Cristin-resultat-ID: 1474354
Sist endret: 8. desember 2017 20:47
NVI-rapporteringsår: 2017
Resultat
Vitenskapelig artikkel
2017

Analysis of the Impact of Fluid Viscosities on the Rate of Counter-Current Spontaneous Imbibition

Bidragsytere:
  • Dag Chun Standnes og
  • Pål Østebø Andersen

Tidsskrift

Energy & Fuels
ISSN 0887-0624
e-ISSN 1520-5029
NVI-nivå 2

Om resultatet

Vitenskapelig artikkel
Publiseringsår: 2017
Volum: 31
Hefte: 7
Sider: 6928 - 6940

Importkilder

Scopus-ID: 2-s2.0-85025170976

Beskrivelse Beskrivelse

Tittel

Analysis of the Impact of Fluid Viscosities on the Rate of Counter-Current Spontaneous Imbibition

Sammendrag

An analysis of the fundamental equation for countercurrent spontaneous imbibition (SI) for water-wet porous media has been performed based on a generalized mobility term MTGEN accounting for fluid–solid and fluid–fluid interaction developed by Andersen et al. ( IOR 2017—19th European Symposium on Improved Oil Recovery, Stavenger, Norway; European Association of Geoscientists & Engineers (EAGE): Houten, The Netherlands, 2017, ). MTGEN contains an additional term in the denominator, compared to the standard mobility term for two-phase flow, resulting from fluid–fluid interaction effects, which is proportional to both fluid viscosities. Evaluating MTGEN at a characteristic water saturation S*w chosen as 0.5; a characteristic generalized mobility term, MT*GEN, was developed. MT*GEN gives rise to a new dimensionless time (tDNew) for scaling of oil recovery vs time for spontaneous countercurrent imbibition specifically addressing the impact of fluid viscosities on the rate. tDNew has been tested and compared with the standard dimensionless time tDMZM derived by Ma, Zhang and Morrow and the dimensionless time expression tDMFMR due to Mason-Fischer-Morrow-Ruth by scaling 2 extensive sets of experimental data by Fischer and Morrow from 2006 where fluid viscosities were varied in the range 1–1647 and 4–43 cP for the aqueous and oleic phases, respectively. Comparison has also been performed for 1 data set reported by Zhang et al. ( SPE Reservoir Eng. 1996, 11, 280−285) where oil viscosity was varied from 4 to 156 cP keeping aqueous phase viscosity constant at 1 cP. The results show that tDNew in general can account for variations in fluid viscosities over the wide ranges in a better way than the two expressions tDMMZ and tDMFMR as it gives significantly less spread in the scaled oil recovery curves. Particularly, for two of the data sets reported by Fischer and Morrow ( J. Pet. Sci. Eng. 2006, 52, 35−53), where oil viscosity was kept constant and water phase viscosity was varied over several orders of magnitude, the reference scaling approaches, using tDMZM or tDMFMR, showed a systematic delay at increased water viscosity. The new time scale could capture this variation and scale all the tests to one curve due to the fluid–fluid interaction term, indicating that viscous coupling effects could impact the time scale at high viscosities. Compared to the reference time scales, tDNew incorporates the following additional data for numerical computations: End-points of the relative permeability functions (1/Iw and 1/Io), curvature of the relative permeability functions (α and β) and a fluid–fluid interaction coefficient (I). tDNew should in principle be universally valid for estimating fluid mobilities at countercurrent flow for all fluid viscosities and all relative permeability shapes. Hence, further testing on more empirical SI data where relative permeability data is available (end-points and shapes) for large variations in fluid viscosities (e.g., water gas systems) is recommended for further corroboration of the suggested scaling equation.

Bidragsytere

Dag Chun Standnes

  • Tilknyttet:
    Forfatter
    ved Institutt for energi- og petroleumsteknologi ved Universitetet i Stavanger

Pål Østebø Andersen

  • Tilknyttet:
    Forfatter
    ved Institutt for energi- og petroleumsteknologi ved Universitetet i Stavanger
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