1887

Abstract

Summary

This work aims to analyse and explain non-standard imbibition, observed here and frequently in the literature. Previously conducted spontaneous imbibition tests in fully oil-saturated and strongly water-wet Bentheimersandstone core plugs, using OEO (One End Open) and TEOFSI (Two Ends Open Free Spontaneous Imbibition) revealed a significant delay at start of imbibition (induction time) before standard theoretical recovery vs time behaviour was established. The radial corefaces had been sealed with epoxy glue to define no-flow boundaries and yield imbibition corresponding to one dimensional (1D) solutions. However; in-situ imaging revealed that flow occurred in a two-dimensional (2D) manner. Particularly, in-situ imaging showedthat the water saturation at the end of imbibition was much higher in the core center than close to the no-flow boundaries. The tests were simulated numerically to interpret possible causes for the non-standard behaviour. First, the core scale model was parameterizedby matching AFO (All Faces Open) experiments (same experimental conditions, but not applying epoxy) and some of the TEOFSI tests that seemed able to be corrected for induction time. The predicted behaviour of the remaining tests was in agreement in terms ofimbibition rate if an induction time correction was made, however much lower recovery was observed than predicted.

Introducing no-flow regions in the model near the epoxy layers and an initially weakly oil-wet state centrally in the core were both necessary mechanisms to fully interpret the tests.The no-flow regions explained the difference in end recovery, but also impacted the imbibition rate (it was reduced). The initial weakly oil-wet state explained the low, but not zero imbibition rate in the induction period. A wettability alteration towardsstrongly water-wet then explained the resulting behaviour. It was found that this event was more likely triggered than gradual. It was however challenging to determine the triggering event.

This work demonstrates that spontaneous imbibition tests are very sensitive to the flow properties near the no-flow boundaries and can potentially affect the interpretation of end pointsaturations and flow functions. In-situ imaging by PET-CT improved the interpretation of the results by direct implementation of no-flow regions in the model. Accurate spontaneous imbibition behaviour must be achieved in the laboratory before upscaling tothe field.

Loading

Article metrics loading...

/content/papers/10.3997/2214-4609.201900129
2019-04-08
2024-03-29
Loading full text...

Full text loading...

