The Effect of Polymer Rheology and Induced Fracturing on Injectivity and Pressure-Transient Behavior
- Authors
- Yiwei Ma (The University of Texas at Austin) | Mark W. McClure (The University of Texas at Austin)
- DOI
- https://doi.org/10.2118/184389-PA
- Document ID
- SPE-184389-PA
- Publisher
- Society of Petroleum Engineers
- Source
- SPE Reservoir Evaluation & Engineering
- Volume
- 20
- Issue
- 02
- Publication Date
- May 2017
- Document Type
- Journal Paper
- Pages
- 394 - 402
- Language
- English
- ISSN
- 1094-6470
- Copyright
- 2017.Society of Petroleum Engineers
- Disciplines
- Keywords
- polymer injection, hydraulic fracture, pressure transient
- Downloads
- 0 in the last 30 days
- 439 since 2007
- Show more detail
- View rights & permissions
| SPE Member Price: | USD 5.00 |
| SPE Non-Member Price: | USD 35.00 |
Summary
Polymer transport and fluid rheology were implemented in a fully implicit hydraulic-fracturing and reservoir simulator. For flow in the matrix, a fluid-rheology function was used with shear thickening at high shear rates and shear thinning at medium and low shear rates. For flow in fractures, a shear-thinning constitutive law with a zero shear-rate plateau was used. The average viscosity in each fracture element was calculated by assuming smooth and parallel fracture walls and numerically solving for the velocity, shear rate, and viscosity distribution across the aperture. The simulator was used to investigate the effect on injectivity of shear thickening at high shear rates near the wellbore. For comparison, simulations were performed by use of the full shear-thickening and shear-thinning rheology function and by use of a shear-thinning- only rheology function. In the former case, the shear thickening caused rapid buildup of fluid pressure and the creation of a hydraulic fracture at the wellbore. Once the fracture formed, shear thickening no longer occurred because there was lower Darcy velocity in the matrix caused by lower concentration of flow at the wellbore. As a result, after the formation of the hydraulic fracture, injectivity in the simulation with shear thickening and thinning was nearly identical to that in the simulation with only shear thinning. The simulations were repeated with the constraint that a hydraulic fracture was not permitted to form. In this case, the simulation with shear thickening had a significantly lower injectivity than the simulation with shear thinning only. This result shows that formation of an induced fracture is a plausible explanation for unexpectedly high injectivity during polymer injection because it prevents shear thickening caused by high flow rate because of concentration of flow at the wellbore.
Simulations were performed to investigate the effect of polymer rheology on the pressure transients occurring after shut-in of an injection well. Shear thickening affected the shut-in transient only at very-early time. Shear thinning affected the entire duration of the transient, causing an increase in effective fluid viscosity as the Darcy velocity gradually decreased over time. Despite fluid rheology effects, linear flow was clearly identifiable after shut-in in the simulations with hydraulic fractures. This result shows that hydraulic fractures around polymer-injection wells can be diagnosed in field data from the linear-flow regime in the shut-in transient, regardless of fluid-rheology effects.
| File Size | 1 MB | Number of Pages | 9 |
References
Amestoy, P. R., Davis, T. A. and Duff, I. S. 2004. Algorithm 837: AMD, An Approximate Minimum Degree Ordering Algorithm. ACM Trans. Math. Software 30 (3): 381–388. https://doi.org/10.1145/1024074.1024081.
Anderson, E., Bai, Z., Bischof, C. et al. 1999. LAPACK Users’ Guide, third edition. Philadelphia, Pennsylvania: Society for Industrial and Applied Mathematics.
Barton, N., Bandis, S. and Bakhtar, K. 1985. Strength, Deformation and Conductivity Coupling of Rock Joints. Int. J. Rock Mech. Min. 22 (3): 121–140. https://doi.org/10.1016/0148-9062(85)93227-9.
Bird, R. B., Stewart, W. E. and Lightfoot, E. N. 2006. Transport Phenomena, second edition. New York City: John Wiley & Sons, Inc.
Bourdet, D., Ayoub, J. A. and Pirard, Y. M. 1989. Use of Pressure Derivative in Well Test Interpretation. SPE Form Eval 4 (2): 293–302. SPE-12777-PA. https://doi.org/10.2118/12777-PA.
Bradley, A. M. 2014. Software for efficient static dislocation-traction calculations in fault simulators. Seimol. Res. Lett. 85 (6): 1358–1365. https://doi.org/10.1785/0220140092.
