Effect of CO2 phase on its water displacements in a sandstone core sample

Al-Zaidi, Ebraheam; Nash, J.H.; Fan, Xianfeng

doi:10.1016/j.ijggc.2018.01.018

Cited by 14 publications

(8 citation statements)

References 55 publications

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“…The data from Figure 1-2 show also that as the fluid pressure increased, the differential pressure profile of the ScCO2-water displacements transformed from the likeness of a gaseous CO2 behaviour to a liquid CO2 behaviour; this transformation occurs at lower-fluid pressures with increasing injection rate. For instance, the differential pressure profile of the 75 bar-experiment is very similar to that of a typical high-fluid pressure gaseous CO2-water displacement while that of 90 bar-experiment is virtually identical to that of a typical liquid CO2-water displacement (Al-Zaidi et al, 2018b). Increasing the CO2 injection rate from 0.1 to 0.4 ml/min caused the transition from a gaseous to liquid CO2 behaviour to occur at lower fluid pressure.…”

Section: Effect Of Fluid Pressure On the Differential Pressure Profilmentioning

confidence: 76%

“…To calculate the core sample pore volume and porosity, the core was saturated with deionized water and then the weight difference between the dry and the wet core sample was used. This study is one in a series, therefore, the core sample description, core sample setup and CO2-water displacements procedures can be found in Al-Zaidi et al (Al-Zaidi et al, 2018b).…”

Section: Methodsmentioning

confidence: 99%

“…Nonetheless, for the 0.4 ml/min-displacements, it started from 77 bar. The similarity to a gaseous or a liquid CO2 behaviour has been decided mainly on the rate of reduction in the differential pressure profile during early times of flooding; the gaseous CO2 displacements are characterized by a high-pressure drop at early stages while the liquid CO2 displacements are characterized by a slight drop (Al-Zaidi et al, 2018b). The transformation of the differential pressure profile at low pressures with increasing injection rate can be related to the increase in viscous pressure drop (with increasing injection rate) that leads to a reduction in the total pressure drop (as stated above); this, in turn, caused the appearance of the liquid CO2 like differential pressure profile, which is characterized by a gradual pressure drop at early stages.…”

Section: Effect Of Fluid Pressure On the Differential Pressure Profilmentioning

confidence: 99%

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Supercritical CO2 behaviour during water displacement in a sandstone core sample

Al-Zaidi

Fan

Edlmann

2018

International Journal of Greenhouse Gas Control

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CO2 injection into underground formations involves the flow of CO2 in subsurface rocks which already contain water. The flow of CO2 into the target formation is governed mainly by capillary forces, viscous forces and interfacial interactions. Any change in subsurface conditions of pressure and temperature during injection will have an impact on the capillary and viscous forces and the interfacial interactions, which, in turn, will have an influence the injection, displacement, migration, and storage capacity and security of CO2. In this study, an experimental investigation has been designed to explore the impact of fluid pressure (74-90 bar), temperature (33-55 °C), and injection rate (0.1-1 ml/min) on the dynamic pressure evolution and displacement efficiency when supercritical CO2 is injected into a water-saturated sandstone core sample. The study also highlights the impact of the capillary forces and viscous forces on the two-phase flow characteristics and shows the conditions where capillary forces or viscous forces become dominant. The authors are not aware of similar experimental studies conducted in the literature so far. The results revealed a moderate to considerable impact of the parameters investigated on the differential pressure profile, cumulative produced volumes, endpoint CO2 relative (effective) permeability and residual water saturation. The extent of the impact of each parameter (e.g. fluid pressure) was a function of the associated parameters (e.g. temperature and injection rate). Increasing fluid pressure caused the differential pressure profile of supercritical CO2water displacement to transform to the likeness of liquid CO2-water displacement, while, increasing temperature transforms it to the likeness of gaseous CO2-water displacement. Increasing fluid pressure caused a considerable reduction in the maximum and quasi-differential pressures, an increase in the endpoint CO2 relative permeability (KrCO2) and a reduction in the residual water saturation (Swr) and cumulative produced volumes. Overall, the impact of temperature is opposite to that of fluid pressure. However, with increasing temperature, the KrCO2 showed a declining trend at high-fluid pressures (90 bar) but an increasing trend at low-fluid pressures (75 bar). Increasing injection rate caused a considerable increase in the maximum and quasi-differential pressures, a rise in the KrCO2, a reduction in the Swr, and an increase in the cumulative produced volumes. The Swr was in range of 0.34-0.41 while KrCO2 was less than 0.37, depending on the operational conditions. Changing the operational conditions caused a higher impact on KrCO2 than that on Swr. The results indicate that capillary forces dominate the multiphase flow characteristics as fluid pressure and temperature are increased.

