Ring Border

Pipeline
Operating & Maintenance
Manual
 Pipeline Operating &
Maintenance Manual
Revision: 2.0 December 2005

TABLE OF CONTENTS
Revision List ..........................................................................................................ii
1.0 Introduction
1.1. Purpose ..................................................................................................... 1
1.2. Scope......................................................................................................... 1
1.3. Document Control and Revision ................................................................ 2
1.4. Roles and Responsibilities......................................................................... 2
2.0 Pipeline Inventory, Records and Maps ................................................................. 3
2.1. Introduction ................................................................................................ 3
2.2. Pipeline Inventory Management ................................................................ 3
3.0 Pipeline Operating & Maintenance ....................................................................... 4
3.1. Pipeline Commissioning............................................................................. 4
3.2. Pipeline Suspension .................................................................................. 4
3.3. Pipeline Deactivation ................................................................................. 5
3.4. Pipeline Abandonment............................................................................... 5
3.5. Leak Detection........................................................................................... 5
3.6. Signage...................................................................................................... 6
3.7. Incident Reporting...................................................................................... 6
3.8. Ground Disturbance................................................................................... 6
3.9. Pipeline Repairs......................................................................................... 6
3.10. Isolation Valve Maintenance ...................................................................... 7
3.11. Pressure Protection Device Maintenance .................................................. 7
3.12. ROW Surveillance ..................................................................................... 7
3.13. Internal Corrosion Control.......................................................................... 8
3.14. External Corrosion Control......................................................................... 8
3.15. Pipeline Monitoring & Inspection................................................................ 8
3.16. Pressure Testing........................................................................................ 9

4.0 Documentation and Record Keeping.................................................................. 10

5.0 Emergency Response Plan ................................................................................ 11

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Appendices
A General Attachments
A.1 Pipeline Commissioning Procedure
A.1.1 Start-up and Shut-down of Lined Pipelines
A.2 Pipeline Decommissioning Procedure
A.3 Site Specific (i.e. liner vents – omit if not applicable)
B Site Specific Attachments
B.1 Pipeline Flow Schematic
B.2 Pipeline Inventory Summary
B.2.1 Active Pipeline Summary
B.2.2 Inactive Pipeline Status Log
B.2.3 Ring Border – NEB Pipeline Summary
B.3 Protective Device Summary
B.3.1 Isolation Valve Summary
B.3.2 Pressure Protection Device Summary
B.4 Integrity Management Plan
B.4.1 Chemical Inhibition Program
B.4.2 Pipeline Assessment Report
B.5 Operations & Maintenance Task List

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REVISION INDEX

Burlington
Rev. # Date Sections Revised
Approval
0 Dec 2003 Initial draft AWH
1.0 Oct 2005 All – EUB pipeline Regs Update AWH
2.0 Dec 2005 All – AB and BC manuals combined AWH
Added Pipeline Decommissioning form
2.1 Jan 2006 AWH
to Appendix A2

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1.0 INTRODUCTION
1.1 PURPOSE
The purpose of this Manual is to provide direction and understanding of responsibility to
Burlington’s operations personnel regarding pipeline operation and maintenance. The
Manual is to be used in conjunction with the most recent editions of Burlington’s
Environment, Health & Safety Handbook and the North Region Emergency Response
Plan.
It is the intention of this Manual to in part describe the procedures required to maintain
the integrity of the facilities for as long as it is in operation. Any reviews and revisions to
this Manual will be initiated by Operations leadership or engineering personnel, as
dictated by significant changes in production parameters, results of condition monitoring
or other such items that are addressed within. As a minimum, the corrosion protection
and monitoring of this system shall be reviewed and adjusted at a frequency of not less
than 5 years.
This document satisfies the Alberta Pipeline Regulation’s, Section 7, BC OGC Pipeline
Regulation section 6(d), and the NEB Onshore Pipeline Regulation’s, Part 6 paragraph
27, requirement for an Operations and Maintenance manual.
The Manual contains and/or provides references to Burlington procedures for various
operating activities.
A summary of operating and maintenance tasks is provided in a table in Appendix B.4 of
this Manual.
1.2 SCOPE
This Manual contains guidelines and procedures for the integrity management of existing
pipelines within the scope of the following provincial jurisdictions:
• British Columbia Oil and Gas Commission (OGC)
• Canadian Standards Association CSA Z662
• Alberta Energy and Utilities Board (AEUB)
• National Energy Board
The specified Burlington owned pipelines included in the scope of this manual are listed
in Appendix B.2.
Excluded from the Manual are:
• Unlicensed pipelines on lease, and
• Unlicensed buried utility lines for sanitary service and fresh water.
This Manual does not specifically address the quality control requirements for the design
and construction of pipelines.

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1.3 Document Control and Revision

The body of this Manual is a controlled document and will be managed by Burlington
EH&S – Safety Engineering. The appendices, containing facility specific details, will be
reviewed at least annually to determine if any changes have occurred that would warrant
an update.
1.4 Roles and Responsibilities:
Operations Leader
a) Ensure Manuals are located on site,
b) Ensure that revisions to the Manual occur on an annual basis and that
operations update their Manuals accordingly,
c) Ensure that all items identified in the task list are addressed as required,
d) Ensure all operators are trained and knowledgeable regarding their
requirements as described within the Manual.
EH&S - Safety Engineering
a) Provide control of Manual updates and distribution,
b) Provide support/guidance for any corrosion assessments,
c) Issue annual updates to Manual,
d) Issue updated maps and pipeline license information when requested by
operations.
Operations Engineer
a) Communicate changes to the system to EH&S - Safety Engineering so
that Manuals can be kept current and accurate,
b) Update Manuals with any changes issued by EH&S - Safety Engineering.

