**5. CO2 well injectivity impairment mechanisms**

CO2 injectivity impairment is a technical and economic constraint on geological storage of CO2 [12, 60, 61]. Under typical storage conditions, several factors could influence CO2 injectivity because of the complex interplay of chemical and physical phenomena in the reservoir, especially in the injection area of the wellbore [46, 62, 63]. The injection area of the wellbore has the highest flactuations of temperature, pressure and flux, making it one of the most important sections of the formation for well injectivity impairment analysis. Lombard et al. [64] identified three main mechanisms responsible for CO2 injectivity impairment: Geochemical, geomechanical and transport phenomena (**Figure 1**). Later Torsaeter et al. [65] did an extensive review on other CO2 injectivity impairment mechanisms that they recommend should be given close attention in addition to salt precipitation effects. The geochemical mechanisms involve CO2-brine-rock interactions, mineral dissolution, and precipitation. The transport effects include drying of the reservoir rock and fines mobilization. The geomechanical effects, which include borehole deformation has not been given enough research attention compared to the geochemical and transport mechanisms. These phenomena depend on the physical and chemical properties of injected CO2 which are in turn driven by reservoir conditions and rock properties.

### **5.1 Geochemical effects**

### *5.1.1 Effect of mineral dissolution*

Mineral dissolution and salt precipitation are the two main geochemical CO2 injectivity impairment mechanisms [64]. The injected CO2 could dissolve in formation brine at the CO2-brine interface, altering the concentration of aquifer fluid, thus leading to precipitation. Regardless of rock composition, the progressive dissolution of CO2 in the brine (formation water) forms carbonic acid that leads to a reduction in pH to about 3–5 [66, 67]. The following reactions occur at the interface between both media

$$\begin{aligned} \text{CO}\_{2(g)} + \text{H}\_2\text{O}\_{(l)} &\leftrightarrow \text{H}\_2\text{CO}\_{3(aq)}\\ \text{H}\_2\text{CO}\_{3(aq)} &\leftrightarrow \text{H}^+\_{(aq)} + \text{HCO}^-\_{3(aq)} \end{aligned} \tag{4}$$

Interactions between CO2 and brine forms carbonic acid and then bicarbonates. In the presence of CaCO3, MgCO3 and FeCO3, the following reactions would lead to formation of water-soluble bicarbonates.

$$H\_2O + CO\_2 + CaCO\_3 \rightleftharpoons Ca(HCO\_3)\_2$$

$$H\_2O + CO\_2 + MgCO\_3 \rightleftharpoons Mg(HCO\_3)\_2\tag{5}$$

$$H\_2O + CO\_2 + FeCO\_3 \rightleftharpoons Fe(HCO\_3)\_2$$

Moreover, the bicarbonates could react with cations in the rock and formation water to form stable carbonates which later could aggregate into small particles or form a scale on the pore walls [68–70]. CO2-brine-rock batch reaction under typical storage conditions have shown various amounts of dissolved minerals in solution [70–73].

Wang et al. [74] investigated mineral dissolution and precipitation in dolomite samples saturated with carbonated water at 93° C and 34.5 Mpa under static conditions. They found that mineral dissolution is predominant in highly permeable pathways in the reservoir rock. Zou et al. [75] conducted CO2–brine–rock reactions under different conditions to investigate the changes of porosity and permeability during sCO2 – fracturing in shale reservoir. They reported that CO2–brine–rock reaction could occur rapidly (in less than 0.5 h), precipitating minerals such as calcite, dolomite, K-feldspar, and albite into solution. Zhang et al. [76] investigated CO2-brinerock reaction in a tight sandstone reservoir under conditions of 75°C and 32MPa. They found that the dissolution of supercritical CO2 in brine created an acidic environment which induced the dissolution of minerals into the brine, leading to precipitation of iron minerals and kaolinite. Tang et al. [77] studied the impact of CO2-brine-rock interaction on formation properties in gas zone and water zones of a reservoir under static and dynamic conditions. They found that CO2-brine-rock interaction occurs in both gas zones and water zones. Aminu et al. [78] investigated the effect of CO2 and the presence of impurities (NO2, SO2, H2S) on reservoir permeability in static CO2-brine-rock reactions. They found that the presence of impurities affacts the impact of mineral dissolution on rock permeability. Okhovat et al. [79] investigated the effect of CO2-water-rock interaction on rock permeability and oil recovery during CO2 injection into a carbonate rock. They found that the extent of damage induced was a function of the injection rate.

*CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation… DOI: http://dx.doi.org/10.5772/intechopen.104854*

#### **Figure 2.**

*Pressure drop profile recorded during injection of carbonated water into a Bentheimer core at flow rate of 0.25 mL/ min at 80 bar and 60°C [80].*

Under static conditions, mineral dissolution could increase rock permeability temporally as new pore spaces are etched and old pore channels could be widened [64]. However, mineral precipitates could aggregate into fine particles in the pore fluid which could form a scale on the pore walls and reduce the flow area.

Sokama-Neuyam et al. [80] conducted experiments to investigate the effect of mineral dissolution on CO2 injectivity using clay-rich Bentheimer Sandstone cores. The cores were flooded with carbonated water at 80 bar and 60°C with about 25 pore volumes (PV) of carbonated water at 0.25 mL/min. Pressure drop profiles recorded during the flooding is shown in **Figure 2** and SEM-EDS analysis of effluent samples collected are shown in **Table 1**.

**Figure 2** shows a period of immiscible displacement, where pressure drop decreased sharply from about 0.1 bar to about 0.04 bar after the core was flooded with


**Table 1.**

*EDS elemental analysis of effluent samples collected during carbonated water flooding into Bentheimer core.*

about 3 PV of carbonated water. As the displaced FW is replaced with the less dense carbonated water, the pressure drop falls sharply until carbonated water breakthrough at the effluent end of the core. Pressure drop was stabilized from about 3 PV to about 7 PV. In this period, the core is fully saturated with carbonated water, leading to stable flow. Unstable flow sets in from about 7 PV to the end of the test. In this period, the pressure drop is seen to rise sharply and fall to a rather haphazard behavior towards the end of the test. The EDS results in **Table 1** shows the effluent sample is composed predominantly of Na (17.53%) and Cl (29.79) which are probably the components of the effluent brine. The results also reveal the presence of minerals such as Fe, Si, Al, Ni, and Co which were not present in the saturating brine and the injected carbonated water. Therefore, Fe, Si, Al, Ni, and Co were most likely dissolved from the Bentheimer core through the interaction of the carbonated water and the rock minerals. The EDS analysis show low amounts of Fe, Si, Al, Ni, and Co, because only few particles were likely to be washed out of the core.

#### *5.1.2 Effect of salt precipitation*

Salt precipitation is an existing injectivity challenge in natural gas wells. Kleinitz et al. [81] reported field observation of severe halite-scaling during natural gas production. Similar field experiences have been reported during injection, storage and production of natural gas [82–84]. In the context of field CO2 injection, Baumann et al. [85] and Grude et al. [86] have reported evidence of salt precipitation effects in the Ketzin pilot reservoir and the Snøhvit field, respectively. More recently, Talman et al. [87] investigated drying and salt precipitation effects in a CO2 injection well at the Aquistore site. Downhole images taken from the injection well, together with recovered samples revealed that scales of salts have formed on the inside of the injection well.

Miri and Hellevang [12] identified the processes leading to salt precipitation as: (1) immiscible two-phase CO2-brine displacement; (2) vaporization of brine into the flowing CO2 stream; (3) capillary back-flow of brine towards the inlet; (4) diffusion of dissolved salt in the porewater; (5) gravity override of CO2; and (6) salt selfenhancing. While results from numerical modeling work reported by Roels et al. [88] suggested that precipitated salt could accumulate far from the wellbore, several research works [89–91] show that precipitated salt accumulates near the wellbore. Permeability impairment between 13 and 83% and porosity reduction between 2 and 15% have been reported from laboratory core-flood experiments [92–97]. These experimental findings have been found to be consistent with theoretical and numerical simulations [61, 98–100].

Pruess and Muller [89] suggested that pre-flush of the injection region with freshwater could reduce salt precipitation. However, Kleinitz et al., [81] have shown that freshwater injection could not mitigate salt precipitation if the flow area is completely plugged by solid salt. Fresh water also has a high tendency to react with rock minerals, leading to other injectivity impairment challenges such as clay swelling.

