Salt precipitation during CO2 storage—A review

International Journal of Greenhouse Gas Control 51 (2016) 136–147

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Salt precipitation during CO2 storage—A review Rohaldin Miri ∗ , Helge Hellevang Department of Geosciences, University of Oslo, P.O. Box 1047 Blindern, N-0316 Oslo, Norway

a r t i c l e

i n f o

Article history: Received 10 July 2015 Received in revised form 3 April 2016 Accepted 23 May 2016 Keywords: CCS Saline aquifers Injectivity Salt precipitation Evaporation

a b s t r a c t This paper reviews the state-of-the-art knowledge gained from experimental and theoretical investigations on salt precipitation in the context of CO2 storage in saline aquifers. Included in this review are physical mechanisms, governing parameters, clogging models, and mitigation techniques. The approach is generally conceptual, and our aim is to specify how serious salt precipitation is for CO2 storage and whether its importance has been overlooked. Our review specifies some new physical understandings suggesting that salt precipitation must be taken into account when evaluating saline aquifers for storage. We also list unresolved areas which demand further experimental investigation and suggest some essential considerations with regard to numerical tools. © 2016 Elsevier Ltd. All rights reserved.

1. Introduction Storage capacity, containment efficiency and injectivity are the three factors that require major pre-assessment to decide the feasibility of CO2 storage in a candidate geological formation. For injectivity, the simple reservoir engineering approach is to go for reservoirs with a high permeability-thickness product (k × h) and highly conductive boundaries (Hosa et al., 2010). A more accurate assessment of the formation’s injectivity, however, requires detailed reservoir simulations and, if possible, an injectivity test. Still, a major uncertainty will exist in these assessments, causing CO2 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 CO2 injection and might severely impact the injectivity (Grude et al., 2014; Muller et al., 2009; Ott et al., 2015; Peysson et al., 2014). When injecting large volumes of under-saturated (dry) supercritical CO2 into a saline aquifer, formation water eventually evaporates and the molar fraction of the water in the CO2 stream increases. In the meantime, as vaporization progresses, the concentration of dissolved salt in the brine builds up. When the salt concentration exceeds its solubility limit under the thermodynamic state of a given reservoir, the excess salt will precipitate out of the aqueous phase (salting-out) and alter the porosity and permeability of the formation (Cinar and Riaz, 2014; Hurter et al., 2007). Strong evidences on the occurrence of salt precipitation primarily have

∗ Corresponding author. E-mail address: [email protected] (R. Miri). http://dx.doi.org/10.1016/j.ijggc.2016.05.015 1750-5836/© 2016 Elsevier Ltd. All rights reserved.

come from field observations of gas injections or storage (Bette and Heinemann, 1989; Jasinski et al., 1997; Kleinitz et al., 2001). In most of these cases, a dramatic injectivity reduction has been reported. Besides that, several experimental and numerical studies also have confirmed this phenomenon in the context of CO2 storage (Muller et al., 2009; Ott et al., 2011; Pruess and Müller, 2009; Wang et al., 2010; Zeidouni et al., 2009a). Although the process of salt formation seems rather simple, profound complexity is hidden deep within. Much of the physics of this process has been demonstrated with general purpose simulation codes such as TOUGH2. Yet, due to lack of a sound physical model, various works have provided conflicting results on how salt precipitation impacts the static and dynamic properties of porous media. As several of these conflicting reports are available, and since review articles are scarce, we find it useful to present an overview of the state-of-the-art. The aim is to summarize findings in previous studies and specify how salt precipitation affects CO2 storage efficiency. In addition we will clarify the underlying physics and discuss the predictability of the current numerical tools.

2. Observations regarding salt precipitation 2.1. Evidences from the field Precipitation of salt, mainly consisting of halite, is a longstanding issue in the gas and petroleum industry. Several field experiences have been reported during production/injection from gas reservoirs (Bette and Heinemann, 1989; Jasinski et al., 1997; Kleinitz et al., 2001) and also during storage of natural gas in Iran, the Netherlands and Germany (Golghanddashti et al., 2013; Kleinitz

Table 1 Summary of the experimental studies for salt precipitation induced by CO2 injection. Fluid properties

Injection condition

Analysing method

Remarks

Berea sandstone core sample K = 100 md ␾ = 20% D = 2.5 cm L = 28 cm

S = 25 wt% NaCl brine

T = 35 ◦ C P = 63 bar Q = NR*

Permeability measurement SEM and ESEM

− 60% reduction in absolute permeability − Suggested pre-flushing with fresh water − Suggested saturated CO2 injection

Wang et al. (2009)

Berea sandstone core sample K = 79 md ␾ = 18% D = 3.76 cm L = 28.1 cm

S = 25 wt% NaCl brine

T = 50 ◦ C P = 82 bar Q = 9.5 ml/min

Permeability measurement SEM and ESEM

− 50% reduction in CO2 relative permeability − Grains coated with salt crystals were observed using SEM

Wang et al. (2010)

Berea sandstone core sample K = 143 md ␾ = 17% D = 3.791 cm L = 29.25 cm

S = 25 wt% NaCl brine

T = 50 ◦ C P = 82 bar Q = 9.2 ml/min

Permeability measurement MRI imaging

− 50% reduction in CO2 relative permeability − MRI confirm salt precipitation near the core inlet

Ott et al. (2010)

Berea sandstone core sample K = 500 md ␾ = 22% D = 1 cm L = 5 cm

S = 20 wt% NaCl brine

T = 45 ◦ C P = 100 bar Q = 2.2 ml/min

Permeability measurement ␮CT imaging

− Local salt accumulation due to capillary-driven backflow of brine − Absolute permeability reduced by a factor of 4 − Effective CO2 permeability increased by a factor of 5 − Salt precipitates in the vicinity of CO2 -flow channels leaving them essentially open − Suggesting kinetic approach for later simulation

Bacci et al. (2011)

St. Bees sandstone K = 7.78 md ␾ = 22.59% D = 6.8 cm L = 15.2 cm

S = 26.4 wt% NaCl brine

T = 45 ◦ C P = 80 bar Q = 25 ml/min

Permeability measurement ICP-AES

− Porosity reduction ∼2.83% − Permeability impairments ∼75%. − Results were used to calibrate Verma-Pruess “tube-in-series” model

Bacci et al. (2013)