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2.0 PIPELINE INVENTORY, RECORDS AND MAPS

2.1 Introduction
This section describes requirements for the maintenance of an accurate pipeline
inventory, of pipeline mechanical and inspection files and of pipeline maps.
2.2 Pipeline Inventory Management
A complete inventory listing of all pipelines shall be maintained for the operating area.
The listing will be kept in Appendix B of this Manual. For each pipeline in the inventory,
the records shall show:
• Location data, (from-to, end facility type)
• Materials data, (diameter, wall thickness, length, grade, coatings)
• Design data, (service, MOP, type)
• Operational data (construction date, operational status, operating
pressure), and
• Unique identifiers. (e.g. License #, line #, etc.)
In addition, files shall be maintained that will allow access to records associated with
each pipeline identified on the inventory. Data pertaining to the following activities will be
kept on file for the operating life of the pipeline.
• Inspection data,
• Service or repair data, including detailed drawings.
A map and a pipeline flow schematic of the operating area shall be maintained
illustrating the connectivity of the pipelines. An up to date copy of the schematic(s) will
be maintained in Appendix B.2 of this Manual. An up to date copy of a map for the
operating area will be maintained in the Facility ERP Manual.
A summary of the location of all line block valves used for the isolation of pipeline
segments in emergency situations is to be contained in Appendix B.3.1 of this Manual.
These valves require regular maintenance and records as per section 3.11 of this
Manual.
A summary of all pressure control devices including but not limited to rupture disks,
emergency shut down valves (ESDV), pressure relief valves (PSV), and pressure control
valves (PCV) is to be contained in Appendix B3.2 of this Manual. These devices require
regular testing and inspection as per section 3.12 of this Manual.

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3.0 PIPELINE OPERATING AND MAINTENANCE

3.1 Pipeline Commissioning
Commissioning a pipeline refers to performing the necessary work required to put a steel
production pipeline into service as part of the gathering system. The commissioning
procedure is included in Appendix A.1.
Prior to the commissioning of a pipeline, operations will ensure that the following
requirements have been met:
• A satisfactory pressure test has been completed and fully documented,
(see section 3.16 “Pressure Testing”)
• The pipeline test pressure has been reduced to at least MOP, and
• All tie-ins have been completed and inspected.
• All pipeline warning signs have been installed, and
• The pipeline has been registered with Alberta One-Call.
Prior to a deactivated pipeline being returned to service an engineering assessment is
required to ensure piping is suitable for its intended service. (CSA Z662 Clause
10.13.2.1)
When a deactivated/suspended pipeline (refer to section 3.3 and 3.4) is returned to
service the BC Assessment Authority in Dawson Creek is to be contacted or an
application to the AEUB must be made and approved prior to commissioning. In cases
where the pipeline has not been in normal operation within the previous 12 months, the
application must include the information identified in Directive 56 Section 3
(Discontinuance refers to a situation where the licensed operating status of the
line was changed to discontinued following an application to the AEUB)
Updates to the “Inactive Pipeline Status Log” (Appendix B.1.2) are also required when a
change of operating status occurs. This provides a record of what was done to the
pipeline during the change of operation.
3.2 Pipeline Suspension
Suspension of a pipeline refers to a planned or unplanned period of inactivity after which
the line will be returned to its original service.
Pipelines that are suspended must be safely maintained and periodically inspected to
ensure the pipeline’s integrity has not been compromised and that it is no danger to the
public and the environment. The OGC considers all suspended pipelines as operational;
as such the requirements of the appropriate CSA standard are to be followed. (OGC
Pipeline and Facilities Application Guide Part 4)
All pipelines will be suspended as per the Decommissioning Procedure outlined in
Appendix A.3.

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Cathodic protection must continue on suspended pipelines.

Upon suspension of a pipeline the BC Assessment Authority in Dawson Creek is to be
contacted.
If operational suspension of the pipeline is expected to be greater than one year, the
pipeline should be formally deactivated as per section 3.3 below.
3.3 Pipeline Deactivation
Deactivation refers to a planned shut down of normal pipeline operations usually
because the pipeline is no longer required for its original function. The line is normally
considered an asset to be used for some other function at a future unspecified date.
Pipelines that are deactivated must be safely maintained and periodically inspected to
ensure the pipeline’s integrity has not been compromised and that it is no danger to the
public and the environment. The OGC considers all deactivated pipelines as operational;
as such the requirements of the appropriate CSA standard are to be followed. (OGC
Pipeline and Facilities Application Guide Part 4)
In Alberta an application for discontinuance must be filed with the AEUB. The application
shall include the relevant information identified in Directive 56. Within 6 months of AEUB
approval the pipeline must be discontinued as per procedures outlined in Appendix A.2.
If the 6-month expiry date cannot be met the AEUB must be notified 30 days in advance.
The discontinuation of unlined pipelines will be performed as per the Decommissioning
Procedure outlined in Appendix A.2, once approved by the AEUB.
Cathodic protection must be maintained on deactivated pipelines.
The BC Assessment Authority in Dawson Creek is to be contacted when a pipeline is
deactivated.
3.4 Pipeline Abandonment
Abandonment refers to the planned shutdown of pipeline operations usually because the
pipeline is no longer required or no longer able to function. The line is normally no longer
considered an asset and no future application is foreseeable.
Within 90 days of the completion of the abandonment, an application must be filed with
the EUB. The application shall include the relevant information identified in Directive 56
Schedule 3.
The abandonment of a pipeline will be performed as per the Decommissioning
Procedure outlined in Appendix A.2, once approved by the AEUB.
Following the purging and depressurizing of the line, cathodic protection will be
removed, and the line will be capped off underground.
Within 1 year of the application submission, all associated surface facilities will be
removed and the surface site reclaimed. However, all crossing signs must be
maintained for as long as the line remains in the ground.

