SPE 158322

Comparison of WAG and Water Over Injection for Carbon Storage and Oil Recovery in a Heavy Oil Field L. E. Sobers, SPE, University of the West Indies

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPETT 2012 Energy Conference and Exhibition held in Port of Spain, Trinidad, 11–13 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Compositional reservoir simulation studies show that CO2 enhanced oil recovery (CO2EOR) combined with carbon storage

using water over gas injection improves production performance and carbon storage compared to WAG injection. The fluid

description is based on matching the PVT-derived viscosity, total and relative volume of a heavy oil sample (density 893

kg/m3 [17 degrees API]). The reservoir description is based on an unconsolidated deltaic, sandstone deposit in the Gulf of

Paria, offshore Trinidad. Water over gas injection is an injection strategy proposed by Stone and Jenkins to increase gas

sweep efficiency. In this injection design water is injected in the upper portion of the reservoir and gas is injected in the

bottom portion of the reservoir using either vertical or horizontal injectors. Increasing the sweep efficiency improves both oil

recovery and carbon storage. The counter current flow of injected fluids uses gravity effects to reduce gas override and water

underride typical of WAG injection strategies and continuous single fluid injection. The results show that the water over gas

injection design results in a larger mixing zone that extends further into the reservoir. Although oil recovery was essentially

the same, with water over gas injection, there was greater than 50% increase in carbon storage, 20% reduction in water cut

and 85% reduction in producing GOR compared to WAG.

Introduction Global warming is the term used to describe the increasing average global temperatures which can lead to significant changes

to the earth’s climate (Houghton, 1990). Anthropogenic CO2 emissions have been identified as the main contributor to

increasing atmospheric CO2 concentrations and global warming (Houghton, 1990). The United Nations’ Intergovernmental

Panel on Climate Change (IPCC) reports that the impact on human life, availability of resources and environmental effects

will be catastrophic. Caribbean countries including Trinidad and Tobago will be particularly susceptible to more frequent and

powerful hurricanes, rising sea level, flooding and widespread tropical diseases (Parry et al eds, 2007; Watson et al eds,

1997). Geologic storage of CO2 in hydrocarbon reservoirs, aquifers and coal seams has been proposed as an intermediate

solution to reducing CO2 emissions. This paper focuses on carbon storage in a producing heavy oil reservoir.

Traditionally water alternating gas (WAG) injection has been used for CO2 enhanced oil recovery (CO2EOR). However this

injection strategy was not developed or optimized for carbon storage. Sobers et al. (2010) concluded that manipulating

injection parameters such as injection rates, size and number of WAG cycles are insufficient measures for permanently

storing large volumes of CO2 to significantly reduce CO2 emissions. This paper compares four CO2 injection schemes in a

moderately heavy oilfield (density 893 kg/m3 [API gravity 17]). The objective is to compare CO2 storage, oil recovery and

performance of traditional methods, WAG and gas flood, to water over gas injection in an unconsolidated sand body. Water

over gas injection is an injection strategy proposed by Stone (1982) where water is injected in the upper portion of the

reservoir and gas is injected in the lower portion. This process is also known as modified simultaneous water alternating gas

injection (SWAG).The horizontal and vertical water over gas injection schemes are shown schematically in Figure 1. In the

vertical injection scheme the injector was completed over the entire reservoir interval where gas was injected in the lower 60

m and water in the upper 40 m of the formation. With the chosen dimensions of the reservoir, it is possible to maintain

injectivity and remain below the reservoir fracture pressure for the duration of the flood.

2 SPE 158322

Figure 1: Schematic of water over gas injection using a single vertical well shown in the x-z plane only (left) and a pair of horizontal wells

(right) with a single vertical producer. The dimensions of the grid are the same for both horizontal and vertical injection (not drawn to

scale).

This paper proposes geological carbon storage combined with enhanced heavy oil recovery as an option for Trinidad and

Tobago to sustainably reduce CO2 emissions.

