Effect of Viscosity on Oil Production by Cocurrent and Countercurrent Imbibition From Cores With Two Ends Open
- Qingbang Meng (China University of Petroleum, Beijing) | Huiqing Liu (China University of Petroleum, Beijing) | Jing Wang (China University of Petroleum, Beijing)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2017
- Document Type
- Journal Paper
- 251 - 259
- 2017.Society of Petroleum Engineers
- spontaneous imbibition, pore structure, oil viscosity, relative permeability
- 2 in the last 30 days
- 405 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Spontaneous imbibition is an important mechanism of oil recovery in naturally fractured reservoirs. The flow of oil from matrix system to fracture system will generally involve both cocurrent and countercurrent imbibition. Understanding the mechanism of cocurrent and countercurrent imbibition is essential in oil recovery from fractured reservoirs. In the previous work, we focused on the purely cocurrent imbibition (Meng et al. 2015), and we now focus on the combination of cocurrent and countercurrent imbibition. In this paper, a new mathematical model, which could be used to simulate the combination of cocurrent and countercurrent imbibition with the two-ends-open oil/water (TEO-OW) boundary condition, is developed. In the TEO-OW boundary condition, one end face of the core is exposed to water and the other is exposed to oil. Experiments of spontaneous imbibition with the TEO-OW boundary condition were performed. Air and oil were used as the nonwetting phase in the experiments to obtain different viscosities ranging from 0.018 to 103.4 cp. The porous media used in the experiments were packed with glass beads or quartz sand, both of which were strongly water-wet. The geometry of the glass beads is spherical and the particle-size distribution is narrow, and the geometry of the quartz sand is irregular and the particle-size distribution is wide. Both oil production from inlet and outlet faces and the advancing distance of the imbibition front were measured against time. The experimental results showed that the largest fraction of the oil/gas production occurred by cocurrent imbibition in both glass-bead packs and quartz sandpacks. In addition, for glass-bead packs, very little of the oil/gas was produced by countercurrent imbibition, and it has almost no change with the increase in oil/gas viscosity. For quartz sandpacks, much more oil/gas was produced by countercurrent imbibition, and it increases noticeably with the increase in oil/gas viscosity (but is still much smaller than cocurrent imbibition). The total oil/gas recovery for glass-bead packs is high and has almost no change with the increase in oil/gas viscosity. In contrast, the total oil/gas recovery for quartz sandpacks is lower and decreases noticeably with the increase in oil/gas viscosity. The relative permeability to water and oil could be obtained by fitting the simulated results with the experimental results. The fitting results show that the relative permeability to water behind the imbibition front decreases with the increase in oil viscosity and the relative permeability to oil for countercurrent imbibition increases with the increase in oil viscosity.
|File Size||999 KB||Number of Pages||9|
Akin, S., Schembre, J. M., Bhat, S. K. et al. 2000. Spontaneous Imbibition Characteristics of Diatomite. J. Pet. Sci. Eng. 25 (3–4): 149–165. https://doi.org/10.1016/S0920-4105(00)00010-3.
Baldwin, B. A. and Spinler, E. A. 2002. In Situ Saturation Development During Spontaneous Imbibition. J. Pet. Sci. Eng. 35 (1–2): 23–32. https://doi.org/10.1016/S0920-4105(02)00161-4.
Bourbiaux, B. J. and Kalaydjian, F. J. 1990. Experimental Study of Cocurrent and Countercurrent Flows in Natural Porous Media. SPE Res Eng 5 (3): 361–368. SPE-18283-PA. https://doi.org/10.2118/18283-PA.
Cai, J., Perfect, E., Cheng, C. et al. 2014. Generalized Modeling of Spontaneous Imbibition Based on Hagen-Poiseuille Flow in Tortuous Capillaries with Variably Shaped Apertures. Langmuir 30 (18): 5142–5151. https://doi.org/10.1021/la5007204.
Cai, J., Yu, B., Zou, M. et al. 2010. Fractal Characterization of Spontaneous Co-current Imbibition in Porous Media. Energ. Fuel. 24 (3): 1860–1867. https://doi.org/10.1021/ef901413p.
Fernø, M. A., Haugen, Å., Wickramathilaka, S. et al. 2013. Magnetic Resonance Imaging of the Development of Fronts During Spontaneous Imbibition. J. Pet. Sci. Eng. 101 (January): 1–11. https://doi.org/10.1016/j.petrol.2012.11.012.
