CO2 Storage in the Nisku Aquifer in the Wabamun Lake Area, Canada - The Effect of Site Characterization Data on Caprock Integrity Modeling

Abstract

Abstract The geomechanical factors put significant constraints on CO2 storage in terms of injection pressures that may be limited by fracture propagation, injection rates that can be achieved without compromising the seal and excessive fracture propagation, and the CO2 placement affected by fracturing. Goodarzi et al (2012) investigated the feasibility of securely storing CO2 in Nisku geological formation located in Wabamun Lake area (Alberta, Canada) using a coupled flow, thermal and geomechanical model. Due to lack of field and lab measurements, the results of the study were reported as pessimistic. This paper utilized recently recorded well log, well test and lab measurements specific to the study area to build porosity, absolute and relative permeability, thermal, mechanical property and stress profiles required for refining the results of the aforementioned study. The results show that injection in the Nisku aquifer (below or at fracture pressure with 1–2 Mt/year) causes only small surface heave in the range of 2–3 mm. Injection above the fracture pressure at 2 Mt/year results in higher well injectivity but also increases the possibility of caprock fracturing. The degree of vertical propagation strongly depends on the caprock stress state and mechanical properties. The importance of the proper site characterization is highlighted by comparison of our current results with our earlier work on the same site reported in Goodarzi et al. (2012), in which estimates were used for many parameters. The predicted fracture dimensions based on updated fluid and rock mechanical properties in the current work are significantly larger than the dimensions reported in the 2012 study. The primary reason for this is the lower initial fracture pressure and higher stiffness of the reservoir rock formation used in this study.This causes smaller fracture width and lower leak-off which will be compensated by larger extent of fracture both horizontally and vertically.. Thermal effects of cold CO2 injection reduce significantly the fracture pressure and enhance the horizontal fracture propagation. The vertical extension of fracture in the thermal model was shown to be smaller than in the isothermal model due to the confining stress contrast created by thermoelastic stresses. This in turn resulted in larger horizontal propagation of fracture in the thermal model. The reduction of fracturing pressure due to thermal effects will reduce the well injectivity if the well is to be operated below fracture pressure, and increase fracture propagation if fracturing is allowed. This aspect needs to be taken into account by operators as well as by regulatory agencies. If it is required to operate below fracturing, the time-variation of fracture pressure under injection condition can be determined using geomechanicaly coupled model and its historical minimum value should be taken as the maximum operating pressure.