Well injectivity during CO2 storage operations in deep saline aquifers—Part 1: Experimental investigation of drying effects, salt precipitation and capillary forces

Abstract

Carbon Capture and Storage (CCS) is a technique than can potentially limit the accumulation of greenhouse gases in the atmosphere. Well injectivity issues are of importance for CCS because the gas injection rate must be maintained at a high level (a million tonnes of CO 2 per year and per site) during the industrial operation period (30 to 40 years). The risk of altered permeability must therefore be determined in order to guarantee the sustainability and the security of the CO 2 geological storage. Injection of dry gas in deep saline aquifers might lead to near wellbore drying and salt precipitation. The solid salt might then reduce the rock permeability by clogging pores or by pore throat restriction. The objective of this paper is to present new experimental results on the drying of rocks induced by continuous injection of large amount of dry gas (N 2). The main goal of the study was to understand and model the physical processes that govern the decrease in water saturation in reservoir rocks. Two types of sandstone were used to study slow and fast drying rates and capillary effects on drying. The experimental results evince the main physical parameters that control the key mechanisms. In a companion paper in this issue (André et al., 2013), we show that the continuous approach in the context of a compositional two-phase flow model can fairly well predict the saturation evolution in the near wellbore and the alteration in permeability due to salt precipitation.

Capillary-Driven Transport of Dissolved Salt to the Drying Zone During $$\hbox {CO}_{2}$$ CO 2 Injection in Homogeneous and Layered Porous Media

“…Brine saturation decreases gradually in the entire domain, and capillary-driven backflow does not occur. Similar results were found by André et al (2014) and Peysson et al (2014) where capillarydriven backflow was limited above a threshold gas injection rate, and salt accumulation near the inlet was only found for low injection velocities. The threshold value of the injection rate was found to depend on the salinity of the brine.…”

“…Under reservoir conditions, the ratio between gas and water mobility is lower, and therefore the capillary-driven term is less pronounced. However, field scale scenarios have been studied numerically (e.g., Giorgis et al 2007;Muller et al 2009;Peysson et al 2014) and have shown that under reservoir conditions, capillary-driven backflow can be strong enough to cause severe injection impairment due to formation clogging in the vicinity of the well.…”

“…Reduced storage capacity can occur by (1) a decrease in available pore space caused by the presence of solid salt (e.g., Bacci et al 2011;Hurter et al 2007;Pruess and Müller 2009) and (2) complete clogging of the porous medium in the vicinity of the injection well by solid salt accumulation (e.g., Giorgis et al 2007;Muller et al 2009;Peysson et al 2014). Whether salt precipitation will affect the injectivity depends on its distribution inside B Saskia M. Roels saskiaroels@hotmail.com 1 Delft University of Technology, Stevinweg 1, 2628 CN Delft, The Netherlands the porous medium.…”

Dynamic Behavior of CO2 in a Wellbore and Storage Formation: Wellbore-Coupled and Salt-Precipitation Processes during Geologic CO2 Sequestration

“…Subsequently, the dry-out zone would be developed in the vicinity of the injection well where residual brine evaporated to dry-CO 2 while precipitating the solid salt [33,34]. Previously, numerous studies including both experimental [35][36][37] and numerical studies [34,[38][39][40][41] evaluated development of dry-out zone and associated saltprecipitation. Among them, Oh et al [36] conducted coreflooding experiments and captured the salt-precipitation at the core-inlet by using SEM images.…”

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].…”