The goal of this research was to study the effect of salinity on the waterflood of initially oil-wet clay-rich sand packs. Two one-foot long sand packs with 8% initial water saturation and 50% porosity were aged in crude oil for two weeks and flooded with either a low salinity (1000 ppm NaCl, pH 6.3) or a high salinity (20000 ppm CaCl, 20000 ppm MgCl, 20000 ppm NaCl, 20000 PPM KCl, pH 6.2) brine. 1D low salinity floods yield an incremental oil recovery of 15% and a significant change in the relative permeability. Initial breakthrough brine analysis showed that the low salinity flood results in more cation exchange activity compared to the high salinity case. A pH change of up to 1.4 point was witnessed for the high salinity case whereas the low salinity case had a 1.1 point pH change. The pH stayed below 7 in both low salinity and high salinity cases. The relative permeability of the low salinity case indicates a more water-wet state than that of the high salinity flood. The 2D study focused on capturing the movement of the water saturation fronts in transparent 2D sand packs via digital recordings. Two-dimensional sand packs of the oil-aged clay-rich sands were constructed in plastic quarter 5-spot models. Secondary water floods were performed. Low salinity flooding yielded higher oil recovery at breakthrough than the high salinity case. There was more areal bypassing in the case of low salinity flooding. It was difficult to pack the 2D cells uniformly which affected the water floods. / text

Injection of low-salinity water showed high potentials in improving oil recovery when compared to high-salinity water. However, the optimum water salinity and conditions are uncertain, due to the lack of understanding the mechanisms of fluid-rock interactions. The main objective of this study is to examine the potential and efficiency of low-salinity water in secondary and tertiary oil recovery for sandstone reservoirs. Similarly, this study aims to help in understanding the dominant mechanisms that aid in improving oil recovery by low-salinity waterflooding. Furthermore, the impact of cation type in injected brines on oil recovery was investigated. Coreflood experiments were conducted to determine the effect of water salinity and chemistry on oil recovery in the secondary and tertiary modes. The contact angle technique was used to study the impact of water salinity and composition on rock wettability. Moreover, the zeta potential at oil/brine and brine/rock interfaces was measured to explain the mechanism causing rock wettability alteration and improving oil recovery. Deionized water and different brines (from 500 to 174,000 mg/l), as well as single cation solutions were tested. Two types of crude oil with different properties and composition were used. Berea sandstone cores were utilized in the coreflood experiments. Coreflood tests indicated that injection of deionized water in the secondary mode resulted in significant oil recovery, up to 22% improvement, compared to seawater flooding. However, no more oil was recovered in the tertiary mode. In addition, injection of NaCl solution increased the oil recovery compared to injection of CaCl2 or MgCl2 at the same concentration. Contact angle results demonstrated that low-salinity water has an impact on the rock wettability; the more reduction in water salinity, the more a water-wet rock surface is produced. In addition, NaCl solutions made the rock more water-wet compared to CaCl2 or MgCl2 at the same concentration. Low-salinity water and NaCl solutions showed a highly negative charge at rock/brine and oil/brine interfaces by zeta potential measurements, which results in greater repulsive forces between the oil and rock surface. This leads to double-layer expansion and water-wet systems. These results demonstrate that the double-layer expansion is a primary mechanism of improving oil recovery when water chemical composition is manipulated.

Asphaltenic crude oil is a complex fluid containing various components with different chemical properties. When it comes in contact with water, its polar components adsorb at the oil/water interface, reducing the interfacial tension and eventually developing viscoelastic films. The interfacial films impact emulsion stability and adhere to the oil-bearing reservoirs rocks, altering their wettability and thus hindering oil mobilization. Here, we investigate the formation of crude oil/water interfacial films. We measure both the time-dependent shear and extensional interfacial rheology moduli, and we relate it to the chemical composition of the films, highlighting the role of polar aromatic molecules in film formation. Varying chemical composition of the aqueous phase, we show that the properties of the interfacial films depend not only on the concentration of ionic species in water but also on their chemical nature. In particular, we highlight the role of sulfate salt in promoting interfacial viscoelasticity and in altering the composition of fully developed films. To study the rock/fluid interaction, we fabricate mixed-wet capillaries with angular cross-sections inspired by the naturally occurring primary drainage of pore-filling brine by invading crude oil. After employing our novel coating procedure, we experimentally investigate water invasion in mixed-wet capillaries and compare it with predictions of dynamic and quasi-static (Mayer-Stowe-Princen (MSP)) meniscus-invasion models. None of the dynamic models built for uniformly-wet pores can fully describe our experimental data in mixed-wet capillaries. However, the experimental results agree with predictions of MSP theory. To our knowledge, this is the first direct experimental validation of MSP theory under mixed-wet conditions. We confirm the possibility of spontaneous piston-type imbibition with high ($> 90^{\circ}$) advancing contact angles into mixed-wet pores, given that the contact angle is lowered below a critical value that is a function of pore geometry and residual water saturation. In oil reservoirs, injection of specific brines would be required to change the contact angle to values below the imbibition threshold. Finally, we extend our study and introduce a powerful 3D high-speed laser imaging of dynamic fluid flow in angular capillaries and investigate its capability to capture non-equilibrium shapes of fluid interfaces.

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