**4.3 Effect of brine salinity on CO2 solubility in brines**

CO2 solubility decreases with increasing salinity as show in Figure 5. The open diamonds show simulated data calculated with Duan et al.'s (2003+2006) CO2 solubility calculator setting the temperature to 323 K and the pressure to 10 MPa. It appears that Duan et al's. (2003+2006) model slightly over predicts CO2 solubilities. The other points shown are experimentally determined values.

Moreover, the type of dissolved salt has an influence on CO2 solubility. Yasunishi and Yoshda (1979) studied CO2 solubilites at atmospheric pressure in a wide variety of salt solutions, these salts included NaCl, KCl, Na2SO4, MgCl2, CaCl2, K2SO4, MgSO4, BaCl2, AlCl3, Al2(SO4)3 among others. They found that for the same electrolyte concentration, KCl solutions can absorb more CO2 than NaCl solutions, while CaCl2 and MgCl2 solutions absorb approximately the same amount of CO2. Monovalent NaCl or KCl solutions with the same salt concentration absorb more CO2 than their divalent CaCl2 or MgCl2 counterparts. For example Yasunishi and Yoshda (1979) measured at atmospheric pressure and 298 K that a 4.216 mol/L NaCl solution absorbs L = 0.3144 (L is the Ostwald coefficient, L = Vg/Vl with

Dissolution Trapping of Carbon Dioxide in

is the fugacity coefficient of CO2, 2

and temperature regime.

(3b).

2

2

equation (5) (Duan and Sun 2003).

2

(Tc = 647.29 K, pc = 22.085 MPa).

The parameters 2

(Duan and Sun 2003).

*<sup>c</sup> H O*

*l*(0) *CO* μ

*c*

Reservoir Formation Brine – A Carbon Storage Mechanism 241

2 2 2

− ++ +

*l*(0) *CO* μ

[ ][ ]

μ

*l*

*CO Na Na K Ca Mg*

− + + + +

Here T is the temperature, p the pressure, R is the universal gas constant, m is the molality of components dissolved in water, yCO2 is the mole fraction of CO2 in the vapour phase, FCO2

liquid phase, λCO2-Na is the interaction parameter between CO2 and Na<sup>+</sup> and ζCO2-Na-Cl is the

The fugacity FCO2 can be calculated via a fifth-order virial equation of state (equation 3). The coefficients ci are stored in a look-up table (Duan et al. 2006) and they vary with the pressure

1 23 4 5 67 8

*F c c cT c T c T CO p c cT c T p c cT c T p c cT p c T cT*

=+ + + + − + + + ++ + + + + +

9 10 11 12 13 14 15

For the pressure and temperature regime most relevant to CCS, i.e. for a pressure below 100 MPa and a temperature range 273-340 K, the coefficients are inserted and shown in equation

0.71734882 0.00015985379 4.9286471 10

=− + <sup>⎡</sup> − ⋅ <sup>⎤</sup> <sup>⎣</sup> <sup>⎦</sup>

− −

*F T CO p*

*T T*

where pH2O is the water vapour pressure which can be estimated with the empirical

26.654627 10.637097

where t = (T-Tc)/Tc and Tc and pc are the critical temperature and critical pressure of water

12 3 4 5 6 7

, / /(630 ) ln

= + ⋅ + + ⋅ + − + ⋅+ ⋅⋅ + ⋅ + ⋅ − + ⋅ − + ⋅⋅

*Par T p a a T a T a T a T a p a p T*

8 9 10 11

3 4 1 38.640844( ) 5.8948420 59.876516

, λCO2-Na and ζCO2-Na-Cl are estimated with equation (6) and Table 1

/ /(630 ) /(630 ) ln

*a pT a p T a p T a T p*

*p T t tt*

⎛ ⎞⎡ <sup>−</sup> − + ⋅+ ⋅ <sup>⎤</sup> <sup>=</sup> ⎜ ⎟⎢ <sup>⎥</sup> ⎝ ⎠⎢+ ⋅+ ⋅ ⎥ ⎣ ⎦

2.7855285 10 1.1877015 10

+− ⋅ + ⋅ ⎡ ⎤ ⎣ ⎦

The mole fraction of CO2 in the vapour phase yCO2 can be computed with equation (4)