CO2EOR CO2 enhanced oil recovery (CO2EOR) is the process of injecting CO2 to improve oil recovery by reducing oil viscosity and

increasing oil volume (Spivak and Chima, 1984; Khatib et al., 1981; Simon and Graue, 1965). Heavy oils are typically

undersaturated, less compressible and more viscous than conventional crude oil at standard conditions with specific gravity

ranging 934-1000 kg/m3 (10-20 degrees API) (Speight, 1998) . Due to the higher viscosities, heavy oil is not produced as

easily as conventional crude; the resistance to flow under natural reservoir energy is much larger. The viscosity of heavy oil

can range from tens to thousands of centipoises at reservoir conditions (Speight, 1998; Craft and Hawkins, 1991). CO2 has

been used in enhanced oil recovery for over 50 years (Holm, 1959; Johnson,1952). Early investigations used CO2 in the

liquid and gaseous phase to maximize oil recovery of conventional crude by miscible flooding (Beeson and Ortloff, 1959;

Dicharry et al, 1973, Johnson, 1952). In subsequent years immiscible recovery using CO2 was also considered where the

main recovery mechanism was dissolution of CO2 into the oil (Holm and Josendal, 1974; Mangalsingh, 1976; Rojas and

Farouq Ali, 1988). Although not miscible with heavy crude, CO2 is soluble to a limited degree which allows reduction in oil

viscosity, density and increased oil volume (Holm and Josendal, 1974). Oil recovery occurs through the processes of water

and immiscible gas drive.

By the principle of mass conservation, the volume of CO2 stored or accumulated in the reservoir is the difference between

CO2 produced (G prod) and CO2 injected (Ginj) plus CO2 initially (Ginit) dissolved in oil.

( ) Equation 1

One clear advantage of CO2 EOR is the opportunity to offset storage costs by incremental oil recovery (Stern, 2007). The

challenge we encounter here is to manipulate CO2 injection realise both oil recovery and carbon storage.

CO2 emissions. CO2 emissions in Trinidad and Tobago originate from three main sources:

1. Petrochemical industries where natural gas is used as feedstock and as fuel (56%)

2. Natural gas processing to produce liquefied natural gas (LNG) (13%) and,

3. Power generation (17%)

The remaining 14% of total CO2 emissions come from transportation (8%), residential use (1%), light industry manufacturing

and flaring (5%). These numbers are based on the unpublished latest (2009) figures compiled by the Natural Gas Institute of

the Americas. Each day 3.54 × 106 m3/day (125 MMscf/day; 40 × 106 metric tonnes per year) of CO2 is produced from the

petrochemical industries at the Point Lisas Industrial Estate and the LNG plants at Point Fortin where a total of 1.13 × 108

m3/day (4 bcf/d) of natural gas is used as feedstock or fuel. These emissions represent less than 1% of the world’s total CO2

emissions However the central location of major CO2 sources at Pt. Lisas industrial estate, proximity of CO2 sources to heavy

oil reservoirs (30-50 km), relatively pure stream of CO2 from ammonia plants (>95% CO2) and the annual average of 9%

decline in oil production presents an opportunity for cost effective CO2EOR and carbon storage. If only high purity (>95%)

CO2 emissions from the Atlantic LNG facilities and the Point Lisas Industrial Estate are considered for CO2 injection, this

would account for 55% of Trinidad and Tobago’s CO2 emissions (Boodlal and Furlonge, 2008).

Displacement Efficiency. Laboratory experiments, correlations and models of CO2 displacement mechanisms are based on

the premise of CO2 and heavy oil being in physical contact and in thermodynamic equilibrium. In porous media this does not

always occur due to the macroscopic displacement efficiency being less than unity (Kilns, 1984). The main operational

challenge to heavy oil CO2 EOR is low sweep efficiency due to the unfavourable mobility ratio between CO2 and oil at

reservoir conditions. The mobility of the fluid phase, i , is defined as ratio of relative permeability of the fluid to its viscosity

at the average saturation of the fluid phase (Craig, 1971). The mobility ratio of fluids in a displacement process is the ratio of

the mobility of the displacing phase, D', to that of the displaced fluid phase, d.

40m

Gas

100 m

150 m

1000 m

Water

60m

Water

Gas

SPE 158322 3

The mobility ratio affects the stability of the displacement front and affects both areal and vertical sweep. If the mobility ratio

is greater than 1, flow becomes unstable during displacement resulting in viscous fingering. The mobility ratio of a

moderately viscous crude and CO2 is unfavorable because CO2 has a much greater Darcy velocity than oil at the average CO2

saturation. The challenge of the injection design is to overcome the effect of the unfavorable mobility ratio. Several

approaches such as polymer and light gas injection have been used to improve sweep efficiency and oil recovery. WAG

injection has been used to improve macroscopic sweep efficiency by reducing the relatively permeability of the CO2 and

providing greater mobility control.

