The extremely high salinity and ionic composition of the aqueous fluids present in oil reservoirs must be considered when developing surfactants and sterically stabilized nanomaterials for reservoir applications. At these harsh conditions, materials fail due to aggregation or heavy adsorption to rocks surfaces. Material losses due to rock adsorption are typically studied at the core scale, which provides important bulk information to inform injection and production decisions. These bulk measurements, however, do not provide direct information about the nanomaterial-rock interactions as a function of salinity or fluid composition. This presentation demonstrates a study of the adhesion of Atomic Force Microscopy (AFM) tips, both bare and carboxyl coated, to calcite as surrogates for nanomaterials and carbonate reservoir rock. The tip-calcite adhesion was studied in three high-salinity fluids: brine 1 (120K ppm TDS), brine 2 (60K ppm TDS), and calcium-doped brine 2a (~60K ppm TDS).  The results show that the amount of total dissolved solids was not a good predictor of the tip-sample adhesion.  Rather, tips submerged in brine with the highest TDS, produced the lowest adhesion to calcite and brine with the lowest TDS, the highest. In addition, doping brine 2 with calcium reduced the adhesion to level of that in brine 1. These observations suggest that the increased calcium binds to the hydroxyl and carboxyl groups on the AFM tips and effectively blocks tip binding to the exposed calcium on the calcite surface, thereby reducing adhesion. To complement the AFM measurements, Molecular Dynamics simulations have also been performed to test the above interpretation and will be discussed. It appears that adding calcium to injected brine can mitigate nanoparticle-rock adhesion and may allow better transport of nanoparticles through the reservoir for tracing or other functions.

Calcium-mediated adhesion in high salinity reservoir fluids

256th National Meeting (2018)

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