Carbon Capture and Storage in Depleted Oil and Gas Reservoirs: The Viewpoint of Wellbore Injectivity

Abstract

Recently, there has been a growing interest in utilizing depleted gas and oil reservoirs for carbon capture and storage. This interest arises from the fact that numerous reservoirs have either been depleted or necessitate enhanced oil and gas recovery (EOR/EGR). The sequestration of CO₂ in subsurface repositories emerges as a highly effective approach for achieving carbon neutrality. This process serves a dual purpose by facilitating EOR/EGR, thereby aiding in the retrieval of residual oil and gas, and concurrently ensuring the secure and permanent storage of CO₂ without the risk of leakage. Injectivity is defined as the fluid’s ability to be introduced into the reservoir without causing rock fracturing. This research aimed to fill the gap in carbon capture and storage (CCS) literature by examining the limited consideration of injectivity, specifically in depleted underground reservoirs. It reviewed critical factors that impact the injectivity of CO₂ and also some field case data in such reservoirs.

1. Introduction

Global warming is one of the main concerns of human beings currently and the global average temperature and sea level will reach 3.5 °C and 95 cm, respectively, by 2100 if the anthropogenic greenhouse gas (GHG) emissions continue to increase [1,2,3,4,5,6,7]. CO₂ accounts for ~64–76% of the total global GHG emissions and is one of the pollutants that endanger public health and welfare [6,7,8,9,10,11].

Several strategies have been introduced to reduce the carbon footprint, including shifting the energy mix to less carbon-intensive sources, reducing energy consumption, replacing fossil fuels with fuels that have shorter carbon chains, improving energy efficiency, and long-term carbon capture and sequestration in underground structures [5,6,12,13]. Among these, carbon capture and storage (CCS) has garnered attention because it decelerates the rate of the increase in atmospheric CO₂ concentrations [5,7,12,14,15,16,17,18,19,20,21,22,23]. CCS can contribute to ~12% of the global decarbonization target by 2050 and stabilize atmospheric GHG concentrations to ~450 ppm CO₂ eq by 2100 [5,7,12,14,15,16,17,18,19,20,21,22,23].

Deep saline aquifers, depleted hydrocarbon reservoirs, and hydrocarbon reservoirs of enhanced oil recovery (EOR) and enhanced gas recovery (EGR) projects, unmineable coal seams of enhanced coal bed methane (ECBM) projects, and salt domes/mined caverns are primary mediums of CO₂ sequestration [3,6,7,8,12,13,18,22,24,25,26,27,28,29,30,31,32,33,34]. CO₂ is trapped in these storage mediums via (i) structural trapping, where an impermeable caprock stops the CO₂ plume; (ii) capillary trapping, where CO₂ remains in pore spaces as residual CO₂ gas saturation; (iii) solubility trapping, where CO₂ dissolution produces dense CO₂-saturated brine; and (iv) mineral trapping caused by the reaction of minerals with CO₂-saturated brine [8,27,35,36,37].

Table 1. Evaluating geologically suitable storage reservoirs [Reproduced with permission [27] Copyright 2015 Elsevier].

Storage Option	Relative Capacity	Relative Cost	Storage Integrity	Technical Feasibility
Active Oil Well (EOR)	Small	Very Low	Good	High
Coal Beds	Unknown	Low	Unknown	Unknown
Depleted oil/gas wells	Moderate	Low	Good	High
Deep Aquifers	Large	Unknown	Unknown	Unknown
Mined caverns/salt domes	Large	Very High	Good	High

shows storage media based on their capacity, cost, integrity, and technical feasibility.

The majority of studies on carbon capture, and storage (CCS) focused on assessing the storage potential of deep saline aquifers; however, oil and gas reservoirs, despite their relatively smaller storage potential, are ideal for CCS owing to their high capacity, containment, reservoir structure, and surface facilities that can be adapted for CO₂ storage operations [3,4,27,38]. However, it should be noted that oil is considered as a hydrophobic fluid and has no harmful effect on pipeline walls, but CO₂ is a moisture content that in contact with water causes sweet corrosion in pipelines [39,40,41,42,43,44]. The facilities already existing are designed for hydrocarbons so it makes the CO₂ corrosion a significant problem in oil and gas production and transportation facilities that the cost of remediation can be higher than replacing the facilities [41,42,45,46,47].

Oil and gas reservoirs have also trapped hydrocarbons under caprock sealing for millions of years at high pressures, ensuring rock integrity for long-term CO₂ geosequestration with less environmental impact [48,49,50]. CO₂ sequestration in these reservoirs can provide an economic incentive, which is additional revenue from oil and gas recovered from CO₂ injection with EOR/EGR technology [7,51,52,53,54,55]. Technologies for CCS can increase the oil recovery through EOR/EGR up to 40%, whereas a recovery factor of 1–18% can be obtained after CO₂ injection in gas reservoirs [6,7,28,48,56]. A study using a Silurian core drilled from Door District in northeast Wisconsin, United States revealed an oil recovery of 34% during CO₂ flooding [57]. Studies conducted on gas reservoirs and CO₂–EGR field pilots have revealed that common depleted gas reservoirs have CO₂ storage capacities of 390–750 gigatons [51,58].

The feasibility of CCS operation mainly depends on adequate storage capacity and threshold well injectivity, which ensure that the desired amount of CO₂ is injected at acceptable rates through a minimum number of wells [3,5,29,59,60]. In other words, even with enormous storage capacities and high-quality overlying seals, CCS operation might not be financially viable without obtaining a minimum level of CO₂ injectivity into a formation [3,5,29,59,60]. Injectivity refers to the fluid’s ability to be injected into a geological formation, i.e., the rate at which it can be injected into a storage medium without causing caprock fractures [7,12]. An adequate CO₂ injectivity is a prerequisite for CCS projects and considerably influences their economics.

CO₂ injectivity is strongly affected by the interactions between injected CO₂ and rock minerals or fluids in storage sites [5,7,9,12,28]. Although CO₂ storage mechanisms in oil and gas reservoirs have been extensively studied, the implementation of CCS at a field scale is met with some limitations [12,27]. Moreover, although the storage and factors affecting oil/gas recovery have been explored, factors influencing wellbore injectivity in depleted hydrocarbon reservoirs remain understudied [12,27]. Herein, wellbore injectivity was investigated along with the main factors affecting the pressure build-up in CCS projects in active/depleted oil and gas reservoirs.

2. Factors Affecting the Injectivity of CO₂

Well injectivity issues are detrimental to CCS projects because large volumes of CO₂ must be stored for long periods in geological time scales [61]. CO₂ injectivity is mainly influenced by innate reservoir properties, residual gas/water saturation, residual oil/condensate saturation, injected fluid properties, mineral dissolution, salt precipitation, asphaltene precipitation, thermodynamic phase behavior of CO₂ in the wellbore, clay swelling, injection rate, and wettability alteration [7,9,12,27,60,62,63,64,65]. These factors and their influences on the wellbore injectivity of CO₂ geosequestration are discussed in subsequent sections.

2.1. Innate Reservoir Properties

CO₂ injection affects petrophysical characteristics, necessitating in-depth investigation [49]. Therefore, the innate reservoir properties that influence CO₂ injectivity were investigated herein: permeability, porosity, rock strength, composition of fluids, and heterogeneity level of the storage medium [12,18,66,67].