Gravity-Dominated Displacement. In addition to the unfavourable mobility ratio there is the tendency, during immiscible

gas injection, for gravity segregation to occur due to the differences in the specific gravity of the injected fluids and crude oil.

The vertical sweep efficiency is function of the gravity number and mobility ratio (Craig et al., 1957). At reservoir conditions

shown in Table 1 the density of CO2 ranges between 400 and 800 kg/m3; moderately heavy oil, between 850 and 970 kg/m3

and; reservoir brine, between 990 and 1020 kg/m3, assuming molality of 0.50. The density difference results in gas over-ride

which leads to poor reservoir sweep by injected fluids. This buoyancy effect has been investigated for CO2 in aquifers (Møll

Nilsen, 2011; Silin, 2006). Injected CO2 rises to the top of the reservoir until it reaches a low permeability caprock where it

spreads out as a mobile plume of dense gas. The amount of trapping is directly related to gas sweep efficiency in porous

media (Obi and Blunt, 2004; Cinar et al, 2007; Iglauer et al, 2009).

Table 1. Parameters used in simulations

Reservoir and Grid Properties

Reference Pressure 27.4 MPa

Temperature 81.7 C

Average porosity 26 %

Average permeability

Water saturation

525 mD

20 %

kv/kh ratio 0.1

Grid dimensions (i× j× k) 100× 30× 50

Grid block dimensions 10m× 3m ×2m

Fluid Properties at reservoir conditions

CO2 Crude MMP 23.0 MPa

Oil Density 893 kg/m3

Brine Density 987 kg/m3

CO2 Density 707 kg/m3

CO2 Compressibility factor 0.577

CO2 Solubility in crude 60 m3/ m3

CO2 Solubility in brine 0.12 m3/ m3

CO2 Injection rate 9.0 × 104 kg/day

CO2 viscosity 5.92 × 10-5 Pa.s

Water viscosity 3.47 × 10-4 Pa.s

Oil viscosity 8.75 × 10-3 Pa.s

In gas injection processes, flow through porous media is gravity-dominated particularly in heavy oil fields where the density

difference is large, capillary forces are in comparison, negligible. The gravity and viscous forces can be compared using the

gravity number, a dimensionless ratio of gravity to viscous forces. The gas Ng_gv and water Ng_gw gravity numbers as defined

by Zhou et al. (1997). In gravity dominated flow the gravity number is much greater than the capillary number. Zhou et al

(1997) used the relationship between mobility, gravity and viscous forces, ( ) ⁄ to define a two-phase

flow system as being dominated by gravity segregation.

For the reservoir and fluid properties given in Table 1, ( )⁄ is 200 assuming the relative permeability of the

displacing fluid and the displaced fluid are equal and the initial viscosity of oil and gas are 8.8 × 10-3 and 5.9 × 10-5 Pa.s

respectively and Ngv_g is 200 as in the case of the CO2 storage in Sleipner (Ide et al, 2007). Similarly for water injection,

assuming the water viscosity is 3.5 × 10-3 Pa.s and Ngv_w is 3 for a water injection rate of 200 m3/day, in the system described,

( )⁄ is 3. As crude viscosity reduces with CO2 dissolution in resident crude ( )⁄ remains greater

than 1. In each case the displacement process is dominated by gravity forces. The water over gas injection strategy uses the

gravity forces to improve gas sweep despite the unfavourable mobility ratio (Rossen et al., 2006).

4 SPE 158322

Reservoir simulation

In this paper compositional reservoir simulation is used to investigate the efficacy of each of the four injection strategies. The

equation of state (EOS) package PVTi within the Schlumberger Eclipse software suite was used to characterise resident oil

phase behaviour. The parameters of the Peng-Robinson EOS (1976) and the Lohrenz-Bray-Clark (1964) equation were

regressed to PVT data. The grid-based Eclipse 300 with the carbon storage option, CO2SOL, was used to predict oil

recovery, carbon storage and production performance.

The main assumptions of this study are: the reservoir has an open outer boundary confined by no-flow barriers above and

below; Newtonian mobilities in all phases and; there is immediate attainment of local steady-state mobilities which depend

only on local saturations. Gas mobility g decreases monotonically with water saturation and w is monotonically increasing

with water saturation. We have accounted for heterogeneity, incompressible phases, mass transfer between phases, fluid

dispersion and unsteady state injection.

