**2. Measurement techniques**

Sections 2.1 and 2.2 discuss key details of measurement techniques used for the IFT and CA data, respectively.

### **2.1. Interfacial tension**

and the other drawn along solid-fluid interface, as shown in **Figure 4(a)**, and is normally measured into the denser fluid phase. If the CA is higher than 90°, the rock has more preference

Akbarabadi and Piri conducted 30 unsteady- and steady-state drainage and imbibition

and 50–612 mD ranges of porosities and permeabilities [9]. They reported that at a given

saturations were volume fractions and in terms of actual mass of the fluids trapped, scCO<sup>2</sup>

microcomputed tomography (microCT) core-flooding experiments using 5 mm diameter and 10 mm length water-wet and oil-wet (originally water-wet sample was treated with 99.9 mol% purity Dodecyltriethoxysilane) Bentheimer sandstone samples having 22% poros-

318 K. The reported air-water CAs on the water-wet and oil-wet porous core samples were 0 and 130°, respectively. From the experimental findings, they concluded that lesser residual

is much higher compared to the range reported by Rahman et al. [9, 10]. The difference in the

lary pressures, as both the properties are known to affect the residual NWP saturation [8]. It should also be noted that the pore volumes of the core samples used by Akbarabadi and Piri

Tokunaga et al. and Wang and Tokunaga conducted drainage and imbibition capillary pres-

stone [12] sandpacks at 45°C and 8.5 and 12 MPa. The reported porosities of the sandpacks were ~38%. Based on the capillary pressure curves, they concluded that higher capillary

1.5 months aged sandstone packs were 8% at 8.5 MPa, whereas the saturations for limestone sand were 11 and 25%. At 12 MPa, the measured SNWP,r in 3 months aged and 4.5 months aged sandstone packs were 20 and 32% and in fresh, 1.5 months aged, and 4 months aged limestone sand were 29, 25, and 44%, respectively. It should be noted that the above SNWP,r were measured at zero capillary pressure. By using capillary scaling criteria, they inferred

For a safe and efficient sequestration process, an accurate representation of IFT and CA that strongly influence the relative permeability and capillary pressure is essential [13]. Further,

). The range of %capillary trapped CO<sup>2</sup>

[9] and Rahman et al. [10] were 24.1–36.3 cc and 0.044 cc, respectively.

(3.46 MPa, 20°C) and the observed difference was attributed to brine being relatively

was capillary trapped during secondary brine imbibition. The influence of wet-

 compared to the native fluid, and hence it can easily imbibe into the caprock and leak through it. An ideal caprock for stratigraphic trapping would have strong wetting preference

) system in three different types of sandstone rock samples with 14.3–21.2%


(11 MPa, 55°C) was trapped compared to gaseous

was investigated by Rahman et al. [10]. They conducted


ranges may be due to the differences in porosities and applied capil-


at higher pressures. The measured SNWP,r in both fresh and

. However, it should be noted that the above

. They also reported that about 49–83% of the

) compared to water-wet reservoirs

alters the wettabilities of the sands

reported by Akbarabadi and Piri

to CO<sup>2</sup>

CO<sup>2</sup>

initial CO<sup>2</sup>

(29.4% of initial CO<sup>2</sup>

%capillary trapped CO<sup>2</sup>

sure measurements for CO<sup>2</sup>

trapping is possible for scCO<sup>2</sup>

towards less brine-wet state.

0.5 wt.% CaCl<sup>2</sup>

to native fluid (i.e. a CA value close to 0°).

