well-completion-maintenance-abandonment-guideline-august-working-v.1.17-2015.pdf

WELL COMPLETION, MAINTENANCE AND

ABANDONMENT GUIDELINE

August | 2015

Version 1.17

Well Completion, Maintenance and Abandonment Guideline, Version 1.17

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 ........................................................................................................... 8 2.7 LEAK DETECTION ................................................................................................ 8

3 WELL SERVICING OPERATIONS .......................................................................... 10

3.1 WELL SERVICING OPERATIONS ............................................................................ 10 3.2 COMPLETIONS / WORKOVERS / MAINTENANCE ..................................................... 10

3.2.1 Shallow Fracturing ............................................................................. 10 3.2.2 Commingling ...................................................................................... 11

3.3 WELL SUSPENSION ........................................................................................... 12 3.3.1 Definitions .......................................................................................... 12 3.3.2 Observation Wells .............................................................................. 12 3.3.3 Suspension Requirements .................................................................. 13 3.3.4 Packer Testing .................................................................................... 18 3.3.5 Long Term Inactive Wells ................................................................... 18 3.3.6 Reactivating Suspended Wells ........................................................... 18 3.3.7 Information / Reporting Requirements .............................................. 18

3.4 CLASSIFICATION OF LOW AND MEDIUM RISK GAS WELLS ......................................... 20 3.5 WELL ABANDONMENT ...................................................................................... 21

4 WELL SERVICING EQUIPMENT AND PROCEDURES ............................................. 22

4.1 BLOWOUT PREVENTION ..................................................................................... 22 4.1.1 Well Servicing Blowout Prevention .................................................... 22 4.1.2 BOP Equipment Classes ...................................................................... 22 4.1.3 General .............................................................................................. 23 4.1.4 Accumulator systems ......................................................................... 23 4.1.5 Requirements Specific to Class A Systems .......................................... 24 4.1.5 Requirements Specific to Class B and C Systems ................................ 24 4.1.6 Line Requirements ............................................................................. 24 4.1.7 Stabbing Valve ................................................................................... 25 4.1.8 Blowout Prevention Manifold ............................................................ 25 4.1.9 Testing of Blowout Prevention Equipment......................................... 25 4.1.10 Special Sour Wells ......................................................................... 26 4.1.11 Slickline, Snubbing and Coil Tubing Operations ............................ 26


BC Oil & Gas Commission

ii

4.1.12 Hammer Unions ............................................................................ 26 4.1.13 Diagrams of Blowout Prevention Systems for Well Servicing ....... 27

4.2 PERSONNEL ..................................................................................................... 31 4.3 FIRE PRECAUTIONS AND EQUIPMENT SPACING ....................................................... 33

4.3.1 Engines ............................................................................................... 33 4.3.2 Fuel .................................................................................................... 33 4.3.3 Smoking ............................................................................................. 33 4.3.4 Recommended Spacing Distances...................................................... 34 4.3.5 Flare Stacks ........................................................................................ 35 4.3.6 Explosives ........................................................................................... 35

4.4 INCIDENT REPORTING ........................................................................................ 35 4.5 CONCURRENT OPERATIONS ................................................................................ 35

5 ENVIRONMENTAL CONSIDERATIONS ................................................................ 36

5.1 SURFACE CASING VENT FLOWS ........................................................................... 36 5.1.1 Definitions .......................................................................................... 36 5.1.2 Checking for Surface Casing Vent Flows ............................................ 36 5.1.3 Testing and Reporting Surface Casing Vent Flows ............................. 37 5.1.4 Surface Casing Vent Flow Repairs ...................................................... 39

5.2 GAS MIGRATION .............................................................................................. 40 5.2.1 Definitions .......................................................................................... 40

5.3 CASING LEAKS AND FAILURES .............................................................................. 42 5.4 NOISE ............................................................................................................ 42 5.5 FLARING AND VENTING ...................................................................................... 42 5.6 FLUID STORAGE ............................................................................................... 42

6 DATA SUBMISSION ............................................................................................ 43

6.1 COMPLETION / WORKOVER / ABANDONMENT REPORTS .......................................... 43

7 COMPLIANCE ..................................................................................................... 46

OGAA ................................................................................................................ 46 Drilling and Production Regulation .................................................................. 46

APPENDIX A: COMPLETION/WORKOVER REPORT GUIDELINES ............................ 47

APPENDIX B: WELL SUSPENSION/INSPECTION FORM INSTRUCTIONS .................. 51

Well Classification ............................................................................................ 51 Formations Open To The Wellbore ................................................................... 51 Pressure Monitoring and Pressure Tests .......................................................... 52 Visual Inspection .............................................................................................. 52 General ............................................................................................................. 53



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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-June-2014

Section 4

Updated s. 4.1.2 Class A & B hydrogen sulphide content samples

from 10 mol % or great to 1 mol % or greater (p. 23).

