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# Calorimetric and densimetric data to help the simulation of the impact of annex gases co-injected with CO 2 during its geological storage

F de los Mozos, K Ballerat-Busserolles, B Liborio, Y Coulier, J-Y Coxam

► To cite this version:

F de los Mozos, K Ballerat-Busserolles, B Liborio, Y Coulier, J-Y Coxam. Calorimetric and densimetric data to help the simulation of the impact of annex gases co-injected with CO 2 during its geological storage. Ying Wu, John J. Carroll, Yongle Hu. The Three Sisters: Acid Gas Injection, Carbon Capture and Sequestration, and Enhanced Oil Recovery, Scrivener Publishing LLC, pp.39-54, 2019, 9781119510062. 10.1002/9781119510079. hal-04111845

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Submitted on 31 May 2023

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# Calorimetric and densimetric data to help the simulation of the impact of annex gases co-injected with CO₂ during its geological storage

F. De los Mozos, K. Ballerat-Busserolles, B. Liborio, Y. Coulier, and J-Y. Coxam

Institut de Chimie de Clermont-Ferrand (ICCF), UMR 6296, Université Clermont Auvergne, CNRS, F-63000 CLERMONT-FERRAND, FRANCE

Corresponding author : karine.ballerat@uca.fr

## Abstract

Most of the industrialized countries have started to significantly reduce their greenhouse gases emissions. CO₂ capture and geological storage processes entered an operational phase with the emergence of several pilot-sites where different technologies are tested. The gas mixture composition to be stored can vary considerably both qualitatively and quantitatively, based on the origin of CO₂, the chosen process of capture and the concerned industrial sector. Indeed, in addition to CO₂, several components can be present at various concentration levels, including O₂, N₂, SOₓ, H₂S, N_yOₓ, that are a concern to the energy industry. These impurities can have an impact on the chemical reactivity with water, reservoir or cap-rock forming minerals, and the materials constituting injection or monitoring wells installed in a repository site. Moreover, some impurities (SOₓ, H₂S, N_yOₓ, CO) are toxic for human health and the environment, even at low concentrations.

This work is part of the objectives of the French ANR program SIGARRR : Simulation of the Impact of Annex Gases (SOₓ, N_yOₓ, O₂) co-injected with CO₂ during its geological storage on the Reservoir-Rocks Reactivity. Based on the technical experience of the consortium, it was appropriate to propose a project to study the behavior of co-injected gases mixtures under storage conditions.

This chapter will focus on the determination of two key properties for the mixtures containing pure gases: Enthalpies of mixing, solubility, and Molar volumes at infinite dilution of aqueous solutions of salts, loaded with different gases, namely CO₂ and SO₂.

## Introduction

Most of the industrialized countries have now started to significantly reduce their greenhouse gases emissions. Capture and geological storage processes entered an operational phase with the emergence of several pilot-sites, notably in France, where several technologies are currently being tested.

During the storage of CO₂ in geological formations, four main mechanisms have to be considered: (i) Structural trapping, which is the presence of an impermeable cap-rock which prevents CO₂ from escaping from the outset, (ii) Residual CO₂ trapping, where CO₂ is trapped by capillary forces in the interstices of the rock formation, (iii) Solubility trapping, where the CO₂ dissolves in the water found in the geological formation and sinks and (iv) Mineral trapping happening when dissolved CO₂ chemically reacts with the rock formation to produce minerals.