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Documentation of these activities must be kept on file and available upon request. Refer
to audit requirements Directive 56 Schedule 1.The BC Oil and Gas Commission will not
grant leave to abandon a pipeline, unless the line is removed in its entirety and the land
restored. (OGC Pipeline Information Bulletin No. 31, January 23, 1997)
Pipelines are to be maintained at a Deactivated level (refer to section 3.4).
3.5 Leak Detection
Operating companies are required to make periodic line balance measurements for
system integrity. Where existing technology for measuring and balancing multiphase
systems is limited or impractical, alternative techniques should be used. Installed
devices or operating practices, or both, are to be capable of early detection of leaks.
(CSA Z662 Clause 10.2.6)
Leak detection of pipelines in the facility can be achieved through several methods.
Methods that should be considered include, but are not limited to the following:
¾ Production accounting material balances.
¾ Visual inspection of Right of Ways (ROW Surveillance),
¾ Investigation of 3rd party reports,
¾ Changes in chart recorder data,
¾ Low pressure alarms,
¾ Over the line flame ionisation surveys.
Personnel responsible for interpreting and responding to the leak detection system shall
be knowledgeable of the leak detection methods and the pipeline system.
Records of all leak detection activity must be maintained and made available to the
Regulator upon request.
3.6 Incident Reporting
In the event of a leak or break in a pipeline where product is released, operations will
take immediate steps to stop the source of release and contain and clean up the spill.
Following initial response, the operator will notify the BRCL site supervisor, and follow
the incident reporting guidelines as established in the “Environment, Health & Safety
Handbook; Incident Notification and Reporting”.
The OGC is to be notified (in the form or manner directed by the chief inspecting
engineer) of the occurrence of; (a) spillage of oil or gas or solids, (b) malfunction of or
damage to the pipeline, or (c) incidents likely to cause or contribute to spillage. The
cause, effect and remedy of these events are to be subsequently reported. (OGC
Pipeline Regulation section 22(1) and (2))
Please see Oil and Gas Commission web page (www.ogc.gov.bc.ca) for guidance with
reporting to the OGC and necessary Notification and Report forms.

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3.7 Signage
Pipeline identification in the form of appropriate signage is required and shall be installed
and maintained at facility leases, road and railway rights-of-way, utility corridors,
subdivision developments, irrigation systems, and water crossings. (OGC Pipeline
Regulation section 18 and CSA Z662 Clause 10.2.8 and Alberta Pipeline Regulation
section 23)
Signs must conform to the size and content requirements as outlined in the Alberta
Pipeline Regulation section 68(2)(b), Schedule 1.
Sour pipeline facilities require signs warning of the possible presence of H2S and
advising about protective gear requirements. (OGC Sour Pipeline Regulation section
6(3))
Operations are responsible for the monitoring of sign condition and replacement should
they be removed, defaced or become illegible.
Operations will perform an annual survey of all signs to ensure they are in accordance
with the requirements of the regulations.
3.8 Ground Disturbance
All ground disturbance activities are to be carried out by qualified personnel in
accordance with the procedures outlined in the Environment, Health & Safety Handbook.
3.9 Pipeline Repairs
Pipeline repairs are an engineering function and as such shall be carried out using
approved procedures. Repairs shall follow engineered repair procedures in accordance
to current edition of CSA Z662.
In BC, prior to the commencement of an extension, alteration or repair of any pipeline or
a pressure component used or to be used in any pipeline, Burlington must file with the
chief inspecting engineer, in duplicate, all the pertinent data, specifications and
documented or other information he/she may require. Within 30 days of the completion
of the extension, alteration or repair a certificate, certifying that all work done and
materials used were in accordance with the data and specifications submitted, is to be
filed with the chief inspecting engineer. (OGC Pipeline Regulation section 11)
Failed sections of pipe shall be replaced with a section similar or equivalent to that of the
existing pipe. The wall thickness of the replacement section shall be equal or greater
(within transition limits) than that of the failed section.
Detailed drawings of the repair including precise locations are to be prepared and filed in
the pipeline file. All pressure test data and OGC submissions must also be maintained in
a pipeline file.
3.10 Isolation Valve Maintenance
Pipeline valves that might be required during and emergency shall be inspected and
partially operated at least once per calendar year, with a maximum interval of 18 months

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between such inspections and operations.

A permanent record of the tests and any repairs shall be kept and made available to the
Board on request.
A list of all isolation valves is located in Appendix B of this manual.
3.11 Pressure Protection Device Maintenance
All pipeline pressure control devices and pressure limiting devices shall be inspected
annually with a maximum interval of 18 months. The exceptions to this requirement are
rupture disks and thermal relief devices. (CSA Z662 Clause 10.6.5)
All pressure relieving devices shall be inspected based on their frequency set as per the
BRC Pressure Equipment Safety Program.
A permanent record of the inspection and tests of process control devices, pressure
limiting devices and pressure relieving devices shall be kept and made available to the
Board on request.
A list of all pressure protection devices is located in Appendix B.
3.12 ROW Surveillance
Operating companies are required to inspect and maintain their pipeline rights-of-way in
accordance to CSA Z662 Clause 10.5 and the Alberta Pipeline Regulations Clause
43(1).
CSA Z662 Clause 10.5.1.1:
Operating companies shall periodically patrol their pipelines in order to observe
conditions and activities on and adjacent to their rights-of-way that may affect the
safety and operation of the pipelines.
Particular attention shall be given to the following:
a) Construction activity,
b) Dredging operations,
c) Erosion,
d) Ice effects,
e) Scour,
f) Seismic activity,
g) Soil slides,
h) Subsidence,
i) Loss of cover, and
j) Evidence of leaks.