There is no experimental data for water over gas injection for CO2 EOR available in the literature that is comparable to the

crude sample and sand properties used in this study. In all instances the same reservoir simulation parameters: two-phase and

three-phase relative permeability; relative permeability hysteresis; trapping coefficient and; fluid description have been used

to match the oil recovery trends in CO2 and water displacement experiments carried out by Dyer and Farouq Ali (1994). The

relative permeability used in these simulations were presented in previous work (Sobers et al., 2010) based on the history

matching of sandpack flooding experiments performed by Dyer and Farouq Ali (1994).

Fluid and Reservoir Description. A single porosity and single permeabilities in the i-, j- and k-direction were randomly

assigned to each cell. The values of these parameters are within 20% of the average properties of porosity and permeability i-,

j- and k-directions. The reservoir and fluid properties used are summarized in Table 1. The fluid properties were determined

by the 3-parameter Peng-Robinson EOS (PR EOS) (1976) and modified Lohrenz Bray Clark (LBC) (Eclipse, 2008)

correlation parameters to the viscosity, relative and total volume of PVT data for the sample. Table 2 lists the regressed

properties of the C2-C6 and C7+ grouped components. The compositional model of the fluid was based on the regression of

the three-parameter PR EOS and the modified Lohrenz Bray Clark (LBC) viscosity correlation on PVT data of a Trinidad

heavy crude. Regression of the PR EOS parameters critical pressure, pcr , critical temperature, Tcr , acentric factor, zcr the

critical z-factor, Vcr the critical volume, , Ωa, Ωb and volume shift was carried out on the C2-C6 and C7+ grouped

components. The thermodynamic properties of CO2 (Altunin, 1975) and methane (Angus et al, 1978) have been established

by published experimental work. The molecular weight and specific of the C7+ fraction were given in the PVT report.

Table 2. Compositional description of crude oil components

Components Mole

%

Weight

%

M

kg-mole

Pcr (MPa) T cr (K) Ωa Ωb

CO2 0.92 0.23 44 7.4 304.7 0.457 0.078 0.225 CH4 42.80 3.90 16 4.6 190.6 0.457 0.078 0.013 C2-C6 14.82 4.47 53 5.1 495.7 0.528 0.117 0.182 C 7+ 41.46 91.39 388 1.5 1196.3 0.391 0.084 0.805

Simulation Constraints. The gas surface injection rate was kept constant at 50 000 m3/day (1 765 Mscf/day). As the gas

reservoir volume changed with reservoir pressure the gas reservoir rate varied between 185 and 240 rm3/day, the gas gravity

number ranged between 200 and 150. The gravity numbers were calculated using initial fluid properties. Applying the

assumed reservoir properties to the relationship developed by Zhou et al. (1997) for water injection at 100 m3/day

corresponds to a gravity number of 6. The producer was constrained to an upper limit of fluid production of 400 rm3/day. In

each instance, except for the base case waterflood, 2.2 × 105 metric tonnes of CO2 was injected. The cut offs were 95% water

cut and a producing GOR of 500 m3/m3.

CO2 Phase Distribution. The retained CO2 is defined as CO2 stored in Equation 1. The percentage of dissolved, mobile

and trapped gas is a fraction of the retained CO2 in the liquid, mobile gas and trapped gas phases respectively. The Land's

trapping model (1968b) was used to estimate the fraction of free gas trapped, CO2 , in the reservoir as

(

)

( (

)) Equation 2

where Sgmax is the maximum saturation of gas achieved historically in each grid block, Sgcr represents critical gas saturation

and C is the Land trapping coefficient (Land 1968a). In this model the critical gas saturation and Land parameter value, C,

were assumed to be 15% and 2 respectively. These values were chosen based on the measurements of Pentland et al. (2010)

on unconsolidated sandpacks. Ide et al. (2007) reported that the trapped CO2 bubbles will remain immobilized below the

critical gas saturation. In addition to trapping carbon storage can occur through dissolution and precipitation of the CO2

(Islam and Chakma, 1993; Bachu et al. 1994; Spiteri et al, 2005).

