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 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 Separation New Paradigm – 1991 “Commercial” - 1996
Oil to Surface
Separator & Pump(s)
Water to Injection
Basic Downhole Separation New Paradigm – 1991 “Commercial”
C-FER/NPEL

8. Onshore Mature Operations
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
C-FER/NPEL

13. Hydrocyclones (De-Oilers)
Tangential Inlet
Oil Concentrate Outlet
Disposal Water Outlet

14. DHOWS Process Design Constraints
Equipment O.D. < 4.5 3,600 bfpd
Equipment O.D. < 6 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. Phase I - $20k – Feasibility Study 1992
Development Project
Phase I - $20k – Feasibility Study 1992
Phase II – $100k - Prototype Development
Phase III – $450k - Field Testing
Offshore Study - $360k – North Sea/Sub Sea Applications
On-going Support to Trials - $1.5M – 16 trials
C-FER/NPEL

16. Timeline of NPEL/C-FER DHOWS JIP

17. Investment in DHOWS Technology
C-FER/NPEL

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

19. ESP Prototype Field Trial
C-FER/NPEL

20. ESP Prototype Field Trial

21. DHOWS Installations: Number
C-FER/NPEL

22. DHOWS Installations: System Type
C-FER/NPEL

23. Breakdown of DHOWS Applications
C-FER/NPEL

24. Basic “DHOWS” Installation - PanCanadian
C-FER/NPEL

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

26. Alliance Field Overall Results: ESP
C-FER/NPEL

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
C-FER/NPEL

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.
C-FER/NPEL

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 WOR Simmons 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
450
400
350
Fracture Pressure
300
250
Power for Single Disposal Well
@ 36,000 bwpd
200
Differential Pressure to Inject (psi)
150
100
Power for Ten DHOWS Wells
@ 3,600 bwpd each 50
Wellhead Pressure 3 6 9 12 15 18 21 24 27 30 33 36
Injection Rate (Thousands of bwpd)

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
Dual Leg Horizontal Well - 2 x 3,000 ft legs
Injection to “Toe” of one leg
Double packer to isolate injection
Produce from second leg and “Heel” of first leg

45. Dual Horizontal Well “DHOWS”
Also Installed With Uphole Injection
Talisman Energy Inc

46. Injection zone(s) above the production zone(s)
Uphole Reinjection
Pump System
Separator
Producing
Zone
Injection
Perforations
Injection zone(s) above the production zone(s)
ESP DHOWS

47. “DHOWS” with C-FER Desander
To Surface
“DHOWS” with C-FER Desander
Pump(s)
- ESP or PCP
Problem - Heavy Oil Wells
“Sand” Plugs Injection
Solution – Desanding
Sand & Oil to Surface
Water to Injection
Desander
Deoiler Hydrocyclone
To Injection

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
C-FER/NPEL

50. Zone cross-flooding between wells
Re-Entry Drillout
Pump (Dual or Single;
ESP, PCP, Beam)
Separator
Injection Zone
Old Producing Zone
(Cement or Leave Open)
Horizontal Re-entry
Horizontal Producing Zone
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
New Injection
Location
New Producing
Location
Existing Swept
Zone
Producing Well
Injector

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
Horizontal Cross-Flood
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 Management Same Well Source/Injector/Recycle
Lake or
River Source
Move toward
“Ideal”
Cap rock
Oil Leg
DHOWS
Water Leg
Cap rock
Pump
Underlying Aquifer

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
Avenue
Edmonton, Alberta
Canada T6N 1G1
tel:
fax:
web: