PIPELINE INTEGRITY AND OPERATIONS MANUAL · The Pipeline Integrity and Operations Manual is...

Document Number: 19359

Do not copy – CONTROLLED DOCUMENT – Effective Date: June 10, 2020

YANGARRA RESOURCES LTD.

PIPELINE INTEGRITY AND OPERATIONS MANUAL

FOR

FERRIER

KELSEY LEWIS USB COPY

DISCLAIMER

This Pipeline Integrity and Operations Manual is designed to provide information, guidelines, schedules and

duties to assist operations personnel. The document provides procedures related to the operation,

inspection maintenance and repair of pipelines and the surrounding area. It is intended to be an important

component of the Integrity Management Program.

Verification of the information contained in this document is the sole responsibility of the client. DataSafe

does not accept any liability arising from the implementation or use of this manual.

This manual is copyrighted by:

DataSafe Recovery Services Ltd.

650, 703 – 6th

Avenue S.W.,

Calgary, Alberta T2P 0T9

Phone: (403) 269-9128

FAX: (403) 269-9140

Unauthorized reproduction is strictly prohibited.

Version 02.05

PIPELINE INTEGRITY MANAGEMENT PROGRAM

Table of Contents Pipeline Operations Manual

Table of Contents Page - 1

PIPELINE INTEGRITY MANAGEMENT POLICY

1. INTRODUCTION

1.1 Purpose and Scope

1.2 Document Control

2. GUIDING PRINCIPLES

2.1 Legislation

2.2 Standards

2.3 Recommended Practices

3. RECORDS

3.1 Record Keeping Requirements

4. OPERATIONS

4.1 General Operator Responsibilities

4.2 Safety

4.3 Fire Fighting Equipment

4.4 Warning Signs and Markers

4.5 Operating Pressures

4.6 Engineering Assessment

4.7 Leak and Break Detection

4.8 Spill Response

4.9 Pipeline Start-up

4.10 Change of Substance or Pressure

4.11 Line Suspension / Abandonment

4.12 Pigging Procedures

4.13 Preparation for Line Maintenance

4.14 Corrosion Management

4.15 Site Security

4.16 Hot Work


Table of Contents Pipeline Operations Manual

Table of Contents Page - 2

5. MAINTENANCE AND REPAIR

5.1 General

5.2 Pipeline Patrol and Surveillance

5.3 Ground Disturbance

5.4 Pipeline Repair

5.5 Pressure Testing

5.6 Inspection of Cathodic Protection System

5.7 Inspection of Pressure Control, Limiting and Relieving Devices

5.8 Valve Maintenance Program

5.9 Meter and Instrumentation Maintenance

5.10 Site Vegetation Control

5.11 Exposed Pipe Examination

5.12 In Line Inspection

6. FORMS

7. ORGANIZATION

8. VALVES AND CROSSINGS (behind Field Location tabs in Master documents)

9. EMERGENCY RESPONSE

8.1 General

Emergency Contact List (behind Field Location tabs in Master documents)

10. PIPELINE RISK ASSESSMENT

11. SYSTEM OVERVIEW (behind Field Location tabs in Master documents)

12. SYSTEM PIPELINE LIST (behind Field Location tabs in Master documents)

13. AREA OPERATORS (behind Field Location tabs in Master documents)

14. PIGGING SCHEDULE (behind Field Location tabs in Master documents)

15. REPAIR LOG (behind Field Location tabs in Master documents)

16. CORROSION CONTROL (behind Field Location tabs in Master documents)

17. CHEMICAL INHIBITOR PROGRAM (behind Field Location tabs in Master documents)

18. MAPS

PIPELINE INTEGRITY MANAGEMENT POLICY

The purpose of our Pipeline Integrity Management Program is to properly monitor and maintain our pipeline

systems to ensure that condition and dependability is appropriate for the intended service. Our Pipeline

Integrity and Operations Manual provides the documents and strategies to achieve and improve the safety

and reliability of our pipeline systems. We will allocate resources to:

• Identify and analyze actual and potential events that can result in pipeline incidents.

• Provide a comprehensive and integrated means for examining and comparing the risks and risk

mitigation procedures that are available.

• Provide a structured and comprehensive means for choosing and implementing risk reduction

activities.

• Ensure we employ appropriately trained and qualified company and third-party personnel for risk

management and pipeline integrity.

INTRODUCTION


Introduction Pipeline Operations Manual

Introduction Page - 1

1. INTRODUCTION AND CORRELATION

1.1 Purpose and Scope

Once a pipeline system is constructed and successfully tested for operation, it is the responsibility of

company field personnel to ensure that it is operated, tested, maintained and, if necessary, repaired to

meet requirements of provincial legislation, industry standards and codes of practice. This document

outlines the actions that will be taken to meet those requirements and provide the necessary information,

documentation and reporting to ensure the objectives of our Pipeline Integrity Management Program and

continuous improvement are met.

This manual provides a guide for the operation, testing, maintenance and repair of oil, gas and water

pipeline systems. It will assist in recognizing normal or emergency operating procedures. The user of the

document is expected to know when to refer to and/or implement other corporate documents such as the

Emergency Response Plan and Safety Manual.

The intent of the manual is to provide documented procedures for pipeline operations that will ensure safe

and efficient functioning and preserve the integrity of pipeline systems. Pipeline operations personnel are

expected to be familiar with this manual and know and understand their responsibilities.

1.2 Document Control

This Pipeline Integrity and Operations Manual will be reviewed and updated annually as a minimum. In

addition amendments will be made as required in response to changes in any of the following:

• Government regulatory requirements

• Industry standards

• Codes of practice

• Addition or change of maintenance, testing or operating procedures

• Responsibility of personnel identified in the document

• Company organization

• Site specific information

Please refer to the Document Distribution report at the back of this section for the location / owner of all

Emergency Response Plan (ERP) and Pipeline Integrity and Operations Manual (PIOM) documents.


IMP Correlation Pipeline Operations Manual

IMP Correlation Page - 2

1.3. Document Correlation to the Integrity Management Program

The Pipeline Integrity and Operations Manual is primarily an action and procedures based document to be

used by field operations personnel. The Pipeline Integrity Management Program (IMP) is a corporate initiative

that involves departments, procedures, documentation, responsibilities and personnel in many areas of the

company. This section has been included in the PIOM in order to assist the reader to better understand the

relevance of pipeline operation actions and procedures within the larger scope of the integrity management

program.

IMP correlation will provide the reader with an overview of each section of the manual. Specifically this

section details:

• Who has responsibilities related to each document section when applicable

• What interfaces within the company may be required

• What outputs are expected from operations activities

• Where the outputs are kept and for how long (record keeping)

• The purpose of the outputs as they relate to the company’s IMP

Guiding Principles – Section 2

Pipeline operations and integrity management are company activities that we perform in accordance with

legislated regulations, industry standards and best practices. By using these resources and adhering to these

requirements we can demonstrate compliance and achieve our IMP objectives using the most effective and

efficient methods. Section 2 – Guiding Principles lists the legislation, standards and practices that we follow to

manage our pipeline operations.

Records and Documents – Section 3

The records and documents section of the Pipeline Integrity and Operations Manual details the minimum set

of records and documents that must be retained to meet CSA standards and government regulations. The

section also provides the retention period for each type of record associated with the pipeline system.

For every pipeline segment record keeping begins with design information, engineering and materials

specifications, construction and government approvals and “as-built” attributes. Throughout the lifetime of

the pipeline records are continually created as a result of production, operations, maintenance, surveillance,

failure and repair activities. Personnel responsible for records and document creation and management are

the production and operations staff and management team and could require internal clerical and technical

personnel.

Records can be kept in digital or paper form and may be duplicated for multiple purposes. Head office should

be considered as the main repository for records and documents but this is not necessarily the most expedient

or efficient location and therefore exceptions are expected. The more important aspect of our pipeline

records is that they must be readily accessible, as needed, for internal purposes or as required by the

regulator.




Operations – Section 4

The Operations section of the Pipeline Integrity and Operations Manual contains sixteen distinct sections.

Each section provides guidelines related to the subject, the regulations, if any, that govern the operation,

whether specific outputs or results are expected, best practice or standards that should be followed and any

additional reference material that may require review prior to or during the activity.

The Operations Section contains the following subjects:

• 4.1 – General Operator Responsibilities

• 4.2 – Safety

• 4.3 – Fire Fighting Equipment

• 4.4 – Warning Signs and Markers

• 4.5 – Operating Pressure

• 4.6 – Engineering Assessment

• 4.7 – Leak and Break Detection

• 4 8 – Spill Response

• 4.9 – Pipeline Start-up

• 4.10 – Change of Substance or Pressure

• 4.11 – Line Suspension / Abandonment

• 4.12 – Pigging Procedures

• 4.13 – Preparation for Line Maintenance

• 4.14 – Corrosion Management

• 4.15 – Site Security

• 4.16 – Hot Work

If records are generated as a result of any of the activities listed above there will be a notation, including

retention requirement, in the section. If notifications to government agencies, the regulator, residents, land

owners or other stakeholders is required it will also be noted in the section.

Personnel with responsibilities for Operations are production and operations staff and management teams,

external services and contractors, engineers and possibly clerical staff for records management.

Maintenance and Repair – Section 5

The maintenance and repair section of the PIOM is broken into twelve parts that cover inspections, testing,

maintenance and repair methods. The IMP depends on these activities being performed following regulations,

and in accordance with standards and best practices. The goal by following these guidelines is to reduce

emergency situations, minimize hazardous conditions and help familiarize operations and maintenance

personnel with locations and installation of pipeline assets and equipment.

The Maintenance and Repair section covers the following subjects:

• 5.1 – General Information

• 5.2 – Pipeline Patrol and Surveillance

• 5.3 – Ground Disturbance

• 5.4 – Pipeline Repair

• 5.5 – Pressure Testing




• 5.6 – Inspection of Cathodic Protection System

• 5.7 – Inspection of Pressure Control, Limiting and Relieving Devices

• 5.8 – Valve Maintenance Program

• 5.9 – Meter and Instrument Maintenance

• 5.10 – Site Vegetation Control

• 5.11 – Exposed Pipe Examination

• 5.12 – In Line Inspection

Records will be created as a result of the activities found in the Maintenance and Repair section. If retention

periods are not noted that information can be found in the records section of the document. There are

several instances where notification to the regulator, land owner, pipeline co-owners, other industrial

operators and internal personnel is required. Follow all notification requirements as documented in the

section.

Maintenance and Repair activities will require involvement of production and operations and staff and

management. In many cases contracted services personnel and engineers will also be needed. There could

also be a need for internal resources from the land department to determine land owner contacts and clerical

personnel for records management.

Forms – Section 6

A set of forms is provided in the document. Please note that this may not be inclusive of all forms that are

required to be completed by operations personnel in the performance of their work. The Forms Table of

Contents page identifies forms that, when used, may require Emergency Response Plan (ERP) activation,

notification or reporting.

All forms that are completed must be reviewed by operations management and retained as detailed in the

records section or as required by the ERP.

Organization – Section 7

The organization section has specific purposes but can also be used by the company to keep any records that

are deemed relevant. An example would be ERP or PIOM training event logs. An organization chart that

defines specific responsibilities for Integrity Management Program expectations must be included in this

section.

Site Specific Information – Information Tabs

The sections that are found in the remainder of the document contain information specific to the location(s)

that this manual pertains to. The tabs in this section are a different colour than those found earlier and are

labelled descriptively relative to the contents of the section. The following is a typical list of the Site Specific

Information sections and a brief description of what each section contains. The information in these sections

tends to be more volatile and change followed by update is expected on a regular basis.




Valves and Crossings

This section should contain reports relative to the valves and crossings specific to each Unique

Pipeline Identifier (UPI). Valves must be listed by type, ESD or Check Valve for instance, and the

location by Legal Survey Description (LSD). Crossings are also listed by UPI and relevant crossings

are utility, roadway, railway and water.

This list should be cross-referenced by operations personnel when performing tasks such as

surveillance and maintenance to ensure that these activities are completed for all assets.

Emergency Response

A brief description and general information of the company ERP is at the beginning of this section.

If this section is referenced during day to day operations, as a result of conditions or hazards that

exist, then it is likely that the ERP should be invoked. To assist personnel to respond effectively and

as quickly as possible the Contact Information section from the company ERP is included here.

Pipeline Assessment

A major component of the company’s IMP is the process of pipeline assessment to determine

current, potential or future risk of failure. Pipeline assessments are performed routinely on a

rotating schedule as well as intermittently when changing conditions become evident.

In this section you will find a flowchart that details our risk assessment process by defining the

actions, decisions and criteria used in assessing risk. This is followed by guideline information for

hazard assessment which provides an overview of some of the factors that must be considered in

the assessment. There is a Risk Assessment Matrix to use when classifying risk severity once the

consequence and frequency factors of a specific situation are determined.

The latest pipeline assessment records are kept in this section. These records provide the current

status and are also used for review when the next assessment is performed. If risk increases then

more immediate mitigation activities are required.

If other types of assessments are performed or alternate methods are used for the assessment a

description of the process, tools and results should be added to the document in the Pipeline

Assessment section.

System Overview

This section is used to store the Site Overview reports for the location(s) covered by the PIOM

document. These reports are used to document detailed descriptions of the property under the

following headings:




- General Summary

- Property Description

- Detection

- Land Use

- Evacuation Summary

- Resident Summary

- Directions From Nearest Urban Centre

- Site Mutual Aid

See the System Overview section to familiarize yourself with the type of information that can be

documented in these reports.

System Pipeline List

An informational table style report listing all of the pipelines in the system with associated pipeline

attributes is contained behind this tab. If the system contains sour gas then the pipeline list is

grouped and includes information such as H2S content and the calculated Emergency Planning Zone

(EPZ).

Area Operators

The lists contained in this section are done by location and provide the main contact phone

numbers for other oil and gas operators within proximity of our operations. Like the emergency

contact list these numbers provide the document user with ready information to use if there is a

need to inform other companies of any situation that is occurring that could impact their operations

or personnel.

Pigging Schedule

There is a pigging frequency attribute that can be added to the Pipeline Assessment report.

However, pigging operations could be significant at certain locations or could require more detail.

In these circumstances any additional documentation can be added to this section of the PIOM. If

this information is kept in another location then a one page summary detailing the location of the

records will be added behind the Pigging Schedule tab.

Repair Log

When any repair is performed a documented record of the repair must be created by Operations or

Maintenance staff and added to this section of the manual. This information is reviewed and

analysed when pipeline assessments are performed. Increased numbers of repair records for

individual segments are an indication that more significant problems could exist. When this occurs

further investigation is required. If analysis indicates a higher risk exists then increased surveillance

and the priority of plans for mitigation activities must be escalated. Operations and Maintenance

management will be involved in these processes. A situation could also warrant the involvement of

engineering personnel.




Corrosion Control

Some corrosion control information such as whether there is cathodic protection on the pipeline

segment or whether the pipe is lined can be included in the Pipeline Assessment report. More

detailed information, if required, can be added to the Corrosion Control section. In a case where

there is significant additional information that is stored in another location a one page summary

detailing the location of the records will be added behind the Corrosion Control tab.

Chemical Inhibitor Program

This section includes specific information related to the Chemical Inhibitor Program and like the

Pigging Schedule and Corrosion Control section it could contain only a summary of the location of

pertinent records.

Maps

This section will contain all representations of the pipeline system(s), such as schematic diagrams,

and geographic maps showing the pipeline system including wells and facilities. These documents

are used for emergency response, surveillance and training purposes by operations and

maintenance staff. When changes occur to the pipeline system these maps and diagrams must be

updated to reflect those changes.

ERP DISTRIBUTION LIST

AB ICS CORPORATE MASTER (Non-Confidential)

FERRIER

Doc # AddressDescriptionLocation / Recipient Phone

DataSafe Recovery Services Ltd. DataSafe, Calgary 650, 703 - 6th Avenue SW, Calgary AB T2P 0T9 5148 (403) 269-9128

Doneff, Collin YANGARRA RESOURCES

LTD., Head Office

1530, 715 - 5th Avenue S.W., Calgary AB T2P 2X6 16695 (403) 262-9558

Evaskevich, Jim YANGARRA RESOURCES

LTD., Head Office



LTD., Head Office


Lewis, Kelsey USB Copy - YANGARRA

RESOURCES LTD., Head

Office


Operator, Area 02-04 PLANT - YANGARRA


Office




Office




Office




Office




Office




Office


Operator, Area ADAM LATOS -

YANGARRA RESOURCES

LTD., Head Office


Operator, Area FIELD OFFICE -

YANGARRA RESOURCES

LTD., Head Office


Operator, Area RIG 1 - YANGARRA


Office


Operator, Area RIG 2 - YANGARRA


Office


Simpson, Lorne YANGARRA RESOURCES

LTD., Head Office


Pipeline Integrity and Operations Manual (Site) (Non-Confidential)

FERRIER

Doc # AddressDescriptionLocation / Recipient Phone

Doneff, Collin YANGARRA RESOURCES

LTD., Head Office



LTD., Head Office


Lewis, Kelsey USB COPY - YANGARRA


Office


Page 1YANGARRA RESOURCES LTD.

ERP DISTRIBUTION LIST

Operator, Area FIELD OFFICE -

YANGARRA RESOURCES

LTD., Head Office


Page 2YANGARRA RESOURCES LTD.

GUIDING PRINCIPLES

GUIDING PRINCIPLES

Legislation / Standards / Best Practice Pipeline Operations Manual

Legislation / Standards / Best Practice Page - 1

2. GUIDING PRINCIPLES

Pipeline operations are regulated by the following legislation, industry standards and recommended

practices.

2.1 Legislation

• Alberta Oil and Gas Conservation Act

- Details requirements for oil and gas facilities

• Alberta Pipeline Act and Regulations

- Details requirements for the operation of pipeline systems

• British Columbia Oil and Gas Activities Act

- Details requirements for the operation of pipeline systems

• British Columbia Pipeline and Liquefied Natural Gas Facility Regulation

- Regulation component of the Oil and Gas Activities Act

• B.C. Oil and Gas Commission Emergency Response Plan Requirements

- Emergency preparedness and response requirements

• Alberta Environmental Protection and Enhancement Act (AEPEA)

- Details environmental requirements for operation of facilities, including chemical and

petroleum product spill reporting requirements

• Transport Canada – 621.19

- Requirements for marking and lighting aerial pipeline crossings

• Occupational Health and Safety Regulations

- Details workplace health and safety regulations

• Alberta Energy Regulator – Manuals, Requirements and Directives

- Ground Disturbance Requirements

- Safe Excavation Near Pipelines

- AER Directive 38 Noise Control

- AER Directive 55 Storage Requirements for the Upstream Petroleum Industry

- AER Directive 56 Energy Development Applications and Schedules

- AER Directive 58 Oilfield Waste Management Requirements for the Upstream

Petroleum Industry

- AER Directive 60 Upstream Petroleum Industry Flaring Guide

- AER Manual 001 Facility and Well Site Inspections

- AER Manual 005 Pipeline Inspections

- AER Directive 71 Emergency Preparedness and Response Requirements for the

Upstream Petroleum Industry

GUIDING PRINCIPLES

Legislation / Standards / Best Practice Pipeline Operations Manual

Legislation / Standards / Best Practice Page - 2

2.2 Standards

• CSA Z245.1 Steel Line Pipe Material Standards

• CSA Z245.11 Steel Fittings Material Standards

• CSA Z245.12 Steel Flanges Material Standards

• CSA Z245.15 Steel Valves Material Standards

• CSA Z245.20 External Fusion Bond Epoxy Coating for Steel Pipe

• CSA Z245.21 External Polyethylene Coating for Steel Pipe

• CSA Z662-15 Oil and Gas Pipeline Systems

2.3 Best Practices

• Canadian Petroleum Safety Council

- Industry Recommended Practices (IRP)

• Canadian Association of Petroleum Producers

- Recommended Practice for Liquid Petroleum Pipeline Leak Prevention and Detection in

Alberta

- Safety Guidelines for Ground Disturbance in the Vicinity of Underground Facilities

• Canadian Gas Association Recommended Practice OCC-1 (CGA OCC-1)

- Discusses the design, installation, operation and maintenance of corrosion control systems

RECORDS

RECORDS

Record and Document Requirements Pipeline Operations Manual

Record and Document Requirements Page - 1

3 Records and Documents

Various records and documentation related to our maintenance and operations activity are administered in

compliance with provincial regulations and CSA Z662 requirements. All personnel have responsibility to

ensure maintenance and operations reports, records and documentation are managed in a manner that

ensures compliance with government conventions.

In addition to meeting legislative requirements the company’s pipeline records initially establish a base line

of the reliability of our pipelines. Subsequent review mechanisms, assessments and performance indicators

will initiate a continuous improvement cycle that is essential to establish an effective Integrity Management

Program. Good records management is essential to change and integrity management processes.

3.1 Record Keeping Requirements

The list of required records includes, but is not limited to:

For the Life of the Pipeline

• Emergency Response Plan (updated at least once a year)

• Company approved drawings, documentation and procedures considered design information

such as:

- Stress calculations

- Soil support calculations

- Anchoring or expansion requirements and calculations

- Riser design

- Plot plans

- Bore details

- Crossing details

- Piping transitions

- Material specifications

- Welding procedures

- Backfill procedures

• Failure/repair records:

- Date and time of discovery

- Cause of leak

- Location

- Methods used to detect leak and concentrations observed

- Operating conditions at the time of discovery

- Response and actions, including persons and agencies notified

- Repair method

- Safety and environmental consequences

• All original and follow up pressure test data results:

- Time and date of test

- Test duration

- Pipe standards and specifications for the section tested

- Qualification pressure and its location and elevation

- Elevation profile

- Location of the test section and testing points

- Pressure test medium used

RECORDS



- Pressure and temperature recording charts and logs

- Pressure-volume charts

- Location and cause of any leak, rupture, or other failure and description of any repair action

taken

• Details of the design, installation and operation of corrosion control systems

• Crossing agreements and class locations

• License and technical specifications of pipelines (PL-100 for example)

• The standards/specifications of all pipe, components, bolting and coating materials used in

construction of the pipeline system

• Technical data concerning the following:

- Locations and lengths for each pipe diameter installed, noting wall thicknesses, grades and

standards or specifications, field test pressure, and where practical, burial depth

- Stations and other facilities – maximum operating limits, and the specifications and

nameplate data of major equipment

- Locations of valves designated as emergency valves, with complete information as to the

dates of inspection and maintenance, and the current intended operating position, whether

open or closed

- Component locations, types and pressure ratings

- Locations and details of any crossings of water, roads, railways, pipelines and other major

utilities

- Locations and details of appurtenances such as corrosion-control devices and weighted

sections

- Location and details of special design and construction methods

- Location and details of failures and repairs

• Details of the welding/joining procedure specification qualification test and the qualified

welding/joining procedure specification are kept at the nearest operating location

• Records of welder/joiner tests and a list of qualified welders/joiners including the procedure

specifications of welds/joins each is qualified to perform

• Records that detail the inspection and testing done, the conditions found and any corrective

action taken, if applicable, for the following:

- Underground tanks

- Pipe-type and bottle-type gas holders

- Pressure control, pressure limiting and pressure relieving systems or devices

- Pipelines that may be subject to changes in class location

- Control and safety devices and equipment

• Locations of equipment and major facilities, such as compressor or pump stations, measuring

stations, terminals, tank farms, block valves and cathodic protection rectifiers

• Design, performance, maintenance, inspection and repair records related to the cathodic

protection system

• Records of the interpretation of radiographs

• Ultrasonic evaluation records

• Measurements of unstable areas where differential settlement or heaving is occurring to enable

analysis of trends toward critical stress

• Internal and External corrosion control program records

RECORDS



Minimum of Five Years

• Audit records of incidents when detectable leaks were not detected by the leak detection

system or were not acted upon by the personnel responsible or when the leak detection system

was not operational for periods in excess on one hour due to equipment failure

• Meter and instrument maintenance and testing records

Minimum of Two Years

• Results of emergency exercises

• Records of observations, including visual inspection and patrols during the right of way

inspection and leakage surveys

• A written inspection report of the pipeline at the crossing locations

• In Line Inspection reports, Radiographs, ultrasonic inspection records, calibration records and

logbooks

• Records of inspection, testing, and assessments of pressure control, relieving and limiting

devices and systems

• Written inspection reports of facilities prior to backfilling

• As a minimum the following information must be included in the Inspection and Monitoring

records:

- Date(s) the activities were performed

- Methods and equipment used

- Results and observations

- Evaluation of the acceptability of the results and observations

- Recommendations

- Implementation of recommendations

Other Retention

• Daily, weekly, and monthly material balance results are kept for a minimum of six months

• Record of data recorded by the operator and by the supervisory control including actions taken

on field investigation alarms for a period of three months

OPERATIONS

OPERATIONS

Procedures and Guidelines Pipeline Operations Manual

Procedures and Guidelines Page - 1

4. OPERATIONS

4.1 General Operator Responsibilities

It is the responsibility of the employees or contract personnel that are involved in the operation of pipeline

facilities to:

• Operate, test and maintain the pipelines in accordance with this manual.

• Provide and maintain complete records as required by this manual; and

• Provide input when changes to this manual are required based on experience, system changes

or changes in technology, or other conditions. This ensures the integrity of our pipelines

systems and their continued safe and efficient operation.

Operation routines and system integrity management can be impacted by change. It is essential that a

change management process be used for all changes to ensure an opportunity for key operating,

maintenance, technical and management groups to assess the impact of change and address any measures

that need to be implemented or documented. Change management is an aspect of continuous

improvement of our operations and pipeline integrity.

4.2 Safety

We place a high value on protecting and maintaining the health and safety of employees and contractors

operating and maintaining our pipeline systems. The company requires that operations and maintenance

activities fully comply with all applicable occupational health and safety regulations and company safety and

loss management standards and practices to ensure a healthy and safe working environment.

Employees and contractors involved in the operation and maintenance of the pipeline system are required

to:

• Be fully trained and competent to do the work assigned to them

• To know and understand the hazards associated with operating, testing and maintaining the

pipeline

• To assess potential job related hazards before beginning a task and taking immediate steps to

control or eliminate all identified potential hazards

• To identify and report any unsafe conditions, unhealthy situations, or abnormal circumstances

associated with pipeline operations, testing or maintenance immediately to the responsible

supervisor

• To follow established operating, testing and maintenance practices and procedures as outlined

in this manual, and the Corporate Health and Safety Manual

• To follow all personal protective clothing and equipment requirements specified by regulations

and company health and safety standards

• Attend environmental and health and safety meetings held in the operating area and training

courses and programs as required by the company or the responsible supervisor

• Participate in emergency response training and exercises

OPERATIONS



4.3 Firefighting Equipment

Firefighting equipment that is maintained at gas plants, batteries, satellites, gas compression and water

injection facilities or company vehicles is:

• Clearly identified

• Maintained in proper operating condition

• Checked at regular intervals with all checks performed being documented on an appropriate

form

• Regularly certified

This equipment is readily accessible and when used shall be positioned upwind of the fire if possible and

practical.

4.4 Warning Signs and Markers

Signs are posted in appropriate areas at the company’s facilities and along pipeline right of way (ROW) to

identify the presence of pipelines and facilities and provide important information. Warning signs will

conform to the design standards and requirements identified in the Pipeline Act and Regulations.

Facility Signs

Signs shall be posted at or near facilities to identify the operating company, the identity and location of the

facility, emergency notification information and other pertinent information to meet provincial

requirements. Signs indicating that smoking is not permitted shall be posted in hazardous areas at facilities,

as appropriate. Warning, caution and danger signs shall be posted at locations where hazards or toxic

substances may be present.

Pipeline Signs

We will post signs in appropriate locations to meet Pipeline Act and CSA Z662 requirements. Locations

include but are not limited to:

• Railway and road right of way

• Utility corridors

• Water crossings

• Fence lines

• In areas of:

- Subdivision development

- Construction activity

- Drainage systems

- Irrigation systems

- Any area of anticipated third party development

Service type, population density, land use, nature of terrain, fencing, potential for public access and need

for public awareness will be considered when locating and spacing signage for pipelines. Signs will be

installed where the pipeline enters and exits road and rail right of ways and, if practical, be visible from the

travelled road or track.

OPERATIONS



Note: signage size, colour and information may vary depending on your location. Ensure that signage

meets local and provincial requirements.

The following example meets AER requirements for signs marking pipelines:

Information is printed on a background of sharply contrasting colour. “WARNING” is 25mm high, bold

lettering. Type of service “GAS PIPELINE” is 13mm high, bold lettering. The sign must include the name of

the operating company and emergency telephone number with area code. Consideration must also be

given to including the required information in a language appropriate to the region.

Material: Aluminum

Material Thickness: 2.057 mm

Dimensions: 17.71" x 11.81" (45.0 cm x 30.0 cm)

Alternative methods of identification must be considered in areas where the use of a sign is impractical or

would not serve the intended purpose.

If the crossing is a navigable waterway for commercial marine traffic, signs will include a “No Anchorage” or

“No Dredging” warning and the size of the sign will be determined by considering the width of the crossing

and the limitations of visibility.

Transport Canada 621.19 specifies the requirements for marking and lighting of aerial pipeline crossings

that could pose a hazard to air or water navigation.

When similarities in piping create the potential for improper operation, the piping will be identified by the

use of signs, stencil markings or colour coding.

Construction Signs

Warning signs will be placed at all company or contractor construction sites that are appropriate for the

nature of activity.

We will provide visual marking of the location of pipelines when requested by, or after becoming aware of,

a third party with construction activity in the vicinity of our pipelines.

Sign Maintenance

Facility and pipeline signage shall be inspected periodically. Any missing, damaged or illegible signs will be

promptly replaced.

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4.5 Operating Pressures

• The operating pressure of a pipeline shall not exceed the licensed maximum operating pressure

during the steady-state operation of the pipeline

• Pressure limiting devices will be installed to ensure that in abnormal conditions, including

transient pressure surges, the maximum operating pressure is not exceeded by more than 10

percent

Pipelines Connected to Artificial Lift Equipment

When artificial lift equipment is in use and is capable of supplying pressure in excess of the pipeline MOP

one of the following two options is required.