96.539512 0.44774938 /

101.81078 / 5.3783879 10

*<sup>p</sup> <sup>T</sup> t t*

( ) <sup>2</sup>

+− + ⋅ ⎡ ⎤ ⎣ ⎦ + +⋅

[ ] [ ]

/ ln / /

7 9 2

6 2

*T p*

−

*T p*

( ) 2 2 *y pp p CO* = − *H O* / (4)

1.9 2

2 2

/ /( 150) /

2 22 2

*m y F p RT*

2

λ

ζ

interaction parameter between CO2 and Na<sup>+</sup> , - Cl .

(0) ln ln /

*CO CO CO CO*

= −

− − − ( )

*mm m m*

( )

*CO Na Cl Cl Na K Mg Ca SO*

2 4

*mm m m m m*

0.07

is the standard chemical potential of CO2 in the

(2)

2

(3)

(3b)

(5)

(6)

2

7

−

Vg = volume of CO2 absorbed and Vl = volume of absorbing brine) while a 4.131 mol/L KCl solution absorbed L = 0.4703. For a 3.955 mol/L MgCl2 solution they measured L = 0.1648. Chloride salt solutions absorbed more CO2 than the corresponding sulphate solutions (that was tested for 3 2 Na , K , Al and Mg <sup>+</sup> ++ + ).

Fig. 5. CO2 solubility as a function of brine salinity. The open diamonds represent data calculated with Duan et al. (2003+2006)'s CO2 solubility calculator; the other points are experimentally measured values

Enick and Klara (1990) tested the influence of dissolved solids on CO2 solubility in the temperature and pressure ranges 298-523 K and 3.40-72.41 MPa. Based on their results they developed an empirical equation for estimating salinity effects on CO2 solubility (equation 1).

$$Y\_{CO\_2,hric} = Y\_{CO\_2,pureH\_2O} \left( 1 - 0.04893414 \cdot S + 0.001302838 \cdot S^2 - 0.00001871199 \cdot S^3 \right) \tag{1}$$

where

YCO2,brine = CO2 solubility in brine (mass fraction) YCO2,pureH2O = CO2 solubility in pure water (mass fraction) S = salinity of brine (weight percent)

#### **4.4 Theoretical model for computing CO2 solubilities**

Duan and Sun (2003, 2006) developed an equation (equation 2) which can predict CO2 solubilites in brine as a function of temperature (range 273-533 K), pressure (range 0-20 MPa) and salinity (different salts/ions can be considered: 2 2 -2 Na , K , Mg , Ca , Cl , SO4 <sup>+</sup> + ++ − ).

Vg = volume of CO2 absorbed and Vl = volume of absorbing brine) while a 4.131 mol/L KCl solution absorbed L = 0.4703. For a 3.955 mol/L MgCl2 solution they measured L = 0.1648. Chloride salt solutions absorbed more CO2 than the corresponding sulphate solutions (that

Nighswander et al. (1989),

Sabirzyanov et al. (2003),

Koschel et al. (2006), 5.8 wt% NaCl Dodds et al. (1956), 0 wt% salt

Duan et al (2003+2006)

1wt% NaCl Li et al. (2004), 1 wt% NaCl Rumpf (1994), 23.3 wt% NaCl Kiepe et al. (2002), 3 wt% NaCl Bando et al. (2003), 3 wt% NaCl

0 wt% salt

2 3

<sup>+</sup> + ++ − ).

0 5 10 15 20 25 30

Fig. 5. CO2 solubility as a function of brine salinity. The open diamonds represent data calculated with Duan et al. (2003+2006)'s CO2 solubility calculator; the other points are

Enick and Klara (1990) tested the influence of dissolved solids on CO2 solubility in the temperature and pressure ranges 298-523 K and 3.40-72.41 MPa. Based on their results they developed an empirical equation for estimating salinity effects on CO2 solubility

( ) 2 22

Duan and Sun (2003, 2006) developed an equation (equation 2) which can predict CO2 solubilites in brine as a function of temperature (range 273-533 K), pressure (range 0-20 MPa) and salinity (different salts/ions can be considered: 2 2 -2 Na , K , Mg , Ca , Cl , SO4

