Scaling Laboratory-Data Surfactant-Imbibition Rates to the Field in Fractured-Shale Formations
- Dongmei Wang (University of North Dakota) | Jin Zhang (University of North Dakota) | Raymond Butler (University of North Dakota) | Kayode Olatunji (University of North Dakota)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- July 2016
- Document Type
- Journal Paper
- 440 - 449
- 2016.Society of Petroleum Engineers
- Scaling, Bakken Formation, Fracture, Imbibition rate, Spontaneours Imbibition
- 4 in the last 30 days
- 477 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
By use of existing methods, typical oil-recovery factors from the Bakken and other shale formations are low, typically less than 5% of original oil in place (OOIP). We are investigating the use of surfactant imbibition to enhance oil recovery from oil shale or other tight rocks. Much of our previous work has measured surfactant-imbibition rates and oil-recovery values in laboratory cores from the Bakken shale, Niobrara chalk/shale, and Eagle Ford formations. With optimized surfactant formulations at reservoir conditions, we observed oil-recovery values up to 20% of OOIP incremental over brine imbibition. However, whether surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil-production rates in a field setting. This, in turn, depends on three factors: the area of formation contact (through fractures and microfractures) when/where the surfactant formulation is introduced; the rates of surfactant imbibition; and the distances of surfactant imbibition into the rock and ultimate oil-displacement effectiveness. In this paper, we use analytical models to scale laboratory surfactant-imbibition rates to a field scale in fractured-shale formations.In laboratory cores, we observed imbibition rates that varied inversely with time. Dimensionless scaling groups were applied that compensate for the effects of sample size and shape, boundary conditions, permeability, porosity, and viscosity. Calculations were made of available fracture area, assuming typical horizontal well lengths and transverse-induced-fracture spacing in typical Bakken wells. These fracture areas were coupled with our imbibition-scaling groups to estimate oil-recovery rates in a field setting. Considering realistic timing, surfactant imbibition will generally not proceed more than a few meters into the low-permeability shale/chalk formations. These calculations indicate insufficient fracture area to provide a viable imbibition process if only the induced-fracture area is considered. However, recent results from geological, microseismic, and pressure-transient studies indicate considerably greater area associated with natural microfractures in our target formations. When the increased area suggested by the presence of microfractures is included in our analyses, the surfactant-imbibition process appears quite promising.
|File Size||1008 KB||Number of Pages||10|
Adibhatla, B., Sun, X. and Mohanty, K. K. 2005. Numerical Studies of Oil Production from Initially Oil-Wet Fracture Blocks by Surfactant Brine Imbibition. Presented at SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, 5–6 December. SPE-97687-MS. http://dx.doi.org/10.2118/97687-MS.
Austad, T. and Miller, J. 1997. Spontaneous Imbibition of Water Into Low Permeable Chalk at Different Wettabilities Using Surfactants. Presented at the International Symposium on Oilfield Chemistry, Houston, 18–21 February. SPE-37236-MS. http://dx.doi.org/10.2118/37236-MS.
Chen, H. L., Lucas, L. R., Nogaret, L. A. D. et al. 2000. Laboratory Monitoring of Surfactant Imbibition Using Computerized Tomography. Presented at SPE International Petroleum Conference and Exhibition in Mexico, Villahermosa, Mexico, 1–3 February. SPE-59006-MS. http://dx.doi.org/10.2118/59006-MS.
Cuiec, L. E., Bourbiaux, B. and Kalaydjian, F. 1994. Oil Recovery by Imbibition in Low-Permeability Chalk. SPE Form Eval 9 (3): 200–208. SPE-20259-PA. http://dx.doi.org/10.2118/20259-PA.
Fischer, H., Wo, S. and Morrow, N. R. 2008. Modeling the Effect of Viscosity Ratio on Spontaneous Imbibition. SPE Res Eval & Eng 11 (3): 505–512. SPE-102641-PA. http://dx.doi.org/10.2118/102641-PA.
Kurtoglu, B. and Kazemi, H. 2012. Evaluation of Bakken Performance Using Coreflooding, Well Testing, and Reservoir Simulation. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October. SPE-155655-MS. http://dx.doi.org/10.2118/155655-MS.
