Salt precipitation due to supercritical gas injection: I. Capillary-driven flow in unimodal sandstone

Abstract

Drying and salt precipitation in geological formations can have serious consequences for upstream operations in terms of injectivity and productivity. Here we investigate the consequences of supercritical CO 2 injection in sandstones. The reported findings are directly relevant for CO 2 sequestration and acid-gas injection operations, but might also be of interest to a broader community dealing with drying and capillary phenomena. By injecting dry supercritical CO 2 into brine-saturated sandstone, we investigate the drying process and the associated precipitation of salts in a capillary-pressure-dominated flow regime. Precipitation patterns were recorded during the drying process by means of CT scanning. The experimental results and numerical simulations show that under a critical flow rate salt precipitates with an inhomogeneous spatial distribution because of brine and solutes being transported in counter-current flow upstream where salt eventually precipitates. A substantial impairment of the absolute permeability has been found, but despite high local salt accumulation, the effective CO 2 permeability increased during all experiments. This phenomenon is a result of the observed microscopic precipitation pattern and eventually the resulting K() relationship. The findings in this paper are related to unimodal sandstone. In a companion paper (Ott et al., 2014) we present data on the distinctly different consequences of salt precipitation in dual-or multi-porosity rocks.

Salt precipitation during CO 2 storage—A review

“…At the same time, however, evaporation of trapped water may provide more space for CO 2 and thereby increase the relative permeability. Therefore, to assess the injectivity loss properly, it is required to measure the combined effect of these two mechanisms (Ott et al, 2015;Roels et al, 2014). The review of the studies presented in Table 1 shows that only two sets of experimental data measuring the effective permeability are available (Ott et al, 2011(Ott et al, , 2015(Ott et al, , 2013Wang et al, 2010Wang et al, , 2009, while the rest of the studies has focused only on finding an alteration relationship between porosity and permeability.…”

“…Ott et al (2015) performed core flooding of dry scCO 2 on brine saturated Berea sandstone with an absolute permeability of 500 mD and 22% porosity, and with two different injection rates (2.2. and 4.4 ml/min). They quantified the salt precipitation using X-ray tomography.…”

“…Still, a major uncertainty will exist in these assessments, causing CO 2 injection in saline aquifers to stand apart from traditional experiences in the field of petroleum exploration. Salt precipitation induced by brine vaporization is a distinct phenomenon in case of dry CO 2 injection and might severely impact the injectivity (Grude et al, 2014;Muller et al, 2009;Ott et al, 2015;Peysson et al, 2014).…”

A Theoretical Study of the Effect of Salt Precipitation on CO2 Injectivity

“…Once the salt concentration reaches its solubility limit owing to the evaporation, salt will precipitate out of solution [36]. The precipitated salt is then able to imbibe water from the flooding front and an effective capillary backflow is established (Figure 2.9b) once the capillary pressure gradient overcomes the injection pressure gradient [1,47]. The water being drawn to the evaporation front leads to further evaporation and increase in salt concentration in the dry-out zone.…”

Global Sensitivity Analysis to Assess Salt Precipitation for CO2 Geological Storage in Deep Saline Aquifers

“…Ott et al conducted a core scale drainage test to compare the salt precipitation of the core with two different pore structures, they found that the porous rock is more prone to form salt precipitation than singlepore rock, and they believe that the impairment of injectivity depends on the mobility of the brine phase, which was based on several core flood experiments [4]. By comparing different CO 2 injection rates ( CO 2 ), Peysson et al and Ott et al found that capillary backflow is almost negligible at higher CO 2 injection rates and that the appearance of salt precipitation is very limited [5][6][7]. Tang et al used brine with different salinities ( NaCl ) to carry out a CO 2 flood experiment, and they found that NaCl has a significant impact on injectivity loss [8].…”