This document discusses the abandonment and remediation of thermal wells located within or near thermal development areas. It provides an overview of relevant directives, regulations and in situ recovery plans. It also presents seven well case studies involving different compliance issues such as inadequate casing or cementing. The case studies describe the background of each well, identified compliance considerations, and approved remedial operations to make the wells thermally compatible for nearby thermal projects. The conclusion emphasizes understanding applicable rules and confirming the status and condition of wells near thermal development areas.

1. Thermal Wells:
Abandonment &
Remediation
Will Butler, P.Eng
Team Lead - Engineering

2. Topics
 Brief overview of Directives, Regulations & IRP’s
 Common Compliance Issues
 Well Case Studies
 4 wells located within thermal development area
 1 well located outside thermal development area
 1 with a liquid SCVF
 1 with a potential gas migration

3. Fundamentals
Understand current directives, regulations and IRP’s
AER Directive 009 – Minimum Casing Cementing Requirements
 Sec. 3.2 – Surface Casing
 Sec. 3.3 – Production, Intermediate & Liner Casing
 Sec. 4.2 – Thermal Cement
 Sec. 5 – Method of Determining Required Cement Top
AER Directive 010 – Minimum Casing Design Requirements

4. Fundamentals
Understand current directives, regulations and IRP’s
AER Directive 020 – Well Abandonment
 Sec. 4.2 – Open-Hole Abandonment in Penetrated Oil Sands Zones
 Sec. 4.6 – Oil Sands Evaluation Wells & Test Hole Wells
 Sec. 5.4 – Cased Wells Penetrating Oil Sands Zones
 Sec. 5.5 – Groundwater Protection
 Sec. 7.0 – Testing & Inspection Requirements for GM & SCVF
ID 2003-01
 Sec. 2 – SCVF/GM Testing, Reporting & Repair Requirements
 Sec. 3 – Casing Failure Reporting & Requirements

5. Fundamentals
Understand current directives, regulations and IRP’s
IRP Volume 03 – In Situ Heavy Oil Operations
Required assessment of offset, abandoned/vintage well & neighbouring
operator wells for compatibility to thermal operations:
 Within 300m of SAGD & 1000m of CSS developments.
 Wells which operator deems a risk factor or by request of landowner
Describes mechanical considerations due to thermal & pressure cycling:
 Casing loads (stress & strain)
 Corrosion considerations
 Coupling suitability

6. Fundamentals
Understand current directives, regulations and IRP’s
IRP Volume 03 – In Situ Heavy Oil Operations
Describes cementing considerations:
 Hydraulic Isolation (Porous & Groundwater)
 Caprock/primary seal integrity
 Cement type & integrity evaluation
 Strength retrogression at operating temperature

7. Common Compliance Issues
 Well is not properly isolated with thermal cement across oil sands
formations
• Primary cement
• Wellbore cement plugs (openhole or cased)
 Existing primary cement integrity is unknown or in question
• Unsuitable for expected temperature & pressure cycling?
• Temperature degradation of non-thermal cement?
• AER generally requires a CBL run before further approval of operations
 Casing failure/corrosion issues present

8. Common Compliance Issues
 Abandonment was not to current D020 standards
 Casing/connections not suitable for potential thermal and pressure cycling
stresses
• Non-premium connections
• Mechanical properties deemed unsuitable by engineering assessment or physical
testing
 SCVF/GM exists
• Liquid SCVF’s are usually “severe” due to high salinities & trace hydrocarbons
• Gas SCVF’s are usually “non-severe” due to flow rate less than 300 m3/d
• GM’s are rare, but observed from time to time

9. Case 1: Background
 Vertical well east of Fort McMurray
 Rig Release: February 1981
 Zonally abandoned and well cut and capped
 Compliant in 1981
 Currently within 100m of a proposed steam
injection well
 Max. temperature = 235oC
 Max. Pressure = 4MPa

10. Case 1: Compliance Considerations
Surface cement plug
Prod. casing/connections are inadequate
for expected temperatures
Cemented with Class G with no returns
to surface
BP capped with Class G
 Non-routine waiver submitted to leave
wellbore as is and operate as an
observation well
 Approval rejected, well must be made
thermally compliant due to steam
chamber proximity

11. Case 1: Operations
Step 1: Drill out surface plug & BP

12. Case 1: Operations
Step 1: Drill out surface plug & BP
Step 2: Run CBL/VDL to verify cement top
and integrity across non-thermal
formations to 109mKB
TOC 25m above sfc. csg shoe
Cement bond is good throughout

13. Case 1: Operations
Step 1: Drill out surface plug & BP
Step 2: Run CBL/VDL to verify cement top
and integrity across non-thermal
formations to 109mKB
Step 3: Section mill & under-ream casing
& cement from 109mKB to
below shoe @ 298mKB
AER Oilsands interval requiring
thermal isolation

