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EOR in Fractured Carbonate Reservoirs – low salinity low temperature conditions

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. Outline. EOR strategy for fractured reservoirs

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EOR in Fractured Carbonate Reservoirs – low salinity low temperature conditions

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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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