Storage and utilization of CO2 in petroleum reservoirs — A simulation study

Energy Convers. Mgmt Vol. 34, No. 9-11, pp. 1205 1212, 1993

0196-8904/93 $6.00+0.00 Copyright © 1993 Pergamon Press Ltd

Printed in Great Britain. All rights reserved

STORAGE AND UTILIZATION OF CO 2 IN PETROLEUM RESERVOIRS - A SIMULATION STUDY M . R . Islam* Department of Geological Engineering South Dakota School of Mines and Technology, Rapid City, SD 57701, USA

and A. Chakma Department of Chemical and Petroleum Engineering University of Calgary, Calgary, Alberta, CANADA T2N 1N4 *Corresponding author

ABSTRACT There is a growing concern about the effect of greenhouse gases on global temperatures and its consequences. Among many greenhouse gases, carbon dioxide produced as a result of fossil fuel burning is a major contributor due to the huge volume emitted into the atmosphere. Because fossil fuels remain the driving force of modern economies, any economic ~owth in the developed or developing countries results in an increased emission of carbon dioxide. Consequently, reduction of carbon dioxide emissions has become an important issue. The Intergovernmental Panel on Climate Change (IPCC) estimates that a worldwide reduction o.f the emission of green house gases by more that 60% is necessary to avert the global climate change. It is now well recognized that the disposal issue is the most important obstacle to overcome for a practical solution of the carbon dioxide problem. In this paper a simulation study on the storage and utilization of carbon dioxide in petroleum reservoirs has been carried out. For simple storage, simulation studies to determine the capacity of a given reservoir are conducted for different reservoirs with a wide range of governing parameters. Major parameters studied are: initial reservoir pressure, final average reservoir pressure, impurities in the injected gas, petrophysieal properties of the reservoir, and initial fluid saturations. For the utilization, simulation studies are carried out for both miscible and immiscible flooding enhanced oil recovery. (EOR) processes. It is difficult to maintain carbon dioxide miscibility m a reservoir. It is found that immiscible but stable injection of carbon dioxide may be very effective in recovering oil. KEYWORDS CO2 storage, disposal, petroleum reservoirs, enhanced oil recovery. INTRODUCTION Recently, many countries have signed .the green house gas abatement protocol of the Rio Earth Summit and have committed to stabilizing green house gas emissions at 1990 level by the year 2000. This goal is not a very easy one to achieve without a significant reduction in energy consumption. While separation of carbon dioxide from major production sources, such as power plants and petrochemical complexes, are technically feasible, the costs remain prohibitive. Once carbon dioxide is separated, it requires disposal or storage. There is no existing solution to the disposal and storage problem. Different options of disposal are being considered by many researchers around the world. These range from disposal in deep ocean to utilization of carbon dioxide in manufacturing of chemicals. Most of the concepts for carbon dioxide disposal are at very early stages of development with the exception of one that involves injection of carbon dioxide in 1205

