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CO2Injection and CO2WAG in Dipping Gas Condensate and Oil ReservoirsMansour Soroush, SPE, Norwegian University of Science and Technology (NTNU); Lars Hoier, SPE, Statoil; andJon Kleppe, SPE, NTNU

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 1418 April 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 beenreviewed 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, itsofficers, 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 toreproduce 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.

Abst ractIn this study, different scenarios of CO2 injection in dipping gas condensate and oil reservoirs are investigated throughreservoir simulations. Both miscible and immiscible flooding conditions were investigated for a range of different injection gasmixtures, and geological realizations.

We find particularly interesting results for miscible flooding of gas condensate systems below dewpoint pressure. Here,

dropped out condensate is the prime target for enhanced recovery projects and multi-contact miscibility could develop throughthe combined condensing/vaporizing mechanism.

Different patterns of permeability variation with depth in layering scenarios with dip angle showed distinct different responseson produced condensate. CO2 WAG in partially depleted gas condensate reservoirs seems to have the same value of oilrecovery in early times, but ultimate recovery is different according to layering heterogeneity. In the case of pure CO2

injection, both up-dip and down-dip, it was found that homogeneous layering showed highest recovery. Here developed multi-contact miscible oil-bank is able to move and sweep condensate above it easier. Applying various gas injection mixtures of

CO2 and C1 combinations, the effect on ultimate recovery were studied. In this case CO 2 injection is above minimummiscibility pressure (MMP) resulting in high recoveries.

CO2WAG in dipping oil reservoir was also studied extensively, based on injection pattern, MMP values and various layeringsystems. CO2WAG in scenarios with increasingly trend of permeability with depth had the highest value of recovery. This isbecause of prevention from early gas breakthrough in upper layers and good sweep efficiency in lower layers. Pure CO2injection with total same injection volume showed lower recovery. This may verify that gravity in WAG water injection periodis the most effective parameter in the case of down-dip WAG.

IntroductionGas injection is an important EOR method for increasing oil recovery. Planning efficient injection scenarios depends on many

parameters. Most important parameters are precise evaluation of MMP in injection process, choosing proper injection gasbased on cost and availability of gas, technical concerns, scheduling the process and special behavior of injected gas incompanion with the reservoir fluids. CO2 is also considered for EOR processes that could be injected either in miscible orimmiscible flooding scenarios.

Immiscible CO2injection has been successfully practiced in heavy-oil reservoirs. Two main mechanisms in immiscible CO2displacement are oil swelling and reducing oil viscosity. Low-pressure reservoirs and reservoirs with oil gravities less thanapproximately 30API are typical candidates for immiscible CO2displacement (Whitson and Brule, 2000).

In higher pressure

injection above MMP, CO2 phase behave from vapor-like to liquid-like CO2-richer phase. This phase extracts someintermediate and heavy components of the reservoir oil or gas condensate and higher recovery is achievable (Whitson andBrule, 2000).

CO2 injection could be investigated in different reservoir conditions and some important parameters should be noticed.Alavian and Whitson (2005) showed that there is good CO2IOR potential in naturally fractured reservoir. Oil recoveries from

CO2injection is reported in the range of 80-90% for the fractured reservoir that they studied. There are also lots of efforts done

on improving MMP measurements that affect directly the CO2 injection process (Emera and Sarma 2005, and Johns et al.

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2010). Hoier and Whitson (2001) found that the best extrapolation method to find infinite grid block approximation inslimtube simulation for MMP estimation is the Pade approximation (Van Dayke, 1978).Although good recovery could be obtained in CO2 injection process, some special problems with CO2 injection should benoticed. Whitson (2000) described these side effects that might have small to large consequences on the whole process. One ofthese problems is multiphase behavior of the CO2-oil that is limited to special reservoir temperatures and CO2concentrations.

According to the reservoir condition, CO2in contact with oil could be in CO2-enriched vapour or CO2-enriched liquid phase.Asphaltine precipitation could be a more serious problem because it happens in a wider range of pressure and CO2

concentrations and this also could result in some wettability alternation in advance (Whitson and Brule, 2000). Howeversimulating different phenomena of CO2 injection leads to better understanding of the process and thus better planning ofinjection projects.

Flooding in Dipping Reservoirs

Flooding behavior in porous media depends on viscous and gravity forces. Viscous dominated flow takes place in opensystems with fluid injection or fluid production from that. Gravity dominated flow can occur both in closed or open systems.

