Field tests have demonstrated that oil production from sandstone reservoirs increases when injected water salinity is low, i.e. ∼1500 ppm total dissolved solids (TDS). In core plug tests performed at reservoir conditions, low salinity flooding has been responsible for incremental recoveries ranging from about 5 to 38%. Previous work has suggested that for the low salinity effect to manifest itself, the oil must contain polar components, the formation water must contain divalent cations and clay must be present in the reservoir, but a clear understanding of the mechanism, from fundamental chemical and physical principals, is still subject to debate.
In the work reported here, an atomic force microscope (AFM) has been used in force spectroscopy mode to investigate the nature and magnitude of the interaction between hydrocarbon molecules with carboxylic acid end groups and the pore surfaces of oil reservoir sandstones. By functionalizing the AFM tip with polar molecules we have been able to measure, quantitatively, the adhesion forces between these molecules and the mineral surfaces under 36,500 and 1500 ppm TDS artificial seawater (ASW) solutions.
Collecting these measurements in two-dimensional arrays, known as force maps, revealed that adhesion was highest on the quartz grain surfaces during exposure to the high salinity solutions and it decreased when salinity decreased in nearly all cases. The drop in adhesion was observed through several high to low salinity cycles. We interpreted certain small features that were visible on the quartz surfaces to be clay that had grown directly on the sand grains from solution during diagenesis. Adhesion on these clay surfaces also changed with modifications in salinity. We observed no difference in behaviour whether the sandstone was preserved or cleaned; both types of core demonstrated a clear low salinity response.