ENHANCED OIL RECOVERY BY WATER ALTERNATING GAS (WAG) INJECTION

D. H. TEHRANI, A. DANESH, M. SOHRABI AND G. HENDERSON

Department of Petroleum Engineering, Heriot-Watt University

Edinburgh, UK

Abstract Normally, a significant quantity of oil remains in an oil reservoir after waterflooding. Some of this oil may be economically produced by WAG injection, an EOR method, which has been successfully used in some reservoirs. However, the physical processes underlying the complex three-phase flow in WAG has not been well understood. There is a need for developing accurate three-phase capillary pressure and relative permeability functions, so that a reliable reservoir performance prediction can be made, before undertaking the relatively large investment for WAG. At Heriot-Watt U. we have an integrated experimental (micromodel) and theoretical (network modelling) programme of research to develop a simulator which can calculate the above mentioned functions. In this presentation the author will show videotape of the WAG process, taking place in the porous media of a micromodel. It will allow the audience to see how the fluids actually flow and displace each other and the important role which capillary pressure plays. Some results of the research will also be presented. Introduction Waterflooding, gas injection and water-alternating-gas injection (WAG) are well-established methods for improving oil recovery. In reservoirs that have been waterflooded, it is still possible to recover a significant part of the remaining oil by injecting gas alternately with water. Gas can occupy part of the pore space that otherwise would be occupied by oil, thereby mobilising the remaining oil. Water, injected subsequently, will displace some of the remaining oil and gas, further reducing the residual oil saturation. Repetition of the WAG injection process can further improve the recovery of oil. Christensen, Stenby and Skauge1 recently reported an excellent review of some sixty field-applications of WAG. Several field trials have been reported as being successful, e.g., in Kuparuk2, Snorre3 and Gulfaks fields4. Both immiscible4-6 and miscible gases7 have been used. A very large number of coreflood experiments8-12 and analytical and numerical simulations11,14 have been carried out. A recent study has even considered the WAG process for improving the hydrocarbon recovery in gas/condensate reservoirs13. Most of the research work, conducted so far, has been on either core flooding8,9,10 or numerical simulation11,12, sometimes alongside field trials. The relationship between the injection gas/water ratio and oil recovery has been empirically investigated using core displacement experiments, often at low pressure and generally with water wet cores8,10. Micromodels were used as early as 1960 for fluid displacement studies15. Some low -pressure micromodel studies of three-phase displacement

have also been performed16,17. However, as far as we know, no micromodel visualisation of the WAG injection has been carried out to directly observe the physical processes taking place in the porous media, using live oil, live water in equilibrium with injection gas and models with different wettability. Larsen et al.18 reported some limited results of their WAG micromodel studies. To do reservoir development planning, for possible implementation of a WAG scheme, the operator needs reliable performance and hydrocarbon recovery prediction, needed for accurate economic evaluation. To achieve this, good simulation incorporating proper reservoir fluid and rock description is needed. This requires accurate sets of relative permeability and capillary pressure functions for each fluid phase, in a three-phase fluid flow regime. The WAG process also involves another major complication. In each cycle of water injection the process is of an imbibition type, whereas as soon as gas injection begins the process will switch to the drainage flow. Therefore, the hysteresis effects have to be accounted for, also. But it is impractical to measure these functions and their hysteresis effects for all the different rock types and fluids present in a reservoir and describe them in terms of IFT which, itself is a function of fluid composition and pressure. We are attempting to develop a 3-phase 3-D mathematical network simulator, which has in it all the significant physical flow processes involved in WAG injection, formulated as accurately as possible. But to gain confidence that such a simulator can indeed reflect the physics of the flow realistically, we test it against a series of WAG experiments performed using micromodels. We can conduct the actual WAG injection, observe and record the flow processes and measure the model fluid saturations and recoveries. To enable us to magnify and view the pore scale images and to analyse the fluid flow, we have had to use 2-D glass micromodels and to use model fluids with known properties. Although the results will not be directly applicable to real reservoirs, they can be used to verify the accuracy of the predictions made by our network model simulator. We will run the pore scale simulator to predict the fluid distributions and the recoveries for a given set of pore geometry, wettability and fluid properties. If these agree with those observed and measured in the micromodel, we shall then have enough confidence, to operate it with real reservoir fluids and rock properties in 3-D mode, to calculate the required pore scale relative permeability and capillary pressure functions. These will later be upscaled for use in the numerical reservoir scale simulation. Objective The objective of the current micromodel studies is to improve our understanding of the physical principles underlying such processes taking place in porous media and to develop a network model simulator that can produce complex three-phase relative permeability and capillary pressure functions. Observing and recording the fluid flow behaviour within the micromodel during the WAG injection process will help to achieve this. The video record of the fluid displacements will be used to obtain qualitative and quantitative information on three-phase fluid flow during WAG injection. These will then be used to compare with the results of the network model, which will attempt to simulate the same processes, using the micromodel fluids and geometrical data. If the simulated results match the pictures and the recovery data obtained by the experiments reasonably well, then it can be confidently used to simulate and obtain the three-phase relative permeability and capillary pressure functions, using realistic reservoir rock and fluid properties in three-dimensional space.