The effect of gravity is considered in many studies including phase density differences and dipping reservoirs. In the case ofhaving an angle of inclination in the system the Darcy equation for flow of each phase will be,

. (1)

In which is considered to be angle of inclination. is assumed to be positive if the flow is upward.Total flux in the reservoir will be,

....(2)Assuming that gas and oil are flowing phases,

......(3)

Fractional flow of gas is,

fU UT

T

...(4)

Assuming a gravity number as below,

N KUT .....(5)

This dimensionless number is defining parameter for effect of gravity in dipping reservoir. Including the gravity numberthe fractional flow equations can be modified as,

...(6)

....(7)

The continuity equation for two flowing phases is,

, ,

.(8)

Defining normalized injection volume and using dimensionless forms of saturation and time, equations could be simplifiedand applying initial and boundary conditions for the problem the proper solution may be obtained. Immiscible flow conditions

are considered for all cases. In miscible flooding, it is critical to understand the mechanisms as well as density and saturationvariations at reservoir conditions.

Condensing Vapourizing MechanismSeveral gas injection experiments verified with equation of state simulations were reported by Zick (1998). He concluded

that a mixture of condensing vaporizing gas drive mechanism is the controlling phenomena for several EOR processes by

enriched gas injection. Actually simulation runs based on his studies indicate that the traditional condensing vaporizingconcept is not occurring in many cases. Above MMP, the condensing/vapourizing mechanism can generate miscibledisplacement. He also showed that the true MMP could be lower than what is predicted by the vapourized or condensing gasdrives mechanisms. This mechanism has been verified by many publications (Hoier and Whitson 2001, Uleberg and Hoier2002). These displacements are characterized by developments of a nearly miscible transition zone that is created by a zone ofoil in equilibrium with gas that has lost its intermediates (Zick, 1998). Fig. 1shows the concept of condensing/vapourizingmechanism. In this study, simulations are based on the concept developed by Zick (1998).

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Fig. 1Oil and gas densities based on condensating/vapourizing mechanism. Net vaporization of heavy component at upstream ofthe front and net condensation of intermediate component at downstream of the front

Model DescriptionA 202015grid system in x, y and z direction, respectively, is considered for a 3D conceptual simulation model. The

reservoir size is 3500 ft by 3500 ft horizontally and has a thickness of 60 ft. Three layers are selected for more detailed studies.Layer 1 is from grid block 1 to grid block 5, layer 2 is from grid block 5 to 10 and layer 3 is from grid block 10 to 15 in zdirection. Two different sets of simulations including an oil reservoir and a gas condensate model are used in this study. Theoil reservoir model is initialized at a depth of 8335 ft with initial pressure of 3984.3 psia and an initial oil saturation of 0.8,

with porosity of 0.3. The Peng-Robinson equation of state at 160 has been used for PVT modeling of this simulation.Another model with the same geology is used for the gas condensate system. The gas condensate model is initialized at a depthof 7500 ft and an initial pressure of 3550 psia, with an initial water saturation of 0.16. Table 1shows the composition that hasbeen used for oil reservoir fluid and injection gas, which is used in one of the injection scenarios to compare with CO2

injection. Gas condensate composition is given in Table 2.Figs. 2-3show capillary pressure and relative permeability curves for the oil reservoir model. Corresponding curves for the

gas condensate reservoir are plotted in Figs. 4-5.One injector and one producer are located on the sides of the both reservoirmodels and completed in all layers. Table 3briefly describes the model properties for the oil and gas condensate reservoirs.Table 4shows geological scenarios that are considered for this study. A dip angle of 10 degree in the direction of the x axis is

considered with down-dip injection and production from up-dip of the reservoir. In some scenarios, up-dip injection isconsidered as well. It is also possible to consider other dip angles and well patterns, but in this study CO2injection behavior isthe main target.

