Experimental studies on displacements of CO₂ in sandstone core samples

Abstract

CO2 sequestration is a promising strategy to reduce the emissions of CO2 concentration in the atmosphere, to enhance hydrocarbon production, and/or to extract geothermal heat. The target formations can be deep saline aquifers, abandoned or depleted hydrocarbon reservoirs, and/or coal bed seams or even deep oceanic waters. Thus, the potential formations for CO2 sequestration and EOR (enhanced oil recovery) projects can vary broadly in pressure and temperature conditions from deep and cold where CO2 can exist in a liquid state to shallow and warm where CO2 can exist in a gaseous state, and to deep and hot where CO2 can exist in a supercritical state. The injection, transport and displacement of CO2 in these formations involves the flow of CO2 in subsurface rocks which already contain water and/or oil, i.e. multiphase flow occurs. Deepening our understanding about multiphase flow characteristics will help us building models that can predict multiphase flow behaviour, designing sequestration and EOR programmes, and selecting appropriate formations for CO2 sequestration more accurately. However, multiphase flow in porous media is a complex process and mainly governed by the interfacial interactions between the injected CO2, formation water, and formation rock in host formation (e.g. interfacial tension, wettability, capillarity, and mass transfer across the interface), and by the capillary , viscous, buoyant, gravity, diffusive, and inertial forces; some of these forces can be neglected based on the rock-fluid properties and the configuration of the model investigated. The most influential forces are the capillary ones as they are responsible for the entrapment of about 70% of the total oil in place, which is left behind primary and secondary production processes. During CO2 injection in subsurface formations, at early stages, most of the injected CO2 (as a non-wetting phase) will displace the formation water/oil (as a wetting phase) in a drainage immiscible displacement. Later, the formation water/oil will push back the injected CO2 in an imbibition displacement. Generally, the main concern for most of the CO2 sequestration projects is the storage capacity and the security of the target formations, which directly influenced by the dynamic of CO2 flow within these formations. Any change in the state of the injected CO2 as well as the subsurface conditions (e.g. pressure, temperature, injection rate and its duration), properties of the injected and present fluids (e.g. brine composition and concentration, and viscosity and density), and properties of the rock formation (e.g. mineral composition, pore size distribution, porosity, permeability, and wettability) will have a direct impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have a direct influence on the injection, displacement, migration, storage capacity and integrity of CO2. Nevertheless, despite their high importance, investigations have widely overlooked the impact of CO2 the phase as well as the operational conditions on multiphase characteristics during CO2 geo-sequestration and CO2 enhanced oil recovery processes. In this PhD project, unsteady-state drainage and imbibition investigations have been performed under a gaseous, liquid, or supercritical CO2 condition to evaluate the significance of the effects that a number of important parameters (namely CO2 phase, fluid pressure, temperature, salinity, and CO2 injection rate) can have on the multiphase flow characteristics (such as differential pressure profile, production profile, displacement efficiency, and endpoint CO2 effective (relative) permeability). The study sheds more light on the impact of capillary and viscous forces on multiphase flow characteristics and shows the conditions when capillary or viscous forces dominate the flow. Up to date, there has been no such experimental data presented in the literature on the potential effects of these parameters on the multiphase flow characteristics when CO2 is injected into a gaseous, liquid, or supercritical state. The first main part of this research deals with gaseous, liquid, and supercritical CO2- water/brine drainage displacements. These displacements have been conducted by injecting CO2 into a water or brine-saturated sandstone core sample under either a gaseous, liquid or supercritical state. The results reveal a moderate to considerable impact of the fluid pressure, temperature, salinity and injection rate on the differential pressure profile, production profile, displacement efficiency, and endpoint CO2 effective (relative) permeability). The results show that the extent and the trend of the impact depend significantly on the state of the injected CO2. For gaseous CO2-water drainage displacements, the results showed that the extent of the impact of the experimental temperature and CO2 injection rate on multiphase flow characteristics, i.e. the differential pressure profile, production profile (i.e. cumulative produced volumes), endpoint relative permeability of CO2 (KrCO2) and residual water saturation (Swr) is a function of the associated fluid pressure. This indicates that for formations where CO2 can exist in a gaseous state, fluid pressure has more influence on multiphase flow characteristics in comparison to other parameters investigated. Overall, the increase in fluid pressure (40-70 bar), temperature (29-45 °C), and CO2 injection rate (0.1-2 ml/min) caused an increase in the differential pressure. The increase in differential pressure with increasing fluid pressure and injection rate indicate that viscous forces dominate the multi-phase flow. Nevertheless, increasing the differential pressure with temperature indicates that capillary forces dominate the multi-phase flow as viscous forces are expected to decrease with this increasing temperature. Capillary forces have a direct impact on the entry pressure and capillary number. Therefore, reducing the impact of capillary forces with increasing pressure and injection rate can ease the upward migration of CO2 (thereby, affecting the storage capacity and integrity of the sequestered CO2) and enhance displacement efficiency. On the other hand, increasing the impact of the capillary force with increasing temperature can result in a more secure storage of CO2 and a reduction in the displacement efficiency. Nevertheless, the change in pressure and