2.1.1. Permeability

Permeability is the ability of a porous medium to facilitate fluid flow and is measured in m² (in the metric system) or Darcy (D) or milli-Darcy (mD in the oilfield system) [68]. The permeability of a formation is closely linked to injectivity [7]. However, Effective wellbore permeability is also a critical parameter for estimating wellbore leakage potential, which significantly influences the CO₂ leak rate [69]. Given the close tie between well permeability and CO₂ leakage, quantitatively assessing well permeability uncertainty is crucial for evaluating CO₂ leakage risk [27,69]. Geochemical reactions as well as temperature can cause changes in permeability at both microscopic and mesoscale [9,70].

For effective CO₂ storage, low permeability is essential, but >100 mD is needed for good injectivity near the well [67]. However, the permeability of a medium should be low for permanent CO₂ storage assurance [67]. CO₂ flow in tight, low-permeability rocks is controlled by reservoir heterogeneity and permeability, which demand significant capillary pressure for CO₂ to penetrate the pores [48,71]. Positive total skin factor and wellbore permeability decline can result from partial penetration and formation damage [72].

Relative permeability significantly controls the injectivity, and pressure build-up in the reservoir [61,64,73]. CO₂ migration through caprocks involves a two-phase flow with capillary effects; however, measuring relative permeability curves is challenging due to low caprock permeability [62].

2.1.2. Porosity

Petroleum reservoirs are porous rocks containing hydrocarbons and connate water [68]. Porosity quantifies the pore volume relative to the total volume [68]. Naturally fractured reservoirs (NFRs) have matrices and fracture zones [68]. Matrices have higher porosity, whereas natural fractures (NF) have higher permeability [68]. The alteration of rock permeability and porosity is a case-specific phenomenon and is influenced by the composition of injection rate of fluid, rock mineral type, pore geometry, and thermodynamics [61].

2.1.3. Pressure

During CCS processes, a significant pressure difference between discharge and target pressure is created, which causes high storage density in depleted reservoirs [38]. Fluid injection into reservoirs is a complicated process, which is a thermoelastic, poroelastic, and chemoelastic coupled problem, and is accompanied by the state change of in situ stresses in reservoirs [19,27,62,74]. Considering the effect of injection on the storage site, changes in pore pressure have a direct impact on rocks’ poroelastic properties [27].

High reservoir pressure in CO₂ injection can lead to mechanical stress and deformation, impacting both the reservoir and caprock sealing, potentially reducing injectivity and emphasizing the importance of preventing reservoir pressure from surpassing caprock fracture pressure for maintaining CO₂ containment and evaluating seal integrity to prevent fracture initiation [22,67]. The amount of oil produced rises and the time it takes for gas to break through reduces with increasing CO₂ injection pressure [55].

According to a study on how reservoir depletion affects stress, as pore pressure drops during reservoir depletion, effective horizontal in situ stress rises by 50 to 80% [74]. CO₂ enhances oil recovery in low-permeability reservoirs due to low viscosity and miscibility [49]. The injectivity is also controlled by the integrity of well bores, the failure of which causes rapid escape of injected CO₂. In turn, the integrity of well bores also depends on the injecting pressure and the upper limit for injecting pressure.

2.1.4. Well Configuration

The reliability analysis of storage sites emphasizes seal capacity, geometry, and integrity as crucial factors [66,67]. The sealing effectiveness of faults, influenced by pore throat size and mineral properties like water-wettability, particularly benefits from minerals such as mica, muscovite, and phlogopite, enhancing the ability to contain CO₂ plumes [67]. By increasing the pressure during the injection, the normal stress on a fault surface decreases and can lead to mechanical breakdown (reactivation) [27]. Moreover, CO₂ leakage is a significant challenge in CCS, occurring through various pathways like casing-cement interfaces, cement-rock contacts, and degraded or fractured materials. Wellbore integrity is critical for preventing these leaks [75].

2.1.5. Heterogeneity Level of the Storage Medium

It is unknown how the storage reservoir’s injectivity is affected by compartmentalization and geological heterogeneities [9,66]. Geological heterogeneities are often classified into two main categories: the presence of alternating layers with varied mechanical properties, pore pressure, and/or lithology and permeability, and the presence of faults and compartmentalization within the specified storage reservoir [9,66]. Reservoir compartmentalization is influenced by fault structures and deposition history, impacting permeability between deposition units [9]. Existing faults and fractures before CO₂ injection may also enhance and/or postpone fluid migration rates [76]. This is the reason why it is included as a vital factor in fully understanding the locations, geometries, and permeabilities of the reservoirs [76].

The multiphase flow of CO₂-brine can be expressed in terms of permeability variation influenced by heterogeneity [77]. Storage capacity depends on heterogeneities and porosity; however, injectivity relies on petrophysical properties such as permeability [77]. Heterogeneities can cause unexpected outcomes in simulating injection processes and CO₂ plume behavior in storage reservoirs, especially in depleted oil or gas fields [9]. Remediation options include acid injection to create high-permeability pathways and surfactant formulations to alter wettability and counteract CO₂ trapping [9].

2.2. Capillary Trapping

Capillary trapping is a physical phenomenon in which CO₂ is trapped as residual gas saturation (SgrCO₂) in pore spaces due to capillary force [27]. Capillary trapping, a mechanism impacting injectivity, leads to residual CO₂ saturation in rock pores, influencing storage capacity [78]. The minimum saturation level at which gas can start to flow is called residual gas saturation [79]. In other words, injected CO₂ trapped in rock pores surrounded by water forms residual CO₂ saturation during capillary trapping [78]. When there is no mobility threshold above the saturation level, this parameter is equal to the residual gas saturation [79]. Residual gas in depleted reservoirs can increase or decrease storage capacity, and decrease brine mobility, density, and viscosity of gas mixtures when dissolved in supercritical CO₂ [67]. Based on a flooding experiment on four core samples (one composite and three Berea samples drilled from the Waarre C Formation in the CO₂CRC’s Naylor Filed) it was concluded that early on in the CO₂ injection process, residual natural gas in the depleted reservoir lowered the CO₂ injectivity [80].

2.3. Residual Oil/Condensate Saturation

After primary and secondary oil recovery, residual oil saturation in reservoirs often ranges from 50 to 60% of the original oil-in-place (OOIP) [56,81]. Higher oil saturation linearly decreases storage capacity, but at 40% oil saturation, storage capacity does not vary very much [73].

2.4. Fluid Properties

Carbon dioxide transitions between gas, liquid, and solid states based on temperature and pressure variations [7]. Low levels of residual gas, water, and condensate in the reservoir are required for efficient CO₂ injectivity [48]. Injecting supercritical or liquid CO₂ in low-pressure reservoirs may cause evaporation in the tubing or wellbore [4,48]. Some properties are presented in Table 2 and the following section to understand more about the effect of fluid properties on wellbore injectivity.

