Imbibition characteristics of Marcellus shale formation

In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition was performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was investigated using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HC1 solutions (0.74-1.2), and high pH alkaline solutions (11.78-12.4) were examined to recover oil from shale rocks. Outcrop samples from Marcellus shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 6%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Marcellus samples in distilled water, 2 wt% KCl, low pH solutions (0.74-1.2), and high pH alkaline solutions (11.78-12.43). During the spontaneous imbibition, the maximum oil recovery was 4% using low pH solution of pH0.74 (3 wt% HCl in 2 wt% KC1 base brine solution) or high pH solutions (pH 11.9 and pH12.4). There was no difference between the oil recoveries achieved by distilled or 2 wt% KC1 solution which might indicate that Marcellus shale is not sensitive to salinity. Oil recoveries from Marcellus shale slightly improved when using low or high pH solutions due to wettability alteration that has been supported by the changes in the measured contact angles before and after exposure to such solutions. The rock hardness of Marcellus samples was significantly affected by using both high and low pH solutions, which resulted in 55-94% loss of its initial value using low pH solutions and 50-68% when using high pH solutions.