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Experimental Facilities These have been described in our previous paper19.

Test Fluids The equilibrated fluids used in the experiments consisted of distilled water, n-decane and methane. To distinguish between the liquid hydrocarbon and the aqueous phase, the colour of the n-decane was changed to red using a hydrocarbon soluble dye (Sudan Red), and similarly, the colour of the water was changed to blue using a water soluble dye (Methyl Blue). Both the blue water and the red n-decane were filtered using fine filter papers to remove any undesolved dye particles. Fluid Preparation - Filtered blue water and methane were brought into equilibrium at the desired pressure and temperature. The same procedure was followed for the equilibration of gas and oil. The solubility of oil in water was considered to be negligible (at 500 psia and 100 oF). Fluid Interfacial Tensions: The equilibrium IFT of the water, n-decane, methane system at 500 psia and 100 °F, were estimated as follows:

Interfacial Tension/mNm-1 Gas/Oil20 (σgo) 15

Gas/Water21(σgw) 65

Oil/Water21(σow) 41 So/w.g = Spreading Coefficient of oil over water = σgw-(σgo+σow)=+ 9 mNm-1. The positive value of the spreading coefficient indicates that there will always be a film, or a layer, of oil spread between gas and water. The resolution of the images does not permit the viewing of the thin oil films, which can be on the order of one nanometer across22. Test Procedure The following procedure was followed for all the tests reported. Initially, the micromodel was saturated with clear distilled water and pressurised to 500 psia and subsequently displaced with blue live water, equilibrated with gas at 500 psia and 100 oF. To simulate the primary drainage of water (initial migration of oil into the water bearing porous medium) equilibrated oil (red n-decane), was injected from the top of the vertical micromodel, and injection continued until oil reached the base of the micromodel. To avoid oil getting into the lower pipes containing the water and gas phases, the oil flood was stopped at the bottom of the micromodel. Fig . 1 shows an example of a section of the micromodel when 100% saturated with equilibrated blue water, with Fig. 2 showing the irreducible water saturation established after oil injection, at the prevailing flow rate. In both cases the micromodel was scanned vertically in 10 separate sections. In these Figures, and throughout this paper, only the images of the middle section are presented, although the images of the entire micromodel were used for saturation and recovery calculations.