Updated s. 4.1.4 to include a rating of production casing (p.30).

Section 6 Updated the submissions section to reflect the new Well Data

Requirements Submission Guideline (p. 46)

13-February-2015 Various

Updated to reflect the change in the water source approval process

and requirements for hydrogeological assessment and data

collection, monitoring, and data reporting.

For more information, refer to INDB 2015-03 on the Commission’s website.

20-April-2015 Various

This document has been updated to reflect the implementation of the

Commission’s eSubmission Portal. Readers are encouraged to

review this document in full. Please see INDB 2015-06 and the

Commission’s BTS webpage for more information.

10-August-2015 Section

2.3

Update reference for packer isolation test procedures to

Commission’s Water Service Well Summary document.



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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 Supplementary Information for Water Source Wells document outlines additional requirements specific to water source wells. The glossary page on the Commission website provides a

comprehensive list of terms.

http://www.bcogc.ca/document.aspx?documentID=874&type=.pdf


http://www.bcogc.ca/node/12337/download

http://www.bcogc.ca/documents/publications/Fact%20Sheets/Glossary_FINAL.pdf



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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 [email protected].

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.

mailto:[email protected]

http://www.bcogc.ca/OGAA/faq.aspx



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2 Well Equipment

The well equipment section outlines the regulatory requirements for 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


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

http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/282_2010

http://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=19&type=irp



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unreasonable1 delay.

Refer to the Commission’s Water Service Well Summary Information document Appendix D for recommended packer testing procedures.

Please submit a PDF file of the report to

[email protected] with the naming convention

WANUM_PIT_YYYYMMMDD_OPTIONAL (example:

11122_PIT_2015JUN05_PASS). YYYYMMMDD is the date the

test was performed. The optional portion of the naming

convention may be any alphanumeric text up to 40 characters in

length. eSubmission of packer isolation tests reports is under

development and will be available soon.

2.4 Subsurface Safety Valves


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


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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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



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2.6 Fencing


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


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


A permit holder must ensure that an adequate Emergency Response Plan is in place before conducting well servicing operations. For more information, contact the Commission’s Emergency Response and Safety Department.

3.2 Completions / Workovers / Maintenance


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 eSubmission Portal. Refer to the eSubmission Portal User Guide for more information.

See Section 6.1 for Completion/Workover Report submission requirements.

3.2.1 Shallow Fracturing


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 the proposed 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


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 Reservoir Engineering 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.


http://www.bcogc.ca/industryzone/forms/resourceconservation.aspx

http://www.bcogc.ca/document.aspx?documentID=637&type=.doc



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3.3 Well Suspension


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 Reservoir Engineering 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.

http://enform.ca/media/3583/irp2_final_2007.pdf

http://enform.ca/media/93722/irp05_draft_rev19_june2010.pdf



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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 / Servicing

Requirements

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.


wellhead sealing elements

(if applicable).

Pressure Testing /

Monitoring / Servicing

Frequency

At the time of suspension and

then annually.


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.


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

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

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.

m of a suitable, non-

freezing fluid at surface.

m of a suitable, non-

freezing fluid at surface.

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-flowing4 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.


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


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.

The suspension report may be submitted as a paper copy or in spreadsheet form.



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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 of Finance 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)

http://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdf

http://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdf



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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.

5 This calculation (adopted from the AER 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 AER Directive 13 and is considered

to be surface killable based on fluid momentum theory.

1

10

100

1000

10000

100000

1 10 100

H2S

(p

pm

)

Flowrate (x 1000 m3/day) 28,000 m

3/day

535 ppm

LOW

RISK

MEDIUM

RISK



21

Figure 3.1: Classification of Low and Medium Risk Gas Wells (Adopted from AER Directive 13).

3.5 Well Abandonment


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 AER 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.

http://www.ercb.ca/docs/documents/directives/directive020.pdf




22

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 1 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

1 mol % or greater

Class C equipment is required for a special sour well.



23

4.1.3 General

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



24

e) Capable of closing the annular preventer within 60

seconds

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



25

b) Be valved and have a working pressure equal to or

greater than that required for the blowout prevention

equipment

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



26

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.

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







27

4.1.13 Diagrams of Blowout Prevention Systems for Well Servicing

Figure 4.A Equipment Symbols



28

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).



