Limitations to Storage Pressure in Finite Saline Aquifers and the Effect of CO2 Solubility on Storage Pressure

The impact of geologic variability on capacity and cost estimates for storing CO2 in deep-saline aquifers

“…Among the least constrained of these variables is the capacity factor. Research by van der Meer et al (van der Meer and Egberts, 2008;van der Meer and van Wees, 2006), Birkholzer and et al ) and Nicot (2008), indicates that the effective capacity factor is reduced if the pressure within the reservoir needs to be managed as it fills with CO 2 . While our injection module includes pressure constraints, our capacity module does not, so our model may be overestimating storage capacity and in turn underestimating storage costs.…”

Have We Overestimated Saline Aquifer CO2Storage Capacities?

“…and to model the pressure response with a model at the same large scale with correct boundary conditions, as the dimensions of the aquifer will directly impact the pressure response [20]. Any small scale model with either constant pressure boundary condition or infinite aquifer boundary condition would drastically underestimate the pressure build up at the injectors and hence overestimate the CO 2 storage capacity.…”

“…This effect was modelled for a typical aquifer [2,20]: -local pressure increase to honour injectivity can reach 10 MPa for the aquifer studied; -average pressure increase to inject a given mass of CO 2 with time will be directly proportional to the size of the domain and Equation (2), ranging from 1 to 24 MPa in the case studied. These papers illustrate the fact that local pressure increase at wells to honour injectivity can be very high compared to typical geomechanical / capillary entry constraints, hence average pressure increase in the aquifer is much smaller than pressure increase at wells, and in the case of a closed aquifer it may not be technically feasible to increase the average aquifer pressure up to the maximum allowable increase while injecting with significant CO 2 rates.…”

“…1). On Utsira case, dissolution processes is expected to develop from 300 to 5 000 years after the injection period [1], 1 000 year period is modelled to dissolve the CO 2 in [20], a parametric study is presented in [21] illustrating the impact of the permeability anisotropy on the time required to dissolve the CO 2 , with 25% of the CO 2 being dissolved after 300 to 20 000 years depending on the k v /k h ratio.…”

Numerical Modeling of Geomechanical Processes Related to CO{sub 2} Injection within Generic Reservoirs

“…While this scenario serves well to study the impact of different parameters (such as permeability, injection rate, fluid flow boundary conditions and seal efficiency) on CO2 flow and pressurization [Zhou et al, 2008;Inoue, 2009;Taberner et al, 2009;Ehlig-Economides And Economides, 2010;Cappa and Rutqvist, 2011], for a geomechanical risk analysis a model geometry reflecting the actual geologic scenario, which exhibits a heterogeneous state of stress is required. The geomechanical risks accompanying aquifer pressurization due to the CO2 injection have been investigated by several authors [Settari and Mourits, 1998;Thomas et al, 2003;Pettersen, 2006;Van der Meer et al, 2006;Rutqvist et al, 2007;Schembre-McCabe et al, 2007;Zhou et al, 2008;Inoue, 2009;Taberner et al, 2009;Tran et al, 2009;Ehlig-Economides And Economides, 2010;Cappa and Rutqvist, 2011;Graupner et al, 2011] with one of the most important being the reactivation of existing faults or fracture sets which can result in induced seismicity [Van der Meer et al, 2006;Rutqvist et al, 2007;Schembre-McCabe et al, 2007;Loizzo et al, 2009] and potential leakage pathways. [Rutqvist et al, 2007;Zhou et al, 2008] have shown that the pressure build-up in models representing horizontally layered sedimentary basins is strongly dependent, amongst others, on the fluid flow boundary conditions.…”