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WELL COMPLETION, 
MAINTENANCE AND 
ABANDONMENT 
GUIDELINE 
April | 2012 
 
 
Version 1.8
Well Completion, Maintenance and Abandonment Guideline, Version 1.8 
 
BC Oil & Gas Commission i 
 
CONTENTS 
MANUAL REVISIONS .............................................................................................. 1 
SUMMARY OF REVISIONS ............................................................................................... 1 
1 PREFACE .............................................................................................................. 2 
1.1 PURPOSE .......................................................................................................... 2 
1.2 SCOPE .............................................................................................................. 2 
1.3 HOW TO USE THIS MANUAL................................................................................. 3 
1.4 ADDITIONAL GUIDANCE ...................................................................................... 3 
1.4.1 Feedback .............................................................................................. 4 
1.4.2 Frequently Asked Questions ................................................................. 4 
2 WELL EQUIPMENT ............................................................................................... 5 
2.1 WELLHEADS ...................................................................................................... 5 
2.2 TUBING ............................................................................................................ 5 
2.3 PACKERS ........................................................................................................... 5 
2.4 SUBSURFACE SAFETY VALVES ................................................................................ 6 
2.5 OIL WELLS ........................................................................................................ 6 
2.6 FENCING ........................................................................................................... 7 
2.7 LEAK DETECTION ................................................................................................ 7 
3 WELL SERVICING OPERATIONS ............................................................................ 9 
3.1 WELL SERVICING OPERATIONS .............................................................................. 9 
3.2 COMPLETIONS / WORKOVERS / MAINTENANCE ....................................................... 9 
3.2.1 Shallow Fracturing ............................................................................... 9 
3.2.2 Commingling ...................................................................................... 10 
3.3 WELL SUSPENSION ........................................................................................... 11 
3.3.1 Definitions .......................................................................................... 11 
3.3.2 Observation Wells .............................................................................. 11 
3.3.3 Suspension Requirements .................................................................. 12 
3.3.4 Packer Testing .................................................................................... 17 
3.3.5 Long Term Inactive Wells ................................................................... 17 
3.3.6 Reactivating Suspended Wells ........................................................... 17 
3.3.7 Information / Reporting Requirements .............................................. 17 
3.4 CLASSIFICATION OF LOW AND MEDIUM RISK GAS WELLS ......................................... 19 
3.5 WELL ABANDONMENT ...................................................................................... 20 
4 WELL SERVICING EQUIPMENT AND PROCEDURES ............................................. 21 
4.1 BLOWOUT PREVENTION ..................................................................................... 21 
4.1.1 Well Servicing Blowout Prevention .................................................... 21 
4.1.2 BOP Equipment Classes ...................................................................... 21 
4.1.3 General .............................................................................................. 21 
4.1.4 Accumulator systems ......................................................................... 22 
4.1.5 Requirements Specific to Class A Systems .......................................... 23 
4.1.5 Requirements Specific to Class B and C Systems ................................ 23 
4.1.6 Line Requirements ............................................................................. 23 
4.1.7 Stabbing Valve ................................................................................... 24 
4.1.8 Blowout Prevention Manifold ............................................................ 24 
4.1.9 Testing of Blowout Prevention Equipment......................................... 24 
4.1.10 Special Sour Wells ......................................................................... 25 
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4.1.11 Slickline, Snubbing and Coil Tubing Operations ............................ 25 
4.1.12 Hammer Unions ............................................................................ 25 
4.1.13 Diagrams of Blowout Prevention Systems for Well Servicing ....... 26 
4.2 PERSONNEL ..................................................................................................... 31 
4.3 FIRE PRECAUTIONS AND EQUIPMENT SPACING ....................................................... 32 
4.3.1 Engines ............................................................................................... 32 
4.3.2 Fuel .................................................................................................... 32 
4.3.3 Smoking ............................................................................................. 32 
4.3.4 Recommended Spacing Distances...................................................... 33 
4.3.5 Flare Stacks ........................................................................................ 34 
4.3.6 Explosives ........................................................................................... 34 
4.4 INCIDENT REPORTING ........................................................................................ 34 
4.5 CONCURRENT OPERATIONS ................................................................................ 34 
5 ENVIRONMENTAL CONSIDERATIONS ................................................................ 35 
5.1 SURFACE CASING VENT FLOWS ........................................................................... 35 
5.1.1 Definitions .......................................................................................... 35 
5.1.2 Checking for Surface Casing Vent Flows ............................................ 35 
5.1.3 Testing and Reporting Surface Casing Vent Flows ............................. 36 
5.1.4 Surface Casing Vent Flow Repairs ...................................................... 38 
5.2 GAS MIGRATION .............................................................................................. 39 
5.2.1 Definitions .......................................................................................... 39 
5.3 CASING LEAKS AND FAILURES .............................................................................. 41 
5.4 NOISE ............................................................................................................ 41 
5.5 FLARING AND VENTING ...................................................................................... 41 
5.6 FLUID STORAGE ............................................................................................... 416 DATA SUBMISSION ............................................................................................ 42 
6.1 COMPLETION/WORKOVER/ABANDONMENT REPORTS ............................................. 42 
6.1.1 Instructions for Completion of the Report ......................................... 42 
6.2 WELL DELIVERABILITY TEST REPORTS ................................................................... 45 
6.2.1 Well Deliverability Test Report Instructions ....................................... 45 
6.3 OIL, GAS AND WATER ANALYSIS ......................................................................... 48 
6.4 HYDRAULIC FRACTURING FLUID REPORTS .............................................................. 48 
6.5 PRODUCTION LOGS ........................................................................................... 48 
7 COMPLIANCE ..................................................................................................... 50 
OGAA ................................................................................................................ 50 
Drilling and Production Regulation .................................................................. 50 
APPENDIX A: COMPLETION/WORKOVER REPORT GUIDELINES ............................ 51 
APPENDIX B: WELL SUSPENSION/INSPECTION FORM INSTRUCTIONS .................. 53 
APPENDIX C: NOTICE OF OPERATION / FLARE USER MANUAL .............................. 56 
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Manual Revisions 
Summary of Revisions 
The Well Completion, Maintenance and Abandonment Manual 
has been revised based upon feedback to provide clarity in 
terms of requirements and process. Structural changes by 
section are highlighted below. 
 
Applications received on or after the effective date will be 
required to meet the revised application standards. 
 
Effective Date Section Description/Rationale 
1-Dec-2010 General Updated Links 
1-Jan -2011 3 Changed the requirements for Wellbore Fluid in tables 3.2, 3.3 and 3.4 
1-Feb-2011 1 Updated links and Feedback email address. 
1-March-2011 General Updated formatting. No process changes. 
1-May-2011 3 & 6 
Completion/Workover Reports. Included information provided in IL 
2011-05 and the Completion/Workover Report Submission Guide. 
1-August-2011 General Updated page numbers 
1-Sept-2011 7 Added Compliance section. 
1- Nov-2011 General 
Updated links to BCOGC. Added Notice of Operation/Notice of Flare 
User Manual to Appendix B. 
1-Jan-2012 4 Updated Table 4.1: Recommended Spacing Distances 
1-Feb-2012 6 Added Section 6.4: Data Submission 
1-May-2012 Appendix B Added Well Suspension/Inspection Report Instructions, p. 52. 
 6 
Added clarification to Section 6.3, p.48: samples must be taken prior to 
or within six months. 
 6 Added Section 6.5: Production Logs, p.48. 
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1 Preface 
1.1 Purpose 
This manual has been created to guide users through the BC 
Oil and Gas Commission (the Commission) processes and 
procedures. It also serves to highlight changes in process, 
procedure, requirements and terminology resulting from the Oil 
and Gas Activities Act (OGAA). 
 