Table 1Oil reservoir composition,

Composition Mole fraction(oil) Mole fraction(injection gas)

CO2 0 0

C1 0.5 0.77

C3 0.03 0.2

C6 0.07 0.03

C10 0.2 0

C15 0.15 0

C20 0.05 0

Table 2Gas condensate composit ion

Composition Mole fraction

CO2 0.0121

N2 0.0194

C1 0.6599

C2 0.0869

C3 0.0591

C4-6 0.0967

C7P1 0.0472

C7P2 0.0153

C7P3 0.0034

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So

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Table 3Reservoirproperties

Gas condensate Oil

Grid block dimensions (ft) 3500350060 3500350060Initial depth (ft) 7500 8335

Initial pressure (psia) 3550 3984.3

Saturation pressure (psia) 3550 2302

Layer 1 Grid blocks 1 to 5 Grid blocks 1 to 5Layer 2 Grid blocks 5 to10 Grid blocks 5 to10

Layer 3 Grid blocks 10 to15 Grid blocks 10 to15

Completion All layers All layers

Porosity 0.3 0.3

Swi 0.16 0.2

Table 4Scenario definitions

Scenario 1 (S1)

Kx=Ky, mD (all layers) 100

Kz, mD (all layers) 50

Scenario 2 (S2 - Heterogen layering, decreasing k with depth)

Kx=Ky, mD layer1 200Kx=Ky, mD layer2 100

Kx=Ky, mD layer3 50

Kz(all layers) 50

Scenario 3 (S3 - Heterogen layering, inc reasing k w ith depth)

Kx=Ky, mD layer1 50

Kx=Ky, mD layer 2 100

Kx=Ky, mD layer 3 200

Kz, mD (all layers) 50

Fig. 2Water-oilcapillary pressure and relative permeability,oil reservoir.

Fig. 3Gas-oilcapillary pressure and relative permeability, oilreservoir.

Fig. 4Water-oilcapillary pressure and relative permeability,gas condensate reservoir.

Fig. 5Gas-oilcapillary pressure and relative permeability,gas condensate reservoir.

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Simulation Scenarios and ResultsA. Oil Reservoir Model

CO2 injection in gas cycles of WAG scenarios and also continuous CO2 injecting are considered for the oil reservoirmodel. Different layering scenarios in a 10-degree dipping reservoir, with miscible and immiscible cases of CO2injection arecompared. Finally, rich gas injection is modeled and compared with the cases of CO2injection.

WAG schedules are defined and started just after opening the production well by a rate of . The first WAG

cycle starts after six months of water injection with rate of followed by six months of injecting CO2with a rate

of . These cycles repeatedly continue as far as the constraints for well control are fulfilled. Well restrictions arean injection bottomhole pressure (BHP) of 10000 psia and a production BHP of 1000 psia. Three geological scenarios for thedipping reservoir are considered for this study, as described in Table 4. Scenario 1 includes three layers with the same

permeability, scenario 2 includes a trend of decreasing permeability in deeper layers and scenario 3 includes a trend ofincreasing permeability in deeper layers. It has been attempted to determine the effect of injecting CO2in all these cases and to

evaluate the influencing parameters and heterogeneities on the result.CO2injection MMP has been obtained from slimtube simulation and the Pade approximation (Van Dayke, 1978) is used to

predict the infinite grid block results. Fig. 6 shows different MMP values that are calculated by PVT modeling and alsoslimtube simulations with different grid sizes. The best result is obtained from three highest number of grid blocks averaging,by the Pade approximation that is compatible with the PVT model result and this value is chosen for true MMP for this study.In Fig. 6 the effect of grid refinement on the result of slimtube simulation is shown, and the result is estimated for the case ofan infinite number of grid blocks. By this method, reliable MMP values could be collected from the calculations.

Fig. 6MMP calculation for CO2injection in oil reservoir (GB: number of grid bl ocks, SL: straight line approximation, Pol: polynomi aldegree two approximation)

As it can be observed in Fig. 7, after several cycles of CO2 WAG in the model, the average reservoir pressure isapproaching the MMP of CO2 injection for all the CO2 WAG scenarios and then the reservoir is pressured. In this case

reservoir pressure will be above MMP and saturation pressure most of the time. It has been shown in Fig. 8 that the highest oilrecovery is achieved in scenario 3 and the lowest is for scenario 2. Increasing the permeability trend to the deeper layersaffects directly the ultimate recovery of the system.

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GB 100 GB 200 GB 500 GB2500

GB5000

Infinity(SL)

Infinity(Pol)

Infinity(Pade 5Points)

Infinity(Pade 3Points)

PVTModeling

Grid Size Effect 2700 2475 2350 2250 2150 1950 1920 1922 1918 1892.59

MMP,psia

Grid size effect

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Fig. 7Average reservoi r pressure, CO2WAG. Fig. 8Oil recovery , CO2WAG.