Sokama-Neuyam [101] grouped the mechanisms of salt precipitation into two successive processes: salt cake development at the injection inlet and drying effects. Salt cake forms on the surface of the core inlet during early stages of brine vaporization prior to drying. As drying commences, salt precipitates into pore spaces in the dry-out zone.

Sokama-Neuyam [101] investigated the development of salt cake on the surface of the injection inlet. They flooded a Bentheimer sandstone saturated with about 120 g/L *CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation… DOI: http://dx.doi.org/10.5772/intechopen.104854*

#### **Figure 3.**

*Photographs of Bentheirmer core after CO2 was injected at 1 mL/min into the core initially saturated with 120 g/L NaCl brine. (A) No salt cake observed at the core outlet. (B) Massive salt cake found at the injection inlet. (C) the entire core remains wet [101].*

NaCl brine with about 100 PV of dry supercritical CO2 at a rate of 1 mL/min. **Figure 3** shows photographs of the rock taken during inspection. In **Figure 3A**, we observe that no salt was formed at the core outlet. **Figure 3B** shows massive salt cake deposition at the core inlet and **Figure 3C** shows that the entire length of the core was still wet. They reported that salt cake formation at the injection inlet was caused by (1) High brine salinity and (2) Poor brine displacement at the injection inlet.

Furthermore, there are similarities between the increasing trend of injectivity impairment expressed by salt precipitation in Sokama-Neuyam [101] and those described by Yusof et al. [102, 103]. In their study, they examined the effects of brine salinity and brine type on CO2 injectivity changes. They found that the injectivity reduction increased almost linearly between 6 and 27.3% as the brine salinity increases from zero to 100,000 ppm. The increasing growth of salt precipitation which reduced the porosity and effective flow area was identified as the main cause of the downtrend of CO2 injectivity. It was also reported that the sandstone core saturated with monovalent salt such as NaCl and KCl was heavily impaired by salt precipitation as compared to the sandstone core filled by the divalent salt system (CaCl2). However, these findings may be somewhat limited by constant brine salinity of 30,000 ppm.

Moreover, to investigate the effect of drying, Sokama-Neuyam [101] flooded a Berea sandstone core initially saturated with NaCl brine with about 300 PV of supercritical CO2 at a rate of 1 mL/min until the core was completely dried. The permeability of the core after drying was measured and a relative injectivity index*β* which measures the injectivity of the core before and after impairment was calculated. They then repeated the test at injection flow rate of 5 mL/min and 10 mL/min, keeping all other parameters constant, to study the effect of injection flow rate. **Figure 4** shows

#### **Figure 4.**

*Effect of drying and salt precipitation on CO2 injectivity. Injectivity impairment, β increased with decreasing CO2 injection rate.*

results of injectivity impairment induced by drying and salt precipitation at varying CO2 injection flow rates.

From **Figure 4**, it was observed that CO2 injectivity was impaired by about 36% for drying rate of 1 mL/min. Injectivity impairment decreased from 36% to about 25% when drying rate was increased to 5 mL/min and remained practically unchanged when the drying rate was further increased to 10 mL/min. Several researchers [94, 96, 104, 105] have earlier reported CO2 injectivity impairment within a range (13–83%) that is in agreement with the these figures. During drying and brine vaporization, when the concentration of brine exceed supersaturation, salt precipitates into the pores in the dry-out region as also observed by Zuluaga et al. [106]. The deposited salts reduce the CO2 flow area, impairing permeability and injectivity.

As drying progresses, a saturation gradient is established which draws more brine into the dry-out region through capillary backflow. Capillary backflow of brine leads to more salt deposition in the dry-out region. The capillary backflow of brine increases with decreasing drying rate because at high CO2 injection flow rates, viscous forces overcome capillary forces. Therefore, less salts are precipitated in the dry-out region at high injection flow rates, inducing low injectivity impairment as observed in **Figure 4**. Injectivity impairment did not change when drying rate was further increased from 5 mL/min to 10 mL/min because at these injection flow rates, the resident brine is quickly swept out of the core, leaving out only immobile brine for salt precipitation.

