Investigation of the Key Parameters Affecting Wettability of a Brazilian Pre-Salt Crude Oil and Brine on Pure Minerals Through Statistical Analysis

Abstract

Wettability is a fundamental property that defines the fluid's distribution in oil reservoirs. Assessing wettability is required to model flow in porous media. Nevertheless, it involves complex intermolecular and surface forces. Contact angle measurement is a quantitative method to determine wettability. However, rock samples must be prepared to assure results representative of reservoir conditions. This work applies statistical analysis to investigate the relevance of variables involved in sample preparation (aging time, solvent used to remove the excess oil from the surface) and mineral type on the wettability of oil and brine from a Pre-Salt field on pure minerals. Since there is limited experimental wettability data at Pre-Salt conditions, this work aims to assist filling this gap. The results showed aging time and mineral type as the most important parameters for analysis. Furthermore, authors found that greater aging time in oil and point of zero charge of the mineral lead to a more oil-wet behavior.

Wettability alteration of oil‐wet carbonate rocks by chitosan derivatives for application in enhanced oil recovery

“…In addition, temperature, pressure, and the aging time of the reservoir's rocks with crude oil also have a significant influence on the EOR additive performance. [59][60][61] Although the literature shows that low-salinity systems are capable of decreasing the residual oil content, the flooding with just brine in the solution presented a poor performance, demonstrating the need for the implementation of an EOR process. 44 The chitosan derivatives were able to satisfactorily increase the residual oil recovery factor in the porous medium experiment.…”

Fe3O4 Nanoparticles as Surfactant Carriers for Enhanced Oil Recovery and Scale Prevention

“…It is worth mentioning that flooding tests in an unconsolidated porous medium often show higher recovery factors than those from reservoir flooding since the pore size and permeability in the unconsolidated medium are significantly higher. 48,49 Additionally, temperature, pressure, and the aging time of the reservoir's rocks with crude oil also have a significant influence on nanofluid performance. 48,49 Nanofluid Stability and Efficiency in a High-Saline Medium.…”

“…48,49 Additionally, temperature, pressure, and the aging time of the reservoir's rocks with crude oil also have a significant influence on nanofluid performance. 48,49 Nanofluid Stability and Efficiency in a High-Saline Medium. Most of the oil reservoirs recently discovered in Brazil are formed by carbonate rocks and are located below a salt layer, in the presalt region.…”

“…The increase in tertiary oil recovery when the nanofluid was used can be related to its efficiency to remove asphaltenes from the rock surface modifying its wettability due to the disjoining pressure caused by the Mag NP and the interfacial tension decrease promoted by CTAB. It is worth mentioning that flooding tests in an unconsolidated porous medium often show higher recovery factors than those from reservoir flooding since the pore size and permeability in the unconsolidated medium are significantly higher. , Additionally, temperature, pressure, and the aging time of the reservoir’s rocks with crude oil also have a significant influence on nanofluid performance. , …”

Surface functionalized Fe3O4‐polyacrylamide dispersion for improved oil recovery at harsh conditions

“…This increase in oil recovery could be due to the dispersion effect in reducing fluids deposition from the rock surface by altering the wettability and decreasing the interfacial tension. 89,90 Moreover, the presence of a negative charge on the surface of SMag-NPs from the citrate groups results in mutual attraction with the positively charged surface on the PAM molecules, which reduces the tendency of particle retention on the rock surface. Consequently, it leads to higher oil recovery by SMag-NPs-PAM than those from PAM and IO-NPs-PAM.…”