Effective Wettability Measurements of CO2-brine-Sandstone System at Different Reservoir Conditions

Al-Menhali, Ali; Krevor, Samuel

doi:10.1016/j.egypro.2014.11.572

Cited by 15 publications

(7 citation statements)

References 14 publications

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“…Rock wettability in brine-CO 2 systems affects the efficiency of the CO 2 injection process, the flow and distribution of fluids within the pore space, and the trapping capacity during CO 2 storage (Al-Menhali and Krevor, 2014). The wetting phase (brine) occupies the smallest pores while the non-wetting phase (CO 2 ) remains in the largest cavities (Dullien, 1992).…”

Section: Introductionmentioning

confidence: 99%

Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

Muñoz‐Ibáñez

Falcón-Suarez

Marín‐Moreno

et al. 2020

Journal of Petroleum Science and Engineering

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CO 2 storage in fractured reservoirs may lead to fast CO 2 flow through interconnected fracture networks; but the role of isolated fractures on brine-CO 2 multiphase flow systems remains unclear. We present the results of a brine-CO 2 flow-through experiment in which we assess the change in transport properties of a synthetic sandstone plug (a surrogate of a saline siliciclastic CO 2 reservoir) containing non-connected fractures aligned 45 � from its axis. The test was performed at 40 MPa of constant hydrostatic confining pressure and ~11 MPa of pore pressure, at room temperature (~19.5 � C), using pure liquid-CO 2 and 35 g L À 1 NaCl salt solution. The injected CO 2-brine volume fraction was increased from 0 to 1 in 0.2 units-steps (drainage). Upon achievement of the maximum CO 2 saturation (S CO2 ~0.6), the plug was flushed-back with the original brine (imbibition). During the test, we monitored simultaneously pore pressure, temperature, axial and radial strains, and bulk electrical resistivity. The fractured sample showed lower values of cross-and end-points in the relative permeability curves to CO 2 compared to non-fractured samples, from comparable experiments performed at similar pressure and brine salinity conditions, but different temperature. Our results suggest that a non-connected fracture network affects the mobility of the individual phases, favouring the trapping of CO 2 in the porous medium and improving the storage efficiency of the reservoir. These evidences show the need of a better understanding of fracture connectivity prior to discard fractured reservoirs as unsuitable geological formations for CO 2 storage.

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Section: Introductionmentioning

confidence: 99%

Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

Muñoz‐Ibáñez

Falcón-Suarez

Marín‐Moreno

et al. 2020

Journal of Petroleum Science and Engineering

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“…Any change in subsurface conditions of pressure and temperature will have a significant impact on the interfacial interactions (Espinoza and Santamarina, 2010;Liu et al;Plug and Bruining, 2007;Yang et al, 2007), the viscous forces due to the change in viscosity (Bachu and Bennion, 2008b) and the capillary forces. The change in interfacial interactions, and viscous and capillary forces due to the change in underground conditions will have a considerable influence on the capillary pressure, relative permeability (Alkan et al, 2010), pore-scale fluid distribution (Al-Menhali and Krevor, 2014), CO2 injection, fluid migration, capacity and long-term fate of CO2 storage in saline aquifers (Levine et al, 2011;Saraji et al, 2013;Wang et al, 2015), CO2-enhanced oil and gas recovery processes (Gozalpour et al, 2005;Qi et al, 2010). According to Salimi et al, the change in capillary pressure, due to the change in the operational conditions, can have a direct influence the CO2-storage capacity and the heat recovery due to its impact on the solubility and density of both CO2 and water (Salimi et al, 2012).…”

Section: Introductionmentioning

confidence: 99%

“…On the other hand, much less laboratory investigations have been done for CO2-water (brine) systems (Perrin and Benson, 2010). Those published have mainly focused on CO2 wettability (Al-Menhali and Krevor, 2014;Bikkina, 2011;Farokhpoor et al, 2013a;Kaveh et al, 2012;Sakurovs and Lavrencic, 2011;Saraji et al, 2013), CO2-water (brine) interfacial tension (Aggelopoulos et al, 2010;Bennion, 2008b, 2009;Busch and Müller, 2011;Chiquet et al, 2007;Li et al, 2012;Yu et al, 2012), relative permeability (Bachu, 2013;Krevor et al, 2015;Liu et al;Perrin et al, 2009) and capillary pressure (Busch and Müller, 2011;Pini et al, 2012;Plug and Bruining, 2007). Cinar and Riaz showed that much of the research has been directed to investigate the fluid properties rather than studying the multiphase flow properties of the CO2-water systems (Cinar and Riaz, 2014).…”

Section: Introductionmentioning

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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“…Despite its importance, the multiphase flow properties of CO2-water (brine) systems are poorly investigated in comparison to CO2oil systems (Bahralolom et al, 1988;Perrin and Benson, 2010). Our literature review shows a large research effort has been allocated to CO2 wettability (Al-Menhali and Krevor, 2014;Bikkina, 2011;Farokhpoor et al, 2013a;Kaveh et al, 2012;Li, 2015;Sakurovs and Lavrencic, 2011;Saraji et al, 2013;Yang et al, 2007) and CO2 interfacial tension (Aggelopoulos et al, 2010;Bennion, 2008, 2009;Busch and Müller, 2011;Chiquet et al, 2007;Li et al, 2012;Yu et al, 2012). Cinar and Riaz in their literature review pointed out the need to more investigations on multiphase flow characteristics of CO2-(water) brine-solid systems (Cinar and Riaz, 2014).…”

Section: Introductionmentioning

confidence: 99%

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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Effective Wettability Measurements of CO2-brine-Sandstone System at Different Reservoir Conditions

Cited by 15 publications

References 14 publications

Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

Gaseous CO2 behaviour during water displacement in a sandstone core sample

Supercritical CO2 behaviour during water displacement in a sandstone core sample

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