CO2–Water–Rock Wettability: Variability, Influencing Factors, and

Apr 13, 2017 - trapping (where a tight caprock acts as a seal barrier through which the CO2 .... to tight rocks (caprocks, sealrocks; very low permeab...
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CO2−Water−Rock Wettability: Variability, Influencing Factors, and Implications for CO2 Geostorage Published as part of the Accounts of Chemical Research special issue “Chemistry of Geologic Carbon Storage”. Stefan Iglauer* Department of Petroleum Engineering, Curtin University, 26 Dick Perry Avenue, Kensington, 6151 Western Australia, Australia ABSTRACT: Carbon geosequestration (CGS) has been identified as a key technology to reduce anthropogenic greenhouse gas emissions and thus significantly mitigate climate change. In CGS, CO2 is captured from large point-source emitters (e.g., coal fired power stations), purified, and injected deep underground into geological formations for disposal. However, the CO2 has a lower density than the resident formation brine and thus migrates upward due to buoyancy forces. To prevent the CO2 from leaking back to the surface, four trapping mechanisms are used: (1) structural trapping (where a tight caprock acts as a seal barrier through which the CO2 cannot percolate), (2) residual trapping (where the CO2 plume is split into many micrometer-sized bubbles, which are immobilized by capillary forces in the pore network of the rock), (3) dissolution trapping (where CO2 dissolves in the formation brine and sinks deep into the reservoir due to a slight increase in brine density), and (4) mineral trapping (where the CO2 introduced into the subsurface chemically reacts with the formation brine or reservoir rock or both to form solid precipitates). The efficiency of these trapping mechanisms and the movement of CO2 through the rock are strongly influenced by the CO2− brine−rock wettability (mainly due to the small capillary-like pores in the rock which form a complex network), and it is thus of key importance to rigorously understand CO2-wettability. In this context, a substantial number of experiments have been conducted from which several conclusions can be drawn: of prime importance is the rock surface chemistry, and hydrophilic surfaces are water-wet while hydrophobic surfaces are CO2-wet. Note that CO2-wet surfaces dramatically reduce CO2 storage capacities. Furthermore, increasing pressure, salinity, or dissolved ion valency increases CO2-wettability, while the effect of temperature is not well understood. Indeed theoretical understanding of CO2-wettability and the ability to quantitatively predict it are currently limited although recent advances have been made. Moreover, data for real storage rock and real injection gas (which contains impurities) is scarce and it is an open question how realistic subsurface conditions can be reproduced in laboratory experiments. In conclusion, however, it is clear that in principal CO2-wettability can vary drastically from completely water-wet to almost completely CO2wet, and this possible variation introduces a large uncertainty into trapping capacity and containment security predictions.

1. INTRODUCTION Carbon geosequestration (CGS) has been identified as a key technology to reduce anthropogenic greenhouse gas emissions and thus significantly mitigate climate change.1 In CGS, CO2 is captured from large point-source emitters (e.g., coal fired power stations), purified, and injected deep underground into geological formations for disposal. Storage depths are typically below 800 m, so that the CO2 is in a dense supercritical (sc) state (note that typical geothermal [30 K/km] and hydrostatic [10 MPa/km] gradients lead to high pressure and elevated temperature conditions in storage formations) and storage capacity is maximized. However, despite being supercritical, the CO2 still has a lower density than the resident formation brine and thus migrates upward due to buoyancy forces. Four main mechanisms prevent the CO2 from leaking back to the surface: (1) structural trapping (where a tight caprock acts as a seal barrier through which the CO2 cannot percolate),2,3 (2) © 2017 American Chemical Society

residual trapping (where the CO2 plume is split into many micrometer-sized bubbles, which are immobilized by capillary forces in the pore network of the rock),4,5 (3) dissolution trapping (where CO2 dissolves in the formation brine and slightly increases the brine density so that the CO2-enriched brine sinks deeper into the reservoir),6 and (4) mineral trapping (where the CO2 introduced into the subsurface chemically reacts with the formation brine or reservoir rock or both to form solid precipitates).7 All storage mechanisms act on different time-scales, and the two primary mechanisms active in the first several hundreds of years of a storage project are structural and residual trapping. These two mechanisms rely on strong capillary forces, which counterbalance the upward oriented buoyancy forces. It is thus of key importance to Received: December 2, 2016 Published: April 13, 2017 1134

