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Injection of in-situ generated CO2 microbubbles into deep saline aquifers for enhanced carbon sequestration
International Journal of Greenhouse Gas Control 83 (2019) 256–264
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International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
Injection of in-situ generated CO2 microbubbles into deep saline aquifers for enhanced carbon sequestration
T
Seokju Seoa, Mohammad Mastiania, Mazen Hafeza, Genevieve Kunkela, Christian Ghattas Asfoura, Kevin Ivan Garcia-Ocampoa, Natalia Linaresa, Cesar Saldanaa, Kwangsoo Yangb, ⁎ Myeongsub Kima, a b
Department of Ocean and Mechanical Engineering, Florida Atlantic University, 777 Glades Road, Boca Raton, FL33431, USA Department of Computer & Electrical Engineering and Computer Science, Florida Atlantic University, 777 Glades Road, Boca Raton, FL33431, USA
ARTICLE INFO
ABSTRACT
Keywords: Carbon sequestration CO2 dissolution CO2 injectivity Deep saline aquifers Microfluidics
Carbon sequestration into deep saline aquifers has been considered a promising technology for mitigating heavy atmospheric carbon dioxide (CO2) concentration. When gaseous CO2 is continuously injected into these aquifers, resident brine near a wellbore area is rapidly evaporated while precipitating significant amounts of salt at pores, thereby damaging the aquifer media unfavorable for subsequent CO2 injection. In addition, the continuous injection of CO2 at a large volume significantly hinders dissolution of CO2 into brine. In this study, we propose a new method of sequential water injection with gaseous CO2 for in-situ generation of micro-sized CO2 bubbles that minimizes the brine drying-out and simultaneously accelerates CO2 dissolution. We observed that, with this method, a partial volume of CO2 dissolves effectively into the co-injected water during pumping, thereby decreasing the rate of brine drying-out at pores. Another benefit of sequential injection is the significantly increased rate of CO2 hydration induced by the large surface-to-volume ratio of tiny bubbles at micro to nanoscale. To further accelerate CO2 hydration, we investigated reactive dynamics of bubble-driven CO2 hydration at different frequencies of sequential injection and pH levels of the solution. Operation at a higher frequency with higher basicity proved to be the most effective in decreasing the bubble size and therefore accelerating CO2 hydration into brine, which is a more feasible CO2 storage plan.
1. Introduction
of saline formations in the near-wellbore (Fuller et al., 2006; Kim et al., 2013) and the slow rate of CO2 hydration (Bhaduri and Šiller, 2013; Seo et al., 2017, 2018b). The large volume of continuous CO2 injection creates a dried zone near the injection well (Miri and Hellevang, 2016; Peysson et al., 2014). In the dried zone, the majority of the pores contain trapped brine that will be eventually evaporated while salinity of brine increases due to continuous CO2 injection (Miri and Hellevang, 2016). The brine drying-out results in salt precipitation and the precipitated salt blocks pores leading to a significant reduction in CO2 injectivity. Salt precipitation near the wellbore in the field-scale projects has been reported at the Snøhvit field (Grude et al., 2014; Hansen et al., 2013) and the Ketzin pilot reservoir (Baumann et al., 2014), respectively. Especially, a rapid pressure increase by salt precipitation was observed after 5000 h of CO2 injection, resulting in a significant decrease in injectivity at the Snøhvit field (Grude et al., 2014). Some laboratory studies have investigated the rate of brine drying-out under different injection/fluid conditions and found important controlling
Carbon capture and sequestration (CCS) technology has been proposed as a promising method of global carbon dioxide (CO2) mitigation (Gunter et al., 1998; Herzog, 2001). This technology aims to capture CO2 from industrial and power plant combustion processes, and then store the captured CO2 away in safe areas (e.g., depleted oil and gas reservoirs, unmineable coal seams, and deep saline aquifers) to prevent it from reaching the atmosphere. Among various possibilities, CO2 injection into geological formations has proven to be the most attractive method at a reasonable cost. Specifically, deep saline aquifers, defined as porous and permeable reservoir rocks containing brine, located at 800 to 2000 m from the surface level are widely available for CO2 storage with the injection rate at more than 1 metric megaton per year (Chow et al., 2003). Although the storage capacity of these aquifers is known to be tremendous, the potential of this option is currently limited by drying-out
⁎
Corresponding author. E-mail address: [email protected] (M. Kim).
https://doi.org/10.1016/j.ijggc.2019.02.017 Received 17 October 2018; Received in revised form 26 February 2019; Accepted 27 February 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.
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parameters for this phenomenon (Peysson et al., 2014; Pruess and Müller, 2009; Rathnaweera et al., 2016; Zhao and Cheng, 2017). CO2 flow rates at 0.0083–0.83 mL/s (Miri et al., 2015) and 0.667 mL/s (Wang et al., 2017) have been used to study the mechanisms of salt crystallization and the changes in formation properties, respectively. In addition, a range of salinity at 0.25–25% has been used (Tang et al., 2015); note that the salt concentration of real brine has been found at 0.71–35% (Michael et al., 2010). Another technical challenge to the feasibility of CO2 sequestration in saline aquifers is the slow reaction rate of carbonic acid (H2CO3) formation from CO2 hydration (Bhaduri and Šiller, 2013; Seo et al., 2017, 2018b). This slow reaction rate can be negatively impacted further by brine containing high salinity contents in natural formations. When CO2 dissolves into brine, the CO2-saturated brine sinks toward the bottom of the aquifers and thereby reduces the risk of CO2 leakage since the density of CO2-saturated brine is greater than that of the original brine (Pau et al., 2010; Zhang and Song, 2014). The dissolved CO2 will combine with metal cations leading to precipitation of minerals. Resultantly, properties of brine in porous media are changed to be the favorable condition for increasing permanent storage of CO2. Therefore, to accelerate CO2 dissolution into deep saline aquifers, a new methodology needs to be developed. The brine drying-out, salt precipitation, and slow CO2 hydration are attributed mainly to a continuous injection of CO2 to the formation fluid. Over the years, many methods other than the continuous injection of CO2 have been proposed to resolve these challenges. For minimizing the brine drying-out, one study suggested a preflush of the saline formation with fresh water and it showed that this method delayed the onset of salt precipitation and reduced its severity significantly. For enhancing CO2 hydration, an ex-situ dissolution of CO2 via an external reactor (Leonenko and Keith, 2008; Zendehboudi et al., 2011; Zirrahi et al., 2013a, 2013b), a reverse gas-lift technology (Shafaei et al., 2012), a static mixer at the bottom of well (Zirrahi et al., 2013a, 2013b), the injection of nanosized CO2 bubbles (Uemura et al., 2016), and catalyst addition to the injection fluid (Seo et al., 2018b, 2017) have been proposed. Among these strategies, the injection of CO2 bubbles, instead of the CO2 stream, has shown promising results to accelerate CO2 hydration remarkably (Leonenko and Keith, 2008; Uemura et al., 2016; Zendehboudi et al., 2011). One limitation of this method is that the pumping process to generate CO2 bubbles in external reactors requires huge energy consumption. Although numerous studies have shown the important mechanisms associated with the brine drying-out and CO2 hydration, they still lack a practical strategy to resolve these concerns. In this study, we present a practical methodology that could address these challenges: significant reduction of drying-out and acceleration of CO2 hydration by sequential injection of water with CO2 into the formation. It is broadly known that the sequential injection of CO2-water into a pipeline will generate various CO2 bubbles in their size due to the gas-liquid two-phase flow (Abdulmouti, 2014; Das et al., 2009). In the literature, it is well known that the fragmentation of large air cavities by the turbulent flow can produce submillimeter bubbles (RodríguezRodríguez et al., 2015). Especially, after the liquid flow has established in a large reactor or tubing, microbubbles can be generated by injecting a short burst of gas into the liquid flow using a solenoid valve (Millard et al., 2015; Ohl, 2001). We hypothesize that the sequential injection of water with CO2 into the aquifers increases the CO2 dissolution rate by producing microsized bubbles in the reservoirs and also effectively decreases brine evaporation by supplying fresh water to salt-saturated pores. This study aims to test this hypothesis and provide a new venue for geologic CO2 injection while minimizing the brine drying-out and maximizing CO2 storage capacity. The time-dependent brine evaporation, resultant salt precipitation, and formation of CO2 bubbles were visualized at high-speed through a microfluidic technique. Microfluidics allowed us to quantify the amounts of brine evaporation and mobile free-phase CO2 successfully by measuring both the velocity of
