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Enhanced Oil Recovery in Fractured Carbonate Reservoirs

Explore EOR strategies for fractured reservoirs at low salinity and temperature. Learn about phase behavior, surfactant selection, viscosity, imbibition, and adsorption experiments.

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Enhanced Oil Recovery in Fractured Carbonate Reservoirs

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  1. EOR in Fractured Carbonate Reservoirs – low salinity low temperature conditions By Aparna Raju Sagi, Maura C. Puerto, Clarence A. Miller, George J. Hirasaki Rice University Mehdi Salehi, Charles Thomas TIORCO April 26, 2011

  2. Outline • EOR strategy for fractured reservoirs • Evaluation at room temperature (~25 °C) • Phase behavior studies – surfactant selection • Viscosity measurements • Imbibition experiments • Adsorption experiments • Evaluation at 30 °C and live oil • Phase behavior experiments • Imbibition experiements • Conclusions

  3. EOR strategy

  4. EOR strategy • Reservoir description • Fractures – high permeability paths • Oil wet – oil trapped in matrix by capillarity • Dolomite, low salinity, 30 °C • Recover oil from matrix spontaneous imbibition • IFT reduction • Surfactants • Wettability alteration • Surfactants • Alkali Ref: Hirasaki et. al, 2003

  5. Current focus – IFT reduction – surfactant flood • Surfactant flood desirable characteristics • Low IFT (order of 10-2 mN/m) • Surfactant-oil-brine phase behavior stays under-optimum • Low adsorption on reservoir rock (chemical cost) • Avoid generation of viscous phases • Tolerance to divalent ions • Solubility in injection and reservoir brine • Easy separation of oil from produced emulsion

  6. Phase behavior studies at ~ 25 °C

  7. Procedure Seal open end 24 hr Oil Initial interface Brine + surfactant Varying parameter Pipette (bottom sealed) micro micro • Parameter • Salinity • Surfactant blend ratio • Soap/surfactant ratio Winsor Type - I Winsor Type - II Winsor Type - III Optimal parameter

  8. Phase behavior, IFT, solubilization parameter lower IFT, mN/m 𝜎mo 𝜎mw middle Solubilization parameter Vo/Vs Vw/Vs upper Salinity, wt% NaCl Reed et al. 1977

  9. Phase behavior • Purpose of phase behavior studies • Determine optimal salinity, Cø • transition from Winsor Type I to Winsor Type II • Calculate solubilization ratio, Vo/Vs and Vw/Vs • Detect viscous emulsions (undesirable) • Parameters • Salinity – 11,000 ppm (incl Ca, Mg) • Surfactant type, Blend ratio (2 surfactants) • Oil type – dead oil vs. live oil • Water oil ratio (WOR) • Surfactant concentration

  10. S13D Salinity scan (Multiples of Brine2) WOR ~ 1 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 Brine2 4wt% optimal salinity Vo/Vs~ 10 at reservoir salinity 0.5wt% optimal salinity 0.25wt% optimal salinity

  11. Viscosity studies at ~ 25 °C

  12. Viscosities of phases – function of salinity 0.5 wt% S13D optimal salinity reservoir salinity Optimalsalinity Oil 0.84 0.94 1.05 1.15 1.26 1.36 1.47 Multiples of Brine 2

  13. Imbibition studies at ~ 25 °C

  14. Imbibition results – S13D reservoir cores (1”) S13D 0.5wt% 126md S13D 0.25wt% 151md Mehdi Salehi, TIORCO

  15. S13D candidate for EOR • under-optimum at reservoir salinity • stays under-optimum upon dilution • Vo/Vs~10 (at 4wt% surfactant concentration)indicative of low IFT • No high viscosity phases at reservoir salinity • ~ 70% recovery in imbibition tests

  16. Adsorption studies at ~ 25 °C

  17. Dynamic adsorption – procedure • Sand pack • Limestone sand ~ 20-40 mesh • Washed to remove fines & dried in oven • Core holder • Core cleaned with Toluene, THF, Chloroform, methanol • Core holder with 400 – 800psi overburden pressure • Vacuum saturation (~ -27 to -29 in Hg) • measure pore volume • Permeability measurement