Guiting limestone K = 1.04 md ␾ = 30.38% D = 3.6 cm L = 7.8 cm

S = 24–36 wt% NaCl brine

T = 45 ◦ C P = 80 bar Q = 25 ml/min

Permeability Measurement Weighting ICP-AES

− Porosity reduction ranged from 3 to 5% − Permeability impairments ranged from 13 to 75%. − Results were used to calibrate Verma-Pruess “tube-in-series” model − No geochemical reaction during vaporization − Fresh water remedy might increase later impairment

Oh et al. (2013)

Berea sandstone core sample K = 170 md  = 20% D = 3.8 cm L = 15 cm

S = 15 wt% NaCl + NaI brine

T = 40 ◦ C P = 100 bar Q = 0.2–10 ml/min

X-ray scanning SEM

− In-situ salt precipitation near the inlet of the core

Ott et al. (2013)

Multi-porosity dolomite K = 170 md  = 20% D = 2.54 cm L = 15 cm

S = 34 wt% NaCl brine

T = 110 ◦ C P = 110 bar Q = 1.12 ml/min

Permeability measurement ␮CT imaging

− Precipitation regimes depend on the injection rate − The timescale of dry-out controls the crystallization process − Effective permeability reduction explained by matrix contribution

Kim et al. (2013)

Microfluidic chip

S = 34 wt% NaCl brine

T = 21 ◦ C V = 1 mm/s

Direct imaging

− Porosity reduction 15–25% − Large bulk crystals in the brine phase − Polycrystalline aggregated structures far from the interface

Peysson et al. (2014)

Vosges sandstone K = 100 md  = 20–22% Moliere sandstone K = 0.01 md  = 0.14% D = 4.9 cm L = 6 cm

Vosgas − KCl + KI mixture Moliere − Paris Basin brine

Vosgas T = 60, 80 ◦ C P = 50 bar Q = 3 ml/min Moliere T = 90, 120 ◦ C P = 50 bar Q = 3 ml/min

X-ray scanning

Vosges core: − Salt accumulation near the inlet − Capillary back flow is dominant mechanism − Permeability decreases ∼70% Moliere core: − Homogenous precipitation − Salt diffusion is dominant − Permeability decreases ∼60%

Roels et al. (2014)

Bentheimer sandstone K = 200 md  = 24% D = 1 cm L = 3 cm

− KI mixture

T = 28 ◦ C P = 1.1 bar Q = 5 ml/min

Permeability measurement ␮CT imaging

− Homogenous salt distribution − Average solid saturation ∼25% − Suggested using kinetic modelling

Tang et al. (2014)

Berea core Sandstone K = 2.16–490 md  = 30% D = 2.5 cm L = 6 cm

S = 0.25–25 wt% brine

T = 100 ◦ C P = 10.1 bar Q = 4.4 ml/min

SEM

− Porosity reduction ∼14.6% − Permeability reduction ∼83.3% − Higher salinity, greater impairment − Lower initial permeability, higher impairment − Salt precipitates in inter-granular pores − Flow channels reduced in size

Ott et al. (2015)

Berea sandstone core sample K = 200 md  = 30% D = 1 cm L = 5 cm

S = 20 wt% NaCl brine

T = 50 ◦ C P = 100 bar Q = 4.4 ml/min

X-ray scanning SEM

− Homogenous salt precipitation − Effective permeability increased

Miri et al. (2015)

Microfluidic chip

S = 34 wt% NaCl brine

T = 22 ◦ C Q = 0.5 and 50 ml/min

Direct pore scale imaging

− Salt forms in both liquid phase and CO2 pathways − Salt self-enhancing mechanism is recognized − Water films conductivity

137

Rock properties

Muller et al. (2009)

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et al., 2003; Place and Smith, 1984). Kleinitz et al. (2003) reported industry experience on plugging of pores by halite-scaling to such an extent that the salt could not be mitigated by using freshwater, it could be dissolved only after very long shut-in times at the well. The study of formation dry-out and salt precipitation in the context of CO2 storage in saline aquifers, however, is a new topic and strong field evidences of the phenomenon have not been reported so far. Still, the source of extra pressure buildup in the Ketzin and Snøhvit CO2 storage projects was partly assigned to salt precipitation. Baumann et al. (2014) identified a one meter interval of salt accumulation in the Ketzin reservoir (35 ◦ C, 7.5 MPa and 220 g/l NaCl) employing radiometric pulsed neutron-gamma (PNG) logging technique. Through analysing the fall-off pressure data, Grude et al. (2014) detected a low permeability zone in the Tubåen Formation at the Snøhvit Field (95 ◦ C, 28 MPa and 14% NaCl) surrounding the well at an early stage of injection. This was attributed to possible salt accumulation. Other reported evidences for salt precipitation are related to laboratory experiments or numerical simulation of relatively idealized 2D-radial systems. 2.2. Evidences from laboratory experiments Table 1 gives a comprehensive list of experimental studies along with summarized conclusions conducted for assessing salt precipitation. The pioneer laboratory study on formation dry-out and precipitation with focus on CO2 sequestration was performed by Muller et al. (2009) for the CO2SINK Project, a European Union research project on testing geological carbon storage near Ketzin, Germany. The test was conducted on a dry Berea core with 100 mD and around 20% porosity saturated with a 25% NaCl solution. They reported 60% reduction in the absolute permeability after the experiment and, based on Scanning Electron Microscopy (SEM) micrographs, allocated this to salt precipitation. Wang et al. (2009, 2010) conducted similar core flooding experiments on the Berea sandstone and mapped the water saturation profile along the core by Magnetic Resonance Imaging (MRI). An effective drying region in the inlet of the core was identified. They also estimated 50% reduction in the CO2 effective permeability due to salt accumulation in the dried region. Ott et al. (2010) mapped the profile of precipitated salt during injection of dry supercritical CO2 (sc CO2 ) along a brine saturated Berea sandstone core sample employing Micro Computer Tomography (␮CT). They reported local pore space occupation by salt causing as high as 20% and also 75% reduction in absolute permeability. Similar to the previous study a large accumulation of salt near the injection inlet was observed. Bacci et al. (2011) documented absolute permeability reductions of up to 86% from their sc CO2 core flooding experiments. Oh et al. (2013) recognised salt precipitation in the inlet of a Berea fractured core using X-ray scanning, but measurements on permeability reduction were not provided. Ott et al. (2012) repeated their previous experiment on the Berea sandstone but this time with a higher flow rate. The measured solid saturation was significantly reduced to 4.5% following a homogenous distribution of salt. Ott et al. (2013) reported effective permeability impairment owing to reduction in the CO2 pathways cross-section due to the presence of micro-porous subsystem. Peysson et al. (2014) investigated the mechanisms of brine evaporation and salt precipitation on the low permeability Moliere (0.01 mD) and the high permeability Vosges (100 mD) sandstone formations. X-ray CT imaging was used in order to quantify the spatial distribution of phases. The high permeability case showed a local salt accumulation, whereas a homogenous distribution was observed for the low permeability sample. Experiments on multi-porosity dolomitic limestone cores have shown qualitative differences from the well-sorted Berea sandstone.