the liquid−CO2 interface and the amount of gaseous CO2 at pore-scale. The results show that the amount of mobile free-phase CO2 injected, which is one of the main sources for the brine drying-out, can be reduced by changing the frequency of sequential injection and pH levels of the injected solution. 2. Materials and methods 2.1. Microfluidic platforms A microfluidic approach was used to visualize and quantify phase equilibria and fluid transport associated with brine evaporation and CO2 dissolution at the pore scale. The potential of this technique to examine phase change analyses and fluid transport at micro- to nanoscale has been proven in many studies due to the fast mass transfer at these scales and its excellent capability for visualization of multiphase flow (Kim et al., 2013; Mastiani et al., 2018, 2017a, 2017b; Seo et al., 2018a). In this approach, an experimental platform containing fluidic channels, called a microfluidic chip, is essential. Microfluidic chips were fabricated by laser ablation using a laser cutter (VersaLaser VLS2.30, Universal Laser Systems, Inc.). Poly(methyl methacrylate) (PMMA) was used for a chip material due to its high chemical resistance and mechanical stability (Sher et al., 2017). As illustrated in Fig. 1, the microfluidic chip consists of 1000 μm wide straight channels for supplying gaseous CO2 and isolated pore channels for trapping brine. The height of all channels is 1500 μm. 2.2. Experimental procedure All tests were performed by pumping fluids under two different conditions: continuous and sequential injection (Fig. 1a). For the continuous injection of CO2 (Fig. 1b), once the microfluidic chip was filled with brine at different salinities, a clamping device sealed the inlet port for the solution to prevent backflow of trapped brine induced by injection of CO2. Then, the CO2 gas with 99.9% purity (Airgas®, Miami, FL) was introduced to the microfluidic chip at different flow rates through the connected inlet port to a regulator mounted on a CO2 tank. For the sequential injection of water with CO2, a fast switching mechanism of a three-way solenoid valve operated by microcontrollerbased (Arduino Uno) electronic control circuits (Fig. 1c) was employed. Two inlets of this solenoid valve were connected to a syringe pump (PHD ULTRA™ 4400, Harvard Apparatus, Natick, MA) and the CO2 regulator. This valve sequentially injected water at 0.03 mL/s from the syringe pump and CO2 gas at 118 mL/s from the tank into the microfluidic platform. This ensures precisely controlled frequencies (0.1 to 0.5 Hz) of sequential injection of water with gaseous CO2. When gaseous CO2 was sequentially introduced with water, CO2 bubbles with a diameter range of 40–150 μm were generated in the trapped brine. The microbubble is defined as bubbles having a diameter less than few hundred μm in this study similar to that in the previous literature in the field of fluid physics (Parmar and Majumder, 2013). Once the tests for CO2 bubble formation at different frequencies were completed, the behavior of brine evaporation and the amount of mobile free-phase CO2 in brine were investigated at various pH levels of pumping water (pH 3, pH 7, and pH 11). A high-speed camera (Fastec IL5S, Fastec Imaging, CA) attached to an inverted microscope (IX73, Olympus Corporation, Japan) was used to capture time-resolved images of the liquid-gas interface and the amount of trapped CO2 in brine. 2.3. Materials and experimental conditions For the fabrication of microfluidic devices, PMMA sheets were purchased from Good Fellow (Berwyn, PA). Sodium chloride (NaCl, ≥99.5% purity), sodium hydroxide (NaOH, ≥98% purity), hydrochloric acid (HCl, 37%), and phosphate buffer powder were purchased from Sigma − Aldrich (St. Louis, MO). One millimolar (mM) phosphate 257
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Fig. 1. (a) Schematic of the experimental setup (not to scale). (b) Continuous CO2 injection to the microfluidic chip with time-dependent brine evaporation at the trapped channel. (c) Sequential water−CO2 injection to the same channel generating CO2 microbubbles.
buffer solution used in all tests was prepared using deionized water produced from a Millipore Milli − Q integral 5 purification system (Millipore, Bedford, MA). Brine evaporation experiments were performed at concentrations of 0%, 5%, 10%, 20%, and 30% NaCl added to 1 mM phosphate buffer solution at different injection rates of dry gaseous CO2 (68, 97 and 118 mL/s). Then, the highest salinity at 30% with the highest injection rate of dry CO2 at 118 mL/s was used to investigate how effectively sequential water injection with CO2 can reduce brine evaporation and the amount of gaseous CO2 in brine. The pH of the sequential water was titrated to desired levels that were created by adding either one M of HCl or NaOH while monitoring with a pH meter (Accumet AE150, Fisher Scientific, Pittsburgh, PA). All experiments were performed at room temperature of 25 °C and atmospheric pressure. An atmospheric pressure condition was used at the outlet.
determined through the projected area of CO2 bubble. Then, the CO2 bubble volume (V = (4/3)π(D/2)3) was determined using the average diameter (D) of CO2 bubbles. 3. Results and discussion 3.1. Continuous injection of CO2 The experiments on the water evaporation at various salinity levels and CO2 flow rates were performed to characterize how different fluid and flow rate conditions in deep saline aquifers influence the brine drying-out. Fig. 2 shows time-lapse optical microscopy images of changes in the gas-liquid interface at an isolated pore channel. The interface was formed when dry gaseous CO2 was continuously injected at 68, 97 and 118 mL/s at different salinities (0, 5, 10, 20, and 30% NaCl). In these conditions, CO2 velocities are 23.51, 33.25, and 40.72 m/s, which represent assumed conditions around injection wells at the CO2 storage site. In general, as the volume flow rate increases, the speed of interface retraction also increases; for example, compare timedependent changes in the location of the interface at 0% salinity in Fig. 2a and c. This behavior was quantitatively analyzed by tracking changes in volume of evaporated brine at a T-junction (Fig. 3). Approximately 2.2 μL of volume of pure water in the channel was evaporated within 120, 46, and 4.6 s at 68, 97 and 118 mL/s of CO2 flow rates, respectively. This analysis shows that the amount of brine
2.4. Image processing for evaporated brine and gaseous CO2 The volumes of evaporated brine and gaseous CO2 in the isolated pore channel were analyzed on the ImageJ software, an open-source image processing program. To measure brine evaporation in various conditions, the changes in the interface between CO2 gas and trapped brine in the isolated pore channel corresponding to water evaporation were tracked by the ImageJ. In addition, the volume fraction of the mobile free-phase CO2 in trapped brine was determined by changes in its volume at 0.04 s intervals. The CO2 bubble diameter (D) was 258
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Fig. 2. Sequential images for changes in the CO2-water interface location at a T-junction at different salinities (0, 5, 10, 20, and 30% NaCl) with different CO2 injection rates at (a) 68, (b) 97, and (c) 118 mL/s.
evaporated exponentially increased as CO2 flow rate increased from 68 to 118 mL/s. In general, an increase in air velocity over water leads to an increase in rate of escaping water molecules (Arnal et al., 2005). In line with this phenomenon, we observed forced convective mass transfer between horizontal CO2 gas flow and water increases with increasing gaseous CO2 flow rates. Reynolds numbers (Re) at different flow rates were determined to be 4464.37, 6313.92, and 7732.42 using 8.36 × 10−6 m2/s of kinematic viscosity of CO2 at 25 °C, 1.58 × 10-3 m of tubing diameter, and CO2 velocities at 23.51, 33.25, and 40.72 m/s. For the impact of salinity on brine evaporation, the kinetics of brine evaporation at different salinity levels are plotted in Fig. 4. This figure is determined by different slopes for the relationship between evaporated brine and the elapsed time (Fig. 3). As the concentration of salinity increases up to 10%, the evaporation rate decreases in all flow rate conditions. However, by increasing the salinity from 10% to 30%, an increase in the evaporation rate is observed in three flow rate conditions. The highest rate of evaporation was determined to be 0.57 μL/s under 30% salinity at the highest CO2 flow rate (118 mL/s). This decrease-to-increase behavior can be explained by an activity coefficient of NaCl solution controlling brine evaporation dynamics. The activity coefficient is used in thermodynamics to explain the behavior of chemical substances. As the activity coefficient decreases, the energy required to separate constituent molecules increases. Conversely, when the activity coefficient increases, molecules have a strong repelling force, and thereby less energy is required to separate them (Pitzer et al., 1984). Evaporation occurs when molecules in a liquid gain enough energy to overcome an attraction force from other molecules. The activity coefficients of brine at different salinities can be calculated from the electromotive force data by Hückel's equation (Harned and Nims, 1932).
Fig. 4. A diagram of changes in the evaporation rate of brine as a function of the salinity (0, 5, 10, 20, and 30% NaCl) with different CO2 injection rates (68, 97, and 118 mL/s) and the graph (◊) of the activity coefficients of NaCl solution at 25 °C.
log =
0.5067 IM 1 + 0.837 2IM
+ 0.0316 2IM
log(1 + 0.036M )
where IM, M, and γ are the ionic strength (mol/L), the concentration (mol/L), and the activity coefficient of NaCl solution at 25 °C, respectively. We estimated each value of the activity coefficient at different salinities ranging from 0% to 30% to characterize the salinity effect on the evaporation rate. A decrease in the activity coefficient while increasing the salinity concentration up to 7% led to a decrease in brine evaporation into the CO2 gas phase (Fig. 4). In contrast, increasing
Fig. 3. Variations of evaporated brine vs. elapsed time at different salinities and CO2 flow rates. (Error bars represent the standard error of the mean from triplicated experiments in each condition.) 259
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Fig. 5. Representative time-lapse optical microscopy images showing the generation and coalescence of CO2 microbubbles during sequential water−CO2 injection.
salinity concentration from 7% to 30% displays an increase in the activity coefficient to 0.869, resulting in a proportional increase in the evaporation rate of brine. The observations of our test results are in a good agreement with the theory of the activity coefficient. These microfluidic tests confirm that continuous injection of gaseous CO2 into deep saline aquifers may lead to an increase in risks of the brine dryingout. The extreme drying-out creates salt precipitation behind and causes formation damage. We observed that the degree of brine dryingout increases as CO2 flow rate increases at salinity greater than 10%.