During injection of dry supercritical CO2 into brine-saturated sandstone cores, the dry-out region close to the injection inlet, extends into the core as more CO2 is injected. The effect of extension of the dry-out zone on CO2 injectivity is vital for understanding the underlying mechanisms of brine vaporization and salt precipitation. Sokama-Neuyam et al. [107] conducted experimental and theoretical study to investigate the development of the dry-out zone and estimate the impact of extension of the dry-out region on CO2 injectivity. **Figure 5** shows the impact of the advancing dry-out zone quantified by a dimensionless dry-out length, *ld* on CO2 injectivity impairment *β*. From **Figure 5**, CO2 injectivity impairment peaked at the onset of drying. Injectivity impairment decreased to a minimum at*ld* of about 0.45 and then rose slightly as the dry-out zone approached the core effluent end. At the *CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation… DOI: http://dx.doi.org/10.5772/intechopen.104854*

#### **Figure 5.**

*The impact of the dry-out length (Ld) on CO2 injectivity impairment (β) induced by salt precipitation. Magnitude of injectivity impairment increased when brine salinity was doubled from 75 g/L to 150 g/L but successive changes in injectivity impairment was not influenced by change in brine salinity [107].*

start-up of drying, two mechanisms could impair CO2 injectivity: salt precipitation and relative permeability effects. Brine vaporization rate is at its highest close to the inlet region because of the high capillary driven back-fluxes. As more brine is vaporized, more salt is precipitated into the pores which in turn increased the resistance to flow in this region. As the drying front advances into the core, brine vaporization and salt precipitation decreased as most of the brine were drawn into the inlet region by capillary backflow, leaving the remaining section of the core with less amount of brine available for salt precipitation. When the core is almost completely dried, brine vaporization and salt precipitation in around the effluent end of the core are almost negligible.

To meet the global CO2 emission reduction target, large injection rates will be required. Thus, after salt precipitation, there is continuous injection of CO2 into the reservoir. The effect of drag forces on the deposited salt was studied by Sokama-Neuyam et al. [108]. A Berea core sample was initially vacuum saturated with FW and vaporized to complete dryness to precipitate salt into the pores. The liquid CO2 permeability of the core and pressure drop across two sections of the core were measured with a pressure-tapped core holder. The core was then flooded with about 150 PV of supercritical CO2 at a constant injection rate of 2.5 mL/min. During this period of CO2 injection, drag forces were expected to act on the precipitated salts. Permeability and pressure drop across the same sections of the core was measured after CO2 flooding. **Figure 6** shows permeability change induced by the effect of drag forces on precipitated salts at varying injection rates.

The net drag force exerted by supercritical CO2 on precipitated salts depends strongly on the volumetric injection flow rate (*v*), increasing with increase in flow rate. The precipitated salts are held to the pore walls mostly by gravitational and electrostatic forces offered by the complex pore structure and rock minerals. If drag forces overcome these attractive forces, the accumulated salts could be dislodged or redistributed in the pores, altering the permeability as a result. The magnitude of permeability change should therefore be proportional to the drag force which in tend depends on the injection flow rate.

CO2 alternating Low Salinity Water Flooding (CO2-LSWAG) is a promising EOR technique [37, 38, 109, 110]. Sokama-Neuyam et al. [97] investigated CO2 alternating

#### **Figure 6.**

*The impact of CO2 injection flow rate on the effect of drag on permeability after salt precipitation. Permeability change is the difference between the core permeability after salt precipitation and before drag test and the permeability after drag test [108].*

**Figure 7.**

*Effect of diluent brine salinity on CO2 injectivity change induced by alternate injection of supercritical CO2 and LSW [111].*

low salinity water injection as a potential technique to mitigate salt precipitation effects on CO2 injectivity. After salt precipitation, a slug of diluent was injected to dissolve the precipitated salts, thus temporarily improving CO2 injectivity. The diluent used was low salinity water (LSW) which was prepared by diluting FW to lower brine salinity. **Figure 7** shows injectivity improvement obtained as a function of mass fraction of salt (*Xs*) in the diluent brine.