1206

ISLAM and CHAKMA: CO2 IN PETROLEUM RESERVOIRS

petroleum reservoirs. Recovery of carbon dioxide at its source of production and recycling it into the reservoir provide an attractive option of reducing carbon dioxide emissions, at least temporarily. Carbon dioxide has found wide applications in EOR. The injection of pure carbon dioxide into oil reservoirs has been shown to be capable of recovering significant amounts of oil after water flooding (Stalk'up, 1978). Carbon dioxide has also been found to improve oil production rates when used in conjunction with steam flood in the presence of nitrogen and/or naphtha. Liquid carbon dioxide may also be used as the carrying fluid in sand fracturing operations, eliminating formation damage normally associated with other fracturing fluids and rapid clean up of the well, following stimulation. In addition, carbon dioxide can also be injected into condensate bearing reservoirs for pressure 'maintenance purpose, so that valuable condensates can be recovered. Most EOR projects require large amounts of carbon dioxide and thus can serve as a major sink for carbon dioxide disposal. There are two types of recovery schemes in which carbon dioxide can be utilized, namely immiscible flooding in which the injected carbon dioxide simply provides an added driving force for oil to flow out of the reservoir pores and miscible flooding where the injected carbon dioxide becomes miscible with the oil under appropriate temperature and pressure conditions. The presence of carbon dioxide results in swelling of the oil along with a reduction in its viscosity, thus making the oil more mobile. However, not all the reservoirs are suitable for miscible carbon dioxide flooding EOR schemes. Traditionally, light oil reservoirs of sandstone or carbonate types, having an oil with API gravity of greater than 25 ° and viscosity less than 20 mPa.s, have been considered to be suitable for miscible carbon dioxide floods. Recently moderately heavy oil reservoirs are also being investigated for immiscible carbon dioxide flooding projects (Chakma apd Jha, 1991; Islam et al., 1993) with positive results. Typically, 10,000 m e of carbon dioxide is consumed per m of incremental oil recovered. For a modest 1% incremental oil recovery in Alberta, Canada by carbon dioxide injection, over 5 billion me/year of carbon dioxide will be required in Alberta alone. A preliminary study suggests that oil recovery projects alone can recycle all of the carbon dioxide generated by large sources, leading to 20-30% reduction in carbon dioxide emissions from some areas (Chakma, 1992). Numerical Simulation Recently, many reservoir simulators have been reported on numerical modeling of carbon dioxide injection. It is ~enerally agreed that a carbon dioxide simulator should be capable of modeling viscosity reduction, swelling of the oil phase, dissolution in the aqueous phase, and compositional .flow (Nghiem and Li, 1986). While considering carbon dioxide injection m a depleted reservoir, one has to include the effect of miscibility of carbon dioxide in oil, especially for light oil reservoirs (Rathmell et al., 1971; Holm and Josendal, 1974; Metcalfe and Yarborough, 1979). At a high injection pressure, carbon dioxide displaces oil through multiple contact miscibility. This requires carbon dioxide to move some distance through the reservoir with dispersion in the longitudinal as well as transverse directions. Additional extraction by carbon dioxide re-establishes miscibility. Even though rigorous modeling of carbon dioxide injection would require incorporation of all these effects, Islam et al. (1992), who used a black-oil simulator, showed that a simplified approach might work as well. In this paper, we have taken a more comprehensive approach'and used a compositional simulator for modeling all aspects of carbon dioxide injection. In this paper, Darcy's law is used along with conservation of mass to model fluid flow in the reservoir. Radial flow (radial geometry) is assumed near the wellbore and linear flow

ISLAM and C H A K M A : CO 2 IN PETROLEUM RESERVOIRS

1207

(cartesian geometry) is used farther away from the wellbore. These equations are coupled with a rigorous wellbore model. The wellbore model consists of time dependent, three-phase, one-dimensional, mass and momentum balance equations. It also allows the selection of turbulent or laminar flow in the wellbore. For the case of gas injection only (storage application), the wellbore flow is reduced to single-phase flow. RESULTS AND DISCUSSION' The reservoir equations are solved along with a different set of wellbore equations. Details of the numerical scheme has been given by Islam and Chakma (1990). Figure 1 shows the reservoir geometry used for numerical simulation. The horizontal well is placed in the middle of the reservoir. Because we are dealing with mainly gas injection and storage, the location of the well does not have much impact. However, for the case of oil recovery with g.as injection, one has to inject carbon dioxide at the top of the reservoir to assure stability of the displacement front. This aspect has been studied elsewhere (Islam et al., 1993). For all the cases, a water zone, containing 100% water saturation, was assumed to be present beneath the reservoir. Figure 2 shows the configuration of the injection/production scheme for the enhanced oil recovery application of carbon dioxide injection. The horizontal well extends to 500 m. Oil viscosity under standard conditions was considered to be 10 mPa.s for all cases. The water-oil relative permeability and capillary pressure data were taken from Islam and Chakrna (1990) and carbon dioxide data were taken from Donaldson et al. (1989).