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Figure 1. (a) Traditional Sw−pc curve measurements. (b) NMR spectra.21,26 Reproduced from ref 21. Copyright 2015 ANLEC. (c) 2D micromodel image.27 Adapted with permission from ref 27. Copyright 2012 American Chemical Society. (d) 3D microCT image.28 Adapted with permission from ref 28. Copyright 2016 Elsevier.

where γ is the CO2−brine interfacial tension, r is the inner radius of the capillary, and θ is the water−CO2−solid contact angle. The parameter γ is well-constrained;15 note that γ strongly decreases with increasing pressure at low pressure and reaches a pseudo-plateau at high pressure (say, twice the critical CO2 pressure); γ also slightly depends on temperature and salinity. Furthermore, it is clear that the water-receding (or CO2-advancing) contact angle is relevant to structural trapping (it determines the capillary entry pressure through eq 2.1, where r is the size of the largest pores or microfractures in the caprock), whereas the water-advancing (or CO2-receding) angle is relevant to the residual trapping process when water or brine reimbibe the reservoir rock. However, the pore morphology of a rock is significantly more complex than a perfect cylindrical capillary tube and highly variable,16 and this highly complicates the prediction of the capillary pressures;17 this constitutes an active area of research.18 Another factor that is highly variable and also not yet well understood is θ, which is essentially an expression of the rock wettability with respect to water and CO2. This Account focuses on this parameter (θ) and how it is affected by thermophysical, physicochemical, and geological variables. As an important point, note that pc can be negative (see detailed

predict these capillary forces so that storage capacities, CO2 injectivities (which both determine the economic feasibility of a storage project), and containment security (which is a regulatory constraint) can be assessed.8

2. WETTABILITY AND CAPILLARY FORCES Capillary forces, intermolecular forces that are created at the molecular level,9 determine capillary pressures, pc (= pnw − pw, where nw is the nonwetting phase and w is the wetting phase) in the formation and in each pore of the rock. Capillary pressures, however, determine the structural trapping capacity3 and the two-phase (or three-phase in case of an oil reservoir)10 fluid dynamics.11 Note that these pore-scale processes then determine the overall reservoir (hectometer) scale flow, including the efficiency of residual and dissolution trapping,12,13 although macroscopic factors also play an important role (e.g., geological heterogeneity of the reservoir).12 In an ideal cylindrical capillary tube with constant crosssectional area (and perfect chemical homogeneity and no surface roughness), pc can be predicted with the Young− Laplace equation:14 pc =

2γ cos θ r

(2.1) 1135

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Figure 2. Variation of CO2-wettability with thermophysical condition and surface chemistry. A water drop on a tilted calcite in CO2 atmosphere is shown. The advancing (θa) and receding (θr) water contact angles are indicated in the images (courtesy Sarmad Al-Anssari).

3.1.2.2. Three-Dimensional X-ray Microcomputed Tomography (microCT). Somewhat similar to the 2D micromodels discussed above are 3D microCT images, which can be acquired at in situ reservoir conditions (i.e., high pressure and elevated temperature).29,32−34 The fluid configurations in the pores can be analyzed, and associated contact angles, CO2− water interfacial curvatures, and related capillary pressures can be directly measured on these images.16,35,36 3.1.2.3. Nuclear Magnetic Resonance (NMR) Measurements. Here the T2 transverse relaxation time of 1H nuclei (usually H2O protons) is measured. T2 can be related to the pore surface (S)−volume (V) ratio:37

discussion below), which then creates an upward oriented CO2sucking force.8

3. MEASURING CO2−BRINE−ROCK WETTABILITY It is consequently necessary to measure CO2-brine-rock wettability; and there are various methods available to accomplish this; these can be split into two main groups: (1) coreflood methods and (2) contact angle measurements. 3.1. Coreflood Methods

