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OUR “NEW TRICKS” FOR YOUR “OLD RESERVOIRS ” Oil Chem Technologies, Inc. Sugar Land, TX

OUR “NEW TRICKS” FOR YOUR “OLD RESERVOIRS ” Oil Chem Technologies, Inc. Sugar Land, TX. Oil Recovery Overview. BAVIER; BASIC CONCEPTS OF EOR PROCESSES(1991). YOUR “OLD RESERVOIRS ”. CHEMICAL IOR TARGET IN SELECTED COUNTRIES. 180. 173. 160. 140. 120. 100. 100. Billion Bbls. 84. 77.

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OUR “NEW TRICKS” FOR YOUR “OLD RESERVOIRS ” Oil Chem Technologies, Inc. Sugar Land, TX

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  1. OUR “NEW TRICKS” FOR YOUR “OLD RESERVOIRS”Oil Chem Technologies, Inc.Sugar Land, TX

  2. Oil Recovery Overview BAVIER; BASIC CONCEPTS OF EOR PROCESSES(1991)

  3. YOUR “OLD RESERVOIRS”

  4. CHEMICAL IOR TARGET IN SELECTED COUNTRIES 180 173 160 140 120 100 100 Billion Bbls 84 77 80 63 61 60 51 40 40 26 24 20 12 10 10 9 7 6 4 4 3 3 0 . 9 0 . 2 0 . 3 0 . 6 0 Iran UK Iraq India USA Libya Brazil Qatar China Oman Dubai Kuwait France Russia Norway Mexico Nigeria Canada Germany Denmark Romania S. Arabia Venezuela Abu Dhabi

  5. REPORTED CHEMICAL IOR PROJECTS WORLDWIDE OGJ April 12, 2004

  6. REPORTED CHEMICAL IOR PRODUCTION WORLDWIDE OGJ April 12, 2004

  7. LOUDON FLOOD - EXXON 1983 • 2.3% surfactant • 96% of the connate salinity • 0.3% pore volume • 0.1% Xanthan gum • 56 million pounds surfactant was injected in 9 months • 68% ROIP

  8. BIG MUDDY – CONOCO 1981 • 3% surfactant • 5% Isobutyl alcohol as co-surfactant • 0.6% salt • 0.22% polyacrylamide • 0.1 pore volume • 15% ROIP

  9. ROBINSON – MARATHON1983 • 10% surfactant – petroleum sulfonate • 0.8% hexanol as co-surfactant • 2.5% salt • No polymer • 0.1 pore volume • 19 –21% ROIP

  10. IOR BY CHEMICAL FLOOD Limited commercial success for the past two decades - Reasons? • Sensitivity to oil price • Large up-front investment • Unpredictable return on investment • Availability of chemicals • Limitations of chemicals • Poor scaling from lab to field

  11. PAST PROBLEMS • High surfactant concentration • Salinity optimization required • Optimum salinity shift in the formation • Potential emulsion block • Potential residual additive in the produced oil • Economical Feasibility

  12. however, • Extensive lab evaluations support the feasibility of chemical flooding • Field data proves chemical flooding is an effective way to recover residual oil • New chemicals and processes open the door for new opportunities

  13. OUR “NEW TRICKS” FOR YOUR “OLD RESERVOIRS”

  14. Solubilization Micellar High surfactant concentration Mobilization ASP LASP OASP Super Surfactant Low surfactant concentration MECHANISM

  15. PRESENTATION OUTLINE • Why Do We Need Surfactant • AP vs. SP • Our New Tricks – For Your Old Reservoirs • ASP • LASP • OASP • Super Surfactant • Smart Surfactant • Flow Improver • Start Your IOR Projects

  16. PRESENTATION OUTLINE • Why Do We Need Surfactant • AP vs. SP • Our New Tricks – For Your Old Reservoirs • ASP • LASP • OASP • Super Surfactant • Smart Surfactant • Flow Improver • Start Your IOR Projects

  17. AP vs SP

  18. AP VS. SP * The price is based on 0.1% surfactant and polymer, 1.0% NaOH

  19. RELATIONSHIP BETWEEN CAPILLARY NUMBER AND OIL RECOVERY Nc =  µ / Nc =Capillary Number  = Darcy Velocity µ = Viscosity  = Interfacial Tension Chatzis and Morrow, SPEJ, (1994) 561.