For users already familiar with the Commission application 
process, this manual provides a quick reference highlighting the 
steps required to complete specific tasks. For users less 
familiar, this manual presents a complete overview of 
Commission requirements and provides links to more detailed 
material. 
This manual is not intended to take the place of the applicable 
legislation. The user is encouraged to read the full text of 
legislation and each applicable regulation and seek direction 
from Commission staff, if and when necessary, for clarification. 
1.2 Scope 
This manual focuses exclusively on requirements and 
processes associated with the Commission’s legislative 
authorities and does not provide information on legal 
responsibilities that the Commission does not regulate. It is the 
responsibility of the applicant or permit holder to know and 
uphold its other legal responsibilities. Examples of legal 
responsibilities outside of this manual include obligations under 
the Federal Fisheries Act, the Transportation Act, the Highway 
Act, the Workers Compensation Act, and the Wildlife Act. 
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1.3 How to Use This Manual 
This manual is divided into sections which will take the user 
through the various operational steps and regulatory 
requirements related to well servicing activities, including 
completions, workovers, maintenance and abandonments. 
 
Section 2.0 Well Equipment explains regulatory requirements for well 
equipment in the Drilling and Production Regulation. 
Section 3.0 Well Servicing Operations outlines and explains the 
requirements for well completions, workovers, maintenance, 
suspension and abandonments. 
Section 4.0 Well Servicing Equipment and Procedures outlines and 
explains blowout prevention standards, personnel requirements 
and fire precautions that permit holders must follow to comply 
with the Drilling and Production Regulation. 
Section 5.0 Environmental Considerations outlines and explains the 
regulatory requirements for flaring, noise, fluid storage, casing 
leaks, surface casing vent flows and gas migration. 
Section 6.0 Data Submission outlines and explains the regulatory 
requirements the operator must include in reports for the 
completion, workover and abandonment of wells. Regulatory 
requirements for reporting on well deliverability tests are also 
included within this section. 
Section 7.0 Compliance describes contravention of legislation and 
regulation and administrative penalties. 
 
1.4 Additional Guidance 
Guidance for submitting applications for wells within the 
jurisdiction of the Commission is located in the Well Permit 
Application Manual. 
Guidance for well construction, drilling, reclamation and waste 
management for wells within the jurisdiction of the Commission 
is located in the Well Drilling and Waste Management manuals 
The glossary page on the Commission website provides a 
comprehensive list of terms. 
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Other navigational and illustrative elements used in the manual 
include: 
 
Hyperlinks: 
Hyperlinked items appear as blue, underlined text. Clicking on a 
hyperlink takes the user directly to a document or location on a 
webpage. 
 Sidebars: 
Sidebars highlight important information such as a change from 
the old procedure, new information, or reminders and tips. 
Figures: 
Figures illustrate a function or process to give the user a visual 
representation of a large or complex item. 
Tables: 
Tables organize information into columns and rows for quick 
comparison. 
 
1.4.1 Feedback 
The Commission is committed to continuous improvement by 
collecting information on the effectiveness of guidelines and 
manuals. Clients and stakeholders wishing to comment on 
Commission guidelines and manuals may send constructive 
comments to OGC.Systems@bcogc.ca. 
 
1.4.2 Frequently Asked Questions 
A Frequently Asked Questions (FAQ) link is available on the 
Commission OGAA website. The information provided is 
categorized into topics which reflect the manuals for easy 
reference. 
 
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2 Well Equipment 
 
The well equipment section outlines the regulatory requirementsfor well equipment in the Drilling and Production Regulation. 
2.1 Wellheads 
[Section 17, Drilling and Production Regulation] 
Wellheads are required to operate safely under the conditions 
anticipated during the life of the well and the wellhead is not to 
be subjected to excessive force. 
Refer to Enform Publications’ Industry Recommended Practice 
(IRP) Volume #5 (IRP 5 – Minimum Wellhead Requirements) for 
more information. 
2.2 Tubing 
[Section 16, Drilling and Production Regulation] 
Tubing is required for the production of gas containing ≥ 5% 
hydrogen sulphide (H2S) and for all injection and disposal 
except for the injection of fresh water. 
2.3 Packers 
[Sections 16 and 39, Drilling and Production Regulation] 
A production packer must be used for: 
 All injection and disposal except for the injection of fresh 
water and 
 Wells containing gas with > 5% H2S, or if a numbered 
highway or populated area is located within the emergency 
planning zone for the well. 
 
“Populated area” means a dwelling, school, picnic ground or 
other place of public concourse. 
Annual packer isolation testing is required for all wells where 
installation of a production packer is required. If a packer test 
fails, the permit holder must complete repairs without 
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unreasonable1 delay. 
Refer to the Alberta Energy and Resources Conservation Board 
(ERCB) Interim Directive ID 2003-01 for recommended packer 
testing procedures. 
The permit holder is required to maintain a record of all packer 
isolation tests and repairs. This information must be submitted 
to the Commission on request. 
 
2.4 Subsurface Safety Valves 
[Section 39, Drilling and Production Regulation] 
Subsurface safety valves are required for wells containing gas 
with > 5% H2S if: 
 A major highway or populated area is located within the 
emergency planning zone for the well 
 The well is located within 800 m of a populated area or 8 
km of a town, city or village and 
 The well could produce > 30 000 m3 of gas per day 
In general, the distance from a city, town or village should be 
measured from the corporate limits. In cases where the 
corporate limits do not reasonably correspond with the 
boundaries of the community, the permit holder may take a 
functional approach such as delineation of the extent of 
developed areas. 
2.5 Oil Wells 
[Section 39, Drilling and Production Regulation] 
Oil wells completed after September 13, 2010 equipped with an 
artificial lift, if the H2S content of the gas exceeds 100 ppm, 
must install the following 
 An automatic shutdown on the stuffing box that will shut 
down the pumping unit in the event of a stuffing box or 
polish rod failure and 
 An automatic vibration shutdown system 
 
1
 In general, all repairs should be completed within 90 days. Reasonable 
delays are acceptable in cases where access is seasonal and the delay does 
not result in a risk to safety or the environment. Delays that extend past the 
next seasonal access window are not reasonable (greater than one year). 
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2.6 Fencing 
[Section 39, Drilling and Production Regulation] 
Permit holders of completed wells that: 
 Are located within 800 m of a populated area or 
 Have a populated area within the emergency planning 
zone for the well 
Fencing or other measures to prevent unauthorized access to 
the well must be installed in these circumstances. 
Fencing or other forms of access control must be proportional to 
the potential for unauthorized access to the wellsite. Access 
control may include fencing of the wellsite, or gating the access 
road. If the well is located in an access-controlled area, no 
additional measures may be required. For wells that are located 
on private land, the method of access control should be 
developed in consultation with the landowner. 
 
2.7 Leak Detection 
[Section 39, Drilling and Production Regulation] 
All completed wells must be equipped with a system to detect 
and control leaks as quickly as practicable. 
The Commission expects that leak detection systems will be 
proportional to the consequences that may result from a leak. 
Leak detection may range from fully automated shutdown 
systems to periodic inspections. 
If an uncontrolled flow from a completed well could produce a 
hydrogen sulphide concentration in atmosphere greater than 
100 ppm at a distance of 50 metres from the well, the permit 
holder must install and maintain: 
 An automated shutdown system and 
 A hydrogen sulphide detection, alarm and automated 
shutdown system if the well is located within 1600 metres 
of a populated area 
For wells completed prior to October 4, 2010, H2S detection and 
automated shutdown systems are not required until 
January 1, 2012 and the permit holder may apply for an 
exemption to the requirement. 
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The following formula may be used to calculate the absolute 
open flow rate of a well that will result in an H2S concentration in 
atmosphere of 100 ppm at a point 50 metres from the well: 
Wellhead AOF (103m3/day) = 147 000 / H2S (ppm) 
or 
Wellhead AOF (103m3/day) = 14.7 / H2S (mol %) 
 
 
 
 
 
 
 
 
 
 
 
 
 
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3 Well Servicing Operations 
The well servicing operations section outlines and explains the 
requirements for the reporting of servicing, suspension, 
reactivation or abandonment of wells. It also outlines the 
notification requirements for completions, workovers and 
maintenance of wells. 
3.1 Well Servicing Operations 
[Section 39, Drilling and Production Regulation] 
A permit holder must ensure that an adequate Emergency 
Response Plan is in place before conducting well servicing 
operations. Refer to the Emergency Response Plan 
Requirements document or contact the Commission Emergency 
Response and Safety Department for more information. 
3.2 Completions / Workovers / Maintenance 
[Section 24, Drilling and Production Regulation] 
 
A Notice of Operations must be submitted to the Commission at 
least 24 hours prior to the start of all completion, workover or 
abandonment operations. An approved Application to Alter is no 
longer required for completion or workover operations. 
 