Considering the whole treatment network of CO₂ storage in geological repositories, the major problem in the separation step is the elimination of some recalcitrant impurities during the treatment of industrial effluents. The gas mixture composition can vary considerably both
qualitatively and quantitatively (varying from 80 to 99% of CO₂)[1], based on the origin of CO₂ and the chosen process of capture (oxycombustion, post-combustion, pre-combustion). The presence of annex gases and the purity level of CO₂ during its separation are essential aspects of capture and are well documented [2]. In addition to CO₂, several components are of concern to the energy industry and can be present at various concentration levels, including O₂, N₂, SOₓ, H₂S, N_yOₓ, H₂, CO, and Ar. Some of these impurities (SOₓ, H₂S, N_yOₓ and CO) are toxic for human health and the environment, even at low concentrations.[3]

The presence of impurities in the CO₂ stream may have an effect on all types of geological storage scenarios, especially in terms of changes in storage capacity and injectivity due to changes in phase behavior with respect with pure CO₂. In addition, impurities could have a significant effect on injectivity through geochemical reactions in the vicinity of injection wells. Geochemical effects such as dissolution of CO₂ and reactions with minerals may determine the long term fate of injected CO₂, especially in deep saline formations; the impurities may affect the risk profile of storage sites, as geochemical reactions are widely seen as a key mechanism for the stabilization of pressure and brine displacement. Geochemical reactions can also affect the integrity of caprock sequences above storage complexes.

Until recent years, the role of gas impurities on the geochemical behavior of storage sites is not well documented. Knauss et al.[4] Evaluated effects of H₂S and SO₂ on the evolution of a mineralogical assemblage that is characteristic of a geological reservoir at the Frio pilot site (USA). They observed that the effects of H₂S are negligible, while SO₂, in oxidizing conditions, maintains a low pH that is not compatible with carbon sequestration by carbonates precipitation. The authors then concluded that laboratory data are lacking and it is consequently hard to validate the numerical approaches even if simulations tend to improve in those contexts.[5, 6]

Determining equilibrium conditions between various phases is crucial when investigating a fluid with several components. Dissolution, transport, and precipitation of chemical species will occur differently depending on the state of the fluid phase (monophasic liquid, biphasic liquid or liquid + vapor). The well-known systems of gas mixtures or water/salt/gas mixtures are highly simplified because of the limited number of species that are considered (binary or ternary mixtures;[7-9] Moreover, Data on solubility of gas mixtures used to construct phase equilibrium diagrams are limited to conditions of temperature and pressure much lower than those typical of the geological storage sites. In addition, the diagrams generally do not take into account high ionic strength aqueous fluids present within geological formations considered for CO₂ storage.

Concerning risk assessment, the impacts of impurities on vulnerable assets (human health, aquifers, ecosystems etc.) in case of leakage are poorly known. One of the main reasons for this lack of knowledge is the absence of data concerning the expected composition of leakage, first studies consequently focused on pure CO₂ leakages. To overcome this issue, usual approaches for impact assessment [10] assume that the leaking gas has the same composition as the injected gas, which is a very strong hypothesis. Furthermore, the toxicity of impurities is strongly dependent on the chemical form and thus on the aqueous speciation of pollutants in the reservoir waters.

To answer this question, the use of models for simulation of the system has to be improved. Different levels are considered, starting with geological models to simulate the rock-aquifer
interactions [11] and the influence of injected gases on those interactions. It is then obvious that the understanding of the rock-aquifer behavior is driven by the physicochemical, and moreover by the thermodynamic properties of the brine loaded with gas. More specifically, the acidity of the solutions, the solubility of the gases and the energetic properties during mixing are key data in the simulations.

In order to start with thermodynamic modeling, the study of dissolution of pure gas in aqueous solutions of electrolytes present in the brine has to be carried out. These simplified ternary systems {gas-salt-water} allow determining interaction parameters, hardly obtained in more complex mixtures.

Gas dissolution can be represented by a thermodynamic model that takes into account physical and chemical equilibria. For physical dissolution, the equation for gas-liquid equilibrium is usually based on a dissymmetrical approach $γ-φ$.[12, 13] The general equation of the model is reported in eq.1, below.

$$H_{i,W}(T, p^{SAT}) \exp\left(\frac{v_{i,W}^{\infty}(p-p^{SAT})}{RT}\right) \gamma_i^* m_i = p y_i^g \phi_i^g \quad \text{Eq. (1)}$$

Where $m_i$ is the molality of the dissolved gaseous component i, $γ_i^*$ is the activity coefficient, $H_{i,W}(T, p^{SAT})$ is Henry's law constant at water saturation pressure, $v_{i,W}^\infty$ is the molar volume at infinite dilution, $y_i^g$ is mole fraction in the gas phase and $\phi_i^g$ is fugacity coefficient.