SPE 158322 5

Results Overview. Table 3 is a comparison of oil recovery and carbon storage of continuous gas injection, vertical WAG in a 3:2

ratio, waterflood, vertical and horizontal water over immiscible gas injection. The producing gas-oil ratio (GOR) is the ratio

of gas to the volume of oil produced at standard conditions. The water cut is the ratio of the volume of water produced to the

total volume of liquid produced at standard conditions. The table below represents performance, early in the flood life, after

injecting 5.0 × 106 kg-mole of CO2 at a surface rate of 50 000 m3/day. Water and gas were injected along the entire length of

the reservoir for the CO2 flood, waterflood and WAG injection. However, for vertical water over gas injection, water is

injected the upper 40m and gas is injected in the lower 60m of the reservoir. The WAG ratio is set to be comparable to the

water over gas injection ratio where more CO2 is injected than water. The optimum WAG ratio injection for this crude as

determined from previous work (Sobers et al, 2010) is 4:1 H2O:CO2. However injecting more water than CO2 will reduce the

carbon storage capacity of the reservoir. Table 3 shows a comparison of CO2 WAG, horizontal and vertical water over gas

injection and continuous injection using a single vertical producer after injecting 5.0 × 106 kg-mole of CO2 at a rate of 50 000

sm3/day (gas gravity 150-200). With the exception of CO2 WAG, the results of the other runs were presented by Sobers et al

(2011).

Table 3. Performance of CO2 injection strategies

Injection

strategy Injector type

Fluid

ratio

H2O:

CO2

%

Oil

Recovery

Carbon

Retention

×106

kg-mole

%

Mobile

Phase

%

Residual

Phase

%

Dissolved

in oil and

water

GOR Water

Cut

CO2 flood Vertical 0:1 0.11 4.69 33 34 33 380 0.02

Waterflood Vertical 1:0 0.11 - - - - - 0.75 Water over

gas Horizontal 2:3 0.16 4.97 6 39 55 78 0.18

Water over

gas Vertical 2:3 0.17 4.71 14 38 48 79 0.37

WAG Vertical 2:3 0.18 2.34 38 35 27 500 0.57

Both WAG and water over gas injection increase oil recovery compared to waterflood and CO2 flood. However results show

that for both horizontal and vertical configurations, water over gas injection is more efficient in CO2 storage than WAG

injection. Of the retained CO2 there is an almost an even distribution of CO2 in the mobile gas, residual gas and dissolved (oil

and water) phases for CO2 flood and WAG injection. However with WAG injection there is a greater producing GOR and

about half the storage.

Compared to the other CO2 injection process water over gas injection increases the volume of CO2 retained and the proportion

CO2 dissolved in oil and water. In Table 3 the fraction of trapped gas is CO2 in the residual phase. Results show that these are

comparable for WAG and water over gas injection. The fraction of gas in the residual phase is particularly important for long

term geological storage of CO2 where the risk of leakage is reduced when a smaller volume of CO2 exists as free gas.

Assuming the reservoir pressure does not decline, the mobile gas is the portion of injected CO2 that is able to migrate through

the reservoir long after injection stops. Therefore reducing the mobile fraction reduces the risk of migration leading to gas

leakage.

Figure 2: Oil recovery profile of gas flood, water alternating gas, waterflood, horizontal and vertical water over gas injection as a function of pore volume of fluid injected after injecting 5.0 × 10

6 kg-mole of CO2 at a rate of 50 000 sm

3/day (gas gravity 150-200)

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

0.00 0.05 0.10 0.15 0.20 0.25 0.30

Oil

Re

cove

ry

Pore Volume Injected

Gas Flood WAG Horizontal W_G Waterflood Vertical W_G

6 SPE 158322

Oil Recovery and Performance. Figure 2 compares the oil recovery realized for a given pore volume for 5 injection

strategies. With the exception of the waterflood, all runs were evaluated after injecting 5.0 × 106 kg-mole of CO2 at a rate of

50 000 sm3/day (gas gravity 150-200). For a given pore volume of fluid injected the gas flood and WAG injector yielded

greater oil recovery than the water over gas injection strategies. However the ultimate recovery is greater for the horizontal

water over gas injection scheme. The main advantage of the gas flood and WAG injection is earlier recovery.

Figure 3: CO2 retention for gas flood, water alternating gas, horizontal and vertical water over gas injection as a function of pore volume of fluid injected after injecting 5.0 × 10

6 kg-mole of CO2 at a rate of 50 000 sm

3/day (gas gravity 150-200).

Carbon Storage. Figure 3 is a comparison of the carbon retention, as defined in equation 1, for four injection strategies. For

a given pore volume of fluid injected, the water over gas injection schemes retain a greater mass of CO2 than WAG injection.

Continuous gas injection in the gas flood retained more than the other methods but Table 3 shows that this occurs with a

GOR at the 500 m3/m3 limit. Both the vertical and horizontal water over gas injection schemes provide better carbon

retention than traditional WAG injection.

