SECCIÓN QUINTA ASCENSORES O ELEVADORES

The CA needs to critically review the issues related to stream composition impacts on geological storage integrity. While some incidental substances can be safely transported in pipelines, they may result in affecting storage integrity. For example, acid gases can be transported safely in pipelines as long as the stream is sufficiently dehydrated, whereas these acid gases could result in reducing storage integrity due to interactions with formation water in the storage site. Of particular importance are the potential deterioration of well-bore cement and other geochemical changes from acid interactions (chemical reactions and mineral dissolution and precipitation, along with related permeability enhancements and clogging effects) with the fluids and rocks in the storage formation and heavy metal contamination of deep saline aquifers.

Czernichowski-Lauriol et al. (2006) has reviewed the literature regarding

geochemical interactions between CO2, formation water, and reservoir rocks. They

found that, depending on the nature and scale of the chemical reactions, CO2

interactions with reservoir rocks and cap rocks may have significant consequences,

either beneficial or deleterious, on CO2 injectivity, storage capacity, sealing efficiency,

and long-term safety and stability. Reaction with formation water is expected to trap

CO2 in a solution phase, and in turn, the dissolved CO2 will react with minerals in the

host formation, causing pH buffering, enhanced solubility trapping due to the formation of dissolved bicarbonate ions and complexes. Reaction of the dissolved

CO2 with certain non-carbonate minerals rich in calcium, iron, or magnesium can also

trap the CO2 as a solid carbonate precipitate, essentially immobilising the CO2 for

geological time periods. Mineral reactions result in modification of porosity and

permeability of the formation, which can either hinder the injection of CO2, or aid its

migration through the injection zone.

A variety of inorganic acids could be formed when the injected CO2 stream with its

incidental components encounters the fluids in the storage site. These acids can corrode the rocks in the storage complex and affect the geochemistry of the rocks. They can also corrode the cement used for sealing the wells and hence cause leaks over the long term.

Table 7 provides a list of potentially important acids that might be formed from the

incidental substances co-injected with the supercritical CO2 when the CO2 comes into

contact with formation water. Not included in this table are arsenic acid, hydrofluoric acid, hydrogen sulphide, selenic acid, and selenious acid, which are not expected to

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contribute significantly to the acidity. The strength of the acids is expressed ratio of the equilibrium constant of the acid relative to that of carbonic acid, which is formed

by CO2 interacting with water. The equilibrium constants used to develop the relative

acidities shown in Table 7 correspond to 25ºC and atmospheric pressure. Since the pressure and temperature will be much higher in situ, the reaction constants for the formed acids will likely be different in the storage formation, as higher temperatures will typically increase the rate of reaction, while higher pressures can have varied effects.

The volume fraction listed in Table 7 is the upper limit of the concentration of each

acid in the CO2 stream based on near-worst-case assumptions. For example, it

assumes that all of the chlorine in the CO2 stream occurs as HCl, even though it is

likely that most of the chlorine will be oxidized and bound with metals during the combustion process (Otero-Rey et al., 2003). The table has been sorted by the concentration of hydrogen ions to identify the potentially most important acids in the

CO2 stream. The most critical acid is hydrochloric acid, which is formed if there is any

free form of chlorine present in the CO2 stream. Sulphurous and sulphuric acid,

formed from SO2 and SO3 mixed with water, are the next important acids of concern.

The contribution of sulphuric acid is about a hundred times less than sulphurous acid,

under the assumption that the concentration of SO3 in the CO2 stream will typically

be about 1% of the concentration of SO2. Carbonic acid, formed by the combination

of CO2 and water, is a weak acid that contributes little to the volume-weighted acidity

of the formation water compared to sulphurous acid and potentially hydrochloric acid if these near-worst-case conditions were to exist. Nitrous acid has a comparable impact as carbonic acid.

The CA should carefully consider potential restriction of the chlorine, SOx, and NOx

content in the injected stream with a view to prevent potentially high levels of acids that could pose an unacceptable level of risk, subject to geological characteristics of the storage site.

