**4.6 Effect of presence of oil (CCS in oil reservoirs)**

CO2 can also be injected into depleted oil reservoirs although storage capacities are much smaller than in aquifers (IPCC 2005). It is estimated that 50 Gt of CO2 can be stored in this way worldwide (Firoozabadi and Cheng 2010) which is roughly 1.5 times of what is emitted per year. So this is clearly not the solution to mitigate global warming, however CO2 solubility in oil is very high, up to 60-80 mol% of CO2 can be dissolved (De Ruiter et al. 1994, Kokal and Sayegh 1993, Emera and Sarma 2006, Firoozabadi and Cheng 2010).

CO2 solubility generally increases with pressure and it is higher at lower temperatures. If the temperature is below the critical CO2 temperature (Tc = 304.13 K), then CO2 solubility increases until the CO2 liquefaction pressure is reached (circa 5.88 MPa), then it levels off

a1 28.9447706 -0.411370585 3.36389723E-4 a2 -0.0354581768 6.07632013E-4 -1.98298980E-5

a8 -0.307405726 -0.0237622469 2.12220830E-3 a9 -0.0907301486 0.0170656236 -5.24873303E-3

In a deep saline aquifer or oil reservoir high pressures and elevated temperatures are found. The pore pressure at depth is usually assumed to be equal to the hydrostatic pressure; a typical hydrostatic pressure gradient is 10.35 MPa/1000m (Dake 2007). In addition a geothermal gradient exists, the reservoir temperature increases with depth. Average typical geothermal gradients are 25-30 K/1000 m (Fridleifsson et al. 2008). Average temperatures and pressures at depth are listed in Table 2, they were calculated assuming typical pressure and temperature gradients and a surface temperature of 293 K. The surface temperature needs to be adjusted for each specific geographical location, e.g. average temperature is low in Norway (average temperature throughout the year is around 281 K) while average yearly

As stated above CO2 solubility decreases with increase in temperature, but increases with increase in pressure. In Table 2 CO2 solubilities calculated with Duan's web based CO2 solubility calculator (Duan et al. 2003, 2006) are shown. The pressure effect over compensates the temperature effect so that CO2 solubility increases with reservoir depth up

With regard to storage of CO2 in a supercritical phase optimal CCS conditions are conditions where the CO2 density ρCO2 is maximal, because then a maximum mass of CO2 can be stored in the same rock pore space. Thermodynamically ρCO2 increases with pressure but decreases with temperature. ρCO2 as a function of depth increases monotonically as the pressure effect

CO2 can also be injected into depleted oil reservoirs although storage capacities are much smaller than in aquifers (IPCC 2005). It is estimated that 50 Gt of CO2 can be stored in this way worldwide (Firoozabadi and Cheng 2010) which is roughly 1.5 times of what is emitted per year. So this is clearly not the solution to mitigate global warming, however CO2 solubility in oil is very high, up to 60-80 mol% of CO2 can be dissolved (De Ruiter et al. 1994,

CO2 solubility generally increases with pressure and it is higher at lower temperatures. If the temperature is below the critical CO2 temperature (Tc = 304.13 K), then CO2 solubility increases until the CO2 liquefaction pressure is reached (circa 5.88 MPa), then it levels off

Kokal and Sayegh 1993, Emera and Sarma 2006, Firoozabadi and Cheng 2010).

*CO RT* **λCO2-Na ζCO2-Na-Cl** 

**T-p coefficient 2**

**(0)** μ*l*

a4 1.02782768E-5 a5 33.8126098 a6 9.04037140E-3 a7 -1.14934031E-3

a10 9.32713393E-4

**4.5 Effect of injection depth on CO2 solubilities** 

temperature is high in Saudi Arabia (298 K).

to a depth of approximately 900m when it reaches a plateau.

also over compensates the temperature effect (Table 2).

**4.6 Effect of presence of oil (CCS in oil reservoirs)** 

a3 -4770.67077 97.5347708

a11 1.41335834E-5 Table 1. CO2 solubility interactions parameters (Duan et al. 2003, 2006) with further pressure increase. CO2 solubility also depends on oil composition and for light oils CO2 can be completely miscible. For example De Ruiters et al. (1994) measured a strong increase of CO2 solubility with pressure in two crude oils, at low pressures (0.69 MPa) the gas-oil ratio (GOR) was approximately 5.3 m3/m3, and GOR increased rapidly up to the CO2 liquefaction pressure when it reached 71 m3/m3 and 102 m3/m3, respectively. With a further pressure increase GOR stayed approximately constant. The experimental temperature in De Ruiters et al. experiments was low (290 K). If the temperature is above Tc as expected for CCS conditions, then CO2 solubility monotonically increases; but it is nominally lower as compared to lower temperatures (Kokal and Sayegh 1993).


\* estimated from Span and Wagner (1996).

\*\* 1 mol/kg NaCl brine, calculated with Duan et al.'s (2003, 2006) calculator.