29

Rating of production casing flange is greater than 21 000 kPa or

rating of production casing flange is less than or equal to 21 000

kPa and the H2S content of the gas is equal to or greater than

10 MOLES per KILOMOLE.

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.)



30

Figure 4.D BOP Class C Wellhead Configuration



31

Figure 4.E BOP Class C Optional Wellhead Configuration

4.2 Personnel


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

http://ww2.enform.ca/



32

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.





33

4.3 Fire Precautions and Equipment Spacing


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.

http://www2.worksafebc.com/publications/OHSRegulation/Part23.asp#SectionNumber:23.8

http://www2.worksafebc.com/publications/OHSRegulation/Part23.asp#SectionNumber:23.8



34

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.

WEL

LHEA

D

FLA

RE

OR

INC

INER

ATO

R

BO

ILER

, STE

AM

GEN

ERA

TIN

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EQU

IPM

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TEG

*

PR

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AN

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UIP

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LAM

MA

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LIQ

UID

S C

RU

DE

OIL

& C

ON

DEN

SATE

TA

NK

S

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.



35

b) Other sources of ignitable vapours include compressors. 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.

http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90

http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90



36

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


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

A water 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



37

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 [email protected] a Surface Casing Flow – Gas Migration Information Form or an industry report form . Test

mailto:[email protected]?subject=Surface%20Casing%20Vent%20Flow%20report

http://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdf

http://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdf



38

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 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



39

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 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(9)(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



40

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(9)(a) of the Drilling and Production Regulation. Requests will be considered if:

The source depth and formation of origin has been clearly identified

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


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-lease environmental damage (such as, groundwater contamination).

A permit holder must report, via email to [email protected], 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:

mailto:[email protected]?subject=Gas%20Migration%20occurence



41

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 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



42

7) Purge instrument and lines

5.3 Casing Leaks and Failures


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


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


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).

http://www.bcogc.ca/documents/BC%20Noise%20Control%20Best%20Management%20Practices%20Guideline%20March%202009.pdf





43

6 Data Submission

General

All data must be submitted to the Commission.

For compete submission requirements, please refer to the Well Data Submission Requirements Manual.

This section provides instructions on Completion, Workover and Abandonment Reports.

6.1 Completion / Workover / Abandonment Reports


One pdf copy of the Completion / Workover / Abandonment Report (CW Report) must be emailed to [email protected] within 30 days of the end of main operations (do not include flow/clean-up). Incomplete reports will not be accepted and will be returned to sender.

Appendix A specifies which operations require a Completion/Workover Report and which operations do not. Refer to the Notice of Operations and Completion Workover Report – Reference Guide for more information.

6.1.1 Completion / Workover / Abandonment form – Cover

Page

Check the appropriate box for type of report (Completion, Workover, Abandonment, Other). The report must include: Well Name, Well Permit #, Bottom hole location, 16 character Unique Well Identifier (UWI), Start and Finish dates of the daily reports included, Intervals worked (Open Hole interval, perforation intervals or location of frac ports) and the geological formation name. Incomplete reports will not be accepted and will be returned.








44

6.1.1.1 Reason for work

State the purpose of the operation (such as, initial completion; to increase productivity; to shut-off water flow, re-entry, recompletion, zonal abandonment, surface abandonment, etc.)

6.1.1.2 Required Attachments to the Completion /

Workover Report

Required attachments include:

Chronological Summary - either on this form if a short summary, or on separate enclosed page, list the major events in this completion report by date, such as perforations or frac port openings, stimulation operations, setting temporary or permanent plugs/zonal abandonments, milling operations, type of production string installed and flowing operations.

Detailed completion/workover daily reports.

Downhole schematic diagram.

6.1.1.3 Example Chronological Short Summary:

2010/11/10 Perf Bluesky 971.2–973.4 mKB 2010/11/13 Frac: Pump 1.5 m3 15% HCL acid. Pump 10 m3 Fracsol, 10 tonnes of 20/40 mesh sand. Formation breakdown @ 21,000 kPa 2010/11/16 Flowed gas 3.720 103m3/d @ 2200 kPa. Water production 2.1 m3/hr. 2010/11/21 Bluesky uneconomic. Set bridge plug at 969 mKB w/ 8 lineal m cement on top. Pressure tested BP.

6.1.1.4 Completion Type

Indicate what kind of completion was done (such as, Open Hole well, Single if one zone capable of producing, Dual or Multi if 2 or more zones capable of producing separately, Commingled if two or more formations producing together).

6.1.1.5 Completion Activity

Indicate all operations performed within this completion report.

6.1.1.6 Stimulation Type

State which stimulation type achieved breakdown or well flow.



45

If Acid Stimulation, state the acid volume pumped in the stimulation in cubic meters (m3) and the maximum pressure used in the acid stimulation in kilopascals (kPa). If Hydraulic Fracturing conducted, submit fracture data file electronically via the eSubmission Portal. Please refer to Hydraulic Fracture CSV How-To Guide.

6.1.1.7 Flow Summary (for each formation)

If applicable, indicate the hydrogen sulphide (H2S) percent, oil rate, water rate, choke size or API gravity.

6.1.1.8 Flow Rate

Indicate the final gas flow rate in 103m3/day.

6.1.1.9 Flow Pressure

Indicate the final flow pressure in kPa.

6.1.1.10 Flow Date

Indicate the final flow date.

6.1.1.11 Radioactive Material

Indicate if radioactive material was used in the workover (such as frac sand). If so, attach documentation explaining the method of disposal or, if buried on site, attach sketch of location showing burial location and indicate depth of burial and volume of material.

6.1.1.12 Result of Work Done

State the outcome of the operation (such as, successful completion of the Montney; well on production; productivity increased; water flow successfully shut-off; well successfully suspended) For the above example, the result would be, “Bluesky tested and suspended with BP”.

http://esubmission.bcogc.ca/



46

7 Compliance

OGAA

A person found by the Courts, to have contravened the Oil and Gas Activities Act may be subject to a fine not exceeding the amount specified in Section 86 of the act. A person found by the Commission, to have contravened OGAA may be liable to an administrative penalty not exceeding the amount specified in the Administrative Penalties Regulation.

Drilling and Production Regulation

A person who contravenes the Drilling and Production Regulation (as specified in the Administrative Penalties Regulation, Section 5) may be liable to an administrative penalty ranging from $2,000 to $500,000.


BC Oil & Gas Commission 47

Appendix A: Completion/Workover Report Guidelines

A Notice of Operation including an uploaded program is required to be submitted for initial completions, completions, workovers and abandonments. Examples are shown below. A Completion / Workover Report is required to be submitted for these operations.

Completion Operations

All cased or open hole operations – using both service and drilling rigs

Perforating

Notching of tubing

Fracturing

Stimulation

Acidization (squeeze, fracturing operations)

Re-perforating an existing zone, tubing scale cleanout, hydrate removal

Milling, abrasion jetting (casing, tubing)

Bare foot completions

Testing, Monitoring and Logging

DFIT (diagnostic fracture injection test), or Mini-Frac test

o Injectivity tests

Logging for re-entry which includes removal of cement plugs

Remedial

Surface casing vent flow / gas migration - repair

Cement squeeze, cement plugs

Suspension

Plugging or suspension of a zone

Installation of:

o Casing

o patch or repair

o installation of liner

o removal or replacement

o bridge plugs (any type)

o cement retainers, cement plugs

o tubing plugs

o packers

o wireline retrievable plug



Wellhead

Inhibiting wellbore for purpose of suspension

Abandonment

All downhole work performed during abandonment operations

Surface cut and cap of a well

Re-Entry

All completion re-entry work (Completion re-entry is the re-entry of any abandoned well where no additional drilling is to occur).

For any workover performed in preparation for a drilling re-entry that is finished prior to and is not to be reported as part of the drilling re-entry (ie: drilling out of or setting of cement plugs, abandonment of hole, recovery or setting of bridge plugs, logging, casing extensions, etc.)

Bottom Hole Equipment

Installation, removal or exchange for:

Artificial lifts (includes all forms of bottom hole pumping methods)

Sub-surface safety valves - except for inspection and repair purposes

Change of:

Flapper valve for injection wells

Sliding sleeve - shifting for commingling of producing zones

Tubing

Depth change

Size change

Installation or removal - e.g.,velocity strings, endless tubing

A Notice of Operation is required to be submitted for the maintenance operations listed below. A Completion / Workover Report is not required for these operations:

Testing, Monitoring and Logging

Surface casing vent flow (SCVF) rate and buildup pressure

Packer isolation testing

o installation of dual master valve and seals for purpose of suspension

o downhole pumps

o plunger lift

o gas lift

o electrical submersible pumps (ESPs)

o bumper springs



Pressure testing – tubing or casing

Microseismic observation

Production logging

Swabbing

Gauge ring and junk basket runs

Suspension and Plugging

Inspection of suspension work

Bottom Hole Equipment

Artificial lift systems – repair

Slickline work – running or removing

Downhole choke – installation or removal

Rod replacement or repair, polish rod

Packers - removal, repair and re-installation

Wellbore Integrity

Cleaning

Acidization (wash or pickling operation)

