Impact of Rock Aging Time on the Initial Wettability of Minerals and Analogue Rocks Using Pre-Salt Fluids Under Reservoir Conditions

Abstract

Wettability is an important property in reservoir characterization. For the heterogeneous carbonate reservoirs in the Brazilian Pre-Salt, parameters that represent wettability are needed to obtain improved reservoir models. In this work, we applied contact angle measurements to analyze rock-fluid interactions between synthetic brine, crude oil from a Pre-Salt field and rocks and minerals with similar characteristics to the Pre-Salt formations. We studied the effects of aging time on different solid substrates. We found that, even though unaged quartz showed greater interaction with the high basic number oil than carbonates, it re mained water-wet for different aging times. On the other hand, calcite and coquinas had increasing contact angles with aging times and were strongly oil-wet after 30 days aging. This evidences that the interactions between acid compounds in the oil and basic sites in the substrate are strong enough to disrupt the water film after aging for 30 days. Therefore, under the Pre-Salt conditions studied in this work, these carbonate rocks and minerals should be considered as preferentially oil-wet.

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.…”

Experimental determination of wetting behavior under non-atmospheric conditions relevant to reservoirs: a practical guide

“…Similar to Alnoush et al, they reported that contact angle decreases with increasing surface roughness in both high and low salinity brines, where the surface roughness impacted the contact angle in a subtler manner in the low salinity brine. Other important aspects to be considered are preconditioning of the solid surface [24,25] and ion interaction specifically with mineral surfaces [26]. Additionally, the drop size dependance of the contact angle needs to be considered.…”