On the micro scale, Kim et al. (2013) and Miri et al. (2015) have reported precipitation of salt crystals in two different forms via lab-on-a-chip experiments; (1) large crystals which grow in the liquid phase away from the CO2 interface; and (2) near-interface aggregated polycrystalline structures supported by a flow of highsaline brine along thin films driven by capillary forces along the pore channels. 2.3. Is injectivity reduced due to salt precipitation? During a CO2 injection process, absolute permeability of samples may be reduced due to salt precipitation. At the same time, however, evaporation of trapped water may provide more space for CO2 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, 2015, 2013; Wang et al., 2010, 2009), while the rest of the studies has focused only on finding an alteration relationship between porosity and permeability. Unfortunately, the results that have been reported from these two reports are not consistent. Ott et al. (2015) performed core flooding of dry scCO2 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. Local salt accumulation was observed at the low injection rate, explained by a capillary backflow mechanism. For the high injection rate, however, the precipitation pattern was homogenous. Despite reduction in the absolute permeability, effective CO2 permeability during the course of dry-out increased by a factor of 5, suggesting little or no change in injectivity. The effective permeability improvement was reported for both flow rates. To explain this behaviour, it was suggested that salt only precipitates in the volume earlier occupied by the trapped brine, leaving the cross-sectional area of percolation pathways open to CO2 flow. This picture has been verified later by Ott et al. (2014) by means of ␮CT scanning. On the other hand, Wang et al. (2009) presented an experimental study of salt precipitation and injectivity impairment during scCO2 injection in brine saturated Berea sandstone cores. They used Magnetic Resonance Images (MRI) to visualize halite precipitation behind the dry gas front and reported reductions in CO2 relative permeability by almost half. Therefore, in view of current literature the uncertainty regarding effect of precipitation on the injectivity is very high and the most important question regarding salt precipitation remains elusive. Some recent experimental observations may however have resolved some of the issues regarding earlier conflicting experimental results. The next section will provide an overview of the state-of-the-art physical models of salt formation. 3. Physics of salt precipitation A combination of physical and chemical processes governs drying and salt precipitation in deep saline aquifers or depleted oil and gas reservoirs. The contribution of chemical processes to the formation dry-out, however, is minor compared to the more active physical processes. Hence, the majority of existing numerical codes, which are capable to simulate the process of drying-out and saltingout, have been established based on implementing the physical process. The main objectives of these tools are to predict the macroscopic distribution (i.e. the progression of the dry-out zone and the average porosity reduction) of the precipitant and to estimate the extent of formation damage. The former depends mostly on the mechanisms of salt transport on a macroscopic scale, while

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Fig. 1. Schematic illustration of different physical mechanisms contributing to the process of salt precipitation (Please note that the length scale has been for the sake of clarity exaggerated in these drawings).

the latter requires a microscopic understanding as permeability impairment is defined by salt distribution on the pore scale (Ott et al., 2015). The ultimate distribution of salt in porous media is a combination of these two. In the following the basic mechanism belonging to each of these categories will be carefully reviewed. 3.1. Macroscopic view Work on the physical mechanisms associated with salt precipitation on macro scale has been performed by Pruess and Müller (2009) and later by André et al. (2014), Kim et al. (2012), Liu et al. (2013) and Meng et al. (2014). Experimental observations show a reasonable consistency with these findings (Ott et al., 2011, 2013; Peysson et al., 2014). Table 2 summarizes various published papers in which numerical tools (mainly TOUGH2) were used to model the process of salt precipitation on the macro scale. The progression of dry-out and extent of precipitation are found to be consequences of interplay between several physical mechanisms which act on different time and length scales. These mechanisms are; (1) two-phase displacement of brine away from the injection well by viscous pressure gradients imposed through injected CO2 , (2) evaporation of brine into the flowing CO2 stream, (3) capillary-driven backflow of aqueous phase toward the injection point due to capillary pressure gradients, (4) molecular diffusion of dissolved salt in the aqueous phase, (5) gravity override of injected CO2 , and (6) salt self-enhancing. These mechanisms are schematically illustrated in Fig. 1 and thoroughly described in the following paragraphs. Just after the start of CO2 injection, a two-phase-flow zone forms where both an aqueous phase and a CO2 -rich phase are

present (Fig. 1a). This zone is leading with a shock front (flooding front) which travels with a velocity determined mainly by injection characteristics. This process is referred to as two-phase displacement where a primary drainage owing to the viscous displacement pushes brine out of the injection well (Ott et al., 2015; Peysson et al., 2014; Pruess and Müller, 2009). As the flooding front moves into the aquifer, a zone is left behind wherein residual brine is trapped in several configurations; such as thin wetting films surrounding the grain surfaces and liquid bridges and/or pools of brine in the pores (Miri et al., 2015). Immediately and simultaneously this drained region is exposed to the constant flow of dry scCO2 with low water vapour pressure, initiating an evaporation regime. The solubility of water in the scCO2 is several orders of magnitude smaller than solubility of the CO2 in the brine (Spycher and Pruess, 2005; Spycher and Pruess, 2010). However, under constant flow a significant portion of water will evaporate into the CO2 stream resulting in formation dry-out. In addition, as water is evaporated the relative permeability of CO2 increases allowing for further evaporation. Eventually a dry-out front forms (Peysson et al., 2014; Pruess, 2009) and travels with a velocity much smaller than the flooding front velocity (Kim et al., 2013) (Fig. 1a). Indeed, both two-phase displacement and evaporation (dissolution) contribute to water being removed from the near well area. However, time scales are well separated. Essentially, there is only little evaporation during two-phase displacement and there is also no convective flow during dry-out (Ott et al., 2014, 2010, 2015; Peysson et al., 2014). Most of the water mass exchange takes place in the dry-out zone, thus creating a saturation gradient across the drying front (Peysson et al., 2014) that is much greater than the saturation

Fig. 2. Schematic of CO2 injection in a saline aquifer and possible configuration of phases in the near-well region.

