Ahmed M. Gomaa

Matrix Acidizing Characteristics in Shale Formations

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 acid on porosity, spontaneous imbibition, mechanical properties, and crack distribution in samples from the Eagle Ford, Mancos, Barnett and Marcellus shale formations. Some of the samples were completely immersed in different HCl solutions (1-3 wt%) at 93°C. We measured the porosity in both the acid-treated and non-treated samples. The treated and non-treated samples were then exposed to spontaneous water imbibition experiments to measure the improvement in oil recovery in both parallel and perpendicular to bedding planes. The mechanical properties of the acid-treated and non-treated samples were also measured in both parallel and perpendicular to bedding planes using the same acid concentrations. The samples were 2.54 and 3.81 cm in diameter and 2.54 to 5.08 cm in length. The measured porosities were 1-3% for the non-treated samples and 1.3-10.5% for the treated samples. We observed that the oil recovery factors of the spontaneous imbibition for the samples treated with acid were 47% from Eagle Ford, 53% from Mancos, 28% from Barnett, and 38% from Marcellus. The recovery factors from the non-treated samples were 12% from Eagle Ford, 4% from Mancos, 13% from Barnett, and 3% from Marcellus. Furthermore, we observed that spontaneous imbibition parallel to bedding planes is higher than imbibition in perpendicular to bedding planes direction, especially for Marcellus samples where the recovery factors varied from 4% for the samples drilled parallel to bedding planes to 38% for the samples drilled in perpendicular to bedding planes. Eagle Ford and Mancos samples showed a reduction in confining compressive strength ranging from 50- 60% when exposed to 3 wt% HCl solutions with more reduction in the samples drilled parallel to bedding planes.

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

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.