Scale

Coil tubing cleanout

Nitrogen / CO2

Blow downs

Well clean-up

Chemical injection for perforation wash

Methanol injection

Wax removal

Sulphur removal

Corrosion inhibitor

Swabbing of any type of tubing

Circulating for clean out of wellbore

Tubing

Fishing, chemical cutters

o plunger lift

o gas lift

o pumpjack

o including all forms of pumping methods

o running recorders

o pressure gradient tests



Hole in tubing – repair

Replacement or changing (same size)

Back pressure valves, installation or removal

Wellhead

Master valves and seals – installation, changes, testing or repair

Primary and secondary seal testing

Surface casing vent assembly installation or repair

Burst plate or vent plate installation or repair

Well head valves maintenance (greasing)

For more information on operations not listed in this table, please contact:

Drilling and Production, Engineering Division, [email protected]

or Trudy Clark, (250)794-5258.




Appendix B: Well Suspension/Inspection Form Instructions

A Well Suspension/Inspection Form must be submitted to the Commission’s Drilling and Production Department within 30 days of suspension of a well and should be submitted by email to [email protected]. Records of suspensions and inspections must be maintained on file until the time of well abandonment and must be provided to the Commission on request. Inspection results may be recorded by filling out the applicable sections of the OGC’s Well Suspension/Inspection Form.

Please note: Incomplete reports will not be accepted.

General

Required for all suspensions and inspections.

Well Name: Enter the full well name (for example, OIL CORP TOMMY B-092-I/092-G-09)

WA#: Enter the well authorization number (for example, 12345)

Permit Holder: Enter the name of the licensed operator (for example, Oil Corporation Ltd.)

Date: Enter the date that suspension operations or the inspection were completed

Site Access: Enter the method of site access (for example, All Weather Road, Dry Summer Road, Frozen Winter Road, Air, ATV Access, Walk-In Access Only, Etc.)

Well Classification

Required at time of suspension. Not required for suspended well inspections.

Risk: Select the well classification: High, Medium or Low risk, as applicable, defined in Section 3.3.

Well Type: Select the well type: 1-6, as applicable, defined in Section 3.3.

Suspension Option: Select the suspension option: A, B or C used for suspension, defined in Section 3.3.

Formations Open To The Wellbore

Required at time of suspension. Not required for suspended well inspections.





Include the formation name, associated H2S (%) and CO2 (%) and formation interval (top and bottom locations in mKB). For formations with multiple perforations, enter the upper and lower interval of the combined perforations, not each individual interval.

Example:

FORMATION H2S (%) CO2 (%) INTERVAL (mKB)

Baldonnel 0.0 2.14 1238.7 -1249.7

Pressure Monitoring and Pressure Tests

Required at time of suspension and when pressure monitoring/testing is required. Not required for visual inspections.

The correct Shut-In Tubing Pressure (SITP) and Shut-In Casing Pressure (SICP) must be recorded in the appropriate category under this section. If there is no tubing or casing installed in the well, this should be stated clearly in the Comments section. All pressure test results should be recorded as Pass, Fail or N/A. A wellhead pressure test is required for all well types. If a wellhead pressure test is reported as Fail or N/A, an explanation, in the form of supporting documentation, will be required with the report submission. Casing and tubing pressure tests are required for applicable wells, as defined in Section 3.3. All pressures should be recorded in kPa, if applicable.

Visual Inspection


Select yes or no, as applicable:

1. “No” indicates that there is no evidence of leaks from the wellhead, including any attached fittings and valves and no evidence of significant corrosion.

2. “Yes” indicates the wellhead meets the requirements for Wellheads and Wellhead Maintenance in Table 3.1.

3. “Yes” indicates the surface casing vent is properly installed and the surface casing vent is open and unobstructed. Indicate in the comments section if the surface casing vent is obstructed for the purpose of managing a vent flow (i.e., a burst plate is installed).

4. “No” indicates there is no evidence of a surface casing vent flow.

5. “Yes” indicates a barricade has been installed around the wellhead. Requirements for a barricade are site-specific.



6. “Yes” indicates a lease sign, meeting the requirements of Section 15(1) of the Drilling and Production Regulation, has been installed.

7. “Yes” indicates noxious weeds are not present on the lease, nor the lease access road.

8. “Yes” indicates brush piles are not present on the lease or the lease access road.

9. “No” indicates there are no open sumps on the lease.

General


Comments: Provide any useful comments, for example, additional suspension detail.

Name, Phone, Email, Cell: Provide the contact information of the person responsible for the report.

Documents

well-completion-maintenance-abandonment-guideline-august-working-v.1.17-2015.pdf