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Table 2 Summary of the research outcomes using rigorous simulations studies for the salt precipitation induced by CO2 injection. Reservoir properties

Injection condition

Sensitivity parameter

Remarks

Giorgis et al. (2007)

K = 400 md  = 0.32% H = 10 m

Salinity = 9 wt% T = 45 ◦ C P = 60 bar Q = 1 kg/s

- Injection rate - Initial brine Saturation

- Extended V & P model - Precipitation extent depends on K-␾ relationship - Amount of precipitation increases with increase in initial brine saturation - For Q > Qcr, increasing rate, decreased amount of precipitation - For Q < Qcr, increasing rate, increased amount of precipitation - For very low injection rate, amount of precipitation in independent of brine saturation

Hurter et al. (2007)

K = 200 md  = 20% H = 30 m

Salinity = 25 wt% T = 35 ◦ C P = 75 bar Q = 1 kg/s

- Salinity - Water content

- Dry-out zone progresses 10 m in 2 years - Experiments are needed for K-␾ relations - Higher salt concentration at edge of plume - Dry CO2 injection improved injectivity Low salinity brine suggests little precipitation

Hurter et al. (2008)

K = 200 md  = 20% H = 30 m

Salinity = 25 wt% T = 35 ◦ C P = 75 bar Q = 1 kg/s

- Injection rate - Capillary pressure - Relative permeability

- For zero capillary pressure precipitation did not occur Increase in injection rate decrease the solid saturation Relative permeability control the spatial distribution of precipitant

Zeidouni et al. (2009a,b)

K = 200 md  = 0.32% H = 100 and 30

Salinity = 15, 25 wt% T = 35, 45 ◦ C P = 75, 120 bar Q = 1, 100 kg/s

- Salinity - Pressure - Temperature - Relative permeability

- Kozeny–Carman model is used - Capillary and gravity were ignored - Homogenous precipitation is obtained Amount of precipitation is minor, 3% - Salt precipitation increases with pressure and salinity - Temperature has minimal effect - Increase in brine relative permeability reduces amount of precipitation

Pruess and Müller (2009)

K = 33 md ␾ = 0.33% H = 100 m

T = 50 ◦ C P = 120 bar Q = 5 kg/s

- Injection rate - Capillarity Mechanism

- Precipitation occurs few meter from the well - Constant and homogenous salt distribution independent of injection rate - Gravity in combination with capillary-driven flow leads to heterogeneous precipitation - 20% salt saturation observed for heterogeneous precipitation

Kim et al. (2012)

K = 10–150 md ␾ = 0.33% H = 100 m

T = 40 ◦ C P = 96–100.6 bar Q = 1–30 kg/s

- Injection rate - Temperature Salinity

- Salt precipitation for high permeability rocks at low injection rates - Localized salt acts like a barrier hampering pressure dissipation - Suggested using negative skin zone

André et al. (2014)

K = 5–500 md H = 100

T = 80 ◦ C P = 50 bar Q = 1 kg/s

- Injection rate - Salinity

- Good agreement between experiments and simulations The higher the brine salinity, the greater the salt deposit Location of salt deposits depends strongly on the injection rate

Guyant et al. (2015)

K = 5–500 md ␾ = 0.15–0.2% H = 230 m

P = 300–350 bar T = 78–80 ◦ C Q = 0.1–1 mt/year,

- Injection rate - Permeability Perforation

- High permeability reservoir under low injection rate has the most permeability reduction

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gradient created in case of a pure viscous displacement. The resulting capillary pressure gradient (Fig. 1b) eventually overcomes the injection pressure gradient and drives the water toward the evaporation front, supporting more evaporation (Ott et al., 2015; Peysson et al., 2014; Pruess, 2009). In addition, as the water is evaporated (dissolved) into the CO2 stream, salt concentration in the trapped brine increases, resulting in salt diffusion (Fig. 1c) outward from the drying front (Pruess, 2009; Shahidzadeh-Bonn et al., 2008). The relative distance between the dry-out front and the flooding front is primarily controlled by this capillary backflow and solute diffusion. Once the salt concentration reaches its solubility limit owing to the evaporation, salt will precipitate out of solution. The precipitated salt has a significant affinity toward brine and can effectively imbibe the water from large distances to the evaporation front, resulting in further precipitation (Miri et al., 2015). The nature of this mechanism is more or less the same as provided by the capillary pressure gradient, but they have different origins. In addition, capillary flow due to salt (Fig. 1d) is much stronger and gives significant stability to the water films, thereby enhancing salt precipitation. When dry CO2 is injected into a saline aquifer, several flow regions will develop based on interplay between the aforementioned mechanisms. These regions can be divided into three regions without losing the generality (Ott et al., 2012; Zeidouni et al., 2009a). In fact, the dry-out Region 1 is separated from the saturated brine phase; Region 3, with an extended mixing zone wherein both aqueous phase and CO2 are in contact; Region 2 (Fig. 2). Similarly these regions will develop when the system is under evaporation only (i.e. without CO2 injection), and salt precipitation is not involved. However, the role of Region 2 is very special in a salt precipitation process. In a usual drying process, Region 2 contains disconnected liquid clusters which develop in front of the continuum liquid region and act to partially screen this region from the evaporating side of the porous medium. Thus these clusters decelerate mass transfer into the gas phase (Yiotis et al., 2004). However, in an evaporation-precipitation process, the precipitated salt in Region 1 gives effective stability to liquid clusters connecting them to the evaporation front. Therefore, liquid clusters act like conduits transferring the liquid from the saturated zone to the dry-out thus enhancing amounts of salt precipitation in the dry-out zone (Miri et al., 2015). 3.1.1. Drying regimes and macroscopic distribution of salt Depending on active drying regimes, salt precipitation can occur in two different forms (local and non-local) which alter the injectivity in different ways. We have identified three drying regimes through in-depth reviewing of the experiments and numerical studies listed in Tables 1 and 2. In the following we use symbols Je and Jc to refer to the stabilized evaporative and capillary fluxes, respectively. (1) The diffusive regime (Je  Jc ) is active at very low injection rates when the low CO2 velocity causes a very low evaporation rate (Fig. 3a). The evaporation, however, draws in some brine near the injection point and thereby decreases the brine saturation and induces a capillary pressure gradient (Ott et al., 2013; Peysson et al., 2014). The brine can therefore be continuously transferred to the injection point under the action of the corresponding capillary pressure gradient. The brine velocity driven by a capillary backflow at steady-state is the same as the evaporation rate, preventing formation of a drying front (André et al., 2014; Peysson et al., 2014). At the same time, water evaporation near the injection surface increases the salt supersaturation, creating a salt gradient inside the column (Peysson, 2012; Peysson et al., 2014). Therefore, salt diffusion can effectively occur under an evaporative flow regime resulting in a