3.1.1. Traditional Techniques. Here experiments related to tight rocks (caprocks, sealrocks; very low permeability) and reservoir rocks (average to high permeability) need to be distinguished. For reservoir rocks, the secondary imbibition (imbibition is the injection of a wetting phase) and secondary drainage (drainage is the injection of a nonwetting phase) water saturation (Sw)−capillary pressure curves are measured, Figure 1. From the integrals of the Sw−pc curves, the wettability index can be determined; classic wettability indices are the Amott and USBM indices.19,20 For instance, the USBM index is defined as log(A1/A2), where A1 and A2 are the integrals of the secondary drainage and imbibition curves. However, such experiments are difficult and time-consuming, and only scCO2 drainage curves have been reliably measured.21,22 These problems are even worse for tight rocks, for which no such data has been reported so far. However, a few drainage−imbibition data sets exist for quartz and calcite sands.23−25 The advantage of these coreflood techniques is, nevertheless, that they mimic the two-phase flow in the rock and can provide important additional data (e.g., residual saturations, Sw−pc curves).12,13 Because of all these problems, typically contact angles are measured, see section 3.2. 3.1.2. New Developments. There are also new developments with which fluid configurations can be observed directly in the pore space (Figure 1). 3.1.2.1. Two-Dimensional Micromodels. Here a 2D model rock (strictly speaking a 3D rock, but only a very thin layer is considered, which can be observed directly with a light microscope) is replicated by etching pore channels into silica sheets and injecting the various fluids to be examined.27,29,30 The main limitations here are the simplified rock geometry and surface chemistry, and the fact that 3D multiphase fluid dynamics cannot be replicated in 2D, for example, the percolation threshold is much lower in 3D.31

⎛S⎞ 1 = ρsur ⎜ ⎟ ⎝V ⎠ T2

(3.1)

where ρsur is the surface relaxivity. T2 thus correlates with the pore size distribution, and smaller T2 are associated with smaller pores, while larger T2 indicate existence of larger pores. Via subtraction of such T2-response curves acquired for fully water saturated and partially CO2 saturated core plugs, the location where the CO2 resides can be identified (if the CO2 resides in small pores, the system is CO2-wet; if it resides in large pores the system is water-wet).21 3.2. Contact Angle Measurements

Here the CO2−brine−rock (or mineral) contact angle is measured. Typically a drop of water is dispensed onto the substrate in CO2 atmosphere, and the droplet is imaged by a high performance video camera (Figure 2). Alternatively, a CO2 bubble can be released beneath the substrate, which is immersed in water. This approach has now been used widely for measuring CO2−rock wettability.8 However, several experimental pitfalls exist, which need to be avoided and which have contributed to a significant degree of uncertainty in the literature. This includes the fact that Young’s (equilibrium) contact angle cannot be directly measured (because of metastable states, which are caused by surface roughness), and thus advancing (θa) and receding (θr) contact angles have to be measured; note that θa and θr can be converted to Young’s contact angles.38 Furthermore, surface contamination has to be avoided as this introduces a strong bias,39 and the surface roughness should be quantified as it influences the contact angle.40 Finally, if a composite substrate 1136

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Table 1. Physical and Physicochemical Properties of Water, CO2, and Some Selected Hydrocarbons for Comparison44

a

property

water

CO2

CH4

n-octane

toluene

electrical dipole moment [10−30 × Cm] static dielectrical constant (at 10 MPa and 340 K) hydrogen bonding Lewis acid−base interactions maximum solubility in water [mol %]

6.186 65.044 strong yes 1a

0 1.13908 weak yes 3.61

0 1.07786 no no 0.36

0 1.91777 (at 333 K) no no 1.6 × 10−5

1.251 2.515 (at 303 K and 101 MPa) weak possible 1.25 × 10−4

Solubility in CO2 (in mol %).

or a base. Formation of such hydrogen bonds or Lewis acid− base pairs at the rock−water interface would strongly enhance the affinity of water for the rock surface and thus reduce the water contact angle.

is tested, the sample’s chemical heterogeneity needs to be taken into account. 3.3. Theoretical Approaches

Contact angles can also be computed via atomistic molecular dynamics simulations.41 The obvious advantage over experimental measurements is that the above listed pitfalls are removed; for instance, there will be no contamination in such calculations. The challenge, however, is the implementation of the correct surface chemistry, which clearly has a large impact (see section 5.2 below), and generally the question is whether all real factors are sufficiently considered in the model.

4.2. Carbon Dioxide (CO2)

Contrary to water, CO2 has a zero external electrical dipole moment and a low dielectrical constant, Table 1. However, CO2 has two relatively strong internal electrical dipole moments, that is, a significant quadrupole moment (Figure 3). CO2 thus has the potential to act as both a weak Lewis acid and a Lewis base.45 Furthermore, CO2 can form weak hydrogen bonds with alcohol or carbonyl groups.45,46 Consequently CO2 can show a significantly higher affinity to a rock surface when compared to the hydrocarbon equivalent. In addition, CO2 and H2O show a limited, but significant mutual miscibility (Table 1), which decreases with increasing salinity and temperature or decreasing pressure. These characteristics should be kept in mind when analyzing H2O−CO2−rock systems, and extrapolations from analogue hydrocarbon systems should be avoided.