Non ideality in liquid phase is represented by an activity coefficient, taking into account interactions between the gas molecules, water and ions. The activity coefficient $γ_i^*$ is estimated using thermodynamic electrolyte models, such as e-NRTL or Pitzer modified models. These models include interaction parameters which need to be adjusted using experimental solubility data and enthalpy data; the enthalpy of solution can be derived from equation 2 using van't Hoff equation. Henry's constant and volume at infinite dilution are determined from solubility and experimental volume data obtained for low gas dilute solution.

Non ideality in gas phase is represented by the fugacity coefficient, derived from an equation of state such as Viriel or Peng-Robinson. The interaction parameters in gas phase are adjusted on vapor-liquid equilibrium data. [13]

In order to obtain the experimental data required for optimizing the thermodynamic models, different experimental methods have been developed in our laboratory. This paper focuses on the determination of volumes at infinite dilution of gas, namely CO₂, using a new experimental methodology for measurements of densities of gas loaded solutions in aqueous solutions. Enthalpies of solution and gas solubility of CO₂ and SO₂ will be also presented, and a comparison of the effect of the two gases on energetic properties and solubility will be described.

## Material and Methods

### Densimetric measurements

The original methodology of the vibrating tube densimeter was modified to allow density measurements for aqueous solutions loaded with controlled amount of gas. Measurements can be performed between 293.15 K and 423 K at pressure up to 15 MPa. Different vibrating tube densimeters have been used, depending on the domain of temperature investigated. At low
temperature, the measurements can be carried out using an Anton Paar MPDS 5 densimeter, while a home-made densimeter is used for the highest temperatures.[14]

The density of the solution is derived from the period of vibration of the vibrating tube following eq. (2).

$$ \Delta\rho = \rho - \rho_0 = K(\tau^2 - \tau_0^2) \qquad \text{eq. (2)} $$

$\rho$ and $\tau$ are the density and the period of vibration related to the solution; $\rho_0$ and $\tau_0$ are the density and the period of vibration related to a reference fluid (water) and K the calibration constant of the densimeter, experimentally determined as function of temperature and pressure.

An original set-up has been designed in order to obtain the densities of gas loaded solutions with well-known composition. The schematic view is shown in figure 1.

<figure><img src="image_2.png" /><figcaption>Figure 1: schematic view of the densimetric device for measurements on gas loaded solutions.</figcaption></figure>

The densimeter worked in flowing mode. This method makes it possible to prepare the mixture flowing through the vibrating tube, with a controlled gas loading charge. This preparation of solution in flowing mode prevents bubble formations and avoids corrosion problems.

Firstly, a well known quantity of gas is carefully introduced in a first high pressure syringe pump. The quantity of gas injected in the pump is calculated from the volume indicated by the pump, previously calibrated and the pressure inside the pump, read with a pressure transducer (precision 0.025% full scale). The temperature of the pump is maintained constant using a julabo thermostatic bath (precision 0.1 K). Then, a precise quantity of liquid is added using a second high pressure pump. The injection pressure of liquid is slightly higher than the initial pressure of the first pump filled with the gas. The quantity of liquid is obtained from the volume variation, the temperature and pressure of the second pump.

In this experiment the main issue is to prepare homogeneous solutions loaded with gas but avoiding any gas phase. It is then necessary to prepare a solution with a composition below the limit of gas solubility, estimated at temperature and pressure of the experiments, to insure no degassing.