Option 1

• Two independently operating overpressure protection devices must be installed that are

designed to protect the pipeline from excess pressure.

• The overpressure protection devices must not allow the licensed MOP of the pipeline to be

exceeded by more than 10% or 35 kPa, whichever is greater.

• Conduct inspections, assessments and testing of the overpressure protection devices in

accordance with CSA Z662, clause 10.9.5.1

Option 2

• A single overpressure protection device must be installed that is designed to protect the

pipeline from excess pressure.

• The overpressure protection devices must not allow the licensed MOP of the pipeline to be

exceeded by more than 10% or 35 kPa, whichever is greater.

• Monthly inspections, assessments and testing of the single device must be performed by a

competent individual.

• A certified instrument technician must conduct annual inspections, assessments and testing.

The maximum interval between these activities must not exceed 18 months.

4.6 Engineering Assessment

An important component of integrity management is that appropriate personnel are contacted and

involved prior to undertaking new construction or when change is made to the operating condition of a

pipeline. The first step to new construction and significant changes is usually an Engineering Assessment.

Engineering Assessments are an integral component of the change management process. Examples of

changes to pipeline operating conditions that would warrant an Engineering Assessment includes:

• Increase in pipeline MOP

• Increase in pipeline operating temperature

• Reduction in pipeline minimum metal temperature

• Change in pipeline service

• Change in fluid properties (viscosity, density, etc.)

• Change in fluid components (i.e. HVP, H2S content, CO2 content, H2O content, etc.)

• Change in flow direction

• Change or failure of pipeline coating

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• Pipeline cover does not meet CSA Z662 requirements

• Construction of a new permanent lease road crossing

• Exposure of pipeline by water or wind erosion (loss of cover)

• Pipeline leaks (due to corrosion, erosion, unknown cause)

• Population density increase near pipeline ROW (review change in Class Location as per CSA

Z662)

• New construction along the pipeline ROW which may affect pipeline operation

• Any other condition not listed above which may significantly affect pipeline operation

An engineering assessment may also be required as the result of pipeline inspection and monitoring results.

The engineering assessment must take the following into consideration:

• Understanding of the performance capabilities and limitations of the inspection method

• Type of imperfection that might correspond to the reported indications

• Accuracy of reported dimensions and characteristics needed for evaluating imperfections

• Potential for unreported defects being associated with an imperfection indication

• Pipeline design, construction and material properties

• Service history and future service conditions

When any condition exists that can lead to failure of a pipeline system an engineering assessment must be

conducted to determine which portions can be susceptible to failures and whether such portions are

suitable for continued service. Failure condition includes but is not limited to:

• Mechanical damage that can develop into failures under sustained operation

• Mill defects not detected during the manufacturing process

• Corrosion

• Stress corrosion cracking

• Coating damage

• Coating deterioration

• Unstable slopes

• Compressive stress related to repetitive loading

Situations requiring an engineering assessment could also arise as a result of Pipeline Patrol and

Surveillance activities. More information related to these routine inspections can be found in the

Maintenance and Repair section.

Any time that operating personnel identify a required change the immediate supervisor should be notified.

Operations staff will work with their immediate supervisor and the Facility Engineer to determine the

engineering work that will be required. The resulting Engineering Assessment will detail the change that is

to be made. Operations personnel will execute the change. The performance of the pipeline will be closely

monitored after the change to ensure that operation is as expected. Stakeholders will monitor and evaluate

that the change meets the intended purpose.

The following diagram provides a graphic representation of our intent to continuously improve our pipeline

integrity by consistently employing an effective change management process.

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Assess

Design

Implement

Evaluate

Stakeholders

Company

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4.7 Leak and Break Detection

Right of way inspections are carried out at regular intervals as specified in the Pipeline Act and Regulations

and CSA Z662. In addition, unusual conditions such as construction or seismic activity, or any unexplained

loss of pressure or production will require additional investigation.

Special consideration will be given to the inspection and maintenance of pipeline crossings of major utilities,

other pipelines, railways, roads and water crossings.

Any of the following conditions could indicate a pipeline leak or break:

• Pooling of hydrocarbons or water on the right of way

• Unusual temperature changes

• Wilting or dead vegetation around right of way

• Soil slides, earth movement, soil erosion or settlement on or near the right of way

• Out of balance material measurement results

• H2S odours

• Gas indication on detector

• Indication by Gas volume analysis or mathematical modelling analysis

• Indication during bar-hole survey

Surveillance will also include:

• Inspection of above ground piping and pipeline appurtenances

• Pipeline identification markers (missing, damaged, obscured)

Internal audit records must be maintained that detail the action taken and results achieved with respect to

the following categories of incident:

• Detectable pipeline leaks that were not detected by the detection system or that were not

acted upon by personnel responsible for interpreting and responding to the material balance

• Occasions when the leak detection system was inoperative in excess of one hour because of

equipment or system failures

These audit records are to be kept on file for five years.

4.8 Spill Response

Regardless of seepage volume, a pipeline break or damage from contact must be reported to the Alberta

Energy Regulator immediately. Note that damage from contact may not cause a pipeline break and

subsequent leak. However, there is a significant increase in risk to a pipeline that has sustained damage by

contact. Thorough inspection and repair of damage from contact to ensure pipeline integrity is required.

In British Columbia immediate notification of a spill is made to PEP (see Contact Information in the

Emergency Response section). Reportable spill volumes are:

• 100 litres for flammable liquids

• 10 Kilograms of natural gas if there is a breakage in a pipeline or fitting operated above 100 psi

that results in a sudden and uncontrolled release

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See the Schedule contained in the Spill Reporting Regulation for reportable levels of other substances.

The following information must be provided:

- the reporting person's name and telephone number

- the name and telephone number of the person who caused the spill

- the location and time of the spill

- the type and quantity of the substance spilled

- the cause and effect of the spill

- details of action taken or proposed to stop, contain or minimize the effects of the spill

- a description of the spill location and of the area surrounding the spill

- the details of further action contemplated or required

- the names of agencies on the scene

- the names of other persons or agencies advised concerning the spill

References:

The Pipeline Act, Part 6, Section 35 (1) states: When a leak or break occurs in a pipeline, the licensee shall

immediately cause the AER to be informed of the location of the leak or break.

Pipeline Regulations Part 1, Section 2 (2) states: A licensee who is required to notify the AER of a pipeline

leak, break, test failure or contact damage shall immediately do so by telephoning the appropriate regional

field centre of the AER.

B.C. Environmental Management Act – Spill Reporting Regulation

The landowner must be notified and the spill area contained to prevent access by domestic stock or wildlife.

Spill Strategy

Operations personnel that discover a spill will initiate immediate action plans to control the situation and

decrease the impact of the spill. Although there could be exceptions under special circumstances, most

often the following general strategy will be used:

• Protect the public and safety of workers

• Shut in the source of the spill

• Assess the spill area

• Initiate containment, recovery and notification process

• Supervise site clean up

• Prepare internal and external reports

• Define the root cause to prevent similar incidents

• Reclaim the affected area

Containment and Recovery Options

The early deployment of temporary containment or diversion tactics can greatly reduce the cost of cleanup

and reclamation. There are a variety of accepted and proven options that can be used for spill containment.

Strategies specific to your location should be considered and prepared for in advance of a spill situation.

Commonly used spill containment and recovery options are:

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• Dikes and inverted weirs

• Bell holes and trenches

• Water flushing

• Sorbents

• Culvert blocks

• In-situ burning (specific conditions only)

Dikes

Dikes will provide an effective way to prevent fluids from continuing to migrate. Prior to constructing a dike

consideration should be given to the spill location, time of year, resources available to contain the spill and

the amount and material spilled. Dikes will be effective for smaller spills. Keep the height and width of a

dike to a minimum and use low areas and seams to reduce construction and disturbance. Existing roads and

other high spots can be used but must be monitored for erosion to prevent washout and subsequent loss of

contaminants. Straw bales can be used where possible and will reduce the use of heavy equipment. Note

that preparation of the ground area may be required and that the bales may need to be staked or

overlapped for significant flows and to prevent leaching under the dike. Snow and ice dikes can be used to

contain spills in the winter.

Dikes and Inverted Weirs

Dikes and inverted weirs are used when a significant amount of material has been spilled. A dike and

inverted weir can be installed to siphon off water from the bottom of the contained area into another

containment area. Culverts are commonly used in the construction of the inverted weir. An inverted weir

can be used to decrease the chance of liquid migrating to a less desirable location and will also substantially

reduce the amount of liquid that must be removed, treated or disposed of. A spill specialist must be

consulted before an inverted weir is put into practice.

Bell Holes and Trenches

Bell holes and trenches are used to contain and prevent further migration of the spill. They also provide an

effective means of collection by using a vacuum truck or pump suction hose. Use numerous shallow holes

or trenches to minimize the risk of fluid penetration in the soil and to reduce the risk of striking

underground hazards. Natural depressions and seams should be used to collect and direct fluid if possible.

Water Flushing

Flushing a spill area, with hot or cold water, is an effective fluid recovery method. A calcium product must

be added to water that is being used to flush an area where a salt water or produced water spill has

occurred. A spill specialist is required to advise on the calcium amendment that is required in each

situation. Note that toxic and flammable vapours can be produced and personal protective equipment and

procedural safety are essential when performing this operation.

Sorbents

Sorbents are used to recover residual oil or contaminants that mechanical equipment is unable to recover.

If sorbents are used ensure they will recover the product effectively, are readily available, easy to apply and

do not create a disposal problem. Consider the use of natural materials such as straw. Note that the cost

OPERATIONS



for disposal of used sorbents is usually high; as a result they will not normally be used for cleanup of

significant amounts of fluid.

Culvert Blocks

Culvert blocks should be kept on site if it is foreseeable that a spill could readily migrate through a culvert.

Consider installing culvert gates in sensitive areas or in locations where the impact of a spill is considered

high. As a minimum precaution, store plywood or other culvert blocking material on site. When a culvert is

blocked liquid levels must be monitored to ensure a washout does not occur.

In-Situ Burning

Burning of a spill contaminant may be an option when:

• Regulatory approval has been granted and appropriate contacts are made

• It is unsafe to contain and recover the product with men and equipment

• Burning would prevent imminent contamination of a sensitive area

• Equipment usage would cause a greater overall impact

• Oil is located on ice that is not of an adequate thickness to allow recovery

• Further mechanical clean up is not feasible

• A controlled burn is possible

• Controls are in place to ensure a safe, effective burn and it is contained to the spill site

Regardless of the choice of control options, the following factors must be taken into consideration:

• Public and personnel safety is the number one priority

• Protect environmentally sensitive areas

• Determine spill boundaries

• Consult regulatory agencies, stakeholders and spill specialists

• Secure the site and control access

• Use of heavy equipment is expensive and can increase reclamation requirements. Minimize use

if possible.

• Never bury contaminated soil. Salvage for proper disposal.

• Remove as much free liquid as possible

• Prevent surface water from entering the spill site

• Avoid unnecessary damage to vegetation

• Remove contaminated soil following regulatory requirements

Fluid Disposal Options

The most cost effective way to deal with recovered fluid is to return it to a company facility for

reprocessing. In situations where the material cannot be reprocessed, for instance, insufficient volume or

too much debris, it may be necessary to involve a reclaiming company. This is a costly alternative directly

related to volume. Ensure as much material is reclaimed by other means as possible and attempt to remove

as much water as possible from emulsion spills.

OPERATIONS



4.9 Pipeline Start-up

The main considerations when starting up and operating a pipeline system are personnel safety and

protection of equipment. High pressures are inherently dangerous and command respect and caution.

The following procedures will be used to safely start-up new, repaired or upgraded pipelines:

Clearance

Provincial regulator approval is required before any pipeline is placed in operation.

Consultation and subsequent clearance from the engineering representative, construction supervisor and

appropriate operating personnel must be obtained before proceeding with the commissioning of any

pipeline.

Pre-Commission Requirements

• Inspection performed and engineer clearance that all new manual valves have been inspected

and correctly set

• Ensure check valves are installed in the direction of flow

• Ensure all vents are closed and plugs are installed

• Ensure all drain valves are closed, locked and plugs and blinds installed as applicable

• Pig signals are installed and in correct direction of flow

• Pig trap closures are in place

• Pressure gauges are appropriate for use

• Cathodic insulating gaskets are installed as per drawings

• Inspect studs and nuts on flanges, ensure there is a minimum of two threads exposed beyond

the nuts on all studs

• Submit pipeline routings to the provincial One Call System

Pipeline Filling

Once clearance and pre-commissioning inspections are satisfied proceed with the following:

• Remove isolation equipment

• Inject corrosion inhibitor if it is to be applied

• Open valves slowly – use caution as the flow rate must be controlled on some systems to

ensure the system capacity is not exceeded

• Vent air if necessary

• Inspect system for leaks

• Perform a visual inspection of all fittings, flanges and valves when the pipeline reaches

operating pressure

4.10 Change of Substance or Pressure

In Alberta the substance shipped and/or the maximum operating pressure of a pipeline can only be changed

after obtaining an approval from the AER.

In all locations change of substance or pressure must comply with CSA Standards.

OPERATIONS



4.11 Line Suspension / Abandonment

Line suspension or discontinuation is the temporary removal of a pipeline from the system. Line

abandonment is considered the permanent removal of a pipeline. In either case the pipeline must be

physically isolated from all operating facilities whether or not the pipeline is removed from the ground.

If the product in a pipeline can be proven non-corrosive using best practice test methods and the line will be

discontinued for less than 3 months, then the product may be left in the pipeline. Otherwise the product

must be considered corrosive. In this situation, or, if the pipeline will be shut-in for more than 3 months,

then the pipeline must be pigged out (refer to Section 4.12 of this manual) and left filled with an approved

medium. If the pipeline has been discontinued for more than 12 months an application must be submitted

to change status records to reflect that the line is discontinued. An integrity management plan for a

discontinued pipeline must be developed and maintained.

Note that under Directive 56 an application for abandonment or discontinuation is not submitted until after

the pipeline has been prepared for the change in status. There are regulatory requirements, including

public notification, that need to be met prior to abandoning a pipeline.

Hazards

A hazard assessment will be performed prior to commencing suspension or abandonment procedures to

determine protective measures that will be implemented. Typical hazards include fire, explosion, sour gas

exposure, excessive pressure and spills. All company and contract personnel will be briefed with respect to

the hazards and the protective measures to be implemented. Appropriate safety and personal protective

equipment such as LEL detectors, H2S monitors, SCBA, goggles/face shield, fire retardant work wear, and

firefighting equipment will be used.

General Discontinuation Procedure

1. Shutdown production, depressurize and isolate the line

2. Purge line with fresh water, followed by air, and where suitable use pigging

3. Block and isolate the line with blind flanges

4. Identify all isolation valves and blinds with line status and content

5. Leave cathodic protection in place

6. Leave line in safe condition

General Abandonment Procedure

1. Isolate line from all operating facilities

2. Clean the line appropriately and purge with air

- Salt water lines will be purged with fresh water followed by air

- Oil emulsion lines may require a mixture surfactant with fresh water, as appropriate,

followed by air

- Investigation followed by other appropriate cleaning procedures may be required for

significant deposits of sand or other materials

3. Use poly pigs between purging media

4. Cut risers and cap below ground at the horizontal position of the pipeline

5. All waste materials and deposits will be stored and disposed of to meet Directive 58 compliance

requirements

OPERATIONS



6. Based on the potential for contamination at the site, investigation and testing will be

performed.

7. Reclamation procedures will be implemented

8. Compile abandonment log and secure regulatory release

9. Notify stakeholders of abandonment

Discontinuing Lines with Pig Traps

Determine any requirements for cathodic protection and consult with engineers whether to use an air or

nitrogen purge. If nitrogen is used, set up a purge program with the contractor.

1. Shutdown input facilities and close isolation valves

2. Insert a pig into the pig trap as per pigging procedures

3. Displace fluid in the normal flow direction

The pig signals must be reversed or removed if fluid is to be displaced in the reverse flow.

The truck operator must be informed of the MOP of the pipeline.

4. Launch the pig with the pressure truck loaded with fresh water

5. Displace a minimum of 30 metres length of the pipeline

6. Install a second pig

7. Launch the second pig using the compressed air or nitrogen truck

Monitor the operation closely to ensure system MOP and meter flow rates are not exceeded.

8. Do not let any significant volume of air or nitrogen into the downstream piping

9. Leave the truck connected to the line, even if it shuts down, until both pigs are received

10. Remove the pigs from the trap

11. Vent excess pressure leaving 200 – 500 kPa in the line

12. Close, lock and tag isolation valves

13. Install blinds where the pipeline connects to fluid sources

14. Notify the provincial regulator of the status

Discontinuing Lines without Pig Traps

Determine any requirements for cathodic protection and arrange for a vacuum truck and a pressure truck

with enough fresh, warm water to displace 110% of the line.

The truck operator must be informed of the MOP of the pipeline.

1. Connect the pressure truck to the inlet and the vacuum truck to the outlet

2. Ensure all valves in the path of flow are open

3. Pump the water from the pressure truck to the vacuum truck

OPERATIONS



Monitor the operation closely to ensure system MOP and meter flow rates are not exceeded.

4. Once the line has been filled with water the vacuum truck can remove the water from every

available drain on the line

5. Close all valves and install blinds where the pipeline connects to fluid sources

6. Lock and tag the isolating valves

7. Notify the provincial regulator of the status

4.12 Pigging Procedures

Pigging is the process used to remove solid deposits such as wax and any trapped fluids from a line.

Procedures for pigging will vary from site to site based on age, configuration of the line, pig trap design and

any other system or operational differences.

Hazards

A hazard assessment will be performed prior to commencing pigging procedures to determine protective

measures that will be implemented. Typical hazards include fire, explosion, exposure to toxic gases,

arm/leg injury due to launcher or receiver caps releasing under pressure and spills. All company and

contract personnel will be briefed with respect to the hazards and the protective measures to be

implemented. Appropriate safety and personal protective equipment such as LEL detectors, H2S monitors,

SCBA, goggles/face shield, gloves, fire retardant work wear, and firefighting equipment will be used.

Procedure Guidelines

Piping modifications that are made prior to pigging operations must follow correct engineering procedures.

Operations personnel will review equipment involved. Particular attention will be given to the handling of

caps with respect to unexpected pressure when a cap is released.

As required by Directive 58, only approved handling and disposal methods will be used for pigging wax and

other solids and fluids as a result of the pigging operation.

A site-specific pigging procedure must be in place prior to commencing the operation. The following

considerations will be addressed:

• Personnel required for the job

• Characteristics of the substance to be pigged

• Requirements if sour products are expected to be encountered

• Inspection of cap, barrel and seals on launcher and trap prior to start of the operation

• Detailed isolation and depressurization procedures

• Detailed draining and ventilation procedures

• Specific review of hazards related to plugging of bleed-off lines

• Proper technique for launching and receiving for equipment involved and potential for hydraulic

shock

• Identification marking of pigs and launch and receive time logging

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Sour Substance Considerations

The maximum H2S content for each pipeline must be determined using records for pipeline grouping and/or

the analyses of producing sour well(s). Unless there are other risk exposures, pigging operations can be

performed without using the “buddy system” or breathing apparatus if the maximum H2S content is less

than 10 ppm. If H2S content is more than 10 ppm breathing apparatus must be worn by the operator

performing the pigging procedure and a second operator with breathing apparatus stationed 15 metres

upwind must be present.

Ensure pig launchers and receivers are bypassed and blocked when not in use.

4.13 Preparation for Line Maintenance

A hazard assessment will be performed prior to commencing purging procedures to determine protective

measures that will be implemented. Typical hazards include fire, explosion, sour gas exposure, excessive

pressure and spills. All company and contract personnel will be briefed with respect to the hazards and the

protective measures to be implemented. Appropriate safety and personal protective equipment such as LEL

detectors, H2S monitors, SCBA, goggles/face shield, fire retardant work wear, and firefighting equipment will

be used.

The procedure to prepare a line for modification, maintenance, or repair is similar to the procedure for

decommissioning a line with the following exceptions:

• The line is completely depressurized when turned over

• A copy of the list of blinds and locked valves is prepared and given to the

construction/maintenance supervisor

When work on the pipeline has been completed, use the procedure for Pipeline Filling in Section 4.9 of this

manual to reactivate the line.

4.14 Corrosion Management

External Protection

Primary external corrosion control is provided by the protective coating on the pipe that isolates the

external surface of the pipeline from the environment. Either the owner or the operator is responsible for

performing and documenting coating system evaluations and selections.

Coatings are applied in accordance with documented procedures that include quality control and address:

• Personnel qualification

• Material quality assurance (coating and abrasives)

• Environmental controls and monitoring (ambient temperature, steel temperature, humidity,

etc.)

• Surface preparation techniques and controls

• Application techniques and controls

• Curing

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• Finished coating inspection and testing

• Repair techniques

• Record keeping

Impressed current cathodic protection systems utilize an external power source that provides an electric

current to mitigate corrosion activity. We will apply cathodic protection systems to all metal pipelines,

metal underground piping and any other metal appurtenances in direct contact with the surrounding soils.

These systems provide a high level of protection but require regular monitoring and maintenance to ensure

long-term performance and continued integrity of the pipeline.

Within one year of completion of construction of pipeline facilities cathodic protection must be installed

and operational and must be maintained until the piping is abandoned. The design, operation, inspection

and maintenance of cathodic protection are to be in accordance with the appropriate Codes, Standards and

Regulations of the Canadian Electrical Code, CSA Z662 and CGA OCC-1.

Persons performing evaluations and selections of coatings and cathodic protection must be able to

demonstrate their understanding and have experience in the application of these corrosion control

techniques.

Riser Inspection

Risers must be inspected regularly for corrosion at the soil to air interface. Insulation must be removed for

visual inspection to determine if the coating is lacking or damaged. Coating can degrade as a result of

exposure to UV light and risers are more prone to mechanical damage. Damaged coating could allow water

to come in contact with piping. Lack of or damaged coating may also affect the reliability of cathodic

protection systems. Ensure that any insulation and taping is appropriately reapplied after the inspection.

Internal Protection

Pipelines will have the potential for corrosion if free water, bacteria, hydrogen sulphide, carbon dioxide or

suspended solids are carried in the fluids. Experience gained in your location and regular testing will

provide information to determine the prevention programs required to ensure the integrity and extend the

life expectancy of the pipeline. Prevention programs could include but are not limited to:

• Removal of water and foreign material by scraping or pigging

• Treatment of residual water or dehydration

• Injection of environmentally acceptable inhibitors, biocides or other chemical agents

• Removal of dissolved gases by chemical or mechanical means

• Gas blanketing

• Continuous internal coating or lining

CAPP 2003-0013 provides information on mitigation of internal corrosion in sweet gas gathering systems.

CAPP 2003-0023 provides information on mitigation of internal corrosion in sour service gas gathering

pipelines. Section 9 of CSA Z662 provides requirements that must be followed related to corrosion and

corrosion control.

Techniques to consider for monitoring internal corrosion control include but are not limited to:

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• Ongoing monitoring of operating conditions

• Deployment of corrosion-monitoring devices such as weight-loss coupons, corrosion probes,

hydrogen probes and removable spool pieces

• Non-destructive inspection such as ultrasonic or eddy current wall thickness measurement

• Visual inspection of the internal surface of cut-outs

• Use of internal electronic inspection equipment

Corrosion control records are retained for the life of the facility.

Safe Working Conditions

When metal pipe sections or fittings are separated electrical potential differences could be present across

the fittings or pipe sections creating the possibility of spark. The following procedure will be used to ensure

this hazard is eliminated:

• Shut off the cathodic protection rectifiers in the immediate vicinity

• Install a temporary bond cable between the sections before the fitting is broken or pipe section

is removed

• Remove the temporary bond cable when the break is reconnected and energize the rectifiers

4.15 Site Security

Operating staff are responsible for maintaining the security of valves and exposed company facilities to

prevent tampering or damage by outside parties.

Physical Barriers

The Alberta Oil and Gas Conservation Act sets a standard for physical barrier requirements for oil and gas

facilities. It states a security fence must be at least 2 metres high and made of small industrial type steel

mesh not greater than 130 square centimetres. This fence must completely enclose the facility and be

equipped with a gate that is locked when the facility is unattended. This type of fence must be erected:

• Around batteries where hydrogen sulphide concentrations in a representative sample of gas

from any well producing to the battery is found to exceed 10 moles/ kilomole and the battery is

located within 800 metres of an occupied dwelling, rural school, picnic ground or other

occupied area

• Around operating wells equipped with a pumping unit located within 800 metres of a city, town,

new town, village, summer village, hamlet or other incorporated centre, unrestricted

development, public facility, picnic area or campground

• As required in an order from the Regulator

The fences described above will be maintained in a proper manner at all times to prevent anyone from

easily climbing over. Large holes, washouts, frost heaves or other large openings under the fence will be

filled in as quickly as possible. Damage or deterioration in a way that would allow free entry by

unauthorized personnel will be repaired or replaced as soon as possible.

Where a battery is located elsewhere a four-strand barbwire fence equipped with either a gate or cattle

guard is required. Operating wells in low risk areas will have four-stand barbwire fencing with cattle guards

OPERATIONS



or injection shelters for protection. Valves are required to be in an operable state, but chained and

padlocked.

An appropriate fence, maintained in a proper manner is required around any shut-in or suspended wells

with equipment remaining on-site.

Physical barriers, security fences, cattle guards and injection shelters that are damaged or deteriorated

should be repaired or replaced in a timely manner.

Signs

“Authorized Personnel Only” signs will be posted in appropriate locations at company facilities or lease

roads leading into a site.

Locks / Bull-Plugging

• Chains with padlocks are required on gates to high-risk facilities

• Valves that are in exposed locations or that may result in a spill or damage to equipment will be

chained and padlocked in the operating position

• If wells are shut-in or suspended, the valves will be bull-plugged wrench tight and chained and

padlocked in the proper position

• All lines that can release to the atmosphere and valves on all operating production field tanks

will be bull-plugged wrench tight

• Padlocks will be used at any appropriate company site to prevent tampering by unauthorized

personnel

• Padlock types and specifications will be appropriate for use and maintained to function at all

times

• Weathered, damaged or non-operable padlocks will be removed and replaced as quickly as

possible

Reporting

Vandalism and theft will be reported to the local RCMP and corporate head office.

4.16 Hot Work

Regulations require that open flames not be allowed within 25 metres of an area where flammable vapours

or gas could be present. When use of an open flame is necessary at such locations a Hot Work Permit must

be completed and the work must be performed in a designated area. Prior to any hot work the area must

be checked with a LEL monitor to ensure there are no flammable gases present. The area is to be

continuously monitored throughout the job.

Hot Work is not permitted if LEL readings are greater than zero.

If the LEL exceeds zero, work must be discontinued immediately. Work can resume when LEL readings

return to zero and remain at zero.

MAINTENANCE AND REPAIR




5. MAINTENANCE AND REPAIR

5.1 General Information

Integrity management depends on regular inspections and testing combined with preventative and

scheduled maintenance routines. These activities reduce emergency repairs and minimize hazardous

conditions. Recurring maintenance, testing and inspections will ensure that operating and maintenance

personnel are familiar with the location and surface routes to installations such as valves, vents and

cathodic protection rectifiers. Changes that occur along right of ways will become readily noticeable. This

knowledge and familiarity is essential to ensure quick and effective emergency response and repair

activities.

In British Columbia it is a regulatory requirement that all pipeline incidents are reported to the Commission

directly or through the Provincial Emergency Program (PEP). A reportable pipeline incident is any incident

resulting in, or having potential to, damage a pipeline even if there is no spillage of products or substances

from the pipeline. Incident reporting is required regardless of the status of a pipeline or the type of product

released. Hits on deactivated or abandoned pipelines, leaks of freshwater from pipelines, or spills of any

substances within the right-of-way of pipelines must be reported.

Pipeline permit holders in British Columbia are required to investigate all pipeline incidents to determine

the cause and contributing factors, and to identify appropriate remedial actions and repairs to prevent a

recurrence. The root cause, repair methods and any changes in the operation or status of the pipeline must

be summarized on Form D – Permit Holder Post Incident Report, which must be submitted to the

Commission within 60 days of an incident. In addition, permit holders must inform the Commission of any

design or operational changes, as well as any change to the operating status of a pipeline, through

submission of a Notice of Intent (NOI) application.

The Post Incident Report must be submitted electronically to the BCOGC. A copy is included in the Forms

section of this document.




5.2 Pipeline Patrol and Surveillance

Inspections of all pipeline right of ways (ROW) are to be performed as required by the Pipeline Act and

Regulations, CSA Z662 and the Pipeline and Liquefied Natural Gas Facility Regulation. The frequency of

inspections is determined by pipeline service and condition, pipeline size, operating pressure, terrain,

weather, population density (class location) and any other operating or unusual conditions. Special

consideration is given to the inspection and maintenance of pipeline crossings of major utilities, other

pipelines, railways, roads and water crossings. The purpose of the inspections is to monitor the conditions

and activities adjacent to the rights of way so quick remedial action can be taken when the system is

damaged or the integrity of the system is threatened.

Operations personnel will patrol and inspect giving particular attention to the following:

• Construction activity

• Dredging operations

• Seismic activity

• Erosion

• Ice effects

• Scour, abrasion

• Soil slides

• Subsidence, collapse

• Loss of cover

• Evidence of leaks, pooling, unhealthy or dead vegetation

Crossing Inspections

Additional consideration must be given to the inspection and maintenance of pipeline crossing of:

• Major utilities

• Other pipelines

• Railways

• Roads

• Water

- Adequacy of cover, erosion

- Accumulation of debris

- Water level

Operations staff in conjunction with the immediate supervisor will establish an inspection schedule with

intervals that could be daily, weekly, bi-monthly and monthly. The inspection interval is based on the risk

associated to each pipeline segment. Unscheduled, immediate inspections could be necessary as a result of

natural hazards such as flooding. Inspection intervals may have to be revised as a result of higher

associated risk such as population encroachment on the ROW (see Class Location, Section 4.3.2 of CSA

Z662).




