Microbial Enhanced Oil Recovery New Strategies Improve Recovery

1. Microbial Enhanced Oil RecoveryNew Strategies Improve Recovery

2. It All Started With a Koala

3. Microbial Oil Enhancement Has Taken Many Forms Range of biotechnologies using bacteria to promote improved oil recovery Paraffin or ashphaltene removal Permeability modification: biofilms Permeability modification: polymers Fermentation: acids, gases and solvents Biosurfactants Methane generation

4. Traditions of Microbial Enhancement Inject bacteria at surface Inject nutrients such as molasses Continuous process Erratic results: Inconsistent field performance Unconvincing data interpretations Mass balance inconsistencies Not capable of scale up Bacteria and nutrient dispersion issues

5. Microbes (Bacteria)

6. Characteristics of Bacteria Dynamic ecology with many species Growth determined by environment Nutrients: cell material and energy Physical Chemical Biological In petroleum reservoirs: Anaerobic, carbon dioxide, sulfate, carbon, bicarbonate

7. The new process Uses microbes naturally present Batch treats with missing nutrients Manages the microbe ecology Promotes hydrophobic bacteria Impacts the oil-water interface Field wide impact True EOR not just improved rate

8. No microbes injectedBatch process �Hibernating bear*� concept Microbes revived and stimulated by a batch nutrient treatment Field specific *No bears are harmed in this process

9. Process mechanism Nutrient creates hydrophobic bacteria Hydrophobic bacteria insert into the oil-water interface: raises energy and increases interfacial area Causes microemulsion/nanoemulsion formation These phase boundaries have ultralow interfacial tension Release oil micro droplets Low external energy requirement instead uses the phase transitions taking place during emulsification Repeating process without further nutrients

11. Process mechanism Nutrient creates hydrophobic bacteria Hydrophobic bacteria insert into the oil-water interface: raises energy and increases interfacial area Causes microemulsion/nanoemulsion formation These phase boundaries have ultralow interfacial tension Release oil micro droplets Low external energy requirement instead uses the phase transitions taking place during emulsification Repeating process without further nutrients

13. Microemulsions and Enhanced oil recovery Microemulsions have characteristic properties such as ultralow interfacial tension, large interfacial area and capacity to solubilize both aqueous and oil-soluble compounds Microemulsions have thermodynamic stability Free energy of emulsion formation comprises interfacial free energy, interaction energy between droplets and entropy of dispersion Interaction energy between droplets has been shown to be negligible and the free energy of formation can be zero or even negative when the interfacial tension is of the order of 10�2 to 10�3 mN/m

15. Process mechanism Nutrient creates hydrophobic bacteria Hydrophobic bacteria insert into the oil-water interface: raises energy and increases interfacial area Causes microemulsion/nanoemulsion formation These phase boundaries have ultralow interfacial tension Release oil micro droplets Low external energy requirement instead uses the phase transitions taking place during emulsification Repeating process without further nutrients

16. Oil micro droplet formation

17. Overview Cell surface effect: Occurs with intact cells or cell surface fragments Field specific nutrients required to initiate interactive ultramicroscopic bacteria and hydrophobicity at interface Reservoir nutrients and metabolites continue the process after a single nutrient treatment

18. Overview Bacteria adhere to adjacent droplets suppressing coalescence and forming expanded oil bank Shear force deforms droplet as surface tension resists deformation Response resembles particulate behaviour not biosurfactants

19. Several methods of application In situ microbial response analysis (IMSRA)/Single well stimulation on producers Waterflood treatment of injectors Natural water drive Potentially, in combination with other EOR

20. Documented production increases

22. Alton Queensland Australia First field application

23. Alton: Well stimulationOver 2,000 incremental bbls

24. Alton facts Highly controlled application and established baseline Geochemical data showed oil previously trapped had been released from the formation Production increased by an average 40% over the baseline for 350 days Water cut was reduced 76oC (169oF)

25. Rankin Texas:First Waterflood 88oC (190oF) Salinity ~ 100g/L Two producers and three water injectors Established 4 year decline of 19% 2 nutrient additions over 2 years Average monthly production increased from 1395 to 1515 barrels of oil 24,400 barrels of addition oil over test period

26. North Sea WaterfloodMulti-cycle Application Field decline 25,000 bopd in 1990 to 12,500 bopd in 1992 Single well stimulation 1991 Microbial application to injection wells in eleven cycles from 1992 to 1995 Production decline changed from 19% to less than 10% following treatment Reduced water cuts on producing wells adjacent to water injection wells treated Water injection characteristics changed indicating re-profiling of injection water

27. California: ongoing

28. California: 235 daysOver 5,000 incremental bbls

29. California Single well stimulation: inject nutrients, over-displace, shut in 3 days, return to production 5 July 2007 Rapid and dramatic response Peak production increased from 20 bopd (83% water cut) to more than 112 bopd (39% water cut) No change offset wells Project expanded to treat all field water injection wells. and additional producers.

30. Canada: Ongoing

31. Canada production

32. Canada Summary: Production increased from 8 bopd at 94% water cut to a maximum of 26 bopd at 80% water cut. Last well test 23 bopd at 83% water cut. Single well stimulation; 7 days shut in Small volume of nutrients Rapid response 10 days after treating Sustained production increase (declining slightly) for four months Project expanded to field water injection wells, producers and a �return to production� for an idle well.

33. Application steps Field screening for suitable bacteria Laboratory analysis of produced water and injection water samples In situ Microbial Response Analysis (ISMRA) test on a producing well/ treatment of producers Targeted water flood/pilot implementation/ treat producers outside pilot area Full field application

34. Preferred fields Free flowing oil eg. API gravity 25 degrees or higher. Temperature up to 80 degrees C (176 degrees F) Salinity below 7.5%, preferably less than 5% Wellbore integrity Fields with well documented field histories and production records Good production facilities, water injection and disposal capability Reliable source of good quality injection water Good reservoir connectivity and understood reservoir sand distribution, faulting, flow barriers, etc.

36. Rigorous science Conceptual advance Low cost per incremental barrel Infrequent batch treatment Real increases in oil recovery