Fig. 3. Schematic illustration of different drying regimes associated with the process of salt precipitation.

rather homogeneous distribution of salt throughout the porous medium. (2) The second drying regime, referred to as the capillary regime (Je ≈ Jc ), will form when the rate of evaporation in the beginning is much larger than the capillary backflow; though, it will stabilize later on (Fig. 3b). In this regime, a drying front develops from the injection well into the aquifer (Peysson et al., 2014; Pruess and Müller, 2009). As the drying front advances, the evaporation rate at the front declines (water vapour pressure increases), whereas the capillary backflow gradually grows (brine saturation gradient increases). Eventually, the capillary backflow equalizes the evaporation flux (steady-state reached) and the drying front stabilizes, ceasing advancement (Kim et al., 2012). In addition, since the evaporation rate is high, relatively speaking, there is not sufficient time for the resulting salt concentration gradient to diffuse away from the drying front. The ultimate consequence of these mechanisms is a massive accumulation of salt at the drying front termed as “local salt precipitation”. However, salt uniformly distributes in the dryout zone left behind the drying front. The simulation performed by Kim et al. (2012) suggested that salt accumulation acts like a barrier separating the dried zone from the rest of the reser-

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voir inducing pressure disequilibrium. They suggested that the nature of injectivity impairment in this case differs from the dry-out zone and is due to pressure build-up caused by the salt barrier. However, recent pore scale experiments have shown that salt accumulation at the evaporation front actually has a porous and permeable structure (Miri et al., 2015), implying pressure continuity between the saturated zone and the dryout zone. Therefore, the injectivity reduction in this case is of the same type as within the dry-out zone and is merely due to a permeability reduction due to local salt distribution. (3) The third drying regime, referred to as the evaporative regime (Je  Jc ), is reached when the injection rate is greater than a critical limit (André et al., 2014; Giorgis et al., 2007; Kim et al., 2012; Ott et al., 2011, 2015) so that the rate of evaporation remains larger than the rate of capillary backflow even when the drying front advances far into the aquifer (Fig. 3c). The drying front is in this case advancing with a constant velocity toward the interior of the reservoir while immediately evaporating the trapped brine along the migration path. It is generally accepted that salt distributes homogenously in this region; yet, there is room for discussion on the extent of precipitation that takes place. Almost all analytical and numerical models predict a constant amount of precipitation corresponding to the salt content of the trapped brine in the pores or as liquid films around the grain surfaces (Giorgis et al., 2007; Pruess and Müller, 2009; Zeidouni et al., 2009a). However, recent research (Miri et al., 2015) has shown that owing to strong capillary suction of precipitated salt, the extent of precipitation could be much greater than the salt content in the residual trapped water alone. Moreover, salt distribution is semi-homogenous in form of detached clusters of precipitant surrounded by CO2 . In this region, the injectivity impairment, if any, is due to the permeability reduction.

3.1.2. Is the salt precipitation only a near-well phenomenon? It is of great interest to properly predict whether and where the local salt accumulation occurs, as this will impact injectivity most intensely. The results presented by Roels et al. (2014) suggested that the local salt accumulation in the field may occur far from the injection well where the flow velocities are much smaller. They argued that the current numerical simulations (e.g. TOUGH2/ECO2N) predict near well salt accumulation even for a diffusive drying regime (where we normally expect a homogenous distribution of precipitants) that is principally due to improper application of a local equilibrium phase partitioning. Quite oppositely, many research works; e.g. (Bacci et al., 2011; Kleinitz et al., 2001; Pruess and Müller, 2009; Van Dorp et al., 2009), point out that precipitation takes place predominantly in the near wellbore area where gas velocity is high, thus inducing evaporation the foremost. This type of precipitation is a characteristic of a capillary drying regime. The core flooding experiment of Peysson et al. (2014) has also supported this behaviour. The saturation distribution obtained from the experiments clearly shows formation of a drying front during the late stage of drying, developing toward the interior of the core sample, while the precipitation accumulation occurs only in the first 5 mm of the core. This can be explained by strong salt capillary suction and also with a self-enhancing mechanism as recently suggested (Miri et al., 2015), meaning that once salt formation is locally initiated it preferentially accumulates at these localities. In summary, we believe that the apparent disagreement on the location of salt accumulation could be answered through application of the presented drying regimes. In other words, if the injection is within capillary drying regime, massive pore clogging will likely occur in the near well zone, whereas within diffusive or evaporative drying regimes the precipitation will be less concentrated.

Fig. 4. Micro-scale representation of physical mechanisms contributing to the evaporation-precipitation process.