2.4.1. Viscosity and Density of Injected CO₂

Density and viscosity are crucial properties in the storage process, receiving significant attention for their impact on storage capacity and enhanced oil recovery rate [82]. The low-density gas phase reduces hydrostatic pressure, impacting flow stability and potentially causing cavitation during phase changes [7]. In the sites with a depth higher than 800 m, the pressures and temperatures reach above the critical points of 7.38 MPa and 31.1 °C, respectively, and CO₂ can be injected as a supercritical fluid [12,22]. Therefore, sequestering CO₂ in shallow reservoirs (<2600 ft. (800 m)) is discouraged because of nonsupercritical conditions, although such complexities can be avoided with an understanding of changing multiphase behavior [7]. Theoretically, CO₂ temperature at the injector well bottom correlates positively with CO₂ injectivity [18]. This is due to density and viscosity decrease with rising bottom hole temperature, enhancing CO₂ mobility and injectivity [18]. The density of the supercritical CO₂ is more like liquid, but the viscosity is like gas [71]. Furthermore, residual CH₄ in reservoirs alters supercritical CO₂ density and viscosity in pore space [48]. In a study conducted by Nicot, et al. [83] on the impact of viscosity on the geologic storage capacity in shallow depth, results showed that a decrease in viscosity of the CO₂ mixtures leads to approximately the same proportion loss in the storage capacity [83].

Above 31.1 °C and critical pressure, CO₂ is supercritical with a mass density of ~0.3−0.8 g/cm³ (less dense than coexisting brine), which is a crucial behavior for storage considerations [7,84]. CO₂’s higher density promotes the stability of displacement fronts, and its supercritical state enhances efficient subsurface storage [85]. CO₂ density influences hydrocarbon extraction; heavier hydrocarbons are extracted at higher densities [71]. In addition, the efficiency of CO₂ storage increases at higher CO₂ densities, enhancing safety by reducing the buoyancy force [12]. CO₂ density at reservoir condition (the temperature between 293 K and the pressure between 25 bar and 700 bar) can be estimated by [67]:

ρ = α + βT + γT² + θT³

(1)

α = (A₁ + B₁P + C₁P² + D₁P³)

(2)

β = (A₂ + B₂P + C₂P² + D₂P³)

(3)

γ = (A₃ + B₃P + C₃P² + D₃P³)

(4)

θ = (A₄ + B₄P + C₄P² + D₄P³)

(5)

In the mentioned equations, α, β, and γ are the temperature coefficients. P is the pressure in bar scale and T is the temperature in Kelvin. ρ is the density with the scale of kg/m³, and θ is the contact angle representing the medium wettability [67].

2.4.2. Injected CO₂ Purity

CO₂ can be captured from fossil fuel power plants but it comprises a variation of impurities such as N₂, NO_x, Ar, O₂, and SO₂ in different concentrations [86]. Injecting this CO₂ may affect the amount of storage in a geological medium [27]. According to Wang, et al. [87], who performed a study on the effect of H₂S and SO₂ on CO₂ injectivity, coinjecting impurities with CO₂ for storage is cost-effective, but impurities negatively affect transport, injection, and storage [87]. Acid impurities such as SO_x and NO_x react with rocks, impacting injectivity and storage integrity; hazardous impurities pose environmental risks in the case of a CO₂ leakage [87].

The coinjection of these impurities may also impact well injectivity and wellbore integrity, thereby reducing porosity, cap rock integrity, CO_2, and water containment altering formation salinity near the well and mineral composition in the reservoir [9,83,86]. It also affects static capacity by altering the density and viscosity of the CO₂ mixture [83]. Lower density impacts CO₂ capacity due to impurity space and generally lower impurity density [83]. Impurity type influences thermal front location, delineating the radial zone with significant induced reservoir cooling [88]. They have a more pronounced impact on plume shape at shallow depths [67]. Separating impurities before injection is crucial for maintaining storage capacity, and removing CO₂ moisture is necessary to prevent corrosion and hydration-related costs [67].

Impurity removal is expensive; therefore, their coinjection will considerably reduce the cost of CO₂ capture [86]. The cost of a CCS project depends on CO₂ separation, with the impurity level affecting storage capacity [59]. The higher the level of impurity, the lower the storage capacity for CO₂ and the lower the CO₂ injected [59]. In addition, injecting a pure CO₂ stream that is free of impurities and water, prevents corrosion and formation damage caused by insoluble iron precipitates, thereby preserving injectivity in porous media [89].

2.4.3. Injectant Temperature

Injectant temperature directly influences total horizontal stress, with lower temperatures reducing near-wellbore stress significantly [19]. Repetitive thermal loading can cause the failure of well barrier material, particularly in CO₂ injection wells that experience temperature variations from injected fluid and rock [21]. The temperature fluctuations can range from 15 °C to 25 °C and 6 °C to 7 °C for onshore and offshore transport, respectively [21]. Thermal stress-induced wellbore damage is influenced by factors such as injection and formation temperature, formation stress state, and the thermal/mechanical properties of well barrier materials [21].

Table 2. The impacts of fluid properties on wellbores injectivity.

Reference	Study Remarks
Jin, Pekot, Smith, Salako, Peterson, Bosshart, Hamling, Mibeck, Hurley and Beddoe [37]	CO2 saturated Mead-Strawn stock-tank oil at 135° F showed that the density of oil increases when CO2 is dissolved in the oil [90]. The gas storage rate in the Bell Creek oil field is linked to the injection rate, decreasing as the injection stabilizes.
Kazemzadeh, et al. [91]	The minimum miscible pressure (MMP) is the ideal pressure for cost-effective injection in oil recovery.
Barrufet, Bacquet and Falcone [59]	The duration of a project on a gas condensate fluid from the Cusiana field located in the northeast of Bogota, Colombia, in the Lianos basin is determined by injectivity, injection rates, and the number of wells; injection rates do not affect the eventual storage capacity.
Tawiah, Duer, Bryant, Larter, O’Brien and Dong [18]	Injection rates in reservoir rocks near the wellbore are influenced by injection pressures, fluid saturation, and fluid mobility.

Table 2. The impacts of fluid properties on wellbores injectivity.

Reference	Study Remarks
Jin, Pekot, Smith, Salako, Peterson, Bosshart, Hamling, Mibeck, Hurley and Beddoe [37]	CO2 saturated Mead-Strawn stock-tank oil at 135° F showed that the density of oil increases when CO2 is dissolved in the oil [90]. The gas storage rate in the Bell Creek oil field is linked to the injection rate, decreasing as the injection stabilizes.
Kazemzadeh, et al. [91]	The minimum miscible pressure (MMP) is the ideal pressure for cost-effective injection in oil recovery.
Barrufet, Bacquet and Falcone [59]	The duration of a project on a gas condensate fluid from the Cusiana field located in the northeast of Bogota, Colombia, in the Lianos basin is determined by injectivity, injection rates, and the number of wells; injection rates do not affect the eventual storage capacity.
Tawiah, Duer, Bryant, Larter, O’Brien and Dong [18]	Injection rates in reservoir rocks near the wellbore are influenced by injection pressures, fluid saturation, and fluid mobility.