microbubbles effectively with a large surface-to-volume ratio leading to significant improvement of a CO2 solubility trapping process because the mass transfer of gaseous CO2 into water will further increase with larger interface areas between these two phases. As in Fig. 5, due to the physical agitation, number and size of CO2 bubbles change over time. The figure shows that the onset of CO2 bubble formation is observed at a few locations at t = 1 s. The CO2 bubbles are accumulated immediately near the T-junction and start to coalesce due to the collision between the CO2 bubbles (see Video 2). It should be noted that microbubbles in an aqueous solution are negatively charged under a wide range of pH (Takahashi, 2005). However, as increasing the ionic strength in the aqueous phase, the reduction in the zeta (ζ) potential of microbubbles was reported (Takahashi, 2005). As a result, CO2 microbubbles in 30% NaCl near the T-junction are easily coalesced to minimize their surface areas when they are in touch. The size of CO2 bubbles apart from the T-junction is significantly decreased due to effective CO2 hydration. As typical natural saline aquifers are characterized as random porous structures, the directional water−CO2 injection into pore structures is certainly of interest. The pore-throat and pore sizes of typical sandstones range from 1 to 500 μm in conventional reservoirs (Nelson, 2009; Radlinski et al., 2004; Wardlaw and Cassan, 1979). To examine the behaviors of CO2 bubble generation in different geometries, transient CO2 bubble formation during sequential water and CO2 injection was recorded at different pore angles (30°, 90°, and 120°, Fig. 6 and see Video 3). The results show that an insignificant variation in the amount of CO2 bubbles was observed in the pore channel at these angles.
3.2. Sequential water injection with CO2 We hypothesized that sequential injection of water with CO2 addresses the challenge with the brine drying-out and provides another benefit to accelerate the rate of CO2 hydration. To test the feasibility of the sequential injection strategy, microfluidic experiments were performed in a simple T-junction microchannel. Fig. 5 shows representative images of CO2 microbubble generation in the microchannel taken by an optical microscope from selected time points (t = 1, 20, and 50 s) at a controlled frequency of 0.1 Hz. As pure water and CO2 were sequentially injected, CO2 microbubbles were generated due to the nature of two-phase flow (Abdulmouti, 2014; Das et al., 2009). Locations of the gas-liquid interface were maintained constant near the T-junction during sequential injection, which consequently delayed the evaporation rate of water. Not only does decreasing the brine drying-out and therefore reducing a risk of salt precipitation, but the sequential injection of pure water−CO2 also increases CO2 hydration into brine. The physical absorption of gaseous CO2 by the liquid phase is determined by Henry’s law.
Pco2 = kH [CO2 ]aq
3.3. Frequency effect
where kH is Henry’s constant for CO2 in pure water (3.45 × 103 kPa L/ mol), [CO2]aq is the concentration of dissolved CO2 in the aqueous phase, and PCO2 is the partial pressure of the CO2. The rate for this physical absorption can be increased further by agitation in the liquid phase (Noyes et al., 1996). The agitation can generate CO2
The high solubility coefficient of CO2 makes it immediately diffuse into an aqueous phase when it is in contact with water. In addition, as aforementioned the high surface-to-volume ratio will improve CO2 hydration into water. To further enhance CO2 gas dissolution and safe storage potential, generation of a much smaller volume of CO2 bubbles
Fig. 6. Representative microscopy images showing the generation and coalescence of CO2 microbubbles at different pore angles (30, 90, and 120° between an inlet channel with isolated pore channel) during sequential water−CO2 injection. 260
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Fig. 7. Time-dependent images of CO2 microbubble generation and coalescence near the T-junction at different water−CO2 injection frequencies (0.1, 0.2, and 0.5 Hz).
is important. We found that the frequency of water-gas injection plays a role in varying the gas bubble sizes. Fig. 7 shows the total volume of CO2 bubbles generated at t = 0˜60 s in a T-junction channel at frequencies of 0.1, 0.2, and 0.5 Hz. At a frequency of 0.5 Hz, number of CO2 micro-bubbles was increased as time increases while their sizes are less than 100 μm at t = 60 s. On the other hand, at 0.1 Hz number of CO2 bubbles was decreased while their sizes are greater than 500 μm at t = 60 s. This implies that an increase in frequency leads to a decrease in the volume of CO2 bubbles occupying the brine at the channel (VCO2/ VChannel) owing to improved CO2 hydration. Fig. 8 shows the change in ratio of the volume of CO2 bubbles to
trapped brine (VCO2/VChannel) in the microchannel at different frequencies. In agreement with the observation in Fig. 7, as the frequency increases, the volume of trapped water is slowly replaced by that of CO2 bubbles. Particularly at the 0.5 Hz, the volume of CO2 bubbles at 60 s was estimated to be approximately 2-fold smaller than that in the 0.1 Hz condition. These significant differences in the volume of CO2 bubbles trapped in brine at different frequencies can be characterized by bubbly two-phase flow. The volume of CO2 bubbles in bubbly twophase flow is likely to be dominated by the ratio of liquid-gas flow rates. Fraga and Stoesser (Fraga and Stoesser, 2016) revealed that smaller bubbles are generated when a high flow rate of an aqueous phase and a 261
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results can be explained by the behavior of the effective Henry’s constant (Seinfeld and Pandis, 2016). The total quantity of dissolved CO2 in brine includes the amount of all species of aqueous CO2, the intermediate bicarbonate (HCO3−) form, and the equilibrium carbonate (CO32-) form in water. First, physical absorption of CO2 into brine is governed by Henry’s law.
CO2(g ) + H2 O
CO2(aq) ,
kH =
PCO2 [CO2 ]aq
CO2 (aq) reacts with water to form carbonic acid (H2CO3), then dissociates into H+ and HCO3− ions at the intermediate stage.
CO2(aq) + H2 O H2 CO3
H+ + HCO3 ,
K1 =
Fig. 8. Variations in the ratio of the volume of CO2 microbubbles to the total volume of brine at the isolated channel at different injection frequencies. The inset figures represent images of the channel taken at t = 60 s.
H2 CO3
H+ HCO3 = 4.45 × 10 CO2(aq)
7
Then, HCO3− dissociates further into H+ and CO32- ions.
HCO3
low flow rate of a gaseous phase are mixed. In our tests, when a valve is operating at low frequency (0.1 Hz), CO2 gas is compressed, thereby creating a high flow rate of a CO2 phase. Due to the incompressibility of the continuous aqueous phase (i.e., water), its flow rate remains constant, which thereby increases the ratio of liquid-gas flow rates in the system. The generation of much smaller CO2 bubbles at 0.5 Hz frequency accelerates CO2 hydration. These results imply that sequential water injection with CO2 at high frequency would facilitate CO2 hydration in brine leading to rapid mineral precipitation. Another important observation is that a decreasing drying-out effect by sequential water injection with gaseous CO2 leads to 15-fold slower brine evaporation rate than continuous injection of CO2 (Fig. 2a vs. Fig. 7).
H+ + CO32 , K2 =
H+ CO32 HCO3
= 4.69 × 10
11
The total amount of CO2 in the aqueous phase can be calculated by solving for the equilibrium constants (K1 and K2) with Henry’s constant.
CO2(total) = CO2(aq) + HCO3 + CO32 =
PCO2 K1 KK 1 + + 1+ 22 kH [H+] [H ]
An effective Henry’s constant, kH*, which accounts for the total dissolved CO2, can be described by the following equation:
kH * =
3.4. The pH effect
PCO2 = CO2(total)
(1 +
kH K1 [H +]
+
K1 K2 [H +]2
)
Each value of the effective Henry’s constant at different pH levels was determined to identify the pH effect on VCO2/VChannel (Fig. 9). In theory, CO2 dissolution into water increases as the value of effective Henry’s constant decreases; for example, kH* = 1.36 × 10−2 at pH 11, 6.33 × 102 at pH 7, and 3.44 × 103 kPa L/mol at pH 3, respectively. Taking this fact into consideration, Fig. 9 shows significant increases in the value of effective Henry’s constant from pH 7 to pH 3 led to a decrease in the CO2 dissolution. In contrast, as noted earlier, no substantial difference was observed at pH 7 and 11.