In addition to the above, the company is required to conduct:

• A daily inspection of any area of construction activity that is in close proximity to a pipeline right

of way

• A continuous inspection of any area of construction activity that:

- is occurring on a pipeline right of way

- may affect the safety of the pipeline

Right of Way Infringement

The following procedures outline our requirements for infringement of pipeline right of ways by outside

parties. The guidelines are based on sweet LVP service and the intent is to meet current AER requirements.

Note that pipeline operation in British Columbia is subject to the Oil and Gas Activities Act and associated

Regulations. A review of the BC Act and Regulations is recommended to ensure compliance to provincial

regulations.

Written approval or a Crossing Agreement is required anytime an external company performs activities in

any of our rights of way.

All activities by external companies on our right of ways will be performed following applicable standards,

regulations and best practices. Operating personnel will report non-conformance to the immediate

supervisor for investigation and follow-up.

Line Crossing

• A minimum of 30 cm clearance between pipelines is required and this depth will be maintained

for the entire width of the right of way

• The new line must go under the existing line (unless approved otherwise)

• Crossings will ideally be more than 25 degrees to minimize the length of exposed line (not

always possible)

• Proper support of exposed facilities must be provided

• No cathodic bonding between lines is allowed

• The crossing must meet requirements of CSA Z662

• The existing pipeline must be exposed by hand excavation (as per Ground Disturbance

procedures)

• A company field operator will witness / inspect exposing of line

• The field operator will check for line coating or insulation damage. The party requiring the ROW

infringement is responsible for the cost of any repairs.

• No equipment is allowed on the ROW unless a minimum 1.5 metre build up cover is applied and

temporary access has been approved

• The field operator must submit a written inspection report for each exposed facility

(photographs are generally included) to Head Office for filing as per regulatory requirements

• External companies must provide a drawing for crossing approval which shows all of the above

details

• A company field operator will witness / inspect the back filling

• A copy of the Crossing Agreement will be kept in Operations files and a copy will be forwarded

to the operations personnel involved




Road Crossing

• A temporary road crossing can be allowed to external companies. A minimum 1.5 metre cover

is required for a lease road and a minimum 1.8 metre cover is required for a road allowance.

• A permanent road crossing must meet requirements of CSA Z662

• If pipe thickness does not meet requirements of CSA Z662 - Table 4.9, the crossing must be

cased (with appropriate centralizers, vents, split casing) or thicker walled line pipe installed

• Road crossing should be 90 degrees to ROW

• All welds within the crossing must be radio graphed

• The extent of the crossing is a minimum of 15 metres on either side of the road centreline

If the line to be crossed meets CSA Z662 wall thickness requirements but operating stress levels are

considered high (>80%) then additional calculations will be necessary to determine if the external loading

will cause any wall deformation or failure.

Well Site Lease

• AER minimum allowable distance from a wellhead to the edge of a ROW is 30 metres

• The lease can border the ROW, however, future expansion must be considered prior to

approval

• Any distance less than 75 metres from a wellhead to the edge of a ROW must be reviewed for

location / interference of cathodic beds and rig anchor locations

Seismic Survey

• The seismic contractor will be required to contact operations personnel before commencing

work

• Operations will provide onsite field related coordination, including flow line location, for the

seismic contractor

• Seismic crews conducting operations in the vicinity of a ROW must maintain the following

minimum distances to the edge of the ROW:

- Vibrator 15 metres

- 2 kg charge 32 metres



• The seismic contractor is expected to report any non-conformance with our company policy or

procedure to the area operations supervisor for investigation and follow-up

• Any non-conformance noted by operations personnel will be reported to the area operations

supervisor for investigation and follow-up

25 KV Electrical Cable - Underground Crossing

• Cable must be shielded across the entire ROW

• Minimum 30 cm clearance

• The electrical system must be designed to allow the cable to be isolated from service for

extended periods of time without impact to other consumers

• Crossing to be under existing pipeline unless otherwise approved by the company

• Ground disturbance policies and procedures must be adhered to




Underground crossings of electrical control cable or fibre optics will meet requirements similar to

transmission cable and will have adequate protection from mechanical damage for the entire width of the

ROW.

5.3 Ground Disturbance

For our purposes, ground disturbance shall be considered any activity that requires breaching the earth to a

depth of more than 30 cm. The disturbance also cannot reduce the cover over a pipeline to less than

permitted at installation. We require that Head Office approval or a Crossing Agreement is in place any

time we create a ground disturbance in the right of way of an underground facility or within 5 metres of any

underground facility where there is no right of way. Complete a Ground Disturbance Permit / Checklist (in

the Forms section) prior to commencing the work.

A company performing a ground disturbance is responsible for proving due diligence of all reasonable

precautions necessary to determine if underground facilities exist. All underground facilities within a 30

metre perimeter of the outside limits of the ground disturbance must be located.

A Ground Disturbance Supervisor must be assigned for any ground disturbance. This will be a company

employee, contractor or consultant authorized by the company. The supervisor must be deemed

competent by formal examination and/or certification to supervise a ground disturbance. The objectives for

ground disturbance supervision are:

• Successful completion of Ground Disturbance Orientation

• Clarify the sources when searching for buried facilities

• Providing notification to facility owners

• Receiving owner notification

• Approvals/crossing agreements

• Regulations

• Creating the plot/site drawing

• Line locating

• Exposure

• Backfill inspections

• Permits and pre-job meetings

• Emergency Response Plans

• Contacting a buried facility

Sources of information that must be available prior to work commencing are:

• AER Baseline maps / ACCUMAP within 30 days

• Certificate of title

• Site drawings (if available)

• Results of our internal or third party search

• Signed copy of the crossing agreement

• As built, facility, local survey plans etc.

• References to visual indicators

• Provincial One Call services if applicable

• Consultation with other area operators, including contractors

• Discussion with the land owner




This search is carried out to determine the owners (permit holders and licensees) of facilities within the

search perimeter. The owners are notified of the:

• Nature and scope of the proposed ground disturbance

• Schedule for undertaking the work

It is the responsibility of the facility owner, at their own cost, to accurately locate and clearly indicate the

horizontal position and alignment of their facility on the surface of the ground.

• Locator services used by our company will be trained and competent at locating all types of

underground facility

• Operations personnel, thoroughly familiar with the area, will be present during locating

activities

• Operations personnel will understand line locator procedures and have a plot plan or site

drawing such as an as built map for reference

• The most effective method of detection is direct connection or clamping

• Blind search sweeping will be performed in four grid patterns (East/West, North/South and at

angles both ways) to ensure maximum detection potential

A ground disturbance cannot be performed within 5 metres of a pipeline where there is no right of way

unless there is written approval by the owner or by the provincial regulator if owner approval cannot be

obtained.

Facility owners must be notified a minimum of two working days, but not more than seven working days,

prior to commencement of the ground disturbance. This notification timeframe requirement may only

differ from regulations if agreed to by both parties.

Exposing Facilities

A site-specific pre-job safety meeting will be held when we perform a ground disturbance that encroaches

on the 5 metre safety zone for an underground facility. All personnel directly involved in the conduct of the

work will be in attendance. The meeting minutes and signed attendance list will be retained on file. New

crewmembers or replacements must be briefed prior to working on the site. As a minimum the meeting

will cover:

• All job safety and procedural considerations (safe work practices) and Crossing Agreement

requirements

• All hazards and risks on the site must be identified and communicated to all workers. Plans

must be developed and measures put in place to manage, eliminate or mitigate risks to an

acceptable level

• Identify all existing underground facilities in the ground disturbance area

• Identify the line size, operating pressure, substance carried (obtain MSDS for substances) and

the markings used for each facility

• Identify the exposure procedure for each facility

• Identify personal protective equipment to be used to conduct the work and in the event of an

emergency

• Identify firefighting equipment requirements and location

• Identify trenching and excavation requirements; OH&S regulations and Ground Disturbance

Safe Work Practices apply. Confined Space procedures may be necessary




• Identify cathodic protection requirements

• Identify barricading and fencing requirements

• Establish escape routes, mustering location and evacuation procedures

• Ensure the site Emergency Response Plan is in place and reviewed

The owner representative and the excavation supervisor must have approved Ground Disturbance training.

All facilities are to be hand excavated using an approved method. A combination of hand and mechanical

excavation, as outlined in Schedule 4 of the Pipeline Regulations, can be used for facilities buried more than

1.5 metres deep.

Mechanical excavation equipment is not to be used within 60 cm of a pipeline without on-site supervision

by an owner representative. The facility must be exposed first by hand excavation methods.

If any contact occurs with a buried facility during ground disturbance that results in a crack or puncture to a

pipeline, scratch, gouge, flattening or dent on the outside surface of a pipe or damage to the external

protective coating the ground disturbance must be immediately halted. The facility owner must be advised

of the location and damage. The owner must immediately notify the provincial regulator and report the

location and type of damage. The particular ground disturbance that was halted as a result of contact must

not recommence without the approval of the owner.

Trenches and Excavations

Provincial regulations may vary with respect to trenches and excavations. In these situations, our personnel

will always employ Ground Disturbance Safe Work Practices.

All trenches and excavations that personnel will be required to work in will be created with appropriate

cutback or sloping or temporary protective structures will be installed prior to entry.

Spoil piles must be at least 1 metre from the side of the excavation and have a slope of less than 45 degrees.

Power poles must be protected from cave-in.

Equipment is not permitted closer to the edge than the distance from the same edge to the bottom of the

excavation. If equipment or heavy objects must closer, an engineer must approve additional support for the

walls of the excavation.

There is legal responsibility to guard an excavation in a manner that is adequate to prevent persons from

falling in. If the excavation is to be left unattended, barricades must be installed to warn people of the

danger and protect personnel, the public, livestock and wildlife from the hazard.

Backfilling Procedures

Notification to the owner of a facility that was exposed due to a ground disturbance must be given at least

24 hours prior to commencing the backfill. The owner must inspect the facility to ensure no damage has

occurred. The written inspection report is retained on file for 2 years.

Backfilling an exposed facility must be done to ensure no damage occurs, or will occur from subsequent

surface activities. Pipelines must be supported by undisturbed or compacted soil. Backfill material will

normally be the spoil removed from the excavation with appropriate care to remove objects that could

damage underground facilities. Clean fill or sand will be used as initial fill within 150 mm of the pipe wall in




all directions. Care must be taken that the facility is not damaged as a result of subsequent backfill activities

and that these activities will be performed in a manner to prevent settling or erosion of the backfill and

support material. Complete a Backfill Inspection Form (in the Forms section) to be included in the records

of the work performed.

Single Penetration Points

Rig anchors, pile driving, auguring, and signposts are examples of single penetration points. All ground

disturbance guidelines apply, however it is likely that the exact location for a single point penetration can be

decided after the facility search. In this way it may be possible to remain more than 30 metres from a

foreign facility or beyond the 5 metre safety zone where a facility would require exposure by hand

excavation prior to the ground disturbance. Also be aware that if the penetration can be achieved by hand

techniques, then facilities within 5 metres need not be exposed. All notification and approval requirements

must still be met.

5.4 Pipeline Repair

All pipeline repairs will be performed in accordance with CSA Z662 and provincial authority requirements.

When it is not immediately practical to repair a pipeline permanently, a temporary repair can be made. It is

expected that a permanent repair will be performed within a year. Any temporary repair creates a risk

situation that will require sufficient periodic inspections to ensure the defective condition has not extended,

there are no leaks and the repair device has not deteriorated in any way.

Engineering review and acceptance of all proposed repairs will be done on an individual basis. Engineer

approval is required for repairs using steel or composite reinforcement sleeves or steel pressure

containment sleeves or if the repair requires hot tapping.

Hazards and Precautions

The potential hazards involved in pipeline repair include fire, explosion, exposure to toxic or irritating

substances and oxygen deficiency. As a result of any excavation, trench cave-in and exposure to broken

utility lines such as electricity are possible. Ground conditions such as mud will increase slip and fall

dangers.

A pre-job meeting will be held with all personnel involved to review the procedures that will be followed

and to ensure that all personnel understand the anticipated dangers and precautions to be taken. At this

meeting the hazards and potential seriousness of an incident will be evaluated and containment, mitigation

and recovery actions will be identified.

Company personnel will ensure that fire retardant work wear and appropriate respiratory protective

equipment is worn during pipeline repair activities. Air monitoring equipment, non-sparking tools and

electronic line location devices will be used. Positive air shutoff on diesel powered equipment and spark

arrestors on exhaust pipes or stacks of engines running in the area are required.

Site security measures must be taken. Danger and Caution signs and barricades will be placed appropriately

and access to the area will be restricted to essential personnel.

Employ ground disturbance, trenching and excavation safe practice procedures and isolate the pipe from

the potential of electrical hazard created by the cathodic protection system.




During the pipe cutting operation all precautions must be taken to eliminate the possibility of sparks. The

pipe must be properly prepared before any hot work is performed. Personnel wearing respiratory

protective equipment will wipe the inside of the pipe on the cut ends a minimum of 1.5 metres. Use air

stopples or mud plugs that have been approved by the engineer. Air monitoring will be performed once the

plug is installed.

Before proceeding with any welding air monitoring will be performed. Consider the possibility of prior

hydrogen charging and the removal of hydrogen using a bake-out process. Fire extinguishers must be

manned when welders are in the excavation.

Welding procedures and practices will be in accordance with CSA Z662 Section 7. There are also welding

criteria that must be complied with in CSA Z662 Sections 10.13 and 10.14. Welders must be qualified to

perform the work as specified in the standards.

Notification

A company representative will notify the following when a repair is to be performed:

• Local and jurisdictional authority

• Pipeline co-owners

• Affected operating facility partners or owners

The notification will be in writing and will include the following information:

• Legal description and license number of the pipeline

• Description of the defect

• Detailed information regarding the repair:

- Permanent or temporary repair

- Repair method to be used

- Requirement for pipeline shutdown

- Actions that will be undertaken to ensure the integrity of the pipeline system

- Anticipated timing to perform permanent repair if original repair is temporary

Repair Methods

Pipeline repair methods take into account the type of damage and whether it is on the pipe body, on a mill

seam weld or on a circumferential joint weld. A dent that contains a stress concentrator (gouge, groove, arc

burn or surface crack) that is on a circumferential weld has significantly different repair requirements than a

dent with no other damage on a pipe body.

Table 10.1 of CSA Z662 details acceptable permanent repair methods and their limitations related to each

type of pipeline defect. The following information has been extracted from the table and shows the repair

methods for each type of defect that have no additional limitations beyond those specified in the associated

repair clause of the standards. Each defect type is also explained in further detail in the standards manual

and the first time a repair method or defect is referenced below the appropriate clause has been noted.




Pipeline Replacement – CSA Z662 clause 10.11.3

This repair method is acceptable for all types of pipe defects.

NOTE: Pipeline replacement is the only acceptable repair method for internal corrosion defects on

sour service pipelines.

Steel Pressure Containment Repair Sleeve – CSA Z662 clause 10.11.4.2

This repair method is acceptable for all types of pipe defects except internal corrosion defects

NOTE: The above methods are the only two that are acceptable for repairing a leak (CSA Z662

clause 10.11.1.4).

NOTE: The above methods are the only two, without limitations, for repair of a dent defect (CSA

Z662 clause 10.10.4.2) with a stress concentrator on a circumferential weld.

Steel Compression Reinforcement Repair Sleeve – CSA Z662 clause 10.11.4.4

Acceptable for:

- External corrosion defects (CSA Z662 clause 10.10.2.7)

- Gouge, groove or arc burn (CSA Z662 clause 10.10.3) on a pipe body or mill seam weld and is not in

a dent

- Dent defect with a stress concentrator on a pipe body or a mill seam weld

- Dent defect without a stress concentrator

- Weld defect (CSA Z662 clauses 10.10.6 and 10.10.7) in a mill seam weld

- Grind defect (CSA Z662 clause 10.11.2.6)

Hot Tap – CSA Z662 clause 10.11.5 (damage must be completely contained in the metal removed)

Acceptable for:

- External corrosion defects

- Gouge, groove or arc burn on a pipe body or a mill seam and is not in a dent

- Dent defect with a stress concentrator on a pipe body or mill seam weld

- Dent defect without a stress concentrator on a pipe body or mill seam weld

- Pipe body surface crack (CSA Z662 clause 10.10.5) not in a dent

- Weld defect in a mill seam weld

- Grind defect

Steel Reinforcement Repair Sleeve – CSA Z662 clause 10.11.4.2

Acceptable for:

- External corrosion defect

- Dent defect without a stress concentrator on the pipe body

- Grind defect




Grinding Repair – CSA Z662 clause 10.11.2

Acceptable for:

- Gouge Groove or arc burn on a pipe body or mill seam weld or circumferential weld and is not in a

dent

- Pipe body surface crack that is not in a dent

- Weld defect in a mill seam weld or circumferential weld

Direct Deposition Welding – CSA Z662 clause 10.11.6

This repair method is acceptable for external corrosion defect or grinding defect repairs.

Welding Repair – CSA Z662 clause 10.10.6

This is acceptable to repair a weld defect in a circumferential weld.

Composite Reinforcement Repair Sleeve – CSA Z662 clause 10.11.4.3

There are no defects that can be repaired by using a composite reinforcement repair sleeve by

itself. Information in Table 10.1 of CSA Z662 will provide details of the conditions that must be met

to use this as a permanent repair method. It may be an option worth considering at pipe bends or

when a welding truck cannot be brought to the location.

Refer to the following Flow Chart from CSA Z662 showing acceptable repair methods.

NOTE: The legend and limitations information is on the page following the flowchart.




Legend

A – Grinding repair (CSA Z662 - Clause 10.11.2)

B – Pipe replacements (CSA Z662 - Clause 10.11.3)

C – Steel pressure-containing sleeve (CSA Z662 - Clause 10.11.4.2)

D – Steel reinforcement sleeve (CSA Z662 - Clause 10.11.4.2)

E – Steel compression reinforcement sleeve (CSA Z662 - Clause 10.11.4.4)

F – Composite reinforcement sleeve (CSA Z662 - Clause 10.11.4.3)

G – Hot tap (CSA Z662 - Clause 10.11.5)

H – Direct deposition welding (CSA Z662 - Clause 10.11.6)

I – Welding repair (CSA Z662 - Clause 10.10.6)

Limitations

These limitations are additional to any specified in the applicable repair clause.

1 This repair method is not acceptable for the defects with metal loss in excess of 80% of the

nominal wall thickness of the pipe.

2 The stress concentrator (gouge, groove, arc burn or crack) shall be removed by grinding as

specified in CSA Z662 Clauses 10.11.2.2 and 10.11.2.3 prior to the application of the sleeve.

3 The stress concentrator (gouge, groove, arc burn or crack) shall be removed by grinding as

specified in CSA Z662 Clauses 10.11.2.2 and 10.11.2.3 prior to the dent being assessed for

acceptability as specified in CSA Z662 Clause 10.10.4, with the depth of the ground area being

excluded from the dent depth. This repair method is not acceptable unless both of the

following apply:

a. The dent is no longer a defect as described in CSA Z662 Clause 10.10.4.2.

b. The pipe is considered to be acceptable based upon an engineering assessment as required

in CSA Z662 Clause 10.10.4.3 unless a steel reinforcement repair sleeve is applied.

4 This repair method is not acceptable unless all of the following apply:

a. The dent is on the pipe body or a mill seam weld.

b. The dent depth is 15% or less of the specified outside diameter of the pipe.

c. Any stress concentrators in the dent are removed by grinding as specified in CSA Z662

Clauses 10.11.2.2 and 10.11.2.3.

d. A suitable material is used to fill the dent prior to application of the sleeve in order to

prevent re-rounding of the pipe.

5 Any circumferential cracks shall be removed by grinding prior to application of the sleeve.

6 The stress concentrator (gouge, groove, arc burn or crack) shall be removed by grinding prior to

performing direct deposition weld repairs.

NOTES:

- Mill seam welds are longitudinal, helical or skelp end pipe seam welds.

- Permanent repairs may be preceded by temporary repairs. (See CSA Z662 Clause 10.12).




If the repair requires shutdown, re-testing may be necessary to establish the integrity of the pipeline prior

to reactivation. This would usually be done by pressure testing. If appropriate, we can apply for approval to

establish the integrity of the pipe using alternate methods.

Regulatory approval is required to put the pipeline back in service.

5.5 Pressure Testing

In Alberta the AER must be notified at least 48 hours prior to the commencement of a pressure test. The

test will be performed in place, before being put into operation and under the same conditions as expected

during normal operations. Otherwise, the pipe should be pretested.

Pressure testing standards are found in Section 8 of CSA Z662. The Pipeline Act and Regulations also

provides requirements for performing tests. Evidence of satisfactory testing must be in place for all

pipelines we operate. The AER may require retesting if satisfactory records are not available.

Prior to the pressure test confirm that the test will not:

• Result in greater than allowable stress in the piping

• Adversely affect the soil surrounding the piping

• Damage valve seats

Consideration must be given to any adverse effects the liquid medium could have on the pipe. Adverse

effects can be caused by the presence of bacteria, oxygen, suspended solids or metals, high salinity, acidity

or industrial contaminants. Any of these conditions may necessitate a plan of treatment of the liquid or the

completed piping to protect against corrosion or other damage.

A pressure testing plan must be developed. The plan will address the safety of the public and the personnel

conducting the test. The plan must consider issues such as pressure, test medium, location, worker and

public access control and the consequences of uncontrolled or controlled depressurization. This list is not

comprehensive and other considerations may be necessary.

The minimum test pressure for any pipeline in Alberta will be 700 kPa unless the AER approves a lower test

pressure. If the pipeline has concentrations of H2S greater than 10 moles/ kilomole then the minimum test

pressure must be 1.4 times the maximum operating pressure.

Pressure testing pipelines within 20 metres of a test head assembly shall not exceed a hoop stress level of

90% SMYS (specified maximum yield strength).

There are specific requirements and/or approvals that must be in place to test a pipeline if the hoop stress

level will exceed 100% SMYS or if test durations will deviate from requirements.

Some pressure testing requirements do not apply for instrument and control piping that does not exceed 25

mm outside diameter.




Liquid Test Medium Other Than Fresh Water

Approval from the AER is required to test a pipeline with any liquid test medium other that fresh water if:

• The volume of the test section exceeds 500 cubic metres

• The hoop stress level during the test is expected to exceed 100% SMYS, or

• The pipeline crosses or is within 100 metres of flowing water

In a situation where new welded steel pipe is to be tested within 100 metres of flowing water non-

destructive inspection of all welds, in accordance with CSA Z662, for the portion within 100 metres of the

flowing water must be performed. Unacceptable welds must be removed and repaired.

Prior to the start of pressure testing:

• Develop and document a contingency plan for immediate response in the event of a leak or spill

• Deploy equipment and resources to the site to ensure that implementation of the contingency

plan can be achieved without delay

• Complete all applicable sections of Form A6.1 – Non-Fresh Water Liquid Pressure Test for

Pipelines at least 48 hours prior to starting the pressure test

• Form A6.1 can be found here:

- http://www.aer.ca/documents/directives/Directive077_FormA61_122211.doc

• Maintain a copy of the completed Form A6.1 on site during the test

• Submit the completed Form A6.1 and the contingency plan to the AER upon request

• Maintain the original completed Form A6.1 for at least two years after the completion date of

the test

Written approval for any deviation from the above requirements must be obtained by request submitted to

[email protected] and must include the completed Form A6.1 along with justification for the

deviation.

Gaseous Test Media

Use of air or other gaseous medium to pressure test a pipeline section with an internal volume greater than

125 cubic metres will require approval from the AER. A detailed proposal of the test must be submitted

that includes a fully documented engineering evaluation that demonstrates the procedure is safe and

sufficiently sensitive to detect leaks.

If the pipeline section is known or suspected to have corrosion, or any other condition that could potentially

cause the pipeline to break, then the testing proposal must include a fully documented engineering

evaluation that demonstrates the testing procedure complies with CSA Z662 and the Pipeline Regulation.

Appropriate measures must be implemented to ensure the protection of people and property in the vicinity.

The Pipeline Regulation and CSA Z662 have specifications regarding the gases that can be used for gaseous

media pressure testing. No gas containing H2S may be used. After completion of the test the gas must be

vented or flared in accordance with Directive 038 and Directive 60.




Recording Requirements

The following requirements apply for the recording of pressure test results:

• The record or chart of a pressure test shall be continuous and legible over the full test period.

The commencement and termination points must be clearly identified.

• Electronic pressure recording devices can be used provided:

- A permanent paper copy of the test data is retained

- The sample rate and instrument sensitivity will identify expected deviations from normal

test pressure

• The pressure during the test must fall between 25% and 90% of the full range of the recording

instrument. The range of the instrument must be recorded on the chart face or on the

permanent paper copy of the test data.

• The recording instrument must be accurate within 2% of its range. Verification that the

instrument is within specifications must be available.

Pre-Tested Pipe for Use in Emergency Repair

Pipe kept in storage can be used in emergency repairs. The pipe must be stored in a way that prevents

deterioration by excessive metal oxidation or UV damage to coatings. The pipe ends must be bagged or

capped.

All pre-tested pipe must conform to standards and be marked accordingly, complete with Heat Number.

Mill Test Certificates must be available as supporting documentation.

Pipe stored for emergency repair will pass testing in accordance with CSA Z662 Section 8. The test pressure

and date of testing will be painted along the length of the pipe. Test charts will be retained on file until the

pre-tested pipe is used.

Pipe not used within five years will be inspected for coating damage and re-tested as per CSA Z662.

When pipe is used from storage the pipe must be transported, handled, installed and buried using good

practices to avoid damage. Pipe documentation will be transferred to the project files and retained for the

life of the pipeline.

Note: The following testing and maintenance routines are essential to the integrity management of our

pipeline systems. By performing these activities we mitigate the risk associated with our pipeline

operations. The records that we produce from performing these tasks will establish the criteria for our

integrity management plan, a pro-active assessment of the repairs, improvements, modifications,

replacement or further testing that is foreseeable. The integrity management plan is executed based on

priority that is established by a risk assessment.

5.6 Inspection of Cathodic Protection System

Measurement of the rectifier voltage and current output levels will be recorded every two months, with no

interval longer than ten weeks. A technical assessment using the recorded information will be performed

annually, with no interval longer than fifteen months. The evaluation of the current required to provide

cathodic protection can give insight into the integrity of the external pipe coating.




Interference bonds, whose failure would jeopardize pipeline protection, will be checked for proper

operation every two months, with no interval longer than ten weeks.

Annually, qualified personnel will perform the following:

• Check condition and efficiency of rectifier and ground bed installations

• Check condition and accuracy of meters and perform calibration if necessary

• Check condition of cased road crossings and measure to determine if contact between pipe and

casing is occurring

• Investigate any evidence of foreign interference

• Check condition of insulation fittings, continuity bonds and casing insulators

Repairs to components of the cathodic protection system are to be performed when inspections or

measurements indicate there are deficiencies.

A complete record of the repairs performed will be kept on file.

5.7 Inspection of Pressure Control, Limiting and Relieving Devices

Pressure control, pressure limiting and pressure relieving systems and devices can be left in place for

inspection, testing and assessment provided these activities can be performed safely and properly.

Annually, with no interval longer than 18 months, the following activities must be performed for pressure

control and pressure limiting systems and/or devices:

• Inspected to determine that they are properly installed and protected from dirt and other

conditions that can prevent their proper operation

• Tested to determine that they are in good operating condition and set to function at the correct

pressure

• An assessment must be performed to determine that they are adequate from the standpoint of

capacity and reliability for the service in which they are employed

A defective or non-functioning overpressure protection device must be repaired or replaced before the

operation of the pipeline resumes.

For all overpressure protection devices we must:

• Maintain adequate inspection, assessment and testing records for the device, and

• Submit the records to the AER upon request

Inspection, assessment and testing records must document the information used to perform effective

evaluation of the overpressure protection device; the results of the inspection, assessment and testing; and

the resolution of any issues regarding a defective or non-functioning device prior to the resumption of

pipeline operations by the licensee.

Rupture disks will be inspected, assessed and, if necessary, replaced in accordance with API 576.

As a minimum, once each calendar year emergency shutdown (ESD) valves and ancillary equipment will be

inspected and proper operation confirmed. Opportunities presented by other maintenance routines such

as compressor oil changes or turnarounds should be used to test ESD valves.




The records of inspection, testing and assessment of these systems and/or devices will be kept on file for

two years.

5.8 Valve Maintenance Program

Wellhead and flow line valves will be maintained as recommended by the manufacturer. Valve

maintenance personnel will use safe work practices and procedures when performing maintenance

activities. The contractor will provide the company with status reports for each location listing the valves;

the maintenance performed and suggested repairs.

Our operating personnel must approve the closing and opening of valves during valve maintenance

procedures.

Other work to be performed on every wellhead includes:

• Tightening hand wheels where needed to prevent stem damage

• Check and tighten gland nuts as needed

• Check the ESD valves for leakage or faulty operation

• Service ball valves

- operator must approve valve operation

- damage to seals may occur if grease is forced into a closed valve

- close the valve after greasing and observe, a pressure increase would indicate the valve is

faulty

- add sealant if appropriate

- submit suggested repairs to the company

Pipeline valves that may be required in an emergency situation must be inspected and partially operated a

minimum of once per calendar year, with no interval longer than 18 months.

The open and closed position of major valves must be clearly marked.

5.9 Meter and Instrumentation Maintenance

As a general practice instruments and measuring equipment shall be calibrated at least annually, or as

required by regulations, standards or best practice. Malfunctions must be immediately corrected to

facilitate proper measurement and/or system security.

The performance of the leak detection system must be monitored regularly to ensure degradation in

performance is detected as soon as possible and remedial action taken. The leak detection system must be

tested annually. This should be done by removal of liquid from the pipeline.

The following information must be recorded:




• Date, time and duration

• Method, location and description of leak

• Operating conditions at the time of the test

• Details of any alarms that were triggered by the test

• Analysis of the performance of the leak detection system and operating personnel during the

test

Maintenance and testing records must be retained on file for five years.

5.10 Site Vegetation Control

As a fire prevention measure, natural vegetation and vegetation used for erosion control or as a windbreak

at our facilities and right of ways will be maintained in an appropriate manner.

