Bubble-Population-Balance Modeling for Supercritical Carbon Dioxide Foam Enhanced-Oil-Recovery Processes: From Pore-Scale to Core-Scale and Field-Scale Events
- Mohammad Izadi (Louisiana State University) | Seung Ihl Kam (Louisiana State University)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- November 2019
- Document Type
- Journal Paper
- 1,467 - 1,480
- 2019.Society of Petroleum Engineers
- bubble population balance model, foam propagation, foam EOR, CO2 foam
- 5 in the last 30 days
- 164 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
A bubble-population-balance foam-modeling technique is developed to investigate how carbon dioxide (CO2) foam behaves rheologically and propagates in a field-scale radial system. The modeling technique is based on pore-scale events and honors three different foam states (weak, strong, and intermediate) and two steady-state strong-foam-flow regimes (high- and low-quality) measured in corescale experiments. The model parameters are first obtained from a fit to laboratory-coreflood experimental data, and then the mechanistic model is applied to different types of CO2 foams, ranging from gaseous to supercritical-CO2 foams, represented by various mobilization pressure gradients.
The results from the fit to existing coreflood data show that a reasonable match can be made satisfying multiple constraints, such as hysteresis exerted by three foam states, non-Newtonian flow behavior caused by gas trapping and shear-thinning rheology, and bubble stability in different capillary pressure environments. When applied to field-scale scenarios, supercritical-CO2 foams requiring low mobilization pressure gradients propagate much farther than gaseous-CO2 foams, far enough to make use of promising supercritical-CO2 foams in the field. This study, for the first time, theoretically demonstrates why supercritical-CO2 foams should be preferred in the field compared with gaseous N2 or CO2 foams.
The companion paper to extend this study to full-field-scale foam propagation in conjunction with gravity segregation is Izadi and Kam (2018).
|File Size||1008 KB||Number of Pages||14|
Aarra, M. G., Skauge, A., Solbakken, J. et al. 2014. Properties of N2 and CO2 Foams as a Function of Pressure. J Pet Sci Eng 116 (April): 72–80. https://doi.org/10.1016/j.petrol.2014.02.017.
Afsharpoor, A., Lee, G. S., and Kam, S. I. 2010. Mechanistic Simulation of Continuous Gas Injection Period During Surfactant-Alternating-Gas (SAG) Processes Using Foam Catastrophe Theory. Chem Eng Sci 65 (11): 3615–3631. https://doi.org/10.1016/j.ces.2010.03.001.
Alvarez, J. M., Rivas, H., and Rossen, W. R. 2001. Unified Model for Steady-State Foam Behavior at High and Low Foam Qualities. SPE J. 6 (3): 325–333. SPE-74141-PA. https://doi.org/10.2118/74141-PA.
Ashoori, E., van der Heijden, T., and Rossen, W. 2010. Fractional-Flow Theory of Foam Displacements With Oil. SPE J. 15 (2): 260–273. SPE-121579-PA. https://doi.org/10.2118/121579-PA.
Beard, D. C. and Weyl, P. K. 1973. Influence of Texture on Porosity and Permeability of Unconsolidated Sand. AAPG Bull 57 (2): 349–369.
Bond, D. C. and Holbrook, C. 1958. Gas Drive Oil Recovery Process. US Patent No. 28,665,07A.
Conn, C. A., Ma, K., Hirasaki, G. J. et al. 2014. Visualizing Oil Displacement With Foam in a Microfluidic Device With Permeability Contrast. Lab Chip 14: 3968–3977. https://doi.org/10.1039/C4LC00620H.
Farajzadeh, R., Lotfollahi, M., Eftekhari, A. A. et al. 2015. Effect of Permeability on Implicit-Texture Foam Model Parameters and the Limiting Capillary Pressure. Energy Fuels 29 (5): 3011–3018. https://doi.org/10.1021/acs.energyfuels.5b00248.
