Effects of salinity and alkaline concentration on the spontaneous imbibition behaviour and rock properties of some shale rocks

Abstract

Waterflooding performance in naturally fractured reservoirs depends on spontaneous imbibition of brine into the rock matrix and expulsion of oil via the fracture face. This paper is to investigate water imbibition characteristics into different shale formations. Distilled water, 2% KCl brine, 30% KCl brine, and high pH alkaline solutions (pH 11.78-13) were examined to recover oil from different shale formations. During the spontaneous imbibition, the maximum oil recovery was 59% for Mancos using distilled water, 44% for Eagle Ford using 2 wt% NaOH in distilled water, 24% for Barnett using distilled water, and 4% for Marcellus using 2 wt% NaOH and 2 wt% KCl. The higher oil recoveries of Mancos samples were correlated with clay swelling in distilled water. More oil was recovered when Eagle Ford cores exposed to NaOH solutions due to favourable mineral dissolution. On the other hand, Barnett was partially damaged when exposed to higher alkaline solutions (2 wt% NaOH), and Marcellus did allow any fluid imbibition. Alkaline solutions were able to alter shale rock wettability to strongly water wet. The rock hardness of the samples was significantly affected by alkaline solutions, which resulted in 50-98% loss of its initial value.