**4. The prerequisites of CCUS**

A viable candidate for CCUS must meet a threshold well injectivity required to inject large volumes of CO2 at high injection rates through a minimum number of wells, adequate storage capacity to hold large volumes of CO2 and robust containment to permanently isolate the sequestered gas from the environment [16]. Storage capacity and well injectivity defines the storage potential of a geological storage facility [11, 46, 47].

#### **4.1 Storage capacity**

Implementation of CCUS technology require accurate estimation of the pore space available in the reservoir rock to hold the injected CO2 [48–51]. The storage capacity estimated can be of different levels of certainty and cost depending on the scale and resolution. The various CO2 trapping mechanisms in deep saline aquifers, namely structural and stratigraphic trapping, residual gas trapping, solubility trapping, mineral trapping and hydrodynamic trapping, which occur at different times during the storage, must be considered in the estimation to obtain a representative estimate [51]. Other parameters that affect the storage capacity include in situ pressure, injectivity, temperature, permeability, and rock compressibility.

The volume of CO2 that can be commercially sequestered in a reservoir within a specific period, using available technology, under current economic conditions, operating methods and governmental regulations has been termed the CO2 storage reserve [11, 48]. The USDOE [52] has developed a simplified model to quantify the storage capacity of deep saline formations which is given by:

$$M\_{\rm CO\_2} = V\_A \phi\_T \rho\_{\rm CO\_2} E\_s \tag{1}$$

In Eq. (1), *MCO*<sup>2</sup> is the mass of CO2 that can be stored, *VA* is the bulk volume of the aquifer, *ϕ<sup>T</sup>* is the effective porosity of the aquifer, *ρCO*<sup>2</sup> is the density of CO2 at reservoir conditions and *Es* is the storage efficiency. The storage efficiency expresses the degree of filling the reservoir [11], also defined as the ratio of the volume occupied by CO2 to the total accessible pore volume of the reservoir [53]:

$$E\_s = \frac{V\_{CO\_2}}{V\_{pore}} \tag{2}$$

In Eq. (2), *VCO*<sup>2</sup> is the volume of injected CO2 and *Vpore* is the accessible reservoir pore volume available for CO2 storage. Eq. (1) and (2) can be coupled to estimate the volumetric CO2 storage capacity of a given deep saline reservoir. CO2 storage

efficiency in deep saline formations depends on the reservoir rock properties (porosity, permeability, net to gross, thickness and area), the efficiency of water displacement by injected CO2 and the degree of conformance of the aquifer [11].

Bachu et al. [54] have also proposed a model to estimate the theoretical CO2 storage capacity of depleted oil and gas reservoirs, based on the assumption that the entire pore space originally occupied by hydrocarbons can be filled by CO2 and that CO2 can be injected until the reservoir pressure reaches the original pressure of the virgin reservoir. These assumptions can be valid if the reservoir is not in contact with an aquifer or already flooded during secondary and tertiary recovery. For practical purposes, an effective storage capacity could be defined to incorporate other important parameters such as displacement efficiency, gravity effects, residual oil and water saturation, reservoir heterogeneity, rock-fluid interactions, and formation damage.

## **4.2 Well injectivity**

The injectivity of a reservoir measures the amount of CO2 an injection well can receive without fracturing the formation [11]. Well injectivity can be expressed with an injectivity index, *I*, often defined as the ratio of volumetric injection flow rate to the pressure drop [55, 56]. For a homogeneous and isotropic reservoir, the steady-state CO2 well injectivity index can be expressed as:

$$I = \frac{q}{\Delta p} = \frac{\rho\_{CO\_2, \text{res}}}{\rho\_{CO\_2, \text{sc}}} \frac{2\pi kh}{\left[\ln\left(\frac{r\_c}{r\_w}\right) + s\right] \mu\_{CO\_2}} \tag{3}$$

In Eq. (3), *q* is the volumetric injection flow rate, Δ*p* is the pressure drop, *ρCO*2,*res* is the density of CO2 under reservoir conditions, *ρCO*2,*sc* is the density of CO2 under standard conditions, *kh* is the permeability-thickness product, *re* is the radius of the reservoir boundary, *rw* is the well radius, *s* is the skin factor and *μCO*<sup>2</sup> is the viscosity of CO2 under reservoir conditions. Well injectivity determines the number of wells required to inject a specific quantity of CO2 into the reservoir. This makes injectivity an important factor for both technical and economic evaluation of CO2 storage projects [56, 57].

#### **4.3 Containment efficiency**

Containment efficiency characterizes the assurance of containment of the injected CO2. The ultimate objective of a CCUS project is to permanently isolate the sequestered CO2 from the environment. Since formation water is denser than supercritical CO2, the CO2 plume tends to rise to the top of the reservoir, where it accumulates beneath the caprock. The containment efficiency of a geological trap is therefore strongly dependent on the seal potential or the ability of the caprock to confine the injected gas and prevent leakage into overlying formations and eventually back into the atmosphere [58]. The caprock must have the lateral extent and geomechanical strength to retain the full CO2 column height.

The integrity of the caprock could be compromised by mechanical deformation induced by pressure from CO2 injection or through geochemical CO2-rock-brine interactions which may dissolve or precipitate minerals to increase the permeability of the caprock [59]. Wells have also been identified as probable leakage pathways. Therefore, robust wellbore integrity is important to prevent leakage through wells.