temperature can also have a direct impact on storage capacity and security of CO2 due to their impact on density and hence on buoyancy forces. Thus, in order to decide the extent of change in storage capacity and security of CO2 with the change in the above-investigated parameters, a qualitative study is required to determine the size of the change in both capillary forces and buoyancy forces. The data showed a significant influence of the capillary forces on the pressure and production profiles. The capillary forces produced high oscillations in the pressure and production profiles while the increase in viscous forces impeded the appearance of these oscillations. The appearance and frequency of these oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents. The appearance of the oscillations can increase CO2 residual saturation due to the re-imbibition process accompanied with these oscillations, thereby increasing storage capacity and integrity of the injected CO2. The differential pressure required to open the blocked flow channels during these oscillations can be useful in calculating the largest effective pore diameters and hence the sealing efficiency of the rock. Swr was in ranges of 0.38-0.42 while KrCO2 was found to be less than 0.25 under our experimental conditions. Increasing fluid pressure, temperature, and CO2 injection rate resulted in an increase in the KrCO2, displacement efficiency (i.e. a reduction in the Swr), and cumulative produced volumes. For liquid CO2-water drainage displacements, the increase in fluid pressure (60-70 bar), CO2 injection rate (0.4-1ml/min) and salinity (1% NaCl, 5% NaCl, and 1% CaCl2) generated an increase in the differential pressure; the highest increase occurred with increasing the injection rate and the lowest with increasing the salinity. On the other hand, on the whole, increasing temperature (20-29 °C) led to a reduction in the differential pressure apart from the gradual increase occurred at the end of flooding. The data indicate that viscous forces dominate multiphase flow when fluid pressure, temperature and injection rate increased; however, as salinity increased, capillary forces dominant dominate the multiphase flow. Increasing the differential pressure with the slight increase in salinity indicates that capillary forces dominate the multi-phase flow as no practical change in viscous forces are expected to occur with this slight adding of salts to water. Increasing the impact of capillary forces impact with salinity can lead to an increase in the storage capacity and integrity of the injected CO2 but can cause a decrease in displacement efficiency. However, the reduction in CO2 solubility with increasing salinity can lead to a reduction in the storage capacity and security of CO2. Therefore, a quantitative study is required to determine the magnitude of change in CO2 storage capacity and security with salinity as a result of increasing capillary forces but reducing solubility. Swr was in ranges of 0.3062- 0.384 while KrCO2 was in ranges of 0.112-0.203. The Swr decreased with increasing fluid pressure and injection rate; the largest reduction occurred with the injection rate. The Swr increased with increasing temperature and water salinity; the largest increase occurred with salinity. The KrCO2 decreased with increasing fluid pressure, temperature, injection rate and salinity; the highest reduction occurred with increasing temperature whiles the lowest occurred with increasing fluid pressure. The cumulative produced volumes decreased slightly with increasing fluid pressure and salinity but showed no noticeable change with increasing temperature and injection rate. The reduction in the cumulative produced volumes with pressure and salinity might indicate an increase in the amount of the stored liquid CO2. For supercritical CO2-water displacements, the results revealed that the extent of the impact of each parameter (e.g. fluid pressure) on the differential pressure profile, cumulative produced volumes, Swr and KrCO2 is a function of the associated parameters (e.g. temperature and injection rate). Most importantly the data show that increasing pressure (74-90 bar) caused a considerable reduction in the differential pressure profile and a transformation of supercritical CO2 behaviour to a liquid-like CO2 behaviour; increasing temperature (33-55 °C), on the other hand, resulted in a significant increase in the differential pressure profile and a transformation of supercritical CO2 behaviour to a gaseous-like CO2 behaviour. Increasing the injection rate causes the transformation to a liquid-like CO2 behaviour to occur at lower pressure. The change observed in the differential pressure reflects the change in the capillary forces and viscous forces. The results suggest that multiphase flow was dominated by capillary forces as fluid pressure and temperature increased and by viscous forces as CO2 injection rate increased considerably. CO2 transformation to a liquid-like CO2 behaviour might enhance the displacement efficiency and upward migration of CO2, thereby reducing the storage capacity and disturbing the integrity of the CO2 sequestration projects. Swr was in ranges of 0.34 to 0.41 while KrCO2 was less than 0.37. The increase in the fluid pressure and injection rate (0.1-1 ml/min) caused a reduction in the Swr and a rise in the KrCO2. Increasing temperature caused an increase in the Swr; but, it a caused decline in the KrCO2 at high fluid pressures (90 bar) and an increase at lower fluid pressures (75 bar). The cumulative produced volumes decreased with increasing fluid pressure and increased with increasing temperature and injection rate. The second main section of this research deals with CO2-oil displacements that were performed under gaseous, liquid, and supercritical conditions to investigate the impact of fluid pressure, temperature, and CO2 injection rate as a function of the CO2 phase on the differential pressure profile, displacement efficiency, and CO2 endpoint effective and relative permeabilities. These displacements have been conducted by injecting CO2 into an oil-saturated sandstone core sample under either a gaseous, liquid or supercritical state. The results reveal a considerable impact for the fluid pressure, temperature, and injection rate on the differential pressure profile, cumulative produced volumes, endpoint CO2 relative permeability and oil recovery; the trend and the size of