Table 7: Illustrative impact of acids resulting from incidental substances in injected

CO2 stream mixing with formation water (source: calculations by ICF International)

Acid Formula Relative

acidity

Volume Fraction

Total acidity impact (relative acidity x volume) Hydrochloric acid HCl 2.3x(10)14 _1.4x(10)-3 _3.7x(10)11 Sulphurous acid H2SO3 3.5x(10)4 1.3x(10)-2 5.3x(10)2 Sulphuric acid H2SO4 2.8x(10)4 1.3x(10)-4 4.2x(10)0 Carbonic acid H2CO3 1.0x(10)0 8.8x(10)-1 1.0x(10)0

Nitrous acid HNO2 1.0x(10)3 7.2x(10)-4 8.2x(10)-1

Note: The table assumes near-worst-case concentration of HCl, H2SO3 and H2SO4, as it does not

have any treatment of flue gas from oxy-fuel combustion, expect for ash removal and dehydration (see Table 3). The volume fractions also do not include the potential removal of sulphurous, sulphuric, and nitrous acids during the compression stage. Hence, the table presents a worst case scenario for acid production from oxy-fuel flue gases. The total acidity impact gives an upper bound estimate of the concentration of hydrogen ions which might be produced from each acid. The relative acidity is based

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on calculations under standard conditions and must be corrected to account for pressure and temperature at reservoir conditions—it is expected that the absolute acidity would increase under reservoir conditions due to higher pressure and temperature. Source: Handbook of Chemistry and Physics, 55th edition, 1974-75. See page D-130 and page D-119.

The geomechanical consequences of the chemically-induced changes in fractures and bulk rock petrophysical properties need to be assessed, since they will have an effect on long term storage stability and security. Geochemical reactions are highly site specific, depending on the precise mineralogy, fluid chemistry, pressure and temperature of the host formation. They are also strongly time-dependent, due to the wide range of reaction kinetics, and may also vary based on distance from injection well due to differences in temperature, pressure, and degree mixing with host formation waters. For example, injection of acidic components in rocks that have significant limestone content will lead to some of the acids will be neutralised and the rocks will act as a buffer. However, injection in mostly sandstone-based rocks would mean that there is very little buffer capacity and any formed acids will start attacking the cementitious material and weaken the rocks. On the other hand, buffering by mineral dissolution may significantly reduce the rocks’ mechanical strength, increase their permeability, and could be less effective depending on the gas stream velocities

and the mass flow of CO2 injected.

Hence, it is important for operators to conduct geochemical analyses of rocks and the associated fluids (i.e., chemical changes, dissolution, precipitation, and leaching of heavy metals) during the site characterisation phase (covered in Annex I of CCSD), as well as part of monitoring during operation and in the post-closure pre-transfer period.

Operators could also experimentally determine the impact of expected incidental substances on rock samples under simulated reservoir conditions. These tests could then be compared with theoretical expectations based on geochemical modelling as part of the site characterisations. These experimental tests along with modelling may

also indicate potential changes to the composition of the CO2 stream in order to

prevent negative impact on storage site integrity. It is to be noted that current understanding of how geochemical tests in the laboratory can be extrapolated to field measurements is still limited. Similarly, geochemical modelling is often subject to great uncertainty due to poor understanding of reaction kinetics and heterogeneity. Given the geochemical reactions that the CO2 stream would undergo, it is important to recognize that the composition of any leakage from the storage site would be different than the composition of the injected stream.

In addition to changes in geomechanical characteristics of the rocks, the different acids formed will also affect the integrity of wells. Bertos et al. (2004) reviewed accelerated carbonation technology in the treatment of cement-based materials and

sequestration of CO2. They found that certain heavy metals (Pb, Cd, and Ni) increase

the susceptibility of cementitious materials to carbonation, i.e., accelerate the deterioration of cement used in injection and monitoring wells at carbon sequestration sites. On the other hand, carbonation has been demonstrated to act

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positively in the immobilization of heavy metal-contaminated soils and other residues (Bertos et al., 2004).

Similar to the tests conducted on rock samples, it is important to empirically assess

and conduct geochemical modelling of the impact of the acids formed from a CO2

stream on materials used for wells during the operation and post-closure pre-transfer period.

The operator may also want to consider that some incidental substances (e.g., H2S

and SOx) are more soluble than CO2, and permeation rates of these substances

through the rocks could also be different relative to CO2. Therefore, there could be

variations in concentration of incidental substances at different locations within the

CO2 plume in a storage site. Furthermore, the concentrations of incidental

substances from a storage leak may be different than the concentrations in a pipeline leak.