Effect of initial water saturation on the performance of fracturing fluids with and without polyallylamine under simulated EGS conditions

Abstract

Objectives/scopeStimuFrac (US Patents 9,873,828 B2 and 9,447,315 B2), a CO2-reactive polymer aqueous solution [polyallylamine (PAA) 1wt% in water] combined with CO2, can potentially be used as a less water-intensive fracturing fluid for enhanced geothermal systems (EGS). Our previous results show that in hot dry rock (HDR), PAA/CO2 fracturing fluids outperformed other fluids such as water, CO2, and CO2/water in generating large fractures with less fluid consumed. The objective of this work is to investigate the effect of initial water saturation on the performance of StimuFrac by conducting hydraulic fracturing tests with ½ foot cubic rock samples held under representative EGS stress/temperature conditions and by using cyclic injection strategies (under constant injection rate). The resulting fracture hydraulic conductivities, breakdown pressures, and volumes of fluids required are compared. Methods/procedures/processTo simulate geothermal reservoir conditions, in all tests, the rock sample was held under triaxial confinement and at 200 °C, and different volumes of water were initially injected into the rock sample before any fracturing processes were initiated. For the single-cycle PAA (or water) alternating CO2 (PAG or WAG) injection fracturing experiments, one complete cycle consisted of two steps: (1) injecting a PAA slug (or water slug) followed by (2) injecting CO2 to initiate and propagate the fracture. For experiments involving multiple injection cycles, the CO2 injection pressure is increased until it peaks and begins to decline (indicating fracture initiation at this moment), and then continued being injected for another 30 s to propagate the fracture. Then, these two-step cycles [injection of PAA (or water) followed by CO2 injection (up to 2–4 mL/min)] are repeated. Applications/significance/noveltyThe results of this study suggest that water saturation significantly affects the fracturing fluid transmission into the rock pore space, thus affecting fracture initiation and propagation. In this study, fracturing tests via a single injection cycle or multiple injection cycles were performed. When the rock samples are split in half following testing, it is evident that fracture propagation is considerably restricted under high water saturation conditions (where a three-day initial water injection was conducted) in comparison to stimulation experiments carried out in hot and dry rock. The fractures propagate less than 1/3 of the distance from the wellbore to the outer rock surface, and in some cases, no fracture is generated. This may be caused by leak-off dominating the fracturing process and the fluid injection rate is insufficient to overcome leak-off, even under high injection rate conditions. Additionally, CO2 could be leaking off into the wellbore annulus and this may be making it more difficult to generate sufficiently high-pressure gradients away from the near-wellbore region. Under low water saturation conditions (dry rock or after 1-day initial water injection), PAA/CO2 consistently generated significantly larger fractures compared with the other fluids. CO2 generated large fractures only in the hot dry rock and only when using high injection rates, though data variability is high.