Technology Oil Potential with DHOWS

2. Technology Oil Potential with DHOWS

3. Downhole Oil/Water Separation Background Basic Operation Development Project Initial Results Economics What Has Already Been Done What Can Be Done What Might Be Done in Future

4. Background Why was it needed? What was the concept? When did it happen? Where could it be used? How was it turned into action? Who got it started?

5. Water and Oil Production in Western Canada

6. Downhole Oil/Water Separation (DHOWS) Problem - Wells being shut-in Still producing oil Producing too much water Most wells shut-in @ WOR<20 Solution - In Well Separation Downhole Mechanical solution more reliable than shut-offs Evaluated membranes, gravity separation, selective filtration, and hydrocyclones Re-Inject water into producing formation

7. Basic Downhole SeparationNew Paradigm – 1991“Commercial” - 1996

8. DHOWS Applications Onshore Mature Operations Water handing one of the highest costs A large number of mature fields with high WOR Small volumes and small wellbores Offshore Reduce volumes to platforms Reduce produced water dumping to ocean Avoid adding to existing platforms Middle East Even a small amount of water a problem

9. Project Development Concept Look at all options for Feasibility Work with appropriate vendors to develop prototypes Move directly to field testing at selected sites Expand testing to develop “commercial” products Follow-up to expand applications

10. Downhole Oil/Water Separation (DHOWS) New Paradigm Engineering Ltd. Project Initiator/Inventor - Bruce Peachey Concept Development & Project Leader Centre For Engineering Research Inc., C-FER Contracting & Development Support Technology Licensing Oil Industry Participants Funding, prioritization & test wells Pump and Hydrocyclone Vendors Prototype Design and Initial Prototypes Equipment Marketing

11. Basic Operation Typical DHOWS Configuration Hydrocyclone Operation Design Constraints

12. Typical DHOWS Configuration

13. Hydrocyclones (De-Oilers)

14. DHOWS Process Design Constraints Equipment O.D. < 4.5 inches @ 3,600 bfpd Equipment O.D. < 6 inches @ 9,000+ bfpd No access for maintenance for 1-12 years Little or no downhole control or instrumentation Low cost and reliable Water/Oil Ratio to surface = 1-2

15. Development Project Phase I - $20k – Feasibility Study 1992 Phase II – $100k - Prototype Development 1993-94 Phase III – $450k - Field Testing 1994-96 Offshore Study - $360k – North Sea/Sub Sea Applications On-going Support to Trials - $1.5M – 16 trials

16. Timeline of NPEL/C-FER DHOWS JIP

17. Investment in DHOWS Technology

18. DHOWS Prototypes ESP - Electric Submersible Pump - 1800 bfpd Reduced water to surface by 97% Oil Rate went up 10-20% at same bottom-hole rates Ran 8 months 1994-95 PCP - Progressing Cavity Pump - 1800 bfpd Reduced water to surface by 85% Well previously in sporadic operation for about 3 yrs. Ran 17 months 1994-1996 Beam Pump - 600 bfpd Reduced water to surface by 85% Demonstrated Gravity Separation Ran for 2 months - rod failure

19. ESP Prototype Field Trial

20. ESP Prototype Field Trial

21. DHOWS Installations: Number

22. DHOWS Installations: System Type

23. Breakdown of DHOWS Applications

24. Basic “DHOWS” Installation - PanCanadian

25. ESP DHOWS Anderson Exploration Ltd., Swan Hills, AB

26. Alliance Field Overall Results: ESP

27. ESP DHOWS Results - Talisman

28. DHOWS Application Requirements Suitable disposal zone accessible from the production wellbore Competent casing/cement for disposal zone isolation Water cuts above 80% Accurate estimate of productivity and injectivity Relatively stable production Favourable Economics

29. Critical Success Factors Disposal Zone Selection location, isolation, injectivity characterization Completion integrity testing disposal zone preparation and testing Operation separation optimization long term injection behavior changes in inflow conditions

30. Typical Installation Steps Prepare well for installation Pull existing lift system Recomplete injection zone perforating, install screen, treat zone Install injection packer and on/off assembly Perform injectivity test Adjust system configuration if necessary Install system Produce kill fluids, then start production

31. Control and Monitoring Control Methods VFD – Variable Frequency Drive Surface choke Surface controlled downhole choke Minimum Monitoring Injection and producing pressure and injection rate Injection water quality Water cut of intermediate stream

32. Future Equipment Development of “Basic” DHOWS Heavy Oil: Solve the problem of sand production Offshore: Already under way. Gas Lift Proposal High Volume: Larger capacity system under development Lower Water cut to surface: Feasible for offshore subsea Alternate Lift Systems: Gas Lift, Flowing, Jet Pump Alternate Separation Units: More options at low rates

33. DHOWS Licensing Status Peachey Patents - assigned to C-FER C-FER licenses pump vendors ESP - World Wide Licenses REDA - AQWANOT Systems Centrilift (Baker-Hughes) - HydroSep Systems PCP/Beam - Canadian only to date BMW Pump/Quinn Oilfield Baker-Hughes - preferred Hydrocyclone vendor Pump Vendors Collect Royalties for C-FER Once per well.