Cannella, W. J., Huh, C. and Seright, R. S. 1988. Prediction of Xanthan Rheology in Porous Media. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 2–5 October. SPE-18089-MS. https://doi.org/10.2118/18089-MS.
Carreau, P. J. 1972. Rheology Equations from Molecular Network Theories. Trans. Soc. Rheol. 16 (1): 99–127. https://doi.org/10.1122/1.549276.
Davis, T. A. 2004. Algorithm 832: UMFPACK, An Unsymmetric-Pattern Multifrontal Method. ACM Trans. Math. Software 30 (2): 196–199. https://doi.org/10.1145/992200.992206.
Delshad, M., Kim, D. H., Magbagbeola, O. A. et al. 2008. Mechanistic Interpretation and Utilization of Viscoelastic Behavior of Polymer Solutions for Improved Polymer-Flood Efficiency. Presented at the SPE Symposium on Improved Oil Recovery, Tulsa, 20–23 April. SPE-113620-MS. https://doi.org/10.2118/113620-MS.
Delshad, M., Pope, G. A. and Sepehrnoori, K. 2000. UTCHEM Version 9.0 Technical Documentation. Austin, Texas: The University of Texas at Austin.
Derezinski, S. J. 1990. Dimensionless Slot Flow Using the Carreau Viscosity Model. J. Plast. Film. Sheet. 6 (4): 276–291. https://doi.org/10.1177/875608799000600404.
Dongarra, J. J., Du Croz, J., Hammarling, S. et al. 1988. An Extended Set of FORTRAN Basic Linear Algebra Subprograms. ACM Trans. Math. Software 14 (1): 1–17. https://doi.org/10.1145/42288.42291.
Gogarty, W. B. 1967. Mobility Control With Polymer Solutions. SPE J. 7 (2): 161–173. SPE-1566-B. https://doi.org/10.2118/1566-B.
Hirasaki, G. J. and Pope, G. A. 1974. Analysis of Factors Influencing Mobility and Adsorption in the Flow of Polymer Solution Through Porous Media. SPE J. 14 (4): 337–346. SPE-4026-PA. https://doi.org/10.2118/4026-PA.
Huh, C. and Pope, G. A. 2008. Residual Oil Saturation from Polymer Floods: Laboratory Measurements and Theoretical Interpretation. Presented at the SPE Symposium on Improved Oil Recovery, Tulsa, 20–23 April. SPE-113417-MS. https://doi.org/10.2118/113417-MS.
Karimi-Fard, M., Durlofsky, L. J. and Aziz, K. 2004. An Efficient Discrete-Fracture Model Applicable for General-Purpose Reservoir Simulators. SPE J. 9 (2): 227–236. SPE-88812-PA. https://doi.org/10.2118/88812-PA.
Lawson, C. L., Hanson, R. J., Krogh, F. T. et al. 1979. Algorithm 539: Basic Linear Algebra Subprograms for Fortran Usage. ACM Trans. Math. Software 5 (3): 308–323. https://doi.org/10.1145/355841.355848.
Lee, K. H. 2012. Impact of Fracture Creation and Growth on Well Injectivity and Reservoir Sweep During Waterflooding and Chemical EOR Processes. Presented at the SPE Annual Technical Conference and Exhibition, Denver.
Liu, J., Delshad, M., Pope, G. A. et al. 1994. Applications of Higher-Order Flux-Limited Methods in Compositional Simulation. Transport Porous Med. 16 (1): 1–29. https://doi.org/10.1007/BF01059774.
Masuda, Y., Tang, K.-C., Miyazawa, M. et al. 1992. 1D Simulation of Polymer Flooding Including the Viscoelastic Effect of Polymer Solution. SPE Res Eval & Eng 7 (2): 247–252. SPE-19499-PA. https://doi.org/10.2118/19499-PA.
McClure, M. W. and Horne, R. N. 2013. Discrete Fracture Network Modeling of Hydraulic Stimulation: Coupling Flow and Geomechanics. New York City: Springer.
McClure, M. W., Blyton, C. A. J., Jung, H. et al. 2014. The Effect of Changing Fracture Compliance on Pressure Transient Behavior During Diagnostic Fracture Injection Tests. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. SPE-170956-MS. https://doi.org/10.2118/170956-MS.