All notifications must be submitted using the Online Reporting 
System. Refer to Appendix B for the instruction manual. 
 
See Section 6.1 for Completion/Workover Report submission 
requirements. 
 
3.2.1 Shallow Fracturing 
[Section 21, Drilling and Production Regulation] 
Fracturing operations conducted at a depth of 600 metres or 
less must be approved in the well permit. Applications for 
shallow fracturing operations should include: 
 The fracture program design including proposed pumping 
rates, volumes, pressures, and fracturing fluids 
 Estimation of the maximum fracture propagation 
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 Assessment of groundwater resources in the area 
 Identification and depth of all wells within 200 metres of the 
proposed shallow fracturing operations 
 Verification of cement integrity through available public 
data of all wells under the Commission’s jurisdiction within 
a 200 metre radius of the well to be fractured 
 Notification of water well owners within 200 metres of theproposed fracturing operations 
 The depth of bedrock and 
 Assessment of the suitability of the candidate well for the 
proposed fracturing operations including casing and 
cement integrity 
Refer to the Well Permit Application Manual for more 
information on well permit applications and amendments. 
3.2.2 Commingling 
[Section 23, Drilling and Production Regulation] 
All zones in a well must remain segregated unless permission 
has been granted for commingled production. Permission may 
be granted in an individual well permit or by a special project for 
commingling under section 75 of OGAA. The Commission has 
designated certain areas where commingling is authorized, 
subject to certain conditions, including: 
 Deep basin 
 Plains and Northern Foothills 
 Outer Foothills 
For more information, refer to the Commingling section within 
the Commission’s Resource Conservation Forms and 
Guidelines page. 
 
The Notification of Commingled Well Production form must be 
submitted to the Commission within 30 days of the 
commencement of commingled production. 
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3.3 Well Suspension 
[Section 25, Drilling and Production Regulation] 
3.3.1 Definitions 
“Activity” means 
(a) production, injection, or disposal of fluids, 
(b) drilling, completion or workover operations and 
(c) reservoir pressure observation. 
 
“Inactive Well” means a well that has not been abandoned but 
(a) has not been active for 12 consecutive months or 
(b) if the well is classified as a special sour well or an acid 
gas disposal well and has not been active for 6 
consecutive months. 
For active production, injection and disposal wells, the date of 
last activity is defined as the first day of the month following the 
last month for which production, injection and disposal volumes 
were reported. 
Observation wells are deemed to be active (see Observation 
Wells section). 
For drilling activity, including new wells and re-entries, the date 
of last activity is defined as the rig release date. 
For completion and workover activity, the date of last activity is 
defined as the completion date. 
A permit holder may apply to the Commission to declassify a 
special sour well. 
 
3.3.2 Observation Wells 
Inactive wells offer good opportunities to monitor reservoir 
behaviour, specifically, pool pressures over time. Tests of these 
wells do not require shutting in producing wells to obtain 
pressure information and can provide accurate sampling points. 
Wells with an operational status of Observation must be tested 
and a Reservoir Pressure Survey Test Report must be 
submitted to the Commission Resource Conservation 
Department at least once every two years. 
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A well may be classified as Observation by submission of a 
BC-11 form (Notice of Commencement or Suspension of 
Operations) to the Ministry of Finance. A brief statement 
indicating what the well will be used to monitor should be 
included in the comments section. 
 Observation wells are treated as active and do not require 
suspension unless declassified. 
 Observation wells will be declassified if pressure data is 
not submitted within 12 months of its due date. 
 Upon declassification, observation wells will be reclassified 
according to the well operation status (i.e. Gas Production) 
that existed prior to their classification as observation wells 
and will require suspension. 
 For observation wells that have been declassified, the date 
of last activity is the due date of the last pressure test 
survey report. 
 
3.3.3 Suspension Requirements 
All wells must be suspended within 60 days of attaining inactive 
status in a manner that ensures the ongoing integrity of the well. 
Any well may be suspended to a higher standard than the 
minimum requirements described in Tables 1 to 4. Reporting 
requirements are outlined in the Information and Reporting 
Requirements section. 
If all zones in a non-special sour well are abandoned and the 
well has not yet been surface abandoned, the well shall be 
categorized as “Low Risk - All cased wells (no perforations or 
open hole)”. 
Permit holders may apply to the Commission Drilling and 
Production Department for an extension of a deadline. 
The following tables describe the Commission’s minimum 
requirements for each category. 
 
 
 
 
 
 
 
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Table 3.1: General Requirements for All Inactive Wells 
Wellheads 
Unperforated wells may use a welded steel plate atop the production casing stub. 
The plate must provide access to the wellbore for pressure measurement. All other 
wells must use standard wellheads as described in IRP2 and IRP5 (draft). 
Wellhead 
Maintenance 
There shall be no wellhead leaks. 
Bullplugs or blind flanges with needle valves must be installed on all outlets except 
the surface casing vent. 
The surface casing vent valve must be open and the surface casing vent 
unobstructed unless otherwise exempted by an official. 
All valves must be chained and locked or valve handles must be removed. 
The flowline must be disconnected from the wellhead. 
Polish rod removal is not required to suspend low risk oil wells as long as the polish 
rod remains connected to the pump jack. 
Pressure testing of the wellhead sealing elements refers to the primary and 
secondary seals only, as applicable. For wellheads that do not have adequate test 
ports, pressure tests may be omitted and visual observation for leaks is acceptable. 
An explanatory note must be included on the well suspension report. 
Surface 
Casing Vent 
Flows 
Surface casing vent flows are to be managed and reported in accordance with 
Commission requirements. 
Lease 
Maintenance 
 A sign stating the well’s surface location, current permit holder, the current 
permit holder’s emergency contact number and appropriate warning symbols 
as defined in Section 17 of the Drilling and Production Regulation must be in 
place. 
 An area of 10 metres radius around the wellhead must be maintained to 
prevent brush from growing and causing a fire hazard. 
 Noxious weeds must be controlled. 
 
Visual 
Inspection 
A visual inspection of the lease and wellhead must be conducted at least yearly to 
observe for wellhead integrity, noxious weeds and other hazards. 
For wells with helicopter access, the visual inspection frequency is the pressure 
testing / monitoring frequency. 
Reporting 
 Submit a BC-11 to the Ministry of Finance as outlined in Section 8.2. 
 A Suspension Report must be submitted to the Commission within 30 days of 
the completion of suspension operations. 
 Records of inspections must be maintained on file and if requested, be made 
available to the Commission for review. 
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Table 3.2: Requirements Specific to Inactive High Risk Wells 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2
 If applicable, install a bridge plug or packer and tubing plug within 100 
metres of the liner top on uncompleted special sour wells. 
Well Types 
 Type 1: Special sour wells2. 
 Type 2: Acid gas disposal wells. 
 