Impermeabl barrieer Horizo~

CO~ injection H°riz°nt~able

Fig.1 CO 2 injection well for storage

Fig. 2 I n j e c t i o n / p r o d u c t i o n w e l l s f o r enhanced oil recovery with CO 2

barrier

CO 2 Storage A constant injection rate of 3.0 103 m3/day was assumed. Numerical runs were started with an injection pressure 0.3 MPa higher than the initial reservoir pressure and were continued until a final injection pressure of 14 MPa was reached. This pressure would correspond to a maximum allowable pressure for most shallow formations (a depth of around 630 m). A higher pressure can be used if the depth of the formation is higher. Following different aspects of carbon dioxide storage were studied. Effect of Initial Reservoir Pressure. Four numerical simulation runs were conducted to investigate the effect of initial reservoir pressures. For all these runs, initial oil saturation was considered to be 5%. Figure 3 shows total carbon dioxide storage amounts for various initial reservoir pressure

1208

ISLAM and CHAKMA: CO2 IN PETROLEUM RESERVOIRS

Kx= O.083dercy = OOS3darcy = O0083d~cy so~ 5% 20~

~

7e

eok o

7e~

z:i

7a ~

• I

~L

K~= 0 083 darcy K~= 0O83 darcy

0

Kz= 00083 darcy So= 5% s,.. L:,o~ tn~aalreserver pt6ssure = 0 7 MPa

C)

2~ "k 4o

I 05

I

J

10

15

20

25

30

35

40

Initial r e s e r v o i r p r e s s u r e , M P a

Fig. 3 Effect of reservoir pressure

e5

=s

los

~ls

Minimum miscibility pressure, MPa

Fig. 4 Effect of miscibility pressure

cases. Because all runs were discontinued when the injection pressure exceeded 14 MPa, total storage amounts were expected to decline linearly with increasing initial pressures. This trend can be seen from the figure. However, as the initial pressure is substantially increased, the storage capacity does not seem to decline at the same rate as in lower pressures. At higher pressure higher amounts of gas dissolution in both oil and water phases is expected. This may account for this peculiar behavior. Effect of Miscibility Pressure. The effect of miscibility pressure was studied in order to observe the role of impurities in carbon dioxide. A small amount of impurities (e.g., flue gas nitrogen, oxygen) may increase the miscibility pressure substantially. Figure 4 shows that as the miscibility pressure increases, there is a sustained decrease in storage capacity of a reservoir. However, the magnitude of the decline is rather small. This result is encouraging because this would indicate that carbon dioxide does not need to be purified prior to storage. Unless there is any toxic contaminant in the gas, the unpurified gas can be injected without sacrificing much storage ability. Figure 5 shows the effect of miscibility pressure on reservoirs with high oil saturation. Here it is assumed that no oil is being produced. Note that in presence of oil, the decline in storage ability with increasing miscibility pressure is steeper than the case of low oil saturation. A high oil saturation is more likely to be affected by miscibility of the gas. Effect of Reservoir Porosity. Five numerical simulation runs were conducted to observe the effect of reservoir porosity on gas storage ability of a reservoir. Figure 6 shows the results of these runs. As can be seen from this figure, porosity has profound effect on total storage capability of a reservotr, especially when the porosity is in the smaller range. As the porosity becomes hi~her, the storage capacity does no longer increase linearly. Note that all these runs were conducted with an oil saturation of 50%. Consequently, with increasing porosity, the dissolution of gas in the oil phase plays a more important role in the process. In any case, the storage capabihty of the reservoir continues to rise with increasing porosity.

I S L A M and C H A K M A " C O 2 I N P E T R O L E U M

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RESERVOIRS

1209

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Porosity, fraction

M i n i m u m miscibility p r e s s u r e , M P a

Fig. 6 Effect of reservoir porosity

Fig. 5 Effect of miscibility pressure in presence of high oil saturation

Effect of Oil Saturation. Initial oil saturation plays an important role on storage ability of a reservoir. This effect was investigated through a series of numerical runs with reservoir oil saturations ranging from 5% to 50%. Figure 7 shows the effect of oil saturation on final carbon dioxide storage volume of the reservoir. As the oil saturation increases, the storage capacity decreases almost linearly (except for the last point). However, the decrease is not as steep, as one would expect from pore volume available for gas alone. In fact, part of the oil acts as a storage site with increasing value for higher pressure. Consequently, for a high oil saturation of 40% the storage capacity does not decline very much. No higher oil saturation was investigated because a very high oil saturation will make a reservoir unsuitable for gas storage without having an oil production well in place.

