Sylvain Delerce

Chiara Marieni

Eric H Oelkers
email: eric.oelkers@get.omp.eu

Carbonate geochemistry and its role in geologic carbon storage

Keywords: Geologic carbon storage, solubility storage, calcite, carbon mineralization, well bore cements, Weyburn, Carbfix

Massive quantities of CO 2 need to be captured and stored to address the potential consequences of global warming. Geologic storage of CO 2 may be the only realistic option available to store the bulk of this CO 2 due to the required storage volumes. Geologic storage involves the injection of CO 2 into the subsurface. This injection will lead to the acidification of the formation fluids and provoke a large number of fluid-mineral reactions in the subsurface. Of these reactions, those among CO 2 -rich fluids and carbonate minerals may be the most significant as these reactions are relatively rapid and have the potential to alter the integrity of caprocks and well bore cements. This review provides a detailed summary of field, laboratory and modeling results illuminating the potential impacts of the injection of large quantities of CO 2 into the subsurface as part of geologic storage efforts.

INTRODUCTION

A large number of recent publications have emphasized the need of society to increase dramatically the scale of carbon capture and storage (CCS) to address the threat of global warming [START_REF] Oelkers | Carbon dioxide sequestration: A solution to a global problem[END_REF][START_REF] Azapagic | Greenhouse gas removal[END_REF][START_REF]Summary for Policymakers[END_REF]. At the time of the publication of this review, approximately 40 Gt of carbon dioxide (CO 2 ) are being emitted to the atmosphere annually due to anthropogenic activities [START_REF] Friedlingstein | Global Carbon Budget[END_REF]. To help stem global warming, the IPCC net zero scenarios [START_REF]Summary for Policymakers[END_REF] recommends from 8 to 18 Gt CO 2 /yr of CCS by the year 2050; the BP Energy Outlook 2020 foresees more than 5 Gt CO 2 /yr of CCS by the year 2050 [5]. To date, however, progress towards these goals has been limited. As of 2020, only 26 commercial CCS facilities were operating globally and these facilities had a CO 2 capture capacity of 40 Mt CO 2 /year [START_REF]Global status of CCS[END_REF]. Of these, most in operation at present are dedicated to enhanced oil recovery (EOR); such EOR projects may account for as much as 90% of the current CCS capacity worldwide. If one considers the carbon emissions from the burning of the additional oil produced from EOR operations, the net reduction of CO 2 emitted to the atmosphere from such efforts is minimal. Taken together, therefore, the total current net reduction of CO 2 to the atmosphere as of 2020 due to global CCS activities may be no more than 5 Mt CO 2 /yr. This will need to be upscaled by three orders of magnitude by 2050 to attain the level of CCS suggested by the 'Net Zero' scenario of the BP Energy Outlook 2020 and substantially further to attain the goals outlined by the IPCC. Such upscaling may be promoted by pressure from public opinion, private companies seeing business opportunities, and an acceleration in policy support for the carbon removal. Each of these factors has led to a notable acceleration of the investments in carbon removal over the past few years [START_REF] Sekera | Assessing Carbon Capture: Public Policy, Science, and Societal Need[END_REF][START_REF] Larsen | Capturing Leadership: Policies for the US to Advance DAC Technology[END_REF].

One of the major challenges of upscaling substantially CCS is the storage of large volumes of carbon dioxide. At ambient pressure and temperature, one Gt of CO 2 occupies 560 km 3 of volume. This decreases to 2.6 km 3 at the supercritical temperature and pressure conditions of 50 o C and 100 bars. If this carbon-dioxide reacts with subsurface minerals to form calcite (CaCO 3 ), 0.84 km 3 of space is required to store 1 Gt of CO 2 . Such large volumes are not practically stored at the surface of the Earth, but available in the subsurface, where higher pressure will help compact the injected gas.

Geologic storage addresses the need for high pressure and large volume required for the global scale application of CCS. Geologic storage consists of the injection of CO 2 into the pore spaces of subsurface rocks. The injection of CO 2 into the subsurface as part of geologic carbon storage efforts, however, alters significantly the chemistry of the subsurface fluid. In particular, once CO 2 is injected into the subsurface some of this CO 2 will dissolve into the aqueous phase producing an acidic fluid. This acidic fluid will react chemically with the coexisting rocks altering the rock permeability and porosity, as well as distributing chemical components and minerals in the subsurface [START_REF] Gaus | Role and impact of CO 2 -rock interactions during CO 2 storage in sedimentary rocks[END_REF]. Of the mineral reactions that occur in the subsurface in response to CO 2 injection the dissolution and precipitation of calcite and other carbonate minerals may be the most significant due to: 1) their ubiquity in most target injection systems, and 2) their relatively rapid reaction rates [START_REF] Chou | Comparative study of the kinetics and mechanisms of dissolution of carbonate minerals[END_REF]. Indeed, the dissolution rate of calcite is sufficiently rapid that this mineral will promptly attain chemical equilibrium with adjacent CO 2 -charged aqueous fluids. Such reactions have the potential to alter significantly reservoir properties, as well as to neutralize the acidic CO 2 -rich aqueous phase. The purpose of the present communication is to review geologic carbon storage with a focus on the carbonate-water reactions occurring in response to the injection of CO 2 into the subsurface.

REVIEW OF SUBSURFACE CO 2 TRAPPING MECHANISMS

The long-term success of geologic storage will require that the injected CO 2 remains in the subsurface over timescales of at least thousands of years. Miocic et al. [START_REF] Miocic | 000 Year Assessment of Fault Leakage Rates Shows Geological Carbon Storage Is Secure[END_REF] argued that to be effective as a climate change mitigation tool, CO 2 must be securely retained for 10,000 years with a leakage rate of below 0.01% per year of the total amount of CO 2 injected. As pure CO 2 is less dense than aqueous formation fluids (see Figure 4 below), injected carbon dioxide could potentially migrate from underground storage sites through boreholes, poor caprocks or faults and fractures. Most CO 2 leakage will be gradual and may go undetected for prolonged periods of time [START_REF] Damen | Identification of early opportunities for CO 2 sequestration-worldwide screening for CO 2 -EOR and CO 2 -ECBM projects[END_REF][START_REF] Bachu | CO 2 storage in geological media: Role, means, status and barriers to deployment[END_REF]. In a study of carbon leakage from the Green River, Utah formation, Burnside et al. [START_REF] Burnside | Man-made versus natural CO 2 leakage: A 400 k.y. history of an analogue for engineered geological storage of CO 2[END_REF] concluded that fault-focused leakage tends to be twice as great as diffusive leakage through confined aquifers, but that leakage through poorly completed boreholes was 13 times greater than that of leakage through faults. Such results suggest that CO 2 leakage via abandoned wells pose a great risk to the integrity of geologic carbon storage reservoirs. In each case, leakage risk may be lessened over time by the various trapping mechanisms that progressively occur within the subsurface reservoir. Such trapping mechanisms have been reported by numerous sources to follow the sequence of trapping mechanisms in the subsurface illustrated in Figure 1 and described in more detail below [START_REF] Gunter | The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage of carbon dioxide[END_REF][START_REF] Johnson | Reactive transport modelling of CO 2 storage in saline aquifers to elucidate fundamental processes, trapping mechanisms and sequestration partitioning[END_REF][START_REF] Bradshaw | CO 2 storage capacity estimation: Issues and development of standards[END_REF][START_REF] Benson | CO 2 sequestration in deep sedimentary formations[END_REF]. Figure 1. Schematic illustration of various trapping mechanisms within geologic carbon storage over time in response to the injection of supercritical CO 2 (scCO 2) into the subsurface. Reproduced with permission from [START_REF] Snaebjörnsdóttir | The chemistry and saturation states of subsurface fluids during the in situ mineralisation of CO 2 and H 2 S at the CarbFix site in SW-Iceland[END_REF], originally from [START_REF] Benson | Underground geological storage[END_REF].

Structural or stratigraphic trapping refers to the emplacement of CO 2 below an impermeable rock formation (called caprock) that will act as a seal to counter the natural buoyancy of the injected CO 2 . This mechanism can be used for long-term storage in saline aquifers, or temporarily in basalt or other reactive rock formations below the seabed surface as described by Goldberg and Slagle [START_REF] Goldberg | A global assessment of deep-sea basalt sites for carbon sequestration[END_REF]. Stratigraphic trapping heavily relies on both the available porosity of the reservoir formation, and the integrity of a low permeability caprock over extended time periods.

Residual trapping refers to the immobilization of CO 2 by capillary forces within the pore space [START_REF] Burnside | International Journal of Greenhouse Gas Control Review and implications of relative permeability of CO 2 / brine systems and residual trapping of CO 2[END_REF]. It has been shown that residual trapping in limestones and sandstones efficiently retains CO 2 in more than two thirds of the total saturation of the pore space [START_REF] Andrew | Pore-scale imaging of trapped supercritical carbon dioxide in sandstones and carbonates[END_REF]. In turn, Rahman et al. [START_REF] Rahman | Journal of Colloid and Interface Science Residual trapping of supercritical CO 2 in oil-wet sandstone[END_REF] showed that the efficiency of this trapping mechanism is reduced by half in the case of oil wet rocks, for example in depleted oil fields.

Solubility trapping occurs as the injected CO 2 dissolves into formation fluids. The efficiency of solubility trapping depends strongly on the solubility of CO 2 in water. This solubility is reviewed below. Carbon dioxide solubility increases with increasing carbon dioxide partial pressure [START_REF] Portier | Modelling CO 2 solubility in pure water and NaCl-type waters from 0 to 300 °C and from 1 to 300 bar. Application to the Utsira Formation at Sleipner[END_REF][START_REF] Zhang | Review of integrity of existing wells in relation to CO 2 geological storage: What do we know?[END_REF], and decreases as the salinity of the formation fluid increases. The latter is called the salting-out effect [START_REF] Gunter | Aquifer disposal of CO 2 -rich gases: Reaction design for added capacity[END_REF]. Once dissolved, CO 2 will be expected to remain in the aqueous phase unless a significant pressure drop occurs, for example if the fluid moves upward towards the Earth's surface. Similarly, as CO 2 solubility decreases with increasing temperature to at least 100°C, it could be released from the fluid phase if the fluid is substantially heated. As CO 2 enriched fluid is denser than the original water itself, its dissolution into water can trigger convective cells where CO 2 enriched fluid sinks and fresh water lifts [START_REF] House | Permanent carbon dioxide storage in deep-sea sediments[END_REF]. This phenomenon can also enhance the storage capacity of a reservoir given that, as the CO 2 enriched fluid sinks, it reaches parts of the reservoir that would otherwise never been reached via CO 2 injection. Solubility trapping can be an effective storage process in the field. For example, through the application of noble gas geochemistry, Zhou et al. [START_REF] Zhou | Identifying and quantifying natural CO 2 sequestration processes over geological timescales: The Jackson Dome CO 2 Deposit, USA[END_REF] concluded that 75% of the CO 2 originally present in the at the Jackson Dome structure dissolved into groundwater over 60 million years.

Mineral trapping occurs as the result of the interaction of injected CO 2 with minerals present in the storage reservoir. Divalent metals liberated from solid phases present in the host rock formation can combine with the injected CO 2 to form stable carbonate minerals, such as calcite [START_REF] Seifritz | CO 2 disposal by means of silicates[END_REF]31]. Calcite, once formed in the Earth's crust, is the most secure form of geologic storage [START_REF] Lackner | Carbon dioxide disposal in carbonate minerals[END_REF][START_REF] Lackner | A guide to CO 2 sequestration[END_REF][START_REF] Sipilä | Carbon dioxide sequestration by mineral carbonation Literature review update 2005-2007[END_REF].

The average residence time of carbonate minerals in the crust is ~200 million years or more [START_REF] Berner | The Phanerozoic Carbon Cycle: CO 2 and O 2[END_REF]. Large bodies of calcite, commonly in the form of limestone, can be observed throughout the world; some examples are shown in Figure 2. In total, there are approximately 64,000,000 Gt of carbon present in carbonate minerals in the Earth's crust [START_REF] Hunt | Distribution of Carbon in Crust of Earth[END_REF][START_REF] Falkowski | The global carbon cycle: A test of our knowledge of earth as a system[END_REF]. This compares with ~870 Gt of carbon (or 410 ppm CO 2 ) presently in the Earth's atmosphere [START_REF] Tans | Trends in Atmospheric Carbon Dioxide: Data from Mauna Loa observatory[END_REF] (using 1 ppm = 2.124 GtC as proposed by Ballantyne et al. [START_REF] Ballantyne | Increase in observed net carbon dioxide uptake by land and oceans during the past 50 years[END_REF]) . Natural processes such as chemical weathering have efficiently transferred atmospheric CO 2 into carbonate rocks over geologic times. For example, the rate of this transfer into the oceanic crust is approximately 0.1 Gt CO 2 /year [START_REF] Alt | The uptake of carbon during alteration of ocean crust[END_REF][START_REF] Coogan | Evidence that low-temperature oceanic hydrothermal systems play an important role in the silicate-carbonate weathering cycle and long-term climate regulation[END_REF][START_REF] Staudigel | Cretaceous ocean crust at DSDP Sites 417 and 418: Carbon uptake from weathering versus loss by magmatic outgassing[END_REF]. Reproduced with permission from [START_REF] Evans | A Poroelastic Model of Serpentinization: Exploring the Interplay Between Rheology, Surface Energy, Reaction, and Fluid Flow[END_REF].

