- Boolean operators
- This OR that
This AND that
This NOT that
- Must include "This" and "That"
- This That
- Must not include "That"
- This -That
- "This" is optional
- This +That
- Exact phrase "This That"
- "This That"
- (this AND that) OR (that AND other)
- Specifying fields
- publisher:"Publisher Name"
author:(Smith OR Jones)
Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood
- Shayan Tavassoli (University of Texas at Austin) | Jun Lu (University of Texas at Austin) | Gary A. Pope (University of Texas at Austin) | Kamy Sepehrnoori (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- October 2014
- Document Type
- Journal Paper
- 931 - 942
- 2014.Society of Petroleum Engineers
- 6.4.6 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 6.3.2 Multi-phase Flow, 6.5 Reservoir Simulation, 6 Reservoir Description and Dynamics, 6.3 Fluid Dynamics, 6.4 Primary and Enhanced Recovery Processes, 6.3.1 Flow in Porous Media
- Gravity Stability, Mechanistic Simulation Model, Surfactant Flood
- 9 in the last 30 days
- 349 since 2007
- Show more detail
Classical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world’s largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.
Adkins, S., Liyanage P. J., Arachchilage, G. W. P., et al. 2010. A New Process for Manufacturing and Stabilizing High-Performance EOR Surfactants at Low Cost for High-Temperature, High-Salinity Oil Reservoirs. Paper SPE 129923 presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 24–28 April. http://dx.doi.org/10.2118/129923-MS.
Adkins, S., Arachchilage, G. W. P., Solairaj, S., et al. 2012. Development of Thermally and Chemically Stable Large-Hydrophobe Alkoxy Carboxylate Surfactants. Paper SPE 154256 presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 14–18 April. http://dx.doi.org/10.2118/154256-MS.
Araktingi, U. G. and Orr, F. M. 1993. Viscous Fingering in Heterogeneous Porous Media. SPE Advanced Technology Series 1 (1): 71–80. http://dx.doi.org/10.2118/18095-PA.
Bear, J. 2007. Hydraulics of Groundwater. Mineola, New York: Dover Publications.
Brooks, R. H. and Corey, A. T. 1966. Properties of Porous Media Affecting Fluid Flow. J. Irr. Drain. Div. 92 (2): 61–88.
Chang, Y. B., Lim, M. T., Pope, G. A., et al. 1994. CO2 Flow Patterns under Multiphase Flow: Heterogeneous Field-Scale Conditions. SPE Res Eng 9 (3): 208–216. http://dx.doi.org/10.2118/22654-PA.
Chouke, R. L., van Meurs, P. and van der Poel, C. 1959. The Instability of Slow, Immiscible, Viscous Liquid-Liquid Displacements in Permeable Media. Trans. AIME 216: 188–194.
Delshad, M., Pope, G. A. and Sepehrnoori, K. 1996. A Compositional Simulator for Modeling Surfactant Enhanced Aquifer Remediation. J. Contam. Hydrol. 23 (4): 303–327. http://dx.doi.org/10.1016/0169-7722(95)00106-9.
Delshad, M. and Pope, G. A. 1989. Comparison of the Three-Phase Oil Relative Permeability Models. Transport Porous Med. 4 (1): 59–83. http://dx.doi.org/10.1007/BF00134742.
Delshad, M., Delshad, M., Pope, G. A., et al. 1987. Two- and Three- Phase Relative Permeabilities of Micellar Fluids. SPE Form Eval 2 (3): 327–337. http://dx.doi.org/10.2118/13581-PA.
Delshad, M., Pope, G. A. and Sepehrnoori, K. 2011. Volume II: Technical Documentation for UTCHEM 2011–7: A Three-Dimensional Chemical Flood Simulator. Technical Documentation, Center for Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, Texas.
Dykstra, H. and Parsons, R. L. 1950. The Prediction of Oil Recovery by Waterflood. In Secondary Recovery of Oil in the United States, second edition, American Petroleum Institute, 160–174. New York City, New York: API.
Engelberts, W. F. and Klinkenberg, L. J. 1951. Laboratory Experiments on the Displacement of Oil by Water from Packs of Granular Material. Paper SPE 4138 presented at the 3rd World Petroleum Congress, The Hague, The Netherlands, 28 May–6 June.
Hickernell, F. J. and Yortsos, Y. C. 1986. Linear Stability of Miscible Displacement Processes in Porous Media in the Absence of Dispersion. Stud. Appl. Math. 74 (2): 93–116.