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Oil satu r ati o n

Fig. 7 Effect of oil saturation

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20

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Final a v e r a g e reservoir pressure, M P a

Fig. 8 Effect of final pressure

Effect of Final Average Pressure. A series of runs was conducted to investigate the effect o t final average reservoir pressures on total gas storage ability of a reservoir. Note that this study is equivalent to investigating the role of maximum allowable injection pressure without invoking fracture in the reservoir. As the depth increases so does the fracturing pressure of the reservoir. For most shallow reservoirs, 20 kPa/m gradient should be used in order to avoid fracturing the reservoir. Consequently, the gas storage activity will be limited to a maximum injection pressure below the fracturing pressure. Because the injection pressure will

ISLAM and CHAKMA: CO2 IN PETROLEUM RESERVOIRS

1210

depend largely on the permeability and size of the reservoir, it was felt more appropriate to study the effect of pressure in terms of average reservoir pressure. Figure 8 shows this effect and indicates clearly that a higher final reservoir pressure (deeper formation) will lead to higher capacity of gas storage. However, this increase is steeper for the lower range of pressures. This behavior is expected because of unique pressure-volume relationship of carbon dioxide. This study indicates that the gas storage capability can be doubled by using a deeper formation as the storage site. Effect of Permeability. Even thouglt permeability itself does not alter the gas storage capacity of a reservoir, permeability plays a major role in determining injectivity and pressure build up in the reservoir. A series of numerical simulation runs was conducted to observe the effect of permeability (vertical permeability being 10% of the lateral permeabilities) on time required to reach a given injection pressure. Results are shown in Fig. 9.

44 I~= 10%OfKI or Ky

=,o ,ao ,~of /

So=5%

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Inl~alreservoirpressure = 2 MPa ]

0010

010

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t00

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Permeabilityinxandy directions,darcy

Fig. 9 Effect of permeability

Fig.

0

04

oe

12

1e

2

24

• Daysof production, 103days

2a

10 Oil recovery with immiscible gas injection

Permeabilities are varied from 0.001 darcy to 10 darcy. For all these runs all other relevant reservoir data were kept unaltered. Figure 9 shows that time required to reach final injection pressure of 14 MPa is reduced exponentially when the lateral permeabilities are increased. High reservoir permeabilities indeed help pressure propagate through the reservoir. This may in turn help maintain a miscible front throughout the reservoir if the reservoir pressure is hi~her than miscibility pressure of the system. However, maintaining misctbility may be impractical when the oil saturation is low. Enhanced Oil Recovery with CO2 A series of numerical simulation runs was conducted for evaluating the potential of off recovery with carbon dioxide injection. The configuration of the injection/production scheme is shown in Fig. 2. Note that the vertical injection well is located 200 'm away from the horizontal produ~tim] well. The pore volume affected by the process was considered to be 10 m and porosity to be 0.32. This configuration was chosen in order to inject gas using gravitational forces which would ensure stable displacement for both miscible and immiscible gas injection for low flow rates. It is important in this case to use stable displacement. This aspect has been studied in detail

1211

ISLAM and CHAKMA: CO: IN PETROLEUM RESERVOIRS

recently by Islam et al. (1993). In the present study, unstable relative permeabillties for unstable displacement are taken from Islam et al. (1992). Figure 10 shows how an unstable displacement may lead to early gas breakthrough. For the same scheme, as flow rate is lowered stable front is established despite high mobility ratio due to the injection of gas with a vertical head. For carbon dioxide injection, oil production continues even after gas breakthrough. At the end of 2800 days, close to 70% of the oil in place is recovered when the displacement front is maintained stable.