Saturation profiles. The gas saturation profiles in figure 4 show the distribution of CO2 in the reservoir at the end of the

simulation runs. The gas saturation distribution gives an indication of the extent of the CO2 plume within the reservoir. In

both water over gas injection strategies there is less gas over ride in the reservoir than the WAG injection case. There is also a

wider (vertical and areal) distribution of gaseous CO2 at lower gas saturations than the WAG injection case.This occurs to a

greater extent for the horizontal than the vertical injection scheme.

0.0E+00

5.0E+05

1.0E+06

1.5E+06

2.0E+06

2.5E+06

3.0E+06

3.5E+06

4.0E+06

4.5E+06

5.0E+06

0.00 0.05 0.10 0.15 0.20

Sto

red

Car

bo

n D

ioxi

de

k

g-m

ole

Pore Volume Injected

Gas Flood WAG Horizontal W_G Vertical W_G

SPE 158322 7

Figure 4: Gas saturation profile between the injector (left) and producer (far corner right) for WAG injection (bottom), horizontal (middle) and vertical (top) water over gas injection after injecting 5.0 × 10

6 kg-mole of CO2 at a rate of 50, 000 sm

3/day (gas gravity

150-200).

Discussion The displacement of a moderately heavy oil using water and CO2 is a gravity-dominated process. However, water over gas

injection hampers the upward migration and promotes the physical dispersion of injected CO2. It also reduces water

underride. The greater sweep efficiency of the water over gas injection scheme results in slightly higher oil recoveries than

WAG injection. Results show that water over gas injection also reduces the producing GOR and water cut. This can

represent reduced cost for water handling facilities and gas reinjection.

The WAG flood resulted in a higher producing GOR than the CO2 flood because the pressure maintenance of water injection

allows greater production of reservoir and injected fluids. The effect of the pressure maintenance is also evident in Figure 2

which shows the higher rate oil recovery using WAG injection. Beyond the short mixing zone near the injector, WAG

injection is essentially a CO2 flood with water pressure maintenance.

Traditional WAG injection can be used for coupled carbon storage and oil recovery. However this injection scheme cannot be

used for storage of significant volumes of CO2 because gravity segregation leads to gas override and one-third of the injected

CO2 remaining in the mobile phase, thus increasing the risk of CO2 leakage over geologic time. Table 3 shows that the

difference between the residual gas fraction at the end of WAG injection and water over gas injection is less than 5 %.

However there is a much greater difference in the fraction of mobile and dissolved CO2 because with increased sweep

efficiency, injected CO2 is in contact with oil and water not yet saturated with CO2. The cumulative effect using water over

gas injection instead of WAG is a doubling of CO2 storage volume and comparable oil recovery.

Conclusions The success of the water over gas injection scheme is contingent on contact between injected fluids to allow for the

dissolution of CO2 in oil and to a lesser extent water. From the results presented, the following may be concluded for a heavy

oil reservoir:

Distance (metres)

0 200 400 600 800 1000

Gas Saturation

8 SPE 158322

1. Water over gas injection for vertical and horizontal injection well configurations can significantly increase carbon

storage compared to WAG injection.

2. Water over gas injection recovers more oil than continuous CO2 flood.

3. Based on economic limits of producing GOR and producing water cut, the ultimate oil recovery is greater for

vertical and horizontal water over gas injection than WAG injection.

4. There is better performance-lower producing GOR and water cut-using the water over gas injection schemes than

WAG injection and CO2 flood.

5. Water over gas injection reduces the fraction of mobile CO2 in the reservoir compared to WAG and CO2 flood.

Nomenclature

fluid density, m/L3, kg/m3

= fluid viscosity, m/Lt, m Pas

C = Land’s trapping coefficient

ER = efficiency, overall reservoir recovery

kav = average vertical permeability, L2, mD

g = acceleration of gravity, L/t2,m/s2

H = reservoir thickness, L, m

L = length of the reservoir, L, m

M = molecular weight, m, kg-mole

MMP = minimum miscibility pressure, MPa

Ngv = gravity number, dimensionless

pcri t = critical pressure, m/Lt2, MPa

Sgcr = critical gas saturation

Sgt = trapped gas saturation

Sgmax = maximum gas saturation in grid block

Tcrit = critical temperature, T, °C

u = flow rate per unit area, L/t, m/s

Subscripts

g = gas phase

o = oil phase

w = water phase

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