  18. Dynamic adsorption - setup Syringe pump/ ISCO pump Core holder/ Sand pack Bromide electrode Bromide concentration reading Pressure monitoring Sample collection Pressure transducer

  19. Limestone sandpack ~ 102D • Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D • Flow rate: 12.24ml/h • Pore volume: 72 ml, Time for 1PV ~ 6hrs 1PV 2PV • 1PV = .38 ft3/ft2 • Lag ~ 0.14 PV • Adsorption0.26 mg/g sand0.12 mg/g reservoir rock

  20. Reservoir core – 6mD 1PV 2PV 3PV 4PV • Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D • Flow rate: 2ml/h • Pore volume: ~12 ml, Time for 1PV ~ 6hrs • 1PV = .035 ft3/ft2 • Effective pore size = 26.8𝜇m • Lag ~ 0.54PV to 1.25PV • Adsorption0.12 mg/g rock to0.28 mg/g rock day 3 day 1

  21. Reservoir core – 6mD plugging Expected pressure drop @ 15ml/hr 1PV 2PV 3PV 4PV 5PV Absence of surfactant Presence of surfactant – dyn ads exp day 1 day 3 – no data day 11 Expected pressure drop @ 2ml/hr 21

  22. HPLC analysis of effluent 1PV 2PV 3PV 4PV HPLC sample diff in area ~ 21 % 1PV 2PV 3PV 4PV day 3 day 1 By Yu Bian

  23. Reservoir core – 15mD 2PV 3PV 4PV 5PV • 2 micron filter @ inlet – pressure monitored • Injection solution: Brine 2 with 1000ppm Br - + 0.5wt% S13D • Flow rate: 1ml/h, Pore volume: ~30 ml, Time for 1PV ~ 1.25 days Bromide • 1PV = .103 ft3/ft2 • Effective pore size= 11.8𝜇m • Lag ~ 0.67PV • Adsorption0.29 mg/g rock Surfactant HPLC sample Pressure day1 3 7 2 4 6 8 9 10 15 14 16 1PV

  24. HPLC analysis of effluent diff in area ~ 25 % By Yu Bian

  25. Adsorption results comparison

  26. Phase behavior studies at ~ 30 °C

  27. S13D phase behavior S13D 1wt% @ 30 °C Type II microemulsion S13D 1wt% @ 30 °C with live oil (600 psi) Type II microemulsion S13D 1wt% @ 25 °C Type I microemulsion

  28. S13D/S13B blend scan 30°C Brine 2 salinity; 2 wt% aq; WOR = 1 10/0 9/1 8/2 7/3 6/4 5/5 4/6 3/7 2/8 1/9 0/10 Optimal blend S13D S13D/S13B ratio S13B

  29. 5 4 3 2 1 0 5 4 3 2 1 0 Phase behavior S13D/S13B blend With dead oil @ 30 °C % Cs S13D 10 9 8 7 6 5 4 3 2 1 0 S13B 0 1 2 3 4 5 6 7 8 9 10 50 40 30 20 10 0 50 40 30 20 10 0 °C Aqueous stability test of S13D/S13B blend S13D 10 9 8 7 6 5 4 3 2 1 0 S13B 0 1 2 3 4 5 6 7 8 9 10

  30. S13D/S13B (70/30) – dead vs live crude @ 30 °C Dead oil – UNDER-OPTIMUM Live oil – OVER-OPTIMUM After mixing & settling for 1 day Before mixing After mixing & settling for 1 day

  31. Imbibition studies at ~ 30 °C

  32. Imbibition results –reservoir cores (1”) S13D 0.5wt% 126mD, 25 °C S13D/S13B 70/30 1wt% 575mD, 30 °C S13D 0.25wt% 151mD25 °C S13D/S13B 60/40 1wt% 221mD, 30 °C Mehdi Salehi, TIORCO

  33. Conclusions

  34. Conclusions • Dynamic adsorption experiments (absence of oil) • Effluent surfactant concentration plateaus at ~80% injected concentration • Higher PO components are deficient in the effluent sample (in plateau region) • Increase in pressure drop with volume throughput • Sensitivity of phase behavior to temperature and oil (dead vs. live) • S13D/S13B 70/30 @ 30 °C performance poor compared to S13D @ 25 °C

  35. Questions

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