Migration of CO2 in Porous Media Filled with water.

Suekane, Tetsuya; Ishii, Toshihiro; Tsushima, Shoji; Hirai, Shuichiro

doi:10.1299/jtst.1.1

Cited by 28 publications

(11 citation statements)

References 17 publications

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“…Some of these forces can be neglected based on the rock-fluid properties and the configuration of the experimental model [20]. Changing CO 2 phase is likely to have a strong influence on capillary forces and viscous forces through its impact on the IFT between CO 2 and oil [28,29], the mass transfer at the interface, the wettability of the solid surface [30,31], and the viscosity and density of CO 2 [32,33]. Thus, the change in CO 2 state is likely to have a strong impact on the differential pressure across the sample, entry pressure, CO 2 injectivity, CO 2 displacement rate, CO 2 plume migration, CO 2 storage capacity, and CO 2 integrity as well as the efficiency of enhanced hydrocarbon recovery [22,34,35].…”

Section: Introductionmentioning

confidence: 99%

The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

Al-Zaidi

Fan

Edlmann

2018

Fluids

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CO 2 sequestration in saline aquifers and hydrocarbon reservoirs is a promising strategy to reduce CO 2 concentration in the atmosphere and/or enhance hydrocarbon production. Change in subsurface conditions of pressure and temperature and CO 2 state is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on the injection, migration, displacement, and storage capacity and integrity of CO 2 processes. In this study, an experimental investigation has been performed to explore the impact of fluid pressure, temperature, and injection rate, as a function of CO 2 phase, on the dynamic pressure evolution and the oil recovery performance of CO 2 during oil displacement in a Berea sandstone core sample. The results reveal a considerable impact of the fluid pressure, temperature, and injection rate on the differential pressure profile, cumulative produced volumes, endpoint CO 2 relative permeability, and oil recovery; the trend and the size of the changes depend on the CO 2 phase as well as the pressure range for gaseous CO 2-oil displacement. The residual oil saturation was in the range of around 0.44-0.7; liquid CO 2 gave the lowest, and low-fluid-pressure gaseous CO 2 gave the highest. The endpoint CO 2 relative permeability was in the range of about 0.015-0.657; supercritical CO 2 gave the highest, and low-pressure gaseous CO 2 gave the lowest. As for increasing fluid pressure, the results indicate that viscous forces were dominant in subcritical CO 2 displacements, while capillary forces were dominant in supercritical CO 2 displacements. As temperature and CO 2 injection rates increase, the viscous forces become more dominant than capillary forces.

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Section: Introductionmentioning

confidence: 99%

The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

Al-Zaidi

Fan

Edlmann

2018

Fluids

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“…Using the MRI technique, some studies were performed on the CO 2 -formation fluid displacement in porous media. Suekane et al (2005Suekane et al ( , 2006Suekane et al ( , 2009 b Fig. 2 3D saturation patterns (CO 2 in red/yellow), a unsaturated CO 2 -brine systems and b saturated CO 2 -brine systems.…”

Section: Mrimentioning

confidence: 99%

Simulation and visualization of the displacement between CO2 and formation fluids at pore-scale levels and its application to the recovery of shale gas

Hou

Gao

et al. 2016

Int J Coal Sci Technol

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This article reports recent developments and advances in the simulation of the CO 2 -formation fluid displacement behaviour at the pore scale of subsurface porous media. Roughly, there are three effective visualization approaches to detect and observe the CO 2 -formation fluid displacement mechanism at the micro-scale, namely, magnetic resonance imaging, X-ray computed tomography and fabricated micromodels, but they are not capable of investigating the displacement process at the nano-scale. Though a lab-on-chip approach for the direct visualization of the fluid flow behaviour in nanoscale channels has been developed using an advanced epi-fluorescence microscopy method combined with a nanofluidic chip, it is still a qualitative analysis method. The lattice Boltzmann method (LBM) can simulate the CO 2 displacement processes in a two-dimensional or three-dimensional (3D) pore structure, but until now, the CO 2 displacement mechanisms had not been thoroughly investigated and the 3D pore structure of real rock had not been directly taken into account in the simulation of the CO 2 displacement process. The status of research on the applications of CO 2 displacement to enhance shale gas recovery is also analyzed in this paper. The coupling of molecular dynamics and LBM in tandem is proposed to simulate the CO 2 -shale gas displacement process based on the 3D digital model of shale obtained from focused ion beams and scanning electron microscopy.

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“…Coalescence of the CO 2 emulsion is suggested because the average droplet diameter of the emulsion increases with time in the pore as shown in Figure 11.8a-c. The distribution of the CO 2 emulsion in sandstone also needs to be investigated with X-ray computed tomography [39] or MRI [40]. As shown in Figure 11.8a, the initial size of the emulsion droplet and its growth rate can be controlled by the surfactant concentration.…”

Section: Future Tasksmentioning

confidence: 99%