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Section: Effect Of Fluid Pressure On the Differential Pressure Profilmentioning

confidence: 76%

Section: Methodsmentioning

confidence: 99%

Section: Effect Of Fluid Pressure On the Differential Pressure Profilmentioning

confidence: 99%

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Supercritical CO2 behaviour during water displacement in a sandstone core sample

Al-Zaidi

Fan

Edlmann

2018

International Journal of Greenhouse Gas Control

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“…Previous work in this laboratory has also conducted non-Darcy flooding tests using supercritical CO 2 (hereafter scCO 2 ), confirming the permeability dependence of both the fluid and the rock properties (Choi et al, 2017). Experimental studies of core flooding using CO 2 have been undertaken to aid efforts to develop geological storage of CO 2 , although these were not non-Darcy flow tests (Al-Zaidi et al, 2018;Krevor et al, 2012;Valle et al, 2018;Wang et al, 2014). These studies focused mainly on relative permeability because of its influence on injection rate and migration of CO 2 during brine formation or enhanced oil recovery.…”

Section: Introductionmentioning

confidence: 76%

Estimation of the Non‐Darcy Coefficient Using Supercritical CO₂ and Various Sandstones

Choi

Song

2019

JGR Solid Earth

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Non-Darcy flow (also known as high-velocity flow, inertial flow, etc.) often occurs in the near-well region of a reservoir during injection or production. This flow needs to be characterized and its origins fully understood, as it is a critical factor in reducing well productivity. The Forchheimer equation, which describes fluid flow considering an inertial effect, can be adopted to analyze non-Darcy flow. In particular, the non-Darcy coefficient in the equation represents inertial resistance in a porous medium and is an empirical value that depends on the pore geometry and fluid properties. This study, as part of research on geological CO 2 storage, reports non-Darcy flow tests with a high flow rate and examines the non-Darcy coefficient by using supercritical CO 2 and various sandstones. The dependence of the coefficient on the properties of the supercritical CO 2 was also assessed in a series of non-Darcy tests under different pore pressures. The coefficient varied with the properties of the supercritical CO 2 and sandstone. As the permeability of sandstone increased, the non-Darcy coefficient decreased nonlinearly and converged to a value. The results also indicate that the coefficient is reduced with a decreasing ratio of density to viscosity for the supercritical CO 2 . An equation predicting the coefficient was derived, having the advantage that both the hydraulic properties of rock and the fluid properties can be considered simultaneously in a dimensionally correct analysis.

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“…The average porosity and absolute water permeability of the core sample were about 14% and 15.8 millidarcys, respectively. This study is one in a series, thus the core sample description, the experimental setup and the CO2-water displacement procedures can be seen in our recent publication (Al-Zaidi et al, 2018).…”

Section: Methodsmentioning

confidence: 99%

Gaseous CO2 behaviour during water displacement in a sandstone core sample

Al-Zaidi

Edlmann

Fan

2019

International Journal of Greenhouse Gas Control

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CO2 injection into subsurface formations involves the flow of CO2 through a porous medium that also contains water. The injection, displacement, migration, storage capacity and security of CO2 is controlled mainly by the interfacial interactions and capillary, viscous, and buoyancy forces which are directly influenced by changes in subsurface conditions of pressure and temperature; the impact of bouncy forces is assumed negligible during this study. In this study, gaseous CO2 is injected into a water-saturated sandstone core sample to explore the impact of fluid pressure (40-70 bar), temperature (29-45 °C), and CO2 injection rate (0.1-2 ml/min) on the dynamic pressure evolution and displacement efficiency. This study highlights the impact of capillary or viscous forces on the two-phase flow characteristics and shows the conditions where capillary or viscous forces become more influential. The results reveal a moderate to considerable impact of the parameters investigated on the differential pressure profile, endpoint CO2 relative permeability (KrCO2 max), and irreducible water saturation (Swr). Overall, the increase in fluid pressure, temperature, and CO2 injection rate cause an increase in the maximum and final differential pressures, an increase in the KrCO2 max , a reduction in the Swr. Swr was in the range of around 0.38-0.45 while KrCO2 max was less than 0.25. The data show a significant influence for the capillary forces on the pressure and production behaviour. The capillary forces produce high oscillations in the pressure and production data while the increase in viscous forces impedes the appearance of these oscillations. The appearance and frequency of the oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents.

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Effect of CO2 phase on its water displacements in a sandstone core sample

Cited by 14 publications

References 55 publications

Supercritical CO2 behaviour during water displacement in a sandstone core sample

Supercritical CO2 behaviour during water displacement in a sandstone core sample

Estimation of the Non‐Darcy Coefficient Using Supercritical CO₂ and Various Sandstones

Gaseous CO2 behaviour during water displacement in a sandstone core sample

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Effect of CO2 phase on its water displacements in a sandstone core sample

Cited by 14 publications

References 55 publications

Supercritical CO2 behaviour during water displacement in a sandstone core sample

Supercritical CO2 behaviour during water displacement in a sandstone core sample

Estimation of the Non‐Darcy Coefficient Using Supercritical CO2 and Various Sandstones

Gaseous CO2 behaviour during water displacement in a sandstone core sample

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Estimation of the Non‐Darcy Coefficient Using Supercritical CO₂ and Various Sandstones