**3.2 CO2-EOR injection consideration**

There are two main groups of considerations for CO2-EOR, namely technical and economical (fiscal) considerations. CO2-EOR injection technical consideration involves a complex engineering and differs from reservoir to reservoir. A detailed description of reservoir field and prospect of miscibility must be taken into account before considering CO2-EOR injection. Usually, the key parameters used in the technical consideration are remaining oil in place, minimum miscibility pressure, reservoir depth, oil API gravity, and formation dip angle.

In offshore fields, there are more factors that need to be considered. Firstly, the separation of CO2 from the produced gas is the ideal choice if the CO2 source is not in the vicinity of the field. Next, at high CO2 concentrations, there is a need for the facilities and operation to process the gas [21]. This is because CO2 becomes acidic as it is injected into the (formation) water and causes corrosion of the equipment in the offshore environment. If the fields are using CO2-WAG processes, then the facilities need to be compatible with acid that could be generated so that the corrosion in the facilities could be prevented [20–22].

Verma et al. [29] studied the parameters that affect the efficiency for increasing the production of methane gas on Marcellus shale and concluded that the gas production can be increased by 7% with the optimal spacing between injection and production well. It can be concluded that the natural fracture permeability is the dominant factor to improve the production of methane. As the fracture half-length increases, the methane production increases and the possibility of CO2 breakthrough also increases. The down side of this process is the cost as well as a high risk of leakage and the field pollution. This is due to the fact that the injecting of CO2 can degrade the gas production as a result of the mixing initial gas in place with the injected CO2 [30]. Due to the miscibility of CO2 and the natural gas, their physical properties were potentially ideal for reservoir re-pressurization. For instance, CO2 has higher density and lower mobility ratio compared to methane. Hence, CO2 will sink in the reservoir; this can stabilize the displacement process between the injected CO2 and the methane initially in place.

Reservoir heterogeneity and solubility of CO2 in formation brine could also play a major role in causing early CO2 breakthrough to the production wells. The latter could be delayed, by re-pressurizing the reservoir [26, 31]. Generally, due to the benefits of CO2 injection to gas reservoir, CO2-EGR could be potentially efficient and therefore an attractive option in spite of a bigger investment required as compared to CO2 injection into oil reservoirs. Nevertheless, it can extract more hydrocarbons as compared to oil reservoirs.

The reservoirs must be subsequently screened for economic consideration based on standardized capital costs and operation expenses that are representative of the reservoirs under consideration. Wei et al. [27] found that the total crude oil recovery potential along with CO2 storage resource and net income for enterprises can be increased if the price of crude oil is high and the price of CO2 and tax is low. The cumulative cost-effective oil production varied between 0.3 and 1.3 billion tons (2.1 and 9.1 billion barrels). This is consistent with research reported from Appalachian basin region, which suggests that CO2-EOR may be economically feasible in the study area when oil prices are \$70/STB or higher [28, 32]. However, the economics of onshore CO2-EOR will face an undesirable impact due to complex geological properties, high viscosity of crude oil, high royalty rates, technology limitations, and the lack of incentives for CO2-EOR projects. Overall, a miscible CO2-EOR process is preferred considering all the technical and economical evaluations as detailed as possible.