The Alberta Pipeline Regulation section 43

(1) The licensee of a pipeline that crosses water or unstable ground shall at least
once annually inspect the pipeline right-of-way to asses:
o The surface conditions on an adjacent to the right of way,

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o Indications of any leak in the pipeline,

o Any construction activity performed by others,
o Any encroachment or development near the pipeline right of way, or
o Any other condition affecting the safety or operation of the pipeline.
(2) The licensee of a pipeline other than one referred to in subsection (1) shall
inspect the pipeline right of way in accordance with that subsection at least once
annually or in accordance with the inspection intervals determined in the integrity
management component of the licensee’s manual or manuals referred to in
section 7.
(3) The licensee shall conduct the inspections required under subsections (1)
and (2)
a) at times of the year judged by the licensee to be the most appropriate
to achieve a satisfactory inspection, and
b) so as to reasonably minimize disturbance or damage to affected
surface property.
During well-site visits operators shall visually survey pipeline right-of-ways and report
anomalies with regard to:
• Surface conditions on and adjacent to the right of way,
• Indications of any leak in the pipeline,
• Any construction activity performed by others,
• Any encroachment or development near the pipeline right of way, and
• Any other condition affecting the safety or operation of the pipeline.
3.13 Internal Corrosion Control
All sour pipelines (containing hydrogen sulphide (H2S) in concentrations of 1 mole % or
more) shall have an internal corrosion protection plan. (OGC Sour Pipeline Regulation
section 7(2))
All pipeline systems containing gas or fluids that are considered corrosive are required to
have an internal corrosion control program except where experience has proven that
corrosion control is not justified. Any exceptions must be documented and monitored to
ensure that the situation does not change. (CSA Z662 Clause 9.1.3)
The corrosion control program shall be monitored for its effectiveness as outlined in
Appendix B.4 of this Manual. (CSA Z662 Clause 9.4.)
Integrity assessments should be updated at an interval that reflects the threats and rate
of change for each system.

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Records documenting the recommended mitigation and monitoring activities shall be

maintained in accordance with the applicable appendix and kept on file and available for
review when requested.
3.14 External Corrosion Control
Cathodic protection shall be provided and maintained on all operating, suspended and
discontinued pipelines. (CSA Z662 Clause 9.2.1.2)
Impressed current cathodic protection systems (those utilizing rectifiers, thermoelectric
generators or other external DC power supply) shall be monitored monthly, not to
exceed 6 weeks, to ensure their proper operation. (CSA Z662 Clause 9.2.10.2.1 and
CGA Recommended Practice OCC-1 Section 4.3.2.3(a)) Records of these checks shall
be maintained.
An annual adjustive survey will be performed to identify any deficiencies in the cathodic
protection system. Deficiencies will be reported and corrected and the survey data
documented. (CSA Z662 Clause 9.2.10.2, CGA Recommended Practice OCC-1 and
AEUB Pipeline Regulation section 52(1) and (2))
3.15 Pipeline Monitoring and Inspection
Internal corrosion monitoring shall be completed in accordance with the Pipeline Integrity
Management Plan in Appendix B.4.
Inspections to ensure the integrity of the system shall be performed as per the Pipeline
Integrity Management Plan in Appendix B.4. In addition, all lines in this system will be
inspected at any time they are exposed for a line crossing or tie-in. The Pipeline
Excavation Inspection Form contained in the Construction Supervisors Handbook will be
completed at the time of exposure and forwarded to EH&S Safety Engineering for review
and filing.
Results of monitoring and inspections shall be kept in the pipeline files and made
available upon request. These records will be maintained by EH&S - Safety
Engineering in GP.
If defects are detected in an NEB regulated pipeline that exceed the allowable
size allowed by CSA Z662 documentation shall be provided to the NEB which
includes:
1. defect dimensions,
2. likely cause,
3. corrective actions to be taken or planned.
3.16 Pressure Testing
Prior to pressure testing existing pipelines an engineering assessment shall be carried
out to: (CSA Z662 Clause 10.11.5.1)
• Determine whether it can sustain the proposed test pressure, and

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• Establish appropriate pressure test limits so that the pressure test will not
adversely affect the integrity of the pipeline.
Before the testing of any pipeline, copies of all test procedures are to be submitted to the
Inspecting Engineer of the commission. (OGC Pipeline Regulation section 19(11))
Any leak occurring during a pressure test shall be reported to the OGC.
All pertinent data surrounding a pressure test must be recorded and made available to
the OGC.
Pressure tests shall be documented to adequately support the success of the tests.
Records of pressure tests that qualify piping for service, shall be retained in the
pipeline’s file throughout its useful life, and shall contain at least the following
information: (CSA Z662 Clause 8.6.1 and 8.6.2.4)
• Time and date of test,
• Pipe specifications,
• Elevation profile and location of test section where applicable,
• Pressure test medium used,
• Test pressure at lowest elevation,
• Test duration,
• Pressure and temperature recording charts, where applicable,
• Pressure volume chart where applicable, and
• Location of any leaks or failures and description of repair action taken.