3.2. Microscopic view Studies on the pore scale examination of salt crystallization have revealed that salt crystals, although at different rates, grow in both the liquid and gas phases (Kim et al., 2013; Miri et al., 2015). The experiments suggest two principal mechanisms by which salt precipitates out of aqueous phase. The first form of crystallization involves relatively large single crystals growing in the aqueous phase, specifically in the low injection rate (i.e. low evaporation rate) when they have sufficient time to grow before liquid thinning begins. The second form involves the growth of aggregates of micro-meter size salt crystals in the gas phase. These structures are characteristic of the evaporation regime owing to quick supersaturation (Kim et al., 2013; Miri et al., 2015). The mechanisms involved in driving evaporation and salt crystallization are very complicated at pore scale. Due to capillary forces, the wetting phase (brine) has a tendency to collect as thick films in the corners of angular pores. However, other configurations such as brine pools, brine domes and liquid bridges also have been documented (Miri et al., 2015). The contact line of each of these evaporating meniscus can be divided in three parts as schematically shown in Fig. 4: The adsorbed region, where a disjoining pressure has been interpreted to dominate the local atomic forces; the bulk meniscus region, where the interfacial curvature has been interpreted to govern the driving physics through surface tension; and the transition or thin-film region in between, where both the disjoining pressure and the interfacial curvature have been interpreted to share a comparable influence (Miri et al., 2015). Numerical simulations have confirmed high evaporative flux at the contact line of the thin-film region (Barmi and Meinhart, 2014; Deegan et al., 1997, 2000; Yunker et al., 2011). Because of this, salt supersaturation increases close to the corners creating a chemical potential difference inside the trapped brine. Therefore contact line evaporation first induces a convective flow of brine to the corners driven by osmotic forces, and secondly a mass flux of dissolved salt ions under diffusion. Remarkably, the crystallization lowers the interfacial tension (Shahidzadeh-Bonn et al., 2008) which in turn induces a Marangoni flow led by surface tension gradients toward the precipitation sites. Thus, salt crystallisation is expected to occur preferentially on the corners and grow with time owing to the convective flow within the aqueous phase. The accumulation of crystals on the corners leads to further spreading of the wetting film with

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Fig. 5. This image shows (a) salt precipitation in a magnified portion of a homogenous micro-chip (Miri et al., 2015). The close-up shows that the porous structure of the precipitated salt. Aggregates are supported with the transport of water through the capillary continuous water films, (b) massive salt aggregation in porous network of micro-chip.

time as brine is drawn from the aqueous phase onto the salt surfaces in the CO2 stream, where evaporation leads to super-saturation and further nucleation and crystallization. Pore-scale observations from our recent study (Miri et al., 2015) suggested that the salt aggregates growing in the CO2 phase have a close-fitting structure with narrow pores which implies massive capillarity (Fig. 5a). Due to the strongly attracted thin films of water forming on salt surfaces, this porous structure can sustainably imbibe brine over long distances to the evaporating front via interconnected water films. The imbibed brine will consequently evaporate on the aggregate, facilitating continued precipitation. The newly precipitated salt provides additional surface area for evaporation which rapidly increases with time. The result of this mechanism is a large accumulation of salt in the form of aggregates in the gas phase (Fig. 5b), which is self-enhancing through the creation of an additional surface area where brine is exposed to CO2 . 3.2.1. Microscopic distribution of salt crystals It is of great importance to know the microscopic pattern of precipitants, since this builds the basis for clogging models which strongly controls the capability to predict the extent of formation damage. The primary impact of the precipitation is to occupy a part of the space earlier available to flow, thus reducing the average porosity of the medium. Experimental works show that a moderate change in porosity (due to salt precipitation) might have a severe effect on permeability. Permeability reductions of 60% (Muller et al., 2009), 30–86% (Bacci et al., 2011), 75% (Ott et al., 2011) and 50% (Peysson et al., 2014) have been estimated due to halite precipitation in the pore network of the Berea sandstone. In addition, salt crystals change the morphology of the porous medium (i.e. the geometric properties of the pore channels) by coating over framework grains and bridging pore-throats (Muller et al., 2009). The clogging models aim to find an intrinsic relation between porosity and permeability caused by alteration in pore size distribution. This is a classical problem in the field of petroleum engineering, and numerous models have been developed for different processes so far. However, most of the existing models in the literature are developed for precipitation of minerals, and they may not be directly applicable to the evaporation-precipitation process. Depending on the pores and throat fraction, reservoir chemistry and whether salt precipitates in the pore body or the throat, the consequential effect on permeability may be significantly different than measured for the precipitation of other minerals. There are two approaches to modelling the effect of porosity on permeability reduction. In the first school of thought it is assumed that salt essentially precipitates only in the brine phase and therefore has insignificant or no influence on the gas phase percolation pathways. Based on this assumption, which is also supported experimentally

by Ott et al. (2014) and Ott et al. (2015), a new clogging model is suggested (Liu et al., 2013). However, as shown by Miri et al. (2015), significant quantities of salt can precipitate in the gas phase due to surface energy driven transport of brine to growing salt aggregates. This observation obviously contradicts with the Liu et al. (2013) clogging model. In the second approach, a homogenous layer of salt covering grain surfaces is proposed. The most popular model in this category is the one given by Verma and Pruess (1988), where a porous medium is conceptualized as a series of connected tubes of varying sizes. The permeability reduction in this model is dominated by throats (tube with smaller size) and therefore the model is capable of predicting drastic permeability reductions corresponding to the local salt accumulation. In other words, when using the Verma and Pruess model it is expected that permeability reduces to zero as soon as the porosity is reduced to 50% or less. Roels et al. (2014) discussed that applying such a model might predict unphysical amounts of salt accumulating near the inlet (e.g. see Section 3.1). Still in the same category, Zeidouni et al. (2009a) have utilized the Kozeny–Carman relationship in conjunction with parameter values like those used by Pruess and Müller (2009) to simulate the process of salt precipitation. They, however, did not find significant permeability reduction. Others have suggested adjustment of the clogging model parameters using experimental analysis, yet, the predictions are place of question due to lack of actual physics included in the models (Bacci et al., 2013, 2011; Hurter et al., 2007). Therefore, the degree of uncertainty associated with clogging models is very high. Further improvement in this area, however, could be obtained by means of pore scale models such as Lattice Boltzmann method (Huber et al., 2014). 4. Sensitivity of governing parameters The above review of the performed numerical and experimental works on salt precipitation shows that the phenomenon is a complex process depending on several parameters, including thermodynamic conditions (pressure, temperature, salinity, composition of CO2 and brine), injection scheme (injection rate, time frame), rock and fluid properties (porosity, permeability) and well completion scheme. In the following some of the most challenging parameters have been reviewed in more detail. 4.1. Salinity Salinity of the aquifer may be the most influential parameter with respect to salt formation, controlling the onset and extent of precipitation. As it is shown in Fig. 6, increasing brine salinity causes a slight decrease of water solubility in the CO2 phase (i.e. decrease in rate of evaporation). However, a noteworthy drop in the dissolution