Fenghour, A. and Wakeham, W. A. 1998. The Viscosity of Carbon Dioxide. J Phys Chem Ref Data 27 (1): 31–44. https://doi.org/10.1063/1.556013.
Friedmann, F., Chen, W. H., and Gauglitz, P. A. 1991. Experimental and Simulation Study of High-Temperature Foam Displacement in Porous Media. SPE Res Eng 6 (1): 37–45. SPE-17357-PA. https://doi.org/10.2118/17357-PA.
Gauglitz, P. A., Friedmann, F., Kam, S. I. et al. 2002. Foam Generation in Homogeneous Porous Media. Chem Eng Sci 57 (19): 4037–4052. https://doi.org/10.1016/S0009-2509(02)00340-8.
Hirasaki, G. J. and Lawson, J. B. 1985. Mechanisms of Foam Flow in Porous Media: Apparent Viscosity in Smooth Capillaries. SPE J. 25 (2): 176–190. SPE-12129-PA. https://doi.org/10.2118/12129-PA.
Hirasaki, G. J., Miller, C. A., Szafranski, R. et al. 1997. Surfactant/Foam Process for Aquifer Remediation. Presented at the International Symposium on Oilfield Chemistry, Houston, 18–21 February. SPE-37257-MS. https://doi.org/10.2118/37257-MS.
Izadi, M. and Kam, S. I. 2018. Investigating Supercritical CO2 Foam Propagation Distance: Conversion From Strong Foam to Weak Foam vs. Gravity Segregation. Transp Porous Media (in press; published online 24 July 2018). https://doi.org/10.1007/s11242-018-1125-z.
Jonas, T. M., Chou, S. I., and Vasicek, S. L. 1990. Evaluation of a CO2 Foam Field Trial: Rangely Weber Sand Unit. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 23–26 September. SPE 20468-MS. https://doi.org/10.2118/20468-MS.
Kam, S. I. 2008. Improved Mechanistic Foam Simulation With Foam Catastrophe Theory. Colloids Surf A Physicochem Eng Asp. 318 (1–3): 62–77. https://doi.org/10.1016/j.colsurfa.2007.12.017.
Kam, S. I. and Rossen, W. R. 2003. A Model for Foam Generation in Homogeneous Media. SPE J. 8 (4): 417–425. SPE-87334-PA. https://doi.org/10.2118/87334-PA.
Khatib, Z. I., Hirasaki, G. J., and Falls, A. H. 1988. Effects of Capillary Pressure on Coalescence and Phase Mobilities in Foams Flowing Through Porous Media. SPE Res Eng 3 (3): 919–926. SPE-15442-PA. https://doi.org/10.2118/15442-PA.
Kovscek, A. R. and Bertin, H. J. 2002. Estimation of Foam Mobility in Heterogeneous Porous Media. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, 13–17 April, SPE-75181-MS. https://doi.org/10.2118/75181-MS.
Kovscek, A. R. and Radke, C. J. 1994. Fundamentals of Foam Transport in Porous Media. In Foams: Fundamentals and Applications in the Petroleum Industry, ed. L. L. Schramm, ACS Advances in Chemistry Series, Vol. 242, Chap. 3, 115–163. Washington, DC: American Chemistry Society.
Kovscek, A. R., Chen, Q., and Gerritsen, M. 2010. Modeling Foam Displacement With the Local-Equilibrium Approximation: Theory and Experimental Verification. SPE J. 15 (1): 171–183. SPE-116735-PA. https://doi.org/10.2118/116735-PA.
Kovscek, A. R., Patzek, T. W., and Radke, C. J. 1995. A Mechanistic Population Balance Model for Transient and Steady-State Foam Flow in Boise Sandstone. Chem Eng Sci 50 (23): 3783–3799. https://doi.org/10.1016/0009-2509(95)00199-F.
Kovscek, A. R., Patzek, T. W., and Radke, C. J. 1997. Mechanistic Foam Flow Simulation in Heterogeneous and Multidimensional Porous Media. SPE J. 2 (4): 511–526. SPE-39102-PA. https://doi.org/10.2118/39102-PA.
