Evaluation of a Greener Fracturing Fluid for Geothermal Energy Recovery: An Experimental and Simulation Study

Abstract

The objective of this work is to study the performance of 1wt% StimuFrac fluid [polyallylamine (PAA) in water] in ½-foot size rock samples under thermal and fluid phase conditions representative of enhanced geothermal systems (EGS) and reveal the mechanisms governing the fracturing process. Four fracturing fluids including water, CO2, CO2 with water, and CO2 with aqueous PAA were used. For all the water “only” fracturing tests, the conductivity of the rock fractured is quite low (less than 2 μm3 based on radial flow assumption), regardless of the constant flow rate or discrete pressure increments injection approach. For all three CO2-based fracturing fluids, granite was fractured at higher breakdown pressures, higher transient flow rates, and generated higher-conductivity fractures as compared to water. When partially saturating the rock sample with 1wt% PAA aqueous solution followed by fracturing with CO2, the volume expansion and viscosity increase triggered by CO2-induced cross-linking PAA leads to a faster pressure increase than CO2 in water saturated or initially dry. This faster pressurization rate is caused by a decrease in relative permeability of CO2 in the presence of the high-viscosity cross-linked fluid compared to the un-crosslinked CO2/water. It was also found that CO2 as a fracturing fluid can generate high fracture conductivity only when injected at very high flow rates in the presence of water or in hot dry rock (HDR). However, the conductivity of CO2 fracturing in HDR is highly variable. CO2 injected in the presence of 1wt% aqueous PAA generates fractures with the highest conductivity independently of injection flow rates and using 1/6 of the mass of CO2 as compared to CO2 fracturing in HDR. The results of this study suggest CO2/PAA is the best performing stimulation fluid under the studied P/T conditions. CO2/PAA offers the following three additional advantages over waterless CO2, and CO2/water fracturing fluids: i) it requires significantly lower volumes of CO2 due to the reduced leak off; ii) large fractures can be generated reproducibly at both low and high CO2 injection flow rate, and iii) the reversible (previously reported) viscosity increase could be beneficial to transport proppants when they become available for EGS.