**5.3. Literature review on EOR/EGR-CO2**

CO2 storage studies started almost two decades ago. Despite this fact, still vast areas of research have not been covered in detail in the area of coupled enhanced oil recovery with CO2 sequestration [28].

DeRuiter et al. [22] studied the solubility and displacement of heavy crude oils with CO2 injection; they have found that the oils exhibit an increase in density due to CO2 solubility. The two samples in their study with API gravities of 18.5 and 14 exhibited an increase in density upon CO2 dissolution.

Morel et al. [29] and Le Romancer et al. [30] studied the effects of diffusion of nitrogen (N<sup>2</sup> ) and CO2 on light oil using an outcrop core system. During 2010, Jamili et al. [31] simulated these previous experiments. These authors reported that diffusion was the main mass transfer mechanism between the matrix and fracture during nitrogen (N2 ) injection. On the other side, CO2 experiments conducted have shown that both diffusion and convection were important mechanisms.

Mehrotra and Svrcek [32–34] during the 1980s reported extensive experimental data on the dissolution of carbon dioxide on different bitumen samples in Alberta reservoirs. Their experimental data confirm a higher solubility of carbon dioxide in bitumen, and they found that this solubility increases as the injection pressure increases.

using carbon dioxide have been practiced for more than 50 years; the results revealed that

which is a great problem in enhanced oil recovery [15]. Furthermore, at high pressures, CO2 density has a density close to that of a liquid and is greater than that of either nitrogen (N2

or N2

and its low price compared with

into fluid. In the past, there are a

may be less likely to precipitate asphaltene,

less prone to gravity segregation compared with N2

sequestration is the mechanism of fluid density increas-

injection has been ignored [18–21]. However, as shown

has an effect on the density of fluid that is pres-

) injection. On the other side, CO2

in the EOR process. Moreover,

)

or

into crude

solubility. The

) and

experi-

compared to CH4

 **dissolution**

ment in oil recovery. Among these mechanisms include a high dissolution of CO2

fluids that are present in the reservoir, creating favorable mechanisms that can make enhance-

oil via mass transfer followed by the following aspects: an increase of oil density, a reduction of the viscosity of the original crude oil, vaporization of intermediate components of the oil,

set of studies that have not taken the effect of density increase from mixing into account; this

ent in the reservoir [22, 23]. Its dissolution and mixing leads to density increase followed by density-driven natural convection phenomena. There are several published studies which reported that this phenomenon has a significant enhancement in hydrocarbon recovery and

 storage studies started almost two decades ago. Despite this fact, still vast areas of research have not been covered in detail in the area of coupled enhanced oil recovery with

DeRuiter et al. [22] studied the solubility and displacement of heavy crude oils with CO2

two samples in their study with API gravities of 18.5 and 14 exhibited an increase in density

 on light oil using an outcrop core system. During 2010, Jamili et al. [31] simulated these previous experiments. These authors reported that diffusion was the main mass transfer mechanism

ments conducted have shown that both diffusion and convection were important mechanisms.

Morel et al. [29] and Le Romancer et al. [30] studied the effects of diffusion of nitrogen (N<sup>2</sup>

injection; they have found that the oils exhibit an increase in density due to CO2

is injected into the reservoir, it interacts physically and chemically with rocks and


6–15% of original oil in place can be recovered by these kinds of processes [14].

other hydrocarbon solvents are the incentives for the use of CO2

The low saturation pressure of CO2

248 Carbon Dioxide Chemistry, Capture and Oil Recovery

**5.2. Oil recovery mechanisms by CO2**

The main scenario followed by CO2

mechanism in the modeling of CO2

sequestration potential [24–27].

sequestration [28].

dissolution.

between the matrix and fracture during nitrogen (N2

in other studies, this may not be true; CO2

**5.3. Literature review on EOR/EGR-CO2**

or methane (CH4

a reduction of CO2

CH4 [16].