the changes are dependent on the CO2 state as well as the fluid pressure range in case of gaseous CO2-oil displacement. In general, liquid CO2-displacements gave the highest differential pressure magnitude. This indicates that a higher energy is required to produce oils from cold environments where CO2 can exist in a liquid state, e.g. West Sak reservoir. As fluid pressure increased, the differential pressure profile of subcritical CO2 (gaseous and liquid)-oil displacements increased while that of supercritical CO2-oil displacements decreased. The results indicate that viscous forces were dominant multiphase flow in subcritical CO2 displacements while capillary forces were dominant the in supercritical CO2 displacements. For reservoirs with supercritical CO2 conditions, the reduction in the differential with increasing pressure means maintaining the reservoir pressure at its highest possible level would result in reducing the energy loss, for the displacement of oil towards producing wells, to its lowest level. On the other hand, increasing temperature caused a reduction in the differential pressure of both subcritical and supercritical CO2-oil displacements while increasing injection rates caused an increase in the differential pressure profiles of these displacements. Moreover, increasing temperature caused the appearance of the differential pressure oscillations in that of gaseous and supercritical displacements but not in that of liquid CO2 displacements. With increasing temperature and CO2 injection rates, the viscous forces became more dominant than capillary forces in both subcritical and supercritical CO2 displacements. The appearance of oscillations with increasing temperature means that as temperature increases the residual trapping due to capillary forces increase. Consequently, a possible reduction in the reservoir temperature due to CO2 injection would result in reducing the impact of capillary forces, thereby increasing displacement efficiency. The significant increase in the differential pressure with increasing injection rate means a considerable reduction in the formation energy can occur as injection rate increases in multiphase flow flooding. Thus, an optimization evaluation is required to determine the optimum injection rate that leads to the highest increase in displacement efficiency and the least reduction in the reservoir energy. Swr was in ranges of around 0.44 to 0.7; liquid CO2 gave the lowest while low-fluid pressure gaseous CO2 gave the highest. KrCO2 during these oil displacements was in ranges of about 0.015 to 0.657; supercritical CO2 gave the highest while low-fluid pressure gaseous CO2 gave the lowest. The third main section of this research deals with water (brine)-CO2 imbibition displacements that were performed under gaseous, liquid, and supercritical conditions to investigate the impact of fluid pressure, temperature, and salinity as a function of the CO2 phase on the differential pressure profile, displacement efficiency, and endpoint effective and relative permeabilities. During these imbibition displacements, deionised water or brine solution (1 % wt. CaCl2) was injected to displace CO2 (as a gaseous, liquid, or supercritical state) from a Berea sandstone core sample. The results showed that the CO2 phase governs the magnitude of the changes observed in the differential pressure profile, endpoint water relative permeability and endpoint water saturation due to the variation in the fluid pressure, temperature, and salinity. Overall, the increase in the fluid pressure, and temperature as well as using of brine solution instead of deionised water caused a reduction in the differential pressure by around 4 to 36%. The magnitude of this reduction is dependent on the state of CO2; the largest reduction in the maximum-differential pressure occurred in liquid CO2 imbibition displacements. The reduction in the differential pressure with increasing pressure and temperature means as CO2 travels upward and hence pressure and temperature are reduced, then more and more energy is required to displace CO2 out of the system, which is preferable for a secure storage of CO2. The reduction of differential pressure with increasing salinity suggests that if the salinity of formation fluids is dropped (due to injection of large amounts of low salinity brine), then more energy is required for the displacement of CO2 out of the system, which is also preferable for CO2 security. Endpoint water relative permeability was in ranges of 0.174 to 0.711 while endpoint water (brine) saturation was in ranges of 0.55 to 0.94. The response of the endpoint water relative permeability and endpoint water saturation to increasing fluid pressure, experimental temperature, and salinity are dependent on the state of CO2. This study has not investigated the impact of gravity and buoyancy forces on the differential pressure profile and production profile while in reality their impact would be expected to be taken into consideration. Moreover, the range of pressure and temperature investigated might be of more interest for shallow formations. The brines investigated are of low concentrations while formation waters, in reality, have much higher concentrations. However, despite these limitations, the findings of this study would still provide deep and detail insight into the impact of the parameters investigated on multiphase flow characteristics, therefore, on injection, migration, displacement, storage capacity and security of CO2. The findings also shed more light on the impact of capillary and viscous forces on multiphase flow characteristics and showed the conditions when one of these forces are expected to dominate the flow. Due to the complexity of real reservoirs, some of the above observations might not be noticed or detected on a field scale. However, one way of upscaling the pressure data is to use the Leverett’s J-function which has been intensively used to convert all the capillary pressure (Pc) data, as a function of the invaded fluid saturation, to a universal curve. To have an idea about the expected impact of capillary and viscous forces on the pressure and production data of a target formation, the parameters that influence these forces of the target formation need to be known; these parameters include the interfacial tension, contact angle, permeability, porosity, and pore size distribution as well as viscosities and saturations of fluids.