Table 2. Variation of temperature, pressure, CO2 solubility and CO2 density with depth

In case of heavy oils CO2 dissolves into the oil phase while some light oil fractions are extracted into the CO2 phase. Depending on the oil and thermophysical condition, vapourliquid, liquid-liquid, liquid-supercritical fluid, liquid-liquid-vapour phase behaviours are observed. The densities of CO2-saturated oil increase at lower temperature (294 K) while they decrease at higher temperature (e.g. 413 K) (Kokal and Sayegh 1993).

This makes CO2 a very efficient solvent for crude oil extraction in tertiary oil recovery processes (Green and Willhite 1998, Blunt et al. 1993). The dissolved CO2 reduces oil viscosity significantly which improves the mobility ratio oil-injected fluid (for improving production) and results in a much better reservoir sweep efficiency. The flow of oil in the reservoir is improved by the improved oil relative permeability, which leads to increased oil production. In addition, CO2 which dissolves into the oil causes oil swelling (up to 50-60%, Firoozabadi and Cheng 2010) which also leads to enhanced oil production. One side effect of CO2 addition to crude oil is that large asphaltene molecules precipitate (crude oil is a very complex fluid (cp. Table 3) with a multitude of components including such large asphaltene

Dissolution Trapping of Carbon Dioxide in

have a CO2 storage element.

transfer of CO2 into the oil and aqueous phases.

by the original hydrocarbon generation (Dandekar 2006).

CO2 as possible.

Pentland 2011).

2011).

Reservoir Formation Brine – A Carbon Storage Mechanism 245

CO2. Exceeding the capillary entry pressure of CO2 into the caprock should also be avoided (then CO2 will also flow through the caprock although very slowly because of the very low

Estimates suggest that many millions of tons of crude oil are produced yearly via enhanced oil recovery with CO2 (CO2-EOR) (Firoozabadi and Cheng (2010)). Crude oil production could be further increased if more CO2 would be used but such CO2-EOR schemes should

In principle oil would be a very good storage medium for CO2 (provided that the oil does not migrate upwards after CO2-takeup, so ideally the process would be designed in such a way that oil density increases), but of course oil is an economically valuable commodity and will be produced, so oil production schemes need to be combined with CCS schemes and optimized, essentially as much oil as possible needs to be recovered while storing as much

Reservoir simulations can calculate such CO2-EOR recovery/injection schemes over several years (Qi et al. 2008, Firoozabadi 2011), one complication here is the three-phase flow and the associated complex fluid thermodynamics occurring in the reservoir. This includes mass

In summary, most of the current CCS schemes which are online are actually EOR processes because of profitability. Example projects are the Weyburn-Midale project in Canada, which started in the year 2000. 1.8 Mt/a of CO2 are injected into a depth of 1500m into a depleted oil reservoir (PTRC 2011, Pentland 2011). 225 m3 of CO2 produce 0.12 m3 extra crude oil there. Another CO2-EOR project is underway in the Salt Creek field in Wyoming, USA; here 2.09 Mt of CO2 are injected yearly and more than 1.2 x <sup>6</sup> 10 m3 of incremental crude oil have been recovered so far and it is planned to store 50 Mt of CO2 in total (Andarko 2010,

**4.7 Effect of presence of gas (gas reservoirs or oil reservoirs with a gas cap)** 

CO2 can also be injected into depleted gas reservoirs in order to produce additional gas, this is called enhanced gas recovery (EGR). The injected CO2 increases reservoir pressure which supports gas production. As in the case of oil reservoirs or indeed aquifers the caprock failure stress must not be exceeded. Natural gas is a mixture of various components (cp. Table 4); the exact composition varies with the location of the gas fields and it is determined

In the reservoir, the CO2 flood front mixes with the natural gas by dispersion and diffusion. In parallel to the CO2 – gas mixing process, CO2 also equilibrates with the formation brine, similar to the mixing processes occurring in deep saline aquifers. The main advantage of CO2-EGR is profitability as in CO2-EOR, and an optimum between additional gas production and CO2 sequestration needs to be found. There are several CO2-EGR pilot units where these processes are tested, e.g. in the Lacq demonstration project in southwest France, <sup>5</sup> 10 t of CO2 will be injected and stored in a depleted gas field at a depth of 4500m (Total

A thorough study of nine natural gas fields (including sandstone and carbonate reservoirs) concludes that the main trapping mechanism over millennial timescales is dissolution trapping. At most 18% of injected CO2 is stored as a solid mineral phase (Gilfillan et al. 2009)

In the case of oil reservoirs with a gas cap, the mixing thermodynamics are a combination of CO2-gas mixing, CO2 dissolution in oil and CO2 dissolution in brine. These complex

and mineral trapping is predicted to happen only for siliclastic reservoirs.

permeability of the caprock shale) resulting in potential CO2 leakage to the surface.

components which are dissolved in the oleic phase under reservoir conditions, Dandekar 2006) which renders the rock surface more oil-wet which again changes multi-phase fluid dynamics in the reservoir. According to contact angle studies (Dickson et al. 2006, Espinoza and Santamaria 2010) this can result in CO2-wet surfaces which would eliminate the possibility of capillary trapping of CO2. Also the surface area CO2-brine would most likely be affected by such wettability effects, which in turn would affect CO2 dissolution kinetics (cp. section 5.1 and equations 12 and 17).