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Fig. 6. Effect of salinity on the mutual solubility of CO2 and water at 348.15 K and different pressure (Ji et al., 2005; Miri et al., 2014).

of CO2 in the brine is observed (Miri et al., 2014; Spycher and Pruess, 2010). It is broadly accepted in the literature that higher salinity gives rise to higher amounts of salt precipitation and therefore leads to higher porosity reduction. Despite this general notion, severe salt precipitation may also occur in aquifers with intermediate salinity (Giorgis et al., 2007). To the best of our knowledge, the boundaries for risky salinities have not been defined so far. However, there are indications of its dependence on the injection rate (André et al., 2014; Hurter et al., 2007; Kim et al., 2012; Ott et al., 2014; Tang et al., 2014; Zeidouni et al., 2009b). It has been shown that reservoirs displaying low to intermediate permeabilities are most vulnerable at low injection rates regardless of formation water salinity (Kim et al., 2012). Accordingly, for reservoirs of low salinity and high permeability, such as the Utsira Formation at the Sleipner Field in the North Sea (3.5% salinity and ∼1 Darcy permeability), field observations of injectivity impairment or well clogging are not reported so far (Eiken et al., 2011). However, for the Ketzin storage site, in a reservoir with high salinity (25%) and intermediate permeability (∼100 mD) salt precipitation has been reported as the main reason for pressure build-up in the course of CO2 injection (Grude et al., 2014). In fact, the lower injection rate (∼100 t/day) compared to Sleipner (∼2800 t/day) accompanied by higher salinity are the key parameters explaining massive salt precipitation in this case, although, the reservoir characteristics at Ketzin may not tolerate higher rates of injection.

4.2. Injection flow rate Among all parameters governing the precipitation process, the most controversial results have been reported for the effect of the CO2 injection rate. Keeping in mind the determinative role of the flow rate in the injectivity calculation, explaining these differences can be an essential step to improve our understanding of the physics of the precipitation process. Some research suggests that a high injection rate will induce a higher pressure gradient, thus suppressing the capillary backflow towards the evaporation surface (André et al., 2014; Giorgis et al., 2007; Hurter et al., 2007; Kim et al., 2012; Pruess and Müller, 2009). The reduced capillary flow, in turn, reduces the possibility of intensive salt accumulation. Utilizing an analytical model for the vaporization-precipitation process, Zeidouni et al. (2009a) showed that the extent of salt precipitation is determined by the combined effect of aqueous phase mobility and vaporization rate. An increase in the injection pressure will slow down the plume mobility owing to increased viscosity of the scCO2 phase, but further evaporation at higher injection pressures will

increase the amount of precipitation. In other words, their results show that an increase in evaporation rate is more significant than a decrease in capillary back-flow, which seems to contradict previous findings. Irrespective of the actual physical impact of the injection rate, many attempts have been made to define a relationship for the critical velocity above which the massive salt accumulation corresponding to the capillary drying regime can be avoided. Most of these studies, however, lack a theoretical basis, and findings strongly depend on the thermodynamic conditions and rock properties of the tests (André et al., 2014; Giorgis et al., 2007; Ott et al., 2015). As a result, the findings of such studies are case dependent and lack generality. 4.3. Capillary pressure It is generally accepted that capillary pressure serves to increase the rates of evaporation by supplying fresh brine to the drying front. But the numerical simulations performed with different codes in order to evaluate the effect of capillary pressure have reported dissimilar results. Pruess and Müller (2009) showed that activating the capillary pressure option in the simulations only alters the precipitation patterns and has a limited effect on the amount of precipitation. In contrast, Hurter et al. (2008) pointed out the capillarity as a significant driver to the salt formation so that no precipitation will occur if one disregard it in the simulations. A more recent study by Miri et al. (2015) revealed that salt aggregates forming in the gas phase also have significant capillarity owing to their micro-porous structure and therefore strongly imbibe brine over long distances to the evaporation front. This type of capillary pressure, however, is not implemented in the current numerical tools and requires further consideration. 4.4. Aqueous phase mobility The shape and endpoint of the aqueous phase relative permeability curves are critical parameters controlling the balance between viscous and capillary forces. With increasing brine mobility the velocity of the flooding front also increases allowing for less gaseous phase encroachment. The resulting increase in the local gas saturation reduces the brine saturation at dry-out fronts, thereby decreasing the amount of salt precipitation (Zeidouni et al., 2009b). It is also important to distinguish between the aqueous phase relative permeability and the local gas saturation, since the latter one, unlike the former, positively contributes to the salt precipitation. The brine relative permeability can even be increased by decreasing

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Fig. 7. Solubility of water in CO2 phase (left) and density difference between CO2 and brine (right) for different pressures and temperatures (Ji et al., 2005; Miri et al., 2014).

the residual water saturation. In order to understand the combined effect of these two parameters, Giorgis et al. (2007) have tested the salt formation under different CO2 injection rates. They reported that above a critical injection rate the solid saturation decreases due to limiting capillary back flow irrespective of initial brine saturation. 4.5. Temperature The vertical migration of CO2 plumes primarily depends on the vertical permeability and the density difference between the injected CO2 and host brine. As it is shown in Fig. 7, increasing temperature causes a noticeable increase of water solubility in the CO2 phase. As a result, the water quickly reaches its saturation limit and salt will precipitate. In addition, elevated CO2 temperature decreases the CO2 density, thereby enhancing the gravity override (Fig. 7) which at the same time proceeds to localized salt precipitation at the dry-out front (Kim et al., 2012). A more general description of the effect of temperature on salt precipitation suggested a pressure dependency so that at higher pressures salt precipitation is observed to be increasing with increases in temperature, while at lower pressures there is an initial decline in the salt precipitation as temperature increases (Zeidouni et al., 2009b). Nevertheless, the impact of temperature on salt precipitation is likely to be much smaller than parameters such as injection rate and capillary pressure. 5. Mitigation strategies Since there is limited knowledge on the physics of salt precipitation in saline aquifers, on the governing spatiotemporal parameters, and on the subsequent impact on the pore morphology, only very few mitigation options have been proposed for this issue up until now. The simplest strategy is to disregard reservoirs with poor rock quality because the formation injectivity is inherently low even without considering the effect of the precipitated salt. The most popular option in the CCS community, however, is the treatment with fresh water. This option may be used either after clogging to dissolve precipitated salt or in the form of pre-flushing prior to CO2 injection, thus decreasing salinity of near-well brine. While technical considerations regarding the design of fresh water injections still require experimental investigation, feasibility of the method has frequently been confirmed by numerical simulations (Hurter et al., 2008; Muller et al., 2009). Hurter et al. (2008) simulated CO2 injection in a saline aquifer for a period of two years and com-