, , 1 0.04893414 0.001302838 0.00001871199 *Y Y CO brine CO pureH O* = −⋅*SS S* + ⋅− ⋅ (1)

salinity [wt%]

YCO2,brine = CO2 solubility in brine (mass fraction) YCO2,pureH2O = CO2 solubility in pure water (mass fraction)

**4.4 Theoretical model for computing CO2 solubilities** 

S = salinity of brine (weight percent)

was tested for 3 2 Na , K , Al and Mg <sup>+</sup> ++ + ).

0

(equation 1).

where

experimentally measured values

0.2

CO2

solubility [mol CO

2/kg brine]

0.4

0.6

0.8

1

1.2

$$\begin{aligned} \ln m\_{\text{CO}\_2} &= \ln y\_{\text{CO}\_2} F\_{\text{CO}\_2} p - \mu\_{\text{CO}\_2}^{l(0)} / RT \\ &- 2\lambda\_{\text{CO}\_2-\text{Na}} \left( m\_{\text{Na}} + m\_K + 2m\_{\text{Ca}} + 2m\_{\text{Mg}} \right) \\ &- \xi\_{\text{CO}\_2-\text{Na}-\text{Cl}} m\_{\text{Cl}} \left( m\_{\text{Na}} + m\_K + m\_{\text{Mg}} + m\_{\text{Ca}} \right) + 0.07 m\_{\text{SO}\_4} \end{aligned} \tag{2}$$

Here T is the temperature, p the pressure, R is the universal gas constant, m is the molality of components dissolved in water, yCO2 is the mole fraction of CO2 in the vapour phase, FCO2 is the fugacity coefficient of CO2, 2 *l*(0) *CO* μ is the standard chemical potential of CO2 in the liquid phase, λCO2-Na is the interaction parameter between CO2 and Na<sup>+</sup> and ζCO2-Na-Cl is the interaction parameter between CO2 and Na<sup>+</sup> , - Cl .

The fugacity FCO2 can be calculated via a fifth-order virial equation of state (equation 3). The coefficients ci are stored in a look-up table (Duan et al. 2006) and they vary with the pressure and temperature regime.

$$\begin{aligned} F\_{CO\_2} &= c\_1 + \left[ c\_2 + c\_3 T + c\_4 \;/\; T + c\_5 \;/\; (T - 150) \right] p + \left[ c\_6 + c\_7 T + c\_8 \;/\; T \right] p^2 \\ &+ \left[ c\_9 + c\_{10} T + c\_{11} \;/\; T \right] \ln p + \left[ c\_{12} + c\_{13} T \right] / p + c\_{14} \;/\; T + c\_{15} T^2 \end{aligned} \tag{3}$$

For the pressure and temperature regime most relevant to CCS, i.e. for a pressure below 100 MPa and a temperature range 273-340 K, the coefficients are inserted and shown in equation (3b).

$$\begin{aligned} F\_{\text{CO}\_2} &= -0.71734882 + \left[ 0.00015985379 - 4.9286471 \cdot 10^{-7} T \right] p \\ &+ \left[ -2.7855285 \cdot 10^{-7} + 1.1877015 \cdot 10^{-9} T \right] p^2 \\ &+ \left[ -96.539512 + 0.44774938 \cdot T \right] / p \\ &+ 101.81078 \left/ T + 5.3783879 \cdot 10^{-6} T^2 \right. \end{aligned} \tag{3b}$$

The mole fraction of CO2 in the vapour phase yCO2 can be computed with equation (4)

$$y\_{CO\_2} = \left(p - p\_{H\_2O}\right) / \, p \tag{4}$$

where pH2O is the water vapour pressure which can be estimated with the empirical equation (5) (Duan and Sun 2003).

$$p\_{H\_2O} = \left(\frac{p\_cT}{T\_c}\right)\left[\frac{1-38.640844(-t)^{1.9}+5.8948420\cdot t + 59.876516\cdot t^2}{+26.654627\cdot t^3 + 10.637097\cdot t^4}\right] \tag{5}$$

where t = (T-Tc)/Tc and Tc and pc are the critical temperature and critical pressure of water (Tc = 647.29 K, pc = 22.085 MPa).