Suspension Options Option A Option B 
Downhole 
Requirements 
Bridge plug or packer and 
tubing plug. 
Bridge plug capped with 8 m 
lineal of cement. 
Pressure Testing / 
Monitoring / ServicingRequirements 
Pressure test both tubing and 
annulus to 7 MPa for 10 
minutes. 
Service and pressure test 
wellhead sealing elements. 
Pressure test the casing to 7 
MPa for 10 minutes. 
Service and pressure test 
wellhead sealing elements 
(if applicable). 
Pressure Testing / 
Monitoring / Servicing 
Frequency 
At the time of suspension and 
then annually. 
At the time of suspension and 
then every 5 years. 
Wellbore Fluid 
Wellbore must be filled with 
non-saline water or corrosion 
inhibited water. The upper 
portion of the wellbore must 
be protected from freezing. 
Freeze protection may be 
accomplished by the 
placement of at least 2 m of a 
suitable, non-freezing fluid at 
surface. 
 
Wellbore must be filled with non-
saline water or corrosion 
inhibited water. The upper 
portion of the wellbore must be 
protected from freezing. Freeze 
protection may be accomplished 
by the placement of at least 2 m 
of a suitable, non-freezing fluid at 
surface. 
 
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Table 3.3: Requirements Specific to Inactive Medium Risk Wells 
 
 
 
 
3
 Flowing oil wells are oil wells with sufficient reservoir pressure to sustain 
flow against atmospheric pressure without artificial lift. The flowing product is 
a fluid. 
Well Types 
 Type 1: Medium risk gas wells (see Section 3.4). 
 Type 2: Non-flowing oil wells ≥ 50 mol/kmol H2S. 
 Type 3: Flowing oil wells3. 
 Type 4: All injection and disposal wells except for acid gas 
disposal wells. 
 Type 6: Completed low risk wells that have been inactive or 
suspended for at least 10 consecutive years. 
Suspension 
Options 
Option A (All types) Option B (All types) Option C (Type 6 Only) 
Downhole / 
Wellhead 
Requirements 
Packer and tubing plug. Bridge plug. Dual master valves. 
Pressure Testing / 
Monitoring / 
Servicing 
Requirements 
Pressure test both the 
tubing and annulus to 7 
MPa for 10 minutes. 
Service and pressure 
test wellhead sealing 
elements. 
Pressure test the 
casing to 7 MPa for 10 
minutes. 
Service and pressure 
test wellhead sealing 
elements. 
Read and record shut-in 
tubing pressure (if 
applicable) and shut-in 
casing pressure. 
Service and pressure test 
wellhead sealing 
elements. 
Pressure Testing / 
Monitoring / 
Servicing 
Frequency 
At the time of 
suspension and then 
every 3 years. 
At the time of 
suspension and then 
every 5 years. 
At the time of suspension 
and then annually. 
Wellbore Fluid 
Wellbore must be filled 
with non-saline water or 
corrosion inhibited 
water. The upper 
portion of the wellbore 
must be protected from 
freezing. Freeze 
protection may be 
accomplished by the 
placement of at least 2 
m of a suitable, non-
freezing fluid at surface. 
Wellbore must be filled 
with non-saline water or 
corrosion inhibited 
water. The upper 
portion of the wellbore 
must be protected from 
freezing. Freeze 
protection may be 
accomplished by the 
placement of at least 2 
m of a suitable, non-
freezing fluid at surface. 
None. 
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 Table 3.4: Requirements Specific to Inactive Low Risk Wells 
 
 
 
 
 
4
 Non-flowing oil wells are oil wells without sufficient reservoir pressure to 
sustain flow against atmospheric pressure without artificial lift. The flowing 
product is a fluid. Removal of polish rods is not required to suspend low-risk 
oil wells as long as the polish rod remains connected to the pump jack. 
Well Types 
 Type 1: All non-special sour cased wells (no perforations or open 
hole sections). 
 Type 2: Low risk gas wells (see Section 3.4). 
 Type 3: Water source wells. 
 Type 5: Non-flowing
4
 oil wells < 50 mol/kmol H2S. 
 
Suspension 
Options 
Option A 
(Types 2,3 and 5 only) 
Option B 
(Type 1 only) 
Downhole 
Requirements 
None. None. 
Pressure Testing 
/ Monitoring / 
Servicing 
Requirements 
Read and record shut-in tubing 
pressure (if applicable) and shut-in 
casing pressure. 
Service and pressure test 
wellhead sealing elements. 
Pressure test casing to 7 MPa for 10 
minutes. 
Service and pressure test wellhead 
sealing elements (if applicable). 
Pressure Testing 
/ Monitoring / 
Servicing 
Frequency 
At the time of suspension and 
then every 5 years. 
At the time of suspension and then every 5 
years. 
Wellbore Fluid None. 
Wellbore must be filled with non-saline 
water or corrosion inhibited water. The 
upper portion of the wellbore must be 
protected from freezing. Freeze protection 
may be accomplished by the placement of 
at least 2 m of a suitable, non-freezing 
fluid at surface. 
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3.3.4 Packer Testing 
Wells that require installation and yearly testing of a production 
packer are exempt from the testing requirements if the well is 
suspended in accordance with the Drilling and Production 
Regulation. 
3.3.5 Long Term Inactive Wells 
All completed low-risk wells must meet medium risk suspension 
requirements after being suspended for 10 consecutive years. 
For example, a completed low-risk well that last reports 
production in December 2008 would be classed as inactive on 
December 31, 2009 and the Operator would have 60 days to 
suspend the well in accordance with low-risk suspension 
requirements. If the well was still suspended on December 31, 
2019, the Operator would have 60 days to suspend the well in 
accordance with medium risk suspension requirements. 
3.3.6 Reactivating Suspended Wells 
The following are the procedures for the reactivation of a 
suspended well: 
All Wells: 
 Inspect, service and pressure test the wellhead 
 Inspect and service control systems and lease facilities 
 Report the reactivation through submission of a BC-11 
form to the Ministry of Finance 
Medium and High-Risk Wells: 
 Pressure test the casing to 7 MPa for 10 minutes 
(if applicable). If the test fails, investigate and repair the 
problem 
 Pressure test the tubing (if present) to 7 MPa for 10 
minutes. If the test fails, investigate and repair the problem 
 
3.3.7 Information / Reporting Requirements 
3.3.7.1 Oil and Gas Commission 
Suspensions 
A Well Suspension/Inspection Form must be submitted to the 
Commission, Drilling and Production Department within 30 days 
of suspension of a well. 
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BC Oil & Gas Commission 18 
The suspension report may be submitted as a paper copy or in 
spreadsheet form. 
Reactivations 
Submission of a reactivation report is not required. 
Reactivations are identified by alternate means (i.e. spud date, 
production reporting). 
Inspections 
Records of inspections must be provided to the Commission on 
request. 
Inspection results may be recorded by filling out the applicable 
sections of the Well Suspension/Inspection Form or through the 
permit holder’s internal database. If an internal inspections 
database is used, it is the permit holder’s responsibility to 
ensure that the required information is recorded. 
 
3.3.7.2 Ministry of Finance 
The form Notice of Commencement or Suspension of 
Operations: BC-11 must be submitted to the Ministry ofFinance 
on or before the 20th day of the calendar month following the 
calendar month in which the following operations occurred at a 
well: 
 Testing operations at a well prior to its being tied in to a 
gas gathering system 
 Initial commencement of production 
 Initial commencement of injection or disposal 
 Suspension of production 
 Suspension of injection or disposal 
 Resumption of production 
 Resumption of injection or disposal 
 
A separate BC-11 is required for each well or completed zone 
within a well. A single form may be completed if a well has both 
a production and a service status in a production month, or if the 
status changes more than once in a production month (for 
example testing and producing) 
 
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3.4 Classification of Low and Medium Risk Gas Wells 
3.4.1 High Risk gas wells are gas wells that are classified as 
special sour or are acid gas disposal wells. 
 
3.4.2 Medium Risk gas wells are gas wells where the 
maximum stabilized wellhead AOF exceeds the Maximum 
Allowable Flowrate5 or 28 x 103 m3/day6 and are not classified 
as high risk gas wells. 
 