Approved methods of vegetation control are mowing and the use of short-term herbicides. Operating

personnel can perform spot spraying and maintenance of small areas. Operating personnel are not

permitted to use products requiring application by licensed personnel. Pipeline right of ways should be kept

clear of vegetation that obstructs visual inspection or impedes access for maintenance and repair or in the

event of an emergency. Where vegetation control may require larger machinery, licensed personnel or

involve large areas, consideration should be given to contracting a grounds keeper.

All vegetation control measures on company property will be performed using appropriate safety and

personal protective equipment and following all precautionary and procedural instructions.

Use of sterilants at our facilities is not recommended. Sterilants may persist in the soil for years and can

wash into agricultural fields resulting in crop damage. The company is liable for compensation claims and

reclamation of damaged areas. Use of long-term herbicide, on an exception basis, must satisfactorily pass

an environmental assessment and be approved by Operations management.

Use of herbicides must be documented and retained in the facility environmental files. Information should

include at least:

• The name of the facility

• The area at the facility where the herbicide was applied

• The name of the herbicide and application rate

5.11 Exposed Pipe Examination

Anytime that a pipe is exposed the coating of the pipe should be examined. This will provide a visual record

of the coating condition of the exposed portion and a reasonable estimation of the relative condition of the

entire pipe joint. Further investigation is warranted if problems with the coating or pipe are observed.

Removal of the old coating and application of new coating is appropriate for small areas. Cut out and

replacement of the existing pipe can be considered for more extensive failure.

Records of the observation, with photographs if warranted, and repair must be kept for the life of the

pipeline.




5.12 In Line Inspection

This type of inspection will provide data to assess if deterioration of the steel pipe or coatings is occurring.

It is useful to establish current base line data for pipelines that have been in operation for many years. It is

also a practical testing method for pipelines with high corrosion rates.

This testing is typically provided by a third party and will require that the pipeline has no conditions that

could interfere with the passage of the tool. Build up of wax or other deposits must be cleared with

cleaning pigs prior to testing.

Further inspections using ultrasonic or radiographic techniques or mechanical measurement may be

scheduled as a result of the in line inspection to further investigate findings. Comparison of subsequent in

line inspection data will establish growth rate or change to any areas of concern.

PIPELINE OPERATIONS MANUAL FORMS Table of Contents Pipeline Operations Manual

Table of Contents

6. FORMS

Note: Emergency Response Plan activation, notification or reporting may be required if any of the highlighted forms are used. Make copies as required or ensure that forms are replaced if original is used.

FIRST RESPONSE FORM 1

ACCIDENT / INCIDENT REPORT 3 FIRST CALL COMMUNICATION (ALBERTA) 5 INCIDENT LOG 7

ANIMAL HEALTH COMPLAINT FORM 9 BOMB THREAT FORM 11 RIGHT OF WAY INSPECTION REPORT 13 PIPELINE INSPECTION AND MONITORING REPORT 15 OUT OF SERVICE FORM 17

EVACUATION ZONE ACCESS CONTROL FORM 19 PLUME TRACKING AND AIR MONITORING FORM 21 SPILL REPORT 23 VALVE SUMMARY (insert in Valves and Crossings section when complete) 27 CROSSING SUMMARY (insert in Valves and Crossings section when complete) 29 GROUND DISTURBANCE PERMIT / CHECKLIST 31 BACKFILL INSPECTION FORM 33 THIRD PARTY INSPECTION 35 REPAIR LOG 37 PIPELINE CROSSING CHECKLIST 39 NEW WELL START UP FORM 41

PIPELINE OPERATIONS MANUAL FORMS Table of Contents Pipeline Operations Manual

Table of Contents

FIRST RESPONSE FORM Forms Pipeline Operations Manual

Forms Page - 1

CALLER INFORMATION

NAME: DATE/TIME:

PHONE: LOCATION:

EMERGENCY EVALUATION

CATEGORY: ALERT LEVEL 1 LEVEL 2 LEVEL 3

EMERGENCY DESCRIPTION:

ON-SCENE COMMANDER: PHONE:

INJURIES:

EVACUATION NEEDED: IMMEDIATE AREA ONLY TOTAL

EVACUATION COORDINATOR: NAME: PHONE:

NOTIFICATION

CHECKLIST

POLICE FIRE AMBULANCE LOCAL AUTHORITY LEAD AGENCY RESIDENTS CENTRE

OTHER: _________________________________________________________________

ROADBLOCKS REQUIRED/ ESTABLISHED

ASSIGNMENTS:

OPERATIONAL ATTRIBUTES

UPID OPERATING PRESSURE SUBSTANCE PROBLEM

DESIGN ATTRIBUTES

DIMENSION / MATERIAL M.O.P. COATING WELD ATTRIBUTES CORROSION SUPPRESSION

PRODUCT RECOVERY

SUBSTANCE VOLUME RELEASED VOLUME RECOVERED

FIRST RESPONSE FORM Forms Pipeline Operations Manual

Forms Page - 2

LOCATION INFORMATION

DESCRIPTION OF LAND:

PROXIMITY TO WATER:

PROXIMITY TO PUBLIC:

IMMEDIATE DANGER:

WEATHER CONDITIONS

WIND DIRECTION/SPEED:

ROAD CONDITIONS:

OTHER:

CONTACTS MADE BY CALLER

CONTACT PHONE CONTACT PHONE

INFORM THE CALLER OF ANY IMMEDIATE DANGER TO HIMSELF OR OTHERS INSTRUCT THE CALLER IN IMMEDIATE PRECAUTIONS TO BE TAKEN

ASSURE THE CALLER THAT IMMEDIATE ACTION WILL BE TAKEN NOTES:

ACCIDENT / INCIDENT REPORT Forms Pipeline Operations Manual

Forms Page - 3

ACCIDENT/INCIDENT DETAILS

EXACT LOCATION:

DATE AND TIME:

REPORTED TO: DATE AND TIME:

TYPE OF ACCIDENT/INCIDENT

LOST TIME INJURY OR ILLNESS PROPERTY DAMAGE

MEDICAL AID PRODUCTION LOSS OTHER

PERSONAL INJURY

NAME OF PERSON INJURED: OCCUPATION:

DESCRIPTION OF INJURY:

PROPERTY DAMAGE OR PRODUCTION LOSS

DESCRIPTION OF DAMAGE OR LOSS:

COST OR AMOUNT OF LOSS:

OBJECT/EQUIPMENT/SUBSTANCE INFLICTING DAMAGES:

DESCRIPTION

DESCRIBE CLEARLY HOW ACCIDENT/INCIDENT OCCURRED:

ACCIDENT / INCIDENT REPORT Forms Pipeline Operations Manual

Forms Page - 4

ANALYSIS

WHAT ACTS, FAILURES OR CONDITIONS CONTRIBUTED MOST DIRECTLY TO THIS ACCIDENT/INCIDENT:

PREVENTION

WHAT ACTION(S) WILL BE TAKEN OR RECOMMENDED TO PREVENT RECURRENCE:

POST-INCIDENT REVIEW

PERSON RESPONSIBLE FOR FOLLOW-UP:

INVESTIGATED BY: DATE AND TIME:

REVIEWED BY MANAGEMENT: DATE AND TIME:

COMMENTS

MANAGEMENT COMMENTS:

ADDITIONAL COMMENTS:

FIRST CALL COMMUNICATION - ALBERTA Forms Pipeline Operations Manual

Forms Page - 5

CO

NT

AC

T D

ET

AIL

S

AER Contact Field Centre

Media Contact

Caller*

Licensee

Phone*

Phone

date* time*

Notification*

start date* start time* end time*

Release* Ongoing

Location* Nearest Town

Nearest Resident Distance / Direction Phone

Media Involvement?*

Worker Injuries*Public

Health and Safety*

Regional

Local National

International

Operator Phone

PU

BL

IC IM

PA

CT

is jeopardized

could be jeopardized

Hospitalization

First aid Fatality

Emergency Assessment Matrix

Completed with licensee* ERP Activated?One

Alert Two

Three Field / Area

Site Specific Corporate

EPZ Size (2 km if unknown) Numbers and Types of Public in EPZ EOC / ICP Location

Public Protection Measure ImplementedNumber Evacuated

Shelter

Notification Roadblocks

Evacuation

RE

LE

AS

E T

YP

E

Release Impact*H2S Concentration*

Off Lease

Environment Affected*

Area Affected (m2)*

Land

Air Standing Water

Flowing Water

Water Body Name

Property Damage* Equipment Loss* Wildlife / Livestock Affected*

Gas ReleaseVolume / Rate

Liquid ReleaseVolume / Rate

Sweet Sour

Release Point Determined

Water Effluent

CO

NT

AIN

ME

NT

Third Party / Outside Assistance Required*Intermittent control possible

Incident contained or controlled Imminent control probable

Incident is uncontrolled

Company WCSS Co-op

First Call Communication

* These fields must be completed to generate an FIS number and/or to complete an Emergency Assessment Matrix.

Release Point Determined

Sensitive Environment*

On Lease

Oil

FIRST CALL COMMUNICATION - ALBERTA Forms Pipeline Operations Manual

Forms Page - 6

Type of IncidentWell Licence No.

OP

ER

AT

ION

TY

PE

Well Status

Blowout Loss of CirculationKick

Producing InjectionServicing

Sour CriticalSweet

Drilling

Standing

Suspended

Pipeline Licence No. Line No.Leak RuptureHit

Production Facility Licence No. AENV Approval No.Gas Plant CompressorGas

Battery OtherOil

AIR

MO

NIT

OR

ING

Estimated Time of ArrivalLicensee Air Monitoring Occuring HandheldMobile

DistanceInitial Readings / Location On SitePPB

Off SitePPM

Contractor Name Phone AMU Phone

Direction Speed

Wind

Meteorological Conditions AER AMU ETA

Communications competed by Licensee and/or AER

DFO First NationsAHW

Environment Canada Indian Oil and GasLocal Authority

AENV

WH&S

Other

CO

MM

UN

ICA

TIO

NS NEB TDGHealth RegionEMA WCSS

RCMP / Police

Ambulance

Fire

Contact Names and Phone Numbers

Incident Cause Natural Human-Induced Unintentional Human-Induced Intentional

OT

HE

R IN

FO

RM

AT

ION

Band / Settlement Name / Contact PhoneFirst Nations Band

Metis Settlement

ComplaintsLocal

Large Area

PhonePrivate Land Title Holder

Public Land Type Irrigation Forestry Grazing Other

PhonePublic Land Administrator Contact

Additional Information

INCIDENT LOG Forms Pipeline Operations Manual

Forms Page - 7

DATE/TIME ACTIONS RESULTS

INCIDENT LOG Forms Pipeline Operations Manual

Forms Page - 8


ANIMAL HEALTH COMPLAINT FORM Forms Pipeline Operations Manual

Forms Page - 9

INITIAL CONTACT QUESTIONNAIRE

Name of person reporting incident: Date: Time:

Address:

Name of livestock owner (if not the same as above):

Address:

Legal Land Location: LSD SEC TWP RGE W Telephone: (work) (home)

Nature of animal health problem: ______ Distressed ______ Death ______ Other

Comments:

QUESTIONS FOR LIVESTOCK OWNER:

Have you consulted your veterinarian: ___ Yes ___ No

Name of veterinarian:

Have you had an animal health examination and documentation of problem? ___ Yes ___ No

Details:

Have you made any submissions to an animal health or veterinary diagnostic laboratory? ___ Yes ___ No

Details:

Have you contacted any government agency or others for assistance or direction regarding this matter? ___ Yes ___ No

Details:

Do you know the possible source of the problem? ___ Yes ___ No

Comments:

Is the source of the problem related to an oil or gas related activity? ___ Yes ___ No

If NO, this matter will be referred to (name & dept.):

LIVESTOCK OWNER DECLARATION:

I agree to an integrated government response in investigating this situation. To allow this integrated government response to occur, I agree to allow veterinary health data collected on my animals to be shared between the participating government agencies involved in this investigation.

__________________ _________________________________________

(Date) (Signature of livestock owner)

INVESTIGATOR QUESTIONS:

Have you or anyone else taken any samples? ___ Yes ___ No

Comments:

Possible source: ___ Oil & Gas Industry – Operator ______________________________________________________

___ Other ___________________________________________________________________________

Have you contacted the operator regarding this matter? ___ Yes ___ No

Describe the site: Is it a ___ well site? ___ pipeline? ___ battery? ___ plant site? ___ farmyard? ___

Is the total lease area ___ partially / ___ totally fenced? Have any photographs been taken? ___ Yes ___ No

Details:

Is there visual evidence of surface water migration off the site? ___ Yes ___ No

ANIMAL HEALTH COMPLAINT FORM Forms Pipeline Operations Manual

Forms Page - 10

Does this lead to a dugout or other drinking water source for livestock? ___ Yes ___ No

What have the livestock been grazing on?

Water conditions? Feed conditions? Soil conditions?

Actions taken by operator / complainant to minimize impact

DIAGRAM OF AREA:

Signature: __________________________________________________

Name (Print): __________________________________________________

Telephone: __________________________________________________

BOMB THREAT FORM Forms Pipeline Operations Manual

Forms Page - 11

If a threat is received by telephone, the receiver of this call should: REMAIN CALM AND LISTEN CAREFULLY PLEASE COMPLETE THIS FORM AS COMPLETELY AS POSSIBLE Time of call: Date of call:

Exact wording of call: (ASK TO REPEAT IF NECESSARY)

Type of Threat:

Expected time of detonation: Location of detonation:

DETERMINE IF YOU ARE ABLE (circle where applicable):

Voice: M F Unknown Familiar: Y N who? Approx. Age: 10-15 / 16-25 / 26-45 / 46-75

Is voice: Calm, Nervous, Young, Old, Middle-aged, Rough, Refined, Speech impediment

Accent of caller: Is caller intoxicated?

Background Noises: traffic, music, machinery, bells, horns, aircraft, tape recorder, motors, boats/ships,

trains, crowded areas (malls, schools, etc.), other:

PARTICULARS REGARDING THE EVENT What time will the bomb explode? Where is it located?

What does it look like? What kind of bomb?

Why are you doing this? Where are you calling from?

What will cause it to explode?

Did you place the bomb?

What is your name or group taking responsibility for this?

CONTINUED ON OTHER SIDE

BOMB THREAT FORM Forms Pipeline Operations Manual

Forms Page - 12

Did caller indicate knowledge of the facility: Y N If so how?

Receiver of call:

Telephone # of call: Ext. #:

Is this a listed or unlisted number?

Is this a night number? Y N If so whose #?

NOTIFICATION Notified immediate Supervisor: Title:

Supervisor contacted building management: Time:

Comments:

Supervisor contacted police: Time:

Comments:

FOLLOW INSTRUCTIONS FROM BUILDING MANAGEMENT OR POLICE

RIGHT OF WAY INSPECTION REPORT Forms Pipeline Operations Manual

Forms Page - 13

Pipeline System Description:

Pipeline Licence Number(s):

Date of Inspection:

Frequency of Inspection:

Block Valve and Pressure:

Control Equipment and Locations:

Inspection Remarks

Right-of-Way Vegetation

Soil Erosion or Differential Settlement

Heavy Equipment or Construction Activity

Seismic Activity

Pipeline Crossings - water - highway - railway - utilities - other pipelines

Aboveground piping and appurtenances condition

Condition of markers or signs - Right-of-Way - Pipeline, Crossings

RIGHT OF WAY INSPECTION REPORT Forms Pipeline Operations Manual

Forms Page - 14

RECOMMENDATIONS:

IMPLEMENTATION PLAN:

PIPELINE INSPECTION AND MONITORING REPORT Forms Pipeline Operations Manual

Forms Page - 15

Pipeline System Description:

Pipeline Licence Number(s):

Date of Inspection:

Frequency of Inspection:

Method / Equipment Used:

Results / Observations:

Engineering Evaluation:

PIPELINE INSPECTION AND MONITORING REPORT Forms Pipeline Operations Manual

Forms Page - 16

RECOMMENDATIONS:

IMPLEMENTATION PLAN:

OUT OF SERVICE FORM Forms Pipeline Operations Manual

Forms Page - 17

PIPELINE ABANDONMENT AND DISCONTINUATION STATUS FORM PIPELINE LICENCE: ____________________ LINE #: __________________ QC#: ______________

(Information can be obtained from the PL 100)

PIPE DIAMETER (OD): _____________________ WALL THICKNESS: ________________________ MATERIAL: _______________ COATED: _______________ PIPE LENGTH: ___________________ LOCATION: From: ______________________________ To: ______________________________ SUBSTANCE CODE: _________________ (what was line transporting prior to current work) DATE WORK COMPLETED: _________________________ STATUS: _______________________ (i.e. Abandoned or Discontinued) CATHODIC PROTECTION: No: _____ Yes: _____ (must be left in place if discontinuing line) VISUAL CONDITION OF PIPELINE: EXTERNAL: ______________________________________________________________________ INTERNAL: ______________________________________________________________________ PIGGED OUT: No: _____ Yes: _____ TYPE: Ribbed: _____ Foam: _____ PURGED WITH: Air: _____ Nitrogen Gas: _____ Water: _____ PHYSICALLY ISOLATED FROM ALL OPERATING FACILITIES: No: _____ Yes: _____ ENDCAPS: Steel Plates: _________ If other, describe: ___________________________________ HAS ALL FLUIDS BEEN REMOVED FROM LINE: No: _____ Yes: _____ HAS ANY PRESSURE BEEN LEFT ON THE LINE: No: _____ Yes: _____ REMARKS: ______________________________________________________________________

___________________________________________________________________

PERFORMED BY (PRINT): ____________________________________________ SIGNATURE: ______________________________________________________ (Enter Location Code or AFE and Item #'s): _____________________________________

OUT OF SERVICE FORM Forms Pipeline Operations Manual

Forms Page - 18

Notes:

EVACUATION ZONE ACCESS CONTROL FORM Forms Pipeline Operations Manual

Forms Page - 19

NOTE: Persons entering the Evacuation Zone must be equipped with Personnel Protective Equipment (PPE) and be updated regarding current conditions.

LOCATION OF ROADBLOCK: ______________________________________________ DATE: ________________

VEHICLE/LICENSE NAME OF DRIVER # OF PERSONS TIME IN TIME OUT

EVACUATION ZONE ACCESS CONTROL FORM Forms Pipeline Operations Manual

Forms Page - 20

VEHICLE/LICENSE NAME OF DRIVER # OF PERSONS TIME IN TIME OUT

PLUME TRACKING AND MONITORING Forms Pipeline Operations Manual

Forms Page - 21

LOG SHEET

No. Wind Speed

Wind Direction

Time Location H2S Level SO2 Level

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

PLUME TRACKING AND MONITORING Forms Pipeline Operations Manual

Forms Page - 22

Notes:

SPILL REPORT Forms Pipeline Operations Manual

Forms Page - 23

INITIAL REPORTING OF SPILL

Spill Detected By (Name and Phone #): ___________________________________________________________________________

Date: ___________________ Time: _______________ Area: ________________________________________________________

Spill Location Legal Description: LS ____ SC ____ TP ____ RG ____ W ____

Management Person Reported To: ______________________________________________________________________________

Date: ______________ Time: _______________

PIPELINE INFORMATION

From: ______________________________________________ To: __________________________________________________

Outside Diameter: ____________________________________ Wall Thickness: ________________________________________

M.O.P.: _____________________________________________ Material: _____________________________________________

Material Type: _______________________________________ Material Grade: ________________________________________

Line Installation Date: _________________________________ Number of Previous Leaks: _______________________________

Protection (e.g. Cathodic): _____________________________________________________________________________________

Type of Line: ___ Flowline ___ Transfer ___ Inj/Disp ___ Condensate ___ Pipeline ___ Fresh Water ___ Produced Water

EQUIPMENT FAILURE INFORMATION

___ Production Storage Tank ___ Pig Launcher/Receiver ___ Flow Line Break

___ Drilling/Servicing Storage Tank ___ Flange Gasket ___ Block Valve

___ Other (please specify): ______________________________________________________

Cause: ___ Corrosion ___ Mechanical Failure ___ Human Error ___ Vandalism ___ Test Failure

PRODUCT SPILLED/RECOVERED

___ Crude Oil Estimated Volume Spilled: ______________m3 Recovered: ______________m3

___ Salt Water Estimated Volume Spilled: ______________m3 Recovered: ______________m3

___ Chemical Estimated Volume Spilled: ______________m3 Recovered: ______________m3

___ Oil Effluent Estimated Volume Spilled: ______________m3 Recovered: ______________m3

___ Fresh Water Estimated Volume Spilled: ______________m3 Recovered: ______________m3

CONTAINMENT

___ Naturally ___ Booms ___ Dikes ___ No Containment ___ Other (Please Specify): __________________________________

AFFECTED LANDOWNERS/RESIDENTS

Name: __________________________________________ Date/Time: _____________________ Phone: _________________






Forms Page - 24

PROVINCIAL OIL & GAS AUTHORITY REPORTED TO

AER Office Location: _________________________________________________ Date: __________________

Person Reported To: _________________________________________________

ECON Office Location: ________________________________________________ Date: __________________


MIEDM Office Location: _______________________________________________ Date: __________________


BCOGC Office Location: _______________________________________________ Date: __________________


SPILL AREA SKETCH

Directions to spill site area: _____________________________________________________________________________________

____________________________________________________________________________________________________________

____________________________________________________________________________________________________________

____________________________________________________________________________________________________________

____________________________________________________________________________________________________________

Surface Feature Affected (choose up to 3): ___ Cultivated ___ Uncultivated ___ Bush ___ Surface Water ___ Groundwater ___ Access ___ Other ______________

Size of Area Affected (fill in one): _________________________ Square Meters ___________________________ Hectares

Total Area Affected: ____________________________________ % on lease ______________________________ % off lease

Soil Amendment: Type: ___________________________________________ Amount: ___________________

NORTH


Forms Page - 25

Comments (include reason for failure):

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

REPAIRS AND RESTORATION

Oil & Gas Regulatory Authority Notified: ___ Yes ___ No Date: _________________ Time: ____________

Landowners/Residents Notified: ___ Yes ___ No Date: _________________ Time: ____________

Contaminated Material Disposed of: ___ Yes ___ No Date: _________________ Time: ____________

Environmental Consultant: _________________________________________

SITE DAMAGE SUMMARY

Damage incurred to environmentally sensitive areas such as lakes, streams, dugouts, etc. (include sketch and show details):

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

Describe other damages such as buildings, equipment, third party property, etc:

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

Describe any injury in connection with the event:

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________


Forms Page - 26

ACTION TAKEN

Remediation strategy and repair strategy. Include details on where material was taken (Facility Name, Landfill, etc.). Comment

regarding the action taken to repair damage (e.g. Dug up and repaired 2 metres of line then backfilled.)

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

___________________________________________________________________________________________________________

REMEDIAL WORK COMPLETION

Oil & Gas Regulatory Authority Office Notified: ___ Yes Date: ______________________

Landowner(s)/Resident(s) Notified: ___ Yes Date: ______________________

Sketch completed and attached to report: ___ Yes Date: ______________________

Cleanup Costs to Date: $ _________________. ____

Estimated Project Remediation Cost: $ _________________. ____

Report Prepared By: _______________________________________ Phone: ___________________ Date: ___________________

VALVE SUMMARY Forms Pipeline Operations Manual

Forms Page - 27

UPI LSD VALVE TYPE STATUS

VALVE SUMMARY Forms Pipeline Operations Manual

Forms Page - 28

UPI LSD VALVE TYPE STATUS

CROSSING SUMMARY Forms Pipeline Operations Manual

Forms Page - 29

UPI LSD CROSSING TYPE AGREEMENT REFERENCE

CROSSING SUMMARY Forms Pipeline Operations Manual

Forms Page - 30

UPI LSD CROSSING TYPE AGREEMENT REFERENCE

GROUND DISTURBANCE PERMIT / CHECKLIST

Forms Pipeline Operations Manual

Forms Page - 31

GROUND DISTURBANCE PERMIT / CHECKLIST


Forms Page - 32

BACKFILL INSPECTION FORM


Forms Page - 33

1. Indicate depth to existing line on above elevation. 2. Indicate depth to new line above or below existing line on above elevation. 3. Cathodic protection installed: Yes No

If yes, what type of protection? _____________________________________________________________________ 4. If pipe contacted, provide the following details:

Coating damage: Yangarra Other Coating repairs completed:_________________________________________________________________________ Pipe/cable damaged: Yangarra Other Regulatory Agency contacted? ______________________ Name: ________________________ Date: ____________

5. Wire color/Size existing line: _______________ / _______________ New line: _______________ / _______________ Owner of foreign or existing facility:

Size and condition of existing facility:

(New) oil, gas, water, etc.:

Contractor doing work:

Approval Print name:

Date completed: Yangarra Signature:

Print name:

Date completed: Foreign Signature:

Date: ________________________

Project: _________________________________________

Yangarra Line ID#: _________________________________

Size: __________________ (indicate unit of measurement)

Location:

LSD _____ Sec _____ Twp _____ Rge _____ W _____M

Other:

Type of New Facility Type of Crossing (check one) (check one) Pipeline Pipeline Road Road Railroad Railroad Watercourse Watercourse Data Cable Data Cable Other Other

BACKFILL INSPECTION FORM


Forms Page - 34

THIRD PARTY PIPELINE INSPECTION REPORT


Forms Page - 35

Pipeline System Description: ___________________________________________________________________ Pipeline Licence Number(s): ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________ Date of Inspection: ___________________________________________________________________ Distance of Pipeline: ___________________________________________________________________ Method / Equipment Used: ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________ Results / Observations: ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________ Engineering Evaluation: ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________ ___________________________________________________________________

THIRD PARTY PIPELINE INSPECTION REPORT


Forms Page - 36

RECOMMENDATIONS: IMPLEMENTATION PLAN:

REPAIR LOG


Forms Page - 37


REPAIR LOG


Forms Page - 38


PIPELINE CROSSING CHECKLIST Forms Pipeline Operations Manual

Forms Page - 39

Licence & Line#: ____________________ Date: ___________________________

By: ________________________________________________________________

Pipeline Owner: ______________________________________________________

Location: _________________________ Date: ___________________________ (Attach sketch if necessary)

Contractor: __________________________________________ Date: ___________________________

1. Is a copy of the Pipeline Crossing Agreement at the site? Yes No 2. Are construction drawings at the site? Yes No 3. Was 48 hours notice given to Yangarra? Yes No

If No, explain: _____________________________________________________________________

Date notice given: _____________________ Person notified: _________________________

4. Was the Yangarra pipeline hand exposed or hydro-vac for the 1 meter on either side of the crossing prior to machine excavation? Yes No

5. Was a Yangarra representative present during pipe exposure? Yes No

6. Yangarra pipeline located by (Name): ___________________________________________________

7. Foreign pipeline maintained at 30 cm below the Yangarra pipeline through right-of-way? Yes No Depth of separation (if other than 30 cm): Yes No 8. Backfill free of rocks, debris, etc.? Yes No 9. Backfill tamped properly? Yes No 10. Was the Yangarra pipeline and/or coating damaged? Yes No If Yes, were proper repairs completed? Yes No 11. If a cathodic test post was specified, was it installed? Yes No

Location: _________________________________________________________________________

12. Remarks: _________________________________________________________________________

Notes: Items 1,2,4,7,8, and 9 are MANDATORY

This certifies that this crossing was performed to Yangarra satisfaction.

Contractor: ____________________ _______________________ ____________________ (Signature) (Print) (Date)

Foreign

Pipe Owner: ____________________ _______________________ ____________________

(Signature) (Print) (Date)

Yangarra

Representative: ____________________ _______________________ ____________________

(Signature) (Print) (Date)

PIPELINE CROSSING CHECKLIST Forms Pipeline Operations Manual

Forms Page - 40

NEW WELL START UP FORM Forms Pipeline Operations Manual

Forms Page - 41

NEW WELL START UP FORM

SURFACE LOCATION_________________________ DATE______________________

DOWNHOLE LOCATION______________________

PIPELINE LICENCE/LINE #_____________________ MOP_______________________

VESSEL A#_________________________________ PSV SN#____________________

VESSEL MOP_______________________________ PSV SET PRESSURE___________

CALIBRATION DATE___________________

OVERPRESSURE DEVICE: YES / NO ESD SET PRESSURE___________

CALIBRATION DATE___________________ FUNCTION TESTED: YES / NO

ESD TAGGED PROPERLY: YES / NO

*****NOTE ***** PSV SET PRESSURE AND ESD SET PRESSURE CANNOT EXCEED THE MOP OF THE PIPELINE

COMMENTS:_______________________________________________________________________

__________________________________________________________________________________

__________________________________________________________________________________

__________________________________________________________________________________

PREFORMED BY:________________________________________________________(PRINT/SIGN)

NEW WELL START UP FORM Forms Pipeline Operations Manual

Forms Page - 42

ORGANIZATION

Pipeline Integrity, Operations, and Maintenance Organizational Structure

Role Responsibilities Assigned to Title

Pipeline Integrity and Operations Manual - Development and improvement

• Research and review government acts, regulations, directives as it applies to the manual. • Research and review industry standards and best practice.

DataSafe Recovery Services Account Manager

Pipeline Integrity and Operations Manual - Annual review (minimum)

• Continuous improvement to licensed materials to maintain compliance. • Verification of external contact information. • Update changes related to Client’s corporate information, personnel and contact numbers as provided by the Client. • Update changes related to field inventories, contractors/suppliers, safety equipment, and risk assessments as provided by the client.

DataSafe Recovery Services Account Manager

Pipeline Integrity and Operations Manual - Maps • Update changes related to field. DataSafe Recovery Services Account Manager

Integrity Management Program - Implementation of plans • Ensure company personnel have access to, and are implementing the Pipeline Integrity and Operations Manual.

Company Office Rep

VP Finance Trish Olynyk Senior Engineers Ryan MacKenzie Thomas Matthews

Daily operations and general maintenance of pipelines • It is the responsibility of company field personnel to ensure that pipelines are operated, and maintained to meet requirements of provincial legislation, industry standards and codes of practice.