2.5. Mineral Dissolution/Precipitation

Mineral dissolution/precipitation in CO₂ (supercritical) and water–rock interactions enhance CO₂ trapping and alter mineral surface wettability, which is crucial for residual trapping [16]. CO₂ injection induces mineral dissolution and precipitation determined via the compositions of the original formation water and rock samples [49,92]. Increasing temperature and decreasing fluid pressure led to reduced carbonate solubility and CO₂ degassing [93]. An increased concentration of Ca or Mg ions from the dissolution of rock can lead to the rapid mineralization of CO₂ [36]. CO₂ dissolution in brine for storage triggers mineral reactions, which transform reservoir mineralogy and influence petrophysical properties such as porosity and permeability [94,95]. Mineral dissolution (chemical mineral dissolution of pore-filling cements such as carbonate and anhydrite [94]) improves formation permeability [7,93,94,96], porosity [93,94,96] and the proportions of pore-exposed grain-rimming clay coatings [94]. Dissolution near the injection site may increase CO₂ storage capacity within the medium, increasing the amount of localized CO₂ storage [97], altering the transport of CO₂ [16], and inducing surface cracking, which can increase the reactive surface area [70]. Uniform mineral dissolution was observed during the simulation of pure quartz sandstone, with slow surface reaction during CO₂ injection into sandstone [98]. The porosity and permeability of the reservoir are increased when rock minerals dissolve, whereas they are decreased when carbonate or sulfate compounds precipitate [49]. Sokama-Neuyam and Ursin’s [99] study presents evidence that mineral dissolution negatively impacts CO₂ injectivity, reducing the efficiency of CO₂ injection. Injectivity impairment experienced a reduction of 9% when brine salinity was halved. The experimented sample belonged to Kocurek Industries, Caldwell, TX, USA, and the impairment of injectivity was measured via the pressure drop measurements [99].

Hydrated well cement, composed primarily of C-S-H and Portandite, is a reactive component in the near-well zone [95]. However, dissolved minerals that aggregate into fine particles in rock formations can enhance chemical reactions, causing pore throat blockage, reducing permeability, and impacting CO₂ mobility near plume boundaries [7,16,94,95]. Moreover, the permeability and porosity increase because of calcite [7], anhydrite [7,94], and carbonate dissolution; it also provides improved fluid pathways [94]. Pore throat sealing minimally affects total rock porosity but significantly deteriorates its permeability [94].

The main reactions that occur during the dissolution of CO₂ in water are as follows [98]:

CO₂ + H₂O ↔ H₂CO₃

(6)

H₂CO₃ ↔ HCO₃⁻ + H⁺

(7)

HCO₃⁻ ↔ CO₃²⁻ + H⁺

(8)

CO₂ dissolves into formation water and generates H⁺, $\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-},$ and $\mathrm{C}{\mathrm{O}}_3^{2-}$ ions, which then react with specific ions in the formation water and rocks [49]. The concentrations of $\mathrm{C}{\mathrm{O}}_3^{2-}$ and $\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-},$ are increased by a larger volume fraction of injected water and an increased Ca²⁺ content in the formation water [49].

2.6. Salt Precipitation

Salt precipitation due to water evaporation has been recognized both experimentally and numerically and proven to lead to the abandonment of wells [61,95]. Formation water that is rich in ions reacts with injected CO₂, vaporizing and precipitating salts in reservoirs [7]. Salt precipitation also occurs in gas condensate reservoirs [61] and is a longstanding issue in the gas and petroleum industry [100]. CO₂ partially dissolves in brine and vaporizes saline water [63]. Evaporated water increases brine salt content, potentially leading to halite deposition if the solubility limit exceeds (~26.5% by weight) [63]. If the salt concentration exceeds the solubility limit under reservoir conditions, minerals precipitate [63,101]. The precipitated salt fills the porous space and clogs the pore network of the formation, modifying the flow channels [7,63,101,102]. It can reduce porosity and permeability, change capillary forces, and cause injectivity loss around the wellbore [5,7,24,27,61,63,95,100,101,102,103] completely blocking the injection [101] and reducing oil/gas productivity [63]. The decrease in permeability reduces the overall porosity and affects the pore space geometry as well as the precipitate distribution within the pore space [101]. The impact of precipitation on permeability varies based on reservoir chemistry and pore structure [103].

Concentrated halite precipitation results from sufficient brine mobility caused by a capillary pressure gradient, which impacts injectivity [101]. Simulations demonstrated that even when dry CO₂ is introduced into a depleted gas reservoir that contains medium-salinity brine, halite can still precipitate [101]. In addition, the combined effect of salt precipitation and fine migration can decrease the permeability three-fold compared to salt precipitation alone [102].

Salt precipitation is high around the injection well because the fluxes, concentrations, and saturation gradients of injected fluids are highest [5]. Even minimal salt deposition near the injection zone can cause significant CO₂ injectivity impairment [5]. However, this effect varies based on initial liquid saturation [103]. With sufficiently mobile brine, the continuously recharged precipitation front that is driven by capillary pressure considerably reduces the formation permeability [103].

For reducing salt precipitation, the most common remediating injectivity method is to inject chemicals [9]. In addition, salt precipitation in production wells can be reduced by diluting produced water with low-salinity water downhole and in production systems [5].

2.6.1. Effects of CO₂ Flow Rate

A critical scCO₂ injection flow rate influences particle migration in porous media, affecting salt precipitation and permeability [102]. Evaporation rate, directly linked to injection rate, influences brine concentration; increased gas volumes enhance halite precipitation [63]. High CO₂ injection rates may detach formation fines, causing pore clogging and reduced injectivity [5]. Optimal brine salinity and injection rate mitigate salt precipitation efficiently [5]. Because of the availability of NaCl, solid saturation rises with initial brine saturation, except at very low rates (0.1 kg/s) [101]. Moreover, high injection rates create a higher pressure gradient, suppressing capillary backflow and reducing the possibility of intensive salt accumulation [100]. Injectivity significantly decreases to a low of 40% point at a CO₂ injection rate of >5 mL/min possibly due to the uneven mineral distribution of a Berea sandstone core with a diameter of 3.81 cm and length of 7.62 cm ± 0.05 [102].

2.6.2. Effects of Brine Salinity

Brine salinity intricately affects CO₂ injectivity and reservoir properties [63]. Initial brine salinity is crucial for determining the residual salinity and salt precipitation; it also influences porosity and reduces permeability [63]. Higher brine salinity increases both salt precipitation and permeability reduction [100]. Injectivity of the Berea sandstone cores improves with reduced brine salinity but declines below 21.102 g/L [102]. Significantly reducing brine salinity by almost half results in only a marginal 9% injectivity decline, highlighting nonlinear mineral precipitation and injectivity dependency [5]. Low brine salinity, such as LSW, induces colloidal particle detachment, causing pore bridging and reduced CO₂ injectivity [5]. Extremely low salinity may cause simulation deviations, causing chemical interactions and impairing injectivity [5]. The positive correlation observed between brine salinity and injectivity impairment emphasizes the importance of brine salinity in assessing the effectiveness of CO₂ injection [102].

2.6.3. Effects of Pore Size

Initial permeability considerably influences subsequent permeability losses during CO₂ injection; lower initial permeability causes more significant reductions in permeability [63]. Higher permeability rocks have larger, less susceptible pore throats; thus, the permeability decreases only slightly [63]. Moreover, the pore channel size plays a crucial role in the dissolution of precipitates [5]. The impact of precipitates on injectivity is expected to be more pronounced in low-permeability rocks due to the potential plugging of narrow pore channels, even with the same precipitation rate [5].

2.6.4. Effects of Particle Size

While the correlation between particle size and pore throat size is a crucial factor, there is a theoretical understanding that the concentration of the suspension may significantly influence plugging mechanisms [102]. This is attributed to the shortened distance between suspended particles as the concentration increases, thereby intensifying the multiparticle blocking of invaded pores [102]. Injected dry CO₂ induces persistent water evaporation and halite precipitation around the well [101]. Despite potential halite effects, a high CO₂ injection rate can mitigate injectivity issues depending on reservoir factors such as the formation’s characteristics, initial reservoir thermodynamic conditions, initial brine saturation, and salinity [101].