Maximum Allowable Flowrate (103m3/day) = 15 x 103 / H2S 
Concentration (ppm) 
 
3.4.3 Low Risk gas wells are gas wells that are not classified 
as Medium or High Risk. 
 
 
Figure 3.1: Classification of Low and Medium Risk Gas Wells (Adopted 
from ERCB Directive 13). 
 
5
 This calculation (adopted from the ERCB Directive 13) determines the 
maximum flowrate for a given H2S concentration that will result in a 
maximum concentration of H2S at the lease boundary of 10 ppm. The lease 
boundary is assumed to be 50 metres from the wellhead. 
6
 Maximum flowrate is adopted from the ERCB Directive 13 and is 
considered to be surface killable based on fluid momentum theory. 
1
10
100
1000
10000
100000
1 10 100
H 2
S 
(p
pm
)
Flowrate (x 1000 m3/day)
28,000 m
3
/day 
535 ppm 
LOW 
RISK 
 
MEDIUM 
RISK 
 
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3.5 Well Abandonment 
[Section 26, Drilling and Production Regulation] 
For drilling wells, notification is not required prior to conducting 
open hole plugbacks or abandonments. 
 
Drilling wells that are downhole, but not surface abandoned at 
the time of rig release, are not considered abandoned. An 
abandonment notification and abandonment report must be 
submitted to the Commission at the time of surface 
abandonment as outlined below for the well status to be 
changed to abandoned. 
 
Notification is required 7 days prior to conducting all other well 
abandonments; however the notification requirement may be 
waived on a case by case basis. An abandonment program 
must be included with the notification. 
Wells must be abandoned in a manner that ensures: 
 Adequate hydraulic isolation between porous zones 
 Fluids will not leak from the well 
 Excessive pressure will not build up in any portion of the 
well 
 The long-term integrity of the wellbore is maintained 
Permit holders are expected to conduct abandonments and 
plugbacks in accordance with the ERCB Directive 20. If there is 
any doubt about the adequacy of a plugging or abandonment 
program, the permit holder should discuss their plans with the 
Commission. Failure to adequately plug or abandon a well may 
result in an order for remedial work. 
Abandonment reports may be submitted using a 
Completion/Workover Report Form. 
 
 
 
 
 
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4 Well Servicing Equipment and Procedures 
The well servicing equipment and procedures section outlines 
and explains blowout prevention standards, personnel 
requirements and fire precautions that permit holders must 
follow to comply with the Drilling and Production Regulation. 
4.1 Blowout Prevention 
[Part 4, Division 2, Drilling and Production Regulation] 
4.1.1 Well Servicing Blowout Prevention 
The following section outlines blowout prevention standards that 
a permit should follow to comply with the requirements of Part 4, 
Division 2 of the Drilling and Production Regulation. It is the 
responsibility of the permit holder to ensure that blowout 
prevention equipment and procedures are adequate. 
A permit holder may use alternate blowout prevention 
equipment and techniques if they can demonstrate by means of 
a detailed engineering analysis that the alternate equipment or 
techniques are adequate as required by section 16(1) of the 
Drilling and Production Regulation. 
4.1.2 BOP Equipment Classes 
For the purposes of well servicing, blowout prevention 
equipment classes are as follows: 
 
Class A equipment is required for a well where the minimum 
pressure rating of the production casing flange is less than or 
equal to 21 000 kilopascals (kPa) and the hydrogen sulphide 
content in a representative sample of the gas is less than 10 
mol %; 
 
Class B equipment is required for a well where the minimum 
pressure rating of the production casing flange is: 
a) greater than 21 000 kPa, or 
b) less than or equal to 21 000 kPa and the hydrogen 
sulphide content in a representative sample of the gas is 
10 mol % or greater 
 
Class C equipment is required for a special sour well. 
 
4.1.3 General 
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BC Oil & Gas Commission 22 
At all times during well servicing, the well must be under control, 
adequate blowout prevention equipment must be installed and 
must be able to shut off flow from the well regardless of the type 
or diameter of tools or equipment in the well. 
The blowout prevention equipment must have a pressure rating 
equal to or greater than the pressure rating of the production 
casing flange or the formation pressure, whichever is the lesser. 
Hydraulic ram type blowout preventers which are not equipped 
with an automatic ram locking device must have hand wheels 
available. 
An accurate pressure gauge to determine the well annulus 
pressure during a well shut-in must be either installed or readily 
accessible for installation. 
A service rig used at the well site must have an operable horn 
on the drilling control panel for sounding alerts. 
A sour service separator and flare system, including appropriate 
manifolding, must be used to process sour well effluent. 
The well control system must be adequately illuminated. 
 
4.1.4 Accumulator systems 
All blowout preventers must be hydraulically operated and 
connected to an accumulator system. 
The accumulator system must be installed and operated in 
accordance with the manufacturer's specifications. The system 
must be: 
a) Connected to the blowout preventers with lines of 
working pressure equal to the working pressure of the 
system, and within 7 metres of the well, the lines must be 
of steel construction unless completely sheathed with 
adequate fire resistant sleeving 
b) Capable of providing, without recharging, fluid of 
sufficient volume and pressure to effect full closure of all 
preventers, and to retain a pressure of 8 400 kPa on the 
accumulator system 
c) Recharged by a pressure controlled pump capable of 
recovering the accumulator pressure drop resulting from 
full closure of all preventers within 5 minutes 
d) Capable of closing any ram type preventer within 30 
seconds 
e) Capable of closing the annular preventer within 60 
seconds 
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BC Oil & Gas Commission 23 
f) Equipped with readily accessible fittings and gauges to 
determine the pre-charge pressure 
g) Equipped with a check valve between the accumulator 
recharge pump and the accumulator and 
h) Connected to a nitrogen supply capable of closing all 
blowout preventers installed on the well 
 
The accumulator nitrogen supply must: 
a) Be capable of providing sufficient volume and pressure to 
fully close all preventers and to retain a minimum 
pressure of 8 400 kPa, and 
b) Have a gauge installed, or readily available for 
installation, to determine the pressure of each nitrogen 
container 
4.1.5 Requirements Specific to Class A Systems 
Class A blowout prevention system 
a) May utilize the rig hydraulic system to recharge the 
accumulator and 
b) Must have operating controls for each preventer in a 
readily accessible location near the operator's position 
and an additional set of controls located a minimum of 
7 meters from the well 
4.1.5 Requirements Specific to Class B and C Systems 
Class B and Class C blowout prevention system must have: 
a) An independent accumulator system with operating 
controls for each preventer located at least 25 metres 
from the well, shielded or housed to protect the operator 
from flow from the well 
b) An additional set of controls in a readily accessible 
location near the operator's position and 
c) Working spools with flanged outlets 
4.1.6 Line Requirements 
The following requirements do not apply to snubbing units and 
service rigs completing rod jobs. 
A blowout prevention system must have two lines, one for 
bleeding off pressure and one for killing the well, which must: 
a) Be either steel or flexible sheathed hose to provide 
adequate fire resistant rating 
b) Be valved and have a working pressure equal to or 
greater than that required for the blowout prevention 
equipment 
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BC Oil & Gas Commission 24 
c) Have one line connected to the rig pump and one line 
connected to the tank 
d) Have one line connected to an outlet below the blowout 
preventers and the necessary equipment to readily 
connect the second line to the tubing 
e) Be at least 50 mm nominal diameter and 
f) Be securely tied down 
4.1.7 Stabbing Valve 
A full opening ball valve (stabbing valve) which can be attached 
to the tubing or other pipe in the well must: 
a) Be ready for use and located in a readily accessible 
location on the service rig 
b) Be maintained in the open position 
c) Have an internal diameter equal to or greater than the 
smallest restriction inside the tubing or casing and 
d) Be kept clean and ice free 
4.1.8 Blowout Prevention Manifold 
The blowout prevention system must include a manifold that: 
a) Consists of an arrangement of valves and steel lines that 
have a working pressure greater than or equal to that of 
the blowout prevention system installed on the well 
b) Contains a check valve to prevent flow from well to rig 
pump 
c) Contains a pressure relief valve upstream of the check 
valve 
d) Is equipped with an accurate pressure gauge which shall 
be either installed or readily accessible for installation 
4.1.9 Testing of Blowout Prevention Equipment 
Before commencing servicing operations at a well, a 10-minute 
pressure test must be conducted on: 
a) Each ram preventer to 1400 kPa, prior to the tests 
described in (b) and (c) 
b) Each ram preventer, the full opening safety valve and the 
connection between the stack and the wellhead, tested to 
the wellhead pressure rating or the formation pressure, 
whichever is less 
c) Each annular preventer to 7000 kilopascals or the 
formation pressure, whichever is less 
Note: For an annular type blowout preventer, all mechanical and 
pressure tests required under subsection (c) must be conducted 
with pipe in the blowout preventer. 
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BC Oil & Gas Commission 25 
All blowout prevention equipment, except for shear rams on 
special sour wells, must be mechanically tested daily, if 
operationally safe to do so; any equipment found defective must 
be made serviceable before operations are resumed. 
All tests must be reported in the servicing log book and in the 
case of a pressure test, the report must state the blowout 
preventer tested, the test duration and the test pressure 
observed at the start and finish of each test. 
At least once every three years, all blowout preventers must be 
shop serviced and shop tested to their working pressure and the 
test data and the maintenance performed must be recorded and 
made available to an official on request. 
4.1.10 Special Sour Wells 
Refer to Enform Publications’ Industry Recommended Practice 
(IRP) #2: Completing and Servicing Critical Sour Wells for 
detailed information. 
4.1.11 Slickline, Snubbing and Coil Tubing Operations 
Refer to Enform IRP#13: Slickline Operations 
Refer to Enform IRP#15: Snubbing Operations 
Refer to Enform IRP#21: Coil Tubing Operations (Draft) 
4.1.12 Hammer Unions 
Hammer unions should not be used in the manifold shack or 
under the rig substructure 
 