A representative chemical reaction forming calcite in the subsurface can be written as follows:

(a) (b) (c) CaAl 2 Si 2 O 8 + CO 2 (g) + 2H 2 O = CaCO 3 + Al 2 Si 2 O 5 (OH) 4 (1) (Anorthite) (Water) (Calcite) (Kaolinite)
where the anorthite component of plagioclase reacts with injected CO 2 and water to form the carbonate mineral calcite and the clay mineral kaolinite. This reaction is chemically spontaneous; it liberates 15.15 kcal/mole of energy at 25°C and a CO 2 partial pressure of 10 bars in the standard state [START_REF] Johnson | SUPCRT92: A software package for calculating the standard molal thermodynamic properties of minerals, gases, aqueous species, and reactions from 1 to 5000 bar and 0 to 1000°C[END_REF]. The fact that this and similar reactions are chemically spontaneous does not mean they are rapid. The rates of such reactions are generally slow at ambient temperatures, and it can take tens to hundreds of years to carbonate the injected CO 2 .

A plot often cited to summarize the trapping mechanisms (Figure 1), originally from Benson et al. [START_REF] Benson | Underground geological storage[END_REF], suggests that as time passes, the bulk of the injected CO 2 is stored, first by structural, then residual, then solubility, and eventually by mineral trapping. As this sequence is followed, the security of the storage is enhanced. Although there is a qualitative timescale in this figure, this is misleading as the time required for residual, solubility, and mineral trapping can vary dramatically depending on the geologic system and the selected method of injection. For example, CO 2 can be dissolved into an aqueous phase before or during its injection into the subsurface leading to essentially instantaneous solubility trapping [START_REF] Sigfusson | Solving the carbon-dioxide buoyancy challenge: The design and field testing of a dissolved CO 2 injection system[END_REF][START_REF] Gunnarsson | The rapid and cost-effective capture and subsurface mineral storage of carbon and sulfur at the CarbFix2 site[END_REF].

In contrast, in many geologic systems little to no mineral trapping may occur. Mineral trapping requires the availability of divalent cations present in silicate minerals, notably Ca, Mg, and Fe that can combine with the injected CO 2 to form stable carbonate minerals, such as represented in reaction [START_REF] Oelkers | Carbon dioxide sequestration: A solution to a global problem[END_REF]. Divalent metal-bearing silicates are rare in sandstones and limestones, limiting greatly mineral trapping in such systems [START_REF] Han | Evaluation of trapping mechanisms in geologic CO 2 sequestration: case study of SACROC notrhern platform, a 35-years CO 2 injection site[END_REF][START_REF] Gunter | Aquifer disposal of CO 2 -rich greenhouse gases: Extension of the time scale of experiment for CO 2 -sequestering reactions by geochemical modelling[END_REF][START_REF] Wilkinson | CO 2 -mineral reaction in a natural analogue for CO 2 storage -Implications for modeling[END_REF][START_REF] Moore | Mineralogical and geochemical consequences of the longterm presence of CO 2 in natural reservoirs: An example from the Springerville-St. Johns Field, Arizona, and New Mexico[END_REF]. For example, Gilfillan et al. [START_REF] Kelemen | In situ carbonation of peridotite for CO 2 storage[END_REF] investigated the mechanisms of carbon storage in nine natural gas fields in sedimentary host rocks located in North America, China and Europe, and found no evidence of mineral trapping in seven of them. In the two remaining gas fields, they concluded that no more than 18% of the original CO 2 in the reservoir was trapped through the formation of carbonate minerals. Similarly, Heinemann et al. [START_REF] Gislason | Carbon storage in basalt[END_REF] concluded that no more than 11% of the CO 2 in the Fizzy discovery of the southern North Sea was trapped in carbonate minerals over ~50 Myr of CO 2 -water-rock interaction.

The reason why carbon mineralization within sedimentary rocks during geologic storage is limited is that these rocks are formed by the weathering of primary rocks. The process of forming sedimentary rocks is very efficient at dissolving divalent metal-bearing silicates and precipitating carbonate minerals during diagenesis; over 90% of the calcium in sedimentary rocks is present within carbonate or evaporite minerals. Such processes leave little remaining input material for the formation of stable carbonate minerals during geologic storage efforts. In contrast, mineral carbon storage can be promoted and accelerated by the injection of CO 2 into reactive igneous rocks, such as basalts or ultramafic rocks [START_REF] Kelemen | In situ carbonation of peridotite for CO 2 storage[END_REF][START_REF] Gislason | Carbon storage in basalt[END_REF][START_REF]Negative Emissions Technologies and Reliable Sequestration: a research agenda[END_REF][START_REF] Snaebjörnsdóttir | Carbon dioxide storage through mineral carbonation[END_REF]. Notably, more than 90% of the CO 2 injected into subsurface fresh basalts at a temperature of ~35°C near the Hellisheiði power plant in Iceland was found to be mineralized as calcite within two years of its injection (see below and [START_REF] Snaebjörnsdóttir | The chemistry and saturation states of subsurface fluids during the in situ mineralisation of CO 2 and H 2 S at the CarbFix site in SW-Iceland[END_REF][START_REF] Matter | Rapid carbon mineralization for permanent disposal of anthropogenic carbon dioxide emissions[END_REF][START_REF] Snaebjörnsdóttir | The geology and hydrology of the CarbFix2 site, SW-Iceland[END_REF]). The basis for understanding the extent and rate of the various geologic carbon storage mechanisms lies in the thermodynamics and kinetics of the CO 2 and carbonate systems as reviewed below.

THERMODYNAMIC CONSIDERATIONS

The CO 2 System

Geologic carbon storage involves the injection of CO 2 into pore space in the subsurface. The properties of this injected CO 2 depend strongly on the temperature and pressure of this phase as illustrated in Figure 3. The critical point of CO 2 is located at a temperature of 31.1°C and a pressure of 73.9 bars. At this critical pressure and below the critical temperature CO 2 is in a liquid form. At the critical temperature but below the critical pressures, CO 2 is a gas phase. Beyond the critical point, carbon dioxide behaves as a supercritical fluid. At such conditions the density of CO 2 is far greater than at lower pressures, such that it will occupy less pore space, and be somewhat less buoyant than it would be in the gaseous state. The density of CO 2 is illustrated as a function of pressure at various temperatures in Figure 4. The density increases dramatically as the phase changes from gas to liquid but decreases substantially with increasing temperature. The most efficient conditions for carbon storage in the subsurface are when the density is highest as the injected carbon dioxide will occupy the least volume. Such conditions are found at lower temperatures and pressures just above the critical point. As such, these are the common conditions sought for conventional geologic storage.

The densities of CO 2 can be compared with corresponding densities of pure water in Figure 4. The density of CO 2 is less than that of water at most near surface conditions. The only exception is at low temperatures and elevated pressures (e.g., at pressures > 180 bars in pure water at ~ 0°C). For this reason, a number of past studies suggested the storage of carbon dioxide at the bottom of the ocean, where its relatively high density might lead to its trapping. Such suggestions have been widely discarded due to the potential for environmental damage and the rapid mixing time of CO 2 in the oceans, which would lead to both ocean acidification and eventually the leakage of CO 2 back to the atmosphere [57].

The CO 2 -H 2 O -NaCl System

Once in the subsurface, CO 2 will dissolve into its adjacent aqueous phase. The extent of this dissolution is largely governed by its solubility. A detailed summary of the solubility and density of CO 2 saturated water and aqueous brines is provided by Yan et al. [START_REF] Yan | Measurement and modeling of CO 2 solubility in NaCl brine and CO 2 -saturated NaCl brine density[END_REF]. Data on the CO 2 solubility in aqueous solutions have been fit by Duan and Sun [START_REF] Duan | An improved model calculating CO 2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar[END_REF] and Duan et al. [START_REF] Duan | An improved model for the calculation of CO 2 solubility in aqueous solutions containing Na + , K + , Ca 2+ , Mg 2+ , Cl -, and SO4 2[END_REF]. These latter publications provided a suite of equations allowing the calculation of CO 2 solubility as a function of temperature, pressure, and salinity of the aqueous phase. The solubility of pure CO 2 into pure water is a function of pressure and temperature, as shown in Figure 5a. The solubility tends to increase non-linerarly with increasing CO 2 pressure due to non-ideal effects, notably near the critical point and the liquidvapor equilibrium curve for this phase. Moreover, the solubility of CO 2 in pure water decreases substantially with increasing temperature from 25 to 100°C. For example, at a pressure of 20 bars the CO 2 solubility decreases by a factor of 3 with increasing temperature over this range. Also, note

that at pressures above ~80 bar the solubility of CO 2 begins to increase with increasing temperature above 100°C leading to a CO 2 solubility minumum as a function of temperature, at constant pressure [START_REF] Duan | An improved model calculating CO 2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar[END_REF].

The pH of CO 2 saturated pure water is illustrated as a function of pressure at selected temperatures in Figure 5b. The pH of this water tends to range from 3 to 4 at CO 2 pressures >15 bars. This is due to the dissociation of carbonic acid (H 2 CO 3 ) formed once CO 2 dissolves into the aqueous phase according to:

CO 2 + H 2 O = H 2 CO 3 (2)
Carbonic acid can dissociate in the aqueous phase to the bicarbonate (HCO 3 -) and carbonate (CO 3 -2

) ions liberating protons to solution according to:

H 2 CO 3 = H + + HCO 3 - ( 3
)
and

HCO 3 -= H + + CO 3 -2 (4)
The protons liberated by these reactions leads CO 2 -rich aqueous solutions to be acidic and to promote the reactivity of minerals (see below). The formation of the carbonate and bicarbonate ions in aqueous solution also stabilizes the presence of CO 2 in the aqueous phase as fluid pH is increased, as shown in Figure 6. The solubility of CO 2 (g) increases substantially at pH>6 due to the dissociation of aqueous carbonic acid. This result indicates that the stability of CO 2 (g) in the aqueous state increases greatly as the pH of the fluid phase increases without otherwise increasing the total inorganic carbon concentration. For example, the dissolution of many mafic minerals, such as olivine, will increase fluid pH while not adding additional dissolved inorganic carbon to the fluid. Such a process will either stabilize the dissolved CO 2 in the coexisting fluid phase, or lead to increase CO 2 dissolution into the aqueous phase if a free CO 2 gas phase is present in the system. The solubility of CO 2 in water and (b) the pH of this CO 2 -saturated water at selected temperatures. These calculations were performed using PHREEQC [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with its carbfix.dat database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2 [START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF]. These calculations were performed using PHREEQC [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with its carbfix.dat database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2 [START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF].

The solubility of CO 2 in an aqueous phase is also greatly affected by the salinity of the fluid. A comparison of the CO 2 solubilities in pure water, in a 0.6 M NaCl solution (close to that of seawater), and in a 5 M NaCl solution (close to that of a halite saturated brine) is shown in Figure 7. The presence of a seawater-like salinity lowers the solubility of CO 2 by ~12% compared to that of freshwater at the same pressure and temperature. This process is referred to as a salting out effect [START_REF] Gunter | Aquifer disposal of CO 2 -rich greenhouse gases: Extension of the time scale of experiment for CO 2 -sequestering reactions by geochemical modelling[END_REF]. The further increasing of water salinity further decreases the solubility of CO 2 in the aqueous phase; the presence of a 5 M NaCl solution is computed to decrease the solubility of CO 2 by ~45 to 55% compared to that of freshwater at the same pressure and temperature. As such, it should be anticipated that solubility trapping is significantly less efficient in very saline formation fluids such as might be expected to be present in evaporite rocks. The yellow, orange and purple curves represent the calculated solubility at a water salinity of 0, 0.6, and 5 mol/kg, respectively. These calculations were performed using PHREEQC [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with the carbfix.dat database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2 [START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF].

Note that the solubility storage of CO 2 requires large volumes of water. Shamshiri and Jafarpour [START_REF] Shamshiri | Controlled CO 2 injection into heterogeneous geologic formations for improved solubility and residual trapping[END_REF] concluded that at typical cold deep-aquifer conditions of 100 bars of CO 2 pressure, 35°C temperature, and 10% salt mass fraction, the solubility of CO 2 in brine is ∼40 kg per cubic meter of brine, amounting to an average storage capacity of ~4 kg CO 2 m -3 in a brine-saturated rock layer with 10% porosity. At such conditions, it would take 250 km 3 of this rock to store one Gt of CO 2 via solubility trapping.

One advantage of solubility trapping is that the density of CO 2 -charged water is somewhat higher than that of CO 2 -free water at identical temperature and water salinity. The density of water and saline brines are illustrated as a function of CO 2 pressure at 50, 100 and 140°C in Figure 8. It can be seen in the figure that the increase of CO 2 pressure and thus the concentration of CO 2 in the aqueous phase causes the density of the aqueous phase to increase from 1.5 to 3% with increasing CO 2 pressure from 0 to 400 bars. Note that this density increase is less than the corresponding density difference between pure water and a concentrated NaCl brine at corresponding temperature and CO 2 pressures. The density of an aqueous 1.0 mol/kg NaCl solution tends to be ~3% greater than freshwater, whereas the density of an aqueous 5.0 mol/kg NaCl solution tends to be ~15% greater than freshwater. Despite the relatively strong effects of NaCl on brine density, it seems reasonable to expect that a CO 2 -rich aqueous fluid generated at the bottom of a CO 2 -water interface beneath a structural trap will tend to sink due to its increased density compared to a CO 2 -free brine of similar salinity. well seals. As pressure decreases, so too does the solubility of CO 2 in the aqueous phase as shown in figure 7. The released CO 2 gas phase is highly buoyant and has a strong tendency to escape back to the atmosphere. In the extreme case, where CO 2-charged water percolates to the surface, the dissolved CO 2 is rapidly released into the atmosphere. If such waters dissolved calcite while in the subsurface this calcite could precipitate in accord with the reaction:

Ca 2+ + 2HCO 3 -= CO 2 (g) + CaCO 3 (calcite) +H 2 O (5)
Such reactions are common at the Earth surface and the process is responsible for the formation of travertine deposits, such as shown in figure 2b.