References

  1. Andersen, P. Ø., Evje, S., Kleppe, H., & Skjæveland, S. M.
    (2015). A model for wettability alteration in fractured reservoirs. SPE Journal, 20(06), 1–261. https://doi.org/10.2118/174555–PA
    [Google Scholar]
  2. Andersen, P. Ø., Skjæveland, S. M., & Standnes, D. C.
    (2017). A Novel Bounded Capillary Pressure Correlation with Application to Both Mixed and Strongly Wetted Porous Media. In SPE Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE.
    [Google Scholar]
  3. Andersen, P. Ø., Brattekås, B., Nødland, O., Lohne, A., Føyen, T. L., & Fernø, M. A.
    (2018a). Darcy-Scale Simulation of Boundary-Condition Effects During Capillary-Dominated Flow in High-Permeability Systems. SPE Reservoir Evaluation & Engineering (preprint). https://doi.org/10.2118/188625-PA
  4. Andersen, P. Ø., Lohne, A., Stavland, A., Hiorth, A., & Brattekås, B.
    (2018b). Core Scale Simulation of Spontaneous Solvent Imbibition from HPAM Gel. In SPE Improved Oil Recovery Conference, 14–18 April, Tulsa, Oklahoma, USA. https://doi.org/10.2118/190189-MS
    [Google Scholar]
  5. Andersen, P. Ø., Qiao, Y., Standnes, D. C., & Evje, S.
    (2019). Cocurrent spontaneous imbibition in porous media with the dynamics of viscous coupling and capillary backpressure. SPE Journal, 24(1), 158–177. https://doi.org/10.2118/190267-PA
    [Google Scholar]
  6. Aronofsky, J. S., Masse, L., & Natanson, S. G.
    (1958). A model for the mechanism of oil recovery from the porous matrix due to water invasion in fractured reservoirs. Petroleum Transactions, AIME, 213, 17–19.
    [Google Scholar]
  7. Baldwin, B. A. and Spinler, E. A.
    (2002) In situ saturation development during spontaneous imbibition. Journal of Petroleum Science and Engineering, 35, 23–32. https://doi.org/10.1016/S0920-4105(02)00161-4
    [Google Scholar]
  8. Brooks, R. H., & Corey, A. T.
    (1966). Properties of porous media affecting fluid flow. Journal of the Irrigation and Drainage Division, 92(2), 61–90.
    [Google Scholar]
  9. Buckley, S. E., & Leverett, M.
    (1942). Mechanism of fluid displacement in sands. Transactions of the AIME, 146(1), 107–116.
    [Google Scholar]
  10. Chen, Z., Huan, G., & Ma, Y.
    (2006). Computational methods for multiphase flows in porous media (Vol. 2). SIAM.
  11. Dullien, F. A.
    (2012). Porous media: fluid transport and pore structure. Academic press.
  12. Fernø, M. A., Haugen, Å., Wickramathilaka, S., Howard, J., Graue, A., Mason, G. and Morrow, N. R.
    (2013). Magnetic resonance imaging of the development of fronts during spontaneous imbibition. Journal of Petroleum Science and Engineering, 101, 1–11. https://doi.org/10.1016/j.petrol.2012.11.012
    [Google Scholar]
  13. Fernø, M. A., Haugen, Å., Brattekås, B., Morrow, N. R. and Mason, G.
    (2015a). Spontaneous Imbibition Revisited: A New Method to Determine Kr and Pc by Inclusion of the Capillary Backpressure. In The 18th European Symposium on Improved Oil Recovery, EAGE, Dresden, Germany, 14–16 April. https://doi.org/10.3997/2214-4609.201412131
    [Google Scholar]
  14. Fernø, M.A., Haugen, Å., Brattekås, B., Mason, G. and Morrow, N.R.
    (2015b). Quick and Affordable SCAL: Spontaneous Core Analysis. In: International Sympoium of the Society of Core Analysts, St.John's New Foundland and Labrador, Canada, 16–21 August.
    [Google Scholar]
  15. Føyen, T. L., Fernø, M. A., & Brattekås, B.
    (2019). The Effects of Nonuniform Wettability and Heterogeneity on Induction Time and Onset of Spontaneous Imbibition. SPE Journal (preprint). https://doi.org/10.2118/190311-PA
  16. Fischer, H. and N. R.Morrow
    (2006) Scaling of oil recovery by spontaneous imbibition for wide variation in aqueous phase viscosity with glycerol as the viscosifying agent. Journal of Petroleum Science and Engineering52, 35–53. https://doi.org/10.1016/j.petrol.2006.03.003
    [Google Scholar]
  17. Haugen, Å., M. A.Fernø, G.Mason and N. R.Morrow
    (2014) Capillary pressure and relative permeability estimated from a single spontaneous imbibition test. Journal of Petroleum Science and Engineering115, 66–77. https://doi.org/10.1016/j.petrol.2014.02.001
    [Google Scholar]
  18. Lohne, A.
    (2013). User's Manual for BugSim–an MEOR Simulator (V1. 2). Technical report, IRIS.
    [Google Scholar]
  19. Mason, G., H.Fischer, N. R.Morrow, D. W.Ruth and S.Wo
    (2009) Effect of sample shape on counter-current spontaneous imbibition production vs time curves. Journal of Petroleum Science and Engineering66, 83–97. https://doi.org/10.1016/j.petrol.2008.12.035
    [Google Scholar]
  20. McPhee, C., Reed, J., & Zubizarreta, I.
    (2015). Core analysis: a best practice guide (Vol. 64). Elsevier.
    [Google Scholar]
  21. Morrow, N. R. and Xie, X.
    (2001). Oil Recovery By Spontaneous Imbibition From Weakly Water-Wet Rocks. Petrophysics, 42(4).
    [Google Scholar]
  22. Pruno, S., Rodvelt, H. E., & Skjæveland, O.
    (2018). Measurement of Spontaneous Imbibition Capillary Pressure, Saturation and Resistivity Index by Counter Current Technique at Net Reservoir Stress and Elevated Temperature.
    [Google Scholar]
  23. Standnes, D. C.
    (2010) Scaling spontaneous imbibition of water data accounting for fluid viscosities. Journal of Petroleum Science and Engineering73, 214–219. https://doi.org/10.1016/j.petrol.2010.07.001
    [Google Scholar]
  24. Wickramathilaka, S., Mason, G., Morrow, N. R., Howard, J. J., and Stevens, J. C.
    (2010). Magnetic Resonance Imaging Of Oil Recovery. In The 11th International Symposium On Reservoir Wettability, Calgary, Canada, 6–8 Sep.
    [Google Scholar]
http://instance.metastore.ingenta.com/content/papers/10.3997/2214-4609.201900129
Loading
/content/papers/10.3997/2214-4609.201900129
Loading

Data & Media loading...

This is a required field
Please enter a valid email address
Approval was a Success
Invalid data
An Error Occurred
Approval was partially successful, following selected items could not be processed due to error