 
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4.1.13 Diagrams of Blowout Prevention Systems for Well 
Servicing 
 
 
 Figure 4.A Equipment Symbols 
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BC Oil & Gas Commission 27 
 
 
 
 
Figure 4.B BOP Class A Pressure Rating and Component Placement 
Notes: 1. Pressure rating of preventers is equal to or 
greater than the production casing flange rating or 
the formation pressure, whichever is the lesser. 
 2. 50 mm lines throughout 
 3. The positioning of the tubing and blind rams may 
be interchanged. 
 4. Spool may have threaded side outlet (and valve) if 
wellhead has threaded fittings. 
 5. A flanged BOP port (and valve) below the lowest 
set of rams may replace spool (valve may be 
threaded if wellhead has threaded fittings). 
 
 
 
 
 
 
 
 
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Figure 4.C BOP Class B Pressure Rating and Component Placement 
Notes: 1. Pressure rating of preventers is equal to or greater 
than the production casing flange rating or the 
formation pressure, whichever is the lesser. 
 2. 50 mm lines throughout 
 3. The positioning of the tubing and blind rams may 
be interchanged. 
 4. Spool may have threaded side outlet (and valve) if 
wellhead has threaded fittings. 
 5. A flanged blowout preventer port (and valve) 
below the lowest set of rams may replace spool 
(valve may be threaded if wellhead has threaded 
fittings.) 
 
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BC Oil & Gas Commission 29 
 
 
Figure 4.D BOP Class C Wellhead Configuration 
 
 
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BC Oil & Gas Commission 30 
 
Figure 4.E BOP Class C Optional Wellhead Configuration 
 
 
 
 
 
 
 
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4.2 Personnel 
[Section 13, Drilling and Production Regulation] 
The permit holder must ensure that there are a sufficient 
number of trained and competent individuals to carry out all well 
operations safely and without causing pollution.The following people must possess a valid Well Service Blowout 
Prevention Certificate, issued by Enform: 
 The driller on tour 
 The rig manager (tool push) and 
 The permit holder’s representative 
 
If gas containing H2S is expected, every crew member must be 
trained in H2S safety. 
Blowout prevention drills should be performed by each rig crew 
every 7 days or once per well, whichever is more frequent. 
Blowout prevention drills should be recorded in the servicing log 
book. 
Evidence of the qualifications of any person referred to in this 
section must be made available to an official on request. 
The rig crew must have an adequate understanding of, and be 
able to operate, the blowout prevention equipment and, when 
requested by an official and if it is safe to do so, the contractor 
or rig crew must: 
 Test the operation and effectiveness of the blowout 
prevention equipment and 
 Perform a blowout prevention drill in accordance with the 
Well Control Procedure placard issued by the Canadian 
Association of Oilwell Drilling Contractors or as outlined by 
the Enform Blowout Prevention Manual 
 
Refer to Enform IRP#7 Standards for Wellsite Supervision of 
Drilling, Completions and Workovers for more information. 
 
 
 
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BC Oil & Gas Commission 32 
 
4.3 Fire Precautions and Equipment Spacing 
[Sections 45 and 47, Drilling and Production Regulation] 
4.3.1 Engines 
Permit holders must ensure that, if engines are located at a 
wellsite, suitable safeguards are installed and tested to prevent 
a fire or explosion in the event of a release of flammable liquids 
or ignitable vapours. 
For engines located within 25 metres of a well, petroleum 
storage tank or other unprotected source of ignitable vapours, 
the Commission recommends that: 
 The engine exhaust pipe is insulated or cooled to prevent 
ignition in the event that flammable material contacts the 
exhaust pipe 
 The exhaust pipe is directed away from the well or source 
of ignitable vapours and 
 The exhaust manifold is sufficiently shielded to prevent 
contact with flammable materials 
 
For diesel engines located within 25 metres of a well, the 
Commission recommends that one of the following devices be 
installed: 
 A positive air shutoff valve, equipped with a readily 
accessible control 
 A system for injecting inert gas into the engine’s cylinders, 
equipped with a readily accessible control or 
 A suitable duct so that air for the engine is obtained at least 
25 metres from the well 
 
Permit holders must also ensure compliance with the 
requirements in Section 23.8 of the Occupational Health and 
Safety Regulation. 
4.3.2 Fuel 
Gasoline or liquid fuel, except for fuel in tanks that are 
connected to operating equipment, must not be stored within 25 
metres of a well and drainage must be away from the wellhead. 
4.3.3 Smoking 
Smoking is prohibited within 25 metres of a well. 
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4.3.4 Recommended Spacing Distances 
Permit holders must ensure that appropriate spacing is 
maintained between potential sources of flammable liquids or 
ignitable vapours and ignition sources. All fires must be 
sufficiently safeguarded and all vessels and equipment from 
which ignitable vapours may issue must be safely vented. 
It is the responsibility of the permit holder to maintain sufficient 
equipment spacing. 
 
 
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WELLHEAD 50 25 NS NS NS 25* 50 
FLARE OR INCINERATOR 50 NS 25 25 25 25 50 
BOILER, STEAM 
GENERATING EQUIPMENT, 
TEG* 
25 NS 25 25 25 25 25 
PRODUCED WATER TANK NS 25 25 NS NS 25* NS 
OTHER SOURCES OF 
IGNITABLE VAPOURS 
NS 25 25 NS NS 25* NS 
SEPARATOR NS 25 25 NS NS 25* NS** 
FLAME TYPE EQUIPMENT 25* 25 25 25* 25* 25* T 25* 
PRODUCED FLAMMABLE 
LIQUIDS CRUDE OIL & 
CONDENSATE TANKS 
50 50 25 NS NS NS** 25* 
 All distances are in metres (m). 
 * 25 m without flame arrestors, not specified with flame arrestors. 
 ** Separator cannot be in the same dyke. 
 T Treaters should be at least 5 m (shell to shell) from other treaters. 
 Note: 
 a) Boilers etc. Includes steam generating equipment, electric generators and TEG units. 
 b) Other sources of ignitable vapours include compressors. 
 
