Analysis of capillary pressure and relative permeability hysteresis under low-salinity waterflooding conditions

Analysis of capillary pressure and relative permeability hysteresis under low-salinity... In this work, we analyze measurements of drainage, spontaneous imbibition and forced imbibition capillary pressure curves in conjunction with two-electrode resistivity on sandstone core samples under low- and high-salinity waterflooding conditions. State-of-the-art laboratory equipment able to work with actual reservoir fluids at reservoir conditions was designed and built to conduct these measurements. Unsteady-state coreflooding experiments under similar experimental conditions to those in the capillary pressure tests were also carried out. A black-oil reservoir simulation model was set up to history match experimental production and pressure data to obtain multi-phase flow functions. Two experiments were conducted on Minnelusa formation (eolian sand) rock samples at 93°C with TC crude oil and synthetic brines. Placement of an oil-wet membrane on one plug end and a water-wet disk on the other end guaranteed that only one phase was able to flow through each sample end at any given time. In one experiment, a 57,491ppm-brine (High-Salinity) was used during the imbibition process, while a 20-fold dilution of the High-Salinity brine (Low-Salinity) was used in the other experiment. Correspondingly, two unsteady-state experiments at fixed injection rate were completed on Minnelusa formation rock samples placed in the coreflooding system using comparable experimental conditions as those in the capillary pressure experiments. Comparison of high- and low-salinity experimental results shows that more noticeable capillary hysteresis toward water-wetness arose in the low-salinity experiment. High-salinity experiment results showed that the imbibition resistivity index was higher than that corresponding to drainage. History matching of the transient production data in capillary pressure experiments along with end-points obtained from unsteady-state core flooding experiments was used to obtain relative permeability curves. Availability of high-quality capillary pressure data at reservoir conditions improved the accuracy of relative permeability curves obtained from history matching unsteady-state core flooding experiments. Our results show a substantial improvement in obtaining both capillary pressure and relative permeability curves at reservoir conditions resulting from a combination of steady- and unsteady-state experiments. Capillary pressure results confirm that hysteresis is more prominent under low-salinity conditions and apparent higher oil trapping is observed during imbibition, compared to high-salinity conditions. Unsteady-state coreflooding results also show that low-salinity brine is not conducive to enhanced oil recovery in low-salinity waterflooding. Geochemical effects appear to negatively impact beneficial interfacial mechanisms proposed to benefit oil recovery such as the formation of more viscoelastic interfaces under low-salinity conditions. We conclude that coupling of fluid–fluid and rock–fluid interactions, including geochemical reactions, needs to be accounted for to better explain low-salinity waterflooding mechanisms. http://www.deepdyve.com/assets/images/DeepDyve-Logo-lg.png Fuel Elsevier

Analysis of capillary pressure and relative permeability hysteresis under low-salinity waterflooding conditions

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Publisher
Elsevier
Copyright
Copyright © 2016 Elsevier Ltd
ISSN
0016-2361
D.O.I.
10.1016/j.fuel.2016.04.039
Publisher site
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Abstract

In this work, we analyze measurements of drainage, spontaneous imbibition and forced imbibition capillary pressure curves in conjunction with two-electrode resistivity on sandstone core samples under low- and high-salinity waterflooding conditions. State-of-the-art laboratory equipment able to work with actual reservoir fluids at reservoir conditions was designed and built to conduct these measurements. Unsteady-state coreflooding experiments under similar experimental conditions to those in the capillary pressure tests were also carried out. A black-oil reservoir simulation model was set up to history match experimental production and pressure data to obtain multi-phase flow functions. Two experiments were conducted on Minnelusa formation (eolian sand) rock samples at 93°C with TC crude oil and synthetic brines. Placement of an oil-wet membrane on one plug end and a water-wet disk on the other end guaranteed that only one phase was able to flow through each sample end at any given time. In one experiment, a 57,491ppm-brine (High-Salinity) was used during the imbibition process, while a 20-fold dilution of the High-Salinity brine (Low-Salinity) was used in the other experiment. Correspondingly, two unsteady-state experiments at fixed injection rate were completed on Minnelusa formation rock samples placed in the coreflooding system using comparable experimental conditions as those in the capillary pressure experiments. Comparison of high- and low-salinity experimental results shows that more noticeable capillary hysteresis toward water-wetness arose in the low-salinity experiment. High-salinity experiment results showed that the imbibition resistivity index was higher than that corresponding to drainage. History matching of the transient production data in capillary pressure experiments along with end-points obtained from unsteady-state core flooding experiments was used to obtain relative permeability curves. Availability of high-quality capillary pressure data at reservoir conditions improved the accuracy of relative permeability curves obtained from history matching unsteady-state core flooding experiments. Our results show a substantial improvement in obtaining both capillary pressure and relative permeability curves at reservoir conditions resulting from a combination of steady- and unsteady-state experiments. Capillary pressure results confirm that hysteresis is more prominent under low-salinity conditions and apparent higher oil trapping is observed during imbibition, compared to high-salinity conditions. Unsteady-state coreflooding results also show that low-salinity brine is not conducive to enhanced oil recovery in low-salinity waterflooding. Geochemical effects appear to negatively impact beneficial interfacial mechanisms proposed to benefit oil recovery such as the formation of more viscoelastic interfaces under low-salinity conditions. We conclude that coupling of fluid–fluid and rock–fluid interactions, including geochemical reactions, needs to be accounted for to better explain low-salinity waterflooding mechanisms.

Journal

FuelElsevier

Published: Sep 15, 2016

References

  • Influence of brine composition and fines migration on crude oil/brine/rock interactions and oil recovery
    Tang, G.-Q.; Morrow, N.R.
  • Geochemical modeling and experimental evaluation of high-ph floods: impact of water–rock interactions in sandstone
    Kazempour, M.; Sundstrom, E.; Alvarado, V.
  • Mitigation of anhydrite dissolution in alkaline floods through injection of conditioned water
    Kazempour, M.; Gregersen, C.S.; Alvarado, V.
  • Can we really measure the relative permeabilities using the micropore membrane method?
    Lenormand, R.; Delaplace, P.; Schmitz, P.

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