pared the results with a second case where fresh water was injected for one month. The case with fresh water pre-flushing showed a smaller amount of salt precipitation and significantly reduced pressure build-up close to the injection well. Rock alteration tests have also shown that, while using fresh water as a solvent initially can led to recovering the permeability of the sample, there is a very high risk of further injectivity loss in the later stages owing to sequential changes in the rock pore size distribution (Bacci et al., 2013). Experience from CO2 injection in the Tubåen Formation at the Snøhvit Field has shown that the weekly injection of a 90:10 mixture of methyl ethyl glycol and water (MEG) can effectively overcome the low injectivity (Grude et al., 2014; Hansen et al., 2013). Another methodology is utilizing highly permeable materials as fill between the borehole and the aquifer along the perforation interval, a methodology well proven in the fields of groundwater and petroleum geoscience. Kim et al. (2012) used numerical simulations to investigate the feasibility of this method to avoid near well pressure build-up induced by precipitated salt. The pressure build-up and salt saturation profiles were obtained by varying the permeability and porosity of the skin zone. They showed that the injectivity is most sensitive to permeability. Thus, utilizing highly permeable material fillings can significantly reduce the injectivity impairment caused by salt precipitation. 6. Summary and conclusions This review of the current literature on formation dry-out indicates that the precipitation of salt might be a real threat for actual field scale injection of dry CO2 in saline aquifers. The destructive impact of precipitation to the intrinsic reservoir rock properties such as porosity and permeability has been clearly demonstrated through numerous experimental and numerical studies accomplished on micro to field scale. Nevertheless, despite the threat and importance, little success has been achieved on the quantification of the expected impact on the formation injectivity and near-well pressure build-up. Some studies even reported injectivity improvement following salt precipitation in contrast to the common opinion of injectivity loss. Therefore, the present day uncertainty regarding injectivity alteration caused by salt precipitation is very high. Several investigations have shown that under certain thermophysical conditions belonging to the capillary drying regime salt might massively precipitate during the course of CO2 injection. However, a clear measure of necessary conditions is not provided so far. This is mainly because conducted studies are largely qualitative and case specific, thus; drawing a general conclusion is challenging.

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In fact, it is widely accepted that there is a critical velocity above which local salt accumulation occurs, but a proper formulation is not given. In addition, much of the literature agrees that the extent of salt precipitation at higher salinity is significantly higher. Then again, a critical salinity limit is not defined at this point, but there are some notions that such a limit will depend also on a critical flow rate. In addition, there are several weaknesses in relation to laboratory tests, including (1) the lack of measurements of effective permeability, (2) improper design of the experiments in accordance with actual reservoir conditions (e.g. ignoring the significant role of water films and the use of closed boundaries preventing inflow of brine), (3) incomplete coverage of pressure, temperature and salinity relevant to long term CO2 injection, (4) lack of complying with a standard procedure so that results of tests which are carried out in different situations, are not comparable. Furthermore, the existence of several discrepancies between the experimental results and the numerical calculations indicate that the state-of-the-art knowledge regarding modelling of salt precipitation is not commensurate with the complexity of the issue. Although more is being learned about the fundamental mechanisms and the clogging behaviour of the phenomenon, further research on the mathematical modelling is the most demanding task today. Performing dimensional analysis to find a relationship between the dependent variable and independent variables of the phenomenon could help to reduce the reported inconsistencies. Future efforts in implementing salt capillary pressure and development with the aid of pore scale modelling are expected to help progress in this area. Lastly, an assessment of the different criteria for the application of the various mitigation options needs to be extensively undertaken. Nevertheless, fresh water treatment appears to be a viable mitigation option, which, if carefully controlled, could prove to be an effective method to move the risk from the area near the well to somewhere deeper within the aquifer reservoir. Acknowledgments This work was partly funded by the Research Council of Norway (RCN) and industry partners through the project 190002/S60 Subsurface storage of CO2 —Injection well management during the operational phase (Inject). The work has also been partly funded by the University of Oslo and the SUCCESS Centre for CO2 storage under grant 193825/S60 from the RCN. References André, L., Peysson, Y., Azaroual, M., 2014. Well injectivity during CO2 storage operations in deep saline aquifers—part 2: numerical simulations of drying, salt deposit mechanisms and role of capillary forces. Int. J. Greenh. Gas Control 22, 301–312. Bacci, G., Korre, A., Durucan, S., 2011. Experimental investigation into salt precipitation during CO2 injection in saline aquifers. Energy Procedia 4, 4450–4456. Bacci, G., Durucan, S., Korre, A., 2013. Experimental and numerical study of the effects of halite scaling on injectivity and seal performance during CO2 injection in saline aquifers. Energy Procedia 37, 3275–3282. Barmi, M.R., Meinhart, C.D., 2014. Convective flows in evaporating sessile droplets. J. Phys. Chem. B 118, 2414–2421. Baumann, G., Henninges, J., De Lucia, M., 2014. Monitoring of saturation changes and salt precipitation during CO2 injection using pulsed neutron-gamma logging at the Ketzin pilot site. Int. J. Greenh. Gas Control 28, 134–146. Bette, S., Heinemann, R., 1989. Compositional Modeling of High-Temperature Gas-Condensate Reservoirs With Water Vaporization. Paper SPE 18422, 6–8. Cinar, Y., Riaz, A., 2014. Carbon dioxide sequestration in saline formations: part 2—review of multiphase flow modeling. J. Petrol. Sci. Eng. 124, 381–398. Deegan, R.D., Bakajin, O., Dupont, T.F., Huber, G., Nagel, S.R., Witten, T.A., 1997. Capillary flow as the cause of ring stains from dried liquid drops. Nature 389, 827–829. Deegan, R.D., Bakajin, O., Dupont, T.F., Huber, G., Nagel, S.R., Witten, T.A., 2000. Contact line deposits in an evaporating drop. Phys. Rev. E 62, 756.

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