4. WATER AND CO2 CHEMISTRY The relative affinity of CO2 and water toward the solid surface essentially determines the wettability. If the system (CO2− H2O−solid) loses Gibbs energy if one fluid displaces the other fluid from the solid surface, then there is a significant thermodynamic driving force toward a reconfiguration of the fluid−fluid−solid system, until the system reaches its minimum in Gibbs energy (and thus equilibrium); this reconfiguration may only be retarded by metastable states (e.g., due to surface roughness).42 Thus, before discussing the key parameters that influence CO2-wettability, a short summary of the water and CO2 chemistries is given; these need to be appreciated in detail to fully assess the induced intermolecular forces and the associated wettability behavior. Importantly, CO2 behaves in a significantly different way from hydrocarbons (e.g., methane, n-octane, or toluene, cp. Table 1). In terms of the solid surface, it is clear that the surface chemistry has a primary impact, this is discussed in more detail in section 5.2.

5. FACTORS INFLUENCING CO2−WATER−ROCK WETTABILITY A substantial number of contact angle measurements on various substrates at various thermophysical conditions have been performed, and most of this data is compiled in Figure 4; however, data spread is very large, demonstrating that essentially all CO2-wettabilities, from completely water-wet to strongly CO2-wet, are physically possible. It is essentially the

4.1. Water

Water (H2O) is a highly polar molecule that has a strong permanent electrical dipole moment and a high dielectric constant (Figure 3 and Table 1). As a consequence water has a

Figure 3. Water and CO2 molecules with bond lengths (pink), bond angles (green), and charges (red) indicated.

high affinity for polar surfaces and a tendency to completely spread on them (as this minimizes the Gibbs energy of the system). This high polarity also results in the association of liquid water molecules in coordinated random networks, caused by the formation of hydrogen bonds.43 Furthermore, water is an amphoteric molecule (i.e., it can act as a base or an acid), and it can thus undergo Lewis acid−base interactions as an acid

Figure 4. Water−CO2−mineral/rock contact angle data measured on various substrates at various thermophysical conditions.8 1137

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Accounts of Chemical Research task of this Account to deconvolute these points and to illustrate the underlying relationships. 5.1. Theoretical Background

The contact angle θ and thus CO2-wettability can be quantified via Young’s equation (which constitutes a balance of interfacial forces):14 cos θ =

γsCO − γws 2

γwCO

(5.1)

2

where γsCO2 is the solid−CO2 interfacial tension, γws is the water−solid interfacial tension, and γwCO2 is the water−CO2 interfacial tension. It is thus clear that CO2-wettability is determined by the individual interfacial tensions; however, γsCO2 and γws cannot be directly measured42 and need to be estimated semiempirically.47 Thus, a more practical relationship was derived:48 1/2 ε0ψs 2D ⎛ 2e 2cz 2Na ⎞ I Δρ ⎜ ⎟ −1 cos θ = − γwCO 2γwCO ⎝ ε0KbDf T ⎠ 2

2

Figure 5. Water−CO2−mineral contact angles on hydrophilic (green) and hydrophobic (red) surfaces.

is consistent with molecular dynamics computations,52 Sw−pc measurements,23−25 2D micromodel imaging of pure and oilwet silica surfaces,29 and 3D microCT imaging of supercritical CO2 in water-wet and oil-wet sandstone.28,32,34 This wetting behavior is also reflected in estimates of the rock−CO2 and rock−water interfacial energies (γsCO2 and γws); γsCO2 is significantly lower in case of hydrophobic surfaces (thus leading to more CO2-wetting), while γws is higher.47 However, one important point, which is currently not well understood, is the fact that in the subsurface, suboxic or reducing conditions prevail52 and the mineral surfaces are thus very unlikely clean. This implies that θ in the reservoir is significantly higher than the θ measured on the clean surfaces;39 for example, small amounts of organic material (total organic content = 510−4400 mg/kg rock) in real natural caprock altered the rock intermediate-wet at reservoir conditions.2 In summary it is clear that it is very unlikely that subsurface systems−at reservoir conditions−are completely water-wet (as traditionally assumed), but instead it is likely that they are intermediate-wet or, particularly in oil reservoirs, even CO2wet; and this needs to be correctly implemented in reservoir simulations to arrive at reliable storage capacity and containment security predictions.12,13