Company Field Personnel Field Superintendent Collin Doneff


Integrity Management Program - Risk assessment and control planning

• Includes the steps of risk analysis (hazard identification, frequency analysis, consequence analysis, risk estimation) and risk evaluation (risk significance and options). • Risk assessment is applicable to the decision-making process in the design, construction, operation, inspection, monitoring, testing, maintenance, repair, modification, rehabilitation, and abandonment of pipelines. • The Pipeline Assessment process must be performed at least annually on every pipeline segment. When risks are identified more frequent assessment is required and the schedule must be documented.

Company Field Personnel Company Office Personnel

Field Superintendent Collin Doneff Senior Engineer Ryan MacKenzie

Integrity Management Program - Integrity performance indicators • Plan and develop method of monitoring to identify anticipated and actual changes that could affect the integrity of the pipeline system.



Chemical inhibitor program for pipelines (if applicable) • Determine the chemical inhibitor programs required to ensure the integrity and extend the life expectancy of the pipeline.


Cathodic maintenance of pipelines (if applicable)

• Will apply cathodic protection systems to all metal pipelines, metal underground piping and any other metal appurtenances in direct contact with the surrounding soils. • Ensuring the design, operation, inspection and maintenance of cathodic protection are handled appropriately.



Integrity Management Program - Inspections, testing, patrols, and monitoring

• Implement and document the methods and procedures used to conduct inspections, testing, patrols, and monitoring. Consideration shall be given to:(a) cathodic protection systems;(b) corrosion monitoring systems and devices;(c) leak detection methods and devices;(d) shutdown devices and systems;(e) pressure-control, pressure-limiting, and pressure-relieving systems;(f) size, location and operational position of pipeline system valves;(g) pipeline system patrolling; and(h) inspection of exposed piping for corrosion and other types of imperfections



Integrity Management Program - Evaluation of inspection, testing, patrol, and monitoring results

• Assess inspection, testing, patrol, and monitoring results. • When inspection, testing, patrol, and monitoring results indicate the presence of conditions or imperfections that might lead to failure or damage incidents with significant consequences, operating companies shall perform an engineering assessment.



Pipeline / Facility Engineer

• An important component of integrity management is that appropriate personnel are contacted and involved prior to undertaking new construction or when change is made to the operating condition of a pipeline. The first step to new construction and significant changes is usually an Engineering Assessment. Engineering Assessments are an integral component of the change management process. • An engineering assessment may also be required as the result of pipeline inspection and monitoring results.

Company Office Personnel Senior Engineers Ryan MacKenzie Thomas Matthews

Repair work for pipelines

• Maintenance and Repair activities will require involvement of production and operations and staff and management. In many cases contracted services personnel and engineers will also be needed.



Land department • Determine land owner contacts if need be during the course of maintenance and repair, or any other applicable activities.

Company Office Personnel Surface Land Administrator Kelsey Lewis

Integrity Management Program - Audits, reviews, and evaluations

• Reviewing completed integrity activities in order to: (a) verify that the relevant methods and procedures for such activities were properly performed; (b) verify that changes in planned activities were reviewed and approved; (c) determine whether the intended objectives were achieved; (d) identify incomplete work and unresolved issues; (e) develop recommendations and plans for future work; and (f) verify that the relevant records were created or revised.

Company Office Personnel Senior Engineer Ryan MacKenzie

Integrity Management Program - Records management

• Manage the responsibilities and procedures for the creation, updating, retention, and deletion of records. • Develop methods of storage and retrieval of records related to a particular pipeline location or segment. • Track evidence of past activities, events, changes, analyses, and decisions. • Create an index describing the types, forms, and locations of records.

Company Office Personnel

Surface Land Administrator Kelsey Lewis Senior Engineer Ryan MacKenzie

VALVES AND CROSSINGS

EMERGENCY RESPONSE

EMERGENCY RESPONSE

General Information Pipeline Operations Manual

General Information Page - 1

EMERGENCY RESPONSE

General

The company’s Emergency Response Plan (ERP) must be invoked when an emergency occurs. The ERP

provides detailed response actions, notification procedures, reporting requirements and reference

information to appropriately respond to the incident.

Several forms in this document are from the Emergency Response Plan manual. They have been identified

in red bold italics in the Table of Contents of the forms section. Use of these forms must coincide with

reference to the ERP to ensure appropriate notification and reporting.

This document contains a copy of the Emergency Contact List created for the ERP. It is included to ensure

that initial immediate contact can be made with appropriate head office and field personnel. The ERP must

be invoked to ensure that subsequent activities are coordinated effectively.

You are the On-Scene Commander until the Incident Commander chooses an alternate.

Contact Information - Company Contacts FERRIER

Corporate Office Responsible for Field Operations


Head OfficeOffice:

(403) 262-9558Phone Number:

(403) 262-8281Fax Number:

(403) 262-955824 hr Emergency Phone:

Site Office for Field Operations


(403) 845-6877Phone Number:

Fax Number:

(403) 580-763824 hr Emergency Phone:

Incident/Corporate Commander

Seq Other Ph TypeTitle Office Phone Home Phone Cell Phone Other PhoneName

1 President (403) 262-9558 (403) 697-4911 (403) 803-5161Jim Evaskevich

2 VP Operations (403) 262-9558 (403) 771-2474Lorne Simpson

Operations Section Chief


1 Field Superintendent (403) 580-7638Collin Doneff

2 Production Foreman (403) 895-3797Mitch Hetu

3 Operator (403) 844-3316Brad Dukart

4 Operator (403) 826-8340Ryan Fancie

5 Operator (403) 844-7042Jeff Gramlich

6 Operator (403) 844-0464Mike Rainer

7 Operator (403) 895-7113Logan Lawton

8 Operator (403) 845-9753Brady Poulsen

9 Operator (403) 895-8489Myles McGinnis

10 Fluid Manager (403) 895-2501Chris Carlson

11 Crew Supervisor (403) 845-8968Billy Normile

Media Relations


President (403) 262-9558 (403) 697-4911 (403) 803-5161Jim Evaskevich

1530, 715 - 5th Avenue S.W.

Calgary, AB

T2P 2X6

Office Address:

Ferrier Field OfficeOffice:

Rocky Mountain House, AB

Office Address:

Monday, June 15, 2020

YANGARRA RESOURCES LTD. Page 1 of 2

This page intentionally left blank



FERRIERContact Information - Emergency Contacts

Local Authorities Contact Information

CountyCLEARWATER

Christine Heggart

(DEM)

Cell

Manager On-call Cell

Name Business

Phone

Area Authority: þ911 Avail

(403) 845-4444Area Office Phone: (403) 845-7330Area Office Fax:

24 hour Number (403) 844-8500

(403) 845-4444 (403) 844-8500

(403) 844-8500

Area Office Alternate Phone:

Area Emergency Liaison Officers:

Alternate

Phone

Alternate Contact:

CountyMOUNTAIN VIEW

Ryan Morrison Cell

Kevin Heppler Cell

Name Business

Phone


(403) 335-3311Area Office Phone: (403) 335-9207Area Office Fax:

(403) 335-3311

(403) 335-3311

(403) 586-0040

(403) 994-0834



Alternate

Phone

Alternate Contact:

CountyPONOKA

Dennis Jones (DEM &

Regional Fire Chief)

Cell

Charlie Cutforth (Deputy

DEM)

Cell

Name Business

Phone


(403) 783-3333Area Office Phone: Area Office Fax:

(403) 783-3333

(403) 783-3333

(403) 913-5105

(403) 783-0995



Alternate

Phone

Alternate Contact:

Nearest Municipalities with Services

ROCKY MOUNTAIN HOUSE





Emergency Tel Dispatch Location

(403) 845-2866Office Phone:

(403) 845-3230Fax:

- 911 -Fire

- 911 -Ambulance

(403) 845-2881

(403) 845-3347Hospital

(403) 347-3373

(403) 845-2882Police

(780) 786-2223

Admin Tel

(403) 845-3347

First contact to emergency services will be to call 911. The nearest Urban

Centre with all emergency services is Rocky Mountain House.

Primary Emergency Services

Responding Centre:



Company Type of Service City Phone

FERRIERSupport Services

Trojan Safety Services Air Monitoring Sylvan Lake (403) 309-3025

Summit Safety Air Monitoring and H2S Safety Drayton Valley (780) 542-9191

Nelson Bros Oilfield Services

(1997) Ltd

Water Hauling Drayton Valley (780) 542-5777

Wrangler Rentals Water Trucks Leduc (780) 980-1331

Hellfire Suppression Services Well Control Rocky Mountain House (403) 846-4499


PIPELINE ASSESSMENT

Oil Gas Water

3 90 0

3 10 0

0 1 0

1 47 0

155

Oil Gas Water

146 6 1

4 3 0

7 0 0

3 0 0

170

71

1

36

119

0

66

2020

2020

Operator: Brad Dukart (403) 844-3316

Field: Willesden GreenOperator:

Head Office: Colin Doneff (403) 580-7638

Account Manager:

District Manager: Trent Elgert (780) 312-4896

Prepared by: Wally Hartung (780) 352-2436

within LSD area: 042-07W5Main Facility: 02-04-042-07W5

# of wells found:

Pipelines

# of lines Operational:

# of lines disc.:

# of lines abandoned:

# of planned lines:

# of lines found:

Wells

# of operating wells:

# of susp. wells:

# of shut in wells:

# of abandoned wells:

Supplied gas analysis were performed on:

Water analysis was performed on:

This document contains CONFIDENTIAL information of Contact Chemicals and is revealed for limited purposes only. It may not be reproduced, used or disclosed to persons not having a need to know consistent with the purpose of the document without the written consent of

Contact Chemicals. Contact Chemicals disclaims all warranties or representations express or implied, including any implied warranties of merchantability or fitness for particular purpose or the accuracy, correctness or completeness of such information herein or that reliance on

such information will accomplish any particular result. All such information is furnished “as is” and by using such information the user is assuming all liabilities for the use or reliance on such information.

This assessment is based on information given by the client and ABADATA 2.0 . Contact Chemicals takes no responsibility on the accuracy of the data. The assessment of the above stated field's assets are based on internal, proprietary risk factors, it should NOT be used as a

replacement for engineering assessments, a client's PIMP and/or KPI.

CONTACT CHEMICALS SHALL NOT BE LIABLE FOR ANY INDIRECT, SPECIAL, PUNITIVE, EXEMPLARY OR CONSEQUENTIAL DAMAGES OR LOSSES FROM ANY CAUSE WHATSOEVER INCLUDING BUT NOT LIMITED TO NEGLIGENCE.

# of Batteries found:

# of satellites found:

lines with low risk:

lines with medium risk:

lines with high risk:

lines requiring treatment:

General comments and concerns: The Willesden Green field has a medium potential corrosion risk divided into 36 low and 119 medium risk line segments. 75 line segments are recommended to be treated due to various risks, such as environmental and/or operating factors.No lines were identified as deadlegs.The gas and water analysis showed that this field's production has low corrosivity however, due to the high production and velocities corrosion may yet still occurr. In addition to the low corrosivity of the gas and fluids, most of this field's steel linesare being pigged monthly.

This field is currently monitored via 4 corrosion coupon located at the inlets of the main facilities: 02-04, 16-02 and 06-02

02-04

AER

License

from

location

to

location

Physical

Risk

Operational

Risk

Chemical

Risk

Theoratical

Corr. Rate

(mpy)

Overall

Risk

Treat

Pipe(yes/no)

Treatment

ReconciliationComments

19415 - 2 8-23-40-6W5 B 6-19-40-5W5 PL 2.5 1.6 2.3 4.82 2.1 no review risks annually

42289 - 7 2-4-42-7W5 CS 10-33-41-7W5 PL 2.6 1.9 2.3 10.03 2.2 no review risks annually sales gas from 02-04

42289 - 8 10-4-42-7W5 BE 11-4-42-7W5 BE 2.3 1.7 1.7 10.03 1.9 no review risks annually

42289 - 10 5-11-42-7W5 WE 4-10-42-7W5 PL 2.6 1.9 2.3 no fluid 2.3 no review risks annually

43702 - 2 11-4-42-7W5 WE 2-4-42-7W5 CS 2.5 1.9 2.3 no fluid 2.2 no Line is not operated

43702 - 3 6-3-42-7W5 WE 2-4-42-7W5 CS 2.6 1.9 2.3 no fluid 2.3 no Environmental risk

43702 - 4 12-29-41-7W5 WE 7-29-41-7W5 PL 2.6 1.7 2.4 Deadleg 2.2 yes Environmental risk

43702 - 8 1-33-41-7W5 WE 10-33-41-7W5 PL 2.6 2.4 2.3 14.67 2.4 no review risks annually

44436 - 1 14-22-41-7W5 BE 11-21-41-7W5 BE 2.2 1.7 1.7 no fluid 1.9 no review risks annually


47376 - 3 4-4-40-8W5 PL 11-33-39-8W5 PL 2.1 1.8 2.0 8.23 2.0 no review risks annually

47376 - 4 4-33-39-8W5 PL 11-33-39-8W5 PL 2.0 1.4 2.0 14.67 1.8 no Environmental risk


48160 - 1 13-20-41-7W5 WE 15-20-41-7W5 PL 2.6 1.8 2.3 14.67 2.2 no Environmental risk

48695 - 1 13-19-40-6W5 BE 2-30-40-6W5 BE 2.3 1.7 1.7 Deadleg 1.9 no Environmental risk

53228 - 1 13-31-37-7W5 BE 12-31-37-7W5 BE 2.2 1.7 1.7 no fluid 1.9 no Line is not operated

53316 - 1 4-28-41-7W5 WE 4-28-41-7W5 PL 2.4 1.8 2.3 no fluid 2.1 yes Line is not operated


53453 - 2 12-16-41-7W5 WE 13-16-41-7W5 PL 2.4 1.8 2.3 no fluid 2.1 yes Multiple risks

53932 - 1 1-35-37-8W5 WE 3-34-37-8W5 PL 2.5 1.6 2.3 no fluid 2.1 no review risks annually sales gas from 16-02

55029 - 2 16-2-38-8W5 B 16-35-37-8W5 PL 2.5 1.8 2.3 10.03 1.6 no Not a bare steel pipeline proximity to Cow Lake; sales gas from 16-02

55029 - 3 15-35-37-8W5 WE 16-35-37-8W5 PL 2.3 2.3 2.3 no fluid 1.7 yes Not a bare steel pipeline

55029 - 4 2-2-38-8W5 WE 15-35-37-8W5 PL 1.9 1.8 2.3 no fluid 2.0 no Line is not operated

55030 - 1 3-34-37-8W5 PL 1-33-37-8W5 PL 2.4 1.9 2.3 14.67 2.2 no review risks annually sales gas from 16-02

55063 - 1 16-35-37-8W5 PL 1-35-37-8W5 PL 2.5 1.9 2.3 no fluid 2.2 no Line is not operated sales gas from 16-02



55895 - 1 4-7-39-5W5 WE 13-6-39-5W5 PL 2.3 1.7 2.3 no fluid 2.1 yes Identified parameter risk



56261 - 1 3-28-41-7W5 WE 4-28-41-7W5 PL 2.3 1.8 2.3 no fluid 2.1 yes Multiple risks







58419 - 2 14-18-41-5W5 WE 2-19-41-5W5 PL 2.0 1.8 1.7 no fluid 1.9 no Environmental risk treated via injection at 14-18


58743 - 1 3-21-41-7W5 WE 13-16-41-7W5 B 2.1 2.3 2.3 14.67 2.2 no review risks annually



59260 - 1 6-2-40-9W5 BE 1-2-40-9W5 BE 1.7 1.7 2.3 14.67 1.3 no Not a bare steel pipeline




59552 - 1 4-4-40-8W5 WE 4-4-40-8W5 PL 1.9 2.2 2.0 14.67 2.0 no review risks annually lines has been discontinued


59787 - 1 3-2-42-8W5 WE 6-2-42-8W5 PL 1.5 1.7 2.3 14.67 1.8 no Environmental risk








59959 - 2 15-7-41-6W5 WE 15-7-41-6W5 PL 2.0 2.1 2.3 9.32 1.5 no Not a bare steel pipeline








60006 - 1 6-2-40-9W5 B 3-2-40-9W5 PL 2.1 1.8 2.0 9.32 2.0 no Environmental risk sales gas from 06-02





60221 - 2 7-27-41-7W5 PL 3-27-41-7W5 PL 1.6 1.4 2.3 1.2 no Not a bare steel pipeline





60311 - 1 7-30-37-7W5 PL 6-25-37-8W5 PL 2.1 2.0 2.3 14.67 1.5 no Not a bare steel pipeline

60311 - 2 16-8-37-7W5 WE 10-18-37-7W5 PL 2.2 1.4 2.3 1.3 no Not a bare steel pipeline


60520 - 1 9-31-37-7W5 PL 16-35-37-8W5 PL 2.6 1.7 2.3 14.67 2.2 no review risks annually treated via injection at 03-23




59996 - 1 1-29-43-9W5 WE 6-21-43-9W5 B 1.5 1.7 2.3 1.2 no Not a bare steel pipeline

45437 - 1 7-14-43-3W5 BE 6-23-43-3W5 BE 1.8 1.7 2.3 14.67 1.3 no Not a bare steel pipeline

53737 - 1 2-14-43-3W5 BE 7-14-43-3W5 BE 1.7 1.7 2.3 Deadleg 1.3 no Not a bare steel pipeline


60062 - 4 12-20-37-7W5 B 16-19-37-7W5 PL 1.8 2.1 2.3 10.03 2.1 no review risks annually



31390 - 2 11-33-39-8W5 PL 9-36-39-9W5 PL 2.8 1.9 2.0 14.67 2.2 yes main gathering line treated via injection at 04-04

31390 - 3 3-36-39-9W5 PL 9-36-39-9W5 PL 2.7 1.8 2.0 10.03 1.6 yes Not a bare steel pipeline proximity to North Sakatchewan River

42289 - 9 2-15-42-7W5 WE 4-10-42-7W5 PL 2.6 1.9 2.3 10.03 2.2 yes Multiple risks

43702 - 1 11-21-41-7W5 WE 7-29-41-7W5 PL 2.6 1.9 1.8 10.03 1.5 yes main gathering line treated via injection at 11-15 & 16-25

43702 - 5 7-29-41-7W5 PL 12-33-41-7W5 PL 2.7 1.9 1.9 14.67 1.5 yes Not a bare steel pipeline treated via injection at 11-15 & 16-25; Big Beaver Crossing

43702 - 6 12-33-41-7W5 PL 2-4-42-7W5 CS 2.6 1.9 1.8 9.34 1.5 yes main gathering line treated via injection at 11-15 & 16-25

43702 - 7 8-19-41-7W5 WE 7-29-41-7W5 PL 2.7 1.8 2.3 10.03 1.7 yes Not a bare steel pipeline proximity to North Saskatewan River

46735 - 2 5-20-41-7W5 WE 8-19-41-7W5 PL 2.4 1.8 2.3 10.03 1.6 yes Not a bare steel pipeline proximity to North Saskatewan River

47376 - 1 4-4-40-8W5 WE 11-33-39-8W5 PL 2.6 1.8 2.0 14.67 2.2 no main gathering line treated via injection at 04-04 (inj based on surface)


52347 - 1 8-3-41-7W5 WE 11-21-41-7W5 PL 2.7 2.1 2.4 14.67 2.4 yes Identified parameter risk partially treated via injection at 11-15 & 16-25 (1km will be batched)

52347 - 2 13-35-40-7W5 WE 8-3-41-7W5 PL 2.5 2.0 2.4 14.67 1.7 yes part of pig run batch volume includes appr. 1km of the 52347-1 segment

52744 - 2 5-31-37-7W5 WE 12-31-37-7W5 PL 2.4 1.9 2.3 14.67 1.6 no part of pig run Combined with 60520-2

53385 - 1 8-30-41-7W5 WE 12-29-41-7W5 PL 2.5 1.8 2.3 14.67 2.2 yes Multiple risks proximity to North Saskatewan River

53453 - 1 13-16-41-7W5 WE 4-28-41-7W5 PL 2.5 1.8 2.3 14.67 2.2 yes Environmental risk proximity to Little Beaver Creek

53453 - 3 15-20-41-7W5 WE 15-20-41-7W5 PL 2.4 1.9 2.3 10.03 2.2 no part of pig run

54016 - 1 3-11-38-8W5 WE 3-11-38-8W5 PL 2.4 1.8 2.3 10.03 1.6 yes Not a bare steel pipeline proximity to Cow Lake; combined with 54970

54571 - 1 1-9-41-7W5 WE 16-9-41-7W5 PL 2.5 1.8 1.7 10.03 2.0 yes Identified parameter risk

54970 - 1 3-11-38-8W5 PL 16-2-38-8W5 B 2.5 1.8 2.3 14.67 2.2 yes Multiple risks proximity to Cow Lake; combined with 54016

55029 - 1 16-35-37-8W5 PL 16-2-38-8W5 B 2.5 1.8 1.8 no fluid 2.1 yes Line is not operated proximity to Cow Lake

55033 - 1 15-26-37-8W5 WE 1-35-37-8W5 PL 2.3 2.4 2.3 14.67 2.3 yes main gathering line

55270 - 1 4-12-41-7W5 WE 1-11-41-7W5 PL 2.3 1.9 2.3 2.1 yes main gathering line

55273 - 1 1-11-41-7W5 WE 1-10-41-7W5 PL 2.4 1.8 2.3 14.67 2.1 yes Multiple risks

56545 - 1 13-31-41-7W5 WE 2-31-41-7W5 PL 2.5 1.8 2.3 9.34 2.2 yes Multiple risks proximity to Big Beaver Creek

57486 - 1 13-11-41-7W5 WE 8-10-41-7W5 PL 2.0 1.8 2.3 9.34 2.0 yes part of pig run

57591 - 1 1-35-37-8W5 WE 1-35-37-8W5 PL 2.3 2.1 2.3 14.67 1.6 no part of pig run

57601 - 1 2-35-37-8W5 WE 1-35-37-8W5 PL 2.3 1.9 2.3 no fluid 2.1 yes combines prod. from multple wells

58050 - 1 4-14-42-8W5 WE 10-15-42-8W5 S 2.5 1.8 2.3 9.34 2.2 yes Identified parameter risk Proximity to North Saskatchewan River; Combined with 58050-2,3,4,5

58050 - 2 10-2-42-8W5 WE 14-2-42-8W5 PL 2.2 1.8 2.3 1.5 yes Not a bare steel pipeline Proximity to North Saskatchewan River; Combined with 58050-1,3,4,5

58050 - 3 14-2-42-8W5 PL 14-2-42-8W5 PL 2.2 1.8 2.3 no fluid 1.5 yes Not a bare steel pipeline Proximity to North Saskatchewan River; Combined with 58050-2,1,4,5

58050 - 4 14-2-42-8W5 PL 4-11-42-8W5 PL 2.2 1.8 2.3 10.03 2.1 yes Identified parameter risk Proximity to North Saskatchewan River; Combined with 58050-2,3,1,5

58050 - 5 4-11-42-8W5 PL 4-14-42-8W5 PL 2.5 1.8 2.3 9.34 1.6 yes Not a bare steel pipeline Proximity to North Saskatchewan River; Combined with 58050-2,3,4,1

58515 - 1 16-25-39-7W5 WE 6-12-40-7W5 PL 2.5 1.8 2.3 10.03 2.2 yes Multiple risks combined with 58515-2,3; treated via injection at 16-25

58515 - 2 14-13-40-7W5 PL 4-12-41-7W5 PL 2.6 1.8 2.3 14.67 2.2 yes Environmental risk combined with 58515-1,3; treated via injection at 16-25

58515 - 3 11-12-40-7W5 PL 14-13-40-7W5 PL 2.3 1.8 2.3 no fluid 1.5 yes Not a bare steel pipeline combined with 58515-2,1; treated via injection at 16-25

59079 - 1 6-25-37-8W5 PL 7-26-37-8W5 PL 2.4 2.1 2.3 no fluid 1.6 yes part of pig run

59259 - 1 15-31-41-5W5 WE 16-31-41-5W5 PL 2.2 2.1 2.3 no fluid 1.6 yes deadleg? confirm operating status

59587 - 1 4-1-40-9W5 WE 1-2-40-9W5 PL 2.4 1.9 2.0 no fluid 1.5 yes main gathering line treated via injection at 04-04

59891 - 1 4-12-41-7W5 WE 1-10-41-7W5 PL 2.3 1.9 2.3 no fluid 1.5 yes main gathering line treated via injection at 11-15 & 16-25

59916 - 1 14-6-40-8W5 PL 9-2-40-9W5 PL 2.4 1.7 2.0 14.67 2.1 yes main gathering line Combined with 59970 & 60045



59959 - 6 11-15-41-6W5 WE 8-16-41-6W5 PL 2.4 1.8 2.3 no fluid 1.5 yes main gathering line treated via injection at 11-15

59959 - 7 8-16-41-6W5 WE 4-16-41-6W5 PL 2.4 1.8 2.3 14.67 1.5 yes Not a bare steel pipeline treated via injection at 11-15

59970 - 1 11-6-40-8W5 WE 14-6-40-8W5 PL 2.2 1.7 2.0 no fluid 1.4 yes main gathering line Combined with 59916 & 60045

59976 - 1 1-2-40-9W5 WE 6-2-40-9W5 B 2.2 1.8 2.0 14.67 1.4 yes main gathering line treated via injection at 04-04

59986 - 1 3-23-38-7W5 WE 12-14-38-7W5 PL 2.5 1.8 2.3 14.67 2.2 yes main gathering line proximity to Clearwater Creek; treated via injection at 03-23

59986 - 3 12-14-38-7W5 PL 13-10-38-7W5 PL 2.4 1.8 2.3 no fluid 2.2 yes Multiple risks crosses Clearwater Creek; treated via injection at 03-23

59986 - 4 9-15-38-7W5 B 12-14-38-7W5 PL 2.4 1.8 1.7 14.67 2.0 no main gathering line proximity to Clearwater Creek; treated via injection at 03-23

59986 - 5 12-14-38-7W5 PL 9-15-38-7W5 B 2.4 1.8 2.3 14.67 2.1 yes main gathering line proximity to Clearwater Creek; treated via injection at 03-23

59986 - 7 1-9-38-7W5 WE 5-10-38-7W5 PL 2.3 1.7 2.3 14.67 2.1 yes main gathering line treated via injection at 03-23

59986 - 8 5-3-38-7W5 WE 4-10-38-7W5 PL 2.3 1.7 2.3 14.67 1.5 yes part of pig run

59986 - 9 13-10-38-7W5 PL 5-10-38-7W5 PL 1.9 1.7 2.3 14.67 2.0 yes Identified parameter risk treated via injection at 03-23


60045 - 1 9-2-40-9W5 PL 8-2-40-9W5 PL 2.3 1.7 2.0 14.67 1.4 yes main gathering line Combined with 59916 & 59970

60062 - 1 7-18-37-7W5 PL 7-30-37-7W5 PL 2.8 2.0 2.3 no fluid 2.4 yes Line is not operated crosses Prairie Creek

60222 - 1 11-19-41-5W5 PL 15-15-41-6W5 PL 2.5 1.8 2.3 no fluid 2.2 yes main gathering line

60520 - 2 12-31-37-7W5 PL 12-31-37-7W5 PL 2.2 1.4 2.3 no fluid 2.0 yes main gathering line combined with 52744-2



60520 - 5 1-9-38-7W5 WE 3-5-38-7W5 PL 2.4 1.7 2.3 16.17 2.1 yes main gathering line crosses Prairie Creek; treated via injection at 03-23

54958 - 1 14-11-43-3W5 WE 2-14-43-3W5 B 1.9 2.1 2.3 16.97 1.5 yes deadleg?

60062 - 2 12-20-37-7W5 B 16-19-37-7W5 PL 2.0 1.8 2.3 17.80 1.4 yes new line cant find on ABADATA

60062 - 3 16-19-37-7W5 PL 12-20-37-7W5 B 2.1 1.8 2.3 18.67 1.4 yes new line

60311 - 8 13-10-037-07W5 13-01-037-07W5 3.3 1.5 2.3 no fluid 2.1 yes Environmental risk crosses the Prairie creek

60311 - 5 13-01-037-07W5 14-06-037-07W5 2.8 1.5 2.3 no fluid 2.0 yes new line

10-18-037-07W5 12-20-037-07W5 3.0 1.5 2.3 no fluid 2.0 yes new line

*Theoretical corrosion rates are calculated based on the DeWaard-Lotz model, marked lines are either coated or made out of none-steel components.