Ma, S., Morrow, N. R. and Zhang, X. 1997. Generalized Scaling of Spontaneous Imbibition Data for Strongly Water-Wet Systems. J Pet Sci Eng 18 (3–4): 165–178. http://dx.doi.org/10.1016/S0920-4105(97)00020-X.
Ma, S., Zhang, X., and Morrow, N. R. 1999. Influences of Fluid Viscosity on Mass Transfer between Rock Matrix and Fractures. J Can Pet Technol 38 (7): 25–30. PETSOC-99-07-02. http://dx.doi.org/10.2118/99-07-02.
Mattax, C. C. and Kyte, J. R. 1962. Imbibition Oil Recovery from Fractured, Water-Driven Reservoir. SPE J. 2 (2): 177–184. SPE-187-PA. http://dx.doi.org/10.2118/187-PA.
Mirzaei, M., Dicarlo, D. A. and Pope, G. A. 2013. Visualization and Analysis of Surfactant Imbibition into Oil-Wet Fractured Cores. Presented at SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September–3 October. SPE-166129-MS. http://dx.doi.org/10.2118/166129-MS.
Morrow, N. R. and Mason, G. 2001. Recovery of Oil by Spontaneous Imbibition. Curr. Opin. Colloid In. 6 (4): 321–337. http://dx.doi.org/10.1016/S1359-0294(01)00100-5.
Stoll, W. M., Hofman, J. P., Ligtheim, D. J. et al. 2008. Toward Field-Scale Wettability Modification—The Limitations of Diffusive Transport. SPE Res Eval & Eng 11 (3): 633–640. SPE-107095-PA. http://dx.doi.org/10.2118/107095-PA.
Torcuk, M. A., Kurtoglu, B., Alharthy, N. et al. 2013. Analytical Solutions for Multiple Matrix in Fractured Reservoirs: Application to Conventional and Unconventional Reservoirs. SPE J. 18 (5): 969–981. SPE-164528-PA. http://dx.doi.org/10.2118/164528-PA.
Wang, D., Butler, R., Liu, H. et al. 2011. Flow Rate Behavior and Imbibition in Shale. SPE Res Eval & Eng 14 (4): 505–512. SPE-138521-PA. http://dx.doi.org/10.2118/138521-PA.
Wang, D., Butler, R., Zhang, J. et al. 2012. Wettability Survey in Bakken Shale With Surfactant-Formulation Imbibition. SPE Res Eval & Eng 15 (6): 695–705. SPE-153853-PA. http://dx.doi.org/10.2118/153853-PA.
Wang, D., Zhang, J. and Butler, R. 2014. Flow Rate Behavior and Imbibition Comparison between Bakken and Niobrara Formations. Presented at SPE/AAPG/SEG Unconventional Resources Technology Conference, Denver, 25–27 August. SPE-2014-1920887-MS. http://dx.doi.org/10.15530/urtec-2014-1920887.
Wu, Y., Shuler, P. J., Blanco, M. et al. 2006. A Study of Wetting Behavior and Surfactant EOR in Carbonates with Model Compounds. Presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22–26 April. SPE-99612-MS. http://dx.doi.org/10.2118/99612-MS.
Yan, C., Luo, G. and Ehlig-Economides, C. A. 2015. Systematic Study of Bakken Well Performance Over Three Well-Completion Design Eras. J Can Pet Technol 54 (2): 95–106. SPE-171566-PA. http://dx.doi.org/10.2118/171566-PA.
Zhang, J., Wang, D. and Butler, R. 2013. Optimal Salinity Study to Support Surfactant Imbibition into the Bakken Shale. Presented at SPE Unconventional Resource Conference, Canada, Calgary, 5–7 November. SPE-167142-MS. http://dx.doi.org/10.2118/167142-MS.
Zhou, X., Morrow, N. R. and Ma, S. 1996. Interrelationship of Wettability, Initial Water Saturation, Aging Time, and Oil Recovery by Spontaneous Imbibition and Waterflooding. Presented at the SPE /DOE Improved Oil Recovery Symposium, Tulsa, 21–24 April. SPE-35436-MS. http://dx.doi.org/10.2118/35436-MS.