Waterflooding is the cheapest and most profitable secondary recovery method that has been used for more than seventy years for conventional oil reservoirs. However, few studies have been done on its viability on unconventional tight formations especially shales. The objective of this study is to investigate the potential of water imbibition in different shale formations. In this study, fresh water, water with different salinities, and high pH alkaline solutions were examined to recover oil from different shale formations. Reservoir core samples from Eagle Ford and outcrop samples from Mancos, Barnett, and Marcellus shales 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. First, we studied the porosity of samples using helium porosimeter, weight difference, and CT Scanning. The average porosity was 3.4% for Mancos, 2% for Eagle Ford, 2.6% for Marcellus, and 7.7% for Barnett shale samples. Second, we studied the rock stability and spontaneous imbibtion of the different used samples in fresh water, different saline solutions (5-15 eq wt% of NaCl and KCl), and high pH alkaline solutions (0.1-2 wt% NaOH). During the spontaneous imbibition, the maximum oil recovery was 59% for Mancos using fresh water, 44% for Eagle Ford using 2 wt% NaOH and fresh water, 24% for Barnett using fresh water, and 4% for Marcellus using 2 wt% NaOH and 2 eq wt% of KCl. The Mancos shale samples were very sensitive to low water salinity (0-15 eq wt %) compared with the other shales. The higher oil recoveries of Mancos samples were positively correlated with clay swelling in fresh water and low saline solutions. Eagle Ford recovered more oil when exposed to NaOH solutions due to favorable mineral dissolution without affecting the cores' stability. On the other hand, Barnett was partially damaged when exposed to higher alkaline solutions (2 wt% NaOH) and Marcellus was very tight to allow any fluid imbibition. Collectively, our study showed a great potential of waterflooding in unconventional shale reservoirs.

Matrix acidizing is typically used to remove drilling and completion damage to reservoir conductivity around the wellbore and dissolve calcite in natural fractures. Despite being a common procedure, few studies have investigated the effect of matrix acidizing on the physical properties and oil recovery factors in shales. This paper describes the effect of HCl treatment on porosity, spontaneous imbibition, and crack distribution in samples from the Eagle Ford, Mancos, Barnett and Marcellus shale formations. Samples measuring 2.54-3.81 cm in diameter and 2.54-5.08 cm in length were exposed to acid with concentrations between 0.8-3% active HCl (4 and 15% of 20% diluted HCl). Active acid concentrations of 0.8% were optimal for balancing enhanced oil recovery while maintaining samples structural stability and integrity. The Pre and post HCl treated samples were saturated with Soltrol 130 TM . Oil recovery was determined by measuring the quantities of oil displaced by uptake of saline water. Recovery factors for Mancos and Eagle Ford shale samples improved from 4 and 16% for non-treated samples to 36 and 71% for the treated samples. In contrast, no change in Barnett and Marcellus shale recovery factors were observed. Porosities were calculated using X-ray computed tomography (CT-scanning). Average porosities prior to acid treatment were 1.6 -3.7% versus 1.6-10.7% after acid treatment. The CT-scanning studies of treated samples also shows that in the Mancos shale randomly oriented cracks developed, while in the Barnett and Marcellus shales cracks developed along bedding planes; very little crack development was observed in Eagle Ford shales. These results are encouraging for the application of matrix acidizing in shale formations to improve microfractures conductivity at distances along strike from the wellbore. Pre HCl Post 3% Active HCl Post 3% Active HCl Pre HCl Post 3% Active HCl Pre HCl Post 3% Active HCl Pre HCl