The experimental procedure consists in measuring the period of vibration of a reference fluid
(in our case water) and of the gas loaded solution. Different decreasing gas loading charges are obtained by dilution of the initial gas loaded solution, prepared as described before, with a solution which does not contained gas. The dilution occurs at a mixing point located on the flow lines, as shown in figure 1. The new gas loading charge is calculated from pump flow rates and solution densities.

The apparent molar volume $V_{\phi,CO_2}$ is calculated from the density, using the equation (3).

$$V_{\phi,CO_2} = \frac{M_S}{\rho_0 + \Delta\rho} - \frac{\Delta\rho}{m_{CO_2}(\rho_0 + \Delta\rho) \cdot \rho_0} \qquad \text{eq. (3)}$$

Where $M_S$ is the molar mass of the solute (the gas in our case) and $m_{CO_2}$ the molality of the solution. The subscript 0 refers to water.

In order to validate the procedure of preparation of the gas loaded solution, the experiments are repeated in same conditions of temperature and pressure, but starting with two different initial solutions (different $CO_2$ compositions). Experimental results for densities and apparent molar volume for {CO₂-water} system are given in figures 2.

<figure><img src="image_3.png" /><figcaption>Figure 2: density (left) and apparent molar volumes (right) of aqueous solutions of $CO_2$ at 314 K and 2.6 MPa. The molar compositions of the initial gas loaded solutions are: ♦, $x_{CO_2} = 0.0065$; □, $x_{CO_2} = 0.0086$.</figcaption></figure>

Figure 2 show a good consistency between the measurements obtained from with 2 different initial solutions of $CO_2$ mole fractions 0.065 and 0.086. This technique makes it possible to obtain molar volume at infinite dilution $V_{CO_2}^{\infty}$ required in equation (1), by extrapolation of $V_{\phi,CO_2}$ at $m_{CO_2} = 0$.

Density measurements as function of $CO_2$ loading have been performed for the binary mixture water + $CO_2$ at temperatures from 293 K to 428 K and pressures up to 10 MPa. Results for molar volumes at infinite dilution versus pressure and temperature are reported on the figure 3.
<figure><img src="image_4.png" /><figcaption>Figure 3: molar volume at infinite dilution of CO₂ in water. Left: results at 298.15 K, versus pressure; Right: results versus temperature. ■: our data, ◇: literature[15-17]</figcaption></figure>

The results are in good agreement with the literature values.[15-17] Figure 3 shows that the pressure has a very small impact on the volume. The molar volume at infinite dilution of CO₂ in water is increasing with temperature, as expected for non-electrolyte molecule in water[18] and will diverge when reaching the critical temperature.

This study will now be extended to other gases in water and aqueous solutions of electrolytes, to give robust data for adjusting models representative of dissolution of annex gases in brines.

## Calorimetric measurements

Enthalpy of solutions and solubility of gas in aqueous solutions have been determined using a method largely used in the group. The enthalpies are obtained as a function of gas loading charge, α (moles CO₂/mole amine), from the experimental heat flux measured by a Setaram C-80 calorimeter during absorption of CO₂. The method is detailed elsewhere.[19-21]

A schematic overview of the experimental set up is given in figure 4. The experiments are performed at constant temperature (±0.01 K) and pressure (±0.025 MPa) in a flow mode. The aqueous solution and the carbon dioxide are injected into a mixing cell located inside the calorimeter. The two fluids flow at controlled volume flow rate using two high-pressure syringe pumps (Isco Model 260 DM). These two pumps are temperature regulated using a thermostatic bath in order to maintain a constant molar flow rate. The gas loading charge is determined from volume flow rates and fluids densities.
<figure><img src="image_5.png" /><figcaption>Figure 4: schematic representation of the calorimetric measurements.</figcaption></figure>

The enthalpy of solution is calculated from the heat flux signal measured during gas absorption following equation (4).

$$ \Delta_{SOL}H = \frac{F - F_{BL}}{K \cdot \dot{n}_i} \qquad \text{eq. (4)} $$

Where $\Delta_{SOL}H$ is the enthalpy of solution, F the heat flux signal during gas absorption, $F_{BL}$ the heat flux signal of the baseline recorded when only one fluid is flowing in the mixing cell, K the calibration constant and $\dot{n}_i$ the molar flow rate of compound i, namely gas or water. The enthalpy of solution (eq. (4)) can be expressed in joule per mole of gas or per mole of solvent. The figure X shows an example of enthalpy of solution per mole of CO₂ or per mole of water as function of gas loading charge.