CO2

CO2

CO2

upon CO2

When CO<sup>2</sup>

a mixture of hydrocarbon solvents with CO2

), which makes CO2

sion, and an improvement of reservoir permeability [17].

ing caused by the dissolution and mixing of injected CO2

Darvish et al. [35] performed a set of experiments of CO2 injection in an outcrop chalk core saturated with oil and was surrounded by an artificial fracture at reservoir conditions. These authors observed the production of gas enriched with methane at an early stage. Next, the amount of intermediate components increased in the production stream, and during the end of the experiments, the heavier components were recovered. Their results were also confirmed by simulation study performed by Moortgat et al. [36].

Malik and Islam [37] conclude that in the Weyburn field of Canada, horizontal injection wells have showed to be efficient for CO<sup>2</sup> -flooding process to improve oil recovery while increasing the CO2 storage potential. Besides employing horizontal wells, Jessen et al. [38] have applied different well control techniques including completion equipment for both injection and production wells, at the same time improving the amount of injected and stored CO2 as well as enhancing oil recovery.

Recently, Li-ping et al. [39] conducted an evaluation study around Ordos Basin in Yulin city of China; this Basin was divided into 17 reservoirs and is considered as the first largest lowpermeability proliferous onshore basin in China with proved reserves more than 10<sup>9</sup> t. These authors conclude that Ordos Basin has good geographical and geological conditions for CO2 storage, and it has nine reservoirs suitable for CO2 immiscible flooding and eight reservoirs suitable for CO2 miscible flooding. The average incremental oil recovery ratios for immiscible and miscible flooding are 6.44 and 12%, respectively.

The booming development and production of shale gas largely depend on the extensive application of water-based hydraulic fracturing treatments. Hence, high water consumption and formation damage are two issues associated with this procedure. More recently, Pei et al. [40] investigated the feasibility of using CO2 for reservoir fracturing and enhanced gas recovery (EGR) in order to reduce water usage and resource degradation, guarantee the environmental sustainability of unconventional resource developments, and create new opportunity for CO2 storage. This study shows that this proposed CO2 -EGR process was mostly like to be successful in the Barnett shale reservoir, but there are some scientific and engineering questions that need to be further investigated to push the proposed technology to be applicable in practice.

Song investigated the effect of operational schemes, reservoir types, and development parameters on both the amount of incremental oil produced and CO2 stored in high water cut oil reservoirs during CO2 water-alternating-gas (WAG) flooding by running a compositional numerical simulator. The author's study shows that the five-spot pattern is more suitable for WAG flooding. Appropriately expanding well spacing improves the economic efficiency, even though the recovery factor decreases slightly. In addition, oil price, rather than CO2 injection cost, is considered as the parameter that impacts the economic efficiency of WAG flooding more significantly [41].

Er et al. [42] investigated the effect of injection flow rate of CO<sup>2</sup> on oil recovery using synthetic micro-scale fractured system saturated by normal decane (n-C10). The authors concluded that for immiscible CO2 displacement, the amount of oil trapped in the system was reduced as well as increasing injection rates of carbon dioxide. They also observed that for miscible CO2 conditions, higher CO2 injection rates yielded faster oil recovery.

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Coal bed methane is also tested for enhanced gas recovery and CO2 storage; Blue Creek and Pocahontas are two fields of coal bed methane in USA. Pashin et al. [43] employed a diverse suite of well testing and monitoring procedures designed to determine the heterogeneity, capacity, injectivity, and performance of mature Blue Creek coal bed methane reservoirs. A total of 516 m3 of water and 252 t of CO2 were injected into coal in a battery of slug tests. The author's results demonstrate that significant injectivity exists in this reservoir and that reservoir heterogeneity is a critical factor to consider when implementing CO2 -enhanced methane recovery programs. Based on the study by Grimm et al. [44], CO2 -CBM project can be conducted in the stratigraphic interval below the Hensley Shale where this confinement horizon is greater than 183 m below the surface and is above the level of hydraulic fracturing in CBM wells.
