Experimental Study of CO2 Injection Into Saline Formations

Cinar, Yildiray; Riaz, Amir

doi:10.2523/110628-ms

Cited by 30 publications

(48 citation statements)

References 0 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Carbon dioxide (CO 2 ) injection into geological formations, either for enhanced oil recovery or for CO 2 geological storage, triggers a complex cascade of interconnected events that may include CO 2 advection (Saripalli & McGrail 2002;Nordbotten et al 2005;Ennis-King & Paterson 2007), buoyancy (Bachu & Adams 2003;Bielinski et al 2008;Okwen et al 2010), convection of CO 2dissolved water (Weir et al 1996;Riaz et al 2006;Hassanzadeh et al 2007;Kneafsey & Pruess 2010), mutual diffusion and dissolution between CO 2 and the water phase and salt precipitation (Gaus et al 2005;Berne et al 2010;Espinoza & Santamarina 2010;Li et al 2011), viscous fingering of CO 2 (Homsy 1987;Fenghour et al 1998;Cinar et al 2009), and capillary trapping of the CO 2 phase by the water-saturated porous formation (Juanes et al 2006;Kopp et al 2009;Saadatpoor et al 2009;Kim 2012). Furthermore, water acidification follows CO 2 dissolution and triggers reactions with minerals in the formation as well as with the cement around wells (Li et al 2008;Solomon et al 2008;Szymczak & Ladd 2009;Espinoza et al 2011).…”

Section: Introductionmentioning

confidence: 99%

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO₂geologic storage

Kim

Santamarina

2015

Geofluids

View full text Add to dashboard Cite

Water acidification follows CO2 injection and leads to reactive fluid transport through pores and rock fractures, with potential implications to reservoirs and wells in CO2 geologic storage and enhanced oil recovery. Kinetic rate laws for dissolution reactions in calcite and anorthite are combined with the Navier‐Stokes law and advection–diffusion transport to perform geometry‐coupled numerical simulations in order to study the evolution of chemical reactions, species concentration, and fracture morphology. Results are summarized as a function of two dimensionless parameters: the Damköhler number Da which is the ratio between advection and reaction times, and the transverse Peclet number Pe defined as the ratio between the time for diffusion across the fracture and the time for advection along the fracture. Reactant species are readily consumed near the inlet in a carbonate reservoir when the flow velocity is low (low transverse Peclet number and Da > 10−1). At high flow velocities, diffusion fails to homogenize the concentration field across the fracture (high transverse Peclet number Pe > 10−1). When the reaction rate is low as in anorthite reservoirs (Da < 10−1), reactant species are more readily transported toward the outlet. At a given Peclet number, a lower Damköhler number causes the flow channel to experience a more uniform aperture enlargement along the length of the fracture. When the length‐to‐aperture ratio is sufficiently large, say l/d > 30, the system response resembles the solution for 1D reactive fluid transport. A decreased length‐to‐aperture ratio slows the diffusive transport of reactant species to the mineral fracture surface, and analyses of fracture networks must take into consideration both the length and slenderness of individual fractures in addition to Pe and Da numbers.

show abstract

Section: Introductionmentioning

confidence: 99%

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO₂geologic storage

Kim

Santamarina

2015

Geofluids

View full text Add to dashboard Cite

show abstract

“…However, the numerical methods based on the continuum description are insufficient to consider the influence of pore-scale parameters on the macroscopic bulk properties and, hence, the details of fingering pattern in the porous media cannot be resolved. 8 Statistical models, i.e., Invasion Percolation (IP), Diffusion-Limited Aggregation (DLA), and anti-DLA, are able to describe certain "specialized" displacement regimes, but they cannot capture transitions from one regime to another. 6,9 The lattice Boltzmann method (LBM) has been developed as an attractive and promising numerical tool for pore-scale simulation of multiphase flows in porous media.…”