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4.0 DOCUMENTATION AND RECORD KEEPING

The following operational records shall be maintained for audit purposes and made
available to the OGC within 10 days upon their request.
• Pipeline Inventory Listing containing all physical data, current operating
data,
• Current maps showing pipeline system,
• Locations of all isolation valves,
• Location of all pressure control devices,
• Pipeline files containing records of all incidents, repairs, and inspections,
• Crossing Agreements,
• Leak Detection Records, (i.e. material balance checks)
• ROW Surveillance records,
• Pressure Protection Device – maintenance/test records,
• Annual Cathodic Protection surveys and monthly monitoring data,
• Internal Corrosion Monitoring records including monthly monitoring data,
• Pressure test results.

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5.0 Emergency Response Planning

All emergencies shall be handled in accordance with the North Region Emergency
Response Plan.
This manual will contain:
¾ The Definition of an Emergency,
¾ Levels of Emergency,
¾ Duties and Responsibilities,
¾ Emergency Response flowchart complete with contact names and phone
numbers,
¾ Spill Response,
¾ Key Contacts.
Once the emergency is handled, incident reporting and subsequent investigation will be
handled in accordance with the Environment, Health & Safety Handbook.
Records of pipeline emergencies are to be maintained to enable each incident to be
analysed. Records shall include but not necessarily be limited to; the date, location,
event description, repair procedure, and acceptance tests.

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APPENDIX A.1

Pipeline Commissioning
Procedure

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Definition Commissioning a pipeline refers to performing the necessary work required

to put the pipeline in service as part of the gathering system.
Function Whether the line is new, has been repaired, or has been out of service
temporarily, there are common concerns that necessitate the
Commissioning procedure. These concerns are that:
• All equipment (pipe, valves etc.) is pressure tested to a specified
percentage above the MOP and serviced as required.
• All corrosion prevention requirements have been satisfied.
• Equipment is purged of air and contaminants, where applicable.
• Blinds are removed and valves are in the proper position.
• All applicable transmitters and alarms are active.
• The proper documentation and notification is complete.
• All pipeline marker signs at roads, highways, and water
crossings are in place and indicate the correct ownership,
pipeline product and contact phone numbers,
• The commissioning procedure to be used is dependent upon the
service of the line, e.g. Solvent injection line, water injection line,
flowline, etc.
New Line To commission a new line:
• Install blinds to isolate the flowline from other facilities and
valves if required.
• Hydrostatically test the line to the required hydrotest pressure as
required by the pipeline license.
• Pig the line with methanol slug to remove water and debris.
• Batch inhibit steel flowlines as per Appendix A.3.
• Remove blinds as required.
• Check all valves and place in desired position.
• Monitor all flanges and fittings for leaks during start-up.
Repaired Line To commission repaired lines:
• Check all valves and place in desired position.
• Where combustible mixtures are a concern, purge line with
sweet gas to an unlit flare stack to break mud plugs and remove
oxygen from line.
• Batch inhibit steel lines to coat new pipe with an inhibitor film as
per Appendix A.3.
• Remove blinds as required.
• Monitor all flanges and threaded fittings during start-up (tape

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and gas test if applicable).

Suspended or To commission a suspended or deactivated line:
Deactivated Line
• Remove any pressure on line and purge if necessary.
• Remove blinds as required.
• Check all valves and place in desired position.
• Monitor all flanges and fittings for leaks during start-up.
• Batch inhibit steel lines to coat pipe with an inhibitor film as per
Appendix A.3.
• Reinstate the previous corrosion treating programs.
Notifications Contact the OGC prior to reactivating a suspended or deactivated pipeline
(a pressure test may be required to confirm the integrity of the line or if
the MOP is going to be of a higher pressure than it was licensed for).
Contact the B.C. Assessment Authority (in Dawson Creek) upon
reactivating a pipeline.
Commissioning of a pipeline suspended for more than 12 months or a
pipeline registered as discontinued or abandoned in accordance with the
Alberta Pipeline Regulation requires AEUB approval. Check operating
status via Accumap and apply for resumption in accordance with Alberta
Pipeline Regulation, Clause 85
Documentation For the commissioning of a new or repaired line as well as for the
resumption of a suspended or discontinued line documentation shall be
filed in the applicable pipeline file.

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APPENDIX A.2

Pipeline Decommissioning
Procedure

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Definition Decommissioning refers to temporarily or permanently taking a piece of

equipment or system out of service. The following three separate modes
are defined in order to be consistent with the regulatory definitions:
• Suspension of a pipeline refers to a planned or unplanned
period of inactivity after which the line will be returned to its
original service.
• Deactivation refers to a planned shut down of normal pipeline
operations usually because the pipeline is no longer required for
it’s original function. The line is normally considered an asset to
be used for some other function at a future unspecified date.
• Abandonment refers to the planned shutdown of pipeline
operations usually because the pipeline is no longer required or
no longer able to function. The line is normally no longer
considered an asset and no future application is foreseeable.
Regulations The British Columbia Pipeline Regulation specified requirements for
deactivation, reactivation and abandonment of pipelines under sections 12
and 21 and CSA Z662 Clauses 10.13 and 10.14 respectively.
Method The method of de-commissioning varies with previous conditions to which
the facility, system or piece of equipment has been exposed. Contributing
factors are:
• New system - hydro-tested with H2O,
• Operating system - type of service (sweet, sour. liquid, gas),
• Duration of suspension.
Purpose The purpose of a de-commissioning program is to achieve one or more of
the following:
• Preserve suspended or discontinued lines for future use by,
• Minimizing internal and external corrosion damage,
• Removing production fluid,
• Render abandoned lines non hazardous by,
• Removing production fluid,
• Physically incapacitate the pipeline.
Responsibilities The Area Foreman for the Region is responsible for developing required
de-commissioning plan and providing submissions to the Regulator.
Personnel performing the de-commissioning must ensure that the program
is properly conducted, documented and filed.