Risk Ranking: < 1.5 = low risk - no treatment required

1.5 to 2 = medium risk - treatment depending on client

2 to 2.5 = elevated risk - treatment recommended

2.5 to 5 = high risk - treatment is recommended

3 to 4 = severe risk -treatment is strongly recommended

4 to 5 = extreme risk - aggressive treatment is strongly recommended

Risk assessment and recommendation for the Willesden Green field

It is recommended to treat all line segments with an overall risk of 2.5 or greater. In circumstances such as environmental risk and/or high theoretical corrosion rates (>100 mpy) should be treated regardless of risk ranking.

oil emulsion or crude oil line on lease oil emulsion (no AER license) foreign 3rd party owned line

= Gas well = Water well natural gas line on lease gas line (no AER license) LVP line

Water line on lease water line (no AER license)

= Oil well = Misc. well

lease 42289-9 (4")

lease

42289-10 (4") discontinued 57873-2 (4") 06-03

04-10

lease

lease

lease 43702-2 (4")

42289-8 (4")

discontinued lease

43702-8 (3") 10-33 42289-7 (6") Sales Gas 53385-1 (3") lease

discontinued

lease

53316-1 (3")

lease 44436-1 (2") discontinued

lease 12-33 43702-6 (6") 12-29

43702-4 (4")

lease

lease 02-31 57873-1 (4") 08-32 43702-5 (6") 07-29 43702-1 (6") 43702-1 (6") 11-21 lease

04-28

60221-3 (3") M:Composite lease

07-27

lease 02-29 53368-1 (3") lease

lease

lease

lease 53453-3 (3") lease

lease 14-22 50315-37 (4")

15-20 InPlay Gas lease

lease

lease 08-19 43702-7 (4") 48160-1 (4") lease

50315-36 (4") 14-15

lease 58743-1 (3") InPlay Gas

lease M: Composite

lease


lease 54571-1 (4") 50315-35 (4") 11-15

46735-1 (3") discontinued InPlay Gas

lease

lease

48014-1 (4") 13-30 lease

lease discontinued lease 57486-1 (3") 08-10

C1218 @ 4L/d

lease 58515-1 (4") 11-12 58515-3 (4") 14-13 58515-2 (4")

59891-1 (4")

lease 59959-2 (3") M: Composite 15-07 59959-1 (6") 55270-1 (4") 55273-1 (4") 52347-1 (6") lease

01-10

lease leaes

53749-1 (3") 52347-2 (6")

Obsidian Gas lease

lease

lease 59530-1 (3") M: Composite 59959-4 (3") 02-17 58418-1 (3") 15-09 lease

15-08 M: Composite discontinued M: Composite

lease 59959-7 (6") lease 14-17 59941-1 (3")

M: Composite

lease lease lease

lease 59026-1 (3")

M: Composite

lease C1218 @ 9L/d

57466-1 (3") M: Composite

lease 58419-2 (3") 12-19 60222-2 (5") 11-19 60222-1 (6") lease 48436-1 (3")

M: Composite M: Composite 15-15 Baytex Gas

lease lease

lease 19415-2 (3") 06-19 06-02 59787-1 (3") M: Composite

lease 58419-1 (3") lease 08-23

M: Composite

lease 10-15 58050-1 (2") 04-14 58050-5 (2") 04-11 58050-4 (2") 14-02 58050-3 (2") 14-02 58050-2 (2")

10-02 lease

lease lease

lease 59556-1 (3") 10-36 13-06 55895-1 (3")

lease 60222-3 (5") M: Composite

M: Composite lease

59959-5 (3") M: Composite leaes

59259-1 (3") 16-31

lease 60222-4 (5") discontinued lease lease 56302-1 (3") 12-11 07-08 56048-1 (3")

M: Composite M: Composite

lease

06-23 55652-1 (3") discontinued 03-15

lease

54958-1 (3") leaes 59541-1 (3") 03-18 08-04 60041-1 (3")

lease 57718-2 (3") 57718-1 (3") 04-23 M: Composite M: Composite

13-29

07-14 53737-1 (3")

discontinued lease

lease lease

10-11 58048-1 (3") M: Composite lease 46507-5 (4") Timberrock Gas

59996-1 (5") 06-21

M: Composite 59986-2 (4") discontinued

C1218 @ 7L/d

06-10

15-09 lease

lease

lease 59986-8 (4")

lease

lease 59986-7 (4") 59986-9 (5") Composite 13-10

04-10 05-10

lease

lease 56068-1 (3")

53228-1 (3")

discontinued lease

60520-4 (6") 14-32 60520-3 (6") 09-31 60520-1 (6") 12-31 60520-1 (6")

03-05 lease 55029-3 (3") 15-35 lease

lease

lease 58932-1 (3") M:Composite 01-15 12-31 55029-4 (3") M: Composite

16-35 55063-1 (6") 01-35 53932-1 (6")

Sales Gas Sales Gas lease

03-34

lease

lease 60003-1 (5") 11-05 59943-1 (5") 04-04

M: Composite M: Composite lease

lease lease lease

59552-1 (3") discontinued 01-33

M: Composite lease Keyera lease

C1218 @ 6L/d

lease 47376-1 (3") lease lease

47376-3 (5") M: Composite lease lease 54016-1 (6") 57601-1 (3") lease

03-11

lease lease lease

lease 59918-1 (3") M: Composite 14-33 lease

59806-1 (5") M: Composite 01-34 59806-1 (5")

lease M: Composite

lease lease

lease lease

lease

lease 60151-2 (5") 04-33 47376-4 (5") lease

M: Composite M: Composite lease lease

lease 60151-1 (3") 04-33 47376-2 (3") lease

M: Composite lease 59924-1 (5")

lease M: Composite

lease

lease

lease 60062-1 (6") 07-30 60311-1 (5") M: Composite 06-25 59079-1 (4") 07-26 59263-1 (3") M: Composite

10-18

59971-1 (5") 03-36 31390-3 (8") lease

lease M: Composite 09-36

lease

lease

lease

lease 13-02 lease

16-19


M: Composite

lease lease

lease 59587-1 (6") 60045-1 (6") 09-02 lease (6") 14-06 60311-5 (6") 13-01 60311-8 (6")

08-02

lease

14-06 lease

lease

lease lease

lease 60006-1 (5") 03-02 lease

M: Composite

lease

= no information available = header = Corr. Coupon = recommended Injection Point = Demulsifier

= piggable section = blind ended = Riser = Corrosion Inhibitor = Scale Inhibitor

= underground tie-in = recommended Corr. Coupon = Wax Inhibitor/Dispersant = Scale/Corrosion Inhibitor

= Other March, 2018

This schematic does not represent geographical relationships; it is for connectivity purposes only

Comments

04-04-40-08W547376-1, 31390-2,

60020-1, 59587-1,

59976-13, 6 & 8 C1218 Corrosion Inhibitor 6

Willesden Green

Injection Points

LocationProtected

LinesLine size Product Type

Inj rate

(L/day)

02-15-042-07W502-15

Sing. Batt. 02/06-03-042-07W5

Suspended14-18-041-05W5

60222-1, 59959-

6,7,3,1

+ others6 C1218 Corrosion Inhibitor 9

03-23-038-07W559986-1,5,4,3,9,7,

60520-5,4,3,1, 55029-

16 C1218 Corrosion Inhibitor 7

is supplemented by

additional injection points05-11-042-07W5

Supended16-25-039-07W5

58515-1,3,2, 59891-

1, 55270-1, 52347-1,

43702-1,5,66 C1218 Corrosion Inhibitor 4

02/11-04-042-07W5

Shut in

04-10-042-07W5

Suspended 43

70

2-3

(6")

11-04-042-07W511-04

Sing. Batt.

10-04-042-07W5

Disposal 02-04-042-07W5

Battery/ Compressor

03-28-041-07W5

(DH: 02/03-21)01-33-041-07W5

Supended

08-30

Sing. Batt.

08-30-041-07W5

(DH: 02/07-29)

03-28-041-07W5

(DH: 03-21)

03-28

Sing. Batt.

56

26

1-1

(3")

11-21-041-07W5

04-28-041-07W5

(DH: 04-21)

04-28

Sing. Batt.12-29-041-07W5

14-22-041-07W5

Suspended12-33-041-07W5

08-27-041-07W5

(DH: 08-26)

02-31-041-07W508-27-041-07W5

(DH: 02/01-26)

56

54

5-1

(3")

08-27

Sing. Batt.

07-27-041-07W5

(DH: 01-26)43

70

2-7

(4")

53

45

3-1

(4")

52

34

7-1

(6")

01-26-041-07W5

(DH: 01-23)13-16-041-07W5

(DH: 14-17)

13-16

Battery13-31-041-07W5

(DH: 02/14-06)

01-26

Sing. Batt.

01-26-041-07W5

(DH: 02/01-23)

13-31-041-07W5

(DH: 03/14-06)

13-31

Battery M: C

om

po

site

60

22

1-2

(3")

M: C

om

po

site

60

22

1-1

(3")

13-31-041-07W5

(DH: 13-07)

02-29

Sing. Batt.

02-29-041-07W5

(DH: 09-20)

01-26-041-07W5

(DH: 03/02-23)16-15

Inplay13-20-041-07W5

(DH: 12-19)

03-21-041-07W5

(DH: 05-19)05-20-041-07W5

(DH: 07-20)5

23

47

-1 (6

")

13-20-041-07W5

13-31-041-07W5

(DH: 02/13-06)

15-20

Sing. Batt.

15-20-041-07W5

(DH: 12-20)

53

45

3-2

(3")

03-27

Battery

InPlay

01-26-041-07W5

(DH: 02-23)12-16-041-07W5

(DH: 02/12-17) 01-26-041-07W5

(DH: 02/02-23)12-16-041-07W5

(DH: 05-17)

12-16

Sing. Batt.

05-20-041-07W5

(DH: 01-20)

05-20

Sing. Batt.

01-09-041-07W5

(DH: 04-09)01-09-041-07W5

(DH: 02/16-09)

01-09

Sing. Batt.

16-09

Inplay13-17-041-07W5

(DH: 02/13-17) Susp. 01-09-041-07W5

(DH: 13-04)

08-19-041-07W513-20

Sing. Batt.

13-20-041-07W5

(DH: 13-19)

13-11-041-07W5

(DH: 04/13-09) 07-10

Sing. Batt.

07-10-041-07W5

(DH: 11-10) Shut in16-25-039-07W5

(DH: 15-19)

13-11-041-07W5

(DH: 02/13-09)

13-11

Sing. Batt.

52

34

7-1

(6")

16-25-039-07W5

Suspended

16-25

Sing. Batt.

59

95

9-3

(6")

04-12-041-07W5

(DH: 04-11)

01-11-041-07W5

(DH: 01-02)15-08

Obsidian

13-35

Sing. Batt.

13-35-041-07W5

(DH: 14-02)01-11-041-07W5

(DH: 02-02) 13-35-041-07W5

(DH:13-02)

15-07-041-06W515-07

Sing. Batt.

04-12

Sing. Batt.

08-03

Sing. Batt.

08-03-041-07W5

(DH: 06-03)01-11

Sing. Batt.

14-08-041-06W514-08

Sing. Batt.13-35-041-07W5

01-17-041-06W501-17

Sing. Batt.

08-16

Sing. Batt.

08-16-041-06W5

(DH: 02/08-14)

01-19

Battery

01-19-042-07W5

(DH: 02-18)

01-17-041-06W508-16-041-06W5

(DH: 02/08-14)

01-19-042-07W5

(DH: 02/02-18)

59

95

9-6

(6")

13-13-040-06W5

(DH: 12-15)

13-13

Sing. Batt.

14-18-041-05W5

(DH: 14-18) 10-35

Sing. Batt.

10-35-041-08W5

(DH: 02/01-26)14-18-041-05W5

(DH: 03/04-07)

14-18

Sing. Batt.

11-15-041-06W5

(DH: 16-14)

07-24

Baytex

06-18-041-05W5

(DH: 04/14-19)

11-15-041-06W5

(DH: 02/16-14)

M: C

om

po

site

60

22

2-3

(5")

11-15

Sing. Batt.

01-23-040-06W5

Abandoned

03-02

Sing. Batt.

03-02-042-08W5

(DH: 03-26)06-18-041-05W5

Shut in

06-18

Sing. Batt.

11-15-041-06W5

(DH: 03/16-14)11-15-041-06W5

(DH: 09-14) 04-07-039-05W5

(DH: 05-12)15-31-041-05W5

(DH: 15-07)

11-15-041-06W5

(DH: 02/09-14) 15-36-039-06W5

(DH: 02/15-01)

15-36

Sing. Batt.

04-07

Battery

04-07-039-05W5

(DH: 05-13)15-31-041-05W5

(DH: 02/16-07)

15-31

Sing. Batt. 04-07-039-05W5

(DH: 04-12)02-15

Sing. Batt.

02-15-041-06W5

(DH: 01-10)

11-11-039-05W5

(DH: 11-02)16-08-039-05W5

(DH: 15-17)16-08-039-05W5

(DH: 16-17)13-29-043-09W5

(DH: 05-05) dis

co

ntin

ue

d

45

43

7-1

(3")

14-11-043-03W5

(DH: 14-14) Shut in

14-07-038-06W5

(DH: 14-19)

14-07

Sing. Batt.

03-03

Sing. Batt.

03-03-039-05W5

(DH: 04-27)

11-31-041-05W5

(DH: 13-07)

11-31

Sing. Batt.

02-15-041-06W5

(DH: 02-10)

01-11-039-05W5

(DH: 12-02)

11-11

Sing. Batt.

16-08

Battery

05-23-038-07W5

(DH: 13-23) Susp.

03-23

Sing. Batt. 03-23-038-07W5

(DH: 01-23) ABD

59

98

6-1

1 (4

")

59

98

6-1

& 5

(6")

ab

an

do

ne

d

59

98

6-1

0 (6

")

02/03-23-038-07W5

Shut in

13-29-043-09W5

(DH: 13-29) ABD

13-29

Sing. Batt.

02-14

Sing. Batt.

02-14-043-03W5

(DH: 15-14) 03-18-038-06W5

Timberrock01-29-043-09W5

(DH: 02-20)

01-29

Sing. Batt.

02-14-043-03W5

(DH: 02/16-14) 05-18-038-06W5

Timberrock

60

52

0-5

(6")

16-35-037-08W5

(DH: 16-02)16-35-037-08W5

(DH: 09-36)

04-02

Battery

04-02-038-08W5

(DH: 04-35)13-31-037-07W5

(DH: 14-36) Susp. 04-02-038-08W5

(DH: 02/04-35)

05-03-038-07W5

(DH: 08-03)

05-03

Sing. Batt. 03-23-038-07W5

Shut in

01-09-038-07W5

(DH: 07-04) Shut in

01-09

Sing. Batt.

59986-4 & 3 (6") 09-15

Satellite

16-35

Battery

15-35-037-08W5

(DH: 15-02)

60

52

0-2

(6")

16-35-037-08W5

(DH: 02/16-36)08-10-040-08W5

(DH: 02/01-34) 55

02

9-1

(6")

55

06

3-2

(6")

08-10-040-08W5

(DH: 01-34)

08-10

Sing. Batt.

02-02

Battery

14-05-040-08W5

(DH: 13-08)

14-05

Sing. Batt.16-02-037-08W5

Battery/CompressorM

:Co

mp

osite

59

94

3-2

(5")

16-02-038-08W5

(DH: 15-11)14-06-037-07W5

(DH: 13-18)

16-02-038-08W5

(DH: 02/16-11)

02-02-038-08W5

(DH: 02/02-35)

52

74

4-2

(4")

02-02-038-08W5

(DH: 01-26)Sa

les

Ga

s

55

02

9-2

(6")

14-05-040-08W5

(DH: 14-08)

05-31

Sing. Batt.

05-31-037-07W5

(DH: 06-36) Sa

les

Ga

s

55

03

0-1

(6")

01-35-037-08W5

(DH: 16-35)04-04

CNRL 14-06-037-07W5

(DH: 15-18)

54

97

0-1

(6")

01-35

Battery

01-35-037-08W5

(DH: 01-36)14-06

Sing. Batt.

03-11

Battery

55

03

3-1

(4")

02-35

Battery

04-04-40-08W5

Shut in

04-04

Sing. Batt.

14-06-037-07W5

(DH: 02/14-18)

03-11-038-08W5

(DH: 13-11)

60

31

1-3

(5") M

: Co

mp

osite

14-06-037-07W5

(DH: 04/14-18)

03-11-038-08W5

(DH: 14-11)

15-26-037-08W5

(DH: 03/14-35)

10-28-039-08W5

(DH: 16-27)

02-35-037-08W5

(DH: 03-23)14-33-040-08W5

(DH: 02/14-09)

03-11-038-08W5

(DH: 04-02)

02-35-037-08W5

(DH: 03-26)14-33-040-08W5

(DH: 15-09)

14-33

Sing. Batt.

03-11-038-08W5

(DH: 02/03-02) 08-34

Battery

08-34-037-08W5

(DH: 02/04-23)16-08-037-07W5

(DH: 08-20) 08-34-037-08W5

(DH: 04-23)10-28-039-08W5

(DH: 02/16-33)

16-08-037-07W5

(DH: 13-21)

15-26

Battery15-26-037-08W5

(DH: 15-35) ABD10-28-039-08W5

(DH: 16-33)

11-33

Header

16-08

Sing. Batt.

16-08-037-07W5

(DH: 08-20) 15-26-037-08W5

(DH: 11-35)

12-28-037-08W5

(DH: 11-16)10-28-039-08W5

(DH: 09-27)

10-28

Sing. Batt.

31

39

0-2

(8")

60

31

1-2

(5") M

:Co

mp

osite

16-08-037-07W5

(DH: 08-20)

60

54

4-1

(5") M

:Co

mp

osite

15-26-037-08W5

(DH: 02/15-35)

12-28

Battery

12-28-037-08W5

(DH: 03-21)12-28-037-08W5

(DH: 04-21)10-28-039-08W5

(DH: 02/1627)10-28-039-08W5

(DH: 02/09-27)

07-26

Battery

07-26-037-08W5

(DH: 03-14)

60

06

2-5

(5") M

: Co

mp

osite

07-26-037-08W5

(DH: 01-23)01-36-039-09W5

(DH: 04-30) 60

02

0-1

(6")

04-01-040-09W5

(DH: 03/04-36)

04-01-040-09W5

(DH: 01-26)

59

58

7-1

(6")

60

06

2-3

(6")

60

06

2-4

(5") M

:Co

mp

osite

01-02-040-09W5

RESPONSE

12-20-037-07W5

(DH: 02/04-17)

01-36-039-09W5

(DH: 02/04-30)

01-36

Sing. Batt. 04-01-040-09W5

(DH: 02/04-36)10-30-039-08W5

(DH: 02-19)

04-01

Battery

04-01-040-09W5

(DH: 04-36)

58

73

9-1

(3") M

: Co

mp

osite

10-30-039-08W5

(DH: 01-19)

10-30

Sing. Batt.

dis

co

ntin

ue

d

01-02-040-09W5

(DH: 02-26)

01-02

Sing. Batt.

12-20-037-07W5

(DH: 02/03-17)

12-20

Battery

13-10

Battery59

91

6-1

(6")5

99

76

-1 (6

")

12-20-037-07W5

(DH: 03-17)

dis

co

ntin

ue

d

06-02-040-9W5

(DH: 02/03-26)

= non-piggable section= segements covered

by injection

= segements covered

by batch

59

26

0-1

(3") M

: Co

mp

osite

12-20-037-07W5

(DH: 04-17)

59

97

0-1

(6") 11-06-040-08W5

(DH: 13-07)11-06

Battery06-02-040-9W5

(DH: 02/03-26) 06-02-040-09W5

Battery/ Compressor

11-06-040-08W5

(DH: 13-07)06-02-040-9W5

(DH: 02/03-26)

11-06-040-08W5

(DH: 13-07)

*note: information stated below based on AER license information obtained from ABADATA 2.0. Contact Chemicals Inc. takes no resposibility for accuracy of this data.

AER

License

from

location

to

location

Length(km) Status Substance

H2S(mol/kmol)

OD(mm)

WT(mm) Material TYPE GRADE

MOP(kPa) Joints

Internal

Coating

Elevation

Profile

Pipeline

Age (yrs) Enviro. Physical Risk

19415 - 2 8-23-40-6W5 B 6-19-40-5W5 PL 2.4 O NG 0 88.9 3.18 S 5LX X42 1720 W U 38 2.5

31390 - 2 11-33-39-8W5 PL 9-36-39-9W5 PL 4.23 O NG 0 219.1 5.6 S Z245.1 3592 9930 W U 22 2.8

31390 - 3 3-36-39-9W5 PL 9-36-39-9W5 PL 1.24 O NG 0 219.1 5.6 S Z245.1 3592 9930 W U 22 2.7

42289 - 7 2-4-42-7W5 CS 10-33-41-7W5 PL 0.65 O NG 0 168.3 4 S Z245.1 3591 9850 W U 15 2.6

42289 - 8 10-4-42-7W5 BE 11-4-42-7W5 BE 0.42 D NG 0 114.3 4.8 S Z245.1 3592 0 W U 14 2.3

42289 - 9 2-15-42-7W5 WE 4-10-42-7W5 PL 2.78 O NG 0 114.3 4.8 S Z245.1 3592 9930 W U not available 14 CC 2.6

42289 - 10 5-11-42-7W5 WE 4-10-42-7W5 PL 2.5 O NG 0 114.3 4 S Z245.1 3592 9930 W U 10 CC 2.6

43702 - 1 11-21-41-7W5 WE 7-29-41-7W5 PL 2.38 O NG 2 168.3 4 S Z245.1 3591 9930 W U 15 2.6

43702 - 2 11-4-42-7W5 WE 2-4-42-7W5 CS 1.1 O NG 2 114.3 4.8 S Z245.1 3591 9930 W U 15 2.5

43702 - 3 6-3-42-7W5 WE 2-4-42-7W5 CS 1.8 O NG 2 168.3 4 S Z245.1 3591 9930 W U 15 2.6

43702 - 4 12-29-41-7W5 WE 7-29-41-7W5 PL 0.81 O NG 2 114.3 4.8 S Z245.1 3591 9930 W U 15 2.6

43702 - 5 7-29-41-7W5 PL 12-33-41-7W5 PL 2.25 O NG 2 168.3 4 S Z245.1 3591 9930 W U 15 CC 2.7

43702 - 6 12-33-41-7W5 PL 2-4-42-7W5 CS 1.42 O NG 2 168.3 4 S Z245.1 3591 9930 W U 15 2.6

43702 - 7 8-19-41-7W5 WE 7-29-41-7W5 PL 2.8 O NG 2 114.3 4.8 S Z245.1 3592 9930 W U 14 CC 2.7


44436 - 1 14-22-41-7W5 BE 11-21-41-7W5 BE 1.52 D NG 0 60.3 3.2 S Z245.1 2901 0 W U 14 2.2

46735 - 1 13-17-41-7W5 BE 8-19-41-7W5 BE 0.7 D NG 2 88.9 4 S Z245.1 3592 0 W U 13 2.3

46735 - 2 5-20-41-7W5 WE 8-19-41-7W5 PL 0.22 O NG 2 88.9 4.8 S Z245.1 3592 9930 W U 9 2.4

47376 - 1 4-4-40-8W5 WE 11-33-39-8W5 PL 1.7 O NG 0 88.9 3.2 S Z245.1 3591 9520 W U 13 2.6

47376 - 2 4-33-39-8W5 WE 11-33-39-8W5 PL 0.6 O NG 0 88.9 3.2 S Z245.1 3591 9520 W U 13 2.5

47376 - 3 4-4-40-8W5 PL 11-33-39-8W5 PL 1.14 P NG 0 130 15.5 G FPLP 601 9930 M U 1 2.1

47376 - 4 4-33-39-8W5 PL 11-33-39-8W5 PL 0.49 P NG 0 130 15.5 G FPLP 601 9930 M U 1 2

48014 - 1 16-25-39-7W5 BE 13-30-39-6W5 BE 0.34 D NG 0 114.3 4 S Z245.1 3592 0 W U 13 2.3

48160 - 1 13-20-41-7W5 WE 15-20-41-7W5 PL 0.54 O NG 0 114.3 4.8 S Z245.1 3592 9930 W U 13 2.6

48695 - 1 13-19-40-6W5 BE 2-30-40-6W5 BE 1.38 D NG 0 88.9 3.2 S Z245.1 3592 0 W U 12 2.3


52347 - 2 13-35-40-7W5 WE 8-3-41-7W5 PL 1.36 O NG 0 168.3 4 S Z245.1 3592 9930 W U 8 2.5

52744 - 2 5-31-37-7W5 WE 12-31-37-7W5 PL 0.35 O OE 0 114.3 4 S Z245.1 3592 9930 W U 8 2.4

53228 - 1 13-31-37-7W5 BE 12-31-37-7W5 BE 0.73 D OE 0 88.9 4 S Z245.1 3592 0 W U 8 2.2

53316 - 1 4-28-41-7W5 WE 4-28-41-7W5 PL 0.19 O NG 0 88.9 3.2 S Z245.1 3592 9930 W U 8 2.4

53368 - 1 2-29-41-7W5 WE 2-29-41-7W5 PL 0.12 O NG 2 88.9 4 S Z245.1 3592 9930 W U 9 2.5

53385 - 1 8-30-41-7W5 WE 12-29-41-7W5 PL 1.11 O NG 2 88.9 4.8 S Z245.1 3592 9930 W U 8 2.5

53453 - 1 13-16-41-7W5 WE 4-28-41-7W5 PL 2.05 O NG 0 114.3 4.8 S Z245.1 3592 9930 W U 8 2.5

53453 - 2 12-16-41-7W5 WE 13-16-41-7W5 PL 0.71 O NG 0 88.9 3.2 S Z245.1 3592 9930 W U 4 2.4

53453 - 3 15-20-41-7W5 WE 15-20-41-7W5 PL 0.37 O NG 0 88.9 4.8 S Z245.1 3592 9930 W U 8 2.4

53932 - 1 1-35-37-8W5 WE 3-34-37-8W5 PL 2.94 O NG 0 168.3 4 S Z245.1 3592 9930 W U 7 2.5

54016 - 1 3-11-38-8W5 WE 3-11-38-8W5 PL 0.19 O NG 0 168.3 4.8 S Z245.1 3592 9930 W U 7 2.4


54970 - 1 3-11-38-8W5 PL 16-2-38-8W5 B 0.82 O NG 0 168.3 4.8 S Z245.1 3592 9930 W U 6 2.5

55029 - 1 16-35-37-8W5 PL 16-2-38-8W5 B 2.7 O NG 0 168.3 4 S Z245.1 2901 9930 W U 6 2.5

55029 - 2 16-2-38-8W5 B 16-35-37-8W5 PL 2.7 O NG 0 168.3 4 S Z245.1 2901 9930 W U 6 2.5

55029 - 3 15-35-37-8W5 WE 16-35-37-8W5 PL 0.27 O NG 0 88.9 3.2 S Z245.1 3592 9930 W U 4 2.3

55029 - 4 2-2-38-8W5 WE 15-35-37-8W5 PL 0.32 O NG 0 101 12 G FPLP 601 9930 M U 2 1.9

55030 - 1 3-34-37-8W5 PL 1-33-37-8W5 PL 0.59 O NG 0 168.3 4 S Z245.1 3592 9930 W U 6 2.4

55033 - 1 15-26-37-8W5 WE 1-35-37-8W5 PL 0.77 O NG 0 114.3 4 S Z245.1 3592 9930 W U 6 2.3

55063 - 1 16-35-37-8W5 PL 1-35-37-8W5 PL 1.53 O NG 0 168.3 4 S Z245.1 2901 9930 W U 6 2.5

55063 - 2 1-35-37-8W5 PL 16-35-37-8W5 PL 1.53 O NG 0 168.3 4 S Z245.1 2901 9930 W U 6 2.5

55270 - 1 4-12-41-7W5 WE 1-11-41-7W5 PL 0.61 O NG 0 114.3 4 S Z245.1 3592 9930 W U 6 2.3


55652 - 1 1-15-41-6W5 BE 3-15-41-6W5 BE 0.63 D NG 0 88.9 4 S Z245.1 3592 0 W U 5 2.2

55895 - 1 4-7-39-5W5 WE 13-6-39-5W5 PL 0.49 O NG 0 88.9 4 S Z245.1 3592 4960 W U 5 2.3

56048 - 1 16-8-39-5W5 WE 7-8-39-5W5 PL 1.03 O NG 0 88.9 4 S Z245.1 3592 4960 W U 5 2.3

56068 - 1 4-2-38-8W5 WE 16-35-37-8W5 PL 1.4 O NG 0 88.9 4 S Z245.1 3592 9930 W U 5 2.4

56261 - 1 3-28-41-7W5 WE 4-28-41-7W5 PL 0.61 O NG 0 88.9 4 S Z245.1 3592 9930 W U 5 2.3

56302 - 1 11-11-39-5W5 WE 12-11-39-5W5 PL 0.27 O NG 0 88.9 4 S Z245.1 3592 4960 W U 5 1.9

56545 - 1 13-31-41-7W5 WE 2-31-41-7W5 PL 1.63 O NG 0 88.9 3.2 S Z245.1 3592 9930 W U 5 2.5

57466 - 1 10-35-41-8W5 WE 10-2-42-8W5 PL 2.44 O NG 0 91 8 G FSLP 750 4950 M U 4 2

57486 - 1 13-11-41-7W5 WE 8-10-41-7W5 PL 1.23 O NG 0 88.9 4 S Z245.1 3592 9930 W U 4 2

57591 - 1 1-35-37-8W5 WE 1-35-37-8W5 PL 0.07 O NG 0 88.9 4 S Z245.1 2901 9930 W U 3 2.3

57601 - 1 2-35-37-8W5 WE 1-35-37-8W5 PL 0.19 O NG 0 88.9 4 S Z245.1 2901 9930 W U 3 2.3

57873 - 1 2-31-41-7W5 WE 8-32-41-7W5 PL 2.3 O NG 2 114.3 4.8 S Z245.1 3592 9930 W U 15 2.7

57873 - 2 4-10-42-7W5 WE 6-3-42-7W5 PL 1.41 O NG 2 114.3 4.8 S Z245.1 3592 9930 W U 14 2.6

58050 - 1 4-14-42-8W5 WE 10-15-42-8W5 S 1.14 O NG 0 60.3 3.18 S 5L B 4950 W U 38 2.5

58050 - 2 10-2-42-8W5 WE 14-2-42-8W5 PL 0.28 O NG 0 60.3 3.9 S Z245.1 2901 4950 W U 19 2.2

58050 - 3 14-2-42-8W5 PL 14-2-42-8W5 PL 0.1 O NG 0 60.3 3.9 S Z245.1 2901 4950 W U 19 CC 2.2

58050 - 4 14-2-42-8W5 PL 4-11-42-8W5 PL 0.6 O NG 0 60.3 3.9 S Z245.1 2901 4950 W U 19 2.2

58050 - 5 4-11-42-8W5 PL 4-14-42-8W5 PL 1.7 O NG 0 60.3 3.91 S Z245.1 2901 4950 W U 35 2.5

58418 - 1 8-16-41-6W5 BE 15-9-41-6W5 BE 1.1 D NG 0 101 12 G FPLP 601 0 M U 2 1.7


58419 - 2 14-18-41-5W5 WE 2-19-41-5W5 PL 0.98 O NG 0 101 12 G FPLP 601 9930 M U 2 2

58515 - 1 16-25-39-7W5 WE 6-12-40-7W5 PL 5.1 O NG 0 114.3 4 S Z245.1 3592 9930 W U 2 2.5


58515 - 3 11-12-40-7W5 PL 14-13-40-7W5 PL 2.19 O NG 0 114.3 4 S Z245.1 3592 9930 W U 2 2.3


58743 - 1 3-21-41-7W5 WE 13-16-41-7W5 B 0.53 O OE 0 101 12 G FPLP 601 9930 M U 2 2.1



59079 - 1 6-25-37-8W5 PL 7-26-37-8W5 PL 1.1 O NG 0 114.3 4 S Z245.1 3592 9930 W U 6 2.4

59259 - 1 15-31-41-5W5 WE 16-31-41-5W5 PL 0.28 O NG 0 88.9 3.2 S Z245.1 2901 9930 W U 2 2.2






59556 - 1 15-36-39-6W5 WE 10-36-39-6W5 PL 0.41 O NG 0 101 12 G FPLP 601 9930 M U 1 2

59587 - 1 4-1-40-9W5 WE 1-2-40-9W5 PL 1.06 O NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2.4


