creating high‐permeability channels in low‐permeable rock.

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Section: Experimental Methodsmentioning

confidence: 99%

Experimental Poroviscoelasticity of Common Sedimentary Rocks

Makhnenko

Podladchikov

2018

JGR Solid Earth

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“…The following properties are assumed to be the same for all the seven datasets. Length of the domain ( L ) is considered to be 500 m. Density difference between CO2 and brine ( w nw     = − ) is assumed to be 300 kg/m 3 and porosity (  ) is 0.2. Brine and CO2 viscosity are assumed to be 0.86 and 0.06 mPa•s, respectively.…”

Section: Interaction Of Gravity Capillary and Viscous Forcesmentioning

confidence: 99%

“…Trapping of carbon dioxide in saline aquifers can be broadly classified into structural/stratigraphic, residual, solubility, and mineral trapping mechanisms. Structural/stratigraphic trapping refers to the processes in which CO 2 is trapped in free phase under a geological structure such as an impermeable layer [3]. In this case, CO 2 could be mobile but trapped since an impermeable layer prevents upward migration of CO 2 .…”

Section: Introductionmentioning

confidence: 99%

Modeling of Carbon Dioxide Leakage from Storage Aquifers

Heidari

2018

Fluids

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Long-term geological storage of CO2 in deep saline aquifers offers the possibility of sustaining access to fossil fuels while reducing emissions. However, prior to implementation, associated risks of CO2 leakage need to be carefully addressed to ensure safety of storage. CO2 storage takes place by several trapping mechanisms that are active on different time scales. The injected CO2 may be trapped under an impermeable rock due to structural trapping. Over time, the contribution of capillary, solubility, and mineral trapping mechanisms come into play. Leaky faults and fractures provide pathways for CO2 to migrate upward toward shallower depths and reduce the effectiveness of storage. Therefore, understanding the transport processes and the impact of various forces such as viscous, capillary and gravity is necessary. In this study, a mechanistic model is developed to investigate the influence of the driving forces on CO2 migration through a water saturated leakage pathway. The developed numerical model is used to determine leakage characteristics for different rock formations from a potential CO2 storage site in central Alberta, Canada. The model allows for preliminary analysis of CO2 leakage and finds applications in screening and site selection for geological storage of CO2 in deep saline aquifers.

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“…An increasing amount of laboratory and modelling studies on the flow properties of mudstones in general, and more specifically fractures and faults in mudstones, is available in the literature (e.g. Kampman et al, 2014;Makhnenko et al, 2017). However, most studies focus on a subset of chemical or mechanical processes in the caprock that affect flow, whereas the potential leakage rates depend on the interplay between fluid pressure and stress regime, and mechanical and chemical interactions in fractures and faults.…”

Section: Approachmentioning

confidence: 99%

Quantifying The Risk Of CO2 Leakage Along Fractures Using An Integrated Experimental, Multiscale Modelling And Monitoring Approach

et al. 2018

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Existing CO2 storage sites have illustrated that intact low-permeability mudrocks are effective barriers to avoid upward migration of CO2 from the storage complex. However, widespread deployment of Carbon Capture and Storage (CCS) as a means of climate change mitigation requires gigaton-scale CCS, rather than the few current megaton projects, to be deployed near large point sources of CO2. In the future, geological storage sites with faulted caprocks cannot always be avoided. We therefore need to rigorously assess geological leakage risks for CCS and specifically improve our understanding of multi-phase fluid migration in faulted and fractured caprocks. The DETECT research program will provide new insights by integrating experimental characterization with multiscale modelling of the combined hydrochemical, hydromechanical and clay swelling and shrinking effects in faulted and fractured mudstones. The purpose of the models is to establish determine realistic flow rates across fractured and faulted mudstone caprocks, to identify existing monitoring tools capable of detecting such fluid migration. Based on these quantitative leakage scenarios, risk and mitigation bow-tie analyses are developed with which suitable and cost-effective monitoring tools can be identified.

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Hydromechanical Aspects of CO2 Breakthrough into Clay-rich Caprock

Cited by 41 publications

References 25 publications

Experimental Poroviscoelasticity of Common Sedimentary Rocks

Experimental Poroviscoelasticity of Common Sedimentary Rocks

Modeling of Carbon Dioxide Leakage from Storage Aquifers

Quantifying The Risk Of CO2 Leakage Along Fractures Using An Integrated Experimental, Multiscale Modelling And Monitoring Approach

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