The parameters 2 *l*(0) *CO* μ , λCO2-Na and ζCO2-Na-Cl are estimated with equation (6) and Table 1 (Duan and Sun 2003).

$$\begin{aligned} \text{Par}\left(T, p\right) &= a\_1 + a\_2 \cdot T + a\_3 \cdot \left(T + a\_4 \cdot T^2 + a\_5 \right) \left(630 - T\right) + a\_6 \cdot p + a\_7 \cdot p \cdot \ln T \\ &+ a\_8 \cdot p \left/ \left.T + a\_9 \cdot p \right\vert \left(630 - T\right) + a\_{10} \cdot p^2 \right\vert \left(630 - T\right)^2 + a\_{11} \cdot T \cdot \ln p \end{aligned} \tag{6}$$

Dissolution Trapping of Carbon Dioxide in

**Depth [m]** 

estimated from Span and Wagner (1996).

\*\* 1 mol/kg NaCl brine, calculated with Duan et al.'s (2003, 2006) calculator.

they decrease at higher temperature (e.g. 413 K) (Kokal and Sayegh 1993).

Table 2. Variation of temperature, pressure, CO2 solubility and CO2 density with depth

In case of heavy oils CO2 dissolves into the oil phase while some light oil fractions are extracted into the CO2 phase. Depending on the oil and thermophysical condition, vapourliquid, liquid-liquid, liquid-supercritical fluid, liquid-liquid-vapour phase behaviours are observed. The densities of CO2-saturated oil increase at lower temperature (294 K) while

This makes CO2 a very efficient solvent for crude oil extraction in tertiary oil recovery processes (Green and Willhite 1998, Blunt et al. 1993). The dissolved CO2 reduces oil viscosity significantly which improves the mobility ratio oil-injected fluid (for improving production) and results in a much better reservoir sweep efficiency. The flow of oil in the reservoir is improved by the improved oil relative permeability, which leads to increased oil production. In addition, CO2 which dissolves into the oil causes oil swelling (up to 50-60%, Firoozabadi and Cheng 2010) which also leads to enhanced oil production. One side effect of CO2 addition to crude oil is that large asphaltene molecules precipitate (crude oil is a very complex fluid (cp. Table 3) with a multitude of components including such large asphaltene

\*

compared to lower temperatures (Kokal and Sayegh 1993).

**Temperature [K]** 

Reservoir Formation Brine – A Carbon Storage Mechanism 243

with further pressure increase. CO2 solubility also depends on oil composition and for light oils CO2 can be completely miscible. For example De Ruiters et al. (1994) measured a strong increase of CO2 solubility with pressure in two crude oils, at low pressures (0.69 MPa) the gas-oil ratio (GOR) was approximately 5.3 m3/m3, and GOR increased rapidly up to the CO2 liquefaction pressure when it reached 71 m3/m3 and 102 m3/m3, respectively. With a further pressure increase GOR stayed approximately constant. The experimental temperature in De Ruiters et al. experiments was low (290 K). If the temperature is above Tc as expected for CCS conditions, then CO2 solubility monotonically increases; but it is nominally lower as

> **Pressure [MPa]**

0 293 0.1 1.8 0.0307 100 296 1.135 21.8 0.3036 200 299 2.17 43.7 0.5037 300 302 3.205 68.3 0.6496 400 305 4.24 96.5 0.7542 500 308 5.275 130 0.8274 600 311 6.31 171.7 0.8769 700 314 7.345 221.8 0.9082 800 317 8.38 311.8 0.9260 900 320 9.415 391.9 0.9338 1000 323 10.45 412.8 0.9353 1100 326 11.485 449.6 0.9344 1200 329 12.52 486.3 0.9334 1300 332 13.555 522.7 0.9330 1400 335 14.59 561.3 0.9335 1500 338 15.625 576.1 0.9348

**ρCO2 [kg/m3]\***

**CO2 solubility [mol/kg]\*\*** 


Table 1. CO2 solubility interactions parameters (Duan et al. 2003, 2006)