To have better understanding of the injection slug movement, saturation maps are plotted at different times of thesimulation. Fig. 9shows the saturation profile after 13 years of WAG cycles for scenario 1. The cross-sections for differentlayering are plotted in Figs. 10-12for scenarios 1, 2 and 3 at the same time (dip angle is exaggerated in plotting to have betterdisplay). Better sweep efficiency occurred in the case of scenario 3 where the permeability trend is increasing with depth. This

is because of gravity effects in water cycles that tend to sweep lower parts and the lower permeability of shallower layerspreventing gas fingering and early breakthrough.

Fig. 9Oil saturation after 13 years, scenario 1.


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The same geology model is considered for continuous CO2injection. CO2injection is started by a rate of 14000 mcf/dand the production starts with rate of10000 stb/d . Fig. 13shows how the average reservoir pressure is changing with timedue to CO2injection below MMP. Pressure stabilizes around 1250 psia. In this case scenario 3 has the best recovery close tothe results of scenario 1, but scenario 2 has lower recovery due to higher values of permeability in upper layer that makes CO2bypass there.

Ultimate recovery is lower in pure CO2injection compared to CO2WAG. Economical analysis based on availability of

CO2 and water and also investigation of production per volume injected will result in the best scenario selection. Fig. 14compares oil recovery from each of the scenarios.

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Fig. 13Average reservoi r pressure, CO2injetion. Fig. 14Oil recovery, CO2injection.

Then it was attempted to inject CO2from up-dip and produce from down-dip to evaluate the differences. Fig. 15showstrends of average reservoir pressure due to CO2 injection and in Fig. 16 the oil recovery obtained in different scenarios is

shown. A higher volume of oil is recovered in this case and gravity helps down-dip production of the oil.

Fig. 15Reservoir pressure, up-dip CO2injecti on. Fig. 16Oil recovery, up-dip CO2injection.

To obtain more results on the effect of miscibility, CO2is also injected in WAG scenarios at immiscible conditions. The

same geology and WAG plan is set with a gas injection rate of 3000 mcf/dand a water injection rate of3000 stb/d . WAGscenarios start after two years of production with a rate of10000 stb/d . As it is demonstrated in Fig. 17, CO2is injected as animmiscible gas and becomes closer to the miscible condition at late simulation times. Fig. 18shows oil recovery of the three

scenarios based on immiscible CO2 injection. Recovery is in the lower range compared to CO 2 WAG because of lowerinjection rates and the same trend of production development is observed in three different layering scenarios. WAG cycles in

an immiscible case are performed in lower injection rates and then well controlling constrains continue to be valid longer.

Fig.17Average reservoi r p ressure, immiscible CO2WAG. Fig. 18Oil recovery, immiscible CO2WAG.

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Rich gas injection is considered in the WAG cycles (composition is given in Table 2) and is compared with CO 2injectionresults. The difference between MMP for both injection plans characterizes these cases. Fig. 19 shows average reservoirpressure of three scenarios due to injecting rich gas. A higher value of MMP is determined for this case through PVT modelingand is verified with slimtube simulation. The higher MMP makes the process to be at an immiscible condition in earlysimulation times. Fig. 20shows the values of oil recovery in different scenarios and almost the same trend is observed for all

the scenarios due to rich gas injection. A comparison of CO 2and rich gas injection in WAG, pressure and oil recovery inscenario 1 is presented in Figs. 21-22. A slightly higher value of produced oil is obtained using CO2as injected gas in WAG,

mainly at a late time of the simulation and this is related to MMP difference.

Fig. 19Average reservoi r pressure, r ich gas WAG. Fig . 20Oil Recovery, rich gas WAG.

Fig. 21Average reservoi r pressure, r ich gas and CO2WAG. Fig. 22Cumulative oil production, rich gas and CO2 WAG.

Different injection plans including CO2WAG, rich gas WAG, and up-dip and down-dip CO2injection are compared andresults are presented in Figs. 23-24. With the same amount of CO2injected, CO2WAG yields highest values of recovery inshorter time, but due to the higher injection pressure, gas will break through and well constrains are not valid anymore, whilein the case of CO2 injection breakthrough time is later and maximum possible recovery is related to up-dip CO 2 injection.Table 5demonstrates a brief comparison of these injection scenarios in homogeneous layers dipping reservoir.