14. Case 1: Operations
Step 1: Drill out surface plug & BP
Step 2: Run CBL/VDL to verify cement top
and integrity across non-thermal
formations to 109mKB
Step 3: Section mill & under-ream casing
& cement from 109mKB to prod.
csg. Shoe @ 298mKB
Step 4: Spot continuous thermal cement
plug from TD to min. 15m above
sfc. csg. shoe
Estimated Cost = $450,000.00

15. Case 2: Background
 Vertical well NW of Cold Lake
 Rig Release: March 1965
 Perfs just below the Grand Rapids formation
top
 Openhole section abandoned in 1965
 Grand Rapids perfs abandoned in 2001
 Well within 200m of proposed steam
chamber targeting the Clearwater Group
 Max. Temperature = 180oC

16. Case 2: Compliance Considerations
Casing cemented to surface with thermal
cement with good returns to surface (verified
by CBL)
Bridge plug set within 15m of Grand Rapids
perfs & capped with 10m of thermal cement
Thermal cement plug set in OH section and
across shoe from 434.0-372.2mKB in 2001
Non-thermal cement plug set in OH section
from TD to 434.0mKB in 1965

17. Case 2: Operations
 AER non-routine waiver to leave wellbore
“as is”, approved on the grounds that:
1. Above 434.0mKB, well is essentially
thermally compliant
2. Clearwater formation (target zone) is
isolated with thermal cement and well above
non-thermal cement plug from TD to
434.0mKB
 No remedial operations required
 Cut & cap well
Estimated cost = $8,000.00

18. Case 3: Background
 Vertical well North of Cold Lake
 Rig Release: November 1985
 Corehole well with no surface casing
 Cement plugs placed before rig release in
1985.
 Well is located within 50m of a proposed
steam chamber targeting the Clearwater
formation

19. Case 3: Compliance Considerations
Thermal cement plug top is located
17.4m above Grand Rapids formation
top
Formations above the Mannville Group
require isolation
• Joli Fou
• Viking

20. Case 3: Operations
 AER non-routine waiver to leave
wellbore “as is”, approved on the
grounds that:
1. Clearwater formation (target zone) is
isolated with thermal cement
2. OH logs indicate absence of porosity
across the Joli Fou & Viking
formations
3. Difficulty associated with attempting
to drill out surface OH cement plug
 No remedial operations required
Estimated cost = $0.00

21. Case 4: Background
 Vertical well south of Fort McMurray
 Rig Release: January 2000
 Perfs @ McMurray, Wabiskaw & Clearwater
formations
 Well is within proposed steam chamber
targeting the McMurray
 Client concerned casing may part due to
thermal stress created by possible steam
chamber contact

22. Case 4: Compliance Considerations
Prod. casing/connections are inadequate
Casing cemented to surface with non-
thermal thixotropic cement with good
returns to surface (verified by CBL)
 Non-routine waiver submitted to AER
with an engineering assessment of
casing stress/strain and cement
integrity from expected steam
chamber operations
 AER approved the following operations

23. Case 4: Operations
Step 1: Remove 38.1mm coil tubing
strings and retrieve Packer @
407mKB

24. Case 4: Operations
Step 1: Remove 38.1mm coil tubing
strings and retrieve Packer @
407mKB
Step 2: Retrieve WR plug @ 416mKB

25. Case 4: Operations
Step 1: Remove 38.1mm coil tubing
strings and retrieve Packer @
407mKB
Step 2: Retrieve WR plug @ 416mKB
Step 3: Chemically cut casing in the
McMurray formation @ 460mKB

26. Case 4: Operations
Step 1: Remove 38.1mm coil tubing
strings and retrieve Packer @
407mKB
Step 2: Retrieve WR plug @ 416mKB
Step 3: Chemically cut casing in the
McMurray formation @ 460mKB
Step 4: Run & set BP @ 459mKB

27. Case 4: Operations
Step 1: Remove 38.1mm coil tubing
strings and retrieve Packer @
407mKB
Step 2: Retrieve WR plug @ 416mKB
Step 3: Chemically cut casing in the
McMurray formation @ 460mKB
Step 4: Run & set BP @ 459mKB
Step 5: Spot continuous thermal cement
plug from TD to min. 15m above
sfc. csg. shoe
Estimated Cost = $90,000.00

28. Case 5: Background
 Vertical well north of Red Earth Creek
 Rig Release: March 1995
 Openhole section penetrates the Bluesky
Formation
 Well is not located within, or near, a
proposed thermal development
 Very little bitumen present in formations in
this area