The CO 2 -H 2 O -MeCO 3 System

Carbon-dioxide/carbonate mineral interaction is somewhat counterintuitive. The increase in CO 2 (g) pressure into an aqueous system leads to the dissolution of calcite consistent with the reverse of reaction (5). The solubility of calcite in the system CO 2 -H 2 O-CaCO 3 is shown as a function of CO 2 (g) pressure in Figure 9a. The increase in CO 2 (g) pressure from 4 to 150 bars increases the solubility of calcite from 2 to 5.39x10 -2 mol/kg H 2 O at 25°C, and from 0.6 to 2x10 -2 mol/kg H 2 O at 100°C. This large increase in solubility highlights one of the most dramatic consequences of the injection of CO 2 into subsurface rocks: the large drive to dissolve calcite and other carbonate minerals, if present near the injection well. The dissolution of such carbonate minerals will at the same time increase the pH of a CO 2 -rich fluid phase. The pH of pure water saturated with CO 2 at 25°C and 1 bar of pressure is 3.4, and at 100 bars of pressure is 2.9 (see Figure 5b). As these fluids are equilibrated with calcite, their pH increases to 6.04 and 4.9, respectively (see Figure 9b). This increase in fluid pH will have the tendency to slow substantially the dissolution rates of many other minerals present in the system because rates tend to decrease substantially with increasing pH (see below). respectively. These calculations were performed using PHREEQC [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with its carbfix.dat database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2 [START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF].

KINETIC CONSIDERATIONS

Rates of CO 2 Dissolution into Water

The rates of CO 2 dissolution into water at the CO 2 -water interface are sufficiently fast, so that they are controlled by the rates of transport of the dissolved carbon in the aqueous phase [START_REF] Karimaie | Experimental Verification of CO 2 Dissolution Rate Due to Diffusion Induced Convection[END_REF]. As such, the rate of carbon dioxide dissolution in stagnant water is controlled by the diffusion of dissolved aqueous CO 2 away from the water-pure CO 2 interface. A detailed review of this dissolution process, as well as the consequences for fluid flow are reviewed in detail by Iglauer [START_REF] Iglauer | Dissolution Trapping of Carbon Dioxide in Reservoir Formation Brine -A Carbon Storage Mechanism[END_REF].

The dissolution of CO 2 into water can provoke water convection accelerating the relatively slow aqueous dissolution process. The injection of pure CO 2 into geologic formations tends to form pools of CO 2 -rich gas phases above the water column trapped by impermeable caprocks. This geometry results from the relatively low density of pure CO 2 compared to water and saline brines at corresponding temperature and pressure conditions (see Figure 4). The migration of CO 2 into the reservoir and the filling of storage traps will dissolve some CO 2 into the water or saline brine adjacent to the CO 2 -rich reservoir. This CO 2 -rich aqueous fluid is approximately 1% denser than the CO 2 -poor reservoir fluid (Figure 8) [START_REF] Ennis-King | Rate of dissolution due to convective mixing in the underground storage of carbon dioxide[END_REF][START_REF] García | Density of Aqueous Solutions of CO[END_REF], and an instability will arise with a denser fluid located above a less dense formation fluid, provoking both the downward movement of water, and the formation of fluid convection cells [START_REF] House | Permanent carbon dioxide storage in deep-sea sediments[END_REF][START_REF] Kneafsey | Laboratory Flow Experiments for Visualizing Carbon Dioxide-Induced, Density-Driven Brine Convection[END_REF][START_REF] Emami-Meybodi | Convective dissolution of CO 2 in saline aquifers: Progress in modeling and experiments[END_REF][START_REF] Sainz-Garcia | Convective mixing fingers and chemistry interaction in carbon storage[END_REF]. Such convection accelerates the dissolution of CO 2 into the aqueous phase, and promotes the movement of the dissolved CO 2 away from the CO 2 -rich gas reservoir, thereby enhancing the storage capacity of the reservoir. Field evidence of such processes have been reported by Sathaye et al. [START_REF] Sathaye | Constraints on the magnitude and rate of CO 2 dissolution at Bravo Dome natural gas field[END_REF].

The dissolution of CO 2 into water can be greatly accelerated before or as the CO 2 is being injected by considering that this process is limited by the CO 2 -water interfacial surface area and transport in the water phase. Taking account of these factors, Gunnarsson et al. [START_REF] Gunnarsson | The rapid and cost-effective capture and subsurface mineral storage of carbon and sulfur at the CarbFix2 site[END_REF] designed and applied a scrubbing tower for the removal of CO 2 directly from exhaust gas streams. In their design, a fine spray of water was showered over an up flowing exhaust gas mixture at a pressure of 6 bars, in a 12.5 m high scrubbing tower. The scrubbing tower is filled with plastic pellets to provide a tortuous pathway that enhances water-gas mixing. The resulting CO 2 -charged water is injected into the subsurface without depressurization to insure the gas does not exsolve before entering the subsurface storage reservoir. Similarly, CO 2 can be dissolved in water as it is injected into the storage reservoir. For example, Sigfusson et al. [START_REF] Sigfusson | Solving the carbon-dioxide buoyancy challenge: The design and field testing of a dissolved CO 2 injection system[END_REF] designed and applied a system to dissolve CO 2 during its injection into the subsurface. In this system, CO 2 and sufficient water required to dissolve the CO 2 were co-injected to a depth of ~330 m, where the CO 2 was added to the down flowing water as small bubbles. An additional rotating static mixer was added below the CO 2 gas bubble outlet. The combination of the small CO 2 bubbles, the down flowing water, and the mixing resulted in the complete dissolution of the CO 2 into the injected water phase in less than 5 minutes, before the CO 2charged water entered the target reservoir rock formation at a depth of 550 m. Alternatively, once injected into an aquifer, dissolution of a pure carbon dioxide phase can be accelerated by injecting water on top of the CO 2 [START_REF] Hassanzadeh | Accelerating CO 2 dissolution in saline aquifers for geological storage -Mechanistic and sensitivity studies[END_REF] or by alternating CO 2 and water injections [START_REF] Baz | A field-scale investigation of residual and dissolution trapping of CO 2 in a saline formation in Western Australia[END_REF][START_REF] Vo Thanh | Robust optimization of CO 2 sequestration through a water alternating gas process under geological uncertainties in Cuu Long Basin, Vietnam[END_REF].

Rates of Mineral Dissolution Reactions with CO 2 -Charged Water

The important role of carbonate mineral-CO 2 -H 2 O interaction during subsurface carbon storage stems largely from the high reactivity of the carbonate minerals. A summary of the 25°C dissolution rates of various minerals normalized to the rates of Ca, Mg or Si release are depicted as a function of fluid pH in Figure 10. The rates of carbonate mineral dissolution are relatively fast compared to the rock forming silicate minerals. Notably, the carbonate minerals calcite and dolomite have surface area normalized dissolution rates 4 to 8 orders of magnitude faster than those of the common silicate minerals, for example quartz, feldspar and clay minerals. These differences highlight the dominance of carbonate-fluid interaction as CO 2 is injected into a reservoir. Whereas such fluids may attain equilibrium with carbonate minerals such as calcite over the course of the first few days after injection, equilibration of this fluid with silicate minerals might be expected to take tens to hundreds of years. Note also the relatively rapid dissolution rates of the evaporite minerals anhydrite and gypsum. The surface area normalized dissolution rates of these minerals are even faster than those of calcite. As such, these minerals will be expected to equilibrate rapidly with their coexisting fluids if present in the target subsurface reservoir rock formation (cf. [START_REF] Yu | An experimental study of gypsum dissolution coupled to CaCO 3 precipitation and its application to carbon storage[END_REF]).

The relatively rapid rates of carbonate mineral dissolution have been observed in a number of field sites. Notably, Kharaka et al. [START_REF] Kharaka | Gas-water-rock interactions in Frio Formation following CO 2 injection: Implications for the storage of greenhouse gases in sedimentary basins[END_REF] reported that the rapid dissolution of carbonate and iron hydroxide minerals rapidly buffered the reservoir fluids in the Frio formation after the injection of 1600 tons of CO 2 into a 24 m thick sandstone at a depth of 1500 m. Similarly, Assayag et al. [START_REF] Assayag | Water-rock interactions during a CO 2 injection field-test: Implications on host rock dissolution and alteration effects[END_REF] observed the relatively fast dissolution of carbonate minerals compared to basic silicate minerals following the injection of CO 2 -charged water into the Palisades sill. In this latter study, substantial carbonate dissolution was observed within 3 weeks of the injection of carbon dioxide-charged water.

Figure 10. Summary of the BET surface area normalized far-from equilibrium dissolution rates of selected rock forming minerals at 25°C, normalized to the release rates of Ca, Mg, and Si. Curves depicted in these plots were generated using equations and parameters from [START_REF] Chou | Comparative study of the kinetics and mechanisms of dissolution of carbonate minerals[END_REF][START_REF] Oelkers | The mechanism, rates and consequences of basaltic glass dissolution: I. An experimental study of the dissolution rates of basaltic glass as a function of aqueous Al, Si and oxalic acid concentration at 25°C and pH 3 and 11[END_REF][START_REF] Critelli | Dissolution rates of actinolite and chlorite from a wholerock experimental study of metabasalt dissolution from 2≤pH≤12 at 25°C[END_REF][START_REF] Brantley | Kinetics of Mineral Dissolution[END_REF][START_REF] Gudbrandsson | An experimental study of crystalline basalt dissolution from 2≤pH≤11 and temperatures from 5 to 75°C[END_REF][START_REF] Busenberg | A comparative study of the dissolution and crystal growth of calcite and aragonite[END_REF][START_REF] Palandri | A compilation of rate parameters of water-mineral interaction kinetics for application to geochemical modeling[END_REF][START_REF] Rimstidt | Systematic review of forsterite dissolution rate data[END_REF][START_REF] Chou | Steady-state kinetics and dissolution mechanisms of albite[END_REF][START_REF] Brantley | Chemical weathering rates of pyroxenes and amphiboles[END_REF][START_REF] Golubev | Experimental determination of the effect of dissolved CO 2 on the dissolution kinetics of Mg and Ca silicates at 25 °C[END_REF][START_REF] Bales | Dissolution kinetics of chrysotile at pH 7 to 10[END_REF] and summarized by Heřmanská et al. [START_REF] Heřmanská | An Updated Kinetic Database For Mineral Dissolution-part I[END_REF].

Mineral Precipitation Rates

In contrast to the dissolution rates of the major rock forming minerals, the precipitation rates of these minerals are far less well quantified [START_REF] Schott | The link between mineral dissolution/precipitation kinetics and solution chemistry[END_REF][START_REF] Schott | Can accurate kinetic laws be created to describe chemical weathering?[END_REF]. Many of the primary silicate minerals such as quartz, feldspars, micas, pyroxenes, and olivine have not been observed to precipitate at ambient temperatures, and most clay minerals precipitate only sparingly over human timescales [START_REF] Yang | Kaolinite dissolution and precipitation kinetics at 22 °C and pH 4[END_REF]. As clay mineral formation tends to lower the permeability of porous rocks in the subsurface, their formation may be a limiting factor in subsurface carbon storage over the long term. In contrast, the precipitation of simple hydrous and amorphous phases tends to be favored and relatively rapid compared to most crystalline silicate minerals at ambient temperatures [START_REF] Carroll | Amorphous silica precipitation (60 to 120°C): Comparison of laboratory and field rates[END_REF][START_REF] Bénézeth | Dissolution/precipitation kinetics of boehmite and gibbsite: Application of a pH-relaxation technique to study near-equilibrium rates[END_REF][START_REF] Gautier | Hydromagnesite solubility product and growth kinetics in aqueous solution from 25 to 75°C[END_REF][START_REF] Harrison | Solubility of the hydrated Mg-carbonates nesquehonite and dypingite from 5 to 35°C: Implications for CO 2 storage and the relative stability of Mg-carbonates[END_REF]. What apparently limits the precipitation rates of many primary silicate minerals at relatively low temperatures is the lack of active sites for precipitation at the mineral surface. Mineral precipitation consists of two distinct processes, nucleation and growth. Mineral growth tends to reduces the available active sites for growth on mineral surfaces, requiring further growth site nucleation for continued precipitation [START_REF] Schott | The link between mineral dissolution/precipitation kinetics and solution chemistry[END_REF][START_REF] Berninger | Assessing dolomite surface reactivity at temperatures from 40 to 120 °C by hydrothermal atomic force microscopy[END_REF].