  20. Using Surfactant AP vs. SP

  21. AP vs. SPAP: 0.1% polymer / 1.0% NaOH SP: 0.1% surf. / 0.1% polymer

  22. PRESENTATION OUTLINE • Why Do We Need Surfactant • AP vs. SP • Our New Tricks – For Your Old Reservoirs • ASP • LASP • OASP • Super Surfactant • Smart Surfactant • Flow Improver • Start Your IOR Projects

  23. ASP SURFACTANTSORS & ORS-HF SERIES

  24. ADVANTAGES • Field Proven • Consistent quality • Low concentration required • One component system • Low viscosity

  25. SHO-VEL-TUM FIELD • On production > 40 yrs, extensive water flood, produced 4 bbl/day • ASP started on 2/98, using Na2CO3 and ORS-62 • Total incremental oil > 10,444 bbl in 1.3 years SPE 84904

  26. OIL SATURATION AFTER ASP INJECTION SPE 84904

  27. ORS-62HF(2) ORS-46HF ORS-41 SS-7593 ORS-97 ORS-41HF ORS-62 SS-B6688 ORS-57HF ORS-41HF INJECTED, ON-GOING & APPROVED PROJECTS

  28. SELECTED REFERENCES USING ORS SURFACTANTS • SPE 100004, 84904, 84075, 71491, 57288, 49018, 36748 • Hart’s Petroleum Engineering International, Dec. 1998. • DOE/PC/910087-0328 (OSTI ID: 3994)

  29. PRESENTATION OUTLINE • Why Do We Need Surfactant • AP vs. SP • Our New Tricks – For Your Old Reservoirs • ASP • LASP • OASP • Super Surfactant • Smart Surfactant • Flow Improver • Start Your IOR Projects

  30. LOW ALKALI SURFACTANT POLYMER FLOOD (LASP)

  31. ASP - POTENTIAL PROBLEMS? After extensive ASP flood in China, results were successful, however: • Alkali causes corrosion of the equipment • Scale forms in the formation • Produced wells plugged and require fracturing treatment to produce oil again • Alkali is detrimental to polymer viscosity • Extra polymer, NaOH and maintenance costs SPE 71492, 71061

  32. ASP LASP • Combines the advantages of ASP and SP • Use 0.1 – 0.6% alkali • Reduces surfactant adsorption • Reduces polymer degradation • Reduce the maintenance cost • Reduce the scale formation • Reduces the total cost of the treatment

  33. ASP vs. LASPCommon ASP: 0.1% surf. / 1.0% NaOH Common LASP: 0.1% surf. / 0.2% NaOH

  34. LASP - IFT vs. % NaOH 0.1% ORS-62HF, TDS ~ 3,500 ppm, API Gravity ~ 40, Temp ~ 40 C,

  35. PRESENTATION OUTLINE • Why Do We Need Surfactant • AP vs. SP • Our New Tricks – For Your Old Reservoirs • ASP • LASP • OASP • Super Surfactant • Smart Surfactant • Flow Improver • Start Your IOR Projects

  36. ORGANIC ALKALI SURFACTANT POLYMER FLOOD(OASP) SPE 99581

  37. COMPATIBILITY WITH HARD WATER Na2 CO3 + Ca ++ CaCO3 Na2 CO3 + Mg ++ MgCO3 NaOH + Ca ++ CaCO3 NaOH + Mg ++ MgCO3

  38. BRINE COMPATIBILITY

  39. Produced Water Water Treatment Alkali Surfactant Polymer Injection Well ASP INJECTION SITE DIAGRAM

  40. Produced Water Organic Alkali Surfactant Polymer Injection Well OASP INJECTION SITE DIAGRAM

  41. Produced Water Water Treatment Alkali Surfactant Polymer Injection Well OASP INJECTION SITE DIAGRAM

  42. ECONOMIC COMPARSION

  43. PRESENTATION OUTLINE • Why Do We Need Surfactant • AP vs. SP • Our New Tricks – For Your Old Reservoirs • ASP • LASP • OASP • Super Surfactant • Smart Surfactant • Flow Improver • Start Your IOR Projects

  44. SUPER SURFACTANTS SS Series

  45. ADVANTAGES • Super Effective • Ultra-Low concentration required (0.02% - 0.2%) • Provides ultra-low IFT • Super Convenient • No alkali is required • No water treatment is required

  46. ADVANTAGES - Continued • Super Tolerant • High TDS brine • High divalent cations • High temperatures

  47. ADVANTAGES - Continued • Super Savings • Surfactant • Alkali • Polymer • Water treatment • Sludge disposal • Surface equipment • Potential scale formation • Equipment maintenance

  48. SS IN HIGH SALINITY BRINETDS ~190,000ppm, Ca, Mg ~ 95,000 ppm Temp. ~ 50 C, API Gravity ~ 35

  49. SS IN HIGH TEMP. HEAVY CRUDETDS ~ 250 PPM, TEMP.~ 100 C, API GRAVITY~15

  50. SELECTED REFERENCES USING SS SURFACTANTS • SPE 75186 – SPE IOR Meeting, April, 2002 • SPE 80237 – SPE Oil Field Chemistry Meeting, Feb., 2003

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