Moe Soe Let, K. P., Manichand, R. N. and Seright, R. S. 2012. Polymer Flooding a ~500-cp Oil. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 14–18 April. SPE-154567-MS. https://doi.org/10.2118/154567-MS.
Needham, R. B. and Doe, P. H. 1987. Polymer Flooding Review. J Pet Technol 39 (12): 1503–1507. SPE-17140-PA. https://doi.org/10.2118/17140-PA.
Olson, J. E. 2004. Predicting Fracture Swarms — the Influence of Subcritical Crack Growth and the Crack-Tip Process Zone on Joint Spacing in Rock. Geol. Soc. London 231 (1): 73–88. https://doi.org/10.1144/GSL.SP.2004.231.01.05.
Pye, D. J. 1964. Improved Secondary Recovery by Control of Water Mobility. J Pet Technol 16 (8): 911–916. SPE-845-PA. https://doi.org/10.2118/845-PA.
Sandiford, B. B. 1964. Laboratory and Field Studies of Water Floods Using Polymer Solutions to Increase Oil Recoveries. J Pet Technol 16 (8): 917–922. SPE-844-PA. https://doi.org/10.2118/844-PA.
Seright, R. S., Mac Seheult, J. and Talashek, T. 2009. Injectivity Characteristics of EOR Polymers. SPE Res Eval & Eng 12 (5): 783–792. SPE-115142-PA. https://doi.org/10.2118/115142-PA.
Sheng, J. J., Leonhardt, B. and Azri, N. 2015. Status of Polymer-Flooding Technology. J Can Pet Technol 54 (2): 116–126. SPE-174541-PA. https://doi.org/10.2118/174541-PA.
Shewchuk, J. R. 1996. Triangle: Engineering a 2D Quality Mesh Generator and Delaunay Triangulator. Lect. Notes Comput. Sci. 1148: 203–222. https://doi.org/10.1007/BFb0014497.
Shou, K. J. and Crouch, S. L. 1995. A Higher Order Displacement Discontinuity Method for Analysis of Crack Problems. Int. J. Rock Mech. Min. 32 (1): 49–55. https://doi.org/10.1016/0148-9062(94)00016-V.
Smith, F. W. 1970. The Behavior of Partially Hydrolyzed Polyacrylamide Solutions in Porous Media. J Pet Technol 22 (2): 148–156. https://doi.org/10.2118/2422-PA.
Standnes, D. C. and Skjevrak, I. 2014. Literature Review of Implemented Polymer Field Projects. J. Pet. Sci. Eng. 122 (October): 761–775. https://doi.org/10.1016/j.petrol.2014.08.024.
Wang, D., Xia, H., Liu, Z. et al. 2001. Study of the Mechanism of Polymer Solution With Visco-Elastic Behavior Increasing Microscopic Oil Displacement Efficiency and the Forming of Steady "Oil Thread" Flow Channels. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 17–19 April. SPE-68723-MS. https://doi.org/10.2118/68723-MS.
Wang, D., Han, P., Shao, Z. et al. 2008. Sweep-Improvement Options for the Daqing Oil Field. SPE Res Eval & Eng 11 (1): 18–26. SPE-99441-PA. https://doi.org/10.2118/99441-PA.
Willis-Richards, J., Watanabe, K. and Takahashi, H. 1996. Progress Toward a Stochastic Rock Mechanics Model of Engineered Geothermal Systems. J. Geophys. Res.-Sol. Ea. 101 (B8): 17481–17496. https://doi.org/10.1029/96JB00882.
Witherspoon, P. A., Wang, J. S. Y., Iwai, K. et al. 1980. Validity of Cubic Law for Fluid Flow in a Deformable Rock Fracture. Water Resour. Res. 16 (6): 1016–1024. https://doi.org/10.1029/WR016i006p01016.
Wu, Y.-S. and Forsyth, P. A. 2006. Efficient Schemes for Reducing Numerical Dispersion in Modeling Multiphase Transport through Porous and Fractured Media. Report No. LBNL-60056, Lawrence Berkeley National Laboratory, Berkeley, California.
Zechner, M., Buchgraber, M., Clemens, T. et al. 2013. Flow of Polyacrylamide Polymers in the Near-Wellbore-Region, Rheological Behavior within Induced Fractures and Near-Wellbore-Area. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–2 October. https://doi.org/10.2118/166085-MS.