59806 - 1 8-34-37-8W5 WE 2-35-37-8W5 PL 1.49 O NG 0 130 15.5 G FPLP 601 9930 M U 1 1.9

59891 - 1 4-12-41-7W5 WE 1-10-41-7W5 PL 2.23 O NG 0 114.3 4 S Z245.1 3592 9930 W U 1 2.3

59892 - 1 10-30-39-8W5 WE 1-36-39-9W5 PL 1.77 O NG 0 130 15.5 G FPLP 601 9930 M U 1 2

59916 - 1 14-6-40-8W5 PL 9-2-40-9W5 PL 2.55 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.4

59918 - 1 14-33-39-8W5 WE 14-33-39-8W5 PL 0.37 P NG 0 101 12 G FPLP 601 9930 M U 2 2.1

59924 - 1 12-28-37-8W5 WE 1-34-37-8W5 PL 3.75 P NG 0 130 15.5 G FPLP 601 9930 M U 2 2.1

59941 - 1 1-19-42-7W5 WE 14-17-42-7W5 PL 1.14 P OE 0 101 12 G FPLP 601 4960 M U 1 1.9



59959 - 1 14-7-41-6W5 PL 4-12-41-7W5 PL 3.17 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.4

59959 - 2 15-7-41-6W5 WE 15-7-41-6W5 PL 0.44 P NG 0 101 12 G FPLP 601 9930 M U 2 2

59959 - 3 1-17-41-6W5 PL 15-7-41-6W5 PL 2.86 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.4

59959 - 4 15-8-41-6W5 PL 2-17-41-6W5 PL 0.31 P NG 0 101 12 G FPLP 601 9930 M U 2 1.9


59959 - 6 11-15-41-6W5 WE 8-16-41-6W5 PL 2.12 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.4

59959 - 7 8-16-41-6W5 WE 4-16-41-6W5 PL 2.07 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 CC 2.4

59970 - 1 11-6-40-8W5 WE 14-6-40-8W5 PL 0.14 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.2

59971 - 1 1-36-39-9W5 WE 3-36-39-9W5 PL 1 P NG 0 130 15.5 G FPLP 601 9930 M U 2 1.9

59976 - 1 1-2-40-9W5 WE 6-2-40-9W5 B 1.03 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.2

59986 - 1 3-23-38-7W5 WE 12-14-38-7W5 PL 1.33 O NG 0 168.3 4 S Z245.1 3592 9930 W U 10 2.5

59986 - 2 5-23-38-7W5 BE 3-23-38-7W5 BE 0.84 D NG 0 114.3 3.2 S Z245.1 3592 0 W U 9 CC 2.1

59986 - 3 12-14-38-7W5 PL 13-10-38-7W5 PL 2.52 O NG 0 168.3 4 S Z245.1 3592 9930 W U 1 RC 2.4

59986 - 4 9-15-38-7W5 B 12-14-38-7W5 PL 0.09 O NG 0 168.3 4.8 S Z245.1 3592 9930 W U 9 2.4

59986 - 5 12-14-38-7W5 PL 9-15-38-7W5 B 0.09 O NG 0 168.3 4.8 S Z245.1 3592 9930 W U 9 2.4

59986 - 7 1-9-38-7W5 WE 5-10-38-7W5 PL 1.1 O NG 0 114.3 4 S Z245.1 3592 4960 W U 8 2.3

59986 - 8 5-3-38-7W5 WE 4-10-38-7W5 PL 1.89 O NG 0 114.3 4 S Z245.1 3592 4960 W U 8 2.3


59986 - 10 13-10-38-7W5 BE 15-9-38-7W5 BE 1.02 A NG 0 168.3 4 S Z245.1 3592 0 W U 1 RC 2.1

59986 - 11 5-10-38-7W5 WE 6-10-38-7W5 PL 0.53 O NG 0 114.3 4 S Z245.1 3592 4960 W U 8 2.2

60003 - 1 14-5-40-8W5 WE 11-5-40-8W5 PL 0.31 P NG 0 130 15.5 G FPLP 601 9930 M U 2 2

60006 - 1 6-2-40-9W5 B 3-2-40-9W5 PL 0.54 P NG 0 130 15.5 G FPLP 601 9930 M U 2 2.1

60020 - 1 9-36-39-9W5 PL 4-1-40-9W5 PL 1.51 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.4


60045 - 1 9-2-40-9W5 PL 8-2-40-9W5 PL 0.5 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.3







60222 - 1 11-19-41-5W5 PL 15-15-41-6W5 PL 5.5 P NG 0 168.3 4 S Z245.1 3592 9930 W U 2 2.5







60520 - 1 9-31-37-7W5 PL 16-35-37-8W5 PL 3.94 P NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2.6

60520 - 2 12-31-37-7W5 PL 12-31-37-7W5 PL 0.04 P NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2.2

60520 - 3 14-32-37-7W5 PL 9-31-37-7W5 PL 1.67 P NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2.4

60520 - 4 3-5-38-7W5 PL 14-32-37-7W5 PL 0.12 P NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2

60520 - 5 1-9-38-7W5 WE 3-5-38-7W5 PL 4.33 P NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2.4


57718 - 1 1-29-43-9W5 WE 4-32-43-9W5 PL 2.28 O NG 0 88.9 4 S Z245.1 2901 9930 W U 3 1.8

57718 - 2 13-29-43-9W5 WE 13-29-43-9W5 PL 0.09 O NG 0 88.9 4 S Z245.1 2901 9930 W U 3 1.8

59996 - 1 1-29-43-9W5 WE 6-21-43-9W5 B 1.72 P NG 0 130 15.5 G FPLP 601 9930 M U 2 1.5

45437 - 1 7-14-43-3W5 BE 6-23-43-3W5 BE 2.47 D OE 0 88.9 4 S Z245.1 2901 0 W U 14 1.8

53737 - 1 2-14-43-3W5 BE 7-14-43-3W5 BE 0.46 D OE 0 88.9 4.8 S Z245.1 3592 0 W U 7 1.7

54958 - 1 14-11-43-3W5 WE 2-14-43-3W5 B 0.74 O OE 0 88.9 4 S Z245.1 3592 9920 W U 6 1.9


60062 - 2 12-20-37-7W5 B 16-19-37-7W5 PL 0.66 P NG 0 168.3 4 S Z245.1 3592 9930 W U not available 1 2

60062 - 3 16-19-37-7W5 PL 12-20-37-7W5 B 0.66 P NG 0 168.3 4 S Z245.1 3592 9930 W U 1 2.1

60062 - 4 12-20-37-7W5 B 16-19-37-7W5 PL 0.66 P NG 0 130 15.5 G FPLP 601 9930 M U 1 1.8



60311 - 8 13-10-037-07W5 13-01-037-07W5 4.03 O NG 0 168.3 S not available 0 CC 3.3

60311 - 5 13-01-037-07W5 14-06-037-07W5 2.13 O NG 0 168.3 S not available 0 2.8

10-18-037-07W5 12-20-037-07W5 3.62 O NG 0 168.3 S not available 0 3

Legend:

Length and size

Operating status

Material and coating

MOP

Elevation Profile

Age

Enviromental

Pipeline risk based on physical properties for Willesden Green

Status Substance Pipe Mat. Internal Coating Risks rating based on:

O = Operating OE = oil emulsion S = Steel U = uncoated

D = Discontinued NG = natural gas G = Composite L = Free Standing

C = Cement

R = Removed SG = sour natural gas V = Polyvinyl Chloride

A = Abandoned FW = fresh water A = Aluminium E = Expanded Polythylene

P = in construction SW = salt water P = Polythylene Y = (unexplained)

LV = LVP C = Cellulose Acetate Butyrate

H = Asbestos Cement

N = Not constructed FG = fuel gas F = Fibreglass

AER

License

segment

status

Total gas

prod.

(e3m

3/day)

Total oil

prod.

(m3/day)

Total water

prod.

(m3/day)

Total fluid

prod.

(m3/day)

Watercut(%)

Gas

Velocity(m/s)

Fluid

Velocity(m/s)

Mixed

Velocity(m/s)

Gas flow

regime

Fluid flow

regime

Operating

temp.(°C)

Operating

pressure(kPa)

Pigging(#/year)

Operational

Risk

19415 - 2 Active 2.9 0 6.9 6.9 100.0 0.25008 0.01493 0.26501 mist laminar 10 860 4 1.6

31390 - 2 Active 316.1 0 65.4 65.4 100.0 0.00683 0.0223 0.02913 mist turbulent 10 4965 4 1.9


42289 - 7 Active 136.8 0 0 0 0.0 0.01158 0 0.01158 mist no fluid 10 4925 4 1.9

42289 - 8 Inactive 0 0 0 0 0.0 0 0 0 N/A no fluid 10 0 no 1.7










43702 - 8 Active 0 0.1 0 0.1 0.0 0 0.00023 0.00023 N/A laminar 10 4965 4 2.4






47376 - 3 Planned 102.3 0 65.4 65.4 100.0 0.03011 0.09833 0.12845 mist turbulent 10 4965 4 1.8

47376 - 4 Planned 106.6 0 0 0 0.0 0.03011 0 0.03011 mist no fluid 10 4965 4 1.4





52347 - 2 Active 3.5 0 0.1 0.1 100.0 0.10251 5.7E-05 0.10257 mist laminar 17 570 4 2















55029 - 3 Active 31.9 0.3 9.3 9.6 96.9 0.04336 0.02079 0.06415 mist laminar 10 4965 4 2.3

55029 - 4 Active 28.8 0 6 6 100.0 0.04978 0.01491 0.06469 mist laminar 10 4965 4 1.8






55273 - 1 Active 6 0 0.1 0.1 100.0 0.02612 0.00013 0.02625 mist laminar 10 4965 4 1.8

55652 - 1 Inactive 0 0 0 0 0.0 0 0 0 N/A no fluid 0 no 1.6









57591 - 1 Active 0 0 0 0 0.0 0 0 0 N/A no fluid 10 4965 4 2.1

57601 - 1 Active 34.8 0 94 94 100.0 0.04509 0.21165 0.25675 mist turbulent 10 4965 4 1.9















58743 - 1 Active 1.6 5.6 4.7 10.3 45.6 0.04977 0.0256 0.07538 mist laminar 10 4965 4 2.3



59079 - 1 Active 213.1 34 0 34 0.0 0.02612 0.04434 0.07046 mist turbulent 10 4965 4 2.1



59263 - 1 Active 17.8 0 19.4 19.4 100.0 0.04977 0.04822 0.09799 mist transitional 10 4965 4 1.8



59552 - 1 Active 0.6 0 0 0 0.0 0.06147 0 0.06147 mist no fluid 10 4020 no 2.2

59556 - 1 Active 1 0 27.7 27.7 100.0 0.04977 0.06885 0.11862 mist turbulent 10 4965 4 1.9


59787 - 1 Active 10 0 58.4 58.4 100.0 0.09985 0.14515 0.245 mist turbulent 10 2475 4 1.7




59916 - 1 Planned 34.9 0 26.6 26.6 100.0 0.01148 0.01525 0.02674 mist laminar 10 4965 4 1.7


59924 - 1 Planned 4.1 0 25.2 25.2 100.0 0.03011 0.03789 0.068 mist transitional 10 4965 4 1.7

59941 - 1 Planned 3.3 6.8 2.3 9.1 25.3 0.09965 0.02262 0.12227 mist laminar 10 2480 4 2.1




59959 - 2 Planned 2.8 0 53.5 53.5 100.0 0.04977 0.13297 0.18275 mist turbulent 10 4965 no 2.1







59971 - 1 Planned 94.2 0 20.7 20.7 100.0 0.03011 0.03112 0.06124 mist transitional 10 4965 4 1.7

















60062 - 1 Active 213.1 34 0 34 0.0 0.01149 0.0195 0.03099 mist transitional 10 4965 4 2








60222 - 3 Planned 44 0 47 47 100.0 0.03011 0.07067 0.10078 mist turbulent 10 4965 4 1.8

60222 - 4 Planned 0 0 0 0 0.0 0 0 0 N/A no fluid 10 4965 4 1.3

60311 - 1 Planned 213.1 34 0 34 0.0 0.03011 0.05112 0.08124 mist turbulent 10 4965 4 2

60311 - 2 Planned 103 0 0 0 0.0 0.03011 0 0.03011 mist no fluid 10 4965 4 1.4


60520 - 1 Planned 16.3 0 0.1 0.1 100.0 0.01148 5.7E-05 0.01154 mist laminar 10 4965 4 1.7












58048 - 1 Active 2.1 0 1 1 100.0 0.05977 0.00249 0.06225 mist laminar 10 4135 4 1.8

60062 - 2 Planned 55 0 0.1 0.1 100.0 0.01153 5.7E-05 0.01158 mist laminar 11 4965 4 1.8

60062 - 3 Planned 55 0 0.1 0.1 100.0 0.01157 5.7E-05 0.01162 mist laminar 12 4965 4 1.8

60062 - 4 Planned 55 0 0.1 0.1 100.0 0.03043 0.00015 0.03058 mist laminar 13 4965 no 2.1





Active 0 0 0 0 0.0 0 0 0 N/A no fluid 18 4965 4 1.5

Production and % of total production Production issues (ie Deadlegs) Flow regimes pigging schedule

Water Cut Production Velocities Operating temp and pressures

Pipeline risk based on operation of the Willesden Green field

Risks rating based on:

AER

License

from

locationpH

(@ 25°C)

Chlorides(ppm)

TDS(ppm)

Iron(ppm)

Manganese(ppm)

Bacteria

ATP(pg/mL)

Bacteria

Dilution(cfu/mL)

H2S

(%)

CO2

(mol frac.)

deWaard

Milliams

Corr.

Coupon(mpy)

Chemical

Corrosion

Risk19415 - 2 8-23-40-6W5 B 7.5 10,000 18,500 30 0.5 3,000 0 0.0104 0.697 2.3

31390 - 2 11-33-39-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

31390 - 3 3-36-39-9W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

42289 - 7 2-4-42-7W5 CS 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

42289 - 8 10-4-42-7W5 BE 0 1.7

42289 - 9 2-15-42-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

42289 - 10 5-11-42-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.500 2.3

43702 - 1 11-21-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 0.045 1.8

43702 - 2 11-4-42-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

43702 - 3 6-3-42-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

43702 - 4 12-29-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0208 0.741 2.4

43702 - 5 7-29-41-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 0.172 1.9

43702 - 6 12-33-41-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 0.101 1.8

43702 - 7 8-19-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

43702 - 8 1-33-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.500 2.3

44436 - 1 14-22-41-7W5 BE 0 1.7

46735 - 1 13-17-41-7W5 BE 0 1.7

46735 - 2 5-20-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

47376 - 1 4-4-40-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

47376 - 2 4-33-39-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

47376 - 3 4-4-40-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

47376 - 4 4-33-39-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

48014 - 1 16-25-39-7W5 BE 0 1.7

48160 - 1 13-20-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

48695 - 1 13-19-40-6W5 BE 0 1.7

52347 - 1 8-3-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0237 0.762 2.4

52347 - 2 13-35-40-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0237 0.762 2.4

52744 - 2 5-31-37-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53228 - 1 13-31-37-7W5 BE 0 1.7

53316 - 1 4-28-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53368 - 1 2-29-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53385 - 1 8-30-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53453 - 1 13-16-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53453 - 2 12-16-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53453 - 3 15-20-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53932 - 1 1-35-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

54016 - 1 3-11-38-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

54571 - 1 1-9-41-7W5 WE 0 1.7

54970 - 1 3-11-38-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55029 - 1 16-35-37-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 0.046 1.8

55029 - 2 16-2-38-8W5 B 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55029 - 3 15-35-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55029 - 4 2-2-38-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55030 - 1 3-34-37-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55033 - 1 15-26-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55063 - 1 16-35-37-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55063 - 2 1-35-37-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55270 - 1 4-12-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55273 - 1 1-11-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

55652 - 1 1-15-41-6W5 BE 0 1.7

55895 - 1 4-7-39-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

56048 - 1 16-8-39-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

56068 - 1 4-2-38-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

56261 - 1 3-28-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

56302 - 1 11-11-39-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

56545 - 1 13-31-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57466 - 1 10-35-41-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57486 - 1 13-11-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57591 - 1 1-35-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57601 - 1 2-35-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57873 - 1 2-31-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57873 - 2 4-10-42-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58050 - 1 4-14-42-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58050 - 2 10-2-42-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58050 - 3 14-2-42-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58050 - 4 14-2-42-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58050 - 5 4-11-42-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58418 - 1 8-16-41-6W5 BE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58419 - 1 6-18-41-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58419 - 2 14-18-41-5W5 WE 0 1.7

58515 - 1 16-25-39-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58515 - 2 14-13-40-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58515 - 3 11-12-40-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58739 - 1 1-2-40-9W5 BE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58743 - 1 3-21-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58932 - 1 8-10-40-8W5 WE 0 1.7

59026 - 1 13-13-40-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59079 - 1 6-25-37-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59259 - 1 15-31-41-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59260 - 1 6-2-40-9W5 BE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59263 - 1 7-26-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59530 - 1 14-8-41-6W5 WE 0 1.7

59541 - 1 14-7-38-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59552 - 1 4-4-40-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.500 2

59556 - 1 15-36-39-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59587 - 1 4-1-40-9W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59787 - 1 3-2-42-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59806 - 1 8-34-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59891 - 1 4-12-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59892 - 1 10-30-39-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59916 - 1 14-6-40-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59918 - 1 14-33-39-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59924 - 1 12-28-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59941 - 1 1-19-42-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59943 - 1 11-5-40-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59943 - 2 4-4-40-8W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59959 - 1 14-7-41-6W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59959 - 2 15-7-41-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59959 - 3 1-17-41-6W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59959 - 4 15-8-41-6W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59959 - 5 2-15-41-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59959 - 6 11-15-41-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59959 - 7 8-16-41-6W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59970 - 1 11-6-40-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59971 - 1 1-36-39-9W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59976 - 1 1-2-40-9W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

59986 - 1 3-23-38-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 2 5-23-38-7W5 BE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 3 12-14-38-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 4 9-15-38-7W5 B 0 1.7

59986 - 5 12-14-38-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 7 1-9-38-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 8 5-3-38-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 9 13-10-38-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59986 - 10 13-10-38-7W5 BE 0 1.7

59986 - 11 5-10-38-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60003 - 1 14-5-40-8W5 WE 0 1.7

60006 - 1 6-2-40-9W5 B 7.5 10000 18500 30 0.5 3000 0 0.0059 0.806 2

60020 - 1 9-36-39-9W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

60041 - 1 3-3-39-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60045 - 1 9-2-40-9W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

60062 - 1 7-18-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60151 - 1 10-28-39-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

60151 - 2 10-28-39-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0059 0.671 2

60221 - 1 1-26-41-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60221 - 2 7-27-41-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60221 - 3 8-27-41-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60222 - 1 11-19-41-5W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60222 - 2 2-19-41-5W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60222 - 3 15-31-41-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60222 - 4 11-31-41-5W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60311 - 1 7-30-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60311 - 2 16-8-37-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60311 - 3 14-6-37-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60520 - 1 9-31-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60520 - 2 12-31-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60520 - 3 14-32-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60520 - 4 3-5-38-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60520 - 5 1-9-38-7W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60544 - 1 7-26-37-8W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57718 - 1 1-29-43-9W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

57718 - 2 13-29-43-9W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

59996 - 1 1-29-43-9W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

45437 - 1 7-14-43-3W5 BE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

53737 - 1 2-14-43-3W5 BE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

54958 - 1 14-11-43-3W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

58048 - 1 2-14-43-3W5 WE 7.5 10000 18500 30 0.5 3000 0 0.0104 0.697 2.3

60062 - 2 12-20-37-7W5 B 7.5 10000 18500 30 0.5 3000 0 0.0104 0.700 2.3

60062 - 3 16-19-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.704 2.3

60062 - 4 12-20-37-7W5 B 7.5 10000 18500 30 0.5 3000 0 0.0104 0.707 2.3

60062 - 5 16-19-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.711 2.3

60311 - 4 6-30-37-7W5 PL 7.5 10000 18500 30 0.5 3000 0 0.0104 0.714 2.3

60311 - 8 13-10-037-07W5 7.5 10000 18500 30 0.5 3000 0 0.0104 0.717 2.3

60311 - 5 13-01-037-07W5 7.5 10000 18500 30 0.5 3000 0 0.0104 0.721 2.3

10-18-037-07W5 7.5 10000 18500 30 0.5 3000 0 0.0104 0.724 2.3

low pH Iron concentration H2S concentration Corrosion coupon data

chlorides concentration Manganese concentration CO2 Concentration

TDS concentration Bacteria levels (Serial or ATP) DeWaard

Pipeline risk based on analysis results of the Willesden Green field

Risks rating based on:

Send Location Receive LocationPipelines

Covered

Line

Length

(km)

Line

OD

(mm)

Wall

Thickness

(mm)

Treat.

Type

Batch

Chemical

Film

Thickness

(MIL)

Chem.

Vol

(L)

Diluent

(L)

Inj. Rate

(L/day)

Treatment

Frequency

Treatment


11-33-39-8W5 PL 9-36-39-9W5 PL 31390 - 2 4.23 219.1 5.6 inj C1218 continous review risks annually sales gas from 02-04

3-36-39-9W5 PL 9-36-39-9W5 PL 31390 - 3 1.24 219.1 5.6 film C1210 3 93 85 quarterly review risks annually

4-4-40-8W5 WE 11-33-39-8W5 PL 47376 - 1 1.7 88.9 3.2 inj C1218 6 continous Identified parameter risk

4-33-39-8W5 WE 11-33-39-8W5 PL 47376 - 2 0.6 88.9 3.2 film C1210 3 75 69 quarterly review risks annually sales gas from 16-02

4-4-40-8W5 PL 11-33-39-8W5 PL 47376 - 3 1.14 130 15.5 Not a bare steel pipeline proximity to Cow Lake; sales gas from 16-02

4-33-39-8W5 PL 11-33-39-8W5 PL 47376 - 4 0.49 130 15.5 Not a bare steel pipeline

1-2-40-9W5 BE 13-2-40-9W5 BE 58739 - 1 1.72 101 12 Line is not operated

8-10-40-8W5 WE 1-15-40-8W5 PL 58932 - 1 1.85 101 12 Not a bare steel pipeline



4-1-40-9W5 WE 1-2-40-9W5 PL 59587 - 1 1.06 168.3 4 inj C1218 continous review risks annually

10-30-39-8W5 WE 1-36-39-9W5 PL 59892 - 1 1.77 130 15.5 Not a bare steel pipeline proximity to North Sakatchewan River

14-33-39-8W5 WE 14-33-39-8W5 PL 59918 - 1 0.37 101 12 Not a bare steel pipeline treated via injection at 11-15 & 16-25

11-6-40-8W5 WE 8-2-40-9W5 PL59970-1; 59916-

1; 60045-13.19 168.3 4 film C1210 3 90 82 quarterly review risks annually

1-36-39-9W5 WE 3-36-39-9W5 PL 59971 - 1 1 130 15.5 Not a bare steel pipeline proximity to Cow Lake; combined with 54970

1-2-40-9W5 WE 6-2-40-9W5 B 59976 - 1 1.03 168.3 4 inj C1218 continous Identified parameter risk

14-5-40-8W5 WE 4-4-40-8W5 PL60003-1;

59943-1&22.1 130 15.5 Not a bare steel pipeline Proximity to North Saskatchewan River; Combined with 58050-1,3,4,5

6-2-40-9W5 B 3-2-40-9W5 PL 60006 - 1 0.54 130 15.5 Not a bare steel pipeline Proximity to North Saskatchewan River; Combined with 58050-2,1,4,5

9-36-39-9W5 PL 4-1-40-9W5 PL 60020 - 1 1.51 168.3 4 inj C1218 continous Identified chemical risks Proximity to North Saskatchewan River; Combined with 58050-2,3,1,5

10-28-39-8W5 WE 4-33-39-8W5 PL 60151 - 1 1.23 101 12 Not a bare steel pipeline combined with 58515-2,1; treated via injection at 16-25

10-28-39-8W5 WE 4-33-39-8W5 PL 60151 - 2 1.23 130 15.5 Not a bare steel pipeline

WEST Batch Table (2020)


Covered

Line

Length

(km)

Line

OD

(mm)

Wall

Thickness

(mm)

Treat.

Type

Batch

Chemical

Film

Thickness

(MIL)

Chem.

Vol

(L)

Diluent

(L)

Inj. Rate

(L/day)

Treatment

Frequency

Treatment


8-23-40-6W5 B 6-19-40-5W5 PL 19415 - 2 2.4 88.9 3.18 review risks annually

5-31-37-7W5 WE 12-31-37-7W5 PL 52744-2; 60520-2 0.39 114.3 4 film C1210 3 20 20 quarterly Multiple risks

13-31-37-7W5 BE 12-31-37-7W5 BE 53228 - 1 0.73 88.9 4 Line is not operated

1-35-37-8W5 WE 3-34-37-8W5 PL 53932 - 1 2.94 168.3 4 review risks annually

3-11-38-8W5 WE 16-2-38-8W5 B 54016-1; 54970-1 1.01 168.3 4.8 film C1210 3 25 23 quarterly review risks annually

16-35-37-8W5 PL 16-2-38-8W5 B 55029 - 1 2.7 168.3 4 film C1210 3 67 61 quarterly review risks annually

16-2-38-8W5 B 16-35-37-8W5 PL 55029 - 2 2.7 168.3 4 review risks annually

15-35-37-8W5 WE 16-35-37-8W5 PL 55029 - 3 0.27 88.9 3.2 review risks annually


3-34-37-8W5 PL 1-33-37-8W5 PL 55030 - 1 0.59 168.3 4 review risks annually

16-35-37-8W5 PL 1-35-37-8W5 PL 55063 - 1 1.53 168.3 4 review risks annually

1-35-37-8W5 PL 16-35-37-8W5 PL 55063 - 2 1.53 168.3 4 review risks annually lines has been discontinued






2-35-37-8W5 WE 1-35-37-8W5 PL 57601 - 1 0.19 88.9 4 film C1210 3 26 24 quarterly review risks annually

10-2-42-8W5 WE 10-15-42-8W5 S 58050-2,3,4,5,1 3.82 60.3 3.9 film C1210 3 44 40 quarterly review risks annually


6-25-37-8W5 PL 7-26-37-8W5 PL 59079 - 1 1.1 114.3 4 film C1210 3 149 135 quarterly review risks annually treated via injection at 03-23






12-28-37-8W5 WE 1-34-37-8W5 PL 59924 - 1 3.75 130 15.5 Not a bare steel pipeline treated via injection at 11-15 & 16-25; Big Beaver Crossing

1-19-42-7W5 WE 14-17-42-7W5 PL 59941 - 1 1.14 101 12 Not a bare steel pipeline treated via injection at 11-15 & 16-25

3-23-38-7W5 WE 12-14-38-7W5 PL 59986 - 1 1.33 168.3 4 inj C1218 7 continous Identified parameter risk proximity to Cow Lake; combined with 54016

5-23-38-7W5 BE 3-23-38-7W5 BE 59986 - 2 0.84 114.3 3.2 Line is not operated proximity to Cow Lake

12-14-38-7W5 PL 13-10-38-7W5 PL 59986 - 3 2.52 168.3 4 inj C1218 continous Environmental risk

9-15-38-7W5 B 12-14-38-7W5 PL 59986 - 4 0.09 168.3 4.8 inj C1218 continous Multiple risks

12-14-38-7W5 PL 9-15-38-7W5 B 59986 - 5 0.09 168.3 4.8 inj C1218 continous Identified parameter risk

1-9-38-7W5 WE 5-10-38-7W5 PL 59986 - 7 1.1 114.3 4 inj C1218 continous Identified parameter risk proximity to Big Beaver Creek

5-3-38-7W5 WE 4-10-38-7W5 PL 59986 - 8 1.89 114.3 4 film C1210 3 37 34 quarterly Identified chemical risks

13-10-38-7W5 PL 5-10-38-7W5 PL 59986 - 9 1.02 130 15.5 inj C1218 continous Not a bare steel pipeline


5-10-38-7W5 WE 6-10-38-7W5 PL 59986 - 11 0.53 114.3 4 Identified parameter risk Proximity to North Saskatchewan River; Combined with 58050-2,3,4,5

3-3-39-5W5 WE 8-4-39-5W5 PL 60041 - 1 1.48 97 10 Not a bare steel pipeline Proximity to North Saskatchewan River; Combined with 58050-2,3,4,1

7-18-37-7W5 PL 7-30-37-7W5 PL 60062 - 1 3.62 168.3 4 film C1210 3 210 191 quarterly Environmental risk combined with 58515-1,3; treated via injection at 16-25

7-30-37-7W5 PL 6-25-37-8W5 PL 60311 - 1 2.46 130 15.5 Not a bare steel pipeline treated via injection at 11-15

16-8-37-7W5 WE 10-18-37-7W5 PL 60311 - 2 3.26 130 15.5 Not a bare steel pipeline Combined with 59916 & 60045

14-6-37-7W5 WE 10-18-37-7W5 PL 60311 - 3 2.97 130 15.5 Not a bare steel pipeline treated via injection at 04-04

9-31-37-7W5 PL 16-35-37-8W5 PL 60520 - 1 3.94 168.3 4 inj C1218 continous Identified parameter risk proximity to Clearwater Creek; treated via injection at 03-23

14-32-37-7W5 PL 9-31-37-7W5 PL 60520 - 3 1.67 168.3 4 inj C1218 continous review risks annually proximity to Clearwater Creek; treated via injection at 03-23

3-5-38-7W5 PL 14-32-37-7W5 PL 60520 - 4 0.12 168.3 4 inj C1218 continous Identified parameter risk proximity to Clearwater Creek; treated via injection at 03-23

1-9-38-7W5 WE 3-5-38-7W5 PL 60520 - 5 4.33 168.3 4 inj C1218 continous Multiple risks treated via injection at 03-23


12-20-37-7W5 B 16-19-37-7W5 PL 60062 - 2 0.66 168.3 4 film C1210 20 20 quarterly Identified parameter risk cant find on ABADATA

16-19-37-7W5 PL 12-20-37-7W5 B 60062 - 3 0.66 168.3 4 film C1210 20 20 quarterly Identified parameter risk

12-20-37-7W5 B 16-19-37-7W5 PL 60062 - 4 0.66 130 15.5 Not a bare steel pipeline



13-10-037-07W5 13-01-037-07W5 4.03 168.3 film C1210 85 85 quarterly new line



SOUTH Batch Table (2020)


Covered

Line

Length

(km)

Line

OD

(mm)

Wall

Thickness

(mm)

Treat.