Hill, S. 1952. Channeling in Packed Columns. Chem. Eng. Sci. 1 (6): 247–253. http://dx.doi.org/10.1016/0009-2509(52)87017-4.
Homsy, G. M. 1987. Viscous Fingering in Porous Media. Annu. Rev. Fluid Mech. 19 (1): 271–311. http://dx.doi.org/10.1146/annurev.fl.19.010187.001415.
Koval, E. J. 1963. A Method for Predicting the Performance of Unstable Miscible Displacement in Heterogeneous Media. SPE J. 3 (2): 145–154. http://dx.doi.org/10.2118/450-PA.
Krueger, C. 1989. Numerical Simulation and Modeling of Viscous Fingering. MS thesis, The University of Texas at Austin, Austin, Texas (1989).
Lake, L. W. 2008. Enhanced Oil Recovery. Old Tappan, New Jersey: Prentice Hall.
Liu, J. 1993. High-Resolution Methods for Enhanced Oil Recovery Simulation. PhD dissertation, The University of Texas at Austin, Austin, Texas (1993).
Liu, J., Delshad, M., Pope, G. A., et al. 1994. Application of Higher-Order Flux-Limited Methods in Compositional Simulation. Transport Porous Med. 16 (1): 1–29. http://dx.doi.org/10.1007/BF01059774.
Lu, J., Pope, G. A. and Weerasooriya, U. P. 2013. Stability Investigation of Low-Tension Surfactant Floods. Paper SPE 164090 presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 8–10 April. http://dx.doi.org/10.2118/164090-MS.
Petrel 2011. Petrel User’s Manual. Reservoir Simulation and Modeling Package. XX: Schlumberger.
PETSc 2010. PETSc User’s Manual. Revision 3.1. Lemont, Illinois: Argonne National Laboratory.
Pope, G. A., Wu, W., Narayanaswamy, G., et al. 2000. Modeling Relative Permeability Effects in Gas-Condensate Reservoirs with a New Trapping Model. SPE Res Eval & Eng 3 (2): 171–178. http://dx.doi.org/10.2118/62497-PA.
Riaz, A. and Meiburg, E. 2003. Radial Source Flows in Porous Media: Linear Stability Analysis of Axial and Helical Perturbations in Miscible Displacements. Phys. Fluids 15 (4): 938–946. http://dx.doi.org/10.1063/1.1556292.
Riaz, A. and Tchelepi, H. A. 2004. Linear Stability Analysis of Immiscible Two-Phase Flow in Porous Media with Capillary Dispersion and Density Variation. Phys. Fluids 16 (12): 4727–4737. http://dx.doi.org/10.1063/1.1812511.
Riaz, A. and Tchelepi, H. A. 2006. Numerical Simulation of Immiscible Two-Phase Flow in Porous Media. Phys. Fluids 18 (1): 014104(1)–014104(12). http://dx.doi.org/10.1063/1.2166388.
Solairaj, S., Britton, C., Lu, J., et al. 2012. New Correlation to Predict the Optimum Surfactant Structure for EOR. Paper SPE 154262 presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 14–18 April. http://dx.doi.org/10.2118/154262-MS.
Tan, C. T. and Homsy, G. M. 1986. Stability of Miscible Displacements in Porous Media: Rectilinear Flows. Phys. Fluids 29 (11): 3549–3556. http://dx.doi.org/10.1063/1.865832.
Tan, C. T. and Homsy, G. M. 1988. Simulation of Nonlinear Viscous Fingering in Miscible Displacement. Phys. Fluids 31 (6): 1330–1338. http://dx.doi.org/10.1063/1.866726.
Todd, M. R. and Longstaff, W. J. 1972. The Development, Testing, and Application of a Numerical Simulator for Predicting Miscible Flood Performance. J. Pet. Tech. 24 (7): 874–882. http://dx.doi.org/10.2118/3484-PA.
Yang, H., Britton, C., Liyanage, P. J., et al. 2010. Low-Cost, High-Performance Chemicals for Enhanced Oil Recovery. Paper SPE 129978 presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 24–28 April. http://dx.doi.org/10.2118/129978-MS.
Not finding what you're looking for? Some of the OnePetro partner societies have developed subject- specific wikis that may help.
The SEG Wiki
The SEG Wiki is a useful collection of information for working geophysicists, educators, and students in the field of geophysics. The initial content has been derived from : Robert E. Sheriff's Encyclopedic Dictionary of Applied Geophysics, fourth edition.