Fischer, H. and Morrow, N. R. 2005. Spontaneous Imbibition with Matched Liquid Viscosities. Presented at SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. SPE-96812-MS. https://doi.org/10.2118/96812-MS.
Fischer, H. and Morrow, N. R. 2006. Scaling of Oil Recovery by Spontaneous Imbibition for Wide Variation in Aqueous Phase Viscosity with Glycerol as the Viscosifying Agent. J. Pet. Sci. Eng. 52 (1–4): 35–53. https://doi.org/10.1016/j.petrol.2006.03.003.
Fischer, H., Wo, S. and Morrow, N. R. 2008. Modeling the Effect of Viscosity Ratio on Spontaneous Imbibition. SPE Res Eval & Eng 11 (3): 577–589. SPE-102641-PA. https://doi.org/10.2118/102641-PA.
Hamidpour, E., Mirzaei-Paiaman, A., Masihi, M. et al. 2015. Experimental Study of Some Important Factors on Nonwetting Phase Recovery by Cocurrent Spontaneous Imbibition. J. Nat. Gas Sci. Eng. 27 (2): 1213–1228. https://doi.org/10.1016/j.jngse.2015.09.070.
Hatiboglu, C. U. and Babadagli, T. 2007. Oil Recovery by Counter-Current Spontaneous Imbibition: Effects of Matrix Shape Factor, Gravity, IFT, Oil Viscosity, Wettability, and Rock Type. J. Pet. Sci. Eng. 59 (1–2): 106–122. https://doi.org/10.1016/j.petrol.2007.03.005.
Hatiboglu, C. U. and Babadagli, T. 2010. Experimental and Visual Analysis of Co- and Countercurrent Spontaneous Imbibition for Different Viscosity Ratios, Interfacial Tensions, and Wettabilities. J. Pet. Sci. Eng. 70 (3–4): 214–228. https://doi.org/10.1016/j.petrol.2009.11.013.
Haugen, Å., Fernø, M. A., Mason, G. et al. 2014. Capillary Pressure and Relative Permeability Estimated from a Single Spontaneous Imbibition Test. J. Pet. Sci. Eng. 115 (March): 66–77. https://doi.org/10.1016/j.petrol.2014.02.001.
Haugen, Å., Fernø, M. A., Mason, G. et al. 2015. The Effect of Viscosity on Relative Permeabilities Derived from Spontaneous Imbibition Tests. Transport Porous Med. 106 (2): 383–404. https://doi.org/10.1007/s11242-014-0406-4.
Karpyn, Z. T., Halleck, P. M. and Grader, A. S. 2009. An Experimental Study of Spontaneous Imbibition in Fractured Sandstone With Contrasting Sedimentary Layers. J. Pet. Sci. Eng. 67 (1–2): 48–56. https://doi.org/10.1016/j.petrol.2009.02.014.
Li, K. and Horne, R. N. 2004. An Analytical Scaling Method for Spontaneous Imbibition in Gas/Water/Rock Systems. SPE J. 9 (3): 322–329. SPE-88996-PA. https://doi.org/10.2118/88996-PA.
Li, Y., Mason, G., Morrow, N. R. et al. 2009. Capillary Pressure at the Imbibition Front During Water-Oil Counter-Current Spontaneous Imbibition. Transport Porous Med. 77 (3): 475–487. https://doi.org/10.1007/s11242-008-9272-2.
Li, Y., Mason, G., Morrow, N. R. et al. 2011. Capillary Pressure at a Saturation Front during Restricted Countercurrent Spontaneous Imbibition with Liquid Displacing Air. Transport Porous Med. 87 (1): 275–289. https://doi.org/10.1007/s11242-010-9681-x.
Li, Y., Morrow, N. R. and Ruth, D. 2003. Similarity Solution for Linear Counter-Current Spontaneous Imbibition. J. Pet. Sci. Eng. 39 (3–4): 309–326. https://doi.org/10.1016/S0920-4105(03)00071-8.
Li, Y., Ruth, D., Mason, G. et al. 2006. Pressures Acting in Counter-Current Spontaneous Imbibition. J. Pet. Sci. Eng. 52 (1–4): 87–99. https://doi.org/10.1016/j.petrol.2006.03.005.
Luo, H., Mohanty, K. K., Delshad, M. et al. 2016. Modeling and Upscaling Unstable Water and Polymer Floods: Dynamic Characterization of the Effective Finger Zone. Presented at SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. SPE-179648-MS. https://doi.org/10.2118/179648-MS.