166 Carbon Capture, Utilization and Sequestration

initial brine saturation (Swi), less scCO<sup>2</sup>

tability on residual trapping of CO<sup>2</sup>

ity and 1800 mD permeability and CO<sup>2</sup>

less wetting to the rock in the presence of scCO<sup>2</sup>

is nearly 4 times higher than the gaseous CO<sup>2</sup>

trapping occurs in oil-wet reservoirs (17.7% of initial CO<sup>2</sup>

that long-term (in the order of months) exposure of scCO<sup>2</sup>

coreflooding tests in a medical CT scanner for CO<sup>2</sup>

Drop shape analysis techniques (e.g., ADSA and ADSA-NA) that are suitable for direct measurement of IFT at high pressure and temperature conditions were used for most of the reported CO<sup>2</sup> -water/brine IFT data [13, 15–28]. In general, the drop shape analysis methods involve: (1) formation of aqueous phase droplet in continuous CO<sup>2</sup> phase as shown in **Figure 3(a)** or CO<sup>2</sup> bubble/droplet in continuous aqueous phase as shown in **Figure 3(b)**, via a needle inside a pressure cell; (2) capturing the droplet image; (3) inputting the phase densities; and (4) obtaining IFT by matching the drop profile to the solutions of the Laplace equation [18, 25]. Capillary rise method was also used for the IFT data [29].

The following are the critical factors suggested to obtain reproducible IFT and/or CA data by: mutual saturation of the fluids and using saturated fluid densities [15]; placing thermocouple close to droplet phase [19]; avoiding contamination caused either due to low purity fluids and/or dissolution/rusting of wetted parts in fluids due to chemical incompatibility [30];

**Figure 3.** (a) Aqueous fluid droplet in CO<sup>2</sup> and (b) CO<sup>2</sup> bubble/droplet in aqueous fluid.

preventing droplet evaporation due to leakage of fluids and/or using unsaturated fluids [31]; and using same type of substrates with similar surface chemistry and morphology [32, 33].

(sessile-drop and captive-bubble) and dynamic (advancing and receding) CA measurements. Both the static and dynamic CAs were conducted using aqueous fluid as the droplet phase

For static CA measurement, the droplet phase is slowly released through a needle and deposited on the substrate immersed in external phase. In the case of advancing CA (w.r.t. droplet phase) measurement, either the droplet phase volume is slowly increased so that the threephase contact line advances to an area where it was previously occupied by the external phase as shown in **Figure 4(e)** or the substrate is slowly titled so that the droplet phase advances on it due to gravitational or buoyant force. In the tilting base method, both the advancing and receding CAs can be measured simultaneously as shown in **Figure 4(c)** and **(d)**. Similarly, in the case of receding CA measurement, the droplet phase volume is slowly decreased so

lary entry pressure of the caprock and thus to estimate the capacity of the host site to hold the

With the recent advancements in CT and microCT technologies, some researchers performed in-situ pore-scale CA measurements [37]. The procedure involves: (1) loading the core sample in an X-ray transparent coreholder; (2) scanning dry and wet core samples at various fluid saturations; (3) identifying rock and fluid phases in the collected tomographs; and (4) mea-

CA data can be indirectly estimated from relative permeability or capillary pressure curves.

displaces aqueous phase, relative wetting preferences of the fluids for the rock can be inferred. Typically, the endpoint relative permeability value less than 0.2 represents a strongly CO<sup>2</sup>

media. An endpoint relative permeability value close to 0.5 indicates an intermediate wetting state [36]. Advancing and receding CAs can also be estimated through capillary scaling of the

Sections 3.1 and 3.2 discuss the fluids and substrate preparation methods and their potential

to brines containing different types of salts and salinities, and CO<sup>2</sup>

phase as the bubble/droplet

169

http://dx.doi.org/10.5772/intechopen.79414

advancing (water/brine


streams

non-wetting porous

injection into the reservoir and also to determine the capil-

Interfacial Tension and Contact Angle Data Relevant to Carbon Sequestration

in a core-flooding experiment where CO<sup>2</sup>


, and Ar have been used for both the published IFT and

receding (water/brine advancing) CA is required to estimate the amount of

(called as sessile drop method, shown in **Figure 4(a)**) or the CO<sup>2</sup>

that the three-phase contact line recedes as shown in **Figure 4(f)**. CO<sup>2</sup>

surement of CA values either manually or using an automated algorithm.

porous media, whereas a value from 0.7 to 1 represents a strongly CO<sup>2</sup>

that can be capillary trapped in the host site [39].

Based on endpoint relative permeability of CO<sup>2</sup>

drainage and imbibition capillary pressure curves [11, 12].