Table 3. Typical composition of black crude oil (\*Dandekar 2006, \*\*McCain 1990). Of course the exact compositions of crude oils are extremely complex and vary widely depending on the exact geographical location. The C fractions C6+ upwards contain many isomers and also hydrocarbons with additional functional groups (e.g. alcohol, ester, carbonyl, amine, etc. pp.). Crude oil also contains metal cations (e.g. Vanadium)

Moreover there is a very important reservoir engineering aspect associated with depleted oil reservoirs; reservoir pressure is low (because of oil production) and CO2 can be injected at fairly high rates and comparatively large quantities of CO2 can be stored. It is important not to exceed the fracture pressure of the caprock which would result in catastrophic leakage of

components which are dissolved in the oleic phase under reservoir conditions, Dandekar 2006) which renders the rock surface more oil-wet which again changes multi-phase fluid dynamics in the reservoir. According to contact angle studies (Dickson et al. 2006, Espinoza and Santamaria 2010) this can result in CO2-wet surfaces which would eliminate the possibility of capillary trapping of CO2. Also the surface area CO2-brine would most likely be affected by such wettability effects, which in turn would affect CO2 dissolution kinetics

> **Component mole %\* mole %\*\***  Methane, CH4 45.93 36.47 Ethane, C2H6 7.32 9.67 Propane, C3H8 6.42 6.95 n-Butane, C4H10 3.87 3.93 i-Butane, C4H10 1.42 1.44 n-Pentane C5H12 2.05 1.41 i-Pentane C5H12 1.68 1.44 Hexanes 2.93 4.33 C7 2.30 C7+

C8 2.21 C9 1.66 C10 1.97 C11 1.61 C12 1.39 C13 1.36 C14 1.28 C15 1.22 C16 1.09 C17 1.04 C18 0.98 C19 0.77 C20+ 6.63 Hydrogen sulphide, H2S 0.60 0 Carbon dioxide, CO2 1.47 0.91 Nitrogen, N2 0.81 0.16

Table 3. Typical composition of black crude oil (\*Dandekar 2006, \*\*McCain 1990). Of course the exact compositions of crude oils are extremely complex and vary widely depending on the exact geographical location. The C fractions C6+ upwards contain many isomers and also hydrocarbons with additional functional groups (e.g. alcohol, ester, carbonyl, amine, etc.

Moreover there is a very important reservoir engineering aspect associated with depleted oil reservoirs; reservoir pressure is low (because of oil production) and CO2 can be injected at fairly high rates and comparatively large quantities of CO2 can be stored. It is important not to exceed the fracture pressure of the caprock which would result in catastrophic leakage of

pp.). Crude oil also contains metal cations (e.g. Vanadium)

33.29

(cp. section 5.1 and equations 12 and 17).

CO2. Exceeding the capillary entry pressure of CO2 into the caprock should also be avoided (then CO2 will also flow through the caprock although very slowly because of the very low permeability of the caprock shale) resulting in potential CO2 leakage to the surface.

Estimates suggest that many millions of tons of crude oil are produced yearly via enhanced oil recovery with CO2 (CO2-EOR) (Firoozabadi and Cheng (2010)). Crude oil production could be further increased if more CO2 would be used but such CO2-EOR schemes should have a CO2 storage element.

In principle oil would be a very good storage medium for CO2 (provided that the oil does not migrate upwards after CO2-takeup, so ideally the process would be designed in such a way that oil density increases), but of course oil is an economically valuable commodity and will be produced, so oil production schemes need to be combined with CCS schemes and optimized, essentially as much oil as possible needs to be recovered while storing as much CO2 as possible.

Reservoir simulations can calculate such CO2-EOR recovery/injection schemes over several years (Qi et al. 2008, Firoozabadi 2011), one complication here is the three-phase flow and the associated complex fluid thermodynamics occurring in the reservoir. This includes mass transfer of CO2 into the oil and aqueous phases.

In summary, most of the current CCS schemes which are online are actually EOR processes because of profitability. Example projects are the Weyburn-Midale project in Canada, which started in the year 2000. 1.8 Mt/a of CO2 are injected into a depth of 1500m into a depleted oil reservoir (PTRC 2011, Pentland 2011). 225 m3 of CO2 produce 0.12 m3 extra crude oil there. Another CO2-EOR project is underway in the Salt Creek field in Wyoming, USA; here 2.09 Mt of CO2 are injected yearly and more than 1.2 x <sup>6</sup> 10 m3 of incremental crude oil have been recovered so far and it is planned to store 50 Mt of CO2 in total (Andarko 2010, Pentland 2011).
