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 low salinity water injection technique (LSWI) has become one of the important research topics in the oil industry because of its possible advantages for improving oil recovery. Several mechanisms describing the LSWI process have been suggested in the literature; however, there is no consensus on a single main mechanism for the low salinity effect on oil recovery. As a result of the latter, there are few models for LSWI and especially for carbonates due to their heterogeneity and complexity. In this research, we proposed a systematic approach for modeling the LSWI effect on oil recovery from carbonates by proposing six different methods for history matching and three different LSWI models for the UTCHEM simulator, empirical, fundamental, and mechanistic LSWI models. The empirical LSWI model uses contact angle measurements and injected water salinity. The fundamental LSWI model captures the effect of LSWI through the trapping number. In the mechanistic LSWI model, we include the effect of different geochemical reactions through Gibbs free energy. Moreover, field-scale predictions of LSWI were performed and followed by a sensitivity analysis for the most influential design parameters using design of experiment (DoE). The LSWI technique was also optimized using the response surface methodology (RSM) where a response surface was built. Also, we moved a step further by investigating the combined effect of injecting low salinity water and carbon dioxide on oil recovery from carbonates through modeling of the process and numerical simulations using the UTCOMP simulator. The analysis showed that CO₂ is the main controller of the residual oil saturation whereas the low salinity water boosts the oil production rate by increasing the oil relative permeability through wettability alteration towards a more water-wet state. In addition, geochemical modeling of LSWI only and the combined effect of LSWI and CO₂ were performed using both UTCHEM and PHREEQC upon which the geochemical model in UTCHEM was modified and validated against PHREEQC. Based on the geochemical interpretation of the LSWI technique, we believe that wettability alteration is the main contributor to the LSWI effect on oil recovery from carbonates by anhydrite dissolution and surface charge change through pH exceeding the point of zero charge. / text

La thèse a pour but d’étudier les effets de changements de mouillabilité de roches dans des conditions d’injections d’eau douce en tant que méthode de récupération d’hydrocarbures. Afin d’identifier le ou les mécanismes à l’origine du gain additionnel de récupération nous avons utilisé un microtomographe RX. Nous avons ainsi imagé les états de saturations finales d’un milieu poreux rempli de saumures et d’huiles. Une fois le drainage primaire réalisé nous avons effectué deux phases d’imbibitions : avec une saumure (récupération secondaire) puis une imbibition d’eau douce (récupération tertiaire). L’analyse de la mouillabilité à l’échelle du pore a permis de mettre en évidence l’effet de la température et de la salinité sur la mouillabilité. Nous avons montré que les changements de mouillages des roches n’étaient pas occasionnées par la seule expansion de la couche électrique en revanche des changements de mouillabilité ont été montrés. Ces changements s’expliquant par des transitions de mouillages de second ordre observées non seulement pour des gouttes d’huiles sur de l’eau mais également sur un substrat en verre. Au final, la mouillabilité en milieux poreux doit être mise en évidence à une échelle sous-Micrométrique ce qui est relativement nouveau dans le domaine pétrolier. / The aim of the thesis is to study rock wettability change effects caused by Low Salinity brine injection as tertiary recovery method. To identify the underlying mechanism or mechanisms of additional oil recovery X-Ray imaging technology was applied. We have also imaged the end-Point saturations of filled by brine and water core samples. Once the primary drainage is realized we carried out two phases imbibitions: with high salinity brine (waterflooding) and with low salinity brine (tertiary recovery mode). The wettability analysis at pore scale permitted to put in evidence the thermal and saline effects playing a decisive role in rock wettability. We have showed wettability changes are not caused by only electrical double layer expansion, however wettability changes was shown. These changes are explained by wettability transition of second order and observed not only for oil droplet on brine, but also for oil deposited on glass substrate. Finally, the pore space wettability needs to be evidenced at sub-Micrometric scale that is new for the petroleum domain.