As soon as oil injection was stopped at the bottom of the micromodel, a spontaneous imbibition of water into the micromodel was observed. The volume of the imbibed water was, however, very small. The model was then waterflooded at a low rate of 0.01 cm3/h from the base to establish the waterflood residual oil saturation (Sorw). This rate corresponds to a capillary number of 2.5E-7, using single-phase flow area, and 5.0E-7 for two-phase flow area. The magnitude of capillary number indicates a capillary dominated flow regime, which is consistent with the observations. Water was observed to flow mostly through the sharp corners of the pores (as can be visualised in the corners of a square tube). This will be referred to as ‘corner filament flow’. The water filaments were seen to thicken progressively leaving oil filaments in the middle of pore bodies and finally causing oil snap off at some pore throats. The fluid distribution in the micromodel at the end of water flooding is shown in Fig. 3 . The entire flow process was recorded on video, and still pictures of the final fluid distributions were taken digitally and stored in computer. Fig. 4 is a magnified image of a section of the micromodel at the end of primary drainage of water (oil injection through water saturated micromodel), which demonstrates the relative position of the wetting phase (blue water) and non-wetting phase (red oil), in a strongly water-wet micromodel. The small pores and the dead-end pores are mostly occupied by water. The direction and the shape of the water-oil interfaces are good indication of strongly water-wet conditions. Fig. 5 shows a magnified image of the same section of the micromodel at the end of the waterflood. Comparison of Figs 4 and 5 highlights the fact that during waterflooding oil was displaced by corner filament flow of water rather than by a piston-like displacement. The slow thickening of water filaments at the sides and corners of oil filled pores during waterflooding was a consequence of a capillary dominated flow regime. Waterflooding of an oil-wet micromodel (not presented in detail here) showed the opposite, i.e., water flowed through the pores in piston-like displacement. Each WAG cycle begins with gas injection and ends with water injection. Five cycles of WAG injection were conducted. In each cycle, the injection of gas or water continued until no further oil production or change in fluid distribution occurred. To distinguish the colourless gas from the colourless glass (resembling grains in a natural porous medium), gas was digitally coloured in yellow, using an image analysis computer program. Fig. 6 shows the fluid distribution in the micromodel after the first cycle of gas injection, with the blue, red and yellow colours representing water, oil and gas respectively. Due to the relatively low interfacial tension between gas and oil (15 mNm-1) and adverse viscosity ratio (0.017), gas has channelled mainly through the oil occupied pores of the micromodel. At the end of gas injection, water injection commenced again at the same rate of 0.01 cm3/h (velocity of ~ 1.2 m/d). During water injection, corner flow of water resulted in water filaments surrounding the gas occupied pores and thickening, until the gas blobs became unstable and finally collapsed. The snap-off of the gas phase occurs as a result of capillary competition between the different phases. Fig. 7 shows the fluid distribution in the micromodel at the end of the water injection period of the first cycle. The fragmentation of the gas blobs is clearly observed. Fig. 8 shows the fluid distribution in the model after the second gas injection, and comparison with Fig. 6, reveals that more pores have been invaded by gas. Fig. 9 shows the micromodel after water injection period of the second cycle, and water has again resulted in further gas snap-off and fluid redistribution. Alternating gas and water injection continued until five cycles were completed. Figs. 10 and 11 , show the results of the fifth WAG cycle. A sequence of events similar to the previous WAG cycles occurred. Comparison of Fig. 11 with Fig. 6 shows that more gas has been trapped and more oil has been recovered. Fig. 12 depicts the recovery of oil during the test with the vertical axis showing the amount of oil recovered, at each stage of the experiment, as percentage of the initial waterflood

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residual oil. This Figure shows that the majority of the additional oil (some 14%) is recovered during the first two cycles and as the result of five cycles of alternating injection of gas and water a total of 15% of the remaining oil, after water flooding, has been produced. Discussion During the initial waterflood, as water was the wetting phase and the rate of water injection was well within capillary dominated regime, water flowed in the corners of the pores in the form of filaments surrounding the oil present in the larger pore bodies. These water filaments were seen to thicken progressively leaving oil filaments in the middle of pores and finally causing oil snap off at some pore throats28. Fig. 13 shows how the wetting phase can imbibe in the sharp corners of a square tube. The micromodel pores, etched by hydrofluoric acid on a glass, are not exactly in square shape, but they do have some sharp corners in which the wetting phase can advance. The oil recovery by waterflood occurred as the result of this corner filament flow of water rather than by piston-like displacement. As the IFT between gas and oil is less than the IFT between gas and water, when gas is encounters the pores of equal radii, it prefers entering those filled with oil rather than water. The invasion of oil filled pores by gas causes a small bank of oil to move ahead of gas front. The oil flowing ahead of the gas is added to the oil already present in those pores, resulting in an improvement in the oil mobility. The oil recovery by initial gas injection, however, is very small, in the order of 6% of the water flood residual oil. During the subsequent water injection, water invades the gas filled pores. Consequently, the gas channels are observed to become narrower as the water filaments grow, and finally the gas becomes fragmented by snapping off which takes place at some pore throats. After switching from water injection to gas injection, some more pores are invaded by gas. Thus the fluid distribution in the micromodel for this second cycle of gas injection is different from that of the first cycle. This is also observed for the first and second cycles of water injection. Comparison of Figs. 6 to 11 shows that the fluid distribution within the micromodel changes each time a new fluid is injected. However, further change in fluid distribution diminishes as the WAG injection proceeds. After the third WAG cycle no significant change of fluid distribution is observed within the micromodel. Fig. 12 depicts the recovery of additional oil after waterflooding, attributable to WAG injection. The initial oil saturation, Soi was 47% of the pore volume and the residual oil saturation (Sorw) at the end of initial waterflood in this experiment was 25% PV, i.e., 53% of initial oil in place. Five cycles of WAG injection produced 21.7% of that remaining oil, which is 11.5% of initial oil in place. The extra oil recovered after two cycles of WAG was 18.8% of Sorw, which is 10% of initial oil in place. This shows that the majority of the benefit of WAG injection has come after the first two cycles. It should, however, be remembered that these are the results of an experiment carried out with a 2-D water-wet micromodel. The figures are not directly applicable to real field conditions, but can be used to verify the validity of the network simulator, when it is also run with a 2-D water-wet system. Relative permeability functions applicable to real field conditions will be obtained later, using the verified network simulator in 3-D and 3-Phase mode with realistic rock and fluid data. Conclusions The results of the reported experiment, which was performed in strongly water-wet glass micromodel, can be summarised as follows: 1. During the initial waterflood, water advances in pores by the process of ‘corner filament flow’. The water filaments, that surround the oil present in the larger pore bodies,