Mason, G. and Morrow, N. R. 2013. Developments in Spontaneous Imbibition and Possibilities for Future Work. J. Pet. Sci. Eng. 110 (October): 268–293. https://doi.org/10.1016/j.petrol.2013.08.018.
Mason, G., Fernø, M. A., Haugen, Å. et al. 2012. Spontaneous Counter-Current Imbibition Outwards from a Hemi-Spherical Depression. J. Pet. Sci. Eng. 90–91 (July): 131–138. https://doi.org/10.1016/j.petrol.2012.04.017.
Mason, G., Fischer, H., Morrow, N. R. et al. 2009a. Spontaneous Counter-Current Imbibition into Core Samples with All Faces Open. Transport Porous Med. 78 (2): 199–216. https://doi.org/10.1007/s11242-008-9296-7.
Mason, G., Fischer, H., Morrow, N. R. et al. 2009b. Effect of Sample Shape on Counter-Current Spontaneous Imbibition Production vs. Time Curves. J. Pet. Sci. Eng. 66 (3–4): 83–97. https://doi.org/10.1016/j.petrol.2008.12.035.
Mason, G., Fischer, H., Morrow, N. R. et al. 2010a. Correlation for the Effect of Fluid Viscosities on Counter-Current Spontaneous Imbibition. J. Pet. Sci. Eng. 72 (1–2): 195–205. https://doi.org/10.1016/j.petrol.2010.03.017.
Mason, G., Fischer, H., Morrow, N. R. et al. 2010b. Oil Production by Spontaneous Imbibition from Sandstone and Chalk Cylindrical Cores with Two Ends Open. Energ. Fuel. 24 (2): 1164–1169. https://doi.org/10.1021/ef901118n.
Meng, Q., Liu, H. and Wang, J. 2015. Entrapment of the Non-Wetting Phase During Co-Current Spontaneous Imbibition. Energ. Fuel. 29 (2): 686–694. https://doi.org/10.1021/ef5025164.
Mirzaei-Paiaman, A. and Masihi, M. 2013. Scaling Equations for Oil/Gas Recovery from Fractured Porous Media by Countercurrent Spontaneous Imbibition: From Development to Application. Energ. Fuel. 27 (8): 4662–4676. https://doi.org/10.1021/ef400990p.
Mirzaei-Paiaman, A., Masihi, M. and Standnes, D.C. 2011. Study on Non-Equilibrium Effects During Spontaneous Imbibition. Energ. Fuel. 25 (7): 3053–3059. https://doi.org/10.1021/ef200305q.
Morrow, N. R. and Mason, G. 2001. Recovery of Oil by Spontaneous Imbibition. Curr. Opin. Colloid In. 6 (4): 321–337. https://doi.org/10.1016/S1359-0294(01)00100-5.
Pooladi-Darvish, M. and Firoozabadi, A. 2000. Cocurrent and Countercurrent Imbibition in a Water-Wet Matrix Block. SPE J. 5 (1): 3–11. SPE-38443-PA. https://doi.org/10.2118/38443-PA.
Standnes, D. C. 2009. Calculation of Viscosity Scaling Groups for Spontaneous Imbibition of Water Using Average Diffusivity Coefficients. Energ. Fuel. 23 (4): 2149–2156. https://doi.org/10.1021/ef8010405.
Wang, J. and Dong, M. 2011. Trapping of the Non-Wetting Phase in an Interacting Triangular Tube Bundle Model. Chem. Eng. Sci. 66 (3): 250–259. https://doi.org/10.1016/j.ces.2010.10.009.
Yildiz, H. O., Gokmen, M. and Cesur, Y. 2006. Effect of Shape Factor, Characteristic Length, and Boundary Conditions on Spontaneous Imbibition. J. Pet. Sci. Eng. 53 (3–4): 158–170. https://doi.org/10.1016/j.petrol.2006.06.002.
Zhang, H., Nikolov, A. and Wasan, D. 2014. Enhanced Oil Recovery (EOR) Using Nanoparticle Dispersions: Underlying Mechanism and Imbibition Experiments. Energ. Fuel. 28 (5): 3002–3009. https://doi.org/10.1021/ef500272r.
Zhou, D., Jia, L., Kamath, J. et al. 2002. Scaling of Counter-Current Imbibition Processes in Low-Permeability Porous Media. J. Pet. Sci. Eng. 33 (1-3): 61–74. https://doi.org/10.1016/S0920-4105(01)00176-0.