Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

Abstract

CO 2 storage in fractured reservoirs may lead to fast CO 2 flow through interconnected fracture networks; but the role of isolated fractures on brine-CO 2 multiphase flow systems remains unclear. We present the results of a brine-CO 2 flow-through experiment in which we assess the change in transport properties of a synthetic sandstone plug (a surrogate of a saline siliciclastic CO 2 reservoir) containing non-connected fractures aligned 45 � from its axis. The test was performed at 40 MPa of constant hydrostatic confining pressure and ~11 MPa of pore pressure, at room temperature (~19.5 � C), using pure liquid-CO 2 and 35 g L À 1 NaCl salt solution. The injected CO 2-brine volume fraction was increased from 0 to 1 in 0.2 units-steps (drainage). Upon achievement of the maximum CO 2 saturation (S CO2 ~0.6), the plug was flushed-back with the original brine (imbibition). During the test, we monitored simultaneously pore pressure, temperature, axial and radial strains, and bulk electrical resistivity. The fractured sample showed lower values of cross-and end-points in the relative permeability curves to CO 2 compared to non-fractured samples, from comparable experiments performed at similar pressure and brine salinity conditions, but different temperature. Our results suggest that a non-connected fracture network affects the mobility of the individual phases, favouring the trapping of CO 2 in the porous medium and improving the storage efficiency of the reservoir. These evidences show the need of a better understanding of fracture connectivity prior to discard fractured reservoirs as unsuitable geological formations for CO 2 storage.

CO2‐Brine Substitution Effects on Ultrasonic Wave Propagation Through Sandstone With Oblique Fractures

“…This minor inflation (~0.12%) is within the porosity fraction commonly attributed to microcracks (0.7%; Fortin et al, 2007). Thus, it could be related to microcracks reopening due to differential pressure (P diff = P c − P p ) drop during the experiment associated with the increase of inlet‐to‐outlet P p gradients with the increasing X CO2 (Muñoz‐Ibáñez et al, 2019).…”

“…The test covers fluid substitution during CO 2 plume advance (drainage) and the natural aquifer recharge after ceasing the injection activities (imbibition) with a maximum CO 2 saturation ~0.6, in agreement with previous CO 2 ‐water fluid substitution tests in sandstones (Burnside & Naylor, 2014). The low capillarity forces of the fractures with respect to the pores lead to preferential CO 2 fracture filling (Muñoz‐Ibáñez et al, 2019), which magnifies the effect of drainage versus imbibition paths.…”

“…Once baked, the sample was immersed in an acidic bath to remove the aluminum discs, resulting in a silica‐cemented sandstone with 45° aligned penny‐shaped cracks. The fracture density (ε f = 0.0298 ± 0.0077) and an average fracture aspect ratio (τ/δ = 0.088 ± 0.001) were obtained from X‐ray CT scan image processing (Amalokwu et al, 2015), which leads to a porosity fraction attributed to fractures of ~10% (Muñoz‐Ibáñez et al, 2019).…”

“…After the BCFT test, the sample was cleaned with deionized water and then dried, before being saturated with CO 2 at the test conditions to collect the corresponding ultrasonic properties. Further information about the testing methodology in Falcon‐Suarez et al (2017), Muñoz‐Ibáñez et al (2019) and as supporting information in the online version of this manuscript.…”

“…To calculate the relaxation frequencies at partial saturation, we use the Brooks‐Corey relative permeability model, suitable for explaining the two fluid phases' interaction in our sample (Muñoz‐Ibáñez et al, 2019), and the fracture and microcrack densities ε f = 0.042 and ε m = 0.02. ε f is derived from the design of synthetic fractures in the sample (Tillotson et al, 2012), while ε m is arbitrarily adopted within the range of values observed in similar synthetic rocks (Papageorgiou et al, 2018). In the Supporting Information, we show how we derive the V P , V S 1 , V S 2 of an effective medium with these properties.…”