**3. Fluids and substrate preparation methods**

Various compositions of aqueous-rich phase and CO<sup>2</sup>

S, SO<sup>2</sup>

, N<sup>2</sup>

impact on the IFT and CA data.

with impurities such as H<sup>2</sup>

**3.1. Fluids**

water and CO<sup>2</sup>

phase (captive bubble method, shown in **Figure 4(b)**).

receding) CA is relevant for CO<sup>2</sup>

. CO<sup>2</sup>

injected CO<sup>2</sup>

CO<sup>2</sup>

#### **2.2. Contact angle**

Wettability of an inert solid surface is its relative affinity towards a fluid in the presence of another immiscible or sparingly soluble fluid. CA measurement is a widely used and accepted method for quantifying wettability of a surface. Direct and indirect measurement methods have been used for the published CA data [12, 16, 23, 31–38]. Direct methods include static

**Figure 4.** (a) Sessile aqueous fluid droplet on substrate in CO<sup>2</sup> ; (b) captive CO<sup>2</sup> bubble/droplet on substrate in aqueous fluid; (c) sessile aqueous fluid droplet on inclined substrate in CO<sup>2</sup> ; (d) captive CO<sup>2</sup> bubble/droplet on inclined substrate in aqueous fluid; (e) advancing aqueous fluid droplet on substrate in CO<sup>2</sup> ; and (f) receding aqueous fluid droplet on substrate in CO<sup>2</sup> . Notation: θ—static CA; θ<sup>a</sup> —aqueous fluid advancing CA; and θ<sup>r</sup> —aqueous fluid receding CA.

(sessile-drop and captive-bubble) and dynamic (advancing and receding) CA measurements. Both the static and dynamic CAs were conducted using aqueous fluid as the droplet phase (called as sessile drop method, shown in **Figure 4(a)**) or the CO<sup>2</sup> phase as the bubble/droplet phase (captive bubble method, shown in **Figure 4(b)**).

For static CA measurement, the droplet phase is slowly released through a needle and deposited on the substrate immersed in external phase. In the case of advancing CA (w.r.t. droplet phase) measurement, either the droplet phase volume is slowly increased so that the threephase contact line advances to an area where it was previously occupied by the external phase as shown in **Figure 4(e)** or the substrate is slowly titled so that the droplet phase advances on it due to gravitational or buoyant force. In the tilting base method, both the advancing and receding CAs can be measured simultaneously as shown in **Figure 4(c)** and **(d)**. Similarly, in the case of receding CA measurement, the droplet phase volume is slowly decreased so that the three-phase contact line recedes as shown in **Figure 4(f)**. CO<sup>2</sup> advancing (water/brine receding) CA is relevant for CO<sup>2</sup> injection into the reservoir and also to determine the capillary entry pressure of the caprock and thus to estimate the capacity of the host site to hold the injected CO<sup>2</sup> . CO<sup>2</sup> receding (water/brine advancing) CA is required to estimate the amount of CO<sup>2</sup> that can be capillary trapped in the host site [39].

With the recent advancements in CT and microCT technologies, some researchers performed in-situ pore-scale CA measurements [37]. The procedure involves: (1) loading the core sample in an X-ray transparent coreholder; (2) scanning dry and wet core samples at various fluid saturations; (3) identifying rock and fluid phases in the collected tomographs; and (4) measurement of CA values either manually or using an automated algorithm.

CA data can be indirectly estimated from relative permeability or capillary pressure curves. Based on endpoint relative permeability of CO<sup>2</sup> in a core-flooding experiment where CO<sup>2</sup> displaces aqueous phase, relative wetting preferences of the fluids for the rock can be inferred. Typically, the endpoint relative permeability value less than 0.2 represents a strongly CO<sup>2</sup> -wet porous media, whereas a value from 0.7 to 1 represents a strongly CO<sup>2</sup> non-wetting porous media. An endpoint relative permeability value close to 0.5 indicates an intermediate wetting state [36]. Advancing and receding CAs can also be estimated through capillary scaling of the drainage and imbibition capillary pressure curves [11, 12].