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Suspension A pipeline suspension will normally be completed in the following

sequence:
• Isolate and depressure to reduce potential safety or
environmental impact in the event of an unintentional release,
• Purge or displace to remove production fluids to prevent
hydrates, freezing, wax plugging, or corrosion depending on the
nature of the fluids,
• If the suspension is expected to be greater than 10 days for sour
lines or 30 days for sweet lines, batch inhibit as per Appendix
A.3,
• Lock-out and tag all connecting valves,
• Notify the B.C. Assessment Authority in Dawson Creek,
• Document and file in the pipeline file.
Deactivation A pipeline deactivation will normally be completed subsequent to all the
steps required for a suspension and the following:
• Purge the line to an inert and non-corrosive fluid;
ƒ Treated water with O2 scavenger and inhibitor, or
ƒ Air with a filming inhibitor, or
ƒ Inert gas (N2).
• Maintain cathodic protection systems,
• Blind or disconnect the segment from any active production
equipment,
• Notify the B.C. Assessment Authority in Dawson Creek,
• File completed work order in the pipeline file.
Abandon A pipeline abandonment will normally be completed subsequent to a
deactivation and the following:
• Physically disconnect the line from all active production
equipment,
• Remove surface connections,
• Plug or cap all open ends,
• Notify the B.C. Assessment Authority in Dawson Creek,
• File completed work order in the pipeline file.
Record Keeping To ensure the status of all pipelines is accurate; a log of suspended and
discontinued pipelines is essential. All pipelines suspended more than 30
days should be tracked using the following table format. The log is reviewed
annually to update pipeline status (deactive or abandon) and records.
Monthly Status Monthly review the operational status of the wells and associated pipelines

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Check to track changes and identify pipelines requiring suspension or deactivation.

Annual Review Annually review each monthly status report, identify pipelines suspended
for more than 6 months consecutively and implement the discontinuation
procedure. Identify pipelines discontinued for more than 12 months and
consider implementing the abandonment procedure.

Log of Inactive Pipelines

Month: Year: Annual Review

AEUB Susp. CP Date Hydro- Hydro- Back in Formal
From To Date Disc.
Lic # Proced. Maint. Back in Test Test Service
Location Location Shut-in
(Line #) Compl. Verified Service Req'd? Done? ? Req'd?

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dd / mm / yyyy
Pipeline Data Shut-in Date: ___/___/_____ EUB License: __________________ - ____
Location (LSD): From - - - W M To - - - W M

Fluid Carried: Sweet NG Sour NG OWE Oil Salt Water

The following three modes of decommissioning are consistent with the regulatory requirements.

Mode 1 – Suspension: A planned or unplanned period of inactivity (< 12 months), after which the
line will be returned to its original service. Ensure the following items are addressed, then date when complete:
Required Completed
Documentation (dd/mm/yyyy)
1 Purge, displace or pig production fluids to prevent hydrates, freezing, wax Daily Report
plugging, or corrosion depending on the nature of the fluids. / /
2 If the suspension is expected to be greater than 10 days for sour lines or Chemical supplier’s
30 days for sweet lines, batch inhibit as per the POMM. Batch Report / /
3 Isolate and reduce pressure (Leave positive pressure ~100 kPa). Daily Report
/ /
4 Lock-out and tag all connecting valves. Daily report / /
5 Document and file in the pipeline operation and maintenance records. Inactive pipeline log / /

Mode 2 – Discontinue: A planned shut down of normal pipeline operations usually because the
pipeline is no longer required for its original function. The line is normally considered an asset to be used for some
other function at a future unspecified date. Ensure the following items are addressed, then date when complete:
Required Completed
Documentation (dd/mm/yyyy)
1 Isolate and reduce pressure. Daily Report
/ /
2 Physically disconnect the line from all energy sources (operating facilities Daily Report
or pipelines). / /
3 Vent the pipeline to atmosphere or separator and flare with consideration Daily Report
given to H2S and EUB G60 requirements. Watch LEL levels and ignition
sources if venting to atmosphere.
Note: Confirm that communication with other pipelines does
not exist by monitoring pressure while venting. / /
4 If the pipeline does not have a pig launcher and receiver, install temporary Daily Report /
ones. Use a good cleaning pig (Consult pig supplier on appropriate style of contractor’s work report
pig.) and pig the pipeline with nitrogen, air(2) or fresh water(2). Capture all
fluids on the receiving end into a temporary tank until the pig is
recovered. Additional pig runs may be required to ensure the pipeline is
clean (1). / /
5 Purge the line with an inert and non-corrosive fluid (check only one): Daily report/
Inert gas (N2) contractor’s work report
Air with a filming inhibitor(2)
Fresh water with O2 scavenger and inhibitor(2)
Leave a positive pressure of approximately 100 kPa on the pipeline to
prevent air from entering. / /
6 Check all risers to ensure that all energy sources are disconnected or Daily report/
blinded. Install ½” or 1” ball valves to serve as test ports. contractor’s work report
Attach tags on all disconnected or blinded risers that provide the following
information:

Pipeline licensee
Licence and line number
Location(s) of other end points
Discontinuation date
Media left inside the pipeline
/ /
7 Maintain cathodic protection on pipeline. Annual CP survey
Reports / /
8 Complete and submit required G55 documents and submit to the EUB EUB Base map
within 90 days of completion (3). Guide 56 Schedule 1 / /

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Guide 56 Schedule 3
Guide 56 Schedule 3.1
9 Compile all required documentation in a pipeline discontinuation report Discontinuation report
and file in the pipeline operation and maintenance records. Inactive pipeline log / /