(5.2)

where I is the van der Waals potential integral ∞ (I = −∫ V (z) dz , where V quantifies the preference of the z min

adsorbate molecule for wetting the substrate instead of forming a droplet and z is the vertical distance from the solid surface),49 Δρ is the fluid density difference (approximately),50 ε0 is the permittivity of vacuum, ψs is the electric potential of the solid surface, D is the dielectric constant of the solid surface and surrounding liquid, e is the elementary charge (1.602 × 10−19 C), c is the ion concentration of the solution, z is the ion valency, Na is Avogadro’s constant (6.022 × 1023 mol−1), Kb is Boltzmann’s constant (1.38 × 10−23 J/K), Df is the dielectric constant of the solution and T is the temperature. The first RHS term of eq 5.2 relates to the influence of pressure (which strongly affects Δρ due to the high compressibility of CO2), while the second terms accounts for the influence of electrolytes; this is discussed further below. In the following paragraphs, the influences of the most important variables are discussed, and knowledge gaps are identified. The order of the discussion and paragraphs follows their direct importance in terms of CO2-wettability.

5.3. Pressure

5.2. Surface Chemistry

Pressure is the second most important parameter that influences θ, and an increased pressure leads to increased θ (i.e., increased CO2-wettability). This trend is apparent in Figure 5, although data spread is convoluted by different mineral types (with different surface chemistries), surface roughnesses, temperatures, and brine compositions. θ as a function of pressure is thus replotted in Figure 6 for a quartz− CO2−deionized water system.55 The influence of pressure is now clearly evident. This increase in θ with pressure is caused by the strong increase in CO2-density with increasing pressure (CO2 has a high compressibility), which leads to strongly enhanced CO2− mineral intermolecular interactions55,56 and a significantly higher CO2−solid affinity, which leads to the dewetting of the surface. For constant temperature, brine composition, and mineral surface the following relationship can be derived:50,57 I cos θ = Δρ − 1 γwCO (5.3)

The solid’s surface chemistry is the primary factor determining CO2-wettability. While hydrophilic (= polar) surfaces are naturally attractive for water (which is a highly polar molecule, see section 4.1), hydrophobic surfaces have a much higher affinity for CO2. Consequently clean minerals (typical minerals in the formation are quartz, calcite, feldspar, and mica) are water-wet (θ ranges between 0 and 60°) due to their hydrophilicity (note that chemically clean surfaces can only be obtained via strongly oxidizing conditions, which are not representative of subsurface conditions).8,39,51,52 Furthermore, it has been demonstrated that the degree of surface hydroxylation and deprotonation strongly affects the wettability.53 Oil-wet surfaces (alkylated surfaces, surfaces aged in crude oil or coal, which mostly consists of organic matter), however, are CO2-wet or intermediate-wet (θ ranges between 70° and 170°).8,54 This is illustrated in Figure 5, where all hydrophobic surfaces have been plotted in red, while all hydrophilic surfaces are shown in green. This contact angle data

2

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Accounts of Chemical Research 5.5. Brine Composition: Salinity and Salt Types

Formation brines are complex mixtures containing a multitude of dissolved salts in varying concentrations. The brine composition also has a significant impact on θ, and in a nutshell, higher ionic strengths lead to increased CO2wettability. 5.5.1. Effect of Salinity. The effect of salinity is relatively well understood qualitatively, although quantification (e.g., via eq 5.2) is still lacking understanding. Increased salinity clearly increases CO2-wettability, cp. Figure 8. Mechanistically, the

Figure 6. Water−CO2−quartz contact angles as a function of pressure and temperature. Adapted with permission from ref 55. Copyright 2016 Elsevier.