In contrast to the sluggish precipitation rates of major silicate minerals, numerous carbonate minerals are observed to readily precipitate at temperatures less than 100°C. Although the experimental data for calcite precipitation rates are largely scattered [START_REF] Wolthers | Calcite growth kinetics: Modeling the effect of solution stoichiometry[END_REF], calcite is observed to rapidly precipitate in natural Earth surface systems from supersaturated solutions (cf. Figure 2). The degree to which other carbonate minerals form in subsurface systems appears to depend on the temperature of the system. Dissolved magnesium precipitates as the carbonate magnesite (MgCO 3 ) and dolomite (CaMg(CO 3 ) 2 ) at temperatures above ~65°C [START_REF] Saldi | Magnesite growth rates as a function of temperature and saturation state[END_REF][START_REF] Johnson | Olivine dissolution and carbonation under conditions relevant for in situ carbon storage[END_REF][START_REF] Gadikota | Chemical and morphological changes during olivine carbonation for CO 2 storage in the presence of NaCl and NaHCO 3[END_REF]. There is some evidence that water-saturated supercritical CO 2 and carboxylated polystyrene microspheres can promote magnesite precipitation at temperatures as low as 22°C [START_REF] Felmy | Reaction of water-saturated supercritical CO 2 with forsterite: Evidence for magnesite formation at low temperatures[END_REF][START_REF] Power | Room Temperature Magnesite Precipitation[END_REF]. Nevertheless, at lower temperatures the precipitation of dolomite and magnesite appear to be kinetically inhibited. At such conditions, less stable hydrous Mg-carbonate minerals, such as hydromagnesite, dypinite and nesquehonite could form [START_REF] Turvey | Hydrotalcites and hydrated Mg-carbonates as carbon sinks in serpentinite mineral wastes from the Woodsreef chrysotile mine, New South Wales, Australia: Controls on carbonate mineralogy and efficiency of CO 2 air capture in mine tailings[END_REF]. In addition, dissolved magnesium is also readily incorporated into clay minerals limiting its availability to promote carbonation (e.g., [START_REF] Rigopoulos | Carbon sequestration via enhanced weathering of peridotites and basalts in seawater[END_REF]). As Mg-bearing clay minerals are relatively slow to precipitate, their role in potentially limiting mineral carbonation may not be evident in short-term laboratory and field experiments. The degree to which Fe combines with dissolved carbonate to form substantial carbonates during carbonation efforts remains unclear.

In oxic conditions, Fe 2+ oxidizes prior to its potential incorporation as a divalent metal carbonate, and the mineral siderite (FeCO 3 ) is only rarely observed in modern sedimentary and basaltic rocks [START_REF] Rogers | CO 2 metasomatism in a basalt-hosted petroleum reservoir, Nuussuaq, West Greenland[END_REF].

The carbonate mineral ankerite ((Mg,Fe,Ca)CO 3 ), however, may be favored in conditions at ambient to moderate temperatures [START_REF] Gysi | CO 2 -water-basalt interaction. Low temperature experiments and implications for CO 2 sequestration into basalts[END_REF][START_REF] Mcgrail | Wallula Basalt Pilot Demonstration Project: Postinjection Results and Conclusions[END_REF] . Both dawsonite (NaAl(CO 3 )(OH)) and ankerite have been observed in sedimentary formations at high CO 2 pressures and temperatures >60°C [START_REF] Zhou | Dawsonite formation in the beier sag, hailar basin, NE China tuff: A natural analog for mineral carbon storage[END_REF][START_REF] Yu | Dawsonite and ankerite formation in the LDX-1 structure, Yinggehai basin, South China sea: An analogy for carbon mineralization in subsurface sandstone aquifers[END_REF].

The thermodynamics and kinetics summarized above indicate that CO 2 will rapidly be dissolved in water at the CO 2 -water interface, and, once dissolved, this acidic CO 2 -charged water will promote its reactions with subsurface minerals. Of these minerals, the reactions among CO 2 -charged water with carbonate minerals will be among the most significant due to: 1) their relatively rapid dissolution rates compared to silicate minerals, and 2) because the precipitation of carbonation minerals leads to the safe long-term storage of the injected CO 2 . The extent and consequences of such reactions are considered in detail below.

Despite our extensive understanding of the physical properties and reactivity of carbonate minerals, the accurate prediction of the mineral reactions in carbonate mineral bearing reservoirs remains a challenge [START_REF] Siqueira | Carbon dioxide injection in carbonate reservoirs -a review of CO 2 -water-rock interaction studies[END_REF]. While the effects of temperature and the fluid composition have been quantified [START_REF] Pokrovsky | Calcite, dolomite and magnesite dissolution kinetics in aqueous solutions at acid to circumneutral pH, 25 to 150 °C and 1 to 55 atm pCO 2 : New constraints on CO 2 sequestration in sedimentary basins[END_REF], factors including porosity homogeneity and the role of fluid flow paths are more difficult to measure directly. Nevertheless, some generalities are evident. Luquot and Gouze [START_REF] Luquot | Experimental determination of porosity and permeability changes induced by injection of CO 2 into carbonate rocks[END_REF] reported the fluid composition of along the flow path of the CO 2 -charged fluids in limestone cores. Close to the injection point, fluids are largely undersaturated with respect to calcite, pCO 2 is high and fluid pH is low, triggering rapid and extensive dissolution of calcite [START_REF] André | Numerical modeling of fluid-rock chemical interactions at the supercritical CO 2 -liquid interface during CO 2 injection into a carbonate reservoir, the Dogger aquifer (Paris Basin, France)[END_REF]. As the fluids move away from the injection point, the fluid pH rapidly rises and the fluid reaches equilibrium with calcite. Further from the injection point, the fluid pH is buffered. At this point the fluids may become supersaturated with carbonate minerals that tend to precipitate. The small size of cores used in laboratory experiments compared to the scale of subsurface CO 2 storage sites, however, limits their direct application to assess the evolution of industrial scale geologic storage efforts. Most experimental results suggest an increase in porosity and permeability close to the injection point, driven by abundant carbonates dissolution. In contrast, some field data suggest injectivity loss due to CO 2 injection into the subsurface [START_REF] Cailly | Geological Storage of CO 2 : A State-of-the-Art of Injection Processes and Technologies[END_REF][START_REF] Svec | Physical Effects of WAG Fluids on Carbonate Core Plugs[END_REF]. In such systems re-precipitation of carbonates several meters downstream from injection wells could still adversely affect injectivity [START_REF] Bacci | An experimental and numerical investigation into the impact of dissolution/precipitation mechanisms on CO 2 injectivity in the wellbore and far field regions[END_REF].

KINETIC MODELING

The impact of the rapid dissolution and precipitation of the carbonate minerals in potential carbon dioxide geologic storage formations can be illustrated using reaction path modeling. To this end a set of kinetic geochemical models was run using the PHREEQC software package (v3) [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with the carbfix.dat (v1.1.0) thermodynamic database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF], and the kinetic database from Heřmanská et al. [START_REF] Heřmanská | An Updated Kinetic Database For Mineral Dissolution-part I[END_REF]. These models consider the interaction among an injected CO 2 -rich water and a host rock as a function of time, rock composition, and surface area. The initial conditions common to all calculations are listed in Table 1. Two types of rocks are considered in these calculations, a crystalline basalt (CB) and a sandstone. These were chosen as such rocks are representative of potential geologic storage systems [START_REF] Aradóttir | Multidimensional reactive transport modeling of CO 2 mineral sequestration in basalts at the Hellisheidi geothermal field, Iceland[END_REF][START_REF] Chadwick | Geological reservoir characterization of a CO 2 storage site: The Utsira Sand, Sleipner, northern North Sea[END_REF][START_REF] White | Simulation of reactive transport of injected CO 2 on the Colorado Plateau, Utah, USA[END_REF]. The compositions of the modeled rocks are summarized in Table 2. Two types of crystalline basalts were considered. To illustrate the consequences of the presence of calcite in the system, one crystalline basalt contained 5 vol% calcite, and the other was calcite-free. In the case of the sandstone, the plagioclase phase was considered to consist of 2 vol% albite and 1 vol% anorthite (cf. [START_REF] White | Simulation of reactive transport of injected CO 2 on the Colorado Plateau, Utah, USA[END_REF]) .

The mineral-fluid interfacial surface area in the model calculations was determined assuming that the gas-charged aqueous fluid is contained within a planar ~1 mm wide fracture. The surface area of each mineral was assumed to be proportional to its volume fraction. The initial gas-charged fluid composition was calculated in PHREEQC at fixed pressure adding the partial pressure of the CO 2 gas component, and fixing the oxidation-reduction conditions to Fe 2+ /Fe 3+ equilibrium in the basaltic rock.

The calculations were run assuming a CO 2 -saturated aqueous fluid was injected into the formation. Primary minerals in the system other than calcite were allowed to dissolve at the rates prescribed by Heřmanská et al. [START_REF] Heřmanská | An Updated Kinetic Database For Mineral Dissolution-part I[END_REF]. Rate of calcite dissolution, if present in the rock formation, was fixed to be at local equilibrium consistent with its relatively fast reaction rates and field observations. This fast reaction rate provokes the immediate dissolution of calcite at the inlet of the system along its flow paths, as the injected CO 2 -rich injected fluid is strongly undersaturated with respect to calcite. Similar field observations have been reported. For example, Lebedev et al. [START_REF] Lebedev | Carbon geosequestration in limestone: Porescale dissolution and geomechanical weakening[END_REF] reported that the injection of CO 2 -rich aqueous fluids rapidly dissolved calcite along the original flow channels and inject points during core flooding experiments at 50°C. All secondary minerals in the model were allowed to precipitate at local equilibrium (but not to dissolve) in response to the dissolution of primary minerals, and the injection of the gas-charged aqueous fluid. The secondary minerals allowed to precipitate in the crystalline basalt systems include calcite, ankerite, aragonite, and siderite, clay minerals (saponites and beidellites), Fe-oxyhydroxides (magnetite, hematite, goethite, and ilmenite), titanite, zeolites (chabazite and thomsonite), and celadonite; in the sandstone system, carbonates (calcite, ankerite, aragonite, dawsonite, and siderite), clay minerals (beidellites), Feoxyhydroxides (magnetite, goethite, hematite, and ilmenite), titanite, zeolites (chabazite and thomsonite), celadonite, and gibbsite were allowed to precipitate.

The molar volumes listed in the thermodynamic database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] were used to calculate the rock and secondary minerals volume as a function of time. The volume changes in the rock were calculated as a function of distance along the fracture using the quasi-stationary state approximation described by Lichtner [START_REF] Lichtner | The quasi-stationary state approximation to coupled mass transport and fluidrock interaction in a porous medium[END_REF]. The mass transport was coupled to fluid-rock interaction assuming purely advective fluid flow in a Lagrangian frame of reference. The fluid was assumed to flow 1 m/day through a planar ~1 m x 1 mm wide fracture. The fracture volume changes were calculated from the difference between the volume of the dissolved rock, including calcite if present, and the volume of the precipitated reaction products. [START_REF] Aradóttir | Multidimensional reactive transport modeling of CO 2 mineral sequestration in basalts at the Hellisheidi geothermal field, Iceland[END_REF] and the sandstone (modified from [START_REF] Chadwick | Geological reservoir characterization of a CO 2 storage site: The Utsira Sand, Sleipner, northern North Sea[END_REF]; see text) considered as host rocks in the reactive path models. As shown in Figure 11, in all the systems where calcite is present, 2.9 g/kg H 2 O of this calcite dissolves into the aqueous fluid phase such that the fluid attains equilibrium with calcite during the first reaction step. This process adds 0.029 mol/kg H 2 O of dissolved CO 2 to the fluid phase, equivalent to a 5% increase in total dissolved CO 2 . This result is roughly consistent with field observations; Raistrick et al. [START_REF] Raistrick | Using chemical and isotopic data to quantify ionic trapping of injected carbon dioxide in oil field brines[END_REF] reported that no more than 20% of the dissolved CO 2 at the Weyburn EOR site originated from carbonate mineral dissolution. This initial calcite dissolution increases the fluid pH to 5.22. In the calcite-free basaltic system, 47 days are required to attain the same fluid pH value. As carbonate mineral precipitation is expected to begin at a pH approaching neutrality, carbonate started to precipitate immediately in the crystalline basalt system with calcite, whereas calcite precipitation started only after 16 days in the calcite-free basalt system. The presence of calcite in the basaltic system does not change the total mass of the CO 2 mineralized (Figure 12). This observation is related to the kinetic model used in the calculations, where precipitation is assumed to occur at local equilibrium. Such may not always be the case, as shown for dolomite [START_REF] Saldi | An experimental study of magnesite precipitation rates at neutral to alkaline conditions and 100-200°C as a function of pH, aqueous solution composition and chemical affinity[END_REF]. Also, a delayed precipitation of Al-Si-rich products, such as clay minerals, could lead to an increase of aqueous Al 3+ in the aqueous solution, which could slow aluminosilicate mineral dissolution rates [31,[START_REF] Oelkers | The effect of aluminum, pH, and chemical affinity on the rates of aluminosilicate dissolution reactions[END_REF]. This suggests that that carbon mineralization rates could be somehow altered by the presence of calcite in the system in contrast to the model results.

Crystalline basalt

Crystalline basalt with calcite

Sandstone

A major change in carbon mineralization rates is observed as a function of lithology, with sandstone carbonation rates being at least three orders of magnitude slower than that of crystalline basalt (see Figure 12). This result is due to a lack of Ca availability and alkalinity in the sandstone. The results of these calculations suggest that the presence of calcite in a storage reservoir leads to the rapid dissolution of calcite from the rock formation near to the injection well. The total mass of calcite removed is governed largely by the mass of water that passes through the system. The results summarized in Figure 13 suggest an increase of 1% in the volume of the 1 m of the fracture nearest to the injection for every 10 kg of water that passes through the system. Eventually all carbonate minerals will be removed from near the injection point. In cases where carbonate minerals are a minor phase, this can be an advantage as it can open pore channels, and increase injectivity. In cases where the rock contains substantial carbonate minerals this can lead to extensive mechanical weakening of the rocks near the injection point (cf. [START_REF] Lebedev | Carbon geosequestration in limestone: Porescale dissolution and geomechanical weakening[END_REF][START_REF] Khather | Experimental investigation of changes in petrophysical properties during CO 2 injection into dolomite-rich rocks[END_REF]). The Weyburn oil fields are located southeast of Regina in southern Saskatchewan, Canada, within the Williston basin (Figure 14a). Oil is produced from the Mississippian Midale beds, located at 1500m depth (Figure 14b). The reservoir consists in two main producing layers: the upper Midale Marly and the lower Midale Vuggy. These reservoirs are dominated by carbonate minerals [START_REF] Hutcheon | Interactions of CO 2 with formation waters, oil and minerals and CO 2 storage at the Weyburn IEA EOR site, Saskatchewan, Canada[END_REF]. The Marly is a low permeability dolostone with an average porosity of 26%. The Vuggy is a heterogeneous limestone with an average porosity of 15%, and an average permeability of 20 mD. The reservoir caprock seal consists of low permeability evaporites [START_REF] Wilson | IEA GHG Weyburn CO2 monitoring & storage project SUMMARY REPORT 2000-2004[END_REF]. Reproduced with permission from [START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF].