The pH of an aqueous solution is considered as another parameter which controls the CO2 solubility trapping process (Seinfeld and Pandis, 2016). Fig. 9 shows a time-dependent ratio of the volume of CO2 bubbles to trapped brine (VCO2/VChannel) at different pH levels. When pH changes from pH 7 to pH 3, the relative volume of CO2 bubbles at the isolated pore channel increases. In contrast, no significant differences in VCO2/VChannel were found between pH 7 and pH 11. These experimental
3.5. Discussion and outlook The impacts of sequential CO2 and water injection into geologic aquifers are significant with an important perspective of water evaporation and resultant brine drying-out when compared with the conventional methods. Up to this point, several methods other than the direct injection of dry CO2 through injection wells have been proposed to improve formation damage during carbon sequestration due to the brine drying-out. One method is an ex-situ approach, where brine is extracted from the saline aquifers, sparged with pressurized gaseous CO2 to produce CO2-saturated brine in reservoir conditions, and then reinjected through the pipeline into the original aquifer (Leonenko and Keith, 2008; Zendehboudi et al., 2011). The main benefit of this methodology is that CO2 dissolution into an aqueous phase can be accelerated by the generation of CO2 bubbles in a mixing chamber due to the gas-liquid two-phase flow. When gaseous CO2 is introduced into water, two-phase flow occurs along with generation of CO2 bubbles in a continuous aqueous phase (Abdulmouti, 2014; Das et al., 2009), ultimately enhancing the CO2 trapping within deep saline aquifers. Although this approach has shown a potential for great reduction of a mobile CO2 phase causing dreadful leakage, the pumping process that
Fig. 9. Bottom-X left-Y: Variations in the ratio of the volume of CO2 microbubble to the total volume of brine at the isolated pore channel at 0.5 Hz frequency at different pH. Top-X right-Y: A diagram of effective Henry’s constant as a function of pH. 262
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circulates brine from the reservoir to the ground pipeline and the pressurization of CO2 in aquifer conditions requires significant energy consumption, making this approach impractical. In addition to this method, simultaneous injection of CO2 and geologic saline water into reservoirs has been considered as a substitute of the ex-situ approach (Hassanzadeh et al., 2009; Leonenko and Keith, 2008; Shafaei et al., 2012). It has been considered that this method not only increases the possibility of permanent storage of CO2 but also reduces economic strain notably, as the energy cost associated with this process is less than 20% of the cost for compressing the CO2 to reservoir conditions (Leonenko and Keith, 2008). However, many bottlenecks restricting field applications of this technology still remain, including the requirement of the additional pipeline installation for brine circulation. On the other hand, the proposed sequential water injection with gaseous CO2 could be a solution by combining advantages of the aforementioned ex-situ approach with simultaneous injection of CO2 with water. The sequential injection of water via a single pipeline can eliminate the need for an additional pipeline for economical technology. In the context of a methodology, a microfluidic-based approach provides new perspectives regarding the brine drying-out at the pore scale in geologic aquifers in a simple and cost-effective manner. However, it should be noted that there still exist opportunities to improve our current results in terms of the material and surface properties of microfluidic models and a variety of ions other than NaCl. In addition, although the ratio of the volume of CO2 bubbles to trapped brine (VCO2/VChannel) strongly depends on the flow rate ratio of the two phases, the operation pressure is still not relevant to the actual operating condition. Temperature is an important parameter to change the rates of brine evaporation and CO2 solubility. The reservoir-specific temperature conditions (e.g., 40 °C (Rathnaweera et al., 2016) and 62 °C (Holt et al., 1995)) can decrease the brine drying-out and CO2 dissolution rates. The water content of CO2 at room temperature of 25 °C and atmospheric pressure is approximately 23 times higher than that at 10 MPa and 40 °C (Salari et al., 2011). Due to this higher CO2 water content, the brine drying-out in our experiments is possibly greater than that in the actual reservoir-specific condition. Nevertheless, the microfluidic approach, for the first time, demonstrates the efficacy of a new novel injection strategy for CO2 into geologic formations. To test the feasibility of the proposed sequential injection approach to the actual saline aquifers, water evaporation and the brine drying-out experiments in the 2D and 3D porous media that mimic the natural aquifers in terms of surface properties and geometry will be performed at higher pressures. The complex nature of these random networks will offer dynamic physicochemical processes close to the actual phenomena and direct visualization of these interactions would provide new understandings of the pertinent multiphase interplay in geologic formations.
amounts of brine evaporation and mobile free-phase CO2 and proven to be a potential solution to mitigate the concerns about the brine dryingout. We found that the brine evaporation rate in the new strategy was approximately 15-fold slower than the conventional gaseous CO2 injection. In addition, the new strategy generated large surface-to-volume ratio microbubbles and these CO2 bubbles effectively accelerated their dissolution in brine due to the increased gas-liquid interfaces. To further enhance CO2 dissolution, operating condition parameters, i.e., injection frequency and solution pH, were controlled. The results show that sequential of water with CO2 injection at a low frequency at higher basicity accelerated CO2 dissolution effectively and decreased the volume fraction of CO2 bubbles occupying the pore. Acknowledgments The authors gratefully acknowledge the funding provided by Janke Research Fund at Florida Environmental Studies. We also thank Heather Crawford for her help with laboratory experiments; Babak Mosavati and Minh Nguyen for their comments on the manuscript. Appendix A. Supplementary data Supplementary material related to this article can be found, in the online version, at doi:https://doi.org/10.1016/j.ijggc.2019.02.017. References Abdulmouti, H., 2014. Multiphase flow, bubble plume, bubble, surface flow, turbulence, buoyant flow, free surface flow, and bubbly flow. Am. J. Fluid Dyn. 47. Arnal, J.M., Sancho, M., Iborra, I., Gozálvez, J.M., Santafé, A., Lora, J., 2005. Concentration of brines from RO desalination plants by natural evaporation. Desalination 182, 435–439. https://doi.org/10.1016/j.desal.2005.02.036. 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. https://doi.org/10.1016/j. ijggc.2014.06.023. Bhaduri, G.A., Šiller, L., 2013. Nickel nanoparticles catalyse reversible hydration of carbon dioxide for mineralization carbon capture and storage. Catal. Sci. Technol. 3, 1234. https://doi.org/10.1039/c3cy20791a. Chow, J.C., Watson, J.G., Herzog, A., Benson, S.M., Hidy, G.M., Gunter, W.D., Penkala, S.J., White, C.M., 2003. Separation and capture of CO2 from large stationary sources and sequestration in geological formations. J. Air Waste Manag. Assoc. 53, 1172–1182. https://doi.org/10.1080/10473289.2003.10466274. Das, A.K., Das, P.K., Thome, J.R., 2009. Transition of Bubbly Flow in Vertical Tubes: New Criteria Through CFD Simulation. J. Fluids Eng. 131, 091303. https://doi.org/10. 1115/1.3203205. Fraga, B., Stoesser, T., 2016. Influence of bubble size, diffuser width, and flow rate on the integral behavior of bubble plumes. J. Geophys. Res. Oceans 121, 3887–3904. https://doi.org/10.1002/2015JC011381. Fuller, R.C., Prevost, J.H., Piri, M., 2006. Three-phase equilibrium and partitioning calculations for CO2 sequestration in saline aquifers: EQUILIBRIUM AND PARTITIONING FOR CO2 SEQUESTRATION. J. Geophys. Res. Solid Earth 111. https://doi.org/10.1029/2005JB003618. Grude, S., Landrø, M., Dvorkin, J., 2014. Pressure effects caused by CO2 injection in the Tubåen Fm., the Snøhvit field. Int. J. Greenh. Gas Control 27, 178–187. https://doi. org/10.1016/j.ijggc.2014.05.013. Gunter, W.D., Wong, S., Cheel, D.B., Sjostrom, G., 1998. Large CO2 sinks: their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Appl. Energy 19. Hansen, O., Gilding, D., Nazarian, B., Osdal, B., Ringrose, P., Kristoffersen, J.-B., Eiken, O., Hansen, H., 2013. Snøhvit: The History of Injecting and Storing 1 Mt CO2 in the Fluvial Tubåen Fm. Energy Procedia 37, 3565–3573. https://doi.org/10.1016/j. egypro.2013.06.249. Harned, H.S., Nims, L.F., 1932. The thermodynamic properties of aqueous sodium chloride solutions from 0 to 40°. J. Am. Chem. Soc. 54, 423–432. https://doi.org/10. 1021/ja01341a002. Hassanzadeh, H., Pooladi-Darvish, M., Keith, D.W., 2009. Accelerating CO2 dissolution in saline aquifers for geological storage — mechanistic and sensitivity studies. Energy Fuels 23, 3328–3336. https://doi.org/10.1021/ef900125m. Herzog, H.J., 2001. Peer reviewed: what future for carbon capture and sequestration? Environ. Sci. Technol. 35, 148A–153A. https://doi.org/10.1021/es012307j. Holt, T., Jensen, J.-I., Lindeberg, E., 1995. Underground storage of CO2 in aquifers and oil reservoirs. Energy Convers. Manage. 36, 535–538. https://doi.org/10.1016/01968904(95)00061-H. Kim, M., Sell, A., Sinton, D., 2013. Aquifer-on-a-Chip: understanding pore-scale salt precipitation dynamics during CO2 sequestration. Lab Chip 13, 2508. https://doi. org/10.1039/c3lc00031a.