<figure><img src="image_6.png" /><figcaption>Figure 5: Enthalpy of mixing of CO₂ in water, at 323 K and 5.1 MPa.</figcaption></figure>
When the enthalpy of solution is expressed per mol of gas (fig. 5, blue points), a constant $\Delta_{\text{SOL}}H$ value is observed at low loading charges. This behavior makes it possible to determine an enthalpy of solution at low loading charges that could be compared to enthalpy value derived from Henry's constant. At highest loading charge, where the liquid is gas saturated, the calculated $\Delta_{\text{SOL}}H$ is decreasing because $CO_2$ considered in equation (4) is not fully absorbed $CO_2$. The absolute uncertainty on the enthalpy of solution is estimated to be about 5%.

When expressed per mol of water (fig 5, red points), the enthalpy of solution increases linearly with $CO_2$ loading charge. The slope corresponds to the enthalpy value on the plateau previously obtained. For the highest loading charges, when the liquid is gas saturated, the calculated $\Delta_{\text{SOL}}H$ is more or less constant. The first point of this plateau corresponds to the gas solubility. The gas solubility can then be graphically determined from calorimetric measurement. The main difficulty with this method is to determine accurately low gas solubilities. The experiments have to be carried out at low gas loading charges that mean to work with small gas flow rate. The global uncertainty on the determination of gas solubility will then increase with the relative uncertainty on volume flow rate. In this work, the relative uncertainty on the limit of gas solubility is estimated to be $\pm 10\%$.

## Absorption of CO₂ in aqueous solutions

The results obtained for dissolution of $CO_2$ in water and in aqueous solutions of electrolytes at 323 K and 5 MPa are reported in figure 6.

<figure><img src="image_7.png" /><figcaption>Figure 6: Enthalpy of solution of $CO_2$ in water and aqueous solutions of electrolytes, at 323 K and 5 MPa. Left : enthalpy per mole of $CO_2$; right : enthalpy per mole of water. ▲: pure water; ×: water + $Na_2SO_4$; ■: water + $NaCl$; ◆: water + $CaCl_2$;</figcaption></figure>

The enthalpy of solution in pure water, expressed per mole of $CO_2$ (fig. 6, left) is exothermic and the value of the plateau is about -13 kJ.mol$^{-1}$. This value is in good agreement with reported literature data.[21] When adding a salt, the enthalpy slightly decreases. $\Delta_{\text{SOL}}H$ in $CaCl_2$ aqueous solution is close to -12.5 kJ.mol$^{-1}$, and reaches -11 kJ.mol$^{-1}$ in $Na_2SO_4$ aqueous solutions. These enthalpy values are consistent with a mechanism of physical dissolution, and with no chemical absorption. The models used to describe these mixtures will then consider only the physical absorption term.

The solubility of $CO_2$ is determined graphically from the plot of the enthalpy per mole of water (fig. 6, right). The value obtained in pure water, expressed in $CO_2$ molar fraction, is
close to 0.014. This result is in good agreement with literature data. [21-23] This solubility decreases when adding salts, as it can be seen on figure 6 (right figure). This behavior corresponds to the salting-out effect, which can be quantified using the equation (5).

$$S.O. (\%) = \frac{x_0-x}{x_0} \cdot 100 \qquad \text{eq. (5)}$$

Where $x_0$ and x are the solubilities in pure water and salted solution, respectively. The salting out effect calculated at 323 K is about 35% for NaCl; this value does not depend on pressure. The salting out effect is due to the structuration of water in presence of ions. In salted solutions, water is less available for the gas solvation because of electrostatic interactions with the ions. The salting out effect slightly increases in $Na_2SO_4$ solutions, with however a difference compared to water within the experimental uncertainty. This value decreases more significantly for $CaCl_2$ (25 %). This may indicate that the charge of the cation has a larger influence on the salting out effect than the anion.

