Experimental and Numerical Study on Spontaneous Imbibition of Fracturing Fluids in Shale Gas Formation

Abstract

Abstract During some hydraulic fracturing processes, it is found that only 10% to 50% of fracturing fluids is recovered. This paper investigates how much of the remaining fracturing fluids are imbibed by shale rocks as a function of time, and also investigates the influence of various parameters on the imbibition process including: lithology, reservoir characteristics, and fluid properties. In addition, based on the experimental results, a numerical model is developed to estimate the amount and rate of spontaneous imbibition during fracturing over the entire fracture face. The rock samples are from the Horn River formation. The fracturing fluids used in the experiments include 2% KCL, 0.07% friction reducer and 2% KCL substitute. Distilled water is also used in experiments as control groups. Through spontaneous imbibition experiments, the relationships between imbibed weight of fluid and time show that the content of clay is the most important factor which affects the total amount imbibed. Shale matrix with high clay content can imbibe volume of fluid greater than its measured porous space because of the clay's strong ability to expand and hold water. Small porosity with less total organic carbon (TOC) results in the highest imbibed rate. Contact angle results show the stronger water wet shale samples have a faster imbibed rate. Temperature also influence amount of imbibition. The total imbibed volume decreases as the environment temperature rises. From this paper, it can help optimally design fracturing fluid for different conditions of shale formation to reduce fluid loss. We find that 2% KCL and 2% KCL substitute fracturing fluid are imbibed 10% to 40% less than 0.07% friction reducer in shale formation with high clay content; while in shale formation with low clay content, the opposite occurs. 0.07% friction reducer is imbibed 10% to 30% less than 2% KCL, but has similar imbibed amount with 2% KCL substitute. The numerical model results are matched with the experiment results in order to estimate relative permeability and initial water saturation in the model which can represent the properties of rocks. This model can use to estimate the total imbibed volume along fracture faces through spontaneous imbibition.