After fracturing, only a small fraction of the fracturing fluid flows back into the well. The water invasion may induce a loss in hydrocarbon mobility, called water blocking. This phenomenon is expected to hinder hydrocarbon productivity but is contradicted by field observations where increased water invasion during soaking may lead to better hydrocarbon production. This paper presents a novel semi-analytic approach to quantitatively evaluate the trade-off between the potential hydrocarbon mobility reduction, water adsorption and counter-current flow production due to spontaneous imbibition. An analytic solution for spontaneous imbibition has been coupled with a fracture pore volume constraint to calculate the water invasion during soaking. The gravity segregation and resulting flowing area reduction in the fracture will cause higher decline of the imbibition rate compared with a 1D selfsimilar solution. In cases where the initial water saturation is below the mobile saturation, water adsorption due to the presence of clays controls the water invasion and the invasion occurs due to a combination of imbibition and adsorption while the relative permeability of hydrocarbon phase stays fairly constant. The blocking effect does not impact flow until the mobile water saturation is reached. The developed solution generates saturation profiles from which the apparent hydrocarbon mobility can be evaluated. The imbibition flux is compared with achievable viscous hydrocarbon flux based on the mobility calculation, and the cross-over of the two phenomena represents an optimal soaking time after which further imbibition would only damage the hydrocarbon productivity. The total backflow volume is translated into a compensation time for the production loss due to water blocking. The result shows the water invasion may even benefit production with proper control over the soaking period.
The horizontal well drilling and hydraulic fracturing technologies have made the economic production of natural gas from low permeability shale formations. A great amount of fracturing fluid is injected to create fractures so that the contact area of the wellbore with the reservoir can be significantly increased (Cheng, 2012). However, after the fracturing process, only small amount of the fracturing fluid is recovered as flowback and a significant amount of the injected fluid is lost to the formation (Longoria et al., 2017). With the water left inside the formation, mainly literature has studied the damage caused for hydrocarbon production. These concerns include but not limited to permeability damage and relative permeability damage caused by water invasion and gathering in the vicinity of the fracture surface (Tannich, 1975; Holditch, 1979; Abrams and Vinegar, 1985; Bostrom et al, 2014; Das el al., 2014). Our focus in this paper is going to be focused on the water blocking effect in terms of hydrocarbon relative permeability reduction and its impact on production.