4. Conclusion We performed pore-scale experiments of geofluid dynamics occurred in deep saline aquifers when gaseous CO2 is sequentially introduced with water using microfluidic platforms. A simple microfluidic imaging technique enabled quantification of a volume fraction of injected CO2 and resultant evaporated brine to open a new opportunity for strategic carbon sequestration plans into deep saline aquifers. Specifically, the principal factors contributing to the brine drying-out by traditional dry CO2 injection can be identified through quantification of the amount of evaporated brine at the pore-scale. The results from this observation are well aligned with the conventional theory of the activity coefficient and offer reliable modeling of interactions between CO2-brine occurred in actual saline aquifers. To overcome the brine drying-out challenge, this study suggests a new strategy of sequential water injection with CO2. This scenario was experimentally tested through the microfluidic technique for quantification of the 263
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Injection of in-situ generated CO2 microbubbles into deep saline aquifers for enhanced carbon sequestration
T
Seokju Seoa, Mohammad Mastiania, Mazen Hafeza, Genevieve Kunkela, Christian Ghattas Asfoura, Kevin Ivan Garcia-Ocampoa, Natalia Linaresa, Cesar Saldanaa, Kwangsoo Yangb, ⁎ Myeongsub Kima, a b
Department of Ocean and Mechanical Engineering, Florida Atlantic University, 777 Glades Road, Boca Raton, FL33431, USA Department of Computer & Electrical Engineering and Computer Science, Florida Atlantic University, 777 Glades Road, Boca Raton, FL33431, USA
ARTICLE INFO
ABSTRACT
Keywords: Carbon sequestration CO2 dissolution CO2 injectivity Deep saline aquifers Microfluidics
Carbon sequestration into deep saline aquifers has been considered a promising technology for mitigating heavy atmospheric carbon dioxide (CO2) concentration. When gaseous CO2 is continuously injected into these aquifers, resident brine near a wellbore area is rapidly evaporated while precipitating significant amounts of salt at pores, thereby damaging the aquifer media unfavorable for subsequent CO2 injection. In addition, the continuous injection of CO2 at a large volume significantly hinders dissolution of CO2 into brine. In this study, we propose a new method of sequential water injection with gaseous CO2 for in-situ generation of micro-sized CO2 bubbles that minimizes the brine drying-out and simultaneously accelerates CO2 dissolution. We observed that, with this method, a partial volume of CO2 dissolves effectively into the co-injected water during pumping, thereby decreasing the rate of brine drying-out at pores. Another benefit of sequential injection is the significantly increased rate of CO2 hydration induced by the large surface-to-volume ratio of tiny bubbles at micro to nanoscale. To further accelerate CO2 hydration, we investigated reactive dynamics of bubble-driven CO2 hydration at different frequencies of sequential injection and pH levels of the solution. Operation at a higher frequency with higher basicity proved to be the most effective in decreasing the bubble size and therefore accelerating CO2 hydration into brine, which is a more feasible CO2 storage plan.
1. Introduction
of saline formations in the near-wellbore (Fuller et al., 2006; Kim et al., 2013) and the slow rate of CO2 hydration (Bhaduri and Šiller, 2013; Seo et al., 2017, 2018b). The large volume of continuous CO2 injection creates a dried zone near the injection well (Miri and Hellevang, 2016; Peysson et al., 2014). In the dried zone, the majority of the pores contain trapped brine that will be eventually evaporated while salinity of brine increases due to continuous CO2 injection (Miri and Hellevang, 2016). The brine drying-out results in salt precipitation and the precipitated salt blocks pores leading to a significant reduction in CO2 injectivity. Salt precipitation near the wellbore in the field-scale projects has been reported at the Snøhvit field (Grude et al., 2014; Hansen et al., 2013) and the Ketzin pilot reservoir (Baumann et al., 2014), respectively. Especially, a rapid pressure increase by salt precipitation was observed after 5000 h of CO2 injection, resulting in a significant decrease in injectivity at the Snøhvit field (Grude et al., 2014). Some laboratory studies have investigated the rate of brine drying-out under different injection/fluid conditions and found important controlling
Carbon capture and sequestration (CCS) technology has been proposed as a promising method of global carbon dioxide (CO2) mitigation (Gunter et al., 1998; Herzog, 2001). This technology aims to capture CO2 from industrial and power plant combustion processes, and then store the captured CO2 away in safe areas (e.g., depleted oil and gas reservoirs, unmineable coal seams, and deep saline aquifers) to prevent it from reaching the atmosphere. Among various possibilities, CO2 injection into geological formations has proven to be the most attractive method at a reasonable cost. Specifically, deep saline aquifers, defined as porous and permeable reservoir rocks containing brine, located at 800 to 2000 m from the surface level are widely available for CO2 storage with the injection rate at more than 1 metric megaton per year (Chow et al., 2003). Although the storage capacity of these aquifers is known to be tremendous, the potential of this option is currently limited by drying-out
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Corresponding author. E-mail address: [email protected] (M. Kim).
https://doi.org/10.1016/j.ijggc.2019.02.017 Received 17 October 2018; Received in revised form 26 February 2019; Accepted 27 February 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.
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parameters for this phenomenon (Peysson et al., 2014; Pruess and Müller, 2009; Rathnaweera et al., 2016; Zhao and Cheng, 2017). CO2 flow rates at 0.0083–0.83 mL/s (Miri et al., 2015) and 0.667 mL/s (Wang et al., 2017) have been used to study the mechanisms of salt crystallization and the changes in formation properties, respectively. In addition, a range of salinity at 0.25–25% has been used (Tang et al., 2015); note that the salt concentration of real brine has been found at 0.71–35% (Michael et al., 2010). Another technical challenge to the feasibility of CO2 sequestration in saline aquifers is the slow reaction rate of carbonic acid (H2CO3) formation from CO2 hydration (Bhaduri and Šiller, 2013; Seo et al., 2017, 2018b). This slow reaction rate can be negatively impacted further by brine containing high salinity contents in natural formations. When CO2 dissolves into brine, the CO2-saturated brine sinks toward the bottom of the aquifers and thereby reduces the risk of CO2 leakage since the density of CO2-saturated brine is greater than that of the original brine (Pau et al., 2010; Zhang and Song, 2014). The dissolved CO2 will combine with metal cations leading to precipitation of minerals. Resultantly, properties of brine in porous media are changed to be the favorable condition for increasing permanent storage of CO2. Therefore, to accelerate CO2 dissolution into deep saline aquifers, a new methodology needs to be developed. The brine drying-out, salt precipitation, and slow CO2 hydration are attributed mainly to a continuous injection of CO2 to the formation fluid. Over the years, many methods other than the continuous injection of CO2 have been proposed to resolve these challenges. For minimizing the brine drying-out, one study suggested a preflush of the saline formation with fresh water and it showed that this method delayed the onset of salt precipitation and reduced its severity significantly. For enhancing CO2 hydration, an ex-situ dissolution of CO2 via an external reactor (Leonenko and Keith, 2008; Zendehboudi et al., 2011; Zirrahi et al., 2013a, 2013b), a reverse gas-lift technology (Shafaei et al., 2012), a static mixer at the bottom of well (Zirrahi et al., 2013a, 2013b), the injection of nanosized CO2 bubbles (Uemura et al., 2016), and catalyst addition to the injection fluid (Seo et al., 2018b, 2017) have been proposed. Among these strategies, the injection of CO2 bubbles, instead of the CO2 stream, has shown promising results to accelerate CO2 hydration remarkably (Leonenko and Keith, 2008; Uemura et al., 2016; Zendehboudi et al., 2011). One limitation of this method is that the pumping process to generate CO2 bubbles in external reactors requires huge energy consumption. Although numerous studies have shown the important mechanisms associated with the brine drying-out and CO2 hydration, they still lack a practical strategy to resolve these concerns. In this study, we present a practical methodology that could address these challenges: significant reduction of drying-out and acceleration of CO2 hydration by sequential injection of water with CO2 into the formation. It is broadly known that the sequential injection of CO2-water into a pipeline will generate various CO2 bubbles in their size due to the gas-liquid two-phase flow (Abdulmouti, 2014; Das et al., 2009). In the literature, it is well known that the fragmentation of large air cavities by the turbulent flow can produce submillimeter bubbles (RodríguezRodríguez et al., 2015). Especially, after the liquid flow has established in a large reactor or tubing, microbubbles can be generated by injecting a short burst of gas into the liquid flow using a solenoid valve (Millard et al., 2015; Ohl, 2001). We hypothesize that the sequential injection of water with CO2 into the aquifers increases the CO2 dissolution rate by producing microsized bubbles in the reservoirs and also effectively decreases brine evaporation by supplying fresh water to salt-saturated pores. This study aims to test this hypothesis and provide a new venue for geologic CO2 injection while minimizing the brine drying-out and maximizing CO2 storage capacity. The time-dependent brine evaporation, resultant salt precipitation, and formation of CO2 bubbles were visualized at high-speed through a microfluidic technique. Microfluidics allowed us to quantify the amounts of brine evaporation and mobile free-phase CO2 successfully by measuring both the velocity of
