Experimental Evaluation Of Fracturing Fluid Interaction With Tight Reservoir Rocks And Propped Fractures

Abstract

Abstract Prediction of gas well production after a Massive Hydraulic Fracture (MHF) treatment is essential for economic assessment of the planned stimulation. Present accepted techniques of predicting the Present accepted techniques of predicting the increase in production (stimulation ratio) are based on the estimated fracture dimension, well and reservoir properties. Fracturing fluid damage is not considered. This study demonstrates that when fracturing fluid damage is included in the stimulation ratio calculations, good agreement with actual post fracturing production can be achieved. Laboratory experiments at simulated in situ conditions (stress, temperature, saturation and fracturing treatment procedure) on actual core samples were performed procedure) on actual core samples were performed to assess fracturing fluid damage to both the matrix permeability and propped fracture conductivity; permeability and propped fracture conductivity; damage was found to be site specific. Laboratory data on cores from unconventional gas reservoirs in both the Eastern and Western parts of the U.S. are presented. The observed damage is identified and explained. Specific examples are presented and predicted production compared with postfracturing flow. Good agreement was obtained. postfracturing flow. Good agreement was obtained Introduction Since 1948, Massive Hydraulic Fracturing (MHF) has been presented as the solution to economically increase gas production from the relatively low pressure, low permeability reservoirs. Results to pressure, low permeability reservoirs. Results to date of MHF treatments vary from extremely successful to extremely disappointing failures. A number of studies over the years and a recent study of some 500 MHF suggests that the majority of the MHF failures result from not achieving "the necessary propped fracture geometry". Simply stated, these treatments failed to create large fractures of appropriate conductivity in the zone of gas concentration. There are three aspects which impair the achievement of "the necessary propped fracture geometry":fracture deviation from the zone of gas concentration;productivity damage due to the fracturing fluid interaction with the host rock matrix; andfracture conductivity damage due to the fracturing fluid interaction with the propped bed. Studies, describing the present status of fracture containment are well present status of fracture containment are well presented in the literature. This paper deals with the presented in the literature. This paper deals with the second and the third aspects. Laboratory data at simulated in situ conditions (stress, temperature, saturation and fracture treatment) and site specific analysis are presented to show the damaging nature caused by fracturing fluids to the matrix permeability and propped fracture conductivity. Tests were extended to study permeability damage clean up by backflowing gas through the damaged fracture face and propped fracture bed (simulating opening of the well after a MHF treatment). Cores used for the study were from reservoirs throughout the U.S.; fracturing fluids were selected for these reservoirs by service companies. 20–40 mesh Ottawa sand was used as proppant for the fracture conductivity tests. Background The selection of a fracturing fluid for an effective MHF job depends not only upon the fluids effectiveness in creating the fracture and transporting the proppants, but also the minimization of damage to formation permeability and fracture conductivity. The effect of fracturing fluid on formation permeability and proppant bed conductivity has been a constant topic of discussion in the literature. Since Van Poolen's early work with an electric models various studies of the degradation of matrix and fracture permeability due to the application of fracturing fluid have been presented. The loss of fracturing fluid to the formation adjacent to the fracture face creates a zone of immobile fracturing liquid and reduces the flow of gas through the formation face due to the reduction of gas relative permeability. Furthermore, the fracturing fluid leaves behind solid and liquid residue in the fracture. Softening of the fracture face can allow proppant embedment thereby reducing the conductivity.