Fig. 23Average reservoi r pressure, inject ion scenarios Fig . 24Oil recovery, injection scenarios

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Table 5comparing ultimate recovery and produced oi l i n scenario 1 (homogeneous layers)

Injection plan Injection location Miscibility conditionUltimate Recovery,

percentProduced oil*, MSTB

CO2WAG down-dip miscible 79.22 19882.36CO2injection down-dip immiscible 78.95 16845.88CO2injection up-dip immiscible 85.15 18246.62

CO2WAG down-dip immiscible 65.44 N.A. **

Rich gas WAG down-dip near miscible 76.57 19219.07*Produced oil at 50000 MMCF gas injected ** 16425.5 MSTB recovered after 20748 MMCF gas injected, then simulation stopped due to very low production BHP

B. Gas Condensate ModelAnother model is constructed with the same geological properties to investigate the process with presence of gas

condensate. Table 2 shows the gas condensate composition that is used for initialization of the model and Peng-Robinson EOS

at 200is set for the PVT model. The same well location is considered for this case but different well constrains have beenused. BHP for the production well is set at 500 psia and the injection BHP is set at 4000 psia.

In the gas condensate case it has been attempted to run the same WAG scenario using CO 2as an injection gas. Then inorder to evaluate the effect of pure CO2injection, C1combinations are also considered. Increasing enrichment levels of CO2in

CO2-C1combination will result in decreasing MMP as it is plotted in Fig. 25. After a critical enrichment level of 0.1015of C1, the combination will be a condensing-vaporizing miscibility mechanism and MMP gradually decreases while mixing

more CO2. According to calculation for the case of pure CO2injection, MMP 1745.02 psiais obtained while with mixing80 percent C1, MMP is 3051.82 psia and for pure C1the calculated MMP is 3480.81 psia. This combination of injection gashas been used in the simulation to verify the effects of different injection gases.

The same geological scenario is used and in all the cases after two years of gas production by the rate of 6200 mcf/d,WAG cycles start with CO2 injection rate of 7500 mcf/dfollowed by water injection rate of 7500 stb/d. All these cases areflooding of gas condensate systems below dewpoint pressure. Here, dropped out condensate is the prime target for enhancedrecovery and multi-contact miscibility could develop through the combined condensing/vaporizing mechanism.

Fig. 25CO2-C1enrichm ent level effect on MMP

It can be observed in Fig. 26that all of the scenarios occur above MMP and miscible injection condition is maintained. Theproduction continues to the end of the WAG plan and again scenario 3 has the highest value of ultimate condensate productionwhile it is very close to scenario 1 and scenario 2 is the lowest one while this time the values are almost the same at short

simulation time of the WAG. More than 80% of condensate is recovered in scenario 3 and scenario 1 while it is around 75% in

scenario 2 after 30 years of WAG cycles. Fig. 27shows condensate recovery by CO2WAG in the gas condensate model.

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E*=0.1015C1

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Fig. 26Average reservoi r pressure, CO2WAG in gascondensate reservoir.

Fig. 27Oil recovery, CO2WAG in gas condensate reservoir.

All the process is repeated again with pure CO2injection with rate of8000 mcf/d . Reservoir pressure response is plottedin Fig. 28, and again the process is occurring above MMP and miscible condition is achieved. Fig. 29is condensate recoveryby pure CO2 injection. More than 80% condensate recovery is achieved by this injection plan and scenario 1 that is

homogeneous layers has the best recovery that is showed in Fig. 29. Scenario 2 is moderate case and scenario 3 is the worstone. Here miscible oil bank is able to move and sweep condensate above it easier in a smooth path in homogenous layering

system. In scenario 3, the bank could penetrate from lower layers and best efficiency is not achievable. Multi-contact miscibleoil-bank could be seen in Fig. 30which is a plot of oil saturation after 10 years of CO 2injection. The condensing vaporizing

mechanism will result in an oil bank creation ahead of the front. This phenomenon is presented by Zick (1988) and discussedby Whitson and Hoier (2001). CO2is also injected from up-dip, Fig. 31shows the pressure and Fig. 32shows condensaterecovery. The same trend could be observed in this case.

Fig. 28Average reservoi r pressure, CO2injection in gascondensate reservoir.