thicken progressively and leave oil filaments in the middle of pores and finally cause oil snap off at the pore throats. Consequently, during water flooding oil production is controlled by filament flow rather than by piston-like displacement, at the pore level. 2. The positive spreading coefficient, in the reported experiment, results in a layer and or a film of oil to be always present between gas and water, in pores that contain all three phases. During gas injection, when gas encounters pores of equal radii, it preferentially enters the oil filled pores, because gas has lower IFT with oil than it has with water. The invasion of oil filled pores by gas causes a small bank of oil to move ahead of gas front causing an increase in local oil saturation in some patches of pores. This in turn increases the mobility of oil in those pores and eventually results in improved oil recovery. 3. During the subsequent water injection, gas channels become narrower as the water filaments grow in thickness, and finally due to the interplay of capillary forces and local gas pressure fluctuations, gas blobs snap off at many of the pore throats and become fragmented. 4. By injecting gas and water alternately more oil can be produced than would otherwise be produced by water or gas injection alone. 5. The major portion of the improved oil recovery is obtained only after a few cycles of WAG injection. In the reported experiment (water-wet system) this occurred after the second cycle.(Fig. 12) Nomenclature

IFT = σ = interfacial tension, mNm-1 Sorw = residual oil saturation to waterflood Sori = residual oil saturation after cycle ‘i’ So/w.g = spreading coefficient of oil over water, in presence of gas and a water wet solid surface, mNm-1 Acknowledgements

The WAG project at Heriot-Watt U. is equally sponsored by: The UK Department of Trade and Industry, BP Amoco plc, Marathon International (GB) Ltd, Mobil (North Sea) Ltd, Norsk Hydro a.s.a, SAGA Petroleum a.s.a, and Total Oil Marine plc, and this support is gratefully acknowledged. References

1. Christensen, J.R., Stenby, E.H. and Skauge, A “ Review of WAG Field Experience”, SPE 39883, SPE International Petroleum Conference and Exhibition of Mexico, Vilahermosa, Mexico 3-5 March 1998. 2. Hallam, R.J., Ma, T.D. and Reinbold, E.W. "Performance Evaluation and Optimization of The Kuparuk Hydrocarbon Miscible Water-Alternating-Gas Flood", 7th EAPG IOR Europe, Moscow, Russia, 27-29 October 1993, pp 403-415. 3. Nybraten, G., Svorstol, I. and Andfossen, P.O. "Water-Alternating-Gas Pilot Evaluation for the Snorre Field", 7th EAPG IOR Europe, Moscow, Russia, 27-29 October 1993, pp 460-468. 4. Dalen, V., Instefjord, R. and Kristensen, R. "A WAG Injection Pilot In the Lower Brent Formation at the Gullfaks Field", 7th EAPG IOR Europe, Moscow, Russia, 27-29 October 1993, pp 460-468. 5. Ma, T.D. and Youngren, G.K. "Performance of Immiscible -Water-Alternating-Gas Injection at Kuparuk River Unit, North Slope, Alaska", 69th Ann. SPE Tech. Conf., New Orleans, 25-28 Sept. 1994. 6. Nybraten, G., Svorstol, I. and Andfossen, P.O. "Water-Alternating-Gas Pilot Evaluation