CASE STUDIES

The Weyburn oil fields were discovered in 1954, and initially produced via conventional primary and secondary recovery. In 2000, the EnCana Corporation started a CO 2 EOR scheme for tertiary recovery. There are currently more than 4000 existing wells in the area distributed over the 40x50 km oil field [START_REF] Hawkes | Overview of wellbore integrity research for the IEA GHG Weyburn-Midale CO 2 Monitoring and Storage Project[END_REF][START_REF] Cavanagh | High-resolution simulations of migration pathways and the related potential well risk at the IEAGHG Weyburn-Midale CO 2 storage project[END_REF], which is a typical well density for oil fields of similar age and size [START_REF] Sacuta | International Energy Agency (IEA) Greenhouse Gas (GHG) Weyburn -Midale CO 2 Monitoring and Storage Project[END_REF]. The implementation of CO 2 -based EOR at this site gave birth to an international research effort to study the impact of EOR and monitor the fate of the injected CO 2 [START_REF] Wilson | IEA GHG Weyburn CO2 monitoring & storage project SUMMARY REPORT 2000-2004[END_REF].

The initial research project consisted of two phases: the first, from 2000 to 2004, was aimed at proving that the Weyburn fields could safely store CO 2 , and estimating the reservoir storage capacity. The second phase, from 2005 to 2012, focused on building a set of best practices and recommendations to support the development of similar projects elsewhere. After the end of these formal research projects, the EOR operations were continued and are still running today. The project initially sourced the CO 2 from a gasification plant of synthetic fuels located in Beulah, North Dakota (USA). The captured CO 2 was transported through a 320 km pipeline to Weyburn. Since 2014, the CO 2 has been sourced from Saskpower's Boundary Dam power plant some 100 km southeast from Weyburn.

A detailed study of the chemical evolution of the Weyburn EOR system has been provided by Shevalier et al. [START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF]. In this study, the results of the baseline characterization of the reservoir geochemistry (e.g., prior to CO 2 injection in August 2000), and 16 monitoring campaigns performed (a) (b) over a 10 years period were presented. Shevalier et al. [START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF] focused on the "Phase 1A study area", shown in Figure 14a. The chemical analyses of wellhead gasses and fluids from 40-55 wells were performed during 11 monitoring campaigns between 2000 and 2004 and another five monitoring campaigns from 2005 to 2010. The CO 2 concentration measured in the gases collected from the wells increased progressively as the injected CO 2 plume spread in the subsurface system and reached the production wells. The median concentration of CO 2 in these gases was 4.1 mol% prior to injection, but close to 64 mol% CO 2 by 2010, 10 years after the start of the injection.

The downhole pH of the reservoir fluids was computed using the program SOLMINEQ88 [START_REF] Kharaka | SOLMINEQ.88: A computer program for geochemical modeling of water-rock interactions[END_REF], taking account of the thermodynamic database of Helgeson et al. [START_REF] Helgeson | Theoretical Prediction of the Thermodynamic Properties of Aqueous Electrolytes At High Pressures and Temperatures -3. Equation of State for Aqueous Species At Infinite Dilution[END_REF][START_REF] Helgeson | Thermodynamic behavior of aqueous electrolytes at hight pressure and temperature.pdf[END_REF]. Calculations were favored over the direct measurement of subsurface fluid pH due to the degassing of the fluid phase as the pressure drops during sampling. The median calculated pH of the fluids from the monitoring wells decreased by more than one pH unit (from 6.2 to 4.9) over the ten years of monitoring, mostly due to the acidification of subsurface fluids caused by CO 2 dissolution. Contour maps of the spatial evolution of the subsurface aqueous solution pH as a function of time are provided in Figure 15. These maps show how the acidification started earlier in the southern part of the Phase 1A study area, and progressively expanded. By the end of the monitoring period, the water in all wells experienced acidification. Further details on the location of the wells used for CO2 injection and the timing of the injections is available in [START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF].

Fluid alkalinity evolved significantly during the monitoring period. Prior to the injection, the alkalinity of the well fluids had a median value of ∼400 mg/L. This increased steadily to a median value of ∼2270 mg/L during the first 10 years of injection. Two main mechanisms leading to the increased alkalinity were interpreted to be 1) the dissolution of the injected CO 2 , and 2) the dissolution of carbonates induced by fluid acidification [START_REF] Raistrick | Using chemical and isotopic data to quantify ionic trapping of injected carbon dioxide in oil field brines[END_REF].

The median calcium concentration in the subsurface fluids increased from 1400 mg/L to ~2000 mg/L during the first 4 years following injection, and then remained essentially constant. Such observations suggest that calcite dissolution occurred within the reservoir in response to the dissolution of CO 2 into the fluid phase [START_REF] Emberley | Monitoring of fluid-rock interaction and CO 2 storage through produced fluid sampling at the Weyburn CO 2 -injection enhanced oil recovery site, Saskatchewan, Canada[END_REF]. Similar observations of calcite dissolution in response to CO 2 injections have been reported in other systems including the Pembina Cardium CO 2 Monitoring Project in central Alberta [START_REF] Shevalier | Monitoring the reservoir geochemistry of the Pembina Cardium CO 2 monitoring project, Drayton Valley, Alberta[END_REF] and six oilfields in Wyoming after cyclic CO 2 treatments [START_REF] Smith | Carbonate Cement dissolution during a cyclic CO 2 enhanced oil recovery treatment[END_REF].

The temporal evolution of pH, alkalinity, and calcium concentration of the Weyburn fluids is plotted in Figure 16, and provides further evidence for the dissolution of calcite in response to CO 2 injection.

There is an overall trend of decreasing pH, increasing alkalinity and increasing Ca concentration over time as the injected CO 2 migrated towards the monitoring wells. These data indicate a significant perturbation of the Weyburn subsurface system at the field scale, confirming that both solubility trapping and calcite dissolution occurred in this system.

The Fate of CO 2 Injected at Weyburn

Five main CO 2 sinks were identified at Weyburn: supercritical CO 2 (scCO 2 ) free phase, CO 2 dissolved in oil, CO 2 solubility in brine, calcite dissolution, and mineralization. Hutcheon et al. [START_REF] Hawkes | Overview of wellbore integrity research for the IEA GHG Weyburn-Midale CO 2 Monitoring and Storage Project[END_REF] estimated how the injected CO 2 was distributed among these sinks through detailed modelling. This model took account of the mineralogical data produced from 100 cores collected from different layers of the Weyburn reservoir, and the reservoir fluid chemistry obtained via the baseline monitoring to define the initial conditions for the model. At the end of the 50-year period considered in the model, more than 50% of the subsurface CO 2 is dissolved in the oil remaining in the reservoir. A further 38% of the CO 2 is stored via stratigraphic trapping, locking some of the injected CO 2 as a free phase bounded by the evaporite caprock. Solubility and mineral trapping were predicted to account for no more than 9% and 2% of the CO 2 stored, respectively. In a separate study based on isotopic signature of the injected CO 2 , Raistrick et al. [130] found that 80% of the DIC present in the subsurface water at Weyburn originated from the direct dissolution of CO 2 into these brines; less than 20% of this DIC originated from calcite dissolution.

The observed changes in reservoir fluid geochemistry may have multiple effects over the long term.

In particular, calcite dissolution can cause a redistribution of the porosity and create preferential flow paths, thus reducing the extent of the reservoir that can be used for storage. The lower fluid pH can increase corrosion particularly near the injection well where fast carbonate mineral dissolution may occur. Nevertheless, to date there are no direct observations reported to assess the impact of calcite dissolution on the reservoir structure, and physical characteristics at Weyburn. Results of experiments performed on core samples from the Midale Vuggy formation, however, provide insight. Cores recovered from the Weyburn Midale reservoir rocks were exposed to CO 2 saturated brine with a composition representative of the reservoir's brine, and at a representative reservoir pressure of ~28 MPa and temperature of ~61°C [START_REF] Elkhoury | Dissolution and deformation in fractured carbonates caused by flow of CO 2 -rich brine under reservoir conditions[END_REF]. Results suggest that the circulation of brine equilibrated with CO 2 leads to significant calcite dissolution along pre-existing fractures. Similarly, Carroll et al. [START_REF] Carroll | Development of scaling parameters to describe CO 2 -rock interactions within Weyburn-Midale carbonate flow units[END_REF] observed the formation of wormholes and the development of an irregular dissolution front while reacting Vuggy limestone cores with a CO 2 rich fluid. The Weyburn case study shows that, when implemented at a field scale, CO 2 storage has a significant impact on the chemistry of carbonate-dominated carbon storage reservoirs. Notable decreases in fluid pH leads to significant carbonate mineral dissolution and potentially re-precipitation, which will eventually alter the fluid flow paths over time.

The CarbFix Mineral Storage Project

The CarbFix carbon storage project is focused on promoting mineral carbonation in the subsurface by injecting CO 2 into reactive basaltic rocks [START_REF] Snaebjörnsdóttir | Carbon dioxide storage through mineral carbonation[END_REF][START_REF] Gislason | A brief history of CarbFix: Challenges and victories of the project's pilot phase[END_REF]. The CarbFix injections to date have been located in Iceland near the Hellisheidi geothermal power plant (Figure 17), which is owned and operated by Reykjavik Energy. The CarbFix project has performed injections at two distinct locations. CarbFix1 injected ~200 tons of CO 2 dissolved in fresh water into relatively unaltered basalts at a depth of ~500 m, and at a temperature of 20-50°C [START_REF] Matter | Rapid carbon mineralization for permanent disposal of anthropogenic carbon dioxide emissions[END_REF][START_REF] Snaebjörnsdóttir | The geology and hydrology of the CarbFix2 site, SW-Iceland[END_REF][START_REF] Alfredsson | The geology and water chemistry of the Hellisheidi, SW-Iceland carbon storage site[END_REF]. The CarbFix2 has injected 12,000+ tons/year of CO 2 dissolved in fresh water into strongly altered basalts since 2014, at a depth below 700 m [START_REF] Gunnarsson | The rapid and cost-effective capture and subsurface mineral storage of carbon and sulfur at the CarbFix2 site[END_REF][START_REF] Clark | CarbFix2: CO 2 and H 2 S mineralization during 3.5 years of continuous injection into basaltic rocks at more than 250 °C[END_REF]. The CarbFix project also co-injects hydrogen sulphide (H 2 S) with CO 2 , mineralizing it as solid sulphides, such as pyrite, for additional cost benefit [START_REF] Marieni | Towards ' green ' geothermal energy: Co-mineralization of carbon and sulfur in geothermal reservoirs[END_REF]. In both the injection cases, CO 2 and H 2 S are dissolved in water prior to their arrival in the subsurface, leading to essentially instantaneous solubility trapping [START_REF] Sigfusson | Solving the carbon-dioxide buoyancy challenge: The design and field testing of a dissolved CO 2 injection system[END_REF][START_REF] Gunnarsson | The rapid and cost-effective capture and subsurface mineral storage of carbon and sulfur at the CarbFix2 site[END_REF]. To assess the fate of the injected CO 2 , inert chemical tracers were co-injected at a fixed proportion to the gas-charged water, and fluid samples were collected from monitoring wells located downstream from the injection well and analysed chemically.

The CO 2 -charged water injected into the subsurface promotes the dissolution of the basalt present in the subsurface liberating cations to the fluid phase. For example, the dissolution of pyroxene, a common mineral in basalt, can be expressed as:

2H + + H 2 O + (Ca,Mg,Fe)SiO 3 = Ca 2+ , Mg 2+ , Fe 2+ + H 4 SiO 4 (6)
Such reactions promote CO 2 mineralization in two ways. First, it consumes protons, which neutralizes the acidic gas-charged water -carbonate mineral precipitation is favored by increasing fluid pH; and second, it provides cations that can react with the dissolved CO 2 to form stable carbonate minerals.

Notably, these cations could promote the mineralization of the injected CO 2 as calcite (CaCO 3 ), dolomite (CaMg(CO 3 ) 2 ), siderite (FeCO 3 ), magnesite (MgCO 3 ), or ankerite (Ca(Fe,Mg,Mn)(CO 3 ) 2 ). The degree to which the released cations form stable carbonate minerals and their identity depends on the fluid composition, the fluid pH, and the temperature [START_REF] Snaebjörnsdóttir | Carbon dioxide storage through mineral carbonation[END_REF]. indicate that more than 50% of the injected CO 2 is mineralized within 2-4 months. Modified from [START_REF] Clark | CarbFix2: CO 2 and H 2 S mineralization during 3.5 years of continuous injection into basaltic rocks at more than 250 °C[END_REF].