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BC Oil & Gas Commission 34 
c) Flame type equipment includes: treaters, reboilers and line heaters. 
 d) All electrical installations must conform to the Canadian Electrical Code. 
 
Table 4.1 Recommended Spacing Distances 
 
Flares and incinerators must be located at least 80 metres from 
any public road, utility, building, installation, works, place of 
public concourse or reservation for national defence. 
4.3.5 Flare Stacks 
A sufficient area beneath and around flare stacks must be 
cleared of flammable materials and vegetation. 
The recommended blackened area beneath a flare stack is 1.5 
times the stack height. 
The Commission recognizes that a lesser area may be justified 
depending on the circumstances. It is the responsibility of the 
permit holder to maintain a sufficient area, given the location 
and the conditions under which flaring will or may occur. 
4.3.6 Explosives 
Explosives must be stored in properly constructed magazines 
and be located a minimum of 150 metres from any well 
servicing operation. 
4.4 Incident Reporting 
Spills and well control incidents must be reported to the 
Provincial Emergency Program (PEP) at 1-800-663-3456, and 
the Commission at (250) 794-5200 
Spills must be reported in accordance with the Spill Reporting 
Regulation. 
4.5 Concurrent Operations 
A concurrent operations plan is required for completions 
operations on any well that is located within 25 metres of 
another well. 
Refer to Commission Information Letter OGC IL 08-20 for more 
information. 
 
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5 Environmental Considerations 
The environmental considerations section outlines and explains 
the regulatory requirements for testing, repairing and reporting 
environmental impacts: surface case venting flows, gas 
migration, casing leaks and failures, noise, flaring and venting, 
fluid storage and spills. 
5.1 Surface Casing Vent Flows 
[Section 41, Drilling and Production Regulation] 
5.1.1 Definitions 
 “Surface Casing Vent Flow” (SCVF) means the flow of gas 
and/or liquid from the surface casing/casing annulus. 
 
“Serious Surface Casing Vent Flow” means 
 A vent flows with hydrogen sulphide (H2S) present 
 A vent flow with a stabilized gas flow rate equal to or 
greater than 300 cubic metres per day (m3/d) 
 A vent flow with a surface casing vent stabilized shut-in 
pressure greater than 
 A hydrocarbon liquid (oil) vent flow 
 A vent flow due to wellhead seal failures or casing failure 
 Awater vent flow if the water contains substances that 
could cause soil or groundwater contamination 
 A vent flow where any usable water zone in not covered by 
cemented casing or 
 Any other vent flow that constitutes a fire, public safety, or 
environmental hazard 
5.1.2 Checking for Surface Casing Vent Flows 
Testing for evidence of a surface casing vent flow must be 
conducted: 
 During initial completion of the well 
 As routine maintenance throughout the life of the well 
 During the abandonment of the well 
 
o one half the formation leak-off pressure at the surface 
casing shoe or 
o 11 kPa/m times the surface casing setting depth 
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BC Oil & Gas Commission 36 
The Commission expects routine tests for surface casing vent 
flows to be conducted at the time of well suspension, during well 
servicing operations (that is, recompletions) and annually for a 
period of five years if a positive surface casing vent flows has 
been identified. 
 
A 10-minute bubble test is adequate to test for the presence of a 
surface casing vent flow. The recommended procedure is as 
follows: 
 
Bubble Test Equipment: 
1) A container of water (from 500 ml to 1L) 
2) Pipe fittings, small hose (minimum 6mm), or other 
equipment necessary to direct gas flow from vent 
downward in the water container 
 
Bubble Test Procedure: 
1) Ensure that there are no gas leaks at fittings and welds; 
2) Ensure there is no H2S present; 
3) Ensure all valves in the vent line are open; 
4) If necessary, connect test fittings to the vent so gas flow 
can be directed into the container of water. 
5) Immerse vent or hose a maximum of 2.5 cm below the 
water surface; 
6) Observe for 10 minutes. Note any gas flow (i.e. bubbles) 
which must be recorded as a positive vent flow; 
7) Record observations. 
5.1.3 Testing and Reporting Surface Casing Vent Flows 
Serious surface casing vent flows present a safety or 
environmental hazard and must be reported to the Commission 
as soon as possible. 
The Commission recommends that permit holders report 
surface casing vent flows that are non-serious -those that do not 
present an immediate safety or environmental hazard. This may 
be accomplished by submitting via email to 
OGCDrilling.Production@bcogc.ca a Surface Casing Flow – 
Gas Migration Information Form or an industry report form . Test 
results for non-serious surface casing vent flows must be 
maintained on file and provided to the Commission on request. 
A permit holder should perform annual surface casing vent flow 
tests on all non-serious surface casing vent flow for a minimum 
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BC Oil & Gas Commission 37 
of five years. The permit holder may select appropriate yearly 
testing measures, however, the Commission may order specific 
test measures for surface casing vent flows of particular 
concern. If there is no change in the flow rate or shut in 
pressure after five years of testing, or if the vent dies out, no 
further testing is expected. If a non-serious vent flow becomes 
serious, the permit holder must notify the Commission as soon 
as possible. 
Recommended surface casing vent flow test procedures are as 
follows: 
 
5.1.3.1 Measuring Flowrate 
Once a positive vent flow is detected, the flow rate and 
stabilized shut in pressures must be recorded. To measure 
venting gas volumes, a positive displacement gas meter, turbine 
meter or an orifice well tester may be used. Equipment selection 
should be based on previous observations indicating what flow 
rate and pressure range can be expected. A positive 
displacement meter will be necessary to measure low volumes 
accurately. An orifice well tester, with proper orifice plate, may 
provide satisfactory measurements if the 24 hour shut in 
pressure is 200 kPa or greater and builds quickly. 
 Install and use the equipment according to manufacturer’s 
instructions and 
1) Do not exceed the pressure/volume range of the 
equipment 
2) Ensure that there are no leaks 
 
5.1.3.2 Measuring Buildup Pressure 
To determine the maximum shut-in surface casing pressure the 
following method can be used. 
Pressure Buildup Required Equipment: 
 Pressure gauge or single pen static pressure recorder with 
24 hour chart or 
 Dead weight pressure gauge or 
 Electronic pressure recorder 
 
A pressure relief valve, calibrated to release the pressure if it 
has built to its maximum allowable surface pressure, should be 
installed on the surface casing vent while measuring the build 
up pressure. If it is anticipated that the maximum allowable shut 
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BC Oil & Gas Commission 38 
in pressure will be exceeded, a suitable recording device must 
be used in order to capture the rise and decline of pressure (i.e. 
electronic recorder). 
Pressure Buildup Testing Procedure: 
1) Install pressure recorder and pressure relief valve. 
2) Ensure that there are no gas leaks at fittings and welds. 
3) If a chart is used, note the chart reading 24 hours later. If 
pressure has not stabilized, it may be necessary to change 
the chart in order to cover a longer time period in order to 
achieve a maximum shut-in pressure. 
4) Monitor the readings to determine when a stabilized 
maximum pressure is obtained and record this value. 
 
5.1.4 Surface Casing Vent Flow Repairs 
5.1.4.1 Non Serious Repair 
Remedial repair may be deferred until well abandonment for 
non-serious surface casing vent flows. 
In an effort to minimize the amount of venting from a non-
serious surface casing vent flow, the permit holder may consider 
the installation of a burst plate or pressure safety valve (PSV). 
The permit holder must obtain an exemption to section 18(8)(a) 
of the Drilling and Production Regulation to allow the installation 
of a burst plate or pressure safety valve. 
Non-serious surface casing vent flows must be repaired at the 
time of well abandonment. 
5.1.4.2 Serious Repair 
The permit holder of a well determined to have a serious 
surface casing vent flow should contact the Commission as 
soon as possible to discuss repair or management 
requirements. 
 