Type

Batch

Chemical

Film

Thickness

(MIL)

Chem.

Vol

(L)

Diluent

(L)

Inj. Rate

(L/day)

Treatment

Frequency

Treatment


2-4-42-7W5 CS 10-33-41-7W5 PL 42289 - 7 0.65 168.3 4 review risks annually

2-15-42-7W5 WE 4-10-42-7W5 PL 42289 - 9 2.78 114.3 4.8 film C1210 3 39 35 quarterly Environmental risk

5-11-42-7W5 WE 4-10-42-7W5 PL 42289 - 10 2.5 114.3 4 Environmental risk

11-21-41-7W5 WE 7-29-41-7W5 PL 43702 - 1 2.38 168.3 4 inj C1218 continous review risks annually

11-4-42-7W5 WE 2-4-42-7W5 CS 43702 - 2 1.1 114.3 4.8 review risks annually

6-3-42-7W5 WE 2-4-42-7W5 CS 43702 - 3 1.8 168.3 4 review risks annually


7-29-41-7W5 PL 12-33-41-7W5 PL 43702 - 5 2.25 168.3 4 inj C1218 continous Environmental risk

12-33-41-7W5 PL 2-4-42-7W5 CS 43702 - 6 1.42 168.3 4 inj C1218 continous review risks annually

8-19-41-7W5 WE 7-29-41-7W5 PL 43702 - 7 2.8 114.3 4.8 film C1210 3 41 37 quarterly Environmental risk

1-33-41-7W5 WE 10-33-41-7W5 PL 43702 - 8 0.91 88.9 4 Environmental risk

14-22-41-7W5 BE 11-21-41-7W5 BE 44436 - 1 1.52 60.3 3.2 Line is not operated


5-20-41-7W5 WE 8-19-41-7W5 PL 46735 - 2 0.22 88.9 4.8 film C1210 3 20 20 quarterly review risks annually

13-20-41-7W5 WE 15-20-41-7W5 PL 48160 - 1 0.54 114.3 4.8 review risks annually sales gas from 16-02

8-3-41-7W5 WE 11-21-41-7W5 PL 52347 - 1 1.1 168.3 4 film C1210 3 104 95 quarterly Environmental risk

13-35-40-7W5 WE 8-3-41-7W5 PL 52347 - 2 2.36 168.3 4 film C1210 3 52 47 quarterly review risks annually


2-29-41-7W5 WE 2-29-41-7W5 PL 53368 - 1 0.12 88.9 4 Multiple risks





1-9-41-7W5 WE 16-9-41-7W5 PL 54571 - 1 1.47 114.3 4 film C1210 3 21 20 quarterly Environmental risk treated via injection at 14-18

4-12-41-7W5 WE 1-11-41-7W5 PL 55270 - 1 0.61 114.3 4 inj C1218 20 20 continous review risks annually

1-11-41-7W5 WE 1-10-41-7W5 PL 55273 - 1 1.63 114.3 4 film C1210 3 26 24 quarterly Environmental risk




13-11-41-7W5 WE 8-10-41-7W5 PL 57486 - 1 1.23 88.9 4 film C1210 3 20 20 quarterly Identified parameter risk




6-18-41-5W5 WE 14-18-41-5W5 PL 58419 - 1 0.75 101 12 inj C1218 continous Not a bare steel pipeline

14-18-41-5W5 WE 2-19-41-5W5 PL 58419 - 2 0.98 101 12 inj C1218 9 continous Not a bare steel pipeline

16-25-39-7W5 WE 4-12-41-7W5 PL 58515-1,2,3 15.44 114.3 4 inj C1218 4 continous review risks annually

3-21-41-7W5 WE 13-16-41-7W5 B 58743 - 1 0.53 101 12 Not a bare steel pipeline



4-12-41-7W5 WE 1-10-41-7W5 PL 59891 - 1 2.23 114.3 4 inj C1218 continous Identified parameter risk treated via injection at 04-04

14-7-41-6W5 PL 4-12-41-7W5 PL 59959 - 1 3.17 168.3 4 inj C1218 continous review risks annually treated via injection at 04-04 (inj based on surface)


1-17-41-6W5 PL 15-7-41-6W5 PL 59959 - 3 2.86 168.3 4 inj C1218 continous Identified parameter risk partially treated via injection at 11-15 & 16-25 (1km will be batched)

15-8-41-6W5 PL 2-17-41-6W5 PL 59959 - 4 0.31 101 12 Not a bare steel pipeline batch volume includes appr. 1km of the 52347-1 segment

2-15-41-6W5 WE 11-15-41-6W5 PL 59959 - 5 1.12 101 12 Not a bare steel pipeline Combined with 60520-2

11-15-41-6W5 WE 8-16-41-6W5 PL 59959 - 6 2.12 168.3 4 inj C1218 continous Identified parameter risk proximity to North Saskatewan River

8-16-41-6W5 WE 4-16-41-6W5 PL 59959 - 7 2.07 168.3 4 inj C1218 continous Environmental risk proximity to Little Beaver Creek

1-26-41-7W5 WE 8-27-41-7W5 PL 60221 - 1 2.28 101 12 Not a bare steel pipeline confirm operating status

7-27-41-7W5 PL 3-27-41-7W5 PL 60221 - 2 0.77 101 12 Not a bare steel pipeline treated via injection at 04-04

8-27-41-7W5 PL 7-27-41-7W5 PL 60221 - 3 0.11 101 12 Not a bare steel pipeline treated via injection at 11-15 & 16-25

11-19-41-5W5 PL 15-15-41-6W5 PL 60222 - 1 5.5 168.3 4 inj C1218 continous Identified parameter risk Combined with 59970 & 60045

2-19-41-5W5 PL 11-19-41-5W5 PL 60222 - 2 1.03 130 15.5 Not a bare steel pipeline treated via injection at 11-15



1-29-43-9W5 WE 4-32-43-9W5 PL 57718 - 1 2.28 88.9 4 Identified chemical risks treated via injection at 03-23

13-29-43-9W5 WE 13-29-43-9W5 PL 57718 - 2 0.09 88.9 4 Identified parameter risk treated via injection at 04-04

1-29-43-9W5 WE 6-21-43-9W5 B 59996 - 1 1.72 130 15.5 Not a bare steel pipeline Combined with 59916 & 59970

7-14-43-3W5 BE 6-23-43-3W5 BE 45437 - 1 2.47 88.9 4 Line is not operated crosses Prairie Creek

2-14-43-3W5 BE 7-14-43-3W5 BE 53737 - 1 0.46 88.9 4.8 Line is not operated

14-11-43-3W5 WE 2-14-43-3W5 B 54958 - 1 0.74 88.9 4 film C1210 3 20 20 May/Nov Identified chemical risks combined with 52744-2

2-14-43-3W5 WE 10-11-43-3W5 PL 58048 - 1 0.63 101 12 Not a bare steel pipeline treated via injection at 03-23

NORTH Batch Table (2020)

SYSTEM OVERVIEW

Local Authorities Involvement FERRIER

Local Authorities Involvement

TypeName

The local authority is an MD, County, Indian Reserve, Municipality or Special Area in which the

property is located or may impact. The involvement of the local authority will vary depending on

where the incident has occurred, as the preparedness, response capability, and willingness to

participate will vary across the province. The company's primary responsibility is to manage the

public safety measures within the hazard area or defined EPZ. Support from the local authority

may be provided within these areas, however, is primarily focused on the areas beyond should the

incident escalate and pose a threat to the public. The local authority can usually be expected to

provide assistance with public safety measure, evacuations, roadblocks, and general

communications with members of the public.

The local authorities defined for this property and their declared limits of support are:

Local Authorities

Date Contacted

MOUNTAIN VIEW County 5/19/2020 10:41:00AM

Mountain View County will provide basic support in the event of an emergency with

roadblocks, including aspects of both physical barricades and personnel. In the

event of an evacuation, it is essential to contact the Mountain View County Alberta

Emergency Management for coordination purposes. For 24-hour emergency contact

the Emergency Liaison Officers by cell, (403) 586-0040, or 911.

The County can dispatch primary support services of between 2 and 10 personnel.

The County has a number of 4X4 vehicles. As they do their own road maintenance a

variety of heavy equipment would also be available. Communications within the

County during an emergency are through cell phones or mobile radios.

Mountain View County has requested that 1 digital copy (CD or USB) of any ERP

with which they're associated, be sent to their mailing address upon completion.

Support Role:

PONOKA County 6/9/2020 10:21:00AM

The County can provide assistance if an emergency were to reach beyond the

scope of the company's capabilities to effectively manage. Assistance roles and

responsibilities may include roadblock equipment and personnel, evacuation

assistance and coordination, and activation of various predetermined evacuation

centres.

Though the County of Ponoka will provide some assistance, it is their expectation

that industry take the lead role when it comes to such things as well blow-outs. Any

incident requiring formal response should be reported to Dennis Jones (Regional

Fire a Chief & DEM) and/or Charlie Cutforth (CAO & DDEM).

Numerous assorted roadblock equipment and signage is kept both in Ponoka, and

Rimbey. A mobile command centre with Hazmat and decontamination capability is

also stored in Ponoka, This includes Heavy equipment and assorted vehicles may

be available if needed and include loaders, gravel trucks, road graders, CAT

scrapers, trailers, and 4x4 trucks. A community spill response trailer is also available

through the fire services.

The County through FCSS keeps an inventory and contact list of community centres

that may be used as evacuation centres in the case of an emergency. The particular

Support Role:




centre used at any given time would depend on the location of the emergency.

The core administration and supervisory team (6 people) would be able to assist in

an emergency.

The primary communication method within the County would be by cell phone.

Coverage is pretty good across the county, though there are some dead spots. All

personnel have cell phones. Both fire services have digital/analog radios and all

public works staff have analog radios as well.

Ponoka has their own Emergency Response Manual in place, included is a section

that deals with the oil and gas industry. Ponoka County would like a hard or digital

copy of all company ERP's. Digital copies can be sent to

[email protected]

CLEARWATER County 3/9/2020 4:07:00PM

Emergency Contacts

Main

Clearwater County Office 24 Hour Manager On-call Number: (403) 844-8500

Christine Heggart (DEM)

Office: (403) 845-4444

Cell: (403) 844-8500

Fire Chief

24 Hour on call cell: (403) 845-2200

Clearwater County requests your Emergency Response Plan reflects the following

roles and responsibilities of our jurisdiction.

-Initiates and manages the local disaster services response in accordance with

County Policy

-May dispatch representative(s) to the Government’s off-site Emergency

Coordination Centre

-Ensures all local emergency services and resources are available in accordance

with County Policy

-If required, activates the Municipal Emergency Operation Centre and coordinates

activities at this centre

-May assist with set up and maintenance of road blocks in accordance with County

Policy

-Assists with Fire Protection in accordance with County Policy

-If necessary, may declare a State of Local Emergency (SOLE) to provide local

authorities with special powers

-Supports the Company in dealing with the emergency in accordance with County

Policy.

The County will require a copy of all AER approved plans. Digital copies are

sufficient and can be sent to [email protected].

Support Role:




Date ContactedTypeName

Municipalities Impacted by the EPZ

Support Role:



N FERRIER SYSTEM PIPELINE LIST

Pipeline InformationYANGARRA RESOURCES LTD. NORTH FERRIER

CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH

(KM)STH2SMOPSUBFCTOFCFROMOPERATORUPI

019415002 YANGARRA RESOURCES CORP. 08-23-040-06W5 B 06-19-040-05W5 PL NG 1720 0 O 2.40 88.9 3.18 S 5LX X42 W 8

042289007 YANGARRA RESOURCES CORP. 02-04-042-07W5 CS 10-33-041-07W5 PL NG 9850 0 O 0.65 168.3 4.00 S Z245.1 3591 W 58

042289008 YANGARRA RESOURCES CORP. 10-04-042-07W5 BE 11-04-042-07W5 BE NG 0 0 D 0.42 114.3 4.80 S Z245.1 3592 W 33

042289009 YANGARRA RESOURCES CORP. 02-15-042-07W5 WE 04-10-042-07W5 PL NG 9930 0 O 2.78 114.3 4.80 S Z245.1 3592 W 33 CC

042289010 YANGARRA RESOURCES CORP. 05-11-042-07W5 WE 04-10-042-07W5 PL NG 9930 0 D 2.50 114.3 4.00 S Z245.1 3592 W 40 CC

043702001 YANGARRA RESOURCES CORP. 11-21-041-07W5 WE 07-29-041-07W5 PL NG 9930 2.00 O 2.38 168.3 4.00 S Z245.1 3591 W 58

043702002 YANGARRA RESOURCES CORP. 11-04-042-07W5 WE 02-04-042-07W5 CS NG 9930 2.00 O 1.10 114.3 4.80 S Z245.1 3591 W 33

043702003 YANGARRA RESOURCES CORP. 06-03-042-07W5 WE 02-04-042-07W5 CS NG 9930 2.00 O 1.80 168.3 4.00 S Z245.1 3591 W 58


043702005 YANGARRA RESOURCES CORP. 07-29-041-07W5 PL 12-33-041-07W5 PL NG 9930 2.00 O 2.25 168.3 4.00 S Z245.1 3591 W 58 CC

043702006 YANGARRA RESOURCES CORP. 12-33-041-07W5 PL 02-04-042-07W5 CS NG 9930 2.00 O 1.42 168.3 4.00 S Z245.1 3591 W 58

043702007 YANGARRA RESOURCES CORP. 08-19-041-07W5 WE 07-29-041-07W5 PL NG 9930 2.00 O 2.80 114.3 4.80 S Z245.1 3592 W 33 CC

043702008 YANGARRA RESOURCES CORP. 01-33-041-07W5 WE 10-33-041-07W5 PL NG 9930 2.00 O 0.91 88.9 4.00 S Z245.1 3591 W 31 CC


045437001 YANGARRA RESOURCES CORP. 07-14-043-03W5 BE 06-23-043-03W5 BE OE 0 0 D 2.47 88.9 4.00 S Z245.1 2901 W 38

046735001 YANGARRA RESOURCES CORP. 13-17-041-07W5 BE 08-19-041-07W5 BE NG 0 2.00 D 0.70 88.9 4.00 S Z245.1 3592 W 31

046735002 YANGARRA RESOURCES CORP. 05-20-041-07W5 WE 08-19-041-07W5 PL NG 9930 2.00 O 0.22 88.9 4.80 S Z245.1 3592 W 26 UN


048160001 YANGARRA RESOURCES CORP. 13-20-041-07W5 WE 15-20-041-07W5 PL NG 9930 0 O 0.54 114.3 4.80 S Z245.1 3592 W 33









Monday, June 15, 2020 Page 1 of 4


CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH





054958001 YANGARRA RESOURCES CORP. 14-11-043-03W5 WE 02-14-043-03W5 B OE 9920 0 O 0.74 88.9 4.00 S Z245.1 3592 W 31







057718001 YANGARRA RESOURCES CORP. 01-29-043-09W5 WE 04-32-043-09W5 PL NG 9930 0 O 2.28 88.9 4.00




058048001 YANGARRA RESOURCES CORP. 02-14-043-03W5 WE 10-11-043-03W5 PL NG 8270 0 O 0.63 101.0 12.00 G FPLP 601 M 0

058418001 YANGARRA RESOURCES CORP. 08-16-041-06W5 WE 15-09-041-06W5 PL NG 9930 0 D 1.10 101.0 12.00 G FPLP 601 M 0




058515002 YANGARRA RESOURCES CORP. 14-13-040-07W5 PL 04-12-041-07W5 PL NG 9930 0 O 8.15 114.3 4.00 S Z245.1 3592 W 40 CC

058515003 YANGARRA RESOURCES CORP. 11-12-040-07W5 PL 14-13-040-07W5 PL NG 9930 0 O 2.19 114.3 4.00 S Z245.1 3592 W 40

058743001 YANGARRA RESOURCES CORP. 03-21-041-07W5 WE 13-16-041-07W5 B OE 9930 0 O 0.53 101.0 12.00 G FPLP 601 M 0

058811001 YANGARRA RESOURCES CORP. 16-03-044-10W5 BE 16-03-044-10W5 BE NG 0 0 D 0.15 101.0 12.00 G FPLP 601 M 0

059001001 YANGARRA RESOURCES CORP. 16-03-044-10W5 CS 07-03-044-10W5 PL NG 9930 0 O 0.92 88.9 4.00 S Z245.1 3592 W 31


059259001 YANGARRA RESOURCES CORP. 15-31-041-05W5 WE 16-31-041-05W5 PL NG 9930 0 D 0.28 88.9 4.00 S Z245.1 2901 W 38




CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH


059556001 YANGARRA RESOURCES CORP. 15-36-039-06W5 WE 10-36-039-06W5 PL NG 9930 0 O 0.41 101.0 12.00 G FPLP 601 M



059941001 YANGARRA RESOURCES CORP. 01-19-042-07W5 WE 14-17-042-07W5 PL OE 4960 0 O 1.14 101.0 12.00 G FPLP 601 M




059959004 YANGARRA RESOURCES CORP. 15-08-041-06W5 PL 02-17-041-06W5 PL NG 9930 0 O 0.31 101.0 12.00 G FPLP 601 M



059959007 YANGARRA RESOURCES CORP. 08-16-041-06W5 WE 04-16-041-06W5 PL NG 9930 0 O 2.07 168.3 4.00 S Z245.1 3592 W 58 C

059996001 YANGARRA RESOURCES CORP. 01-29-043-09W5 WE 06-21-043-09W5 B NG 9930 0 O 1.72 130.0 15.50 G FPLP 601 M








060446001 YANGARRA RESOURCES CORP. 07-03-044-10W5 PL 13-34-043-10W5 B NG 9930 0 O 1.91 130.0 15.50 G FPLP 601 M

060446002 YANGARRA RESOURCES CORP. 13-34-043-10W5 B 07-03-044-10W5 PL NG 9930 0 O 1.91 130.0 15.50 G FPLP 601 M



S FERRIER SYSTEM PIPELINE LIST

Pipeline InformationYANGARRA RESOURCES LTD. SOUTH FERRIER

CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH


037170001 YANGARRA RESOURCES CORP. 07-28-033-01W5 BE 15-29-033-01W5 BE NG 0 0 D 1.63 88.9 12.17 P 3408 9 B 50





054970001 YANGARRA RESOURCES LTD. 03-11-038-08W5 PL 16-02-038-08W5 B NG 9930 0 O 0.82 168.3 4.80 S Z245.1 3592 W 48

055029001 YANGARRA RESOURCES CORP. 16-35-037-08W5 PL 16-02-038-08W5 B NG 9930 0 O 2.70 168.3 4.00 S Z245.1 2901 W 72

055029002 YANGARRA RESOURCES CORP. 16-02-038-08W5 B 16-35-037-08W5 PL NG 9930 0 O 2.70 168.3 4.00 S Z245.1 2901 W 72





055033002 YANGARRA RESOURCES CORP. 15-26-037-08W5 WE 01-35-037-08W5 PL NG 9930 0 P 0.77 130.0 15.50 G FPLP 601 M

















CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH


059986002 YANGARRA RESOURCES CORP. 05-23-038-07W5 BE 03-23-038-07W5 BE NG 0 0 D 0.84 114.3 3.20 S Z245.1 3592 W 0 C

059986003 YANGARRA RESOURCES CORP. 12-14-038-07W5 PL 13-10-038-07W5 PL NG 9930 0 O 3.54 168.3 4.00 S Z245.1 3592 W 58 R






059986010 YANGARRA RESOURCES CORP. 13-10-038-07W5 BE 15-09-038-07W5 BE NG 0 0 A 1.02 168.3 4.00 S Z245.1 3592 W 0 R

059986011 YANGARRA RESOURCES CORP. 05-10-038-07W5 BE 06-10-038-07W5 BE NG 0 0 A 0.53 114.3 4.00 S Z245.1 3592 W 0


060062001 YANGARRA RESOURCES CORP. 07-18-037-07W5 PL 07-30-037-07W5 PL NG 9930 0 O 3.62 168.3 4.00 S Z245.1 2901 W 0 C










060311006 YANGARRA RESOURCES CORP. 14-06-037-07W5 WE 10-18-037-07W5 PL NG 9930 0 O 2.97 130.0 15.50 G FPLP 601 M C


060311008 YANGARRA RESOURCES CORP. 13-10-037-08W5 WE 13-01-037-08W5 PL NG 9930 0 O 4.14 168.3 4.00 S Z245.1 3592 W 58 C







CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH






061501001 YANGARRA RESOURCES CORP. 05-17-037-07W5 WE 10-18-037-07W5 PL NG 9930 0 P 1.21 168.3 4.00 S Z245.1 3592 W 58 C

061613001 YANGARRA RESOURCES CORP. 16-08-037-07W5 BE 08-18-037-07W5 BE OE 0 0 D 1.80 88.9 4.00 S Z245.1 2901 W 0 C



W FERRIER SYSTEM PIPELINE LIST

Pipeline InformationYANGARRA RESOURCES LTD. WEST FERRIER

CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH









057466001 YANGARRA RESOURCES LTD. 10-35-041-08W5 WE 10-02-042-08W5 PL NG 4950 0 O 2.44 91.0 8.00 G FSLP 750 M 0

058050001 YANGARRA RESOURCES CORP. 04-14-042-08W5 WE 10-15-042-08W5 S NG 4950 0 O 1.14 60.3 3.18 S 5L B W 19


058050003 YANGARRA RESOURCES CORP. 14-02-042-08W5 PL 14-02-042-08W5 PL NG 4950 0 O 0.10 60.3 3.90 S Z245.1 2901 W 13 CC













059943003 YANGARRA RESOURCES CORP. 08-10-040-08W5 WE 04-04-040-08W5 PL NG 9930 0 P 4.16 168.3 4.00 S Z245.1 3592 W 58



059976001 YANGARRA RESOURCES CORP. 01-02-040-09W5 WE 06-02-040-09W5 B NG 9930 0 O 1.03 168.3 4.00 S Z245.1 3592 W 58


Pipeline InformationYANGARRA RESOURCES LTD. WEST FERRIER

CROSSINGSTRESS

LVJOINTSGRADETYPE

MAT

CODE

WT

(mm)

DI

(mm)

LGTH









AREA OPERATORS

Company Area Operators FERRIER

Company Name Office Name

Area Operators Description

Office Phone Numbers

BONAVISTA OIL & GAS LTD. Head Office Phone: (403) 213-4300

700, 311 - 6 Avenue SW Fax:

Calgary, Alberta T2P 3H3 24hr: (403) 213-4300

HARVEST OPERATIONS CORP. Head Office Phone: (403) 265-1178

2100, 330 - 5 Avenue SW Fax:

Calgary, Alberta T2P 0L4 24hr: (800) 760-2826

KEYERA ENERGY LTD. Head Office Phone: (403) 205-8300


Calgary, Alberta T2P 3N4 24hr: (403) 205-8300

NAL RESOURCES LIMITED Head Office Phone: (403) 294-3600


Calgary, Alberta T2P 0S2 24hr: (403) 294-3600

PLAINS MIDSTREAM CANADA ULC Head Office Phone: (403) 298-2100

1400-607 8 Ave SW Fax:

Calgary, Alberta T2P0A7 24hr: (866) 875-2554

TAQA NORTH LTD. Head Office Phone: (403) 724-5000

2100, 308 - 4 Avenue SW Fax:

Calgary, Alberta 24hr: (403) 724-5000

BAYTEX ENERGY LTD. Head Office Phone: (403) 269-4282

2200, 205 - 5 Avenue SW Fax:

Calgary, Alberta T2P 2V7 24hr:

CANADIAN NATURAL RESOURCES

LIMITED

Head Office Phone: (403) 517-6700

2500, 855 - 2 Street SW Fax:

Calgary, Alberta T2P 4J8 24hr:

CANLIN ENERGY CORPORATION Head Office Phone: (403) 266-6393

1000, 111 - 5 Avenue SW Fax:

Calgary, Alberta T2P 3Y6 24hr:

ENERPLUS CORPORATION Head Office Phone: (403) 298-2200

3000 333 7 AVE SW Fax:

Calgary, Alberta T2P2Z1 24hr:

ENTRADA RESOURCES INC. Head Office Phone: (587) 393-0932

717 - 7 Avenue SW Fax:

Calgary, Alberta T2P 0Z3 24hr: (844) 547-2666

FIRENZE ENERGY LTD. Head Office Phone: (403) 410-6790

2550-700 2 St SW, c/o Toscana Resource

Corporation

Fax:

Calgary, Alberta T2P2W2 24hr:

GAIN ENERGY LTD. Head Office Phone: (403) 294-1336

30th Floor, 520 - 3 Avneue SW Fax:

Calgary, Alberta T2P 0R3 24hr:

June 15, 2020

Page 1 of 4YANGARRA RESOURCES LTD.





INPLAY OIL CORP. Head Office Phone: (587) 955-9570


Calgary, Alberta T2P 3G4 24hr: (403) 648-8201

NOVA GAS TRANSMISSION LTD. Head Office Phone: (403) 920-6233

450 - 1 Street SW Fax:

Calgary, Alberta T2P 5H1 24hr:

OBSIDIAN ENERGY LTD. Head Office Phone: (403) 777-2500


Calgary, Alberta T2P 1K3 24hr: (877) 792-2990

PARAMOUNT RESOURCES LTD. Head Office Phone: (403) 290-3600

4700, 888 - 3 Street SW Fax:

Calgary, Alberta T2P 5C5 24hr:

PEMBINA PIPELINE CORPORATION Head Office Phone: (403) 231-7500

2000, 700 - 9 Avenue SW Fax:

Calgary, Alberta T2P 3V4 24hr:

REPSOL OIL & GAS CANADA INC. Head Office Phone: (403) 237-1234

2000, 888 - 3 Street SW Fax:

Calgary, Alberta T2P 5C5 24hr: (888) 723-9576

SHELL CANADA LIMITED Head Office Phone: (403) 691-3111

400 - 4 Avenue SW, PO Box 100 Stn M Fax:


BACCALIEU ENERGY INC. Head Office Phone: (403) 261-1500


Calgary, Alberta T2P 3M3 24hr:

HARD ROCK RESOURCES LTD. Head Office Phone: (403) 340-2550

Box 326 Fax:

Blackfalds, Alberta T0M 0J0 24hr:

ORLEN UPSTREAM CANADA LTD. Head Office Phone: (403) 265-4115

400, 850 - 2 Street SW Fax: (403) 232-8463

Calgary, Alberta T2P 0R8 24hr: (866) 835-6132

SITKA EXPLORATION LTD. Headoffice Phone: (403) 237-0900

1500-505 3 St SW Calgary, AB T2P 3E6 Fax:

24hr:

WHITECAP RESOURCES INC. Head Office Phone: (403) 266-0767

500-222 3 Ave SW Fax:

Calgary, Alberta T2P0B4 24hr:

BELLATRIX EXPLORATION LTD. Head Office Phone: (403) 266-8670

2300 530 8 AVE SW Fax:

Calgary, Alberta T2P3S8 24hr:

June 15, 2020






SECURE ENERGY SERVICES INC. Head Office Phone: (403) 984-6100

1900-205 5 Ave SW Fax:

Calgary, Alberta T2P2V7 24hr:

SIGNALTA RESOURCES LIMITED Head Office Phone: (403) 265-5091

1000, 605 - 5 Avenue SW Fax:


SINOPEC DAYLIGHT ENERGY LTD. Head Office Phone: (403) 266-6900

2700, 112 - 4 Avenue SW Fax: (403) 266-6988

Calgary, Alberta T2P 0H3 24hr: (866) 616-6300

GEAR ENERGY LTD. Head Office Phone: (403) 262-0242


Calgary, Alberta T2P 3N8 24hr:

CERTUS OIL & GAS INC. Head Office Phone: (587) 323-8390


Calgary, Alberta T2P 3M3 24hr: (800) 887-0605

June 15, 2020



June 15, 2020


PIGGING SCHEDULE

REPAIR LOG

CORROSION CONTROL

CHEMICAL INHIBITOR PROGRAM

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HARVEST OPERATIONS CORP.023315001



PEMBINA PIPELINE CORPORATION055740004



CANLIN ENERGY CORPORATION030679004


BONAVISTA ENERGY CORPORATION022220001

ENTRADA RESOURCES INC.058619001



ENERPLUS CORPORATION033539001





TAQA NORTH LTD.024521001




GAIN ENERGY LTD.056434004


KEYERA ENERGY LTD.054972001

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INPLAY OIL CORP.050315035

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Issue Date: April 20, 2020 Area: Ferrier

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PIPELINE INTEGRITY AND OPERATIONS MANUAL · The Pipeline Integrity and Operations Manual is...

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Transcript of PIPELINE INTEGRITY AND OPERATIONS MANUAL · The Pipeline Integrity and Operations Manual is...