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04

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Fig. 11 Oil recovery with impure CO 2

0 [ o

,

=

o=

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I le

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=

I 24

I

t 28

Days of production, 10 'days

Fig. 12 Comparison o f miscible and immiscible CO 2 injection

The possibility of using impure carbon dioxide is investigated by using a different set of relative permeability and volume-pressure data (Fig. 11). Some of this point was clarified earlier by Meszaros et al. (1990) and Islam et al. (1992). Note that even for impure carbon dioxide (e.g., in presence of flue g a s ) , oil recovery is high if a stable displacement front can be maintained. Of course, this front can be maintained by using gas injection through a structurally high well and low rate of injection. A comparison between miscible and immiscible displacement oil recovery is made in Fig. 12. For the case of miscible carbon dioxide injection, the gas breakthrough takes place after more than 80% pore volume of gas injection. This behavior is expected if miscibility throughout the reservoir can be maintained. However, depending on heterogeneity in the porous, media, it. may not be easy to maintain such miscibility, especially when the reservozr zs shallow and high injection pressure is prohibitive. CONCLUSIONS A numerical simulation study is conducted to study the potential of carbon dioxide storage in depleted gas reservoirs. Results show that the use of a prudent injection scheme would allow one to use a single injection well to store a standard carbon dioxide volume more than 150 times the pore volume of the reservoirs. The storage capacity of the reservoir increases substantially for high-porosity reservoirs. A high permeability, on the other hand decreases time to reach equilibrium reservoir pressure. It is recommended that the injection pressure be kept well below the fracturing pressure of the reservoir and the final reservoir pressure be left slightly below the initial reservoir pressure (prior to depletion). The use of impure carbon dioxide does not decrease the storage capacity very much.

1212

ISLAM and CHAKMA: CO2 IN PETROLEUM RESERVOIRS

Both miscible and immiscible applications of carbon dioxide recover substantial amounts of oil. However, in both cases it is important to maintain a stable displacement front which can be maintained by injecting gas from a structurally higher location and by using low injection rate. REFERENCES

Bailey, R.T. and I.C. Webster (1991). Progress in a study of CO 2 capture and use for EOR. paper presented at the 41st Canadian Chemical Engineering Conference, Vancouver, BC., October 7. Chakma, A. (1992). CO 2 Separation and recycling a route to zero net production of CO 2 in the Alberta energy industry. Energy Convers. and Mgmt., Vol. 5-8, 795-802. Chakma, A. and K.N. Jha (1991). CO 2 injection with horizontal wells for the enhanced recovery of heavy oils: a comparison of 2D and 3D model experiments. SPE 22593, SPE Ann. Tech. Conf., Dallas, October 6-9. Donaldson, E.C., Chilingarian, and Yen, T.F., (1989). Enhanced Oil Recovery, H processes and operations. Elsevier. Holm, L.W. and Josendal, V.A. (1974). Mechanisms of oil displacement by carbon dioxide. Trans AIME, vol. 257, 1427. Islam, M.R., A. Chakma and K.N. Jha (1993). Heavy oil recovery by inert gas injection with horizontal wells. J. Pet. Sci. Eng., in press. Islam, M.R., Erno, B.P., and Davis, D. (1992). Hot gas and waterflood equivalence of in situ combustion. J. Can. Pet. Tech., 31(8), Oct., 44-52. Meszaros, G., Chakma, A., Jha, K.N., and Islam, M.R. (1990). Scaled model studies and numerical simulation of inert gas injection with horizontal wells, paper SPE 20529, Ann. Tech. Conf., New Orleans, LA. Metcalfe, R.S. and Yarborugh, L. (1979). Effect of phase equilibria on the CO2 displacement mechanism. Soc. Pet. Eng. J., 19 (8), 242-252. Nghiem, L.X., and Li, Y.K., (1986). Effect of phase behavior on CO2 displacement efficiency at low temperatures: model studies with an equation of state. SPE Res. Eng., July, 414-422. J.J., Stalkup, F.I., Hassinger, R.C. (1971). A Laboratory Investigation of Miscible Displacement by Carbon Dioxide. Soc. Pet. Eng. Ann. Meet., Houston, Texas, SPE 3483. Rathmell,

0

Stallmp, F.I. (1978). Carbon Dioxide Miscible Flooding: Outlook For The Future, J. Pet. Tech., Aug., 1102.

Past,

Present

and