2.6.5. Effects of Water Saturation

Irreducible water saturation (Swi) determines the maximum relative permeability of CO₂; higher Swi results in lower maximum permeability [63]. A decrease in water saturation triggers brine capillary backflow, sustaining evaporation and precipitation [63].

2.6.6. Effects of Temperature

Elevated temperatures decrease water saturation and increase halite and salt precipitation in high-temperature gas reservoirs [63]. Rising temperature increases CO₂ phase water solubility, causing rapid saturation and salt precipitation [100]. Temperature only slightly impacts salt precipitation compared with factors such as injection rate and capillary pressure [100]. Numerical simulations were conducted to assess the dry-out process during CO₂ injection; however, the impact of halite precipitation on field operations could not be accurately predicted due to undefined relations between changes in porosity and permeability [103].

2.7. Asphaltene Precipitation

Crude oil is a complex mixture containing different hydrocarbons, primarily saturates, aromatics, resins, and asphaltenes (SARA) [56,104,105]. The most polar components are asphaltenes because they contain heteroatoms like oxygen, sulfur, or nitrogen, while saturated and aromatic compounds are nonpolar [55,106]. The stability of asphaltene depends on aromatic-to-saturate and resin-to-asphaltene ratios in crude oil [105]. Resins are an excellent bridging agent for all components of crude oil because they contain both polar and nonpolar sites [55,105,107].

Asphaltenes, the heaviest and most polar crude oil fractions, have a molecular weight of 100 to 10,000 g/mol [55,56,81,104,105,106,107,108,109,110,111]. They are composed mainly of carbon and hydrogen, with condensed aromatic rings surrounded by insoluble aliphatic chains [55,56,81,104,105,106,107,108,109,110,111]. While insoluble in light hydrocarbon solvents, asphaltenes are soluble in aromatics such as toluene and xylene [55,56,81,104,105,106,107,108,109,110,111]. They are generally incompatible with light petroleum fractions leading to undesirable effects in many stages of the petroleum industry such as pipeline routes, oil and gas production, and EOR/EGR [56]. The nature of asphaltenes is not clearly understood due to their complex nature and because various parameters affect their precipitation [56,104]. Thus, a universal model to predict and simulate their precipitation has not been developed yet [56,104,109]; their exact chemical structure also remains unknown [109].

Crude oil components are in equilibrium under reservoir conditions, but precipitation can occur due to pressure or temperature changes during oil field operations, such as high flow rates or gas introduction [55,104,107]. Asphaltene precipitation can be problematic and has caused major issues with flow assurance for the oil industry in recent decades [106,111]. For instance, when CO₂ is injected into the oil reservoir formation, the equilibrium state of the asphaltene–oil colloidal system in porous media is altered by variations in thermodynamic conditions, such as pressure (e.g., during primary depletion of highly under-saturated reservoirs [109]), temperature, asphaltene concentration, CO₂ content, oil composition, flow condition, and chemical additives; this results in a liquid-like solid precipitation with high viscosity [52,54,81,106,107,109]. Asphaltene precipitation can occur from reservoirs containing even very small amounts of asphaltene [107]. This will be far more severe when the reservoir pressure drops below the bubble point if the reservoir pressure is initially above the bubble point [55,104]. The molar volume of oil increases as the pressure decreases, subsequently decreasing the asphaltene solubility [105]. The maximum amount of asphaltene is precipitated at the bubble point [104,105] both with/without CO₂ injection [104] because of high amounts of dissolved gas by volume in oil [104,105]. In addition, precipitation is more at higher CO₂ injection rates [54].

The interaction coefficient between CO₂ and asphaltene is considerably higher than other components (natural gas and nitrogen [110]) with asphaltene [56,110]. Elevated CO₂ concentration increases the bubble point, precipitation, and interaction coefficient with asphaltene due to shared polarity [56,104].

Asphaltenes precipitated during CO₂ flooding, can either remain suspended or deposit onto surfaces, particularly high-specific-area clay minerals [28,52,54,55,56,81,104,105,107,109,110]. This deposition can lead to reservoir and wellbore pore plugging, reduced porosity, permeability, and CO₂ injectivity, and altered wettability from water-wet to oil-wet [28,52,54,55,56,81,104,105,107,109,110]. Formation damage and a negative impact on production efficiency may result from pressure drop increase and changes in pore surface wettability [28,52,54,55,56,81,104,105,107,109,110]. Precipitation also threatens the capacity of surface facilities by plugging tubular and flow lines and clogging production separators, such as damage to pumps [56,104,106]. Despite all these disadvantages, asphaltene precipitation yields oil with less asphaltene content [81,110], making it lighter and less viscous than crude oil [56].

The degree of asphaltene precipitation during CO₂ injection is influenced by factors such as injection method, pressure, and miscibility [55]. It also depends on the asphaltene content in crude oil, correlated with injected CO₂, reservoir conditions, pressure, and temperature [28,112].

2.7.1. Effects of Permeability

Asphaltene deposition reduces permeability [112] and improves oil displacement by water due to increased oil relative permeability [108]. In particular, permeability affects the stability of asphaltenes and has a significant impact on deposition [111]. Deposited asphaltenes are more stable and migrate significantly less in more permeable reservoirs [111]. With increasing rock permeability, the impact of asphaltene deposition on the decreasing core permeability and oil recovery reduces [113]. Oil reservoirs with lower permeability exhibit more severe formation damages caused by simultaneous sulfur and asphaltene deposition than those with higher permeability [112,113]. Permeability reduction fluctuates between 40% and 90%, influenced by fluid composition, porous medium pore structure, and proximity to the core inlet or outlet [111]. Maximum asphaltene precipitation was reported at the core inlet, with a linear relation between permeability-reduction factor and asphaltene amount [107].

2.7.2. Effects of Pore Size Distribution

The characteristics of crude oil, the pore-plugging mechanism, and the deposition process are all impacted by the size distribution of precipitated asphaltene [56]. The analysis of pore size distribution can be utilized to determine how much asphaltene deposition reduces permeability [112]. Pore size distribution must be determined to identify fluid transport properties of porous media [108]. With increasing pore sizes (pore diameter > 8 μm [111]), the weight percent of asphaltene decreased and the oil recovery rate increased [55,111]. Small pores (<8.0 µm [111] or 9.0 µm [112] in radius) showed higher sensitivity to more asphaltene deposition, indicating their significant contribution to reducing permeability [111,112]. Asphaltene precipitation in unconventional reservoirs may be more severe than in conventional reservoirs due to considerable differences in pore sizes [55].

2.7.3. Effects of Temperature

Temperature is recognized as a relevant parameter for asphaltene stability [106]. When the temperature is raised during the CO₂-EOR process, asphaltene from crude oil can become unstable since CO₂ is usually in a supercritical state [54]. In multiphase flows, low heat transfer increases asphaltene deposition depending on the concentration and velocity of reactants [28]. The temperature of the reservoir considerably influences the kinetics of asphaltene precipitation, controlling the precipitation onset time and the size of deposits [54].

Oil recovery increases with increasing temperature; however, CO₂ breakthrough time decreases due to low oil viscosity [55]. Higher temperature also leads to increased asphaltene weight percent in bypassed oil due to resin instability [55]. Moreover, the asphaltene precipitation onset point increases with CO₂ injection at higher temperatures, which also increases the solubility parameter difference value [114]. In contrast, lower temperatures with liquid CO₂ decrease asphaltene stability due to its nonpolar behavior [106]. At higher temperatures, when CO₂ becomes supercritical, polar–polar interactions are enhanced and asphaltene precipitation is reduced due to steric repulsion and increased side-chain motion [106].