The measured fluid compositions of all monitoring well fluids were interpreted using PHREEQC [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] to identify the likley mineral reactions ocurring in the subsurface during and after the CarbFix1 and CarbFix2 injections. The results are shown in Figures 20 and21. Note that positive, negative, and zero saturation index (SI) values correspond to aqueous fluids that are supersaturated, undersaturated, and at equilibrium with the indicated mineral. Calculations show that approximately 100 days after the start of the CarbFix1 injection the monitoring fluid samples became supersaturated with respect to calcite with a saturation index of 0.6, which would be sufficient to grow calcite on the surfaces of the silicate minerals present in the reservoir. Moreover, calcite was observed to have precipitated within the monitoring well following the injection. The saturation state of the monitoring fluid samples with respect to the carbonate phases magnesite and dolomite followed a similar pattern as calcite, but these were not identified in the field. Similarly, siderite was calculated to be supersaturated in the sampled monitoring well fluids, but this mineral has not been found in the field. Such results are consistent with the fixation of the injected CO 2 as the mineral calcite. Analogous results were found for the CarbFix2 injections, as shown in Figure 21, where the sampled monitoring well fluids were determined to be at equilibrium or supersaturated with respect to calcite and dolomite during the continuous CarbFix2 CO 2 injections.

The results of such calculations show that much of the CO 2 injected during CarbFix injections has been fixed through mineralization reactions. Notably, the tracer calculations demonstrate the quantity of CO 2 removed from the injected fluid phase, and the chemical analyses of the monitoring well fluids through geochemical calculations demonstrate that this CO 2 was fixed as carbonate minerals, largely as calcite. Such findings highlight the potential for subsurface storage through mineral reactions at other sites containing reactive minerals throughout the world. , the diagonal lines denote times when well HN-14 was used for the injection of gas-charged waters, and the vertical dashed line represents the time when the amount of CO 2 injected into the subsurface was doubled. The SI of these mineral in the injected gas-charged waters, after mixing with geothermal effluent water and heating to 260°C, but prior to their interaction with the rock, are depicted by horizontal red lines. Reproduced with Permission from [START_REF] Clark | CarbFix2: CO 2 and H 2 S mineralization during 3.5 years of continuous injection into basaltic rocks at more than 250 °C[END_REF].

CARBONATE CHEMISTRY AND WELLBORE INTEGRITY

The observations summarized above suggest that one of the most significant reactions provoked by water-CO 2 -rock interaction is the rapid dissolution and precipitation of carbonate phases near injection wells. Such reactions can be detrimental to subsurface carbon storage efforts as the material used in well completion (steel, cement) can be impacted by fluid acidification and calcite dissolution. Degraded wells involved in the reservoir's operations, such as for injection, production, and monitoring, and also pre-existing legacy wells can be a significant source of leakage as they connect the reservoir to the surface [START_REF] Benson | Underground geological storage[END_REF][START_REF] Carroll | Review: Role of chemistry, mechanics, and transport on well integrity in CO 2 storage environments[END_REF][START_REF] Gasda | Spatial characterization of the location of potentially leaky wells penetrating a deep saline aquifer in a mature sedimentary basin[END_REF].

Numerous studies have assessed the behaviour of the materials used in well completions, mainly steel casing and Portland cement, when exposed to CO 2 at reservoir conditions, with the aim of determining if they are suitable for long-term CO 2 storage. Typically, Portland cement is used for cementing the well casing to the surrounding rocks, and to isolate the different rock formations crossed by the well from each other and from the reservoir. The abandonment procedure also typically involves plugging the well with Portland cement.

Traditionally Portland cement is produced by heating crushed limestone mixed with clays to obtain the clinker that is then ground, and mixed with gypsum. As a result, its final composition is dominated by calcium (more than 60 wt%), with main phases being tricalcium silicate ((CaO) 3 SiO 2 ), dicalcium silicate ((CaO) 2 SiO 2 ), tricalcium aluminate ((CaO) 3 Al 2 O 3 ), and gypsum (CaSO 4 • 2H 2 O). Upon contact with water, the cement hydrates, and produces mainly calcium silicate hydrate (CSH) and calcium hydroxide or portlandite (Ca(OH) 2 ).

Carbonation and Cement Alteration

The cement used in well completion, in particular at the bottom of wells, is exposed to formation waters, and CO 2 -rich fluids when used for carbon storage purposes. Chemical degradation of the cement may compromise its sealing and mechanical properties, and favour the creation of fractures or pathways, allowing CO 2 to migrate upwards. The overall mechanism of cement degradation involves three main steps: 1) CO 2 dissolution into formation water, 2) cement carbonation, and eventually 3) dissolution of the calcium carbonates precipitated during the carbonation step [START_REF] Kutchko | Degradation of well cement by CO 2 under geologic sequestration conditions[END_REF][START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF].

The interaction of the injected CO 2 -rich acidic aqueous phase both dissolves cement materials, releasing Ca to the fluid phase, and tends to neutralize the fluid pH creating aqueous bicarbonate. As the fluid percolates further into the cement, it is progressively enriched in Ca 2+ and HCO 3 -by further cement dissolution eventually reaching the supersaturation with respect to CaCO 3 phases. This process leads to the precipitation of calcite, aragonite, and, in some cases, vaterite. This process creates a carbonation front with a characteristic orange color that has been observed both in laboratory experiments (Figure 22) [START_REF] Kutchko | Degradation of well cement by CO 2 under geologic sequestration conditions[END_REF][START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF][START_REF] Duguid | Degradation of cement at the reservoir/cement interface from exposure to carbonated brine[END_REF][START_REF] Kutchko | Rate of CO 2 attack on hydrated class H well cement under geologic sequestration conditions[END_REF][START_REF] Luquot | Hydro-dynamically controlled alteration of fractured Portland cements flowed by CO 2 -rich brine[END_REF], and in field cores (Figure 23) [START_REF] Carey | Analysis and performance of oil well cement with 30 years of CO 2 exposure from the SACROC Unit, West Texas, USA[END_REF][START_REF] Crow | Wellbore integrity analysis of a natural CO 2 producer[END_REF]. This orange alteration is probably due to a change in the iron-bearing cement phases. Carey et al. [START_REF] Carey | Analysis and performance of oil well cement with 30 years of CO 2 exposure from the SACROC Unit, West Texas, USA[END_REF] hypothesized that this coloration is due to the formation of amorphous iron hydroxides in response to the release of Fe 3+ from complex hydrated Ca-bearing cement phases [START_REF] Taylor | Cement chemistry[END_REF]. Authors generally agree that the carbonation of the cement makes it stronger, reduces its porosity and permeability, and thus represents a defence against alteration. Indeed, carbonation is even used commercially to improve the mechanical properties of cement for construction while providing a sink for long-term storage of CO 2 [START_REF] Zhang | Review on carbonation curing of cement-based materials[END_REF]. The overall reactions of this process can be written as follows:

(7) (8) (9) (10)
where is an amorphous silica gel, and is the binding phase in cement paste. As the cement becomes depleted in Ca(OH) 2 and more CO 2 -rich acidic fluids reach the casing, their pH is no longer buffered, and starts to drop [START_REF] Kutchko | Degradation of well cement by CO 2 under geologic sequestration conditions[END_REF][START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF]. The newly formed carbonate minerals start to dissolve, leaving behind an amorphous silica gel [START_REF] Kutchko | Degradation of well cement by CO 2 under geologic sequestration conditions[END_REF][START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF][START_REF] Omosebi | Degradation of well cement in HPHT acidic environment: Effects of CO 2 concentration and pressure[END_REF]. This amorphous silica phase has higher porosity and permeability, and lower mechanical resistance than the original cement [START_REF] Omosebi | Degradation of well cement in HPHT acidic environment: Effects of CO 2 concentration and pressure[END_REF]. As the alteration front progresses inside the cement, the thickness of this weak amorphous layer increases, jeopardizing the integrity of the cement.

Effects of The Fluid Composition on Cement Alteration

The saturation state of the injected CO 2 -charged reservoir fluids with respect to calcite appears to have a strong role in cement durability. Experiments conducted with pure water or brines undersaturated with calcite showed extensive cement degradation, characterized by permeability increase, element zonation, and cement carbonation [START_REF] Duguid | Degradation of cement at the reservoir/cement interface from exposure to carbonated brine[END_REF][START_REF] Rimmelé | Heterogeneous porosity distribution in Portland cement exposed to CO 2 -rich fluids[END_REF]. In contrast, when the fluids were previously saturated with calcite, there was no driving force to dissolve the calcite formed by cement carbonation. In such cases, the degradation process stopped after mild carbonation, with little to no dissolution occurring [START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF][START_REF] Duguid | Degradation of cement at the reservoir/cement interface from exposure to carbonated brine[END_REF][START_REF] Carey | Analysis and performance of oil well cement with 30 years of CO 2 exposure from the SACROC Unit, West Texas, USA[END_REF][START_REF] Carey | Experimental investigation of wellbore integrity and CO 2brine flow along the casing-cement microannulus[END_REF]. Such studies suggest that, so long as the reservoir fluids are saturated with calcite, the cement degradation from CO 2 exposure is negligible.

Luquot et al. [START_REF] Luquot | Hydro-dynamically controlled alteration of fractured Portland cements flowed by CO 2 -rich brine[END_REF] reacted a brine designed to be at equilibrium with calcite by flowing it through fractured cement cores with typical well cements. In the experiment with the highest fluid flow rate, authors observed the three layers of the typical cement degradation pattern on fracture surfaces, including the formation of a highly porous silica layer corresponding to the dissolution of calcite formed during carbonation. Such results appear to be inconsistent with other experiments with calcite-saturated brines where no significant dissolution of calcite was observed. However, while Duguid and Scherer [START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF] and Carey et al. [START_REF] Carey | Experimental investigation of wellbore integrity and CO 2brine flow along the casing-cement microannulus[END_REF] saturated their brine with CO 2 first and then equilibrated it with calcite prior to injection, the opposite was true for Luquot et al. [START_REF] Luquot | Hydro-dynamically controlled alteration of fractured Portland cements flowed by CO 2 -rich brine[END_REF], who first equilibrated the brine with calcite at atmospheric CO 2 pressure, and then charged the resulting brine with scCO 2 . As a result, the brine entering the reactor in the Luquot et al. [START_REF] Luquot | Hydro-dynamically controlled alteration of fractured Portland cements flowed by CO 2 -rich brine[END_REF] experiment was undersaturated with respect to calcite, which explains why they observe the dissolution layer.

In their review, Zhang and Bachu [START_REF] Zhang | Review of integrity of existing wells in relation to CO 2 geological storage: What do we know?[END_REF] argued that, at field conditions, virtually all reservoir brines would be saturated with calcite as calcium carbonates are almost ubiquitously present in reservoir rocks, and very little calcite is necessary for the aqueous phase to reach saturation. Indeed, geochemical calculations covering 10 to 100°C, and 10 to 30 MPa of CO 2 partial pressure performed using PHREEQC geochemical software [START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] and the carbfix.dat database [START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] show that, with porosity up to 40%, as little as 0.1 wt% calcite is sufficient to saturate pure water, a 0.5 M NaCl brine or a synthetic Utsira pore water brine (composition from [START_REF] Portier | Modelling CO 2 solubility in pure water and NaCl-type waters from 0 to 300 °C and from 1 to 300 bar. Application to the Utsira Formation at Sleipner[END_REF]). Field observations of the rapid enrichment of reservoir fluids in calcium were reported in the Frio sandstone formation, where the injection of CO 2 triggered the rapid dissolution of the minor carbonate fraction of the rock [START_REF] Kharaka | Gas-water-rock interactions in Frio Formation following CO 2 injection: Implications for the storage of greenhouse gases in sedimentary basins[END_REF]. Carbonate mineral saturation will not be reached, however, near the gas injection point and/or near the water-CO 2 (g) interface, where fluids will remain strongly undersaturated over the long term because of continuous injection. There, it is likely that cement degradation and carbonate mineral dissolution will occur, potentially creating undesired pathways and leakage.

The flow regime of reactive fluids has also been proposed as a factor enhancing cement degradation.

The continuous renewal of the CO 2 -charged fluids would favour cement carbonation, and eventual degradation. Such was observed by Duguid and Scherer [START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF], where cement cores subjected to a continuous flow of CO 2 -saturated brines with pH of 2.4 and 3.7 were almost completely degraded after 31 days. Nonetheless, in other flow through experiments where the reactive fluids were saturated with respect to calcite [START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF][START_REF] Carey | Experimental investigation of wellbore integrity and CO 2brine flow along the casing-cement microannulus[END_REF], no significant cement dissolution or mass loss was observed, again demonstrating that the saturation state of the fluid with respect to calcite is a critical factor. Continuous flow conditions likely enhance the degradation process, but other factors such as the composition of the fluids play a more important role.

When cement cores are only exposed to wet or dry scCO 2 , the degradation patterns differ from what observed with aqueous CO 2 -bearing fluids. Cement cores exposed to wet or dry scCO 2 do not exhibit the characteristic orange layer associated with the carbonation front, but rather a single greyish zone with distributed carbonates [START_REF] Kutchko | Rate of CO 2 attack on hydrated class H well cement under geologic sequestration conditions[END_REF][START_REF] Jung | Experimental study of potential wellbore cement carbonation by various phases of carbon dioxide during geologic carbon sequestration[END_REF]. Overall, the rate of penetration of the alteration front into the cement was observed to be lower for scCO 2 than for CO 2 -charged brines [START_REF] Kutchko | Rate of CO 2 attack on hydrated class H well cement under geologic sequestration conditions[END_REF][START_REF] Rimmelé | Heterogeneous porosity distribution in Portland cement exposed to CO 2 -rich fluids[END_REF][START_REF] Jung | Experimental study of potential wellbore cement carbonation by various phases of carbon dioxide during geologic carbon sequestration[END_REF]. Only in one study [START_REF] Barlet-Gouédard | Mitigation strategies for the risk of CO2 migration through wellbores[END_REF] the opposite was observed. However, the fast curing of the cement in this experiment, as well as higher pressure and temperature may explain this difference.