Section: Introductionmentioning

confidence: 99%

Lattice Boltzmann simulation of immiscible fluid displacement in porous media: Homogeneous versus heterogeneous pore network

2015

View full text Add to dashboard Cite

Injection of anthropogenic carbon dioxide (CO 2 ) into geological formations is a promising approach to reduce greenhouse gas emissions into the atmosphere. Predicting the amount of CO 2 that can be captured and its long-term storage stability in subsurface requires a fundamental understanding of multiphase displacement phenomena at the pore scale. In this paper, the lattice Boltzmann method is employed to simulate the immiscible displacement of a wetting fluid by a non-wetting one in two microfluidic flow cells, one with a homogeneous pore network and the other with a randomly heterogeneous pore network. We have identified three different displacement patterns, namely, stable displacement, capillary fingering, and viscous fingering, all of which are strongly dependent upon the capillary number (Ca), viscosity ratio (M), and the media heterogeneity. The non-wetting fluid saturation (S nw ) is found to increase nearly linearly with log Ca for each constant M. Increasing M (viscosity ratio of non-wetting fluid to wetting fluid) or decreasing the media heterogeneity can enhance the stability of the displacement process, resulting in an increase in S nw . In either pore networks, the specific interfacial length is linearly proportional to S nw during drainage with equal proportionality constant for all cases excluding those revealing considerable viscous fingering. Our numerical results confirm the previous experimental finding that the steady state specific interfacial length exhibits a linear dependence on S nw for either favorable (M ≥ 1) or unfavorable (M < 1) displacement, and the slope is slightly higher for the unfavorable displacement. C 2015 Author(s). All article content, except where otherwise noted, is licensed under a Creative Commons Attribution 3.0 Unported License. [http://dx

show abstract

“…Such unstable interfaces are important in applications, significantly for sugar refining, oil recovery, hydrology and carbon sequestration [2][3][4][5][6] and much recent work has focused on how to control the instabilities [7][8][9][10] . Viscous fingering plays a central role in our understanding of pattern formation in part because it is amenable to both theory and experiment 1,6,[11][12][13][14] .…”

mentioning

confidence: 99%

Fingering versus stability in the limit of zero interfacial tension

2014

View full text Add to dashboard Cite

The invasion of one fluid into another of higher viscosity in a quasi-two dimensional geometry typically produces complex fingering patterns. Because interfacial tension suppresses short-wavelength fluctuations, its elimination by using pairs of miscible fluids would suggest an instability producing highly ramified singular structures. Previous studies focused on wavelength selection at the instability onset and overlooked the striking features appearing more globally. Here we investigate the non-linear growth that occurs after the instability has been fully established. We find a rich variety of patterns that are characterized by the viscosity ratio between the inner and the outer fluid, Z in /Z out , as distinct from the mostunstable wavelength, which determines the onset of the instability. As Z in /Z out increases, a regime dominated by long highly-branched fractal fingers gives way to one dominated by blunt stable structures characteristic of proportionate growth. Simultaneously, a central region of complete outer-fluid displacement grows until it encompasses the entire pattern at Z in /Z out E0.3.

show abstract

Experimental Study of CO2 Injection Into Saline Formations

Cited by 30 publications

References 0 publications

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO₂geologic storage

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO₂geologic storage

Lattice Boltzmann simulation of immiscible fluid displacement in porous media: Homogeneous versus heterogeneous pore network

Fingering versus stability in the limit of zero interfacial tension

Contact Info

Product

Resources

About

Experimental Study of CO2 Injection Into Saline Formations

Cited by 30 publications

References 0 publications

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO2geologic storage

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO2geologic storage

Lattice Boltzmann simulation of immiscible fluid displacement in porous media: Homogeneous versus heterogeneous pore network

Fingering versus stability in the limit of zero interfacial tension

Contact Info

Product

Resources

About

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO₂geologic storage

Geometry‐coupled reactive fluid transport at the fracture scale: application toCO₂geologic storage