29. Case 5: Compliance Considerations
Prod. casing/connections inadequate?
Casing cemented to surface with Class G
cement with good returns to surface (verified
by CBL)
 AER non-routine procedure was
approved based on the following:
1. Very little to no bitumen in formations
from OH logs
2. Unlikelihood of a thermal project
developing in the area
 Condition: Should thermal operations
develop within vicinity of the well, it
must be remediated to a state that
AER deems “thermally compatible”

30. Case 5: Operations
Step 1: Retrieve 60.3mm tubing

31. Case 5: Operations
Step 1: Retrieve 60.3mm tubing
Step 2: Spot continuous thermal cement
plug from TD to surface
Estimated cost = $35,000.00

32. Case 6: Background
 Vertical well north of Cold Lake
 Rig Release: March 2013
 Well has an existing liquid SCVF issue
(~500ml/day)
 From offset activity, likely source from the 2nd
White Specks
 Two cement squeeze attempts at 2WS were
unsuccessful
 Previous logs indicate excellent caprock at the
surface casing shoe

33. Case 6: Compliance Considerations
 Casing designed with premium connections
 Production casing cemented to surface with
thermal cement (Verified with CBL)
 Only 10m between squeezed abrasive slots
and surface casing shoe with no caprock
 2WS source is well above the Grand Rapids
formation
 Non-thermal cement may be used
 Non-routine waiver submitted to AER to
access caprock at surface casing shoe &
perform remedial cement squeeze
 AER approved the following operations:

34. Case 6: Operations
 Drill out cement plug to ~5m below surface
casing shoe

35. Case 6: Operations
 Drill out cement plug to ~5m below surface
casing shoe
 Perform six 120o Abrasive cuts from 172-
174mKB
 Establish feed rate into abrasive slots at
a maximum of 3.1MPa (fracture gradient)

36. Case 6: Operations
 Drill out cement plug to ~5m below surface
casing shoe
 Perform six 120o Abrasive cuts from 172-
174mKB
 Spot a Non-thermal cement plug from
178mKB to surface
 Squeeze cement to a maximum of 3.5MPa
Estimated cost = $160,000.00

37. Case 7: Background
 Vertical well east of Christina Lake
 Rig Release: March 2012
 Well has an existing GM issue
 Drilling reports indicated significant gas at the
McMurray formation top
 Confirmed by original OH & neutron logs
 Review of nearby wells revealed a gas injector
belonging to another operator
 Injector was maintaining a gas cap in the
Wabiskaw/McMurray formation

38. Case 7: Compliance Considerations
 Openhole cemented to surface with thermal
cement, but placement method is unknown
 Balanced, staged, layered, etc.?
 Openhole caliper log indicates significant wellbore
deviation from McMurray formation to surface
 Cement to formation bond is likely very poor
 Proposed intervention interval is 50m above the
Grand Rapids formation
 Non-thermal cement may be used
 High risk in attempting to drill out OH cement
plug in order to target McMurray source
 AER waiver required for well re-entry

39. Case 7: Operations
 Install new wellhead and SCVF assembly &
confirm if leak is a SCVF or GM

40. Case 7: Operations
 Install new wellhead and SCVF assembly &
confirm if leak is a SCVF or GM
 If possible, shut in injector well & allow stored gas
to migrate & dissipate

41. Case 7: Operations
 Install new wellhead and SCVF assembly &
confirm if leak is a SCVF or GM
 If possible shut in injector well & allow stored gas
to migrate & dissipate
 Drill out cement in surface casing to 25m below
the shoe

42. Case 7: Operations
 Install new wellhead and SCVF assembly &
confirm if leak is a SCVF or GM
 If possible shut in injector well & allow stored gas
to migrate & dissipate
 Drill out cement in surface casing to 25m below
the shoe
 Under-ream a minimum of OH diameter (or
greater) to within 1-2m of casing shoe

43. Case 7: Operations
 Install new wellhead and SCVF assembly &
confirm if leak is a SCVF or GM
 If possible shut in injector well & allow stored gas
to migrate & dissipate
 Drill out cement in surface casing to 25m below
the shoe
 Under-ream a minimum of OH diameter (or
greater) to within 1-2m of casing shoe
 Spot continuous thixotropic or expanding cement
blend from PBD to min. 15m above the sfc. csg
shoe (no squeeze)
Estimated cost = $240,000.00

44. In Conclusion
 Know and understand applicable regulations & IRP’s for oilsands &
thermal development areas
 Confirm status & condition of wells, including proximal & those of offset
operators, near thermal development areas
 300m from SAGD operations
 1000m from CSS operations
 Generally, a well is not thermally compliant unless all requirements in the
directives are met

45. In Conclusion
 Wells may receive AER approval to abandon with alternative methods, if
an engineering assessment supports long term integrity of the well
 Physical Testing
 Numerical Analysis
 Computer simulation of temperature & pressure effects
 Historical case studies in comparable areas

46. Questions