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for the Snorre Field", 7th EAPG IOR Europe, Moscow, Russia, 27-29 October 1993, pp 460-468. 7. Hallam, R.J., Ma, T.D. and Reinbold, E.W. "Performance Evaluation and Optimization of The Kuparuk Hydrocarbon Miscible Water-Alternating-Gas Flood", 7th EAPG IOR Europe, Moscow, Russia, 27-29 October 1993, pp 403-415. 8. Minssieux, L. and Duquerroix, J.P. "Water-Alternating-Gas Flow Mecha-nisms in Presence of Residual Oil", 69th Ann. SPE Tech. Conf., New Orleans, 25-28 Sept. 1994. 9. Skauge, A. and Aarra, M. "Effect of Wettability on Oil Recovery by WAG", 7th EAPG IOR Europe, Moscow, Russia, 27-29 October 1993, pp 452-458. 10. Zekri, A.Y. and Natuh, A.A. "Laboratory Study of the Effects of Miscible WAG Process on Tertiary Oil Recovery", 5th Abu Dhabi Nat. Oil Co./SPE Conf., Abu Dhabi, UAE, 18-20 May 1992. 11. Larsen, J.K. and Skauge, A. “Simulation of the Immiscible WAG Process Using Cycle-Dependent Three-Phase Relative Permeabilities”, SPE 56475, SPE Annual Technical Conference and Exhibition, Houston, Texas 3-6 Oct 1999. 12. Christensen, J. R., Stenby, E.H. and Skauge, A. “Compositional and Relative Permeability Hysteresis Effects on Near Miscible WAG”, SPE/DOE Improved Oil Recovery Symposium, Tulsa Oklahoma, 19-22 April 1998. 13. Cullick, A.S., Lu, H.S., Cohen, M.F., Watson, J.P. and Jones, L.G. "Water-Alternating-Gas May Improve Gas-Condensate Recovery", SPERE, V. 8, No. 3, pp 207-213, Aug. 1993. 14. Nguyen, T.A. and Farouq Ali, S.M. "Immiscible Carbon Dioxide Floods, Using Impure Gas in the WAG Mode", 44th Annual CIM Pet. Soc. Tech. Mtg., Calgary, Canada, 9-12 May 1993. 15. Mattax, C. C. and Kyte, J. R., “Ever see waterflood?”, Oil and Gas Journal, 59:115-128 (1961) 16. Oren, P.E. and Pinczewski, W.V. “The effect of film flow on the mobilisation of waterflood residual oil by gas flooding”, 6th European IOR Symposium,Stavanger, Norway, May 21-23, 1991. 17. Oren, P.E., Billiotte, J. and Pinczewski, W.V. “Mobilisation of waterflood residual oil by gas injection for water-wet conditions, SPE Formation Evaluation, 7(1) 70-78, 1992. 18. Larsen. J.K., Bech, N. and Winter, A. “Three-Phase Immiscible WAG Injection: Micromodel Experiments and Network Models”, SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 3-5 April 2000. 19. Tehrani, D. H., Sohrabi, M, Henderson G. D. and Danesh A. “DTI’s Improved Oil Recovery Research Dissemination Seminar”, London, 18 June 1999. 20. Stegemeier, G. L., Pennington, B. F., Brauer, E. B. and Hough, E. W., “Interfacial Tension of the Methane-Normal Decane System”, SPEJ, Sept. 1962, pp. 257-260. 21. Firoozabadi, A. and Ramey, Jr., H. J., “Surface tension of water-hydrocarbon systems at reservoir conditions”, The Journal of Canadian Petroleum Technology, May-June 1988, Vol.27, No.3. 22. Lenormand, R. and Zarcone, C. “Role of Roughness and Edges During Imbibition in Square Capillaries”, SPE13264, SPE Annual Technical Conference and Exhibition, Houston, Texas 3-16-19 Sept. 1984.

Fig. 1-100% water Fig. 2-Primary drainage of Fig. 3-After waterflood saturated model water (initial OIP)

Fig. 4-Water/oil distribution Fig. 5-Water/oil distribution before waterflood after waterflood

Fig. 6 -After first cycle of Fig. 7-After first cycle of Fig. 8 After seco nd cycle of

gas injection water injection. gas injection.

Fig. 9 - After 2nd cycle of Fig. 10-After fifth cycle of Fig. 11-After fifth cycle of water injection. gas injection. water injection

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Fig. 12-Oil recovery at each stage of the experiment as percentage of initial waterflood

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Fig. 13 - Corner Filament Flow in a Square Water-Wet Tube. (a) – Profile along the diagonal line. (b) – Profile along the middle of the tube parallel with sides. (c) – Water in the corners on top of the tube. (d) – Water in the corners on top of the water column.

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