The evolution of the porosity in experiments with scCO 2 is similar to that with CO 2 -charged water: porosity first decreases as calcite precipitates, and then increases as this calcite dissolves. The process, however, is generally slower in scCO 2 than in CO 2 -charged water [START_REF] Rimmelé | Heterogeneous porosity distribution in Portland cement exposed to CO 2 -rich fluids[END_REF][START_REF] Barlet-Gouédard | Mitigation strategies for the risk of CO2 migration through wellbores[END_REF]. This observation is consistent with that of Zhang and Bachu [START_REF] Zhang | Review of integrity of existing wells in relation to CO 2 geological storage: What do we know?[END_REF] in their review of the integrity of wells exposed to CO 2 -rich fluids, who reported that the dissolution of the precipitated calcite is more efficient in CO 2charged water.

Cements exposed to scCO 2 also appear to better preserve their mechanical strength. Barlet-Gouédard et al. [START_REF] Barlet-Gouédard | A solution against well cement degradation under CO 2 geological storage environment[END_REF] reported that cements exposed to wet scCO 2 for six weeks retained 65% of their initial mechanical strength, whereas those exposed to CO 2 -charged water retained only 33% of their initial strength. Some authors suggested that the milder degradation observed in the presence of scCO 2 may be used to protect injection wells by creating a "bubble effect", with scCO 2 flushing the aqueous brine away from the injection well [START_REF] Zhang | Review of integrity of existing wells in relation to CO 2 geological storage: What do we know?[END_REF][START_REF] Sweatman | Effective zonal isolation for CO 2 sequestration wells[END_REF][START_REF] Taberner | Injection of Supercritical CO2 into Deep Saline Carbonate Formations[END_REF].

Impacts of The Cement Composition

The composition of the cement as well as the casting conditions can change its resistance to CO 2 . For example, studies of cement resistance have involved different classes of Portland cement, mainly classes A, G, and H. Omosebi et al. [START_REF] Omosebi | Degradation of well cement in HPHT acidic environment: Effects of CO 2 concentration and pressure[END_REF] suggested that class H cement was slightly more resistant to degradation by CO 2 than class G cement in that it conserved higher compressive strength, and reduced porosity and permeability after exposure. Nevertheless, the class of the Portland cement only results in minor resistance differences to CO 2 attack [START_REF] Jung | Experimental study of potential wellbore cement carbonation by various phases of carbon dioxide during geologic carbon sequestration[END_REF].

Cements with added pozzolanic materials, such as fly ash or silica flour, exhibit a different behaviour than pristine cement. These mixtures offer advantages such as improved workability, higher strength and durability, as well as reduced costs. When exposed to CO 2 -rich environments, pozzolanic cements do not react to the characteristic orange layer reaction front consistently observed on pristine cements [START_REF] Crow | Wellbore integrity analysis of a natural CO 2 producer[END_REF][START_REF] Kutchko | CO 2 reaction with hydrated class H well cement under geologic sequestration conditions: Effects of flyash admixtures[END_REF]. They tend to uniformly carbonate and at higher rates than pristine cement [START_REF] Ledesma | Zeolite and fly ash in the composition of oil well cement: Evaluation of degradation by CO 2 under geological storage condition[END_REF][START_REF] Zhang | Experimental study of well cement carbonation under geological storage conditions[END_REF]. This behaviour has been attributed to a higher penetration rate of the CO 2 into the pozzolanic cements [START_REF] Carroll | Review: Role of chemistry, mechanics, and transport on well integrity in CO 2 storage environments[END_REF], and to the lower content of portlandite limiting the carbonation reactions. Laudet et al. [START_REF] Laudet | The behavior of oil well cement at downhole CO 2 storage conditions: Static and dynamic laboratory experiments[END_REF] found that while the carbonation process was proportional to the square root of time for pristine cement, it was directly proportional to time for cement with added silica flour, so that the alteration was likely limited by surface reaction kinetics rather than diffusion, consistent with the conclusions of Kutchko et al. [START_REF] Kutchko | CO 2 reaction with hydrated class H well cement under geologic sequestration conditions: Effects of flyash admixtures[END_REF]. Such results highlight the importance of chemical transport within the cement in the degradation process.

Despite such differences, pozzolanic cements appear to conserve permeability below 200 μD, as recommended by the American Petroleum Institute. Only in Zhang and Talman [START_REF] Zhang | Experimental study of well cement carbonation under geological storage conditions[END_REF] did a lightweight cement rapidly increased its permeability up to 1000 μD. Overall, pozzolanic cements are more rapidly carbonated, which might indicate a lower resistance to chemical aggression compared to pristine cement. On the other hand, pozzolanic cement show higher mechanical strength [START_REF] Ledesma | Zeolite and fly ash in the composition of oil well cement: Evaluation of degradation by CO 2 under geological storage condition[END_REF], so there might be a trade-off between the two. Pozzolanic cement might be preferred when important mechanical stresses are expected (to prevent fractures), whereas pristine cement may be preferred in environments where mechanical stresses are expected to be low.

The curing conditions of the cements also impact the capacity of the cement to efficiently "armor" against CO 2 attack. Kutchko et al. [START_REF] Kutchko | Degradation of well cement by CO 2 under geologic sequestration conditions[END_REF] and Strazisar and Kutchko [START_REF] Strazisar | Degradation of wellbore cement due to CO 2 injection-effects of pressure and temperature[END_REF] tested different curing conditions, and concluded that despite having the same chemical composition, cements cured at higher pressure and temperature (PT) are more resistant to CO 2 attack. They attributed this enhanced resistance to the morphology of the Ca(OH) 2 crystals. In cements cured under high pressure and temperature conditions, smaller and more evenly distributed Ca(OH) 2 crystal formed, allowing the carbonation front provoked by the interaction with CO 2 -rich aqueous phase to be more homogeneous and "tight". Jung and Um [START_REF] Jung | Experimental study of potential wellbore cement carbonation by various phases of carbon dioxide during geologic carbon sequestration[END_REF] obtained results consistent with Kutchko's experiment, but Jung et al. [START_REF] Jung | Wellbore cement fracture evolution at the cementbasalt caprock interface during geologic carbon sequestration[END_REF] reported that the progress of the reaction front was similar between cement cured at ambient PT or high PT after 3 months of exposure to CO 2 . The comparison of these results suggests that high PT curing conditions may provide an advantage for cement resistance for short exposure durations, but less as time progresses.

Calcite Precipitation and Self-Sealing Effects

In the absence of significant chemical transport pathways (such as fractures and interconnected pores), cement degradation is limited by diffusion. In such cases, conventional cements may perform adequately over decades. Yet, where fractures are present in the cement, fluid flow can be focused along cement linings upwards along the fracture pathway due to the pressure gradient between the reservoir and the upper rock formations. It is uncertain if such fracture pathways will trigger an accelerated degradation of the cement, or would self-heal and clog. Observations suggest that when fractures are either perpendicular to the pressure gradient or dead-end (non-conductive) fractures, the precipitation of carbonates dominates, resulting in a relatively rapid fracture clogging [START_REF] Luquot | Hydro-dynamically controlled alteration of fractured Portland cements flowed by CO 2 -rich brine[END_REF][START_REF] Sweatman | Effective zonal isolation for CO 2 sequestration wells[END_REF]. This self-sealing behaviour was also reported by Liteanu and Spiers [START_REF] Liteanu | Fracture healing and transport properties of wellbore cement in the presence of supercritical CO 2[END_REF].

When fractures are parallel to the pressure gradient and connect the areas of different pressures, several parameters define the fate of the fracture. The fracture aperture, the fluid flow rate, and the residence time of the fluids in the fracture all have a role in the rate and potential for calcite fracture clogging. Huerta et al. [START_REF] Huerta | Experimental evidence for self-limiting reactive flow through a fractured cement core: Implications for time-dependent wellbore leakage[END_REF] observed distinct behaviours depending on the combination of these factors, but with all experiments resulting in the self-sealing of the fractures. Similarly, Luquot et al. [START_REF] Luquot | Hydro-dynamically controlled alteration of fractured Portland cements flowed by CO 2 -rich brine[END_REF] observed that at low to intermediate flow rates, fractures tend to heal and clog. Only in conductive, high flow fractures, the flow was maintained over the course of the experiments. It is interesting to note that, even in such cases, the fractures did not grow and the flow was only maintained. This behaviour was attributed to the amorphous silica layer remaining after the carbonation and subsequent calcite dissolution occurred, limiting the aperture of the fracture. Liteanu and Spiers [START_REF] Liteanu | Fracture healing and transport properties of wellbore cement in the presence of supercritical CO 2[END_REF] obtained similar results in batch experiments, exposing wet cement paste to scCO 2 . The carbonation reaction caused the porosity of the cement to decrease and allowed the healing of small fractures. Brunet et al. [START_REF] Brunet | Fracture opening or self-sealing: Critical residence time as a unifying parameter for cement-CO 2 -brine interactions[END_REF] simulated a range of values of aperture and residence time to assess the resulting fate of the fractures through a series of computational models. The notion of critical aperture threshold was introduced as an indicator of the expected behaviour of the fractures. In their review, Carroll et al. [START_REF] Carroll | Review: Role of chemistry, mechanics, and transport on well integrity in CO 2 storage environments[END_REF] concluded that self-healing processes are common in geologic reservoirs.

A summary of the effects of various factors on cement resistance to CO 2 is provided in Table 3. Only a few of the parameters listed in this table are controllable. The cement durability in carbon injection systems could be improved through varying the cement composition, or choosing to replace the cement with other materials. It might also be possible to adjust the injection parameters to create the "bubble effect" to protect the cement as suggested by Sweatman et al. [START_REF] Sweatman | Effective zonal isolation for CO 2 sequestration wells[END_REF]. However, the rest are uncontrollable factors that need to be measured and considered in the initial development of a CO 2 storage reservoir.

Corrosion and Cement Degradation of The Weyburn Wells

Insight into the long-term effects of CO 2 injection on well cements can be attained from experience at the Weyburn EOR site. An extensive wellbore integrity monitoring program was conducted within the project. Five wells were further studied to assess the corrosion rate and the integrity of the concrete cementing the casing [START_REF] Sacuta | International Energy Agency (IEA) Greenhouse Gas (GHG) Weyburn -Midale CO 2 Monitoring and Storage Project[END_REF]. The data was obtained by direct measurements in the wells using a wide range of well logging techniques. These data were, however, collected for operation purposes (i.e., to diagnose problems on operating wells), not for detailed mechanistic study. This represented a significant challenge for the authors as well logs were not consistent in time. Well repairs also interfered with the tracking of corrosion impacts, for example when a liner was installed to fix suspected leakage issues. Of the five studied wells, wells 1 to 3 were CO 2 injection wells, while wells 4 and 5 were selected as control wells located far from the injection zone. No significant difference could be observed between wells used for CO 2 injection compared to those not directly exposed. All five wells have suffered some corrosion. The only consistent patterns were the more pronounced internal casing corrosion at the bottom part of the wells, and the stronger external casing corrosion on the shallower part of the wells. For example, after 6 years of CO 2 injection, the lower part of the casing of well 1 was completely corroded, and resulted in the abandonment of the well. Moreover, control well 5 exhibited extensive casing loss, and several holes appeared in the casing at depths between 800 and 900m. This extensive degradation caused this well to stop operations in 1995. Sacuta et al. [START_REF] Sacuta | International Energy Agency (IEA) Greenhouse Gas (GHG) Weyburn -Midale CO 2 Monitoring and Storage Project[END_REF] suggested that the accelerated corrosion observed in this well casing could be the result of sulphur and iron-reducing bacteria present in production fluids (e.g. [START_REF] Heitz | Microbially influenced corrosion of materials[END_REF]), as well as stray current producing an alteration of the electrical field inside the concrete (e.g., [START_REF] Bertolini | Corrosion behaviour of steel in concrete in the presence of stray current[END_REF]).

All the wells showed limited cement degradation on the sections logged with only small defects in specific locations: minor channelling and poor bonding to formation rock at specific depths. Authors concluded that all the wells conserved their isolation properties. This finding is consistent with the fact that the saturation index of calcite in the Weyburn fluids remained close to equilibrium values throughout the project [START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF], thus preventing the carbonation of the cement to proceed completely, as suggested by Carey et al. [START_REF] Carey | Analysis and performance of oil well cement with 30 years of CO 2 exposure from the SACROC Unit, West Texas, USA[END_REF] and Duguid and Scherer [START_REF] Duguid | Degradation of oilwell cement due to exposure to carbonated brine[END_REF].

Our understanding of alteration processes of well cements exposed to CO 2 injection has significantly improved since 2005, and the original IPCC report on CO 2 storage [START_REF] Benson | Underground geological storage[END_REF]. There is a general consensus on the mechanisms causing the cement degradation in field reservoirs. Acidic CO 2 -rich fluids first dissolve cement phases, and mobilize calcium. The buffering of the fluid pH by cement dissolution in pore fluids then allows this calcium to react with dissolved carbonate, and to precipitate CaCO 3 phases, mainly calcite. Finally, depending on conditions, this secondary calcite is further dissolved. In this latter case, only an amorphous and porous silica gel remains.