5.1.4.3 Surface Casing Vent Flow Production 
If the permit holder wishes to explore the option of producing the 
surface casing vent flow, an application must be made to the 
Drilling and Production Department to obtain an exemption to 
section 18(8)(a) of the Drilling and Production Regulation. 
Requests will be considered if: 
 The source depth and formation of origin has been clearly 
identified 
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 The permit holder owns the mineral rights to produce the 
source formation 
 The cemented portion of the surface casing or the next 
casing string covers the deepest known usable 
groundwater and 
 The flow has been analyzed and determined to be sweet (0 
percent H2S) 
The Commission may rescind the approval to produce from the 
surface casing vent and may require the surface casing vent 
flow to be repaired at any time if the Commission determines a 
safety or environmental hazard exists. 
5.2 Gas Migration 
[Section 41, Drilling and Production Regulation] 
5.2.1 Definitions 
“Gas Migration” (GM) means a flow of gas that is detectable at 
the surface outside of the outermost casing string (often referred 
to as external migration or seepage). 
 
“Serious Gas Migration” means gas migration that 
1) Contains hydrogen sulphide 
2) Creates a fire or public safety hazard or 
3) May cause off-leaseenvironmental damage (such as, 
groundwater contamination). 
A permit holder must report, via email to 
OGCDrilling.Production@bcogc.ca, all occurrences of gas 
migration to the Commission as soon as possible. 
The permit holder is not required to test for gas migration unless 
there is visible evidence that it is occurring. Upon initial 
discovery of gas migration, a gas sample should be collected to 
identify the source of the gas. Recommended gas migration 
testing procedures are as follows: 
 
5.2.1.1 Gas Migration Testing 
Once gas migration is visible, the Commission requires that 
testing be carried out to identify the source of the gas. Testing 
must be done in frost free months only and periods immediately 
after a rainfall must be avoided. If less than full scale readings 
are obtained, the soil horizon must be examined to ensure that 
readings are not the result of contaminated solids due to spills 
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of diesel fuel, solvents, oil, etc. If contaminated soils are 
suspected, the soil must be excavated and removed. Retesting 
is then required. Instrumentation must be calibrated regularly 
and checked daily when in use. 
Select sample testing points as follows: 
 Two within 30 cm of wellbore on opposite sides 
 At two metre intervals outward from the wellbore every 90 
(a cross with the wellbore at centre) to a distance of six 
metres and 
 At any points within 75 metres of the wellbore where there 
is apparent vegetation stress 
Required Equipment: 
 Bar or auger (64 mm or less in diameter) capable of 
penetrating a minimum of 50 cm 
 Calibrated monitor or other instrument capable of detecting 
hydrocarbon at one percent lower explosive limit (LEL) 
 Equipment or material to seal the hole at surface while soil 
gases are being evacuated from the soil through the 
instrument 
 
Test Procedure: 
1) Perform instrument check (for example,calibration, voltage, 
zero) 
2) Insert auger or make a bar hole a minimum of 50 cm deep 
3) Isolate the hole from atmospheric contaminations 
4) Insert hose, wand, or other equipment a minimum of 30 cm 
into hole, maintaining a seal at surface to prevent 
atmospheric gas and soil gas mixing 
5) Withdraw soil gas sample. The volume, rate, etc., will 
depend on the instrumentation being used. Ensure that a 
sufficient sample is removed to purge lines and 
instrumentation 
6) Record observations 
7) Purge instrument and lines 
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5.3 Casing Leaks and Failures 
[Section 18, Drilling and Production Regulation] 
A permit holder must notify the Commission of any casing leak 
or casing failure as soon as possible. The leak or failure must 
be repaired within a reasonable time frame, giving consideration 
to the accessibility of the site and the seriousness of the leak or 
failure. 
5.4 Noise 
[Section 40, Drilling and Production Regulation] 
A permit holder must ensure that well operations do not cause 
excessive noise. Permit holders should work with area residents 
to minimize noise impacts when undertaking completions 
activities near populated areas. 
The B.C. Noise Control Guideline (OGC IL 09-09) contains 
information regarding acceptable noise levels and noise 
assessment techniques. 
5.5 Flaring and Venting 
Refer to the Flaring and Venting Reduction Guideline for 
detailed guidance. 
5.6 Fluid Storage 
[Section 50, Drilling and Production Regulation] 
Secondary containment of tanks associated with completions 
operations is generally not required. For extended, unmanned 
flowback operations that require a facility permit, secondary 
containment in accordance with the National Fire Protection 
Agency’s Flammable and Combustible Liquids Code (NFPA 30) 
is required. 
 Fracturing fluid returns must be stored in accordance with the 
Commission’s Information Letter on the storage of fluid returns 
from hydraulic fracturing operations (OGC IL 09-07). 
 
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6 Data Submission 
This section describes the regulatory requirements for reporting 
on the completion, workover and abandonment of wells, as well 
as regulatory requirements for reporting on well deliverability 
tests and hydraulic fracturing fluid. 
All data referred to in this section, with the exception of 
hydraulic fracturing fluid reports, must be submitted to the 
Commission’s Victoria office: 
Well Data Management 
BC Oil and Gas Commission 
300-398 Harbour Road 
Victoria, B.C. V9A 0B7 
Hydraulic fracturing fluid reports are only accepted electronically 
and can be uploaded to KERMIT. 
 
6.1 Completion/Workover/Abandonment Reports 
[Sections 26 and 36, Drilling and Production Regulation] 
Two signed copies of the Completion/Workover Report and 
required attachments must be submitted to the Commission 
office in Victoria within 30 days of completing the operation. 
Incomplete reports will not be accepted and will be returned to 
sender. 
If a well has been abandoned, a summary of the surface 
abandonment must be included for the well status to be 
changed to abandoned and the location to be a candidate for a 
Certificate of Restoration. 
Appendix A specifies which operations require a 
Completion/Workover Report and which operations do not. 
Refer to Information Bulletin 2011-05 for more information. 
6.1.1 Instructions for Completion of the Report 
Statements such as “see attached daily reports” are 
unacceptable and deemed incomplete. Incomplete reports will 
not be accepted and will be returned. 
 
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6.1.1.1 Reason for work 
State the purpose of the operation (For example, initial 
completion; to increase productivity; to shut-off water flow, etc.) 
 
6.1.1.2 Chronological summary of work done 
Including date, state the highlights of the operation such as 
perforation intervals, zone(s), stimulation operations, final flow 
rates, pressure tests, fluid recovery, plugs, type of completion 
string installed. 
 
6.1.1.3 Example Summary: 
2006/11/10 Perf Bluesky 971.2–973.4 mKB 
2006/11/13 Frac: Pump 1.5 m3 15% HCL acid. 
Pump 10 m3 Fracsol, 10 tonnes of 20/40 mesh sand. 
Formation breakdown @ 21,000 kPa. 
2006/11/16 Flowed gas 3.720 103m3/d @ 2200 kPa. 
Water production 2.1 m3/hr. 
2006/11/21 Bluesky uneconomic. 
Abandoned perfs w/bridge plug at 969 mKB w/ 8 lineal m 
cement on top. 
Pressure tested BP. 
2006/11/28 Cut off casing 1 m below ground, welded vented 
plate on casing. Wellsite requires surface restoration. 
A Downhole Schematic Diagram and a copy of the Detailed 
Daily Report of the completion, workover or abandonment 
operations must be attached to each copy of the 
Completion/Workover Report. In cases where a service rig is 
not used, a copy of the service company’s report to the operator 
may be submitted instead of the detailed daily reports. 
 
6.1.1.4 Completion Type 
Indicate what kind of completion was done (for example, 
completion of two zones [dual], multiple zones perforated [three 
or more], openhole well). 
 
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6.1.1.5 Completion Activity 
Indicate the main purpose or type of the completion or workover 
(for example, openhole, perforate, fracture, acidize, cement 
squeeze or remedial). 
 
6.1.1.6 Stimulation Type 
State which stimulation type achieved breakdown or well flow. 
 
6.1.1.7