Remarkably, this relation holds also for various other types of gases (N2, Ar, He, and SF6 were tested); and, interestingly, I/ γwCO2 is constant (for constant temperature, brine composition, and mineral).50 However, calculating I is complex, and wettability is thus typically determined experimentally (cp. section 3). Furthermore, if temperature, brine composition, or the substrate varies, eq 5.3 needs to be expanded into eq 5.2. 5.4. Temperature

The effect of temperature is more elaborate as several θinfluencing parameters are functions of temperature themselves. For instance, the fluid density difference Δρ, the CO2−water interfacial tension γwCO2, the dielectric constant of the fluid D f, or of course the temperature itself. The detailed functional and mechanistic influence of temperature on θ is thus an open research question, and typically θ is measured experimentally for specified conditions on selected substrates. For example, Figure 7 shows θa as a function of temperature (and pressure) for water−quartz and −coal systems. While θa decreases with temperature for quartz, it increases for coal.55,58 In conclusion, further research in this area is needed to establish a more fundamental understanding of the temperature effect.

Figure 8. Water−CO2−quartz contact angles as a function of salinity and salt type (10 MPa and 323 K). Adapted with permission from ref 55. Copyright 2016 Elsevier.

rock surface is (electrically) charged (due to (i) permanent structural charges caused by isomorphic substitutions, e.g., Al(III) can replace Si(IV) in the crystal lattice of layer silicates, that is, clay minerals; (ii) chemical reactions of surface functional groups (e.g., protonation/deprotonation of surface hydroxyl groups); or (iii) adsorption of surface active molecules); and this surface charge depends on the pH value and the type of mineral.59 In the brine, dissolved ions (of opposite charge) move toward the charged surface and form an electrical double-layer thereby inducing a rapid decay in the electrical potential above the solid surface, which reduces the overall polarity of the surface. This reduced surface polarity results in less hydrophilicity, and thus θ increases, Figure 8. This effect is more pronounced at higher salinities (more precisely, higher ionic strengths), and thus more saline brines are more CO2-wet. Also note that salinities in the subsurface can vary greatly (up to the maximum saturation),60 and this factor should be considered in an accurate rock-wettability analysis. 5.5.2. Type of Ions or Salts Dissolved in the Formation Brine. The ion type dissolved in the water is another significant factor; ions with higher valency (Mg2+, Ca2+, Al3+, SO42−) have significantly higher charge-to-volume ratios and ionic strengths 1 n (Is = 2 ∑i = 1 cizi 2 , where n is the number of ion types, c their concentration, and z their charge) than monovalent ions (Na+, K+, Cl−) and thus shield the surface charge more effectively, which leads to higher θ and increased (water) dewetting of the

Figure 7. Advancing water−CO2−quartz and high rank coal (semianthracite) contact angles as a function of pressure and temperature.55,58 1139

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Accounts of Chemical Research surface. Ideally formation brine samples are used for the wettability analysis of real storage projects.

However, wettability is a complex phenomenon determined by intermolecular forces, and wettability is still not well constrained. In this Account, the state-of-the-art knowledge is summarized, background relations are outlined, several clear trends have been highlighted, and knowledge gaps were identified. In summary, it is clear that CO2-wettability increases with pressure, brine salinity, and particularly hydrophobicity of the rock surface. The influence of temperature, however, is not well understood yet. Furthermore, and importantly, data for real storage rock is scarce, and it is questionable how representative the systems investigated so far were with respect to realistic subsurface conditions and real CO2 injection streams (which contain impurities). For example, small TOC levels (∼1000 mg/kg) dramatically increased CO2-wettability in a real caprock of a proposed CO2 storage site.2 Another open question is how CO2-wettability changes over time, for instance, with slower surface chemical reactions or adsorption processes (note that storage projects are planned for hundreds to thousands of years). These knowledge gaps present a significant risk in terms of CO2 storage capacity and containment security predictions.

5.6. Impurities in the CO2 Injection Stream

The captured CO2 is not absolutely pure, although this is a design criterion for CO2 separation processes. The purity levels depend on the selected separation process and typically range from 95 to 99.95+ vol %.61 Thus, significant amounts of impurities (O2, N2, Ar, NOx , SOx , CO, H2, H2S, or CH4) are present in injected CO2 streams, particularly in case of the precombustion or oxy-fuel processes.61 Furthermore, unwanted gases produced during hydrocarbon recovery operations (separated gas) are sometimes (re)injected into the formation; particularly when H2S levels are high (note that such gas compositions vary strongly, and very high H2S levels can be reached; for example, 14−98% CO2 and 2−83% H2S are reinjected into Canadian gas fields).62 Testing these impurities with respect to θ is, however, limited. While N2, and N2−CO2 mixtures are more water-wet than pure CO2,63,64 H2S is less water-wet,65 and SO2 showed no significant influence on θ.66 N2 injection would, however, significantly reduce CO2 storage capacity as addition of N2 would dramatically reduce the density of the stored fluid. H2S, particularly when considering its lower water-wettability, is an acid and highly poisonous gas (note that the immediately dangerous for life and health IDLH concentration is 100 ppm) and poses a serious concern from a health and safety perspective. However, data for real flue or injection gas is very scarce, and θ for real injection gas is currently unknown.