Carbonate chemistry is central to the mechanisms of cement degradation and resistance. Notably, the saturation state of the reservoir fluids with respect to calcite is critical for estimating the risk of significant cement alteration in response to the presence of CO 2 . Portland cement can withstand the conditions of CO 2 storage if the formation waters are at or close to saturation with respect to calcite. Such may be the case in many potential subsurface storage systems, but will likely not be the case for CO 2 injection wells or very nearby to such wells. New materials more resistant to CO 2 degradation, such as geopolymers, have been proposed [START_REF] Barlet-Gouédard | Mitigation strategies for the risk of CO2 migration through wellbores[END_REF]. The limit to their implementation is their higher cost compared with Portland cement.

CONCLUSIONS

The observations summarized above show that the effect of CO 2 injection into the subsurface depends greatly on the composition of the target reservoir rocks. Carbon dioxide injected into most sedimentary rocks will likely remain as a distinct phase for an extended period of time. This CO 2 will dissolve into adjacent formation fluids slowly, limited by its solubility in the aqueous phase. The density of the aqueous fluid is altered by increasing its CO 2 content. As such CO 2 dissolution into the fluid phase may provoke the fluid convection enhancing solubility storage over time. Nevertheless, solubility storage requires vast volumes of pore space. The extent to which mineral storage occurs in such systems is likely limited by the lack of silicate mineral bound divalent metals in most sedimentary rocks.

The redistribution of carbonate minerals in such systems may, however, be extensive. Carbonate minerals are expected to dissolve, if present, as CO 2 dissolves into the aqueous phase. As the dissolution of carbonate minerals is rapid, especially in acidic fluids, this will lead to the extensive removal of carbonate minerals near the water-CO 2 phase interface. This process is likely to dominate near CO 2 injection wells. The metals released through this process can precipitate as either the same or a different carbonate mineral further from this interface as the pH of the fluid phase increases. This overall process of carbonate dissolution, transport and re-precipitation may alter the porosity, permeability and the injectivity properties of the reservoir. However, it will provide only negligible net mineral carbon storage.

In contrast, the targeting of geologic carbon storage into reactive rocks, rich in silicate-bound divalent cations, such as basalts, can promote the rapid mineral storage of injected carbon dioxide. The dissolution of these rocks by acidic CO 2 -rich waters also increases the pH and alkalinity of the fluid, both stabilizing CO 2 in the aqueous phase and promoting the formation of stable carbonate minerals.

A significant risk of geologic carbon storage is the potential for the long-term leakage of the injected carbon. Notably, the corrosion of injection wells and the degradation of cement have the potential to open up fluid pathways towards the surface. Both aqueous fluids undersaturated with respect to calcite, and scCO 2 are abundant near the injection wells. Each has been shown to rapidly degrade well cements. Such alteration process may be limited further from injection wells as the aqueous fluid will tend to saturate with respect to carbonate minerals as one moves away from the CO 2 source. Such carbonate mineral saturated aqueous fluids tend to strengthen rather than degrade well cements. Perhaps the greatest leakage risk stems from disperse sources, which can be challenging to identify and quantify. Despite such risks, the massive upscaling of geologic carbon storage is likely essential over the next few decades. Although, society is planning to decrease significantly the consumption of hydrocarbons, carbon emissions to the atmosphere will continue for some time. Geologic carbon storage appears to be the only option able to provide the large volumes required for applying CCS at the vital scale to attenuate the increasing atmospheric carbon dioxide concentrations at a global level.

NOMENCLATURE °C

Figure 2 .

 2 Figure 2. Images of natural carbonates deposits of various origins: (a) White and red chalk cliffs at Hunstanton seashore, Norfolk (UK), consist in biogenic carbonates accumulated by Coccoliths during the Cretaceous and turned into chalk (Andrew Dunn, Wikicommons 1 ). (b) In Pamukkale (Turkey) hydrothermal fluids coming from carbonate-rich formations emerge at the surface; the pressure drop causes dissolved CO 2 to degas, a rise in pH, and the spontaneous precipitation of those extensive travertine fields (Antoine Taveneaux, Wikicommons 2 ). (c) "Ladder cracks" filled with secondary calcite visible on an outcrop of partially serpentinized peridotites in Oman; these are a natural example of the spontaneous carbonation of basic silicate rocks due to hydrothermal activity. Reproduced with permission from [43].

Figure 3 .

 3 Figure 3. Phase diagram of CO 2 as a function of temperature and pressure. Modified from Finney and Jacobs, Wikicommons 3 .

Figure 4 .

 4 Figure 4. (a) Densities of pure CO 2 [58]; (b) densities of pure H 2 O [59] and (c) the difference between these two densities as a function of pressure at the indicated temperatures. The blue, red, violet, grey and olive curves correspond to values for 0, 25, 50, 100 and 200°C.

  Figure5. (a) The solubility of CO 2 in water and (b) the pH of this CO 2 -saturated water at selected temperatures. These calculations were performed using PHREEQC[START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with its carbfix.dat database[START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2[START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF].

Figure 6 .

 6 Figure 6. Logarithm of CO 2 (g) solubility at a pressure of 1 bar as a function of fluid pH at 25, 100, and 200°C in a 0.1 mol NaCl solution and sufficient NaOH to increase the pH to the indicated values.These calculations were performed using PHREEQC[START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with its carbfix.dat database[START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2[START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF].

Figure 7 .

 7 Figure 7. Solubility of CO 2 (g) as a function of pressure a temperature of (a) 25°C and (b) 100°C. The yellow, orange and purple curves represent the calculated solubility at a water salinity of 0, 0.6, and 5 mol/kg, respectively. These calculations were performed using PHREEQC[START_REF] Parkhurst | Description of Input and Examples for PHREEQC Version 3 -A Computer Program for Speciation , Batch-Reaction , One-Dimensional Transport , and Inverse Geochemical Calculations[END_REF] together with the carbfix.dat database[START_REF] Voigt | Evaluation and refinement of thermodynamic databases for mineral carbonation[END_REF] , which takes account of the Peng-Robinson equation of state for CO 2[START_REF] Peng | Two and three phase equilibrium calculations for systems containing water[END_REF].

Figure 8 .

 8 Figure 8. The density of aqueous fluids equilibrated with the indicated CO 2 pressure at 50°C, 100°C, and 140°C. The brown, grey, and blue symbols represent densities measured by Yan et al.[START_REF] Yan | Measurement and modeling of CO 2 solubility in NaCl brine and CO 2 -saturated NaCl brine density[END_REF] in NaCl-free water, in 1.0 mol/kg aqueous NaCl, and in 5.0 mol/kg aqueous NaCl, respectively. The dashed curves in this figure are provided for the aid of the viewer.

Figure 9 .

 9 Figure 9. The (a) solubility of calcite and (b) pH of a 0.1 mol/kg aqueous NaCl solution equilibrated with calcite as a function of CO 2 (g) pressure. In both cases calculations were performed by allowing the aqueous NaCl solution to equilibrate with calcite and pure CO 2 at the indicated pressure. The curves in (a) thus refer to the number of moles of calcite dissolved for the one kg of the fluid to attain equilibrium. The red and blue curves show results for temperatures of 25 and 100°C,

Figure 11 .

 11 Figure 11. Evolution of fluid pH as a function of distance along the planar 1 mm wide fracture, for three host rock systems: i) CB without calcite, ii) CB with calcite, and iii) sandstone.

Figure 12 .

 12 Figure 12. Evolution of dissolved inorganic carbon (DIC) as a function of distance, for three host rock systems: CB without calcite, CB with calcite, and iii) sandstone. The dashed line represents the initial DIC concentration.

Figure 13 .

 13 Figure 13. Evolution of the fracture volume change with distance from the injection point, per kg of water flow and assuming a fluid flow rate of 1 m/day, for three host rock systems: i) CB without calcite, ii) CB with calcite, and iii) sandstone. The dashed line represents the initial condition of fracture volume (1000 cm 3 ). Also, positive values of fracture volume change represent a fracture opening, whereas negative values its clogging.

Figure 14 .

 14 Figure 14. (a) Location map of the Weyburn field. Inset map: map of the oil field with Phase 1A area highlighted. This was the first area to be injected with CO 2 . (b) Simplified stratigraphy of Weyburn.Reproduced with permission from[START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF].

Figure 15 .

 15 Figure 15. Contour maps of the evolution of the downhole fluid pH from 2000 to 2010 in Weyburn Phase 1A area. The solid blue line delineates the Phase 1A study area. The dots represent the locations of wells sampled in each of the campaigns. Reproduced with permission from[START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF]. Further details on the location of the wells used for CO2 injection and the timing of the injections is available in[START_REF] Shevalier | Brine geochemistry changes induced by CO 2 injection observed over a 10 year period in the Weyburn oil field[END_REF].

Figure 16 .

 16 Figure 16. (a) Plot of total alkalinity as a function of downhole fluid pH for all the sampling events. (b) Plot of total alkalinity as a function of calcium concentrations for all the sampling events. The dashed line indicates calcite dissolution. Baseline was measured during August 2000, monitor 3 to 11 from 2001 to 2004, and monitor 12 to 16 from 2008 to 2010. Reproduced with permission from [133].

Figure 17 .Figure 18 .

 1718 Figure 17. Map showing the locations of the CarbFix1 and CarbFix2 injection sites. Also shown are various injection and production wells, active faults, and roads in the area. Modified from [147].

Figure 19 .

 19 Figure 19. In situ concentrations of DIC in samples collected from the HE-31, HE-48, and HE-44 monitoring wells located 984, 1356, and 1482 m, respectively, from the HN-16 CarbFix2 injection well prior to and during the injection of CO 2 . Black circles depict the measured concentrations, while the white circles correspond to concentrations calculated assuming non-reactive fluid mixing. The grey bar corresponds to times before the CO 2 injection started (see caption ofFigure21). Results indicate that more than 50% of the injected CO 2 is mineralized within 2-4 months. Modified from[START_REF] Clark | CarbFix2: CO 2 and H 2 S mineralization during 3.5 years of continuous injection into basaltic rocks at more than 250 °C[END_REF].

Figure 20 .

 20 Figure 20. Saturation index (SI) values of collected HN-04 monitoring well water samples during and after the CarbFix1 injection with respect to A) magnesite, siderite, and calcite; B) dolomite, aragonite, and ankerite, C) Mg-Fe and Ca-Mg-Fe carbonate solid solutions, and D) pyrrhotite, pyrite, sulphur, and mackinawite prior to, during, and after the injection of pure CO 2 and a CO 2 /H 2 S gas mixture into the CarbFix1 subsurface storage site. All saturation indices were calculated assuming the oxygen fugacity was controlled by equilibrium of the H 2 S/SO 4 2-as a redox couple. The timing of CarbFix1 injections are indicated by grey bars. Reproduced with Permission from [19].

Figure 21 .

 21 Figure[START_REF] Goldberg | A global assessment of deep-sea basalt sites for carbon sequestration[END_REF]. In situ saturation indices of the fluids collected from the HE-31, HE-48, and HE-44 monitoring wells during the CarbFix2 injection with respect to the carbonate minerals -ankerite, calcite, dolomite, magnesite, and siderite. The black symbols corespond to calculated fluid saturation indices, the gray shaded area indicates times before the injection of gas-charged water into well HN-16, the diagonal lines denote times when well HN-14 was used for the injection of gas-charged waters, and the vertical dashed line represents the time when the amount of CO 2 injected into the subsurface was doubled. The SI of these mineral in the injected gas-charged waters, after mixing with geothermal effluent water and heating to 260°C, but prior to their interaction with the rock, are depicted by horizontal red lines. Reproduced with Permission from[START_REF] Clark | CarbFix2: CO 2 and H 2 S mineralization during 3.5 years of continuous injection into basaltic rocks at more than 250 °C[END_REF].

Figure 22 .

 22 Figure 22. Time-lapse pictures of the carbonation front progressing into neat cement paste reacted at 50°C and fluid pH of 2.4 in a laboratory experiment. Reproduced with permission from [152].

Figure 23 .

 23 Figure 23. Polished core fragment of a gray cement casing from the SACROC unit in Texas showing an orange-colored alteration zone containing carbonates. Reproduced with permission from [156].

Table 1 .

 1 Initial conditions applied to all the reactive path models.

	Rock/water ratio		1 m 3 /kg
	Initial CO 2 partial pressure ~20 bar
	DIC		~0.6 mol/kg
	Temperature		25°C
	pH		3.29
	Rock surface (	)	20,000 cm 2 /kg water
	Total time		1 year
	Time step		1 day

Table 2 .

 2 Composition (vol%) and mass of the crystalline basalt with and without calcite

Table 3 .

 3 Overview of the parameters affecting cement resistance in CO 2 -rich environments

	Parameter	Lower resistance of	Higher resistance of	References
		cement	cement
	Nature of the reactive	CO 2 charged water/brine	Dry or wet scCO 2, with	[166,177]
	fluid	(aqueous)	wet scCO 2 being more
			aggressive
			Bubble effect to protect
			wells
	Salinity of reactive	Low (typically pure	High (brines) with salting	[25,48]
	aqueous fluid acting on	water)	out effect = less CO 2 in
	CO 2 solubility		solution
	Calcite saturation state of	Reactive fluid under-	Reactive fluid saturated	[152,155,157,178]
	the aqueous reactive fluid	saturated with calcite	with calcite
	Cement curing time	Shorter	Longer	[151]
	Cement curing P and T	Cements cured at low P	Cements cured at higher	[151]
		and T conditions	pressure and temperature
			conditions
	Cement composition	Pozzolan cements	Neat cement (richer in	[151]
			Portlandite)	[164]
			Newly developed special
			cements
	Flow rate	continuous flow	Static conditions	[152]

Residence time of the fluids in the fractures

	Conductive fractures with	High residence time, small	[149,155,175]
	high aperture allowing	aperture, secondary and
	sustained flow rate	dead-end fractures

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