the liquid−CO2 interface and the amount of gaseous CO2 at pore-scale. The results show that the amount of mobile free-phase CO2 injected, which is one of the main sources for the brine drying-out, can be reduced by changing the frequency of sequential injection and pH levels of the injected solution. 2. Materials and methods 2.1. Microfluidic platforms A microfluidic approach was used to visualize and quantify phase equilibria and fluid transport associated with brine evaporation and CO2 dissolution at the pore scale. The potential of this technique to examine phase change analyses and fluid transport at micro- to nanoscale has been proven in many studies due to the fast mass transfer at these scales and its excellent capability for visualization of multiphase flow (Kim et al., 2013; Mastiani et al., 2018, 2017a, 2017b; Seo et al., 2018a). In this approach, an experimental platform containing fluidic channels, called a microfluidic chip, is essential. Microfluidic chips were fabricated by laser ablation using a laser cutter (VersaLaser VLS2.30, Universal Laser Systems, Inc.). Poly(methyl methacrylate) (PMMA) was used for a chip material due to its high chemical resistance and mechanical stability (Sher et al., 2017). As illustrated in Fig. 1, the microfluidic chip consists of 1000 μm wide straight channels for supplying gaseous CO2 and isolated pore channels for trapping brine. The height of all channels is 1500 μm. 2.2. Experimental procedure All tests were performed by pumping fluids under two different conditions: continuous and sequential injection (Fig. 1a). For the continuous injection of CO2 (Fig. 1b), once the microfluidic chip was filled with brine at different salinities, a clamping device sealed the inlet port for the solution to prevent backflow of trapped brine induced by injection of CO2. Then, the CO2 gas with 99.9% purity (Airgas®, Miami, FL) was introduced to the microfluidic chip at different flow rates through the connected inlet port to a regulator mounted on a CO2 tank. For the sequential injection of water with CO2, a fast switching mechanism of a three-way solenoid valve operated by microcontrollerbased (Arduino Uno) electronic control circuits (Fig. 1c) was employed. Two inlets of this solenoid valve were connected to a syringe pump (PHD ULTRA™ 4400, Harvard Apparatus, Natick, MA) and the CO2 regulator. This valve sequentially injected water at 0.03 mL/s from the syringe pump and CO2 gas at 118 mL/s from the tank into the microfluidic platform. This ensures precisely controlled frequencies (0.1 to 0.5 Hz) of sequential injection of water with gaseous CO2. When gaseous CO2 was sequentially introduced with water, CO2 bubbles with a diameter range of 40–150 μm were generated in the trapped brine. The microbubble is defined as bubbles having a diameter less than few hundred μm in this study similar to that in the previous literature in the field of fluid physics (Parmar and Majumder, 2013). Once the tests for CO2 bubble formation at different frequencies were completed, the behavior of brine evaporation and the amount of mobile free-phase CO2 in brine were investigated at various pH levels of pumping water (pH 3, pH 7, and pH 11). A high-speed camera (Fastec IL5S, Fastec Imaging, CA) attached to an inverted microscope (IX73, Olympus Corporation, Japan) was used to capture time-resolved images of the liquid-gas interface and the amount of trapped CO2 in brine. 2.3. Materials and experimental conditions For the fabrication of microfluidic devices, PMMA sheets were purchased from Good Fellow (Berwyn, PA). Sodium chloride (NaCl, ≥99.5% purity), sodium hydroxide (NaOH, ≥98% purity), hydrochloric acid (HCl, 37%), and phosphate buffer powder were purchased from Sigma − Aldrich (St. Louis, MO). One millimolar (mM) phosphate 257
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Fig. 1. (a) Schematic of the experimental setup (not to scale). (b) Continuous CO2 injection to the microfluidic chip with time-dependent brine evaporation at the trapped channel. (c) Sequential water−CO2 injection to the same channel generating CO2 microbubbles.
buffer solution used in all tests was prepared using deionized water produced from a Millipore Milli − Q integral 5 purification system (Millipore, Bedford, MA). Brine evaporation experiments were performed at concentrations of 0%, 5%, 10%, 20%, and 30% NaCl added to 1 mM phosphate buffer solution at different injection rates of dry gaseous CO2 (68, 97 and 118 mL/s). Then, the highest salinity at 30% with the highest injection rate of dry CO2 at 118 mL/s was used to investigate how effectively sequential water injection with CO2 can reduce brine evaporation and the amount of gaseous CO2 in brine. The pH of the sequential water was titrated to desired levels that were created by adding either one M of HCl or NaOH while monitoring with a pH meter (Accumet AE150, Fisher Scientific, Pittsburgh, PA). All experiments were performed at room temperature of 25 °C and atmospheric pressure. An atmospheric pressure condition was used at the outlet.
determined through the projected area of CO2 bubble. Then, the CO2 bubble volume (V = (4/3)π(D/2)3) was determined using the average diameter (D) of CO2 bubbles. 3. Results and discussion 3.1. Continuous injection of CO2 The experiments on the water evaporation at various salinity levels and CO2 flow rates were performed to characterize how different fluid and flow rate conditions in deep saline aquifers influence the brine drying-out. Fig. 2 shows time-lapse optical microscopy images of changes in the gas-liquid interface at an isolated pore channel. The interface was formed when dry gaseous CO2 was continuously injected at 68, 97 and 118 mL/s at different salinities (0, 5, 10, 20, and 30% NaCl). In these conditions, CO2 velocities are 23.51, 33.25, and 40.72 m/s, which represent assumed conditions around injection wells at the CO2 storage site. In general, as the volume flow rate increases, the speed of interface retraction also increases; for example, compare timedependent changes in the location of the interface at 0% salinity in Fig. 2a and c. This behavior was quantitatively analyzed by tracking changes in volume of evaporated brine at a T-junction (Fig. 3). Approximately 2.2 μL of volume of pure water in the channel was evaporated within 120, 46, and 4.6 s at 68, 97 and 118 mL/s of CO2 flow rates, respectively. This analysis shows that the amount of brine
2.4. Image processing for evaporated brine and gaseous CO2 The volumes of evaporated brine and gaseous CO2 in the isolated pore channel were analyzed on the ImageJ software, an open-source image processing program. To measure brine evaporation in various conditions, the changes in the interface between CO2 gas and trapped brine in the isolated pore channel corresponding to water evaporation were tracked by the ImageJ. In addition, the volume fraction of the mobile free-phase CO2 in trapped brine was determined by changes in its volume at 0.04 s intervals. The CO2 bubble diameter (D) was 258
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Fig. 2. Sequential images for changes in the CO2-water interface location at a T-junction at different salinities (0, 5, 10, 20, and 30% NaCl) with different CO2 injection rates at (a) 68, (b) 97, and (c) 118 mL/s.
evaporated exponentially increased as CO2 flow rate increased from 68 to 118 mL/s. In general, an increase in air velocity over water leads to an increase in rate of escaping water molecules (Arnal et al., 2005). In line with this phenomenon, we observed forced convective mass transfer between horizontal CO2 gas flow and water increases with increasing gaseous CO2 flow rates. Reynolds numbers (Re) at different flow rates were determined to be 4464.37, 6313.92, and 7732.42 using 8.36 × 10−6 m2/s of kinematic viscosity of CO2 at 25 °C, 1.58 × 10-3 m of tubing diameter, and CO2 velocities at 23.51, 33.25, and 40.72 m/s. For the impact of salinity on brine evaporation, the kinetics of brine evaporation at different salinity levels are plotted in Fig. 4. This figure is determined by different slopes for the relationship between evaporated brine and the elapsed time (Fig. 3). As the concentration of salinity increases up to 10%, the evaporation rate decreases in all flow rate conditions. However, by increasing the salinity from 10% to 30%, an increase in the evaporation rate is observed in three flow rate conditions. The highest rate of evaporation was determined to be 0.57 μL/s under 30% salinity at the highest CO2 flow rate (118 mL/s). This decrease-to-increase behavior can be explained by an activity coefficient of NaCl solution controlling brine evaporation dynamics. The activity coefficient is used in thermodynamics to explain the behavior of chemical substances. As the activity coefficient decreases, the energy required to separate constituent molecules increases. Conversely, when the activity coefficient increases, molecules have a strong repelling force, and thereby less energy is required to separate them (Pitzer et al., 1984). Evaporation occurs when molecules in a liquid gain enough energy to overcome an attraction force from other molecules. The activity coefficients of brine at different salinities can be calculated from the electromotive force data by Hückel's equation (Harned and Nims, 1932).
Fig. 4. A diagram of changes in the evaporation rate of brine as a function of the salinity (0, 5, 10, 20, and 30% NaCl) with different CO2 injection rates (68, 97, and 118 mL/s) and the graph (◊) of the activity coefficients of NaCl solution at 25 °C.
log =
0.5067 IM 1 + 0.837 2IM
+ 0.0316 2IM
log(1 + 0.036M )
where IM, M, and γ are the ionic strength (mol/L), the concentration (mol/L), and the activity coefficient of NaCl solution at 25 °C, respectively. We estimated each value of the activity coefficient at different salinities ranging from 0% to 30% to characterize the salinity effect on the evaporation rate. A decrease in the activity coefficient while increasing the salinity concentration up to 7% led to a decrease in brine evaporation into the CO2 gas phase (Fig. 4). In contrast, increasing
Fig. 3. Variations of evaporated brine vs. elapsed time at different salinities and CO2 flow rates. (Error bars represent the standard error of the mean from triplicated experiments in each condition.) 259
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Fig. 5. Representative time-lapse optical microscopy images showing the generation and coalescence of CO2 microbubbles during sequential water−CO2 injection.
salinity concentration from 7% to 30% displays an increase in the activity coefficient to 0.869, resulting in a proportional increase in the evaporation rate of brine. The observations of our test results are in a good agreement with the theory of the activity coefficient. These microfluidic tests confirm that continuous injection of gaseous CO2 into deep saline aquifers may lead to an increase in risks of the brine dryingout. The extreme drying-out creates salt precipitation behind and causes formation damage. We observed that the degree of brine dryingout increases as CO2 flow rate increases at salinity greater than 10%.