Li, B., Hirasaki, G. J., and Miller, C. A. 2006. Upscaling of Foam Mobility Control to Three Dimensions. Presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22–26 April. SPE-99719-MS. https://doi.org/10.2118/99719-MS.
Liu, N., Ghorpade, S. V., Harris, L. et al. 2010. The Effect of Pressure and Temperature on Brine-CO2 Relative Permeability and IFT at Reservoir Conditions. Presented at SPE Eastern Regional Meeting, Morgantown, West Virginia, 13–15 October. SPE-139029-MS. https://doi.org/10.2118/139029-MS.
Lee, S. and Kam, S. I. 2013. Enhanced Oil Recovery by Using CO2 Foams: Fundamentals and Field Applications. In Enhanced Oil Recovery: Field Case Studies, ed. J. J. Sheng, Chap. 2, 23–61. Waltham, Massachusetts: Gulf Professional Publishing.
Lee, S. and Kam, S. I. 2014. Three-Phase Fractional Flow Analysis for Foam-Assisted Non-Aqueous Phase Liquid (NAPL) Remediation. Transp Porous Media 101 (3): 373–400. https://doi.org/10.1007/s11242-013-0250-y.
Lee, W., Lee, S., Izadi, M. et al. 2016. Dimensionality-Dependent Foam Rheological Properties: How to Go From Linear to Radial Geometry for Foam Modeling and Simulation. SPE J. 21 (5): 1669–1687. SPE-175015-PA. https://doi.org/10.2118/175015-PA.
Lotfollahi, M., Farajzadeh, R., Delshad, M. et al. 2016. Comparison of Implicit-Texture and Population-Balance Foam Models. J Nat Gas Sci Eng 31 (April): 184–197. https://doi.org/10.1016/j.jngse.2016.03.018.
McCain, W. D. 1991. Reservoir-Fluid Property Correlations—State of the Art. SPE Res Eng 6 (2): 266–272. SPE-18571-PA. https://doi.org/10.2118/18571-PA.
Myers, T. J. and Radke, C. J. 2000. Transient Foam Displacement in the Presence of Residual Oil: Experiment and Simulation Using a Population-Balance Model. Ind. Eng. Chem. Res. 39 (8): 2725–2741. https://doi.org/10.1021/ie990909u.
Osterloh, W. T. and Jante, M. J. Jr. 1992. Effects of Gas and Liquid Velocity on Steady-State Foam Flow at High Temperature. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, 22–24 April, Tulsa. SPE-24179-MS. https://doi.org/10.2118/24179-MS.
Ransohoff, T. C. and Radke, C. J. 1988. Mechanisms of Foam Generation in Glass-Bead Packs. SPE J. 3 (2): 573–585. SPE-15441-PA. https://doi.org/10.2118/15441-PA.
Rossen, W. R. 1996. Foams in Enhanced Oil Recovery. In Foams: Theory, Measurements, and Applications, ed. R. K. Prud’homme and S. Khan, Chap. 11, 413–464. New York City: Marcel Dekker.
Rossen, W. R. and Gauglitz, P. A. 1990. Percolation Theory of Creation and Mobilization of Foam in Porous Media. AIChE J. 36 (8): 1176–1188. https://doi.org/10.1002/aic.690360807.
Yin, G. 2007. Experimental Study of CO2 Foam Flooding in Berea Sandstone at Reservoir Conditions. Master’s thesis, New Mexico Institute of Mining and Technology, Socorro, New Mexico (March 2007).
Yu, G., Rossen, W. R., and Vincent-Bonnieu, S. 2019. Coreflood Study of Effect of Surfactant Concentration on Foam Generation in Porous Media. Ind. Eng. Chem. Res. 58 (1): 420–427. https://doi.org/10.2118/10.1021/acs.iecr.8b03141.