Fig. 29Oil recovery, CO2injection in gas condensatereservoir.

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Fig. 30Oil saturation in scenario 1, CO2injection in gas condensate reservoir and oil bank cr eation.

Fig. 31Average reservoi r pressure, up-dip CO2 injection in

gas condensate reservoir.

Fig. 32Conensaterecovery, up-dip CO2injection in gas

condensate reservoir.To evaluate the effect of different combinations of injection gases, C1, CO2and a mixture of 80% CO2and 20% of C1are

used for gas injection cycles. Fig. 33shows the average reservoir pressure trend in these combinations and the MMP values. Inthe C1injection case, the process is always below MMP and immiscible gas injection is performed while in CO2injection the

system is always above MMP. In the case of a combination mixture of 80% CO 2, the process is in a near miscible condition.Condensate recovery can be observed in Fig. 34. In the pure CO2injection scenarios, recovery tend to be lower than other

cases in short term injection periods, while it exceeds and reaches the highest ultimate recovery at the end of the process.WAG with CO2, WAG with C1, and up-dip and down-dip CO2injection are compared and presented in Figs. 35-37.For

this reservoir condition, the highest ultimate condensate recovery could be achieved while performing CO2 WAG and C1WAG results in the lowest value of ultimate condensate recovery. In Table 6a brief comparison of all continuous injectionand WAG scenarios in gas condensate reservoir is showed. All the cases in Table 6 are from scenario 1 that is homogeneouslayering system. To be able to compare the cases economically, produced condensate at the same injected gas is also provided

in Table 6.

0

500

1000

1500

2000

2500

3000

35004000

4500

0 5000 10000 15000


Time, days

PAVG S1

PAVG S2

PAVG S3

MMP=1745.02 psi a

0

10

20

30

40

50

60

70

0 5000 10000 15000

Oilrecovery,%

Time, days

OILREC S1

OILREC S2

OILREC S3

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SPE 154062 13

Fig. 33Reservoir pr essure, injecting C1, CO2andcombination in gas condensate reservoir.

Fig. 34Condensate recovery, injecting C1, CO2andcombinationin gas condensate reservoir.

Fig. 35Reservoir pressure, comparing injection plans i n gascondensate reservoirs.

Fig. 36Oil production, different injection plans.

Fig. 37Oil recovery, different injection scenarios.

Table 6Comparing ultimate recovery and produced condensate in scenario 1 (homogeneous layers)

Injection plan Injection location Miscibility conditionUltimate condensate

recovery, percentProduced

condensate*, MSTB

CO2WAG down-dip miscible 81.96 2290.1

CO2injection down-dip miscible 81.76 1570.59

CO2injection up-dip miscible 60.40 1333.33

C1WAG down-dip immiscible 57.59 1608.88

80%C1-20%CO2WAG down-dip near-miscible 62.53 1748.64

*Produced condensate at 38000 MMCF gas injected

0

500

1000

1500

2000

2500

3000

3500

4000

0 3000 6000 9000 12000


Time, days

PAVG C1

PAVG CO2

PAVG 80C1-20CO2

C1 MMP=3480.81 psi a

80% C1-20%CO2MMP=3051.81 psia

CO2 MMP=1745.02 psi a

0

10

20

30

40

50

60

70

80

90

0 3000 6000 9000 12000

Conensaterecovery,%

Time, days

OILREC C1

OILREC CO2

OILREC 80C1-20CO2

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0 4000 8000 12000


Time, days

PAVG WAGCO2

PAVG WAGC1

PAVG CO2

PAVG CO2 UP-Dip

CO2 MMP=1745.02 psi a

C1 MMP=3480.81 psi a

0

500

1000

1500

2000

2500

0 30000 60000 90000 120000

Cumulativeoilproduced,

MSTB

Cumulative gas injected, MMCF

CUMOIL WAGCO2

CUMOIL WAGC1

CUMOIL CO2

CUMOIL CO2 UP-Dip

0

10

20

30

40

50

60

70

80

90

0 3000 6000 9000 12000 15000

Oilrecovery,%

Time, days

OILREC WAGCO2

OILREC WAGC1

OILREC CO2

OILREC CO2 UP-Dip

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14 SPE 154062

ConclusionA conceptual numerical simulation is carried out using a dipping reservoir model with both oil and gas condensate fluids.Different scenarios are compared and investigated through CO2EOR processes. According to the results of this study, thefollowing observations are made:

1. CO2injection in both the oil and the gas condensate dipping reservoirs could be achievable and good values of oilrecovery are obtained.