microbubbles effectively with a large surface-to-volume ratio leading to significant improvement of a CO2 solubility trapping process because the mass transfer of gaseous CO2 into water will further increase with larger interface areas between these two phases. As in Fig. 5, due to the physical agitation, number and size of CO2 bubbles change over time. The figure shows that the onset of CO2 bubble formation is observed at a few locations at t = 1 s. The CO2 bubbles are accumulated immediately near the T-junction and start to coalesce due to the collision between the CO2 bubbles (see Video 2). It should be noted that microbubbles in an aqueous solution are negatively charged under a wide range of pH (Takahashi, 2005). However, as increasing the ionic strength in the aqueous phase, the reduction in the zeta (ζ) potential of microbubbles was reported (Takahashi, 2005). As a result, CO2 microbubbles in 30% NaCl near the T-junction are easily coalesced to minimize their surface areas when they are in touch. The size of CO2 bubbles apart from the T-junction is significantly decreased due to effective CO2 hydration. As typical natural saline aquifers are characterized as random porous structures, the directional water−CO2 injection into pore structures is certainly of interest. The pore-throat and pore sizes of typical sandstones range from 1 to 500 μm in conventional reservoirs (Nelson, 2009; Radlinski et al., 2004; Wardlaw and Cassan, 1979). To examine the behaviors of CO2 bubble generation in different geometries, transient CO2 bubble formation during sequential water and CO2 injection was recorded at different pore angles (30°, 90°, and 120°, Fig. 6 and see Video 3). The results show that an insignificant variation in the amount of CO2 bubbles was observed in the pore channel at these angles.
3.2. Sequential water injection with CO2 We hypothesized that sequential injection of water with CO2 addresses the challenge with the brine drying-out and provides another benefit to accelerate the rate of CO2 hydration. To test the feasibility of the sequential injection strategy, microfluidic experiments were performed in a simple T-junction microchannel. Fig. 5 shows representative images of CO2 microbubble generation in the microchannel taken by an optical microscope from selected time points (t = 1, 20, and 50 s) at a controlled frequency of 0.1 Hz. As pure water and CO2 were sequentially injected, CO2 microbubbles were generated due to the nature of two-phase flow (Abdulmouti, 2014; Das et al., 2009). Locations of the gas-liquid interface were maintained constant near the T-junction during sequential injection, which consequently delayed the evaporation rate of water. Not only does decreasing the brine drying-out and therefore reducing a risk of salt precipitation, but the sequential injection of pure water−CO2 also increases CO2 hydration into brine. The physical absorption of gaseous CO2 by the liquid phase is determined by Henry’s law.
Pco2 = kH [CO2 ]aq
3.3. Frequency effect
where kH is Henry’s constant for CO2 in pure water (3.45 × 103 kPa L/ mol), [CO2]aq is the concentration of dissolved CO2 in the aqueous phase, and PCO2 is the partial pressure of the CO2. The rate for this physical absorption can be increased further by agitation in the liquid phase (Noyes et al., 1996). The agitation can generate CO2
The high solubility coefficient of CO2 makes it immediately diffuse into an aqueous phase when it is in contact with water. In addition, as aforementioned the high surface-to-volume ratio will improve CO2 hydration into water. To further enhance CO2 gas dissolution and safe storage potential, generation of a much smaller volume of CO2 bubbles
Fig. 6. Representative microscopy images showing the generation and coalescence of CO2 microbubbles at different pore angles (30, 90, and 120° between an inlet channel with isolated pore channel) during sequential water−CO2 injection. 260
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Fig. 7. Time-dependent images of CO2 microbubble generation and coalescence near the T-junction at different water−CO2 injection frequencies (0.1, 0.2, and 0.5 Hz).
is important. We found that the frequency of water-gas injection plays a role in varying the gas bubble sizes. Fig. 7 shows the total volume of CO2 bubbles generated at t = 0˜60 s in a T-junction channel at frequencies of 0.1, 0.2, and 0.5 Hz. At a frequency of 0.5 Hz, number of CO2 micro-bubbles was increased as time increases while their sizes are less than 100 μm at t = 60 s. On the other hand, at 0.1 Hz number of CO2 bubbles was decreased while their sizes are greater than 500 μm at t = 60 s. This implies that an increase in frequency leads to a decrease in the volume of CO2 bubbles occupying the brine at the channel (VCO2/ VChannel) owing to improved CO2 hydration. Fig. 8 shows the change in ratio of the volume of CO2 bubbles to
trapped brine (VCO2/VChannel) in the microchannel at different frequencies. In agreement with the observation in Fig. 7, as the frequency increases, the volume of trapped water is slowly replaced by that of CO2 bubbles. Particularly at the 0.5 Hz, the volume of CO2 bubbles at 60 s was estimated to be approximately 2-fold smaller than that in the 0.1 Hz condition. These significant differences in the volume of CO2 bubbles trapped in brine at different frequencies can be characterized by bubbly two-phase flow. The volume of CO2 bubbles in bubbly twophase flow is likely to be dominated by the ratio of liquid-gas flow rates. Fraga and Stoesser (Fraga and Stoesser, 2016) revealed that smaller bubbles are generated when a high flow rate of an aqueous phase and a 261
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results can be explained by the behavior of the effective Henry’s constant (Seinfeld and Pandis, 2016). The total quantity of dissolved CO2 in brine includes the amount of all species of aqueous CO2, the intermediate bicarbonate (HCO3−) form, and the equilibrium carbonate (CO32-) form in water. First, physical absorption of CO2 into brine is governed by Henry’s law.
CO2(g ) + H2 O
CO2(aq) ,
kH =
PCO2 [CO2 ]aq
CO2 (aq) reacts with water to form carbonic acid (H2CO3), then dissociates into H+ and HCO3− ions at the intermediate stage.
CO2(aq) + H2 O H2 CO3
H+ + HCO3 ,
K1 =
Fig. 8. Variations in the ratio of the volume of CO2 microbubbles to the total volume of brine at the isolated channel at different injection frequencies. The inset figures represent images of the channel taken at t = 60 s.
H2 CO3
H+ HCO3 = 4.45 × 10 CO2(aq)
7
Then, HCO3− dissociates further into H+ and CO32- ions.
HCO3
low flow rate of a gaseous phase are mixed. In our tests, when a valve is operating at low frequency (0.1 Hz), CO2 gas is compressed, thereby creating a high flow rate of a CO2 phase. Due to the incompressibility of the continuous aqueous phase (i.e., water), its flow rate remains constant, which thereby increases the ratio of liquid-gas flow rates in the system. The generation of much smaller CO2 bubbles at 0.5 Hz frequency accelerates CO2 hydration. These results imply that sequential water injection with CO2 at high frequency would facilitate CO2 hydration in brine leading to rapid mineral precipitation. Another important observation is that a decreasing drying-out effect by sequential water injection with gaseous CO2 leads to 15-fold slower brine evaporation rate than continuous injection of CO2 (Fig. 2a vs. Fig. 7).
H+ + CO32 , K2 =
H+ CO32 HCO3
= 4.69 × 10
11
The total amount of CO2 in the aqueous phase can be calculated by solving for the equilibrium constants (K1 and K2) with Henry’s constant.
CO2(total) = CO2(aq) + HCO3 + CO32 =
PCO2 K1 KK 1 + + 1+ 22 kH [H+] [H ]
An effective Henry’s constant, kH*, which accounts for the total dissolved CO2, can be described by the following equation:
kH * =
3.4. The pH effect
PCO2 = CO2(total)
(1 +
kH K1 [H +]
+
K1 K2 [H +]2
)
Each value of the effective Henry’s constant at different pH levels was determined to identify the pH effect on VCO2/VChannel (Fig. 9). In theory, CO2 dissolution into water increases as the value of effective Henry’s constant decreases; for example, kH* = 1.36 × 10−2 at pH 11, 6.33 × 102 at pH 7, and 3.44 × 103 kPa L/mol at pH 3, respectively. Taking this fact into consideration, Fig. 9 shows significant increases in the value of effective Henry’s constant from pH 7 to pH 3 led to a decrease in the CO2 dissolution. In contrast, as noted earlier, no substantial difference was observed at pH 7 and 11.