Mode 3 – Abandon: A planned shutdown of pipeline operations usually because the pipeline is no
longer required or no longer able to function. The line is normally no longer considered an asset and no future
application is foreseeable. Ensure the following items are addressed, then date when complete:
Required Completed
Documentation (dd/mm/yyyy)
1 Isolate and reduce pressure. Daily Report
/ /
2 Physically disconnect the line from all energy sources (operating facilities Daily Report
or pipelines). / /
3 Vent the pipeline to atmosphere or separator and flare with consideration Daily Report
given to H2S and EUB G60 requirements. Watch LEL levels and ignition
sources if venting to atmosphere.
Note: Confirm that communication with other pipelines does not
exist by monitoring pressure while venting. / /
4 If the pipeline does not have a pig launcher and receiver, install temporary Daily Report /
ones. Use a good cleaning pig (Consult pig supplier on appropriate style of contractor’s work report
pig.) and pig the pipeline with nitrogen, air or fresh water. Capture all
fluids on the receiving end into a temporary tank until the pig is recovered.
Additional pig runs may be required to ensure the pipeline is clean (1). / /
5 Purge the line with nitrogen, air or fresh water (check only one): Daily report/
Inert gas (N2) contractor’s work report
Air
Fresh water
/ /
6 Cut all risers off below surface at pipeline level and cap, except when it is Daily report/
located within the boundaries of a facility that will continue to have other contractor’s work report
equipment operating.

Attach tags on all ends that provide the following information:

Pipeline licensee
Licence and line number
Location(s) of other end points
Abandonment date
Media left inside the pipeline
/ /
7 Remove all cathodic protection. CP survey report / /
8 Complete and submit required G55 documents and submit to the EUB EUB Base map
within 90 days of completion (3). Guide 56 Schedule 1
Guide 56 Schedule 3
Guide 56 Schedule 3.1 / /
9 Compile all required documentation in a pipeline abandonment report and Abandonment report
file in the pipeline operation and maintenance records. Inactive pipeline log / /

(1) A detailed cleaning procedure, developed with the assistance of a chemical supplier, may be required to
thoroughly clean the pipeline.

(2) The use compressed air or fresh water for decommissioning a pipeline requires that a batch inhibitor be
applied between two batching pigs as a last step before the final purge. Consult with a chemical supplier for
assistance on designing an appropriate batch treatment.

(3) Assistance in this matter is available through the EHS group, specifically the Pipeline Engineering Integrity
Team (Allan Hobbins 780-539-3007, Northern Materials Engineering, 780-469-1164).

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APPENDIX A.3

Pigging and Batching Procedure

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Premise These guidelines are intended to provide direction on how to prevent corrosion
damage in pipelines that are being brought into service or being temporarily
removed from service. This is not intended to include routine maintenance batch
inhibition treatments that are part of the corrosion mitigation program for the
pipeline.
It has been proven that a coating of a suitable corrosion inhibitor applied to a
pipeline before initial production will dramatically reduce the likelihood of corrosion
caused by detrimental flow conditions and the lack of protective scales, which may
exist during start-up. To this end it is expected that a batch treatment be applied
to a pipeline for the following situations:
• All new pipelines will be batch inhibited as one of the final steps in the
construction process,
• Sour lines that are to be shut-in for longer than 10 days, as part of the
shut-in activities,
• Sour lines that have been shut in for longer than 3 months or that have
not been previously batch treated immediately prior to start-up,
• Sweet lines that are to shut-in for longer than 3 months or that may
contain significant concentrations of methanol (i.e. >10% concentration
in the water), as part of the shut-in activities,
• Sweet lines that have been shut-in for longer than 1 year immediately
prior to start-up.
In circumstances where there are no pigging facilities the alternative is to utilize an
inhibitor with a strong vapour phase component in it. An application procedure will
have to be developed for each situation by Operations, the supplier and EH&S
Safety Engineering.
Inhibitors The following is a list of the currently approved batch inhibitors that are to be
utilized as part of this procedure:
• Champion Technologies Cortron RU-196 mixed 1:1 with clean diesel,
• Baker Petrolite CRO 345 mixed 1:2 with clean diesel,
• Brenntag T-8537 mixed 1:1 with clean diesel.
Selection of the inhibitor from the above list should be based primarily upon
matching suppliers with any current mitigation program in the facility but
consideration may also be given to availability and pricing.

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Batch Size In order to achieve the recommended 3 mil (0.003”) inhibitor film the following
formula is used to calculate the volume of inhibitor required:
2.8L x Line Size (cm) x Line Length (km)

Inhibitor Diesel Diesel

Line Size volume / km volume / km volume / km
(L) (L) (1:1) (L) (1:2)
2” (60.3 mm) 17 17 34
3” (88.9 mm) 25 25 50
4” (114.3 mm) 32 32 64
6” (168.3 mm) 47 47 94
8” (219.9 mm) 61 61 122
10” (273.1 mm) 76 76 152
Batch To initiate a thorough 3mil Protective film on any pipeline, the following steps are
Procedure recommended.
• Combine required litres of inhibitor and diesel in a clean pressure truck
compartment. Mix thoroughly.
• Put one new Super pig into the pig launcher. If the line is suspected to
contain solids or debris, a scraper type pig should be inserted instead.
• Using the pressure truck, push the inhibitor pill mixture into the pig
launcher behind the pig.
• Put a Super pig (filmer) into the sender. This pig should be in good to
new shape.
• Launch the pigs and inhibitor batch down the pipeline. For optimum
filming it is suggested that velocities not exceed 2.2 m/sec. (5 mph).
There is no easy way to design pig speed so trial and error will have to
be applied. Try sending a pig and timing how long it takes to travel a
known distance. Adjust pressures to achieve a maximum speed of 5
mph. Note: the slower the better.
• Monitor the amount of chemical returning, approx 1/3 of the initial batch
would be considered normal. If the pigs come in together, there is a
possibility that the last portion of the line was not adequately treated.
Pigs Although manufactures design specialty pigs, the most common preferred and
recommended pig for batch treatments is a super pig. The following
recommended pig specifications:

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 Pigging and Batching Procedure December 2005

• Lead Pig: Super pig; shore 90 material, containing a cup, 2 disks, and
a cup. Diameter should be 4 to 5% above pipeline I.D.
• Trailing Pig: Super pig; shore 80 material, containing a cup, 2 notched
disks and a filming disk. Diameter should be 2 to 3% above pipeline
I.D.
• Pig Sizing: Even though both pigs are in the system at the same time
and under the same operating conditions; the second pig must actually
travel faster than the first pig in order to displace or squeeze the
inhibitor back over it. The second pig will actually begin to catch the
first pig. If this does not take place the two pigs and chemical simply
travel through the system as a single unit transporting the chemical
instead of leaving it on the circumference of the line.
• Although it will vary with shore hardness, super pigs are supposed to
be 60% collapsible.
• Attention needs to be paid to pig sizing versus line I.D. for both new
and used pigs. A batch inhibitor pig should be replaced if it is worn to
less than 1% oversize of the pipe internal diameter.
• Pig diameter can be measured with:
a. Callipers or ruler across centreline.
b. Tape measure
c. Pushing the pig through a permanently mounted pipe sample
located near the pig sender
Supplier Pipe-tech Corporation Ltd of Calgary is the preferred supplier of specialty pigs.
Pipe-tech sells a complete line of batching pigs; you must supply pipeline OD
and ID as well as pig sender style when ordering pigs. Ask for filming pigs,
one lead and one filmer per set (see picture below). Pipe-tech can be reached
at 1-887-287-3558.

Lead pig followed by the filming pig Lead Filmer

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APPENDIX B.1

Pipeline Inventory Summary

B.1.1 Active Pipeline Summary

B.1.2 Inactive Pipeline Status Log
B.2.3 Ring Border – NEB Pipeline Summary
(Ring Border - NEB Pipeline Summary.xls)

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Operations to create inventory of pipeline segments. See attached pipeline matrix.xls.

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 Inactive Pipeline Status Log
Appendix B.1.2

Revision: 2.0 December 2005

Company: Burlington Resources Canada Ltd. Area: Page 1 of 1

Date AEUB New Cathodic Follow-up
Item Confirmed by
of License # FROM TO Operating Actions Taken Protection Actions Refer
# (BRC rep.)
Action Line # Status Status to Item #

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APPENDIX B.2

Pipeline Flow Schematic

(Refer to ERP for pipeline map)

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APPENDIX B.3

Protective Device Summary

B.3.1 Isolation Valve Summary

B.3.2 Pressure Protection Device Summary

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 Isolation Valve Summary
Appendix B.3.1

Revision: 2.0 December 2005

Description of Systems Isolated

Location Valve Type
(whole or partial isolation)

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 Pressure Protection Device
Summary
Appendix B.3.2
Revision: 2.0 December 2005

Location PPD Type Set Pressure Comments

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APPENDIX B.4

Integrity Management Plan

B.4.1 Pipeline Integrity Management Plan

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APPENDIX B.5

Pipeline
Operations & Maintenance
Task List

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 Operating & Maintenance Task List
Appendix B.9

Revision: 2.0 December 2005

TIMING /
REF. ROUTINE ACTIVITY RESPONSIBILITY REPORT TO: COMMENTS
FREQUENCY
Do by exception only as part of travel
3.6 Leak Surveillance Operations Routine Incident Report
routine to wells.
Complete during routine well-site visits
3.13 ROW Surveillance Operations Annual BRCL and by appropriate air or ground vehicle
for sections not visible from road/lease.
App At least
Pipeline Pigging Operations Log Entry
G.4 Monthly
Cathodic Protection Adjustive Operations /
3.15 Probe Annual Include all pipeline risers, test stations.
Survey EH&S
Cathodic Protection Rectifier
3.14 Operations Monthly Probe
Readings
3.2 / Ensure Shut-in Pipelines are
Suspended as per 1st Quarter
App Operations Log
Procedures 2003
A.2
Semi-annual No valves in list. All manual valves due
3.11 Isolation Valve Maintenance Operations Log Entry
(<6 months) annually.

Pressure Protection Device Annual

3.12 Operations Log Entry Add new devices to list
Maintenance (<18 months)
Ensure signs are legible and in place at
3.8 Signage Operations Ongoing Nil all crossings/facilities. Replace as
required.
Each
3.7 Incident Reporting Operations EH&S / OGC
occurrence
3.9 Ground Disturbance Facilities / Each

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 Operating & Maintenance Task List
Appendix B.9

Revision: 2.0 December 2005

TIMING /
REF. ROUTINE ACTIVITY RESPONSIBILITY REPORT TO: COMMENTS
FREQUENCY
Operations occurrence
Facilities / Each
3.10 Pipeline Repairs occurrence EH&S / OGC
Operations
Annual (or as
Operations
2.2 License Data Updates changes EH&S
Engineering
occur)
BRCL
2.2 Pipeline Status Review Operations Annual
(Pipeline Manual)
App Assess production and work- Operations /
Ongoing EH&S
G.4 over changes Engineering
Compliance Report of Task
Operations Monthly
Activities
Review Pipeline Operating
Operations / EH&S Annual
Manual and update

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