2.7.4. Effects of CO₂ Concentration

The amount of asphaltene precipitation depends on the concentration of injected CO₂ gas and rapidly increases when the CO₂ concentration exceeds its critical value [107]. The formation of a gas phase can cause the asphaltene phase volume to reduce at very high CO₂ concentrations [109]. Maximum amounts of asphaltene precipitates were obtained at saturation pressure, which gradually increased with an increase in the mole of CO₂ gas [107]. Higher CO₂ concentration increases asphaltene precipitation in the single-phase region and bubble point [115]. At higher concentrations of injected gas and reservoir pressures above and below the bubble point, asphaltene precipitation increases [104].

2.7.5. Effects of Porosity

The porosity and asphaltene accumulation along the core are correlated [111]. Porosity decreases in response to any increase in asphaltene deposits in a particular core region, and vice versa [111]. When the injection pressure was roughly at the MMP, there was an increase in oil recovery from the smaller pores [112]. CO₂ penetrated the small pores during miscible flooding, improving the oil recovery [112]. This highlights how crucial the MMP is for improving oil recovery from small pores [112].

2.7.6. Effects of Pressure

Asphaltene precipitation increases with injection pressure [55,112,114]. By increasing the injection pressure, more CO₂ molar percentage is required to achieve asphaltene precipitation [114]. For samples of crude oil, there was a small increase in the mean asphaltene particle size as the pressure was raised [116]. In contrast, Lei, Pingping, Ying, Jigen, Shi and Aifang [52] reported that at a constant injection pressure, the asphaltene precipitate amount first increases and decreases as the injected CO₂ amount increases; the asphaltene precipitate amount reaches its maximum when the gas phase occurs in the CO₂–oil system [52].

2.7.7. Effects of Viscosity

The gas phase, the liquid phase rich in hydrocarbons, and the liquid phase rich in asphaltene have different viscosities depending on the phase composition, temperature, and pressure [109]. The dissolution of CO₂ in crude oil and reduction in its asphaltene content considerably reduce oil viscosity, thereby decreasing the weight percent of asphaltene [109]. This is one of the main reasons for lower amounts of oil production at higher viscosity [55]. The weight percentage of asphaltene showed a positive correlation with the rise in viscosity for both the oil extracted and the oil that bypassed the system [55].

2.7.8. Effects of Flow Rate

By increasing the CO₂ flow rate, pressure decreases considerably, indicating asphaltene deposition and permeability reduction [28,113,117]. Thus, by reducing the flow rate, the formation damage can be considerably reduced when producing crude oils with medium and high contents of sulfur and asphaltene [113].

2.8. Fine Mobilization

Mobile particles with an equivalent diameter of <40 μm are known as fines [9]. They are assumed to be initially located on the surface of quartz grains [118]. The nonswelling and swelling clays that detach from the pore-grain interface can migrate [9,119]. Fines mobilize through chemical or mechanical interaction with pore fluid, including clay swelling and fluid flow-induced mobilization [9]. During CO₂ injection, fine particles are lifted into the reservoir and possibly plug the pore channels depending on the petrophysical characteristics of the rock, particle sizes, hydrodynamic conditions, solid concentrations, reservoir properties, and ionic strength and/or pH of the carrying fluid [7,9,60,89,94,95,120,121]. Born repulsion, electrical double-layer repulsion, and London–van der Waals attraction contribute to the potential energy that characterizes fine detachment [122]. The short-range potential known as the Born repulsive potential is created by the electron clouds’ overlap [122]. Fines can originate in the injected fluid due to its contamination by contact with casing cement, drilling fluid filter cake residue on the wellbore wall, or from the formation itself [9,60,94]. The result of experiments on the Berea core sample with permeability (60–100 mD) and porosity (19–20%) showed that fines mobilization harms injectivity more than drying or high salt concentration [60].

The critical salt concentration (CSC) is defined as a specific salt concentration at which the fine particles may be released [122]. It can impair formation permeability (which some laboratory observations suggest may be permanent [119]) by blocking/bridging the pore throats [7,60,94,118,120,121] and productivity [7], but negligible porosity change [121]. Significant injectivity reduction could be caused by minor particles in the pore fluid or wellbore fluid in the immediate injection area [9,60,94].

The modeling of fine migration and effects of mineral dissolution can be expressed by [123]:

$$\frac{k}{k_0}=\frac{1}{[1+{\beta }_s{\sigma }_s-\beta (\phi -{\phi }_i\left)\right]}$$

(9)

where β and β_s are the dissolution coefficient and the formation damage coefficient, respectively, and σ_s is the volumetric concentration of retained fines [123]. Their values for the same brine salinity can be achieved by Wang, Bedrikovetsky, Yin, Othman, Zeinijahromi and Le-Hussain [123]. k and k₀ are permeability and initial permeability, respectively. φ is defined as porosity and φ_i is the initial porosity [123].

Well impairment can lead to many challenges, including the possibility of an uncontrolled rise in cap rock pore pressure above the permissible fracturing pressure, the start and spread of fractures, and preferred flow pathways for CO₂ leaks [120]. Injectable wells may need to be abandoned in severe cases [120]. Clogging caused by fine release, migration, and capture is commonly considered an irreversible process [120]. However, some remedies can be suggested such as high injection velocities for deposition away from the wellbore due to radial flow because of the radially divergent nature of the injection flow [9]. In addition, greater permeability impairment is caused by core plugs with higher clay contents, most likely as a result of larger clay particles and smaller pore throats that make blocking and bridging easier [121]. Injecting at higher permeability intervals may further reduce the possibility of injectivity loss [121]. Clay fines can only detach when the pore space’s salinity falls below a particular critical salinity, which can be prevented by raising the injected water’s salinity above the CSC [119].

2.8.1. Effects of Permeability

In typically highly permeable sandstones, fine migration has been studied as the main cause of permeability decrease [9]. The injectivity will rapidly decrease due to a decrease in permeability resulting from increasing pore pressure [120]. Until the permeability is restored through additional physical or chemical treatments, the fluid can no longer be injected into the damaged formation at the required high flow rates [120]. A decrease in permeability implies that higher pressure will be required to inject the fluid into the formation, causing changes in injectivity [7]. The low-permeability reservoir rocks showed a more noticeable decrease in permeability [121]. Therefore, low-permeability reservoirs show lower injectivity loss [7,121]. Even within a short timeframe, changes in reservoir permeability affect injectivity, productivity, and CO₂ flow dynamics, impacting saturation distribution [120].

2.8.2. Particle Concentration

Particle concentration considerably affects CO₂ injectivity [7]. The concentration of fine particles in the fluid has a direct impact on the deposition rate [28]. The interaction between the particle and the pore throat increases as the particle concentration rises [7]. CO₂ injectivity impairment increased with an increase in the concentration of fine particles [7,60].