2. CO2WAG in dipping oil reservoir results in high recoveries based on injection pattern, MMP values and layering

systems. CO2 WAG in a reservoir with increasing permeability trend with depth (scenario 1) had the highestvalues of recovery. This is because of prevention from early gas breakthrough in upper layers and good sweepefficiency in lower layers.

3. In the oil reservoirs, it has been observed that immiscible up-dip continues CO2injection could achieve highestrecovery while higher oil production could be obtained in shorter time with the same value of gas injected in

miscible CO2WAG.4. CO2WAG in gas condensate systems seems to have the same value of condensate recovery in early times but

ultimate recovery trend is almost the same as the oil reservoir cases according to layering heterogeneity.5. In the case of pure CO2injection up-dip and down-dip, the homogeneous layering system showed highest possible

recovery. Here, the oil bank is able to move and sweep the condensate above it easier and in a smooth path in thehomogenous layering system. In scenario 3 the bank could penetrate from lower layers and the best efficiency isnot achievable.

6. CO2 injection is compared to the C1 and C1-CO2 injection combinations and this leads to higher variation in

ultimate recovery in the case of the gas condensate model. In this case, CO2injection is far above MMP and goodrecovery is achieved compared to other cases.

7. In all the dipping reservoir injection cases, heterogeneities can play both positive and negative role on therecovery based on the injection fluid type and schedule and it should be investigated individually in each case.

Nomenclature , , , , , , , , , , , ,

Greek

, ,

, , ,

Abbreviations

, , , , ,

1, 2 3 , ,

Aknow ledgementThe authors wish to express special appreciation to the research center BIGCCS (International CCS Center) for hosting the

research, and to STATOIL for the financial grant to the publication.

ReferencesAlavian S.A., Whitson C.H. 2005. CO2 IOR Potential in Naturally Fractured Haft Kel Field, Iran, International Petroleum Technology

Conference, held in Doha, Qatar 21-23 November, IPTC 10641Emera M.K., Sarma H.K. 2005, Genetic Algorithm (GA)-Based Correlations Offer More Reliable Prediction of Minimum Miscibility

Pressures (MMP) Between the Reservoir Oil and CO2 or Flue Gas, presented at Petroleum Society 6

th

Canadian internationalPetroleum Conference, Calgary, Alberta.

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15/15

SPE 154062 15

Grenwalder M., Clemens T. 2008. Immiscible Gas Injection: Challenges, Example of 16th

TH Horizon, Austria, presented at SPEEuropec/EAGE annual conferences in Rome, Italy, 9-12 June. SPE 113504

Hoier, L. 1997.Miscibility Variation in Compositional Grading Petroleum Reservoirs, PhD thesis, NTNU, Trondheim, Norway

Hoier, L. and Whitson C.H. 2001.Miscibility Variation in Compositionally Grading Reservoirs, SPE Reservoir Evaluation and EngineeringJournal

Karim F., Berzins T.V., Schenewerk P.A., Bassiouni Z.A., and Wolcott J.M. 1992.Light Oil Recovery from Cyclic CO2Injection: Influence

of Drive Gas, CO2Injection Rate, and Reservoir Dip, presented at SPE Rocky Mountain regional meeting held in Casper, Wyoming,May 18-21, SPE 24336

Uleberg K. Hoier L. 2002.Miscible Gas Injection in Fractured Reservoirs, presented at SPE/DOE improved oil recovery symposium held inTulsa, Oklahoma, US, 13-17 April. SPE 75146

Van Dyke, M. 1978. Perturbation Methods in Fluid Mechanic Parabolic Press, 2ndedition, 205-207Whitson C.H., and Brule M.R. 2000. Phase Behaviour, Monograph, SPE of AIME, Richardson, Texas

Zick A.A., 1986.A Combined Condensing Vapourising Mechanism in the Displacement of Oil by Enriched Gases, presented at 61st Annualtechnical conference of SPE held in New Orleans, LA, US, SPE 15493

Conversion Factor

1.589873 01 3.048 01 2.831685 02

6.894757 00

141.5/131.5 32/1.8 02

co2 -wag

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