In general, CO2 injectivity improved from 8.66 to 31.62% when the mass fraction of salt in the diluent,*Xs* was decreased stepwise from 8.44 to about 2.11. The solubility of precipitated minerals in the diluent LSW increased with decreasing brine salinity, because, as the brine is further diluted, more free water molecules become available to interact with the precipitated salts. At*Xs* ¼ 1*:*06, injectivity dropped significantly and the experimental data deviates dramatically from the simulation results, signifying additional injectivity impairment other than salt precipitation. At this point, the diluent starts to interact chemically with the rock minerals. Interaction between rock minerals and the diluent could induce clay swelling and colloidal transport, which have the tendency to aggravate CO2 injectivity impairment.

### **5.2 Transport effects**

The mechanisms of fines migration and the impact of particle transport on the petrophysical properties of reservoir rocks have been previously researched. Khilar and Fogler [112] presented the mechanisms of colloidal and hydrodynamic induced release of fine particles in porous media. Muecke [113] investigated parameters controlling the movement of fine particles within the pore spaces. They identified the pH and salinity of formation brine, flow rate and temperature as some of the underlying parameters. Khilar and Fogler [114] asserted the existence of a critical salt concentration below which the pore fluid could weaken the Van der Waal's forces holding fine particles to the pore walls. Gruesbeck and Collins, [115] investigated the effect of hydrodynamic forces on the release and transport of fines. They identified a minimum interstitial velocity for fines entrainment. The effect of two-phase flow and rock wettability on fines entrainment has been experimentally investigated by Sarkar and Sharma [116]. They found that, the wettability of the core could affect the extent and rate of permeability impairment induced by migratory fines. Analytical models have been developed by Sharma and Yortsos [117] to investigate the mechanisms of size exclusion and quantify the effect of particle entrapment on rock permeability. Many other studies of fines migration in porous media under various conditions have been reported [118–120]. A thorough analysis of formation damage induced by migratory fines can be found in Civan [121].

We have already discussed that geochemical CO2-brine-rock reaction could generate secondary minerals into the pore fluid [73, 122, 123]. In addition, CO2-brine interactions could alter the pH of formation fluid which could induce the release of formation fines from the pore walls [115, 124]. While flowing with the injected fluid, the mineral particles could clog pore channels and impair injectivity. Whether entrapment or piping of fines will dominate the flow depends on characteristics of the generated fine particles, the porous medium and the permeating fluid in which the particles are suspended [125–127]. Pore structure, the size and concentration of the minerals and the hydrodynamic and colloidal conditions of the suspending medium could also affect their impact on CO2 injectivity. Under radial flow conditions, plugging effects could be limited to the near well region where fluxes are highest.

The general mechanisms of fines mobilization in porous media have been well researched and understood. However, the unique properties of supercritical CO2 including its gas-like viscosity and liquid-like density [128] coupled with the expected high CO2 injection rates required to meet global emission reduction targets and the drying effect of supercritical CO2 makes fines mobilization under CO2 injection conditions a unique challenge that must be investigated separately. Adaptation and extension of previous general findings on fines migration is required to understand the mechanisms and impact of fines migration within the context of CO2 injection.

Sokama-Neuyam [80] conducted core-flood experiments to measure the effect of dissolution on injectivity. A Berea sandstone core sample with known permeability was initially saturated with FW, and then flooded with about 25 PV of carbonated water at 80 bar and 60°C at constant injection rate of 0.25 mL/min to release and mobilize fine particles in the rock. The permeability of the core after carbonated water flooding was measured, and injectivity impairment index, *β*, was calculated. The experiment was then repeated at injection flow rates of 0.5 mL/min and 1.0 mL/min. **Figure 8** shows injectivity impairment decreased with increasing carbonated water injection flow rate.

#### **Figure 8.**

*Effect of injection flow rate on injectivity impairment induced by fines plugging. Injectivity impairment decreased with increasing carbonated water injection flow rate [80].*

As injection flow rate is increased, the resident time of carbonated water in the rock is shortened. The number of fines generated will then decrease as the injection flow rate is increased. In addition, at high injection flow rate, hydrodynamic forces could lift smaller particles out of the core with the effluent fluid. The number of fines available to plug the rock, and therefore the chances of injectivity impairment, will reduce as carbonated water injection flow rate is increased. Up to 26% injectivity impairment was induced by mineral dissolution and fines mobilization during carbonated water injection into the Berea sandstone cores. Injectivity impairment decreased as injection flow rate was increased.