## Absorption of SO₂ in aqueous solutions

The same experimental work has been performed with sulfur dioxide instead of carbon dioxide. The experiment were carried out at lower pressure than for $CO_2$ (namely 0.3 MPa) for safety and experimental constraints. The results are reported in figure 7, for dissolution in water and in aqueous solutions of NaCl and $Na_2SO_4$.

<figure><img src="image_8.png" /><figcaption>Figure 7: Enthalpy of solution of $SO_2$ in pure water and aqueous solutions of electrolytes, at 323 K and 0.3 MPa. ▲: pure water; ×: water + $Na_2SO_4$; ■: water + NaCl;</figcaption></figure>

The enthalpy of solution of $SO_2$ in water per mole of gas is close to -28 kJ.mol⁻¹. This value is consistent with literature value reported at 298.15 K.[24] The mechanism of gas dissolution includes here chemical reactions such as ionizations of $SO_2$ to form $HSO_3^-$ and $SO_3^{2-}$. The addition of salt decreases significantly the enthalpy of solution (fig. 7, left).

When plotting the enthalpy per mole of water (figure 7, right) for the calculation of gas solubility, it can be observed that this graphical determination of a first point on the plateau is more difficult than for $CO_2$. The solubility of $SO_2$ in water reported in literature [25] is about 0.022 in molar fraction. Our calorimetric data shows no clear plateau around this value. However, close to this value, it can be observed a change in the slope of the $\Delta_{SOL}H$, probably linked to this solubility. The residual slope has to be attributed to intermolecular
reorganization in the solution in presence of ions. When adding salt in the solution, it can be
observed that the change in the slope related to the gas solubility increases exhibiting an
opposite behavior compared to CO₂; the presence of salt leads to a salting-in effect of the gas.
A deeper study must be carried out to explain how interactions with ionic species can affect
the chemical reactions during gas dissolution.

### *Comparison between the two gases*

The experimental enthalpies of solution of gas in water and aqueous solutions of NaCl and Na₂SO₄ has been reported in figure 8. Comparison between the different salted solutions is performed at a same ionic strength. This work shows that for CO₂ dissolution, the enthalpy of solution does not vary when adding electrolytes; the physical dissolution of gas is not so much sensible to the nature and to the electrical charge of ions.

<figure><img src="image_9.png" /><figcaption>Figure 8: Enthalpy of solution of gases as function of the composition of the solution; ■: SO₂; ◆: CO₂.</figcaption></figure>

For SO₂ dissolution, ΔSOLOH decreases significantly when adding NaCl. This change is larger when adding Na₂SO₄, probably because of the presence of divalent anion. The chemical reactions in water leading to the formation of hydrogen sulfite increases both the enthalpy of solution and gas solubility compared to physical dissolution of CO₂. The presence of salt decreases the enthalpy. A thermodynamic representation of SO₂ dissolution, including chemical reactions, will permit to explain the influence of the presence of ions, in term of ion-pair formation with the sulfite or structuration of the solution due to electrostatic forces. The thermodynamic modeling could also help to explain the salting-in effect observed with SO₂, while the presence of salts generates a salting-out effect in presence of CO₂.

### Acknowledgement

This work is part of the French ANR program SIGARRR (ANR-13-SEED-0006): Simulation of the Impact of Annex Gases (SOₓ, NyOₓ, O₂) co-injected with CO₂ during its geological storage on the Reservoir-Rocks Reactivity.
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