The pH of an aqueous solution is considered as another parameter which controls the CO2 solubility trapping process (Seinfeld and Pandis, 2016). Fig. 9 shows a time-dependent ratio of the volume of CO2 bubbles to trapped brine (VCO2/VChannel) at different pH levels. When pH changes from pH 7 to pH 3, the relative volume of CO2 bubbles at the isolated pore channel increases. In contrast, no significant differences in VCO2/VChannel were found between pH 7 and pH 11. These experimental
3.5. Discussion and outlook The impacts of sequential CO2 and water injection into geologic aquifers are significant with an important perspective of water evaporation and resultant brine drying-out when compared with the conventional methods. Up to this point, several methods other than the direct injection of dry CO2 through injection wells have been proposed to improve formation damage during carbon sequestration due to the brine drying-out. One method is an ex-situ approach, where brine is extracted from the saline aquifers, sparged with pressurized gaseous CO2 to produce CO2-saturated brine in reservoir conditions, and then reinjected through the pipeline into the original aquifer (Leonenko and Keith, 2008; Zendehboudi et al., 2011). The main benefit of this methodology is that CO2 dissolution into an aqueous phase can be accelerated by the generation of CO2 bubbles in a mixing chamber due to the gas-liquid two-phase flow. When gaseous CO2 is introduced into water, two-phase flow occurs along with generation of CO2 bubbles in a continuous aqueous phase (Abdulmouti, 2014; Das et al., 2009), ultimately enhancing the CO2 trapping within deep saline aquifers. Although this approach has shown a potential for great reduction of a mobile CO2 phase causing dreadful leakage, the pumping process that
Fig. 9. Bottom-X left-Y: Variations in the ratio of the volume of CO2 microbubble to the total volume of brine at the isolated pore channel at 0.5 Hz frequency at different pH. Top-X right-Y: A diagram of effective Henry’s constant as a function of pH. 262
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circulates brine from the reservoir to the ground pipeline and the pressurization of CO2 in aquifer conditions requires significant energy consumption, making this approach impractical. In addition to this method, simultaneous injection of CO2 and geologic saline water into reservoirs has been considered as a substitute of the ex-situ approach (Hassanzadeh et al., 2009; Leonenko and Keith, 2008; Shafaei et al., 2012). It has been considered that this method not only increases the possibility of permanent storage of CO2 but also reduces economic strain notably, as the energy cost associated with this process is less than 20% of the cost for compressing the CO2 to reservoir conditions (Leonenko and Keith, 2008). However, many bottlenecks restricting field applications of this technology still remain, including the requirement of the additional pipeline installation for brine circulation. On the other hand, the proposed sequential water injection with gaseous CO2 could be a solution by combining advantages of the aforementioned ex-situ approach with simultaneous injection of CO2 with water. The sequential injection of water via a single pipeline can eliminate the need for an additional pipeline for economical technology. In the context of a methodology, a microfluidic-based approach provides new perspectives regarding the brine drying-out at the pore scale in geologic aquifers in a simple and cost-effective manner. However, it should be noted that there still exist opportunities to improve our current results in terms of the material and surface properties of microfluidic models and a variety of ions other than NaCl. In addition, although the ratio of the volume of CO2 bubbles to trapped brine (VCO2/VChannel) strongly depends on the flow rate ratio of the two phases, the operation pressure is still not relevant to the actual operating condition. Temperature is an important parameter to change the rates of brine evaporation and CO2 solubility. The reservoir-specific temperature conditions (e.g., 40 °C (Rathnaweera et al., 2016) and 62 °C (Holt et al., 1995)) can decrease the brine drying-out and CO2 dissolution rates. The water content of CO2 at room temperature of 25 °C and atmospheric pressure is approximately 23 times higher than that at 10 MPa and 40 °C (Salari et al., 2011). Due to this higher CO2 water content, the brine drying-out in our experiments is possibly greater than that in the actual reservoir-specific condition. Nevertheless, the microfluidic approach, for the first time, demonstrates the efficacy of a new novel injection strategy for CO2 into geologic formations. To test the feasibility of the proposed sequential injection approach to the actual saline aquifers, water evaporation and the brine drying-out experiments in the 2D and 3D porous media that mimic the natural aquifers in terms of surface properties and geometry will be performed at higher pressures. The complex nature of these random networks will offer dynamic physicochemical processes close to the actual phenomena and direct visualization of these interactions would provide new understandings of the pertinent multiphase interplay in geologic formations.
amounts of brine evaporation and mobile free-phase CO2 and proven to be a potential solution to mitigate the concerns about the brine dryingout. We found that the brine evaporation rate in the new strategy was approximately 15-fold slower than the conventional gaseous CO2 injection. In addition, the new strategy generated large surface-to-volume ratio microbubbles and these CO2 bubbles effectively accelerated their dissolution in brine due to the increased gas-liquid interfaces. To further enhance CO2 dissolution, operating condition parameters, i.e., injection frequency and solution pH, were controlled. The results show that sequential of water with CO2 injection at a low frequency at higher basicity accelerated CO2 dissolution effectively and decreased the volume fraction of CO2 bubbles occupying the pore. Acknowledgments The authors gratefully acknowledge the funding provided by Janke Research Fund at Florida Environmental Studies. We also thank Heather Crawford for her help with laboratory experiments; Babak Mosavati and Minh Nguyen for their comments on the manuscript. Appendix A. Supplementary data Supplementary material related to this article can be found, in the online version, at doi:https://doi.org/10.1016/j.ijggc.2019.02.017. References Abdulmouti, H., 2014. Multiphase flow, bubble plume, bubble, surface flow, turbulence, buoyant flow, free surface flow, and bubbly flow. Am. J. Fluid Dyn. 47. Arnal, J.M., Sancho, M., Iborra, I., Gozálvez, J.M., Santafé, A., Lora, J., 2005. Concentration of brines from RO desalination plants by natural evaporation. Desalination 182, 435–439. https://doi.org/10.1016/j.desal.2005.02.036. 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. https://doi.org/10.1016/j. ijggc.2014.06.023. Bhaduri, G.A., Šiller, L., 2013. Nickel nanoparticles catalyse reversible hydration of carbon dioxide for mineralization carbon capture and storage. Catal. Sci. Technol. 3, 1234. https://doi.org/10.1039/c3cy20791a. Chow, J.C., Watson, J.G., Herzog, A., Benson, S.M., Hidy, G.M., Gunter, W.D., Penkala, S.J., White, C.M., 2003. Separation and capture of CO2 from large stationary sources and sequestration in geological formations. J. Air Waste Manag. Assoc. 53, 1172–1182. https://doi.org/10.1080/10473289.2003.10466274. Das, A.K., Das, P.K., Thome, J.R., 2009. Transition of Bubbly Flow in Vertical Tubes: New Criteria Through CFD Simulation. J. Fluids Eng. 131, 091303. https://doi.org/10. 1115/1.3203205. Fraga, B., Stoesser, T., 2016. Influence of bubble size, diffuser width, and flow rate on the integral behavior of bubble plumes. J. Geophys. Res. Oceans 121, 3887–3904. https://doi.org/10.1002/2015JC011381. Fuller, R.C., Prevost, J.H., Piri, M., 2006. Three-phase equilibrium and partitioning calculations for CO2 sequestration in saline aquifers: EQUILIBRIUM AND PARTITIONING FOR CO2 SEQUESTRATION. J. Geophys. Res. Solid Earth 111. https://doi.org/10.1029/2005JB003618. Grude, S., Landrø, M., Dvorkin, J., 2014. Pressure effects caused by CO2 injection in the Tubåen Fm., the Snøhvit field. Int. J. Greenh. Gas Control 27, 178–187. https://doi. org/10.1016/j.ijggc.2014.05.013. Gunter, W.D., Wong, S., Cheel, D.B., Sjostrom, G., 1998. Large CO2 sinks: their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Appl. Energy 19. Hansen, O., Gilding, D., Nazarian, B., Osdal, B., Ringrose, P., Kristoffersen, J.-B., Eiken, O., Hansen, H., 2013. Snøhvit: The History of Injecting and Storing 1 Mt CO2 in the Fluvial Tubåen Fm. Energy Procedia 37, 3565–3573. https://doi.org/10.1016/j. egypro.2013.06.249. Harned, H.S., Nims, L.F., 1932. The thermodynamic properties of aqueous sodium chloride solutions from 0 to 40°. J. Am. Chem. Soc. 54, 423–432. https://doi.org/10. 1021/ja01341a002. Hassanzadeh, H., Pooladi-Darvish, M., Keith, D.W., 2009. Accelerating CO2 dissolution in saline aquifers for geological storage — mechanistic and sensitivity studies. Energy Fuels 23, 3328–3336. https://doi.org/10.1021/ef900125m. Herzog, H.J., 2001. Peer reviewed: what future for carbon capture and sequestration? Environ. Sci. Technol. 35, 148A–153A. https://doi.org/10.1021/es012307j. Holt, T., Jensen, J.-I., Lindeberg, E., 1995. Underground storage of CO2 in aquifers and oil reservoirs. Energy Convers. Manage. 36, 535–538. https://doi.org/10.1016/01968904(95)00061-H. Kim, M., Sell, A., Sinton, D., 2013. Aquifer-on-a-Chip: understanding pore-scale salt precipitation dynamics during CO2 sequestration. Lab Chip 13, 2508. https://doi. org/10.1039/c3lc00031a.
4. Conclusion We performed pore-scale experiments of geofluid dynamics occurred in deep saline aquifers when gaseous CO2 is sequentially introduced with water using microfluidic platforms. A simple microfluidic imaging technique enabled quantification of a volume fraction of injected CO2 and resultant evaporated brine to open a new opportunity for strategic carbon sequestration plans into deep saline aquifers. Specifically, the principal factors contributing to the brine drying-out by traditional dry CO2 injection can be identified through quantification of the amount of evaporated brine at the pore-scale. The results from this observation are well aligned with the conventional theory of the activity coefficient and offer reliable modeling of interactions between CO2-brine occurred in actual saline aquifers. To overcome the brine drying-out challenge, this study suggests a new strategy of sequential water injection with CO2. This scenario was experimentally tested through the microfluidic technique for quantification of the 263
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