Sokama-Neuyam et al. [129] attempted to quantify and compare the individual effects of fines mobilization and salt precipitation on CO2 injectivity. Mono-disperse colloid solutions were used to represent the pore fluid containing particles after mineral dissolution. A Berea sandstone core sample was initially saturated with mono-disperse colloid solution with average particle size of 0.08 μm and particle concentration of 0.3 wt.% and flooded with about 40 PV of supercritical CO2 at 5 mL/min to complete dryness. The relative injectivity change, β, was calculated from the permeability of the core measured before and after it was exposed to mineral impairment. The experiment was repeated for particle concentrations of 0.5 and 1.0 wt.%. **Figure 9** shows injectivity impairment induced as a function of composition of the pore fluid.

In **Figure 9**, while salt precipitation reduced injectivity by about 26.8%, particle concentration of 0.3 wt.% impaired injectivity by 74.9% through fines mobilization. About 1.0 wt.% of particles in the pore fluid almost plugged the rock. When CO2 invades the pores, the mono-disperse particles could plug the narrow pore channels through bridging, surface deposition, or multi-particle blocking. As particle concentration increases, the distance between suspended particles shortens, enhancing multi-particle blocking of the invaded pores. On the other hand, precipitated salts coat the pore walls to reduce the flow area. While salt precipitation reduces the flow area, fines entrapment could plug and isolate the flow path, making them inaccessible to fluid flow. The results suggest that, under linear flow conditions, fines mobilization could induce severe CO2 injectivity impairment comparable to the impact of salt precipitation.

*CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation… DOI: http://dx.doi.org/10.5772/intechopen.104854*

**Figure 9.**

*The relative impact of fines mobilization and salt precipitation on CO2 injectivity. Fines migration had a more severe impact on injectivity compared to salt precipitation [129].*

#### **5.3 The coupled effect of salt precipitation and fines mobilization**

Preliminary theoretical studies suggests that fines mobilization could compound CO2 injectivity impairment induced by salt precipitation [80, 101]. After salt precipitation, the deposited salt reduces the pore spaces, increasing the jamming ratio of particles being transported in the flowing stream. A schematic diagram that summarizes the role of mineral dissolution, salt precipitation and fines migration mechanisms on CO2 injectivity impairment is shown in **Figure 10**. Salt precipitation increases the susceptibility of the rock to fines entrapment. Sokama-Neuyam et al. [131], developed a dynamic core-scale model based on experimental observations to investigate the coupled effect of fines mobilization and salt precipitation on CO2 injectivity. The effect of brine salinity, initial core permeability and the order of coupling were studied. **Figure 11** shows injectivity impairment induced by the combined effect of particle entrapment and salt precipitation compared to the effect of only fines mobilization.

#### **Figure 10.**

*Schematic diagram of mineral dissolution, salt precipitation and fines migration mechanisms during CO2 injection into saline aquifer [130].*

**Figure 11.** *Effect of fines mobilization compared to coupled effect of salt precipitation and particle entrapment [131].*

Generally, injectivity impairment induced by particle entrapment increases with average particle size in the inlet fluid, *rp*. For the base case (No salt), particles less than the average pore radius (6 μm) did not induce significant injectivity impairment. These particles generally piped through the pores as they have a jamming ratio less than 1.0. As *rp* increases, more pores attain a jamming ratio greater than 1.0 and are plugged and isolated. As more pores are plugged and isolated, the flow area available to injected CO2 decreases, impairing the injectivity. **Figure 11** also shows that coupling particles entrapment and salt precipitation increases CO2 injectivity impairment significantly with the severity of impairment increasing with initial brine salinity. The deposited salt reduces the pore spaces and increases the jamming ratio. Particles that could pipe through the clean pores would be entrapped after salt precipitation. Thus, salt precipitation could compound the effect of fines mobilization on CO2 injectivity.