2.8.3. Injection Rate

Injectivity loss increased with increasing CO₂ injection rate [7]. Turbulence from a higher flow rate makes the particle stack tighter and enables their even redistribution in the pore network [7]. In contrast, Sokama-Neuyam, Ginting, Timilsina and Ursin [60] concluded that the CO₂ injection rate did considerably influence the reduction in CO₂ injectivity induced by fine entrapment [60]. However, at high injection velocities, the strong fluxes may dislodge the particles bridging the pore channels, opening some of the clogged channels [60]. The fluid’s density, the square of its velocity, viscosity, and compressibility, as well as the size and form of the particles, all affect how much force is needed to raise them [60]. Hydrodynamic force acting on the particles is increased by supercritical CO₂’s gas-like viscosity and liquid-like density [60]. Typical CO₂ injection rates under storage conditions are approximately 1 Mt/pa [60].

2.8.4. Particle Size

Particle size and pore constriction, or more pertinently, the size of the fine particle to pore constriction, is crucial for determining the entrapment or piping mechanism occurring in the pore throat [7,60]. The larger the size of the particle, the higher the injectivity loss [7].

2.9. Clay Swelling

Many targeted geological storage sites are sealed by shale or mudstone rich in clay minerals such as sandstone gas reservoirs, which are heterogeneous and mainly composed of clay minerals and silica with small amounts of carbonates [35,58,124,125]. Clays are interlayer aluminosilicate minerals that have different structures [58]. They are crucial for the geological storage of CO₂ [126]. CO₂ is stored for a long term by overlying caprocks that act as low-permeability barriers to upward fluid flow [17,124,125,126,127].

Clay minerals are generally <1 mm in diameter and are therefore known as micro to nanocrystalline materials [128]. Clay minerals’ layered structure and atom arrangement give them a platy morphology [128]. Illite, chlorite, smectite, and kaolinite are the main types of clay found in typical sandstone rocks [58]. A property that sets swelling clay minerals apart from other clays and micas is their easy interchangeability with the surrounding environment [125]. Of the different common rock-forming minerals, calcite is the most reactive because of its high solubility and kinetics [24]. These rocks are frequently composed of smectites, or expanding clays like montmorillonites, which are frequently found in faults that laterally seal possible storage reservoirs at depths and temperatures of up to 3.5 km and 100 °C, respectively [17,124]. At greater depths, smectites generally begin to transform into nonswelling clay minerals [124]. Smectites, a mixed layer of illite and smectite, and a mixed layer of chlorite and smectite are most sensitive to water and are hydrophilic [129]. These minerals, when present in the pore network, can drastically reduce the intrinsic permeability [129]. When the clay is exposed to solutions containing cations, the present cations may be exchanged with other cations [129]. The highest amount of total cations in clays that can be exchanged with a solution of a particular pH is known as the cation exchange capacity of clays [17,129]. The different capabilities of CO₂ adsorption and selectivity of mixed clays are caused by a variety of elements in clay structures, including cation exchange capacity (which is low in nonswelling forms such as kaolinite), charge on the clay surface, and interlayer distance [58]. Smectite clays are often used as samples due to their high swelling capacity [129]. The quantity and thermodynamic properties of water in the system have a significant impact on the intercalation and retention of CO₂ in smectite interlayers [130]. Illite and kaolinite, not known for interlayer expansion under any experimental conditions, can adsorb significant amounts of CO₂ [17]. If the surface area of the clays contacting the solution is large, the activities of divalent cations may be reduced either via sorption onto clay surfaces or via cation exchange [128]. Clays also increase the adsorption capacity of sandstone rocks because of their high surface area [58].

Clay swelling is a major cause of damage formation in hydrocarbon reservoirs and can substantially reduce nanoparticle mobility in porous media [127]. It can cause substantial changes in the reservoir structure, blocking the swelling pores, and causing dynamical behavior of the intercalated fluid molecules concerning the bulk fluid phase [17,125,130]. Another way to clog pore throats and reduce injection rates is by the mobilization of detrital or diagenetic clays [67]. The term “swelling clay” is derived from the ability of clay particles to increase their molar volume, thereby shrinking or contracting the interlayer pores based on the migration of polar molecules, such as water or organic molecules, into and out of the interlayers [9,124,125,127,130]. This migration depends on the clay mineral type and its hydration state [9,124,125,127,130]. The impact of clay swelling is most severe when incompatible fluids (e.g., oil) come in contact with swelling clays, leading to reduced formation permeability [127]. The same phenomenon is observed in the presence of CO₂ in brine solution or in contact with resident brine [9,131]. CO₂ can laterally displace the fluid and brine from the rock to assist in the intercalation of other chemical species in the clay, particularly during the early stages of injection [35,125,130].

The long-term efficacy of impermeable cap rocks in sealing the reservoir against the leakage of injected CO₂ needs further evaluation [125]. To ensure a safe CO₂ injection into reservoir formations, caprock failure and subsidence must be prevented, and the overlaying caprock must operate effectively [132].

2.9.1. Effects of Pressure

Pressure and temperature changes do not impact the clay nanoscale structure, suggesting stable seal quality during CO₂ injection [84]. At lower pressures, the CO₂ adsorption selectivity is enhanced, whereas at higher pressures, the adsorption amount increases [53]. Nonswelling clays can exhibit swelling under high pressure and temperature with CO₂ and water coexistence [133]. Supercritical CO₂ can alter capillary entry pressure in swelling clays, affecting injectivity, and may reduce long-term CO₂ storage capacity due to mineral dissolution and precipitation [9,131].

2.9.2. Effects on Strain

Because of the strain that the intercalated molecules may produce, the pore can swell or shrink [133]. Strain changes induced by CO₂ injection are considerably larger than those from pore-pressure changes alone [132,133]. CO₂ injection initially increases the strain rapidly and then stabilizes [35]. Strain changes vary spatially due to sedimentary structure, with local low-porosity layers acting as barriers [35]. Swelling strain rapidly increases with CO₂ pressure and decreases at higher pressures [17]. Linear strain is the length change relative to the initial length, and volumetric strain is the volume change relative to the initial volume [134]. Swelling strain can be predicted when micropore volume is known [133].

Material strain varies with the consolidation state [132]. Consolidated conditions exhibit higher strains than overconsolidated conditions due to microstructural differences [132]. Larger strain changes are observed due to CO₂ adsorption, particularly in kaolinite-rich rock [35]. Moreover, swelling strain can be substantial, leading to differential matrix swelling during brine displacement [35]. CO₂-induced swelling stress in Na-SWy-1 montmorillonite decreases as the effective stress and burial depth increase [124].

2.9.3. Effects of Temperature

At higher temperatures, CO₂ adsorption on sandstone rocks decreases [58]. Bandera sandstone showed the least reduction due to favorable CO₂ adsorption conditions on carbonate minerals [58]. By increasing the treatment temperature, the aromatic and aliphatic hydrocarbons in clay-rich shales are reduced [131]. Hot CO₂ injection doubles natural gas production and improves CO₂ sequestering in depleted gas reservoirs [58].

2.10. Hydrate Formation

The expansion of CO₂ is linked with the Joule-Thomson phenomenon, potentially causing the formation of dry ice or hydrates, consequently diminishing the injectivity of CO₂ [4]. Hydrates are formed due to the interaction of water with CO₂ and gaseous hydrocarbons such as methane during injection into depleted reservoirs [89]. Such formations depend on specific conditions such as injection rate, pressure, and lower temperatures [89].

Figure 1 compares the impact of injectivity loss with cases involved with salt deposition, mineral dissolution, fine migration, hydrates, and also without injectivity disruption [89].