■

Corresponding Author

*E-mail: [email protected]. ORCID

Stefan Iglauer: 0000-0002-8080-1590

5.7. Surface Roughness

Notes

Surface roughness is long known to have an effect on θ. Consider for example the Wenzel equation:40 cos θrough = r cos θsmooth

AUTHOR INFORMATION

The author declares no competing financial interest. Biography

(5.4)

Stefan Iglauer is an Associate Professor at Curtin University, Perth, Australia, in the Department of Petroleum Engineering. His research interests are in CO2 geostorage and hydrocarbon recovery with a particular focus on pore-scale processes. Stefan has authored more than 100 technical publications; he holds a Ph.D. degree in materials science from Oxford Brookes University (U.K.) and a M.Sc. degree in chemistry from the University of Paderborn (Germany).

where θrough is the contact angle measured, θsmooth is the contact angle on an ideal (100% mathematically flat) surface, and r is the roughness ratio (r is the measured surface area divided by the ideal surface area; thus r = 1 for an ideal surface). Generally a higher surface roughness induces more surface wetting; thus, with increasing surface roughness, a water-wet surface turns even more water-wet and a CO2-wet surface turns more CO2wet. For CO2−brine−mineral surfaces, this was also observed. While Al-Yaseri et al.55 determined relatively small differences in θ (around 5°) for a rough quartz surface (560 nm RMS surface roughness) versus an ideal surface estimated via eq 5.4, a larger difference was measured by Wang et al.,67 where θ for a smooth silica surface (RMS = 5.8 nm) ranged from 31° to 38° (1.5 M NaCl brine, 0−20 MPa, 323 K) but dropped to 1° on a rougher surface (RMS = 2300 nm). The detailed influence of a 3D pore wall morphology, however, requires further research work.

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REFERENCES

(1) Intergovernmental Panel on Climate Change, IPCC special report on carbon dioxide capture and storage, Cambridge University Press: Cambridge, U.K., 2005. (2) Iglauer, S.; Al-Yaseri, A. Z.; Rezaee, R.; Lebedev, M. CO2wettability of caprocks: Implications for structural storage capacity and containment security. Geophys. Res. Lett. 2015, 42, 9279−9284. (3) Broseta, D. Assessing seal rock integrity for CO2 geological storage purposes. In Geomechanics of CO2 Storage Facilities; PljaudierCabot, G., Pereira, J. M., Eds.; Wiley: London, 2012. (4) Pentland, C. H.; El-Maghraby, R.; Iglauer, S.; Blunt, M. J. Measurements of the capillary trapping of super-critical carbon dioxide in Berea sandstone. Geophys. Res. Lett. 2011, 38, L06401. (5) Krevor, S.; Blunt, M. J.; Benson, S. M.; Pentland, C. H.; Reynolds, C.; Al-Menhali, A.; Niu, B. Capillary trapping for geologic carbon dioxide storage−From pore scale physics to field scale implications. Int. J. Greenhouse Gas Control 2015, 40, 221−237. (6) Lindeberg, E.; Wessel-Berg, D. Vertical convection in an aquifer column under a gas cap of CO2. Energy Convers. Manage. 1997, 38, S229−234. (7) Gaus, I. Role and impact of CO2/rock interactions during CO2 storage in sedimentary rocks. Int. J. Greenhouse Gas Control 2010, 4, 73−89.

6. CONCLUSIONS AND IMPLICATIONS The CO2-wettability of the storage formation is of key importance for CO2 geosequestration as it determines injectivities, storage capacities, and containment security.8 Specifically CO2-wettability determines the pore-scale (micrometer scale) configuration of the fluids (CO2 and water) in the pore network of the rock,28 which strongly influences mesoscale flow parameters (e.g., relative permeability)68 and overall hectometer (reservoir) scale fluid dynamics, and structural, residual, and dissolution trapping capacities.2,12,13 1140

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Accounts of Chemical Research

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DOI: 10.1021/acs.accounts.6b00602 Acc. Chem. Res. 2017, 50, 1134−1142