34. “Basic” DHOWS Technical Summary Positive experience is quickly building with over 30 field trials so far. Still fewer than 20 people world-wide have been involved in more than one application. All trials have shown water reductions of 85-97% Application of DHOWS can increase oil production and increase net returns

35. Impacts of DHOWS on Economic Recovery DHOWS is new so we are still learning Impacts vary by pool and by well Individual well costs could go up or down Overall operation costs will usually go down Production increases observed in most applications Analysis will try and relate DHOWS and Conventional economic limits based on analysis of the WOR vs. Cum Oil plot

36. Economic Cut-Offs for Typical Well Water Budget = US$5/bbl oil

37. Impact of DHOWS on Economic WOR Simmons Well #106

38. Impact of DHOWS on Economic WORSimmons Well #109

39. Impacts of DHOWS on Costs Cost to lift Water to Surface (Could go up or down) Gathering and Facilities Costs (Capital & Operating down) Disposal System (Capital and Operating down) Well Utilization (#Injectors down; #Producers up) Scale/Corrosion Costs (Capital and Operating down) Environmental Costs (Prevention & Clean-up costs down)

40. Disposal Power Consumption

41. Overall Profitability for a Sample Well

42. Mid-morning Coffee Break

43. What Has Already Been Done “DHOWS” Commercial Systems Developed with C-FER ESP Commercial – AQWANOTTM and HydrosepTM PCP (Weatherford) and Beam (Quinn) available New “DHOWS” Versions in Trial Stage Desanding (PCP and ESP) Gravity Separation Systems - Beam Pumps Texaco/Dresser, Quinn (Q-Sep) Reverse Coning Without Separators

44. DHOWS Horizontal Well - Talisman Energy

45. Dual Horizontal Well “DHOWS”

46. Uphole Reinjection Injection zone(s) above the production zone(s) ESP DHOWS

47. “DHOWS” with C-FER Desander

48. What Can Be Done Reverse Coning with DHOWS Re-Entry Drillout (Single Well) Re-Entry Drilling (Multi-well) Cross-Flooding Between Zones

49. Coning Control with DHOWS

50. Re-Entry Drillout Create or activate water disposal leg on producing well or producing leg on watered-out or water disposal well Re-entry drillout or drilled and plugged-off during initial drilling program Zone cross-flooding between wells

51. Re-Entry Drilling Use when zone between injector and producer is swept Directionally drill to establish new producing or injection location(s) Producing zone in well provides water for flood Existing wellbore could be used as producing zone or injection zone

52. Cross-Flooding Multi-layered reservoir application Some wells produce from lower zone & inject into upper zone Other wells produce from upper and inject lower Double the number of injectors or producers without drilling!

53. Horizontal Well Flooding Use to produce from one horizontal well Inject into a second horizontal well which is offset lower, higher or going in the opposite direction Inject into the vertical section of a re-entry horizontal producer.

54. What Might be Done In Future Offshore: Already under way. Gas Lift Proposal High Volume: Larger capacity system under development Lower Water cut to surface: Feasible for offshore subsea Alternate Lift Systems: Flowing, Jet Pump Alternate Separation Units: More options at low rates Ultimate Vision: No water handling on surface

55. Oilfield Water ManagementSame Well Source/Injector/Recycle

56. The Middle East Water Challenge Reservoirs contain billions of barrels Recovery only projected to be 40% due to water Most wells flowing only oil now No water handling infrastructure Wells “die” at 30-40% water cut Major costs and infrastructure to operate with water Solution needed: Install in well and leave for years No external power No increase in water

57. Smart Well Technologies Building on DHOWS concepts Modular processes Few large fixed capital installations In well if possible and economic Keep Systems Simple = Reliable Monitoring and Diagnostics Benefits of Downhole Monitoring Real-time Remote Monitoring Enhanced Analysis

58. New Technology Production Decline

59. Downhole Oil/Water Separation Summary Positive experience is quickly building. All “DHOWS” wells show water reduced 85-97% Still many applications to try Plenty of potential and opportunity for new concepts

60. Contact Information Advanced Technology Centre 9650-20 Avenue Edmonton, Alberta Canada T6N 1G1 tel: 780.450.3613 fax: 780.462.7297 email: info@newparadigm.ab.ca web: www.newparadigm.ab.ca