In Figure 1 case 1 was modeled using the following reaction in CMG simulators [89]:

Halite ↔ Cl⁻ + Na⁺

(10)

The value for case 2 was obtained from modeling the below reactions based on the reservoir rock mineralogy of a sample composed of 1.1% Calcite and 0.4% Dolomite [89].

Calcite + H⁺ ↔ Ca²⁺ + HCO₃⁻

(11)

Dolomite + H⁺ ↔ Ca²⁺ + Mg²⁺ + 2HCO₃⁻

(12)

Case 3 was calculated from reaction (11) and in the case of hydrate, it was modeled in CMG-STARS assuming that the permeability of the block was zero from the initial hydrate formation time [89]. Injectivity decreased to 73% from the base case in specific conditions [89].

3. CO₂ Injectivity in Field Cases

This field case study aimed to improve a general understanding of CO₂ injectivity into depleted hydrocarbon reservoirs by analyzing practical examples. The results are expected to provide concrete insights and useful recommendations to those who lead the responsibility of influencing environmental and energy management. However, the rapidly evolving confidential matters in CCS political settings may have resulted in uncertainties, leading to the potential for outdated information.

3.1. Niagaran Pinnacle Reef Oil Field

In the depleted pinnacle reef fields in Michigan, USA, CCS operations are performed by the Midwest Regional Carbon Sequestration Partnership (MRCSP) [135,136,137,138]. In the Michigan Basin, there are several hundred pinnacle reef structures, including this field [136]. It is a pinnacle reef that is late Silurian in age and has undergone significant primary and secondary recovery phases [136]. The shallow shelf carbonate depositional system that covered the Lower Peninsula of Michigan, northern Indiana, northeastern Illinois, eastern Wisconsin, northwest Ohio, and the Bruce Peninsula of Ontario gave rise to the reefs along the Niagaran Pinnacle Reef Trend oil fields [135].

MRCSP studies an extensive reef trend with over 880 closely spaced, highly compartmentalized, and laterally discontinuous reefs (Figure 2) [138]. The northern reef trend is divided into gas, oil, and water zones [138].

3.2. Netherlands Fields

The Netherlands leads the European Union in natural gas production with over 190 exploited gas fields. Fields in mature or depleted phases in the Netherlands are used for CO₂ storage [139]. Induced seismicity affects 15% with ML w3.6. CO₂ storage in depleted gas fields is favored due to proven seal quality and there is no record of seal integrity failure due to fault reactivation in seismically active Netherlands [139]. The most suitable sites to store CO₂ are depleted gas fields (79%), followed by aquifers (19%) [139].

The number of wells, injection rates, duration of the project, and reservoir thickness and depth all affect drilling costs [23]. The costs increase linearly with the length of drilling up to a 3 km depth [23]. After 3 km, costs increase exponentially with depth [23]. The injectivity index assesses the ability of wells to inject fluids into a porous, permeable formation in petroleum reservoir engineering [140]. The injectivity index is the ratio of injection rate to pressure difference [140]. Because data are not available for every site, average injection rates based on the stratigraphic unit were utilized instead of site-specific injection rates (

Table 3. The average CO₂ injection rate of hydrocarbon fields per stratigraphic unit in Mt/y per well [Reproduced with permission [23] Copyright 2010 Elsevier].

	Formation	Hydrocarbon Field
Lower Cretaceous Group	Vlieland Sandstone Fm	1
Lower Germanic Trias Group	Lower Buntsandstein Fm	0.4
Niedersachsen Group	Friese front Fm (sandstone members)	0.4
Upper Rotliegend Group	Zechstein Fm (carbonate members) Slochteren Fm (sandstone members)	0.2 1
Limburg Group		0.4

) [23].

3.3. Malaysia

Malaysia explores CCS to cut greenhouse gas emissions and environmental impact [141]. Malaysia’s largest gas field was drilled with about 20 wells and they are largely depleted [142]. The structure of the field is defined by a mild anticline, exhibiting a typical north–south orientation [142]. The average porosity of the reservoir exceeds 26%, and its permeability is favorable at an average of 1000 mD for CO₂ storage [142].

Fractures may initiate during injection if pressure surpasses the caprock fracture threshold [33]. To address the challenges with injectivity, the optimal injection rate must be determined before field-scale injection [50]. CO₂ injection within safe limits prevents formation damage from fine migration in heterogeneous formations around the wellbore [50]. By maintaining injection below the critical limit, considering rock permeability, wellbore formation damage can be prevented [50].

3.4. Goldeneye

Goldeneye, a depleted gas field and platform in the northern North Sea, UK, was operated by Shell (2004–2011) about 100 km northeast of Moray Firth, Scotland [143,144]. This site is ideal for CO₂ storage because of factors such as young facilities, a dedicated pipeline, excellent Darcy sandstone quality, and good containment [145]. This storage site is located at 58°0′10.8″ N, 0°22′48″ W, and has a 120 m water depth [144]. The seafloor, besides pipelines and offshore platforms, is mostly flat with occasional pockmarks and abandoned wells [144]. The current infrastructure facilitates cost-effective appraisal and expansion into connected saline aquifer systems near or overlying the Goldeneye field [145].

Depleted field storage projects may stop injection below preproduction pressures to ensure containment and address uncertainties in capacity [146]. In cases such as Goldeneye, the “pressure-sink” effect acts as a risk-mitigating factor, causing water to flow back into the pressure anomaly [146]. Demonstrating long-term stability for site closure in the EU, particularly with potential pressure increases, can be challenging [146].

3.5. Cranfield

The depleted deep clastic Cranfield field in southwestern Mississippi, USA, presents potential for CCS operations [34,64,146,147]. From its discovery in 1943 until 1966, oil was produced there [34,64,146,147]. In 2008, the EOR CO₂ injection project began [34]. At a depth of 3300 m, the Detailed Area Study (DAS) pilot project aims to reach the Cretaceous Lower Tuscaloosa Formation [34]. The CO₂ injection pilot, which commenced on 1 December 2009, began at ~175 kg/min; the value was increased to ~300 kg/min after 20 days and ~500 kg/min after 156 days [34]. Over 31/4 years, approximately 3 million metric tons of CO₂ have been injected into the Cranfield field [148]. The CO₂ injection zone in the Lower Tuscaloosa Formation forms a four-way anticline with a diameter of 6.4 km (4 mi), shaped by an inactive salt dome [147].

Injected CO₂ flow rates are directly proportional to its relative permeability, which is a crucial parameter [34]. Low gas relative permeabilities lead to slower CO₂ plume spreading and increased pressure build-up [34]. Moreover, salt precipitation from water evaporation may impact injectivity, thereby increasing the CO₂ flow and reducing the porosity [149]. Pressure build-up is yet to be quantitatively determined [149].

4. Conclusions

The assessment of injectivity is vital for the secure sequestration of CO₂ in targeted depleted reservoirs. This study addressed various factors affecting injectivity and presents field case data. It was concluded that hydrophysical, chemical, and geo-mechanical processes significantly influence injectivity. The reviewed papers in the literature highlight that asphaltene precipitation, mineral dissolution, and fine mobilization can disturb injectivity by causing core plugging. Additionally, properties like purity, density, and viscosity of injected CO₂ play a crucial role in ensuring effective injection and storage.

A comprehensive understanding of diverse trapping mechanisms and the adept modeling of CCS in depleted reservoirs is mandatory for achieving successful CO₂ injection. Therefore, it is advisable to pursue further research in this domain.